IR 05000416/1985033

Insp Rept 50-416/85-33 on 850817-0916.Violations Noted: Failure to Test Containment Air Lock Test Connections,Per 10CFR50,App J & Exceeding 30-day Reporting Criteria,Per 10CFR50.73

ML20138A365
Person / Time
Site:	Grand Gulf
Issue date:	09/26/1985
From:	Butcher R, Caldwell J, Panciera V NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20138A345	List: IR 05000416/1985033 IR 05000817/2009016 ML20138A341
References
50-416-85-33, NUDOCS 8510080538
Download: ML20138A365 (9)

Text

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REGION 11

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101 MARIETTA STREET, N.W.

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9....+g Report No.:

50-416/85-33

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Licensee: Mississippi Power and Light Company Jackson, MS 39205 Docket No.:

50-416 License No.-

NPF-29

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Facility Name: Grand Gulf Inspection Conducted: August 17 - September 16, 1985 Inspectors:

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R. C. ButctTur, Senio s'i d Inspector d6

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Cal Resident ector ate igned

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Approved by:

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V. W. Pan'ciera ject Section 2B

~ te igned Division of Reactor Projects SUMMARY Scope: This routine inspection entailed 170 resident inspector-hours at the site in the areas of Operational Safety Verification, Maintenance Observation, Surveillance Observation, Reportable Occurrences, and Design, Design Changes and Modifications.

Results: Of the five areas inspected, no apparent violations or deviations were identified in three areas; three apparent violations were found in two areas.

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REPORT DETAILS 1.

Licensee Employees Persons Contacted J. E. Cross, General Manager

• C. R. Hutchinson, Manager, Plant Maintenance

• R. F. Rogers, Technical Assistant

• J. D. Bailey, Compliance Coordinator M. J. Wright, Manager, Plant Operations

• L. F. Daughtery, Compliance Superintendent D. Cupstid, Start-up Supervisor R. H. McAnulty, Electrical Superintendent R. V. Moomaw, I&C Superintendent B. Harris, Compliance Coordinator J. L. Robertson, Operations Superintendent

• L. F. Dale, Director, Nuclear Licensing and Safety 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 September 16, 1985, 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.

Inspector Followup Item (50-416/85-33-01);

Clarify Technical Specification to reflect valve E12F023 function.

(paragraph 5.a.)

b.

Violation (50-416/85-33-02); Failure to initiate an Incident Report regarding the operability of an SRV.

(paragarph 7)

c.

Inspector Followup Item (50-416/85-33-03); Instructions to provide for Unit I dependence upon Unit 2.

(paragraph 5.b)

d.

Violation (50-416/85-33-04); Failure to submit an LER within 30 days.

(paragraph 8)

e.

Violation (50-416/33-05); Failure to leak test containment and drywell air lock test flanges.

(paragraph 8)

3.

Licensee Action on Previous Enforcement Matters (92702)

Not inspected.

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4.

Unresolved Items Urresolved items were not identified during this inspection.

5.

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 con'trols and switches; annunciator alarms;

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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.

Weekly, when onsite, a selected ESF system is 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 verifi-cations; shif t 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.

i The following comments were noted:

a.

On July 3,1985, the Plant Safety Review Committee (PSRC) determined that the reactor pressure vessel head spray valve, E12F023, which branches off of loop B of the Residual Heat Removal (RHR) system, should be red tagged and isolated closed with its associated circuit breaker tagged open.

This was the result of a Bechtel safe shutdown fire hazard analysis that indicated that in the event of a fire in a given location the E12F023 valve could inadvertently open and partially divert a portion of the Low Pressure Coolant Injection (LPCI) B flow and therefore, the plant would be in an unanalyzed condition.

Since the Final Safety Analysis Report (FSAR) does not address the use of the reactor vessel head spray valve as necessary for any safety function, tagging open the E12F023 circuit breaker would prevent the plant from entering an unanalyzed condition in case of a fire.

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i Subsequently, on August 5, 1985, the resident inspector became aware of the above action and recognized that the remote shutdown board contained a control for the F023 valve.

Technical Specification (TS) 3.3.7.4 requires that the remote shutdown system instrumentation and controls shown in table 3.3.7.4-1 be operable or, with the number of operable remote shutdown system controls less than required, restore the inoperable control to operable status within 7 days or be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. TS Table 3.3.7.4-1 lists the control for the E12F023 valve as "RHR to RCIC Head Spray Line Valve." This reflects the fact that the head spray valve originally branched off the Reactor Core Isolation Cooling (RCIC) line and was later switched to branch off the RHR B line.

The resident inspector contacted Region II management to determine what course of action should be taken since the seven day Limiting Condition for Operation (LCO) for T.S.

3.3.7.4 had been exceeded.

Region II management contacted NRR and it was determined that the NRC considered valve E12F023 operable because its safety function was to remain closed and there was no requirement for E12F023 to open for either safe shutdown or to carry out a safety function. Based on this interpretation, the E12F023 valve is to remain tagged in the closed position with its circuit breaker open and the licensee is to submit a TS change clarifying the requirement.

This will be tracked as an Inspector Followup Item (50-416/85-33-01).

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b.

On August 23, 1985, the plant staff became aware that the Unit 2 Standby Service Water (SSW) system piping could possible damage Unit 1 SSW system piping in a seismic event due to the removal of components from the Unit 2 systems. Since the Unit 2 SSW system is not required to be operational, some components from Unit 2 have been removed for use in Unit 1 or for other reasons.

The licensee did not have a program to review the effect of the removal of Unit 2 SSW components on the seismic qualification of the remaining structure / systems to ensure Unit 1 operability was not affected.

The plant was shutdown at the time the plant staff became aware of the SSW Unit 1 to Unit 2 interface question and startup was delayed until Nuclear Plant Engineering (NPE)

could certify that Unit 2 SSW equipment in the SSW basin, as currently installed, was compatible with Unit 1 SSW requirements in case of a seismic event.

Subsequent analysis has shown that the Unit 2 piping was acceptable in case of a seismic event. NPE is conducting further walkdows/ investigations to ensure other interface areas, such as in the control building, are acceptable.

The licensee is preparing instructions to ensure that those Unit 2 structures, systems, or components that interface with Unit i requirements are adequately reviewed prior to being modified for obtaining spare components or for other reasons.

This will be Inspector Followup Item (50-416/85-33-03).

6.

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

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Specifications, radiological controls, observation of all or part of the actual work and/or retesting in progress, :pecified retest requirements, and

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adherence to the appropriate quality controls.

In the areas inspected, no violations or deviations were identified.

7.

Surveillance Testing Observation (61726)

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The inspector observed the performance of selected surveillances.

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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.

The following event was reviewed:

On August 18, 1985, at 12:00 noon, the B21F051D Safety Relief Valve (SRV)

inadvertently opened while Instrumentation and Controls (I&C) technicians were performing a' safety relief valve low-low set logic test (06-IC-1821-M-1001-2). The B21F051D valve remained open approximately one minute while the logic was reset and the technicians secured from the surveillance. The surveillance test initiated the low-low set logic 'B' on the F051D valve.

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The corresponding low-low set logic 'F' tripped from a transient signal and this caused the F051D valve to lift. The licensee attributes the transient signal to the unplugging of a trip unit during the course of making adjustments while performing the surveillance.

On August 19, 1985, the inspectors questioned the licensee on why SRV F0518 did not also actuate and questioned the operability of F0518. Valve F0510 has a normal set pressure of 1103 psig at which time the low-low set function is actuated.

F0510 then has a close setting of 926 psig and an open setpoint of 1033 psig.

Valve F051B has a normal set pressure of 1113 psig but the low-low set function actuates concurrently with F0510 and therefore, when F0510 opens, F0518 should also open. F051B has a low-low setpoint to close at 936 psig and to open at 1073 psig. The PSRC was not made aware of the inspectors concerns until August 23, 1985, when the plant was shutdown for other reasons. The PSRC made the check of the actuation circuitry for valve F051B a prerequisite for startup and valve F0518 was to be manually actuated af ter startup to verify the solenoid was operable. The licensee's circuitry check was satisfactory and on August 26, 1985, the F0518 valve was manually actuated. Valve F051B appeared to function properly and no reasons can be given for its failure to operate on August 18, 1985. 10 CFR 50, Appendix B, Criterion XVI as implemented by the licensee's Operational Quality Assurance Manual (MPL-TOP-1A), Policy 16, requires procedures be established that provide for the evaluation of conditions such as nonconformances, failures, malfunctions, deficiencies, violations, deviations, reportable occurrences, 10 CFR 21 items, and defective material and equipment to determine the need for corrective action and to identify possible adverse quality trends.

Administrative Procedure (AP) 01-5-03-1, GGNS Quality Program, paragraph 6.1.10.c states that Plant Incident Reports shall be used to report and evaluate incidents involving equipment failures, personnel errors and

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procedural deficiencies which detrimentally affect nuclear safety.

The failure to initiate an Incident Report on August 19, 1985, regarding the question of the operability of SRV F051B is a violation (50-416/85-33-02).

8.

Reportable Occurrences (90712 and 92700)

The below listed Licensee Event Reports (LERs) were reviewed to determine if the information provided met NRC reporting requirements.

The determination included adequacy of event description and corrective action taken or planned, existence of patential 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 LERs were reviewed using the guidance of the general policy and procedure for NRC enforcement actions. The following LERs are closed.

LER No.

Report Date Event

• 84-055 1/5/85 Lack of overcurrent protection of contaniment penetrations.

• 85-007 3/12/85 Turbine trip and scram when switching SJAEs.85-011 3/26/85 Technical Specification for Halon Storage Tank pressure not met.85-012 4/5/85 Shutdown cooling isolation.

• 85-013 5/3/85 Reactor scram due to high water level.

• 85-015 5/3/85 Inadvertent RCIC isolation.

• 85-018 5/14/85 Reactor high level scram.85-019 5/17/85 Reactor Water Clean Up (RWCU)

isolation.

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• 85-020 6/24/85 Reactor scram due to turbine trip on i

low condenser vacuum.

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85-022-1 7/19/85 RWCU isolations.

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'85-023 7/18/85 RWCU isolations.

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l 85-025 7/24/85 RWCU isolations.

• 85-026 8/7/85 Containment air lock test flanges not leak tested.

The subject of LER 84-055 was addressed in Inspection Report 50-416/84-5 _.

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The subject of LER 85-007 was addressed in Inspection Report 50-416/85-06.

The subject of LER 85-013 was addressed in Inspection Report 50-416/85-14.

LER 85-014 was inadvertently closed in lieu of 85-013.

The subject of LER 85-015 was addressed in Inspection Report 50-416/85-09.

The subject of LER 85-018 was addressed in Inspection Report 50-416/85-20.

The subject of LER 85-020 was addressed in Inspection Report 50-416/85-22.

The subject of LER 85-026 is discussed below.

LER 85-026 reported that the containment and drywell air lock test flanges had not been local leak rate tested.

During the review of this LER the l

inspector discovered that these flanges had been identified as not being tested in 1983.

In November 1983 the Plant Safety Review Committee (PSRC)

l requested that a Design Change Request (DCR) be initiated to allow for leak I

testing these flanges. A DCR 83/558 was initiated in February of 1984 to l

add valves to the' flanges to allow the flange and valves to be leak tested during the associated containment and drywell air lock leak test. This DCR l

was not reviewed for incorporation into a Design Change Package (DCP) until l

December 1984 because the licensee had, in 1983, improperly determined that the leak test for the test flanges was not required.

During the review for incorporating the DCR 83/558 into a DCP the Nuclear Plant Engineering (NPE) department determined that the valves added to these test connections would become part of the containment and drywell pressure boundary when the inner door to the air locks was open or inoperable.

Therefore the containment valves would fall under the requirements of 10 CFR 50, Appendix J, for leak rate testing and the drywell valves would fall under TS 4.6.2.3 for bypass leakage testing, and therefore should be added to the TS. However, the requirement to leak test the flanges that these valves would replace was not recognized at this time according to NPE.

On March 26, 1985, NPE sent a memo from F. W. Titus, Manager of NPE, to L. F. Dale, Director of Nuclear Licensing and Safety, requesting a TS change be written to cover the leak rate testing of the valves added to the drywell and containment air lock test connections per DCP 83/558.

This request clearly stated that these test connectione 4;th valves in place of the blind flanges on the air lock test connection > < re required in order to be in compliance with 10 CFR 50, Appendiv )

0 e ing the time between March 26, when licensing received this TS clar. a r

,ist from NPE, and June 21, when the TS change was presented to th. PShu far review, the licensee was requested, for other reasons, to perform a complete review of all containment and drywell penetrations to verify their compliance with TSs and 10 CFR 50, Appendix J requirements. This review was completed and submitted to the NRc in a letter from L. F. Dale, MP&L, to H. R. Denton, NRC, dated May 14, 1985. This submittal, however, did not address the containment and

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drywell air lock test connections even though it stated that all containment and drywell penetrations, except for electrical penetrations, were reviewed and plan: procedures presently in place covered 10 CFR 50, Appendix J testing for all primary containment penetration boundaries. According to the licensee, the discovery that the test connections for the drywell and containment air lock doors should be tested but were not, was June 21, 1985, when the TS change for DCP 83/558 was presented to the PSRC for review. The PSRC requested NPE to determine if the plant was presently in compliance with 10 CFR 50, Appendix J, for these test connections. On June 25, 1985, NPE told the PSRC that the containment air lock test connections should be leak tested to be in compliance with 10 CFR 50, Appendix J.

The plant had already performed a successful leak test on the containment air lock test connections on June 21, 1985, at the request of the PSRC.

The drywell air lock test connection was successfully tested on June 27, 1985.

The failure of the licensee to test the containment air lock test connections as required to be in compliance with 10 CFR 50, Appendix J and TS 4.6.1.3.b, and the drywell air lock test connection as required to be in compliance with TS 4.6.2.3.b will be identified as a violation (50-416/

85-33-05).

Also during this review the inspector discovered the licensee had exceeded the 30 day reporting criteria of 10 CFR 50.73. The djscovery or event date for this LER was June 21, 1985 when the PSRC requested the test connections be tested and NPE to determine the applicability of 10 CFR 50, Appendix J and TSs to the test connections. This date June 21, 1985, started the 30 day cloc4, not _the July 17, 1985, date as reported in the LER. Therefore the 30 day period was up on July 22, 1985, and the LER was not reported until August 7, 1985. 10 CFR 50.73 requries licensees to submit an LER within 30 days after discovery of the event. The failure of the licensee to meet the 30 day reporting criteria of 10 CFR 50.73 will be identified as a violation (50-416/85-33-04).

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9.

Design, Design Changes and Modifications (37700)

l Design Change Package (DCP) 83/4067 was implemented to replace the cap screws attaching the diesel generator turbocharger plate to the engine mounting block for the turbocharger due to multiple failures of these cap

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screws. This DCP, although completed in October 1983, was not reviewed by i

the PSRC until January 1985.

The NRC had requested the PSRC to complete their review of the back log of DCPs during the NRC's review of the s

licensee's readiness to go above 50% power.

This DCP was reviewed by the PSRC as a part of that back log.

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The inspector reviewed this DCP for QA controls, Technical Specification requirments, test results and appropriate 10 CFR 50.59 reviews. This review

revealed numerous procedural violations such as returning the diesel to operation on October 21, 1983, prior to the complete engineering review and close out of the last change to the DCP and the retest control forms.

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Further inspection revealed a Plant Quality Deficiency Report (PQDR) had been initiated on January 6, 1984, documenting these procedural violations and performance deficiencies.

This PQDR and attachments explained the reasons for the deficiencies and the corrective actions to be taken by the licensee to prevent further occurrences. These corrective actions appear to be adequate and the inspectors, during future DCP reviews, will inspect to see if these corrective actions have been effective in preventing further deficiencies of this nature.

In the areas inspected, no violations or deviations were identified.

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