IR 05000317/1989200
| ML20247G925 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 05/22/1989 |
| From: | Grimes B, Haughney C, Konklin J Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20247G899 | List: |
| References | |
| 50-317-89-200, 50-318-89-200, NUDOCS 8905310112 | |
| Download: ML20247G925 (47) | |
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U.S. NOCLEAR REGULATORY COMMISSION 0FFICE OF NUCLEAR REACTOR REGULATION
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DIVISION DF REACTOR INSPECTION -
AND SAFEGUARDS
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Report No.: 50-317/89-200 50-318/89-200 Docket Nos.: 50-317 and 50-318 l
Licensee: Baltimore Gas and Electric Company P. O. Box 1475 Baltimore, Maryland 21203 Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Inspection Conducted: Febr ry 27 - March 31. -1909 -
Team Leader: J , _
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Date Sitjned[
Charles J. Hgdg $ef, Chief f Special Insphefion Brarict 3 6'R S Deputy Team Leader: m MBS//Y, s E, Konklin, Chief Dste Srgned eam Inspection Section C, DRIS, NRK Tea:n Members:
Operations Maintenance Group
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James E. Cummins, Group Leader DRIS, NRR; Jay R. Ball, Operations Engineer, DRIS, NRR; Stephen Pindale, Resident Inspector, RI; Jincy Smith, Operations Engineer, DRIS, NRR; Ward F. Sraith, Senior Resident
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Inspector, RIV; J. D. Wilcox, Jr., Consultant Man 3 . at Group Stephen C. Guthrie, Group Leader, DRIS, NRR; Robert A. Burns, Consultant; Bruce W. Deist, Consultant; Timothy C. Stockert, Consultant Other NRC personnel attending exit meeting: Brian K. Grimes, Director, DRIS, NRR; Robert A. Capra, Director, PDII, MRR; Lowell E. Tripp, Chief, RP3, RI; f Karold Eichenholz, Senior Resident Inspector RI; Vincent L. Prichett, Resident Inspector, RI; David . mroth,Projec neer, R i
. Approved By: I i ph /8'/
Date Signed Brian K. Grfmes, Diffctor.
) Division of Reactor Inspection and Safeguards l
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. Office of Nuclear Reactor Regulation C-\,,e,
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TABLE OF CONTENTS PAGE
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1.0 INSPECTION SCOPE AND OBJECTIVES ............................... I 2.0 DETAILED INSPECTION FINDINGS .................................. 2 l Operst1 9 t ........................................... 2 2. Scope C'Iew:-; .,..................................... 2 i 2. Conduct or Operations ................................. 2 2. Shift Staffing and Overtime Controls .................. 6 2. Procedure and Drawing Controls ........................ 6 2. Equipment Status Controls ............................. 8 2. Tempora ry Modi fi cati on Cont rol s . . . . . . . . . . . . . . . . . . . . . . . 9 2. Log Keeping and Turrovers ............................. 10 2. Facility Conditions and Housekeeping .................. 11 2. Operatir.g Experience Feedback Process ................. 11 1 Maintenance ........................................... 12 2. Scope of Review ....................................... 12 2. Observation of Maintenance Activities ........ ........ 12 2. Plant Material Conditions ............................. 13 2. Document Review ....................................... 14 2. Control of Techni cal Ma nual s . . . . . . . . . . . . . . . . . . . . . . . . . . 15 2. Control of Weld Rod ................................... 16 Ouality control Inspections of Maintenance I Activities .......................................... 18 2. Qu'ality Control Inspection Progran ..................... 18 2. Licensee Actions in Quality Control Area .............. 18 f Surveillance Testing .................................. 19 l
2. Scope of Review ....................................... 19 2. Surveillance Program Administration ................... 19 2. Surveillance Test Procedure ........................... 19 2. Surveillance Test Observations ........................ 22 2. Calibration of Pennanently Ins +.alled Plant Equipment .. 23 ,
i l Corrective Action ...................................... 24 2. cope of Review ......-................................ 24 2. Quality Assurance Audits and Program Evaluations ...... 24
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l 2. Nonconformance Repo rti ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2. Corrective Maintenance Requests ....................... 26 l
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l 3.0 MANAGEMENT EFFECTIVENESS REVIEW ............................... 27 1 Scope of Review ..........................o........... 27 3.1.1 Management Team Composition and Methodology ............ 27 Organizational Structure ............................... 27 3.2.1 Requirements for OrganTiational Effectiveness .......... 28 3.2.2 Organizational Dynamic: ................................ 29 3.2.3 Cultural Considerations ................................. 30 3.2.4 Procedure Problems ..................................... 33 ,
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. Management Processes ................................... 34
'3;3.1 State of the Art Management Processes .................. 34 3.3.2 Leadership ............................................. 35 3.3.3 Staffing and Personnel Qualifications .................. 35 3.3.4 . T rai ni ng a nd Devel opment - . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Management Application and Practice .................... 36 3.4.1 Change Management ...................................... 36-3.4.2 Performance Management ................................. 37 3.4.3 Management's Emphasis on Production .................., 37-3.4.4 Planning, Scheduling and Prioritization ................ 38 Analycis of Activities and Events ...................... 38 3. Procedure Upgrade Action Plan (PUAP) Review ............ 39 3.5.2 Event Review ........................................... 40 Conclusion ........................................... . 41
4.0 EXIT MEETING ............................................ 42 ATTACHMENT A - NON-NRC ATTENDEES AT EXIT MEETING ON MARCH 31, 1989 ATTACHMENT B - ABBREVIATIONS AND ACRONYMS ATTACHMENT C - UNRESOLVED ITEMS
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1.0 INSPECTION SCOPE AND OBJECTIVES From February 27 through March 31, 1989, a team of 12 NRC inspectors performed a special team inspection at Calvert Cliffs Nuclear Power Plant. The intent of the inspection was to determine the causes of recent events and to investigate what was perceived as a general decline in the level of performance at the Calvert Cliffs plant. The inspection team consisted of two groups, the opera-tions and maintenance group and the management group. The operations and maintenance group conducted inspections in the areas of operations, maintenance, quality control, surveillance testing, and corrective action. The management group evaluated the effectiveness of Calvert Cliffs management in managing the safe operation of the plan i l
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2.0 DETAILED INSPECTION FINDINGS 2.1 Operations 2.1.1 Scope of Review The team conducted inspection tours of the plant, observed control room operations, and held infonnal interviews with plant employees to verify that the facility was being operated safely and in conformance with regulatory requirements. Other objectives of the review were to ensure that the 11cen-see's management control system was effectively discharging its responsibili-ties, to assess the adequacy of selected plant procedures that pertain to operations, and to ensure that controls over procedure and plant changes were implemented and executed in accordance with technical specification requirement .1.2 Conduct of Operations The team observed control room activities at random times during all three shifts. Inspectors from the team monitored the control room for more than 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />, observing 6 shift turnovers in the control room and shift supervisor's office. The team noted that at all times access was well controlled and operator behavior was commensurate with the plant configuration and any activi-ties that were taking place. The atmosphere was generally quiet and conducive to the operators' need to concentrate on control board indications. The control room was free of distractions and control room supervisors appeared sensitive to any potential distractions caused by anyone. Control room access was strictly controlled by the on-shift operators. Non-shift personnel were required to stop at a labeled point in the tack of the control room and request pennission to approach a rea line on the carpet, which enclosed the control boards for both units. By procedure, only the unit control room operator granted pennission to cron the line into the vacinity of the control board Control room access and disruptions were further reduced by the system tagging group whose functions are described in Section 2.1.5 belo The team observed good procedural compliance in the control room and elsewhere in the plant during two reactor shutdowns, a reactor startup, and steady-state operations. The operators were aware of the licensee's recently re-emphasized requirement for strict compliance wjth written procedures, and usually complied with those procedures or obtained a procedural change, particularly for complex, highly visible operations. However, the four exa.nples of procedural adherence problems discussed below occurred during the inspection perio These examples tend to confirm the teams conclusions that lack of procedural compliance continues to be a proble (1) On March 6,1989, the main condenser vacuum was nearly lost during a condenser air in-leakage check because the operator failed to perfonn step i IV.B.2 of operating instruction 01-13. " Condenser Air Removal," which required the condenser air removal units (vacuum pumps) to be shifted to I
the separators instead of to the atmosphere, which was the normal operating configuration. When the low vacuum alarm tripped in the control room, the operator realized his error and performed the step before vacuum was lost. There was a " CAUTION" in 01-13 preceding step IV.B.2, in-2-
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, bold print warning the operator that failure to perform all steps in the correct order may result in loss of condenser vacuu (2) On March 9, 1989, while Unit 2 was returning to full power, voltage was lost on nonsafety-related 480-volt bus 23A during preventive maintenance on tie breaker S2-2312 between busses 23A and 238. Condenser vacuum pump 23 lost power, thus causing a partial loss of condenser vacuum. This problem was caused in part because a maintenance technician misused a multimeter when he used a resistance scale instead of a voltage scal The problem was aggravated by a wiring error in the switchgear resulting in 125 volts de being present on an incorrect terminal. These errors made <
by maintenance staff directly affected the operation of the plan (3) On March 19, 1989, while in Mode 5 (cold shutdown) on Unit 1, an inadvertent safety injection actuation occurred while the operator was performing surveillance test procedure STP-0-7, " Engineering Safety Features Logic Test." The event occurred because the operator failed to perform a step in the procedure that would have blocked the safety injec-tion signal. This incident is also discussed in Section 3.2.4 belo (4) On March 20, 1989, a partial engineered safety feature actuation signal (ESFAS) logic cabinet "B" actuation was received on Unit I while in Mode 5, causing boric acid pump 12 and component cooling pump 12 to start, and causing 4 high-pressure safety injection header motor-operated valves to open. This event occurred while an operator was attempting te restore j the ESFAS cabinet to a normal configuration after maintenance. The operator skipped two steps in operating instruction 01-34, " Engineered Safety Features Actuation System."
In each of these four cases, it appeared that the individuals who failed to follow the applicable procedures had the procedures in hand but did not follow them in a deliberate, step-by-step manner. The team concluded that managers and supervisors were not paying enough attention to ensuring that employees performed routine repetitive activities properly.
l The team observed a notably small number of lighted (alanned) annunciators l while both units were at power, indicating that the licensee's " dark board" efforts had successfully reduced the number of nuisance alarms. Every time an j alarm appeared, an operator responded to it promptly and appropriatel '
L During the Unit I shutdown on March 3, 1939, the team witnessed the performance of STP-0-67-1, Revision 20. " Check Valve Operability Verification." The purpose of this test was to verify seating of the steam generator feedwater check valves FS-130 and FW-133, which were in the rcain feedwater piping just inside the containment. The procedure was followed precisely and satisfactory results were obtained; however, the team noted two weaknesses not necessarily related to operations. The team examined the installation of test gauges required by the surveillance test procedure (STP). The STP simply required
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that test gauges be installed on the low-pressure side of main feedwater regulating valve differential pressure detectors PDT-4516 and 4517. Similar words appeared on the supporting work order. Neither document specified to which valve, by number, the gauges should be connected. The team consulted drawing 60-702-E, Revision 10 " Condensate and Feedwater System, Unit 1 " to identify where the connection should be made. Upon inspecting the installation,
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.the team found errors in instrument valve identification tagging, and noted i that the instrument piping had not been installed as shown on the drawin )
These were not safety-related valves and pipes, but the error should have l been discovered in the past and correcte The team also noted that the test was delayed momentarily because the STP called for test gauge " calibration due date" but the sticker on the gauges read
" calibration date." The operator explained that these particular gauges were calibrated by the maintenance workers who installed them, rather than by measuring and test equipment (H&TE) personnel. The operator obtained the correct information by telephone, entered it in the procedure, and then pro-ceeded with the test. The team discussed the licensee's practice of calibrat-ing M&TE with instrument maintenance supervision. The gauges used for STP 0-67-1 were maintained by the instrument maintenance group. Further review revealed that this group had an inventory of pressure gauges which, when
.needed, wem calibrated against "more accurate" gauges and then installed in the system being tested. When the gauges wem returned, they were placed back on the shelf and no record was made of where they were used, and no checks were made to verify that the gauges were still indicating properly after use. No
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method of recall existed nor was there any means to verify the test data taken from such gauges could be relied upon. The team found no procedural controls over this practice. This situation was contrary to Calvert Cliffs instruction CCI-120D, " Calibration Program for Measuring and Test Equipment," which !
required the supervisor of'each group responsible for M&TE to ensure that approved calibration procedures for test equipment were available and use (Unresolved Item 50-317/89-200-01).
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The team was concerned about these problems and was also concerned that failum to properly control M&TE may have placed an indeterminate amount of technical specification surveillance test results in question. As a result of these failures, the operability of the affected components on systems may have been questionable. This concern was discussed with the licensee on March 9 and 10, 1989. After returning for the second phase of the inspection, the team reviewed the licensee's activities to determine what corrective actions had been takin. Ashop/labmemo(speedimemo)hadbeenissuedtoinstrument maintenance personnel directing them to check the gauges for calibration before and after use. All of the gauges had been checked and hone were found out of ca13bration. The licensee had taken no action to comply with CCI-1200, and had conoacted no reviews to ascertain the possible need to issue a nonconformance repott. The team considered this limited action to demonstrate a weakness in the hcensee's corrective action progra The team walked through abnonnal operating procedure A0P-9, " Alternate Safe Shutdown Control Room Evacuation Procedure." Performance of AOP-9 required extensive operator actions throughout the plant, and required participation from most of the operators on shift. The licensed and non-licensed plant
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operator training for A0P-9 consisted of independent classroom training and procedure walkthrough to locate equipment. The independent procedure walk-through appeared inadequate because the operating shift would have to perform complex required actions as a team. It appeared to the team that the procedure walkthrough training would have been more effective if licensed and !
non-licensed personnel had been trained togethe ,
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The team attended one of the meetings conducted by the General Supervisor-Nuclear Operations with each of the operations shift sections. The purpose of the meeting was to discuss a variety of issues, emphasizing what company management expected of its employees with regard to strict adherence to proce-dures, safe work practices, thinking through complex activities in advance, I placing quality and safety ahead of schedule, exhibiting a questioning attitude (not following procedures blindly), expecting to be held accountable for actions, striving to improve perfonnance, and erring on the side of conserva-tism. The licensee's 1989 Nuclear Program Plan was addressed also. The group appeared attentive and seemed to leave the meeting with a better understanding of what the company expected of them. A written sununary of the issues discussed was handed out during the meetin The inspection team interviewed operations staff to obtain their perception of the effectiveness of interface and support provided by operations management and other support groups. From the interviews, the team concluded that the interface, support, and qualifications of system engineers were perceived as improving, but that the engineering group needed more input from operations personnel when resolving engineering problems. The policy of assigning less-experienced engineers as system engineers and rotating them out of the positions after they became qualified was still considered a proble Operations managers appeared to be trying to foster better relationships through meetings in which they informed their employees about management expectation People who were interviewed stated that in the past, operations management and support groups did not seek their employees' ideas and recom-mendations, nor did they utilize such input when it was presented. An example of management's failure to act on recomended changes was the post-maintenance operational testing process described below. Recently, employees have seen some improvements in this area. Although the operator's outlook tended to be optimistic, there appeared to be a " wait and see" attitude about the recently implemented change The maintenance grcup was perceived by the operations group as responsive and effective in safety-related areas, although several of the people who were interviewed felt the area of nonsafety-related equipment maintenance needed significant improvement. A concern was expressed over the cumbersome post-maintenance operational testing process covered by operations unit administra-tive policy 85.4, dated February 8, 1988. This policy required the operators ( to determine all post-maintenance testing. The process caused backlogs of tests because the work to be performed was described too briefly in most maintenances orders (M0s), and because such a large number of M0s had to be
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processed during busy outage periods. The operators expressed concern that when they were busy they could conceivably prescribe inadequate or improper post-maintenance tests. The licensee walked the inspection team through the process, and it appeared that the operstors had a valid concern about the potential for inadequate testing. The inspection team talked with the licensee about this concern; the licensee told the team that the process was being revised to have post-maintenance testing specified by other than operations personnel, and then concurred with by operations to ensure regulatory require-ments were being me _ _ _ _ _ _ _ _ _ _ _ ._ ___-__ _________ - - ___ - ___ _ __ .-
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2.1.3 Shift Staffing na Overtime Controls, Control room staffing consisted of one reactor operator for each unit, a control rcom operator behind the desk of each unit who maintained the reactor operator's logs, a control room supervisor in charge of the control room for both units, and a shift supervisor. In addition, depending on the activities taking place, an " overseer" holding a senior reactor operator's license was present to ensure positive control over such activities as startup, shutdown, and draindown of the Unit I reactor coolant system for reactor coolant pump !
seal maintenance. The reactor and control room operators were on a daily rotation so that a given operator would be Unit I reactor operator one day, Unit 2 operator the next day, Unit 2 control room operator on third day, and Unit I control room operator on the fourth day. The rotation policy appeared to be beneficial in maintaining operator attentiveness by reducing daily repetition in responsibilities. Control room staffing methods were considered a strengt The licensee's shift staffing appeared very adequate in the total number of personnel and shift assignments. In addition, the fire brigade shift team members were not assigned duties for remote shutdown outside of the control room. This practice ensured that adequate personnel would be available to concurrently fight fire and perform a remote shutdown as require A review of overtime records from November 6,1988 through March 5,1989, revealed four instances in which the overtime guidelines in Calvert Cliffs instruction CCI-140E, " Shift Staffing," Attachment 1, were exceeded. During January and February 1989, 4 people worked more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour period without getting management approval as was required by procedure. The licensee completed overtime authorization forms for employees who exceeded the guidelines in March, after the teani inspected this are A review of more recent overtime records showed that from March 16 through 22, 1989, 16 operators exceeded the 72-hour guideline. Six worked 80 hour9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br />s-and 10 worked 76 hours8.796296e-4 days <br />0.0211 hours <br />1.256614e-4 weeks <br />2.8918e-5 months <br />. Possible fatigue was listed as a contributing cause of the loss of nonsafety-related 480-volt load center bus 23A since the maintenance group was working six 10-hour days per wee .1.4 Procedure and Drawing Controls The team reviewed 10 Calvert Cliffs instructions (CCIs) 3 operating procedures-(0Ps), 4 operating instructions (OIs), 1 emergency operating procedure (EOP), 2 I
operations surveillance test procedures (STPs), and 1 abnormal operating procedure (AOP). These procedures were generally adequate except as noted belo The team reviewed the CCIs that applied to the review, approval, and change l control of plant procedures. The procedures in combination did not appear to adequately implement Technical Specification (TS) 6.8.3, which provided for
"non-intent" temporary changes to procedures. The instructions for processing such changes appeared to be fragmented and inconsistent for procedures that came under the purview of technical specification administrative requirement For example, 0C1-3001, "Calvert Cliffs Operating Manual (CCOM) " Section V. A.,
t required changes to operations procedures to be made in accordance with CCI-10lK, " Review and Approval Procedures for Proposed Calvert Cliffs-6-
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Procedures." Then CCI-3001 gave details about how to make a change and get it approved. CCI-101K briefly discussed some of the rules associated with e.hanges. Section V.S.2. of CCI-101K required all changes to be reviewed by the plant operations safety review comittee (POSRC) within 14 days pursuant to TS 6. CCI-104I, " Surveillance Test Programs," Appendix 104.30, appeared to make an !
attempt at defining " intent changes." However, it only applied to surveillance test procedures (STPs) and not to operations procedures. Appendix 104.30, Section 3.3, took exception to the 14-day requirements for POSRC review of changes by stating that corrections of obvious typographical errors, grammatical errors, and minor format changes were not considered intent changes and needed only the applicable maintenance / work group supervisor concurrenc Appendix 104 30 appeared to raise more questions than it answered. Even after reviewing the CCIs and discussing the problem with licensee management, the team was not able to detemine the licensee's position on intent changes to procedures. The licensee acknowledged the problems discussed above and committed to evaluate and correct the condition. The team considemd this condition to be a weakness in the licensee's control of procedure (Unresolved Item 50-317/89-200-02).
The team reviewed the General Supervisor, Operations (GS0) standing instruc-tions, and it to the team appeared that some of these instructions provided directions for operator actions that should have been included in a procedur Examples of such GS0 standing instructions follow:
- 83-12, Loss of Bus 11 (125-v-de). This standing instruction stated that l
in the event of the loss of bus ll, the Unit 1 turbine and reactor will automatically trip; but the Unit 2 turbine will not trip, and all remote and automatic electrical functions will be lost. The standing instruction directed that an operator be posted at the Unit 2 turbine in direct communication with the control room in order to provide a means of manually tripping the turbine should it become necessary. The team noted that there was an annunciator in the control room that alerted the operators in the event of a bus 11125-Vdc undervoltage condition. The l annunciator response manual referred operators to standing instruction 83-12. The action required in the standing instruction should have been placed in the annunciator response manual or in an abnomal operating procedur * 84-2, Reactor Trip Breaker Operability. This standing instruction directed the operators to the technical specifications and to CCI-11B,
"Calvert Cliffs Reporting Requirements." if.one or more reactor trip t breakers were inoperable. The team did not see a reference to the GSO standing instruction in the appropriate surveillance test procedure, STP 0-6-1, Revision 14. "RPS Startup Test." It appeared that as a minimum,
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the GS0 standing instruction should have been referenced in the STP.
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- 83-2, Sampling of Oils. This standing instruction directed that samples of lube oil or electrohydraulic control (EHC) fluid will be tested when they are received. It appeared that a procedure should have been imple-mented to cover this function, as described in step 10 of Regulatory Guide 1.33, " Quality Assurance Program Requirements (Operation)," Revision 2 February 197 t - _ ._- _ _ _ _ _ _ _ __ -
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The use of the General Supervisor Operations standing instructioning as'a means of providing directions for operator actions rather than including these
' directions in an' approved procedure is considered an unresolved ite .(Unresolved Item 50-317/89-200-03).
' On March 1,1989, the team observed an example of inappropriate control of procedure changes. The throttle trip circuit for Unit 2 auxiliary feedwater (AFW) pump 22 failed, causing the trip switch on the main control room panel to catch fire before the fuses blew. In order to verify operability of the adjacent control-circuits for AFW pump 21, the licensee implemented a "non-intent" change to STP 0-9-2, " Auxiliary Feedwater Actuation System Monthly Logic. Test," which was a complex change deleting many steps throughout the procedure. .Upon questioning whether or not this should be an intent change requiring prior POSRC approval, the team was told that STP 0-9-2, as changed, was not being conducted to satisfy a technical specification surveillance-requirement. Thus the licensee considered the change to be a non-intent change. The licensee went on to explain that the reason for the change was to prevent the turbine-driven pump from actually starting, because only the control circuit needed to be tested. The team considered this change to be an intent change and as such should have had prior POSRC review. The test was conducted as changed, and there did not appear to be any significant problems other than the difficulty experienced by the operator in following the proce-dure with so many marked-up steps. because of the method used to indicate what was changed, the operator had to exercise extreme care not to miss steps intended to be performed. The practice of using marked-up procedures to conduct safety-related activities in a nuclear power plant is considered a significant weakness, especially in the modern day world of word processin The team checked the control room piping and instrument diagrams -(P& ids), logic diagrams, and electrical drawings for clarity and adequacy of the design change notice (DCN) revision process and to ensure that the latest controlled copies were in the control room. No discrepancies were found and all drawings reviewed were legible and of excellent quality. The use and the availability of. legible, high quality drawings for control room operators is considered a significant strengt .1.5 Eouipment Status Controls The team reviewed CCI-12H, " Safety Tagging," which delineated the licensee's equipeent tagout' process. An independent safety tagging group was responsible to the operations and maintenance coordinator for establishing safe boundaries for maintenance and modifications. A coordinator who held a. senior reactor operator license and tagging personnel who were licensed reactor operators were on rotational assignments from the operations group. This concept, by provid-ing well-qualified personnel dedicated to only one task, reduced the distrac-tions of shift operating personnel. Subsequent to the teams departure from the site, NRC Regional based inspectors did, however, identify certain weaknestes 1 in this program, which are discussed in NRC inspection report 50-317/89-11, l
50-318/89-1 While conducting control room observations, the team attempted to obtain the current status of equipment-out-of-service. There did not appear to be an equipment-out-of-service log. Technical specification limiting conditions for operation (LCO) in effect at any given time were listed in the control roo'm ,,
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operators' logs and on a video screen. A computer printout showed what was danger-tagged out of service. In combination, the computer printout and the control room operators' logs were considered adequate for system-out-of-service status, according to=the operators. The team pointed out that systems or components could be placed out-of-service without a tagout and without the plant entering an LCO action statement. Although the safety significance may have been diminished if a component or system was not controlled by an LCO, the team suggested that as an improvement item, the licensee should consider having some form of equipment-out-of-service status readily available to the operator .1 6 Temporary Modification Controls Temporary modifications (TMs) were implemented at Calvert Cliffs by CCI-117H,
" Temporary Modification Control." The team reviewed the procedure and found it '
confusing and contrary to the administrative requirements in the technical specifications. The team had the following concerns related to CCI-117H:
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The exceptions to controls by CCI-117H listed in Section III.B. made little sense. The wording appeared to allow the installation of a bypass switch on a safety-related system with no removal certification.-
- In Section IV.A, the definition of a TM listed three specific types of devices installed and then stated, "or cther form of temporary modifica-tion." The definition appeared too non-specific to provide meaningful guidanc * Section V. A.3 required maintenance personnel to ensure that. interim i changes (presumably TMs) that were disapproved by the POSRC were to be restored to their "before" condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. TS 6.5.1.6 did not t provide for safety-related TMs to be installed before the POSRC reviewed the * Section V.D.1.a required the system engineers to perform a technical review (Attachment 7 of CCI-117) to verify whether the system was safety related. Attachment 7 did not appear to provide for this verificatio * Section V.D.2 required the system engineers to ensure that TMs which were safety related were reviewed by the POSRC within 14 days of implementa-tion. Again, TS 6.5.1.6 did n'ot allow TMs to be implemented before'the POSRC review. When the team reviewed the TM log, the team noted that two safety-related TMs were implemented on Unit 2 before the POSRC review.. TM'
2-87-111 was implemented on July 15,1987(POSRCMinutes87-75). TM
.2-87-121 was implemented on October 21,1987(POSRCMinutes87-98). This practice was contrary to the requirements of TS 6.5. * Yhe " NOTE" in Section VI.A.1.b permitted the shift supervisor to install any TM for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> without any technical review or safety evalua-tion. There was no evidence that this type of TM had been done in the past; however, it could have been done. This practice was prohibited by technical specifications and by 10 CFR 50.59, was not conducive to safety and, therefore, was unacceptabl L-___-_______-
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The team discussed the problems identified in CCI-117H with the licensee's design engineer who was responsible for the procedure. .During the interview, the engineer showed the team a proposed revision that resolved many of the team's questions. However, the areas discussed above which were contrary to technical specification requirements still existed in the proposed revisio When the team returned to the plant site on March 27, S89, licensee personnel described additional changes under consideration for the control of TMs. These actions included removal of the 14-day allowance discussed above, placing an
" emergency only" caveat with the 24-hour allowance discussed above, and further clarifying the revised procedure. More thorough screening forms previously used for permanent field change requests were completed on all open TMs for both unitt. Out of approximately 78 open TMs, 6 should have received a prior 10 CFR 50.59 safety evaluation, but had not. These reviews were done after the fact, and one of the six appeared to be initially a potential unreviewed safety question. The licensee was evaluating this TM for 10 CFR 50.73 deportability considerations. Another 12 TMs should have been reviewed by the POSRC, but were not. These review, were subsequently done. A small task group of senior personnel were empowered to explore the processes used to evaluate the safety implications of maintenance, modifications, and troubleshooting activitie The licensee could not provide a completion date for this activity, nor could the licensee tell the team when resultant program changes would be implemente (UnresolvedItem 50-317/89-200-04). .
The team noted a number of minor omissions and errors on the TM log sheets that appeared to reflect the results of having a confusing controlling procedure such as CCI-117H, as discussed above. These minor problems did not appear to be safety significant and were found mostly in nonsafety-related TM package Unit 2 had approximately 50 TMs installed. This amount appeared to be excessive. It was apparent that there was no significant effort under way to reduce the number, even though the POSRC reviewed TMs aged 12 months or more every quarter year as required by CCI-117H. The Baltimore Gas and Electric Company Nuclear Program Plan, dated January 13, 1989, did not appear to address any goals for reducing the number of TM The team also noted that 14 TMs installed according to the TH log sheet :
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(Attachment 3 of CCI-117H) in front of the TM log book for Unit 2 had no data packages in the book to support the open entries. CCI-117H required the dati packages to be retained in the book until the TMs were removed from the platt and closed. When questioned about this deficiency, the licensee told the One ,
team that 11 of the 14 TMs had been closed and the lo TM was unaccounted for, and two were out for review (g sheet was wrong.not imp team also counted 12 open TM data packages missing from the Unit 1 book. The licensee found 11 closed; thus the Unit 1 log sheet was also incorrect. One TM package was unaccounted for. When the team returned to the site on March 27, 1989, the licensee had found all the missing TM packages, and was able to
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update the lo .1.7 Log Keeping and Turnovers ,
The team reviewed the control room operstors' logs on a daily basis while on site. In general, the logs were infonnative and provided a clear chronology of events. CCI-114D, " Plant Logs," provided excellent detailed instructions for keeping the control room operators' logs. The instructions required as mud
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detail as possible, subsequent' clarifying entries, and reasons for actions logged. The team noted that many log entries were somewhat cryptic, leaving a question in the reader's mind as to why an action was taken, or what was done to resolve e given. problem. The team discussed log-keeping with the licensee's operations management and pointed out the areas needing improvemen The team observed a number of shift turnovers. Turnovers involved licensed opern ors performing the duties of whift supervisor, control room supervisor, plant watch supervisor, control room operator, and reactor ' operator. Shift turnovers were usually thorough and included a detailed discussion of plant activities, walkdown of control boards, review of logs, and the completion of-other shift turnover checklist items. There appeared to be adequate time allocated for turnovers and the team did not cbserve any weaknesses in this are .1.8 Facility Conditions and Housekeeping The team members conducted several inspection tours of the inside and outside areas of the plant. The team noted the cleanliness and absence of clutter
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(tools., trash, scaffolds, and anti-contamination material) inside the plan Contaminated areas requiring protective clothing had been minimized by the licensee. There were very few water leaks from plant systems and very few instances of boric acid crystal accumulation on valves and pump The team accompanied non-licensed operators on their rounds to pennit the team
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members to observe how the operators executed their normal duties. In general, the operators were professional, knowledgeable, and enthusiastic. They K appeared to take personal responsibility for the equipment in their charge and, in most cases, aspired to move up in.the organization. The good attitudes expressed by these operators and the generally good cleanliness and material conditions in the facility indicated a strong sense of ownership and pride that the Calvert Cliffs workforce evidently felt for their statio .1.9 Operating Experience Feedback Process The team reviewed the plant operating experience assessment committee (POEAC)
functions described in CCI-139E " Organization and Operation of the Plant Operating Experience Assessment Committee." The POEAC functioned as a subcom-mittee of the POSRC and reviewed all industry and plant experience documents for distribution to applicable groups. The POEAC consisted of members representing operations, radiation safety, training, chemistry, maintenance, and all engineering groups. All committee members were trained in accordance with the POEAC Training Manual. The meeting minutes reviewed copeared to effectively I
distribute data to appropriate groups. The group reviewed all NRC Information Notices and Bulletins; vendor information; and Institute of Nuclear Power Operations (INP0)' Safety Evaluation Reports (SERs) and Significant Operating EventReports-(SOERs). The effectiveness of the functions perfonned by this group were considered a strength by the tea e
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t 2.2 Maintenance 2.2.1 Scope of Review The team evaluated selected maintenance activities that took place during this inspection by reviewing procedures, observing work in progress, performing visual inspections of completed work, reviewing records of completed work, and interviewing licensee personnel. Administrative and maintenance procedures were reviewed for completeness, clarity, and confonnance to design and regulatory requirement .2.2 Obser;stion of Maintenance Activities The team observed the three maintenance activities discussed below. The team also reviewed appropriate documentation related to these maintenance activi-tie (1) Preventive maintenance PM 1-24-M-SA-3. Revision 4 (MO #209-054-112A),
" Test No. 11 Emergency Diesel Generator Injectors" removed 24 injectors from the emergency diesel generator (EDG), tested the injectors, adjusted 3 of the injectors, and reinstalled the 24 injectors. This PM activity control QC) (wasinspector performed andby four one QCmechanics and observed training inspector. Two system by one quality engineers overviewed this activity which took approximately one shift to complete. The inspection team determined that the PM did not provide adequate instructions to the craft. The craft used the diesel generator technical manual as the primary source of infonnation for. accomplishing the work.. However, the PM instructions provided did not specify the sections of the technical manual for the craft personnel to follow. This arrangement left the decision of which parts of the technical manual to l
follow up to the discretion of the craft worker. In addition, the team determined from discussions with licensee personnel that the required OC independent inspection for this activity could be waived by the QC group, if QC personnel were not availabl (2) Electrical maintenance order MO 209-009-049A, " Replace Environmentally Qualified (EQ) Motor 2-MOV-625" provided instructions for removing a non-EQ (not environmentally qualified) motor, supporting and installing a - i new EQ motor, and stroke testing the valve (2-MOV-625) with the new motor j installed on it. The team determined that the M0 did not provide adequate instructions to the craft personnel to ensure that the work was perfonned correctly or that it was adequately documented. Specifically, the M0 did not provide definitive instructions for removing and reinstalling the 7'
motor, for electrically disconnecting and reconnecting the motor, or for lubricating the motor gasket. The M0 listed four technical manuals and five other references (i.e., drawings); however, the work instructions did not specify how these references were to be used nor did the instructions i
refer to any specific sections in these references. The team did not observe any of the references at the job sit (3) Electrical maintenance order MO 209-055-138A, " Rebuild Spare Penetration -
SN3010" was issued for rebuilding and voltage-drop testing a spare electrical penetration located in the warehouse. The MO was performed by
' two mechanics, and for a few days a system engineer monitored the wor '
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The M0 simply stated that the rebuil'ing d and drop testing should be per-formed in accordance with the technical manual. Instructions in the M0 left it to the craft worker to determine which sections of the technical manual to use to accomplish the desired work. Instructions for performing the work were provided in the technical manual; however, the M0 did not specify the sections of the manual that the craft person should follo In addition to reviewing this activity, the inspection team also noted that one of the supports for the spare electrical penetration was ben The lic'nsee e did not document this condition in a nonconformance report (NCR) until the team raised the question of whether an NCR should have been writte From these examples and from an examination of other preventative and corrective maintenance procedures and instructions, the team concluded that the work instructions currently used for performing maintenance activities did not contain adequate details to ensure that the activities were being performed correctly or to provide meaningful acceptance criteria and hold points for quality control inspectors. The instructions appeared so incomplete that craftsmen were required to use their judgment in performing nearly every maintenance step, regardless of the complexit, (UnresolvedItem 50-317/89-200-05).
2.2.3 Plant Material Conditions The team performed several walkthrough inspections in the auxiliary building, turbine building, and emergency diesel generator rooms. The team felt that the overall cleanliness of the plant was acceptable. However, the team identified the material deficiencies discussed below, which showed instances where licen-see personnel failed to identify and correct material defects. The licensee initiated maintenance requests (MRs) to evaluate the deficiencies and the MR number that identifies each of the deficiencies is provided in parenthese (1) Room 101 Unit 2 - 15' elevation: A chain operator for valve 2-CC-270 passed through cable tray ZA 2AA15. This condition had the potential to damage the cables when operated and additionally posed a personnel safety hazard. (MRNo.39602)
(2) Room 101 Unit 2 - 15' elevation: The support for valve 2-SI-319 operator extension had a sheared anchor bol (MR No. 39603)
r (3) Room 101 Unit 2 - 15' elevation: The support for piping to valve 2-SI-1011 had one missing anchor nut and one anchor nut had less than full f'
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thread engagemen (MRNo.39604) ,
.(4) Room 101 Unit 2 - 15' elevation: The support for valve 2-SI-452 had an anchor bolt nut installed with less than full thread engagement. (MRN )
(5) Room 101 Unit 2 - 15' elevation: The packing gland fastener was bent on valve 2-51-1037. From observing similar valves, there appeared to be a problem with the size of packing gland nuts used on this type of valv Tho licensee initiated MR No. 3906 to evaluate this specific situation but i
did not address the potential that a generic problem could exist.
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(6) Room 101 Unit 2 - 15' elevation: A hanger support plate had 2 out of 4 anchor bolts missing on the concrete column next to flow transmitter
'2-51-4148-F (MR No. 39608)
(7) Room 101 Unit 2 - 15' elevation: The local mechanical position indicator for valve 2-SI-656 indicated 67 percent open while the valve position in the control room indicated the valve should have been fully open. Since there was a question about the actual valve position, the valve was cycled from fully open to fully closed. The local position indicator did not change. position when the valve was cycle (MRNo.39609)
(8) Unit 1 - 15' elevation (11 and 12 emerge.cy core cooling system [ECCS]
pump rooms): The pump-bearing temperature-element (TE) wires were not terminated (wires were coiled on TE housing on pumps 11 and 12 and deter-minated on 13 pump).- (MR No. 463445)
Although none of the above conditions appeared to affect the operability of any 1 system or component, the team concluded that the licensee did need to place additional emphasis on identifying and correcting similar m.aterial deficiencies beyond the mere correction of housekeeping problem .2.4 Document Review The inspection team reviewed numerous completed maintenance PM records. The records were obtained from the document control vault and had been completed by the craft workers and reviewed by their supervisors. The team detemined that some of the documents were incomplete in that information spaces on the docu-ments had not been completed with the required information. The documents discussed below contain examples of this proble (1) Appropriate licensee personnel failed to sign-off designated spaces, including hold points, to document work was satisfactorily completed on PM instructions PM-1-12-M-M-1, PM-1-12-M-M-2, and PM-1-12-M-M- These PM instructions were used by the craft personnel on October 7 and 10, 1988 to grease and inspect the bearings on salt water pumps 11, 12, and 1 (2) Appropriate licensee personnel failed to sign-off designated spaces, including field and engineering reviews, to document the work satis-factorily completed on PM instructions PM-1-24-M-Q-4. These instructions were used by the craft personnel on October 3, 1988 to grease a diesel fuel oil tank equipmen (3) Appropriate licensee personnel failed to sign-off designated spaces, f including a space provided to document wheth2r bolts were found loose or not, on PM instructions PM-1-24-M-2W-1 PM-1-24-M-2W-2, and PM-1-24-M-2W-3. These instructions were used by the craft personnel to L"
inspect diesel engines 11, 12, and 13 blower bolts. This inspection was performed by the licensee as part of the corrective action described in LER 81-7 These examples are an indication of' carelessness in completing documentatio [
The team was concerned that these examples of incomplete equipment history .
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could be a generic issue, which would inhibit licensee efforts to use thei,r
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equipri.ent history as' a tool to conduct meaningful root cause analysis of future equipment problem (UnresolvedItem 50-217/89-200-06).
2.2.5 Control of Technical Manuals-The inspection team reviewed the licensee's program for controlling, reviewing, and distributing the vendor-sup) lied technical manuals that were to be used by ,
plant personnel. The licensee 1ad 6pproved and implemented Calvert Cliffs instruction CCI 122E, " Control of Technical Manuals," to provide instructions ,
for controlling the turnover, receipt, distribution, and change of technical manuals relating to the components installed at Calvert Cliffs. The. team identified the following weaknesses in the licensee's program for controlling technical manuals:
(1) Paragraph V.B.2 of CCI-122E stated "When sending a technical manual to the technical librarian, the sender shall review the technical manual and any associated documentation and provide as much information as possible using the technical manual turnover cover sheets (attachment 1)." The teani '
determined that CCI-122E was not being followed because the technica librarian did not have turnover cover sheets for the technical manuals listed below: I (a) "Woodware Booster Servomotor," dated March 24, 1988, from warehouse-(b) " Lambda - Regulated Power Supplies (LQ-412-42341) " dated March 24, 1988 from engineering (c) " Target Rock Technical Manual (TM100-01-01) " dated Jaouary 13, 1989, source unknown (d) "American Wanning and Ventilation 184,* dated November 4,1988, from j engineering l
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(e) " Smoke Ejector, Super Van - Super Vacuum #2989," dated November 14, 1988, from storeroom ;
(2) Paragraph V.B.3F of CCI-122E stated: " Forward the manual to the GS-P and PE for technical review" and paragraph V.B.4 stated: "Within 15 working l
days of receipt,'the GS-P and PE shall return approved manuals to the '
technicallibrarianalongwith'thecorpletedattachment(2)." After reviewing the documentation available with the technical librarian and talking with the engineering technician who handled vendor manuals, the i l
team identified a total of 51 vendor manuals or changes:to these manuals that had not been technically reviewed. Some of these unreviewed manuals
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or changes dated back to 198 (3) The lice.nsee had not provided the engineering department any guidance detailing what the technical review consisted of and, on the basis of
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discussion with the technical review engineers, the engineers did not ,
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appear to be sure what was required to complete the technical revie ,
The failure to assure the proper review and control of vendor-supplied technical manuals.is considered an unresolved item. The team was concerned that these basic weaknesses in technical manual control may be symptomatic of-15-
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a highly troubling and suprising generic issue, particularly in view of the widespread attention the nuclear industry and the NRC have given to the related o provisions of Generic Letter 83-28 ." Required Actions Based on Generic Implications of Salem ATWS Events" (Unresolved Item 50-317/89-200-07).
2.2.6- Contro1~of Weld Rod The team observed selected weld rod control activities, reviewed related licensee documents, and discussed the weld rod control program with licensee personnel. The licensee had not implemented POSRC-approved procedures for assuring that the welding process was appropriately controlled. Baltimore Gas and Electric Company welding program procedures WPP 6.006, " Weld Authorization and Docu e ntation," Revision 9;'and WPP 6.009, " Control of Welding Filler Metals," Revision 10, were used to perfom welding process activities at the {
Calvert Cliffs Nuclear Power Plant. The team made the following additional findings related to weld material control:
(1) The licensee's document which delineated the requirements for filler l'
material control was shop / lab memorandum No. M-64. Revision 0, issued on February la, 1989, but which was not approved by the POSRC. Procedure CCI-222, "Calvert Cliffs Control of Welding Activities," which was previously implemented by the licensee, had been cancelled November 11, 1988. Therefore, between November 11, 1988 and February 14, 1989, the licensee did not have any approved uritten instructions for filler material contro (2) . A sketch was posted adjacent to each weld rod bake oven as an aid to help the attendant keep track of the type of weld rod available in the ove The: sketch depicted the location of each compartment in the oven and identified the type of weld rod being heated in each compartment. The team identified the three instances below in which the type of weld rod being heated in the oven appeared to be different from the type of weld ( rod identified on the sketch adjacent to the oven:
Identification on Sketch Actually in Oven Stellite 215L, 1/8" Ste111te 21 E 316-15, 3/8" E 316 L-15, 1/8" EV ICR-FE, 3/32" E 309 L-16, 1/8" (3) Shop / lab memorandum No. M-64 referenced procedures WPP 6.009 and WPP 6.006 f for providing instructions related to issuing weld material; however, these procedures were not available at stations that issued the weld
! materia (4) Shop / lab memo No. M-04, Revision 0 stated that "the toolroom attendant shall issue filler material in the following manner: The attendant shall complete the submittal filler material control tag (FMCT) and attach the
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hard copy to the rod container. The attendant and the welder to whom the issue is being made will verify that the filler material is the same type and size specified on the FMCT and will indicate this verification by their signature on the FMCT. At the end of the shift, the welder shall record the filler marial type, SRI tag number, Nuclear Class / Cod _______ _ __-_ - -
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, e quantity used, and heat number / lot number in the appropriate section of the MO in accordance with CCI-200."
The team determined that on back shifts welders were drawing rods without the tool room attendant being present and completing the tool room attendant's portion of the filler material control tag In addition on back shifts the welderr were attaching both the hard and soft copies to the rod containe (5) The inspection team reviewed the completed preventive maintenance (PM) and inspection card PM T-WRO-SA-53 for weld rod hold oven ST-1 located in the tool room. The team reviewed the documentation for the three previous times this preventive maintenance was performed and identified the following deficiencies:
(a) Revision numbers were not completed on the PM inspection card for the PMs conducted on February 22, August 17, 1988, and February 14, 198 Also, locations were not filled in on the PM inspection card dated August 17, 198 .
(b) The date for procedure reviewed was not filled in for the PM conducted on August 17, 198 ;
< (c) The preventive maintenance and inspection card " calibration data sheet" used for recording data for the PMs conducted on February 22 August 17, 1988, and February 14, 1989 was diffemnt from the calibration data sheet provided in the test equipment calibration o procedure M-TEC-7, Revision 2, which was the current controlling proce-dure for the calibration data sheet. This documentation indicated that the latest revision of M-TEC-7 had not been used at the time these PM activities were performed, resulting in the use of the J
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outdated for (6) Paragraph 7.0 of licensee welding program procedure WPP 6.009 specified I that the temperature in the weld rod oven should be maintained between l
225'F and 350*F. However, on March 28, 1989, the inspector observed that the thennometer on weld rod oven T-21, located near the intake structure, indicated 220*F. The inspector also determined from discussions with attendants at the weld rod issue station that the attendants did not know what the weld rod even temperature requirement wa Collectively, these findings indicate a lack of adequate management attention to the control of activities associated with welding processes. In particular, findings (1), (2), {3), and (6) above represent a series of highly troubling weaknesses when viewed in the traditional context of 10 CFR 50. Appendix B, Criterion IX, Control of Processes. Improvements in current welding program controls and in the implementation of controls already in existence appear to be essential. (UnresolvedItem 50-317/89-200-08).
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2.3 Quality Control Inspection of Maintenance Activities 2.3.1 Quality Control Inspection Program
The team inspected the licensee's program for performing independent
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inspections of activities affecting quality as required by 10 CFR Part 50 Appendix B, Criterion X. The licensee's qualitl control (QC) group perfonned this function.- The team observed QC inspection activities, discussed inspec-tion activities with licensee personnel, and revieweJ inspection-related documents. The team identified a major weakness % this area: the licensee did not have approved procedures or written Instructions for controlling, implementing, and documenting the QC inspections. Not having procedures or written instructions for controlling inspection activities was contrary to the Calvert Cliffs Quality Assurance Policy Section 1B.10. " Inspection," which
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stated that activities that affect the quality of safety-related and designated nonsafety-related items are inspected as specified in approved instructions, procedures,' and plans that specify requirements and acceptance criteria to ensure that work is done in conformance with particular requirement The team identified the deficiencies discussed below in the licensee's QC inspections and felt that the lack of written approved inr,tructions was a primary cause of these deficiencie * Because inspection activities were not effectively planned and scheduled, required inspections of activities affecting quality were routinely waived because QC inspectors were not availabl .
- Since no guidelines had been provided to the QC inspectors on what and how to inspect, the licensee relied on the inspector's judgment to ensure that i
the required inspections were performed, that they were performed correctly, that appropriate acceptance criteria were met, and that the inspections were adequately documente * On the basis'of interviews and observations, it appeared to the team that, genere'ly activities between QC inspectors and craft personnel took place
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I in an s p dient atmosphere; however, in some instances th two groups appeared to be adversaries. This adversarial relationship which appeared -
i related mostly to individual personalities, and the atmosphere in which pertinent questions may not have been asked, could not serve quality or safety well. The team told the licensee that they should take expedited c attention to improve this area to ensure that independent inspections are
$ not affected by interface problems between individuals or by an emphasis on production over quality or safety. (Unresolved Item 50-317/89-200-09).
2.3.2 Licensee Actions in Quality Control Area After being inforned of the team's findings in the QC area at the interim exit meeting on March 10, 1989, the licensee appointed a full-time QC project director and engaged a consultant to further evaluate and address the finding The licensee was also developing a procedures writing program in the QC area.
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2.4 Surveillance Testing 2.4.1 Scope of Review The team reviewed the licensee's surveillance testing and calibration control activities to assess the effectiveness of the existing programs. Such reviews were perfomed by directly observing licensee activities, reviewing the administrative guidelines governing program implementation, and interviewing personnel involved with surveillance activitie I 2.4.2 Surveillance Program Administration Calvert Cliffs Instruction C01-1041, Surveillance Tasting Program," established the responsibilities and administrative requirements for the surveillance testing program. The team reviewed CCI-104I and found that the responsibility for implementation of the surveillance test program was divided among various groups at the plant (e.g., operations, maintenance). The procedure specified that a single individual be responsible for the overall administration of the program;- however, the various groups independently scheduled, coordinated, and bore responsibility for their own surveillance activities. CCI-104I appeared to be very detailed and complex for the administrative nature of such a docu-ment. The use of lower tier group implementing procedures or.a more central-ized and consistent program could help eliminate implementation inconsistencies and diffused responsibilities that existed in the current program. The team
found that the licensee had identified this concern as an area needing improve-l aent, and substantive changes to the surveillance testing program were being made, but were not yet' implemented. The majcrity of surveillance requirements-related to the technical specifications were perfonned by the operations and 4 the electrical and controls (E&C) groups. One full-time individual was responsible for administering the operations surveillance test procedures (STPs). This individual's duties included coordinating and scheduling STPs and trending STP data. The ESC test program was administratively implemented by two key individuals, one coordinator and one schedule .4.3 Surveillance Test Procedures The team reviewed selected STPs for content and format to determine whether the procedures were adequate to accomplish the intended purposes. The STPs were G o reviewed to ensure that they conformed with the licensee's requirements
.- Tcr formatting surveillance procedures and other licensee commitments with l respect to preparation, maintenance, and implementation of procedures. The team also examined the technical content of STP STPs were written by a procedure development group associated with the responsible station group that perfonned the testing activities. The team found several fomat inconsistencies among the procedures reviewed, both within specific department STPs and among the different department STPs. CCI-1041 specified that the responsible surveillance coordinator ensure that STPs confom to the fomat outlined in Attachment 3 of Appendix 104.10 to the procedure. That format included: (I) General Precautions; (II, III) Subtitles (each subtitle followed by A: Initial Condition and B: Procedure);and(IV)
References. Many format inconsistencies existed such as variant nomenclature, different subheading fomats, and variations in the use of signoffs for completed L steps. The majority of station STPs contained performer initials and date n
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signoffs for procedure steps, while some only contained a block for providing checks for procedure steps. Some STPs had neither type of signoff to
. demonstrate that the appropriate step had been performed. CCI-104I did not provide any guidance on the use of signoffs in STP Procedure writer's guides varivi among the different procedure groups. Only
'the operations and instrumentation and controls procedure development groups maintained writer's guides. Those guides had been developed internally, were i specific to each of the two groups, and varied with respect to items such as
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fomat, use of signoffs, and use of section types. The licensee was pursuing the development of a site-wide writer's guide; however, it was not clear to the team that all groups m uld be affected by this new guide. (UnresolvedItem 50-317/89-200-10).
The licensee's quali< assurance policy documented a commitment to ANS-3.2/ ANSI N18.7-1976, " Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants." Section 5.3 of the standard, " Preparation'of Instructions and Procedures " provides requirements and recommendations regarding procedures for affecting safety at nuclear power plants. The standard stated that although procedure format may vary from plant to plant,
. procedures shall appropriately include such elements as statement of appli-cability, references, prerequisites, limitations end actions, acceptance '
criteria, and checkoff list The team found that although the majority of the procedure fonnat itesis were covered within the. licensee's STPs within the general section subheadings, acceptance criteria were not always clearly defined or identified as such in the STPs that the team reviewed. Since there were no separate acceptance criteria sections in the STPs, it was not always obvious which steps or activities in STPs implemented the technical specification acceptance criteri For some of the steps that were intended to meet acceptance criteria, accept-able ranges were noted in parentheses; however, others were not. For example, the surveillance requirements of TS 4.6.6.1.a required that ventilation flow through the filter and charcoal absorber is initiated, and the train operates for at least 15 minutes. STP-0-70-2, " Staggered Test of 'A' Train Components,"
Section IV, properly tests the system; however, the acceptance criteria referenced above were not identified in the STP. Similar examples wem found in other STP A separate acceptance criteria section would clearly identify which items or parameters were to be tested and the associated specific quantitative or qualitative acceptance criteria that must be verified in order to satisfac-torily test systems or subsystems. The absence of such a section was a contri-
-buting factor to a recent plant event in which the failure to perfo m a portion of a required surveillance test was not identified for several months. Speci-fically, on February 8, 1989, the licensee identified that since August 25, l 1988, three performances of STP 0-6-1, " Reactor Protective System Startup l Test," failed to perform the channel functional test of the manual reactor trip actuation required in the technical specifications. Due to an administrative error during reproduction, the last page of the STP, which contained the steps to perform the channel functional test, was lost. The STP fonnat did not delineate test objectives nor specific acceptance criteria in a separate section, therefore, non-technical reviews of the STP did not identify that a -
portion of the test had not been complete "
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The. team observed selected STPs throughout the inspection, the quality of i several procedures was found to be poor, especially the electrical and control procedure Three ESC procedures (STPs M-210B-2 and M-213-2, and PM 2-58-1-0 2)
were properly stopped by the technicians while the tests were in progress e because the procedures were both technically and administrative 1y incorrect i several areas. . Further review by the team identified that the same errors had existed in the procedures used during several- previous test perforinance ,
Quarterly preventive maintenance procedure 2-58-I-0-2, performed on March 1, 1 c 1989, contained a step to ensure that blocking bistables were tripped in the ;
steam generator isolation signal channel under test, when the bistables -
actually should have cleared. The last performance, December 20, 1988, was '
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also incorrect, but was change 6 using a temporary procedure change, as allowed by CCI-1041. All prior performances reviewed over the past several years contained that same incorrect step; however, the procedure was' signed off and approved as being satisfactorily completed without changing or correcting the procedure. Similar procedure problems were found with STPs M-2108-2 and
!- M-213-2. The two monthly STPs were found to have essentially the same procedural errors on previous performances. That is, each time the procedure was performed over the last few months, appropriate temporary changes _ were made, however, the~ procedures were not permanently corrected for subsequent
i perfomance, CCI-1041 allowed STPs to be changed several ways, including non-intent temporary procedure changes, which were required to be reviewed by the Plant Operations and Safety Review Committee (POSRC) within le days of implementation. Such a change had to be approved by twc senior operator
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license holders. CCI-104I specified that temporary changes which involved only the correction of obvious typographical errors, grammatical errors, and minor format changes (administrative changes) did not need to be reviewed by the POSRC. Only the work group supervisor was required to document conc' ence by initiating the temporary procedure change. The licensee most often used the administrative change process, although some technical inadequacies also appeared to'be changed inappropriately using that same process. Nearly all procedure changes reviewed by the team contained multiple procedure changes that had not subsequently been included in the pemanent procedure. Therefore, L different personnel performing subsequent tests using the same procedures were required to identify and resolve the same procedures deficiencies previously identified. (Unresolved Item 50-317/89-200-11).
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From observation and review of STPs', the team noted that the emergency diesel i generators (EDGs) were started a relativcly high number of times each month for surveillance testing. Specifically, during routine testing, each of the two dedicated EDGs were started four times.a month, and the swing EDG was started eight times a month. Several additional engine starts occurred because of post-maintenance testing requirements. Further, the team noted that~all starts were st starts (to full-load engine speeds) preceded by a pre-lubrication sequenc The team reviewed the maintenance and surveillance section of the EDG technical manual and found that the vendor recommended one start a month by startirg the respective EDG to idle speed (300-500 rpm),andthentogradually increase engine speed to 900 rpm within 1 to 2 minutes. The team found that there was no justification for deviating from the vendor's recommendation The team felt that the area of evaluation and incorporation of the l- recommendations made by the vendor in its technical manual required further-21-
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licensee attention to determine whether there were programmatic weaknesses in ]
this area. This item is considered uresolved and is related to Unresolved j ltem 50-317/89-200-06 described in Section 2.2.5 of this report. (Unresolved j Itom 50-317/89-200-12).
The industry average for EDG starts per year was about 50; Calvert Cliffs EDG starts approached an avusge of 150 a year for each EDG. Excessive EDG starts could lead to unnecessary wear of EDG components. This concern was brought to the licensee's attention; the licensee stated that it had initiated efforts to resolve the concern. The principal reason for the large number of EDG starts was due to not having the. capability to test the safety injection actuation signal and undervoltage relay contacts in the EDG starting circuitry without starting the EDGs; however, this condition had existed since initial plant operation in the mid-1970's. Station modification field change request (FCR)
No. 88-0034 was recently initiated to modify the circuitry to allow contact testing without starting the respective ED .4.4 Surveillance Test Observations The team witnessed or reviewed selected surveillance tests to deterinine whether properly approved procedures were in use, procedure details were adequate, test instrumentation was used properly and was within its required calibration cycle, testing was performed by qualified personnel, technical specification limiting conditions for operation were met, systems were properly restored to service, and test results satisfied acceptance criteria or were properly dispositioned. The team members witnessed the following surveillance tests being performe !
l STP No. 0-5-1-1 Auxiliary Feedwater System Test," performed on March 27,1989(procedurereviewonly)
STP No. 0-7-1, * Engineering Safety Features Logic Test," performed on March 6, 1989 STP No. 0-8A-1, "11 Diesel Generator and 4 kV Bus 11 LOCI Sequencer
. Test," performed on March 6, 1989 i STP No. 0-70-2, " Staggered Test of ' A' Train Ccmponents," performed on March 1, 1989 STP No. 0-23E-2, "ECCS Pump Performance Test," performed on March 7 1989 f
l STP No. 0-98-1, " Containment Hi Range Monitors Monthly Test," ,
) perforined on March 1,1989
j STP No. 0-100-1, " Main Steam Effluent Radiation Monitor Functional Test," performed on March 1, 1989 STP No. M-210B-2, " Reactor Protective System Function Test," performed on February 26, 1989
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STP No. H-213-2, " Calibration _of Power Range Nuclear Instrumentation by Comparison with Incore Nuclear Instrumentation,"
performed on March 3, 1989 STP No. M-350-1, "#12 Station Battery Quarterly Check," performed on December 29, 1988 (procedure review only)
STP No. M-521-1, "ESFAS Response Time Test," performed on i March 27, 1989 PM No. 2-58 I-0-2, " Steam Generator Pressure Loops (Cleaning of Resistors Developing Signals to RPS and ESFAS),"
performed on February 20, 1989 peformed in conjunctionwithSTPNo.M-210B-2)
The team found that the majority of licensee personnel involved with surveillance testing activities were generally competent and professiona However, several deficiencies were identified which indicated that increased licensee. attention to this area was necessary. In one case, testing activities were rushed to the point that the activity had to be repeated to ensure satis-factory results. Procedural deficiencies appeared to compound the confusion experienced during that process. Another deficiency was that during perfom-ance of STP 0-7-1, "ESF Logic Test," the operator quickly performed a repeti-tive sequence on four separate instrumentation channels witbut reading each step to the person actually performing the activity. Approximately 10 steps were then quickly signed off following the activity. The operatirs subse-quently confimed that all steps were satisfied after questioning by the team member. It appeared obvious that the operators involved with the test were familiar with it and therefore, did not pay strict attention to the procedur A third example occurred on March 19, 1989, whenaninadvertentUnitIsafety).
injection occurred during the performance of the same STP as above (STP 0-7-1 The licensee attributed the root cause of the event to be the failure of the operator to follow the procedure step-by-step when reinstating a pressurizer pressure safety injection block signal. The operator. knew that the block signal nieded to be reinstated, and proceeded to adjust the associated poten-l tiometer setpoints without referencing the procedure which was at the job site. The procedure contained two other ste the block signal and one verification step) ps (one to to be performed remotely prior reinstate to adjusting
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the potentiometer.
I I Such problems indicated that increased attention regarding compliance with and i
attention to procedures was necessary. It appeared that ifcensee personnel were not deliberate and methodical in routine and repeated activities to the extent that some activities were performed by memory, rather than by procedure adherence, even though these procedures were required and necessar .4.5 Calibration of Permanently Installed Plant Equipment The team reviewed the licensee's program for scheduling and calibrating permanently installed safety-related equipment used to measure system perfor-mance. Calibration of such equi
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I the preventive maintenance progra (PM)CCI-211I, pment"PM was Program" scheduled (Novemberand27, controlled b 1 1988) defined the overall station PM requirements and policies. The overall
. responsibility for the PM program was assigned to the nuclear engineering x-23-l- _ ---- _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ __ -
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services (NES) department. However, responsibilities for the various PM functions were shared among various plant group The E8C group calibrated permanently installed plant equipment such as gauges,
. transmitters, indicators, and recorders. Many of these instruments performed safety-related functions; however, plant technical specifications did not require that they be calibrated. These locally and remotely located instru-ments served as the bases for ensuring that systems and subsystems were in conformance with TS liniiting conditions for operation. Proper calibration for the above instrumentation was therefore necessary to provide adequate confidence that test results were accurat ANS-3.2/ ANSI N18.7-1976, Section 5.2.6, specifies that records shall be made and equipment suitably marked to indicate calibration status. In the past, the licensee placed different types of stickers on installed equipment to show calibration status (calibration date, due date, calibrator); however, the use of stickers for installed equipment was discontinued about 1980. -The licensee i subsequently began to use calibration stickers in 1987. The team observed four different types of calibration stickers being used in the plant and the information noted on the different types of stickers was inconsistent. Many instruments did not have a calibration sticker attached to the The licensee's surveillance test procedures (STPs) directed the use of
. permanent plant instrumentation for obtaining information to verify system operability. The surveillance test procedures reviewed by the team did not contain steps to log the calibration performance dates or calibration due date for the instrumentation that was used for the test. Additionally, there was no master calibration schedule which cross-referenced instrument numbers, calibra-tion perfomance dates, calibration due dates, or calibration frequency. The team noted that the surveillance program relied upon proper performance of the PM program to assure safety-related instrumentation calibration. This situation was a potential programmatic weakness since the lack of a master calibration schedule or matrix containing pertinent calibration information, the inconsistencies with respect to the calibration sticker process, and the l lack of a calibration verification on installed instruments referenced by STPs
did not permit a readily accessible mechanism for verifying the current status of instrument calibration and system operability. (UnresolvedItem -
50-317/89-200-13).
2.5 Corrective Action Programs f
2.5.1 Scope of Review Corrective action programs were inspected for their effectiveness i identifying problems, analyzing root causes, and detemining the adequacy, timeliness, and management involvement in corrective and preventive action This review focused on the licensee's three primary means of identifying items requiring some fom of corrective action: quality assurance audits and program evaluations, nonconformance reporting, and corrective maintenance request l 2.5.2 Quality Assurance Audits and Program Evaluations In the area of quality assurance audits and program evaluations, the team found the audits and evaluations performed by the licensee's quality auditing group to be generally thorough and effective in identifying specific areas of concern-24-
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in need of corrective action. The team interviewed a number of auditors and found all to be quite knowledgeable in their particular area of expertis However, it did not appear to the team that adequate or timely corrective and preventive actions had been taken by licensee management in response to certain findings and recommendations contained in these reports. This weakness was
, evidenced by the period of time some findings had remained open, the appearance of the same finding or a similar finding in a subsequent audit, and the team's identification of continuing problems in certain area One particular example of this weakness lay in the area of quality control (QC). .An evaluaticn of the nuclear maintenance department's QC program conducted in January 1988 documented weaknesses that existed in the QC program with regard to the planning of QC inspections, inconsistency in the implementa-tion.of inspection criteria, and the training of inspector In February 1988, quality assurance audit No. 88-38 of initial and continuing training of mechanical maintenance, modification and maintenance QC personnel again identi-fied that policy and procedures had not been established to define responsi-bilities and training requirements for the QC function. The team's observation during this inspection with regard to the effectiveness of the QC inspection program confirmed a continuing lack of a well-defined role for Q .5.3 Nonconformance Reporting The team reviewed selected nonconformance reports (NCRs), both open and closed, and identified what it judged to be poor responses to some deficiencies identified through this process due to the untimeliness of the responses, poor analysis of the root cause of equipment failure, untimely bounding of safety significance, and sometime superficial or simplistic corrective and preventive action This weakness was illustrated in the respona to NCR 7137 concerning failure of the No. 22 containment spray pump motor in June 1987. The NCR did not receiv final disposition for almost a year following the failure, and the related documentation did not appear to justify the only stated root cause of failure was lack of lubrication for the motor bearing. The only corrective or preven-tive action taken was to remind operations personnel of the importance of monitoring proper motor bearing oil level. The untimely and limited corrective action for this NCR gave the team the impression that the licensee did not appear to appreciate the safety significance of the failure, apparently (
considering the event relatively insignificant because the redundant contain- J
ment spray pump had remained operabl The team also identified a number of concerns with the handling of NCRs, 7124 I
7126, and 7234, related to the installation of a non-qualified air regulator on auxiliary pressurizer spray valve 1-CV-517 in May 1987, and the subsequent determination by the end of September 1987 that other elastomers used in the valve and other similar valves in both Units 1 and 2 were also not qualifie ;
Of particular concern was the apparent untimely bounding of the safety signifi-cance of these deviations from original design requirements with a formal
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justification fo- continued operation. Such formal justification was not i prepared until April 1988 following a quality surveillance which questioned whether or not an adequate safety analysis had been performed, and if the deviations had been evaluated for potential deportability to the NR )
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.The timeliness;of the evaluation of NCRs and other potentially reportable event < was determined by the team to be a weakness which the licensee had also identified in a number of audits over the past year. The licensee had created a Deportability Task Force to deal with thase issues. By the end of this inspection,.the licensee had just begun to implenent some of the task force reconnendation The team observed instances in which it appeared appropriate for an NCR to have 1 i
been initiated by licensee personnel. In a few cases, this was not done or J appeared to have been done only after a team member prompted the licensee to do so.. The tean, concluded from these experiences that the NCR system was not being fully utilized by all personnel within the licensee's organization to~
ensure the prompt identification and evaluation of potentially significant conditions adverse to qualit .{
2.5.4 Corrective Maintenance Requests The team reviewed records of approximately 50 corrective maintenance aquests completed within the last 6 months. These were identified through the use of the licensee's integrated corrective action program (ICAP) data base. The ICAP
- data base was designed to provide the capability of analyzing trends in equip-ment failures. In discussing the capabilities of this system with licensee personnel, it became apparent that this system was still in the developmental stages although it had been in existence for nearly three years. The system apparently had received limited use with most requests for information having been reactive as opposed to proactive in natur The team revie n d selected maintenance requests and detected a discernible trend with regard to the' functioning of the safety injection tank level indica-tors as evidenced by a.need to perfonn frequent calibrations and an apparent problem with excess leakage from the Unit 1 injection tanks. The team deter-mined in followup discussions that the responsible system engineer was know-ledgeable and aware of this problem. The system engineer provided the team with a-previously developed action plan for correcting the problem. A team member observed the implementation of portions of the license <'s action plan, t
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including the disassembly and inspection of a number of valves in Unit 1 for .
signs of excessive wea The team reviewed maintenance records and determined that in general the ,
' records of maintenance activities were frequently sketchy. This situation made'
the determination of trends or the comparison of certain maintenance activities -i
.to previous ones difficult, thus potentially undercutting the effectiveness of this program.
L l For a discussion of examples of incomplete equipment history records, see Section 2.2.4 of this repor . 1
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3.0 Management Effectiveness Review 3.1 Scope of Review The objective of the management team was to assess plant management's effec-tiveness in planning, organizing, staffing, directing, and controlling the operation of the facility. The team conducted approximately 320 person hours of
' interviews with management and staff at all levels and in all department In addition, the team performed limited observations of plant and control room activities, reviewed programs and events, and observed on and off site review committee meetings. _The team emphasized in its evaluation the . identification of management related root and contributing causes of re:ognized fundamental problems affecting safe reactor operation. Because of thin apparent subjective nature of the findings in the management area, with itt emphasis on human versus engineering.perfomance, the team sought to substantiate apparently subjective findings with objective perfomance indicators to the extent possibl .1.1 Management Team Composition and Methods The management team members were specifically selected to bring a balanced approach to the inspection by making use of diverse academic and occupational backgrounds in nuclear plant senior management, operations, training, indus-trial psychology, management science, organizational design, and inspections and regulatory complianc The team developed a model and method with which to focus the evaluatio The team first assassed the structural and design requirements of the organ-ization ' focusing on culture, communications interfaces, strategic planning for resource requirements, work and business goal setting, and performance ( monitoring and reportin After determining and evaluating the organizational structure in which work was performed, the team inventoried and evaluated the management and leader-ship skills available amon the managers and plant staff. This second phase I focused on management know edge as a separate academic discipline, organiza-tional climate, human relations skills, leadership and supervisory effective-
.- ness, staffing quantity and quclity, and operational knowledge and experi-enc The team then evaluated management effectiveness as applied and practiced in
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the operation of the facility, focusing on planning and scheduling, change
! management, quality programs, communications effectiveness, resource alloca-( tion, priority setting, and operating philosophy. The team factored 17to its l- evaluation management's perfomance history, use of state-of-the-art manage-
' ment tools, systenis, and processes, the handling of safety concerns, and the l
plant's regulatory relationshi .2 Organizational Structure The team evaluated the licensee's chosen organizational structure without attempting to determine whether that organizational structure was the most appropriate for the facility. The team concentrated on the identification of-27-
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the attributes necessary to operate effectively within the chosen model and the evaluation of those attribute .2.1 Requirements for Organizational Effectiveness The licensee's organization in place at the time of the inspection was a complex project management matrix design known to present special challenge Unlike traditional vertically aligned organizations where individuals are likely to have functional authority that is generally commensurate with the responsibilities that person must discharge. in the matrix design there is virtually no one below the level of plant manager with sufficient authority to accomplish objectives without having to negotiate and share resources with others in the organization. Although very few had the word " manager" in their titles, many persons had management responsibility for completing projects, requiring the application of specialized project management and leadership skills as prerequisites to successful completion of their assignment The team concluded that licensee management and staff at all. levels of the organization had not identified or addressed all of the special challenges presented by the complex matrix design. The organization was found to be weak in the following attributes.
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o A shared vision of clearly communicated and consistently demon-strated organizational goals and objectives, o Extensive sharing of information u An integrated, site-wide planning and scheduling system o A demonstrated understanding of the interdependence of furetions o A layer of middle management that was effective at translating for workers the broadly stated policies and goals of management into meaningful performance expectations and work habit o A number of licensee persons interviewed appeared to not grasp that in the chosen matrix design virtually every site activity, no matter how small, was a project. Although the majority of each person's work contributed to a project, the team found the following attributes of effective project management to be generally deficien o The Project Management Manual did not provide a readily understood definition of functional responsibilities or accountability (owner-ship)withintheorganizatio o The facility's lack of a site-wide planning and scheduling system was found to impede the distribution of shared information. Success-ful project management requires all participants to be informed and
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communicatin o The team found little evidence of conflict management being recognized as a management skill to be used or develope .
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o Accountability for project completion was found to be diffused throughout the organization and generally was not clearly defined for the affected participant o The cultural factors of trust and respect, key ingredients in negotiation and shared objectives, were found to be absent in some Case .2.2 Organizational Dynamics The: team concluded that the liensee's organuation was, in effect, horizontally divided into three separate operating entities, each functioning more or less independently and divided horizontally by barriers of communica-tion, philosophy, and attitude. The team also identified vertical barriers to cooperation and communication between department j The three managers (Plant Manager and Managers of Quality Assurance and Engineering) comprised the management entity below the Vice President Nuclear Engineering Division. The team determined that in order to function effec-tively within the organizational structure the managers would be the major architects of policy Would be a source of Clearly understood expectations in terms of broadly stated organizational goals and objectives, and would strate-gically plan, organize, staff, direct, and control the site's activitie They would be the source of management guidance that demonstrated a safety-oriented operating philosophy, would convey clearly defined perfonnance expectations, and would provide leadership by exampl The team concluded that, rather than demonstrating an operating style that emphasized safety and quality, the managers have been a source of mixed I messages that demonstrated a production bias. This emphasis was a major contributor to the cultural evolution of corner-cutting and procedural noncompliance among workers. The managers were generally not recognized by i subordinates for their leadership skills. Managers were determined to be l generally lacking in their ability to recognize and manage change, and were generally unaware of the attributes of a positive regulatory relationshi Having remained relatively isolated, with little infusion of managerial techni-ques, philosophy, or a nuclear safety orientation from the rest of the nuclear industry, the team concluded that the managers lacked a clear understanding of c
how to correct the fundamental causes of their problems as well as the identi-fied syiaptoms.
[
I Tne team determined that the secand tier of management, the General Supervi-sor (GS), was effectively separated from the managers above and the workers L
! below. Rather than translating management's strategic goals and policies into work practices and expectations, the GS group was found to be the enforcers of an operating style that emphasized production over safety. Rather than focusing management's stated goals and policies, the 65 group tended to J act as a filter. Subordinates were consistently unable to readily identify, with one notable exception, any member of the GS group who was recognized as a leader. Interview results indicated that the GS group gendrally had a limited understanding of the special requirements for effective management imposed by the matrix structure. Organizationally, there has been little infusion of new personnel into the GS group, and the team concluded that the benefit to the-29-
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plant of rotational assignments within the GS group could be enhanced by exposure to how activities are managed in other nuclear plant The work force below the GS level would, in the organizational hierarchy, be tasked with accomplishing work necessary to meet defined performance objec-tives. The team concluded that they have been effective at keepir:g the plant maintained and operating in spite of organizational connunications barriers, inadequate and uncontrolled procedural guidance, an ineffective quality control )
(QC) organization, and limited resources in the form of manpower, qualified .J parts, or technical information. Faced with an operating style that has i effectively told them to do what was necessary to keep the plant on line i and generating, and offered little and at times, confusing guidance in the form I of prioritization, planning, or quality and safety orientation, the work force l was found to have operated out of a posture of not pennitting procedures, quality control, technical requirements, or administrative controls to impede their support of production. The team concluded that very little of the stated goals and policies had filtered down to the workers, leaving a frustrated desire for guidance and direction. To paraphrase several persons, workers
"wish they (management) would just tell us what they want."
The team examined the organizational relationship of the Vice President (VP)
to the three managers. The new VP, who was clearly still in the process of becoming familiar with the facility and staff after having assumed his new ,
duties approximately one month prior to the inspection period, stated his perception of his role and relationship as one of a corporate officer with an office on site as opposed to a site manager who is also a corporate office The VP stated that he did not feel it appropriate to routinely interject himself into situational events or operational decisions, preferring instead to allow his managers the freedom to exercise their individual and collective judgment. The team expressed a corcern that, in the process of reversing the plant's declining performance tend, an evolutionary approach would be pursued where a more expedited and ditect approach would appear to be warranted.
I The team concluded that the terms and conditions under which work was accomplished in the organization were being developed by default at lower ,
! levels of the organization. Persons at those levels were developing their own J performance standards and expectations based on their perception of an operating philosophy which stressed production. Perfonnance problems such as
procedure noncompliance, operational events, ineffective QC, and inadequate and f uncontrolled procedures were considered to reflect a work force striving to l deliver good perfonnance without adequate guidance or resource .2.3 Cultural Considerations During interviews licensee personnel regularly pointed to "our culture" as an explanation of why certain attitudes and practices prevailed. Although few among plant management or staff were able to define the ters, many were able to describe to the team cultural characteristics of the organization which impacted directly on the way in which business was conducted at the plan The- team concluded that although management was able to identify cultural symptoms, they did not appear conversant with what culturally based operating l philosophies were in place within the plant departments. Attempts to redefine the plant's operating philosophy, and in the process redefine the cultural l
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environment, appeared to have been focused on a poster campaign under the theme
" Challenge 89," which portrayed to workers an operating philosophy which <
assigned a high priority to safety and quality. Plant workers expressed their !
skepticism about Challenge 89, noting other poster initiatives (as recent as 1982-83) in which management's actions were not consistent with the philosophy being promote During the inspection management continued to send conflicting messages to the work force. For example, workers thought it conservative to shutdown the plant on March 8 for feedwater regulating valve repair and test, but the traditional production bias was reinforced when on March 9 management elected to startup with an unisolable pinhole leak in a steam generator blowdown line. Management also appeared not to have described their rationale for ordering the startup to the work forc The underlying cultural values and ideals appeared to include:
o a "get it done" attitude that supported production to the detriment of procedural adherence or appropriate administrative control o a message that said " don't spend too much to get it done," adding to the tendency to cut corner o A message that said " don't cause trouble by questioning management" or doing things that might impede productio In addition to these prevailing values, the team identified certain operating styles which had evolved among various groups. The control room staff, for example, had developed an operating style in which licensed personnel assumed personal responsibility for plant safety without regard for the prevailing
! philosophy being promoted by management. Operators apparently came to think of I themselves as being successful in spite of, rather than because of, plant management, maintenance, I & C, QC, systems, design, and fuels engineers, and regulator Meanwhile, among maintenance personnel a results-oriented operating style evolved in response to the production emphasis. Craftsmen responded to l
austerity programs by doing more with less and, were intolerant of administra-tive, technical..or quality control which appeared to impede accomplishment of the tas In the Quality Control (QC) organization, no defined operating style existe Quality Control until recently lacked a clearly-defined organizational home and l
defined mission, its function.and responsibilities having been absorbed under the Maintenance Department's incompletely implemented peer evaluation program, inspection procedures were found to be nonexistent and the technical skills of l inspectors were not widely respected by the crafts.
l The team could not identify a cohesive operating philosophy that applied to the engineering department, perhaps because the four distinct engineering groups on site (system, project, design, and fuels engineers) appeared to l function as separate entities under two departments. Cultural considerations which impacted the engineer's effectiveness included a lack of respect among operators for the technical skills of the relatively young and inexperienced
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system engineer group, an opinion which has been improving over time, and the lack of respect for fuels engineers, an opinion which has not been improving nver time. Design engineering continued to be considered a " black hole" by those in need of its services, although the team found evidence that the GS for Drsign Engineering has taken steps to address this concern. In short, comuni-cations barriers within the engineering department and between the engineers and their customers impeded the effectiveness of the grou .
The following observations relate to the climate in which work was perfonne o With the production orientation found throughout the organization, the team concluded that teamwork was considered by the plant staff to be doing that which was necessary to support operations rather than working together toward a shared safety or performance objectiv o The organization was found to be without a clearly defined vision of the present or future, and was operating from a reactive rather than a proactive mode. Placement of the plant on the NRC watch list, discom-forted many of the plant staff, who expressed a desire to return to the pre-1985 era when CCNPP was universally perceived as a good operator. Some denied any decline in perfonnance, others were quick to assign blame to regulators, but the majority of the plant staff appeared to have accepted that their performance was not as good as they had once assumed. The plant staff was generally unable to identify how, why, or when performance slipped or what each individual could do to contribute to plant performance improvement o The work force indicated to the team a willingness to take the necessary l actions to return to excellence, but generally could not identify the source of management leadership necessary to constructively channel that energ o Many non-degreed persons were found to be frustrated by what they per-ceived to be a limited career path. The team found some indication that educational. assistance, lateral assignments, and advancement were avail-
- able but were not perceived as viable options by some worker o The team found only a limited sense of urgency or aggressiveness in addressing problems once identified, creating frustration for those staffers who sought management deci= ions and problem resolution. How-(~ ever, for problems affecting plant operability, such as a technical specification action statements, the team concluded that there existed an intense unity of purpose and spirit of cooperatio o The team concluded that an incident in 1988 involving the death of a plant worker was and continued to be a significant emotional event at all levels of the organization. Unlike the other operational events of concern to regulators during that same period, the fatality' appeared to be the single event that forced many workers to gruogingly acknowledge that problems existe .
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J 3. Procedure Problems In light of the significant operating events in which inadequate procedures i and procedural noncompliance has been a root or contributing cause, the team 1 .was particularly concerned about the low regard for procedures found through-out all groups. Problems associated with procedure misuse, control, and quality were considered by the team to represent a significant impediment to operational safety and performance at CCNPP. The following selected quotes gleaned from management and plant staff interviews were considered by the team to offer insight into the cultural aspects underlying the plant's problems with procedure o "We considered procedures to be guidelines and noi nard and fast rules."
o "We had a history of taking liberties with procedures; it was a cultural problem."
o "Our procedures were not very good and in order to get the jobs done, we had to ignore procedure steps; this led to a complacent attitude toward-procedure adherence."
o "We didn't always think we needed procedures; some of us thou5 h t they interfered with our workers thinking things out."
o "We were able to run the plant safely and effectively in the early days without procedures because we had a highly skilled staff. Since then our skill level has been diluted." ,
o "We took pride in doing the job with the resources available and doing it on schedule. Schedules were more important than quality."
The team noted that the plant staff tended to speak of procedure problems in the past tense. In fact, during the inspection the team was unable to identify any recent significant improvement in procedure quality or compliance, even
. after. management edicts that procedures would be followed without exception.
>" For example, on March 20 a control room operator in the process of returning an Emergency Safety Features Safety Actuation System cabinet to service skipped two steps in the procedure, backtracked through the procedure to reinitiate the sequence, and inadvertently initiated a partial safety
[~ injection system actuatio Management's action to resolve perceived shortcomings in the quality, control, and use of procedures was limited to guidance requiring compliance with proce-dures known to be-inadequate.and a hastily developed Procedure Upgrade Action Plan (PUAP). The PUAP is described elsewhere in this report. The team concluded that licensee management had an incomplete perception of the extent of the problem and its potential for adversely impacting safety. sThe problem .
was exacerbated by the observed lack of understanding among plant staff and &
management of the characteristic attributes of a high quality procedure, how it should be modified while preserving its safety integrity, how it should be administrative 1y controlled, and how thoroughly it must be performe l
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3.3 Management Processes 3.3.1 State-of-the-Art Management Processes Many state-of-the-art managerial and administrative tools and controls were found to be absent at CCNP o Procedure control was found to be virtually nonexistent. Controlled copies were not explicitly identified, and every co)y was considered a controlled copy although there was no effective mec1anism for ensuring the current approved revision was in use. Copies in use in the field or staged at workstations were not always complete or explicitly identified as being controlled. Examples of inadequate procedure controls are discussed in Sections 2.2.6 and 2.4.3 of this twpor o The temporary procedure change process was found to be cumberrome, particularly in the maintenance department. Once identified, months were .
required to correct a procedural deficiency, a delay which complicated H workers attempts at verbatim compliance. In the case of some monthly surveillance, for instance, the team found examples where a technician l who identified a procedure deficiency in the first month would obtain i approval for a one-time change to complete that perfonnance. When the
procedure was used in the second month, the defect would still be in the procedure, but.not flagged in any way. If the technician identified the defect, another one time change could be processed, but not a pennanent change. This cycle appeared virtually unlimited. Prior to the emphasis on verbatim compliance, these defects were ignored or bypassed, but the I new emphasis on compliance revealed the need for a mechanism to promptly correct procedure deficiencie o The procurement of safety grade spare parts having the appropriate documentation from the vendor or certification resulting from an engi-neering evaluation was found to complicate the efforts of technician For example, after a fire in a switch in the unit 2 control panel, repairs were delayed due to parts availability such that to start the plant up on schedule would have required removing the same switch from the shutdown unit 1 panel. On one day of the inspection, electrical maintenance supervisors detennined that there were no documented safety grade fuses in stock and the failure of any installed fuse would have meant the inability to repair that component. There was no apparent effective engineering
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involvement in procurement and support from engineering was found to be insufficien o There existed no administrative mechanism to handle minor modification Even small changes received a full engineering evaluation and formal 10 CFR 50.59 processing, resulting in extensive delays to accomplish '
minor modifications. This administrative hurdle was thought to contri-bute to a tendency to modify the plant without processing the change as a modification. Several workers described how they had added loads to busses or modified piping systems or components without obtaining an engineering evaluation or approval, and without documenting the altera-tion in manuals or drawings. The team was concerned with the implications of these statements for the plant configuration. (UnresolvedItem
. 50-317/89-200-14).
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o The absence'of computerized, networked data bases was conspicuous. One innovative GS was developing an infomation base and had ordered work stations. .The Nuclear Infomation Planning System which was near imple-mentation was expected to contribute significantly to the availability of a computerized, accessible data bas :
o Vendor manual control was found to be ineffective. Vendor manual control deficiencies are described in detail in Section 2.2.5 of this repor ,
o The quality of procedures used to implement or perfom maintenance or surveillance were found to be representative of that found in plants a decade or more ago. Cautions were few, acceptance criteria and the use of QC hold points and sign-offs were rare, and there was no mechanism to 1 incorporate the as-found conditions or repairs into machinery history or ,
trending program o Maintenance procedures wen found to be not sufficiently detailed to ensure quality. For example, a procedure to inspect and replace as necessary the fuel injectors on the emergency diesel generator simply j referred the technician to a technical manual which was four inches thick I and uncontrolled without guidance on which portions were required. The team briefly examined two new maintenance procedures prepared by contrac-tors which appeared to contain state-of-the-art instructional text, visual aids, and requirements. The contrast between the two new procedures and the hundreds of others in use at the station was strikin o The programmatic controls nomally associated with a number of the criteria _ of 10 CFR .50, Appendix B, appeared to be absent, illustrating the l extent to which the plant has remained isolated from industry advance j Specific deficiencies associated with QC are presented in Section 2.3 of this repor .3.2 Leadership Demonstrated effective leadership was considered by the team to be a crucial !
incredient to the licensen's efforts to return to excellence. Leadership i
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l skills must be distributed throughout the organization in a successfully l performing matrix structure, where functional authority is dispersed and people
'- must rely on their ability to negotiate, their ability to effectively comuni- 4
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cate ideas and expectations, and on their interpersonal skills. Active leader- !
l ship among the executive team members was considered to be particularly important, if the needed changes at the facility were to proceed at an urgent, i rather than an evolutionary pace. The team observed that outside of the new VP and the new GS for QA there were few leaders identified as such by the work '
forc l 3.3.3 Staffing and Personnel Qualifications ]
Since achieving comercial operation for both units in 1977 with a staff of less than 100, CCNPP has increased in site staffing to beyond 1000. Corporate management has indicated a willingness to fund additional positions in response to being placed on the NRC's watch list, and sid-level managers in maintenance and Oc were searching for. qualified persons to supplement their existing staffs. The team concluded that the plant staff was, in general, sufficiently
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large to safely operate the facility if management provided the appropriate systems, processes, and controls to effectively plan, prioritize, and perform wor The ability of the plant's highly stable work force to operate and maintain the facility over several productive and relatively event free years offered evidence that the technical competence of the plant staff was adequate. The team focused its concerns more on the apparent skills of the executive team members and the 12 GSs. The team determined that among the four managers comprising the executive team, there was relatively little exposure to nuclear plant operation. The team concluded that the executive team did not always display a full appreciation for the special treatment required by a nuclea '
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facility. Among the GSs. the team determined that the group has consisted of essentially the same individuals for about a decade, which includes the period of declining performance. There have been several rotational assignments within this group. While the team felt confident that the required level of l technical knowledge was present, the team was not convinced that the GS group !
had yet developed the managerin1 skills to reverse the declining trend at the facility. Of particular concern to the team was the inability of most middle managers to define the causes of problems, or to connunicate how they intended to improve their effectiveness in addressing the plant's difficulties. The team identified the need for fresh input from competent managers or advisors familiar with current industry standards who could bring to the facility a perspective gained by direct exposure to other effectively managed, safely .
operated and maintained nuclear plant .3.4 Training and Development The team determined that formal training in management skills was not provided for newly appointed supervisors. The lack of emphasis on training in managerial and leadership skills appears to extend to senior managers and ;
supports the team's concern that the licensee did not generally recognize
" management" as a discipline apart from engineering, with a complimentary set of skills to be learned and develope .4 Management Application and Practice l 3.4.1 Change Management ,
An underlying contributor to many problems affecting the CCNPP was the apparent inability of management to effectively manage the consequences of change occurring within or imposed upon the organization. Their past approach was considered by the team to have been reactive and overly simplistic, proceeding directly from identification of a problem to implementation of a solution with a lack of the intennediate steps associated with effective implementation of the process. The problem has been exacerbated by the licensee's tendency to limit the proposed solution to adding the problem to a list of action items, resulting in the generation of uncoordinated, unprioritized lists of action items. Attributes generally absent from the process, the team observed, included comprehensive issue identification, assignment of responsibility for results, resource connitments, implementation planning, feedback, and followu '
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Examples which concerned the team included: (1) the way in which QC activities were directed to be absorbed into the maintenance group using an intended peer evaluation concept, with a subsequent transfer back to the QA organization, a series of transitions that appeared to have contributed to a weak, unstructured program; and (2) the transfer of the engineering organization from Baltimore to the site and subsequent development of the System Engineer system using mostly young, inexperienced engineers lacking familiarity with plant systems and credibility among the plant staff. Both of these initiatives. suffered from inadequate planning, a simplistic view of the change process, and a failure to
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visualize the impact the change would have on the facility and the individuals involve .4.2 Performance Management The licensee was found to rely heavily on management-by-objecthe (MBO), a process th.;t is more difficult to effectively implement in the matrix organiza-tion than in the traditional structure because of the diffusion of account -
ability and ownership of projects throughout the organization. Managers have difficulty objectively measuring a subordinate's success when that subordinate seldom has the authority needed to satisfy the objective. Project management ,
effectiveness could be enhanced through wide recognition that virtually all I site activities were projects, no matter how small. Performance objectives that evaluated an' individual's contribution to projects which that person leads or supports were not eviden The consistent theme heard in nearly all interviews with individuals from i
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throughout the organization was that management essentially left workers to their own devices to channel their energy, to plan and prioritize their work, and to make personal interpretations of how each could make a contributio The work force gave a clear message to the team that management has not been effecti a at conveying clearly defined performance expectation .4.3 Management's Emphasis on Production l
The team concluded that in the past, management had, demonstrated an operating <
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style that emphasized production relative to quality and safety. Management had conveyed, through their actions, several important messages to the work l force, o Although management had sponsored several performance based self- {
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assessments, the poor record in correcting identified deficiencies left q l the work force doubting management's commitment to accomplishing safety a '
performance improvements. The team reviewed the licensee sponsored Safety
System Functional Inspection (SSFI), the Duke Engineering Assessment, the I
Operational Safety Review Team (0SART) report, and several internal ( studies and QA audits, and generally found them to be comprehensive. The j QA audits were of particularly high quality, reflecting depth of investi- i j
gation and a willingness to raise tough questions. Plant staff was frustrated with the lack of management aggressiveness to correct deficien-cies growing out of the SSFI, particularly one finding related to check valve testing in the auxiliary feedwater system which had remained unresolved since early 198 *
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The team noted that, in the case of the Duke assessment, the report contained 28 findings, 27 cf which were provided to the Duke evaluation team by CCNPP as self-identified deficiencies. The twenty-eighth item was separately identified by the Duke team and rejected for action by CCNPP, To date the corrective actions for the 27 have not been a high priority.
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} o Management had shown a lack of understanding of the importance of QC when they absorbed QC into the maintenance department under an intended peer i Evaluation concept and then assigned QC inspectors responsibility for the successful completion of the job. In addition, personnel policies created a climate in which a qualified tradesman's transfer to QC was regarded as a loss of status and pay, further diminishing the importance of the QC organizatio o The work force held a perception that managers were more concerned with the superficial appearance and cleanliness of the plant (particularly in the well-traveled areas) than with the actual material condition of the facility, o The plant staff appeared to be confused about the working definition of
" intent" as it relates to procedure changes and temporary modification The . team detennined that plant management did not have a functional understanding of " intent." ,
3.4.4 Planning, ScheJuling, and Prioritization Planning and scheduling was found to be fragmented, and the organization lacked The a
operations sitc-wide,an integrated, maintenanceaccessible planning)and coordination (OMC wasscheduling syste the dominant scheduling group on site, and during outages the role of the OMC supervisor was expanded to l include responsibility for outage management. The team observed confusion on the part of plant staff members about the distribution of authority and responsibility in the OMC function as well as in the roles of the project and 4 system engineers during outage The licensee employed a consultant to prepare a comprehensive plan to devise and implement a site-wide integrated nuclear information planning system ;
(NIPS), which was scheduled to be phased in over the next 18 to 60 months. The 1 k- site staff responsible for NIPS did a thorough job of salesmanship among the i system users., The development and implementation of the NIPS program was a 1
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rare example of a sound approach to cha'nge management identified by the tea .5 Analysis of Activities and Events The team reviewed several major programs and initiatives to assess management 1 effectiveness as applied in the operation of the facilit In addition, the j team reviewed significant operating events from the Fall of 1988 to evaluate j management effectiveness before, during, and after this perio j j
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'3.5.1. Procedure Upgrade Action Plan (PUAP) Review The team's findings from their review of the PUAP was representative of management effectiveness in planning, organizing, staffing, directing, and -
controlling site activities. Additionally, these findings were illustrative of management deficiencies in the areas of planning, staffing, change manage-ment, project management and control, priority setting, decision mating, organizational dpamics in the matrix structure, and reactionary " quick fix" solutions for ret glatory concerns. _ In nearly every respect management performance on the PUAP was found to be at the opposite end of the performance
' spectrum from that seen during reviews of the NIPS program, wbkn was an activity reviewed by the team in which management effectivener: could be considered a strengt The PUAP review identified the following deficiencie o The PUAP was considered by the team to be a quick fix in response to regulators; total planning time for the program was two weeks. By comparison, the NIPS program was planned for over a year. No strettgic change management techniques were applied to PUAP. Management appeared to perceive a need for a change, and ordered the staff to quickly improve procedures, o The licensee underestimated the magnitude of the project, in part because the planning process was apparently undertaken with little appreciation
- for the poor quality of existing procedures or a well defined perspective on the attributes of a truly quality procedur .
o There had been little apparent consideration given to how to implement the required changes given the cultural aspects of the plant staff"s attitude toward procedure quality, adherence, or contro There was no comprehensive manpower planning to ensure sufficient numbers of appropriately qualified persons. The' project manager stated that if the schedule slips, they will "just throw more bodies at it."
o A sense of ownership for the pre ect or for the finished product was found to be missing. The project manager had workers scattered through-out the organization with litt.le influence over any of-the '
o The: involvement' of personnel from operations, maintenance, engineering, and QC who will have to rewrite the procedures and be the eventual end us e was unspecified. No groundwork had been done to' ensure their
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coca .tment or investment, and no priority was assigned for completion.
l o The team concluded that the quality of the finished product envisioned
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by PUAP would be' questionable. The authors assigned to rewrite the procedures were generally first or second line supervisors with little exposure to the attributes of a quality procedure and who indicated their opinion that their existing procedures already range in quality from excellent to state of the art. Management had not established criteria i or conveyed expectations about the quality of the finished produc ___-________-_--__D
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o The decision on which procedures to rewrite and in what order led the team to speculate that additional rewrites will be required. The first tier administrative procedures that describe how to write procedures and the second tier that defines programs were scheduled for rewrite after the third tier implementing procedures were to be completed, o The project's completion schedule was unrealistically defined. The few identified schedule milestones were unrealistic and had already been extende o There was a general lack of understanding about how regulators would view the program in terms of its adequacy. The licensee seemed sur-prised during the early phase of the inspection when the team was able to identify so many deficiencies. By the close of the inspection period the licensee had called in outside consultants to evaluate and help improve the progra .5.2 Event Review- ,
The team reviewed in detail major events from 1988 with the purpose of evaluating management effectiveness before, during, and after each even The July delta T-power mismatch event, in which a limiting safety system l
setpoint for high power trip and axial flow offset trip were exceeded when
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operators responded to an apparent power mismatch by lowering delta T-power to match the power level indicated by nuclear instrumentation, was considered by the team to be representative of the events in tenns cf management performance. Like the PUAP review, the conclusions derived from the e'.ent reviews were illustrative of the deficiencies described thmughout this repor ,
Management effectiveness deficiencies identified during the review of the power mismatch event include:
o The lack of importance attached to procedure adherence was a major factor l in the event. Additional contributors to the scenario included the lack l o'f respect for procedure quality and the technical and administrative deficiencies which were allowed to continue unaddresse o The plant staff tended to use prncedures as guides rather than requirements.
I Verbal communications, verbal agreements between operators, technicians, l - and other key players, and unverified assumptions were typical of the way business was conducte Communications barriers between elements of the matrix organization played a major role in the event. Fuels engineers were present in the control room during the gower mismatch event but did not inject themselves into h
- the discussion. Likewise, operators did not consult these engineers, L
reportedly because of lack of respect for their expertise. The system engineer and instrument maintenatee supervisor verbally agreed to perform a critical surveillance at 30 percent power, but failed to involve the l- operators or the fuels engineers.
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o Operators did not reflect a questioning attitude when power indications were inconsistent but were willing to rely on unverified assumption .6 Conclusion
'The team concluded that management's emphasis on power production relative to the safety aspects of plant operation had resulted in a work environment which downplayed the importance of strict procedural adherence, stringent progranna-tic controls, and a strong, involved, quality control organizatio It appeared to the team that the licensee had failed to keep' pace with changes that have occurred within the nuclear industry, and that the particular manage-
- ment skills required by the current site organizational structure had not yet been fully developed by plant managemen The team concluded that unless. all levels of the organization incorporate-into their work activities an emphasis on safety and quality over production,
! the operational events which have characterized the licensee's declining performance could be expected to continue.
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4.0 EXIT MEETING l
On March 31, 1989, the inspection team and other NRC representatives met with licensee personnel to discuss the scope and findings of the inspectio .Mr. Brian K. Grimes, Director, DRIS, NRR, represented NRC management at this meeting. Licensee personnel who attended the exit meeting are listed in Attachment A. During the inspection, the team also contacted other members of the licensee's staff to discuss issues and ongoing activitie I
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ATTACHMENT A
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NON-NRC ATTENDEES AT EXIT MEETING MARCH 31, 1989 NAME TITLE Edward A. Crook President, Utility Operations L~': George C. Creel Vice President Nuclear Energy Ann E. Edwards Assistant to Vice President Nuclear Energy Charles H.. Cruse Manager, Nuclear Engineering. Services Robert E. Denton Manager, Quality Assurance and Staff Services Department Leon B. Russell Manager, Calvert Cliffs Nuclear Power Plant Department Thomas E. Magette- Manager, Nuclear Programs, Maryland Department of Natural Resources, Stephen Rosenback Project Leader, Nuclear Information Planning System Kenneth M. Romney Project Director. Quality Control
- John R. Hill . Supervisor, Operator Training Kenneth A. Pickering Supervisor, Quality Control Paul Pieringer- Supervisor, Independent Safety Evaluation Unit Marvin E. .Bownan General Supervisor, Planning and Support Larry Gibbs General Supervisor, Nuclear Security Richard P. Heibel General Supervisor, Quality Assurance Peter E. Katz General Supervisor, Design Engineering W. James Lippold General Supervisor. Technical Services Engineering Norman L. Millis General Supervisor, Radiation Safety Alan R. Thornton General Supervisor, Plant and Project Engineering John T. Carrol Performance Consultant Raymond L. Wenderlich General Supervisor, Nuclear Operations Wayne L. Whitaker General Supervisor, Mechanical Maintenance Gerry L. Adams Secretary / Steno, Nuclear Engineering Services Department Louis S. Larragoite Engineer, Licensing' Unit
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Bill Gallion Organization Planning Staff Services Robert M. Douglas Nuclear Energy Performance Consultant-Mike ~Mankowski Development Consultant Larry L..Wechbaugh General Supervisor Electrical and Controls
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ATTACHMENT B ABBREVIATIONS AND ACRONYMS-AFW auxiliary feedwater AO abnonnal operating procedure
, CCI Calvert Cliffs Instruction
'- CCNPP Calvert Cliffs Nuclear Power Plant i CCOM Calvert Cliffs Operating Manual !
DCN design change notice E& electrical and control
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ECCS emergency core cooling system EDG Emergency Diesel Generator EHC electrohydr5ulic control EDP emergency operating procedure E0 environmentally qualified ESFAS engineered safety features actuation system GS0 General Supervisor Operations ICAP integrated corrective action program INP0 Institute of Nuclear Power Operations LCO limiting condition (s) for operation M&TE measuring and test equipment M0 maintenance order
< MR maintenance request NCR nonconfonnance report NES nuclear engineering services NRC Nuclear Regulatory Comission 01 operating instruction-OP operating procedure P&ID piping and instrument diagram PM preventive maintenance POEAC Plant Operating Experience Assessment Committee POSRC Plant Operations and Safety Review Cosaittee QA- quality assurance d
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safety evaluation report i 50ER significant operating event report quality control
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OC STI special team inspection '
STP surveillance test procedure TE temperature element ' -
TM temporary modification TS technical specifications WPP welding program procedure
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ATTACHMENT C UNRESOLVED ITEMS
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Number- Description Section
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01 Lack of Control Over Measuring 2. and Test Equipment 02 Licensee's Position of Intent 2. Changes to Procedures
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03 Use of GSO Standing Instructions 2. in Lieu of Approved Procedures 04 Evaluation of Safety Implications 2.1.6
- of Maintenance, Modifications and Troubleshooting Activities 05 Lack of Detailed Work Instruction 2. for Performirg Maintenance Activities 06 Lack of Adequacy of Maintenance Histry 2. Documentation 07 Failure to Assure Proper Review and '2. Control of Vendor Tech Manuals 08 Lack of Adequate Control.0ver Welding 2. Process Activities 09 No Procedures for. Control of QC 2. Inspection Activities 10 Implementation of Site-Wide Writer's '2.4.3 k Guide for Surveillance Procedure Upgrades
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11 Procedure Deficiencies Not Resolved 2. in a Timely Manner
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Vendor Recommendations Into Surveillance Procedure Requirements 13 Program Weaknesses Associated With- 2. '
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Calibration of Permanently Installed Plant Equipment 14- Implications of Potential Facility 3. Configuration Control Problems Caused by Poorly Controlled Maintenance Activities y
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