Text

Insp Rept 50-416/86-08 on 860318-0414.Violation Noted: Failure to Change Operating Procedures Affected by Design Change to safety-related Sys Prior to Svc Water Sys Being Declared Operable
	ML20203N972
Person / Time
Site:	Grand Gulf
Issue date:	04/22/1986
From:	Butcher R, Caldwell J, Dance H; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20203N954	List: ML20203N953; ML20203N958; ML20203N972;
References
	50-416-86-08, 50-416-86-8, NUDOCS 8605060245
	Download: ML20203N972 (12)
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UNIT ED STATES

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NUCLEAR REGULATORY COMMISSION

O REGION 11

'3* .

101 MARIETTA STREET.N.W.

- ATLANTA. GEORGI A 30323

\...../

Report No.: 50-416/86-08

Licensee: Mississippi Power And Light Company

Jackson, MS 39205-

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

Facility Name: Grand Gulf 1

Inspection Conducted: Ma ch 18 - April 14,1986

Inspe ors: } 's ** 3 42l

' p R. C. Butcher Senior Resident inspector

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Date Signed

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,yt,-J. L. Caldwell, Resident Inspector

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Date Signed

Approved by: h <>- - ,

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H'. C. Ornte, Section Chief Date Si'gned

Division of Reactor Projects

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SUMMARY

Scope: This routine inspection entailed 155 resident inspector-hours at the site

in the areas of Operational Safety Verification, Maintenance Observation,

, Surveillance Observation, Engineering Safety Feature System Walkdown, Reportable

Occurrences, Operating Reactor Events, Inspector Followup -and Unresolved Items,

and Design Changes and Modifications.

Results: One violation - Failure to change operating procedures affected by a

design change to a safety related system prior to the system being declared

operable.

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8605060245 860423 6

PDR ADOCK 0500

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REPORT DETAILS

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1. Licensee Employees Contacted

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4 J. E. Cross, Site Director

C. R. Hutchinson, General Manager

R. F. Rogers, Technical Assistant

J. D. Bailey, Compliance Coordinator

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M. J. Wright, Manager, Plant Operations '

, *L. F. Daughtery, Compliance Superintendent

D. G.-Cupstid, Start-up Supervisor

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R. H. McAnuity, Electrical Superintendent

~R. V. Moomaw, Manager, Plant Maintenance

W. P. Harris, Compliance Coordinator

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J. L. Robertson, Operations Superintendent

j' L. G. Temple, I & C Superintendent

J. H. Mueller, Mechanical Superintendent

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W. E. Edge, Manager, Nuclear Site Quality Assurance

S. M..Feith, Director, Quality Assurance

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Other licensee employees contacted included technicians, operators, security

. force members, and office personnel.

Attended exit interview

2. Exit Interview

The inspection scope and findings were summarized on April 11, 1986, with

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

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as proprietary. any of .the' material provided to or' reviewed by the inspectors

during this inspection. The_ licensee had no comment on the following

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inspection findings:

a .- 416/86-08-01, Inspector Followup Item. Development of alternate

methods for ensuring ADS operability. (Paragraph 4)

b. . 416/86-08-02, Inspector Followup Item. Development of a program and

procedures to ensure accurate drawings and a computer system to correct

the drawing legibility problem. (Paragraph 4)

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c. 416/86-08-03, Violation. Failure to ensure all operating procedures

had been changed to reflect a new design change to a safety system

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prior to the system being declared operable. (Paragraph 11)

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3. Licensee Action on Previous Enforcement Matters (92702)

. a. (Closed) Violation 416/85-46-01, Failure to follow procedures. For

item a., the licensee revised System Operating Instruction

04-1-01-E12-1, Residual - Heat Removal System, to require approved

written procedures for the unique circumstances requiring shutdown

4 cooling while in mode 2. For items b. and c., the licensee discussed

4 the event with operations personnel and revised the alarm Resource ,

j Instructions to caution operators to observe redundant instruments,

b. (Closed) Deviation 416/85-45-02. The licensee has taken action to' test

and inspect the operation of the Engineered Safety Feature (ESF) room

1 coolers to verify their operability. With this test and an engineering

evaluation the licensee determined that the ESF room ~ coolers, even

though- partially plugged,- were stili operable. The licensee has

developed General Maintenance Instruction 07-S-13-56, Testing of .the

ESF Switchgear Room Coolers, which will periodically test ~ and inspect

the coolers. This instruction will also record data for trending

purposes so that the engineering department can get a better feel for

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how often this test should be performed. - The licensee has informed the

inspectors that this test will be performed on a quarterly basis until

such time as sufficient ' data has been collected to determi.ne the

correct periodicity.

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

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visited at least daily when an inspector was onsite. Observations included

instrument readings, setpoints and recordings status of operating systems;

tags and clearances on equipment controls and switches; annunciator alarms;

adherence to limiting conditions for operation; temporary alterations in

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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

confirmation is made by verifying the following: accessible valve flow path

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

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lubrication, cooling and general condition, and instrumentation.

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General plant tours were conducted on at least a biweekly basis of portions

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

areas. Observations included safety related tagout verifications; shift

turnover, sampling program, housekeeping and general plant conditions, fire

protection equipment, control of . activities in progress, radiation

protection controls, physical security, problem identification systems, and

containment isolation.

The following comments were noted:

On March 19, 1986 at 11:00 a.m., the licensee recognized that excessive air

flow was required to maintain the Automatic Depressurization System (ADS) at

the normal operating pressure of 183 psig. The plant instrument air system

with parallel booster compressors mounted outside the ADS containment

penetration is used to supply the ADS air receivers and accumulators. The

instrument air system is a non-safety related system. The ADS is safety

related inboard from the containment outboard motor operated isolation

valve. There are presently no technical specification (TS) requirements for

ADS leakage. The licensee became aware of excessive stroking of the booster

compressors and discovered the in-line flow meter, used for indicating an

instrument air line break, was indicating a make up flow of 10 to 20 SCFM of

instrument air. The licensee then conducted an air pressure drop test and

the results correlated with the indicated make up flow.

FSAR, paragraph 5.2.2.4.1, states that the accumulators capacity is

sufficient for each ADS valve to provide two actuations against 70 percent

of maximum drywell pressure. The receiver's capacity is sufficient to

account for system leakage and to allow for three actuations of each ADS

valve over a minimum of seven days without replenishment. Alternatively,

the receiver's capacity is sufficient for 100 actuations, over a six day

period, of the low-low setpoint safety / relief valve. For longer periods of

time the receivers and accumulators can be recharged by utilizing compressed

air cylinders and the test connection provided outside containment. The

instrument air supply line from the outside containment isolation valve to

the air receiver tanks is designed to the requirements of ASME Section III,

Class 2 and 3, as applicable, and is seismic category 1. Based on requests

for additional information, in a letter dated October 24, 1983, the licensee

stated the following:

a. An ADS air drop test will be acccmplished at an 18 month frequency.

b. The instrument air system, including the booster compressors, are not

safety related and the ADS is not dependent upon it during an accident.

c. The ADS pressure is recorded every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when the system dome

pressure is greater than 135 psig.

d. An ADS low receiver pressure annunciator will be installed at the next

refueling outage.

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l e.. The ADS receiver and accumulator system has been analyzed assuming a

leakage rate of- 1.0 SCFH for each ADS valve on the system. There are

eight ADS valves.

f. The FSAR and earlier letters indicated that the system was designed to

i provide three actuations of each ADS valve over a minimum period of

seven days. This has been revised to five days at which time an air

source will be manually connected for long term operability.

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Also, in a letter dated December 20, 1982, the licensee stated that the

operator round sheets would be modified to require reading a pressure gauge

installed down stream of the booster compressors and if the gauge reads 150

, psig or less, the action statement of TS 3.5.1.e applies. TS 3.5.1.e states

that with two or more of the requirad ADS valves inoperable, be in at least

. hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reduce reactor steam dome pressure to

135 psig within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . As was demonstrated on March 19, 1986,

the use of an ADS low receiver pressure annunciator will not insure the ADS

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is operable per the FSAR. In the event of an accident with the loss of the

non-safety related instrument air system the ADS must be leak tight such

'that no more than eight SCFH leakage is allowed There are no provisions .

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installed or required to be installed to ensure the ADS leakage rate is

monitored.

The licensee shut down on March 19, 1986 and investigated the need for

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excessive air makeup to the ADS. It was discovered that the accumulator

! relief valves (there are 17 accumulator relief valves) were the source of

leakage. One relief valve was stuck open and three others were weeping

! noticeable. An analysis of the ADS showed that the relief valves have a set

pressure of 190 psig +/- 3% and reseat pressure was 10 to 15% below set

pressure. The relief valves are tested for leak tightness at 90% of set

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pressure or 171 psig. This would indicate, with an operating pressure of

183 psig, that the relief valves were operating over their leak test

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pressure and close to the lower limit of their set pressure. If a relief

valve did lift due to a pressure surge, then the system pressure would have ,

, to be reduced to less than 161.5 psig to ensure reseating. The relief

} valves are manufactured by.Lonergan.

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Based on the above, the licensee removed and tested all 17 relief valves and

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reduced valve leakage to no more than five bubbles per minute at 171 psig.

F .The operating pressure has been revised to 165 psig. The booster compressor

outlet low pressure alarm setpoint was 160 psig and required repressurizing

above 173 psig to clear the alarm. A new low pressure alarm switch was

installed that still alarms at 160 psig but clears at a pressure less than

the new operating pressure of 165 psig. The licensee reinstalled all the

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relief valves, pressurized the ADS and leak checked all accessible

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, mechanical joints. The plant returned to operation on March 24, 1986.

. Although the licensee recognized a problem with excessive ADS air makeup and

took appropriate actions, there are no TS surveillance requirements that

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would reveal excessive makeup air demand. The licensee is investigating

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alternate methods for ensuring ADS operability. This will be an Inspector

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Followup Item (416/86-08-01).

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While walking down the ADS, the inspectors found the latest ADS as-built

drawing, M-1067, revision 23A, was inaccurate in that air filter D024 and

associated isolation valves F482, F483 and F484 were not shown although they

are installed in the plant. M-1067, revision 22A, did include the filter

and associated valves. Also, the drawing quality is very poor in that some

parts of the drawing were almost illegible. The licensee has recognized the

problem with drawing inaccuracies and legibility problems. A Plant Quality

Deficiency Report was issued on February 14, 1985, describing problems with

drawing inaccuracies and legibility. The licensee is presently developing a

program and procedures to address and solve the problem with drawing

inaccuracies. The licensee has also bought a new computer system which

should correct the problem of legibility of the drawings. This computer

system is expected to be fully operable after the first refueling outage

scheduled to commance in September 1986. The drawing accuracy and

legibility problem will be identified as an Inspector Followup Item

(416/86-08-02).

On March 2, 1986, during the performance of transferring recirculation pumps

from 60 Hertz power to the Low Frequency Motor Generator (LFMG) sets to

reduce reactor power, the B recirculation pump secured completely. The

licensee's investigation revealed the output breaker for the LFMG set to the

B recirculation pump failed to close. This failure was a result of the

breaker's closing springs not being charged and the charging motor not being

energized. The licensee determined that the last time this breaker was

racked out it had not been fully racked out resulting in the closing spring

not being discharged and per procedure the operator had deenergized the

charging motor. Once the work was complete the breaker was racked in but

the operator failed to reenergize the charging motor. Since the closing

spring had not been discharged the breaker indication still showed the

spring charged. The first time the breaker was given a signal to close, as

it was during the previous reactor startup, it became discharged and without

the charging motor energized the closing spring remained discharged.

Therefore, the next time the breaker was given a signal to close, as it was

on March 2, 1986, the breaker did not close resulting in the B recirculation

pump securing completely. The breaker charging motor was reenergized

charging the closing spring and enabling operations to place the B

recirculation pump on the LFMG set without any detrimental effects to the

plant. The breaker in question is a non-safety related breaker but, the

circumstances leading to the failure of the breaker to close could occur on

safety related breakers. The licensee has taken compensatory actions to

prevent recurrence of this failure on both safety and non-safety related

breakers. These actions are as follows:

a. Plant Administrative procedure 01-5-06-1, Protective Tagging System,

has been changed by adding the instructions, for checking the charging

motor switch on and verifying the springs are charged for breakers

being racked in to the red equipment clearance sheet.

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b. Operations Section Procedure 02-5-01-2, Control and Use of Operations

Section Directives, has been changed by adding the instructions for

breaker verification ensuring that the closing springs are charged and

the charging motor switch is on. Breaker rack out instructions were

added also, to ensure that breakers are fully racked out and the

closing springs are discharged,

c. The Operation Superintendent discussed this situation with all of the

operating shifts.

d. The Operator Training department was notified of the breaker racking !

problem and will incorporate the lessons learned into the training

program,

e. Operations is changing the auxiliary building, control building and

turbine building round sheets to require operators to check each

operable breaker weekly to verify that the charging springs are charged

and the charging motor switch is on.

The licensee has fully investigated and determined the cause of this event

and has taken appropriate corrective actions.

No violations or deviations were identified.

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 or 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.

6. 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 TS, 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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7. ESF System Walkdown (71710)

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

Pressure Core Spray (LPCS) 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.

There were no problems identified during the walkdown. However, one

observation made by the inspector relates to the comments in Paragraph 4.a

of this report on the illegibility of drawings. The LPCS system piping and

instrumentation diagram (M1087) used by the licensee is of very poor

quality. Numerous valves and instrument identification numbers are not

discernible from the drawings. The inspector was able to determine the

identification of these valves and instrumentation by walking down the

system and comparing the as-built system to the drawing.

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 policy and procedure for NRC enforcement actions.

The following License Event Reports (LERs) are closed.

LER No. Event Date Event

86-007 February 20, 1986 Inadvertent Residual

Heat Removal Pump Start

83-078 July 1, 1983 Air Relief Valve

Setpoint Drift

86-004 February 12,1986 Reactor Scram During

Shutdown for Excessive

Coolant Leakage

86-005 February 15, 1986 Standby Gas Treatment

Filter Train Heater

Failed Surveillance

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The subject of LER 86-007 was discussed in IE Report 86-04 and is tracked as

violation 416/86-04-01.

The subject of LER 86-004 is discussed in paragraph 9 of this inspection

report.

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.

Scram No. 38. Or February 12, 1986 unit 1 of the Grand Gulf Nuclear Station

experienced a scram from approximately 13% power. At the time of the scram,

the plant was in the process of being shutdown in response to TS 3.4.3.2

which requires a plant shutdown anytime unidentified leakage exceeds 5 gpm

dnd cannot be corrected within a certain time period. The cause of the

unidentified leakage rate exceeding 5 gpm was the partial failure of the B

recirculating pump seals.

At approximately 7:33 p.m. on February 12, 1986, the reactor scrammed from a

low water Irvel in the vessel. This loss of level resulted from the loss of

the operating reactor feed pump securing make up flow to the vessel. The

apparent cause of the loss of the feed pump was due to reactor pressure

exceeding feed pump discharge pressure causing a no flow situation through

the feed pump. The feed pump minimum flow valve began to open in response

to this no flow situation and in parallel a 15 second timer initiated. The

minimum flow valve failed to open enough to allow the minimum feed pump

operating flow before the 15 second timer timed out causing the feed pump to

trip. Before the operators could restart either of the feed pumps the

vessel level decreased below the low level scram setpoint.

The licensee has determined that new valve positioners had been placed on

the feed pump minimum flow valves in April of 1985. These new positioners

were used because the original positioners were no longer being

manufactured. When the new positioners had been installed on the minimum

flow valves the overall valve operating response time was tested and found

to be unchanged. However, the licensee has now discovered that with the new

positioners installed the minimum flow valves will not open fast enough to

the minimum operating flow position to prevent the 15 second timer from

timing out, even though the over all response time is the same. The

licensee has increased the delay time from 15 seconds to 30 seconds and is

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investigating the possibility of obtaining new positioners which will react

! much faster than the ones presently installed.

No violations or deviations were identified.

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10. Inspector Followup and Unresolved Items (92701)

(Closed) Inspector Followup Item 416/85-46-04. The licensee has revised

Administrative Procedure 01-5-06-5, Incident Reports / Reportable Events, to

clarify that significant events should be documented on an incident report

even if the event is not reportable. A list of examples of conditions and

situations that might not be reportable but should be considered as reeding

to be documented on a incident report is provided.

(Closed) Unresolved Item 416/85-45-03. This item requested the licensee

provide written documentation from the pump vendor and the licensee's

engineering organization, supporting the contention that 3400 gallons

unusable volume was an acceptable value for determining minimum fuel oil

tank level for the Emergency Diesel Generators. The licensee has provided

the inspectors with a letter from Wright Masters of Crane Chempump Company

to Felix Bryan of Mississippi Power and Light (MP&L) dated March 17, 1986,

stating that a minimum level in the fuel oil tank of four inches above the

center line of the fuel transfer pump suction flange would permit continuous

pump operation. The letter went on to say that the fuel transfer pump could

be operated with levels down to 0.75 inches above the pump suction flange

center line but there would be a chance of shaf t journal and bearing wear.

The cover mema for the above mentioned letter from F. W. Titus, Director of

Nuclear Plant Engineering (NPE) to C. R. Hutchinson, GGNS General Manager

dated March 29, 1986, states that four inches above the fuel transfer pump

suction center line is equivalent to approximately 3,400 gallons.

Therefore, the original minimum level in the fuel oil tank based on the

unusable volume of 3,400 gallons was acceptable. However, in the cover memo

NPE recommends that the new minimum level based on the unusable volume of

8,200 gallons remain because of the possibility of damage to the fuel

transfer pump if the level were allowed to drop below 3,400.

11. Design, Design Changes and Modifications (37700)

Design Change Package (DCP) 82/5020, Standby Service Water (SSW) Loop B

System Modifications and the associated Maintenance Work Orders (MW0s) were

reviewed by the inspectors. This DCP was implemented by the licensee to

meet part of license conditions 2.C.20 which requires the SSW system to be

modified so that design flow can be achieved to all SSW system components.

The major SSW system modifications associated with this DCP include

replacing the existing pump motor with a larger one, installing three new

relief valves, replacing the butterfly minimum flow valve with a globe valve

and modifying system supports as necessary. Each of these changes were

evaluated by the licensee using the 10 CFR 50.59 process to determine if NRC

review and concurrence was required and consequently all the necessary

Technical Specification changes required to support the design change were

submitted and approved prior to declaring the system operable

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The inspector reviewed the MW0s listed below which implemented the DCP in

the plant. This review consisted of a verification that the work was

performed in accordance with established plant procedures, that all MW0s

required appropriate retests and that the work was properly documented and

reviewed by the Quality Assurance and Engineering organizations.

MWO F 56470 Electrical Support for SSW "B" Motor

Replacement

MWO F 56469 Replace Cables Between D/G and Switchgear

MWO F 56486 Install Relief Valves in Water Treatment

Building

MWO F 56488 Modify SSW B Sample Pump

MWO F 55382 Rework Valves

KWO F 56489 Fabrication

MWO F 56487 Remove and Reinstall Pump

This review did not uncover any noncompliances except for the second example

of Violation 84-04-01 discussed in Inspection Report 84-04, paragraph 10.

However, the inspector observed that the DCP and MWO system was very hard to

follow and extremely difficult to audit due to a large number of different

forms and documents used to document the work. These documents are also not

filed in the same place in the vault. Therefore, ensuring that you have all

of the completed records is a difficult and time consuming process.

During the review of the DCP, Oesign Change Implementation Package (DCIP)

and Technical Special Test Instruction (TSTI), 1P41-85-001-1-S, the

inspector came across several statements requiring administrative controls

be esta 411shed to verify that the minimum flow valve was locked in a

positior. required to allow the proper flow rate. The DCP and the TSTI

established this flow rate to be 9,500 gpm with a valve position of 43%

open. Upon review of the plants System Operating Instruction (501)

04-1-01-P41-1, Standby Service Water System and Surveillance Procedure (SP)

06-0P-1P41-Q-0005, SSW Loop B Valve and Pump Operability Test, the inspector

discovered that these procedures still reflected the old design which

included a butterfly valve with a position of 30% open and a flow rate of

10,500 gpm. Plant Administrative Procedure (AP) 01-S-07-4, Plant Changes

and Modifications, paragraph 6.6.3 requires that all procedures requiring

changes to reflect a new design must be changed prior to returning the

system to operation. The SSW B system was returned to operation with the

DCP incorporated in November of 1985 and the inspectors discovered that the

procedures had not been changed in March of 1986. The SOI had not been

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performed since the TSTI had been completed therefore, the minimum flow

valve was left in the correct position. However, the inspectors discovered

that the SP had been performed in December of 1985 and the procedure allowed

operations to set the minimum flow valve position for flow rates from 9,500

gpm to 10,500 gpm. The inspectors toured the B SSW basin on March 13, 1986

to determine the actual position of the minimum flow valve and discovered

the minimum flow valve position indication to be at 50% open, instead of the

43% as determined in the TSTI. Discussions with the operations staff

determined that the last time SP 06-0P-1P41-0-0005 was performed, the Shift

Supervisor on duty was aware of TSTI IP41-85-001-1-S and instructed the

operators to set the minimum flow valve at a position corresponding to 9,500

gpm. This was confirmed by operations performing a surveillance on the SSW

B system and verifying the actual flow rate te be 9,500 gpm even though the

valve position indication was reading 50% opsn. The concern for limiting

the minimum recirculation flow is to protect the SSW pump from damage due to

pump run out. The minimum flow rate was set at 9,000 +/- 500 gpm which is

lower than the original 10,500 gpm due to a relief valve now being installed

in the discharge line. The combination of the relief valve open and the

minimum flow valve open could exceed the pump run out condition if the flow

by the minimum flow valve is not limited. Operations has changed both 501

04-1-01-P41-1 and SP 06-0P-IP41-0-0005 to reflect the nroper minimum flow

valve position corresponding to 9,500 gpm.

TS 6.8.1 requires written procedures be established implemented and

maintained covering surveillance and test activities of safety-related

equipment and procedures recommended in Appendix A of Regulatory Guide 1.33,

Revision 2, February 1978. Paragraph 4 of Regulatory Guide 1.33 recommends

procedures for startup, operation and shutdown of safety-related BWR

systems. The failure of the licensee to change 50I-04-1-01-P41-1 and SP

06-0P-IP41-0-0005 to reflect the design change to the SSW B system is

identified as a Violation (416/86-08-03).

During the inspection of the SSW B basin, the inspectors noticed a large

amount of water on the floor near the electrical switchgear and equipment

located in the SSW B valve room. This water appeared to have come from the

,

relief valve installed in the discharge line of the B SSW system. The

'

inspectors notified the licensee and were informed that they were aware of a

leak on the relief valve of the B SSW system and had written a Maintenance

Work Order to fix the leak. However, licensee management was not aware of

the large amount of water in the B SSW room. The licensee performed an

operational test of the B SSW system and discovered a plug missing from the

relief valve which was causing the water problem in the B SSW valve room.

This plug was replaced stopping the leak licensee management has instituted

a program requiring more management frequent tours of all areas of the plant

to look for undesirable situations. This program was not established just

as a result of this discovery but also as a result of other recent licensee

identified problems.

l The inspectors also reviewed the plant controlled as-built drawings and

found that the changes implemented by DCP 82/5020 had been incorporated.

t

ML20203N972

Text

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