ML19346A119
| ML19346A119 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 05/31/1981 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML18086A623 | List: |
| References | |
| NUREG-0517, NUREG-0517-S06, NUREG-517, NUREG-517-S6, NUDOCS 8106050139 | |
| Download: ML19346A119 (61) | |
Text
O NUREG-0517 Supplement No. 6 Safety Evaluation Report related to the operation of Salem l\\ uclear Generating Station, Unit No. 2 Docket No. 50 '211 l
Public Service Electric and Gas Company, et al.
U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation May 1981 p "%,,
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NUREG-0517 Suppwnent No. 6 Safety Evaluation Report related to the operation of Salem Nuclear Generating Station, Unit No. 2 Docket No. 50-311 Public Service Electric and Gas Company, et al.
U.S. Nuclear Regulatory Commission Officu of Nuclear Reactor Regulation May 1981
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E TABLE OF CONTENTS PAGE
1.0 INTRODUCTION
AND GENERAL DISCUSSION........................
1 -.1 3-1.1 Introdection..........................................
1 -1 3.0 DESIGN CRITERIA - STRUCTURES, COMPONENTS, EQUIPMENT AND SYSTEMS. '7-1 3.11 Environmental Design of Engineered Safety Features E q u i p me n t..........................................
3-1 9.0 AUX ILI ARY AND EMERGENCY SYSTEMS............................
9-1 9.7 Fi re P rotec ti o n Sy s tem................................
9-1 22.0 TMI-2 REQUIREMENTS.........................................
22.1-1 22.1 I n tro d u c ti o n.........................................
22.1-1 a
III. Emergency Preparations and Radiation Protection......
22.2-1 III.A.l.1 Upgrade Emergency P reparedness..................
22.2-1
23.0 CONCLUSION
S...............................................
23-1 APPENDIX A CONTINUATION OF CHRONOLOGY FOR RADIOLOGICAL SAFETY REVIEW OF SALEM NUCLEAR GENERATING STATION, UNIT 2..
A-1 APPENDIX G REVIEW 0F PSE8G'S CABLE SEPARATION STUDY G-1 APPENDIX H FEDERAL EMERGENCY MANAGEMENT AGENCY LETTER, " FINDINGS AND DETERMINATION RELATING TO THE STATUS OF STATE AND LOCAL EMERGENCY PREPAREDNESS FOR THE SALEM UNIT 2 NUCLEAR PLANT", DATED APRIL 24, 1981 H-1 i
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1.0 INTRODUCTION
AND GENERAL DISCUSSION 1.1 Introduction In October 1974, the U. S. Atomic Energy Comission IAEC) 'ssued its Safety Evaluation Report (3ER) regarding the application by the Public Service Electric and Gas Company (PSE8G or licensee) for licenses to operate the Salem Nuclear Generating Station, Units 1 and 2.
Since then, the Nuclear Regulatory Comission (NRC) has issued Supplements 1 through 5 which documented the resolution of several outstanding issues in further support of the licensing activities.
Further review of the Unit 2 operating license application resulted from a number of studies performed fo110 wing the accident at the Three Mile Island Unit 2 (1HI-2) reactor plant.
On April 18, 1980, a fuel loading and low power testing license was issued for Salem Unit 2 based, in part, upon requirements established for the Tf11-2 accident.
Initially, the license permitted fuel loading and zero power testing.
The license was subsequently amended: Amendment No. 2, dated August 22, 1980, j
permitted the licensee to perform the low power test program identified in Section 8.16 of Appendix A to the license at power levels not to exceed 5 percent j
of rated core thermal power.
The purpose of this supplement is to further update our Safety Evaluation Report by providing (1) our findings from additional audits of the licensee's equipment i
I qualification program; (2) our evaluation and status of the licensee's fire protection program; and (3) our evaluation and status of the licensee's Emergency Preparedness. These matters were discussed at a Commission briefing held on April 28, 1981.
l Each of the following sections of this supplement is numoered the same as the corresponding section of the Safety Evaluation Report and Supplements No.1-5, I
except Sectioa 22.0 which addresses THI-2 requirements and Section 23.0 which preser.ts our conclusions.
l Each section is supplementary to and not in lieu of the discussion in the Safety l
Evaluation Report and Supplements No.1-5 thereto, except where specifically t
noted. Appendix A is a continuation of the chronology of principal actions related to the processing of the applica. tion. Appendix G contains a NRC review team's report of findings from an on-site review of PSE&G's cable separation study.
Appendix H contains a letter from the Tcueral Emergency Management Agency (FEMA) on the subject of FEMA's findings and determinations of the status l
of State and local emergency preparedness for Salem Unit 2.
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3.0 DESIGN CRITERIA-STRUCT81RES, COMPON: NTS EQUIPMENT AND SYSTEM 5 3.11 Environmental Design of Engineered Safety Features Equipment In Section 3.11 of SER Tupplement No. 5, we stated that an additional audit, at PSE8G of fices and the publication of the Safety Evaluation Report would complete the staff's evaluation of the licensee's environmental qualification program.
By letter, dated March 6,1981, we transmitted to PSE8G the primary results of our review of environmental qualifications of safety-related electrical equipment at Salem Unit 2.
This review identified a number of potential equipment deficiencies involving a lack of proper documentation, inadequate justification of assumed environmental conditions following an accident, and/or inadequate environmental testing of equipir,ent such that conformance to DDR guidelines could not be demonstrated.
PSE8G was required to respond within 10 days of receipt of the report with a written statement supporting the safe operation of their facility tding into account the NRC staff's preliminary list of deficiencies. PSE8G responded by letter dated March 19, 1981, that appropriate corrective actions which the staff identified had been taken and concluded that Salem 2 could operate in a safe manner.
The NRC technical review has been completed. A Safety Evaluation Report i
has been prepared which confirms the preliminary results forwarded to PSE8G on March 6,1981, and identifies no outstanding items which require immediate corrective action. This SER requires PSE&G to provide, within 90 days, documentation of the missing qualification information which demonstrates that such equipment meets the 00R guidelines or NUREG-0588 or comit to a corrective action (requalification, replacement, relocation, and so forth) consistent with the requirements to establish qualification by June 30, 1982.
If the latter option is chosen, the licensee must provide specific justification for operation until such corrective action is complete.
In this SER, the staff concludes that conformance with the above requirements and satisfactory completion of the corrective actions by June 30,1982 will ensure compliance with the Comission Memorandum and Order of May 23, 1980.
l The staff further concludes that there is reasonable assurance of safe operation l
of this facility pending completion of these corrective actions.
i 3-1
9.0 AUXILIARY AND EMERGENCY SYSTEllS 9.7 Fire Protection System In Appendix E t'. Supplement 4 of the Safety Evaluation Report, dated April 1960, we presented our Fire Protection Safety Evaluation Report for Salem Units 1 and 2.
In that Supplement report we stated that the applicant committed to provide an alternate shutdown method Nr our review that would be independent of the relay and switchgear rooms. We also stated that the applicant comitted to perform a fire interaction analysis on all r9dundant systems and components necessary for safe cold shutdown which are separated only by distance and are within 20' of each other. Where additional protection and/or separation are required to assure a safe shutdown condition, the applicant committed to:
(1) achieve a minimum of 20 ft. separation between divisions; (2) provide a one-hour rated barrier to separate one train from the other; or (3) provide an alternate shutdown method that is independent of the l
interaction areas.
By letter dated November 5,1979, the applicant made these commitment., stated his criteria for the fire interaction analysis, and provided preliminary descriptions of the type of modifications he pioposed. The applicant also stated that additional information would be provided to the staff when the analyses and the design changes were finalized.
The staff required that the interim results of PSE8G's fire interaction analysis be reviewed prior to issuance of a full power license. To expedite this action a NRC fire protectica review team was assembled for the purpose of conducting an on-site review of PSE8G's fire interaction analysis (cable interaction study) for Salem Units 1 and 2.
The objectives of this team were to:
(1) make a finding on the adeqtacy of PSE8G's fire interaction l
study and the program used to implement the results of that study; and (2) make a finding on the adequacy of the corrective actions implemented as a result of the fire interaction program. These findings would be limited to the adequacy of the fire protection measures on a short term basis. The adequacy of the me sures on a 'long term basis would be covered by the staff in its review of the licensee's compliance with the requirements of Appendix R to 10 CFR Part 50.
l The on-site fire protection review of the fire interaction study was conducted from April 30, 1981 to May 7, 1981. The team's report is attached as Appendix G to this Supplement. The team concluded that "the fire prctection measures are adequate for continued operation of Unit 1 and for issuance of a (full power) license with appropriate license conditions for Unit 2..." The license conditions resulting from this review are listed at the conclusion of this section.
9-1
In Section III, " Additional Considerations," of its report, the NRC review team acknowledged that the findings from the raview may impact previous commitments made by PSE&G. PSE8G was requested:
(1) to re-examine its cable wrap schedule and provide the NRC with a new date for completion of wrapping which would include the additional areas identified by the team; (2) to re-examine its schedule for responding to NRC Generic Letter 81-12 (Attachment A) and provide the NRC with a new date for that response; and (3) to re-evaluate its schedule for overall program verification and to propose a new schedule by letter to the Office of Inspection and Enforcement.
By letter dated May 14, 1981, PSE&G addressed the above considerations and provided a proposed schedule for completion of these items. The staff has reviewed the proposed schedule and finds that the adjustments are appropriate to enable PSE8G to incorporate the review team's findings into PSE&G's fire protection program.
The revised schedule is reflected in the license conditions licted at the end of this section.
In its letter dated M y 14,1981, PSE8G requested one exception from the schedule A
specified in the review team's report. Due to material ordering problems, PSE8G cannot support a near term installation of emergency lighting. P5E8G has proposed that until all emergency lighting has been installed:
(1) a continuous fire watch would be established in the relay room; and (2) sufficient dedicated portable battery powered lighting would be provided for the operating personnel necessary to achieve coid shutdown.
Since loss of a?1 lighting can be postulated only with a fire in the relay room, the staff finds that PSE&G's proposal provides adequate protection on an interim basis until all cmergency ilghting is installed.
During the course of the staff's on-site review, one area in the 480/230 VAC switchgear room on elevatica 84' in the Auxiliary Building was identified in which a single postulated EO-foot diameter fire could potentially fail all instrument channels, including the independent safe shutdown instrumentation provided for alternative shutdown. The review team concluded that this presented an immediate safety concern. Accordingly, the Office of Inspection and Enforcement obtained, and documented in correspondence dated May 5,1981, a licensee commitment to take immediate corrective actions. This commitment is reflected in the license conditions listed at the conclusion of this section.
The results of the on-site review were based upon approximately a fifty percent audit of the licensee's fire interaction analysis. All identified deficiencies were related back to specific basic assumptions and criteria use,d by the licensee in the fire Interaction analysis.
To ensure that all additional related deficiencies, if any, are identified and corrected the licensee will be required to review his fire interaction analysis in light of the NRC review team's findings; to report the results of this review to the NRC; and to l
l correct all additional deficiencies by July 31, 1981. As part of our evaluation of PSE8G's compliance with Appendix R, the staff will evaluate PSE8G's final documented fire interaction analysis.
On November 19, 1980, the Commission published an amendment to its regulations which required Salem Unit 1 to comply with Sections III.G, III.J, and III.0 of Appendix R t6 10 CFR Part 50. As indicated in Supplement 5 to our SER, I
dated January 1981, the applicant committed, by letter dated December 1,1980 to implement in Salem Unit 2 any changes required for Salem Unit 1 to comply with l
Appendix R requirements.
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By letter dated March 19, 1981, the applicant requested several exemptions from the requirements of Appendix R.
Our review of these exemption requests for Salem 1 and 2 is being delayed pending receipt of the final design descriptions of the modifications made to provide fire protection for shutdown systems and the alternative shutdown capability.
By letter dated April 22, 1981, the licensee committed to comply with Appendix R Section Ill.L with respect to alternative shutdown capability and to provide the information we required to complete our review by May 19, 1981. As a result of PSE8G's efforts to support the staff's recent on-site fire protection review, PSE8G has requested and we have approved an extension of this schedule to July 17, 1981 for an interim response and to August 17, 1981 for the final s$mi ttal.
In SER Supplement No. 5, we stated that the alternate shutdown capability to achieve hot shutdown from outside the control room is now operational. This statement was in error. As stated above, the applicant has not yet formally submitted a description of this capability. However, this matter was reviewed by the on-site team.
By letter dated September 4, 1980, PSEaG reported the status of the design modifications to provide an alternate shutdown capability. This report included the statement, " Currently, equipment and procedures exist for achieving hot shutdown frem outside the Control Room." Subsequently we have found that the capability referred to did not include adequate consideration of fire damage, which necessitated the license conditions listed at the end of this section.
At present, we are aeveloping a program for evaluating Appendix R exemption requests for all operating plants. We will be completing our evaluation of these fire pro-tection program aspects at Salem Units 1 and 2 as part of that program.
In Supplement No. 5 to the Salem Unit 2 SER, we also stated that an action item yet to be completed was the wrapping of several cable trays with a mineral wool blanket to give a 1-hour fire barrier between divisions separated by less than 20 ft.
We concluded that it was reasonable to wait until March 20, 1981, to wrap these cable trays. By letter dated April 22, 1981, the licensee informed us that the wrapping of cable trays was delayed because they were unable to obtain adequate quantities of the mineral wool from the vendor. The licensee stated that as of April 22, 1981 they would have 40% of all trays wrapped and that the wrapping would be 100% complete by June 15, 1981. A further delay in final cable wrapping until July 31, 1981, was requested by PSEaG in a letter dated May 14, 1981 in order to incoroorate into its program the findings from the NRC review. We have concluded that the licensee is making a reasonable effort to complete this item and their schedule is acceptable. The full power license will be conditioned with a requirement to complete this item by July 31, 1981.
We find that the fire protection program for the Salem Nuclear Generating Station is adequate at the present time, meets the requirements of GDC-3, and witn the licensee's commitments and scheduled modifications, meets the guidelines contained in Appendix A to BTP 9.5-1.
Until the committed fire protection system improvements are operational, we consider the existing fire detection and suppression systems; the existing barriers between fire areas; improved administrative procedures for 9-3
I control of combustibles and ignition sources; the trained onsite fire brigade; the capability to extinguish Hre manually;.and the fire protection technical specifications provide adequate protection against a fire that would threaten safe shutdown.
On this basis we conclude that Salem Unit 2 is acceptable for full power operation subject to license conditions listed below which will assure the timely completion of required modifications.
Full power license conditions:
1.
Prior to exceeding five pe; cent rated thermal power, PSE&G shali:
a.
Wrap thc primary feeds for 125 volt DC control power to the 4160 volt, 460 volt and 230 volt switchgear located above the 4160 volt switchgear at elevation 64.
b.
Take the following corrective action for deficiencies associated with the alternative shutdown capability:
(1) Coordinate operating procedures to ensure application of the appropriate alternative method when dictated by plant rii-cumstance or conditions.
(2) Provide direction to the Senior Shift Supervisor as to when control room evacuation is dictated; provide direction as to which procedures, keys, operator aids, and equipment will be required in the new control location; and provide a discussion of shift organi::ation and personnel deployment for remote operation.
(3) Provide for pre-staging of the special equipment or tools required by local operating procedure;. These items include hand tools, pneumatic jumpers, prepared electrical jumpers, and diesel control power cables.
(
(4) Provide a means to maintain system status once local operation has been initiated and to restore normal function to disturbed i
control systems.
(5) Provide guidance for ensuring or verifying adequate shutdown margin when outside the control room.
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(6) Provide a means to obtain direct temperature information from the hot and cold legs during cooldown as part of the ;1 ternate shutdown procedures.
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(7)
Install adequate measures to ensure that effective communications with alternative shutdown control stations can be established.
(8)
Increase minimum staffing level, on shift, to include the following individuals; 2 Senior Reactor Operators, 4 Nuclear Control Operators,10 Equipment / Utility Operators, the Shift Technical Advisor, and one maintenance electrician.
2.
PSE8G shall install adequate 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> emergency lighting, independent of plant power systems, at all locations which may be required to be manned during the alternate shutdown procedure as well as at all avenues of entrance to and egress from those areas. The emergency lighting shall be installed prior to exceeding fire percent power or a continuous fire watch shall be established in the relay room and sufficient dedicated portable battery powered lighting will be provided for the operating personnel necessary to achieve cold shutdown.
3.
By July 31, 1981, PSE8G shall:
Modify or extend existing barriers in 4160 volt switchgear room in a.
order to protect redundant control and power cables currently located above the fire barrier; b.
Provide a one-hour barrier for the cable trays associated with the turbine-driven auxiliary feedwater pump in the auxiliary feedwater pump room; c.
Provide a one-hour barrier around one of the redundant cables associcted with power, instrumentation, and control for the diesel generators (located in the proximity of the diesel generators) where separation is less than 20 feet.
d.
Provide smoke detectors in the area of the power feeds to redundant diesel generators in the 4 ft. wide hallway near the waste gas tanks.
e.
Wrap redundant cables supplying power to the 4 kv switchgear from the diesel generators in the 4 kv switchgear room where separation n i
less than 20 feet.
l f.
Wrap redundant cables supplying power from 230 volt switchgear to the battery chargers where separation is less than 20 feet.
g.
Raise barriers separating equipment needed for shutdown so that the top of the barrier is above the top of the redundant raceways or wrap both redundant raceways in the following areas: 460-230 volt switchgear,125 volt D-C switchgear, the valve motor control centers located in the electrical penetration area, and the pressurizer heater buses located in the electrical penetration area.
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h.
Extend barrriers in an "L" shape con;iguration for the following equipment: the 4160 volt switchgear. 460-230 volt switchgear, the 125 Y DC switchgear, the valve motor control centers, and the pressurizer heater buses.
1.
Wrap one of the redundant power cables from the diesel generators located in the fuel oil storage tank room.
- j. Provide or:e hour fire barrier for the 207 panel or the turbine driven auxiliary feedwater control cabinet.
k.
Provide a one hour fire barrier for the remote shutdown panel.
1.
PSE&G shall review its Fire Interaction analysis for any additional areas impacted by the assumptions and criteria identified in the NRC review team's repcrt as being inconsistently applied or with which the team did not concur. PSE&G shall report the results of this review to the NRC and complete all additional corrective actions by July 31, 1981.
4.
By June 5,1981, PSE8G shall re-route the alternate shutdown power feed in order to provide protection for this cable from a fire affecting the normal instrument trains. Until this modification is complete a continuous fire watch shall be stationed in the elevation 84 switchgear room. During the perioo when new leads are being landed, and r.3 power feed to the alternate shutdown instruments is available, an additional fire watch shall be stationed continuously in the Relay Room.
5.
By July 15, 1981, PSE&G complete final engineering verification of the fire protection analysis and corrective actions.
6.
During the performance of Startup Procedure SUP 82.5, Shutdown From Outside Control Room, PSE&G shall satisfactorily demonstrate the following additional operations:
a.
Local start of diesel generator using alternative control power source.
b.
Local operation of 4 KV breaker.
c.
Local start of the containment fan cooler unit.
d.
Local operation of a motor operated and an air operated valve.
e.
Local control of charging.
7.
Prior to July 31, 1981, PSE&G shall complete all requi-d cable wrapping.
The Office of Inspection and Enforcement will monitor the licensee's progress and verify the completion of the open fire protection action items identified in the license conditions specified above.
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A ATTACHMENT A TO SECTION 9.7 0F SUPPLEMENT 6 i
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'o UNITED STATES
~,,
NUCLEAR REGULATORY COMMISSION o
,E WASHINGTON, D. C. 20555
\\*....
February 20,*1981 TO ALL POWER REACTOR LiuENSEES WITH PLANTS LICENSED PRIOR m JANUARY 1,1979
SUBJECT:
FIRE PROTECTION RULE (45 FR 76602, NOVEMBER 19, 1980) -
Generic Letter 81-12 Paragraph 50.48(b) of 10 CFR Part 50, which became effective on February 17, 1981, requires all nuclear plants licensed to operate prior to January 1,1979 to meet the requirements of Sections III.G, III.J and III.0 of Appendix t to 10 CFR Part 50 regardless of any previous approvals by the Nuclear Regulatory Comission (NRC) for alternative design features for those items. This would require each licensee to reassess all those areas of the plant "... where cables or equipment, including associated non-safety circuits, that could prevent operation or cause maloperation due to hot shorts, open circuits or shorts to ground or (sic) redundant trains o! tystems necessary to achieve and maintain hot shutdown conditions are located within the same fire area outside of primary containment..."* to determine whether the requirements of Section III.G.2 of l
Appendix R are satisfied.
If not, the licensee must provide alternative shutdown capability in conformance with Section III.G.3 or request an exemption if there i
is some justifiable basis.
Paragraph 50.48(c)(5) requires that any modifications that the licensee plans in order to meet the requirements of Section III.G.3 of Appendix R must be reviewed and approved by the NRC. This paragraph also requires that the plans, schedules and design descriptions of such modifications must be submitted by March 19,*1981. To expedite our review process and reduce the number of requests for additional information with regard to this review, we are enclos-irig two documents which specify the information that we will require to conplete our reviews of alternative safe shutdown capability. Enclosure 1 is " Staff Position Safe Shutdown Capability". This document was originally sent to you in late 1979. Section 8 specifies the information required for staff review.
If you have already submitted any of the information required, you need only reference that previous submittal. indicates the additional information needed to ensure that associated circuits for alter-native safe shutdown equipment is included in your reassessment ana in our review.
If you made no modifications that were required to provide alternative safe shutdown capability and if your reassessment concludes that alternative safe shutdown capability in accordance with the provisions of Section III.G.3 is not necessary, you do not have to provide the information requested by these Enclosures.
S
- Quoted from Sec+1nn III.G.2 of Appendix R to 10 CFR Part 50. Note that the "or" preceding " redundant trains" is a typographical error and should read "of redundant trains".
9-9 Finally, we request thtt as part of your submittal of plans and schedules for meeting the provisions of Paragraphs (c)(2), (c)(3) and (c)(4) of 10 CFR 50.48 as required by Paragraph 50.48(c)(5), you include the results of your reassessment of the design features at your plant for meeting the require-ments of Sections III.G, III.J and III.0 of Appendix R to 10 CFR Part 50.
This detailed information need not acconpany the design description that must be submitted by March 19, 1981. However, we request that it be submitted as soon as possible, but no later than May 19, 1981.
This request for information was approved by GA0 under a blanket clearance number R0071 which expires September 30, 1981. Conments en burden and dupli-cation may be directed to the U. S. General Accounting Office, Regulatory Reports Review, Room 5106, 441 G Street, N. W., Washington, D. C.
20548.
Sincerely.
L Darrel G. (isenhut, Diiec or Division of _icensing Office of Nuciear Reactor Regulation
Enclosures:
1.
Staff Positior 2.
Request for Additional Information cc w/enclostrres:
See next page t
9-10
STAFF POSITION SAFE SHUTDOWN CAPASILITY Staff Conc,e3 During the staff's evaluation of fire protection programs at operating plants, one or more specific plant areas may be identified in which the staff does not have adequate assurance that a postulated fire will not damage both redundant divisions of shutdown systems.
This lack of assurance in safe shutdown capability has resulted from one or both of the following situaticns:
- Case A: The licensee has not adequately identified the systems and components required for safe shutdown and their location in specific fire areas.
- Case B: The licensee has not demonstrated that t.he fire protection for specific plant areas will prevent damage to both redundant divisions of safe shutdown components identified in these areas.
For Case A, the staff has ' required that an adequate safe shutdown analysis be performed. This evaluation includes the identification of the systems required for safe shutdown and the location of the system components in the plant. Where it is determined by this evaluation that safe shutdown components of both redundant divisions are located in the same fire area, the licensee is required to demonstrate that a postulated fire will not damage both divisions or provide alternate shutdown capability as in Case 8.
For Case B, the staff may have required that an alternate shutdown capability be provided with is independent of the area of concern or the licensee may have proposed such a capability in lieu of certain additional fire protection modifications in the area. The specific modifications associated with the area of concern along with other systems and equipment already independent of the area form the l
alternate shutdown capability. For each plant, the modifications needed and the combinations of systems which provide the shutdown functions may be unique for each critical area; however, the shStdown functions provided should maintain plant parameters within the bounds of the limiting safety consequences deemed acceptable for the design basis event.
1 Staff Pcsition_
Safe shutdown capability should be demonstrated (Case A) or alte-nate shutdown capability provided (Case B) in accordance with the guidelines provided below:
- 1. Desien Basis Event l
Tne design ' asis event for considering de need for alternate shut:cwn is a postulated fi e in a s:er,ific fire area containing redundant safe shutdown cables /eouip: ent in close proximity where it nas been determined that fire protecticn :neans cannot assure that safe shut:cwn capability will be - eserved. Twc cases shculd be c:nsidered: (1) offsite power is available; and (2) offsitt!
power h net available.
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_ 2. Limitine Safety Consecuences and Recuired Shutdown Functions 2.1 No fission product boundary integrity shall be affected:
a.
No fuel clad damage; b.
No rupture of any primary coolant boundary; c.
No rupture of the containment boundary.
2.2 The re. actor coolant system process variables shall be within those predicted for a loss of normal ac power.
2.3 The alternate shutdown capability shall be able to achieve and maintain suberitical conditions in the ranctor, maintain reactor coolant inventory, achieve and mairtain hot standby
- conditions (hot shutdown
- for a ENR) for an extended period of time, achieve cold shutdown
- conditions within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and maintain cold shutdown conditions thereafter.
As defined in the Standard Technical Specifications.
- 3. Performance Goals 3.1 ihe reactivity control function shall be capable of achieving and maintaining cold shutdown reactivity conditions.
3.2 The reactor coolant makeup function shall be capable of maintaining the reactor coplant level above the top of the core for BWR's and in the pressurizer for PWR's.
i 3.3 The reactor heat removal function shall be capable of achieving and maintaining decay heat removal.
3.4 The process monitoring function shall be capable of providing direct readings of the process variables necessary to perfom and control the above functions.
l 3.5 The supporting function shall be capable of providing the l
process cooling, lubrication, etc. necessary to pemit the operation of the equipment used for safe shutdown by the systems identified in 3.1 - 3.4.
3.6 The equipment and systems used to achieve and maintain hot standby conditions (het shutdown for a SWA) should be (1) free of fire damage; (2) capable of maintaining such conditiens for an extsnded time g,eriod longer thea 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if the ecuipment recuired to achieve and maintain cold shutdown is not available due to fire damage: and (3) cacable of beino powered oy an ensite emergency power system.
3.7 The ecuipment and systems used to achieve and maintain cold shutdown concitions should be either free of fire damage or the ' ire damage to suen systems snoulc be limited such that recairs can be~made and cold shutdown conditiens senieved witnin 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Equipment and systems used prior to 72 hcurs l
after the fire shculd be cacable of being powered by an onsite j
emergency pcwer system; those used after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> may be powered by l
9-12 l
l-
l u
l 1,
l offsite power.
l 3.8 These systems need not be designed to (1) seismic category I l
criteria; (2) single failure criteria; or (3) cope with other plant accidents such as pipe breaks cr stuck valves f
(A::pendix A BTP 9.5-1), except these portions of these systems which interface with or impact existing safety systems.
I
- 4. PWR Eouipment Generally Necessary For Hot Standby (1) Reactivity Centrol Reactor trip capability (scram). Beration :apabili:y e.g.,
charging pump, makeup pump or high pressura injection pump l
taking suction from concentrated borated ater supolies, and letdown systec if required.
(2) Reacter Coolant Makeue i
Reacter coolant makeup capability, e.g., charging pumps or the high pressure injection pumps.
Pcwer caerated relief
(
valves may be recuired to reduce pressure to allow use of the high pressurt injection pumps.
l (3) Reacter Coolant System Pressure Centrol i
React:r pressure centrol capability, e.g., charging pumps or pressurizer heaters and use of the letdown systems if required.
(4) Deca'y Heat Remeval Decay heat removal capability, e.g., pcwer c:erated relief l
valves.(steam generator) or safety relief valves for heat removal with a water supply and er:ergency or zuiliary feedwater pumes for makeup to the steam generator. Service i
water or other pumps may be required to provide water for auxiliary l
feed pumo suction if the condensate storage tank capacity is not adequate for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
(5) Process Monitorine Instri.mentatien Process monitoring capability e.g., pressuri:er pressure and level, steam generator level.
(6) Sue: ort.
The ecui; ment recuired to sur:crt c:eration of the above cescribed snutd wn ecui; ent e.,.....-.cnent c cling water servi:e water, et:. acc cnsite : er f. urces ( AC, DC) with i
their asscciated electrical cistributi:n system.
l 9-13
4-l
- 5. PWR Ecuiement Generally Necessary For Cold Shutdewn*
(1) Reactor Coolant System Pressure Reduction to Residual Heat Removal System' (RnR) Cacacility Reactor coolant system pressure reduction by c:eldewn using steam generator power operated relief valves or atmospheric dump valves.
(2) Decay Heat Removal Decay heat removal capability e.g., residual heat removal system, compenent cooling water system and service water system to removal heat and maintain cold shutd:wn.-
(3) Succort Support capability a..g., onsite power sources (AC & DC) er offsite after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and the associated electrical distributien system to supply the abeve equipnent.
Equipment necessary in addition to that already provided to maintain hot stancby.
- 6. BWR Ecui ment Generally Necessary For Hot Shutdown (1) Reactivity Cen:rol Reacter trip capability (scram).
(2) Reacter teol_ar.t Makeue Reactor coolant inventory (makeup capability e.g., reactor core isolaticn cooling system RCIC) er the high pressure ceclant injection system (HPCI).
(3) Reactor Pressure Centrol and Decay Heat Removal Depressurizatien system valves or safety relief valves for dump to the suppression pool. The residual heat removal system in steam condensing mode, and service water system may also be used for heat removal to the ultimate heat sink.
(4) Sue:ressien Peel Coeline Resicual heat rem: val system (in sue:ression ;ool cooling i
mece) service water system to maintain het snutd:wn.
l (5) Pr: cess M:nitorine i
Frecess m: nit: ring ca:acility e.g., react:r vessel level j
anc pressure and su; ressi:n occi tem:erature.
9-14 TT gmOW-T+
wt=---
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veer-
-,e---%*t--F-we=-
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eq=g
-+ew
+p F-T-
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(6) Support '
Support capability e.g., ensite power source (AC & DC) and their associated distribution systems to provide for the shutdown equipment.
- 7. SWR Ecutoment Generally Necessary For Cold Shutdown
- At this point the equipment necessary for hot shutdown has reduced the primary system pressure and temperature to where the RHR system may be placed in service in RHR cooling mode.
(1) Decay Heat Removal Residual heat removal system in the RHR c:oling mode, service water system.
l (2) Suecort Onsite sources (AC & DC) or offsite after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and their associated distribution systems to provide for shutdown equipment.
Equipment provided in addition to that for achieving het shutdown.
- 8. Infomation Recuired For Staff Review (a) Description of the systems or portions thereof used to
' rovide the shutdown capability and modifications required to achieve the alternsta shutdown capability if required.
(b) System design by c'rawings which show normal and alternate shutdown control and power circuits, location of components, and that wiring which is in the area and the wiring which is out of the area that required the alternate system.
(c)
Demonstrate that ::hanges to safety systems will not degrade safety sys: ems.
(e.g.
new isolation switches l
and control switchies should meet design criteria and standards in FSAR for electvical equipment in the system that the switch is to be installed; cabinets that the switches are to be mounted in should also meet the same criteria (FSAR) as other safety related cabinets and panels; to avoid inadvertent isolation from the control room, the isolation switches should be keylocked, or alar:ned in the control roon if in the " local" or " isolated" position; periccic checks should be made to verify switch is in the procer position for normal coeration; and a single transfer switch or other new device should not be a source for a single failure to cause los s of redundant safety syste:r.s).
(d)
Demonstrate that wiring, inclucing cower sources for the c:ntrol circuit and equi: ment :: era:icn for the alternate shutdcwn metnod, is inoependent of ecuiprent wiring in t.5e area to be avcided.
9-15
_ _ (e)
Demonstrate that alternate shutdown power sources, including i
all breakers, have isolation devices on control circuits that are routed, through the area to be avoided, even if the breaker is to be operated manually.-
)
(f)
Demonstiate that licensee procedure (s) have been developed which describe the tasks to be performed to effect the shutdown me thod. A sumary of these procedures should be submitted.
(g)
Demonstrate that spare fuses are available'for control circuits where these fuses,may be required in suppiying power to control circuits used for the shutdown method and may be blown by the effects of a :able spreading room fire. The spare fuses should be locat2d convenient to the axisting fuses. The shutdown proce:ure should inform the operator to check these fuces.
(h) Demonstrate that the manpower required to perform the shutdown functions using the procedures of (f) as well as to provide fire brigade members to fight the fire is available as required by the firc brigade technical specifications.
(1) Demonstrate that adequate acceptance tests are performed.
These should verify that: equipment operates from the local control station when the transfer or isolation switch is placed in the " local" position and that the equipment cannot be operated from the control room; and that equip-ment operates from the control reem but cannot be operated at the local contro1 ~ station when the trant'e* or isolation switch is in the " remote" position.
(j) Technical Specifications of the surveillance rtquirements and limiting conditions for operation for that equipment not already covered by existing Tech. Specs. For exagle, if new isolation and control switches are added to a service water system, the existing Tech. Spec. surveillance require-ments on the service water system should add a statement similar to the following:
"Every third pump test should also verify that the pump starts from the alternate shutdown station after moving all service water system isolation switches to the local control position."
(k) Demonstrate that the systems available are adequate to perform tne necessary shutdewn functions. The functions requireo theuld be based on previous analyses, if possible (e.g.,
in the FSAR), such as a loss of nornal a.c. power or shutdown on a Group I isolation (BWR). The equipment required for the i
f ahernate ca: ability shculd be the same or equivalent to that relied en it the above analysis.
l 9-16
-~..
T (1)
Demonstrate that repair procedures for cold shutdown systems are developed and material for repairs is maintained on site.
9-17
~ REQUEST FOR ADDITIONAL INFORMATION J,
1.
Se:: tion III.G of Appendix R to 10 CFR Part 50 requires cabling for or associated with redundant safe shutdown systems necessary to achieve and maintain hot shutdown conditions be separated by fire barriers having a three-hour fire rating or equivalent protection ( see Section III.G.2 of Appendix R). Therefore, if option III.G.3 is chosen for the protection of shutdown capability cabling required for or associated with the alternative method of hot shutdown for each fire-area, must be physically spearated_by the equivalent of a three-hour rated fire barrier from the fire area.
In evaluating alternative shutdown nethods, associated circuits are circuits that could prevent _ operation or cause maloperation of the alternative trahl j
which is used to achieve and maintain hot shutdown condition'due to fire induced hat shorts, open circuits or shorts to ground.
Safety related and non-safety related cable's that are associated with the equipment and cables of the alternative, or dedicated method of' shutdown are those that have a separation from the fire area less than that required I
by Section III.G.2 of Appendix R to 10 CFR 50 and have either (1) a comon i
power source with the alternate shutdown equipment and the power source is not electrically protected from the post-fire shutdown circuit of concern 4
by coordinated circuit breakers, fuses or similar devices, (2) a connection to circuits of equipment whose spurious operation will adversely affect i
the shutdcWn capability, e.g., RHR/RCS Isolation Valves, or (3) a comon i
enclosure, e.g., raceway, panel, function box, with alternative shutdown cables and are not electrically protected from the post-fire shutdown circuits of concern by circuit breakers, fuses or similar devices.
For each fire area where an alternative or dedicated shutdown method, in accordance with Section III.G.3 of Appendix R to 10 CFR Part 50, is l
provided by proposed modifications, the following information is required 1
i to demonstrate that associated circuits will not prevent operation or cause maloperation of the alternative or dedicated shutdown method:
I I
A.
Provide a tab?e that lists all equipment including instrumentation and support system equipment that are required by the alternative or dedicated method of achieving and maintaining hot shutdown.
B.
For each alternative shutdown equipment listed in 1.A above, provide a table that lists the essential cables (instrumentation, control and power) that are located in the fire area.
C.
Provide a table %.:t lists safety related and non-safety related cables associated with the equipment and cables constituting the alternative or dedicated method of shutdown that are located in the fire area.
D.
Show that fire-induced failures of the cables listed in B and C above will not prevent operation or cause maloperation of the alternative or dedicated shutdown method.
j E.
For each cable listed in 1.B above, provide detailed electrical j
schematic drawings that show how each cable is isolated from the j
fire area.
9-18
_.,-._ _,_ _.~_..___ _ _ _ _. _ _ -. _ ____._._ _ _ _ - _ - -.
2.
The residual heat removal system is generally a low pressure system that interfaces with the high pressure primary coolant system.
To preclude a LOCA through this interface, we require compliance with the recommenda-tions of Branch Technical Position RSB 5-1.
Thus, this interface most likely consists of two redundant and independent motor operated valves.
' ase two motor operated valves and their associated cable ray be subject.
60 a single fire hazard.
It is our concern that this single fire could cause the two valves to open resulting in a fire-initiated LOCA through the subject high-low pressure system interface.
To assure that this interface and other high-low pressure interfaces are adequately pro-tected from the effects of a single' fire, we require the following information:
A.
Identify each high-low. pressure interface that uses redundant electrically controlled devices (such as two series motor operated valves) to isolate or preclude rupture of any primary coolant boundary.
B.
Identify the device's essential cabling (power and control) and describe the cable routing (by fire area) from source to termination.
i C.
Identify each location where the identified cables are separated by less than a wall having a three-hour fire rating from cables for the redundant device.
D.
For the areas identified in item 2.C above (if any), provide the bases and justification as to the acceptability of the existing design or any proposed modifications.
l I
22.0 TMI-2 REQUIREMENTS 22.1 Introduction In a letter dated June 26, 1980, we advised all applicants for construction permits and operating licenses of the Commission's guidance regarding the requirements to be met for current operating license applications.
The requirements are derived from NRC's Action Plan (NUREG-0660) and are' found in NUREG-0694, "TMI-Related Requirements for New Operating Licenses."
The requirements discussed in NUREG-0694 were listed in four categories:
those required for fuel loading and low power testing; those required for full-nower operation; those requiring inteirnal NRC action; and those required to be implemented by a certain date.
Subsequently, by letter dated October 31, 1980, a compilation of those THI-related items that have been specifically approved by the Commission for implementation was issued to all licensees and applicants.
This letter transmitted NUREG-0737, " Clarification of THI Action Plan Requirements," which included information about schedules, applicability, method of implementation review, submittal dates, and clarification of technical positions.
Requirements for fuel loading and low poder testing were addressed in Part II of Supplement No. 4 to the Salem Nuclear Generating Station Unit 2 Safety Evaluation Report.
Supplement 5 addressed full power requirements and dated requirements of NUREG-0694 as clarified and supplemented by NUREG-07?'. This t
supplement provides an updated status of the full power requirements for item i
III.A.1.1.
Upgrade Energency Preparedness.
l The applicable full power requirement is discussed below and follows the numbering sequeace used in NUREG-0694 and NUREG-0737. The staff's review of the issues described in this section are based on the explicit requirements contained in NUREG-0694 as updated in NUREG-0737.
l 22.1-1
22.2 Full Power Requirements III. Emergency Preparations and Radiation Protection III.A.1.1 Upgrade Emergency Preparedness Position Provide an emergency response plan in compliance with NUREG-0654, Rev.1 (November 1980) " Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants."
NRC will give substantial weight to FEMA findings on offsite plans in judging the adequacy against NUREG-0654. Perform an emergency exercise to test the integrated capability and a major portion of the basic elements existing within emergency preparedness plans and organizations.
This requirement shall be met before issuance of a full-power license.
Discussion and Conclusions Based upon our review, as documented in this section, of the licensee's plans and procedures, the NRC and FEMA evaluation of the joint exercise, and our review of the FEMA findings, we find that the state of onsite and offsite emergency preparedness provides reasonaute assurance that adequate protective measures can and will be taken in the event of a radiological emergency.
a.
Emergency Plan Preparation The applicant has corrected the deficiencies in the emergency plan which were previously identified in Aopendix F to Supplement 5 of the Salem Safety Evaluation Report.
Based on our review, we conclude that the Salem emergency plan, together with the commitment from the licensee in their letter dated May 7,1981 meets the planning standards in 10 CFR 50.47, the requirements of Appendix E to 10 CFR 50, and the guidance set forth in NUREG-0654/ FEMA-REP-1,
" Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants,"
Revision 1, November 1980.
The applicant's letter of My 7,1981 commits to the following conditions:
(1) Provide meteorological and dose assessment remote interrogation capability to meet the criteria of Appendix 2, NUREG-0654, Revision 1 as.follows:
(a) a functional description of upgraded capabilities by January 1,1982, (b) installation of hardware and software by July 1,1982 provided that NRC approval is received by four months prior to that time and (c) full operational capability by October 1,1982.
22.2-1
(2) Provide substantiation that the back-up source of meteorological information from the NWS Office, Greater Wilmington Airport adequately characterizes the site conditions with respect to wind direction and wind speed by July 1,1981.
(3) Provide substantiation that uncertainties associated with plume trajectory prediction, associated with the occurrence of sea-land breeze circulations within the plume exposure pathway zone, are compatible with the planned recommendations for protective actions that would be based upon such projections by July 1,1981.
The Federal Emergency Management Agency (FEMA) has provided interim findings
( Appendix H) on the State and local emergency response plans. FEMA found based on a joint exercise, site specific to the Salem Nuclear Plant, that the stated objectives of the exercise were generally achieved even though the scenario had some limitations; end, that the deficiencies noted in the exercise can be readily corrected with additional SOPS, drills and training.
In summary FEMA concluded that the deficiencies which currently exist in the state of Radiological Emergency Preparedness in the States of New Jersey and Delaware should not preclude the two states from coping with an accident at the Salem Nuclear Plant.
b.
Emergency Plan Implementation We have examined the implementation of the emergency plan and the applicant's actions in response to the deficiencies identified in a NRC letter from B. Grier to R. Eckert dated April 7,1981. By letter of April 24, 1981, the applicant committed to correct each of the aforementioned deficiencies by Hay 15, 1981 with the exception of the training program documentation, which will be completed within 120 days. Based on further discussions with the applicant in a meeting on April 23 and 24,1981, and on their connitment letter of April 24, 1981, we have reasonable assurance that deficiencies will be corrected by May 15,1981 with the exception noted above. The staff does not consider the documentation of the training program as a required item to achieve an adequate state of emergency preparedness. We consider that the current state of training is adequate to perform the essential j
functions that may be required in the event of a radiological emergency.
Based upon our review and the licensee's commitment, we conclude l
that the applicant has satisfied the Emergency Preparedness requirements specified for cortpletion prior to the issuance of a full power license.
The applicant's current state of Emergency Preparedness provides reasonable assurance that adequate protective measures can and will l
be taken in the event of a radiological emergency.
l l
22.2-2
23.0 CONCLUSION
S Based on our evaluation of the application as set forth in our Safety Evaluation Report issued in October,1974 and Supplement Nos.1-5 and our evaluation as set forth in this supplement, we conclude that the operating license can be issued to allow power operations at full rated power (3411 megawatts thermal) subject to license conditions.
We conclude that the construction of the facility has been completed in accordance with the requirements of Section 50.57(a)(1) of 10 CFR Part 50, and that construction of the facility has been monitored in accordance with the inspection program of the Commission's staff.
Subsequent to the issuance of the operating license for full rated power for Salem Nuclear Generating Station Unit 2, the facility may then be operated only in accordance with the Commission's regulations and the conditions of the operating license under the continuing surveillance of the Commission's staff.
We conclude that the activities authorized by the license can be conducted without endangering the health and safety of the public, and we reaffirm our conclusions as stated in our Safety Evaluation Report and its supplements.
23-1
APPENDIX A CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL SAFETY REVIEW January 21, 1981 Letter from licensee concerning emergency plan evacuability study January 23, 1981 Letter from licensee providing test and scheuule information concerning environmental qualification of safety-related equipment.
January 26, 1981 Letter from licensee forwarding " Environmental-Qualification Review Report," Revision 1, Volume 1 (proprietary and non-proprietary).
January 29, 1981 Letter from licensee discussing modifications and remedial actions with regard to masonry walls.
January 30, 1981 Issuance of Supplement No. 5 to Safety Evaluation Report February 3, 1981 Letter to licensee forwarding pages omitted from December 22 transmittal concerning control of heavy loads.
February 4, 1981 Letter from licensee requesting exemption from proposed technical specifications concerning testing of snubbers.
February 6, 1981 Letter from ifcensee transmitting, " Instrumentation for Detection of Inadequate Core Cooling" (proprietary and non-proprietary).
February 6, 1981 Letter from licensee providing information on reactor vessel level indicating system.
February 9, 1981 Letter to licensee advising that proposed audible alarm level is acceptable.
i l
February 9, 1981 Letter from licensee forwarding New Jersey Radiological Emergency Response Plan.
February 10, 1981 Letter from licensee transmitting monthly operating report for January 1981.
February 10, 1981 Letter from licensee requesting extension of license expiration date.
l February 10, 1981 Letter to licensee concerning seismic qualification of auxiliary l
feedwater systems l
i i
l 1
A-1
February 11, 1981 Letter from licensee requesting extension to March 16 for submittal of Training and Qualification Plan.
February 18, 1981 Letter to licensee concerning post-THI requirements for Emergency Operations Facility February 20, 1981 Letter to licensee concerning "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking," NUREG-0619 February 23, 1981 Letter from licensee transmitting Revision 3 of "Environmentai Qualification Review Report," Volumes 1 & 2 (proprietary and non-proprietary)
February 25, 1981 Letter to licensee concerning emergency procedures and training for station blackout events.
February 26, 1981 Issuance of Amendment 5 to DPR-75 to extend term of license to April 18, 1983.
February 27, 1981 Letter to licensee transmitting request for additional information.
Hard 5, 1981 Letter to licensee concerning functional criteria for emergency response facilities.
March 6, 1981 Letter to licensee forwarding preliminary results of environmental qualification of safety-related electrical equipment.
March 10,1981 Letter to 'icensee transmitting clarification of staff's handling of proprietary information on environmental qualification of Class IE electrical equipment.
March 13,1981 Letter from licensee forwarding Submittal 2 of Security Training and Qualification Plan.
March 13,1981 Letter from licensee transmitting Annual Financial Report for 1980.
l March 18,1981 Letter to licensee advising that cable tray fire barrier is acceptable.
March 19,1981 Letter from licensee concerning environmental qualification ~
of safety related electrical equipment.
March 19,1981 Letter from licensee advising of proposal for compliance with 10 CFR Part 50, Appendix R concerning fire protection.
A-2 1
March 24,1981 Letter from licensee transmitting revised pages for Security Training and Qualification Plan.
March 24, 1981 Letter to licensee transmitting request for additional information on fire protection.
March 26, 1981 Meeting with licensee to discuss proposed technical specifications.
March 27,1981 Letter to licensee concerning proposed license condition on protection against loss of auxiliary feedwater pump suction flow.
March 27,1981 Letter to licensee requesting best estimate of monthly cost, including costs for replacement energy and capital expense, to maintain unit in inactive status while awaiting full power license.
April 2,1981 Letter from licensee transmitting information concerning its compliance with Regulatory Guide 1.97.
April 3,1981 Letter from licensee in response to March 27, 1981 letter regarding costs of replacement energy and capital expense.
April 7,1981 Letter to licensee forwarding required actions resulting from emergency planning appraisal.
April 13,1981 Meeting with licensee to discuss Salem's compliance with 10 CFR Part 50, Appendix R.
April 14,1981 Letter from licensee transmitting LER 81-03/03L April 16,1981 Letter from licensee transmitting updated Q list.
April 16,1981 Letter to ifcensee transmitting request for information on control system failures.
April 20,1981 Letter from licensee providing confirmation of implementation dates for upgraded Emergency Response Facilities.
l April 21,1981 Letter to licensee requesting that inservice inspe: tion boundary diagrams be sent to Battelle Pacific Northwest l
Laboratory.
April 22,1981 Letter from licensee concerning compliance with Appendix l
R - Item III.L April 23,1981 Letter from 11censee concerning containment minimum pressure setpoint.
April 24,1981 Letter from licensee confirming actions to be taken in response to emergency planning appraisal.
A-3
April 24,1981 Letter from FEMA to NRC transmitting FEMA findings on Salem emergency preparedness.
April-29,1981 Letter from licensee transmitting Annual Reports for 1980 May 1, 1981 Letter from licensee forwarding "Startup Test Report" May 4, 1981 Letter from licensee concerning shift manning.
May 5,1981 Letter to licensee confirming fire protection' actions to be taken by licensee.
May 5,19?1 Letter to licensee requesting response to emergency planning open action items.
MAy 7, 1981 Letter from licensee confirming actions to be taken for emergency planning.
MAy 11,1981 fleeting witi. licensee to review its cable interaction study.
1 May 12,1981 Letter for licensee transmitting updated "Q" list.
May 14,1981 Letter from licensee providing response to NRC staff fire protection review.
A-4
s.
APPENDIX G REVIEW 0F PSE&G's CABLE SEPARATION STUDY i
G-1 1
p* "2w,#
j
,' h UNITED STATES.
[v 7;
NUCLEAR REGULATORY COMMISSION
-)
m S..
5
- y WASHINGTON, D. C. 20555 4,
./
WAY 1 1 1984 l
Docket Nos.:
50-272/311 APPLICANT: Public Service Electric & Gas Company.
FACILITY:
Salem, Units 1 and 2
SUBJECT:
SUMMARY
OF MEETINGS AND SITE VISIT TO REVIEW THE PSE&G CABLE INTERACTION STUDY A series of meetings were held from April 30,1981 to May 6,1981 at the Salem Station to review PSE&G's cable-interaction study. An exit interview was held on May 7,1981 to discuss the findings of the review. These findings are -found in the attached report.
P Wg&w anis Kerrigan, Proje M Manager Licensing Branch No. 3 Division of Licensing
Enclosure:
As stated l
I f
I i
G-3
MAY.1.1.1981 j
1 i
REPORT ON PSE&G CABLE SEPARATION STUDY J. Kerrigan G. Meyer L. Norrholm i
R. Pallino J. Knox J. Behm j
B. Mann j
G-4 I
REVIEP OF PSEAG CABLE SEPARATION STUDY As part of the overall fire protection review, the staff reviews the ceble separation study performed by the licensee to confim that there is reasonable assurance that a single fire would not destroy the redundant components of systems necessary for shutdown.
In order to expedite the conduct rf this review for the Salem Station, a team of people was sent to the plant. The team consisted of:
- 1) Janis Kerrigan, team leader
- 2) Gary Meyer, Project Manager for Unit 2
- 3) Lief Norrholm, Senior Resident Inspector
- 4) Ralph Pallino, Repional Inspector
- 5) John Knox, NRC staff electrical expert
- 6) Jim Behm, fire protection consultant
- 7) Bernie Mann, NRC staff systens expert The objectives of the team were to:
- 1) make a finding on the adequacy of the cable separation study and the program used to implement the results of that study, and
- 2) make a finding on the adequacy of the corrective actions implemented
~
as a result of the cable interact' ion program. These findings should concentrate on the adequacy of the fire protection measures on an inisrim basis. The adequacy of the neasures on a long tem basis will be covered by the staff in its review of the licensee's compliance with App. R.
G-5
_2_
I. Evaluation of Program Implementation In order to evaluate the adequacy of the implementation of the licensee's -
fire protection program, we followed a number of. systematic review steps.
Those steps and our conclusions are presented below.-
First, we evsluated whether the systems considered and identified by the licensee in his program are adequate to bring the plant to hot shutdown, to maintain hot shutdown for either short or long time periods, and to bring the plant-to cold shutdown. Based on discussions with the licensee, we conclude that there is reasonable assurance that the systens identified exceed the minimun number required to maintain hot shutdown and to bring the plant to safe cold shutdown given a design bases fire.
Second, we evaluated whether the equipment and cables associated with each system were identified and are of a sufficient number to assure systen functionability.
Based on a 50 percent audit,. piping and instrument drawings and discussions with the applicant, we conclude that there is reasonable assurance that equipment and cables have been identified that exceed the minimum number required to assure system functionability.
Third, we evaluated whether the licensee adequately identified the routing of cables throughout the plant. Based on a 50 percent audit, discussions l
with the licensee, computer printouts of cable routing schedules, physicel G-6
-m e,
equipment and raceway layout drawings, and actual cable;racqsay-tracing
~
during plant walkthroughs, we conclude that there is reasonable assurance
~ that cable routing was adequately identified.
Fourth, we evaluated whether the licensee's program identified' the specific equipment and cables requiring protection from a design basis fire. Based on a 50 percent audit, discussions with the applicant, and plant walk throughs, we conclude that there is reasonable assurance that equipment and cables requiring additional protection were identified.
The final step of the licensee's program (overall program verificatien) has not yet, been completed. OIE will moniter the licensee's progress in this area.
The team t.erefore concludes that the cable separation program for the Salem Station is acceptable.
i s
G-7
r
,,.i
~
I,I. Adequacy of Corrective Actions In order to accomplish our second objective, which was to evaluate the adequacy of the corrective actions taken, the tean performed an extensive field audit.
Based on that audit, the team found that for nany areas of the plant the fire protection measures implenented at the Station met or_ exceeded NRC requirements.
However, we did find that sone additional fire protection measures would be required in some areas.
In reaching our findings, we were able to trace the particular fire protection measures implemented back to the basic -6ssumptions and criteria used by the licensee. (See Table 1). We then divided these criteria into 5 basic categories:
- 1) Criteria that had no impact on our review and therefore the acceptability of these criteria was not addressed by the team.
(Criteria 2,9,12).
- 2) Criteria which the team agrees with and which the team found no examples of the criteria not being met.
(Criteria 3, 6, 7, 8A, 11, 13, 14c).
- 3) Criteria which the tean agrees with and which the team found examples of the criteria not being met (Criterion 1). The tean understands that the final program verfication is not corplete, and we realize that at least some of the examples would have been picked up.
For items in this category, the team found that additional fire protection measures would be necessary.
- 4) Criteria with which the team did not agree.
The team concluded that the fire protecticn measures implemented using the criteria in this category were not adequate and that additional fire protection neasures would be necessary.
(Criteria 4, 8b,14a,14b).
G-8
- 5) One criterion (10) which dealt with areas of the plant which require alternate shutdown capability.
A.
Category 1 Criteria In regard to Criterion 2, "The intensity of the postulated fire decreases with height provided that no combustibles are present within the zone of influence," Criterion 9, " Cable-initiated fires are not credible," and Criterion 12, "An exposure fire inside containment is not credible," we conclude that these criteria had no inpact on this evaluation.
Thus their acceptability will not be addressed in this report.
B.
Category 2 Criteria In-regard to Criterion 3, "If horizontal filled cable trays are present within and/or above the 20 foot diameter zone of influence of the fire, the zone of influence is extt.nded out, in a cone shape configuration to include these combustibles," Criterion 6, " Cable will burn, but does not support combustion.
Therefore, there is assumed to be no further propagation of fire along a horizontal cable tray once the fire source is removed,"
Criterion 7, " Conduit, although not considered to be combustible, was also not considered to provide a fire barrier to its enclosed cables," Criterion 8A, "The primary fire suppression system in an affected area is assumed to fail,"
Criterion 11, " Manual fire-fighting techniques only are required for the control room since the control roon is constantly manned," Criterion 13, "All auxiliary feedwater trains will be protected that are within the 20 foot zone of influence of the fire," Criterion 14.c, "A 1 1/2 hour barrier on ventilation ducts that go through a three hour barrier separating redundant system is an adequate protective measure", we agree with the criteria, found no examples of non-compliance with these criteria during our review and thus, conclude G-9
6-that there is reasonable assurance that the licensee.has met'these-criteria.
C; Category 3 Criteria
- 1.
Criterion 1.
'In regard to Criterion 1, "The design basis fire has a 20 faot diameter zone of influence and has a zone of influence that extends from the floor to 'the ceiling," we agree with this criterion but as a result of our review we found several areas in which the licensee did not apply _ this criterion.
(A list of. these are areas is contained in Table 2.) Two examples of this are:
- Example a: Two trains of the primary 125 DC control power to the 4160 volt, 460 volt and 230 volt switchgear-are located within 20 feet of their.
redundant counterpart above the 4160 volt switchgear at elevation 64.
The licensee indicated that the backup feed to the. switchgear could l
I be used in the event of fire, however, we,found that both the primary and backup feeds are located within 20 feet so that redundant trains
~
would be affected. The team concludes that the primary feeds to 'the switchgear need to be wrapped. The wrap for Unit 2 should be installed before exceeding five percent power and the wrap for Unit 1 should be installed within two weeks.
Example b: During the course of the staff's onsite review, one area in the 480/230 a
VAC Switchgear Roem on elevation 84' in the Auxiliary Building was identified in which a single postulated 20-foot diameter fire could potentially fail all instrument channels, including the independent safe shutdown instrumentation provided for alternate shutdown. The review team concluded that this presented an inmediate safety concern.
G-10
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s-w Accordingly, the Office of Inspection and Enforcement obtained, and documented in correspondence dated May 5,1981, a licensee committment to take immediate corrective actions. These actions included:
a.
Re-routing of the alternate shutdown power feed in order to provide protection for this cable -from a fire affecting the normal instrument
\\
trains.
This will be completed by June 5,1981 for Units 1 and 2.
b.
Immediate stationing of a dedicated, continuous fire watch in the 84' elevation switchgear room until the modification described above is completed.
c.
During the period when new leads are being landed, and no power feed to the alternate shutdown instruments is available, an additional fire watch will be stationed continuously in the Relay Room.
d.
The final engineering verification of the fire protection analysis and corrective actions, which will confirm no similar mis-routings, will be completed by June 5,1981.
l The Office of Inspection and Enforcement will confirm these actions.
For other examples falling under this category (see table 2), the team conclusion is that modifications should be completed in accordance with the licensee's cable wrap schedule.
l' l
l G-11 D.
Category 4 Criteria In regard to Criteria 4, 8.b, ~14.a, and 14.b, we do not agree with the criteria ano conclude that the fire protection measures implemented using ~the criteria are not adequate and that addit'onal fire protection should be required.. The basis for our not agreein; and the additional protection necessary is discussed below.
- 1. Criterion 4 The licensee has assumed that an exposure fire, which originates on the floor, will only have a flame height of from two to four fe'et. Also if this fire is located against one side of the fire partition barrier the licensee has assumed that there will be no horiz'ntal heat transmission across the top of the eight foot barrier. We disagree witn the licensee's assumptions for the following reasons:
1.
Transient conbustibles may be stacked against the fire partition which could produce a flame front which exceeds the height of the barrier. This is especially true with flammable liquids in which a flame front of from 10 to 12 feet nay be expected. Such a flame height will 3xpose redundant safety trtins above the barrier if they are within the zone of influence of the fire.
2.
Heat transfer will occur across the top of the fire partition well as extending outward. Also, heat will start spreading outward from its-source at the ceiling level thereby by-passing the 8 foot high barrier located on the floor. Therefore, the redundant safety system on the other side of the barrier can be exposed to the sane fire.
G-12
. 3.
A celated ccntern abuut this criterion is that the length of the installed barriers do not preclude water used in fighting the fire manually from affecting redundant equipment.
During the team audit, several areas were identified in which' the licensee applied criterion 4 (See in Table 2). The team concludes that corrective action for all areas in which criterion 4 w r applied to components needed for shutdown should be completed in accordance with the licensee's cable wrap schedule.
One example of an area in which criterion 4 was applied is discussed below. The corrective action is also discussed.
Example:
In the 4160 volt switchgear room, redundant control and power cables are located above the fire barrier separating the switchgear units.
For the reasons stated above, the team concluded that the existing barriers need to be modified or extended and that t.ne redundant cabling above the barrier needs to be protected in order to minimize the likelihood of affecting redundant equipment by either the fire itself or by water used in fighting the fire manually. These modifications should be completed on the licensee's cable wrap schedule.
l 2.
Criterion 8b 1
j Tne licensee has assumed that where redundant safety related conduit and/or 1
cable trays are within a 20 foot zone of influence of the fire that an automatic suppresion system is not necessary. We disagree with the licensee's assumptions. Within this zone of influence we expect one of the safety systems to faii as a result of the fire.
We do not consider it acceptable G-13
- to leave a fire iripinging on the only safety-division remaining until the plant fire brigade responds and manually extinguishes the fire In addition during the forty _ year life of the plant any modifications to the cable' tray may lessen its fire resistance to an unacceptable level.
The NRC fire consultant recomended tnat primary suppression systems be automatic versus manual. One area in which a manual suppression system is used for '.he protection of redundant equipment is the 460 volt switchgear room. Other areas identified by the team are included in Table 2.
We find the manual suppression system acceptable on an interin basis.' For the long term fix, we understand that the licensee has requested an exemption from the Appendix R requirement that the primary suppression system be automatic. We recommend that the NRC review of the exemption request consider the NRC fire consaltant's recommendation for the Salem Plant.
3.
Criterion 14a The licensee has assumed that for an exposure fire whi.h originates on the floor, a one hour fire rated barrier or partiticn between redundant safety related equipment and/or conduit - cable trays is sufficient to prevent damage to the one safety train. The licensee l
l has also assumed that an automatic primary fire suppression e tem i
j is not necessary since the fire brigade will respond in suffi fent l
time to prevent loss of redundant safety trains.
The NRC fire consultant recommended that primary automatic suppression 7
systems be installed where redundant cables are within the influence of c
i G-14
l the 20 foot design basis fire and protected only by a 1-hour fire barrier wrap. We find the manual hose suppression acceptable on an interim basis. For the larg term we understand that the licensee has requested an exemption from the-Appendix R requirement that barriers and automatic suppression be installed. We recommend that the NRC review of the exemption request consider the NRC fire consultant's recommendation for the Salem plant.
- 4. Criterion 14b The licensee has assbmed that for specific areas protected by an automatic suppression system, the primary fire suppression system fails. The licensee has provided a redundant automatic suppression system for these areas.
We disagree s'.h the licensee's assumptions that the redundant suppression system wi'i react fast enough to prevent damage to safety related equipment and/or cable tray and conduit. The thermal lag of the sprinkler heads has a heat sink of sufficient magnitude to prevent their operation prior to damage to safety systems. This is true of all automatic sprinkler heads.
During the team audit, several areas were identified in which the licensee applic1 :riterion 14b (listed in Table 2). The team concludes that corrective actions for all areas in which Criterion 14b was applied to components needed l
for shutdown should be completed in accordance with the licensee's cable wrap i
schedule. One example of an area in which Criterion 14b was applied is discussed below.
The corrective action is also discussed.
G-15 Exampic:
In the auxiliary feedwater pump room redundant equipment and cables are separated by less than 20 feet and are protected by redundant automatic sprinklers.
For the reasons stated above, the team concludes that a one-hour barrier should be provided for the cable trays associated with the turbine-driven auxiliary feedwater pump.
This corrective actise should be completed in accordance with the licensee's cable wrap schedule.
E.
Category 5 Criterion Criterion 10 states that " Relay room cable and equiprent and cables in the vicinity of the ceiling of the 460 V switchgear room cannot be passively protected, and, therefore, an alternate shutdown syste.n is required for' those areas."
The team agrees with this assumption.
An evaluation of the interim acceptability of the licensee's alternate shutdown system follows.
PSE&G has adopted a basic approach to shutdown in the event of fire which involves maintaining operational control from the unit control room as long as it remains habitable. For those plant areas in which a single postulated fire could affect control or operability of redundant equipment, alternative means, through local operation of available equipment, are provided in order to achieve cold shutdown. These alternative means can be 1
applied whether control is maintained in the control room or is transferred to another location in the event, considered unlikely by the licensee, tha+
occupancy of the control room becomes impossible.
t G-16
^
- PSEaG uses standard functional operating procedures (Operating Instruction I-3.8 Maintaining Hot Standby, Operuting Instruction I-3.6, Hot Standby to Cold Shutdown) and Emergency procedures (Emergency Instruction 4.9, Blackout) augmented by Appendices which detail alternative methods of system operation. Explicit instructions for alternative operational methods are provided in a single document, indexed by system, which provides specific local operating procedures for each valve, motor, or component which may be required to be operated in order to achieve cold shutdown or to correct a mis-operation precipitated by fire damage.
Each type of local operating instruction was reviewed by the team to confirm technical adequacy. Actual operation of a 4 KV motor, a 460 V motor, a motor operated valve, and an air operated valve were demonstrated using these procedures. Local start of a diesel generator was reviewed for technical adequacy based on a drawing review.
Demonstration of this capability was deferred until PSE8G completes a design change in progress tc provide alternate control power at each diesel control center. The procedure presently requires pulling temporary cable to provide this alternative.
lne team concluded that PSE&G has available sufficient operational information to achieve cold shutdown in any postulated fire which could affect equipment availability or control.
The team also concluded that poor organization of the procedures and lack of preplanning were evident which would result in significant lost time were these procedures implemented as currently written.
Accordingly, the team concludes that the following aspects of the alternate shutdown procedure should be required to be corrected prior to Unit 2 operation above 5% rated thermal power.
In addition based on the licensee's procedural practices and the commonability of these procedures, these corrective actions should be taken for Unit 1 concurrently. The aspects of the alternate shutdown G-17 pr:c:: dure that should be corrected are:
The lack of coordination in the procedures to ensure applicatien of the appropriate alternative method when dictated by plant circunstance or conditions.
The lack of direction to the Senior Shift Supervisor as to when control roon evacuation is dictated, and lack of definition as to which procedures, keys, cperator aids, and equipment will be required in the new control location; the lack of discussion of shift organization and personnel deployment for remote operation, Most local cperating instructions require the use of special equipment or tools.
These items are specifically identified in the procedure but have not been pre-staged in a defined location. These items include hand tools, pneumatic jumpers, prepared electrical jumpers, and diesel control power cables.
No mechanism is provided to maintain system status once local operation has bacn initiated. No provision to restore normal function to disturhed control systens has been defined.
- No indication of reactor flux level is provided for the dedicated alternate shutdown system. Accordingly, guidance for ensuring or verifying adequate shutdown marg'n when outside the control roon should be pavided.
Dedicated alternate shutdown instrumentation does not include loop or core temperature. For hot standby operation, the licensee plans to use l
l steam generator saturation pressure information to infer primary temperature.
In order to achieve cooldown, direct temperature information from the hot and l
coid legs should be required and can be achieved, if not otherwise available, by installation of temporary instrumentation to the detector lead in the p2netration area.
l-Only the portable racio/ repeater communications systems is identified as imune to the effects of an exposure fire in the relay room.
It was determined G-18
! l during the review that use of a hand-held portable radio to control activities in the plant from the hot shutdown station is extremely difficult due to ambient noise. We conclude that adequate measures should be implemented to ensure that effective communications with that station can be established.
- A single exposure fire in the Reicy Room can precipitate a total loss of station lighting. We conclude that adequate 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> energency liohting, independent of plant power systens should be installed at all locations which may be required to be manned during the alternate shutdown procedure as well as at all avenues of entrance to and egress from those areas.
In order to account for personnel requirements to support unaffected unit operation, the fire brigade, and alternate shutdown functions on the affected unit,18 shift members were identified. Minimum staffing requirements presently do not include a'el of the following individuals; 2 Senior Reactor Operators, 4 Nuclear Control Operators,10 Equipment / Utility Operators, the Shift Technical Advisor, and one maintenance electrician. This staffing level is necessary, on shif t, to support a workable alternate shutdown capability.
This would necessitate adding an additional two people not currently on shift.
Conpletion of the above listed corrective actions should be verified by the Office of Inspection and Enforcement prior to Unit 2 operation above 5% rated thermal power.
i In addition, in order to fully validate the licensee's capability to accomplish remote shutdown and cooldown, the team concludes that it is necessary for the licensee to perform a demonstration during the performance of Startup Procedure SUP 82.5, Shutdown From Outside Control Room. The following additional operations ekuuld be required during that test;
- Local start of diesel generator using alternative control power source.
G-19
- 16.-
Local operation of 4 KV breaker 4
Local' start of the containmer.t fan cooler unit.
s Local operation of a motor operated-and' an air operated valve.
Local control.of charging.
4 i
i 1
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4 i
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i l
4 I
r k'
G-20 i
,.. _, -.. _ -.. - _ - _ _ _.. - _ _......,,.. _.. _..... _.... _. ~..
III.
Additional Considerations In a recent letter to NRC the licensee indicated that all cable wrap operations at Unit 'c would be completed in June 1981.
In view of the teams findings which indicates additional barriers should be provided in certain areas, the licensee should re-examine the cable wrap schedule and provide the NRC with a new date for completion of wrapping which would include the additional areas identified by the team.
In a letter to NRC the licensee confirmed that response to Generic letter 81-12,
" Fire Protection Rule," would be provided by May 19, 1981. The team recognizes that the licensee's staff interaction with the team and the findings of the team will impact the licensee's ability to meet that date. Therefore, the licensee should re-examine the schedule for responding to Generic Letter 81-12 and provide the NRC with a new date for that response.
In addition, 0IE recently sent a letter to PSE&G which requires that overall program verification be completed by June 5,1981.
If the team findings have impacted this schedule, a letter should be sent to 0IE indicating the licensee's proposed new schedule for completing this action.
l l
l l
G-21
. IV. Summary The team concludes'that fire protection measures are adequate for continued operation of Unit 1 and for issuance of a license with appropriate license conditions for Unit 2 with the understanding that the corrective actions discussed above would be implemented on a schedule that would be subject to staff approval.
]
6 k
i l
l 1
i 4
1 i
G-22
TABLE 1 Licensee Assumptions or Criteria 1.
The design basis fire has a 20 foot diameter zone of influence and has a zone of influence that extends from the floor to the ceiling 2.
The intensity of the postulated fire decreases with height provided that no combustibles are present within the zone of influence.
If horizontal filled cable trays are present within and/or above the 20 foot diameter zone of influence of the tire, the zone of influence is extended out, in a cone shape configuration to include these combustibles.
4.
The design basis fire originates from a transient combustible on the floor and is assumed to be 2-4 feet high. Heat will not be transmitted horizontally above the eight foot fire barrier. The zcne of influence is truncated at the barrier.
l 6.
Cable will burn, but does not support combastion. Tt.erefore, there l
1s assumed to be no further propagation of fire along a horizontal cable tray once the fire source is removed.
7.
Conduit, although not considered to be a combustible, was also not considered to provide a fire barrier to its enclosed cables.
8a. The primary fire suppression system in an affected area is assumed to fail.
8b. An automatic primary fire suppression system does not have to be provided for redundant safety systems within a fire zone of influence of 20 feet.
9.
Cable - initiated fires are not credible.
- 10. Relay room cable and equipment and cables in the vicinity of the ceiling of the 460 V switchgear room cannot be passively protected, and, therefore, an alternate shutdown system is required for those areas.
l G-23 l
l
... 11.
Manual fire-fighting techniques only are required for the control room since the control room is constantly manned.
- 12. An exposure fire inside containment is not credible. However, electrical penetrations will be protected by a radiant heat shield.
In addition, fire protection is being provided for the RCPs.
- 13. All AFW trains will be protected that are within the 20 foot zone of influence of the fire.
- 14. One of the following protective measures is sufficient:
a) A one-hour-fire barrier between redundant components within a fire area.
b) Redundant suppression systems.
c) A 1 1/2 hour barrier on ventilation ducts that go through a 3-hour barrier separating redundant systems.
G-24
l TABLE 2 I
FURTHER EXAMPLES GF AREAS REQUIRING ADDITIONAL PROTECTION 1.
Category 3, Criterion 1 a.
Redundant cables, associated with power, instrumentation, and control for the diesel generators (located in proximity of the diesel generators) were routed within 20 feet of their redundant counterpart. A one-hour barrier around one of the cables was not provided in accordance with the licensee's criteria. These cables shoulo be wrapped in accordance with the licensee's criteria and cable wrap schedule.
b.
Smoke detectors are not provided in the area of the power feeds to redendant diesel generators in the 4 ft wide hallway near the waste gas tanks.
Smoke detectors should be installed on a schedule to be proposed by the licensee.
c.
Redundant cables supplying power to the 4 KV switchgear from the diesel generators are located within 20 feet of each other in the 4 KV switchaear room. These cables should be wrapped in accordance with the licensee's criteria and cable _ wrap schedule.
d.
Redundant cables supplyino power from the 230 volt switchgear to 1
the battery chargers are not wrapped and are within the 20 foot j
fire zone.
These cables should be wrapped in accordance with the licensee's criteria and cable wrap schedule.
G-25
. l 2.
Category 4, Criterion 4 i
a.
Barriers separating equipment needed for shutdown should be raised so that the top of the barrier is above the top of.the redundant raceways or both redundant. raceways snould be wrapped. One of the above corrective actions should be completed in accordance with the licensee's cable wrap schedule for the following areas:
460-230 volt switchgear, 125 volt D-C switchgear, the valve. motor control-centers located in the electrical penetration area, and the pressurizer heater buses located in the electrical penetration area.
b.
In order to minimize the effects of fire and water from fire hoses on redundant equipment, barriers should be extended in an "L" shape configuration and be installed in accordance with the licensee's cable wrap schedule.
Equipment identified during our review that require extended barriers include:
the 4160 volt switchgear, 460-230 volt switchgear, the 125 V DC switchgear, the valve motor control centers, and the pressurizer heater buses.
G-26 1
3.
Category 4, Criterion 8b The following areas where identified during our review as having manual suppression systems for the protection of redundant equipment.
a.
electrical penetration area b.
460-230 volt switchgear room c.
the deluge system for the fuel oil storage tank room d.
the hall below the diesel generator rooms where redundant power feed tt diesels cross e.
4160 volt switshgear roon We find the manual suppressiion acceptable on an interim basis, pending NRC staff review of the licensee's (Appendix R) exemption 4.
Category 4, Criterion 14b a.
Redundant power cables from the diesel generators located in the fuel oil storage tank room are separated by more th6n 20 feet but the fixed fire load of diesel fuel ctl necessitates a larger than 20 foot separation. Thus, one of the redundant cables should be wrapped in accordance with the licensee's cable wrap schedule.
b.
A one hour fire barrier should be provided the 207 panel or the turbine driven auxiliary feedwater control cabinet in accordance with the licensee's cable wrap schedule.
c.
A one hour fire barrier should be provided for the remote shutdown panel in accordance with the licensee's cable wrap schedule.
G-27
l i
APPENDIX H FEDERAL EMERGENCY HANAGEMENT AGENCY LETTER
" Findings and Determination Relation to the Status of State and Local Emergency Preparedness for the Salem Unit 2 Nuclear Plant" Dated April 24, 1981 H-1
FEDERAL EMERGENCY MANAGEMENT AGENCY C~
Washington D.C. 20472,
APR 2 4 19 81 KMORANDUM:
Brian Grime US Nuclear egulato mission
(
FROM:
John E. Dicke Director, Radiological Eme ency Preparedness Division l)
SUBJECT:
Findings and Determination Relating to the Status of State and Local Emergency Preparedness for the Salem Unit 2 Nuclear Plant.
Inis responds to your February 5 and March 10, 1981, requests for the above information.
No formal submission of HEP Plans by either the State of New Jersey or the State of Delaware have been made to FEMA Regions in accordance with FEMA proposed Rule 44 CFR 350.7.
Both States have, however, submitted draft REP Plans for review and comment by their respective Regional Assistance Committees (RAC).
New Jersey submitted a draft on January 16, 1981.
RAC review comments were furnished to the State on February 25, 1981.
Certain revisions to these plans were made and furnished to the RAC on March 27, 1981.
The RAC is not finished reviewing the revisions because of an inqadequate cross reference list. Delaware submitted a draft on December 29, 1980.
I RAC review comments were furnished to the Stste on February 23, 1981.
Delaware has furnished a revised plan received in the FEMA Region on March 31, 1981, which addressed "short term" items.
A later edition of the plans, dated April 1981 was received by the Region on April 6,1981.
It appears to address more of the RAC concerns first identified in February, however the RAC members have not completely evaluated the acequacy of the April revision.
[
Neither State has completely satisfied the requirement for a public meeting in accordance with 44 CFR 350.10. New Jersey held a public 3
meeting on March 20, 1981; however notification to the public was not timely. Another public reseting is scheduled for April 29, 1981. Delaware has scheduled a public meeting on June 15, 1981.
A joint exercise site specific to the Salem nuclear plant was conducted on April 8,1981, with participation by both States and the local governments within the 10 mile EPZ.
The stated objectives of the exercise were generally achieved, even though the scenario had some limitations. While a number of deficiencies were noted, they can be readily corrected with additional SOPS, drills and training.
In summary the overall state of Radiological Emergency Preparedness in the States of New Jersey and Delaware have been significantly improved during the past year. While there is still a need for considerable improvement, the deficiencies which exist should not preclude the two States from coping with an accident at the Salem nuclear plant.
<: e U.S. NUCLE AR REGULATORY COMMISSION
'"U NUREG-0517 BIBLIOGRAPHtC DATA SHEET Surplement :lo. 6
- 4. TITLE AND SU8 TITLE (Add Volume No, of morenaarl
- 2. (Leave bleel Safety Evaluation Report Related to the Operation of Salem Nuclear Generating Station, Unit No. 2
- 3. RECIPIENT'S ACCESSlot* No.
- 7. AUTHoRISI
- 5. DATE REPORT COMPLETED M ON TH lYEAM May 1981 l
- 9. PEEFoRMING oRGANIZATloN NAME AND MAILING ADORESS (lactude 2. Codel DATE REPORT ISSUED Office of Nuclear Reactor Regulation
"(
I ^" gy 19 UcS. Nuclear Regulatory Commission
'~"""~'#
Washington, D.C.
20555
- 8. (Leave Nanki
- 12. SPONSORING ORGAN 12ATioN NAME AND MAILING ADDRESS (/nclude Isa Codel p
Same as 9. above
- 11. CONTRACT No.
- 13. TYPE of REPORT PE RIOD COVE AsD (/nclussve daars)
- 15. SUPPLEMENTARY NOTES
- 14. / Leave We&/
Docket No. 50.-311
- 16. ABSTR ACT 000 worr' or less)
Supplement No. 6 to the Safet: Evaluation Report for the application filed by Public Service Electric and Gas Company, Biladelphia Electric Company, Delmarva Power and I4ght Company, and Atlantic City Electric Company.or a license to operate the Salem Nuchar Generating Station, Unit No. 2 (Docket No. 50-311) located in Salem County, New Jersey has been prepared by the Office of Nuclear Reactor Regulation of the U. S.
Nuclear Regulatory Conrnission. The purpose of this supplement is to further update the Safety Evaluation Report by providing (1) our findings from additional audits of the licensees' equipnent qualification program, (2) our evaluation and status of the licensees' fire protection program, and (3) our evaluation and status of the licensees' emergency preparedness. Based on our evaluation of the application as set forth in the Safety Evaluation Report and its Supplements 1 - 6, we have concluded that Salem 2 can be operated in accordane.e with Facility Operating License DFB-75, and its Technical Speci-fications, without endangering the health and safety of the public.
\\
- 17. KE / WoRDS AND DOCUMENT ANALYSIS 17a DESCRIPToRS 17b IDENTIFIERSloPEN ENDE D TERMS
.r
- 18. (N AILABILITY ST ATEMENT 19 SECURITY CLASS (This reporff 21 No oF PAGES Unciannified 22PNCE Unlimited 20 SECURITY CIASS (Thes papf Unclass fied s
N%C FORM 335 47 771 LA Y