GO2-06-080, Proposed Amendment of Facility Operating License to Remove Operating Mode Restrictions for Performing Emergency Diesel Generator Surveillance Testing

Proposed Amendment of Facility Operating License to Remove Operating Mode Restrictions for Performing Emergency Diesel Generator Surveillance Testing

ML061520485
Person / Time
Site:	Columbia
Issue date:	05/22/2006
From:	Oxenford W Energy Northwest
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
GO2-06-080
Download: ML061520485 (33)

Text

SENERGY

'NORTHWEST People Vision Solutions P.O. Box 968

• Richland, WA

• 99352-0968 May 22, 2006 G02-06-080 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001

Subject:

COLUMBIA GENERATING STATION, DOCKET NO. 50-397 PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING

Dear Sir or Madam:

Pursuant to 10 CFR 50.90, Energy Northwest hereby requests the following license amendment for Columbia Generating Station (Columbia). Energy Northwest requests modification of Columbia's Technical Specifications to revise several of the Surveillance Requirements (SRs) pertaining to testing of the Division 3 standby diesel generator (DG-3). The proposed change would modify specific restrictions associated with these SRs that prohibit performing required testing in Modes 1, 2 or 3. This proposed modification would affect SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19.

The proposed change has been evaluated in accordance with 10 CFR 50.91 using criteria in 10 CFR 50.92(c) and this change presents a no significant hazards consideration and, accordingly, a finding of no significant hazards consideration is justified. The bases for this determination are included in Attachment 1 to this letter.

The proposed change does not include any new commitments. The NRC has approved similar Technical Specification changes for other plants. For example, Perry, Clinton, and River Bend Station have each received similar license amendments on February 24, 1999, October 2, 2000, and March 14, 2003 respectively.

Energy Northwest requests the effective date for this Technical Specification change to be within 30 days of approval. Although this request is neither exigent nor emergency, your prompt review is requested. Energy Northwest has identified this change as affecting activities planned during the upcoming refueling outage (R-18) and on that basis requests approval of this proposed change by February 28, 2007. The requested approval date and implementation period will enable Columbia to optimize refueling outage planning and activities.

J+-tool

A PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Page 2 Ifyou have any questions or require additional information, please contact Mr. GV Cullen at 509-377-6105.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the date of this letter.

Respectfully, WS Oxenford Vice President, Technical Services Mail Drop PE04 Attachments:

1. Evaluation of Proposed Changes

2. Proposed Technical Specifications Changes (mark-up)

3. Proposed Technical Specifications Pages (retyped)

4. Changes to Technical Specifications Bases cc: BS Mallett - NRC RIV BJ Benney - NRC NRR NRC Senior Resident Inspector/988C RN Sherman - BPA/1 399 WA Horin - Winston & Strawn JO Luce - EFSEC RRCowley - WDOH

-I PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 1 of 11 Evaluation of Proposed Changes

1.0 DESCRIPTION

The proposed changes to Technical Specifications (TS) Surveillance Requirements (SRs) 3.8.1.11, 3.8.1.12, 3.8.1.16, and 3.8.1.19 are requested to allow performance of the associated testing of the High Pressure Core Spray (HPCS) Diesel Generator (DG-

3) during Modes 1, 2, or 3 such that the testing will no longer have to be performed during plant outages. This license amendment request is made for the purpose of reducing outage critical path time and work scope and it will also reduce the amount of system realignments and operator workload during outages.

The MODE restrictions for SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19 will remain applicable to the Division 1 and Division 2 DGs (DG-1 and DG-2). The change will be put into effect by adding "not applicable to DG-3" to the current Notes in the four TS SRs.

Since the proposed changes can provide significant reductions in outage critical path time, Energy Northwest is respectfully requesting review and approval of this license amendment request by February 28, 2007. This would support scheduling of these SRs before or after the outage such that planning for the outage can be finalized with the noted SRs removed from the outage scope. The NRC has approved similar Technical Specifications changes for other plants. For example, Perry, Clinton, and River Bend Station have each received similar license amendments on February 24, 1999, October 2, 2000, and March 14, 2003 respectively.

The proposed changes to the TS are reflected in the marked-up TS pages provided in Attachment 2. Associated changes to the TS Bases are contained in Attachment 4.

The proposed TS Bases changes are provided for information only and will be controlled by TS 5.5.10, 'Technical Specifications (TS) Bases Control Program."

2.0 PROPOSED CHANGE

S Revise SR 3.8.1.11 to remove the MODE restriction from Note 2 for DG-3 only. This SR requires testing to verify that on an actual or simulated loss of offsite power, emergency buses de-energize and each required DG auto-starts and energizes loads from a standby condition.

Revise SR 3.8.1.12 to remove the MODE restriction from Note 2 for DG-3 only. This SR requires testing to verify that on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal that each required DG auto-starts and energizes loads from a standby condition.

Revise SR 3.8.1.16 to remove the MODE restriction from the Note for DG-3 only. This SR requires testing to verify that each required DG:

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Page 2 of 11

1. Synchronizes with off site power source while loaded with emergency loads upon a simulated restoration of offsite power;

2. Transfers loads to offsite power source; and

3. Returns to ready-to-load operation.

Revise SR 3.8.1.19 to remove the MODE restriction from Note 2 for DG-3 only. This SR requires testing to verify that on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated Emergency Core Cooling System (ECCS) initiation signal:

1. The de-energization of emergency buses;

2. Load shedding from emergency buses for DG-1 and DG-2; and

3. DG auto-starts and loads from a standby condition.

3.0 BACKGROUND

Columbia Generating Station (Columbia) Technical Specification Limiting Condition for Operation (LCO) 3.8.1, "AC Sources - Operating," specifies requirements for the Electrical Power Distribution System AC sources during modes 1, 2, and 3. The Class 1E AC Electrical Power Distribution System AC sources at Columbia consist of the offsite power sources and the onsite standby power sources, (DGs 1, 2, and 3). As required by 10 CFR 50, Appendix A, GDC 17, the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The Class 1 E AC distribution system at Columbia supplies electrical power to three divisional load groups, with each division powered by an independent Class 1E, 4.16 kV ESF bus. The Division 1 and 2 ESF buses have two separate and independent off site sources of power. The Division 3 ESF bus has one offsite source of power. Each ESF bus has a dedicated onsite DG. The ESF systems of any two of the three divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.

Offsite power is supplied to the Columbia switchyard from two transmission network interconnection points. One network connection is the preferred 230 kV offsite source from the Ashe substation the other is the backup 115 kV source from the Benton substation. From these two substations, two electrically and physically separated circuits (preferred and backup sources) provide AC power to the Division 1 and 2 critical 4.16 kV ESF buses, while only one qualified (230 kV) circuit supplies offsite power to the Division 3 ESF bus. The offsite AC electrical power sources are designed and located to minimize, to the extent practical, the likelihood of their simultaneous failure

• 2.

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 3 of 11 under operating and postulated accident and environmental conditions. A detailed description of the off site power network and circuits to the onsite Class 1E ESF buses is found in Columbia's Final Safety Analysis Report (FSAR), Chapter 8. An offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESF bus(es).

As previously stated, the onsite standby power source for each 4.16 kV ESF bus is a dedicated DG. The DGs start automatically upon receipt of a Loss of Coolant Accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) or on an ESF bus degraded voltage or undervoltage signal (refer to LCO 3.3.8.1, "Loss of Offsite Power (LOOP) Instrumentation"). In the event of a loss of all offsite power to the critical buses, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a LOCA. A detailed description of the onsite power network is found in Columbia's, FSAR Chapter 8, section 8.3, "Onsite Power System".

The Division 3, HPCS DG has the capability to restore power quickly to the HPCS bus in the event offsite power is unavailable and to provide all required power for the startup and operation of the HPCS pump motor in a manner compatible with the safe shutdown of the plant. The HPCS DG starts automatically on a signal from the plant protection system; the unit is both started and connected to the bus automatically upon receipt of a bus undervoltage signal. The failure of DG-3 does not negate the capability of other onsite power sources (DG-1 & DG-2). Procedures are used to prevent paralleling of DG-3 with the normal transformer so that the short circuit capability of the switchgear is not exceeded. Means are provided for periodic exercising of DG-3 under load. To accomplish this, supply of the Division 3 4.16 kV Class 1E bus is transferred to the startup source. Under this condition, DG-3 is synchronized to the 230 kV offsite source and loaded via manual adjustment of the unit voltage and speed controls.

The HPCS system is designed and constructed to allow active components to be tested during any MODE of plant operation. The system has a full-flow test line to either the suppression pool or the Condensate water Storage Tank (CST) which allows testing without injecting into the reactor vessel. These features, along with the design of the electrical distribution system facilitate safe performance of testing pursuant to the subject SRs in modes 1, 2, or 3. This on-line testing will minimize system manipulations and reduce operator workload during refueling outages. Performing this testing during normal power operations will eliminate approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> of operator intensive testing during an outage.

. I PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 4 of 11

4.0 TECHNICAL ANALYSIS

4.1 General Basis Although the TS Bases, as currently written, state that one of the reasons for the SR Note imposing MODE restrictions (for SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19) is to preclude the potential for perturbations of the electrical distribution system during plant operation, reconsideration of this basis for DG-3 determined that the noted concern is unwarranted with respect to requiring the affected SRs to be performed only during shutdown conditions. This conclusion is based on (1)the Columbia AC power supply and associated protection features (2) industry and plant experience with the performance of testing required per the affected SRs, (3) administrative controls that minimize plant risks during performance of the affected testing, and (4)the low probability of a significant voltage perturbation during such testing. From a deterministic perspective, the effect on safety of performing the subject SRs for DG-3 during plant operation is not significantly different than the effect on safety associated with the performance of other DG surveillances required by the Technical Specifications but which are not prohibited from being performed during plant operation.

For example, SRs 3.8.1.9, 3.8.1.10, and 3.8.1.17 are performed by paralleling the DG in test with offsite power, similar to the existing monthly run of the DG (to meet SRs 3.8.1.2 and 3.8.1.3), which is conducted with the plant on-line. Further, performance of the required testing at power does not challenge any safety systems or interfere with normal plant operation.

4.2 Administrative Controls for On-line Maintenance Columbia's Technical Specifications impose requirements/restrictions on the amount of equipment allowed out of service at any given time. Required Action B.2 of Technical Specifications LCO 3.8.1, "AC Sources-Operating," requires identification of inoperable required features that are redundant to required features supported by the inoperable DG. This Required Action is applicable throughout the entire period of DG inoperability.

Inoperable features on the redundant division would then cause entry into other more severe Required Actions, thus providing further incentive not to make another DG inoperable. Additionally, the Safety Function Determination Program (SFDP), required by Technical Specification 5.5.11, ensures that a loss of safety function is detected and appropriate actions taken.

Energy Northwest's approach to performing maintenance requires a protected division concept. This means that without special considerations, work is only allowed on one division at a time. Additionally, access to areas of the plant containing protected equipment is restricted. This administrative control provides additional assurance that only one division at a time is worked on and it helps eliminate inadvertent work on the other division. Columbia's procedures contain precautions to minimize risk associated with surveillance testing, maintenance activities, and degraded grid conditions when paralleling a DG with offsite power. For example, during testing only one DG is operated in parallel with off site power at a time. This configuration provides for

. I ° S PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 5 of 11 sufficient independence of the onsite power sources from offsite power while still enabling testing to demonstrate DG operability. In this configuration, it is possible for only one DG to be affected by an unstable offsite power system (even then, it may be possible for operator action to be taken to manually reset the affected lockout relay so that the DG can be restarted).

4.3 On-line Risk Management Columbia's Plant Administrative Procedure, 1.5.14 "Risk Assessment and Management for Maintenance/Surveillance Activities," provides procedural requirements to conduct risk assessment for all maintenance performed while in MODES 1, 2 or 3. The purpose of this procedure is to ensure that a process is in place to assess the overall impact of maintenance on plant risk and to manage the risk associated with equipment unavailability. This program implements the requirements of 10 CFR 50.65(a)(4),

"Maintenance Rule." This program uses a risk evaluation tool to assess the potential risk implications of planned or emergent work activities during power operations. This tool alerts Planning & Scheduling/Operations personnel if plant risk goals are being approached, or would be exceeded if work was allowed to be performed. These proceduralized administrative controls minimize any potential to allow work on redundant DGs. The risk evaluation tool is a comprehensive modeling of important equipment and allows the site to evaluate the adverse effects of other maintenance activities and their impact on DG maintenance.

4.4 On-line Testing versus Outage Testing Due to the relationship between DG-3 and the HPCS system, the Technical Specifications allow up to 14 days of inoperability for DG-3 if the Reactor Core Isolation Cooling (RCIC) system is operable. This Completion Time provides ample time for the performance of the SRs that are proposed to be revised in this request. The actual time needed to perform these SRs is approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. By virtue of HPCS being a stand-alone system with its dedicated DG and independent distribution system, there is minimal opportunity for the performance of these SRs to have any impact on other safety related plant equipment. Also due to the smaller size of the loads associated with the HPCS system there is less potential for this testing to create a perturbation on the grid than there is with DG-1 or DG-2. Evaluation of DG-3 test results for the subject SRs has shown that the important bus voltage parameters stay within prescribed limits.

The on-line performance of LCO 3.8.1 SRs for DG-3 has little effect on managing equipment unavailability goals described in 10 CFR 50.65(a)(3). The maintenance rule unavailability performance criteria for DG-3 is set at 250 hours0.00289 days <br />0.0694 hours <br />4.133598e-4 weeks <br />9.5125e-5 months <br /> for a 24-month rolling period. Based on this, Energy Northwest has established an administrative goal of 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of unavailability for the 24-month refueling cycle. The addition of 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> of unavailable time per operating cycle does not challenge achievement of the goal.

.% . j PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 6 of 11 In comparing the Technical Specification requirements for ECCS and AC Sources during MODES 1, 2, or 3 to MODES 4 or 5, the requirements are more restrictive during MODES 1, 2, or 3. Due to the more restrictive criteria during MODES 1, 2, or 3, when performing the testing during these MODES the defense in depth concept is better supported by other ECCS systems.

As described in Columbia's FSAR, Section 6.3.4.2.1 "HPCS Testing", HPCS can be tested at full flow with CST water at any time during plant operation except when the reactor vessel water level is low, or when the condensate level in the condensate storage tank is below the reserve level, or when the valves from the suppression pool to the pump are open.

4.5 Deterministic Evaluation SR 3.8.1.11 The following information pertains to DG-3 only. Surveillance Requirement 3.8.1.11 requires, at least once per 24 months, verification, on an actual or simulated LOOP signal, that DG-3 automatically starts from standby conditions and supplies permanently connected (Columbia's design for DG-3 does not feature auto-sequencing of loads) loads for >_5 minutes. Currently, this SR contains a Note that prohibits performance during Modes 1, 2, or 3. The Technical Specification Bases states the reason for the Note is that performing the surveillances would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.

Columbia's test procedure for meeting SR 3.8.1.11 disconnects the Division 3 4.16 kV ESF bus from offsite power and re-energizes the bus from DG-3. At this point, acceptable performance parameters of DG-3 are verified. The DG-3 is then paralleled to the offsite source; load tested, and then shut-down leaving the offsite source powering the bus. Flow testing of the HPCS system is not performed in this test procedure.

Because the HPCS is a stand-alone system with a dedicated DG and independent electrical distribution system, there is minimal opportunity for the performance of these SRs to have any impact on other safety-related plant equipment or normal plant operation. Additionally, due to the minimal size of the loads associated with the HPCS system, there is minimal potential for this testing to create a perturbation on the offsite power grid when the Division 3 electrical bus is de-energized.

Although a required offsite circuit is removed from service (only for the Division 3 bus however), the period of time this condition exists is small compared to the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by Technical Specifications to restore one inoperable offsite circuit. The above discussion and past experience performing these tests shows that conducting this test procedure in modes 1, 2, or 3 would not challenge plant safety systems or cause any significant perturbations in the electrical system. Therefore the reasons for the mode restriction note are not valid.

.I .

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 7 of 11 SR 3.8.1.12, SR 3.8.1.16 and SR 3.8.1.19 Surveillance Requirement 3.8.1.12 requires, at least once per 24 months, verification on an actual or simulated ECCS initiation signal, that each DG auto-start from standby configuration and operate for >_5 minutes. Surveillance Requirement 3.8.1.16 requires, at least once per 24 months, verification that each DG can be synchronized with the offsite power source while loaded with emergency loads, and upon a simulated restoration of offsite power transfer all loads to an offsite power source and return to ready-to-load operation. Surveillance Requirement 3.8.1.19 requires, at least once per 24 months, verification on an actual or simulated LOOP signal in conjunction with an actual or simulated Emergency Core Cooling System (ECCS) initiation signal that DG-3 supplies permanently connected loads for >_5 minutes. Currently, TS contain Notes that prohibit performance of these SRs during Modes 1, 2, or 3. For SR 3.8.1.12 the stated reason for the Note is that, during power operation with the reactor being critical, performance of this SR could cause perturbations to the electrical distribution system that could challenge continued, steady state operation and, as a result, plant safety systems. For SRs 3.8.1.16 and 3.8.1.19 the stated reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems. The following discussion justifies the proposal to perform these tests for DG-3 during Modes 1 or 2 for SR 3.8.1.12 and Modes 1, 2, or 3 for SR 3.8.1.16 and SR 3.8.1.19.

Columbia's test procedure for meeting these SRs starts the HPCS system in the full flow test mode with suction from, and discharge to, the CSTs as described in section 4.4 above. With system flow established an ECCS initiation signal is generated by connecting an ECCS test switch to the HPCS logic test receptacle on the main control room panel that contains the initiation relay logic. The control logics associated with these tests are Division 3 only and do not impact components in other divisions. The control logic is temporarily modified to prevent an actual injection into the reactor pressure vessel during the test. With the ECCS initiation signal present, DG-3 starts and runs unloaded for > 5 minutes while acceptable performance parameters (voltage and frequency) of DG-3 are verified. Next, the ECCS initiation signal is cleared and DG-3 is shutdown. In the next part of the test the ECCS initiation signal is again applied in the same fashion along with a simulated loss of offsite power signal, DG-3 subsequently starts and the offsite power supply to the Division 3 ESF bus auto trips.

At this point in the test verification that DG-3 supplies permanently connected loads for

> 5 minutes is performed. After this is verified DG-3 is paralleled to the offsite power source, the loaded bus is transferred and the HPCS pump is secured.

Again, for these three SRs, the reasons stated in the TS Bases for the mode restriction notes are not valid when applied to DG-3. As stated previously, the HPCS system is a stand-alone system with a dedicated DG and independent electrical distribution system; there is, therefore, minimal impact from the performance of these SRs on other safety-related plant equipment. Although a required offsite circuit is removed from the Division 3 electrical bus during the test, the period of time this condition exists is small compared

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Page 8 of 11 to the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by Technical Specifications to restore one inoperable offsite circuit. Additionally, the minimal size of the loads associated with the HPCS system, present minimal potential for creating a perturbation on the grid when shifting the load between DG-3 and the offsite power source. Completed test results have shown that the required bus voltage parameters stay within expected limits and no anomalous actions regarding load transfer sequences occur. Therefore, the proposed changes are acceptable.

Considering the above discussion and past experience performing these tests, conducting these tests at power is no more challenging to normal plant operation than performance of the periodic HPCS system test which is conducted quarterly during power operation. Therefore, contrary to the stated reasons for the Notes, the operation of the HPCS during the performance of these SRs will not challenge plant safety, disrupt power operation, or cause any significant perturbations in the electrical system.

Deterministic Conclusion Based on the above discussions of the individual SRs, there is sufficient assurance that performing SRs 3.8.1.11, 3.8.1.12, 3.8.1.16, and 3.8.1.19 during power operations will not appreciably increase the probability of a transient that could cause any perturbation on the Columbia Generating Station electrical distribution system, disrupt power operation, or challenge any safety systems. Therefore, in conclusion, the proposed changes are justifiable from a deterministic perspective.

5.0 REGULATORY ANALYSIS

5.1 Applicable Regulatory Requirements/Criteria The proposed changes have been evaluated to determine whether applicable regulations and requirements continue to be met. This amendment request provides sufficient information to demonstrate that the request does not alter compliance with any applicable regulatory requirement or criteria. The regulatory requirements that were reviewed were:

• General Design Criteria -17, "Electrical Power Systems," of Appendix A to Title 10 of the Code of Federal Regulations (CFR) Part 50 which requires, in part, that nuclear power plants have an onsite and offsite electrical power system to permit the functioning of structures, systems, and components important to safety.

" General Design Criteria -18, "Inspection and Testing of Electrical Power Systems," of Appendix A to Title 10 of the Code of Federal Regulations (CFR) Part 50 which requires electrical power systems important to safety to be designed to permit appropriate inspection and testing.

. f PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment I Page 9 of 11 5.2 No Significant Hazards Consideration The proposed change will revise Technical Specification LCO 3.8.1, "AC Sources -

Operating" to modify SRs pertaining to the testing of DG-3. Specifically, changes will remove specific Mode restrictions for performing testing to satisfy SRs for DG-3. This would allow the performance of all SRs for DG-3 during any Mode of plant operation and removal of these tasks from refueling outage scope of work. Approval of this license amendment request will also reduce the amount of system re-alignments and operator workload during an outage.

In accordance with 10 CFR 50.92(c), a proposed change to the operating license involves a no significant hazards consideration if operation of the facility in accordance with the proposed change would not: 1) involve a significant increase in the probability or consequences of any accident previously evaluated; 2) create the possibility of a new or different kind of accident from any accident previously evaluated; or 3) involve a significant reduction in a margin of safety. Energy Northwest has evaluated the proposed changes to the Columbia Generating Station Technical Specifications using the three criteria set forth in 10 CFR 50.92(c) and has determined that they involve no significant hazards consideration as described below:

1. Does the operation of Columbia Generating Station in accordance with the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The DG and its associated emergency loads are accident mitigating features, not accident initiating equipment. Therefore, there will be no impact on any accident probabilities by the approval of the requested amendment. The design of plant equipment is not being modified by these proposed changes. The capability of DG-1 and DG-2 to supply power to their safety related buses as designed will not be compromised by permitting performance of DG-3 testing during power operations. Columbia's Technical Specifications require the RCIC system to be operable whenever this testing is performed at power. This ensures that the high-pressure injection function is maintained during the time the HPCS injection valve is disabled during testing. In the event of a design basis accident during testing, the HPCS system could be returned to service well within the 14-day outage time allowed by Technical Specifications. Additionally, the ability of the Standby Liquid Coolant (SLC) system to perform its design safety function would not be affected because SLC is connected downstream of the HPCS injection valve. Therefore, there would be no significant impact on any accident consequences.

Based on the above, the proposed change to permit certain DG surveillance tests to be performed during plant operation will have no effect on accident probabilities or consequences. Therefore, the proposed change does not involve

I PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Attachment 1 Page 10 of 11 a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the operation of Columbia Generating Station in accordance with the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No No new accident causal mechanisms would be introduced as a result of NRC approval of this amendment request since no changes are being made to the plant that would introduce any new accident causal mechanisms. Equipment will be operated in the same configuration with the exception of the plant mode in which the testing is conducted. This amendment request does not impact any plant systems that are accident initiators; neither does it adversely impact any accident mitigating systems.

Based on the above, implementation of the proposed changes would not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does the operation of Columbia Generating Station in accordance with the proposed amendment involve a significant reduction in the margin of safety?

Response: No Margin of safety is related to the confidence in the ability of the fission product barriers to perform their design functions during and following an accident situation. These barriers include the fuel cladding, the reactor coolant system, and the containment system. The proposed changes to the testing requirements for the DG do not affect the operability requirements for the DG, as verification of such operability will continue to be performed as required. Continued verification of operability supports the capability of the DG to perform its required function of providing emergency power to plant equipment that supports or constitutes the fission product barriers. Consequently, the performance of these fission product barriers will not be impacted by implementation of this proposed amendment. In addition, the proposed changes involve no changes to setpoints or limits established or assumed by the accident analysis. On this, and the above basis, no safety margins will be impacted.

Energy Northwest concludes that there is no significant reduction in the margin of safety.

Based upon the analysis provided herein, the proposed amendments do not involve a significant hazards consideration.

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Page 11 of 11

6.0 ENVIRONMENTAL CONSIDERATION

The proposed license amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed license amendment does not involve; (i) a significant hazards consideration; (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite; or, (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment needs be prepared in connection with the proposed amendment.

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Proposed Technical Specifications Changes (mark-up)

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.11 -------------------NOTES -------------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1, 2, or 3.

However, credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of 24 months offsite power signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for Divisions 1 and 2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in < 15 seconds for DG-1 and DG-2, and in < 18 seconds for DG-3,

2. energizes auto-connected shutdown loads,

3. maintains steady state voltage

> 3910 V and < 4400 V,

• I

4. maintains steady state frequency 58.8 Hz and < 61.2 Hz, and

5. supplies permanently connected and auto-connected shutdown loads for

> 5 minutes.

(continued)

Columbia Generating Station 3.8.1-10 Amendment No. 149,169 181

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.12 --------------------NOTES -------------------

1. All DG starts may be preceded by an engine prelube period. " AP*

" C

2. This Surveillance shall not b%

performed in MODE 1 or 2. owever, credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated Emergency 24 months Core Cooling System (ECCS) initiation signal each required DG auto-starts from standby condition and:

a. For DG-1 and DG-2, in < 15 ýseconds achieves voltage > 3910 V, and after steady state conditions are reached, maintains voltage > 3910 V and

< 4400 V and, for DG-3, in

< 15 seconds achieves voltage

>3910 V, and after steady state conditions are reached, maintains voltage > 3910 V and < 4400 V;

b. In < 15 seconds, achieves frequency

> 58.8 Hz and after steady state conditions are achieved, maintains frequency 2 58.8 Hz and < 61.2 Hz;

c. Operates for > 5 minutes;

d. Permanently connected loads remain energized from the offsite.power system; and

e. Emergency loads are auto-connected to the offsite power system.

(continued)

Columbia Generating Station 3.8.1-11 Amendment No. 149,169 181

• I AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.16 ...........-- - NO --------------------

This Surveillanc all not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify each required DG: 24 months

a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c. Returns to ready-to-load operation.

SR 3.8.1.17 NOTE --------------------

Credit may be taken for unplanned events that satisfy this SR.

Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides 24 months the test mode by:

a. Returning DG to ready-to-load operation; and

b. Automatically energizing the emergency load from offsite power.

(continued)

Columbia Generating Station 3.8.1-15 Amendment No. 149,169 173

AC Sources -Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.18 ------------------NOTE ---------------------

This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify interval between each sequenced load 24 months block is within +/- 10% of design interval for each time delay relay.

SR 3.8.1.19 -------------------NOTES ---------------

1. All DG starts may be preceded by an engine prelube period.

(146-I fPPLI Fý&6u-

2. This Surveillance shall not b performed in MODE 1, 2, or However, credit may be taken for unplanned events that satisfy this SR.

Verify, on an actual or simulated loss of 24 months offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for DG-1 and DG-2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in < 15 seconds,

2. energizes auto-connected emergency loads,

3. maintains steady state-voltage

> 3910 V and < 4400 V, -: I (continued)

Columbia Generating Station 3.8.1-16 Amendment No. 149,169 181

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Proposed Technical Specifications Pages (retyped)

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.9 ----------------- NOTES ---------------------

1. Credit may be taken for unplanned events that satisfy this SR.

I

2. If performed with the DG synchronized with offsite power, it shall be performed at a power factor as close to the power factor of the single largest post-accident load as practicable.

Verify each required DG rejects a load greater than or equal to its associated single largest post-accident load, and 24 months following load rejection, the frequency is

< 66.75 Hz.

SR 3.8.1.10 ---------------- NOTES------------------

1. Credit may be taken for unplanned events that satisfy this SR.

I

2. If performed with the DG synchronized with offsite power, it shall be performed at the accident load power factor, or at a power factor as close to the accident load.power factor as practicable with the field excitation current > 90% of the continuous rating.

Verify each required DG does not trip and voltage is maintained < 4784 V during and following a load rejection of a load 24 months

> 4400 kW for DG-1 and DG-2 and > 2600 kW for DG-3.

(continued)

Columbia Generating Station 3.8.1-9 Amendment No. 149,169 173

.5j AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.11 -------------------NOTES -------------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1, 2, or 3 (not applicable to DG-3). However, credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of 24 months offsite power signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for Divisions 1 and 2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in < 15 seconds for DG-1 and DG-2, and in < 18 seconds for DG-3,

2. energizes auto-connected shutdown loads,

3. maintains steady state voltage

> 3910 V and . 4400 V,

4. maintains steady state frequency 58.8 Hz and < 61.2 Hz, and

5. supplies permanently connected and auto-connected shutdown loads for 5 minutes.

(continued)

Columbia Generating Station 3.8.1-10 Amendment No. 149,169,181-

AC Sources- Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.12 -------------------NOTES -------------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1 or 2 (not applicable to DG-3). However, credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated Emergency 24 months Core Cooling System (ECCS) initiation signal each required DG auto-starts from standby condition and:

a. For DG-1 and DG-2, in < 15 seconds achieves voltage > 3910 V, and after steady state conditions are reached, maintains voltage > 3910 V and 4400 V and, for DG-3, in 15 seconds achieves voltage 3910 V, and after steady state conditions are reached, maintains voltage > 3910 V and < 4400 V;

b. In < 15 seconds, achieves frequency k 58.8 Hz and after steady state conditions are achieved, maintains frequency Ž 58.8 Hz and < 61.2 Hz:

c. Operates for > 5 minutes;

d. Permanently connected loads remain energized from the offsite power system; and

e. Emergency loads are auto-connected to the offsite power system. -

(continued)

Columbia Generating Station 3.8.1-11 Amendment No. 149,169,1847

S AC Sources- Operating 3.8.1 SURVEILLANCE REQUIREMENTS T SURVEILLANCE FREQUENCY 4-SR 3.8.1.13 ------------------NOTE --------------------

Credit may be taken for unplanned events that satisfy this SR.

I Verify each required DG's automatic trips are bypassed on an actual or simulated ECCS initiation signal except: 24 months

a. Engine overspeed;

b. Generator differential current; and

c. Incomplete starting sequence.

(continued)

Columbia Generating Station 3.8.1-12 Amendment No. 149,169 173

4 AC Sources -Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.16 -------------------NOTE --------------------

This Surveillance shall not be performed in MODE 1, 2, or 3 (not applicable to DG-3).

However, credit may be taken for unplanned I

events that satisfy this SR.

Verify each required DG: 24 months

a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c. Returns to ready-to-load operation.

SR 3.8.1.17 ------------------ NOTE ---------------------

Credit may be taken for unplanned events that satisfy this SR.

Verify, with a DG operating in test mode 24 months and connected to its bus, an actual or simulated ECCS initiation signal overrides the test mode by:

a. Returning DG to ready-to-load operation; and

b. Automatically'energizing the emergency load from offsite power.

(continued)

Columbia Generating Station 3.8.1-15 Amendment No. 149,169,17-3

AC Sources- Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.18 -----------------NOTE------------------

This Surveillance shall not be performed in MODE 1, 2. or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify interval between each sequenced load 24 months block is within +/- 10% of design interval for each time delay relay.

SR 3.8.1.19 ------------------ NOTES----------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1, 2, or 3 (not applicable to DG-3). However, credit I may be taken for unplanned events that satisfy this SR.

Verify, on an actual or simulated loss of 24 months offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for DG-1 and DG-2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in < 15 seconds,

2. energizes auto-connected emergency loads, (continued)

Columbia Generating Station 3.8.1-16 Amendment No. 149,169,181-

AC Sources -Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.19 (continued)

3. maintains steady state voltage

> 3910 V and ( 4400 V.

4. maintains steady state frequency

> 58.8 Hz and < 61.2 Hz, and

5. supplies permanently connected and auto-connected emergency loads for

> 5 minutes.

SR 3.8.1.20 ------------------- NOTE --------------------

All DG starts may be preceded by an engine prelube period.

Verify, when started simultaneously from 10 years standby condition, DG-1 and DG-2 achieves, in < 15 seconds, voltage > 3910 V and frequency Ž 58.8 Hz, and DG-3 achieves, in

< 15 seconds, voltage > 3910 V and frequency > 58.8 Hz.

Columbia Generating Station 3.8.1-17 Amendment No. 149,169,184-

PROPOSED AMENDMENT OF FACILITY OPERATING LICENSE TO REMOVE OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING Changes to Technical Specifications Bases

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.3. SR 3.3.5.1.4. and SR 3.3.5.1.5 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequencies are based upon the assumption of a 92 day, 18 month, or 24 month calibration interval, as applicable, in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.5.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage~and the potential for unplanned transients if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. FSAR, Section 6.2.

2. FSAR, Section 6.3.

3. FSAR, Chapter 15.

4. 10 CFR 50.36(c)(2)(ii).

5. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.

Columbia Generating Station B 3.3.5.1-40 Revision 35

ECCS- Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.5 REQUIREMENTS (continued) The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for anunplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

SR 3.5.1.6 The ADS designated SRVs are required to actuate automatically upon receipt of specific initiation signals.

A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e.,

solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. This Surveillance also ensures the automatic alignment of the ADS accumulator backup compressed gas system on an actual or simulated ADS header pressure low signal. SR 3.5.1.7 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety 'function.

The 24 month Frequency is based on the need to perform this Survllance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

Columbia Generating Station B 3.5.1-12 Revision 241

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.

The requirement to verify the connection and power supply of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained I>,' APP L1 C'Xf31jý consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove 1I 2-)'G3 a required offsite circuit from service, perturb the ect 'cal distribution system, and challenge plant safety system. Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.1.12 Consistent with Regulatory Guide 1.9 (Ref. 12), paragraph C.2.2.5, this Surveillance demonstrates that the DG (continued)

Columbia Generating Station B 3.8.1-27 Revision 44

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS to the electrical distribution systems that could challenge con dy state operation and, as a result, plant

-,4*'#p* safety system . Credit may be taken for unplanned events RPP L I C AdL1 _66 that satisfy this SR.

G3SR 3.8.1.13 Consistent with Regulatory Guide 1.9 (Ref. 12), paragraph C.2.2.12, this Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ECCS initiation test signal and critical protective functions (engine overspeed, generator differential current, and incomplete starting sequence) trip the DG to avert substantial damage to the DG unit. The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately.

The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The 24 month Frequency is based on engineering judgment, taking into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

The SR is modified by a Note., The reason for the Note is that credit may be taken for unplanned events that satisfy this SR.

SR 3.8.1.14 Consistent with Regulatory Guide 1.9 (Ref. 12),

paragraph C.2.2.9, this Surveillance requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of which is at a load equivalent to 90% to 100% of frnntinijpd Columbia Generating Station B 3.8.1-29 Revision 44

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.15 (continued)

REQUIREMENTS Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

SR 3.8.1.16 Consistent with Regulatory Guide 1.9 (Ref. 12),

paragraph C.2.2.11, this Surveillance ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and that the DG can be returned to ready-to-load status when offsite power is restored. It also ensures that the auto-start logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs.

The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and the individual load timers are reset.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycles.

This S2 R is modified by a Note.--he reason for the Note is Jre u performing the Surveillance would remove a requiredion that g6-" A'PPLIC9LZ offsite circuit from service,aperturb te the electri

• *^*\

• distribution system, and challenge safety system. Credits may be taken for unplanned events that satisfy this SR.

SR 3.8.1.17 Consistent with Regulatory Guide 1.9 (Ref. 12), paragraph C.2.2.13, demonstration of the parallel test mode override ensures that the DG availability under accident conditions is not compromised as the result of testing. Interlocks to the LOCA sensing circuits cause the DG to automatically reset to ready-to-load operation if an ECCS initiation (continued)

Columbia Generating Station B 3.8.1-32 Revision 44

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)

REQUI REMENTS The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with an expected fuel cycle length.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil (4pr.1 being continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason t9PPL)e ABLi* for Note 2 is that performing the Surveillance would remove 3ired offsite circuit from service, perturb the electri al distribution system, and challenge plant safety ystem Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 12), paragraph C.2.2.14.

This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. FSAR, Chapter 8.

3. Deleted (continued)

Columbia Generating Station B 3.8.1-35 Revision 44