IR 05000334/1997005

Insp Repts 50-334/97-05 & 50-412/97-05 on 970608-0719. Violations Noted.Major Areas Inspected:Operations, Engineering,Maintenance & Plant Support

ML20217P777
Person / Time
Site:	Beaver Valley
Issue date:	08/18/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20217P765	List: IR 05000334/1997005 ML20217P762 ML20217P773
References
50-334-97-05, 50-334-97-5, 50-412-97-05, 50-412-97-5, NUDOCS 9708280232
Download: ML20217P777 (52)

Text

.-

O ENCLOSURE 2 U S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No , 50 412 License No DPR 86, NPF 73

- Report No , 97 05 Licensee: Duquesne Light Company (DLC)

Facility: Beaver Valley Power Station,-Units 1 and 2

_

- Location: post Office Box 4 Shippingport, PA 15077 Dates: June 8,1997 through July 19,1997 -

Inspectors: D. Kern, Senior Resident inspector

- F. Lyon, Resident inspector G. Dentel, Resident inspector J. Laughlin, Emergency Preparedness Specialist L. Peluso, Radiation Physicist

.

Approved by: P. Eselgroth, Chief Reactor Projects Branch 7

- -

-

-

e-DOh b $34 pon -

---

,

_ _ - - _ _ _ _ _ _ _ .

.

. . .

. .. .

.

EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2 NRC Inspection Report 50 334/97 05 & 50-412/97 05 This integrated Inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6 week period of resident inspection, in addition, it includes the results of an announced inspection by regional inspectors in the area of radiological environmental monitoring and an in office review of emergency plan change Operations e On June 27, the licensee shutdown Unit 1 due to concerns that two reactor protection system trip functions did not meet design requirements. The prompt decision based on available information and the well controlled shutdown demonstrated a strong focus on plant safety. (Section 01.2)

e On July 10, the licensee shutdown Unit 2 due to increased reactor coolant pump (RCP) sealleakoff which approached vendor recommended limits. Operators effectively monitored RCP seal performance during the shut down and promptly transferred emergency electrical busses to off site power to minimize the challenge to safety equipment. (Section 01.3)

e An inadvertent actuation of the Unit 1 overpressure protection system (OPPS)

occurred when operators failed to observe slowly rising reactor coolant system

'

pressure after se:uring a reactor coolant pump. The OPPS operated properly during the event. The event was caused primarily by inattention to detail by the operating crew, demonstrated by f ailure to monitor critical primary parameters. Operations and DLC management took appropriate immediate corrective action (Section 01.5)

e Operators and technicians demonstrated a good questioning attitude in identifying four separate instances (Control Room Emergency Bottled Air Pressurization Systems, Emergency Diesel Generator,125 VDC Bus Alignment, Service Water System) where Technical Specification (TS) surveillance testing was not adequately performed to demonstrate system operability, in each case the test procedures were inadequate to address TS testing requirements. (Section 03.1)

e Operations personnel identified two longstanding practices during which licensed operators did not properly control equipment configuration and did not recognize TS limiting condition of operations (LCO) applicability. The events involved implementing approved station procedures which bypassed both source range nuclear instrument (SRNI) trip channels and made both trains of supplementary leak e

li

. .. . . .

. . . . . . .

.- .

. .

.

...

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

,

s-collection and release system (SLCRS) inoperable. These events represented licensed operator knowledge weaknesses as well as performance deficiencies by the Onsite Safety Committee (OSC) during the procedure approval process. (Section 04.1)

e Poor procedure human factors, poor labeling, insufficient operator selfshecking techniques, and f ailure to include " precautions and limitations" in the work instructions resulted in an emergency shutdown versus a normal shutdown of the emergency response facility diesel generator. No safety consequences resulted due to the emergency shutdown. These observations indicated both work planning and procedural weaknesses. The system engineer provided detailed knowledge and excellent overall support. (Section 08.5)

e The licensee event reports (LERs) reviewed this period described the events with appropriate details. The root cause analysis was effective in determining the root cause and corrective actions were comprehensive. The inspectors noted that several LERs exceeded the 30 day reportability limit as specified in 10 CFR 50.7 The reporting delays primarily occurred prior to administration of a revised reportability assessment process. (Dections 08.6 to 08.9)

Maintenanga p

e inadequate maintenance work instructions, job pre briefing, and poor operator communications on Unit 1 resulted in an unplanned reactor coolant system cooldown, letdown system isolation, and inadvertent actuation of the P 12 High Steam Flow Safety injection (SI) Block Permissive interlock engineered safety feature. Corrective actions taken for two similar events within the last 10 months were ineffective. This was a violation. (Section M1.2)

Enoineerina e- Engineering determined that under a particular failure mode, the steam generator low low level reactor protection system trip function was Inoperable and that this vulnerability existed since original plant startup in 1976. A design change was properly developed and installed to correct this design deficiency. Engineering evaluation and corrective actions to address the issue were comprehensive. NRC enforcement discretion was exercised, and no violation issued, in recognition of licensee self identification and correction through voluntary initiatives of en old design issue. (Section E1.1)

e The system engineer identified increased Unit 2 RCP sealleakoff flowrates during routine tracking and trending. System engineers, with vendor essistance, developed an action plan and corrective actions to address the increase in sealleakoff. The corrective actions were technically sound, but failed to stop the increasing RCP first stage sealleakoff which forced DLC to shutdown the plant for RCP seal replacement. (Section E1.2)

lii

)

_ _ _ _ _ _ _

.

O

• Engineers determined that non seismically qualified carbon dioxide (CO2) fire suppression system actuation relays existed in both Unit 1 emergency diesel generators since original plant operations. This discovery resulted from recent licensee initiatives to enhance safety culture and questioning attitudes on the part of engineering personnel. NRC enforcement discretion was exercised, and no violation issued, in recognition of licensee self identification and correction through voluntary initiatives of an old design issue. (Section E1.3)

• Licensing engineers determined that three installed containment isolation valve check valves did not meet the Updated Final Safety Analysis Report (UFSAR)

specified design requirements and therefore the unit containment was in an unanalyzed condition since original plant operation. The unit was in cold shutdown at time of discovery. The deficiencies were promptly corrected and the valves retested prior to changing modes. NRC enforcement discre'lon was exercised, and no violation issued, in recognition of licensee self identifica ,on and correction through vow.tary initiatives of an old design issue. (Section E1.4)

Plant Suonort

• The licensee continued to implement an effective radiological environmental ,

monitoring program (REMP) and meteorological monitoring program (MMP). The Offsite Dose Calculation Manual (ODCM), Technical Specifications (TS), and the UFSAR were properly implemented. The 1995 and 1996 audit reports effectively assessed the strengths and weaknesses of the REMP and MMP. The licensee's performance of the REMP and MMP was good. However, the practice of using a clear acrylic spray to affix particulates to the air particulate filters, not preparing the calibration standards in the same way, and not accounting for beta attenuation was an Unresolved Item requiring further review. (Sections R1 to R8)

Safety Assessment and Quality Verification

• The licensee effectively resolved several design issues prior to Unit 1 restart. The Nuclear Safety Review Board meeting to assess the cumulative effect of all outstanding Bnes for Continued Operations provided meaningful insight regarding operational limitations placed on the operating crew. The management decision to delay the Unit 1 restart until letdown and excess letdown system support deficiencies were corrected demonstrated a conservative safety perspectiv (Section 01.4)

• The licensee identified severallongstanding plant design deficiencies, operator performance weaknesses, and TS surveillance testing deficiencies at both unit This trend of increased self identification of problems demonstrated improved awareness and focus on plant safety. Wider use of the station condition report system, the UFSAR verification project, and safety culture awareness seminars have contributed to this trend. (Sections 03.1, 04.1, E1.1, E1.3, E1.4)

Iv

]

.

_ - - _ _ - - - - - - _ - - - _ _ - - -

,

.

O TABLE OF CONTENTS PAGE N EX ECUTIVE S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il TABLE O F C O NT ENT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v 1. Operations .................................................... 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.2 Unit 1 Forced Shutdown Oesign issues . . . . . . . . . . . . . . . . . . 1 01.3 Unit 2 Forced Shutdown Reactor Coolant Pump Seal Leakoff . . 2 01.4 Unit 1 Restart Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 01.5 Inadvertent Overpressure Protection System Actuation . . . . . . . . 5 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 6 02.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . . 6 03 Operations Procedures and Documentation ..................... 6 03.1 Missed Caorations Technical Specification (TS) Surveillance Tests........................................... 6 04 Operator Kmaledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 8 04.1 Operator Failure to Recogn5e TS Applicability . . . . . . . . . . . . . . 8 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 08.1 (Closed) URI 50 334 &412/96 10 01 . . . . . . . . . . . . . . . . . . . . 10 08.2 (Closed) Licensee Event Report (LER) 50 334&412/97 11 ..... 10 08.3 (Closed) LER 50 3 34 &412/9 7 13 . . . . . . . . . . . . . . . . . . . . . . 10 08.4 (Closed) LER 50 3 34 &412/97 14 . . . . . . . . . . . . . . . . . . . . . . 10 08.5 Emergency Response Facility (ERF) Diesel Generator . . . . . . . . . 10 08.6 (Closed) LER 50 412/96 04 .......................... 12 08.7 (Closed) LER 5 0 412 /9 6-0 7 . . . . . . . . . . . . . . . . . . . . . . . . . . 12 08.8 (Closed) LER 5 0-3 3 4 /9 6-0 6 . . . . . . . . . . . . . . . . . . . . . . . . . . 13 08.9 LER Reportability ................................. 13 11. M a i n t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 M1 Conduct of Maintenance ................................. 13 M1.1 Routine Surveillance Observations (01726) ............... 13 M8 Miscellaneous Maintenance issues (92902 .................... 16 M8.1 (Closed) eel 50 334/97 02 04 ........................ 16 M8.2 (Closed) eel 50 334 &412/97 02-05 . . . . . . . . . . . . . . . . . . . . 16 M8.3 (Closed) eel 50 334 &412/97 02 09 . . . . . . . . . . . . . . . . . . . . 16 M8.4 (Closed) eel 50 334 &412/97 02 07 . . . . . . . . . . . . . . . . . . . . 16 M8.5 (Closed) eel 50-334 &412/97-02 08 . . . . . . . . . . . . . . . . . . . . 17 M8.6 (Closed) eel 50 334 &412/97 02 09 . . . . . . . . . . . . . . . . . . . . 17 t il . En gin e e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 El Conduct of Engineering .................................. 17 E Reactor Protection System (RPS) Design Deficiencies . . . . . . . . 17 E1.2 Reactor Coolant Pump Seal Leakoff increase . . . . . . . . . . . . . . 19 E1.3 Inoperable Unit 1 Emergency Diesel Generators (EDG) . . . . . . . . 20 E1.4 Unit 1 Containment isolation Valve Verification . . . . . . . . . . . . 22 v

4-l

-

.

I V. Pl a n t S u pp or t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 23 R1.1 Implementation of the Radiological Environmental Monitoring Pr og r a m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 R1.2 Meteorological Monitoring Program (MMP) . . . . . . . . . . . . . . . . 25 R2 Status of RP&C Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 27 R5 RP&C Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . - 28 R6 RP&C Organization and Administration ....................... 29 R7 Quality Assurance in Radiological Protection and Chemistry Activities . 29

. R7.1 Quality Assurance Audit Program . . . . . . . . . . . . . . . . . . . . . 29 R7.2 Quality Assurance of Analytical Measurements ............-30 P3 EP Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . 31 P3.1 In Office Review of Licensee Procedure Changes (82701) .... 31-L1 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 V. Management Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 X2 Pre Decisional Enforcement Conference Summary ............... 32 X3 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 X3.1 Maintenance Rule Baseline inspection . . . . . . . . . . . . . . . . . . . 32 PART!AL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 INSPECTION PROC EDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 ITEMS OPENED AND CLOSED ....................................... 34 LIST O F ACRO NYM S U S ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 EMERGENCY PREPAREDNESS PLAN PROCEDURES REVIEWED .-. . . . . . . . . . . . , . .- 39 -

vi

- --

..

,

___ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _

.

.

Report Details Summarv of Plant Status Unit 1 began this inspection period at 100 percent power. On June 27, operators commenced a controlled plant shutdown due to licensee concerns with the seismic qualification of feedwater flow instrumentation and the conformance of aspects of the reactor protection system to IEEE 279. Unit 1 entered Mode 5 (cold shutdown) on July 3 and remained in a forced outage through the remainder of the perio Unit 2 began this inspection period at 100 percent power. On July 10, operators commenced a controlled plant shutdown due to elevated sealleakoff on reactor coolant pumps 21 A and 21C. Unit 2 entered Mode 5 on July 12 and remained in a forced outage through +he remainder of the perio l. Oogrations 01 Conduct of Operations 01.1 General Comments (71707P Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professionel and safety conscious; specific events and noteworthy observations are detailed in the sections belo .2 Unit i Forced Shutdown - Deslan isg31 Insoection Scone (71707,93702)

On June 27,1997, station management determined that the Unit 1 reactor protection system (RPS) did not meet design requirements and directed that the unit be shut down. The inspectors observed the reactor si,utdown to evaluate operator performance and station oversight activities, Qhtervations and Findinas On June 27,1997, while evaluating maintenance rule scope applicability, DLC engineers determined that six feedwater flow transmitters which provide input to the Unit 1 steam flow /feedwater flow mismatch coincident with low steam

. generator (SG) level RPS trip were not seismically mounted.1he Nuclear Safety Review Board (NSRB) reviewed the issue and determined that the specified trip

' Topical headings such a 01, M8, etc., are used in accordance with the NRC

' standardized reactor inspection report outline. Individual reports are not expected to address all outline topics.

- -

_ _ _ . _

- _ _ _ _ _ _ _ _ _ _ _ ____ _ __________

.. .. . .

.. .

.

function did not meet the design criteria specified in IEEE 2791971, " Criteria for Protection Systems for Nuclear Power Generating Stations," and recommended to the plant manager and the Nuclear Shift Supervisor (NSS) that the trip function be declared inoperable (see Section E1.1).

The NSS reviewed TS 3.3.1.1, Table 3.31, item 15 and determined that with no channels of the steam flow /feedwater flow mismatch coincident with low SG level RPS trip operable, TS 3.0.3 applied. The licensee entered TS 3.0.3 at 7:15 pm due to the plant being outside its design basis. Operators began a TS required shutdown at 8:13 pm and achieved hot standby at 1:28 am on June 28,199 The inspectors observed the plant shutdown from the control room and verified that the 10 CFR 50.72 NRC notification was properly performed. Operators properly reviewed procedures and prebriefed the shutdown evolution. Operations management provided appropriate oversight in the control room during the shutdown evolutio Based on RPS circult diagram review and discussions with engineers, the licensee concluded that a second RPS trip function (low low SG level trip) appeared to be inoperable due to a control system to protection system interaction vulnerability which was not permitted by IEEE 2791971. This issue had developed rapidly and engineers had not effectively communicated this to the NSRB at their June 27 meeting. Following discussions with the inspectors and engineers, operations personnel updated their 10 CFR 50.72 notification to state that the low low SG level trip function was inoperable. The inspectors verified that the TS 3. shutdown action was appropriate to address both RPS trip concern During plant cooldown to Mode 5 for various repairs, operators unisolated a residual heat removal (RHR) sample system piping penetration to obtain a required chemistry sample prior to initiating RHR. This line had been previously isolated per TS 3.6. and drained to address thermal overpressure protection concerns because there is no relief valve installed on this line. The licensee properly made a 10 CFR 50.72 notification to report the opening of these valves, Conclusions On June 27, operators shutdown Unit 1 due to concerns that two RPS trip functions did not meet design requirements. The prompt decision based on availulv information and well controlled shutdown demonstrated a strong focus on plant safet .3 Unit 2 Forced Shutdown - Reactor Coolant Pumo Seal Leakoff J.osoection Scoce f 71707. 93702)

'

Reactor coolant pump (RCP) sealleakoff gradually increased during the past four months, Operators established an action plan to monitor leakage and shutdown the unit prior to the leakoff reaching the vendor's recommended operating limit. The inspectors evaluated operator performance regarding sealleakoff monitoring and the suhseauent Unit 2 forced shutdown, w

, .

___-_

.

..

. .

_ . .

.

3 Observations and Findinas At 11:35 am, on July 10,1997, operators initiated a Unit 2 reactor shutdown due to reactor coolant pump (RCP) first stage sealleakoff flow rates approaching vendor recommended limits. The shutdown was performed to protect thei RCP equipment, and was not required by TS. The vendor limits were established to prevent RCP thermal barrier or seal damage and/or seal f ailure. The C" RCP experienced the greatest sealleakoff which reached 5.96 gpm. Earlier that morning, the "C" RCP sealleakoff experienced a quick and unexpected 0.25 gpm increase shortly after operators raised the pumps sealinjection flow based on engineering recommendations. The increase was unexpected based on past experience and vendor consultation. The inspectors monitored the reactor shutdown from the control room. Operators demonstrated sound safety judgement by transferring the emergency 4KV electrical busses to off site power as sealleakoff approached the procedural limit which would necessitate a reactor trip RCP seulleakoff decreased a small amount as the power was reduced. Unit 2 was taken off line at 7:45 pm

= and achieved hot shutdown at 8:08 pm. Operators and engineers closely trended sealleakoff throughout the reactor shutdown. The reactor was placed in cold shutdown for repair All three RCPs experienced gradually increasing sealleakoff since March 1997.

( Engineers worked closely with the vendor to evaluate root cause and corrective actions. The most probable cause of the increase in sealleakoff flow rates is a phenomenon known as " electrophoresis" or minute corrosion products accumulating on the RCP seal face (see Section E1.2). Corrective actions to address the increased leakoff flow rates prior to plant shutdown includ3d installing finer dimension RCP sealinjection filter cartridges, rebuilding filter housings to eliminate potential filter bypass flow, and evaluations of potential corrosion product source These actions were unsuccessful in stopping the rate increas The "A" and "C" RCP seals were replaced during the shutdown. Management determined that the "B" RCP seal performed adequately to support continued operation, Conclusions On July 10,1997, operators shut down Unit 2 due to increased RCP sealleakoff which approached vendor recommended limits. Operators effectively monitored RCP seal performance during the shut down and promptly transferred emergency electrical busses to off site power to minimize the challenge to safety equipmen .4 Unit 1 Restart Assessment Insoection Scope (71707)

Several operability and design questions led to the Unit 1 forced shutdow Additional construction and design questions were evaluated prior to restart. The inspectors observed these evaluations to asssss management effectiveness and safety perspectiv . .. .

.-_--- I

.

. _---- -_- _

- ..

4 b. Observations and Findinns The licensee evaluated and resolved several design issues during the Unit 1 forced outage including: Assessed IEEE 279 applicability (including seismic qualifications) to anticipatory reactor trip function . Installed a SG level median selector switch design change to address the IEEE 279 control and protection interaction design deficiency for the SG Low Low Level trip functio . - Verified feedwater injection line and auxillary feedwater injection line isolation valves as currently installed versus design requirement . Resolved numerous discrepancies betweer, 'le Updated Final Safety Analysis

,

Report (UFSAR) and the administratively controlled containment penetration / isolation valve table maintained in the Licensing Requirements Manua . Evaluated and submitted an ASME Section ill relief request to permit an alternate means of providing overpressure relief protection for certain components (primarily the gaseous waste system and the volume control tank). Assessed and repaired / modified approximately 45 seismic suprorts for small bore piping (e.g.121/2 inch lines including reactor coolant system (RCS)

excess letdown, RCS letdown, reactor coolant pump (RCP) sealleakoff, RCP fill). Reevaluated Generic Safety Issue A 46 " Seismic Qualification of Equipment at Operating Plants" component outliers with additional focus placed on potential system interactions. This action resulted from the licensee determination that the Unit 1 EDGs had been inoperable due to non-seismically qualified fire suppression system automatic actuation relay The inspectors reviewed design drawings, UFSAR and other licensing basis documents, NSRB meetings, and approximately 30 licensee 10 CFR 50.59 safety evaluations. The safety evaluations were technically sound. The SG level median selector switch design change was properly developed to resolve the IEEE 279 concern regarding control and protection system interaction Prior to Unit 1 restart the NSRB met to review all existing Unit 1 basis for continued operation (BCO) documents and their cumulative effect on operators. The inspectors observed this meeting and noted that NSRB members asked appropriate questions regarding RCS inventory control. The excess letdown system was unavailable due to seismic support concerns and the design of some seismic

, supports for a letdown system filter were recently called into question. Following in depth discussions, the NSRB advised that the unavailability of excess letdown was an excessive burden on the operating crews. Based on this input, the plant manager decided that the known seismic support deficiencies would be corrected prior to unit startup. Although plant startup with these existing conditions was permissible by the operating license, management determined that the existing plant configuration would adversely limit operator actions and equipment availabilit _ _ _ _ _ -

-__ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _

.

5 Conclusions The licensee effectively resolved numerous design issues prior to Unit 1 restar The NSRB met to assess the cumulative effect of all outstanding BCOs on the operating crews. Based on NSRB recommendation, the Unit 1 restart was delayed until letdown and excess letdown system support deficiencies were corrected, demonstrating a conservative safety perspectiv .5 Inadvertent overoressure Protection System Actuation On July 18, an inadvertent actuation of the Unit 1 overpressure protection system (OPPS) occurred when operators failed to observe slowly rising reactor coolant system (RCS) pressure after securing a reactor coolant pump (RCP). Operators were in the process of cooling down Unit i from about 190 degrees F to 135 degrees to conduct repair work on the excess letdown system piping support Initially, RCPs 1 A and 1C were in service and RCS pressure was about 370 psig as measured by the wide range pressure instrument (PT RC-403). The "C" loop pressurizer spray valve was in manual control and open about 20%, and the "A" loop spray valve was in manual and close Control room operators secured RCP 1 A in accordance with procedure and closely monitored RCS temperature and pressurizer level due to the expected drop in both parameters when the RCP was secured. Operators failed to note slowly rising RCS pressure. Securing the RCP reduced the flow through the spray valve; with spray and pressurizer heaters no longer at approximate equilibrium, RCS pressure began to rise about 2 psig per minute. About 23 minutes after the pump was serured, the OPPS actuated and pressurizer power operated relief valve (PORV) PCV RC 455C opened. - Pressure was reduced from about 414 psig to about 380 psig when the PORV closed. Applicable alarms were received in the control room, and operators stabilized RCS pressure by adjusting pressurizer spray flow. The OPPS operated properly during the event. The operating crew had conducted a pie-evolution briefing before the RCP was secured, but the expected RCS pressure response was not discussed and was not anticipate The event was documented in Condition Report 971232. As an immediate corrective action, Operations implemented procedure changes to add an RCS pressure alarm of 390 psia to the " Computer Monitored Alarm," annunciator A4 47, to warn the operator of rising pressure before reaching the OPPS setpoin Additional corrective actions were under evaiuation as part of DLC review of the event, which was in progress at the end of the period, inspectors assessed that the event was due to inattention of the operating crew, demonstrated by failure to monitor critical primary parameters. Operations and DLC management took appropriate immediate corrective actions. Additional corrective actions to prevent recurrence were under evaluation at the end of the perio I

_ _ - _ _ _ _ _ - _ _ - _ _

..

.

02 Operational Status of Facilities and Equipmerit 02.1 Enaineered Safetv Feature System Walkdowns (7170]]

The Inspectors walked down accessible portions of selected systems to assess equipment operability, material condition, and housekeeping. Minor discrepancies

- were brought to DLC staff's attention and corrected. No substantive concerns were identified. The following system was walked down:

e Unit 2 Quench Spray System 03 Operations Procedures and Documentation 03.1 Missed Ooerations Technical Soecification (TS) Surveillance Tests Insoection Scone (71707. 92901. 92902. 92903)

The licensee identified several missed TS surveillances over the past six month Several actions were recently initiated to identify and correct these problems on a programmatic basis. The inspectors reviewed preliminary licensee findings to-determine whether corrective actions were properly focussed to ensure TS surveillance test requirements were met to properly verify equipment operabilit Insoector Findinas and Observations Operations, maintenance, and engineering personnel recently began several activities to improve the TS surveillance program. Actions included a programmatic review of TS surveillance testing (beginning with electrical power systems and emergency core cooling systems) and more careful scrutiny of surveillance test procedures and post maintenance testing (PMT).

On May 9,1997, while determining PMT requirements for the Control Room Emergency Habitability System, technicians identified that 1/20ST 44A.15,

" Chlorine Actuation by Unit 1 SSPS of Control Room Isolation / Control Room Emergency Bottled Air Pressurization Systems (CREBAPS)," was inadequate to verify system operability as previously performed to satisfy PMT requirements on August 12,1996. Specifically, contacts 1 & 2 on relays K630A and K630B, which actuate damper isolation and air bottle actuation, were not adequately teste Absent proper testing to verify CREBAPS operability following maintenance, the CREBAPS system should have been declared inoperable from August 12,1996, to May 9,1997. Subsequent testing on May 9 confirmed that the relays and the CREBAPS system were operable and that the safety consequence was, therefore, low. Discovery of this testing deficiency demonstrated a questioning attitude with regard to surveillanco test requirements and acceptance criteri . - _ ___ - - -_____________ ____

,

.

On June 11 and 12,1997, operators identified two longstanding TS surveillance test deficiencies pertaining to eler.trical power systems. TS 4.8.2.3.1 requires weekly DC bus train battery charger circuit breaker alignment verificatio Operators had used battery charger current measurements to satisfy this requirement in lieu of physically checking the breaker alignmen TS 4.8.1.1.2.c.1 requires that each emergency diesel generator (EDG) be demonstrated operable by checking for and removing accumulated water from the day tank after each operation (greater than one hour) of 'he EDG Procedures specified this check to be done following routine surveillance testing, but did not address checking for water after other EDG operations (such as following an automatic EDG start on bus undervoltage). The licensee identified four occasions during the past four years when the EDG day tank water check was not done following a one hour or longer period of operatio On July 10,1997 system engineers determined that the Unit 2 B service water pump vacuum break check valve (2SWS'487) was not tested in the forward direction during the last quarterly surveillance test performed on May 22,199 The primary cause for omitting this test was that planners and operations personnel failed to account for this test being performed when the service water system (SWS) was in a different configuration than normal. Due to the test omission, operators declared the valve inoperable on July 10, and properly applied the requirements of TS 4.0.3. The valve was subsequently tested satisfactorily and declared operable. The inspectors determined that immediate actions upon discovery were goo Each of the above deficiencies was a violation of TS surveillance testing requirements in each case, immediate corrective actions confirmed that the component was operable and safety consequence was minimal. Three of the issues were reported as required by 10 CFR 50.72 (Sections 08.2,08.3, and 08.4) with the reportability determination on the fourth item in progress at the close of the inspection period. The three licensee event reports accurately described the event, safety consequences, and corrective actions. The effectiveness of long term corrective actions will be tracked and evaluated during closure to a previously issued violation concerning TS surveillance testing program weaknesses. These four violations represent additional examples of TS surveillance test program weaknesses which were the subject of an escalated notice of violation (NOV),

issued on July 3,1997. These licensee identified and corrected violations are being treated as a Non Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50 334&412/97 05 06). Conclusions Operators and technicians identified four separate instances (CAEBAPS, EDG,125 VDC Bus Alignment, SWS) where TS surveillance testing was not adequately performed to demonstrate system operability, in each case the test procedures were inadequate to address TS testing requirements. These four violations

- _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

B represent additional examples of T3 surveillance test program weaknesses which were the subject of an escalated notice of violation (NOV), issued on July 3,199 The violations were encompassed by the July 3 NOV and occurred bel ore the licensee's corrective actions were fully implemented and therefore are not cite Operator Knowledge and Performance 04.1 Operator Failure to Reconnire TS Acolicability inspection Scoce (71707)

Operators identified two routinely performed activities which were not permitted by TS in each case procedures were written to permit the activity, but licensed operators failed to recognize that the resulting equipment configuration required certain TS limiting condition of operations (LCO) to be applied. The inspectors reviewed the activities, how they were identified, and corrective actions take , Observations and Findinns Sucolemental Le.pk Collection and_. Release System (SLCRSJ On May 20,1997, the Unit 2 "A" SLCRS exhaust air filter train was removed from service for corrective maintenance. On May 21 the "B" SLCRS tralh was removed from service for four minutes to support test equipment installation on the "A" SLCRS train, by placing the fan control switch in pull-to lock. An operator was stationed at the control switch as a compensatory measure to start the fan if needed. However, the Nuclear Shift Supervisor (NSS) permitted this work to occur without recognizing that placing the f an control switch in pull-to lock made the "B" SLCRS train inoperable. This resulted in both SLCRS trains being inoperable, which is not permitted by TS and should have resulted in cognizant entry into TS 3. The NSS did not realize that TS 3.0.3 was applicable. The next shift recognized the operability concern and declined to place the "B" SLCRS trai7 in pull to lock while the "A" SLCRS train remained out of servic Condition reports (CR) 970938 and 971141 were initiated to evaluate this condition. The event was properly documented in LER 50-412/97003. Subsequent licensee investigation determined that eight existing station proceduras permit both SLCRS exhaust fans to be secured simultaneously and identified several past instances when both SLCRS trains wera inoperable. Extent of condition reviews, corresponding corrective actions, and further reportability issues were in progrecs as part of the condition report process. The inspectors determined that appropriate immediate actions were taken to ensure aillicensed perr.onnel were aware that a component is inoperable when its control switch is placed in the pull to lock position. Actions to preclude recurrence included reviews of the SLCRS licensing basis, SLCRS testing methodology, establishing technical review requirements by engineers for all future surveillance test revisions, and a TS surveillance test validation. The inspectors determined that the schedule for corrective action completion by January 30,1998, was reasonabl . .

,

.. ..

... .

. .. .. __

. - _ - _ - _ _ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _

. . .

9 Source Ranae Nuclear Instruments (SRMigl During initiallicensed operator training, operations personnel identified that the Unit 1 station shutdown procedure,10M 51.4A, " Station Shutdown Minimum Load to Startup Mode or Hot Standby Mode," Rev 9, directed both SRNis to be bypassed at a time not permitted by TS. Specifically, with the reactor critical at to 1.5% power step B.1 directed that the SRNI N 31 and N32 level trip bypass switches be placed in " bypass." 10M 51.4A directs the trip bypass switches be returned to " normal" shortly af ter entering Mode 3 which means the trip function would typically have been bypassed for 510 minutes. TS Table 3.31 (item 0.a)

specifies that the minimum number of operable SRNI trip channels is two. Both channels bypassed is a condition not permitted by TS and should have been recognized as condition requiring entry into TS 3.0.3. The inspectors reviewed operator logs for two plant shutdowns in 1990 and noted that the control room staff failed to document applicability of TS 3.3.1 and TS 3.0.3. Although not documented, the inspectnra datoimined it unlikely that the LrO allowed outage times were exceede Operations personnel determined that the procedure had been revised to bypass the SRNI trip as discussed above in 1987 as corrective action to address an inadvartent reactor trip which occurred when the SRNI energized and spiked above the P-6 trip setpoint. The inspectorF determined that this revision demonstrated a misunderstanding of the TS requirements by both operations personnel and the Onsite Safety Committee (OSC),

l'iperators promptly revised 10M 51.4A in timo to support the June 27,1997, Unit 1 shutdown (Gection 01.2). Further corrective actions to pieclude recurrence .

were being developed through the condition report system and on LER due shortly after the end of this aport period. Based on discussions with licensing personnel,

'

the inspectocs determined that the licensee now had a good understanding of the TS require:nonts and that proposed corrective actions were properly focused, l.icensing personnel indicated that corrective actions would address the failure of the OSC to fully address TS requirements when approving station proc 6duros as well as failure by licensed operators to be cognizant of TS applicability to plant c.onditions. Corrective action imptomentation will be evaluated during LER follow up inspectio The inspectors concluded inat the equipment control deficiancies involving SLCRS and the SRNI trip features were violations of 10 CFR 50, Appendix 0, Criterion XVI, and station procedures in that the OSC and operators failed to identify and correct conditions adverse to quality and operators failed to log tS3 TS LCO entries. Both issues were licensee identified and corrective action was initiated according to a reasonalle schedule. These issues were similar to those documented as a violation in NRC Inspection Report No. 50-334(412)/97 04. However, licensee corrective actions to the previous violation have not been fully i nplemented and therefore could not have prevented these occurrences. This licensee identified and corrected

-

violation is being treated as a Non-Cited Violation, consistent with Section Vll. of the NRC Enforcement Policy (NCV 50 334&412/97 05 01).

.

_ _ _ - _ _ _ _

.

O 10 _ Conclusions Operations personnel identified two longstanding practices during which licensed operators failed to properly control equipment configuration and failed to recognize TS limiting condition of operations (LCO) applicability. The events involved implementing approved station procedures which bypassed both SRNI trip channels and made both trains of SLCRS inoperable. The inspector determined that these events represented licensed operator knowledge weaknesses as well as performance deficiencies by the OSC during the procedure approval process. Self identification was a key factor in treating the events as a non cited violatio Miscellaneous Operations issues (92901,92700)

08.1 LOlosed) URI 50-334&412/96 10-01: Repetition of Configuration Control Problems Despite Prnvious Corrective Action This URI was closed by NRC ietter dated March 24,1997. (VIDs 50 334&412/EA 97 078 01013,50-334/EA 97 076 01023, and 50-334&412/EA 97 076 01033)

08.2 ICinandLLissanne Event Report (LER) 50-334&412/97 11: Inadequate Testing of Unit 1 Solid State Protection System Relays K630A and K6309 This LER is described and closed in Section 0 .3 LC1gf.ndLLER 50 334&412/97 13: Failure to Perform DC Bus Train Weekly Breaker Alignm9nt as Required by TS This LER is described and closed in Section 0 .4 (Closed) LER 50 334&412/0/.1.4: f Failure to Check for and Remove Accumulated Water in the EDG Day Tanks as Required by TS This LER is described and closed in Section 0 .5 Eawgency Response Facility (ERF) Digs _ql Generator, trynggtlon Scone (71707,62707)

The inspectors observed operator response to an inadvenent start of the ERF Diesel Generator (DG). The following procedures were utilized during the securing of the ERF DG:

• 1/20ST 58E.1, *RG Diesei Generator (RG EG-1) Test," Rev.10

• 1/20M 58E.4.AC, "ERFS Load Shed Programmable Controlier Shutdown,"

Re e 1/20M-58E.4, ERFS Transformer 3B Shutdown," Rev. 7

.  ;

___- _

,

b. Observations and Findinas On June 6,1997, during the restoration of the ERF DG programmable logic controllers (PLCs), the ERF DG started unexpectedly. The PLCs were being modified in response to previous failures (see Inspection Report 50-334(412)/97002). Computer engineering preliminary evaluation identified procedure deficiencies in the restoration procedure and differences between actual field conditions versus bench test conditions as the causes of the inadvertent star The inspectors directly observod operations response to the event. A senior reactor operator (SRO) and two non-licensed operators were involved in the securing of the ERF DG, The SRO effectively ensured that instrument & control (l&C) technicians and the computer engineers had completed data gathering and that shutdown of the ERF DG began quickly. The ERF DG was shutdown using a partial procedure (portions of 1/20ST-58E.1) While proceeding through this procedure, the operator tripped the ERF DG using the emergency stop buttons instead of the normal stop buttons as designated in the procedure. The normal stop buttons would initiate a timed idle cooldown period, whereas the emergency stop buttons resulted in an immediate shutdowa. The inspectors attributed the operator error to poor  !

procedure human factors, poor labeling, insufficient operator self-checking techniques, and failure to include the precautions and limitations in the partial procedur The operator performing the procedure observed his error and quickly informed the SRO. The system engineer for emergency diesel generators (EDGs) arrived at the ERF DGs and provided assistance to the operators. The system engineer informed operators and the inspectors based on vendor information that emergency shutdown of the ERF DG does not adversely affect the diesel. -The system engineer assisted the operators with alarm response and provided additional information on overall ERF DGs operatio The licensee issued two condition reports (CR 971008 and CR 971010) to address the inadvertent start of the ERF DG and the emergency shutdown of the diese Corrective actions to address the procedural and labeling deficiencies have been completed. Additional corrective actions to address the personnel problems were being planned at the close of the inspection perio The ERF DG provJes a backup power supply to the ERF substation. The ERF substation supplies the emergency response facility, ERF Appendix R equipment and some additional Appendix R equipment (including the Unit 1 dedicated auxiliary feedwater pump). The ERF substation and the equipment it supplies are QA Category ll) <:omponents (non-safety equipment). Although the inspectors assessed that no regulatory requirements were violated during the event, the inspectors

, determined that this was an indicator of work planning and procedural weaknesse I

__

- .

.. ..

.

. .. . . . . - _ _ _ - _ _ _ - - _ _ __

,

.

c, . C.pnetusions Operators responded to an ERF DG inadvertent start during restoration of the programmable iogic controllers. The inspectors observed poor procedure human factors, poor labeling, insufficient operator self-checking techniques, and f ailure to include the precautions and limitations in that work instructions resu;ted in an emergency shutdown versus a normal shutdown. No safety consequences resulted due to the emergency shutdown. The system e.ngineer provided detailed knowledge and excellent overall suppor .6 (Closen LER 50-412/96-04: Bypass Feedwater Regulating Valve Leakage Leads to Manual Reactor Trip During Shutdown For Refuelin This event was discussed in NRC Inspection Report 50 334(412)/96007. As documented in the inspection report, operators immediate actions to manually trip the reactor were appropriate. During the last two reactor trips (January 6 and March 19,1997), system engineers did not observe excessive bypass feedwater regulating valve leakaqe. Additional monitoring of bypass feedwater regulating valve leakage is scheduled for the next refueling outage. The inspectors determined

~t hat corrective actions were comprehensive and LER commitments were complete .7 (Closed) LER 50-412/96-07: Control Room Ventilation System Purge Mode Operatio On October 15,1996, at 9:25 a.m. operators placed the Unit 2 control room ventilation system in the purge mode to ver.tilate paint fumes from the control

- room. This action temporarily rendered the control room emergency bottled air pressurization subsystem (CREBAPS) and the control room emergency supply -

-filtration subsystem inoperable. At 11:05 a.m., the purge mode was secured and the control ventilation system was restored to the normal lineup, when it was identified that the UFSAR specifies a maximum normal ventilation intake flow rate of 500 cfm for the control room. The purge mode, designed to remove smoke or toxic gases, delivers approximately 20,000 cfm. The licensee determined that TS 3.0.3 should have been invoked at the time of purge initiation. This was reported as an operation prohibited by Technical Specification The licensee determined the root causes were: 1) painting permitted in the control

' room with no provision for mitigating the paint fumes; 2) operators were not aware of the UFSAR design basis for the control room ventilation flow rates; and 3)

operators interpreted paint fumes to constitute the toxic gas described in the control room ventilation system purge procedure. Corrective actions included changes to work control and planning, operator training, and operating procedures. The inspectors concluded the corrective actions addressed the root causes and verified the corrective actions were completed. The Unit 2 UFSAR states the licensee ability to meet 10 CFR 50 Appendix A General Design Criteria (GDC) 19 is based an

.

. . . ..

.

.

. . . _ - _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _

,

'

!

assumed flow rate of 500 cim. The ventilation system operated in the purge mode, without a fire or toxic gas event, placed the plant outside the design basis as described in UFSAR Section 6.5.1.1, " Design Bases." This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-412/97-05-02).

08.8 (Closed) LER 50-334/96-06: Inadequate Testing of Safety injection Relay This event was discussed in NRC Inspection Report 50-334(412)/96004. On November 8,1995, a licensee Safety System Functional Evaluation (SSFE) self-assessment determined that Unit 1 safety injection cutomatic transfer to recirculation latch-in relays were not tested. The relays were subsequently tested in December 29,1995. The f ailure to test the relays is a violation of TS 4.5.2. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-334/97-05 03).

08.9 LER Reportability The inspectors reviewed the reportability requirements associated with Licensee Event Reports. The inspectors determined that the LERs were reported according to the proper criteria; however, LER 50-334/96006 and LER 50-412/96007 were 185 and 65 days after the event date. The inspectors noted that one previous LER was reported outside of the 30 day limit (92 days for LER 50-412/96002). The inspectors noted that the licensee expected to submit an LER on "Proceduralized Voluntary Entry into TS 3.0.3 by Allowing Bypass of Both Source Range Channels input to High Flux Trip," approximately 85 days after the event date. The inspectors noted that extensive changes and corrective actions have been completed in regards to reportability reviews.10 CFR 50.73 requires that Licensee Event Reports must be submitted within 30 days of discovery of a reportable even Failure to submit the report withir. 30 days is a violation of 10 CFR 50.73. This constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy (NCV 50-334&412/97-05-04).

II. Maintenance M1 Conduct of Maintenance M 1.1 Routine Surveillance Observations (61726)

The inspectors observed selected surveillance tests. Operational surveillance tests (OSTs) and operation tranuals (oms) reviewed and observed by the inspectors are listed belo * 10ST4 "6 Month Hydrogen Recombiner 1B Test," Re * 20ST 1.11B " Safeguards Protection System Train "A" SIS Go Test," Rev. 8

• 2OM 30.4.D " Spare Service Water Pump Startup," Rev. 3

_ _ _ _ _ ]

~

I

,

• 10ST 2 " Steam Turbine Drive Auxiliary Feed Pump Test (1FW P-21,"

Re The surveillance testing was performed safely and in accordance with proper procedures. Additional observations regarding surveillance testing are discussed in the following sections. The inspectors noted that an appropriate level of supervisory attention was given to the testing, depending on its sensitivit ,

M1.2 Inadeavate Eauioment Trouble Shootina Activitiss Insoection Scone (62707,92901. 92902,93702)

On July 1,1997, an unplanned engineered safety feature (ESF) actuation occurred during trouble: hooting maintenance activities on the Unit 1 main condenser steam dump system. The inspectors reviewed the event to determine the cause and evaluate licensee follow-up action Observations and Findinas

<

A steam dump valve did not properly control during the June 27,1997, Unit 1 shutdown (Section 1.2), instrumentation and Control (l&C) technicians performed calibration and troubleshooting maintenance activities to correct the problem on July 1,1997. The July 1 steam dump maintenance activities resulted in an inadvertent RCS cooldown. This in turn caused an unplanned letdown system isolation and inadvertent actuation of the P 12 High Steam Flow - Safety injection s

(SI) Block Permissive interlock ESF as described in the timeline belo (1040) I&C technicians commenced work on condenser steam dump valve controller on bank "B" with the "B" steam dump bank isolated (valve MS 2). RCS temperature was being controlled at 547 degrees F by the "A" steam dump bank with a programmed signal sufficient to open one valve (PCV-MS-106A).

(1049) l&C technicians lifted the lead for current loop to PCV-MS-106 PCV-MS-106B goes shut as planned. However, unknown to the l&C technicians or to operators, this open current loop also caused PCV-MS-106A to shut (a second valve, TCV-MS-106A8 on the same bank also gets a closed signal). RCS Tave begins rising slowly since no steam dumps are ope (1104) RCS temperature stabilizes at 550F, as the steam dump demand signal increased sufficiently to open two additional "A" bank valves (TCV-MS-106A4 and TCV-MS-106A5).

. ._

_ _ _ _ _ _ _ _ _ _ _

. _ - _ _ - _ _ - - _ _ _ _ _ _--

_ _ _ _ _

.

(1115) I&C technician relanded the current loop lead on PCV-MS 106B. The

"B" bank was stillisolated by MS 2. However, the current loop now reconnected group 1 of the "A" bank into the control signal. PCV-MS 106A and TCV-MS-106A8 open due to the large Tref Tave mismatch. Four steam dump valves are now open with a large delta T mismatc (1116) RCS cooldown was now excessive. Operators standing near the panel note the large number of open steam dump valves and turned the steam dump control switches to off which closed all steam dump valve (1117) RCS temperature continues down to 543F, which satisfied the P 12 Hi steam flow Si block permissive. The licensee made a 10 CFR 50.72 report regarding this actuatio (1127) The RCS cooldown also causod pressurizer level to shrink. The RCS letdown line isolated due to the low pressurizer level condition. This was an equipment protection isolation feature rather than an ESF actuation and therefore did not require reporting. l&C technicians restore steam dump control and operators restored letdow Inadequate work planning by maintenance personnel and weak questioning by licensed operators led to the ESF actuation. l&C technicians failed to effectively review appropriate control drawings and identify the control interaction between the

"A" and "B" steam dump bank The work instructions directed the technicians to calibrate the I/P PY-MS-106B control instrument per an attached data sheet. There was no specific mention of what other components (e.g., some of the "A" bank steam dump valves) would be affected when leads were lifted to calibrate the controller. It was performed as skill-of-the-craft work, in addition, operations personnel did not sufficiently question the work activity before authorizing it. After authorizing the work, the NSS did not brief his contro!

room staff on this maintenance activity. As a result, reactor operators at the control stations were unaware of the work in progress, and the potential for an unplanned RCS cooldown (with corresponding positive reactivity addition to the core). Both the operations and maintenance departments initiated detailed reviews of this et ant. The inspectors discussed the event with operations personnel and determined that the licensee investigation was probing the event to better understand the causal factor Troubleshooting weaknesses were previously documented in NRC IR Nos. 50-334&412/96-08 and 97-01 and resulted in a non-cited violation. The two examples were inadvertent actuation of the Control Room Emergency Air Pressurization System (CREBAPS) and inadvertent opening of two Unit 2 atmospheric steam dumps during secondary process rack troubleshooting. Inadequate maintenance work instructions and poor operator communications contributed to both event ....

_ - - _ _ _ _ _

_

.

!- 16 l Maintenance affecting ESF equipment or having the potential to offect core reactivity is important and must have appropriate controls implemented to ensure the work is properly performed. TS 6.8.1 requires written procedures.be properly established and implemented for activities referenced in Appendix "A" of NRC Regulatory Guide (RG) 1.33, Rev. 2. RG 1.33 states that maintenance activities that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. 10 CFR 50, Appendix

_

B, Criterion XVI " Corrective Actions" requires measures to be established to assure that conditions adverse to quality are promptly identified and corrected. Inadequate work instructions and poor operator communications resulted in the July 1 inadvertent P 12 interlock ESF actuation. Corrective actions taken to address two previous troubleshooting problems discussed above were ineffective in that they failed to preclude the July 1 event. This is a violation of 10 CFR 50, Appendix "B",

Criterion XVI (VIO 50-334&412/97-05-05).

- Conclusions inadequate maintenance work instructions, job pre-briefing, and poor operator

. communications resulted in an unplanned reactor coolant system cooldown, letdown system isolation, and inadvertent actuation of the P-12 High Steam Flow -

Safety injection (SI) Block Permissive interlock engineered safety featur M8 Miscellaneous Maintenance issues (92902)

M8.1 (Closed) eel 50 334/97 02-04: Missed TS Surveillance Test-EDG Load Test This eel was closed issued by NRC letter dated July 3,1997. (VIO 50 334/EA 97-255 01013)

M8.2 (Closed) eel 50-334&412/97-02-05: Missed TS Surveillance Tests-RHR Pressure Isolation Valve Test '

This eel was closed by NRC letter dated July 3,1997. (VIO 50-334&412/EA 97-255 01023)

M8.3 (Closed) eel 50-334&412/97-02-06: Missed TS Surveillance Tests-Hydrogen Recombiner Test This eel was closed by NRC letter dated July 3,1997. (VIO 50-334&412/EA 97-255 01033)

M8.4 (Closed) eel 50-334&412/97-02-07: Missed TS Surveillance Tests-Untested Logic interlock This eel was closed by NRC letter dated July 3,1997. (VIO 50-334&412/EA 97-255 01043)

_ _ _ _ _ _ - _ -

.

__ _ _ - - _ - - - - _ - _ - - _ _ - - - - - - - - - - - - - - - - - - _ - - - - - - - - - - - -

.

M8.5 (Closed) eel 50-334&412/97-02-08: Missed TS Surveillance Tests-CREBAPS Discharge Trip Valve Test This eel was closed issued by NRC letter dated July 3,1997. (VIO 50 334&412/EA 97 255 01053)

M8.6 (Closed) eel 50-334&412/97-02 09: Missed TS Surveillance Tests Boron injection Flowpath Verification This eel was closed by NRC letter dated July 3,1997. (VIO 50 334&412/EA 97-255 01063)

111. Enaineerina El Conduct of Engineering E Reactor Protection System (RPS) Desian Deficiencies Lnsoection Scope (37551. 92903. 93702)

Engineers questioned whether two RPS trip circuits satisfied IEEE-279 " Criteria for Protection Systems for Nuclear Power Generating Stations," design requirement The inspectors reviewed design documents and observed licensee evaluation of this issue to assess engineering effectiveness, Observations and Findinas On June 27,1997, while evaluating maintenance rule scope applicability, engineers determined that two Unit 1 reactor protection system (RPS) trip functions may not meet design requirements specified in IEEE-279-1971, UFSAR Section 7.2, and the original station safety evaluation report (SER) section 7.2. The NSRB met promptly to discuss the issues. Based on available information, the NSRB concluded that the steam flow /feedwater flow mismatch coincident with low SG level RPS trip (Flow Mismatch Trip) was inoperable because six feedwater transmitters which provide input to the circuit did not satisfy seismic installation requirements. A second issue regarding whether the low-low steam generator (SG, RPS trip function satisfied IEEE-279-1971 " Single Random Failure" requirements was discussed, but was not sufficiently understood for the NSRB to reach a conclusion. The NSRB recommended that the Flow Mismatch Trip be considered inoperable (see Section 01.2). The inspectors observed the NSRB activities and determined that the board members demonstrated a good questioning attitude and clear focus on reactor safety. Engineers had difficulty presenting the second RPS trip issue which had rapidly developed that same da The inspectors reviewed the seismic and single failure design issues with engineer The UFSAR accident analysis credits the SG low-low level trip for protective action, but the Flow Mismatch Trip is not credited. Engineers determined that the SER and UFSAR indicate that all RPS trips will meet all criteria of IEEE-279. IEEE-279 Section 4.7.3 states "Where a single random failure can cause a control system l

..

.

.

.

_____________ _

- - - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

, ..

.

action that results in a generating station condition requiring protective action and can also prevent proper action of a protection system channel designed to protect against the condition, the remaining redundant protection channels chall be capable of providing the protective action even when degraded by a second random failure."

Engineers identified a scenario under which the Unit 1 SG low low level trip did not satisfy this control / protection interaction requirement as follows. A SG level transmitter fails high. This eliminates one of the three protection channel signals to the 2 of 3 coincidence trip logic. The same transmitter inputs the false high level signal to the feedwater control circuit which causes the feedwater regulation valve to shut causing a loss of feedwater to the SG. A second random failure, required by lEEE-279, occurs which causes one of the two remaining SG level channel transmitters to fail as is. The remaining one SG level channel transmitter is unable to generate the SG low-low trip function even though a loss of feedwater and corresponding loss of SG level condition exists. The Flow Mismatch Trip which would normally be credited as an alternate trip feature to protect against a loss of feedwater could not be credited at Unit 1 since feedwater flow transmitters were non-seismically qualified and therefore-did not meet the criteria of IEEE-279 Section 4.7.4. The inspectors concluded that the engineers' evaluation and determination

- of inoperability was technically soun The RPS vendor had previously issued a letter concerning control / protection interaction vulnerability in 1989. The vendor letter indicated that the Flow Mismatch Trip could be used as a backup to the SG low low level trip, but noted that this may wly be valid at higher power levels. A design change was recommended to completely eliminate the control / protection interaction concer The licensee incorrectly concluded that this was not a reactor safety issue at Unit They originally treated it as an equipment reliability issue and assigned a lower -

priority to its resolution. Engineers failed to recognize that the feedwater flow transmitters were not seismically mounted and therefore were unaware that the alternate Flow Mismatch Trip could not be relied upon under design conditions. A design change had been initiated to address the problem, but had subsequently been cancelled due to the lower priority. The control / protection interaction design deficiency was properly corrected during the current inspection period by installation of a SG level median selector switch into the feedwater control circuit. The design change was properly installed and tested prior to unit restar ,

'

The inspectors concluded that the SG low-low level RPS trip function was inoperable under a particular failure mode and this vulnerability existed since original plant startup in 1976 and that operators did not perform the appropriate TS required action until June 27,1997. This is a violation of 10 CFR 50, Appendix B, Criterion 111, " Design Control" and TS 3.3.1.1. This violation resulted from an old design issue which the licensee failed to recognize for over 20 years. This condition was safety significant because this reactor trip is credited in the station's accident analysis as described in UFSAR Section 14. There was no safety consequence to this condition because the SG low-low level trip was not failed to operate and the conditions under which the Flow Mismatch Trip would be relied upon to backup the SG low-low level trip have a very low probability of occurrence. The licensee identified this issue through a voluntary initiative (reassessment of maintenance rule

.

.

.

. .. ..

.

.

. . . ._ _

. _ _ _ _ _ _ _ _ _ _ _ O

scoping applicability to feedwater transmitters), the discrepancy was corrected within a reasonable timeframe following identification, and it is unlikely that this 4 issue would have been identified through routine licensee efforts. The deficiency was identified by the licensee as a result of a voluntary initiative, corrective actions were prompt and comprehensive, the violation was not likely to be identified by routine licensee efforts such as normal surveillance or quality assurance activities and the violation is not reasonably linked to current performance. As a result, this apparent violation of NRC requirements will not be cited in accordance with Section Vll.B.3 of the NRC Enforcement Poliev. (eel 50 334/97 05-07) Conclusions

.

The SG low-low level RPS trip function under a particular failure mode was determined to be inoperable and this vulnerability existed since original plant startup in 1976. Engineering evaluation and corrective actions to address the issue were comprehensive. NRC enforcement discretion was exercised, and no violation issued, in recognition of licensee self identification and correction through voluntary initiative E1.2 Reactor Coolant Pumo Seal Leakoff increase Insoection Scope (37551. 71707)

The inspectors .1erved system engineering response to increases in Unit 2 Reactor Coolant Pump (HCP) sealleakoff for all three RCPs. The inspectors reviewed the data being trended by the system engineers argi the corresponding corrective actions. The inspectors held numerous interviews with the system engineer throughout the inspection perio Observations and Findinos On July 10,1997, operators performed a controlled shutdown on Unit 2 due to RCP sealleakoff reaching 5.9 gpm for the "C" RCP. The inspectors observed the shutdown and related activities (Section 01.3). While shutdown, the licensee replaced the RCP seal packages for the "A" and "C" RCP In March, the Unit 2 RCP sealleakoff for the No.1 seals began to slowly increase for all three RCPs. RCP sealleakoff flow had been steady at approximately 2.3, r 1.2, and 3.3 gpm for RCP "A," "B," and "C," respectively. The sys'em engineer identified the increased leakoff rates during routine trending and monitoring. The alarm response procedure for a high sealleakoff rate instructs operators to trip the reactor at 6.0 gpm. The response is to protect against seat failure for the RCPs and a subsequent loss of coolant accident (LOCA)if the secondary seal would fai c

_ _ _ _ _ _ - _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _

..

The inspectors discussed the increased leakoff flow with the system engineer. The increase leakoff flow for the No.1 seal was attributed to small particles damaging or adhering to the film riding seal (a phenomenon known as " electrophoresis"). The damage to the seals results h a slow degradation to the seal. The system engineer developed several possible r,auses for the small particles and worked closely with the RCP vendor throughout the evaluation, e in early June, the "C" RCP sealleakoff flow approached 5.0 gpm. The system engineer developed an action plan to address the increased sealleakoff. The plan included the following actions: (1) calibration of the sealleakoff flow instrumentation; (2) replacing the sealinjection filter with a new filter; and (3)

monitoring and tightening the sealinjection filter bypass valve. An additional contingency planned was the replacement of the sealinjection filter with a smaller size filter. The action plan and additional contingencies were completed without any noticeable effect on RCP sealleakof In July, the "C" RCP sealleakoff flow reached 5.5 gpm and eventually increased to 5.9 gpm. Additional measures were taken to address the increase in sealleakoff rates and preparations were made to prepare for a shutdown and RCP seal replacement. Mechanics rebuilt the sealinjection line filter housings. During this work, visual observations indicated that some injection flow had been bypassing the filter cartridge. The inspectors observed good system engineering and vendor involvement; however, the root cause of the particles entering the system was not identified. The investigation continued after the inspection period ended with off-site laboratory inspection of the removed RCP seals, Conclusions

The system engineer identified increased Unit 2 RCP sealleakoff flowrates during routine tracking and trending. System engineers, with vendor assistance, developed an action plan and corrective actions to address the increase in sealleakoff. The corrective actions corrective actions were technically sound, but failed to stop the increasing RCP first stage sealleakoff which forced the reactor to shutdown for seal RCP seal replacemen E1.3 Inocerable Unit 1 EmcInency Diesel Generators (EDG)

' Insoection Scope ( 37551.92903)

On July 5,1997, engineers determined that non-seismically qualified relays installed in the EDG room carbon dioxide (CO2) fire suppression systems could make both EDGs inoperable during a seismic event. -The inspectors reviewed applicable design documents and interviewed engineers to assess licensee evaluation of this issu Observations and Findinas Engineers recently identified a longstanding design condition which resulted in an RPS trip function being inoperable (see Section E1.1). The engineering department

' incorporated lessons learned during this discovery into ongoing safety culture

.

.

. - . ..

. _ - _ _ _ - \

. -_

.

training seminars for the engineering staff. In addition, several groups of engineers discussed the extent of condition reviews and how interactions frora one system may adversely affect another system. During these discussions the lead engineer for the Generic Safety Issue A-46 " Seismic Qualification of Equipment in Operating Plants" questioned whether previous resolution to A 40 outlier issues remained vali The engineer reviewed the reported outliers and determined that the non-seismically qualified CO2 fire suppression system actuation relays could inadvertently operate during a seismic event. This would fill the Unit 1 EDG rooms with CO2 and displace the air. The Unit 1 EDGs, which take suction for combustion from the EDG H room, would be unable to support cylinder combustion, and would be inoperabl UFSAR Section 9.10 states that the fire protection system is designed on the basis that rupture or inadvertent operation will not significantly impair the safety capability of structures, systems, or components important to safety or designed to seismic category I requirements. Based on this information, the engineers initiated a condition report, informed the NSS, and the EDGs were declared inoperabl Compensatory measures were promptly taken to disable the automatic actuation feature and station dedicated fire watch personnel in both Unit 1 EDG rooms, The inspectors determined that the operability determination and compensatory measures were both prompt and appropriat The inspectors discussed this issue with engineers including an extent of condition review performed by the lead A 46 program engineer to reassess the remaining A-46 program outliers. No additional immediate operability concerns were identified prior to the end of the inspection period. The engineer demonstrated a strong understanding of A-46 program requirements and related industry informatio Permanent actions to upgrade the CO2 actuation relays to seismic qualification were initiated. The compensatory fire watches remained in place at the end of the report period.

The inspectors determined that both EDGs had been technically inoperable for prolonged periods since original unit operation in 1976. Operators failed to recognize the EDG inoperability and therefore failed to implement the actions required by TS 3.8.1.1. This was a violation of regulatory requirements. The inspectors determined that this violation would most likely have been identified by the licensee's ongoing 100% UFSAR verification initiative. The deficiency was identified by the licensee as a result of a voluntary initiative, corrective actions were prompt and comprehensive, the violation was not likely to be identified by routine licensee efforts such as normal surveillance or quality assurance activities and the violation is not reasonably linked to current performance. As a result, this apparent violation of NRC requirements will not be cited in accordance with Section Vll. of the NRC Enforcement Poliev. (eel 50 334/97 05-09)

. .. .. .

. .

.. _ - _ _ _ _ _ _ _ _ .

_ - - _ _ - _ _ _ _ - _ -

.-

.

22 Conclusions Engineers identified that non seismically CO2 fire suppression system actuation relays resulted in both Unit 1 EDGs being inoperable since original plant operatio This discovery resulted from recent licensee initiatives to enhance safety culture and questioning attitudes on the part of engineering personnel, in recognition of

_

licensee self identifica:lon and corrective action initiatives, this violation will not be cite E1.4 Unit 1 Containment Isolation Valve Verification Insoection Scoos (37551,92903)

During the recent Unit 1 shutdown, licensing engineers questioned the adequacy of several containment penetration isolations. The inspectors evaluated licensing and engineering resolution of these issues,

. Qhservations and Findinos

- Licensing engineers questioned whether the feedwater injection line and associated j isolation valves as specified in the Licensing Requirements Manual (LRM)

containment isolation valve (CIV) table met seismic requirements. Subsequent

'

evaluations confirmed that the feedwater injection line and the associated CIVs

.were seismically qualified. On reviewing the issue further, the inspactors and licensing personnel noted several differences between the UFSAR CIV table and the administratively controlled LRM CIV table. Licensed operators used the LRM CIV table as e reference to identify CIVs and containment penetrations, o The Vice President, Nuclear Operations, directed that the LRM CIV table and the UFSAR CIV table be validated prior to Unit 1 restart. The inspectors c,bserved licensing engineers and reviewed approximately 20 satety evaluations written to support changes to one or both documents to resolve differences. The safety evaluations were of good qualit During the review, licensing engineers determined that three installed CIV check valves did not meet the UFSAR specified design requirements and, therefore, the -

unit was in an unanalyzed condition. The unit was maintained in mode 5, for which containment requirements do not apply, until the issues were resolved. UFSAR Section 5.3.4.2 states that all(Westinghouse) check valves, when used as containment isolation valves, are loaded to close against a 2 psi positive differential pressure. The UFSAR further states that weight and spring loaded check valves used for containment isolation are designed to require a differential pressure (D/P)

across the valve in the normal flow direction exceeding the expected post design basis accident (DBA) D/P between atmosphere and containment (about 1.2 psi). . As 7 a result, leakage into containment through incoming lines with check valves inside l containment caused by passivo failures of such lines between the containment penetration and the outside isolation is prevented. Beaver Valley accident analysis assumes that safety systems restore containment to subatmospheric pressure within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> fellowing a DBA for their 10 CFR 100 dose calculations.

.

.

. . . . .

. .

. . . . . . _ . . . . . . . . . . . .

-

.- - . . . .- .. .

. -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

.

Licensing engineers determined that three check valves,1SA 15,11A 91, and 1RC-72 were not weight or spring loaded. Although the valves were on small(21/2",

1", and 3")line penetrations, they still did not meet the intended design and therefore invalidated the previous accident analysis. One of the lines was cut and capped. The other two valves were replaced and ratested with corroctly designed valves. No similar deficiencies wore identified on either uni This design deficiency existed and therefore containment was in an unanalyzed condition since original plant operation in 1976. While the likelihood of passive failure of these lines during a DBA is low, containment integrity and the duration of this condition is safety s?gnificant. Operators failed to recognize this condition and implement the actions required by TS 3.6.3.1 until July 10,1997. This was a violation. This conditlon was identified and promptly corrected through a voluntary licensee initiative. Appropriate actions were taken to evaluate extent of condition and applicability to Unit 2. The deficiency was identified by the licensee as a result of a voluntary initiative, corrective actions were prompt and comprehensive, the violation was not likely to be identified by routine licensee efforts such as normal survsillance or quality assurance activities and the violation is not reasonably linked to current performance. As a result, this apparent violation of NRC requirements witl not be cited in accordance with Section Vll.B.3 of the NRC Enforcement Polic (eel 50 334/97 05 09)

, Conclusions Licensing engineers determined that three installed CIV check valves did not meet the UFSAR specified design requirements and therefore the unit containment was in an unanalyzed condition since original plant operation. The unit was in cold shutdown at time of discovery. The deficiencies were promptly corrected and retested prior to changing modes, in recognition of identification and timely correction through a voluntary licensee initiative, this violation will not be subject to

- enforcement actio IV. Plant Support

<

R1 Hadiological Piotection and Chemistry (RP&C) Controls R1.1 Imolementation of the Radiolooical Environmental Monitorino Prooram Insoection Scope (84750)  !

The inspector reviewed the controls and surveillance requirements of the REMP, including sampling and analysis of environmental media, land use cen::us, and interlaboratory comparison program against Section 3.0 and Appendix C of the ODCM and Section 2.8 of the UFSA ,

_ _ _ _ _ _ _ _ _ _ - _ _

- _ - _ _ _ - _ - _ _ - _ _ _ _ _

O

b. Observations and Findinos The REMP was implemented by Safety and Environmental Services (SES) of the Health Physics (HP) Department. The inspector observed the contractor personnel exchange air particulate filters and charcoal canisters from selected air samplers, collect milk from a milk farm, and visited several selected thermoluminescent dosimetry (TLD) locations for direct radiation measurements. The inspector discussed certain sample techniques not observed such as collection of soil, vegetation, and sediment samples. Sampling practices were designed to minimize the chances of cross contamination. Samples wero collected from the locations and s

at the frequencies required by the TS and ODCM, The analytical results demonstrated that the types and frequencies of analyses were performed as required. The inspector noted that radiological dose to the public was in conformance with technical specification The inspector observed the contractor spray the air particulate filters with a commercial brand clear acrylic. A light coat of a clear acrylic was sprayed onto each filter to affix the particulate material to the filter. The inspector questioned the eftict of the scrylic on the gross beta analysis results. The licensee did not know

$ the effect of the acrylic on the analysis. The licensee did not prepare the calibration standards by spraying with the acrylic and consequently had no basis to ascertain if the acrylic deposited on the sample resulted in any significant analysis error, particularly with regard to beta particle attenuation. Since the licensee did not consider attenuation of beta particles using this method of sample preparation and the effect of the acrylic on the beta analysis results is unknown, then the gross beta analysis results of the air particulate filtors may be suspect. This matter is considered an unresolved item pending review of the effect of the sample preparation method. (URI 50 334&412/97 0510)

The licensee continued to collect and analyze supplemental samples in addition to the routine samples required by Table 3.12-1 of the ODCM to enhance the data source of the environmental monitoring program. The type, frequency, and analytical results of the routine and extra samples were documented in the Annual Radiological Environmental Reports for 1995 and 1996 (annual reports).

Program changes implemented in January 1996 were documented in the annual report for 1996. The licensee removed from the REMP analyses not specifically required by the ODCM. These program changes and the justification for the changes were reviewed by the inspector. The inspector noted that the ODCM, UFSAR, and the EPM did not appear to be similar. This had also been documented as a deficiency in the 1996 Quality Services Unit (OSU) audit report. (See Section R7.1 of this report for details.) Overall, the inspector noted that the licensee determined that the program changes would not impact the intent of the REMP cnd there were no UFSAR discrepancies. The inspector noted that the licensee continued to collect more samples than required by the ODCM and included the extra samples in the procedure EPM 3.01, " Environmental Sampling."

i l

_ _ _ _ _ _ _ _ _

.

The 1996 land use census was performed by a consultant during July 29 -

August 2,1996, using the guidance in procedure EPM 2.01, " Description of the Radiological Environmental Monitoring Program" and Sections 3.12.3 and 4.12. of the ODCM. Performance of the land use census was thorough and complet No program changes mre required as a result of the censu The inspector reviewed the wind direction assessments (wind roses) from the past five years and compared them to the pre-operational wind roses to detect changes, if any, in the prevailing wind directions. No significant changes were determine The environmental monitoring control and li.dicator stations are still vali Analytical data from January April 1997, was reviewed for frequency and type of analysis required in the ODCM. The licenseo performed the types of analyses required at the frequencies specified. The Inwer limits of detection (LLD) were me No anomalous data or trends viere note The health physics specialist, SES, who was responsible for the REMP performed non-routine (unscheduled) surveillances to evaluate the contractor's performance and maintain oversight of the REMP implementation. The specialist documented the surveillances and tracked recommendations and discrepancies for trending and performance assessment. The inspector reviewed surveillances from January to June 1997 and noted that four surveillances had been performed. The surveillances verified performance against procedures and regulatory requirements. No discrepancies were identified, Conclusions Based on the above review, observations, and discussions, the inspector determined the overall implementation of the REMP was effective and performance continued to be good. However, the gross beta analysis results are suspect due to the practice of spraying a clear acrylic on the air particulate filters without assessing or knowing the affect on the accuracy of sample analysis. The item is considered unresolved pending review to determine if any analytical errors were introduced by this practic R1.2 Meteoroloaical Monitorina Proaram (MMP) Insoection Scope (84750)

The Meteorological Monitoring Program (MMP) was inspected against TS 3/4.3. Unit 1 and 3/4.3.3 Unit 2, and Section 2.3.3 of the UFSAR. The following activities were conducted to assess the licensee's ability to implement the progra * Review of calibration procedures, calibration results, and channel check logs;

• Review of calibration results of individual sensors;

• Discussion of data acquisition and availability of data;

.

.- .

_ _ _ _ _ _ _

_ _ _ _ . .

• Observation of the material condition of meteorological equipmen b. Observations and Findinos There were three groups whicn had certain responsibilities to keep the meteorological monitoring equipment and computers operating properly. The Instrument and Controls Department (l&C) had the responsibility for emuring the meteort, logical monitoring instrumentation (wind speed, wind direction, temperature)

were calibrated and maintained. A contractor used the licensee's procedures to perform calibrations three times per year, more often than the semiannual TS requirement. The inspector reviewed the calibration results from December 1995 through April 1997. The calibrations were performed according to the procedures and were within the acceptance criteria. The Radiological Engineering and Health (REH), HP Department ensured data collection was continuous and the computers ~

were operating properly. The Senior HP, once per day, checked data acquisition capability of the meteorological computer and investigated any anomalous data; and every week, performed a functional check of the computer. The daily acquisition checks were performed according to procedure RE 5.214, " Monitoring System Operation-Daily" and the weekly functional checks were performed according to procedure RE 5.301, " Meteorological Data Collection Operation," The inspector reviewed the results from June 11 through May 27,1997 and verified that both procedures were performed. The Operations Department had responsibility to perform a daily channel check required by TS Operations also was responsible for two surveillance tests related to the MMP. The tests were performed using ccmbined unit procedures 1/2 OST 45.7, " Diesel Test" and 1/2 OST 45.8,

" Meteorological System Test." The inspector reviewed the operations logs and the test results and determined that they were performed during the frequencies specified and that the results were acceptabl The inspector visited the meteorological equipment building to observe the condition of the instrumentation. Overall, the instrumentation was operable with the exception of the strip chart recorders. None of the recorders were operating. Tags with work request submittal dates were on the recorders indicating some recorders were inoperable since April 1997 and others inoperable since May 1997. The licensee stated that intermittent problems with the strip chart recorders were noted since 1995. Repeated attempts to fix and keep the recorders operable had been unsuccessful. The licensee stated that the recorders will be repaired during the

<

next calibration scheduled for August 199 l&C submitted one work request in October 1995 to fix all the recorders instead of submitting individual work requests for each recorder. Shortly thereafter, a design change package (DCP 2166) had been initiated to replace all the met tower recorders with two data loggers. The chart recorders are old and becoming obsolete, as are the wind speed, wind direction, and temperature sensors. The DCP has not yet been completed because the recorders were considered low priorit The inspector discussed this issue with the Director of Design Basis Engineering (DBE), Nuclear Engineering Department. Design Basis Engineering had been reorganized effective April 9,1997 and a new group had been created to focus on design changes exclusively. The design basis engineering director stated that the

- _ - _ - _ _ _ - _ _ _ _ _ _ - . _ _ _ _

.

recorders remained a low priority, however, completion of DCP 2166 was scheduled for May 1,1998. The inspector reviewed the schedule and noted that the schedule had been based on an objective screening criteria (i.e. Maintenance Rule, Probabilistic Risk Analysis, system engineering priorities, temporary modifications, and TS) and replacement of recorders was scheduled for May 1, 199 The strip chart recorders were considered a backup method of data acquisition and were rarely used because of the high reliability of the computer. However, on February 14,1997, power was lost to the site emergency response facility (ERF)

from 4:53 a.m. -12:05 p.m. (6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) due to a spurious signal from a programmable logic controller at the ERF substation. (See Section P2.1 of the Integrated Inspection Report 50 334/97-01 and 50-412/97 01, dated April 7,1997 for details.) This loss of power to the ERF meant that the computer also lost power and was unable to obtain the meteorological data from the sensors and the strip chart recorders were needed to collect the data, in this case, the strip chart recorders had been operating and the meteoro!ogical data had been collecte Although the recorders were working at that time, they were not considered reliabl Conclusion Based on the above observations, the licensee conducted an effective MMP overal The meteorological instruments, in general, were in good working condition but are old and facing obsolescence. Backup strip chart recorders were inoperable at the time of the inspection; however, no violation of any regulatory requirement was note .

R2 Status of RP&C Facilities and Equipment Insoection Scope (8475Q1 The operational and physical condition of equipment used for environmental sampling (air samplers and water compositors) to implement the REMP had been evaluated, Observations and Findinas The air samplers and water compositors were in good operational and physical condition. Components of the sampling equipment were periodically checked, and when necessary, replaced, or fixed. During weekly exchanges of the air particulate filters and air iodine charcoal cartridges, the contractor verified the pump air flow was one cubic foot per minute (cfm) by measuring the length of time the gas meter dial indicated 1 cubic foot (ft'). According to the procedure 2.01, " Description of REMP", the pump should draw 1 ft' of air across the filters within 55 to 58 seconds and if it does not, the flow regulator is adjusted accordingly. The possibility of masking problems and errors associated with timing the air flow was discusse The inspector reviewed the air sample logs and determined that adjustment appeared to be random and no operability concerns were eviden l

__j

_ _ _ _ _ _ _ _ _ _ _

.

The licensee now has a program to calibrate the Dry Gas Test Meter annually. The procedure EPM 3.02, " Maintenance and Calibration of Environmental Sampling Equipment" had been revised to reflect an annual calibration frequency. The meter will be calibrated annually according to this procedure. The program was implemented as a result of a discrepancy identified during the 1996 OSU audit regarding calibration frequency. A discrepancy report was generated and assigned to SES. In 1996, SES sent the DGTM to be calibrated using a 2' Bell Prover. The previous, calibration had been performed in 1992 and the DGTM had been used to calibrate the air samplers in the field. The inspector reviewed the results to determine whether the DGTM was stillin calibration in the interim. Two flow rates were tested (high and low), and the results showed a 0.0% difference compared to the Bell Prover for both flow rates. The inspector determined that the meter calibration was valid from 1992 through 1996 based on this set of results, c. Conclusions Based on the above review, observations, and discussions, the inspector determined the overall conoition of the air samplers and water compocitors was good and the air sampler calibration was vali R5 RP&C Procedures and Documentation Insoection Scone (84750)

The inspector reviewed the 1995 and 1996 Annual Radiclogical Environmental Reports, and selected HEMP procedures, Observations and Findinas The annual radiological environmental monitoring reports for 1995 and 1996 provided a comprehensive summary of the results of the REMP around the Beaver Valley site and met t'a TS, Section 6.9.1.10 (both units) reporting requirement No omissions, mistakes, or obvious anomalous results and trends were note The licensee's procedure manual, Environmental Programs Manual (EPM), included four chapters related to the REMP. The chapters were (1) Administrative, (2)

Description of REMP, (3) Field Procedures, and (4) Dose Calculations. The procedure contained sufficient guidance to conduct an effective REM Administrative revisions had been made to clarify procedures. The two administrative procedures were added to the manual as a result of a deficiency identified during the 1995 QSU audit. The procedure, EPM 1.01, " Control of the Environmental Programs Manual", described the method to be used to control the EPM procedures. The procedure, EPM 1.02, " Preparation of Procedures", described the method to be used to prepare REMP procedures. The inspector noted that the calibration frequency of the dry gas test meter had been included to the appropriate field procedure, l

. - _ - _ _ - _ _ _ _ _ _

.

.

-_ ___-_ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

29 c. Conclusion Based on the above observations and review, overall the licensee's procedures provided the appropriate guidance to implement an effective REM R6 RP&C Organization and Administration a. Insoection Scone (84750)

The inspecter reviewed the organization and administration of the REMP and MMP, including any organization changes and oversight of the REMP and MMP since the previous inspection, b. Observations and Findinas There were no organization changes relative to implementation of the REMP or the MMP since the previous inspection of these creas, c. Conclusi2D Overall, the organization which implements the REMP and the MMP has remained consisten R7 Quality Assurance in Radiological Protection and Cheulstry Activities R7.1 Quality Assurance Audit Proaram Insoection Scope (84750)

The licensee's audit program was reviewed against TS Section 6.5.2.8 (both units).

The inspector reviewed the Quality Services Unit (OSU) audit reports and a self-assessment conducted by SES, HP Departmen Observations and Findinas The licensee's audit program was the responsibility of the QSU The inspector reviewed the " Site Radiological Effluent and Environmental Monitoring Programs" audit reports for 1995 (BV C-95-08) and 1996 (BV-C-96-06). Three of the seven principal areas evaluated during the audits were REMP, Problem Identification and Resolution, and Performance Standards and Performance Measures. Both audits identified several deficiencies. The 1995 (BV C-95-08) audit identified a total of five deficiencies, one of which was related to the REMP procedures. One procedure from chapter 2 and from chapter 3 of the EPM needed administrative clarificatio The 1996 (BV-C-96-06) audit identified twelve deficiencies, two of whicn were related to the REMP. The first deficiency identified sampling location differencas between the UFSAR, ODCM, and EPM. The reason for the finding was partly due to the confusing language in the UFSAR which described the current REM Closure of this deficiency report was still open pending verification of corrective actions. The inspector discussed the corrective actions with the QSU auditor and

.. .. .

.. . . . . ..

. ..

_ _ _ .

.

SES Changes to the UFSAR had been made by SES to clarify the wording which described the REMP. The changes had been submitted to licensing within the required response due date. Licensing was awaiting approval from the NRC at the time of this inspection. The second deficiency was related to the calibration frequency of the dry gas test meter. This defici, ::y had been close The inspector noted the SES, HP Department conducted a self-assessment of the REMP program. The inspector reviewed the self assessment procedure and the results. The procedures included personnel responsibilities, auditing instruction ( audit plan, scope, standards, assessment), report format, response to recommendations, follow up, problem identification and resolution. The results showed that the licenseo's self assessment of the REMP strictly followed the procedure and was comprehensive. Every aspect of the REMP program was reviewed. Many issues were recommendations for improvement (generally administrative in nature) and several findings were consideteo program discrepancies. The licensee had defined a low tolerance level to identify program discrepancies. All recommendations and discrepancies were accepted, resolved, and incorporated in the REMP program. One discrepancy renained open pending completion of a UFSAR change request approval. The inspector determined that the discrepancies were appropriate, root causes were properly identified, where applicable, and corrective actions were timely and appropriate. The licensee plans to follow the corrective actions to verify effectiveness, Conclusion Based on the above review of the audit reports and the self-assessment report, the inspector determined that both audits were comprehensive and of excellent technical depth, The auditor's ability to identify deficiencies, strengths and weaknesses was excellent. The SES group conducted an objective self assessment by comparing all the details of the REMP with the applicable TS and ODCM, UFSAR requirements, and the Regulatory Guides and ANSI Standards. As a result of the self-assessment, the SES group was able to make improvements based on their own findings. The SES group conducted a comprehensive self assessmen R7.2 Quality Assurance of Analvtical Measurements Insoection Scone (84750)

+

The inspector reviewed the Quality Assurance (QA) and Quality Control (OC)

programs against Section 3/4.12.3 of the ODCM and recommendations of Regulatory Guide 4.15, " Quality Assurance for Radiological Monitoring Programs (Normal Operations) - Effluent Streams and the Environment" to determine whether the licensee had adequate control with respect to sampling, analyzing, and evaluating data for the implementation of the REM .. .

. . . ..

.. .

- - _ _ _ - _ - _ _ - _ _ _ _ _ _ _ - _ _ - - _ _

,

L 31 . Observations and Findinas The contractor laboratory, Teledyne Brown Engineering Laboratory (TBE), continued to analyze the REMP samples and conduct quality control and quality assurance program The TBE implemented an interlaboratory ec:nparison program, required by the TS, through continued participation with Environmental Protection Agency (EPA)

drinking water program and the program provided by Analytics, incorporated. The-inspector reviewed the analytical results of these programs and noted the results-were within the established acceptance criteria, Conclusion Based on the above observations, the inspector determined that the performance of the contract laboratory was good and the interlaboratory program was effectiv P3 EP Procedures and Documentation P In-Office Review of Licensee Procedure Chanaes (82701)

An in office review of revisions'to the Emergency Plan implementing Procedures

/

submitted by the licensee was completed, i A list of the specific revisions reviewed are included in Attachment 1 to this report. Based on the licensee's determination that the changes do not decrease the overall effectivehess of the Emergency Plan, and thr.t it continues to meet the standards of 10 CFR 50.47(b) and the requirements of Appendix E to Part 50, NRC approval is not required for those changes. -Implementation of those changes will be subject to inspection in the futur L1- Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the

- Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compared plant practices, procedures and/or parameters  :

to the UFSAR descriptio While conducting the inspections discussed in this report, the inspectors reviewed

_ the applicable portions of the UFSAR that related to the areas inspected. The -

inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters, with the exception. of the description of dew point instrumentation for the meteorological monitoring program found in Section 2.3.3 of the UFSAR. Discrepancios are also discussed in Sections E1.1, El.3, and E1.4. The licensee is currently committed to providing a corrected UFSAR to the NRC in 1998. Corrections to this section will be inc'uded in this submissio ,

h

- _ _ . _ - _ _ _ - - . - _ _ _ - _ - _ _

- -__-_-____- _ _ ___-_---__---_---

.

V. Mananoment Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 24,1997. Results of the radiological inspection were presented to licensee management on June 13. The licensee acknowledged the findings presente Tiie inspectors asked the licensee whether any materials examined during the inspection

_

should be considered proprietary. No proprietary information was identifie X2 Pre Deciolonal Enforcement Conference Summary On June 13,1997, a pre-decisional enforcement conference was held at the Region I to discuss TS surveillance test program weaknesses. A copy of the slides presented by the licensee at the conference is attache X Management Meeting Summary X3.1 Maintenance Rule Baseline insoection

'

The maintenance rule baseline inspection was conducted at Beaver Val!cy Power Station from July 8 through July 12. The NRC inspection team was led by Mr. J. H. Williams of the Region l Operator Licensing and Human Performance Branch. The results of the inspection were discussed with OLC management at an exit meeting on July 12 at the site and will be promulgated via separate correspondenc Attachment: Predecisional Enforcement Conference Slides

_ ____________ -

- -_ __ - _ - _ _ __ _ _ ___-_ ___-___ ______

.C

PARTIAL LIST OF PERSONS CONTACTED Licensee J. Cross, President, Generation Group S. Jain, Vice President, Nuclear Services -

B. Tulte, General Manager, Nuclear Operations C. Hawley, General Manager, Maintenance Programs Unit J. Arias, Director, Safety & Licensing K. Ostrowski, Manager,-Quality Services R. Vento, Manager, Health Physics D. Orndorf, Manager, Chemistry O. Arredondo, Nuclear Procurement ,

F. Curi, Manager, Nuclear Construction C. Custer, Acting Manager, System and Performance Engineering R. Hart, Senior Licensing Supervisor, Compliance W.' Kline, Manager, Nuclear Engineering R. Hruby, Director, Nuclear Engineering B. Sepelak, Senior Engineer, Nuclear Safety T. Cosgrove, Technical Assistant to Vice President Nuclear Operations June 13 Radiological Protection Exit

A. Bevan, Health Physics Specialist, SES, HP

J. Bowden, Director, Instrument & Controls

9. Hart, Senior Licensing Supervisor

C. Hawley, General Manager-MPU R. Hruby, Jr., Director, Design Basis Engineering

H. Koehnke, Senior QSU Specialist

S. LaVie, Senior HP, REH, HP

W. McIntire, Director SES, HP D. Murcko, l&C Supervisor

B. Sepelak, Licensing Engineering

R. Vento, Manager Health Physics

Denotes those present at the exit meeting on June 13,1997,

-

--

- -

' -

-

- -

.-

. . _ _ _ _ _ _ _ _ . . . _ _

.. - _ _ - _ - _ - - _ - - _ _ _ _ _ - - - _ - _ - _ _ _ _

.. .. .

. .. . . . . .

C

INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726:. - Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations-IP 82701: Operational Status of the Emergency Preparedness Program IP 84750: Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Follow up Operations

_

IP 92902: Follow up - Maintenance IP 92903: Follow-up - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED AND CLOSED Opened 50-334&412/97 05-05 VIO Inadequate control of troubleshooting activities leads to ESF actuation (Section M1.2)

.50-334&412/97-05 10 URI Clear Acrylic Spray used to Affix Particulates to the Air Particulate Filters and Not Accounting for Beta Attenuation (Section R1,1)

50-334&412/EA 97-076 - V_IO . Configuration Control-Failure to implement 01013 Procedures as Written (Section 08.1)

.

50 334/EA 97-076 01023 VIO Falsure to Monitor Oxygen Concentration During WGDT Filling Operations (Section 8.1)

50-334&412/EA 97-076 VIO Inadequate Corrective Action-Failure 'to 01033 Identify / Correct Configuration Control Deficiencies (Section 08.1)

50-334/EA 97-255 01013 VIO Missed TS Surveillance Test-EDG Load Test (Section M8.1)

50 334&412/EA 97 255 VIO Missed TS Surveillance Tests-RHR Pressure 01023- Isolation Valve Test (Section M8.2)

t 50-334&412/EA 97-255 VIO Missed TS Surveillance Tests Hydrogen 01033 Recombiner Test (Section M8.3)

' 50 334&412/EA 97-255 - VIO - Missed TS Surveillance Tests-Untested 01043 Logic Interlock (Section M8.4)

.. . .

_ . . _ - _ _

_ _ _ _ _ - _ - _ _ _ _ _ _ _ _ - _ _

..

.. .. . . ..

.

,

50 334&412/EA 97 255 VIO Missed TS Surveillance Tests CREBAPS 01053 Discharge Trip Valve Test (Section M8.5)

50 334&4'12/EA 97 255 VIO Missed TS Surveillance-Tosts Boron injection 01063 Flowpath Verification (Section MB.8)

G91d-50 334&412/96 10-01 - URI Repetition of Configuration Control Problems Despite Previous Corrective Actions (Section 08.1)

50 334/97 02-04 eel Missed TS Surveillance Test EDG Load Test (Section M8.1)

50 334&412/97-02-05 eel Missed TS Surveillance Tests-RHR Pressure isolation i Valve Test (Section M8.2)

50 334&412/97-02 06 eel Missed TS Surveillance Tests Hydiogen Recombiner Test (Section M8.3)

50-334&412/97 02-07 eel Missed TS Surveillance Tests-Untested Logic Interlock (Section M8.4)

'50-334&412/97-02-08 eel Missed TS Surveillance Tests CREBAPS Discharge Trip Valve Test (Section M8.5)

50 334&412/97-02-09 eel Missed TS Surveillance Tests Boron injection Flowpath Verification (Section M8.6)

50-334/96-06 LER Inadequate Testing of Safety injection Relays (Section 08.8)

50 412/96-04 LER Bypass Feedwater Regulating Valve Leakage Leads to Manual Reactor Trip During Shutdown For Refueling (Section 08.6)

50 412/96 07 LER Control Room Ventilation System Purge Mode Operation (Section 08.7)

%

-50-334&412/97-11 LER . Inadequate Testing of Unit 1 Solid State Protection System Relays K630A and K630B (Section 08.2)

50 334&412/97-13 LER Failure to Perform DC Bus Train Weekly Breaker Alignment as Required by TS (Section 08.3)

,

.

.. _ _ - - _ _ _ - _ _ _ - - _ _ - _ . _ _ _ _ . _- -- _ -

. . . . . .. ..

.

'

Closed 50 334&412/97 14 LER Failure to Check for and Remove Accumulated Water in the EDG Day Tanks as Required by TS (Section 08.4)

Qoened/ Closed 50-324&412/97 05 01 NCV Source Range Nuclear Instrumentation and Supplemental Leak Collection and Release System Functions Inoperable / Procedure Weakness (Section 04.1)

50-412/97 05-02 NCV Condition Outsida of Design Basis - Control Room Ventilation in Purge Mode (Section 08.7)

50-334/97 05 03 -NCV Inadequate Testing of Safety injection Relays (Section 08.8)

50 334&412/97 05-04

'

-

NCV Failure to Report LERs Within 10 CFR 50.73 Time Limits (Section 08.9)

50-334&412/97-05 06 NCV - Missed surveillance tests (Section O3.1)

50 334/97 05-07 eel RPS Design Deficiencies (Section E1.1)

50 334/97 05-08 eel Inoperable EDG (Section E1.3)

50-334/97 05-09 eel . Containment Rod Isolation Valve Deficiencies (Section E1.4)

l

. - . ..

.. .. ..

- _ _ - _ _ _ _ _ _ . ___ _

.

t 37 LIST OF ACRONYMS USED BCO Basis for Continued Operation BVPS Beaver Valley Power Station efm cubic foot per minute CLV Containment isolation Valve CO2 Carbon Dioxide CR Condition Report CREBAPS Control Room Emergency Bottled Air System DBA Design Basis Accident

-

-

DBE Design Basis Engineering DCP Design Change Package DG Diesel Generator DLC Duquesne Light Company EDG Emergency Diesel Generator EPA Environmental Protection Agency EPM Environmental Programs Manual ERF Emergency Response Facility ESF Engineered Safety Feature gpm gallons per minute HP Health Physics I&C Instrument & Control LCO Limiting Condition for Operation LER Licensee Event Report LLD Lower Limits of Detection LOCA Loss of Coolant Accident LRM L!:ensing Requiremont Manual MMP Meteorological Monitoring Program NCV Non-Cited Violation NOV Notice of Violation NSRB Nuclear Safety Review Board NSS Nuclear Shift Supervisor ODCM Offsite Dose Calculation Manual OM Operation Manual OPPS Overpressure Protection System OSC Onsite Safety Committee OST Operational Surveillance Test PDR Public Document Room PLC Programmable Logic Controllers PMP Post Maintenance Testing PMT Post Maintenance Testing PORV Power Operated Relief Valve QA Quality Assurance QC Quality Control OSU Quality Services Unit RCP Reactor Coolant Pump RCS Reactor Coolant System REH Radiological Engineering & Health

- _ _ _ _ _

- _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ - - _ _ _ _ - - - - - _ - - - - _ - - - _ - - _ - - - - - _ - - .

.

REMP Radiological Environmental Monitoring Program RG Regulatory Guide RHR Residual Heat Removal RP&C Radiological Protection and Chemistry RPS Reactor Protection System SES Safety & Environmental Sorvices SG Steam Generator SI Safety injection SLCRS Supplemental Leak and Collection System SRNI Source Range Nuclear instrument SRO Senior Resctor Operator SSFE Safety System Functional Evaluation SWS Service Water System TBE Teledyne Brown Engineering Laboratory TLD Thermoluminescent Dosimetry TS Technical Specifications UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation

.

__

. . . ..

- .. .

.

EMERGENCY PREPAREDNESS PLAN PROCEDURES REVIEWED D_ocument Document Title Revision (s)

EPP/l 2 Unusual Event 10,11 EPP/l 3 Alert 10,11 EPP/l 4 Site Area Emergency 10,11 EPP/l 5 General Emergency 10,11 IP Notifications 14,15 IP Emergency Support Centers (OSC& ROC) Activation, Operation and Deactivation 9 IP Emergency Response Organization Teams 3 IP Emergency Radiological Monitoring 7 IP Onsite Monitoring For Airborne Release 7 IP Offsite Monitoring For Airborne Release 7 IP Offsite Monitoring For Liquid Release 6 6 IP Emergency Environmental Monitoring 6, 7 IP Environmental Assessment and Dose Projecthn Controlling Procedure 8 IP 2. Dose Projection Backup Methods 8 IP 2. Dose Projection ARERAS/ MIDAS With FSAR Defaults 9

'P 2. Dose Projection ARERAS/ MIDAS With Real Time inputs . 10 IP 2. Dose Projection ARERAS/ MIDAS With Manual inputs 10 IP 2. Alternate Meteorological Parameters 8 IP 2. Dose Projection By Hand Calculation Known isotopic Release 6 IP 2. Release Source Term Determination Based on Field Measurements 6 IP 2.6.10 Ground Contamination Assessment and Protective Actions 6 IP 2.6.11 Dose Projections Miscellaneous Data 8

- IP 2.6.12 Dose Projections ARERAS/ MIDAS With Severe Accident Assessment _

IP 2. Liquid Release Estimate Computer Method 7 IP Site Assembly And Personnel Accountability 8 IP Emergency Response Protection 8 IP Traffic And Access Control 8 IP Offsite Protective Actions - 7 IP Emergency Personnol Monitoring 7 IP. Re-entry to Affected Areas Criteria and Guidelines 8 IP Termination of the Emergency and Recovery 7 IP Emergency Equipment inventory and Maintenance Procedure 8

).

-

, __ -. - - - - - _ _ - - . - - - - - - - - - . -

- -

40 Rocument Rorgment Title Revision (s)

IP Administration of Emergency Preparedness Plan Drills and Exercises 7 IP Fires in Radiologically Controlled Areas 8 IP Nuclear Communications Emergency Response Organization Controlling Procedure 8 IP Activation, Operation and Deactivation of Nuclear Communications Emergency Operations Facility (EOF) 1 IP Activation, Operation and Deactivation of Nuclear Communications of the Joint Public Information Center (JPIC) 1 IP Activation, Operation and Deactivation of the Nuclear Communications Corporate Offices 1 IP 1 Emergency Hesponse Organization Corporate Support 1

.

,. _ _ _ . _ _ _

.

. ,

ATTACF. MENT Predecisional Enforcement Conference NRC and Duquesne Light Company June 13,1997 l King of Prussia, PA l 5$ hi W "

Slide I i Predecisional Enforcement Conference

~

'

_ _ _

-

. .

.

-

Duquesne Light Participants

+ R. L. LeGrand Division Vice President, Nuclear Operations ,

Group & Plant Manager

+ S. C. Jain Division Vice President, Nuclear Services Group

+ B. T. Tuite General Manager, Nuclear Operations Unit

+ K. L. Ostrowski Manager, Quality Services Unit

+ J. Arias Director, Safety & Licensing l

Predecisional Enforcement Conference slide 2 . ,

Agenda

+ Opening Remarks S. C. Jain

+ Root Cause R. L. LeGrand

+ Contributing Factors R. L. LeGrand

+ Corrective Actions R. L. LeGrand

+ Closing Ren; arks S. C. Jain

-

Predecisional Enforcement Conference Slide 3

-.

-.

_

. . . . .

.

Root Cause

+ Management Oversight and Control of the TS Surveillance Program

.

!

I Predecisional Enforcement Conference Slide 4

m a Contributing Factors

+ Identified weakness in Technical Specification surveillance procedures

+ Centralized Scheduling

+ Coordination and Communication l j Predecisional Enforcement Conference Slide 5

.

..

.

.. .

.

..

l

..

-; .4 Corrective Actions

+ Quality Services Unit assessraent of TS surveillance sequencing (4/10/97)

+ Programmatic Enhancements of TS Surveillance Program Review of existing procedures (1/30/98) Technical Review by SPED (7/31/97) Coordination & Scheduling (7/31/97) Self Assessment (2nd Quarter 1998)

l i

l I

Predecisional Enforcement Conference Slide 6

_ _ - _