IR 05000346/1998017

Insp Rept 50-346/98-17 on 980918-1109.Violations Noted.Major Areas Inspected:Licensee Operations,Maint,Engineering & Plant Support

ML20198B550
Person / Time
Site:	Davis Besse
Issue date:	12/09/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20198B542	List: IR 05000346/1998017 ML20198B539 ML20198B543
References
50-346-98-17, NUDOCS 9812210009
Download: ML20198B550 (16)

Text

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

l l'

l

, U. S. NUCLEAR REGULATORY COMMISSION

,

REGION 111 i

l Docket No: 50-346 l

! License No: NPF-3

j Report No: 50-346/98017(DRP)

,

.

Licensee: Toledo Edison Company i

Facility: Davis-Besse Nuclear Power Station Location: 5501 N. State Route 2 Oak Harbor, OH 43449 i

Dates: September 18 - November 9,1998 Inspectors: S. Campbell, Senior Resident inspector K. Zellers, Resident inspector l

l Approved by: Thomas J. Kozak, Chief l Reactor Projects Branch 4

!

'l

!

i

!

l

!

,

9912210009 981209 l PDR ADOCK 05000346

'

8 PDR

, I 1 l l

l I

EXECUTIVE SUMMARY Davis-Besse Nuclear Power Station NRC Inspection Report 50-346/98017(DRP) l This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 7-week period of resident inspectio Operations

.

Two manual reactor trips, an automatic reactor trip and a plant runback occurred during this inspection period. The inspectors concluded that the operators responded conservatively and promptly to ensure the reactor was in a stable condition following each event. Operators correctly implemented procedures and properly entered and exited Technical Specifications. Communications during the events were effective and senior reactor operators demonstrated very good command and control during each event. However, it was of concern that the licensee's processes were not effective in preventing these events from occurring (Section 01.1).

. Licensee management took several actions in order to prevent recurrence of the recent events and improve overall performance, including: issuing a stop work order following the October 21 plant runback to focus efforts in identifying and correcting the causes of the events; establishing a work review team to review work packages prior to issuance; and initiating a collective significance review to identify organizational and equipment issues that contributed to the events. The inspectors concluded that these actions were initially effective in ensuring work packages were adequate to support error free work activities for the remainder of the inspection period (Section 06.1).

.

With the exception of a main steam safety valve (MSSV) gag that became loose during the September 24 trip, plant equipment responded as designed during and following the plant transient (Section 01.2).

. Plant operators were prepared for the possibility that the main feedwater regulating valve could go closed during surveillance testing of the steam / feed regulating control system and, when it did, responded promptly by manually tripping the reacto Operators also responded well to the MSSV that lifted and to a failed turbine bypass valve subsequent to the trip (Section 01.2).

l

. Station personnel responded to a lockout of Bus K and isolation of the Transformer X02 in accordance with plant procedures. Good teamwork between station personnel was noted. Subsequently, Transformer X02 was promptly restored to service (Section 01.5).

Maintenance

. One violation was identified associated with the performance of an inadequate maintenance work order which resulted in a plant runback from 100 percent to 60 percent power. Control room operators were unaware of the work activity which led

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

,

to the runback due to the failure of the shift manager to inform the operators that he approved work to de-energize a circuit in panel YAU. The control room operators ;

. responded promptly and effectively to ensure the plant was placed in a stable condition in a timely manner following the event (Section 01.4).

'

.

One Non-Cited Violaticn was identified when the inspectors determined that an !

instrument and' controls technician specified the wrong overpower trip setpoint during the reactor protection system Channel 2 calibration check. Contributing to this procedural error was the failure of the l&C technician to verify the correct overpower trip setpoint with the shift supervisor. The error was corrected and the calibration was completed correctly (Section M1.1).

Enaineerina

.

The inspectors concluded that although there was some basis for determining that a solenoid valve used for closing the main feedwater regulating valve was operating correctly, the decision to declare it functional and continue with testing was non-conservative. Once the testing was resumed, a main feed regulating valve went closed I and operators initiated a manual reactor trip of the plant (Section 01.2).

<

. .- -

Report Detalis Summary of Plant Status The plant was operated at approximately 100 percent power from September 18 until September 24, when operators manually tripped the reactor following the unexpected closure cf a main feedwater regulating valve. The plant was restarted on September 26 and was operated at approximately 100 percent power until October 14 when operators manually tripped the reactor after a component cooling water (CCW) rupture disk on a letdown cooler failed.

Details of this trip are described in Special Inspection Report 50-34G/98019. A plant restart was commenced on October 18 and an automatic trip occurred at 4 percent power while operators placed one channel of the anticipatory reactor trip system (ARTS) out of bypass. On October 19, a plant restart was commenced and at 0600 on October 21, the plant reached 100 percent power. At approximately 0810, an automatic plant runback to 60 percent power occurred when instrument power for one train of secondary equipment was lost while an electrician removed a fuse as directed by a work package for abandoning the primary water storage tank (PWST). Plant power was increased back to 100 percent later that day and remained at that power level for the remainder of the ins;evion perio . Operations 01 Conduct of Operations 01.1 General Comments The inspectors conducted frequent reviews of ongoing plant activities. Plant operators l responded promptly and effectively to equipment malfunctions and plant transients on I several occasions during the inspection period. However, it was of concern that the licensee's processes were esot effective in preventing these events from occurrin Specific events and noteworthy observations are detailed in the sections belo l

01.2 Closure of Main Feedwater Reaulatina Valve Durina Surveillance Test l Inspection Scope (93702)

On September 24, with the plant being operated at 100 percent power, control room operators received indications that main feedwater regulating valve (MFRV) SP6B was closing. In response, the operators manually tripped the reactor. The inspectors responded to the control room, reviewed the circumstances surrounding this event, and observed the operators' response to this even Observations and Findinas Steam Generator 1 MFRV SP6B is closed by the steam / feed regulating control system (SFRCS) by venting air from underneath its valve operator which allows the valve operator spring to close the valve. The air is vented by de-energizing two solenoid operated air valves, SVSP6B1 and SVSP6B2. Valve SVSP6B1 is de-energized when

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

i i

'

SFRCS logic for Channel 2 receives a valid trip signal and valve SVSP682 is de-energized when SFRCS logic for Channel 4 receives a valid trip signa Procedure DB-MI-03212, " Channel Functional Test of SFRCS Actuation Channel 2 3 Logic for Mode 1," provides instructions for individually testing the logic of both of these valves to verify proper operatio During performance of Procedure DB-MI-03212 on September 24, SVSP6B1 was re-energized but a status light indicated that it was in the wrong mechanical position. The

'

valve could not be removed and replaced without closing MFRV SP68, which would have required a power reduction to 20 percent. Maintenance personnel generated a

"

test deficiency and maintenance and engineering personnel commenced troubleshooting efforts. It was determined that the solenoid was energized as expected, and that either the valve was not mechanically positioned correctly or the position

., indication switch was not working properly. Using an acoustic sensor, engineering personnel observed a response from the valve when it was energized and incorrectly concluded that the valve had functioned properly and that the position indication switch had failed. Their conclusion was influenced by the fact that an identical solenoid operated air valve had experienced a failed position indication in October 1997.

i Based on the assumption that the position indicator had failed and that the solenoid valve was in its proper position, the test deficiency was resolved and Procedure DB-MI-03212 was resumed. Operators discussed the possibility that

,

SVSP6B1 was in a failed position and determined that if the MFRV went closed during the Channel 4 testing, a manual reactor trip would be initiated. Because SVSP6B1 was

actually failed, when SVSP6B2 was tested during SFRCS logic Channel 4 testing, the air under the operator for MFRV SP68 vented, which caused it to close. The plant operators then tripped the reactor. Corrective actions included replacing and testing

'

SVSP681 and discussing the lessons learned from the event with plant engineering and

-

maintenance engineering personnel to reinforce expectations for troubleshooting plant

,

equipment problem After the trip, the gag installed on Main Steam Safety Valve (MSSV) SP17B6 jarred loose. MSSV SP1786 had been determined to be inoperable and had been previously locked shut with a gag because of a low lift point during the tornado event of June 24.

. During the September 24 trip, the loose gag allowed the MSSV to open, which required c the operators to take manual control of the turbine bypass valves (TBV) to reduce steam

, header pressure from about 995 to about 940 pounds per square inch gage (psig) to reseat the MSSV. A subsequent licensee review identified that, due to vibration, the gag screw nut backed out, which allowed the MSSV to open partially and push the gag out of the way. Corrective actions included adding a lock nut to the gag screw and raising the MSSV setpoint so that the gag would not be challenged. The inspectors reviewed the response of the trip and determined that with the exception of the gag becoming loos 3, the plant responded to the trip as designe Six hours after the September 24 trip, operators isolated 4 of the 6 TBVs to enhance the control of the cooldown of the plant to 532 degrees F. When the cooldown commenced, TBV SP13A2 failed to close on demand and caused a slight overcooling even Operators entered Abnormal Procedure DB-OP-02525, " Steam Leaks," to address the

--

apparently stuck open TBV and shut main steam stop valve MS100, which isolated, among other components, steam to TBV SP13A2 and stopped the overcooling transient. Subrequently, operators isolated TBV SP13A2 locally and MS100 was reopened. Plant operators responded promptly to the event by determining and addressing the stuck open valve within seven minutes. The transient caused cooled down of one RCS loop from 543.8 to 529.2 degrees F. The lowest steam generator pressure observed was at approximately 790 psig. The inspectors reviewed the Technical Specifications (TSs) and the abnormal procedure and determined no violations had occurre Subsequently, the licensee determined that TBV SP13A2 was mechanically bound and could not be closed past the 25 percent open position. An engineering evaluation was performed during which it was determined that the plant could be safely operated in Mode 1 because of the sufficient relief capacity of the remaining TBVs. The licensee planned to repair the TBV in the next outag Conclusions Engineering personnel incorrectly assumed that a solenoid valve position indicator switch had failed when the valve had actually failed. Based on this assumption, surveillance testing was resumed which led to the closure of a main feedwater regulating valve and a manual reactor trip. The inspectors concluded that, although there was some basis for determining that the valve was operating correctly, the decision to declare it functional and continue with testing was non-conservativ Plant operators were prepared for the possibility that the MFRV could go closed and responded promptly by manually tripping the reactor. Operators also responded well to the MSSV that lifted and to a failed turbine bypass valve subsequent to the trip.

01.3 Automatic Reactor Trio Durina Plant Restart Activities Inspection Scope (71707)

On October 18, the inspectors were observing reactor restart activities in the control room when an automatic reactor trip occurred from 4 percent power due to an inadvertent anticipatory reactor trip system (ARTS) actuatio Observations and Findinas The ARTS sends a signal to open the control rod drive trip breakers upon a loss of the main turbine generator at greater than 45 percent power, a loss of both MFPs and/or when the SFRCS actuates. During a shutdown, the ARTS is bypassed to prevent an automatic reactor trip. Procedures DB-OP-06901 and -06224 provide instructions for placing ARTS out of bypass during plant restar Procedure DB-OP-06901, Step 3.19, directed that Procedure DB-OP-06224 be used to transition feedwater operation from the motor driven feedwater pump (MDFP) to main feed pump (MFP) 2. Operators completed steps in DB-OP-06224 up to the point where

, 1

!

l l

!

l

'

it directed that the ARTS input test toggle switches for MFP 2 be placed into the operate position. However, this step could not be procedurally completed because MFP 2 was not yet supplying feedwater to the steam generators. Consequently, control room i operators returned to Procedure DB-OP-06901, Step 3.20, and transitioned feedwater l l flow to MFP 2.

Thereafter, the operators determined that the instructions in both procedures were l similar for removing ARTS from bypass. Therefore, instead of reentering j Procedure DB-OP-06224, which instructed that the MFP 2 input test toggle switches be repositioned from " TRIP" to " OPERATE" on all channels before rotating the individual l channel bypass switches, the operators continued using Procedure DB-OP-0690 Procedure DB-OP-06901 was sequenced such that the Channel 1 MFP 2 input test l toggle switch was removed from " TRIP" to " OPERATE" and the Channel 1 bypass cwitch taken to normal before taking the ARTS Channels 2,3, and 4 MFP 2 input test toggle switches to " OPERATE". When the operator rotated the Channel 1 bypass keyswitch with its MFP 2 test toggle switch in " OPERATE," ARTS Channels 2,3, and 4 actuated, satisfying the two-out-of-four coincidence logic to trip the reactor. The control room operators immediately implemented Procedure DB-OP-02000, "RPS, SFAS, SFRCS Trip, or SG Tube Rupture" after the automatic trip. All plant equipment operated as designed following the automatic trip signal and no complications were experience During the initial investigation of the event, the licensee determined that the bypass switch had a " break- before-make" characteristic as determined by spare switch testing and conversations with vendor representatives. This resulted in determining that the inadequate procedural step sequencing caused the trip; therefore, the licensee corrected the governing plant procedures to prevent recurrence and started the plant back up to Mode 1. Subsequently, during the licensee event report review, engineering personnel conducted additional conversations with vendor representatives and determined that the switches had a "make-before-break" characteristic which invalidated the initial root cause determination. Since the trip, successful ARTS logic channel testing demonstrated that the ARTS would perform its design function while the plant vtas in Mode 1. As of the time of this report issuance, plant engineering personnel were planning to perform troubleshocting activities during a mid-cycle outage planned for March 1999 to determine the root cause and conduct appropriate corrective action Because the cause of the trip was not known at the end of the inspection period, this is considered an Inspection Followup item (IFl 50-346/98017-01(DRP)).

c. Conclusions A reactor trip occurred with the reactor at about 4 percent power when an operator configured anticipatory reactor trip system (ARTS) Channel 1 as directed by a plant procedure. The initial root cause was determined to be inadequate procedure sequencing due to a bypass switch ' break-before-make" characteristic. Based on this evaluation and corrective actions to change the governing procedures, the plant was

started up to Mode 1 operations. However, a subsequent review identified that the

'

switch had a "make-before-break" characteristic which resulted in an indeterminate root

l l

,. -- . . - - - .- . . - . - - - . - - - - . - - - - - ...

I cause. Nevertheless, the inspectors determined that the ARTS would perform its design function in Mode 1 due to successful completion of logic testin .4 Plant Runback (71707) Insoection Scooe On October 21, with the plant being operated at approximately 100 percent power, a  ;

runback to 60 percent power occurred during the performance of a maintenance work order (MWO)in support of abandoning the primary water storage tank (PWST). The inspectors responded to the control room and observed the operators' response to this l even Observations and Findinas i

On October 21, activities were underway for Plant Modification 95-0050 under which the <

. PWST was being abandoned. As part of this modification, an electrician was assigned  !

to remove a PWST temperature circuit. The electrician followed the instructions in ,

,. Maintenance Work Order (MWO) 2-95-0050-01 for this activity. One step in the MWO  !

directed that the fuses from Circuit 12 in panel YAU and Fuse 72 for PWST temperature indicator TT-6824 be remove I The instructions in the MWO were confusing because they directed the removal of both '

fuses from panel YAU and Fuse 72, which was not in panel YAU. The electrician contacted the shift manager, who questioned whether the electrician had reviewed Electrical Distribution Manual DWG E 1040A to determine which electrical loads were i

'

serviced by panel YAU. The electrician responded that he had reviewed the manual, which provided a vague description of miscellaneous loads that were serviced by panel YAU. Nevertheless, with an understanding that the work activity had been approved, the shift manager granted approval to start work. The shift manager told the electrician that he would inform the control room of the activity, but was momentarily distracted and never made the notificatio Immediately after obtaining approval, at 0810, a switch in panel YAU was opened to isolate power to the fuses which caused numerous control room annunciators to alarm ,

including the loss of several pertinent plant indications and the repositioning of valve A permissive contact in the integrated control system (ICS) for MFP high discharge pressure closed, as designed, which sent a signal to automatically decrease plant power from 100 to 60 percent. In response, the operators appropriately placed the steam generator / reactor demand station on the ICS in manual, which terminated the runback :

at 0812. During the runback, the ICS automatically inserted the regulating rods which caused a redistribution of neutron flux to the bottom of the core. In response, the i operators inserted the axial power shaping rods from 40 to 30 percent withdrawn to balance the core flux distribution. . At 0817, an annunciator for rod tilt,' imbalance and rod insertion limits alarmed because the rod index for the regulating rod was at 247 percent withdrawn with reactor power at 62 percent, which placed reactor operation in the restricted region per TS 3.1.3.6. Technical Specification 3.1.3.6 was entered and the

.. .

!

operators began adding boron to the core to allow rod withdrawal and eliminate the restricted operation conditio While the operators were determining the cause of the event, the shift manager entered the control room and mentioned to the control room personnel that work had been performed in panel YAU. Subsequently, the shift manager directed the electrician to restore power to panel YAU. Power was restored at 0818 which restored the alarms and indicators lost during the event. At 0829, the rods were borated out to a rod index of 250 percent withdrawn and reactor power remained stable at 62 percen Subsequently, TS 3.1.3.6 was exited when the rod tilt, imbalance and rod insertion limits annunciator cleare The inspectors were informed that on Octoler 17,1997, the MWO was prepared using Design Change Number (DCN) E2012A-150 for abandoning the PWST. A review of the DCN indicated panel YAU as the circuit source, YAU 12 as the circuit and Fuse 72 in Panel C5758C, which is in the control room, as the fuse to be removed. Inattention-to-detail by the planner while using the DCN to draft the MWO caused him to write instructions for removing fuses from panel YAU instead of removing Fuse 72 in Pan 31 C5758C. The planner stated that he did not walkdown the job before developing the MWO, which was considered a missed opportunity in verifying the MWO instructions. Subsequent to the event, the licensee found, during a walkdown of the panel, that the DCN was in error and should have referenced removing Fuse 72 from Panel C5758D and not C5758C. In response to this event, licensee management implemented numerous corrective actions, which are detailed in Section 06.1 of this repor Appendix B of 10 CFR Part 50, Criterion V requires, in part, that activities affecting quality shall be prescribed by documented instructions appropriate to the cMHanc Contrary to the above, between October 17,1997, and October 21,1998, MWO 2-95-0050 used to abandon the PWST, an activity which affected quality, was not appropriate to the circumstance in that the MWO specified removal of fuses from panel YAU instead of Fuse 72 in Panel C5857D. Failure to specify the correct fuse iri the MWO caused removal of the wrong fuse and a plant runback (VIO 50-346/98017-02(DRP)).

c. Conclusions One violation was identified associated with the performance of an inadequate maintenance work order which resulted in a plant runback from 100 percent to 60 percent power. Contro! .com operators were unaware of the work activity which led to the runback due to the faliuie of the shift manager to inform the operators that he approved work to dennergize a circuit in panel YAU. The control room operators responded promptly r.nd effectively to ensure the plant was placed in a stable condition in a timely manner fc11owing the even i

__ _

, .n . .. .,

i i

i t

.

01.5 Ooerator Response to a Fault on Startuo Transformer XO2 (72707)

f

'

A ground fault condition on the Ohio Edison offsite transmission line to the site caused j; . air circuit breaker (ACB) 34562 and ACB 34564 to trip open as designed, which isolated L and de-energized the 345 kilovolt Bus K and Transformer X02 on October 7. The inspectors observed that control room personnel properly used applicable procedures,

-

a that operations management provided good oversight recommendations to the shift

!: supervisor, and that maintenance and engineering personnel provided timely support. A

subsequent review determined that a lighting strike was the most probable cause of the

,

. fault. The Ohio Edison line was realigned to the switchyard and the event was -

subsequently documented on PCAQR 98-1819.' The inspectors determined that

operators responded to the lockout in accordance with plant procedures and that station personnel exhibited good teamwork in responding to the event.

t i . .

O2 Operational Status of Facilities and Equipment

I 1-O2.1 System Walkdcwns (71707)

The inspectors walk'ed down the accessible portions of the following engineered safety

, features (ESF) and important-to-safety systems during the inspection period:

-

Emergency Diesel Generators

! -

Low Voltage Switchgear Rooms

.

U No substantive concems were identified as a result of the walkdowns. System lineups

.. ' and major flowpaths were verified to be consistent with plant procedures / drawings and f

the Updated Safety Analysis Report. Pump / motor fluid levels were within their normal bands.

,

06, Operations Organization and Administration f 06.1 PJant Manaaement Resconse to Operational Events f Insoection Scope (71707)

The inspectors assessed the effectiveness of the actions taken by plant management to

- address the events described in this inspection report. These actions included a work stoppage, the implementation of a work review team, and the initiation of a collective si0nificance review of the event Observations and Findinos

. On October 21, plant management issued a stop work order with the authorization to conduct only emergent work necessary to maintain safe plant operation and/or tests required to meet TS surveillance requirements. The decision to stop work followed the October 21 plant runback.'

l

Tne work schedule was reviewed and activities were rescheduled to ensure the activities were effectively managed and that sufficient resources were available to perform the work. A three-member review team was established to supplement the normal work package process which provided additional confidence that the work packages could be performed safely and without adverse impact on plant reliabilit The licensee conducted interviews with personnel in each organizational section to determine if work environment conditions contributed to the events. The results of the interviews were used to provide human performance enhancements, which were implemented by each section, to improve overall station performance. Collective significance PCAQR 98-1904 was written to review major events that occurred during 1998. The work stop was lifted on October 2 A management review team composed of industry experts and individuals from Perry and Davis-Besse developed an overview of the events and provided a list of outstanding questions to p! ant management at a debriefing on October 30. Additionally, the team noted areas that required management atts " .. euch as prioritizing the maintenance work item backlog, human performance enhv. cements, conservative decision making and monitoring organizational behavior. Actions were being developed as part of the plan to improve overall performance at the facility. The immediate actions taken to address the events have initially been effective as the plant was operated without incident for the remainder of the inspection perio c. Conclusions Licensee management took several actions in order to prevent recurrence of the recent events and improve overall performance, including: issuing a stop work order following the October 21 plant runback to focus efforts in identifying and correcting the causes of the recent events, establishing a work review team to review work packages prior to issuance, and initiating a collective significance review to identify organizational and equipment issues that contributed to the events. The inspectors concluded that these actions were initially effective in ensuring work package.s were adequate to support error free work activities for the remainder of the inspection perio II. Maintenance M1 Conduct of Maintenance M1.1 Reactor Protection System (RPS) Channel 2 Calibration Imoroperly Performed Inspection Scope (61726)

On October 2,1998, the inspectors observed the performance of Procedure DB-MI-03058, " Reactor Protection System Channel 2 Calibration of Overpower, Power / Imbalance / Flow, and Power / Pumps Trip Functions."

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

,

l

! Observations and Findinas l

The inspectors determined that an instrumentation and control (l&C) technician had

,

'

documented a choice of a overpower trip setpoint that was inconsistent with TSs during the performance of Step 8.1.4.a. The technician had determined that the overpower trip setpoint was 104.5 percent reactor power. However, due to one MSSV being gagged and inoperable, TS Limiting Condition for Operation 3.7.1.1.a required that the overpower trip setpoint be 103 percen When the inspectors notified the technician of the observation, he stopped the test, and verified the concern with operations and l&C management. After the test deficiency was resolved, the test was recommenced using the correct overpower trip setpoin Subsequently, I&C management determined that the correct setpoint was used for PoS channels 1,3, and . Step 8.1.4.a was written so that the technician had to choose between a setpoint based on 4 reactor coolant pump (RCP) operation, three RCP operation, or a setpoint specified by the shift supervisor. The inspectors determined that the technician assumed that the setpoint for 4 RCP operation applied and that he was unaware of the reduced overpower trip setpoint. The procedure did not direct him to independently verify that the chosen trip setpoint was correct, and he did not validate the setpoint with the shift supervisor. in response to the concern, l&C management generated PCAQR 1998-1785, and proposed changing the relevant procedures to require that I&C technicians verify with the shift supervisor the correct overpower trip setpoin The significance of the error was small because if the channel had been improperly calibrated, the remaining three properly calibrated RPS channels would have caused the RPS to trip the reactor at 103 percent power. Additionally, licensee management noted that the calibration check itself would have identified and corrected the discrepanc Technical Specification 6.8.1.c states that written procedures shall be established, implemented, and maintained covering surveillance and test activities of safety related equipment. The performan:o ef Procedure DB-MI-03058 satisfied the requirement of TS surveillance requirement 4.3.1.1.1 to perform channel calibrations of the RPS overpower trip setpoint. The improper performance of the procedure is a violation. Due to the likelihood that the licensee would have identified this procedural error through their review of the calibration, identification credit is warranted for this situation. Therefore, this, non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation in accordance with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-346/98017-03(DRP)). Conclusions One Non-Cited Violation was identified when the inspectors determined that an instrument and controls technician speci'ied the wrong overpower trip setpoint during the reactor protection system Channel 2 calibration check. Contributing to this l

l 12

. -

procedural error was the failure of the l&C technician to verify the correct overpower trip setpoint with the shift supervisor. The error was corrected and the calibration was completed correctl Ill. Enaineerina E8 Miscellaneous Engineering issues (92903)

E (Closed) LER 50-346/98010-00: Misdiagnosis of Solenoid Valve for Feedwater Regulating Valve During Testing Results in Manual Reactor Trip. The circumstances surrounding this event are described in Section O1.2 of this report. No violations of NRC requirements were identified during this review. This item is close V. Manaaement Meetinos X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on November 9,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie .

, .

.

.

. - _ _ _ _

_ _ _ _ _ .. - _ __

, ,

i PARTIAL LIST OF PERSONS CONTACTED

,

Licensee j

J. K. Wood, Vice President  !

J. H. Lash, Plant. Manager )

T. J. Myers, Director, Nuclear Support Gervices

'

L. W. Worley, Director, Nuclear Assurance J. L. Freels, Manager, Regulatory Affairs J. L. Michaelis, Manager, Maintenance R. J. Scott, Manager, Radiation Protection

,

H. W. Stevens, Jr., Manager, Nuclear Safety & Inspections j

M. C. Beier, Manager, Quality Assessment '

J. W. Rogers, Manager, Plant Engineering-C. A. Price, Manager, Business Services L. M. Dohrmann, Manager, Quality Services G. A. Skeel, Manager, Security F. L. Swanger, Manager, Design Basis Engineering l S. A. Coakley, Manager, Work Management  !

P. R. Hess, Manager, Supply )

M. A. Hoffman, Supervisor, Technical Training j T. J. Chambers, Supervisor, Quality Assessment D. H. Lockwood, Supervisor, Compliance R. B. Coad, Jr., Superintendent, Radiation Protection G. W. Gillespie, Superintendent, Chemistry D. M. Imlay, Superintendent, Operations J. E. Reddington, Superintendent, Mechanical Services M. J. Roder, Superintendent, E/C Maintenance D. L. Miller, Senior Engineer, Licensing NRC S. J. Campbell, Senior Resident inspector, Davis-Besse K. S. Zellers, Resident inspector, Davis-Besse

. . . . . _ 4 _ _ _ _ _ _ _ . . _ . . _ _ _ . ~ . _ _ _ _ - . . - _ _ . _ - _ .

-

_

t

!

j' INSPECTION PROCEDURES USED IP 37551: Onsite Engineering l IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 92903: Followup - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED Opened 50-346/98017-01(DRP) IFl Automatic Reactor Trip During Plant Restart 50-346/98017-02(DRP) VIO Inadequate Instructions for Abandoning the PWST 50-346/98017-03(DRP) NCV Failure to Follow RPS Surveillance Procedure

~

Closed 50-346/98010-00(DRP) LER Misdiagnosis of Solenoid Valve for Feedwater Control Valve During Testing Results in Manual Reactor Trip 50-346/98017-02(DRP) VIO Inadequate Instructions for Abandoning the PWST 50-346/98017-03(DRP) NCV Failure to Follow RPS Surveillance Procedure l

l'

l l

!

[

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

, ,,

'

LIST OF ACRONYMS AND INITIALISMS USED ACB Air Circuit Breaker AFP Auxiliary Feedwater Pump ARTS Anticipatory Reactor Trip System CCW Component Cooling Water CFR Code of Federal Regulations DCN Design Change Number DWG Drawing ESF Engineered Safety Feature l&C Instrumentation and Controls ICS . Integrated Control System IFl inspection Followup item IR inspection Report LER Licensee Event Report MDFP Motor Driven Feedwater Pump MFP Main Feedwater Pump MSSV Main Steam Safety Valve MWO Maintenance Work Order NCV Non-Cited Violation NRC: Nuclear Regulatory Commission PCAQR Potential Condition Adverse to Quality Report PDR Public Document Room PSIG Pounds Per Square Inch Gage PWST. Primary Water Storage Tank RC Reactor Coolant System RG Regulatory Guide RPS Reactor Protection System SFAS Safety Features Actuation System TA Temporary Alteration TBV' Turbine Bypass Valve TS Technical Specification USAR Updated Safety Analysis Report VIO Violation

.

- .