IR 05000277/1986007

Insp Repts 50-277/86-07 & 50-278/86-07 on 860327-0509. Violation Noted:Failure to Perform Jet Pump Operability Surveillance Requirements During Unit 3 Single Loop Operation

ML20205R943
Person / Time
Site:	Peach Bottom
Issue date:	05/23/1986
From:	Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20205R937	List: IR 05000277/1986007 ML20205R931 ML20205R938
References
TASK-2.K.3.16, TASK-2.K.3.18, TASK-TM 50-277-86-07, 50-277-86-7, 50-278-86-07, 50-278-86-7, NUDOCS 8606060049
Download: ML20205R943 (28)

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U.S. NUCLEAR REGULATORY COMMISSION j REGION I ,

i Report No. 50-277/86-07 & 50-278/86-07 Docket No. 50-277 & 50-278 License No. DPR-44 & DPR-56 (

Licensee: Philadelphia Electric Company 2301 Market Street

Philadelphia, Pennsylvania 19101 '

Facility Name: Peach Bottom Atomic Power Station Units 2 and 3 j Inspection At: Delta, Pennsylvania

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! Inspection Conducted: March 27 - May 9, 1986 i Inspectors: T. P. Johnson, Sr. Resident Inspector J. H. Williams, Resident Inspector J. E. Beall, Project Engineer 4 B. M. Hillman, Reactor Engineer T. B. Silko, Reactor Engineer i Reviewed By: f 3 6 E. Beall, Project Engineer date

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Approved By: kN Robert M. Gallo, Chief Z3f86 date DRP, Section 2A

i Inspection Summary: Routine, on-site regular and backshift resident

inspection (141 hours0.00163 days <br />0.0392 hours <br />2.331349e-4 weeks <br />5.36505e-5 months <br /> Unit 2; 138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, operational safety, radiation protection, physical security, i

control room activities, licensee events, surveillance testing, outage

! activities, maintenance, and outstanding item i 1 Results: Failure to perform jet pump operability surveillance requirements

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during Unit 3 single loop operation is an apparent violation. Personnel i errors resulted in three Unit 3 scrams (one at 81*/; power and two while

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shutdown).

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DETAILS 1. Persons Contacted J. T. Budzynski, Reactor Engineer J. B. Cotton, Superintendent Plant Services

• R. S. Fleischmann, Manager, Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Health Physicist J. F. Mitman, Maintenance Engineer D. L. Oltmans, Senior Chemist F. W. Polaski, Outage Planning Engineer S. R. Roberts, Operations Engineer D. C. Smith, Superintendent Operations S. A. Spitko, Administration Engineer Other licensee employees were also contacte *Present at exit interview on site and for summation of preliminary finding . Plant Status 2.1 Unit 2

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Unit 2 began the inspection period at ful powe Reactor power was decreased on April 13, 1986, to perform a rod swap. Power remained at near 60% from April 13 to April 16, 1986, due to potential grid instability caused oy the offsite electrical distribution lineup in place after the #1 transformer fire in the North substation (see detail 4.2.2). The unit returned to full power on April 18, 1986. On April 23, 1986, the unit scrammed from 100% power during turbine valve testing (see detail 4.2.3).

The unit restarted on April 26, 1986, and remained at full power for the remainder of the period except during a rod swap on May 1, 198 . 2.2 Unit 3 The unit began the inspection period at near full power. On March 27, 1986, the B recirculation pump tripped due to a ground fault in one of the motor phase leads (see detail 4.2.1). The unit remained in single loop operation until March 31, 1986. The unit remained in power ascension until the unit was shut down on April 11, 1986, to repair miscellaneous valves including the RFP minimum flow valves (see detail 12).

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i On April 13, 1986, an explosion and fire occurred in the #1 transformer in the North substation (see detail 4.2.2). Unit 3 l restarted on April 23, 1986, and began power ascension. The unit scrammed from 81% power during breaker and relay testing in the North substation on April 26, 1986 (see detail 4.2.4). The unit

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restarted on April 27, 1986, and remained at full power during the

remainder of the_ inspection perio . Previous Inspection Item Update 3.1 (Closed) Inspector Follow Ite '278/85-41-04) Unit 3 broken steam

{ separator hold down bolts, a e bolt that was dropped into the

! reactor vessel. NRC Inspectic 8/85-44 and 278/86-03 discusses j the followup of this event, and ie open item is close i 3.2 (Closed) Unresolved Item (277/77-07-05). Follow the licensee's

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response to I&E Circular 77-04, Neutron Monitoring and Flow Bypass Switch Replacemen The Circular identifies a possible failure t

mode for the switches and recommended that licensee's monitor 4 switch performance. In June 1980, the licensee replaced all j affected switches with an improved design. The item is therefore

) close i 1 3.3 (Closed) Unresolved Item (277/78-09-04; 278/78-12-03).

Operability of bypass circuitry for certain emergency diesel generator trip Specifically, I&E Circular 77-16 required that all trips except generator overcurrent, the high differential current, 7 and the engine overspeed be bypassed during certain accident

conditions. The inspector has reviewed the diesel generator trip circuitry and verified all automatic trips except for the three identified are blocked during actuation of ESF systems. In

, addition, surveillance procedure, ST 8.1.6, Diesel Generator .

( Annual Inspection Post Maintenance. Test, verifies the operability

, of the trip bypass circuitr The above item is close i' 3.4 (Closed) Inspector Follow Item (277/79-BU-27; 278/79-BU-27). Loss of non-class IE instrumentation and control power system bus during operation. Actions required by this bulletin were reviewed

in NRC Inspection 277/84-26 and 278/84-22. The torus temperature and level modifications, main stack and reactor building radiation monitor modifications and relief valve monitor modifications have i all been completed. The emergency procedure for loss of the i j non-interruptable AC power supply has also been implemente [

These items complete all the actions required by I&E Bulletin ,

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79-27, therefore, this item is close i l iE F

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3.5 (Closed) Inspector Follow Item (277/77-19-10). Determine the QA status of the AC static inverter, one of two power supplies to the uninterruptable AC power syste CFR 50 Appendix B. requires all components "....important to safety" be controlled under a quality control program. The licensee's FSAR, section 8.6.6, states that "....the uninterruptable AC system is a convenience to the operators and loss of loads does not affect the safety of the plant". Since the uninterruptable AC system is not safety related its AC static inverter power supply is likewise not sai'ety related. The licensee's current QA status of the static inverter is therefore correc The inspector follow item is close .6 (Closed) Inspector Follow Item (277/85-08-03; 278/85-08-03).

Review the licensee's program for periodic procedures revie Administrative procedure A-36 requires a five year periodic review of all station procedure NRC Inspection 277/85-08 and 278/85-08 identified overdue reviews for "S" (system operating) and "M" (maintenance) procedures. The licensee had previously identified these overdue reviews, and had taken action to perform the required reviews. The inspector reviewed "M" procedures index, Rev. 232, dated April 19, 1986, and spot checked the safety-related "S" procedures indices. No instances of overdue reviews were identified. Based on the above, the inspector follow item is close .7 (Closed) Inspector Follow Item (278/85-08-02). Shutdown cooling mode of RHR per operating procedure S.3.2.C.1. The inspector reviewed the revised S.3.2.C.1, Rev. 16, dated February 28, 198 The procedure incorporates the use of the drag valves, CV-2(3)677A,0 as the preferred method of shutdown cooling. The inspector monitored shutdown cooling on Unit 3 during the recent maintenance outage and determined the method to be in accordance with procedure S.3.2.C.1. The inspector follow item is close .

3.8 (0 pen) Inspector Follow Item (277/86-03-01). RPS Power Supply Trip Breakers. ASCO Electrical Products Co., Inc., made a 10 CFR Part 21 report dated April 14, 1986, regarding the Westinghouse circuit breakers used in RPS power supply breakers. The part 21 report states that the defect occurs when the shunt trip coil is energized, the "A" contact does not always open. Thus, an intermit-tent duty coil could be continuously energized resulting in the shunt trip coil burning ou The inspector reviewed the report and discussed it with the license On April 16, 1986, the inspector participated in a conference call with PECo and NRC:RI regarding these RPS breakers. During the conference call, PECo agreed to formulate their position with respect to breaker problems, interim testing, long term corrective actions and reportability for both the Peach Bottom and Limerick unit l . . .. -

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! On April 28, 1986, the licensee informed the inspector that one of

. the Unit 2 RPS alternate power supply trip breakers failed the j weekly continuity check of the trip coil conducted in accordance t

with procedure ST 13.54. The breaker passed the test on April 18,

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1986, the breaker tripped on April 22, 1986, and the breaker failed the test on April 23, 1986. The alternate power supply is currently i riot in service as RPS is powered from its normal motor generator

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feeds. The licensee confirmed satisfactory operator actions to reset

the breaker on April 22, 1986. The licensee's investigation is continuing, and the breaker will be repaired when spare parts are

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available.

I J The inspector follow item remains open pending completion of i

licensee actions as stated above and subsequent NRC revie ; 3.9 (Closed) Unresolved Item (277/83-29-02;278/83-28-03). Potential

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for air leakage on back-up air supply to the 18 inch containment

vent and purge butterfly valves. The backup air supply is a safety grade nitrogen bottle system to supply motive power to

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close and inflate the boot-seal on the 18 inch butterfly valve The concern is that a leak on the safety grade supply would not be detected as the normal instrument air has sufficient capacity to

provide adequate makeup. Thus, a leak from a safety grade bottle could be masked and not be detected; and, this might jeopardize the i ability of the backup safety grade bottles to perform their safety

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function. The licensee committed to perform routine periodic leak i

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testing of the backup safety grade bottles and supply syste Testing was performed as part of modification acceptance testing I

(MAT) after modification 1007 during the last refueling outages

for both units. MAT 1007 was completed satisfactorily on Unit 2

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on June 28, 1985, and on Unit 3 on January 10, 1986. The

! inspector reviewed QA audit report No. AP85-109 which documents

the MAT's completion and discussed the MAT with the licensee. A j surveillance test is currently being written to incorporate the

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periodic leak testing of the backup safety grade supply once every refueling outage. In addition, the licensee has requested <

i approval for a modification (and associated TS change) to improve i long term availability of the safety grade nitrogen supply. The modification would replace the backup safety grade nitrogen j bottles with a supply froM the containment air dilution (CAD)

syste The CAD system connections would be in parallel with the ,

normal instrument air supply. The. inspector reviewed the licensee's

) submittal letter, dated November 6, 1985, including surveillance l

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requirements. The inspector concluded that this item is resolve The inspector will continue to follow the licensee's drafting'of the

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' 3.10 (Closed) Unresolved Item (278/83-35-01). Effect of the loss of normal instrument air on containment ventilation valves. After

_ reviewing a loss of normal instrument air on Unit 3 on Uecember 28, 1983, the inspector expressed concern that low boot seal j pressure alarms had occurred for two containment ventilation valves

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although each valve has a back-up safety grade nitrogen supply bottle that should maintain ' seal pressure on a loss of instrument ai j Subsequent licensee investigation concluded that the containment

ventilation valves did not open during the 1983 event and that j repetition of the alarm should be avoided by a change to certain system low pressure setpoints. The inspector reviewed the licensee's

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, upset report and engineering evaluation (Modification Request No.

l 1604). The licensee intends to modify the pressure switch setpoints that provide the valve position indication and low pressure alarms in the control room. (The pressure switch is in parallel with valve

, position lights so that the valve indicates not closed, i.e., mid-position, when the valve is not full closed or the seal pressure is ,

below the setpoint). The licensee intends to perform the MOD 1604 during the next refueling outage for both units. The inspector

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concluded that this item is resolved based on the licensee's upset report, engineering evaluation, and discussions with licensee engineers. The inspector will continue to follow progress of MOD

! 1604 tc modify the pressure switch setpoint .11 (Closed) Inspector Follow Item (277/84-31-01; 278/84-31-01).

Technical Specification changes to include suppression chamber water level wide range instruments in response to TMI-2 action plan item II .F. The concern was that when these Technical

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Specification changes were made, the narrow range level

' instruments were not omitted from Table 3.2.F as had occurred at another plant. The inspection verified that both narrow range and

wide range suppression chamber water level instruments were in

! Table 3.2.F of the Technical Specifications. The inspector follow i

item is close .12 (Closed) Inspector Follow Item (277/84-31-03; 278/84-31-03).

Review the results of standby gas treatment system (SGTS) damper inspections to be done during a dual unit outage. A portion of-i secondary containment SGTS ductwork had collapsed in 1983, as a result of improper operation of a damper while the SGTS was in operatio The inspector reviewed maintenance request forms (MRF)

1850070380 and 1850070370 which documented damper inspections during a dual unit outage in November 1984. One damper was found

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to have foreign material stuck to i The foreign material was removed and the damper cleaned and reassembled. -No further problems with collapsed ductwork have been noted. The inspector follow item j is closed.

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} 3.13 (Closed) Violation (277/84-01-01; 278/84-01-01). Failure to i obtain prior Technical Specification changes and Commission j approval for procedural changes affecting functioning of the RWM

and RSCS. The violation, with two examples, led to the issuance

! of an NRC Order Modifying License to the licensee on June 18, j 1984. The Order required the licensee to submit a plan to appraise i and improve the safety evaluation process, plant operating proce-

dures, and procedure review program. On October 19, 1984, NRC j approved the licensee's plan which utilized an independent consultant 1 team to conduct the appraisal and to recommend improvements. On

February 3, 1986, NRC issued a letter to the licensee which docu-mented the completion of NRC review of the appraisal results and the

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actions taken to implement improvement recommendation The letter noted that no deficiencies had been identified and that all terms of the Order had been satisfied. The inspector performed additional followup inspection in one area of the Order which involved assuring that all FSAR commitments and Technical Specification requirements are addressed in station procedures. The inspector selected a sample of items and, using the licensee's recently devel'oped computer software, verified that the selected requirements were covered in approved station procedures. Based on the February 3, 1986, letter which documented NRC review of the licensee's actions, and the results of the inspectors followup verification, the violation is close . Plant Operations Review

, 4.1 Station Tours

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The inspector observed plant operations during daily facility tours. The following areas were inspected:

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Cable Spreading Room

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Reactor Buildings

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Radwaste Building

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Pump House

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Protected and Vital Areas

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Security Facilities (CAS, SAS, Access Control, Aux SAS)

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High Radiation and Contamination Control Areas  ;

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Shift Turnover i 4. Control Room and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical j Specifications. Presence of a senior licensed operator i

in the control room was verified frequentl ;

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4. The inspector frequently observed that selected control room instrumentation cor firmed that instruments were operable and indicated values were within Technical Specification requirements and normal operating limit ECCS switch positioning and valve lineups were verified

based on control room indicators and plant observation Observations included flow setpoints, breaker positioning, PCIS status, and radiation monitoring instrument . Selected control room off-normal alarms (annunciators)

were discussed with control room operators and shift supervision to assure they were knowledgeable of alarm status, plant conditions, and that corrective action, if required, was being taken. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition .1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personne .1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure .

compliance with administrative procedures and regulatory

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guidanc No inadequacies were identifie .1.6 The inspector observed main stack and ventilation stack radiation monitors and recorders, and periodically reviewed traces from backshif t periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. No inadequacies were identifie .1.7 The inspector observed control room indications of fire detection instrumentation and fire suppression systems, monitored use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations. No inadequacies were identifie .1.8 The inspector observed overall facility housekeeping l conditions, including control of combustibles, loose trash and debris. Cleanup was spot-checkad during and i after maintenanc Plant housekeeping was generally I acceptabl .1.9 The inspector verified operability of selected safety related equipment and systems by in plant checks of valve positioning, control of locked valves, power {

supply availability, operating procedures, plant

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drawings, instrumentation and breaker positionin Selected major csmponents were visually inspected for leakage, proper lubrication, cooling water supply, o,nerating air sunnly and nanaral conditions. No significant piping vibration was detected. The inspector reviewed selected blocking permits (tagouts)

for conformance to licensee procedures. No inadequacies were identifie .1.10 In followup to questions raised during the enforcement conference from NRC Inspection 278/86-09, the inspector reviewed the licensee's control of keys for key-lock switches in the control room. The inspector noted that there were numerous key-lock switches in the control room including: valve control for ECCS suction valves, PCIS bypass switches, miscellaneous test switches, RSCS bypass switches, reactor mode selector switch, RWM bypass switch, et The inspector noted differences for similar type key-lock switches within each unit, and inconsistencies for the same switches between unit The use of key-lock switches is procedurally controlled as verified by operator interviews and procedure reviews. The inspector also noted that the control room design review had a human engineering deficiency (HED) finding, HED 15-10. The HED 15-10 resolution was that key-lock switches are " controlled by procedures, and that in most cases keys remain in the switches during normal operations". Tne inspector discussed this key-lock switch philosophy with the licensee. The licensee conducted a review of the control of key-lock switche Final determination of which switches will have keys remaining in the key locks is pendin The inspector will review this in a future inspection.

4.2 Followup On Events Occurring During the Inspection 4. Unit 3 Recirculation Pump Trip and Single Loop Operation 4.2. Sequence of Events On March 27, 1986, Unit 3 was operating at 91%

power when at 6:11 a.m., the B recirculation pump tripped due to an electrical fault. The operating shift immediately implemented OT-112, " Recirculation Pump Trip" and inserted control rods to reduce reactor power. The licensee continued to operate in a single loop until 4:30 p.m. on March 31, 1986, when the B recirculation pump was started using procedure S.2.3.1.M. Power was maintained below 35%  ;

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while in single loop operation (SLO) to stay in a region of the power-flow operating map for which thermal-hydraulic stability monitorina was not required by Technical Specification (TS) 3. The licensee's investigation of the cause of the recirculation pump trip identified a 4KV power feed to the pump motor with a high resistance faul Electrical power to the pump motor is supplied by nine single conductor 750 kcmil aluminum cables. An evaluation by the Electrical Engineering Division concluded that two of the three cables per phase was adequate to operate the pump for at least two years. A temporary modification was made to use only two of the three cables per phase during this cycl PORC meeting 86-035 approved this chang The inspector reviewed the PORC minutes and modification documentation and discussed the 1 change with the Modification Coordinato No unacceptable conditions were identifie .2. Single Loop Operations The inspector reviewed requirements for single loop operation and associated procedures. The following procedures were reviewed:

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ST 3.10 " Core Thermal Hydraulic Stability Monitoring", Rev. O performed 3/27/8 OT-112 " Recirculation Pump Trip". Rev. .

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ST 3.3.2.A - Single Loop, " Calibration of APRM System for Single Loop Operation",

Rev 2, performed 3/27/86 and Rev. 3 performed 3/28/8 S.2.3.1.J " Operation with One Recirculation Pump Out of Service -

Single Loop Operation", Rev. S.2.3.1.A "Startup of a Recirculation Pump", Rev. S.2.3.1.M " Interim Starting Instructions for the Recirc M-G Sets", Rev. .

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ST 9.21-2 " Jet Pump Operability - Single Loop Operation", Rev. 1, performed 3/27/86 and 3/31/86.

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TS surveillance requirement 4.6.E.1 states that whenever there is recirculation flow in the reactor in the startup or run modes, jet pump operability shall be checked daily by verifying that the following conditions do not occur simultaneously:

(a) The indicated value of core flow rate varies from the value derived from loop flow measurements by more than 10%.

(b) The diffuser to lower plenum differential pressure reading on an individual jet pump varies from the mean of all jet pump differential pressures by more than 10%.

TS 4.6.E.2 also requires when operating with one recirculating pump with the equalizer valve closed, the diffuser to lower plenum differential pressure shall be checked daily and the differential pressure of any jet pump the idle loop snall not vary by more than 10%

from established patter Plant procedures require the equalizer valve to be closed in single loop operatio ST 9.21-2 Revision 1, is written to implement the requirements of TS 4.6.E.1 and 2 nowever, on March 27, 1986, item (a) was not determined and item (b) was outside the allowed limits with an explanatory note stating that at low flow the limit was not applicable. As a result, data on the idle loop was not obtained as require Failure to adequately check jet pump operability from 6:11 a.m. on March 27, 1986, to 4:30 p.m. on March 31, 1986, is an apparent violation of Technical Specification surveillance requirement 4.6.E.1 and 2 (278/86-07-01). When the licensee was informed of the apparent violation, immediate steps were taken to revise ST 9.21-2 to include the appropriate checks of jet pump operabilit Tne inspector reviewed ST 9.21-3 (Single Loop),

Revision 0, dated May 9, 1986, which includes baseline data for comparison with operating jet pump data. All tests required by Technical Specification are include The inspector reviewed ST 9.21-2 (Single Loop), Revision 2,

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dated May 9, 1986. Adequate instructions are now provided to collect baseline data and perform the jet pump operability test on a daily basis.

Because this violation was corrected during this. inspection period and corrective actions to avoid further violations were also made and reviewed, no written response is require The inspector reviewed Unit 3 Technical Specifications, GE SIL 380, and NRC Generic Letters 86-02 and 86-09 relating to thermal hydraulic stability monitoring. When operating in certain regions of the power-flow i map, SIL 380 recommends that_ operators be alert to unstable oscillations in LPRM and

. APRM reading Generic Letter 86-02 notes j that calculation of decay ratios for core

stability have uncertainties of 20% which

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could place certain operations on the verge of unstable oscillations. The generic letter l recommends following the SIL and notes that j these thermal hydraulic stability i

considerations will be factored into future licensing evaluations. Unit 3 has Technical

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Specifications which account for these

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licensee's procedures are written to avoid regions of potential instabilities. The

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! inspector questioned the need to implement stability monitoring on Unit General

Design Criterion 12 requires the reactor core be designed to assure that power oscillations which

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can be reliably and readily detected and l' suppressed. Based upon the information in SIL 380, Generic Letter 86-02, and discussions with 7 staff engineers the licensee is implementing changes to procedures to monitor for

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thermal-hydraulic stability on Unit The inspector will follow the. stability monitoring i j program implementation for Unit !

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} 4. North Substation #1 Transformer Fire on April 13, 1986 l 4.2. Sequence of Events and Licensee Acti,ns An explosion ana resuit>,t fire occurred in the #1 transformer at 11:07 a.m. on Sunday, i April 13, 1986. The #1 transformer (located at the North substation about one mile from the plant) ties the 220KV distribution system with l the 500 KV Peach Bottom ring bus at the North substation. The cause of transformer

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explosion was an apparent internal electrical fault in the A phase, and resulting in a fire and damage to the adjacent B chas The plant fire brigade initially resporded to the scene

and, six offsite fire companies were notified l

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and responded. The fire was out at 1:02 on April 13, 1986. The Delta-Cardiff fire

company remained on the scene until about 7

00 , The loss of the #1 transformer caused a trip

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of breaker 3435, and loss of the #3 startup offsite power source. At the time of the

explosion, Unit 2 was at 75% power and Unit 3 was i

in cold shutdown. Unit 3 had been shutdown at 9:34 p.m. on April 11, 1986, to repair several valves. The loss of the #3 startup source, i

caused a fast transfer of the 4KV emergency buses

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(E22, E42, E13, E33) to the #2 startup source and

resulted in PCIS signals and isolations on both

! units. In addition, a half scram and half PCIS j Group I occurred on Unit 3 as one.RPS bus lost i

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power while on alternate feed (E13 power). The ,

licensee made an ENS call at 11:30 a.m. and notified the senior resident inspector at 11:45 The licensee started the E-2 DG to supply the j E-22 and E-23 emergency 4KV buses at 12:10 l p.m., in order to have different power

supplies for the RPS. At 6:10 p.m., the operators manually tripped the E-2 DG due to '

] fluctuations in the centrol switch red and i green light indication The E-2 DG trip caused a loss of the E-22 and E-23 buses and

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resulted in half scrams and Group II PCIS signals on both units. The licensee '

re-energized the E-22 and E-23 buses from the i

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1. 2 startup offsite power source, reset the half scrams and isolations, and made another ENS cal The #3 startup source was returnea to service at 6:00 p.m., on April 15, 1986; and, the E-2 DG was repaired, tested, and declared operable at 9:55 p.m., on April 15, 1986. With the

'Jorth substation out of service, the PJM grid was determined to be in a condition such that Unit 2 was limited to about 60% power. The Unit 2 limit of 60% was lifted and the unit returned to full power on March 16, 198 .2. NRC Followup

The SRI responded to the event onsite at approximately 1:00 p.m. , on April 13, 198 The inspector reviewed the plant status from the control room; and inspected fire fighting and resultant damage in the North substatio The inspector reviewed plant indications and confirmed that Unit 2 was operating safely at 75% power and Unit 3 was in a cold shutdown condition. The inspector noted that there were no controls nor indications for the 500KV breakers #15 and #65, and for the #3 startup sourc The in plant emergency 4KV buses were powered as follows: #2 startup source carrying E12, E13, E32, E33, E42, E43; and, E-2 DG carrying E22 and E23. The lineup is in accordance with procedure S.8.3.D.3, Unscheduled Tripping of Number 3 Off-Site Startup Source, Revision 5, December 5, 1985. The lineup provides for independent sources of power for the reactor protection syste The inspector examined the #1 transformer damage on April 13, and again on April 14, 1986. Fire fighting command, control, and coordination with off-site fire companies was noted to be good. The A phase of #1 transformer was destroyed by an apparent internal explosio In addition, the transformer oil from the A phase ignited the B phase of the transformer causing excessive damage. Breaker control and indication cables located in an open trench near the #1 transformer were also damaged by the oil fire, resulting in loss of control for the 500KV North substation switchyard breaker .- - . _ _ . _. - -. - - -. -

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The inspector reviewed Technical Specifications (TS) Limiting Conditions for Operation (LC0) .3.9, for operation with out of service electrical power sources. Upon the loss of the #3 startup off sil.e power source, Unit 2 was governed by T5 3.9.B.1, which allows operation for seven day '

Unit 3 could not startup without #3 startup source available as required by TS 3. When

the E-2 DG was inoperable concurrent with the #3 l startup source out of service, TS 3.9.B.4

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governed Unit 2 operatio TS 3.9.B.4 allows operation of unit for seven days with one out of

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service DG and one off-site power source as long as: (1) the other startup source is available to

! the 4KV emergency buses, and (2) TS 3.5.F is satisfied, i.e., all low pressure ECCS and the i three remaining DGs are available. The inspector

] verified that the licensee met these TS LCO The ir.spector raised a concern regarding the

seven day LCO with~both a DG and one startup i power source out of servic Peach Bottom TS

, allow seven days of operations with: (1) one 1 DG out of service, (2) one startup source out '

of se_rvice, or (3) one DG and one startup source out of service. NRR is reviewing the adequacy of TS LCO 3.9. The inspector will review this in a future inspection. (IFI 277/86-07-01).

! 4. Unit 2 Scram on April 23, 1986 Unit 2 scrammed from 100% power at 9:08 p.m. on April 23, 1986. The scram signal was caused by turbine control valve (TCV) fast closure, and occurred during routine

testing of the turbine combined intermediate valves (CIV)

l per RT 5.8, Rev. 5. During the test, when the #2 CIV pushbutton was released the #1 CIV closed apparently due.to an EHC oil pressure transient. The closure of two CIVs apparently caused a pressure spike in the cross around piping, and a turbine power / load unbalance occurred. The power / load unbalance caused a generator lockout and a

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turbine generator tri Thus a TCV fast closure scram on

low EHC pressure occurred. Plant response to the scram was

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normal. Reactor water level dropped to below the group

! II/III PCIS setpoint (approximately -35 inches) and water l level was recovered by the reactor feed pumps. The turbine bypass valves opened as expected, and reactor pressure

!

increased to about 1070 psig. The licensee made a one hour ENS call and informed the senior resident inspector. The unit proceeded into cold shutdown.

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On April 24, 1986, the inspector reviewed the control

, room logs, recorder charts and traces, computer sequence of events log, computer alarm typer, the licensee's

'

preliminary upset report, and the completed GP-18, Scram Review Procedwe. The inspect.u also discussed the scram and event followup with the licensed operators on shift and with licensee engineer While the unit was shut down, the licensee repaired the B and C reactor feed pump minimum flow valves (see detail 12.1). Unit 2 was started up on April 26, 1986, and was critical at 4:03 The unit was synchronized with

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grid at 1:50 a.m. on April 27, 1986, and returned to

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full power operatio The inspector observed portions of the startup.

! I Within the scope of the review of the Unit 2 scram and

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followup actions, no violations were iaentifie .

i 4. Unit 3 Scram on April 26, 1986 l Unit 3 scrammed from 81*. power at 9:51 a.m. on April 26, i 1986. The scram was caused by t rbine control valve

(TCV) fast closure, and occurred during breaker and 4 relay testing of the North substation. Testing on the

] open #65 breaker resulted in the tripping of the #15 breaker due to an I&C technician error. Thus causing a j generator lockout and TCV fast closure. (The #15 and #65 l breakers are the Unit 3 generator output breakers.)

i j Response to the scram was normal. Reactor level j decreased to below the group II/III PCIS setpoint and I

the reactor feed pumps recovered level. The turbine j bypass valves opened to limit reactor pressure to 1050 l psi The licensee made an ENS call and informed the l senior resident inspecto During the unit recovery and j

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prestartup operations, two automatic scrams occurred with the unit shut down as follows: (1) during neutron monitoring system testing per ST 3.2.3 when two IRMs were unbypassed by the licensed operator with their mode i switches out of operate, and (2) when the reactor mode j

selector switch was placed in startup with a high level in

} the scram discharge volume. The licensee reset both scrams

! and made ENS calls. Unit 3 was restarted on April 27, l j

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1986, with the reactor critical at 12:52 p.m. The unit was l synchronized with the grid at 12:15 a.m. on April 28, 198 Both generator breakers (#15 and #65) were returned to j service.

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! On April 28,1956, the inspector reviewed the licensee's l post scram review and followup including: licensee's i upset report; GP-18, Scram Review. Procedure; control

room logs and chart recorder traces; and computer alarm

typer and sequence of even h lug. The inspector also '

interviewed control room licensed operators and licensee l engineers.

i The inspector reviewed the circumstances of the two i licensed operator personnel errors that resulted in scram signals while shut down. Both were due to failure .

to follow procedures. While performing ST 3 2.3, IRM  !

t Functional Test, the operator was testing two channels at T

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time and missed a step which requires him to place the IRM

mode switch to operate. When the IRMs were subsequently

.

unbypassed, a full scram signal occurred. While performing I

GP 11.E, Scram Reset, the operator placed the reactor mode switch in startup without first ensuring that the scram

discharge volume was drained.

j The inspector discussed these procedural violations with l the licensee. The errors were committed by one j individual, were identified by the licensee, and the i

licensee took disciplinary action. The inspector had no

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further questions regarding these errors at this tim '

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Withi'i the scope of the review of the Unit 3 scram and followup, and with the exception of the above two

procedural violations, no deficiencies were identifie . Unit 2 Reactor Coolant Leak Rate

] Unit 2 exoerienced a higher than normal and increasing i drywell unidentified leakage based on drywell floor

] drain sump (DWFDS) pump out. 'As of April'30, 1983, the

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DWFDS 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> average pumpout increased to a value of 3.5 j gpm. TS 3.6.C.1 limits the reactor coolant leakage to the j drywell to 5.0 gpm from unidentified sources. The licensee j verifies compliance with TS 3.6.C.1 by recording DWFDS i j pumpout rates every four hours as required by TS 4.6.C.1; l and as long as the DWFDS average pumpout rate is less than

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5.0 gpm, the TS LCO is met.

1 The licensee noted that the acoustic monitoring system

! sensor on the RCIC inboard steam supply motor operated i

valve (MO-2-13-15) was indicating a valve packing leak (stem leakage). On May 1, 1986, the licensee back-

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i l seated the valve and the DWFDS pun' pout decreased to j

, gpm. The valve acoustic sensor indicated the stem 4 j leakage had stopped as the monitor indicated only

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j background readings. The licensee identified the I difference in DWFPS pumpouts with RCIC valve backseated j and not backseated as 2.5 gpm. Thus, the 2.3 gpm

pumpout of the DWFDS was considered as identified

leakagc. TS 3.6.C.1 limits the tviel unidentified and j identified leakage to 25 gpm.

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While the RCIC MO-2-13-15 valve was backseated, tne i licensee declared the RCIC system inoperable because the i valve could not meet the isolation time criteria of 15

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seconds (TS Table 3.7.1). The RCIC outboard steam

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! isolation motor operated valve (MO-2-13-16) was closed to isolate the RCIC steam line as required by TS , 3.7.D.2.

. The licensee modified procedure ST 9.17-2,~ Reactor Coolant Leakage Test - Unit 2, Rev. 3, to account for the 2.5 gpm identified leak associated with RCIC

, M0-2-13-15. The inspector reviewed the ST procedure, monitored the test performance, and discussed the test

, with operators. On May 1, 1986, the licensee performed i '

a safety evaluation and approved it at PORC meeting 86-051. The inspector reviewed the safety evaluation

and discussed it with the license ,

. Within the scope of the review of the Unit 2 coolant j leakage and licensee actions, no violations were note .3 Logs and Records

The inspector reviewed logs and records for accuracy, l completeness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety,

! correct equipment and lock-out status, jumper log validity, ,

j conformance to Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed: Shift i

Supervision Log, Reactor Engineering Log Unit 2, Reactor Operator's Log, Unit 3 Reactor Operator's Log, Control Operator

Log Book and STA Log Book, Night Orders, Fladiation Work Permits,

!' Locked Valve Log, Maintenance Request Forms and Ignition Source Control Checklists. Control Room logs were compared against Administrative Procedure A-7, Shift Operation Frequent

' initialing of entries by licensed operators, shift supervision, and licensee on-site management constituted evidence of licensee j review. No unacceptable conditions were identified.

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4.4 Engineered Safeguards Features (ESF) System Walkdowns ,

The inspector performed a detailed walkdown of portions of the

high pressure coolant injection (HPCI) system, reactor core

. isolation cooling (RCIC) system, and automatic depressurization J system ( ADS) in order to independently verify the operability of

the Unit 2 and 3 systems. The HPCI and RCIC system, and ADS l

walkdowns included verifications of the following' items:

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Inspection of system equipment condition ,

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Confirmation that the system check-of f-list (COL) anc' -

operating procedures are consistent with plant drawings.

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Verification that system valves, breakers, and switches are

properly aligned.

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Verification that instrumentation is properly valved in and operabl Verification that valves required to be locked have

appropriate locking device Verification that control room switches, indications and controls are satisfactor Verification that surveillance test procedures properly implement the Technical Specifications surveillance requirement Within the scope of the ESF walkdowns of the HPCI and RCIC systems, and the ADS, no unacceptable conditions were note . TMI Action Plan (TAP) Item Status 5.1 TAP Item II.K.3.16.B, Reduction of Challenges and Failures of Relief Valves (Closed)

The only remaining open item for TAP Item II.K.3.16.B, was'to lower the reactor vessel water level isolation setpoint for main steam isolation valve (MSIV) closure from level 2 (-48") to level 1 (-160"). As stated in licensee letter dated June 19, 1984, the modification would be implemented no later than the first refueling outage after issuance of a licen,e amendment. The license amendment application was transmitted to the NRC by letter dated April 19, 1984. NRR issued Technical Specification (TS)

Amendments Nos. 111 and 115 on October 2, 1985. The licensee implemented the Amendment to lower MSIV closure from -48" to -160" on February 20, 1986, for Unit 2 and on February 14, 1986, for Unit .

. .

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The change was performed under plant modification No. 632. The change lowered the setpoint for the devices which cause a low level MSIV Group I PCIS isolation (LIS-3-2(3)-099A thru D). The inspector reviewed the modification package and associated documentation including: safety evaluation, PORC approval, maintenance request forms, surveillance and calibration tests and records,and related checklist The inspector also reviewed GE's analysis NEDC-24367, dated September 1981 and TS Amendments No and 115. The inspector discussed the setpoint change and modification with licensee engineers and licensed operator Within the scope of the review of the actions taken by the licensee in response to TAP Item II.K.3.16.8 for Unit 2 and Unit 3, no unacceptable conditions were identified. TAP Item II.K.3.16.B, is closed for Units 2 and ,

5.2 tap Item II.K.3.18.C, Modification of ADS Logic (Closed - Unit 3)

The Unit 3 Autcmatic Depressurization System (ADS) has been modified in accordance with TAP Item II.K.3.18 to automatically initiate in the absence of a high drvwell pressure initiation signal. The ADS functions as a backup to the High Pressure Coolant Injection System (HPCI) by depressurizing the reactor vessel so that low pressure systems may inject water for core cooling. The ADS was previously actuated upon coincident signals of reactor vessel low water level, high drywell pressure, a low pressure Emergency Core Cooling System (ECCS) pump running, and a 105 second time delay which allows ADS to be bypassed if the operator believes the actuation signal is erroneous or if vessel water level can be restored. However, for transient and accident events which do not produce high drywell pressure, and are further degraded by a loss of HPCI, manual actuation of the ADS would be required to ensure adequate core' coolin To reduce the dependence for manual actuation to ensure adequate core cooling, the licensee installed bypass timers which will automatically bypass the drywell high pressure condition required for ADS actuation if reactor vessel water level remains below the

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ADS initiation setpoint (level 1) for a sustained period. Aftet a set time delay of 9 minutes (plus or minus 1 minute) and the 105 second time delay, ADS will be automatically actuated in the absence of a drywell high pressure signal if a reactor vessel low water level condition still exists and a low pressure ECCS pump is runnin Four 9 minute time delays have been added, one for each ADS drywell high pressure initiation channel. There are two ADS actuation channels (Division 1 and Division 2), either of which can perform the required ADS function. There are two bypass timers associated with each ADS division. The low reactor water i

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level signal is sealed in so that the bypass timer (9 minutes) ;

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will not automatically reset upon recovery of low reactor water level. The 105 second actuation timer will reset if reactor water level recovers above the trip setpoint (-160") before it times ou ,

i Another modification made to the Unit 3 ADS consists of the addition of two ADS manual inhibit switches (one per ADS division)

i that permit the operator to override the ADS automatic blowdown

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logic if necessary. These manual inhibit switches are located on control room panel C03 near the controls for the safety relief '

i valves. A key-locked switch is used for the manual inhibit l function to provide a mean's of limiting the potential for  !

inadvertent actuation of the manual inhibit. Alarms alert the

, operator of time-out of the bypass timer and activation of the manual inhibit switche The above ADS logic modification was approved by NRR in Technical :

Specification (TS) Amendments Nos. 106/110, dated March 5, 1985. The modification was completed on Unit 3 during the 1985-1986 refueling outage; and, is scheduled for Unit 2 during the 1987 refueling outag The inspector reviewed the completed modification package No. 633

, and associated documentation including: safety evaluation,

construction job memo, electrical schematics (MI-S52), PORC approval sheets, modification acceptance test results, maintenance

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request forms and related checklists. The inspector reviewed the TS Amendment Nos. 106/110, BWR Owners Group Evaluation of the ADS Logic Modification; and related NRC/PECo correspondence on the i subject. The inspector also reviewed the revised plant procedures which implemented this ADS logic change including surveillance test procedures, system operating procedures, alarm cards, and emergency operating (TRIP) procedures. The inspector discussed

the modification with licensee engineers and plant licensed

operator .

Within the scope of the review of actions taken by licensee in

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response to TAP Item II.K.3.16.B for Unit 3, no unacceptable -

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conditions were noted. TAP Item II.K.3.16.B is closed for Unit ,

6. Review of Licensee Event Reports (LERs)

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6.1 The inspector reviewed LER's

ubmitted to NRC:RI to verify that the details were clearly reported, including the accuracy of the

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description and corrective action adequacy. The inspector ,

i determined whether further information was required, whether '

generic implications were indicated, and whether the event

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warranted on-site followup. The following LER's were reviewed:

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LER N LER Date Event Date Subject 2-85-19, Rev. 1 E-2 DG and 2A RHR pump inoperability, and resultant April 4, 1986 Unit 2 shutdown September 19, 1985 2-86-11 PCIS Group IIA due to error April 24, 1986 March 26, 1986

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3-85-15, Rev. 1 Exceeding LLRT for type 8 and C tests April 11, 1986 September 30, 1985 3-86-03 PCIS while shutdown due to pulling wrong fuse March 24, 198C February 19, 1986

• 3-86-04 3D RHR pump unexpected actuations March 31, 1986 February 28, 1986

• 3-86-05 .

Low level scram and PCIS Groups II/III during Unit April 7,1986 3 startup March 6, 1986 3-86-06 3A core spray logic loss due to blown fuse April 3, 1986 March 4, 1986 3-86-07 Inadvertent bypassing of RSCS April 4, 1986 March 5, 1986 3-86-08 HPCI inoperable April 3, 1986 March 4, 1986

• 3-86-09 Rod Withdrawal Errors April 16, 1986 March 18, 1986

• 3-86-10 Shutdown scram due to low water level May 5, 1986 April 11,1986

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i 6.2 On-Site-Followup For LER's selected for on-site followup and review (denoted by asterisks above), the inspector verified that appropriate l corrective action was taken or responsibility assigned and that continued operations of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed r

safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe i l 6. LER 3-86-04 concerns an inadvertent start of the 3D RHR pump on two occasions, February 28 and March 24, 198 In both cases the 3D RHR pump started and operated in i

the minimum flow recirculation mode; and, the reactor operator shut down the pump after about one minute of operation. The cause of the first event could not be determined; however, further troubleshooting after the second event noted an exposed wire in the 3D RHR pump

breaker cubicle. A metal support piece had worn through the insulation of two wires associated with the 3D RHR pump closing circuit. The worn insulation and exposed wires combined with another ground in the system apparently caused the pump start relay to become energized resulting in pump start. The licensee taped the exposed wires and the bundle of wires was i repositioned to avoid further damage. The exposed wire was permanently repaired during the Unit 3 outage on April 22, 1986. The remaining RHR pump breaker cubicles 7~

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' were also inspected and no discrepancies were foun The inspector examined electrical print E-184 sheet 8, and discussed the event with lict+see engineers and

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operator The inspector verified that corrective

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actions were complete The inspector had no further questions at this time. Within the scope of review of this LER and event, no violations were identified.

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6. LER 3-86-05 concerns an automatic Unit 3 reactor scram and PCIS Group II/III on low reactor water level on '

t March 6, 1986. The scram followup was conducted by the

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inspector and reviewed in NRC Inspection 278/86-0 Further licensee review of the cause of the scram >

concluded that the decreasing vacuum was due to ,

maintenance on the C condensate pump packing glan :

Apparent leakage past the suction valve and pump gland caused a vacuum decreas In addition, the licensee identified an alignment problem with the reactor feed  !

pumps (RFP). The A and B RFP's controls were verified '

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i to be properly aligned, however the C RFP motor gear unit (MGU) low speed stop was found to be set at 800 rpm

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' l in lieu of 2200 rpm. Thus, when the operator, in ~

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! response to a high reactor level, adjusted the MGU of i the CRFP, to lower feed flow, the RFP speed decreased to

! 800 rpm, reactor level subsequently decreased to the

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low level scram setpoint. The C RFP MGU low speed stop setting will be adjusted during an upcoming maintenance

outage. During the interim, operators were informed of the lower than normal low speed stop setting of the MGU

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for the "C" RFP. Within the s' cope of the review of this LER and followup actions, no violations were note . LER 3-86-09 concerns rod withdrawal errors with the RWM out of service during a Unit 3 startup on March 8, 1986; and subsequent bypassing of the RSCS and manual scra The event was reviewed in NRC Inspection 278/86-09.

T 6. LER 3-86-10 concerns a shutdown scram while controlling level with the RCIC system due to failure of the RFPs minimum flow valves (see detail 12). The inspector reviewed the event with operators and licensee engineers. Within the scope of the review of the event, followup and LER review, no violations were noted.

Surve111ar.ce Testing

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The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room

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operators were knowledgeable regarding testing in progress, approved

procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria ,

were met. Parts of the following tests were observed: ,

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ST 10.8, Control Rod Withdrawal Tests, Rev. 10, performed on Unit

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3 on April 21 and 22, 1986

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ST 9.17-2, 3, Reactor Coolant Leakage Test, Rev. 2 and 3 (Unit 2),

Rev. 0 (Unit 3), performed on both units during the inspection

period.

A

No inadequacies were identified.

In addit-ion, a review of completed surveillance tests was performed as noted in detail 4.2.1.

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l Control Rod Blade Cracking ,

General Electric (GE) has informed the NRC of observed cracking on Peach Bottom Unit 3 control rod blades. A meeting was conducted by GE on April 3, 1986, at NRR. GE's continuing surveillance program on control rod blades indicates the cracking to be primarily in the sheath

,

~.--,---,----..-.n, , --,--w--- -. < ,- . , , - - . ,.-,, . . - - - .,,-,e.--.--m,< .

m- .-.-.,-c.,,.-, -r-,w, .g . -w-- v - ---

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.

to handle weld creviced region, and is reportedly more extensive at Peach Bottom than reported earlier at other plants. GE has informed all BWR

, owners of these findings by letter and by a Rapid Information i Communication Service Information Letter (RICSIL #2), dated April 1,198 The affected control rod blades were an advanced design fabricated in 1982, and may include some hafnium absorber rod Through-wall cracking

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was also found in one of the 60 boron carbide absorber rods. .GE believes I that the greater amount of cracking at Peach Bottom was primarily due to i

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differences in configuration of the welds (continuous vs. intermittent and the resulting increases in crevices) and differences in water chemistry '

(high conductivity). GE is planning to modify the existing sheath design to minimize crevice effects. GE is also planning to inspect additional control rod blades at Peach Bottom as well as other BWRs. NRR is

! following the generic implications of the above information since 16 BWRs j have similarly designed control rod blade The inspector discussed the control rod blade cracking with licensee engineers. The licensee determined that regarding the advanced blade design: No blades are in service in Unit 2, and fourteen blades (22-15, 30-15, 38-15, 30-23, 14-31, 38-31, 46-31, 30-39, 22-47, 30-47,

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38-47, 46-23, 46-39, 14-23) are in service in Unit 3. The inspector reviewed the RICSIL #2 and GE correspondence to PECo dated April 2 and 7, 1986. The inspector also discussed the blade cracking with licensee engineers; and, the inspector had no further questions at this time.

i The long term corrective actions will be reviewed in a future

inspection (IFI 278/86-07-02).

Radiation Protection During this report period, the inspector examined work in progress in

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both units, including the following:

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Health Physics (HP) controls i

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Badging

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Protective clothing use

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Adherence to Radiation Work Permit (RWP) requirements

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Surveys

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Handling of potentially contaminated equipment and materials The inspector observed individuals frisking in accordance with Health Physics procedures. A sampling of high radiation doors was verified to be locked as required. Compliance with RWP requirements was verified i during each tour. RWP line entries were reviewed to verify that I

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l 26 l personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identifie '

10. Physical Security

., i 10.1 Routine Observations

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The inspector monitored security activities for compliance with ,

the accepted Security Plan and associated implementing procedures,

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i including: operations of the CAS and SAS, checks of vehicles on-site to verify proper control, observation of protected area

! access control and badging procedures on each shift, inspection of j physical barriers, checks on control of vital area access and

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escort procedures. No inadequacies were identifie i 10.2 Bomb Threats

<

At 10:35 p.m., on May 6, 1986, the Peach Bottom control room shift clerk received an anonymous telephone call stating that two bombs

were set to go off at 1:00 a.m., May 7, 198 The licensee l believed the caller to be a male in his 20's or 30's with no i abnormal speech pattern The licensee initiated bomb threat and notification procedures. At approximately 10:49 p.m., the same

, night, the York County police dispatcher received an anonymous

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phone call over the emergency 911 number reporting that two bombs were set to go off at about 1:00 a.m., May 7, 1986, at specific

areas of the Peach Bottom plant (area 116 and area 165). .

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Non-essential personnel were evacuated from plant buildings. The bomb search turned up no device. Normal plant operations were resumed at 1:40 a.m. The licensee could not positively determine whether the two calls were made by the same individua At 10:36 p.m., on May 7, 1986, another anonymous call was received by the Lancaster County police dispatcher over the emergency 911 number stating, " Listen carefully, I planted two bombs at Peach Bottom last night and I will set them off tonight if the American people do not wake up". The licensee decided not to evacuate the olant buildings after receiving this threat because of the hoax calls the previous night. The licensee considered this threat a restatement of the May 6, 1986, bomb threats and not credibl Security force personnel conducted searches of plant areas with negative result In both bomb threat instances, the inspector was notified by licensee management at about 11:00 p.m. each night. The inspector reviewed the licensee's. bomb threat procedures (security implementing procedures) and plant evacuation procedure Discussions with licensee security personnel and plant management

were held. Within the scope of the review of the two. bomb threats, no violations were identified.

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1 In-Office Review of Public and Special Reports The inspector reviewed the following:

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Annual Occupational Exposure Report for 1985, Revision 1, April 23, 198 Unit 3 January 1985 Containment Integrated Leak Rate Test Report, April 21, 198 No violations were identifie . Reactor Feed Pump (RFP) Minimum Flow Valves ,

During the inspection period, the reactor feed pumps (RFP) minimum flow valves on both units experienced failures. The air operated valves,

, A0-2(3)139A,B,C, are manufactured by ITT Hammel Dahl Conoflow, Inc.,

and are designed as an "S" type plug valve. The model number is SB-54XW-WXXM-3. The valve opens on low RFP flow to prevent pump damage on overheating and the valve fails open on loss of air signal.

! Both units have experienced similar valve failures over the last several years due to the valve operator stem separating from the valve plug. The stem is threaded into the plug, pinned and then tack welded. The licensee has attributed the failures to valve cycling, line vibration, and cavitation damage; and the failures have resulted in stem and plug separation. RFP flow will cause the valve to close and remain closed i

when the stem / plug separation occurs. The valve is located in the vicinity of the RFPs; and the valve sees RFP discharge conditions on one side (400 degrees F and 1100 psig) and condenser vacuum conditions on the other sid In order to effect a safe RFP shutdown without minimum flow protection; the licensee developed an operating procedure, S.7.6.C.2, " Shutdown of

, a RFP with Failed Min Flow Valve", Rev. O. The inspector reviewed the procedure and discussed the procedure implementation during a Unit 3 t

shutdown on April 11, 1986, with the operators.

. The inspector also discussed these RFP minimum flow valve failures with i

licensee engineers and maintenance personnel. The licensee is pursuing a plant modification for long term corrective actions. The modification would replace the currently designed valve and relocate the valve nearer to the main condenser. The relocation would provide a water leg on the valve in an effort to reduce valve cavitation. The licensee indicated that the modification would be scheduled for both units the next refueling outage. The inspector will follow the modification on the RFP minimum flow valves (IFI 277/86-07-02).

During the review of RFP minimum flow valves, no violations were noted.

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1 Inspector Folicw Items Inspector follow items are items for which the current inspection findings are acceptable, but due to on going licensee work or special inspector interest in an area, are specifically noted for future follow-u Follow-up is at the discretion of the inspector and regional managemen Inspector follow items are discussed in details 4.2.2, 8, end 1 . Management Meetings 14.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Station Superintendent at the conclusion of the inspectio During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspector No written inspection material was provided to the licensee during the inspection. No proprietary information is included in this repor .2 Attendance at Management Meetings Conducted by Region-Based Inspectors The resident inspectors attended entrance and exit interviews by region-based inspectors as follows:

Inspection Reporting Date Subject Report N Inspector April 1, 2 Security 86-10/10 Bailey April 8-11 QA 86-11/11 Dev l

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