ML13330B527
| ML13330B527 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 07/01/1991 |
| From: | Rosenblum R SOUTHERN CALIFORNIA EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| RTR-REGGD-01.097, RTR-REGGD-1.097, TASK-06-07.C2, TASK-6-7.C2, TASK-RR NUDOCS 9107050194 | |
| Download: ML13330B527 (12) | |
Text
Southern Caifornia Edison Company 23 PARKER STREET IRVINE, CALIFORNIA 92718 R. M. ROSENBLUM TELEPHONE MANAGER OF (714) 454-4505 NUCLEAR REGULATORY AFFAIRS July 1, 1991 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555 Gentlemen:
Subject:
Docket No. 50-206 Status of Integrated Resolution of SEP Topic VI-7.C.2 and Regulatory Guide 1.97 Issues San Onofre Nuclear Generating Station, Unit 1
References:
- 1)
Systemic Evaluation Program Topic VI-7.C.2, "Failure Mode Analysis"
- 2)
Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident"
- 3)
Letter, from F. R. Nandy, SCE to NRC dated February 17, 1989
- 4)
Letter, from F. R. Nandy, SCE to NRC dated June 3, 1989
- 5)
Letter, from F. R. Nandy, SCE to NRC dated May 2, 1990 Our resolution of the remaining items from SEP Topic VI-7.C.2 and the electrical separation issues related to Regulatory Guide (RG) 1.97 will utilize results from the recently completed Emergency Core Cooling System (ECCS) Single Failure Analysis (SFA). Since the ECCS SFA was completed later than we had anticipated, the evaluation of these issues has also been delayed.
We expect to complete our evaluation by December 31, 1991, at which time we will also resolve the other remaining open items for SEP Topic VI-7.C.2 and the RG 1.97 issues related to separation. We plan to provide an interim submittal by September 30, 1991, with additional details of our criteria for resolution of the separation issues, and the resolution of RG 1.97 issues not related to separation.
BACKGROUND SEP Topic VI-7.C.2 was resolved in the-Integrated Plant Safety Assessment Report (NUREG-0829, December 1986), based on our commitment to evaluate a number of proposed modifications. RG 1.97 issues'were resolved in the 1991 Safety Evaluation Report (SER), with the exception of certain instrumentation which may not meet the requirements. These issues include several related to electrical separation. Because the electrical separation issues from the SEP 9.107050194 910701 PDR ; ADOCK 05000206 P
Document Control Desk
-2 and RG 1.97 were related, we had previously informed the NRC that we were integrating the resolution of these open items (references 3 and 4).
Based on the anticipated completion of the ECCS SFA by July 31, 1990, we informed the NRC that we would provide the integrated resolution by June 30, 1991 (reference 5).
We have also indicated that certain ECCS single failure issues would be addressed in our SEP Topic VI-7.C.2 resolution. We agreed to include non separation related RG 1.97 issues in our integrated resolution during a March 1991 NRC inspection. In the associated Inspection Report, the NRC stated that our June 30, 1991 submittal should include resolution of RG 1.97 issues not related to separation. A more detailed history of these issues is provided in Enclosure 1, and a summary of the issues is provided in.
SEPARATION REVIEW The SEP recognized that some older plants were built and licensed prior to the existence of many of the standards governing more modern plants. Rather than imposing backfits on older plants, the SEP provided for acceptance of departures from modern standards based on engineering judgement supplemented by risk assessments. We are currently conducting an overall separation review of existing cable routing using the SEP process.
Seven of the 42 outstanding SEP Topic VI-7.C.2/RG 1.97 issues involve separation of electrical cables and power supplies.
The scope of our separation review includes cables which serve the equipment evaluated in our 1991 ECCS SFA, the containment and main feedwater isolation valves, the currently identified RG 1.97 instruments, and the load shedding features of the electrical system. This cable population includes the cables involved in the seven outstanding SEP Topic VI-7.C.2/RG 1.97 separation issues. The initiating events considered are the following ECCS design basis events: Loss of Coolant Accident (LOCA), Main Steam Line Break (MSLB), and Main Feed Line Break (MFLB).
Our separation review assesses the degree of conformance of the cable population described above with RG 1.75, "Physical Independence of Electric Systems", and IEEE Std. 384, "Standard Criteria for Independence of Class IE Equipment and Circuits".
Unit 1 was designed and constructed prior to issuance of these standards. The separation review identifies specific locations where the separation requirements of these standards are not met.
These locations are evaluated against deterministic and risk assessment criteria. Backfit modifications are initiated commensurate with the assessed risk. The details of our criteria and methodology will be provided in our follow-up letter.
Document Control Desk
-3 We will be contacting you to arrange further discussions on this matter. If you have questions or comments, please do not hesitate to contact me.
Very truly yours, Enclosures cc:
George Kalman, NRC Senior Project Manager, San Onofre Unit 1 J. 0. Bradfute, NRC Project Manager, San Onofre Unit 1 J. B. Martin, Regional Administrator, NRC Region V C. W. Caldwell, NRC Senior Resident Inspector, San Onofre Units 1, 2&3
ENCLOSURE 1 HISTORY OF SEP TOPIC VI-7.C/RG 1.97 ISSUES The outstanding SEP Topic VI-7.C.2/RG 1.97 issues are documented in four reports; the NRC's 1986 SEP Integrated Plant Safety Assessment Report (IPSAR),
SCE's 1991 Emergency Core Cooling System (ECCS) Single Failure Analysis (SFA),
the NRC's 1991 RG 1.97 Safety Evaluation Report (SER), and the NRC's 1991 RG 1.97 Inspection Report. These reports contain a total of 42 SEP VI-7.C.2/RG 1.97 issues. A detailed history of these reports is provided below. The superscript numbers in the text below refer to the numbered references provided at the end of this enclosure.
HISTORY OF SEP TOPIC VI-7.C.2 ISSUES In 1974', the AEC required us to reanalyze the ECCS performance using criteria in the recently issued 10CFR50.46, "Acceptance Criteria for Emergency Core Cooling Systems for Light Water Nuclear Power Reactors." Section 50.46 references Appendix A, Criterion 35, which specifies single failure requirements. In 19752, the NRC requested us to include a single failure evaluation in the ECCS reanalysis. In a 1976 request for information concerning our single failure evaluation, the NRC requested us to define the seismic and environmental qualification (EQ) status of ECCS equipment, and to provide the electrical and physical separation design criteria for safety equipment and functions.
In response to the NRC request, we contracted NUS Corporation to perform a separation and LOCA environment assessment. The NUS report was issued in 19774. Although the plant was designed and constructed prior to issuance of RG 1.75 and IEEE-384, these documents were used as the standard in the NUS assessment, since they provided the current industry standards for electrical separation. The NUS report contained sixteen backfit recommendations, some of which addressed EQ concerns and some of which addressed separation concerns.
Disposition of the recommended backfits was deferred to the SEP. The NRC reviewed the 1977 NUS assessment as part of SEP Topic VI-7.C.2 and, in their 1986 IPSARs, documented our commitment to evaluate the sixteen recommended backfits for implementation. The sixteen recommended backfits are listed in.
HISTORY OF 1991 ECCS SINGLE FAILURE ANALYSIS ISSUES A failure of a main steam pressure transmitter in 1986 caused a transient on all three channels of the feedwater control system, and concurrent inoperability of all three channels of the steam/feedwater flow mismatch scram in the Reactor Protection System (RPS). In response to this event, we committed to several actions, including completion of single failure analyses (SFAs) for the RPS and Engineered Safety Features (ESF) Systems to determine susceptibility of the plant desipn to single failureS 6.
These single failure analyses were completed in 1987. 8 Page 1 of 4
Subsequent to the 1987 RPS and ESF SFAs, we discovered additional single failure susceptibilities in the ECCS.
We committed9 to perform a new ECCS SFA which was submitted to the NRC in 1991.10 This new analysis was performed to current SFA standards. It superseded all previous ECCS SFAs and established a new, current single failure design basis for the plant.
The 1991 ECCS SFA identified additional potential single failure susceptibilities which required evaluation and resolution. These susceptibilities were resolved through changes to procedures or design calculations, were resolved by backfit modifications, or were shown to be acceptable by other means. Others were incorporated into other ongoing programs for final resolution. The 1991 ECCS SFA and a subsequent Follow-Up Report" identified six issues that were to be integrated into SEP Topic VI 7.C.2 for final resolution. The six issues are listed in Enclosure 2.
HISTORY OF REGULATORY GUIDE 1.97 ISSUES Generic Letter 82-3312 required licensees to provide a report to the NRC describing how the post-accident monitoring instrumentation for their facility met the guidelines of RG 1.97. Cygna Energy Services prepared this report which we submitted in 1985.
Since the plant was designed and constructed prior to issuance of RG 1.97, deviations from this regulatory guide were expected and were identified. The report justified some of the deviations based on satisfying the intent of RG 1.97. Backfit hardware upgrades were recommended to resolve the other deviations. The NRC transmitted a technical evaluation of the Cygna report containing a number of unresolved items in 1986.
We responded to the unresolved items in 1987s In 198816 the NRC requested additional information pertaining to the hardware upgrades recommended by the Cygna report. We informed the NRC' 7 8 that RG 1.97 issues pertaining to separation and redundancy would be integrated into our resolution of SEP Topic VI-7.C.2, and that the integrated resolution would be submitted after completion of the new ECCS SFA (discussed above). We subsequently informed the NRC19 that the integrated SEP Topic VI-7.C.2/R.G.
1.97 resolution would be submitted by June 30, 1991, based on completing the new ECCS SFA by July 31, 1990.
In 1991, the NRC issued an SER20 based on our submittals regarding RG 1.97.
The SER stated that the plant design was acceptable with respect to conformance to RG 1.97 except for certain attributes associated with thirteen post-accident variables. The thirteen variables are listed in Enclosure 2.
SCE's compliance with RG 1.97 was inspected by the NRC during March, 1991.
During discussions with the Inspectors, we agreed to address non-separation issues as well as separation related issues in our integrated SEP Topic VI 7.C.2/RG 1.97 resolution. In the resulting Inspection Report21, the Inspectors identified seven Follow-up Items and stated that we should address issues not related to separation in our June 30, 1991 submittal.
The seven followup items are listed in Enclosure 2.
Page 2 of 4
S 0
REFERENCES FOR HISTORY OF SEP TOPIC VI-7.C.2/RG 1.97 ISSUES
- 1.
Letter from A. Ciambusso, U.S. Atomic Energy Commission, to J. B. Moore, Southern California Edison, dated May 8, 1974
- 2.
Letter from R. A. Purple, U.S. Nuclear Regulatory Commission, to J. B.
Moore, Southern California Edison, dated July 22, 1975
- 3.
Letter from R. A. Purple, U. S. Nuclear Regulatory Commission, to J. B.
Moore, Southern California Edison, dated April 8, 1976
- 4.
Letter from K. P. Baskin, Southern California Edison, to A. Schwencer, U. S. Nuclear Regulatory Commission, dated December 20, 1987
- 5.
Letter from H. R. Denton, U. S. Nuclear Regulatory Commission, to K. P.
Baskin, Southern California Edison, dated December 18, 1986
- 6.
Letter from M. 0. Medford, Southern California Edison, to G. E. Lear, U. S. Nuclear Regulatory Commission, dated October 31, 1986
- 7.
Letter from M. 0. Medford, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated March 11, 1987
- 8.
Letter from M. 0. Medford, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated November 6, 1987
- 9.
Letter from K. P. Baskin, Southern California Edison, to J. B. Martin, U. S. Nuclear Regulatory Commission, dated March 17, 1989
- 10.
Letter from F. R. Nandy, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated February 22, 1991
- 11.
Letter from F. R. Nandy, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated February 27, 1991
- 12.
Letter from D. G. Eisenhut, U. S. Nuclear Regulatory Commission to all Licensees of Operating Reactors, Applicants for Operating Licenses and Holders of Construction Permits, dated December 17, 1982
- 13.
Letter from M. 0. Medford, Southern California Edison, to G. E. Lear, Southern California Edison, dated December 16, 1985
- 14.
Letter from R. F. Dudley, U. S. Nuclear Regulatory Commission, to K. P. Baskin, Southern California Edison, dated December 22, 1986
- 15.
Letter from M. 0. Medford, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated May 29, 1987
- 16.
Letter from C. M. Trammell, U. S. Nuclear Regulatory Commission, to K. P. Baskin, Southern California Edison, dated October 14, 1988 Page 3 of 4
- 17.
Letter from F. R. Nandy, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated February 17, 1989.
- 18.
Letter from F. R. Nandy, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated June 3, 1989
- 19.
Letter from F. R. Nandy, Southern California Edison, to Document Control Desk, U. S. Nuclear Regulatory Commission, dated May 2, 1990
- 20.
Letter from G. Kalman, U. S. Nuclear Regulatory Commission, to H. B. Ray, Southern California Edison, dated February 22, 1991
- 21.
Letter from D. F. Kirsch, U. S. Nuclear Regulatory Commission, to H. B. Ray, Southern California Edison, dated April 3, 1991 Page 4 of 4
ENCLOSURE 2 CURRENT SEP TOPIC VI-7.C.2/
RG 1.97 ISSUES Below are the currently identified SEP Topic VI-7.C.2/RG 1.97 issues listed by source document.
1986 NRC IPSAR -
The item numbers below correspond to the item numbers is paragraph 4.25.4 of the IPSAR.
(1) Relocate air horn above elevation 4 ft, and provide a dripproof cover.
(2) Provide power-interrupt devices actuated on safety injection system (SIS) operation, or take other corrective action for pumps, valves, and other equipment that may be submerged during a LOCA and that are connected to power supplies with a post-LOCA function.
(3) Reroute power cables to provide cable separation for several pumps and valves including the charging pumps, safety injection pumps, and component cooling water pumps.
(4) Reroute control cables to provide cable separation for pumps and valves including the charging pumps, feedwater pumps, and salt water cooling pumps.
(5) Arrange vital buses 1, 2, 3, and 4, and the utility bus and associated transfer switches to provide physical separation of the input and output cables to those buses.
(6) Provide missile barriers between the two charging pumps, the component cooling water pumps, and the two safety injection pumps, or confirm that the probability of missile impact or the energy of such a missile is sufficiently low.
(7) Provide missile barriers between the RWST and the safety injection pumps and the refueling water pumps, or confirm that the probability of missile impact or the energy of such a missile is sufficiently low.
(8) Bypass thermal overload cutout switches for valves MOV 720A and B during SIS conditions.
(9) Provide isolation relays for PIC 1111X and PC605X controllers and LS 54 switch contacts.
(10)
Provide separation and isolation for the pressurizer level and pressure instrumentation in the control room console.
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(11)
Provide separation and isolation for the bistable output relays associated with the safety injection actuation signal.
(12)
Rewire station lighting system to eliminate presence of both power trains in a transfer switch. Also, separate emergency lighting to provide a connection to each of the dc buses while maintaining circuit independence.
(13)
Remove DC1 power from breaker 12C02 on 4,160-V bus 2C and all breakers on 4,160-V bus 18.
Isolate the cabling between breaker positions 11C11 on 4,160-V bus 1C and 12C11 on 4,160-V bus 2C.
(14) Align 480-V SWGR3 to the power associated with 4,160-V bus 2C and remove the DC 1 power from the switchgear. Isolate the cabling between breaker 1103 on 480-V SWGR 1 and breaker 1203 on 480-V SWGR 2.
(15) Obtain environmental qualification data, or replace components with qualified units for specified equipment.
(16) Modify breaker circuitry for circulating air fans A-10, A-11, and A-12 to ensure they are locked out by the sequencer in the event of an SIS, or modify ducting to eliminate possibility of sucking water into fan units.
The item numbers below correspond to the Action Item numbers in Appendix C of the ECCS SFA report.
19.1 Evaluate isolation adequacy for unqualified loads on 125VDC bus.
19.3 Modifications addressing spurious auto-transfer of vital busses deferred until integrated resolution of SEP Topic VI-7.C.2.
20.2 Evaluate potential fault propagation due to common-cause faults with concurrent 125VDC failure.
23.2 Address mechanistically caused fires and explosions not excluded by NRC BTP 9.5-1 or Appendix R.
35.6 Evaluate continued acceptability of no maintained lockout on SIS and SISLOP for NSR loads.
37.1 Evaluate 125VDC bus % ground criteria for tech spec action entry and/or modifications to eliminate train-common 125VDC devices.
The item letters below correspond to the item letters in section 3.0 of the SER.
a-g) R.G. 1.97 recommends the use of Category 1; (a) neutron flux, (b)
RCS cold leg water temperature, (c) RCS pressure, (d) wide range steam generator level, (e) condensate storage tank level, (f) pressurizer level, (g) and Category 2 recirculation (high pressure Page 2 of 5
safety injection) flow instrumentation. The licensee has designated the recirculation flow as a Type A variable. R.G. 1.97 requires that Type A variables meet the Category 1 criteria. The instrumentation provided by the licensee meets the Category 1 criteria with the exception of separation and independence.
h)
R.G. 1.97 recommends Category 3 quench tank temperature instrumentation with a range of 50OF to 7500F to monitor the operation of the primary cooling system. The instrumentation provided by the licensee monitors a range of 100 OF to 250F. The licensee did not provide a justification for this deviation.
The staff finds this deviation unacceptable. The licensee should expand the range of the existing instrumentation to cover a minimum of 50oF to a saturated steam temperature that corresponds to the tank rupture disk relief pressure. Since the tank rupture disk is set at 100 psig, the range should be extended to cover at least 3270F.
i)
R.G. 1.97 recommends Category 3 quench tank pressure instrumentation with a range of zero to design pressure to monitor the operation of the primary cooling system. The instrumentation provided by the licensee monitors a range of zero to 50 psig. The licensee did not provide a justification for this deviation.
The staff finds this deviation unacceptable. The licensee should expand the range of the existing instrumentation to cover the tank rupture disk relief pressure. Since the tank rupture disk is set at 100 psig, the range should be extended to cover at least 100 psig.
j) R.G. 1.97 recommends Category 2 containment atmosphere temperature instrumentation to monitor the accomplishment of cooling by the containment cooling system. The licensee has not provided this instrumentation. The justification provided by the licensee is that containment pressure is a diverse alternate to containment temperature.
R.G. 1.97 states that, "monitoring instrumentation inputs should be from sensors that directly measure the desired variables."
The licensee's instrumentation does not directly monitor containment atmosphere temperature. Therefore, the licensee's deviation is unacceptable. The licensee should provide Category 2 containment atmosphere temperature instrumentation as recommended by R.G. 1.97.
k)
R.G. 1.97 recommends Category 2 containment sump water temperature instrumentation to monitor the operation of the containment cooling system. The licensee has not provided containment sump water temperature instrumentation. The licensee's justification for not providing this instrumentation is that containment cooling operation is monitored by containment pressure and system status (i.e., flow, valve position and pump status) of the containment spray and recirculation system. The instrumentation described by Page 3 of 5
the licensee does not provide sufficient information for the operator to determine the quantity of heat being removed from the containment. Therefore the licensee's justification is unacceptable. The licensee should provide Category 2 instrumentation that will monitor the heat removed from the containment.
- 1)
R.G. 1.97 recommends Category 2 emergency ventilation damper position instrumentation to indicate the damper position of the ventilation system. The licensee has not provided information concerning this instrumentation. The licensee should provide Category 2 emergency ventilation damper position instrumentation as recommended by R.G. 1.97.
m)
R.G. 1.97 recommends Category 2 steam generator pressure instrumentation with a range of atmospheric pressure to 120 percent of design pressure to monitor the operation of the steam generators. The instrumentation provided by the licensee has a range of zero to 1000 psia. The lowest safety valve setpoint is 985 psia. Thus, the corresponding range recommended by the regulatory guide is zero to 1182 psia.
The justification provided by the licensee is that 1000 psia is the limit of the peak secondary pressure. The licensee also states that an increased range would increase uncertainty and would adversely affect the RCS mismatch trip and the feedwater control system.
The licensee has not indicated if all safety valves, including any setpoint tolerances, are open before the steam pressure exceeds the instrument range. Therefore, the licensee's inference that the peak pressure seen by this instrumentation is 1000 psia is without basis. It is conceivable that the steam pressure can be higher than the upper limit of the licensee's range.
Therefore, the licensee's justification is unacceptable. The licensee should expand the range of the steam generator pressure instrumentation, while maintaining accuracy for trip setpoints, to cover any expected pressure that the steam lines may experience.
1991 NRC RG 1.97 INSPECTION REPORT -
The item numbers below correspond to the Inspector Followup item numbers in section 3 of the Inspection Report.
50-206/91-07-01: Verify the SPDS records these [Steam Generator wide range level channels LT-465A, -465B, -465C] after the Cycle 12 refueling outage.
50-206/91-07-02: Verify the licensee provides independent power sources to the instrument loops for LT-465A, LT-465B, and LT-465C.
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50-206/91-07-03: Verify the licensee provides independent power sources to the instrument loops for LI [FI]-3453, LI [FI]-3453, and LI
[FI]-3455 [Auxiliary Feedwater Flow].
50-206/91-07-04: Verify the control room post-accident monitoring instrumentation is labeled for this purpose [post accident monitoring] after the Cycle 12 refueling outage.
50-206/91-07-05: Post-accident pressurizer pressure recorder PR-430 was installed on the J-console in the control room, but it was not explicitly documented on the piping and instrument diagram 5178105-11. The licensee is committed to make a change for an adequate representation on the diagram.
50-206/91-07-06: Verify the redundant channel is installed for main steam pressure during the Cycle 12 refueling outage.
50-206/91-07-07: Follow the resolution of the SER open items. Verify the completion of any new commitments by the licensee and orders by the NRC.
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