IR 05000334/1985012

Insp Rept 50-334/85-12 on 850406-0513.No Violation Noted. Major Areas Inspected:Plant Operations,Housekeeping,Fire Protection,Radiological Controls,Physical Security & Surveillance Activities

ML20126B496
Person / Time
Site:	Beaver Valley
Issue date:	05/24/1985
From:	Dante Johnson, Lester Tripp, Troskoski W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20126B473	List: IR 05000334/1985012 ML20126B470
References
50-334-85-12, NUDOCS 8506140117
Download: ML20126B496 (14)

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U.S. NUCLEAR REGULATORY COMMISSION DCS Nos. 850411 REGION I 850405 850130 Report N /85-12 831103 840125 Docket N Licensee: Duquesne Light Company Post Office Box 4 Shippingport, Pennsylvania 15077 Facility Name: Beaver Valley Power Station, Unit 1 Location: Shippingport, Pennsylvania Dates: April 6 - May 13, 1985

Inspector: /[. . J fbb

' M. T date

't).E.br 5Koski,e Senior Resident Inspector 9/uIas 70 M. Jo Gon, Resident Inspector (fate'

Approved by #. '4 V. E. Trfpb, Chief, Projects Section 3A 8 ff8b

~ dat'e Projects Branch 3 Inspection Summary: Inspection No. 50-334/85-12 on April 6 - May 13, 1985 Areas Inspected: Routine inspections by the resident inspectors (132 hours0.00153 days <br />0.0367 hours <br />2.18254e-4 weeks <br />5.0226e-5 months <br />) of licensee actions on previous inspection findings, plant operations, housekeeping, fire protection, radiological controls, physical security, engineered safety features verification, surveillance activities, licensee response to selected safety issues, and licensee event report Results: No violations were identified.

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'l B506140117 850610 PDR ADOCK 05000334

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DETAILS

- Persons Contacted-J. J.~Carey, Vice President, Nuclear Group R. J..Druga, Manager, Technical Services

.T. D. Jones,. General Manager, Nuclear Operations W. S. Lacey, Plant Manager -

-J.-D. Sieber, General Manager, Nuclear Services N.-R.' Tonet, General Manager, Nuclear Engr. & Constr. Unit J. V. Vassello, Manager, Nuclear Safety The inspector also contacted other licensee employees and contractors during this inspectio . Followup on Outstanding Items'

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The NRC Outstanding Items (01) List was reviewed with cognizant-licensee per-sonnel. Items selected by the inspector were subsequently reviewed through-

' discussions with-licensee personnel, documentation reviews and field inspec-tion to determine whether licensee actions specified in the OI's had been-satisfactorily completed. 'The overall status of previously identified in-spection findings were reviewed, and planned and completed licensee actions were-discussed for those items reported below:

(Closed) Inspector Follow Item (84-28-03): Quality Control to conduct sur-

.veillance inspections of general stores-in accordance with 0QC Procedure This item involved the lack of a regular QC inspection of general stores areas, except for the annual. inspection. This was not consistent with 0QC Procedure 8.1, Paragraphs 4.5 and'4.6, which requires' surveillance of "as shipped conditions and long term periodic maintenance for items in storage."

0QC.has since developed approved surveillance check lists-for storage area These checklists will be performed on a scheduled frequency or on an as-needed basis if the surveillance results warrant increased attentio The. inspector-reviewed the surveillance checklists and considers them acceptable to ensure proper storage. The inspector had no other concerns and this item is close (0 pen) Violation (84-33-03): Failure to establish containment integrity prio to leaving Mode 5 during startup from the fourth-refueling outage. The in-spector reviewed the corrective actions outlined in the licensee's response to the Notice of Violation and proposed imposition of civil penalty dated

' April 11, 1985. The immediate corrective actions taken which included closing drain valve RS-113 upon discovery, management discussions with the individuals involved to identify the causes, circumstances and necessary corrective'ac-tions, additional-training for each operating crew with regard to the proceed-ing items, a'nd personnel disciplinary action, were verified by the inspector through selective examination of documents and discussions with cognizant licensee personne _

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The licensee's letter identified 12 areas where action would be taken to pre-vent recurrenc During startup from the one week maintenance outage con-ducted during the first week of May, 1985, (see Detail 3 of this inspection report for further discussion), the inspector confirmed completion of the following items: OST 1.13.7, 18 Month Recirculation Pump Auto Start and Flow Test, though not run at this time, has been revised to require closing the outside recirc spray pump casing drain valves RS-113 and 11 This action now requires a double verificatio OST 1.47.2, Monthly Containment Integrity Verification, has been reviewed to identify valves or connections not previously addressed for all con-tainment penetrations. The inspector reviewed the test completed prior to entry into Mode Through discussions with Operations and Maintenance personnel, the in-spector verified that tighter plant configuration control is being es-tablished by reinforcing the "Off-Log-Only" clearance procedure require-ment This practice is continuing to receive a critical review by the licensee and a final disposition may still be evolving because of pos-sible responses to INP0 concern Station Startup Checklist 8, completed prior to leaving cold shutdown and Station Startup Checklist E, completed prior to leaving cold shutdown conditions when the turbine plant is isolated, have been revised to re-quire performance of OST 1.4 Station Startup Checklists 1.50.3B thru F were revised to require a de-tailed clearance review prior to each mode escalation above cold shut-down. This review is outlined in OM 1.48.68, and satisfactorily ad-dresses the concern that the status of all equipment important to safety be known prior to leaving cold shutdow The Operations Department has been reorganized in such a manner as to provide additional management resources where necessar Through close inspector followup of plant startup activities from the May, 1985, maintenance outage, it was verified that other concerns which could have contributed to the multiple operational problems encountered during startup from the fourth refueling outage, such as the inordinate number of personnel undergoing on-the-job training, and what was preceived to have been management pressure to return the plant on-line, have been notably absent during this startup. Though the Operations Department has yet to finalize many of their programs and policies in this regard, it appears that their investigation into the circumstances which allowed a containment integrity violation to occur has addressed many of the possible contributing factors. The development of detailed corrective action to tighten plant configuration control to assure operating staff knowledge of system and component status and the establishment

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~of restrictions for startups prior to entry into Mode 4, should ensure ade-

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, quate control of future reactor startups. The licensee has been responsive o l- in aggressively dealing with this safety issu _

This1 item remains open pending final completion of the remaining long term corrective actions that the licensee has committed to completing by'either b July-31, 1985, or the next refueling outage, as applicabl (Closed) Inspector Follow Item (85-01-01): Remove last cycle's rod worth

' power defect curves from the shutdown margin calculation procedure OST 1.4 . The inspector reviewed Revision 26 to the surveillance procedure and verified that the power defect curve contained in Fig. 1 and integral rod worth curve

in Fig. 2 had'been permanently updated with reactor core Cycle 5 data. This I satisfactorily closes the item.

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• (Closed) Violation (84-15-01): Inadequate test control for station batterie NRC Inspection Report 50-334/84-30 reviewed the licensee's duty cycle load

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calculations and test program used to prove design operability. As no prob-t lems were found with testing, this item is closed.

[ (Closed) Unresolved Item (84-20-02): Verify that containment particulate

, monitor can perform its design function at an elevated count rate expected for core cycle 5. The inspector reviewed the Nuclear Services Unit Memo of 4 . January 15, 1985, which summarized leak detection system capabilities set

, forth in the FSAR, and provided calculations to determine the time required

to detect various sized reactor coolant system leakages assuming typical reactor coolant gaseous activity levels. The licensee determined that the

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containment area particulate monitor, RM-215A, by itself,'was not reliable

for determining reactor coolant pressure boundary leakage within a 1-gpm ac-

- curacy within one hour. However, the licensee believes that the sensitivity to detect at least a leak as large as 5 gpm exists under all conditions. From

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a review of the reactor coolant system leak data of April 26, 1985, and through discussions with licensee personnel, it can reasonably be concluded that RM-215A'and B are not the most sensitive leak detection methods available.

This function appears to be performed by sump alarms, flow rate and makeup

! frequency to the VCT (under steady state conditions) and OST 1.6.2, RCS Inven-

< - tory Calculations. When used together, these systems have demonstrated the g combined capability of detecting small leak rates inside containment before

exceeding the 1.0 gpm technical specification limit. Therefore, the high-baseline of about 80,000 cpm observed on RM-215A during the end of the last

, core cycle does not appear to adversely affect the. licensee's ability to

identify a design-based reactor coolant system leak. The inspector had no l

further concerns and this item is close (0 pen) Violation (85-02-01): Failure to properly perform leak testing of RCS i pressure-isolation valves per ASME Subsection IWV-3420, and failure to pro-

_ perly perform SI accumulator check valve leak test. This violation concerned the_ incorrect performance of two check valve surveillance tests. OST 1.11.16

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was' performed on RCS pressure isolation check valves and the results were

verified as satisfactory without accounting for the fact that the test was l

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accomplished at a pressure lower than functional maximum pressure and the measured results were not corrected as required by ASME Section XI, Subsection IW-3420. The licensee has subsequently adjusted the results of previously accomplished-tests of the subject check valves per IW-3420, and the results were within the acceptable range. These calculations were verified by the

' inspector. Additional action has included a revision to OST 1.11.16 to ensure

. incorporation of test data correction factor OST 1.11.4, SI Accumulator Check Valve Test, was incorrectly performed in that satisfactory completion required zero leakage, but in certain conditions a positive leakage indication was considered acceptable. The procedure will be revised to ensure that proper test conditions are established prior to accomplishment of the test; i.e., bleeding off trapped pressure in the lines prior to recording leakage data to ensure that only true leakage is recorde This change will be reviewed in a future inspectio 'The licensee also plans a review of leak test methods for Category A valves, and any resultant revisions to procedures or the IST program will be completed-prior.to the next refueling outage. The above actions will satisfactorily address the concerns identified in'this violation, which remains open pending their implementatio (Closed) Violation (85-02-02): Failure to specify the use of only QA Category I components in surveillance tests to meet the minimum boric acid storage tank volumes specified in the technical specification. This violation concerned the use of a non-seismic, non-class 1E electrical system (Boron Recovery) to supplement the total inventory of stored boric acid to meet BVPS Technical Specifications 3.1.2.7 and 3.1.2.8. This was a violation of 10 CFR 50, Ap-pendix A, General Design Criteria. The licensee has revised the-subject sur-veillance test procedure (OST 1.7.8), to prohibit the use of BR-TK-7 in cal-culations that account for the concentrated boric acid inventory. The licen-see additionally reviewed other volumetric requirements of various storage tanks to ensure that the above problem did not exist with these tanks or sub-systems. The inspector verified that the revised version of OST 1.7.8 was in use and was being accomplished properly. The volume in BR-TK-7 is still monitored but not used for technical specification requirements. This action is considered satisfactory and the violation is close . Plant Operations General

' Inspection tours of the plant areas listed below were conducted during both day and night shifts with respect to Technical Specification (TS)

compliance, housekeeping and cleanliness, fire protection, radiation control, physical security and plant protection, operational and main-tenance administrative control Control Room

-- Primary Auxiliary Building

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- . Turbine' Building

-- Service Building

-- Main Intake Structure-

-- Main Steam Valve Room

-- Purge Duct Room

-- East / West Cable Vaults-

-- Emergency Diesel Generator Rooms

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Containment Building-

-- Penetration Areas

-- Safeguards Areas .

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-- Various Switchgear Rooms / Cable Spreading Room

-- Protected Areas-Acceptance criteria for~the above areas included the following:

-- BVPS FSAR

-- Technical-Specifications (TS)

-- BVPS ' Operating Manual -(OM), Chapter 48, Conduct of Operations

-- OM'1.48.5, Section D, Jumpers and Lifted Leads

-- OM 1.48.6, Clearance Procedures

, - ;0M 1.48.8, Records

-- OM 1.48.9, Rules of. Practice

-- OM Chapter 55A, Periodic Checks, Operating Surveillance Tests

-- BVPS Maintenance Manual ( m ), Chapter 1, Conduct of Maintenance

-- BVPS Radcon Manual (RCM)

-- 10 CFR 50.54(k), Control Room Manning Requirements

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-- BVPS Site / Station Administrative Procedures (SAP)

-- BVPS Physical Security Plan (PSP)

-- Inspector Judgement Operations

$ The inspector toured the Control Room regularly to verify compliance with

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NRC requirements and facility technical specifications (TS). Direct ob-servations of instrumentation, recorder traces and control panels were made for items important to safety. Included in the reviews were the rod position indicators, nuclear instrumentation systems, radiation monitors, containment pressure and temperature parameters, onsite/offsite'

emergency power sources, availability of reactor protection' systems and proper alignment of engineered safety feature systems. Where an abnormal condition existed (such as out-of-service equipment), adherence to ap-propriate TS action statements were independently verified. Also, various operation logs and records, including completed surveillance tests, equipment clearance permits in progress, status board maintenance

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and temporary operating procedures were reviewed on a sampling basis for -

compliance with technical specifications and those administrative con-trols listed in paragraph 3 !

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During the course of the inspection, discussions were conducted with operators concerning reasons for selected annunciators and knowledge of recent changes to procedures, facility configuration and plant condition The inspector verified adherence to approved procedures for ongoing ac-tivities observed. Shift turnovers were witnessed and staffing require-

-ments confirme Except where noted below, inspector comments or ques-

.tions resulting from these daily reviews were acceptably resolved by licensee personne (1) A primary coolant system leak of about 0.5 gpm developed inside containment during the week of April 21, 1985. During this time, the containment sump pumpout rate gradually increased from about 40 to 66 gph, while containment particulate and gaseous radiation monitors (RM-215 A&B) showed no increase above normal backgroun A review of OST 1.6.2, RCS Inventory, indicated a slight increase of unidentified leakage from 0.24 to 0.55 gpm, which was below the technical specification 1.0 gpm leak rate. Positive indications of a high energy leak inside the pressurizer cubicle occurred on April 23, 1985, when the C safety valve tail pipe temperature reached the 150 degree alarm point. The alarm point was reset to 165 degrees, which was never exceede After the containment sump pumpout rate reached the administrative guidelines of 60 gph, Operations personnel made an at power con-tainment entry on April 26, 1985 and identified the source of the leak as coming from the pressurizer manway cover. The licensee shut down the reactor that day to begin a week long maintenance outag When the plant was brought to cold shutdown, the inspection by lic-ensee personnel found steam cutting of up to 0.826 inches deep on the carbon steel manway flange and 0.344 inches on the manway cover, with about a 6 inch widt No damage was visible on the stainless steel sealing surfac The inspector reviewed the licensee's planned corrective action through discussions with OLC engineering personnel and documentation revie These actions consisted of replacing the failed flexatel-

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lic gasket, grinding out the steam cut to eliminate possible stress risers, performing a magnetic particle examination, and conducting a hydrostatic test at operating pressure and temperatur The licensee performed engineering calculations which were reviewed and approved by Westinghouse, the NSSS vendor, to show that minimum wall thickness assumed in the original construction code (NB-3000)

would not be violated. The repairs were done to ASME XI require-ments. For the manway cover, which had several pits inside the bolt -

holes of up to 1/8 inches, no repair was attempted. Bolt hole ex-amination was performed to IWA-2240,Section XI and Code Interpre-tations XI 80-08 and 81-07 to verify that there was no evidence of

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crackin Discussions with NRC Region I Specialists identified no

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fproblems with this approach. One concern raised was whether the

~BVPS Inservice Inspection Program would be revised to re-examine

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this' repair. This is Unresolved Item (85-12-01). ,

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After the plant was restarted on May-6, 1985, inspector review o I' .the containment sump pumpout rates indicated a drop to about 8 gp Background readings on RM215-A&B dropped by a factor of 10. Main-tenance on the manway cover and several. valves inside containment

',' appears to have been effectiv ,

Discussions with DLC management indicated that because of past flange leaks (RTD manifold, among others), consideration was being:

given to establish a program whereby all flange connections are i periodically checked for tightness at some pre-determined interval L (based on time or temperature cycles). The licensee is currently b '

reviewing this with other plants to determine what their experience

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Inspector Follow Item (85-12-02).

) (2) On April 27, 1985, component cooling water heat exchanger 1A (CCR- l HX-1A) developed a leak at the rate of one inch of surge tank level i every 15-20 seconds. The plant was in hot standby at the time, in

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preparation for cooling down to correct the pressurizer manway cover leak. The heat exchanger was temporarily removed from service, which left only one CCR system operable as the second (of three)

heat exchangers was out of service for retubing. Calculations.in-

! dicated that about 7,000 gallons of chromated water was released to the river. The licensee immediately plugged the failed tubes,

but did not pull them for examination to determine the failure mode

! because of the immediate need to return it to. service. Licensee representatives informed the inspector that after completion of the ,

retubing job on CCR-HX-1C, 1A would be taken out of service to pull '

[ the failed tubes. Determination of the failure mode is an Inspector Follow Item (85-12-03).

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) (3) The reactor trip breakers were spuriously actuated on May 1,'1985, ,

while the reactor was shutdown with all control rods inserted. MSP

~ .01, Steam Line Pressure Protection, Loop 1, Channel II, was in

progress at the time. When the technician switched the solid state i protection system Train A multiplexer from A&B thru inhibit, the Pressurizer Low Pressure and Reactor Coolant Loop Low Flow trips '

actuate Each of these trips should have remained blocked by

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permissive P-7, because 3 of 4 power range channels were below the *

. P-10 setpoint and 2 of 2 impulse pressure channels were below the P-13 setpoint, as the plant was in cold shutdown. The licensee reran portions of the MSP in an attempt to duplicate i

the failure. These attempts verified that the MSP was correctly written and that the technician could not have caused the trip from

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where he was at in the solid state protection system.

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Discussions with licensee personnel indicated that for a single failure to unblock P-7, either impulse pressure transmitter 446 or 447 would have had to spike high. A multi-channel recorder has been hooked up to each channel in an attempt to identify the proble No noise was seen and the problem has not repeated itself to dat (4) A reactor trip occurred from about 15% power at 11:53 a.m. on May 6, 1985, due to a low-low steam generator water level. The cause of the trip was due to feedwater control problems encountered by the operators when switching feedwater control from the bypass valves to the main control valves, while ramping power up with steam generator water levels oscillating. All safety systems functioned as expecte During the review of the historic data storage and retrieval print-out, the inspector noted that containment pressure monitor LM-1008 exhibited unusual behavior in that a step change of about 0.6 psia was noted on four occasions during the data run. On each occasion, the parameter would return back to its normal baseline data. This was brought to the licensee's attention for further I&C assessment, as other pressure transmitter spikes have previously occurred since changeout with environmentally qualified components during the past refueling outage (see detail 3b.4 of NRC Inspection Report 50-334/

84-33).

(5) During the month of April,1985, more than a dozen over-temperature delta-temperature (0 TDT) high alarms annunciated for no apparent reason. After investigation, the licensee determined that one pos-sible cause was due to security personnel performing radio checks in certain locations, which produced enough electrical noise to interfere with the instrumentation signal. A test is currently underway to determine what areas of the plant are most susceptibl More spurious OTDT alarms occurred during May, 1985, that apparently were not due to radio interference. Though the majority occurred on the C loop, soveral also occurred on the B loop. A multi-channel recorder showed all temperature inputs and setpoint signals were steady, with the spikes coming in on the comparator output. Even after changeout of the comparator module, the spurious signals per-sisted. Further review of this is Inspector Follow Item (85-12-05).

(6) Charging Pump CH-B-1C was returned to service on April 13, 1985, and the Operational Surveillance Test was successfully complete It was noted that the drive gear inboard thermocouple was giving invalid readings. It was also noted that the wrong grade oil (DTE 26 instead of 24) had been added to the circulating oil syste The inspector discussed this with licensee personnel and determined that the lube oil log kept in the Control Room was not a controlled

cop Apparently, the oil added to the C charging pump was of the type viscosity that was to be added to the modified A charging pump

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lube oil system. The C charging pump was taken out of service and the oil changed out. Further evaluation by the licensee determined that this grade of oil would not have degraded pump performanc The licensee's representativ.e informed the inspector that admini-strative controls would be developed for the lube oil log. The in-spector had no futher concern c. Plant Security / Physical Protection Implementation of the Physical Security Plan was-observed in the areas listed in Paragraph 3A above with regard to the following:

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Protected area barriers were not degraded;

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Isolation zones were clear;

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Persons and packages were checked prior to allowing entry into the Protected Area;

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Vehicles were properly searched and vehicle access to the Protected Area was in accordance with approved procedure Security access controls to Vital Areas were being maintained and that persons in Vital Areas were properly authorize Security posts were adequately manned, equipped and security per-sonnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and,

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Adequate lighting maintaine No inadequacies were observe d. Radiation Controls

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Radiation controls, including posting of radiation areas, the conditions of step-off pads, disposal of protective clothing, completion of Radi-ation Work Permits, compliance with Radiation Work Permits, personnel monitoring devices being worn, cleanliness of work areas, radiation con-trol job coverage, area monitor operability (portable and permanent),

area monitor calibration, and personnel frisking procedures were observed on a sampling basi No inadequacies were note e. Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in areas listed in paragraph 3a. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas was also observe No inadequacies were note .

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4. Engineered Safety Features (ESF) Verification The operability of the River Water System during the week of April 8,1985, was verified by performing a walkdown of accessible portions that included the following as appropriate: System lineup procedures match plant drawings and the as-built configur-atio Equipment conditions were observed for items which might degrade per-formance. Hangers and supports were operabl The interior of breakers, electrical and instrumentation cabinets were inspected for debris, loose material, jumpers, et Instrumentation was properly valved in and functioning; and had current calibration date Valves were verified to be in the proper position with power availabl Valve locking mechanisms were checked, where require Technical specification required surveillance testing was curren No violations were identifie . Surveillance Activities To ascertain that surveillance of safety-related systems or components is being conducted in accordance with license requirements, the inspector ob-served portions of selected tests to verify that: The surveillance test procedure conforms to technical specification requirement Required administrative approvals and tagouts are obtained before initi-ating the tes Testing is being accomplished by qualified personnel in accordance with an approved test procedur Required test instrumentation is calibrate LCOs are me The test data are accurate and complete. Selected test result data was independently reviewed to verify accurac Independently verify the system was properly returned to servic . _ . __

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, Test results meet technical specification requirements and test discre-pancies are rectifie i .- The surveillance test'was completed at the required frequenc The following in progress tests were witnessed by the inspector:

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OST 1.30.6, River Water Pump 1C Test, conducted April 15, 198 OST 1.7.6, Centrifugal Charging Pump 1C Test, conducted April 17, 198 ;OST 1.2.8, Nuclear Source Range Channel Functional Check, conducted May 1, 198 OST 1.1.7, Manual Reactor Trip Test, conducted May 6, 198 .

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MSP 21.04, P-475 1A Steamline Pressure Protection Channel III, conducted May 9 1985.'

No problems were identifie ; Survey of Licensee's Response to Selected Safety Issues

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' Information Notice 83-75: Improper Control Rod Manipulation This item concerns potentially mispositioned control rods and the ade-quacy of the licensee's procedures and training to ensure proper action is taken by operators in respose to this condition. Although the design at Beaver Valley does not incorporate a rod worth minimizer as referred to in the information notice, a similar problem of a mispositioned rod

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occurred and was discussed in Inspection Report 50-334/85-02. At that time, it was determined that operator training and control room surveil-lance requirements were adequate to identify this condition in a timely manner. The inspector has additionally verified that AOP-5, Dropped RCCA, and AOP-6, RCCA or RCCA Group Misalignment, provided for actions that are consistent with BVPS technical specifications, Information Notice 84-06: Steam Binding of Auxiliary Feedwater Pumps

.This item concerns the potential of steam binding in the auxiliary feed-water pump due to leakage from the main feedwater system past various check valves. A review was conducted to verify that procedures were i developed to prevent, detect, and correct any back leakage problems, that i those procedures were properly implemented, and that personnel training has been completed in this area. Historically, this item has not been '

a problem at BVPS Unit 1. Past inspector walkdowns of this system during i plant operation have not identified a high temperature problem in the auxiliary feedwater piping. Licensee personnel routinely check and log :

this each shift by physically touching the piping, as no local or remote l temperature indication exists. Procedures that accomplish surveillance ,

testing on the AFW pumps have proven to adequately promote proper check !

valve seating. Discussisns with plant operators who routinely operate '

or check the auxiliary ? 'edwater system indicated that this concern is addressed as part of the non-licensed operator training. Additionally, l t

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the licensee developed a procedure to address steam binding of the auxiliary feedwater pumps as contained in OM Chapter 1.24.4, which was reviewed and approved by the Onsite Safety Committe The licensee's actions regarding the above safety issues appears to be ade-quate and no problems were identified at this tim . Maintenance and Modification Activities A 1 inch station air valve just installed under DCP 129, Steam Generator Blowdown Modification, was opened on April 12, 1985, by construction personnel causing a header pressure drop from about 125 psi to about 85 psi. The sta-tion air header trip valve closed, isolating the instrument air system to prevent dragging pressure down furthe By procedure, Operations personnel are required to manually trip the plant when instrument air pressure drops below 75 psi. During discussions of the incident critique with DLC personnel, the inspector was informed that no red danger tag was placed on the unlabeled 1 inch valve; however, a construction hold tag was. A section of pipe with the valve had been tapped into the pressurized station air system, with the approval of operations, and had not been turned over to the plant because the construction group was still performing modification work. The inspector raised a concern that a portion of a fluid system could be modified by con-struction without a station isolation point. Specifically, the equipment clearance procedures on the secondary side appeared to have broken down by not placing a station clearance or isolation point downstream of the con-struction work. Follow up in this area is Inspector Follow Item (85-12-06).

8. Inoffice Review of Licensee Event Reports (LERs)

The inspector reviewed LERs submitted to the NRC:RI office to verify that the details of the event were clearly reported, including the accuracy of the de-scription of cause and adequacy of corrective action. The inspector deter-mined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followu The following LER was reviewed:

LER: 85-06: Turbine Trip / Reactor Trip Due To High S/G Water Level During Startu LER 85-06 details a reactor trip from 17% power due to a combination of per-sonnel error in the operation of the main feed control valve, combined with the sluggish response of the bypass control valve concurrent with condenser steam dump operation which led to the steam generator swell. Initially, both the main and bypass control valves were in manual control for the C steam generator. When the main feed control valve was placed in automatic control, the result was a rapid increase in steam generator level. The difficulty that the licensee encountered is very si.nilar to the reactor trip that occurred from 15% power on May 6, 1985, as discussed in Detail 3b.4 of this inspection report. Through discussions with the Operations Supervisor, the inspector was informed that more explicit operational guidelines were being developed

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to ensure a smoother transfer of feedwater control from the bypass to the main feed control valve. Further review of the licensee's solution to this recur-ring problem is Inspector Follow Item (85-12-07). ' Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A'

summary of inspection findings was further discussed with the licensee at the  !

conclusion of the report perio !t

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