IR 05000327/2003009

IR 05000327-03-009 & 05000328-03-009, on 09/08/03 Through 09/12/03 & 09/22/03 Through 09/26/03, for Sequoyah Nuclear Plant Units 1 & 2, Hamilton County, Tn; Annual Baseline Inspection of Identification & Resolution of Problems

ML032970472
Person / Time
Site:	Sequoyah
Issue date:	10/24/2003
From:	Cahill S Reactor Projects Region 2 Branch 6
To:	Scalice J Tennessee Valley Authority
References
IR-03-009
Download: ML032970472 (28)

Text

ber 24, 2003

SUBJECT:

SEQUOYAH NUCLEAR PLANT - NRC PROBLEM IDENTIFICATION AND RESOLUTION PROGRAM INSPECTION REPORT 05000327/2003009 AND 05000328/2003009

Dear Mr. Scalice:

On September 26, 2003, the NRC completed a team inspection at your Sequoyah 1 and 2 reactor facilities. The enclosed report documents the inspection findings, which were discussed on September 26, 2003, with Mr. Purcell and other members of your staff.

This inspection was an examination of activities conducted under your licenses as they relate to the identification and resolution of problems and compliance with the Commissions rules and regulations and the conditions of your operating licenses. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.

On the basis of the sample selected for review, there were no findings of significance identified by the inspectors during this inspection. The team concluded overall that problems were acceptably identified, evaluated and resolved within the problem identification and resolution program. However, some deficiencies were identified in the implementation of the program.

These included: unclear or incomplete corrective actions; lack of thoroughness evaluations; and inconsistent categorization of program items. Additionally, two licensee identified non-cited violations are listed in Section 4OA7 of this report. If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the 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 Sequoyah.

TVA 2 In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/NRC/ADAMS.index.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Stephen, J. Cahill Reactor Projects Branch 6 Division of Reactor Projects Docket Nos. 50-327, 50-328 License Nos. DPR-77, DPR-79

Enclosure:

Inspection Report 05000327/2003009; 05000328/2003009 w/Attachment

REGION II==

Docket Nos: 50-327, 50-328 License Nos: DPR-77, DPR-79 Report No: 50-327/03-09, 50-328/03-09 Licensee: Tennessee Valley Authority (TVA)

Facility: Sequoyah Nuclear Plant, Units 1 & 2 Location: Sequoyah Access Road Hamilton County, TN 37379 Dates: September 8 - 12 and September 22 - 26, 2003 Inspectors: B. Holbrook, Lead Inspector, Senior Reactor Inspector, Browns Ferry Nuclear Plant D. Forbes, Physical Security Inspector, Region II R. Monk, Resident Inspector, Browns Ferry Nuclear Plant R. Telson, Resident Inspector, Sequoyah Nuclear Plant Approved by: S. Cahill, Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure

Summary of Findings IR 05000327/2003-009, 05000328/2003009; on 9/08/2003 - 9/26/2003; Tennessee Valley Authority, Sequoyah Nuclear Plant, Units 1 and 2, annual baseline inspection of the identification and resolution of problems.

The inspection was conducted by an NRC Senior Reactor Inspector, two Resident Inspectors, and a Physical Security Inspector. No findings of significance were identified. 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.

A. NRC-Identified and Self-Revealing Findings None B. Licensee-Identified Violations Two violations of very low safety significance, which were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective actions are listed in Section 4OA7.

Identification and Resolution of Problems The team determined that, overall, the licensee was effective at identifying problems, entering them into the corrective action program (CAP) for resolution, and implementing corrective actions to prevent recurrence. However, there were several examples where the documentation of problem evaluation reports (PERs) was not clear, concise, or comprehensive.

The team had to seek out plant personnel knowledgeable of some problems to gain a clear understanding of the issue in order to assess if the corrective actions identified were adequate.

The inspection team did identify a significant improvement in the quality of PER development and documentation during recent months when compared to older PERs, indicating increased management and supervisory attention to overall PER quality.

Senior management involvement in the problem identification and resolution (PI&R) program was evident in the daily management review committee meeting, where all PERs were reviewed. The licensees threshold for identifying problems was low as evidenced by the large number of PERs identified. The number of PERs met the licensees goal for problem identification. However, due to the large number, backlog presented a challenge and did not meet the licensees goals. The team did not identify any significant problems due to the backlog. The team also did not identify any adverse conditions which were not in the CAP for resolution.

Licensee audits and assessments critically assessed PI&R activity and identified improvement needs. Prioritization and evaluation of problems were generally effective and consistent with risk and safety significance; however, there were some examples where evaluations were not thorough and detailed. Corrective actions specified for problems were generally adequate; although some minor examples were identified where the corrective actions were not complete, or not comprehensive.

Long term equipment problems continue to challenge plant staff and unit operation. This was most evident for safety related chillers and plant electrical breakers. Some corrective actions for chiller problems and component performance were not timely. The overall system health of safety related chillers, since the last PI&R inspection in December 2001, has declined.

However, slight improvement was noted for specific components. The trending element of the CAP was not always effective in identifying potential adverse trends. The corrective actions for balance-of-plant equipment issues were not as detailed, rigorous, or effective in correcting problems as with safety related equipment.

Based on interviews conducted during the inspection, workers at the site feel free to raise issues with their management and to input them into the problem identification and resolution program.

Report Details 4. OTHER ACTIVITIES (OA)

4OA2 Problems Identification and Resolution a. Effectiveness of Problem Identification (1) Inspection Scope To determine if problems were being properly identified and entered into the CAP for resolution, the inspectors reviewed PERs from an approximate two year period since the last PI&R Inspection for issues across the reactor safety cornerstones. The team also conducted a more detailed system review focused on systems identified in the licensees listing of top ten risk reduction worth systems and top ten risk achievement worth systems. The systems selected were also identified as systems important to mitigating accident conditions. The systems selected for review were the auxiliary feedwater system (AFW), essential raw cooling water system (ERCW), and the emergency diesel generators (EDGs). To determine if problems were being properly identified, characterized, and entered into the corrective action program for evaluation and resolution, the inspectors reviewed PERs, selected work orders (WOs), planned modifications, and system health reports associated with the systems.

The inspectors conducted a walkdown, with the responsible system engineer, of accessible portions of the above systems to determine if deficiencies existed that had not been entered into the CAP. Discussions with the system engineer and plant personnel were conducted to assess overall system health and performance and to determine if known deficiencies were being entered into the CAP.

Selected audits and self-assessments were reviewed to determine if identified issues were entered into the CAP for resolution. CAP status tracking and performance trending data were reviewed to determine if there was any significant change in the rate of PER generation and to assess the licensees actions with respect to abnormal trends.

Open items in the Employee Concerns Program (ECP) backlog were reviewed for timeliness of review, closure, significance and issue disposition.

The inspectors reviewed personnel contamination reports, safeguards event reports, and licensee identified deficiencies associated with emergency preparedness to verify that they were appropriately entered into the licensee's CAP. The team also reviewed licensee actions in response to non-cited violations from NRC inspection reports; corrective actions taken for licensee event reports; and actions with respect to operating experience items to ensure they were assessed for inclusion into the CAP.

The inspectors also reviewed items in the physical protection cornerstone to determine if problems were being properly identified, characterized, and resolved. The team identified PERs and safeguards event reports for security deficiencies and evaluated the items to determine if the licensee was trending deficiencies appropriately. Selected licensee corrective action program documents associated with this program area were reviewed and are listed in the attachment.

The team also reviewed licensee security self assessments from 2001 and 2002 as well as Nuclear Assurance Department safeguards audits from 2002 and 2003. The effectiveness of these assessments and audits was evaluated by comparing the assessment and results against self-revealing and NRC-identified issues. While reviewing licensee corrective actions, problems identified for security activities were evaluated against the requirements contained in the Sequoyah Physical Security and Safeguards Contingency Plan, and referenced licensee procedures. Specific documents reviewed are listed in the attachment.

(2) Assessment The team determined that the licensee was effectively identifying problems and entering them into the CAP for resolution. This was evidenced by the large number of PERs identified and their low threshold, the importance of issues being identified and documented, and the relative few deficiencies being identified by external organizations.

The number of PERs met the licensees internal goals for problem identification.

However, due to the large number of PERs initiated, the backlog of PERs presented a challenge and did not meet the licensees internal goals. The team reviewed the scope of the backlog and did not identify any significant problems that were attributable to the backlog.

During the inspection teams review and walkdown of the accessible portions of the AFW, ERCW, and EDG systems, the team did not identify any significant conditions adverse to quality. The system engineers tracked deficiencies and were familiar the overall system health and long term performance of their systems. For example, the EDGs have been classified Yellow (Red, Yellow, White and Green monitoring scale) in the System Health report for the past 10 quarters partially due to a problem with the pressure control valves (PCVs) in the air start system that was identified in November 2002. At times, a PCV will open and result in a spurious uncontrolled blowdown of the air start receiver. A design change implemented to correct the problem was not completely successful. While the PCV problem was not a current operability concern, it kept the EDG system in a declined performance status so the system engineer had rated the system health as Yellow. The system engineer also had developed a checklist to monitor PCV performance and maintained a list of system deficiencies, improvement issues, and proposed system design changes to address long standing performance issues. He also had provided operations personnel with interim guidance until another corrective action could be implemented. The PCV problem is documented as an open B level PER. The team considered this effective oversight of the recurring problem in the licensees CAP.

The inspection team identified a significant improvement in the quality of PER development and documentation during recent months when compared to older PERs reviewed during the inspection. PER quality improvement has been a recent goal and focus area for site management. The observed improvements were indicative of this increased management and supervisory attention. However, the team identified examples where PER documentation was not clear or concise. Frequently the inspection team had to seek out knowledgeable personnel to gain a better understanding of the issue in order to assess the adequacy of the corrective actions

planned or taken. When one PER was closed to an existing PER, or when PERs were combined, the problem descriptions were not always clearly carried forward. The inspection team did not identify any significant issues which were deleted or dropped.

However, the team identified this as a licensee challenge to ensure corrective actions would correct the appropriate problem.

The team verified that issues and deficiencies raised by audits and self-assessments were appropriately entered into the CAP. Self-assessments were critical, detailed, and identified items to correct or improve programs and processes. One particularly good assessment was the Sequoyah Reliability Improvement Plan dated July 30, 2003. The Plan was a work in progress and was expected to develop as it progressed. It addressed five areas (Operations, Maintenance and Modifications, Engineering, Outage and Scheduling, and Management) and was developed to improve the declining performance of Unit 2, which has experienced six reactor trips and two forced outages since the spring of 2002, and to ensure that Unit 1 does not experience similar issues.

The team noted implementation of immediate and long term actions and that an extensive assessment of the CAP with suggested improvements was forthcoming.

The Operating Experience (OE) samples reviewed by the team indicated that OE items were given appropriate consideration by plant personnel. OE items were captured in PERs and received management review during the daily review of PERs. Items were appropriately screened and, if required, incorporated into programs and processes.

Items resulting from the Employee Concerns Program (EPC) were reviewed, classified, and entered into the CAP for resolution in accordance with SPP-3.1.

The inspection team identified some deficiencies with implementation of CAP procedure requirements for conducting trend analysis. For example, a sort of the PER database for torque issues for the previous two years identified more than 100 different PERs for both safety related and non-safety related equipment. The problems included over-torquing, possible under-torquing (cause unresolved) and torquing with unclear procedure guidance. Although most of these PERs were level D or C and did not require corrective actions to prevent recurrence, the licensee credited trend analysis as the means to identify adverse performance or common causes to be corrected. The inspectors observed that a trending PER had not been initiated and no previous actions had been taken to strengthen the torquing process.

The team determined that the licensee was effective at identifying security problems at an appropriately low level and entering them into the CAP. The team did not identify any security deficiencies that had not been previously identified by the licensee and identified in a PER. Assessments and audits were generally of sufficient depth and identified issues similar to those that were self-revealing.

b. Prioritization and Evaluation of Issues (1) Inspection Scope Licensee special purpose procedure (SPP)-3.1 contained four classifications of PER significance: A level was the most significant, usually safety related and requiring a formal root cause analysis; B level was considered significant, required further evaluation, and may require a formal root cause determination based upon management decision; C level was for routine problems warranting additional corrective evaluation and action; and D level was for issues that could be quickly resolved/closed and trended or routine problems which were adequately addressed by immediate actions or the work control process.

The team reviewed a sampling of PERs to determine if issues were classified and resolved in accordance with the requirements of procedure SPP-3.1. The team attended the licensees management review committee (MRC) meeting to observe the final classification assignment for emerging PERs. The team reviewed root cause analyses and apparent causes for PER items to assess the quality, adequacy, and thoroughness of the evaluations. In addition, the team assessed the corrective action items resulting from the cause determinations to determine if procedure requirements were met to correct the problem and to prevent recurrence if required. The cause codes identified in the PERs were compared to the identified apparent cause or root cause analyses determination to determine if the causes were correct and that the causes were adequately addressed by the corrective action item. Selected audits and self-assessments were reviewed by the team to determine if problems were developed into PERs. Also, the review was to determine if the PERs were correctly classified in accordance with procedure guidance and that corrective action items were completed as described in the corrective action plan. Documents reviewed are listed in the attachment.

(2) Assessment In the area of Problem Evaluation, the team found that the licensee generally performed appropriate evaluations of problems identified in the CAP process. However, some deficiencies were noted in evaluating the effects of continued plant operations in off-normal conditions. Examples of this include: 1) operation with the #7 heater drain tank level control valve 'dogged' which reduced the secondary plant's ability to withstand a condensate system transient resulting in a reactor trip: 2) operation of a cooling water valve with excessive manual torque which broke the valve allowing it to isolate cooling water to the stator resulting in a reactor trip: 3) operation with a combination of leaking High Pressure Stop Valves to the main feed (MF) pumps and isolated MF pump recirculation valves which often result in additional operator actions and equipment challenges following MF water isolations.

During interviews with various levels of plant personnel the team found that personnel had received feedback on problems they had identified as well as on self-assessment and audit findings.

The team also determined that PERs were generally categorized correctly. However, there were several examples where the team determined a higher level or more rigorous evaluation was more appropriate and may have been more effective in resolving the problem. Examples included:

• C level PER 02-002372, Main Generator Loose Frame Foot Bolting, was initiated for a Unit 1 turbine/generator vibration problem. It stated that all accessible Frame Foot Bolting (79 of 100) was checked by hand. All bolts on the North Side (43 of 50) were found to be hand tight (vice the vendor recommended 800 ft/lbs). No immediate action was documented. Since this was a C level PER, no root cause was performed and it received less rigor and management oversight. Neither the PER nor corrective action addressed the reason for the loose bolting and no documentation in the CAP indicates it was ever resolved.

The inspectors noted the generator is not covered under the Quality Assurance program of 10 CFR 50, Appendix B and has no safety related function and this was therefore not a violation of regulatory requirements.

• C level PER 03-006554-000, documented that the 1A ERCW supply header was opened in order to replace a section of piping. A significant quantity of silt was present, starting about 5 feet from valve 1-FCV-67-147 and increasing so that the 24" pipe was half full. The silt problem revealed a condition contrary to findings associated with corporate A level PER 02-000203-000 that identified the need for overall program reevaluation based on raw water corrosion control deficiencies. The silt also contradicted a ultrasonic examination of ERCW piping that indicated no significant silt accumulation.

While the presence of silt was identified, the deficiency was not placed into the above context and, as such, did not provide a complete and accurate identification of this problem. As a C level PER, it was not explicitly evaluated for all potential problems. During this inspection, the inspectors determined that valve 1-FCV-67-147 is a unit crosstie valve, is normally closed, and has no safety function. The inspection team concluded that opening the valve such that safety related components would be affected, would be highly unlikely and presented no safety concern.

• C level PER 02-005524-000, noted that the No. 1 reactor coolant pump (RCP)

on U2 failed to start and did not start on a second attempt after having instrumented various contacts on the RCP breaker. The pump started on a third attempt. The apparent cause was characterized as a high resistance in the control wiring of the closure circuit or mechanical binding of the breaker or closing coil, but a cause could not be proven during troubleshooting.

Development of a corrective action plan was delayed with the following justification: RCPs 1 and 3 are presently running and of course will remain running until the next refueling outage or forced outage. Therefore the start circuit issue does not affect nuclear safety or personnel. Based on this, it is acceptable to extend the corrective action plan development. This did not consider that emergency procedure FR-C.1, Inadequate Core Cooling, identified specific conditions requiring the starting of RCPs. Due to the C level classification of this PER, it received less rigor and management oversight and this aspect was not considered. The inspection team noted that placing the RCPs in service with an unresolved problem has not had an adverse consequence.

• D level PER 03-010200, documented that the Emergency Gas Treatment System (EGTS) had to be placed in service without prior planning and this caused Unit 2 to enter an unplanned LCO. Based on Condition Classification Criteria of SPP-3.1, this PER should have been a C level since an unplanned LCO entry occurred.

The inspection assessed the licensees use of Root Cause and Apparent Cause analysis and the quality, depth, and focus of the analysis. Identification of the causes of some deficiencies was not thorough and detailed. The evaluations were not always reassessed using more current information. Examples include the following:

• PER 02-012966-000, identified a problem with an EDG engine air start pressure control valve (PCV) that bled down the air start receiver for approximately 10 seconds during an EDG start, creating the potential concern for the receiver to fall below the TS limit of 210 psig. The root cause section of the PER indicated that a Kepner-Tregoe analysis was performed. Based upon a test document provided, no blow down events could be replicated and the PER concluded Therefore, the possible causes are considered highly unlikely. PCV induced blowdown events have occurred multiple times since, but the root cause analysis had not been updated to reflect that the events continue to occur. The licensee had addressed each problem. The inspection team determined that there was no EDG operability concern since the problem only affected one train of the air system.

• PER 02-009749, identified a problem with the air regulators for the Motor Driven Auxiliary Feedwater control valves. In the PER, there was a lengthy description of the desired valve air setting, the current valve settings, and that a study had recommended that an additional 20% air pressure above the vendors specifications be applied. Missing from the description was that the vendor expressed concern with repeated stressing of the diaphragm housing bolts while the valves cycled. This PER was deemed a condition adverse to quality (GL 91-18) issue and required a Functional Evaluation (FE). The FE took into consideration the low number of valve cycles. However, nothing was communicated to Operations regarding the vendors concern with valve cycling and there was no tracking system for the number of valve cycles.

c. Effectiveness of Corrective Actions (1) Inspection Scope The inspectors reviewed PERs to assess the adequacy of the corrective actions applied to the PER adverse conditions. Inspectors also reviewed WOs, audits, and self-assessments to evaluate the effectiveness of corrective actions, and to determine if the timeliness met the licensees problem identification and resolution requirements, including corrective actions to address common cause or generic concerns. The PERs selected included the system PERs and WOs discussed in report section 4OA2.a(1), as well as a selection of human performance PERs attributed to operations, engineering, and maintenance personnel. The inspectors reviewed the corrective actions taken in response to seven NCVs documented in NRC inspection reports between December 2001 and September 2003 to verify CAP procedure requirements were met and that actions were thorough and comprehensive. The inspectors selected a sampling of the 25 oldest PERs to verify that the basis for the delay in correcting the identified problems was valid and that extensions were approved and justified as required by the CAP procedure. A sampling of deleted PERs were reviewed to assess the basis for the deletion and if the deletion was appropriate for the issue. Documents reviewed are listed in the attachment.

(2) Assessment The inspection team determined that the licensees corrective actions were generally effective in resolving equipment deficiencies. However, there were examples where the corrective actions were not totally effective or timely in resolving issues. The trending element of the CAP was not always effective in identifying potential adverse trends. The corrective actions for balance-of-plant equipment issues were not as detailed, rigorous, or effective in correcting problems as with safety related equipment. Examples where the corrective actions were not totally effective or timely in resolving issues included the following:

• An NCV was documented during the last PI&R inspection in December 2001, for the failure to promptly identify and correct long-standing problems with safety-related chillers. During this inspection, the inspection team identified that a high level of effort has been expended to improve these chillers. However, performance of the chillers has continued to decline as evidenced by the number of functional failures (2, 3, and 4 respectively in the previous 3 quarters), the continued decrease in the system health declining from yellow to red, the incomplete corrective actions from PER 00-011349-000, dated 12/12/2000, and the length of extensions of other outstanding PERSs. The inspectors noted that some small performance improvement had occurred in certain components of the chiller systems. The licensee continued to implement design changes and to work on their long term corrective action plan for system improvement.

• The inspection team noted that between January 2002 and July 2003, there were approximately 85 FME-related PERs, including one A level and two B level PERs. The inspectors noted that the A level PER did not document any

immediate actions and did not contain any evidence of a briefing or stand-down to express concern to workers. Following a discussion with the inspection team, a briefing sheet was presented to craft departments expressing a concern for FME controls and reminder of program requirements. The inspection team determined that the actions discussed in the A level PER were detailed, thorough, and when completed could resolve the broad range of FME problems.

However, the licensee had missed many opportunities to previously strengthen the FME program in response to the previous large number of PERs. The inspectors concluded that the current licensee plans to address FME program deficiencies would likely be effective, but previous CAP efforts to develop comprehensive corrective actions had not been timely or effective.

• The team noted that between January 2002 and August 2003, there were approximately 45 PERs associated with breaker problems. Most of the problems resulted from poor vendor workmanship and quality control and licensee receipt inspection. Some breaker problems were identified after being placed in service but most were discovered on new or newly rebuilt breakers before being placed in service. Most of the PERs were C and D level. The licensee had initiated B level PER 01-009568 in late 2001, and had revised the PER seven times to include newly identified problems. The inspection team noted that on July 23, 2003, the licensee met with the vendor to discuss breaker problems and to address overall quality improvement.

The inspection team determined that, even though the vendor was actively involved with onsite actions to correct problems, the CAP program was not very effective in raising the breaker problem to a higher level of management attention. This was evidenced by the CAP documentation indicating that a senior management meeting occurred in July 2003, after a number of PERs had been written on similar and repeat problems since late 2001. The actions outlined in the June 2003, PER, such as: 1) TVAN representatives will conduct onsite visits at the vendors facility to work with assemblers and perform spot inspections: 2) actions to strengthen the receipt inspection program: 3) improve the quality checklist by including TVAs specific checks: 4) increased quality assessments may have resolved many of the problems sooner.

The inspection team reviewed the licensee response to multiple self-assessments that identified that the quality of apparent and root causes was not improving. Over a given period of time, the quality would improve, but then fluctuate. The licensee had initiated extensive retraining to improve root and apparent causes in 2001. The inspection team determined that some PER actions to improve root and apparent causes were unclear, closed by methods not normally used, and some were not acted upon. Examples included the following:

• Self-assessment SQN-SIT-03-001, 2002, identified that 26% of apparent and root causes reviewed did not meet managements expectations. As a result PERs were initiated to address the deficiencies. D level PER 02-014206-000 was initiated for the chemistry department because three of four analyses reviewed did not meet managements expectations. The inspectors noted that

the apparent causes were worker duties improperly focused or insufficient and management follow-up or monitoring of activities did not identify the problem.

The inspectors noted that the PER was closed with no action taken.

• PER 02-014204-000, D level was issued for operations (five of ten analyses did not meet managements expectations) and was closed after the analyses were corrected and the root cause coordinator was informed of his shortcomings.

• PER 03-002423-000, C level resulted from a Nuclear Assurance audit and identified that the quality of root causes showed some improvement in some areas, however, the performance trend has reached a plateau and is not showing continued improvement. The PER identified seven corrective actions.

All were addressed and closed via E-mail. Site management informed the inspectors that E-mail was not the normal expected method to address corrective actions.

The inspection team noted that the long standing equipment problems included safety and non-safety related balance-of-plant equipment. Non-safety related equipment issues caused the majority of the six recent reactor trips on Unit 2 and have been the major challenge to recent unit operation. These systems were outside the 10 CFR 50, Appendix B program and are not considered significant conditions adverse to quality.

Examples where the corrective actions for balance-of-plant equipment issues were not as detailed, rigorous, or effective as with safety related equipment included the following:

• Feed water pump steam stop valves that do not fully close, feed water pump minimum flow valves that do not cycle properly, a load cell/switch on a spent fuel pool crane that is obsolete and indicating 1/2 the actual load, and known problems with fans and dampers of a containment ventilation system. The inspection team noted that some corrective actions for these long standing problems indicate a design change or unit outage may be required and repair implementation may be delayed for an extended time. The licensee generally had long term fixes planned or proposed fixes in review to address the problems.

d. Assessment of Safety-Conscious Work Environment (1) Inspection Scope The inspection team reviewed numerous audits, assessments, PERs, WOs, and other corrective action documents and held discussions with numerous personnel at various levels in the organization to assess if a work environment existed that was conductive to the identification of nuclear safety issues. The team also examined the licensees ECP tracking document and files and discussed the program requirements with the administrator to determine if issues affecting nuclear safety were being appropriately addressed.

(2) Assessment The inspection team determined that workers at the site felt free to raise safety concerns. Personnel stated that they would not hesitate to raise nuclear safety issues to their management. They also understood and believed that they could raise issues without fear of retaliation by their management. Workers stated that the use of direct supervision was their preferred approach to raising issues, but would not hesitate to use other mechanisms such as the ECP or the NRC. The inspection team did not identify any concerns related to safety conscious work environment.

40A3 Event Followup 1. (Closed) LER 50-327/2002-001-00, Westinghouse Electric Corporation Error Results in Nonconservative Steam Generator Level Setpoint:

This LER documented that Westinghouse determined that the demonstrated accuracy calculation for low-low level trip setpoint narrow range span did not account for the measured bias associated with the differential pressure created by the steam flow past the mid-deck plate in the moisture separator section of the steam generator. The licensee documented this problem in the corrective action program as PER 02-002298-000. The inspectors reviewed the LER and verified no safety design margins had been exceeded. No findings of significance were identified.

2. (Closed) Licensee Event Report (LER) 50-328/2003-001-00, Reactor Trip Signal as a Result of a Low-Low Steam Generator Level.:

This LER documented a January 1, 2003, Unit 2 reactor trip signal on steam generator Loop 2 low-low level. There was no pump or valve operation because the unit was shutdown in Mode 5. The licensee determined that technicians had bypassed the steam generator low level alarms instead of low-low level trips. This was because information contained in the procedure was too generic. The licensee documented this problem in the corrective action program as PER 03-000003-000. The inspectors reviewed the LER and no findings of significance were identified.

3. (Closed) LER 50-328/2003-004-00, Reactor Trip From A Neutral Over-Current Condition On The 2B Hotwell Pump and a Failure to Perform a Technical Specification Required Action:

This LER documented that, following the reactor trip, the dose equivalent iodine exceeded technical specification (TS) limits. TS required sampling of the reactor coolant system every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> until the activity is within limits. The licensee determined that one of the samples was not taken within frequency. The sample was taken about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 35 minutes late. The licensee determined that the cause of the TS violation was a narrow turnover scope that was not specifically tracking the sampling frequency relative to the TS action.

This event was determined to be of very low safety significance (Green), by the Significance Determination Process (SDP) because the sampling was completed later and determined to be within specifications. The inspectors determined that licensee actions taken or planned were reasonable. This issue constitutes a violation of very low safety significance that is not subject to enforcement action in accordance with Section IV of NRCs Enforcement Policy. The licensee entered this event into the corrective action program as PER 03-002422-000. This LER is discussed in Section 40A7.

4. (Closed) LER 50-328/2003-005-00, Reactor Trip From Spurious Turbine Vibration Trip Signal:

This LER documents an equipment failure that resulted in a reactor trip. Plant personnel had opened a drawer to place a vibration trip cutout switch in the cutout position. When the drawer was closed, a spurious vibration trip signal was generated.

The licensee determined that exposed wire conductors in the drawer had shorted with another conductor causing the problem. The exposed conductors were repaired and the vibration trip relay was disabled. The licensee entered this event into the corrective action program as PER 03-0012538. The inspectors reviewed the LER and no findings of significance were identified.

5. (Closed) LER 50-328/2003-006-00, Failure to Meet Technical Specification Limiting Condition for Operation Action Time for the Component Cooling System:

This LER documented that the common spare component cooling system (CCS) pump, that was supplying the B-train loads, was removed from service for maintenance and the 1B-B CCS pump was aligned to supply the B-train loads. Personnel later determined that the 1B-B CCS pump does not auto start from a Unit 2 safety injection signal. At the time of discovery, Unit 2 had already exceeded the LCO action time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Maintenance was expedited and the spare pump was later returned to service. The licensee determined the cause was that operators did not fully understand the TS applicability relative to the CCS equipment alignment. This event was determined to be of very low safety significance (Green), by the Significance Determination Process (SDP) because the redundant systems and pumps were available and had no impact on plant operation either in normal or off-normal conditions. The inspectors determined that licensee actions taken or planned were reasonable. This issue constitutes a violation of very low safety significance that is not subject to enforcement action in accordance with Section IV of NRCs Enforcement Policy. The licensee entered this event into the corrective action program as PER 03-005924. This LER is discussed in Section 40A7.

4OA6 Meetings, Including Exit The inspectors presented the inspection results to Mr. R. Purcell, Site Vice President and other members of the licensee management and staff at the conclusion of the inspection on September 26, 2003. The licensee acknowledged the findings presented.

The lead inspector asked the licensees management whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee Identified Violations The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600 for being dispositioned as an NCVs.

1. Unit 2 Technical Specification 3.4.8 requires, in part that, specific activity of the primary coolant shall be limited to less than or equal to 0.35 microcuries/gram Dose Equivalent I-131. The applicability for Modes 1, 2, 3, 4, and 5 is with the specific activity of the primary coolant greater than 0.35 microcuries/gram Dose Equivalent I-131, perform the sampling and analysis required of item 4a of table 4.4-4 until the specific activity of the primary coolant is restored to within its limits. Table 4.4-4 requires that sampling be performed once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, whenever the specific activity exceeds 0.35 microcuries/gram. Contrary to this, on March 10, 2003 sampling of the Unit 2 reactor coolant was not completed within the four hour time requirement. This finding was of very low safety significance because the sampling was conducted approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 35 minutes late and was within Technical Specifications limits. The licensee entered this into the corrective action program as PER 03-002422-000.

2. Unit 2 Technical Specification 3.7.3 Requires at least two independent component cooling water loops shall be Operable in Modes 1, 2, 3, and 4. With only one component cooling water loop Operable, restore at least two loops to Operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least Hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Contrary to this, on April 24 through 26, 2003, (approximately 67 hours7.75463e-4 days <br />0.0186 hours <br />1.107804e-4 weeks <br />2.54935e-5 months <br />) a Unit 1 pump aligned for a Unit 2 loop of cooling would not receive an automatic start signal from Unit 2 for all accident conditions and the loop should have been considered inoperable.

This finding was of very low safety significance because the pump that would not receive an automatic start signal was already running and additional pumps were available and operable to provide more than adequate cooling capacity. The licensee entered this into the corrective action program as PER 03-005924.

SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED R. Beecken, Vice President, Nuclear Support H. Butterworth, Senior Manager M. France, TVA Corporate Security D. Kulisek, Plant Manager.

C. Kent, Chemistry Manager G. Michell, Pinkerton, General Manager R. Proffitt, Nuclear Engineer R. Purcell, Site Vice President R. Rogers, Engineering Design Manager P. Salas, Licensing and Industry Affairs Manager B. Schnetzler, TVA Corporate Security Manager M. Tipton, Security Supervisor D. Thompson, Acting Security Manager NRC Personnel V. McCree, Director, Division of Reactor Projects S. Cahill, Chief, Branch 6, Division of Reactor Projects ITEMS OPENED AND CLOSED Closed 50-327/2002-001-00 LER Westinghouse Electric Corporation Error Results in Nonconservative Steam Generator Level Setpoint (Section 40A3.1)

50-328/2003-001-00 LER Reactor Trip Signal as a Result of a Low-Low Steam Generator Level (Section 40A3.2)

50-328/2003-004-00 LER Reactor Trip From A Neutral Over-Current Condition On The 2B Hotwell Pump and a Failure to Perform a Technical Specification Required Action (Section 40A3.3)

50-328/2003-005-00 LER Reactor Trip From Spurious Turbine Vibration Trip Signal (Section 40A3.4)

50-328/2003-006-00 LER Failure to Meet Technical Specification Limiting Condition for Operation Action Time for the Component Cooling System (Section 40A3.5)

Attachment

PARTIAL LIST OF DOCUMENTS REVIEWED Procedures Reviewed Number Description/Title NADP-3 Managing the Operating Experience Program ODM-1.0 Conduct of Operations ODM-3.7 Operator Work Arounds OPDP-1 Conduct of Operations SPP-1.0 Concerns Resolution SPP-1.3 Plant Access and Security SPP-1.6, TVAN Sef Assessment Program SPP-2.2 Administration of Site Technical Procedures SPP- 3.1 Corrective Action Program SPP- 6.1 Work Order Process Initiation SPP- 6.5 Foreign Material Exclusion SPP-9.7 Corrosion Control Program BP- 250 Corrective Action Program Handbook 0-TI-CEM-043-016.5, Support Systems - Sampling Methods 0-PI-DXX-000-704.1, Degradation Monitoring Program for Raw Water Systems 0-TI-SXX-000-146.0, Program for Implementing NRC Generic Letter 89-13 0-PI-CEM-067-712.0, Essential Raw Cooling Water Microbiologically Induced Corrosion/Mollusk Control AOP-M0.1, Loss of Essential Raw Cooling Water Audits, Self-Assessments, and Trend Reports Sequoyah Reliability Improvement Plan, Rev. 5 Audit Report No. SSA0106, Security Safeguards Information and Fitness For Duty (FFD)

Programs, December 21, 2001 Audit Report No. SSA0205, Security Safeguards Information and Fitness For Duty (FFD)

Programs, December 12, 2002 Audit Report No. SA-NSS-03-003, Nuclear Security Self Assessment, August 15, 2003 Sequoyah Physical Security Plan/Contingency Plan, Revision 8 Oversight Analysis Report Ending December31, 2003 Audit Report No. SSA0204, Engineering Functional Area Audit Audit Report No. SSA0301, Fire Protection and Loss Prevention Operations Analysis of PERs, January, February and June, 2003 Assessment of SG Replacement CAP Trend Analysis Assessment of Maintenance-Modifications CAP Trend Analysis, January, February and June, 2003 Assessment of Engineering CAP Trend Analysis, January, February and June, 2003 Assessment of RADCHEM CAP Trend Analysis, January, February and June, 2003

Assessment No. NA-CH-01-002 Nuclear Assurance Assessment of the TVAN Clearance Program found that corrective actions to prevent recurrence (for clearance problems) have not always been effective and effectiveness reviews have not been performed for level B PERs.

PERs Reviewed for Security Related Issued Safeguards Event Report 02-3-114 Safeguards Event Report 02-4-134 02-013160 Security Equipment Issue 02-003485 Security Equipment Issue 02-001132 Control of Safeguards 02-005700 Security Equipment Issue 02-009718 Security Equipment Issue 02-009213 Security Equipment Issue 02-014931 Security Equipment Issue 02-006857 Security Equipment Issue 02-012935 Security Equipment Issue 02-006919 Security Equipment Issue 02-003447 Security Equipment Issue 02-014922 Security Equipment Issue 02-013161 Security Equipment Issue 03-001787 Security Equipment Issue 02-009491 Improper Badge Entry 03-010733 Posting of Response 03-011371 Review of Commitments 03-010767 Vehicle Escort 03-011458 Equipment Testing 03-011467 Equipment Testing 03-011468 Equipment Testing 03-011470 Equipment Testing 03-010020 Equipment Observation PERs Reviewed for Main and Auxiliary Feedwater Problem 01-003219 Vibration issues on U1 TDAFW pump 02-009676 Effect of recirc valve on operability 02-013543 Caulking on control cabinets 02-013515 Flow modifier 02-015116 Sump switches 03-011953 1A Main Feed Pump spinning 1000 rpm post Unit trip 03-002634 1A Main Feed Pump running dead-headed causing seal failures 03-001708 All Main Feed Pumps spinning post Unit trip 03-002665 2B Main Feed Pump speed control (400 rpm swings)

03-002740 2B Main Feed Pump speed control 03-002314 Speed control in manual of U2 TDAFW PERs Reviewed for EDG 01-007184 PCV valve problems 01-010452 EDG failed to start 02-001424 EDG failed to start 02-003722 EDG failed to start during testing 02-012966 PCV valves blew down air receiver 03-008109 PCV blew down 03-009465 Replace PCV 03-009416 OE assessment identified lack of cable inspections 03-012611 EDG oil leak

PERs Reviewed for ERCW 02-000203 Continuing raw water corrosion control deficiencies indicate the need for overall program re-evaluation 03-006554 Silt observed in 1A ERCW supply header when opened in order to replace supply piping 03-008909 A throughwall leak not associated with a weld was discovered on 8 inch ERCW piping Non-cited (NCV), Licensee Identified (LIV) Violations and PERs Reviewed PER 02-005087 (LIV 50-328/ 2002-02-03) Unintended closure of suction valve 2-FCV-62-132 to operating 2B-B CCP resulting in destruction of pump PER 02-000281 (LIV 50-327, 328/ 2001-05-05)

PER 02-003222 (NCV 50/327, 328/ 2001-05-03) Potential violation of intent of procedure SPP-2.2, step 3.1.1.A, administrative guidance for procedure change PER 02-003543 NRC identified that pre-fire plans do not contain for fire brigade incident commander on potential effects that fire suppression or smoke removal efforts may have on required fire safe shutdown operator actions PER 02-003550 (NCV 50-327, 328/2002-03-02)

PER 02-003552 NRC identified weaknesses in operator understanding and familiarity with fire protection AOP-N.01 and -N.08 PER 02-003645 (NCV 50-327/ 2002-03-01) Failure to provide adequate protection for cables to redundant SSD components PER 02-001183 (LIV 50-327, 328/ 2002-02-04) ERCW piping leak downstream of valve 1-67-537A in 1A CS room; 4" of water discovered on floor PER 02-003735 (LIV 50-327, 328/ 2002-02-04) ERCW piping downstream of 2A-A EDG below minimum wall thickness requirements PER 03-001577 (NCV 50-327, 328/ 2003-03-01) Ventilation permits were not logged into the shield building tracking sheet and the square inches were not added to the total areas open PER 03-003612 (NCV 50-327, 328/ 2003-03-01) Failure to provide adequate instructions for controlling shield building breach 50-327/2001-05-04 (LIV) Failure to follow clearance procedure - clearance order closed without refilling 1A-A CS HX 50-327, 328/2001-05-05 (LIV) Inadequate instruction to ensure piping adjacent to valve 1-FCV-63-8 was full of water following maintenance 50-328/2002-02-03 (LIV) Failure to follow procedure - Incorrect position of valve 2-FCV-62-132, charging pump suction 50-327, 328/2002-02-04 (LIV) Inadequate guidance defining the elements and standards of an effective cavitation program 50-327/2002-03-01 (NCV) Failure to provide adequate protection for cables to redundant SSD components 50-327, 328/2002-03-02 (NCV) Inadequate procedural guidance for implementing abnormal operating procedures for plant fires 50-327, 328/2003-03-01 (NCV) Inadequate instructions for controlling shield building breaches

PERs Reviewed for Maintenance Preventable Functional Failures 02-015333 Vibration on 480V Board Room 2B-B AHU 02-011061 480V Breaker loose wire 02-010113 Vibration on Penetration Room B AHU 03-003715 RWST Level Indicators 03-009117 Containment Vacuum Breaker 03-000211 Vibration on 480V Board Room 2B-B AHU 03-002422 #7 HDT LCV diaphragm failure 03-004344 Bad jumper to spare breaker 03-004025 TCV for B 6.9Kv Board chiller PERs Review for Torquing Issues 01-000485 Emergency Diesels 02-001249 Emergency Diesels 02-013611 PK Studs 02-014067 Aux Bldg Crane 02-014333 EBR A Chiller 03-000698 Emergency Diesels 03-005652 RSG #4 Lower Lateral Bumper Pad 03-007489 PK Studs PERs Reviewed for Chiller Issues 00-011349 All Safety Related Chillers 01-008319 SDR A Chiller 02-010285 EBR A Chiller 02-013072 EBR A Chiller 02-013824 Dunham Bush Chillers 02-014333 EBR A Chiller 03-000185 MCR A Chiller 03-001586 MCR A&B Chiller (overlapping failures)

03-007073 MCR A AHU 02-000542 480V Board Room 1B AHU 02-003157 480V Board Room Chillers (all)

03-009919 480V Board Room Chiller 1B PERs and Miscellaneous Documents Reviewed 01-005036 MOV 2-FCV-70-156 thermal overloads opened on May 29, 2001 01-009247 MOV 0-FCV-070-0198-B thermal overloads opened while performing MOVATS testing on or about October 12, 2001.

01-011549 LIV 50-327/2001-05-05, 1A CS heat exchanger discovered not full of water 02-002217 Closed to PER 02-001183-000 02-006086 (LER 2002-03) Level A-RC, May 31, 2003, Unit 2 Reactor Trip due to Turbo-Generator Trip from Stator Water Cooling Failure

02-006114 (LER 2002-03) Level B-RC, Cracked Disc on Unit 2 Stator Cooling Water Heat Exchanger Shutoff Valve 2-VLV-024-0531 02-09486 Adverse trend in the number of NRC violations and findings for the last two years 02-005524 Level C - On 5/16/02 the No. 1 RCP on U2 failed to start when the handswitch was placed to start. The pump did not start on the second attempt while engineering was present at the breaker after having instrumented various contacts.

02-02298 Westinghouse design error SG low-low level 03-001708 Main Feed Water Pump Stop Valves 03-002634 Main Feed Water Pump Recirc Valves 03-012670 Rx Trip Breakers 03-010200 Containment Vent 03-003340 SFP Load Cell 03-05924 Failure to enter TS LCO 3.7.3 03-02580 Failure to meet TS LCO 3.4.8 03-02422 Failure to repair and return to service valve 2-LCV-0060190A 03-00003 Unit 2 reactor trip while shutdown 03-004354 While resetting a supervisory turbine trip module on 4/12/2003, the turbine tripped from Turbine High Vibration Turbine Trip, which initiated a reactor trip.

The turbine trip controls were in cutout and therefore a turbine trip should not have been initiated.

03-002422 Failure to repair and return to service 2-LCV-006-190A valve in a timely manner increased the risk of continued U2 operation from condensate system transients.

03-012875 During performance of NRC inspection 2003-09 (Problem Identification and Resolution), the NRC identified closure of PER 02-003645-000 without completion of specified CA.

System 067 3rd Quarter FY03 Status Report, Essential Raw Cooling Water Performance Indicator Report, Quarters 1-3, 2003 NRC GL 89-13 Service Water System Problems Affecting Safety-Related Equipment B87 931104 002 TVAN Calculation, ASME Section XI Inservice and Augmented Valve Identification for the Second 10 Year Interval Letter to NRC, Subject - Sequoyah (SQN), Browns Ferry (BFN), and Watts Bar (WBN)

Nuclear Plants - Response to Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment, Dated January 26, 1990 Letter to NRC, Subject - Sequoyah Nuclear Plant (SQN) - Revised Program and Status Update Regarding NRC Generic Letter (GL) 89-13 - Service Water System Problems Affecting Safety-Related Equipment Memo from GL 89-13 Coordinator on September 24, 2003, addressing questions regarding silt found in the ERCW system 01-005035 Perform 0-MI-EMV-317-146.0 and MI-11.2C on MOV 2-FCV-70-156 to troubleshoot thermal overloads opening on May 29, 2001.

Temporary Modifications Reviewed 0-03-011-018 03/26/03 Aux Boiler Fuel Oil Supply strainer addition 1-03-026-047 06/09/03 Revision of turbine eccentricity zero point alarm 1-03-029-057 06/14/03 Trip function of Stator Ground Relay disabled

2-03-014-003 04/11/03 Furmanite (leak repair) of AFW valve 2-03-018-067 05/09/03 2TCV-67-109 ERCW flow to 2D-B CRDM Cooler failed open 2-03-015-047 04/13/03 Remove Turbine Vibration Trip relay PERs Reviewed for Reactor Trips:

02-008460 Trip on undervoltage condition on 2 RCP busses (Breaker spurious closure during rack in)

03-002313 Secondary valve in long term off-normal position 02-006086 Loss of Stator Cooling Water due to broken Henry Pratt valve 02-015494 Grounded motor on #3 RCP PERs Reviewed for Breaker Problems 01-009568 Vendor material conditions 01-009435 ERCW breaker problem 01-011634 Parts missing 02-003290 Assembly problem 02-001039 New breaker assembly problem 03-009947 Failed test 02-004132 Spare breaker found damaged 02-001383 New breaker assembly problem 02-004576 Linkage problem 02-006377 ERCW breaker problem 02-006809 Cracked insulator 02-005444 Breaker problem 02-005516 Assembly problem 02-009900 Assembly problem 02-009002 Assembly problem 02-012681 Assembly problem 02-010344 Assembly problem 02-010567 No spare breakers 02-015035 Water in breaker 03-011386 Receipt inspection ID problem 03-000369 Failed to open 03-008335 Breaker not trip 03-001396 Tripped free 03-003369 Damaged breaker 03-003426 Charging spring problem 03-003637 Failed to discharge 03-005396 Charging motor failure 03-006015 Alignment problem 03-007495 Inadequate tolerance 03-007728 Inadequate tolerances 03-008296 Multiple problems 03-008549 Moc switch problem 03-010054 Assembly problem PERs reviewed for Root Cause and Apparent Cause 02-014206 Apparent causes not adequate 02-014204 Apparent causes not adequate 02-014312 Apparent causes not adequate 02-014205 Apparent causes not adequate 02-014311 Actions resulting form engineering self-assessment 03-002423 Root causes not showing continued improvement PERs reviewed for FME 02-003855 EIP data indicates weak knowledge of FME 02-010042 12 PERs associated with FME in past year 02-000278 FME in main oil system 02-002864 FME in refuel cavity

02-004161 FME in Unit 2 condenser 02-004257 FME in feedwater heater 02-004487 FME in Unit 2 reactor 02-004769 FME in drains 02-005184 FME in ice condenser 02-006792 FME in lower containment 02-010813 FME log for spent fuel pool area inaccurate 02-009894 FME log for spent fuel pool inaccurate 03-007973 FME discovered in Unit 1 reactor vessel 03-009344 Unit downpower due to FME 03-000005 FME identified in CRDM area 03-000564 FME (rag) found in EDG oil scavenging pump 03-002099 FME found in piping 03-002811 RCP 1-2 found with tape over flywheel baffles 03-003219 Inadequate FME during grinding near spent fuel pool 03-004086 FME (leather glove) in spent fuel pool 03-007401 Work on generator exciter without FME controls 03-007973 FME in Unit 2 reactor vessel 03-008035 FME found in ice condenser 03-008986 24 FME PERS identified following Unit 1 outage assessment PERs reviewed for GL 91-18 Degraded Conditions 98-001574 Westinghouse setpoint methodology 00-004645 Containment pressurization due to air line leak 01-010210 PRT LT not calibrated 01-011309 MCR Overhead duct qualification 02-014754 TDAFWP Room Sump Design Basis