IR 05000261/2005006

IR 05000261-05-006, on 02/14 - 18/2005, 02/28 - 03/04/2005, and 03/23 - 24/2005; H. B. Robinson Steam Electric Plant, Unit 2; Safety System Design and Performance Capability Inspection

ML051230007
Person / Time
Site:	Robinson
Issue date:	05/02/2005
From:	Ogle C NRC/RGN-II/DRS/EB
To:	Moyer J Carolina Power & Light Co
References
IR-05-006
Download: ML051230007 (42)

Text

May 2, 2005

SUBJECT:

H.B. ROBINSON STEAM ELECTRIC PLANT - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION REPORT NO.

05000261/2005006

Dear Mr. Moyer:

On March 4, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability team inspection at your H.B. Robinson Steam Electric Plant, Unit 2. The enclosed report documents the inspection findings which were discussed with you and other members of your staff on March 4, 2005. Following completion of additional in-office and on site review, a final exit was held on site with you and other members of your staff on March 24, 2005.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspection team reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified Severity Level IV violation and one NRC-identified finding of very low safety significance (Green) involving a violation of NRC requirements.

However, because of their very low safety significance and because they are entered into your corrective action program, the NRC is treating these violations as non-cited violations (NCVs)

consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the H.B. Robinson Steam Electric Plant.

CP&L

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

\\\\RA\\\\

Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket No.: 50-261 License No.: DPR-23

Enclosure:

NRC Inspection Report 05000261/2005006 w/Attachment: Supplemental Information

REGION II==

Docket No.:

50-261 License No.:

DPR-23 Report No.:

05000261/2005006 Licensee:

Carolina Power and Light (CP&L)

Facility:

H.B. Robinson Steam Electric Plant, Unit 2 Location:

3581 West Entrance Road Hartsville, SC 29550 Dates:

February 14-18, 2005 February 28 - March 4, 2005 March 23-24, 2005 Inspectors:

M. Thomas, Senior Reactor Inspector (Team Lead)

D. Jones, Resident Inspector D. Mas-Penaranda, Reactor Inspector L. Mellen, Senior Reactor Inspector (March 23-24, 2005)

T. Nazario, Reactor Inspector R. Reyes, Resident Inspector C. Smith, Senior Reactor Inspector Approved by:

Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety

SUMMARY OF FINDINGS

IR 05000261/2005-006; 02/14 - 18/2005, 02/28 - 03/04/2005, 03/23 - 24/2005; H.B. Robinson

Steam Electric Plant, Unit 2; Safety System Design and Performance Capability Inspection.

This inspection was conducted by a team of inspectors from the NRC Region II Office. The team identified two findings. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP).

Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

SL IV: The inspectors identified a Severity Level IV (SL IV) non-cited violation (NCV) of 10 CFR 50.59 requirements for the licensees failure to fully evaluate a change to the plant which potentially involved an unreviewed safety question (USQ). Specifically, the licensee implemented a plant change in 1992 which directed the discharge of safety injection system (SIS) relief valve SI-857A to an open floor drain in the auxiliary building (contrary to the Updated Final Safety Analysis Report), without evaluating the effects on dose consequences. The potential USQ was related to an increase in the dose consequences, if valve SI-857A, which is located outside containment, were to lift (and potentially fail to reseat) during post-LOCA recirculation conditions.

This finding was evaluated using traditional enforcement and is more than minor because it was a change to the facility which would require NRC review and approval prior to implementation. This finding affected the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to preclude undesirable consequences. However, the technical issue was determined to be of very low safety significance, given the low likelihood of a scenario involving a loss of coolant accident and actuation of SI-857A. The licensee entered this issue into the corrective action program as Action Request 151238.

(Section 1R21.2.21.b)

Green: The inspectors identified a non-cited violation (NCV) of 10 CFR 50, Appendix B,

Criterion III, for inadequate design control, in that, the licensee failed to assure that applicable design requirements were correctly translated into Procedure EPP-9,

Transfer to Cold Leg Recirculation. Specifically, the licensee did not incorporate the postulated failure of a residual heat removal pump to stop on demand as a design input into Engineering Service Request ESR-99-00273, Large Break Loss of Coolant Accident Switchover Analysis.

This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to preclude undesirable consequences. This finding was determined to be of very low safety significance because the licensee provided field validation information for Procedure EPP-9 which indicated that, under worst case conditions, margin was available to achieve the switchover to recirculation within the time assumed in the accident analyses. The licensee entered this issue into the corrective action program as Action Request 154571 and initiated a revision to Procedure EPP-9. (Section 1R21.2.22.b)

Licensee-Identified Violations

None.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events and Mitigating Systems

1R21 Safety System Design and Performance Capability

The team evaluated the capability of installed plant detection and mitigation equipment which provide the high pressure safety injection, low pressure safety injection, and recirculation functions during a loss of coolant accident (LOCA) at H.B. Robinson. The high pressure safety injection function is provided by the high head safety injection (HHSI) system and the low pressure safety injection function is provided by the low head safety injection (LHSI)/residual heat removal (RHR) system. The recirculation phase is initiated manually by operator actions when the contents of the refueling water storage tank (RWST) are depleted. During recirculation, the injection of subcooled water into the core continues by taking suction from the containment emergency core cooling system (ECCS) sump, cooling the sump fluid through the RHR heat exchanger and delivering it to the reactor coolant system (RCS) cold legs or hot legs using the HHSI or RHR pumps.

.11 Process Medium

a. Inspection Scope

The team reviewed the water sources required during the LOCA event to verify their availability and reliability. These included the RWST and the condensate storage tank (CST). The review included design documentation, drawings, Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS), and corrective action history.

The team reviewed the RWST as a viable ECCS suction source. The calculation for sizing of the RWST vent was reviewed to verify that the vent was adequately sized for the maximum RWST volume draw-down, and the team walked down the RWST to verify the vent was installed in accordance with design and vendor documents. In addition, maintenance records were reviewed to verify adequate preventive maintenance on the vent. The team reviewed RWST calculations to verify that the minimum water level required to prevent vortexing in the RWST was addressed. The team reviewed the design and testing of the diesel driven fire pump to verify the capability of the pump to refill the CST. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.12 Energy Sources

a. Inspection Scope

The team reviewed Nuclear Generation Group Analysis/Calculation RNP-E-8.002, AC Auxiliary Electrical Distribution System Voltage/Load Flow/Fault Current Study, and selected attachments, in order to verify that the HHSI and the RHR pump motors would have adequate terminal voltage to perform their design function under degraded voltage conditions. This review also included vital power to the RHR pump pit cooling fans and power from motor control centers (MCC) 1 and 2 to the RHR sump pumps. The team also reviewed Calculation RNP-E-8.042, AC MOV Protection Evaluation Based on Computer Program Motor Guard 3.1", and selected attachments in order to verify that the listed motor operated valve (MOV) motor operators were adequately protected by thermal overloads, and that the torque developed by the MOV motor operators was acceptable under degraded voltage conditions. The team specifically reviewed O to Calculation RNP-E-8.002, Degraded Grid Voltage Relay Setpoint Basis Calculation, to verify the adequacy of the steady state voltages at 480 Volt Emergency Busses E1 and E2, in addition to MCCs 5 and 6. The team also reviewed Attachment EE to Calculation RNP-E-8.002, Minimum Voltage Requirements at E1, E2, MCCs 5, 6, 9, 10, 16 and 18, in order to verify that positive margin existed between the available and required load terminal voltages for the HHSI and RHR pump motors. The team reviewed Attachment 1 to Engineering Service Request (ESR) 00-00175, RNP-E-8.002 Rev. 4, Impact Evaluation, Rev. 0, and the mechanical setup calculations for the MOVs to verify the adequacy of the torque developed by MOV motor operators. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.13 Instrumentation and Controls

a. Inspection Scope

The team reviewed the instrumentation used for initiation and control of HHSI and RHR systems to verify the controls would be functional and provide desired control during events requiring the high pressure injection function. In addition, the team reviewed test documentation and calibration records to verify that the testing and inspection of the HHSI and RHR instrumentation were adequate to monitor and identify any equipment degradation. The team reviewed the setpoints and uncertainty calculations for the instrument loops related to the RWST to containment sump switchover function to verify that the existing setpoints for these instruments were in accordance with the operating limits. Also, the team reviewed the last two completed surveillance procedures and calibration test records for these instruments to verify that the instruments were properly calibrated and maintained in accordance with design output documents and vendor specifications. The team also reviewed control wiring diagrams of selected MOVs to verify that the control systems were in accordance with their design bases and would be functional and provide desired control during accident/event conditions. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.14 Operator Actions

a. Inspection Scope

The team reviewed the emergency operating procedure network (PATH-1), including end path procedures (EPPs), abnormal operating procedures (AOPs) and annunciator panel procedures (APPs) that would be used in the identification and mitigation of a LOCA event. The team focused on installed equipment and operator actions that could be used to mitigate the event. The review was done to verify that the instructions were consistent with the UFSAR description of a LOCA event and with the Westinghouse Owners Group (WOG) Emergency Response Guidelines (ERGs), any step deviations were justified and reasonable, and the instructions were written clearly and followed the emergency operating procedures (EOP) writers guide. The team held discussions with licensed operators and training instructors and reviewed job performance measures pertaining to a LOCA event to confirm that training was consistent with the applicable operating procedures. In addition, the team observed simulation of LOCA scenarios on the plant simulator and walked down portions of applicable procedures to verify that operator training, procedure guidance, and instrumentation were adequate to identify a LOCA event and implement post-LOCA mitigation strategies. The manual operator action times for performance of LOCA mitigation activities were reviewed for consistency with UFSAR accident analyses, ERGs, and operator training. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.15 Heat Removal

a. Inspection Scope

The team reviewed heat load calculations for cooling the RHR pump rooms and reviewed the calculated peak temperature responses during a LOCA for these rooms.

The team reviewed the engineering evaluation that described the acceptable service water leakage criteria for the safety related room cooling coils HVH-8A and HVH-8B.

The team reviewed the preventive maintenance and corrective maintenance history on the coolers to verify that the coolers were being properly maintained. Vendor hydraulic and thermal design specifications for the coolers were reviewed and compared with design basis requirements to verify acceptable cooler heat removal capability. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.21 Installed Configuration

a. Inspection Scope

The team performed field walk downs of HHSI and RHR components to observe the material condition and configuration. The team walked down 480 volt emergency busses E1 and E2, and the HHSI pump motors to verify that the configuration for each component was consistent with the corresponding design drawings. The team reviewed the settings for the emergency bus undervoltage protection relays to verify that they were set in accordance with the requirements of the analysis performed for the emergency bus degraded grid voltage relay settings. The team performed field walk downs of the RWST level instrumentation to verify that the installed configuration of the instruments was consistent with design drawings and setpoint calculations. The team also examined the material condition of the level instruments. This review was performed to verify that the observable material condition was acceptable and that the instruments were adequately installed. The team performed field walk downs of the RHR heat exchangers, HHSI pumps, containment spray pumps, component cooling water pumps and heat exchangers, charging pumps, RWST, and the CST, to observe the material condition and configuration and to verify that valve positions were as specified in system operating procedures and design drawings. The team also performed field walk downs of the RHR pump rooms to observe the material condition of the RHR pumps, valves, and room coolers. This included reviewing actions being taken in the main control room to monitor a small leak on the RHR pump B room cooler. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

Introduction:

The inspectors identified a Severity Level IV (SL IV) non-cited violation (NCV) of 10 CFR 50.59 requirements for the licensees failure to fully evaluate a change to the plant which potentially involved an unreviewed safety question (USQ).

Specifically, the licensee implemented a plant change in 1992 which directed the discharge of safety injection system (SIS) relief valve SI-857A to an open floor drain in the auxiliary building (contrary to the UFSAR), without evaluating the effects on dose consequences. The potential USQ involves an increase in the dose consequences, if valve SI-857A, which is located outside containment, were to lift (and potentially fail to reseat) during post-LOCA recirculation conditions.

Description:

The UFSAR Section 6.3.2.2.3 states that those portions of the SIS located outside containment which are designed to circulate radioactively contaminated water under post-accident conditions will meet certain requirements. One of the requirements was collection of the discharges from the SIS relief valves into closed systems. The inspectors determined that this requirement existed in the UFSAR during original plant licensing and has not changed. During review of design drawings and in-plant walkdowns, the inspectors observed that the installed configuration for SIS relief valve SI-857A was not in accordance with UFSAR Section 6.3.2.2.3. The inspectors determined that the licensee implemented a plant modification in 1992 which directed the discharge of SIS relief valve SI-857A to an open floor drain in the auxiliary building.

Based on a review of historical documents, the inspectors noted that the licensee initiated Adverse Condition Report (ACR)92-079 and issued Licensee Event Report (LER)92-005 in 1992 when a configuration was identified which constituted a potential release path during LOCA conditions. The LER stated that SIS relief valve SI-857B was a single containment isolation barrier which discharged to an open floor drain in the auxiliary building. During a LOCA, failure of SI-857B to reseat after lifting would result in the release of post-accident radioactively contaminated water. ACR 92-079 was resolved when the licensee implemented Modification 1128 in 1992 to remove relief valve SI-857B and cap the associated line. The modification package stated that upon removal of SI-857B, relief valve SI-857A would provide over-pressure protection for a portion of the SIS. The modification package also identified that the existing discharge path of relief valve SI-857A was unacceptable because it discharged to the RWST. As a corrective action, Modification 1128 also rerouted the discharge piping of SI-857A from the RWST to the same open floor drain where SI-857B had previously relieved.

(The inspectors determined that the relief discharge path to the RWST for SI-857A, which was not in accordance with UFSAR Section 6.3.2.2.3 either, existed from original plant licensing until it was changed in 1992 by Modification 1128). The licensees 10 CFR 50.59 safety evaluation for rerouting the discharge piping of SI-857A, stated that there were no new safety issues because SI-857B had previously relieved to that same floor drain. The 10 CFR 50.59 evaluation did not recognize that re-directing the relief discharge of SI-857A from the RWST to this floor drain was not in compliance with UFSAR Section 6.3.2.2.3 and, as a result, the modification could increase the consequences of an accident evaluated previously in the safety analysis report (i.e., a LOCA). This represented a potential USQ. The inspectors based this conclusion on the fact that, if SI-857A were to lift (and potentially fail to reseat) during post-LOCA recirculation conditions, the discharge from SI-857A could be as much as 20 gallons per minute (per vendor documentation and ESR 97-00594), whereas, licensee post-LOCA evaluations of the radiological consequences of leakage from systems outside containment that could contain highly radioactive fluids (e.g., RHR and SIS) were based on an assumed combined maximum allowable leakage of two gallons per hour.

However, the issue was determined to be of very low safety significance due to the low likelihood of SI-857A lifting, as discussed in the Analysis section below. Failure to identify the requirement in UFSAR Section 6.3.2.2.3 resulted in the licensee implementing this change without evaluating the effects on dose consequences of SI-857A lifting (and potentially failing to reseat).

The inspectors also determined that the licensee had multiple opportunities to identify that the installed configuration for relief valve SI-857A was not in accordance with UFSAR Section 6.3.2.2.3. Some of these missed opportunities included:

• Development and issuance of the SIS design basis document in 1988

• Implementation of Modification 1128 in 1992 which removed relief valve SI-857B and rerouted the relief discharge of SI-857A to the auxiliary building floor drain

• UFSAR validation project in 1997

• Initiation of Action Request (AR) 9702265 and related ESR 97-00594 in 1997 to address the lifting of relief valve SI-857A during surveillance testing.

The inspectors noted that relief valve SI-857B was reinstalled in the SIS in 1993 by Modification 1142. The relief discharge for SI-857B was routed to the pressurizer relief tank inside containment. This configuration for SI-857B was in accordance with UFSAR Section 6.3.2.2.3. In addition, the inspectors noted that one of the corrective actions for AR 9702265 involved changing the lift setting for relief valve SI-857B. The lift setting for SI-857B was set below that of SI-857A, which was intended to cause SI-857B to lift before SI-857A.

Analysis:

This finding is more than minor because it was a change to the facility which would require NRC review and approval prior to implementation. This finding affected the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to preclude undesirable consequences. The significance of this violation was not formally evaluated under the Reactor Oversight Process per the Enforcement Policy because the Agency views 10 CFR 50.59 issues as potentially impeding the regulatory process (i.e., it precluded NRC review of a change to the facility). However, the technical issue was determined to be of low significance, given the low likelihood of a scenario involving a LOCA and actuation of SI-857A. The likelihood of this scenario is further reduced, given the fact that the relief setting of SI-857B is below that of SI-857A. As a result, the regulatory significance was categorized as a Severity Level IV violation under Supplement I of the current Enforcement Policy.

Enforcement:

The version of 10 CFR 50.59 that existed at the time of the change stated, in part, that a licensee may make changes in the facility as described in the safety analysis report, without prior Commission approval, unless the proposed change involves an unreviewed safety question. 10 CFR 50.59 further states that a proposed change, shall be deemed to involve an unreviewed safety question if the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report may be increased.

UFSAR Section 6.3.2.2.3 states, in part, that relief valves on portions of the SIS located outside containment which circulate radioactively contaminated water under post-accident conditions, are required to discharge into closed systems. This requirement existed in the UFSAR during initial plant licensing and has not changed.

Contrary to the above, in 1992, the 10 CFR 50.59 evaluation for Modification 1128 was not adequate, in that, it did not fully evaluate the effects on dose consequences of relief valve SI-857A lifting (or failing to reseat after lifting) when the discharge path of SIS relief valve SI-857A was directed to an open floor drain in the auxiliary building instead of a closed system. The modification resulted in a configuration which was not in accordance with UFSAR Section 6.3.2.2.3 and potentially involved a USQ. The potential USQ involves an increase in dose consequences if relief valve SI-857A, located outside containment, were to lift (and potentially fail to reseat) during post-LOCA recirculation conditions. The licensees failure to route the discharge of relief valve SI-857A to a closed system has existed since original plant licensing.

Section 8.1.3 of the NRC Enforcement Manual states that violations which existed under the old and new rule should be categorized using the current enforcement guidance.

This finding is assessed as a Severity Level IV violation, based on the low likelihood of this scenario, as noted above in the Analysis section. The failure to obtain NRC review and approval, through a license amendment, prior to implementation of a change in the facility potentially involving a USQ, as required by 10 CFR 50.59, is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy. This item is identified as NCV 05000261/2005006-01, Failure to Fully Evaluate a Change to the Discharge Path of Relief Valve SI-857A Which Potentially Involves an Unreviewed Safety Question. The licensee entered this issue into the corrective action program as AR 151238151238

.22 Operation

a. Inspection Scope

The team walked down selected portions of emergency operating procedures to check for human factors in the procedures and in the plant; including clarity, accuracy, lighting, labeling, noise, communications, and accessibility. The team also checked if selected system alignments were consistent with design and licensing basis assumptions. In addition, the team checked if the times required to perform the local operator actions were consistent with the times available for the actions as described in analyses and calculations. Included in these walk downs were selected local manual operator actions from procedures EPP-1 and EPP-9. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

Introduction:

The inspectors identified a Green, non-cited violation, of 10 CFR 50, Appendix B, Criterion III, for inadequate design control, in that, the licensee failed to assure that applicable design requirements were correctly translated into Procedure EPP-9, Transfer to Cold Leg Recirculation. Specifically, the licensee did not identify nor incorporate the postulated failure of an RHR pump to stop on demand as a design input into ESR 99-00273, Large Break Loss of Coolant Accident Switchover

Analysis.

Description: In 1999, the licensee performed engineering evaluation ESR 99-00273, Large Break Loss of Coolant Accident (LBLOCA) Switchover Analysis, to establish the operator action times for realigning the suction of the RHR pumps from the RWST to the containment sump in Procedure EPP-9, Transfer to Cold Leg Recirculation. The inspectors reviewed Procedure EPP-9 and ESR 99-00273. During this review, the inspectors identified a scenario, involving a postulated failure of an RHR pump to stop on demand, that was a more limiting scenario during switchover from injection to cold leg recirculation for certain LOCAs. The licensees evaluations did not incorporate this postulated failure of an RHR pump to stop as a design input and/or assumption. The inspectors determined from a review of related engineering evaluations and discussions with licensee personnel, that this postulated failure scenario had not been previously identified nor validated by the licensee in engineering calculations performed to support the times assumed in the UFSAR Chapter 15 accident analyses for completion of the manual operator actions required to accomplish the switchover. UFSAR Section 6.3.1.3 states that postulated single active failures in the SIS will not impair the ability of the system to perform its design objectives.

The licensees failure to consider an RHR pump failure scenario as a design input resulted in Procedure EPP-9 being inadequate in some scenarios. Procedure EPP-9 provides the manual operator actions to realign the suction of the RHR pumps from the RWST to the containment sump, and is entered when the RWST low-level alarm is received during a LOCA. To ensure that adequate time is available for the operators to perform the necessary realignment, EPP-9 directs the operators to secure the RHR pumps to reduce the flow from the RWST shortly after the procedure is initiated. Failure of an RHR pump to stop on demand, reduces the available time for the operators to accomplish the transfer of the RHR pumps suction from the RWST to the containment sump. If the transfer is not completed prior to reaching the RWST low-low level alarm, procedure EPP-9 directs the operators to secure all ECCS flow until the realignment is completed. Failure to re-start the ECCS pumps within the times assumed in the accident analyses could result in the plant being in an unanalyzed condition.

Analysis:

The performance deficiency was that the licensee did not incorporate the postulated failure of an RHR pump to stop on demand as a design input or assumption into ESR 99-00273. This performance deficiency, which occurred in 1999, resulted in the licensee issuing an inadequate emergency procedure (i.e., Rev. 22 to Procedure EPP-9). EPP-9, Rev. 22 was inadequate because it had no operator instructions or guidance for responding to a failure of an RHR pump to stop on demand. Failure to secure the RHR pump in a timely manner would reduce the time available to perform the required manual operator actions. As a consequence of this procedural omission, the control room would have to identify, diagnose, and dispatch an operator to locally secure the RHR pump during this time critical evolution, without procedural guidance. This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to preclude undesirable consequences.

Using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, the inspectors determined that this finding applied to the mitigating systems cornerstone. The finding is a design deficiency. However, this deficiency did not result in a loss of function or a loss of safety system function per Generic Letter (GL) 91-18, Rev. 1. Although failure to secure the RHR pump in a timely manner would reduce the time available for performing the manual operator actions required for switchover to recirculation, the licensee provided the inspectors with recent field validation information for Procedure EPP-9 which indicated that, under worst case conditions, margin was available to achieve the switchover to recirculation within the time limits assumed in the accident analyses. Therefore, this finding screened as Green in the Mitigating Systems Cornerstone in the Phase 1 worksheet, a finding of very low risk significance.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control requires in part, that measures shall be established to assure that applicable regulatory requirements and the design bases are correctly translated into specifications, drawings, procedures, and instructions. Licensee Procedure EGR-NGGC-0005, Engineering Change, requires that design inputs shall be specified to the level of detail necessary to permit the activity to be carried out in a correct manner and to provide a consistent basis for making decisions, accomplishing design verification measures and evaluating design changes.

Procedure EGR-NGGC-0005 further states that basic design inputs include operational requirements such as emergency operation including postulated accident conditions.

Contrary to the above, in 1999, the licensee did not identify nor incorporate the postulated failure of an RHR pump to stop when called upon as a design input into Engineering Service Request ESR 99-00273. The failure to include the design input in ESR 99-00273 resulted in Procedure EPP-9 being revised and issued without instructions or guidance for responding to a postulated failure of the RHR pump to stop on demand. This failure by the licensee to assure that applicable design requirements were correctly identified and incorporated into Procedure EPP-9 was identified as NCV 05000261/2005006-02, Failure to Identify and Translate Design Inputs and Assumptions into Emergency Procedures. The licensee entered this issue into the corrective action program as Action Request 154571 and initiated a revision to Procedure EPP-9.

.23 Design

a. Inspection Scope

Mechanical Design Review The team reviewed design calculations, specifications, and the UFSAR to verify that system and equipment design functions were appropriately evaluated and maintained.

Surveillance test procedures and equipment monitoring activities were reviewed to verify that design criteria were appropriately translated into acceptance criteria. The team reviewed calculations and system configurations to assess whether adequate NPSH was available to the RHR, HHSI, and containment spray pumps during the period of maximum flow from the RWST, during the period just before switchover to containment sump recirculation, and during RHR pumps operation from the containment sump. The system design and configuration controls were reviewed to assure pump minimum flow requirements were adequate to prevent flashing from occurring and pump run out protection was provided. A specific list of documents reviewed is included in the to this report.

Electrical, Instrumentation and Controls Design Review The team reviewed the setup calculations and the post-test evaluation of static test results for selected ECCS MOVs in order to verify that acceptance criteria for the MOV motor operators met vendor recommendations and the installed thermal overloads were correctly sized based on motor load currents. The team also reviewed control wiring diagrams of selected MOVs to verify that the control systems were in accordance with their design bases and would be functional and provide desired control during accident/event conditions.

b. Findings

No findings of significance were identified.

.24 Testing and Inspection

a. Inspection Scope

The team reviewed performance and post-maintenance testing of selected ECCS pumps and valves to verify that the tests and inspections were appropriately confirming that the assumptions of the licensing and design bases were being maintained and that performance degradation would be identified. The team reviewed post-test evaluation of the static test results for selected ECCS MOVs in order to verify that acceptance criteria for MOV motor operators were being met, as demonstrated by test results. The team also reviewed the disposition of test deficiencies identified during MOV static testing of MOV motor operators to ensure that the test deficiencies were adequately reviewed and evaluated by engineering personnel, and that final resolution of the test deficiencies was technically acceptable. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.31 Component Degradation

a. Inspection Scope

The team reviewed surveillance and maintenance records to verify that the components were continuing to perform within the limits specified by the design basis. The review also included engineering change documentation, drawings, UFSAR, TS, corrective actions history, and foreign material exclusion history for the ECCS. Walkdowns of the boron injection tank room, HHSI pump room, and RWST exterior were performed to verify the structural integrity and condition of supports, hangers, base plates, and structural attachments associated with the ECCS equipment. Calculations were reviewed to verify that design criteria were appropriately implemented into the design.

The team reviewed surveillance and maintenance records, performance trending data, equipment history as identified by plant work orders and corrective actions history, and system health reports to assess the licensees actions to verify and maintain the safety function, reliability, and availability of selected components. Also reviewed were potential common cause failure mechanisms due to maintenance, parts replacement, and modifications. The team reviewed completed work orders (WOs) of preventive maintenance activities performed for the HHSI and RHR pump motors and/or the motor feeder circuit breakers. The team reviewed completed surveillances and preventive maintenance work orders for selected RHR flow and pressure instruments. The reviews were performed to verify that potential degradation was monitored or prevented and that the component replacement parts satisfied the technical and quality requirements of the parts being replaced. A specific list of documents reviewed is included in the to this report.

b. Findings

No findings of significance were identified.

.32 Equipment/Environmental Qualification

a. Inspection Scope

The team reviewed environmental qualification records of the HHSI and RHR pump motors and selected SIS MOVs, in order to verify that equipment qualification was suitable for the environment expected under all conditions. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.33 Equipment Protection

a. Inspection Scope

The team performed field walkdowns of internal flood mitigation equipment in the auxiliary building and the RHR pump pit to observe general material condition, identify degraded conditions, and verify that the installed configuration was consistent with design drawings and design inputs to calculations. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.34 Component Inputs/Outputs

e. Inspection Scope

The team reviewed selected MOV operator requirements calculations to assess the capability of the MOVs to perform their design function under degraded voltage conditions. The team reviewed the setpoints and uncertainty calculations for the instrument loops related to the RWST and containment sump switchover function to verify that the existing setpoints for these instruments were in accordance with the operating limits. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.35 Operating Experience

a. Inspection Scope

The team reviewed the licensees applicability evaluations, extent of condition reviews, and corrective actions for industry and station operating experience issues related to ECCS equipment problems, such as foreign material in the RHR pump suction, to verify that plant specific issues were being appropriately addressed. The team reviewed WOs, procedures, performed field observations, and held discussions with engineering staff to verify that operating experience related corrective actions were being accomplished. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The team reviewed selected system health reports, maintenance records, calibration and surveillance test records, and ARs to verify that design and performance problems were identified and entered into the corrective action program. The team assessed the scope of the licensees extent-of-condition reviews and the adequacy of the corrective actions. Additionally, the team reviewed a sample of corrective maintenance work orders on the selected pumps and valves. A specific list of documents reviewed is included in the Attachment to this report.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

The lead inspector presented the inspection results on March 4, 2005, to Mr. J. Moyer, Site Vice President, and other members of his staff. Following completion of additional in-office and on site review, a final exit was held on site with Mr. Moyer and other members of his staff on March 24, 2005. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Bailey, Senior Nuclear Self Evaluation Specialist/Operating Experience Coordinator

C. Baucom, Supervisor, Licensing/Regulatory Programs

D. Blakeney, Supervisor, Plant Support

C. Castell, Lead Engineer, Licensing/Regulatory Programs

C. Church, Engineering Manager

B. Clark, Manager, Nuclear Assessment

W. Farmer, Superintendent, Systems Engineering

J. Hendrickson, Lead Engineer, Systems Engineering

J. Huegel, Manager, Maintenance-Nuclear

R. Ivey, Operations Manager

K. Jones, Supervisor, Reactor Systems

J. Lucas, Manager, Support Services-Nuclear

G Ludlam, Training Manager

J. Moyer, Vice President-Robinson Plant

W. Noll, Director of Site Operations

V. Smith, Senior Nuclear Procedure Writer, Plant Support

J. Stanley, Superintendent, Technical Services

D. Stoddard, Plant General Manager

J. Valentino, Lead Engineer, Licensing/Regulatory Programs

NRC

P. Fredrickson, Chief, Projects Branch 4, Division of Reactor Projects

R. Hagar, Senior Resident Inspector

LIST OF ITEMS

Opened and Closed

05000261/2005006-01 NCV Failure to Fully Evaluate a Change to the Discharge Path of Relief Valve SI-857A Which Potentially Involves an Unreviewed Safety Question (Section 1R21.2.21.b)

05000261/2005006-02 NCV Failure to Identify and Translate Design Inputs and Assumptions into Emergency Procedures (Section 1R21.2.22.b)

Discussed

None

LIST OF DOCUMENTS

AND EQUIPMENT REVIEWED