ML20215E413
| ML20215E413 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 10/06/1986 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20215E407 | List: |
| References | |
| TAC-59440, TAC-61038, TAC-61039, TAC-61931, NUDOCS 8610150285 | |
| Download: ML20215E413 (9) | |
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UNITED STATES
[1 er NUCLEAR REGULATORY COMMISSION
'VASHINGTON, D. C. 20555 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT N0.
20 TO FACILITY OPERATING LICENSE N0. NPF-29 MISSISSIPPI POWER & LIGHT COMPANY MIDDLE SOUTH ENERGY, INC.
SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION GRAND GULF NUCLEAR STATION, UNIT I DOCKET NO. 50-416
1.0 INTRODUCTION
By letter dated August 12, 1985, as amended September 25, 1985 and supplemented October 5 and October 22, 1985 and May 30, 1986, Mississippi Fower & Light Company (the licensee) requested an amendment to Facility 4
Operating License No. NPF-29 for the Grand Gulf Nuclear Station.(GGNS),
Unit 1.
The proposed amendment would change the Technical Specifications to reflect the installation of pressure interlocks for the injection valves in the low pressure emergency core cooling (ECC) systems. Specifications woulc be added to Table 3.3.3-1 and Table 3.3.3-2, for instrumentation designed to permit opening of injection valves in the low pressure coolant injection (LPCI) system and the low pressure core spray (LPCS) system only when the reactor coolant system pressure is below a permissible value. Table 3.3.3-3 and Surveillance Requirement 4.5.1 would be changed to reflect the appropriate response time requirement for these injection valves, after the interlocks are installed. Table 4.3.3.1-1 would be changed by adding surveillance requirements for the new interlock instru-mentation. The amendment would delete surveillance requirements for check valves in the LPCI and LPCS systems (Surveillance Requirement 4.4.3.2.2) which were included in the Technical Specifications because the interlock instrumentation was not installed.
Finally, alann setpoints and inter-lock setpoints would be included in Table 3.4.3.2-2 and Table 3.4.3.2-3 respectively, for the reactor coolant system leakage pressure monitors in the LPCI and LPCS systems.
By letter dated March 21, 1986, as supplemented May 30, 1986, the licensee requested an amendment to the GGNS operating license to reflect modification of the actuation instrumentation for the automatic depressurization system (ADS) and installation of a strong motion seismic accelerometer in a support for the high pressure core spray (HPCS) system. Table 3.3.3-1, Table 3.3.3-2 and Table 4.3.3.1-1 would be changed to include limiting conditions for operation, setpoints, and surveillance requirements, respectively, for the new ADS bypass timers and manual inhibit switches.
Table 3.3.7.2-1 and Table 4.3.7.2-1 would be changed to include limiting 861015o285 861006 PDR ADOCK 05000416 P
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. conditions for operation and surveillance requirements, respectively, for the new seismic monitoring instrumentation.
By-letter dated July 15, 1986, the licensee requested an amendment to delete the requirements for four peak recording accelerographs mounted on reactor piping systems. One accelerograph is mounted on reactor recirculation piping, one on main steam piping, one on low pressure core spray piping, and one on high pressure core spray piping. Table 3.3.7.2-1 and Table 4.3.7.2-1 would be changed to delete limiting conditions for operation and surveillance requirement, respectively, for this seismic monitoring instrumentation.
The results of the staff's safety evaluation of these three applications for license amendments is provided separately below.
2.0 EVALUATI0f; 2.1 Addition of pressure interlock instrumentation for low pressure ECC systems. (August 12, 1985 application)
Facility Operating License NPF-29, Condition 2.C.(18) requires the licensee to implement isolation protection against overpressurization of the low pressure emergency core cooling systems (LPCI and LPCS) through the implementation of reactor vessel pressure permissive interlocks. The licensee had desianed interlock instrumentation to be installed durino thefirstrefuelingoutageandproposedTechnicalSpecification(T.S.)
changes to support the design changes. This interlock instrumentation is designed to minimize the likelihocd cf opening injection valves in the LPCI and LPCS systems when the reactor pressure is greater than that allowed by the ASME Code for these low design pressure systems.
The licensee proposed limiting conditions for operation for the new pressure permissive interlock instrumentation in T.S. Table 3.3.3-1 "ECCS Actuation Instrumentation." The Technical Specifications will require a minimum of three instrument channels to be operable for all operating conditions with Action 31 (declare ADS trip system or ECCS inoperable) applicable for Operating Conditions 4 and 5.
In response to staff's request., the licensee provided information by letter dated October 5, 1985 to clarify what constitutes a channel for the pressure permissive interlocks. The licensee states that the minimum requirement of 3 operating channels per trip function is applicable to the "one-out-of-two twice" logic utilized in the design change and is adequate to assure operability of the required low pressure injection function con-sidering the diversity of injection systems and logic channels available (four per trip function). The staff finds that these instrument channel operability requirements are acceptable.
The licensee proposed surveillance requirements for the new interlock channels in T.S. Table 4.3.3.1-1 "ECCS Actuation Instrumentation Sur-veillance Requirements." The surveillance frequencies wili be once per
. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for channel check, once per month for channel functional test, and once per refueling cycle for channel calibration for all operating conditions.
The staff finds that the channel surveillance frequencies proposed in T.S. Table 4.3.3.1-1 are acceptable.
The pressure permissive interlocks for the low pressure ECCS injection valves are designed to be active for both automatic and manual operation from the control room. The licensee proposed not to include such an interlock for the remote shutdown panel (RSP) control circuits for the ECCS injection valves. The staff found this proposal unacceptable based on the position that interlocks should be installed as part of the RSP control circuits consistent with the corresponding control room control circuits design and in accordance with Standard Review Plan Section 7.4 as related to the interpretation of GDC 19. By letter dated November 22, 1985, the staff informed the licensee of its position and provided accep-table alternatives to the implementation of pressure pennissive interlocks which included administrative control over the operation of these valves.
The staff met with the licensee on April 1,1986 to discuss potential resolutions of this issue.
By letter dated May 30, 1986, the licensee committed to install keylocked control switches that will be in series but separate from the existing return-to-auto control switches implemented for control from the remote shutdown panel (RSP). The keylocked switch will block operation of the LPCI injection valves 01E12-F042A and Q1E12-F042B from the RSP.
Installation of these keylocked control switches will be completed prior to startup after the first refueling outage. The licensee has further committed to have administrative controls in place to ensure that the RSP control of the subject valves will require delib-erate action before the valves can be opened (i.e., the keylocked switch will be key removable in the " disable" position with the key controlled through administrative procedures to ensure that the valve is in the closed position during normal plant operation). The licensee has confirmed that valve position indication will not be negated in the control room nor at the RSP through the implementation of this special control scheme. The use of spring-return-to-auto control switches on the RSPs alleviates the concern related to change-of-state of equipment since no transfer of control is involved. The staff concludes that the use of spring-return control switches in combination with the separate keylocked control feature provides reasonable assurance that operator error is not likely to result in an intersystem LOCA during testing or actual safe shutdown operation from the remote shutdown panels. Accordingly, the staff concludes that the proposed implementation of interlocks for automatic operation of ECCS injection valves and for manual operation of ECCS injection valves from the control room only is acceptable.
The licensee proposed setpoints for the new interlock instrumentation for manual operation of the LPCI and LPCS injection valves in Table 3.4.3.2-2 (for the alarm function) and Table 3.4.3.2-3 (for the interlock function). The setpoints are 25 psi below the design pressures of the j
LPCI system (500 psig) and of the LPCS system (600 psig), and are there-fore acceptable.
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. The licensee proposed setpoints for the new interlock instrumentation for automatic actuation of the LPCI and LPCS systems in Table 3.3.3-2.
The maxir.am allowable value of the trip setpoint proposed by the licensee (534 psig) is less than the design pressure of the LPCS system (600 psig),
but it exceeds the design pressure of the LPCI system (500 psig). The nominal trip setpoint which makes allowance for drift was proposed to be 516 psig.
By letter dated May 30, 1986, the licensee provided additional analyses to support the proposed setpoints. Two considerations were addressed in the selection of the setpoint for ECCS valve pressure inter-locks. First, from a loss of coolant accident (LOCA) perspective, it is desirable to open the valves as soon as possible during a LOCA in order to minimize the resulting peak cladding temperature (PCT). The highest possible setpoint is therefore desirable for this consideration. The second consideration is protection of the low pressure ECC systems from overpressurization as a result of premature valve opening. From this perspective it is desirable to have the setpoint as low as possible. The licensee addressed the first consideration by providing the results of loss-of-coolant accident analyses. The analyses were performed to deter-mine the limiting (lowest) setpoint value which would still result in the calculated PCT being less than the 10 CFR 50.46 limit of 2200* F.
Approved evaluation models were used for the analyses.
It was determined that a lower analytical limit of 436 psig results in a calculated PCT of 2149 F.
When adjusted for loop accuracy, system static head, and other uncer-tainties this translates into a technical specification allowable value of 452 psig. A lower bound allowable value greater than or equal to 452 psig is therefore acceptable. To address the overpressurization consider-ation the licensee performed an analysis of the LPCI system piping. The LPCI system is designed for a working pressure of 500 psig. However, the ASME B&PV Code Section III specifies an overpressurization protection limit of 110% of the design pressure, or 550 psig. Analyses performed by the licensee indicated that stresses caused by this pressure (550 psig),
combined with other loadings at every operating plant condition, satisfy the requirements of the Code with adequate margins. Taking uncertainties such as instrument loop accuracy, calibration allowances, and system static head into consideration, the maximum allowable value for the technical specifications was determined to be 534 psig. An allowable value higher than 534 psig may result in the pressure on the LPCI system exceeding 110%
of design pressure. Based on its review of the above licensee analysis, the staff concludes that a technical specification allowable value for. this interlock setpoint greater than 452 psig and less than 534 psig is accep-table, and that the proposed nominal trip setpoint of 516 psig is therefore acceptable.
In its application dated August 12, 1985, the licensee proposed to delete the ECCS response times specified for the LPCS and the LPCI systems in Table 3.3.3-2.
The licensee stated that this deletion was necessary because the system response with valve interlocks would vary, depending on the rate of depressurization during a loss of coolant accident. The presently specified system response time (40 seconds) includes 10 seconds for starting an emergency diesel generator and 30 seconds for opening the injection valve in the system.
In response to staff questions, regarding
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surveillance tests of. injection valve opening, the licensee proposed by letter dated September 25, 1985 to include in Surveillance Requirement 4.5.1 a requirement of 29 seconds for the time for LPCI and LPCS injection
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valves to move from the closed position to the open position. Surveillance
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tests of emergency diesel generator starting times (10 seconds) are presently
-included in Surveillances Requirement-4.8.1.1.2. The proposed response time for LPCS and LPCI injection valves in Surveillance Requirement 4.5.1 in i
conjunction with the present response time for emergency diesel generator I
starting in Surveillance Requirement 4.8.1.1.2 is not significantly dif-ferent from the presently specified response time for the LPCS and LPCI i
systems in Table 3.3.3-3.
Accordingly, the staff concludes that deletion j
of response times for LPCS and LPCI in Table 3.3.3-3 is acceptable.
i The licensee proposed to eliminate that' portion of Surveillance Require-ment 4.4.3.2.2 which requires leak-rate testing after each disturbance of three check valves in the LPCI system (IE12-F041A, B and C) and one check valve in the LPCS system (1E21-F006). This requirement was put.in the i
present Technical Specifications until pressure interlocks, pressure j
alarms and continuous control room valve position indicators for the motor operated injection valves in the LPCI and LPCS are installed and made operable. Accordingly, the staff concludes that deletion of this surveillance requirement is acceptable when the above instrumentation is i
installed and made operable during the first refueling outage.
L 2.2 Modification of actuation instrumentation for the automatic depressuriza-tion system and addition of a seismic strong motion accelerometer (March 21, 1986 application) 7 The licensee proposed limiting conditions for operation, setpoints, and surveillance requirements for ADS bypass timers and manual inhibit switches for the ADS instrumentation in Table 3.3.3-1, Table 3.3.3-2 and Table 4
4.3.3.1-1, respectively.
In addition, the name of the presently identified ^
" ADS timer" is changed to " ADS initiation timer." The proposed design change associated with this technical specification change modifies the ADS design to meet the requirements of NUREG-0737, Item II.K.3.18, " Mod-ification of Automatic Depressurization System Logic - feasibility for increased diversity for some event sequences."
It was required by the Grand Gulf Unit 1 Operating License Condition 2.C.(33)(f).
In 1981, the BWR Owners Group submitted a response to TMI Action Plan Item II.K.3.18.
In 1982, the-Owners Group proposed additional ADS logic modifications to satisfy the NUREG-0737 requirements and address ATWS considerations. The staff has reviewed the modifications proposed by the Owners Group and j
concluded that the following two options are acceptable:
(1) Removal of the high drywell pressure trip in conjunction with the addition of a manual switch which inhibits ADS actuation.
(2) Addition of a manual inhibit switch in conjunction with a timer which bypasses the high drywell pressure trip after a sustained low water level indication.
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. Operating License Condition 2.C.(33)(f) requires the licensee to modify the ADS in accordance with the second option.
In addition to the modifi-cations, the licensee was required to provide justification for the timer delay settings, revise the emergency procedures for use of the manual inhibit switch, and submit proposed Technical Specification Surveillance procedures for the timer and switch.
The proposed modification will provide a bypass of the drywell high pressure signal after a set time delay. This modification provides automatic ADS initiation, if required, for events such as a break externsi to the drywell or a stuck open safety relief valve. The bypass timer is actuated on low reactor pressure vessel water level - level 1.
The manual inhibit switch provides the capability to inhibit ADS operation without repeatedly pressing the reset pushbutton as required with the current design. One manual inhibit switch for each ADS division is provided. The inhibit action will activate a white indicating light and an annunciator to alert the operator. The inhibit switch will not affect the manual ADS actuation or the high pressure safety relief function.
The licensee stated that the use of manual inhibit switch will be incor-parated into the plant emergency operating procedures. The licensee has provided the results of analyses which show that a bypass timer setting of 10 minutes results in a calculated fuel element peak cladding temperature (PCT) of 1862 F, which is below the criteria of 2200*F given in 10 CFR 50.46. Approved evaluation models were used for the analyses. Based on its review of the licensee's application including logic diagrams, the staff concludes that the licensee's proposed modification of ADS actuation instrumentation and the associated changes to the Technical Specifications in Tables 3.3.3-1, 3.3.3-2, and 4.3.3.1-1 are consistent with the BWR Owners Group responses to TMI Action Plan Item II.K.3.18, and therefore, are acceptable.
In its application dated March 21, 1986, the licensee also proposed tc add a strong motion accelerometer for a reactor piping support in Technical Specification Table 3.3.7.2-1 " Seismic Monitoring Instrumentation" and in Table 4.3.7.2-1 " Seismic Monitoring Instrumentation Surveillance Require-ments." This change results from License Condition 2.C.(7) which requires the completion of installation of triaxial strong motion accelerometers on reactor supports. Currently, there are five strong motion accelerometers (SMA's) installed in GGNS Unit 1.
One SMA is located on the Unit 1 con-tainment attached to the drywell wall at El.
150'-6" and on the same containment azimuth as the base slab SMA. A third SMA is located in the Unit 1 auxiliary building attached to one of the standby gas treatment system filter train supports which is seismic Category I equipment. A fourth SMA is located in the standby service water pump house A, which is an independent Category I structure. The fifth SMA is located in the free field approximately 250 feet from any station structure, with axes oriented in the same direction as the containment building accelerometers. The SMA to be mounted on a support for the high pressure core spray system will complete the installation of SMAs for GGNS Unit 1.
Because installation of the SMA on a reactor piping support and inclusion of this instrumentation in the Technical Specifications fulfills License Condition 2.C.(7), the staff concludes that the proposed TS change is acceptable.
. 2.3 Deletion of seismic peak recording accelerographs (July 15, 1986 application)
The licensee proposed to remove four seismic peak recording accelerographs (PRAs) mounted on reactor piping and to delete this instrumentation from Technical Specifications in Table 3.3.7.2-1 and Table 4.3.7.2-1.
The four PRAs are mounted on reactor recirculation piping, main. Steam piping, low pressure core spray (LPCS) piping and high pressure core spray (HPCS) piping.
The licensee in its letter dated May 4,1984, reported that these four instrun'ents were found non-functional during surveillance. The licensee's commitments to review this matter were documented in its letter dated May 31, 1984. This included a comitment to implement appropriate design changes prior to restart following the first refueling outage, as well as a commitment to submit a proposed Technical Specification change on a schedule consistent with the implementation of these modifications. The NRC staff review of this issue was subsequently documented in Supplement No. 6 to the SER (Section 16.3.1).
It was concluded that no change to the Technical Specifications would be required until the first refueling outage because the instruments were not used to actuate engineered safety features and post-seismic damage could be evaluated, if necessary, using conservative analyses based on the measurements of other seismic instru-ments which were operable.
In its follow-up letter dated January 10, 1986, the licensee described its proposed deletion of the above four PRAs, in fulfillment of the commitments made in its May 31, 1984 letter. The licensee's justification for such a proposed action is as follows.
(1) The vendor (Kinematrics) has confirmed that a passive device (PRA) is not suitable for installation on a system which is subjected to frequent transients.
(2) The peak acceleration response due to a seismic event can not be separated from the response due to the system transients.
In many cases the predicted peak seismic response is less than that due to the system transients.
(3) A meaningful and conclusive evaluation of the piping response due to a seismic event cannot be performed by relying on a peak acceleration value at a single location on the piping system.
(4) Currently there are five strong motion accelerometers (SMAs) installed in the plant. One SMA is installed on the containment foundation, one on the drywell wall, one in the standby service water pump house, and one on the standby gas treatment system filter drain.
The fifth SMA is installed on the free field. These recorders will provide reliable acceleration time history, which can be converted to seismic response spectra. These can easily be compared with the respective GGNS design seismic spectra for post-seismic damage evaluation.
., (5) A sixth SMA will be installed on a reactor piping support for the high pressure core spray system by restart from the first refueling outage (See Section 2.2 of this evaluation). This SMA will provide an acceleration time history at the support location, which can better serve to confirm the post-seismic evaluation for this plant component than the PRA which is currently located on the corresponding piping system.
(6) There are seven PRAs mounted at various locations inside and outside the containment which will provide reliable and meaningful information for post-seismic damage evaluation.
The staff has reviewed the proposed deletion of these four PRAs in the light of the guidelines in Regulatory Guide 1.12 " Instrumentation for Earthquakes" Revision 1, and Standard Review Plan Section 3.7.4 (NUREG-0800).
Regulatory Guide 1.12 and SRP Section 3.7.4 recommend that three triaxial peak recording accelerographs be provided; one on reactor equipment, one on reacter piping, and one on Seismic Category I equipment or piping out-side of containment.
There are currently 11 PRAs provided. One is located on a reactor vessel support, four on reactor piping systems as stated previously, one on the containment dome, one on the control building foundation, one in the control room, one on the standby diesel generator, one on the auxiliary building foundation, and one in standby service water pump house B.
The seven PRAs remaining after deletion of the four PRAs on reactor piping meet regulatory guidelines for PRAs to be mounted on reactor equipment and on equipment or piping outside containment. The strong motion accelerometer (SMA) to be installed on the support for the high pressure core spray piping during the first refueling outage (See Section 2.2 of this evaluation) is an acceptable alternative to a PRA mounted on reactor piping. Therefore guide-lines in Regulatory Guide 1.12 and SRP Section 3.7.4 will continue to be satisfied af ter deletion of the four PRAs and addition of the one SMA.
The probable cause of malfunction of the PRAs which are mounted on the reactor piping is believed to be the following. A PRA is a passive device capable of recording peak acceleration during a transient event.
The reactor piping is subjected to various transients during startup and normal plant operation. During these transients, the peak acceleration recorded by instruments mounted on the piping can be very high, and can exceed the range of the PRAs (0.01 to 2.0g), making them inoperable.
Based on its review of the licensee's submittals, the staff concludes that the four PRAs which are mounted on the reactor piping do not serve any meaningful purpose for post-seismic damage evaluation. The staff also concludes that with the sixth SMA which will be installed when the four PRAs are removed and the already available devices there are sufficient seismic instruments to provide required information for post-seismic damage evaluation. The staff further concludes that Regulatory Guide 1.12, l
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l Revision 1, and Standard Review Plan Section 3.7.4 (NUREG-0800) are met without credit for the four pipe - mounted PRAs. Therefore the proposed celetion of the four PRAs from the Technical Specifications is acceptable.
3.0 ENVIRONMENTAL CONSIDERATION
This amendment involves changes to requirements with respect to the-installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 and changes to the surveillance require-ments. The staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued proposed findings' that this amendment involves no significant hazards consideration and there has been no public comment on such findings. Accordingly, this amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of this amendment.
4.0 CONCLUSION
The Commission made proposed determinations that the amendments involve no significant hazards consideration, which were published in the Federal Register (51 FR 31740 on September 4, 1986, 51 FR 15402 on April 23, 1986, ana 51 FR 30577 on August 27,1986), and consulted with the state of Mississippi. No public comments were received, and the state of Mississippi did not have any comments.
The staff has concluded, based on the considerations discussed above, that:
(1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (2) such activities will be conducted in compliance with the Connission's regulations and the issuance of this amendment will not be inimical to the common defense and the security nor to the health and safety of the public.
Prinicipal Contributors:
R. Stevens, Electrical, Instrumentation and Control Systems Branch, DBL H._Li, Electrical, Instrumentation and Control Systems Branch, DBL T. Collins, Reactor Systems Branch, DBL A. Gilbert, Reactor Systems Branch, DBL H. Shaw, Engineering Branch, DBL C. P. Tan, Engineering Branch, DBL F. Skopec, Reactor Systems Branch, DBL A. Lee. Engineering Branch, DBL L. Kintner, BWR Project Directorate No. 4, DBL Dated:
October 6,1986 t
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