ML053480168
| ML053480168 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/26/2005 |
| From: | Rosalyn Jones Duke Power Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML053480168 (14) | |
Text
PWDuke RONALD A JONES Power Oconee Nuclear Site Duke Power ON01 VP / 7800 Rochester Hwy.
Seneca, SC 29672 864 885 3158 864 885 3564 fax October 26, 2005 U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Attention: Document Control Desk
Subject:
Oconee Nuclear Station Docket Numbers 50-269, 270, and 287 Response to Request for Additional Information Pertaining to Defense in Depth and Diversity Assessment Associated with the Digital Upgrade of Oconee's Reactor Protective System and Engineered Safeguards Protective System On March 20, 2003, Duke Energy Corporation submitted a defense-in-depth and diversity (D-in-D&D) assessment associated with the planned digital upgrade of the reactor protective system (RPS) and the engineered safeguards protective system (ESPS) at Oconee Nuclear Station (ONS). Duke met with the NRC on July 1, 2003 to present the results of the D-in-D&D assessment. At the time of submittal, Duke requested the NRC to review and approve the D-in-D&D assessment prior to submitting the License Amendment Request (LAR) for the RPS/ESPS digital modification to allow Duke to finalize design requirements for the modification. The LAR associated with this modification was subsequently submitted on February 14, 2005.
During the July 1, 2003, meeting, the NRC staff requested that Duke docket information provided during the meeting and provide additional information subsequent to the meeting. The additional information was provided via phone conversations or electronic mail within two months of the meeting. Duke docketed the information by letter dated September 23, 2004. In that letter, Duke requested approval of the D-in-D&D assessment by October 31, 2004.
www. dukepower. corn
U. S. Nuclear Regulatory Commission October 26, 2005 Page 2 Subsequently, in an August 17, 2005, meeting to address RAIs on the RPS/ESPS LAR, NRC indicated that the Staff had additional questions associated with the operator response times for certain events analyzed in the D-in-D&D assessment. These questions were provided verbally during the meeting and by electronic mail on August 26, 2005. The Attachment provides Duke's response to the additional questions.
In the response to RAI 7 in the Attachment, Duke committed to provide the results of sensitivity analyses by December 15, 2005.
If there are any additional questions, please contact Boyd Shingleton at (864) 885-4716.
Very tr y ours, R. A Jo s, Vice President Oconee Nuclear Site
U. S. Nuclear Regulatory Commission October 26, 2005 Page 3 cc: Mr. L. N. Olshan, Project Manager Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop 0-14 H25 Washington, D. C. 20555 Dr. W. D. Travers, Regional Administrator U. S. Nuclear Regulatory Commission - Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, Georgia 30303 Mr. M. C. Shannon Senior Resident Inspector Oconee Nuclear Station Mr. Henry Porter, Director Division of Radioactive Waste Management Bureau of Land and Waste Management Department of Health & Environmental Control 2600 Bull Street Columbia, SC 29201
U. S. Nuclear Regulatory Commission October 26, 2005 Page 4 bcc:
Robert E. Hall James T. Fuller Robert W. Cornett Barry R Loftis Barbara M. Thomas B. Graham Davenport T. P. Gillespie Robert L. Medlin Lisa F. Vaughn Paul M. Stovall David B. Coyle Scott L. Batson Robert L. Gill - NAID Lee A Keller - CNS Charles J. Thomas - MNS Gregg B. Swindlehurst H Duncan Brewer Robert P Boyer NSRB, EC05N ELL, ECO50 File - T.S. Working BWOG Tech Spec Committee (5)
ONS Document Management Reene' V. Gambrell a
U. S. Nuclear Regulatory Commission October 26, 2005 Page 5 R. A. Jones, being duly sworn, states that he is Vice President, Oconee Nuclear Site, Duke Energy Corporation, that he is authorized on the part of said Company to sign and file with the U. S. Nuclear Regulatory Commission this revision to the Renewed Facility Operating License Nos. DPR-38, DPR-47, DPR-55; and that all the statements and matters set forth herein are true and correct to the best of his knowledge.
R. A. Jon s ice President Oconee Nu lear Site Subscribed and sworn to before me this day of 2005 W' Comary EPublic My--
Commnission Expires:
October 26, 2005 Page 1 Attachment NRC Request for Additional Information (RAI)
Associated with the Digital Upgrade of Oconee's Reactor Protective System and Engineered Safeguards Protective System NRC Background Information The NRC requests additional information pertaining to the assessment of the Control Rod Ejection and the Small Break Loss of Coolant Accident (LOCA).
Control Rod Ejection The licensee proposed crediting the following operator actions:
- Manual high pressure injection (HPI) actuation at 5 minutes.
- Manual reactor building cooling system (RBCS) and reactor building spray (RBS) actuation at 8 minutes.
Small Break LOCA - Essentiallythe same questions The licensee proposed crediting the following operator actions:
- Manual reactor trip at 2 minutes.
- Manual reactor building cooling system (RBCS) and reactor building spray (RBS) actuation at 8 minutes.
Duke Background Information Duke's responses to the questions were combined since the Small Break Loss of Coolant Accident (SBLOCA) scenario bounds the control rod ejection scenario. The basis for this is provided in Duke's response to RAI 6.
RAI 1
What alarms and indications will the operators use to determine that a manual reactor trip is required during this event? What alarms and indications will the operators use to determine that manual HPI actuation is required during this event? What alarms and indications will be used to determine that manual RBCS and RBS actuation are required? Please verify that the alarms and indications used will be available and unaffected by the RPS/ESPS SWCMF. Where are these alarms/indications located (on the main control panels in the control room or locally or both?).
Attachment October 26, 2005 Page 2 Duke Response to RAI 1 Oconee operators will continue to use Reactor Coolant System (RCS) pressure, pressurizer level, RCS makeup flow, and/or subcooling margin indications to determine whether a reactor trip is required. The operators will continue to use subcooling monitors or wide range RCS pressure or RB pressure indications to recognize the need to initiate HPI. The operators will continue to use RB pressure indications to initiate Reactor Building Cooling (RBC) and Reactor Building Spray (RBS) Systems. Alarms that will actuate are not used by operators to mitigate the event or to take actions but rather to reinforce their recognition of the conditions that exist.
These indications and alarms will be available and unaffected by the Reactor Protective System (RPS)/Engineered Safeguards Protective System (ESPS) Software Common Mode Failure (SWCMF) and are located on the front control board in the control room.
With the exception of RCS makeup flow, the indications identified above are Regulatory Guide (RG) 1.97 instrumentation.
RAI 2
In detail, what is/are the manipulations required to manually trip the reactor. What is/are the manipulations required to manually actuate HPI and LPI, RBCS, and RBS? (For example, will reactor trip pushbuttons be used? Are all ESPS functions (HPI, low pressure injection (LPI), RBS, RBCS, reactor building isolations) manually actuated from common push buttons?) Please verify that the controls used will be available and unaffected by the RPS/ESPS SWCMF. Where are these actuation controls located (on the main control panels in the control room or locally or both?)
Duke Response.to RAI 2 Operators are required to push one button to initiate a reactor trip. The manual reactor trip function is independent of the automatic RPS trip function and will be unaffected by the RPS/ESPS SWCMF. The manual reactor trip pushbutton is located on the main control board. This is true for the current and the proposed RPS/ESPS design.
Engineered Safeguards at Oconee consists of eight channels. Channels 1&2 provide High Pressure Injection and Non-essential Containment Isolation. Channels 3&4 provide Low Pressure Injection and Low Pressure Service Water. Channels 5&6 provide Reactor Building Cooling, Reactor Building Essential Isolation, and Penetration Room Ventilation. Channels 7&8 provide Reactor Building Spray. Each of these eight channels has a TRIP pushbutton that will actuate the channel when pressed (i.e., there are eight TRIP pushbuttons). To manually initiate Engineered Safeguards for any channel, operators depress one TRIP pushbutton for each Channel. For example to initiate both channels of HPI and Non-essential RB isolation, operators are required to push two buttons (one for Channel 1 and one for Channel 2). All ESPS Channel Trip pushbuttons are directly adjacent to each other and located on the front Main Control
Attachment October 26, 2005 Page 3 Board. The same sequence must be followed for each of the other channels. This is true for the current and the proposed RPS/ESPS design.
RAI 3
What alarms and indications will the operators use to determine the success of their actions, i.e., that manual actuation of HPI, RBCS, and RBS were successful? Please verify that the alarms and indications used will be available and unaffected by the RPS/ESPS SWCMF. Where are these actuation controls located (on the main control panels in the control room or locally or both?)
Duke Response to RAI 3 The operator by procedure and training will verify the expected system responses using RG 1.97 indications (flow, pressure, level, etc). The status of ESPS devices (pumps, valves, fans) is provided by a light indication at the control board switches for each of the devices so the operator can determine whether the device is On/Off or Open/Closed.
HPI/RBS status can also be confirmed by checking their associated flow indicators.
None of these indications would be affected by a RPS/ESPS SWCMF. Other indications are also available to the operator via the OAC (Operator Aid Computer) to provide additional information. Alarms are NOT used by operators to mitigate event(s); however they can be used to assess the status of systems & equipment. Pump status can also be determined by observing pump amp indications.
RAI 4
Please discuss how the indications and operator actions are driven by plant procedures.
Duke Response to RAI 4 The SBLOCA scenario would prompt entry into the abnormal procedure (AP) for excessive RCS leakage due to exceeding the Technical Specification (TS) RCS leakage limit. This would be recognized by decreasing RCS pressure, rapidly decreasing pressurizer level, increasing HPI makeup flow, and/or loss of subcooling margin. The Immediate Manual Actions (IMAs) of the AP require a reactor trip if normal RCS makeup capability is exceeded. The reactor trip prompts entry into the IMAs of the EOP and subsequent Rules. For the control rod ejection scenario, the Diverse Scram System (DSS) would automatically trip the reactor which would prompt entry into the Emergency Operating Procedure (EOP) IMAs.
EOP Rule 2 (Loss of Subcooling Margin) requires HPI to be manually actuated. Once IMAs are complete, the SRO transfers to Subsequent Actions (SAs). Once the need for ESPS is recognized by the operator, the SRO will direct the performance of Enclosure 5.1. Enclosure 5.1 requires operators to verify that all required ESPS channels have actuated. If they have not, the EOP directs the operators to actuate the affected ESPS channels. Operations procedures direct the operators to actuate the channels when the
Attachment October 26, 2005 Page 4 actuation setpoints have been exceeded. HPI would be manually actuated when RCS pressure is < 1600 psig (ESPS actuation setpoint). RBCS and RBS would be manually actuated when RB pressure 2 3 psig and 10 psig respectively (ESPS actuation setpoints).
RAI 5
Please present a rough time-line from event initiation for indications/alarms received, procedures entered, decision making, and actions taken.
Duke Response to RAI 5 Duke opted to conduct validation runs using operating crews in the control room simulator, as suggested by RAI 6, to establish the time-line from event initiation for indications/alarms received, procedures entered, decision making, and actions taken.
Refer to Duke's response to RAI 6
RAI 6
All of the above information can be gathered by conducting carefully monitored validation runs (demonstrations) using operating crews in the control room simulator. To that end, and to provide a level of assurance that the proposed operator actions are feasible (i.e., can be performed in the time available such that damage to the plant, personnel, or an undesirable plant condition is avoided), and can be performed reliably (i.e., the actions are successfully performed by different crews), please conduct validation runs as follows:
Perform on a minimum of three operating crews, using the minimum crew size allowed by plant procedures/Technical Specifications.
Configure the simulator as best as possible for the given event conditions: A control rod ejection event, with no automatic reactor trip, no automatic ESPS actuation, and all indications, alarms, and controls downstream of RPS and ESPS inoperable. Please choose conditions (e.g., initial reactor power, neutron flux profile, control rod selected for ejection, etc.) that result in the most limiting times for operator actions.
Do not pre-announce or pre-brief the crews on the scenario that will be run.
Conduct as an "out of the box" simulator scenario.
Please provide a time line for each crew from the start of event initiation, to include: indications and alarms received, procedures entered, steps performed, and the times when the proposed actions are taken, i.e., HPI, RBCS, and RBS actuations.
Attachment October 26, 2005 Page 5 Duke Response to RAI 6 Duke conducted simulator validation runs to demonstrate that the operator actions times assumed in the Defense-in-Depth & Diversity (D3) Assessment for the control rod ejection and SBLOCA scenarios are feasible and can be performed reliably. This validation was performed by three operating crews, using the minimum crew size (1 SRO and 2 ROs) allowed by the Oconee Selected Licensee Commitment (SLC) Manual.
The simulator was configured as best as possible for the given event conditions, as described below. Conditions were selected that would result in the most limiting times for operator actions. The simulator validation runs were unannounced.
A composite scenario was selected for the simulator validation runs. The basis for the composite scenario, which considers the limiting aspects of both the control rod ejection and SBLOCA scenarios, with the objective of defining a limiting scenario, is provided below.
All of the information was gathered by conducting carefully monitored validation runs (demonstrations) using operating crews in the control room simulator. For the control rod ejection event, the DSS would rapidly trip the reactor on high RCS pressure when RCS pressure reaches 2450 psig. Due to the present operational configuration (rods between greater than 88% withdrawn on Group 7), Oconee would not have a reactivity excursion and resultant RCS pressure spike upon rod ejection. Therefore, it is more conservative not to simulate the DSS trip. The operators were required to recognize the need for a reactor trip based on excessive RCS leakage symptoms. At that point, the EOP would be entered and followed as described in the response to RAI 4 above. A time-line from event initiation for indications received, procedures entered, decision making, and actions taken is provided below based on three simulator validations performed by different shift crews with the minimum crew size allowed by the Oconee Selected Licensee Commitments (SLC) Manual.
Initial Conditions:
- 100% FP, End of Life
- Unit 2 and 3 at 100%
- Operational Aid Computer is Out-of-Service (all OAC screens were off) to prevent numerous indications and alarms related to ESPS and RPS being available to the operator (due to the inability to block specific alarms that would not be available).
- Unit 2 is performing Loss of Computer procedure Event
- T=O LOCA equivalent to 1.5" diameter break initiated
- T=0 RPS and ESPS fail to actuate
Attachment October 26, 2005 Page 6 The following is the data collected from 3 independent crews:
Crew 1 Crew 2 Crew 3 D3 09113/05 09118105 09/22J05 Assumption
________________________(minl/sec) (min/sec) (min/sec) (min/sec)
Event Start 0:00 0:00 0:00 0:00 Rx Manually Tripped 0:35 0:18 0:34 2:00 RCS Press=1600 psig (ES 1&2 1:07 0:51 1:07 Setpt)
Subcooling Margin=0 1:38 1:13 1:24 ESPS 1&2 (HPI) Manually Initiated 1:40 1:44 1:43 5:00 RB Press=3 psig (ES 3,4,5,6 Setpt) 2:52 2:52 2:52 ESPS 3, 4, 5, 6 Manually Initiated 3:22 3:21 2:57 8:00 RB Press=10 psig (ES 7&8 Setpt) 8:38 8:39
- ESPS 7&8 Manually Initiated 9:07 9:47 6:46 8:00
- Crew actuated ESPS 7&8 in anticipation of reaching 10 psig Since the setpoint for RBS actuation is not reached until approximately 8.5 minutes into the event, the assumed time of 8 minutes for actuation was not achieved for two of the crews. Both of the crews initiated RBS within 30 seconds of reaching the setpoint. The operator response time for containment cooling is not critical since its purpose is for long term mitigation. The sensitivity studies performed in response to RAI 7 will demonstrate this point.
Basis for Composite Scenario 2
The scenario selected for performing the simulator validation is a 0.0123 ft break located on the reactor vessel head. This break area is the same as that modeled in the UFSAR Chapter 15.12 rod ejection analysis. No ejected control rod is simulated. The operator action times for the small break LOCA are applied.
The RAI requests Oconee to perform simulator validation of the operator action response times specified for the control rod ejection and SBLOCA transients. To facilitate this request, a composite scenario was selected. The basis for the composite scenario, which considers the limiting aspects of both transients with the objective of defining a limiting scenario for use in performing simulator validation, is provided below.
The operator action times involved are applicable to both transients with one exception.
The 2 minute operator action time to manually trip the reactor is only specified for the SBLOCA transient as the control rod ejection transient described in the D3 assessment will result in a DSS actuation. The operator action times identified for manual actuation of HPI, RBCS and RBS are intentionally specified to be identical as these times were based upon procedural response and not transient phenomena. Each of the operator action times will be addressed below.
Attachment October 26, 2005 Page 7 The control rod ejection transient described in the D3 assessment is based on the UFSAR Chapter 15.12 Rod Ejection Accident. The SBLOCA transient is a core flood line break (CFLB). Both transients include a SBLOCA, with the control rod ejection having a 1.5 inch diameter break (0.0123 ft2) on the reactor vessel head, and the CFLB being a 0.44 ft2 break on the reactor vessel downcomer. There are a wide variety of alarms that have the potential for alerting the operator to the presence of each transient.
The indication selected for use in determining the operator response times is the RCS subcooled margin. The rate at which the RCS pressure decreases is the primary consideration in determining when a loss of subcooled margin is expected to occur.
2 Thus, the RCS pressure response obtained for a 0.0123 ft break (control rod ejection) is expected to be significantly slower that of a 0.44 ft2 break (CFLB).
The control rod ejection transient described in the D3 assessment will trip the reactor on a DSS actuation. The CFLB transient requires operator action to trip the reactor. Given these two vastly different transient responses, it is possible to conservatively bound the operator action to trip the reactor. The smaller control rod ejection break will provide a less significant transient response which will result in a slower operator response time.
Similarly, the indications available to the operator for the control rod ejection break are likely to delay the response to initiate HPI. Since both the control rod ejection and CFLB utilize the same operator action time, the less severe transient was used in the simulator validation.
The operator action time to initiate LPI flow has been replaced by the addition of a diverse LPI actuation signal to ensure satisfactory results for a double-ended guillotine large break LOCA. The response time for the diverse LPI actuation is anticipated to be significantly faster than that considered in the analyses. Thus, this aspect of the operator response times does not need to be validated.
The final operator action time that needed to be considered is the actuation of the RBC and RBS systems. The RB pressure setpoints for these actuations are 3 psig for the RBC system actuation and 10 psig for RBS system. The same time is provided for both of these actuations based upon procedural response and not transient phenomena. The containment building pressurization from a 0.01 23 ft2 break (control rod ejection) is much less than that of a 0.44 ft2 break (CFLB). Therefore the smaller of the two breaks is also appropriate for use in the simulator validation.
RAI 7
How much time is available for operators to take the actions such that accident acceptance criteria are met (reactor coolant system overpressure, radiological, reactor building pressure, coolable geometry)?
(It is clear from the licensee's submittal what operator action times were assumed - what is not clear is how much time do operators have.)
Attachment October 26, 2005 Page 8 Response to RAI 7 Duke is performing sensitivity analyses to demonstrate that additional time is available for operator actions. However, the results of the simulator validations clearly demonstrate margin is available for operator response times. The response to this RAI will be supplemented by December 15, 2005 with the results of the sensitivity analyses.
Other Questions:
RAI 8
Please describe any proposed additional procedural guidance associated with the new digital RPS/ESPS.
RAI 9
Please describe any proposed additional licensed operator training associated with the new digital RPS/ESPS.
Response to RAI 8 and 9 The need for new operator procedural guidance and additional licensed operator training associated with the new digital RPS/ESPS has been identified and is scheduled for development. This is developed as part of the plant modification process and must be completed prior to implementation in the fall of 2006 for the first unit.
RAI 10
Please describe any plans for proposed simulator modifications, such that the simulator will accurately model the new digital RPSIESPS.
Response to RAI 10 The simulator will be modified to accurately model both the new digital RPS/ESPS and maintain the old RPS/ESPS system. This modification will be completed on a schedule consistent with the schedule for implementing the digital upgrade on Unit 1. The old RPS/ESPS will be maintained for operator training until the digital upgrade is completed on all three Oconee Units. The modification on the last Unit (Unit 2) is scheduled to be completed in the fall 2008 outage. At that time, the old model will be removed.
Attachment October 26, 2005 Page 9
RAI 11
In the event of non-accidents, how will operators respond to instances where the TXS system becomes unavailable? Would they be required to assume more manual duties as a pre-caution to mitigate against accidents such as SB LOCA?
Response to RAI 11 The operator will respond the same as they are required to do now. If a required channel of the TXS system becomes unavailable during MODES of APPLICABILITY, the applicable Required Actions (RAs) of Technical Specification 3.3.1 are required to be taken within the Completion Time of the applicable RAs. If the entire TXS system becomes inoperable (or unavailable), a unit shutdown would be required.
Because of these requirements, there is no need for the operator to assume more manual duties and this would not be required.