IR 05000413/1998015

Insp Repts 50-413/98-15 & 50-414/98-15 on 981102-06 & 16-20. No Violations Noted.Major Areas Inspected:Licensee Corrective Action Program by Sampling Activities Defined in Nuclear Sys Directive 210,rev 1

ML20199E500
Person / Time
Site:	Catawba
Issue date:	01/04/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20199E498	List: IR 05000413/1998015 ML20199E493
References
50-413-98-15, 50-414-98-15, NUDOCS 9901200446
Download: ML20199E500 (33)

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i U.S. NUCLEAR REGULATORY COMMISSION  !

REGION ll

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' Docket Nos: 50-413 and 50-414 l 1 I l

License Nos: NPF-35 and NPF-52 l

Report Nos.: 50-413/98-15 and 50-414/98-15 I Licensee: Duke Energy Corporation Facility: Catawba Nuclear Station, Units 1 and 2 Location: 422 South Church Street Charlotte, NC 28242 l Dates: November 2 through November 6,1998, and November 16 through November 20,1998 inspectors: S. Shaeffer, Senior Resident inspector, McGuire (Lead Inspector)

N. Economos, Reactor inspector, Region ll l R. Franovich, Resident inspector, Catawba 1 R. Moore, Reactor Inspector, Region 11 Approved by: C. Ogle, Chief, Projects Branch 1 I Division of Reactor Projects i

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Enclosure

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EXECUTIVE SUMMARY Catawba Nuclear Station Units 1 and 2 NRC Inspection Report 50-413/98-15,50-414/98-15

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This two-week team inspection reviewed sspects of the licensee's corrective action program by l sampling activities defined in Nuclear System Directive 210, Corrective Action Program Directive, Revision 1, including aspects of licensee operations, maintenance, and engineerin Operations

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The licensee's problem investigation process program met the requirements of Title 10 Code of Federal Regulations Part 50 (10 CFR 50), Appendix B, Criterion XVI, Corrective Action, with few exceptions. Existing implementation processes were well established

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and provided a sound basis to support the timely identification and correction of problems. (Section 07.1)

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Screening of problem investigation process reports was good in that safety significance was appropriately identified. Overall cause determinations, operability evaluations, and assigned corrective actions for identified problems were adequate. Deletion of problem

. investigation process reports was adequately controlled; although some documentation problems were noted. (Section 07.1)

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Overall, operability evaluations were adequate to determine the current impact on equipment and system operation. (Section 07.1.b.(2))

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One example of an operability determination that was not clearly supported was i

identified during review of Problem Identification Process Report 0-C98-921, which concerned the operability of a pressurizer power operated relief valve. (Section 07.1.b.(2))

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An unresolved item was identified pending a past operability review of the auxiliary building ventilation system with respect to exceeding the 3 percent iodine penetration limit due to ineffective controls to compensate for non-conservative Technical Specification surveillance acceptance criteria. (Section 07.1.b.(3)(a))

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An unresolved item was identified pending completion of the licensee's review to determine if Technical Specification surveillance acceptance criteria for annulus ventilation system drawdown testing were non-conservative. (Section 07.1.b.(3)(b))

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The root causes and corrective actions associated with a loss of control room pressure I were not well documented in Licensee Event Report 50-413/98-01. (Section 07.1.b.(3) l (c))

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The licensee's internal audit process was effective in identifying problems with licensee l event report quality. (Section 07.1.b.(3) (c)) )

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= A non-cited violation of 10 CFR 50, Appendix B, Criterion XVI was identified for failure to i

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adequately identify and correct an adverse condition related to repairs on pressure retaining components in accordance with applicable code requirements. (Section

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O7.1.b.(3) (d))

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Reviews of trend data indicated that the licensee was actively monitoring problem j

identification process performance measures and problem identification process report i backlogs were not excessive. The licensee had also established a low threshold for identifying problems. The licensee's problem identification process report system 3 provided an excellent tool for producing trendable data. (Section 07.1.b.(4)) i 1 .

The licensee's implementation of management exceptions for problem identification I

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process issues was adequately controlled and consistent with safety significance; l however, the process was not formally documented in the licensee's corrective action program. (Section 07.1.b.(5)) 1

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The quality of the evaluations and the effectivaness of corrective actions for the problem

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identification process reports reviewed were generally good. Several minor problem i

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identified; however, the aggregate impact of these minor issues, when put in perspective

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of all the problem identification process reports reviewed, was not indicative of a i programmatic problem. (Section 07.1.b.(7)) l

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The program to monitor the backlog of operations procedure changes was well l

established, goal-setting strategies were aggressive, and the licensee was effectively reducing the number of backlogged procedure changes. (Section M3.1)

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Audits and assessments were effective in identifying problems and areas for improvement in the licensee's corrective action program. Corporate regulatory audits were effective in promoting change at the Catawba Nuclear Station. Self-assessments at the site level were effective in finding process deficiencies and investigating new program changes. (Section 07.2)

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Audits and assessments were performed in accordance with the licensee's Quality Assurance program and site procedures. (Section O7.2)

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The onsite and offsite review committees have been effective in identify and resolving safety issues at Catawba Nuclear Station. Both committee's operated in accordance with applicable requirements and provided adequate reviews of station activities with appropriate focus on nuclear safety. (Section 07.3)

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Management's initiative's to monitor and improve the corrective action program using site specific tools appeared to be progressive. A number of good processes were established and management was continuing to define other initiatives to improve other areas. (Section 07.4)

. Observed implementation of the Engineering Support Program review board was detailed, probing, and beneficial to improve the overall reliability of the system and the oversight of the system engineering function. (Section 07.4)

. Monthly performance measures provided a well established framework for monitoring and improving all performance measures, including aspects applicable to the corrective action program. (Section 07.4)

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The licensee's program for monitoring and reducing the number of component

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. mispositionings was effective in reducing the total number of mispositioned component (Section O7.5) 1 l

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The Top Equipment Problem Resolution and Failure Analysis Trending System l programs were effective engineering programs for the identification and resolution of '

equipment problems. Individual processes were, in general, adequate to track and monitor the status of equipment and specific programmatic issues; although, some

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lacked simplified indicators to assess the process effectiveness without a detailed review. (Section M2.1)

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The licensee had appropriately identified and documented operator workarounds in accordance with established procedures. An operator work around list was managed by l qualified personnel with a proactive approach to resolving deficiencies. The licensee i had identified the necessary contingencies and corrective actions to address each workaround. (Section M2.1)

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The licensee has effectively managed safety and non-safety-related equipment problems that could impact equipment reliability and plant safety. (Section M2.1)

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Performance monitoring and oversight of the maintenance procedure change backlog was not well established. (Section M3.1)

. A non-cited violation of 10 CFR 50, Appendix B, Criterion XVI was identified for inadequate corrective actions to ensure compliance with surveillance requirement 4.6.1.9.3, which requires leak testing of the inboard and outboard containment hydrogen sample and purge system valves on a staggered basis. (Section M8.1)

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The licensee's Operating Experience Program was effective in communicating applicable generic information to Catawba Nuclear Station, and corrective actions were appropriate, timely, and tracked to completion. (Section E2.1)

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The licensee's daily Site Direction Meeting provided a forum for focusing site resources on emerging operating experience issues with potential applicability to Catawba Nuclear Station. (Section E2.1)

. The licensee's processes for tracking NRC commitments was effective and corrective actions for previous problems in this area were considered adequate. (Section E3.1)

. The licensee appropriately resolved Updated Final Safety Analysis Report (UFSAR)

discrepancies identified by routine plant activities and the special UFSAR Accuracy Verification Project. (Section E3.2)

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The licensee performed an appropriate level of root cause analysis, consistent with the significance of the equipment failure or human error which occurred. Trending of ,

corr mon cause for human errors was performed and corrective actions were assigned to i

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address common cause issues. The 1997 post-trip reviews were of adequale depth and ,

detail to provide a basis for the plant restart. (Section E7.1)

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A non-cited violation was identified for a procedural error that caused all four Unit 2 over r.ower differential temperature trip setpoints to be non-conservatively calibrated since -

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February 1997. (Section E7.2)

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Report Details Summary of Plant Status Unit 1 Unit 1 operated at 100 percent power for the duration of the inspection perio Unit 2 Unit 2 operated at 100 percent power for the duration of the inspection perio I. Operations 07 Quality Assurancein Operations 07.1 Review of the Problem Investiaation Process Inspection Scope (71707. 40500)

The inspectors reviewed the licensee's corrective action program implemented by Nuclear System Directive (NSD) 208, Problem Investigation Process (PIP), Revision 18 and NSD 210, Corrective Action Program Directive, Revision The PIP reports reviewed were maintained in a computer database having an excellent capability to generate user-defined sorts or summaries. Prior to the inspection, the i inspectors screened a large sample of PIP summaries. From these summaries, the l inspectors selected individual PIPS for review. The selected PIPS were evaluated for timeliness of response, quality of evaluation, effectiveness of corrective action, accuracy !

j of information, and compliance with reporting requirements. Other aspects of the l process reviewed included significance screening, operability evaluations, cause determination, and timeliness of corrective actions. Under the licensee's program, each PlP was assigned a significance category code selected from four defined categorie l

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Categories 1 and 2 were for more significant events (MSE), and categories 3 and 4 were for less significance events (LSE). Assignment of a category code invoked the level of response and evaluation defined by the procedure for that categor A final sample of approximately 120 PIPS were reviewed in detail. The majority of the sample were Category 3, LSE PIPS, and a smaller number of Category 1 and Category 2, MSE PIPS, initiated in 1997 and 1998. The sample included both completed and in-process PIP Observations and Findinas (1) PIP Sianificance Screenina NSD 208 defines the criteria for determining the significance of PIPS. The inspectors observed a multi-organizational screening team evaluate each new PIP for significance in accordance with the established criteria during daily meetings. A number of PIPS were conservatively categorized as Category 2 MSE PIPS initially to ensure that both

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operability impact. These PIPS would subsequently be downgraded to LSE PIPS if no I operability or reportability concerns were identified. The inspectors also reviewed I several Category 3 PIPS for which the PIP screening criteria indicated could have been l categorized as a Category 2 MSE PlP due to a potential for adverse trend. For each !

item reviewed, the root cause of the specific problems was determined not to be common and therefore no adverse trend was apparent. Based on the inspectors observations, both initial screening and downgrading of PlPs was adequately controlled !

by the Safety Review Group (SRG). The inspectors noted that members of the  !

screening team were periodically rotated with other personnel from the various plant j organizations, which effectively allowed more individuals to acquire a common threshold i for the significance of problems and the appropriate category rating within the corrective l action process. The inspectors' sample indicated that the licensee was effectively

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categorizing PIPS with respect to safety significanc (2) Operability Evaluations I

Based on a review of selected PIPS, the inspectors determined that, overall, operability )

evaluations were adequate to determine the current impact on equipment and system operation. In general, operability evaluation were determined to be timely and appropriate to the circumstance. The inspectors noted that the operability justifications were sometimes documented in the problem evaluation section of the PIP rather than in the designated operability section. This problem did not appear to have affected the quality of the operability reviews and was characterized as inconsistent documentation location within the PIP for One specific problem was identified during the review of PIP 0-C98-921, which was written to address a concern regarding the operability of Pressurizer Power Operated Relief Valve (PORV) NC-34A with its associated controller (the master controller) in j manual control. The operability evaluation documented in the PIP contained some I irrelevant and/or inaccurate information, which generated confusion and concern l regarding the viability of the determination that the valve was operable. However, the l inspectors ultimately concluded that the licensee's operability conclusion was supportable. The licensee agreed that the operability determination was not clearly l supported in the PIP and stated their intention to change the supporting information in '

the TS Bases and UFSA (3) Cause Determinations - Corrective Actions The inspectors assessed cause determinations during the selected PIP review and reviewed whether the assigned corrective actions for these PIPS addressed the apparent l cause. The licensee's process established that Category 3 LSE PIPS received a less l rigorous cause determination than MSE PIPS. As such, the support documentation for I

some LSE PIPS was generally less detailed and as such made it more difficult to assess the root cause determinations. In the LSE sample reviewed, the corrective actions appeared appropriate to address the cause of the identified problem to prevent recurrence. Cause determinations for the MSE PIPS reviewed were adequate and assigned corrective actions were appropriate. Additional reviews of the licensee's root cause evaluation process is documented in Section E7.1 of the report. In general, the majority of PIPS reviewed contained adequate cause determinations. However, some i

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problems were identified with either cause determinations or specific corrective actions as discussed below:

(a) The inspectors reviewed PIP 0-C98-4254, which documented a surveillance testing issue associated with the auxiliary building ventilation (VA) system. TS Surveillance Requirement 4.7.7.b.2 requires that a laboratory analysis of a representative activated carbon sample has methyl iodide penetration of less than 4%; surveillance requirement 4.7.7.b.3 requires that a system flow rate of 30,000 cubic feet per minute (cfm) +/- 10% be demonstrated during testing. The PIP stated that the TS surveillance test acceptance criteria for filter train air flow rate and carbon bed penetration values were non-conservative. The inspector was informed that the licensee had previously discovered this non-conservatism l

in the surveillance requirements in 199 The inspectors reviewed PIP 1-C94-1539, which documented a high flow rate discovered during surveillance testing on November 3,1994. This PIP documented an operability conclusion that the system was operable in spite of I

, exceeding the TS surveillance test acceptance criterion of 30,000 cfm +/- 10%.

The inspectors considered this 1994 conclusion indicative of a lack of understanding of TS operability. This specific TS operability issue was

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subsequently corrected following the NRC's identification in March 1998 of a similar escalated enforcement issue (documented in NRC Inspection Report 50-413,414/98-03). The licensee had determined in November 1994 that both the

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surveillance test's upper flow limit of 33,000 cfm and carbon iodine penetration

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l limit of 4% were not sufficiently conservative to ensure adequate residence time ,

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with and quality of the carbon bed. Although more restrictive limits were l l proposed in the "Reportability" section of PIP 1-C94-1539, corrective actions to change the associated procedures were not provided in the PI On October 29,1998, the licensee initiated PIP 1-C98-4214 to document another high flow condition identified during a retest following HEPA filter replacemen The licensee subsequently recognized that the procedure limited air flow rate to 32,000 cfm but did not restrict the iodine penetration limit to 3%. The licensee l concluded that actions to change the procedures in 1994 had not been completed to address the iodine penetration criterion. The licensee reviewed the completed procedures for previous tests and determined that the 3% penetration limit had been exceeded three times since the non-conservative TS had been

identified. A past operability evaluation is being performed for these occurrences l to determine if the issue is reportable. The licensee also took immediate corrective actions to characterize the Unit 1 and 2 A and B trains of VA system operable but degraded with the non-conservative TS surveillance criteria; initiate a compensatory action for maintaining the VA systems operable with administrative controls in place to impose more restrictive surveillance acceptance criteria; and develop an action plan to determine what changes to the TS may be warranted. The inspectors verified that the system was currently

, operable with these more restrictive administrative limits. The inspectors concluded that, although initial corrective actions were not thoroughly implemented, final measures were taken to correct the proble .-- - - . - . _ - - - ~_ -- - - - _- _ _ . - -

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As indicated above, the failure to correct and establish effective controls to compensate for non-conservative Technical Specification surveillance acceptance criteria resulted in the auxiliary building ventilation system exceeding the 3% iodine penetration limit. Pending NRC review of the licensee's past operability evaluation, this is identified as Unresolved item (URI) 50-413,414/98-15-01: Review of VA System Past Operabilit (b) The licensee identified an additional surveillance test procedure that provided more restrictive acceptance criteria than those in the TS; this item was documented in PIP 0-C98-4404. Technical Specification surveillance requirement 4.6.1.8.d.4 requires that, at least once every 18 months, the licensee verify that each annulus ventilation (VE) system be capable of producing e negative pressure of greater than or egyal to 0.5 inch nier gsuge in the annulus within one minute siter a start signal. Procedure PT/1(2)/A/4450/03C, Annulus .

Ventilation System Performance Test, specifies -1.25 inches water gauge l vacuum within 16 seconds of a start signal. The licensee determined that these ;

more restrictive acceptance criteria were developed for testing under normal l

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conditions to ensure that the criteria in the TS surveillance requirement could be met under accident conditions. The inspector noted that the time criterion recently had been changed from 59 seconds to 16 seconds in Revision 7 of the l

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procedure, approved September 9,1998. The inspectors determined that the TS surveillance test did not specify the conditions under which the acceptance criteria must be met. The inspectors questioned the licensee if the TS surveillance acceptance criteria were non-conservative for normal test conditions or if the TS surveillance acceptance criteria were intended to be met during i accident conditions (thereby demonstrated with more restrictive criteria during tests under non-accident conditions). The licensee initiated PIP 0-C98-4716 to determine if the TS surveillance criteria are actually non-conservative. Pending completion of the licensee's review, this item is characterized as Unresolved item I (URI) 50-413,414/98-15-02: Potentially Non-Conservative TS Surveillance j Criteria for Annulus Ventilation System Drawdow l (c) The inspector reviewed Licensee Event Report (LER) 50-413/98-01 and PIP j C98-0476 regarding a dual unit entry into TS 3.0.3 for both trains of the control '

room area ventilation (VC) system being inoperable. The LER stated that the l root cause of the event was inadequate procedure. However, the inspectors concluded that the event was more directly attributed to a human performance problem involving an uncontrolled change in work scope as a result of an l ineffective air handling unit (AHU) isolation. The dampers used to isolate the !

I AHU leaked, allowing air to enter and pressurize the AHU. To relieve the l l pressure, maintenance personnel opened an AHU door slightly. Hence, the work l scope changed without restoration controls in place ensure that the door was !

l closed following maintenance work. The door was left in the open position when ;

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the AHU was returned to service, and the operating train of the VC system was unable to maintain control room pressure with the AHU door open. As s result, the shared control room depressurized and both units entered TS 3.0.3.

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The LER stated that a human performance error for inadequate self-checking was a contributing root cause. The corrective action documented in the LER was to correct the associated maintenance procedure and counsel the individuals involved to emphasize the importance of self-checking. No specific corrective actions were identified to address the failure "stop work" to obtain formal controls for work involving ventilation systems. Furthermore, station management's expectation to "stop work" to allow for a procedure change if an inadequate l procedure is encountered was not discussed in the LER. The inspector l

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concluded that the LER root cause failed to address a broader issue of weak expectations for controlling work associated with ventilation systems. This contributed to a general lack of sensitivity toward ventilation systems, which subsequently led to a number of recent events that were the subject of LERs and NRC enforcement action. The inspector discussed the LER with maintenance management. The licensee acknowledged the human perforrnance issues that lead to the event and addressed the expectations for stopping work to establish controls when work scope changes are required. The inspectors considered corrective actions for subsequent events effective in elevating sensitivity to i ventilation systems. The inspectors determined that adequate corrective actions were taken to address ventilation system expectations, as well as the human l performance aspects of the event, although these corrective actions were not documented in the LE The inspectors noted that a similar concern associated with the root cause determination in LER 50-414/98-01 (regarding a Unit 2 entry into TS 3. because of a VE system problem) was documented in NRC Inspection Report 50-413,414/98-02. The inspectors also noted that the licensee's corporate office conducted an investigation of ventilation system reportable events in July 1998 and reached similar conclusions regarding the adequacy of root cause determination and corrective actions documented in LERs 50-413/98-01 and 50-414/98-01. The licensee's investigation findings are documented in Event investigation Team Report SA-98-61(CN)(EIT), Review of 1998 Ventilation System Related LERs. The inspectors concluded that the root causes and corrective action to address events documented in the referenced LERs were not well documented; however, the licensee was effective in identifying these problems with LER quality through their internal audit proces (d) The inspectors noted that the corrective action deceribed in PIP 1-C98-3036, involving the repair and nondestructive testing of an Amencan Society of Mechanical Engineers (ASME) Class 3, valve,1RN351, did not follow the rules and requirements set forth in the governing code: ASME,Section XI,1989 Edition (code). For example, Article IWA-4000 Repair Procedures, provides rules

and requirements for the repair of pressure retaining components by welding.

l Subsection IWA-4130 requires that welding repairs be performed in accordance with a repair program which includes, but is not limited to, welding procedures and nondestructive examination procedures. Subsection IWA-4600 Examination, requires that repairers areas be examined to establish a new preservice record and that the method of examination (s) included the method that detected the flaw. These requirements are delineated in the licensee's ASME Section XI l Manual (Manual) dated December 12,1994, and NSD 300, ASME Section XI l

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Program. Section E of the Manual: Repair , Replacement and Maintenance Activities, Rev. 5, requires that flaw repair by welding be done with appropriate welding procedures and that prior to returning the component to operable status, the repair be examined for acceptability using the same NDE examination method that detected the fla By review of the subject PlP and associated weld process control forms, the inspectors determined that the licensee performed a base metal repair on the )

subject valve's body, i.e. pressure boundary, to correct material loss due to !

erosion corrosion. Following the repair, a surface examination using the liquid penetrant method, identified certain code rejectable indications, in the repair area. These defects were evaluated as not being critical and as not presenting an operability concern for the actual operation of the valve. As such, the valve was returned to service without a repair to remove the code rejectable indications from the pressure boundary as required by ND-2548 Elimination of Surface Defect During the final quality assurance (QA) review of the work order package, the licensee's OA group questioned the process by which engineering determined that code rejectab!e indications in the base metal repair were acceptable as is for service . The QA group discussed the issue with the level 111 non-destructive examination (NDE) examiner who indicated that per the ASME code the defects had to be evaluated or a request for relief from code requirements had to be submitted to the NRC for their review and approva Since this had not been done, on August 25,1998, engineering recommended that operations declare valve 1RN-351 and the associated KC train 1B inoperable and issued work order 98078737-01 to replace the valve. The code rejectable indications were subsequently repaired by welding and grinding. The area in question was subsequently penetrant testing (PT) examined and found to be acceptable for servic The licensee performed a root cause evaluation of this problem and determined that the individuals involved in the disposition of the unacceptable indications did not consider that the weld repair area was part of the ASME pressure boundar As such they did not consider that rejectable indications were required to be removed or reduced to an acceptable level prior to returning the valve back to service. Targeted individuals were scheduled to receive instruction on the requirements associated with repairs of code components in order to preclude recurrence of this proble The inspectors determined that the licensee's initial actions were contrary to the

! requirements of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action However, consistent with Section Vll.B.1 of the NRC Enforcement Policy, this non-repetitive, licensee-identified failure to perform repairs on ASME Section XI pressure retaining components in accordance with applicable requirements was identified as NCV 50-413/98-15-03: Failure to Perform Repairs on Pressure Retaining Components in Accordance with Applicable Code Requirements.

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l (4) PIP Corrective Action Backloa The inspectors reviewed the backlog and timeliness of PIP corrective actions relative to established licensee performance monitoring. The PIP corrective action backlog was l being actively monitored by site management via a number of graphical data sheets

! produced by the SRG. Some of the performance measures being monitored on a monthly basis included: open PIPS; overdue activities; PIPS generated year to date; PIPS l

greater than 6 months; and number of root cause evaluations initiated. The licensee's l PIP system provided an excellent tool for producing this data. The generated reviews

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also provided a site comparison to the other Duke Energy nuclear sites. At the end of the inspection period, the total number of PIPS that were generated year to date was approximately 4,300, which the inspectors concluded was indicative of a low reporting threshold for problems. Also at this time, the licensee had a weekly average of approximately 1,600 open PIPS with less than 10 PIP activities identified as overdue and approximately 400 PIPS greater than 6 months old. This data indicated that good management oversight was being applied to ensuring PIP backlogs were maintained at a reasonable leve Conclusions

Based on evaluation of the trend data, the inspectors concluded that the licensee was actively monitoring PIP performance measures and PIP backlogs were not excessive.

l The licensee had also established a low threshold for identifying problems. The l licensee's PIP report system provided an excellent tool for producing trendable dat (5) Use of Manaaement Exceptions The inspectors reviewed the category of PIP corrective actions designated as i

management exceptions. This designation was reserved for activities scheduled for, as an example, a future outage. Currently, the site had 97 management exceptions identified (62 LSE and 35 MSE) that were greater than six months old. The inspectors

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questioned why the PIP corrective actions in the management exception category l greater than six months old were not included in the PIP corrective action backlog. The i licensee stated that the PlP corrective action backlog did not include management exception items because they did not meet the licensee's definition of what was l

considered to be a backlog item due to being items for which short term resolution was not practical. The inspectors reviewed the current list of management exceptions and

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did not consider that any of the long term items, if not quickly resolved, would adversely l impact system performance. The items appeared to have been conservatively

! designated to this area with respect to safety significance. However, the inspectors did observe that the use of the management exception process had only been informally j developed and was not documented in a Nuclear Site Directive (NSD). As such, periodic

! reviews of management exceptions items were not established and acceptance criteria had only been informally developed.

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Conclusions j The inspectors concluded that the licensee's implementation of management exceptioris for PIP issues was adequate and consistent with safety significance; however, the process was not formally documented in the licensee's corrective action progra (6) Deleted Problem Reports The inspectors sampled deleted PIP reports to decide if there were valid reasons for '

l canceling the reports examined. The inspectors discussed with site personnel the i specific reasons for deletion of a number of PIPS and evaluated other associated licensee documents. Based on a selected sample, the inspectors concluded that overall justifications for deleted PIPS were adequately documented in the PIP evaluation for j Most of the deleted PIPS were due to duplication of effort. Several were voided due to l l error or misunderstanding. However, the inspector did identify several deleted PIPS where the documented reason was insufficient to support the action taken. In one example, the reason stated in the PIP was that the individual required to address the PIP l did not have enough resources to determine if a problem existed. Other deletions i requiring more documentation included several communication issues which were later l deleted based on a request from the originator several days after the PIP was generated.

i The inspectors discussed the deletion process with the Regulatory Compliance Grou The inspectors were informed that recently, the deletion of PIPS was being more closely

! scrutinized and that a fewer number of individuals have deletion capability. The l inspectors considered that these examples were not pervasive.

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Conclusions The inspectors concluded that the process for deleting PIPS was currently being adequately controlled, with few exceptions.

l (7) Overall PIP Quality

The inspectors found that the quality of the evaluations and the effectiveness of corrective actions for the PIPS reviewed were generally good. Several minor PIP documentation issues with regard to adequacy were identified; however, the aggregate I impact of these minor issues, when put in perspective of all the PIPS reviewed, was not l indicative of a programmatic proble The inspectors did not identify any problems with reporting requirements in reviewing the PlPs.

l Overe'l Conclusions for Review of the Problem Investiaation Process The licensee's problem investigation process program met the requirements of the licensee's controlling procedure and the requirements of 10 CFR 50, Appendix B,

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Criterion XVI, Corrective Action with few exceptions. Existing implementation processes were well established and provided a sound basis to support the timely identification and correction of problem . -

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Screening of PIPS was good in that the significance was appropriately identifie Downgrading of PIPS was adequately controlled. Overall cause determinations, operability evaluations, and assigned corrective actions for identified problems were adequate. However, two NCVs were identified for examples of problems that were adequately identified and corrected by the license .2 Quality Assurance Audits and Assessments Inspection Scope (40500)

Audit and assessment reports were reviewed for compliance with 10 CFR 50 Appendix B requirements, the Duke Power Company Quality Assurance Program Topical Report (Duke-1-A); the Catawba Technical Specifications; NSD 208, dated November 1997, Problem investigation Process; and NSD 607, dated June 1997, Self-Assessment These audits and assessments were done on various licensee activitie _ Observations and Findinas Audits The inspectors reviewed the following audit reports, which were performed by the Regulatory Audit Group from the Duke Power General Office and the SR SA-97-03 (CN)(RA): Corrective Action, March 23,1997 SA-97-09 (CN)(RA): Corrective Action, August 28,1997 SA-97-12 (CN)(RA)(SITA): Corrective Actions in Response to Self Initiated Technical Audit (SITA) Concerns, Jt.ne 11,1997 SA-98-04 (CN)(SRG): Corrective Action Program, March 29,1998 SA-98-17 (CN)(RA): Follow-up of Audit Findings and Corrective Action, May 19,1998 The inspectors observed that the audits were adequate in content, identified valid issues, and caused positive changes in the licensee's corrective action program. The inspectors determined that Catawba management group generally responded well to the audit findings. The general office audit groups returned multiple times on inspections to ensure the Catawba compliance organization was tracking with corporate and regulatory axpectation Self-Aesessments Self assessment activities were specified in NSD 607, Self-Assessments. Generally, a smallinternal team performs assessments in each subsection of the site organizatio l These assessments were annual reviews divided in quarterly sections with a written )

approved plan signed by the group manager. The assessment included topics important to safety and reliability, areas of identified weakness (such as findings indicated by Institute of Nuclear Power, NRC, Nuclear Safety Review Board, auditors, and others),

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new or recently revised programs and processes, and personnel safety issue Assessment findings and recommendation were entered into the PIP database. The following self assessments were reviewed by the inspectors:

PIP N DEPARTMENT ASSESSMENT NO. DATE 0-C97-3485 Engineering SA-97-77 10/13/97 0-C98-1485 Engineering MSE-01-98 4/21/98 0-C98-2859 Operations SA-98-60 8/11/98 In reference to the operational assessment above, the inspectors determined that it was performed by the Operating Experience Assessment Group (OEA) to evaluate implementation of the trending program, for all three Duke Nuclear sites, per NSD 223, Trending of PIP Data. OEA's work effort in the area resulted in four recommendations for evaluation, which were as follows: (1) define and implement a structured and consistent approach to Mily and monthly trending, (2) establish a consistent coding scheme for trending PIPS, applicable to the three sites, (3) established a policy or process to consistently documents individual group trend evaluation reports for all three sites, and (4) conduct followup assessments to the regularly scheduled quarterly trends to monitor progress of corrective action The assessments were useful to the plant, had a safety focus, and met their defined purposes. The findings were tracked to completion. In several cases, again responding to corporate audit findings, the later assessments referenced operational event  :

information relevant to the Catawba site, Conclusions l

The audits and assessments reviewed were effective in identifying problems and areas for improvement in the licensee's corrective action program. Corporate regulatory audits were effective in promoting change at the Catawba Nuclear Station. Self-assessments at the site level were effective in finding process deficiencies and investigating new program change The audits and assessments reviewed were performed in accordance with the licensee's Quality Assurance program and site procedure .3 Onsite and Offsite Review Committee Inspection Scope (40500)

The inspectors evaluated licensee compliance with TS, Selected License Commitments (SLC), and the licensee administrative procedures regarding Plant Operations Review Committee (PORC) and Nuclear Safety Review Board (NSRB) activities. The inspectors also evaluated the ability of these organizations to effectively identify, assess, and resolve significant plant safety issue . - - - - - . - - - - - _ -

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11 Observations and Findinas Plant Operations Review Committee l The inspectors reviewed NSD 308, Plant Operations Review Committee, Revision 4 and t applicable regulatory requirements that established the operating guidelines for the Catawba PORC. The PORC was established to evaluate plant operations, and provide a cross-disciplinary management review of complex issues that have the potential to impact safe operation of the station. The inspectors reviewed PORC minutes and noted that the PORC was fairly consistent in accurately characterizing the significance of plant ,

l issues and the potentialimpact on plant safety. The PORC considered equipment l l functionality, regulatory requirements, and overall extent of the adverse condition in their i l decision-making proces I

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! The inspectors confirmed that the PORC membership included representatives from l each of the necessary organizations including operations, engineering, maintenance, '

! safety assurance, and plant support. The PORC membership had a good breadth of (

knowledge regarding integrated plant operations and was effective in seeking out and resolving issues in areas needing improvement.

l l Nuclear Safety Review Board The inspectors reviewed TS 6.5.2 and NSD 309, Nuclear Safety Review Board, Revision 7, which outline the responsibilities and requirements of the NSRB. The NSRB serves as an independent review board, providing a backup review to the normal station organization, reporting to the Executive Vice President, Nuclear. The NSRB monitors and evaluates trend information provided by the Catawba SRG and proposes recommendations when warranted. The NSRB also provided independent review and audit of designated licensee activities to identify items needing increased management attentio In addition to attending a number of the Duke Energy NSRB meetings in 1997 and 1998, i the inspectors reviewed selected NSRB meeting summaries for those years. Based on

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the review, the inspectors noted that NSRB focused on technical issues consistent with inspection and third party findings. The NSRB utilized inputs from regulatory agencies and various industry sources to assess plant safety performance. The NSRB made observations and recommendations regarding plant specific and generic issues requiring increased management attention.

l Conclusions The onsite and offsite review committees have been effective in identify and resolving safety issues at Catawba Nuclear Station. Both committee's operated in accordance

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with applicable requirements and provided adequate reviews of station activities with appropriate focus on nuclear safety.

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07.4 Manaaement initiatives in Corrective Action Process a. Inspection Scope (40500)

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The inspectors review selected initiative's used to manage and improve implementation of the corrective action and other programs at the Catawba Nuclear Statio b. Observations and Findinas

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The inspectors reviewed selected license initiative's used to manage and improve implementation of the corrective action program. In general, management personnel were familiar with and utilized established process tools to track corrective action timeliness and quality. The processes most utilized included the Top Equipment

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Problem Resolution (TEPR), Failure Analysis Trending Systems (FATS), Major Equipment Problem Resolution (MEPR) and the Operator Work Around Problem Resolution (WAPR) as discussed in Section M2.1. Licensee management was in the process of formalizing other corrective action improvement initiatives similar to those established at the utilities other sites which acted as lea One specific initiative that the site had incorporated was the use of Engineering Support Program (ESP) boards. he inspectors attended a review board for the radiation monitoring system, reviewed standard agenda format and objectives for the review boards, and discussed the process with engineering personnel. The ESP review board objectives were established, in part, to 1) provide constructive input to the system !

engineers for improving management in the areas of generation risk, 2) evaluate methods presented by the system engineer to improve system reliability, and 3) to assess the results of a structured generation risk review for the subject system. The ,

licensee began these types of reviews in 1998 and has accomplished a number of l

complete reviews since inception. In general, the ESP review board meets every six i weeks to review an additional system with followup reviews scheduled on six month I intervals. Methodology training was developed for the system engineers to acquaint !

them with management's expectations of the review proces !

i The inspectors attended an ESP review board for the radiation monitoring system. The ESP board was comprised of a multi-disciplined team from operations, maintenance, engineering and other personnel, including management. Prior to the meeting, the system engineer and other support personnel prepared an ice condenser system health report which were reviewed by the ESP board participants. During the meeting, the system engineer presented the performed reviews focusing on risk management and received candid feedback on both positive attributes as well as areas targeted for improvement, in addition to the above, the inspectors also reviewed a colored windows scorecard on the site's corrective action MSE PIP program that presents the status of the corrective action programs at each of the licensee's three nuclear facilities. This is a part of a proactive Duke Energy corporate management initiative which produces a monthly Performance Measures Status Report at the sites. The report includes performance measures on corrective actions for MSE PIPS and other items such as root cause analysis quality and timeliness. The inspectors considered these monthly performance

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measures provided a well established framework for monitoring and improving all performance measures, including aspects applicable to the corrective action program, l Conclusions Management's initiative's to monitor and improve the corrective action program using l site specific tools appeared to be progressive. A number of good processes were

, established and management was continuing to define other initiatives to improve other ( areas.

l Observed implementation of the Engineering Support Program review board, which was

! designed to improve the overall reliability of the system and the oversight of the system l engineering function, was detailed, probing, and beneficia l

Monthly performance measures provided a well established framework for monitoring and improving all performance measures, including aspects applicable to the corrective i

action program.

l 07.5 Assessment and Trendina of Mispositionina Events I Inspection Scope (40500) i l

The inspectors reviewed the licensee's assessment and trending of mispositioning occurrence I Observations and Findinas l

To address the causes of component mispositionings, the licensee has improved l

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procedures and processes. While this has effectively reduced the potential for a component mispositioning, human error was identified as a recurring root cause. The monthly mispositioning meeting (3M), a management focus initiative, provided a forum for discussing component mispositionings. In addition, the Human Performance Steering Team (HPST) periodically reviewed 3M discussion topics involving human performance issues and provided recommendations for managing mispositionings. As an example, the term " component mispositioning" applies to active components only. The HPST recently proposed expanding the definition of an " active component" to include fuses as a result of a Catawba event and lessons learned. The licensee's reviews also focused on establishing and implementing barriers to mispositions in the form of administrative i tools such as self-checking and Stop-Think-Act-Review (STAR). In addition, based on l the licensee's analysis of mispositions that have occurred in the past, a number of corrective action recommendations were made and were being tracked in the PIP program. The inspectors concluded that the licensee's program for monitoring and reducing the number of component mispositionings was effective in reducing the total

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number of mispositioned components. Early efforts appear to have been successful at reducing the number of mispositioning events from 85 mispositionings and 4 mispositioning events in 1992 to 18 mispositionings and 1 mispositioning event in 199 . - -. . -. - _ - - - - - - - - _ _ - - - - . - -. . .-

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14 Conclusions The inspectors concluded that the licensee's program for monitoring and reducing the number of component mispositionings was effective in reducing the total number of

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mispositioned component Miscellaneous Operations issues (90712,92901)

0 (Closed) LER 414/97-04: Inadequate Test of a Containment Isolation Valve When Procedure Step Not Performed (Closed) Violation (VIO) 50-414/97-09-03: Failure to Follow Procedure Results in invalid Local Leak Rate Test of Valve 2NV-874 These items addressed the licensee's failure to follow procedure which resulted in an invalid leak rate test. An additionalissue was the untimely review of the completed test procedure. The test was completed in the April 1997 outage and not reviewed until June 1997, after unit restart. Corrective actions specified in the LER and the September 15, 1997 violation response included retest of the valve, iraining of the responsible individual on self-checking techniques, and operations' evaluation of the review process for completed test procedure Completion of corrective actions was documented in PIP 2-C97-1851. The retest and individual training were completed as specified in the violation response. The successful leak test of the valve was completed on June 7,1997. The operations' evaluation of the procedure review process noted that adequate guidance was provided in procedure OMP 1-4, Use of Procedures, dated September 18,1998, requiring the timely review of completed procedures. This information was provided to the operations test group who was responsible for the procedure review. This item is closed i

08.2 (Closed) URI 50-413.414/98-05-04: Potentially inadequate Corrective Action to Justify ,

Annunciator Response Procedure (ARP) Response Time for Loss of EDG Cooling This item addressed an apparent deficient technical justification to resolve a discrepancy between the UFSAR and the alarm response procedure regarding the length of time an Emergency Diesel Generator (EDG) could operate without cooling water. The technical evaluation was documented in PIP 0-C96-1160, dated June 11,1996. The technical justification was based on a 1991 EDG event and a safeguard calculation. These references appeared to not adequately justify the ARP response time. The item was unresolved pending further discussion with the responsible engineer who was not available during the initialinspection. Based on the review in Section E3.2 of this report, j this item is closed.

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08.3 (Closed) LER 50-413/98-06: Missed Technical Specification Surveillance on Pressurizer Heater Emergency Power Supply Testing Due to a Literal Compliance issue (Closed) URI 50-413.414/98-05-03: Technical Specification Discrepancy involving Pressurizer Heater Power Supply Manual Transfer Capability These items regarded a problem which was identified by the licensee during a self

. assessment review that was perfor med to examine literal compliance with TS 4.4. requirements. The licensee's review determined that the subject TS requirement, were not compatible with system design (see inspection Report 50-413/98-05, Section M3.2).

On May 22,1998 the licensee declared the system inoperable and requested the NRC grant discretionary enforcement on this matter. On the same date, the NRC authorized by telephone the licensee's request and on June 17,1998, the NRC issued a memo of approval. In addition, the licensee issued PlP C98-1812, dated May 14,1998, to track progress on the corrective action taken, and the expected target date for completio The inspectors reviewed the subject LER and PIP for technical content and adequac The inspectors' review of the LER determined that the licensee had identified the root cause of the problem and had implemented appropriate corrective action (s) which included amendments / revisions to the applicable TS and UFSAR sections. These actions were either completed or in the process of completion and adequately addressed the subject of the URI. These items are close .4 (Closed) LER 50-413/97-10: Reactor Trip Breaker Opened Due to Uncertainty of Rod Position This LER was submitted on January 26,1998. It identified a Unit 1 manual reactor trip that was attributed to uncertainty over the actual position of Rod J-3 in shutdown Bank The reactor trip was attributed to a card failure, in the digital road position indication (DRPI) system. At the time of this event, Unit 1 was in Mode 4, He @utdown. In preparation for Cycle 11 startup, operations personnel were withdraw.ng rods for Shutdown Banks A and B when an alarm was received from the DRPI system for shutdown Bank B and Rod J- By document review, the inspectors determined that the licensee followed TS 3.1. requirements, took appropriate steps to open the reactor trip breakers and stabilized the plant per station procedures. The failed detector / encoder card was removed and replaced with a new one which was successfully tested in service, to assure proper operation and, that Rod J-3 was in the correct position. Engineering's evaluation of the card's failure rate, determined that it was within the range of industry acceptable limits and that this failure rate could not be predicted ort an individual card basi The licensee's root cause evaluation attributed the event to a randomly failed detector / encoder card in Data A Cabinet of the DRPI System. Maintenance replaced the failed card per Work Order 97112453-01 and the subsequent inservice test showed that the subject rod was in the correct position. In addition to the inspectors review, the licensee's PORC reviewed the failure investigation and found it acceptable. This LER is close _ _ - _ _ _ _ _

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ll. Maintenance M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Resolution of Eauioment Problems Inspection Scope (40500)

The inspectors reviewed licensee activities to identify and resolve equipment problem Applicable programs included the TEPR, FATS, MEPR and the WAPR. The inspectors reviewed available performance measures and program specific data to assess the effectiveness of the subject program l Observations and Findinas The TEPR provided a mechanism to focus resources and management attention on ,

resolving long term plant equipment problems improvement issues. The process is '

described in Site Directive 3.0.19, Top Equipment Problem Resolution Process, Revision 1. This program included the MEPR list and the WAPR list. Items on these lists were assigned sponsors and action plans were developed. The MEPR items tended to be broad scope improvement issues and the scope was routinely reviewed and expanded as related equipment issues emerged. Examples of MEPR items included containment cooling, piping failures, power supply failures, and auxiliary feedwater system problem Simplified indicators of performance and results monitoring were not readily available; however, the inspectors reviewed a more detailed breakdown of the MEPR items developed by the assigned sponsors which demonstrated progress in resolving the items.

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The inspectors reviewed the licensee controlled WAPR list. The list was developed and maintained by the operations organization to formally document challenges to operators during all modes of operation. The program was outlined in Duke Power Nuclear System Directive (NSD) 506, Operator Workarounds. The inspectors determined that l

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the licensee had initiated workarounds to support operational activities, and the listed workarounds were documented as required by procedure. For each of the operator workarounds reviewed, the inspectors confirmed that appropriate guidance and contingencies were in place to support the operators' ability to complete the compensatory or essential actions identified. The inspectors also determined that the licensee had identified the corrective actions, or were in the process of identifying corrective actions that would reduce the number of operator workaround The inspectors noted that the licensee had also assessed the aggregate effect of .

equipment deficiencies requiring compensatory actions and/or essential actions.

l Compensatory actions were defined as actions taken due to an equipment deficiency that must occur during normal operation. Essential actions were defined as actions that

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must be taken by a watchstander during a plant event due to an equipment deficiency.

l The licensee had established goals of less than one hour of compensatory action time

per watchstation per shift, and less than or equal to two essential actions per watchstation per shift.

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With respect to the WAPR, there were 35 items resolved in 1997 and 29 resolved to date in 1998. There were 13 WAPR items currently open at the time of the inspectio The WAPRs tended to be smaller scope items with short terms to resolution. The inspector reviewed both the MEPR and WAPR processes and considered that they received a high level of management oversight. The inspectors concluded that the licensee appropriately identified and documented operator workarounds. The WAPR list was managed by qualified personnel with a proactive approach to resolving deficiencie The inspectors also concluded that the licensee had identified the necessary contingencies and corrective actions to address each workaroun The FATS program was an engineering tool used to identify repetitive equipment failures based on equipment history. Summaries of equipment failure histories were developed quarterly. PIPS were initiated for equipment with high failure rates to track cause i determinations and corrective actions. A review of FATS summaries since 1995 indicated a reduction in the number of electrical and mechanical equipment with high failure rate Conclusion The Top Equipment Problem Resolution and Failure Analysis Trending System programs were effective engineering programs for the identification and resolution of equipment problems. Individual processes were, in general, adequate to track and monitor the status of equipment and specific programmatic issues; although, some lacked simplified indicators to assess the process effectiveness without a detailed revie The licensee had appropriately identified and documented operator workarounds. An operator work around list was managed by qualified personnel with a proactive approach to resolving deficiencies. The inspectors also concluded that the licensee had identified the necessary contingencies and corrective actions to address each workaroun As a result of the reviews, the inspectors concluded that the licensee has effectively managed safety and non-safety-related equipment problems that could impact equipment reliability and plant safet M3 Maintenance Procedures and Documentation M3.1 Evaluation of Procedure Chance Backloas Int section Scope (40500)

The inspectors reviewed procedure change backlog Observation and Findinas Catawba's procedure change backlog was managed within primarily two procedure writer groups, one associated with operations and the other with maintenance. The inspector interviewed the owners of the procedure backlog within each group. Within the

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operations group, the procedure change backlog was being closely monitored on a monthly basis; goals were defined and performance was measured; and individual performance was tied to backlog reduction effort and success. The inspectors reviewed the Catawba Operations Support Group Performance Indicators, which documented progress in reducing operation's procedure change backlog since 1996 and identified current goals for reducing the backlog. The backlog inventory has decreased from 370 )

procedure changes in 1996 to 253 procedure changes in 1998. The inspectors I concluded that, within the operations group, the program to monitor the backlog of procedure changes was mature, goal-setting strategies were aggressive, and the licensee was effectively reducing the number of backlogged procedure change The number of procedure changes in the maintenance procedure change backlog was ,

approximately 725, and the maintenance procedure change backlog monitoring program l was in its formative stages. Although the maintenance procedure backlog has been incorporated into the computerized monitoring program for approximately a year, backlog numbers were not being formally tracked, performance goals have not been established, and performance measures have not been addressed. Efforts to establish the program as an effective tool for monitoring procedure change backlog reduction have not been aggressiv Conclusions - ,

Processes to monitor the backlog of operations procedure changes were well established, goal-setting strategies were aggressive, and the licensee was effectively reducing the number of backlogged procedure changes. However, efforts to establish the maintenance procedure backlog program as an effective tool for monitoring procedure change backlog reduction have not been as aggressive.

l M8 Miscellaneous Maintenance issues (90712,92902)

l M8.1 (Closed) LER 50-413/96-10: Missed Technical Specification Surveillance for VY System Containment isolation Valves l

l (Open) LER 50-413/98-07: Missed Technical Specification Surveillance on Containment l Penetration Testing due to a Literal Compliance issue Licensee Event Report 50-413/96-10 documented a failure to test, at least once per six months on a staggered test basis, specified inboard and outboard soft seat valves of the containment hydrogen sample and purge (VY) system for leakage. The licensee

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identified this issue on November 7,1996. According to the LER, the root cause of the l event was a failure to identify VY system containment isolation valves composed of resilient seat material to ensure that they would be tested per the requirements of TS surveillance 4.6.1.9.3. The LER stated that corrective actions were taken to revise the scheduling of periodic leak rate tests for containment penetrations M332 and M346 for both units to meet the requirements of TS Surveillance 4.6.1.9.3. The inspector verified that penetrations M332 and M346 were declared inoperable and valves 2VY-16,2VY-158,2VY-17A and 2VY-18B were successfully tested by reviewing PT/2/A/4200/01C, Approved October 9,1995, and completed November 8,1996. The licensee verified that the Unit 1 valves had been tested within the required interva . . . __ _ _ ._ .. _ - - _ _ . _ _ __ ._ _ _ _ __ _ _

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On June 8,1998, the licensee determined that, among others, penetrations M332 and M346 still were not being tested in accordance with TS 4.6.1.9.3 and reported this finding to the NRC in LER 50-413/98-07. The licensee determined that the associated valves had been tested on a staggered penetration basis rather than on a staggered train

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(inboard vs outboard) basis. The licensee immediately declared affected penetrations, including M346 for both units, inoperable; all affected penetrations were successfully tested and returned to operable status within the time limits allowed by TS 4.0.3. The ,

inspectors noted that the LER did not discuss a corrective action to ensure that future

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tests would be scheduled on a staggered (per train) basis and asked the licensee if a corrective action of this nature had been taken. The licensee responded that scheduling changes had been made to ensure the inboard and outboard valves were tested on a staggeied basis. The inspectors reviewed the licensee's work management system and verified that the valves were scheduled for testing on an appropriate staggered basi The inspector concluded that the LER documentation was incomplete, although appropriate measures were taken to prevent recurrence. The inspectors determined that the licensee's initial actions were contrary to the requirements of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action. This non-repetitive, licensee-identified and corrected violation is characterized as NCV 5013,414/98-15-04: Inadequate Corrective Action to Ensure Compliance with Surveillance Requirement 4.6.1.9.3, consistent with Section Vll.B.1 of the NRC Enforcement Policy. This enforcement action addresses both the 1996 and the 1998 violations; however, LER 50-413/98-07 will remain open pending the licensee's completion, and NRC review, of planned corrective action Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E Review of Ooeratina Experience Proaram a. Inspection Scope (40500)

The inspectors reviewed the licensee's program for identifying, tracking, disseminating and resolving operating experience items. A sample of generic items applicable to Catawba Nuclear Station were reviewed to determine if corrective actions were adequate and timely. The inspector reviewed NSD 204, Operating Experience Program (OEP)

Description, Revision 5, and correspondence between the NRC and the licensee related to Generic Letter 83-28, Required Actions Based on Generic Implication of Salem i Anticipated Transient without Scram (ATWS) Even l b. Observations and Findinas According to NSD 204, the OEA group in the General Office (GO) is responsible for receiving, evaluating and resolving significant Duke Energy PIPS and a large number of l external OEP documents from the industry and the NRC. The OEA incorporated each

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externally received document into their Operational Experience Data Base (OEDB):

Duke Energy items are tracked and resolved within the PIP process. An OEA champion is assigned to facilitate the evaluation and resolution of each item, which is reviewed by a screening team for potential applicability and significance to the Duke Energy nuclear stations. For items that are applicable to a Duke Energy nuclear station, corrective

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actions are negotiated with station personnel and a station PIP is generated for each site affected. The OEA group is responsible for tracking corrective actions until they are implemente The inspectors reviewed a sample of PIPS associated with 10 CFR Part 21 Notifications, NRC Information Notices, and vendor notices to assess the adeauacy of the licensee's corrective actions related to OED8 items. The inspectors concluded that corrective actions were appropriate and implemented in a timely manner, and that PIP closure was not authorized by OEA until all corrective actions had been initiated and complete The inspectors noted that OEDB items were discussed in the daily site direction meeting i to ensure that potentially applicable issues and events received management attentio The inspectors considered this a good practice for keeping abreast of industry and Duke Energy-wide issues and addressing potential problems before plant safety is impacte The inspectors were aware of a number of previously identified problems with the licensee's OEP. These items were reviewed to assess the adequacy of the licensee followup to these items. One specific review involved a 1993 loss of offsite power event at McGuire Nuclear Station, during which a main steam isolation valve failed to fully

close. The inspectors reviewed the McGuire Nuclear Station NRC Inspection Report 50-369,370/95-03, which documented a subsequent inspection of the licensee's OEP. The 1995 inspection conclusion was that the licensee had enhanced their vendor technical interface program to ensure timely resolution of information updates at the site ; However, that same report identified instances where associated PIPS were closed out when corrective actions had been initiated but not completed were identified. During the current inspection, inspectors did not identify similar concerns in the OEP problem resolution proces c. Conclusions Based upon a review of selected PIPS, the inspectors concluded that the OEP was effective in communicating applicable generic information to Catawba Nuclear Station; corrective actions were appropriate and timely; and corrective actions were tracked to completion. The licensee's daily site direction meeting provided a forum for focusing site resources on emerging operating experience issues that may have site impac E3 Enaineerina Procedures and Documentation E Commitment Trackina System Effectiveness

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The Commitment Tracking Program is managed by a single individual at the Catawba Nuclear Station. Contemporary NRC commitments were tracked to implementation via PIPS. Commitments that predated this process have been incorporated into a document database and were retrievable by word search querie The PlP process provides for special flags that designste applicable corrective actions as NRC commitments and distinguish these corrective actions from all others, ensuring that controls are in place to require the regulatory compliance group's concurrence for authorization of commitment changes or delaying implementation of commitments. The inspectors concluded that the licensee's program for managing NRC commitments

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provided adequate controls for ensuring that commitments were effectively met or, if l changed, appropriate actions could be taken.

l l The inspectors noted that there were two instances within the previous year whereby l NRC commitment changes had been made without proper notification of the NRC.

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These instances resulted in the issuance of Deviation 50-413,414/97-14-02 (this item is closed in Section E8.1 of this inspection report). The root cause for these isolated instances was characterized as human error, and corrective actions to address the root l cause were appropriate. The inspectors concluded that the licensee's process for tracking NRC commitments was effectiv E3.2 Updated Final Safety Analysis Report (UFSAR) Accuracy Verification Project Insoection Scope (40500. 37551)

The inspectors reviewed the identification and resolution of findings related to UFSAR discrepancies identified in conjunction with the licensee's UFSAR Accuracy Verification l

Project. Additionally, the inspectors reviewed the activit a for resolution and tracking of routinely identified UFSAR discrepancie i Observations and Findinos The UFSAR verification project was expanded in 1997 to include a line by line review of ;

the entire UFSAR. A project manager and 4 contractors were assigned to accomplish this task. Approximately 1100 discrepancies have been identified to date. These were entered into a project specific tracking program with a find and fix approach implemented when possible. The discrepancies were categorized as editorial and technical with the majority of identified discrepancies being editorial. The technical discrepancies required l a 10 CFR 50.59 evaluation. Approximately 900 of the identified discrepancies were resolved. The project guidance provided criteria for the initiation of PlPs for those items requiring increased review. The licensee was submitting semi-annual UFSAR updates to resolve discrepancies. The inspectors reviewed a sample of UFSAR discrepancies -

identified by the project and verified thene were appropriately addressed. Management involvement included monthly oversight meetings. The inspectors concluded that, based

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on the sample review and established licensee processes for resolving UFSAR discrepancies, identified problems were entered into the PIP program and resolve The inspectors also reviewed an UFSAR related issue previously discussed as Unresolved item 50-413,414/98-05-04, Potentially inadequate Corrective Action to Justify Annunciator Response Procedure (ARP) Response Time for Loss of EDG Cooling. PIP 96-1160, dated June 11,1996, addressed a discrepancy between the UFSAR and an ARP regarding the time an EDG could run without cooling water. The l corrective actions were to delete the UFSAR referenced allowable time (five minutes)

and provide a technical justification for the time referenced in the ARP (ten minutes).

l The technicaljustification was based on a 1991 EDG event and a safeguard calculation.

l The 1991 event did not clearly envelope the loss of EDG cooling situation, in that, the event was a reduction of cooling not a loss of cooling. The inspectors identified that the

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calculation assumptions did not encompass the EDG loss of cooling worst case

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22 conditions and assumed a steam cooling mechanism of the pistons. This was inconsistent with vendor informatio The inspector discussed the technical evaluation with the responsible engineer. The information provided by the engineer indicated the licensee agreed that the alarm response procedure time had not been adequately addressed in the technical justification. The licensee initiated PIP C98-4451 to address and resolve the discrepancies in the previous technical justification. However, the engineer also provided additional information which adequately justified the specified time for a loss of cooling water as defined in the ARP. Based on this, the inspector concluded this was not a safety significant issue. In addition, the loss of EDG cooling water scenario was a low probability event and would impact only one train of the emergency power suppl Accordingly, this failure to take adequate corrective actions to justify the ARP constitutes i a 10 CFR 50, Appendix B, Criterion XVI violation of minor significance and is not subject to formal enforcement actio Conclusion l Based on a sample review, the licensee appropriately resolved UFSAR discrepancies l identified by routine plant activities and the special UFSAR Accuracy Verification Projec Based on a review of corrective actions for a UFSAR discrepancy, a minor violation was identified for not adequately performing an engineering technicaljustificatio E7 Quality Aesurance in Engineering Activities E Root Cause identification and Evaluation Effectiveness Inspection Scope (40500)

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The inspectors reviewed the licensee's root cause evaluation process and performance associated with plant problems documented in PIPS and post trip reviews. Additionally, trending of root cause related to human performance deficiencies were assesse I Observations and Findinas The licensee's corrective action process requires a comprehensive root cause analysis be performed on Category 1 and 2 PIPS. Additional root cause analysis is performed on ,

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selected Category 3 PIPS resulting in the performance of 80 to 120 root cause analysis evaluations yearly. Less comprehensive apparent cause analyses were performed for the remaining Category 3 PIPS. Guidance for performance of both levels of cause analyses was provided by NSD-212, Cause Analysis, Revision 6. Training was provided

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for licensee staff performing both levels of cause analyses. The inspectors reviewed approximately 50 PIPS including both levels of cause analysis. The cause analyses in

these PIPS were adequate to determine the problem cause and assigned corrective j actions were consistent with the cause determination ;

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The inspectors reviewed the post trip reviews for the three 1997 reactor trips. The reviews focused on assessment of plant response to the trip and the identification of the I trip initiators. The root cause evaluations were addressed in associated PIPS. Recent changes in the post trip review process, as indicated in revision 3 to NSD 505, Investigation of Reactor Trips or Significant Transients, expanded the required station !

involvement in the review process beyond the reactor engineering organization. The 1997 post trip reviews were of adequate depth and detail to provide a basis for the plant restart. Associated PIPS provided an adequate root cause for the equipment malfunction which caused the trip. There were no reactor trips in 199 I Trending of root cause human performance codes was accomplished semi-annually by a ,

common cause analysis (CCA) which reviewed the cause codes for PIPS over a six-month period. Findings from the CCA were entered into the PIP process with assigned l corrective actions. For example, the CCA for July to December 1997, identified common causes which included administrative procedure non-compliance, inadequate identification and documentation of work delays, documentation errors during !

l development and review of modifications, and over confidence of operations staff during ;

slightly off-normal evolution j c. Conclusion

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The licensee performed an appropriate level of root cause analysis, consistent with the significance of the equipment failure or human error which occurred. Trending of common cause for human errors was performed and corrective actions were assigned to address common cause issues. The 1997 post trip reviews were of adequate depth and detail to provide a basis for the plant restar E7.2 Corrective Action Review- Non-Comoliance with Over Power Differential Temperature 1 Setooint Specification

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a. Inspection Scope (40500)

The inspectors reviewed PIP 2-C98-4181 to determine if corrective actions were appropriate to prevent recurrenc l b. Observations and Findinas Station PIP 2-C98-4181 documented a discrepancy the licensee identified in all four channels of the Unit 2 Over Power Differential Temperature (OPAT) Trip Setpoint. On October 27,1998, the licensee determined that an incorrect value for T", defined in TS Table 2.2-1 as indicated average coolant temperature (T,, ) at rated thermal power, was used to develop calibration values in volts, direct current (VDC) for the OPAT trip setpoints. As a result, the calibration values provided in procedures IP/2/A/3222/076A (B, C and D), Calibration Procedure for AT/T,y Channel 1 (2, 3 and 4), were incorrect, and the setpoints were calibrated in a non-conservative manner that reduced the margin between the desired setpcint and the allowable limit provided in TS Table 2.2-1. The i

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licensee expressed high confidence that the OPAT trip setpoints were still within the l l

allowable value and initiated an operability evaluation to confirm this determinatio '

The inspectors determined that the error was introduced into the procedures in February 4 1997, when Revision 50 to IP/2/A/3222/076A was approved. Several unrelated changes I were made to the procedure and discussed in PIP 2-C96-2354. The inspector reviewed PIP 2-C96-2354 and determined that the change to T" was not discussed in detail in the PIP or in the 50.59 screening evaluation form accompanying the procedure change. The inspector discussed the PIP with engineering personnel and determined that the change to T" was made because the value in TS Table 2.2-1 for T" was specified to be s 590.8 Fahrenheit (F). The licensee indicated that Unit 2 T,y at rated thermal power had been 590.8 F until 1995, when a Tn, reduction modification was implemented to reduce I

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the maximum reactor coolant system temperature to which steam generator tubes would be exposed and, thereby, extend the life of the Unit 2 steam generators. A procedure change accompanied the modification in 1995 to reflect the new T,y at rated thermal power, which was 587.5 F. In late 1996 and early 1997, engineering personnel were developing unrelated procedural changes (discussed in PIP 2-C96-2354) and noticed l that the value for T"in the procedure was not 590.8*F. Failing to recognize that the value of T" = 587.5 F, engineering personnel proceeded to change the value of T" to )

590.8 F, effectively reversing the 1995 change that accompanied the Tn, reduction modification. The inspectors noted that the procedure change was made without sufficient review to conclude that the change would not adversely impact plant operatio l A more thorough evaluation of the proposed change by the originator and qualified reviewer might have revealed the inappropriateness of the chang The licensee completed procedural changes to correct the T" value in the calibration procedures; calibration of all four channels was completed on October 29,1998. On ;

November 24,1998, the licensee's completed a past operability evaluation, which I demonstrated that none of the four channels had exceeded the allowable value as a )

result of the procedural error. However, because of the procedural error, the setpoints were not appropriately calibrated at the desired setpoint. The inspectors concluded that the procedural error constituted a violation of TS 6.8.1.a. This non-repetitive, licensee identified and corrected violation is characterized as Non-Cited Violation (NCV) 50-414/98-15-05: Unit 2 Operation with OPAT Trip Setpoints Nonconservatively Calibrated, consistent with Section Vll.B.1 of the NRC Enforcement Policy. The inspectors discussed the implications for Unit 2 OTAT as well as the Unit 1 AT trip functions with the licensee and concluded that these setpoints were not affected by the erro c. Conclusions l

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, A non-cited violation was identified for a procedural error that caused all four Unit 2 OPAT trip setpoints to be non-conservatively calibrated since February 1997.

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E8 Miscellaneous Engineering issues (92903)

E (Closed) Deviation (DEV) 50-413.414/97-14-02: Changing NRC Commitments Without Properly Notifying the NRC This deviation consisted of two examples involving a changed corrective action and a changed implementation date that were designated as NRC commitments. The inspector verified that corrective actions were completed as specified in the licensee's response to the deviatio V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members ofilicensee management at the conclusion of the inspection on November 19,1998. The lic.ensee acknowledged the findings presented. No proprietary information was identifie PARTIAL LIST OF PERSONS CONTACTED Licensee S. Bradshaw, Safety Assurance Manager l

S. Beagles, Safety Review Group Manager l R. Glover, Operations Superintendent

! P. Herran, Engineering Manager R. Jones, Station Manager G. Gilbert, Regulatory Compliance Manager G. Peterson, Catawba Site Vice-President INSPECTION PROCEDURES USED IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 37551: Onsite Engineering IP 71707: Conduct of Operations IP 92901: Operations - Followup i IP 92902: Maintenance - Followup t

IP 92903: Engineering - Followup IP 90712: Licensee Event Report Review i

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ITEMS OPENED, CLOSED, AND DISCUSSED j

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OPENED 50-413,414/98-15-01 URI Review of VA System Past Operability (Section O7.1.b.(3) (a))

50-413,414/98-15-02 URI Potentially Non-Conservative TS Surveillance '

Criteria for Annulus Ventilation System Drawdown !

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(Section O.7.1.b.(3) (b))

50-413/98-15-03 NCV Failure to Perform Repairs on Pressure Retaining l Components in Accordance with Applicable Code Requirements (Gect;on 07.1.b.(3) (d))

50-413,414/98-15-04 NCV Inadequate Corrective Action to Ensure Compliance with Surveillance Requirement j 4.6.1.9.3 (Section M8.1)

50-414/98-15-05 NCV Unit 2 Operation with OPAT Trip Setpoints Non-conservatively Calibrated (Section E7.2)

CLOSED 50-414/97-04 LER Inadequate Test of a Containment isolation Valve When Procedure Step Not Performed (Section l 08 n)

50- 414/97-09-03 VIO Failure to Follow Procedure Results in Invalid Local l Leak Rate Test of Valve 2NV-874 (Section O8.1)

50-413,414/98-05-04 URI Potentially inadequate Corrective Action to Justify ARP Response Time for Loss of EDG Cooling (Sections 08.2 7 - i E3.2)

50-413/98-06 LER Missed Technical Specification Surveillance On Pressurizer Heater Emergency Power Supply

, Testing Due to a Literal Compliance Issue (Section 08.3)

l l 50-413,414/98-05-03 URI Technical Specification Discrepancy Involving i

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Pressurizer Heater Power Supply Manual Transfer Capability (Section 08.3)

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50-413/97-10 LER Reaction Trip Breaker Opened Due to Uncertainty of Rod Position (Section 08.4)

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50-413/96-10 LER Missed Technical Specification Surveillance for VY System Containment Isolation Valves (Section M8.1)

50-413,'414/97-14-02 DEV Changing NRC Commitments Without Properly Notifying the NRC (Section E8.1)

DISCUSSED 50-413/98-07 LER Missed Technical Specification Surveillance on '

Containment Penetration Testing due to a Literal Compliance issue (Section M8.1)

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l LIST OF ACRONYMS USED AHU Air Handling Unit ARP Annunciator Response Procedure ATWS Anticipated Transient Without Scram ASME American Society of Mechanical Engineers CCA Common Cause Analysis CFM Cubic feet per Minute CFR Code of Federal Regulations DC Direct Current  ;

DRPl Digital Rod Position Indication System EDG Emergency diesel Generator ESP Engineering Support Program l FATS Failure Analysis Trending System F Fahrenheit GO Corporate General Office HPST Human Performance Steering Team LER Licensee Event Report LSE Less Significant Events MEPR Major Equipment Problem Resolution  !

MSE More Significant Event i NCV Non-Cited Violation NDE Non-Destructive Examination NRC Nuclear Regulatory Commission NSD Nuclear Site Directive NSRB Nuclear Safety Review Board l OEA Operating Experience Assessment Group l l

OEDP Operational Experience Data Base OEP Operating Experience Program j l PDR Public Document Room l

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PIP Problem investigation Process  !

PORC Plant Operations Review Committee PORV Pressurized Power Operated Relief Valve

! QA Quality Assurance i SLC Selected License Commitment SRG Safety Review Group

, Average Coolant Temperature

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TEPR Top Equipment Problem Resolution

' Reactor Coolant Hot Log Temperature TS Technical Specifications UFSAR Updated Final Safety Analysis URI Unresolved item i

VA Auxiliary Building Ventilation

! VC Control Room Ventilation

VE Annulus Ventilation

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VIO Violation V Volts WAPR Work Around Problem Resolution 3M Monthly Mispositioning Meeting l

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