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Insp Repts 50-416/87-40 & 50-417/87-04 on 871219-880115. Violations Noted.Major Areas Inspected:Operational Safety Verification,Maint Observation,Surveillance Observation,Esf Sys Walkdown,Design Changes & Mod & Containment Integrity
	ML20150C076
Person / Time
Site:	Grand Gulf
Issue date:	02/22/1988
From:	Butcher R, Dance H, Mathis J; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20150C055	List: ML20150C052; ML20150C069; ML20150C076;
References
	50-416-87-40, 50-417-87-04, 50-417-87-4, NUDOCS 8803170317
	Download: ML20150C076 (13)
	v • d • e

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UNITED STATES

,pga afooq'o NUCLEAR REGULATORY COMMISSION

y\ gn REGION 11

g j 101 MARIETTA STREET, N.W.

i () l c ATLANTA, GEORGI A 30323 -

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Report No.: 50-416/87-40 and 50-417/87-04

Licensee: System Energy Resources, Inc.

Jackson, MS 39205

Docket Nos.: 50-416 and 50-417 License Nos.: NPF-29 and CPPR-119

Facility Name: Grand Gulf

Inspection Condycted: Decerr.ber 19, 1987 - January 15, 1988

. Inspectors: e M >[p/fV

R. C. Butchec Senior Resident Inspector Date Signed

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.Mathis[8esidentInspector

Approved by:

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C. Dance, Section Chief

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Date Signed

Division of Reactor Projects

SUMMARY

Scope: This routine inspection was conducted by the resident inspectors at ,

the site in the areas of Licensee Action on Previous Enforcement Matters, l

Operational Safety Verification, Maintenance' Observation, Surveillance

Observation, ESF System Walkdown, Reportable Occurrences, Operating Reactor

Events, Inspector Followup and Unresolved Items, Compliance with the ATWS Rule,

10 CFR 50.62, Refueling Activities, Startup from Refueling, Fastener Testing

Per TI 5200/26, Design Changes and Modification, and Verification of

Containment Integrity.

Results: One violation was identified: Failure to determine normal indicated !

delta pressure and set HPCS system, LPCS system, and LPCI subsystems i

instrumentation as required by Technical Specifications.

8803170317 880222

PDR ADOCK 05000416

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REPORT DETAILS

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1. Licensee Employees Contacted

J. E. Cross, GGNS Site Director

C. R. Hutchinson, GGNS General Manager

R. F. Rogers, Manager, Special Projects

A. S. McCurdy, Manager, Plant Operations

J. D. Bailey, Compliance Coordinator

M. J. Wright, Manager, Plant Support

L. F. Daughtery, Compliance Superintendent

D. G. Cupstid, Start-up Supervisor

R. H. McAnuity, Electrical Superintendent

J. P. Dimmette, Manager, Plant Maintenance

W. P. Harris, Compliance Coordinator

J. L. Robertson, Licensing Superintendent

L. G. Temple, I & C Superintendent

J. H. Mueller, Mechanical Superintendent -

L. B. Moulder, Operations Superintendent

J. V. Parrish, Chemistry / Radiation Control Superintendent

S. M. Feith, Director, Quality Programs

S. F. Tanner, Manager, Quality Services

D. L. Pace, Manager, Nuclear Design

Other licensee employees contacted included technicians, operators,

security force members, and office personnel.

Attended exit interview

2. Exit Interview (30703) l

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The inspection scope and findings were summarized on January 15, 1988, I

with those persons indicated in paragraph 1 above. The licensee did nc l

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

the it!spectors during this inspection. The licensee stated that more

review is required before they agree or disagree with the iinspection

findings:

416/87-40-1. Violation. Failure to determine normal indicated delta

pressure and set HPCS system, LPCS system and LPCI subsystems instrumenta-

tion as required by TS 4.5.1.c.2 (b). (paragraph 4 )

3. Licensee Action on Previous Enforcement Matters (92702)

Not inspected this report period.

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4. Operational Safety, Radiological Protection and Physical Security )

Verification (71707, 71709 and 71881)

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 R

visited at loast daily when an inspector was on site. 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 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. ,

Weekly, when the inspectors were onsite, selected Engineered Safety

Feature (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, lubrication,

cooling and general condition, and instrumentation.

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

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

areas were visited. Observations included safety related tagout

verifications, shift turnover, sampling program, housekeeping and general

plant conditions, fire protection equipment, control of activities in

progress I problem identification systems, and containment isolation. The

licensee s onsite emergency response facilities were toured to determine '

facility readiness.

The inspectors reviewed at least one Radiation Work Permit (RWP), observed

health physics management involvement and awareness of significant plant

activities, and observed plant radiation controls. The inspectors

verified licensee compliance with physical security manning and access

control requirements. Periodically the inspectors verified the adequacy

of physical security detection and assessment aids.

On January 9, 1988 the licensee initiated Material Nonconformance

Report (MNCR) 0015-88 documenting that the Low Pressure Core Spray

(LPCS)/ Residual Heat Removal (RHR) A line break annunciator alarmed at 80

percent power during startup from refueling outage number 2. While

continuing up in power the reactor scrammed at about 93% power (see

writeup in paragraph 9). Before the reactor scram, the MNCR describes !

several things were being done to verify the actual differential pressure I

was being measured. The differential pressure being measured is from the !

LPCS injection line to the RHR A line downstream of the injection valves

which should give close pressure readings unless thereais a line break in

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either line within the downcomer region. Technical Specification 3.5.1,

which is applicable for Operational Conditions 1, 2 and 3, action

statement g requires that with an ECCS header delta P instrumentation

channel inoperable, restore the inoperable channel to operable status

within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or determine ECCS header delta P locally at least once per

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , otherwise declare the associated ECCS inoperable. Technical

Specification 4.5.1.c.2.(b) requires every 18 months performing a channel

calibration of the header delta P instrumentation and verifying the :

setpoint of the HPCS system, LPCS system and LPCI subsystems to be 1.2 + :

0.1 psid change from the normal indicated delta P. Research by the '

licensee indicates that G.E. Service Information Letter (SIL) 300 issued

in September 1979 and IE Circular No. 79-24 dated November 26, 1979 j

addressed the installation and testing of pipe break detection systems and :

recognized that the systems would be calibrated to' read near zero delta P l

during cold shutdown and would possibly alarm during reactor startup. The ;

alarm should clear when approaching rated power indicating that the '

instrumentation is working. This would make the pipe break detection

system effective only near rated power. This guidance does not appear to :

be reflected in TSs. The Final Safety Analysis Report has a brief l

description of the HPCS and LPCS/RHR A line break detection systems only. !

High Pressure Core Spray is described in paragraph 7.3.1.1.1.3.11.2 and j

LPCS/RHR A is described in paragraph 7.3.1.1.1.5.11.2. The RHR B/RHR C

line break detection system is not mentioned. The licensee has not

determined what is the normal delta P for the LPCS/RHR A lines. The

instrumentation setpoint as specified in Surveillance Procedure

06-IC-1E31-R-0021, Revision 23, LPCS/RHR/HPCS Header Differential Pressure

Calibration, was based on original calculations. Technical Specification l

4.5.1.c.2 (b) requires that every 18 months a channel calibration of the i

header delta P (nstrumentation setpoints be verified for the HPCS system,

LPCS system and LPCI subsystems to be 1.2 + 0.1 psid from the normal i

indicated delta P. Failure to determine the normal indicated delta P and :

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verify the HPCS system, LPCS system and LPCI subsystems setpoints to be

within 1.2 + 0.1 psid of normal is a violation 416/87-40-01. The NRC l

Project Msniiger was requested to determine an interpretation of the

meaning of normal indicated delta pressure in TS 4.5.1.c.2(b). He stated

the normal indicated delta pressure should be determined while at normal ,

rated power. This supports the previously discussed SIL and IE Circular. l

5. Maintenance Observation (62703)

During the report period, the inspectors observed portions of the

maintenance activities listed below. The observations included a review {

of the Maintenance Work Orders (MW0s) and other related documents for I

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

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.

MWO # I80322 Rework loop controls; replace potentiometer module and '

pushbutton switch modules on P680 panel. I

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MWO # M80346 Open condenser, perform a leakage inspection and plug tubes

that are leaking.

No violations or deviations were identified.

6. Surveillance Observation (61726)

The inspectors' observed the performance of portions of the surveillances

listed below. 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.

06-0P-1P41-Q-0004, Revision 24, Standby Service Water Loop A Valve & Pump

Operability Test.

06-RE-SC11-V-0402, Revision 26, Control Rod Scram Testing.

06-0P-1E51-R-0005, Revision 26, RCIC Pump Low Pressure Flow Verification

Test-

06-IC-1821-M-0014, Revision 21, Safety Relief Valve -Tail Pipe- Pressure

Switch Function Test.

06-ME-1M10-R-0003, Revision 25, Drywell Bypass Leakage Rate.

06-0P-1E51-Q-0002, Revision 28, RCIC System Valve Operability Test. '

06-IC-1C71-R-0013, Revision 25, Reactor Mode Switch Interlocks Functional

Test.

06-0P-1821-R-0002, Revision 26, ADS /SRV Valve Operability. l

06-ME-1M23-V-0001, Revision 28, Containment and Drywell Airlock Seal Leak

Te~s t.

No violations or deviations were identified.

7. Engineered Safety Features System Walkdown (71710) ;

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A con,plete walkdown was conducted on the accessible portions of the j

Standby Gas Treatment System. The walkdown consisted of an inspection and i

verification, where possible, of the required system valve alignment, i

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 I

rodents, and system free from other degrading conditions.

No violations or deviations were identified,

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8. Reportable Occurrences (90712 & 92700)

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

information provided met. the NRC reporting requirements. l

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, regarding licensee identified violations.

The following License Event Reports (LERs) are closed.

LER No. Event Date Event

87-019 November 17, 1987 Heavy Load Transported Over New

Fuel In The Upper Containment Fuel

Pool. -

87-005 April 15, 1987 Three Main Steam Line Radiation

Monitors Exceed Technical

Specification Trip Limit. '

87-020

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November 19, 1987 Shutdown Cooling Isolation Due To

a Blown Fuse.87-022 December 7, 1987 RWCU Isolation Due To a Blown

Fuse.

The event of LER 87-019 was discussed in Inspection Report 416/87-35.

The even't of LER 87-005 is discussed in paragraph 13 of this report.

The event of LER 87-020 was discussed in Inspection Report 416/87-35.

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.

On December 19, 1987 at approximately 8:48 p.m. during performance of I&C

Surveillance procedure 06-IC-1821-R-0004-1, Main Steam Line Isolation

Valve Closure Calibration, a full scram was received. The reactor was in

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cold shutdown (refueling mode) with all rods in. During the surveillance

upon closing Main Steam Isolation Valve (MSIV) F022A a full scram occurred i

instead of the expected 1/2 scram in Division 2. Upon investigation by

the licensee it was found that the fuse (IC71-F11A) reinstalled in step

5.29 of data sheet III for MSIV F022A was signed off by one I&C technician

and verified by another I&C technician as to being installed. The

licensee determined that fuse IC71-F11A ' popped out of its holder which

would give a 1/2 scram for Reactor Protection System (RPS) Division 1. In

preparation for closing of MSIV F022A, fuse C71-F118 was pulled out in

step 5.30. This set up conditions for a 1/2 scram in RPS. Division 2 upon

the closing of MSIV F022A. Therefore, when F022A was closed a full scram

occurred. Incident Report (IR) Number 87-12-14 was written to document

this event.

On January 10,1988 at 3:08 p.m. the reactor scrammed from 93.5 percent

reactor power. Investigation by the licensee determined that a phase

differential from the 8 main transformer initiated a turbine trip which

initiated a reactor scram. No Emergency Core Cooling Systems (ECCSs)

injected and water level decreased to approximately -2.5 inches. Reactor

pressure reached an indicated 1109 psig initiating an ATWS recirculation

pump trip. No safety-relief valvas lif ted. The phase differential fault

was caused by the failure of the 8 transformer. Upon investigating the

transformer problem the licensee was forced to stay down for at least 4

days after scramming to replace the failed transformer and bring on line

the spare transformer. This activity is covered by the following MWD

packages: E80383, E80384, E80427, E62703, E72878, E80375, E74336, E80326,

and E80276.

The inspectors followed the replacement of the spare transformer. The

spare transformer was already installed adjacent to the normal 3 main

transformers and only required hardware type changes to tie into the

existing generator leads. The licensee plans to use one of the 3

transformers from unit 2 as a spare by removing the failed transformer and

installing the unit 2 transformer in its place. Limiting Condition for

Operation (LCO)88-035 was initiated on three low low set valves whose

proper operation was originally questioned. It now appears that the low

low set logic for Channel A and Channel 8 trip units tripped but

corresponding channels E and F trip units did not trip so no safety relief

valves lifted. This indicated proper relief valve operation and the LC0

was lifted. The reactor was taken critical on January 13,1988 at

5:45 p.m. in preparation for connecting onto the grid. The reactor was

synchronized to the grid at 9:53 p.m. on January 15, 1988. l

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On January 11,1988 at 7:15 a.m. a reactor scram occurred due to low water ;

level. The reactor was in hot shutdown at 310 psig at the time of the l

event. Operators noticed the reactor vessel water level was increasing i

and the set pressure was decreasing causing the bypass valve to open. l

Reactor pressure decreased to approximately 270 psig before the operators !

could manually stop the set pressure decrease. Reactor water level then

decreased to approximately 9 inches resulting in a reactor vessel low

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water level scram. This incident was documented by the licensee in

Incident Report ' Number 88-1-6. The licensee initiated Maintenance Work

Order (MWO) 1803322 to rework loop controls and to replace potentiometer

module and pushbutton switches on P680 panel.

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Ne violations or deviations were identified.

10. Inspector Followup and Unresolved Items (92701)

(Closed) Inspector Followup Item 416/87-22-03. The licensee issued

Licensee Event Report (LER) 87-009-01 clarifying the use of an existing

bypass switch which will allow bypassing the Reactor Water Cleanup (RWCU)

isolation logic. System Operating Instruction (SDI) 04-1-01-G33-1 has

been revised to delete the reference to an anticipated group 8 isolation.

An engineering review is being performed to determine the amount of time

the present 45 second automatic bypass time delay can be extended and the

licensee will submit a change request when an allowable time limit is

determined.

11. Compliance With the ATWS Rule, 10 CFR 50.62 (25020)

.

The inspection requirements of TI 2500/20 were addressed previously in

Inspection Reports 416/87-23 and 416/87-35. During this inspection period

the inspectors witnessed the testing of the work performed by DCP 85/4053.

The testing of the modifications done to the Standby Liquid Control System

to meet 10 CFR 50.62 acceptance criteria was controlled by Modification

Special Test Instruction (MSTI) IC41-87-002-0-S. The test was divided :

into the following sections.

Section 7.1 of test MSTI 1C41-87-002-0-5 flushed the SLC system as

required to ensure only reactor grade water will be pumped to the reactor.

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Section 7.2 stroked the valve IC41F008, in which modifications were made

during this outage, and compared remote indication with actual position.

Section 7.3 demonstrated the capability of the SLCS to deliver the Boron

solution to the reactor at the required two pump flow rate without

exceeding the calculated pump operating pressure. Both pumps was operated

inthenormalinjectionlineup.

Section 7.4 demonstrated that the required discharge pressure was

enveloped by the 1300 psig Technical Specification discharge pressure.

Pump discharge pressure of at least 1300 psig was achieved by throttling

pump discharge valves and flow was verified to be at least 82.4 gpm with l

both SLCS pumps operating.

Section 7.5 verified that each pump produced a flowrate of at least 41.2

gpm with at least 1300 psig discharge pressure.

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The portions. of MSTI 1C41-87-002-0-S witnessed by the inspector consisted

of pump flow capacity test for SLC pump A and B, SLC pump A and B were

simultaneously started by closing both the installed test switches on

panel 1H22-P011. Throttle valve 1C41-F221 was slowly closed to achieve a

stable pressure greater than or equal to 1300 psig. Pump discharge relief

valves (1C41-F-029A & B) were then verified _ to have not lifted. The

combine discharge flow of SLC pump A and B were measured to be 82.5 gpm.

In addition to the combined pump flow capacity test, the inspector

witnessed the single pump flow test for both the A and B pumps. The

recorded pump discharge flows for pump A and B were 44 gpm and 46 gpm

respectively. The remaining portions of MSTI 1C41-87-0002-0-5 were

reviewed for conformance to the acceptance criteria.

12. Fastener Testing To Determine Conformance With Applicable Material

Specifications (25026) - Unit 2 Only

This inspection was conducted on Unit 2 per Temporary Instruction 2500/26

to ensure fasteners selected in response to NRC Bulletin 87-02 are

representative of installed fasteners and that suspect fasteners are

selected for testing. Ten non--safety related studs, bolts and/or

cap

and /or capscrews and ten safety related nuts were to be selected fromscrews; te

stock for testing. The inspector participated in the licensee's selection

of samples required by action item 2 of Bulletin 87-02 for Unit 2.

The sample selected was based, in part, from the types and grades of

fasteners utilized on Unit 2 to date and the test laboratory (Wyle)

requirements that the fasteners had to be 1/2 inch diameter or larger and

a minimum length of 3 x the diameter. All fasteners were procured as

safety related except the non-safety related bolting as identified in the

sample was supplied as part of the non-safety related structural steel

purchased as part of the contract for erection of the turbine building.

From interviews with licensee personnel the following proportion of use of

fasteners was determined:

Type and Grade Percent Use (approx)

Nuts: SA-307, Gr. A 5

SA-194, Gr. 7 5

SA-194, Gr. 2H 45

SA-307, Gr. B 15

A -325 25

A -563, Gr. D 5

Bolts: SA-307, Gr. A 5 ,

& SA-307, Gr. B 15 l

Studs #A -325 30

A -490 10

SA-193, Gr. B7 40

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Also procured as non-safety related for turbine building

erection.

Based on the above figures, the following fastener sampling was agreed to:

SAFETY RELATED BOLTS / STUDS

SAMPLE I.D. ITEM DESCRIPTION HEAD MARKING

GGNS-U2-1 1 1/8" x 6 1/2" Stud Bolt SA193 87 87, T, FX65

GGNS-U2-2 7/8" x 5 1/2" Stud Bolt SA193 B7 B7, T, LA73

GGNS-U2-3 5/8" x4 3/4" Stud Bolt SA193 B7 B7, C, K2

GGNS U2-4 1/2" x 5 1/2" Stud Bolt SA193 87 87, C, C2

GGNS U2-5 1/2" x 4 1/4" HHH Bolt SA307-B TB, 1Q39

GGNS U2-6 5/8" x 3 1/4" HHH Bolt SA307-B TB, IF15

GGNS U2-7 1" x 4 1/2" HHH Bolt SA 307-B TB, HD40

GGNS U2-8 1" x 4 1/4" HHH Bolt A325 RBW, A325

GGNS U2-9 1" x 8 1/2" HHH Bolt A325 TB, A325

GGNS U2-10 7/8" x 5" HHH Bolt A490 TB, A490

GGNS U2-11 1/2" x 3" HHH Bolt A307 GR-A TB,IQ53

SAFETY RELATED NUTS .

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SAMPLE I.D. ITEM DESCRIPTION HEAD MARKING I

GGNS-U2-1A 1 1/8" HH Nut SA194 2H 2HT, 0211 ;

GGNS-U2-2A 7/8" HH Nut SA194 2H 2HK, C4 '

GGNS-U2-3A 5/8" HH Nut SA194-2H 2HU, K6

GGNS-U2-4A 1/2" HH Nut SA194-2H 2HT, 0253-

GGNS-U2-5A 1/2" HH Nut SA307-B T, HD73

GGNS-U2-6A 5/8" HH Nut SA307-8 T, 1F18

GGNS-U2-7A 1" HH Nut SA307-8- T, HD46 ,

GGNS-U2-8A A" HH Nut A325 Three Circ. Lines l

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GGNS-U2-9A 1" HH Nut A325 Three Circ. Lines

GGNS-U2-10A 7/6" HH Nut SA194-2H 2H, S, V,

GGNS-U2-11A 1/2" HH Nut A 307 GR-A 7, IQ54

GGNS-U2-12A 1 1/8" HH Nut SA 194 GR-7 C, Y1, 01, 7

GGNS-U2-13A 2 3/4" HH Nut A563 GR-D T, D

NON SAFETY RELATED BOLTS

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SAMPLE I.D. ITEM DESCRIPTION HEAD MARKING !

GGNS-U2-A (2) 3/4" x 3 1/4" HHH Bolts A490 A490,SBC

GGNS-U2-8 (2) 3/4" x 3 1/4" HHH Bolts A325 A325,SB 1

GGNS-U2-C (2) 1" x 5" HHH Bolt A325 A325,RBW .

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GGNS-U2-D 1" x 5" HHH Bolt A325 A325,RBW

GGNS-U2-E 3/4" x 3 1/4" HHH Bolt A490 A490, SB

GGNS-U2-F (2) 3/4" x 3" HHH Bolt A490 A490, S8

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NON SAFETY RELATED NUTS

SAMPLE I.O. ITEM DESCRIPTION HEAD MARKING

GGNS-U2 A ~ (2) 3/4" HH Nuts A194-2H P2H

GGNS-U2-B-1 (2) 3/4" HH Nuts A325 Three Cire. Lines

GGNS-U2-01 (2) 1" HH Nut A325 Three Circ. Lines

GGNS-U2-01 1" HH Nut A194-2H Three Circ. Lines

GGNS-U2-El 3/4" HH Nuts A325-2H 2H, P

GGNS-U2-F1 (2) 3/4" HH Nut A194-2H 2H, P

The inspectors verified that each fastener was tagged with identifying

sample number, description, and heat code / material type. In addition, the

inspector verified that each sample was put in a separate plastic bag

along with the NRC supplied Fastener Testing Data Sheets.

13. Design, Design Changes and Modifications (37700)

The inspectors reviewed the following design change for conformance with

the requirements of TS and 10 CFR 50.59. Design Change Implementation

Package (DCIP) 84/0160, Revision 0, replaced the existing INMAC Main Steam

Line (MSL) log radiation monitors with NUMAC log radiation monitors.

Licensee Event Report 87-005-02 documented the problem the licensee was 1

experiencing with an instrument drift problem with the existing equipment.

Technical Specification 3.3.2-2.2.b requires the MSL high radiation trip

setpoints to be set less than 3 times full power background with an

allowable value of 3.6 times full power background. The instruments

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provide a reactor scram signal, a mechanical vacuum pump trip signal and

, an MS' isolation signal if the high radiation sigiial is reached in a one -

out '

two taken twice logic. The inspectors verified the.

folic, . .ig: a) The licensee reviewed and approved the design changes in

accordance with TS and approved procedures. b) The design change had been i

properly documented and an approved evaluation per 10 CFR 50.59 was ;

perforrted, c) Design change retests were accomplished within procedural

tiec requirements and results were satisfactory. d) The operating l

procedures were modified to reflect the design change, e) The new MSL j

radiation monitors were fully operable and operators were familiar with

taking data for operating logs.

The following maintenance work packages were reviewed to determine if they

included applicable specifications, guides and coces covering the work;

identification of required inspections or retests and QA/QC requirements.

MWP 87/1239 REWORK PANEL H13-P669

MWP 87/1240 REWORK PANEL H13-P671

MWP 87/1241 REWORK PANEL H13-P670

MWP 87/1242 REWORK PANEL H13-P672

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No violations or deviations were identified.

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14. Verification of Containment Integrity (61715)

The inspectors verified that the licensee established primary containment

integrity following cold shutdown for the refueling outage. Ten primary

containment penetrations were verified to be correctly aligned by local

observation where available and by remote indication. The primary

containment upper and lower air lock seal leak tests were witnessed by the

inspectors and the Standby Gas Treatment System was walked down to verify

operability. See paragraph 6 for the containment airlock seal leak test

and paragraph 7 for the Standby Gas Treatment System walkdown.

No violations or deviatt 's were identified.

15. Refueling Activity (60710)

The refueling outage for cycle two was previously reported in Inspection

Reports 416/87-29 and 416/87-33. Reactor vessel reassembly started on ,

December 20, 1987. The reactor vessel head tensioning was completed on

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December 22, 1987 in accordance with the procedure 06-CP-1813-V-0001.

Following the head tensioning the reactor mode switch was placed in

shutdown. The inspector verified that surveillances required to be

completed prior to entering shutdown mode of operation were completed.

On December 29, 1987, the inspectors witnessed portions of procedure >

06-ME-1M10-R-0003, Revision 25, Drywell Bypass Leakage Rate, performed by

the licensee. The test determines the drywell leakage with the drywell

pressurized to approximately 3 psid and verifies that the drywell bypass

leakage is less than or equal to 3500 scfm. This tese is required to be

performed at least once pur 18 months in accordance with T.S. 4.6.2.2.

The test result for the drywell leakage was approximately 1500 scfm. The

inspector calculated the leakage independent of the licensee and got the

same value. There were no deficiencies associated with this test.

No violations or deviations were identified.

16. Plant Startup From Refueling (71711)

Startup for Unit 1, Cycle 3 started on January 3,1988. The reactor mode ;

switch was placed to startup at 5:30 p.m. on January 3,1988. The

controlling procedure for startup, Integrated Operating Instruction (I0I)

03-1-01-1, was reviewed by the inspectors to verify that startup was being

conducted in accordance with technically sound and approved procedures anc'

to assure that they had been revised to reflect changes made to the

facility and to the start-up testing program. The following precritical i

test were witnessed by the inspector:

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a. Control Rod Scram Testing (06-RE-SC11-V-0402)

b. Reactor Mode Switch Interlocks Functional Test (06-IC-1071-R-0013)

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Criticality for cycle 3 was achieved on group 2, gang 6 position 26 at

3:54 a.m. on January 4,1988. The reactor coolant temp;rature recorded

was 146.25 F. The calculated Shutdown Margin was determined to be 1.586

(%$ K/K). The inspector verified that criticality was achieved in a

controlled manner.

No violations or deviations were identified.

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ML20150C076

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