ML20215L248

Safety Evaluation Supporting Amend 21 to License NPF-29

ML20215L248
Person / Time
Site:	Grand Gulf
Issue date:	10/17/1986
From:	Office of Nuclear Reactor Regulation
To:
Shared Package
ML20215L247	List: ML20215L243 ML20215L248
References
TAC-60587, TAC-60588, TAC-60589, TAC-60590, TAC-60591, TAC-60592, TAC-61196, TAC-61782, NUDOCS 8610280545
Download: ML20215L248 (15)

Text

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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT NO. 21 TO FACILITY OPERATING LICENSE NO. NPF-29 MISSISSIPPI POWER & LIGHT COMPANY MIDDLE SOUTH ENERGY, INC.

SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION GRAND GULF NUCLEAR STATION, UNIT 1 DOCKET NO. 50-416

1.0 INTRODUCTION

By letters dated January 29, 1986 (as amended April 14, July 10, and August 26, 1986), June 13, 1986 (as amended August 26, 1986) and July 25, 1986 (as amended August 11,1986), Mississippi Power & Light Company (the licensee) requested amendments to Facility Operating License No. NPF-29 for the Grand Gulf Nuclear Station, Unit 1 (GGNS-1).

These three applications are addressed separately in this section and in the evaluation below.

1.1 January 29, 1986 application The proposed amendment would make six changes in the Technical Specifi-cations:

(1) change the names and valve numbers of certain plant service water system valves listed in Technical Specification Table 3.6.4-1, 3.8.4.1-1, and 3.8.4.2-1 to reflect the incorporation of those valves into the drywell chilled water system; (2) clarify which quality assurance records specified in Technical Specification 6.10.2.1 must be retained for the duration of the operating license; (3) change Technical Specifica-tion 3/4.6.5, "Drywell Post-LOCA Vacuum Breakers" to reflect the installation of position indicators for the vacuum breaker check valves and to clarify the specification and associated bases; (4) delete reference to Specifica-tion 6.9.1.13.f in Technical Specification 3.12, " Radiological Environmental Monitoring"; (5) change Technical Specification 3/4.1.3, " Control Rods" to reflect installation in the control rod scram discharge volume system of diverse and redundant level instrumentation and redundant vent and drain valves and to allow an alternate system test in lieu of a scram test following valve installation and maintenance; and, (6) change notes in Technical Specification Tables, 3.3.3-1 and 4.3.3.1-1 to make permanent the temporary condition allowing the HPCS actuation signals of Drywell Pressure-High and Manual Initiation to be inoperable when the reactor water level is higher than level 8 and reactor pressure is less than 600 psig.

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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT NO. 21 TO FACILITY OPERATING LICENSE NO. NPF-29 MISSISSIPPI POWER & LIGHT COMPANY MIDDLE SOUTH ENERGY, INC.

SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION GRAND GULF NUCLEAR STATION, UNIT 1 DOCKET NO. 50-416

1.0 INTRODUCTION

By letters dated January 29, 1986 (as amended April 14, July 16, and August 26, 1986), June 13, 1986 (as amended August 26, 1986) and July 25, 1986 (as amended August 11,1986), Mississippi Power & Light Company (the licensee) requested amendments to Facility Operating License No. NPF-29 for the Grand Gulf Nuclear Station, Unit 1 (GGNS-1).

These three applications are addressed separately in this section and in the evaluation below.

1.1 January 29, 1986 application The proposed amendment would make six changes in the Technical Specifi-cations:

(1) change the names and valve numbers of certain plant service water system valves listed in Technical Specification Table 3.6.4-1, 3.8.4.1-1, and 3.8.4.2-1 to reflect the incorporation of those valves into the drywell chilled water system; (2) clarify which quality assurance records specified in Technical Specification 6.10.2.1 must be retained for the duration of the operating license; (3) change Technical Specifica-tion 3/4.6.5, "Drywell Post-LOCA Vacuum Breakers" to reflect the installation of position indicators for the vacuum breaker check valves and to clarify the specification and associated bases; (4) delete reference to Specifica-tion 6.9.1.13.f in Technical Specification 3.12, " Radiological Environmental Monitoring"; (5) change Technical Specification 3/4.1.3, " Control Rods" to reflect installation in the control rod scram discharge volume system of diverse and redundant level instrumentation and redundant vent and drain valves and to allow an alternate system test in lieu of a scram test following valve installation and maintenance; and, (6) change notes in Technical Specification Tables, 3.3.3-1 and 4.3.3.1-1 to make permanent the temporary condition allowing the HPCS actuation signals of Drywell Pressure-High and Manual Initiation to be inoperable when the reactor water level is higher than Level 8 and reactor pressure is less than 600 psig.

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. Change (1) relates to the designation of the isolation valves for the newly installed drywell chilled water (DCW) system. The system circulates chilled water from freon chillers through the drywell coolers and the steam tunnel cooler during nonnal operation.

It utilizes existing valves and that have previously been components of the plant service water (pipingPSW) sys which was originally intended to perfonn the above mentioned cooling functions.

However, during pre-operational testing at the facility, tests indicated that additional drywell cooling beyond that provided by the PSW would be required to support full power operation of the facility. The newly installed DCW system significantly increases the heat removal capacity of the drywell j

cooling system. Specifically, the licensee proposed a revision of the table listing the containment and drywell isolation valves (Table 3.6.4-1).

This revision involves only changing the system name and associated valve numbers for certain PSW system isolation valves listed in the table to indicate that

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these valves are now components of the newly installed DCW system. The licensee further stated that the TS requirements that ensure the isolation function of these valves remain unaffected by the proposed revision. The licensee also proposed a revision to the Technical Specification Table 3.8.4.1-1 and Table 3.8.4.2-1 to include changes of the nomenclature of the penetration conductor overcurrent protective devices and the motor-operated valve thennal overload protective devices associated with the renamed isolation valves.

With regard to change (2), an inconsistency regarding the quality assurance (QA) record retention requirements of the Catawba Nuclear Station, Unit 1, Technical Specifications has recently been called to the staff's attention by Duke Power Company. These requirements are relatively standard for all i

newly licensed plants. TS Section 6.10.1 indicates that a number of records of 0A activities required by the Operational Quality Assurance Manual (00AM)

'Nhall be retained for at least 5 years." (For example, Items a, b, and d in the second paragraph of 6.10.1) The inconsistency is that Item i of i

Section 6.10.2 requires that records of QA activities required by the 00AM (i.e., these same records) "be retained for the duration of the Unit Operating License." Accordingly, the staff requested Mississippi Power &

Light Company to consider applicable changes to the Technical Specifications.

In change (3), the licensee proposed changes to Technical Specification (TS) 3/4.6.5. This TS provides the limiting conditions for operation (LCO), the action statements, and the surveillance requirements (SR) for the drywell post-LOCA vacuum relief subsystems, which are utilized for providing vacuum relief for the drywell in post-LOCA situations. The licensee, particularly, sought deletion of all temporary requirements from the current TS (i.e.,

those required until restart after the first refueling outage). These requirements were included in the existing TS to account for the lack of separate position indicators for the vacuum breakers (i.e., check valves) stems at the time the the GGNS-1 license of the post-LOCA vacuum relief subsy(35) requires that these be installed was issued. License Condition 2.C.

prior to startup following the first refueling outage. The licensee

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3-i justified the proposed deletion of the temporary requirements on the basis of staff's previous (July 23, 1985 letter) approval of the position indica-tor design submittal (May 24,1986) and the planned installation of these indicators during the first refueling outage. Based on its review, the staff agreed with the licensee's proposed deletion of the temporary require-ments. The staff, however, suggested that the revised TS 3/4.6.5 should (1) include the drywell purge vacuum relief subsystems since these are also used to provide vacuum relief for the drywell in the post-LOCA situations, (2) retain the 31-day surveillance requirement for the components of the drywell vacuum relief subsystems since these are consistent with the standard TS for similar BWRs (the licensee proposed deletion of this requirement),

(3) include the position indicators for the associated motor-operated isolation valves (MOVs) in series with the vacuum breakers, since staff's acceptance of the licensee's proposed separate position indicators of limited qualification (i.e., for normal operation environment only) for the vacuum.

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breakers is based on the availability of LOCA environmentally qualified position indicators for the MOVs, and (4) include a revised bases section for TS 3/4.6.5 to reflect the inclusion of the drywell purge vacuum relief subsystems.

In response to the above suggestions, by letter dated July 16, 1986, the licensee proposed revised changes to TS 3/4.6.5 with justification and also proposed a revised bases section and revised index pages to reflect j

the above changes. These revised proposed changes delete the temporary requirements and incorporate all of the above staff suggestions.

With regard to change (4), the licensee requested deletion of a reference to reporting requirements in TS Section 6.0 because these reporting requirements had been previously deleted. Deletion of reporting require-ments in TS Section 6.0 from Technical Specifications was requested by staff after publication of specific reporting requirements as rules in 10 CFR 50.72 and 10 CFR 50.73.

In change (5) the licensee requested changes to allow implementation of a design change to add redundant scram discharge volume (SDV) vent and drain valves. In the submittal made on April 14, 1986 the licensee proposed new action requirements and withdrew new License Condition l

2.C.(41) proposed in the January 29, 1986 submittal. This license condition was proposed to be replaced with deletion of the 50% rod density i

scram test in Surveillance Requirement 4.1.3.1.4.a.

The August 26, 1986 submittal was made after NRR staff expressed concerns regarding deletion of the 50% rod density scram test. The proposed changes to the previous submittal include retaining the 50% rod density scram test and adding a i

footnote which will provide an exception to the provisions of Specification 4.0.4 provided the surveillance is performed at least once per 18 months.

In change (5), the licensee also requested changes to the Technical i

Specifications to allow implementation of diverse and redundant scram discharge volume (SDV) level instrumentation after its installation during 4

i the first refueling outage. TS Table 3.3.1-1 and Table 4.3.1.1-1, are revised in a manner such that the applicable Technical Specification j

requirements for the SDV Water Level - High instrumentation apply to the l

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4 transmitter / trip unit, and the redundant float switch separately. This amendment also revises TS Table 2.2.1-1 by adding a list of both types of level instruments to identify individual setpoint requirements.

With regard to change (6), the licensee requested a change to the high pressure core spray (HPCS) system actuation instrumentation operability requirements in TS Table 3.3.3-1 and Table 4.3.3.1-1.

Table 3.3.3-1 and Table 4.3.3.1-1 presently permit the HPCS injection function for Drywell Pressure-High and Manual Initiation signals to be inoperable at times when the indicated Reactor Vessel Water Level-High (Level 8) isolation signal is present coincident with the reactor pressure below 600 psig. The original notes to the tables included a phrase " Prior to STARTUP following the first refueling outage" to allow the utility to consider the necessity for a design modification to the water level instrumentation. Deletion of the phrase, as proposed by the licensee, would extend the subject operability requirements beyond the first refueling outage into subsequent plant operations (i.e., the temporary requirements would bec,ome permanent).

1.2 June 13, 1986 application The proposed amendment would change Technical Specification 3/4.5.1, "ECCS - Operating," with respect to the automatic depressurization system (ADS) air system by adding surveillance requirements and an associated action statement for the accumulator low pressure alarm system instru-mentation channels and by adding a leakage test for the ADS air system.

The proposed changes result from prior commitments made by the licensee to install a pressure instrument to monitor and test the ADS air system.

These commitments were subsequently placed in License Condition 2.C.(33)g with implementation to be completed prior to start-up following the first refueling outage.

l 1.3 July 25, 1986 application l

l License Condition 2.C.(33)(b) requires the licensee to conduct a test simulating loss of all alternating current power (station blackout) in order to satisfy the requirements in TMI Action Plan Item I.G.I.

By Generic Letter 83-24, "TMI-2 Task Action Plan Item I.G.1, Special Low Power Testing and Training, Recommendations for BWRs," holders of an operating license were requested to consnit to the recommendations of the BWR Owners Group with respect to this additional testing, and to respond to the Generic Letter by determining whether a proposed station blackout (SBO) test would have the potential for damaging plant equipment.

In a letter from O. D. Kingsley, Jr., Mississippi Power and Light Company (MP&L) to H. R. Denton, NRC, dated April 3, 1986, MP&L presented the results of an analysis of a postulated SB0 event for the Grand Gulf Nuclear Station which is evaluated below.

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2.0 EVALUATION i

2.1 January 29, 1986 application Change (1) Drywell chilled water system isolation valves.

l The staff has reviewed the licensee's proposed revision of Table 3.6.4-1 and supporting justification. Based on the review, the staff agrees with the licensee that the proposed revision is administrative in nature.

It involves only a change in system name and chan numbers for certain plant service water (PSW) ges in associated valvesystem valves table. The purpose of the change is to indicate that these valves are now j

components of the newly installed drywell chilled water DCW system. Also, the revision of the table does not impact the isolation function of these a

valves as required by the current GGNS-1 TS. The staff agrees with the licensee that the proposed ' change will accurately reflect the newly installed DCW system. Also, it will facilitate preparation of associated documentation j

such as piping and insrtrument diagrams to show that certain PSW system valves are now DCW system components. The staff concludes that proposed revision of Table 3.6.4-1 is acceptable.

The staff has also reviewed the licensee's proposed revision of Table 3.8.4.1-1,

" Primary Containment Penetration Conductor Overcurrent Protective Devices" and Table 3.8.4.2-1, " Motor Operated Valves Thermal Overload Protection."

i The revision consists solely of changing the nomenclature of the protective devices to indicate that these components are now included in the newly installed chilled water system. The breaker numbers, their trip setpoints i

and response times in Table 3.8.4.1-1 and the thermal overload protection devices for MOVs in Table 3.8.4.2-1 are not affected by this change. The staff has reviewed the licensee's submittal and concludes that the proposed Technical Specifications include changes only in the designation of the system and its associated components and are therefore acceptable.

Change (2) Retention of QA records.

The staff has reviewed the proposed change to TS 6.10.2 regarding retention of records of 0A activities. The licensee proposed changing TS 6.10.2.1 to require retention of QA records required by the Operational Quality Assurance Manual if they are not listed in TS 6.10.1. Those listed in TS 6.10.1 are presently and would continue to be retained for 5 years.

This change is in accordance with the staff's recommendation and is there-fore acceptable.

Change (3) Drywell vacuum relief system The staff has reviewed the licensee's proposed Technical Specification 3/4.6.5 and the associated Bases 3/4.6.5 for the modified drywell vacuum relief system which equalizes pressure between the containment and drywell following a loss of coolant accident (LOCA). The licensee states that post-LOCA vacuum relief for the drywell is required to control rapid steam condensation in the drywell due to weirwall overflow that may result from a vacuum in the drywell following a LOCA. The water swell from rapid condensation in the drywell could cause drag and impact loadings to essential equipment and systems in the drywell above the weirwall. The

6-i licensee states that the vacuum relief function for the drywell in the above situation is provided by four drywell vacuum relief subsystems (an independent drywell vacuum relief capability also exists via a normal drywell vacuum relief line which handles normal operating transients and small pipe ruptures in the containment). The four drywell vacuum relief subsystems are comprised of two drywell purge vacuum relief subsystems (part of the combustible gas control purge system) associated with two 10-inch drywell vacuum relief lines, and two drywell post-LOCA vacuum i

relief subsystems arranged in parallel and associated with one 10-inch drywell vacuum relief line. The latter two subsystems are redundant, since operability of either one will ensure the availability of the common associated 10-inch vacuum relief line. Each drywell post-LOCA vacuum relief subsystem consists of a drywell vacuum breaker (i.e.,

l check valves F004A & B for the A and B subsystems) in series with a motor-operated butterfly isolation valve (F005A & B for the A and B subsystems). Each drywell purge vacuum relief subsystem consists of two vacuum breakers (I.E., check valves F001A and F002A for the subsystem A; i

i check valves F001B and F0028 for the subsystem B) and one motor-operated butterfly isolation valve (F003A and F0038 for the subsystems A and B) all in series. Vacuum relief is initiated automatically by flow of containment air through all three 10-inch drywell vacuum relief lines via the valves mentioned above to the drywell at a differential pressure of less than or equal to 1 psi across the check valves. The above subsystems also ensure that the design drywell bypass leakage is not exceeded if a LOCA should occur during plant operational conditions 1, 2 and 3.

All the above subsystems also include separate position indicators for all the 10 valves, which help to identify potential drywell bypass leakage paths during the above operational conditions. Licensee's proposed i

limiting condition for operation (LCO) 3.6.5 and surveillance requirement (SR) 4.6.5 for the above drywell vacuum relief subsystems ensure the above objectives. Specifically, the proposed LCO requires that all the four subsystems be operable with their associated valves in the closed position in plant operational conditions 1, 2 and 3.

The proposed SR require periodic surveillance tests or verifications (i.e., at least once every 7 days, 31 days or 18 months depending upon the type of the test or I

verification) for the check valves, isolation valves, differential pressure actuation instrumentation for the isolation valves, and the position indicators to demonstrate that these are operable and that all the valves are in closed position during plant operational conditions 1, 2 and 3.

Assuming a vacuum breaker capability of A/(K)0.5 equal to 0.38 ft, the 2

licensee has performed a drywell negative pressure analysis and determined that a minimum of two 10-inch drywell vacuum relief lines will be required to control possible rapid weirwall overflow that can result from a large break LOCA. The staff agrees with the above determination, particularly, because the licensee has previously demonstrated the acceptability of the dynamic loads from the pool created by reverse differential pressure cal-culated for the drywell, assuming no credit for the operation of drywell vacuum breakers (see GGNS, Units 1 and 2 Updated Final Safety Analysis w-.

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. Report, Section 6.2 and GGNS Safety Evaluation Report (SER) Supplement No. 3, Section 22, July 1982). The licensee states that the above minimum requirement for drywell vacuum relief lines can be ensured by requiring that either both the drywell purge vacuum relief subsystems or one drywell purge vacuum relief subsystem and one drywell post-LOCA vacuum relief sub-system be operable during operational conditions 1, 2 and 3.

Licensee's proposed Action Statements 3.6.5a, b and c cover the situations arising from inoperable drywell vacuum relief subsystem (s) (i.e., inoperable in the sense that the associated valve (s) is (are) inoperable for opening but known to be closed) during plant operational conditions 1, 2 and 3 and follow from the above mentioned minimum requirement and how it can be met.

Specifically, for such situations, these action statements allow continued plant operation, provided corrective action (s), i.e., restoring the inoperable valve (s) to operable status, is (are) completed within 30 days or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> depending upon whether one or two 10-inch drywell vacuum relief line(s) is (are) affected. However, the above 72-hour time limit for corrective actions to continue plant operation is not allowed for the situation in which both purge vacuum relief subsystems are affected. The requirement that the affected valve (s) be linown to be closed stipulated in the above action statements ensures that the design drywell bypass leakage will not be exceeded should a LOCA occur in plant operational conditions 1, 2 and 3.

Additionally, licensee's proposed Action Statement 3.6.5.d covers the l

situation arising from an open drywell isolation breaker (i.e., check l

valve F002A, F002B, F004A or F0048) in plant operational conditions 1, 2 and 3.

Specifically, for such a situation, the action statement allows continued plant operation, provided the open valve is closed within one hour to prevent a potential drywell bypass leakage path in a timely manner.

Since the other vacuum breaker (s) of the drywell purge subsystem (s) (i.e.,

check valves F001A and/or F0018) being open in operational conditions 1, 2 and 3 does (do) not result in drywell bypass leakage paths, provided the upstream vacuum breakers (i.e., F002A and F002B) are in a closed position, the Action Statement 3.6.5.d does not cover them. However, these valves (s) being in open position (s) correspond to inoperable purge subsystem (s) which are covered by plant TS 3.6.7.3, " Combustible Gas Control Purge System." Licensee's proposed Action Statement 3.6.5.e allows con-tinued plant operation, in the event, the position indicator of any operable i

valve is inoperable, provided the operable valve is verified closed at l

1 east once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by local indication.

t The staff concludes that the licensee's proposed changes to TS 3/4.6.5 and the associated TS bases as identiffed in the July 16, 1986 submittal, are acceptable. The staff's acceptance is based on the following findings:

a.

The LCO includes all four drywell vacuum relief subsystems which provide drywell vacuum relief in post-LOCA situations; i

i b.

The proposed corrective actions and the times for completing them for continuing plant operation are consistent with applicable Standard Technical Specifications; l

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. c.

The proposed changes to TS 3/4.6.5 provide reasonable assurance that the needed vacuum relief will be available for the drywell in post-LOCA situations and that the drywell design basis bypass leakage will not be exceeded should a LOCA occur during plant operational conditions 1, 2 and 3; and The proposed bases for TS 3/4.6.5 adequately describe the d.

safety functions of the vacuum relief subsystems, from which the TSs were derived.

Change (4) Reporting of radiological environmental monitoring results.

The staff has reviewed the licensee's requested deletion from TS 3.12.1.b of a reference to TS 6.9.1.13.f for reporting requirements in the event radiological monitoring results exceed specified reporting levels. The GGNS-1 Technical Specifications currently in effect, do not contain a TS 6.9.1.13.f because it was deleted to conform to recently effective Comission rules,10 CFR 50.72 and 10 CFR 50.73. Section 3.12.1.b of the TS already refers to a Special Report pursuant to TS 6.9.2.

Thus, the reference to TS 6.9.1.13.f on Page 3/4 12-1 is superfluous and should be deleted as a typographical error. Accordingly, the staff concludes the proposed change is acceptable.

Change (5) Scram discharge volume redundant level instrumentation, vent valve and drain valve.

The proposed design change associated with this technical specification change, modifies the scram discharge volume (SDV) design to meet the requirements of the NRC generic study, "BWR Scram Discharge Volume System Safety Evaluation", dated December 1, 1980. The design change is required by the Grand Gulf Unit 1 Operating License Condition 2.C.(15).

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i As a part of the required design change, two float-type level switches l

per trip system are added. These new switches provide independent trip signals to the reactor protection system in addition to the existing analog i

level transmitters. The purpose of this modification is to minimize the potential for a common mode failure due to a drain or a vent valve not closing and resulting in an uncontrolled loss of coolant. The licensee has stated that this design modification conforms to the requirements of IEEE Standard 279-1971 and other design comitments with respect to the reactor protection system. The new float switches are qualified to the same requirements of the existing level transmitters. The trip setpoints and allowable values for both the transmitter / trip units and the float 1

switches are based on an available SDV of 645 gallons. This corresponds to a level of 10" below the lowest elevation of the SDV or, equivalently, a level of 64" in'the scram discharge instrument volume. The zero for the trip unit scale is equivalent to 46" in the instrument volume and the scale range is 0-30".

The trip setpoint is 46" + (60% of 30") = 64" and the I

allowable value is 46" + (63% of 30") = 64.9" or 65".

Therefore, the set-points and allowable values for both the transmitter / trip units and the float switches are equivalent. The staff finds that the licensee's design modification and the technical specification changes in Tables 3.3.1-1, l

4.3.1.1-1 and 2.2.1-1 are acceptable.

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, i The other part of the design change required by License Condition 2.C.(15) is the addition of a redundant vent valve and a redundant drain valve to the SDV. The changes to TS 3/4.1.3.1 resulting from this design change are evaluated below.

Proposed Action Statement d of TS 3.1.3.1 gives the required action if om SDV vent valve and/or one drain valve is found to be inoperable and open.

During nonnal operation, the SDV is vented and drained to the suppression pool through a vent line and a drain line.

In the present design there is one drain valve and one vent valve.

In the modified design, each line con-tains two valves in series which are actuated to close upon a scram, thus allowing the control rod drive effluent to be contained in the SDV.

In the event of a scram, and failure of all SDV vent and drain valves to close, there would be a slight heat-up of the suppression pool. The capacity of I

the residual heat removal system would be more than adequate to remove this

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heat load.

Reactor vessel makeup water would be assured from either the condensate and feedwater system, or the high pressure core spray system.

Therefore, the safe shutdown capbility of the unit is not adversely l

affected. The present TS prescribes steps to be taken when one SDV vent

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and/or one drain valve is inoperable and open. The required action is the closing of the inoperable valve within one hour. No action is required for i

an inoperable closed valve. The proposed change applies to an inoperable condition while the subject valves are open and eliminates the require-j ment to close them. The allowed time of operation with inoperable valves is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee states that the present requirement to close the inoperable vaTve(s) could cause the plant to undergo an unnecessary transient if operational leakage into the SDV is enough to reach the scram i

level setpoint.

In addition, by this change, the action statement will conform to that of the Perry Plant and the Clinton Plant, which are also BWR-6, Mark III plants. The staff concludes that proposed Action Statement d is acceptable because in the event of a scram, the remaining operable i

vent and drain valves can still be expected to perform their function of i

preventing blowdown of reactor coolant via the SDV.

In addition, unnecessary scrams may be reduced and the safe shutdown capability of the plant will not be adversely affected.

i Proposed Action Statement e of TS 3.1.3.1 gives the required action if two SDV vent and/or drain valves are found to be inoperable and open.

In the event of a scram, while operating in this condition, there could be a blowdown of the reactor coolant, via the SDV, into the suppression l

pool. This would slightly raise the temperature of the suppression pool.

l The proposed action includes requiring having one vent valve and one drain valve operable (permitting closure on scram) within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This is more restrictive than the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed for operating with one vent l

valve and one drain valve inoperable and open as discussed in proposed Action Statement d.

The action further requires restoring all valves to i

operable status within the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />, or closing at least one vent valve and one drain valve and being in 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 />.

l This additional 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> restoration time for the remaining inoperable I

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. vent valve and/or drain valve is consistent with the proposed Action State-ment d.

The required action is that all vent valves and drain valves be made operable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The staff concludes that proposed Action Statement e is acceptable.

Proposed Action Statement f of TS 3.1.3.1 gives required action if the SDV vent valves and/or drain valves are found to be inoperable and closed.

The action is to restore all valves to operable status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in 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 />. The staff finds this to be acceptable because if a scram does occur the SDV vent and drain valves are in their preferred position. When there is no scram and these valves are shut, water will accumulate in the SDV. Although this may initiate a scram, the valves are in their preferred closed position and therefore the safe shutdown capability of the plant would not be adversely affected.

The staff concludes that proposed Action Statement f is acceptable.

Proposed Surveillance Requirement a of TS 4.1.3.1.4 gives the required surveillance test to determine operability of the vent valves and the drain valves by means,of a scram test from a normal control configuration of less than or equal to 50% control rod density. This rod configuration requires the reactor to be in Operational Condition 1, Power Operation, i

or 2, Startup, when the test is run. The present survei'. lance require-ment is that the SDV vent valves and drain valves be demonstrated operable i

by performing such a scram test at least once every eighteen months. A i

demonstration of operability is also required when major modifications are made to the SDV which could affect operability including the installa-tion of the new vent valve and the new drain valve. However, by TS 4.0.4, entry into either of the Operational Conditions cannot be made unless the

{

surveillance has been perfomed. Thus, an exception to TS 4.0.4 is required to run the initial test. The proposed change adds a footnote which provides an exception to TS 4.0.4, as long as the surveillance is performed at least once per eighteen months. Hence, operational condition 1 or 2 may be entered without having run the surveillance test and the operation may be continued i

as long as the surveillance is perfomed within eighteen months, and at i

least once per eighteen months thereafter. The above provisions address periodic demonstration of SDV system operability under nomal plant operation conditions. However, the staff was concerned that there is no provision for showing operability prior to any startup following significant SDV l

system modification. The licensee has responded to this concern by making l

a comitment to evaluate each maintenance activity affecting SDV operability

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and to perform retests of parts, or of the entire SDV, as necessary, to ensure operability of affected components.

In particular, with respect to the first startup following the installation of the additional vent valve and drain valve, the licensee has provided information regarding the location of the work area, number of personnel involved and a method of installation to ensure proper installation of the valves. The licensee also has commit-ted to special testing to ensure proper vent and drain flow. A scram injec-tion signal test is also to be perfomed after the modification is complete.

i This test is to demonstrate that all SDV vent valves and drain valves closure times meet the 30 second closure criteria. A reset will follow i

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t and the vent valves and drain valves will be verified to open and the SDV checked to ensure proper drainage. The staff has reviewed the above infor-mation and finds that the licensee's approach is reasonable and provides adequate assurance of SDV system operability. Based on its review of the proposed changes to TS 3/4.1.3.1, the staff concludes that proposed Surveil-lance Requirement a of TS 4.1.3.1 is acceptable because unnecessary scrams for testing will be eliminated and acceptable alternative tests following SDV system modification will be run to demonstrate SDV operability.

Change (6) Operability requirements for high pressure core spray (HPCS) actuation instrumentation.

To justify the non-operability of the HPCS injection function on Drywell Pressure-High and Manual Initiation when the reactor pressure vessel Level 8 isolation signal is present coincident with reactor pressure below 600 psig, the licensee has provided a discussion and accident analysis in the January 29, 1986 submittal to demonstrate that the calculated peak clad temperature (PCT) remains well below the 2220*F limit. Specifically, a steam line break infide the containment was reanalyzed with the assump-1 tion that the high drywell pressure initiation feature is defeated and HPCS is initiated only by low water level. Other assumptions in the cal-culation were the same as the previous Final Safety Analysis Report (FSAR) analysis (e.g., worst single failure); the PCT was calculated to be 1322 F.

The ECCS performance analysis was done with analytical methods previously approved by the staff (General Electric company Analytical Model for loss of Coolant Analysis in Accordance with 10 CFR 50 Appendix R, NE00-20566, August 1974).

A previous concern with water level instrumentation was that the upset, narrow and wide range water level instruments are calibrated for normal operating conditions and would read higher than actual level at low coolant temperatures and pressures. This would result in the actuation of the level 8 interlock with actual water level lower than at operating i

conditions. The staff agrees with the licensee's conclusion that for the purpose of preventing vessel overfill, this actuation of the interlock would not compromise plant safety.

In addition, the reanalysis of the steam line break for no HPCS injection on a high drywell pressure signal shows that the HPCS injection function is not required at times when a false level 8 isolation signal is present.

Based on our review of the licensee's reanalysis of the relevant LOCA and l

accompanying discussion, we conclude that the predicted PCT of 1322*F remains well below the 2220*F limit of 10 CFR 50.46 for the condition of no HCS Injection when the Level 8 isolation signal is present coincident with reactor pressure below 600 psig, i

i i

. _. _ _ General Design Criterion 13 states, in part, that " Instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for i

accident conditions as appropriate to assure adequate safety...".

The proposed Technical Specification change for Grand Gulf would retain the necessary safety functions on low water level at RCS pressures below 600 psig, because the measurement error in water level decreases as the water level decreases and actuation of emergency systems would still occur. Since (1) the actuation of the interlock for the purpose of pre-venting vessel overfill would not compromise plant safety, (2) the re-analysis of the steam line break shows that HPCS injection is not required when a false Level 8 isolation signal is present and (3) initiation of HPCS on low water level is not adversely affected by this change, the staff concludes that the requirement of General Design Criterion 13 for adequate instrumentation remains satisfied.

Thus, the staff concludes that the proposed change (6) to the TSs is acceptable because it s ets 10 CFR 50.46 and General Design Criterion 13.

2.2 June 13, 1986 application The purpose of the air accumulators for the automatic depressurization system (ADS) is to provide the safety relief valves that are in the ADS with sufficient air supply to cycle the valves open two times at design reactor coolant pressure.should the normal ADS air supply fail. The air accumulators and associated equipment and instrumentation are designed to I

perform their safety function in an accident environment for 100 days following an accident. Air leakage from the accumulators must be accounted for in order to assure that the inventory of compressed air in the accumu-lators is available for their safety function.

l The licensee previously submitted the design of the air accumulators and the associated equipment and instrumentation. The NRC staff approved the i

l design by letters dated March 15, 1985 and November 22, 1985. The staff concluded that the requirements of TMI Action Plan Item II.K.3.28, " Verify Qualification of Accumulators on ADS Valves" (NUREG-0737) were satisfied by the proposed design.

The NRC staff has reviewed the licensee's June 13, 1986 application as amended August 26, 1986 which requests changes to the Technical Specifica-tions to implement the previously approved design. The changes include:

surveillance tests for a low pressure alarm system channel function test and channel calibration including the low pressure alarm setpoint; an action statement if the instrumentation is inoperable; and, a leakage test of the ADS air system every 18 months.

The leakage test is initiated by turning off the instrument air booster compressors and by venting the booster compressor discharge to atmosphere.

The pressure decay rate in each of the two ADS air headers is monitored, l

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, and the air pressure at the end of the seven days is determined by extra-polation. The leakage test is considered acceptable if the air pressure after seven days (based on extrapolation from test data) is above 110

)

psig. Tests have shown that with the ADS air system at 110 psig, each ADS valve can be actuated two times against 70% of drywell design pressure.

i The staff concludes this test acceptance criterion is. acceptable because it meets the previously approved design requirements in staff's March 15, 1

1986 letter.

Instrumentation to monitor ADS air receiver pressure will consist of a separate alarm and pressure indicator in the control room for each of two redundant divisions. Environmental Qualification of pressure transmitters will be in accordance with 10CFR50.49. Design codes for installation will be in accordance with IEEE-323, 1974 and all applicable codes listed in the Final Safety Analysis Report (FSAR). The trip setpoint for the ADS air receiver pressure alam'is based on an analytical lower limit of 147 psig. The lower limit is determined by the minimum pressure required to provide two actuations for each ADS valve and then hold the ADS valves open for five days under the most limiting accident conditions. The upper limit for the alam will be administrative 1y controlled to ensure that it I

is below the ADS booster compressor start signal trip setpoint and is currently set at a nominal 160 psig. To ensure that an alarm is generated well before the minimum required ADS air receiver pressure is reached, the nominal trip setpoint will be 150 psig. This nominal trip setpoint will be maintained to ensure that an alam is generated, operators will take appropriate action in accordance with alarm response instructions including declaring the ADS system inoperable. These alarm response instructions will replace the administrative controls currently used to monitor the pressure every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and take action if the pressure reads less than 150 psig. The action statement for inoperable low pressure alam system instrumentation channels requires monitoring the pressure locally every i

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and restoring the inoperable channels to operable status within 7 days or declare the associated ADS valves to be inoperable. The surveil-lance requirements are acceptable to the staff because they meet previously approved design requirements in the staffs March 15, 1986 letter. The action statement is acceptable to the staff because the present surveillance interval of once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> has been demonstrated to be adequate and the 7 day allowance is adequate to effect most repairs to the instrumentation.

In addition to the proposed changes to the Technical Specifications, the licensee will implement administrative procedures to test the instrument air quality of the ADS air system. A sample of instrument air will be taken every 6 months to ensure that the proper air quality is maintained.

These air samples will be analyzed for moisture content, particle size, and oil content and will be required to meet the General Electric design requirements for ADS system safety-related components. This General Electric design specification requires that the ADS air supply be oil-free (less than 1 ppm), dried to a dew point of - 40"F at 100 psig, and filtered to 50 microns. The proposed administrative procedure will require that the instrument air quality be verified to be within the required limits at

. least once every 6 months. The 6 month test interval will allow for comparisons of test data for determining if system degradation is taking place.

In the event the instrument air quality fails to meet the design requirements, an engineering evaluation will be performed within 7 days.

The licensee presently contracts the sampling of ADS instrument air quality to an off-site laboratory. The laboratory supplies the evacuated cylinder used to collect the air sample. These cylinders must be requested from the laboratory just prior to collecting a sample. Once the sample is drawn, the cylinder is shipped back to the laboratory for analysis. Total analysis time from the time the cylinder is requested until results are received from the s ple is approximately 3 to 4 weeks. The licensee concluded that a testina interval of less than six months would place undue constraints on the operation of the plant. The staff concludes that a six month testing interval will allow for the comparison of previous tests and the early detection of system degradation, and is, therefore, acceptable.

In summary, the staff concludes that the proposed changes to the Technical Specifications and the administrative control of testing instrument air quality meet the design requirements previously approved by the staff in its March 18, 1986 letter and are therefore acceptable.

2.3 July 25, 1986 application The staff has reviewed the results of the licensee's response to Generic letter 83-24 and its request to revise License Condition 2.C.(33)(b).

In its analysis of a station blackout (SBO) test, the licensee concluded that a SB0 test could damage equipment in the drywell due to drywell temperature levels above normal. The safety-related equipment would not be endangered and could survive a SB0; however, the non-safety-related equipment could be damaged. In addition, the safety-related equipment in the drywell would suffer accelerated thermal aging from a SB0 test.

The licensee's analysis complies with Generic letter 83-24 and is suffi-cient justification for not performing a SB0 test at Grand Gulf Nuclear Station. Further, the staff notes that the licensee's evaluation is consistent with similar evaluations made for Clinton, Susquehanna, Hope Creek, LaSalle, and other BWRs.

In its April 3,1986 submittal, the licensee committed to comply with the recommendations of the BWR Owners Group letter to the NRC dated February 4, 1981 regarding augmented testing (BWROG-8120). This augmented testing will be completed during the first refueling outage, scheduled to begin in September 1986 and end in November 1986.

Based on its review the staff concludes that the SB0 test need not be performed at Grand Gulf Nuclear Station. Also, since the Grand Gulf Nuclear Station has committed to the BWR Owners Group recommendations for augmented testing, we conclude that the Grand Gulf Nuclear Station Test Program described in the FSAR, without the SB0 test, meets TMI-2 Action Plan Item I.G.1 requirements. Since the proposed License Condition 2.C.(33)(b)

' O

. i replaces the requirement for the SB0 test with the requirement for augmented testing recommended by the BWR Owners Group, the proposed license condition is acceptable.

3.0 ENVIRONMENTAL CONSIDERATION

This amendment involves changes to requirements with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 and changes to the surveillance require-ments. The staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued proposed findings that this amendment involves no significant hazards consideration and there has been no public' comment on such findings. Accordingly, this amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), na dnvironmental impact statement or environmental assessment need be prepared in connection with the issuance of this amendment.

4.0 CONCLUSION

The Commission made proposed determinations that the amendment involves no significant hazards consideration which were published in the Federal Register on August 13, 1986, (51 FR 29002) and on September 10, 1986, (51 FR 32275, 32276, and 32277) and consulted with the state of Mississippi.

No public comments were received, and the state of Mississippi did not have any comments.

i The staff has concluded, based on the consideration discussed above, that:

(1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (2) such activities will be conducted in compliance with the Commission's regulations and the issuance of this amendment will not be inimical to the common defense and the security nor to the health and safety of the public.

Principal Contributors:

N. Trehan, Electrical, Instrumentation, and Control Systems Branch, DBL i

M. McCoy, Reactor Systems Branch, DBL i

T. Chandrasekaran, Plant Systems Branch, DBL H. Li, Electrical, Instrumentation, and Control Systems Branch, DBL i

D. Katze, Plant Systems Branch, DBL J. Lombardo, Engineering Branch, DBL W. Luckas, Brookhaven National Laboratory L. Kintner, Project Directorate No. 4, DBL i

Dated: October 17, 1986 4

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