View source for MNS-14-070, Duke Energy Request for NRC Grant Discretion from Enforcing the Shutdown Requirement of Technical Specifications (TS) 3.8.1 (AC Sources - Operating)

{{Adams
| number = ML14251A026
| issue date = 08/25/2014
| title = Duke Energy Request for NRC Grant Discretion from Enforcing the Shutdown Requirement of Technical Specifications (TS) 3.8.1 (AC Sources - Operating)
| author name = Capps S
| author affiliation = Duke Energy Carolinas, LLC
| addressee name = 
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000369
| license number = 
| contact person = 
| case reference number = MNS-14-070
| document type = Letter type:MNS
| page count = 16
}}

=Text=
{{#Wiki_filter:Steven D. Capps Vice President ENERGY.                                                                                      McGuire Nuclear Station Duke Energy MG01VP 1 12700 Hagers Ferry Road Huntersville, NC 28078 o: 980.875.4805 f: 980.875.4809 Steven .Capps@duke-energy.com August 25, 2014 Serial: MNS-14-070 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555

==Subject:==
Duke Energy Carolinas, LLC (Duke Energy)
McGuire Nuclear Station, Unit 1 Docket Number 50-369 Notice of Enforcement Discretion (NOED) Request Technical Specifications (TS) 3.8.1 (AC Sources - Operating)
Duke Energy requests that the NRC grant discretion from enforcing the shutdown requirement of the above TS. This request was discussed with the NRC staff in a telephone conference call on August 21, 2014. The enforcement discretion was granted verbally by the NRC following the conference call. This submittal (letter and enclosure) fulfills the requirement to submit the written enforcement discretion request within two working days of the oral request.
This request concerns an extension of the TS Completion Time for Diesel Generator (DG) "1B" inoperability from the current 72 hours by an additional 48 hours for a total of 120 hours. The issue necessitating this NOED request is failure of an intake valve stem on Cylinder 5 Left on DG "1B". The piston, head assembly (which includes valves), cylinder liner, and pushrods are being replaced and the replacement activity cannot be completed within the Completion Time requirement of the above TS. The details of this request are fully explained in the enclosure to this letter.
McGuire was performing DG "1B" 24 hour run when the intake valve failure condition was discovered. As shown in the enclosed justification, Duke Energy maintains that granting of enforcement discretion in this case is in the best interest of nuclear safety.
The enclosure to this letter provides the information required by NRC Inspection Manual Chapter 0410, "Notices of Enforcement Discretion".
Duke Energy has reviewed NRC Inspection Manual Chapter 0410 and has concluded that Section 06.02a.1(a) is satisfied. Enforcement discretion is required to avoid an unnecessary plant transient, as a result of complying with the requirement of the above TS. Enforcement discretion would minimize potential safety consequences and operational risks.
This NOED request was reviewed and approved by the McGuire Plant Operations Review Committee on August 21, 2014. It was subsequently granted by the NRC on the same day.
DG "IB" was restored to operable status on August 23, 2014 at 0424 hours.
There are no regulatory commitments in this submittal.
www.duke-energy.com

U.S. Nuclear Regulatory Commission Page 2 August 25, 2014 Inquiries on this matter should be directed to George Murphy, McGuire Regulatory Affairs, at (980) 875-5715.
Sincerely, Steven D. Capps Attachment

U.S. Nuclear Regulatory Commission Page 3 August 25, 2014 xc (with attachment):
V.M. McCree Regional Administrator U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 G.E. Miller NRC Project Manager (McGuire)
U.S. Nuclear Regulatory Commission One White Flint North, Mail Stop 8 G9A 11555 Rockville Pike Rockville, MD 20852-2738 J. Zeiler Senior Resident Inspector (McGuire)
U.S. Nuclear Regulatory Commission McGuire Nuclear Station W.L. Cox III, Section Chief North Carolina Department of Environment and Natural Resources Division of Environmental Health, Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699-1645

U.S. Nuclear Regulatory Commission                                                   Attachment August 25, 2014                                                                      Page 1 McGuire Nuclear Station, Unit 1 Request for Enforcement Discretion TS 3.8.1 (AC Sources - Operating)

===Background===
At McGuire, a dedicated DG is utilized as the standby emergency power source for each 4160-volt emergency bus. On a safety injection signal or on a bus loss of voltage or degraded voltage signal, DG "1B" will start automatically to supply electrical power to 4160-volt emergency bus 1ETB. DG "1B" was declared inoperable on August 18, 2014, at 1729. The DG was secured approximately 14 hours into its 24 hour run due to a problem with cylinder 5L.
On August 18, 2014, at 1718, DG "1 B" cylinder 5L had exhaust temperature monitors drop from a steady 741 OF down to 611 OF. Control room and local indications of KW, KVARS, KV, Amps, and Power Factor were observed to be fluctuating. The OSM directed a procedural shutdown (stepping down load) of DG "1B." An SRO in the field reported an unusual sound from the engine when load was reduced. At this time, the OSM directed unloading and stopping DG "I1B" immediately and DG "l B" was declared inoperable on August 18, 2014, at 1729 hours.
The most probable cause of DG "1B" inoperability is high cycle fatigue failure of an intake valve on cylinder 5L, as determined by Metallurgy Laboratory results. Repair and operability testing of DG "1 B" will not be completed within the 72 hour completion time mandated by TS 3.8.1, Required Action B.4. Therefore, Duke Energy is requesting that the Completion Time of the above Required Action be extended from the current 72 hours by an additional 48 hours, for a total of 120 hours, so that this work can be completed.
Duke Energy hereby requests that the NRC grant discretion in enforcing TS LCO 3.8.1 relative to compliance with the 72-hour Completion Time of Required Action B.4 and allow McGuire Unit 1 to remain in Mode 1 (Power Operation) until repairs are completed and testing to demonstrate operability of DG "1 B" is completed.
Basis for NOED Duke Energy has reviewed NRC Inspection Manual Chapter (IMC) 0410, "Notices of Enforcement Discretion," and has concluded that the criteria specified in IMC 0410, Section 06.02a.1 .(a.) for a Regular NOED is satisfied. This criterion applies to plants in power operation desiring to avoid unnecessary transients as a result of compliance with the TS or license condition and thus minimize the potential safety consequences and operational risks.
Duke Energy performed a risk-informed evaluation demonstrating the risk associated with continued operation for an additional 48 hours is within the plant's normal risk management controls. There is no net increase in radiological risk to the public or adverse impact on the environment associated with a Completion Time extension of 48 hours. Normal work control risk management impact, expressed in terms of incremental core damage probability and large early release probability, are specified in industry and NRC guidance on configuration risk management. Conclusions of the risk-informed analysis are included below as the safety basis for the request, which includes an evaluation of the safety significance and potential consequences of the proposed course of action.

U.S. Nuclear Regulatory Commission                                                  Attachment August 25, 2014                                                                      Page 2 The following provides the information, described in IMC 0410, required to be included in requests for enforcement discretion.
: 1. Type of NOED being requested, which of the NOED criteria is satisfied, and how those criteria are satisfied.
This request is for a Regular NOED. The requested enforcement discretion is not associated with a natural event. It is requested to avoid an unnecessary plant transient of McGuire Unit 1.
The proposed enforcement discretion request meets the first NOED criteria in Section 03.03 of IMC 0410 by avoiding an unnecessary plant transient and thus minimizes potential safety consequences and operational risks as a result of compliance with TS 3.8.1, Required Actions B.4 and G.
: 2. TS or license condition that will be violated.
Duke Energy is requesting enforcement discretion from TS LCO 3.8.1, Required Action B.4.
This LCO governs AC Sources - Operating for Modes 1, 2, 3, and 4. LCO 3.8.1 requires in part that two DGs be operable. Condition B for this LCO states that with one DG inoperable, the DG must be restored to operable status within 72 hours, in addition to the other Required Actions that must be performed. Condition G states that with the Required Action and associated Completion Time of Condition B not met, the unit must be in Mode 3 within 6 hours and in Mode 5 within 36 hours.
Without enforcement discretion, McGuire Unit 1 will have to enter Condition G no later than August 21, 2014, at 1729 hours; be in Mode 3 in 6 hours (2329 hours on August 21, 2014); and be in Mode 5 in 36 hours (0529 hours on August 23, 2014).
: 3. Description of the circumstances, including: likely causes; the need for prompt action; the action taken to avoid the need for a NOED; and any relevant historical events.
DG "IB" was declared inoperable on August 18, 2014, at 1729 hours. The DG was secured approximately 14 hours into its 24 hour run due to unusual sounds and load/voltage fluctuations on both local and control room indications.
Cylinder 5L exhibited a knocking noise and a significant drop in cylinder exhaust temperature (from a steady 741 OF down to 611 OF) during the 24-hour test for DG "1B." Control room and local indications of KW, KVARS, KV, Amps, and Power Factor were observed to be fluctuating.
The OSM directed a procedural shutdown (stepping down load) of DG "l B." An SRO in the field reported an unusual sound from the engine when load was reduced. At this time the OSM directed unloading and stopping DG "1B" immediately and DG "1 B" was declared inoperable on August 18, 2014, at 1729 hours.
Duke Energy has been engaged in troubleshooting and repair efforts since DG "IB" was declared inoperable. Unit Threat and Failure Investigation Process (FIP) teams were immediately formed, and troubleshooting/recovery commenced with continuous coverage.
The cause of the DG "I B" inoperability is failure of an intake valve stem on cylinder 5L. When the rocker box was removed, the intake valve spring was in a relaxed state (not compressed),

U.S. Nuclear Regulatory Commission                                                      Attachment August 25, 2014                                                                         Page 3 indicating that the intake valve and/or stem was broken and was no longer captured by the valve stem keeper. Further examination concluded that the intake valve failed at the bottom of the keeper groove on the valve stem which in turn caused the valve to repeatedly contact the valve seat insert partially breaking it into small pieces which fell into the cylinder damaging the piston, head, exhaust valve, and cylinder liner.
Duke Energy's Metallurgy Laboratory analyzed the broken valve stem. Relatively fine striations with no apparent ductile tearing, combined with relatively large fracture area, suggests that high cycle fatigue caused the failure of the intake valve stem on cylinder 5L. Estimated cycles based on run time per year over an installed life of 16 years at rated engine speed is approximately 27 million cycles, which is well below the expected service life.
Operating Experience (OE) revealed a similar event occurred at McGuire. In 1984, DG "IA" experienced an exhaust valve stem failure similar to the current failure of DG "1B" intake valve stem. This metallurgical report indicated the valve stem failed due to high cycle fatigue. The apparent cause was incorrect adjustment of the valve tappet setting or by backing off the adjusting screw. This event also led to breaking off of pieces of the valve seat, which also occurred in DG "1B" cylinder 5L.
Inspection results going back to 2008 and 2013 show there have not been any significant changes to the tappet to valve clearance. Inspections performed in 2008 and 2013 both indicate 5 threads above the lock nut before and after adjustment. This supports that the tappet adjustment has not changed in the last 12 years. In summary, incorrect adjustments of valve tappet settings or backing off of adjustment screws as seen in the 1984 event have been eliminated. Additionally, procedural specification of valve lash adjustment is consistent across all valves and does not present a vulnerability to a common mode issue. It should be noted that the 1984 valve that exhibited failure was manufactured by Nordberg, and the current failed valve was manufactured by NAK per the Original Equipment Manufacturer (OEM) drawings.
Industry OE showed the Brunswick Nuclear station as the other nuclear station using this diesel in a safety related application. Interviews with Brunswick Engineers indicated no history of failed valves at Brunswick for their Nordberg diesels.
Investigation of the fatigue failure that occurred on the valve stem is ongoing. Replacement of the piston, head assembly (which includes valves), cylinder liner, and pushrods is currently in progress to address the failure. However, approximately 58 hours of maintenance time is required to complete the aforementioned replacements. In addition, a series of maintenance break-in runs for a total of 32 hours is required, followed by a three hour post-maintenance operability run, and will result in exceeding the LCO time requirement.
Repair and operability testing of DG "1B" will not be completed within the 72 hour completion time mandated by TS 3.8.1, Required Action B.4. Therefore, Duke Energy is requesting that the Completion Time of the above Required Action be extended from the current 72 hours by an additional 48 hours, for a total of 120 hours, so that this work can be completed.
: 4. Cause of the situation that has led to the NOED request.
DG "1B" was declared inoperable on August 18, 2014, at 1729 hours. Duke Energy has been engaged in troubleshooting and repair efforts since that time. Cylinder 5L exhibited knocking

U.S. Nuclear Regulatory Commission                                                      Attachment August 25, 2014                                                                         Page 4 noise and a significant drop in cylinder exhaust temperature during the 24-hour test for DG "1 B."
The cause of the DG "I B" inoperability is failure of an intake valve on cylinder 5L. When the rocker box was removed, the intake valve spring was in a relaxed state (not compressed),
indicating that the intake valve and/or stem was broken and was no longer captured by the valve stem keeper. Further examination concluded that the intake valve failed at the bottom of the keeper groove on the valve stem which in turn caused the valve to repeatedly contact the valve seat insert partially breaking it into small pieces which fell into the cylinder damaging the piston, head, exhaust valve, and cylinder liner.
Duke Energy's Metallurgy Laboratory analyzed the broken valve stem. Relatively fine striations with no apparent ductile tearing, combined with relatively large fracture area, suggest that high cycle fatigue caused the failure of the intake valve stem on cylinder 5L.
Lab analysis indicates the failure mechanism is high cycle fatigue of the 5L cylinder intake valve. This type of failure is typically presented by exceeding the endurance limit for the material, in terms of number of cycles and tensile strength. Factors that could have presented a vulnerability to exceed the endurance limit include improper lash setup, manufacturing flaws, worn or broken valve springs, or improper loading on top of the stem.
The fillets on the top and bottom of the spring retainer keeper notch were examined against the specification. This fillet is required to be 1/32" radius per the drawing. The lower fillet was destroyed with the failure, but the upper fillet was examined and determined to be in specification.
The springs from the intake valve were observed to be intact. Valve springs were measured at rest and compressed at the Met Lab. Results were consistent with those shown on the design drawing. Compressive loads were also measured on the springs and compared to the design drawing. Measured data was consistent with design data.
Loading at the top of the valve stem was examined for indications of side loading. The primary means of making this determination was examination of the valve stem guide in the head. The guide showed no signs of side loading on the valve stem during travel up and down. The top of the valve stem did not show any indication of unusual wear between the stem and the tappet socket. Excessive wear would be present if a significant side load was presented by the socket against the valve stem due to the angle of the rocker arm. DG "1B" Cylinder 5L cam lobe positioning has been visually verified to have not moved. Additional inspection was performed before completion of maintenance activities to physically measure the cam lobe positioning to confirm it was within tolerance for normal configuration. Additionally, engine analysis data has been reviewed for DG "IB" Cylinder 5L for the last 10 years and no increase in intake valve closure force have been observed during that period. The last engine analysis data for 1 B was obtained in June 2014. Engine analysis data for the other 3 engines was also reviewed and no abnormal valve closure profiles were observed.
A review of modifications, work orders, and procedure changes performed since the last successful performance of a surveillance test which adequately verified the failed function's capability revealed that there were no modifications performed on any other DG's that could have caused the failure to occur. There were no changes performed on any procedure affecting the other DGs that could have caused the failure to occur. There was no maintenance

U.S. Nuclear Regulatory Commission                                                      Attachment August 25, 2014                                                                          Page 5 performed on the other DGs that could have caused the failure to occur. The failure was not due to any changes to the environmental conditions such as humidity, temperature, foreign material, or others that could also have affected additional DGs. The failure was not due to fuel contamination. There was no evidence of tampering.
In summary, the cause of the DG "IB" Cylinder 5L intake valve stem failure is high cycle fatigue.
Preliminary investigation has ruled out generic design concerns, infant mortality, abnormal valve spring force, and improper valve closure force. Additionally, significant margin exists between normal operating cyclic forces and the fatigue limit for the spring material. No Part 21 notifications existed prior to this failure for this valve stem. Additional investigation will continue through the cause analysis and corrective action program.
: 5. Course of action to resolve the situation within the proposed NOED timeframe.
A work plan has been developed to return DG "1 B" to operable status. This work is being performed around the clock by a dedicated Unit Threat team. This will ensure that appropriate focus is placed on scheduling, prioritization, contingencies, and relief turnover. Senior Corporate and Site Management personnel will continue to closely monitor the work activities to assure prompt completion. McGuire has confidence that this plan will be successful in restoring DG "I B" to an operable status within the additional 48 hours requested by this NOED. The course of action is as follows:
* Replacement of the piston, head assembly (which includes valves), cylinder liner, and pushrods is currently being performed at this time to address the failure. Investigation of the fatigue failure that occurred on the valve stem is ongoing. Current schedule for completion of replacement and restoration activities is 8/21/2014 at 1700 hours.
* Series of DG break-in runs following replacement of parts. Current schedule for completion of break-in runs is 8/23/2014 at 0100 hours.
    "    DG operability run. Current schedule for completion of operability run is 8/23/2014 at 0600 hours.
: 6. Demonstrate that the resolution itself does not result in a different, unnecessary transient.
The planned resolution of the DG "1 B" inoperable condition is replacement of the piston, head assembly (which includes valves), cylinder liner, and pushrods. Post-maintenance testing ensures proper operation of DG "1B" before considering the equipment operable. These activities will not result in a different, unnecessary transient, and no actions will be taken that can affect other safety related systems or equipment.
: 7. Demonstrate that there was insufficient time to process an emergency TS change or license amendment or that a license amendment is not needed.
DG "IB" was declared inoperable on August 18, 2014, at 1729 hours due to an emergent failure. Duke Energy has been engaged in troubleshooting and repair efforts on a continuous basis since that time. The Completion Time for TS 3.8.1, Condition B is 72 hours. By the time the condition with DG "1 B" was evaluated to determine the necessary repairs, there was insufficient time for McGuire to prepare and the NRC to process and approve an emergency TS change request or license amendment.

U.S. Nuclear Regulatory Commission                                                       Attachment August 25, 2014                                                                          Page 6
: 8. Condition and operational status of the plant, including safety-related equipment out of service or otherwise inoperable, and non-safety-related equipment that is degraded or out of service that may have risk significance and that may increase the probability of a plant transient or may complicate the recovery from a transient or may be used to mitigate the condition.
During the period of the proposed enforcement discretion, Units 1 and 2 will remain in Mode 1 (at power operation). The redundant Unit 1 DG "IA" and offsite power sources are not affected.
There is no non-safety equipment that is degraded or out of service that may have risk significance. The common cause evaluation of the failure determined that no common mode failure mechanism exists on the DG "1A," DG "2A," or DG "2B". A review of active TS action items and scheduled surveillances revealed the following equipment out of service:
Safety Equipment:
* 1B CPCS/NS (Containment Pressure Control System/Containment Spray) - 8/21 from 2000 to 2200 for Surveillance testing.
* Unit 1B VX (Containment Air Return and Hydrogen Skimmer) - 8/21 from 2200 to Midnight for Surveillance testing.
: 9. Period for the NOED, including a justification for the duration of the noncompliance.
Repair and operability testing of DG "1B" will not be completed within the 72 hour completion time mandated by TS 3.8.1, Required Action B.4. Therefore, Duke Energy is requesting that the Completion Time of the above Required Action be extended from the current 72 hours by an additional 48 hours, for a total of 120 hours, so that repairs can be completed, clearances removed, and testing to demonstrate operability of DG "1 B" can be completed.
Replacement of the piston, head assembly (which includes valves), cylinder liner, and pushrods are currently being performed at this time to address the failure. Investigation of the fatigue failure that occurred on the valve stem is ongoing. However, approximately 58 hours of maintenance time is required to complete the aforementioned replacements. In addition, a series of maintenance break-in runs for a total of 32 hours is required, followed by a three hour post-maintenance operability run, and will result in exceeding the LCO time requirement.
As demonstrated in Item 13, the requested enforcement discretion will result in no net increase in radiological risk. In addition to the risk insights, other than DG "1 B", sufficient onsite emergency AC power and offsite power supplies remain operable to complete their intended safety function. Appropriate plant redundant and support systems will be protected to ensure there is no undue risk of redundant or support equipment inoperability during the proposed enforcement discretion time frame.
There is no net increase in radiological risk by extending the Completion Time to accomplish required repairs and testing. Additionally, there is an inherent safety benefit of restoring DG "I B" without shutting Unit 1 down when compared to shutting the Unit down without DG "I B" available. Therefore, requiring this repair to be performed with Unit 1 shut down would result in additional plant equipment and personnel challenges without any significant benefit to the safety of the plant or the health and safety of the public. A detailed work plan was developed, and this

U.S. Nuclear Regulatory Commission                                                    Attachment August 25, 2014                                                                       Page 7 work is being performed around the clock in order to restore DG "1B" to operable status as soon as possible.
: 10. Compensatory measures the plant has both taken and will take to reduce the risk associated with the specific configuration.
In order to provide additional risk margin during the additional period of time requested by this NOED, the following equipment and systems will be "Protected" and discretionary maintenance will not be performed on them:
         *  "1A" DG 1"IA" Nuclear Service Water train
         * "IA" and "IB" offsite power supplies S1 ETA switch gear room S1 ETB-1 breaker
* Unit 1/2 McGuire switchyard and relay house
* Unit 1/2 main step-up transformer yard
* Unit 1/2 6.9kV essential switchgear rooms
* Safe Shutdown Facility (SSF)
* Both Unit 1 Motor Driven AFW Pumps
* Unit 1 Turbine Driven AFW Pump
* SATB
         * "IA" Hydrogen Igniter In addition, the following compensatory measures will also be taken prior to the period of the proposed NOED:
: 1. Defer non-essential surveillances and other discretionary maintenance activities in the switchyard and on electrical equipment where human error could contribute to the likelihood of a loss of offsite power (LOOP).
: 2. Perform a briefing with operators regarding the importance of throttling Auxiliary Feedwater flow to the Steam Generators during a Station Blackout Event. The briefing will include a walkthrough of the procedure actions.
: 3. Station personnel will communicate to the System Operations Center once per shift regarding the Unit status and the need to maintain grid stability during the period of enforcement discretion.
: 4. Prior to entering the period of enforcement discretion, the operating crews will review the procedures for operating the SSF and station an operator in the SSF.
: 5. Assign a dedicated operator to transfer plant control from the control room to the SSF if necessary and transfer power for the hydrogen igniters from the normal power to SSF power if necessary.
: 6. Ensure no work activities will be performed on Unit 2 that would affect DGs.
: 7. Perform a briefing with operators each shift regarding the importance of cross-connecting offsite power from Unit 2. The briefing will include a walkthrough of the procedure actions.
: 8. Ensure no work on Instrument Air (VI) system occurs during the period of enforcement discretion.
: 9. A briefing will be conducted each shift with operators regarding the importance of

U.S. Nuclear Regulatory Commission                                                      Attachment August 25, 2014                                                                          Page 8 tripping the RCPs at the secondary breakers. The briefing will include a walkthrough of the procedure actions.
: 10. Continuous fire watches with suppression capability will be implemented for fire areas deemed to be high risk. These areas include: Unit 1 Cable Spreading Room 801, Unit 1 6.9KV Switchgear Room and Unit 1 Turbine Building near Load Center 1LXF.
: 11. Throttle valve 1WL-361 (Unit 1 VUCDT Inlet Isolation) per a troubleshooting/alternate system alignment procedure. This line will be throttled to reduce flow such that it is no longer a Large Early Release pathway.
: 12. Check weather forecast once per shift.
: 11. Status and potential challenges to offsite and onsite power sources, including any current or planned maintenance in the distribution system and any current or planned maintenance to the emergency diesel generators.
Redundant DG "1A" and offsite power sources are not affected. The Unit 2 DGs are fully operable. The common cause evaluation of the failure determined that no common mode failure mechanism exists on the DG "IA," DG "2A," or DG "2B". The power grid is currently stable. There are no foreseen challenges to these offsite and onsite power sources. Measures will be implemented to preclude any discretionary maintenance activities on systems in the plant that could impact the AC power system. The load dispatcher confirmed that there are no operations on the grid that would present a challenge to the offsite power system to the McGuire site. Compensatory measures have been implemented to prevent any work activities in the plant that could challenge the availability and reliability of redundant systems.
: 12. Safety basis for the request and an evaluation of the safety significance and potential consequences of the proposed course of action.
A. Use of zero maintenance model Using the zero maintenance PRA model, the ICCDP associated with the unavailable DG calculated for the 48 hour enforcement discretion period was 3.1 E-7, which is below the 5E-7 guidance threshold. The ICLERP calculated for the 48 hour enforcement discretion period was 4.1E-8, which is below the 5E-8 guidance threshold.
B. Dominant risk contributors Large Early Release Frequency (LERF) is the limiting risk metric.
The dominant contributors to LERF include:
Fires - A challenging fire impacts the power to Train 1A equipment or directly impacts Train 1A equipment. The fire either directly or indirectly results in a loss offsite power leading to a loss of the 1 B train due to the DG unavailability. The operator stationed at the SSF for the period of enforcement discretion will start the SSF. Failure of the SSF or turbine-driven AFW pump results in core damage. Loss of the hydrogen igniters due to a loss of power could lead to a potential containment failure.
Non-fires are similar to fires but with a loss of offsite power followed by a failure of DG 1A.
With DG 1B unavailable, the operator stationed at the SSF for the period of enforcement

U.S. Nuclear Regulatory Commission                                                    Attachment August 25, 2014                                                                       Page 9 discretion will start the SSF. Failures of the SSF or turbine-driven AFW pump lead to core damage if offsite power is not restored. Loss of the hydrogen igniters due to a loss of power could lead to a potential containment failure.
The Core Damage Frequency (CDF) sequences are similar to LERF sequences except that hydrogen igniter failure is not needed for core damage.
C. Compensatory risk management actions The following items were credited in the PRA analysis:
        "   The containment ventilation unit condensate drain line is a potential LERF pathway postulated in the PRA for certain station blackout sequences. During the period of enforcement discretion, the line will be throttled to reduce flow such that it is no longer a Large Early Release pathway. This action eliminates the LERF sequences associated with this drain line.
* Prior to entering the period of enforcement discretion, the operating crews will review the procedures governing operation of the Unit 1 turbine-driven AFW pump including locally throttling flow. These measures were incorporated into the analysis by an adjustment to the Human Reliability Analysis (HRA).
In addition to the above, the following items were credited in the fire analysis:
* Prior to entering the period of enforcement discretion, the operating crews will review the procedures for starting the SSF. Additionally, an operator will be stationed at the SSF during the period of enforcement discretion. This action will improve the reliability of the SSF by reducing the time required to staff the SSF following an event. This action will improve the operator success probability for events such as fires by reducing the confusion/stress associated with the early stages of a fire. This action was accounted for in the fire analysis by adjusting the HRA.
* A briefing will be conducted with operators regarding the importance of cross-connecting offsite power from Unit 2. This action was accounted for in the fire analysis by adjusting the HRA.
        " A briefing will be conducted with operators regarding the importance of tripping the RCPs at the secondary breakers. The briefing will include a walkthrough of the procedure actions. This action was accounted for in the fire analysis by adjusting the HRA.
* A dedicated operator will be assigned to transfer plant control from the control room to the SSF if necessary. This action improves the reliability of the SSF. It was accounted for in the analysis by adjusting the HRA.
While not incorporated into the analysis, the following compensatory measures are being taken to further reduce plant risk during the enforcement discretion period:
Continuous fire watches with suppression capability will be used in high risk fire areas (see list in Item 10). Having a continuous fire watch reduces the probability that small fires will grow to a challenging fire before being discovered and extinguished.

U.S. Nuclear Regulatory Commission                                                      Attachment August 25, 2014                                                                         Page 10
* The dedicated operator for transferring plant control from the control room to the SSF (above) will be assigned to transfer power for the hydrogen igniters from the normal power to SSF power if necessary. This action will reduce the probability of a large early release due to a potential containment failure.
         " Equipment will be protected to help ensure its availability (see list in Item 10)
Protecting this equipment will provide higher confidence in its ability to perform its function should an event occur during the enforcement discretion period.
* Non-essential surveillances or other discretionary maintenance activities in the switchyard and on electrical equipment where human error could contribute to the likelihood of a loss of offsite power will be suspended. This will help ensure power availability from the switchyard and reduce the loss of offsite power frequency.
* Station personnel will communicate to the System Operations Center once per shift regarding the unit status and the need to maintain grid stability during the period of enforcement discretion. This will help ensure power availability from the switchyard and reduce the loss of offsite power frequency.
D. Extent of condition The FIP Team has reviewed the common cause failure considerations based the conditions exhibited on DG "1B" cylinder 5L. The most recent DG "1A", "2A" and "2B" operational runs do not indicate abnormal cylinder temperature traces. Preliminary discussions with the Metallurgy Laboratory indicate a fatigue failure in the inlet valve spring retainer keeper region for DG "1B" cylinder 5L. This type of fatigue issue found with the 5L cylinder inlet valve stem is not detected on the other operating diesels. Additional operation of the other diesel engines is not expected to yield tangible information on expected service life.
The FIP Team concluded the remaining three (3) emergency diesel generators are capable of performing their design basis function. Due to the extreme rarity of the fatigue based failure within the inlet valve stem spring retainer keeper area, the problem is believed to be isolated to DG "1B" cylinder 5L intake valve. Nevertheless, as a conservative measure, common cause was considered in this analysis by increasing the failure probability of the DG "1A" to the common cause beta factor.
E. External event risks The external hazards considered include, Fire, external flooding, high winds and seismic.
The Fire risk is directly quantified. For a 48 hour period the ICCDP and ICLERP attributed to fire was determined to be 2.2E-7 and 3.OE-8, respectively. Compensatory actions are planned to reduce fire risk as detailed in the above sections.
The high wind external hazard was evaluated by review of weather forecast and periodic update of weather forecast.
The External Flooding for McGuire is also dominated by precipitation and that is also part of the weather forecast and can be neglected.
The seismic risk evaluation is mitigated by protecting safety related and seismically evaluated SSCs other than the EDG. The Seismic event that could impact off-site power is a low probability event when compared to the existing loss of off-site power. This includes a

U.S. Nuclear Regulatory Commission                                                  Attachment August 25, 2014                                                                     Page 11 review of the newly develop Ground Motion Response Spectrum.
: 13. Demonstration that the NOED condition, along with any compensatory measures, will result in no net increase in radiological risk, either in a quantitative assessment that risk will be within the normal work control levels (ICCDP less than or equal to 5E-7 and/or ICLERP less than or equal to 5E-8) or defensible qualitative evaluation.
The analysis that was completed showed for a 48 hour period, the ICCDP and ICLERP values are 3.1E-7 and 4.1E-8, respectively. Both risk metrics are below their respective guidance thresholds.
: 14. Forecasted weather and pandemic conditions for the NOED period and any plant vulnerabilities related to weather or pandemic conditions.
The weather forecast for the area is as follows:
* Thursday - mostly sunny. A chance of showers with a slight chance of afternoon thunderstorms. Highs in the mid-90s. North winds around 5 mph. Chance of rain 30 percent. An isolated severe storm is possible, but main risk would be gusty winds. Tornados are very unlikely.
* Friday - mostly sunny skies. Humid with highs in the mid-90s. Northwest winds around 5 mph. No severe weather expected at this time.
* Saturday - mostly sunny skies with a slight chance of afternoon thunderstorms. Humid with highs in the lower 90s. North winds around 5 mph. Possibility of an isolated severe storm, but main risk would be gusty winds. Tornados are very unlikely.
     "   Sunday - mostly cloudy skies with a chance of afternoon showers. Highs in the lower 80s. No severe weather is expected at this time.
Overall, there is only a slight chance of thunderstorms in the Charlotte/Mecklenburg area on Thursday and Saturday afternoons. Possibility of an isolated severe storm, but main risk would be gusty winds. Tornados are very unlikely. Conditions do not appear conducive for tornado development.
There is no threat of pandemic conditions during the proposed duration of the enforcement discretion.
: 15. Basis for the conclusion that the noncompliance will not create undue risk to public health and safety.
Duke Energy has evaluated the proposed request and determined that it involves no significant hazards considerations. According to 10 CFR 50.92, "Issuance of amendment," paragraph (c),
a proposed amendment to an operating license involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not:
(A) Involve a significant increase in the probability or consequences of an accident previously evaluated; (B) Create the possibility of a new or different kind of accident from any accident previously evaluated;

U.S. Nuclear Regulatory Commission                                                     Attachment August 25, 2014                                                                        Page 12 (C) Involve a significant reduction in a margin of safety In support of this determination, an evaluation of each of the three criteria set forth in 10 CFR 50.92 is provided below regarding the proposed action.
(A) The request for enforcement discretion does not involve a significant increase in the probability of occurrence or consequences of any accident previously evaluated The probability of occurrence of an accident will not be significantly affected by granting this enforcement discretion. As discussed in Item 13 above, the requested period for enforcement discretion does not significantly increase the total base case CDF or LERF values. The ICCDP calculated for the requested 48 hour enforcement discretion period is 3.1 E-07, which is below the 5E-07 threshold. The ICLERP calculated for the 48 hour enforcement discretion period is 4.1 E-08, which is below the 5E-08 threshold.
(B) The request for enforcement discretion does not create the possibility of a new or different kind of accident from any accident previously evaluated As a result of this request for enforcement discretion, no new equipment is being introduced, and installed equipment is not being operated in a different manner. There are no changes being made to the parameters within which the unit is operated, and similarly, no setpoints at which protective or mitigative actions are initiated are affected. This request for enforcement discretion does not alter the manner in which equipment operation is initiated, and demands on credited equipment will not change. No alteration in the procedures that ensure the unit remains within analyzed limits is proposed, and no change is being made to procedures relied upon to respond to an off-normal event. As such, no new failure modes are being introduced.
The proposed action does not alter assumptions made in the safety analysis. Therefore, the request for enforcement discretion does not create the possibility of a new or different kind of accident from any accident previously evaluated.
(C) The request for enforcement discretion does not involve a significant reduction in a margin of safety Based on the operability of Unit 1 DG "IA" and offsite power sources, the accident analysis assumptions continue to be met for the proposed period of enforcement discretion. Similarly, the system's design and operation are not affected by proposed period of enforcement discretion, and the safety analysis acceptance criteria are not altered by the proposed changes.
Finally, the proposed compensatory measures will provide assurance that no significant reduction in safety margin occurs.
Based on the above, the extended Completion Time will not create undue risk to public health and safety.
: 16. Basis for the conclusion that the noncompliance will not involve adverse consequences to the environment.
This request for enforcement discretion does not result in any significant changes in the types, or significant increase in the amounts, of any effluents that may be released offsite. In addition,

U.S. Nuclear Regulatory Commission                                                  Attachment August 25, 2014                                                                     Page 13 no significant increase in individual or cumulative occupational radiation exposures is involved as a result of the request. Therefore, it can be concluded that the NRC's granting of this request for enforcement discretion does not involve any adverse consequences to the environment.
: 17. Approval by the facility organization that normally reviews safety issues.
The requested NOED was reviewed and approved by the McGuire Plant Operations Review Committee (PORC) on August 21, 2014.
: 18. Commitment to a written NOED request within two working days and a follow-up license amendment request within four working days following the staff's verbal granting of the NOED, if needed.
This letter fulfills the requirement to submit a written NOED request within two working days.
This request for enforcement discretion involves a non-compliance with a TS Required Action that is not expected to re-occur. Based on the short duration (a maximum of 48 hours) of the requested non-compliance, a follow-up license amendment request is not warranted. At present there are no plans to extend the current 72-hour Completion Time of TS 3.8.1, Required Action B.4 on a permanent basis. IMC 0410 states that a follow-up amendment is not required if the NRC agrees before granting the NOED. The NRC agreed during the conference call providing verbal approval of the NOED that no other follow-up amendment request is required.
: 19. Provide additional information if the NOED request is a natural event NOED.
This NOED request is not due to a natural event; hence, additional information specific to a natural event NOED is not required.}}