IR 05000267/1989016

Insp Rept 50-267/89-16 on 890716-0831.Violation Noted.Major Areas Inspected:Onsite Followup of Ler,Followup on Violations,Followup of Open Item,Review of Part 21 Repts & Review of Licensee Action of Events

ML20248B315
Person / Time
Site:	Fort Saint Vrain
Issue date:	09/26/1989
From:	Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20248B301	List: IR 05000267/1989016 ML20248B297 ML20248B305
References
50-267-89-16, NUDOCS 8910030162
Download: ML20248B315 (16)

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APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-267/89-16 Operating License: DPR-34 Docket: 50-267 Licensee: Public Service Company of Colorado (PSC)

P.O. Box 840 Denver, Colorado 80201-0840 Facility Name: Fort St. Vrain Nuclear Generating Station (FSV)

Inspection At: FSV, Platteville, Colorado Inspection Conducted: July 16 through August 31, 1989 Inspectors: R. E. Farrell, Senior Resident Inspector P. W. Michaud, Resident Inspector H. D. Chaney, Senior Radiation Specialist R. P. Mullikin, Project Inspector

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Approved: .

.4 26 T. F. Westerman, Chief, Project Section 8 Date Division of Reactor Projects Inspection Suninary Inspection Conducted July 16 through Aucust 31, 1989 (Report 50-267/89-16)

Areas Inspected: Routine, unannounced inspection of onsite followup of Ticensee event reports, followup on violatiens, followup of an open item, review cf the 10 CFR Part 21 reports, review of licensee action on Generic Letter 83-28, operational safety verification, onsite followup of events, monthly surveillance observation, and monthly maintenance observatio Results:

During the inspection period, the licensee set a new facility record for net electrical generation in 1 month: 167,699 MW hours in July 198 The licensee's reactor engineers worked around the clock performing Test RT-500 to measure core fluctuations of fuel blocks as core pressure differential increased. In working around the clock without authorization, these engineers violated Technical Specification (TS) AC 7.1.1.2.b. i which limits continuous safety-related activity to 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24-hour period by an individual (see paragraph 10 of this report).

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APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-267/89-16 Operating License: DPR-34 Docket: 50-267 Licensee: Public Service Company of Colorado (PSC)

P.O. Box 840 Denver, Colorado 80201-0840 Facility Name: Fort St. Vrain Nuclear Generating Station (FSV)

Inspection At: FSV, Platteville, Colorado Inspection Conducted: July 16 through August 31, 1989 Inspectors: R. E. Farrell, Senior Resident Inspector P. W. Michaud, Resident Inspector H. D. Chaney, Senior Radiation Specialist R. P. Mullikin, Project Inspector Approved: . N h 7$ M 2 T. F. Westerman, Chief, Project Section B Date 4 Division of Reactor Projects Inspection Summary Inspection Conducted July 16 through August 31, 1989 (Report 50-267/89-16)

Areas Inspected: Routine, unannounced inspection of onsite followup of licensee event reports, review of the 10 CFR Part 21 reports, review of licensee action on Generic Letter 83-28, operational safety verification, onsite followup of events, nonthly surveillance observation, and monthly maintenance observatio Results:

During the inspection period, the licensee set a new facility record for net electrical generation in 1 month: 167,699 MW hours in July 198 '

• The licensee's reactor engineers worked around the clock performing Test RT-500 to measure core fluctuations of fuel blocks as core pressere differential increased. In working around the clock without authorization, these engineers violated Technical Specification (TS) AC 7.1.1.2.b. which limits continuous safety-related activity to 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24-hour period by an individual (see paragraph 10 of this report).

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A slack cable alarm during control rod scram testing on August 17, 1989, indicated a stuck control rod in Region 1 *

The control rod in Region 19 was removed and inspected. Both absorber string cable clevis bolts were broke *

A through wall crack was found on a steam generator main steam ring header which collects the 2400 psig, 1000*F steam as it exits the steam generato *

Subsequent investigation identified tertiary creep cracking in several of the 12 steam generator main steam ring header *

On August 29, 1989, the licensee announced that the combination of control rod and main steam ring header problems made continued operation impractica *

The licensee ceased further attempts to operate the plant and declared August 18, 1989, the start of the 100-day cooldown period prior to defueling for decommissionin l l

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-3-DETAILS Persons Contacted D. Alps, Supervisor, Security -

• P. Anderson, Supervisor, Nuclear Regulatory Affairs

• M. Block, Systems Engineering Manager R. Craun, Nuclear Site Engineering Manager A. Crawford, Vice President, Nuclear Operations

• J. Eggebraten, Project Manager

• D. Evans, Operations Manager

• M. Ferris, QA Operations Manager

• C. Fuller, Manager, Nuclear Production

• D. Goss, Nuclear Regulator Affairs Manager

• J. Gramling, Supervisor, Nuclear Licensing Operations M. Holmes, Nuclear Licensing Manager

• D. Rodgers, Nuclear Computer Services Manager

• L. Scott, QA Services Manager

• N. Snyder, Maintenance Manager

• P. Tomlinson, Manager, Quality Assurance

• D. Warembourg, Manager, Nuclear Engineering The inspectors also contacted other licensee and contractor personnel during the inspectio I

• Denotes those attending the exit interview conducted August 30, 198 . Plant Status During the inspection period, the month of July was the best net electrical generation calendar month in the plant's history. During July, the plant generated 167,699 MW hours of electricity. This was followed in August by control rod and main steam ringheader problems. These problems 1 caused the licensee, Public Service Company of Colorado, to announce on  !

August 29, 1989, that effective immediately, nuclear operations were ended. The licensee is making preparations for defueling and placing the plant in a safe storage condition prior to eventual dismantlemen ! Onsite followup of Licensee Event Reports (LERs) (92700) -l l

The inspectors reviewed selected LERs to determine whether corrective 'j actions, as stated in the LERs, are appropriate to correct the cause of the event and to verify that these corrective acticns have.been implemente LER 85-03 reported a failure of one cell in Station Battery 1A, The l station batteries were replaced under Change Notice (CN) 2672 in 1988.

l The inspectors verified that the battery surveillance procedures were j

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revised to change the battery type reference, float voltage, and l ventilation requirements to make them consistent with the manufacturer's I recommendations and other guidelines. Battery tests were performed in I

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-4-accordance with these revised procedures. Amendment 64 to the TS was issued en September 15, 1988, to change the charging time to reflect that required by the new batteries. These actions were verified by the inspectors and provide a sufficient basis to clue this LE LER 86-19 reported a transient that increased reactor power above the authorized limit of 35 percent, which was in effect at the time. This event was examined in NRC Inspection Report 50-267/86-16. The licensee's short-term corrective actions included administratively limiting power to 30 percent, with instructions to scram the reactor if power exceeded 34 percent. Long-term corrective actions included a review of standard clearance point forms to ensure proper precautions are taken any time a pressure control velve is used as a block valve on a clearance. These actions were completed in December 1986 and no recurrence of this typt of event has been observed. This LER is close LER 87-01 described a routine surveillance test which identified relief valve setpoints which fell out of the range specified in the TS. Further testing by the licensee indicated that the discrepancies were due to the test configuration rather than a physical degradation of the valves. The licensee revised the applicable procedure to add the requirement to bench test these valves rather than allowing in-place testing. The inspectors reviewed these actions and their results and concluded that they are sufficient to close this LE LER 87-20 reported a Loop II shutdown (ESF actuation) with the reactor shut down. The event was caused by personnel error in failing to reset operating helium circulator trips prior to resetting trips on a circulator being placed in operation. This event was reviewed with all reactor operators during requalification training, which was completed on October 14, 1988. No recurrences of this type have been observed by the inspectors. This LER is close No violations or deviations were identified in the review of this program are . Followup on Violations (92702)  !

(Closed) Violation (257/8807-01): Emeroency Diesel Generator Valve Lineup

- Two valves in the emergency diesel generator's air starting system which were required to be shut were found open. The licensee immediately performed a complete diesel generator system valve lineup and no other l mispositioned valves were found. The two mispositioned valves and four other valves were sealed shut and placed on the plant's sealed and critical valve checklist to preclude unintentional changes in the air start system valve lineup. The inspectors reviewed the licensee's actions i and found them acceptable. No subsequent occurrences of this nature have been observed. This item is close (Closed) Violation (267/8807-02): Failure to Have Adequate Procedures -

Three unnumbered valves were found in the cooling water line to the engine

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. 1-5-driven fire water pump that were not identified on the plant valve lineup checklist. The licensee subsequently installed permanent identification tags on the valves and added the three valves to the system lineup checklist. The inspectors verified that these actions had been complete This item is close (Closed) Violation (267/8820-01): Failure to Follow Procedure - While 1 placing a clearance on some electrical equipment, an incorrect fuse was pulled which caused a loss of a helium circulator bearing water pum ,

This occurred due to a misunderstanding of the clearance and electrical '

drawings by the workman involved. This incident was reviewed with the electrical staff and the individuals involve Training provided to plant l electricians now includes sessions on clearance requirement These L actions were reviewed by the inspectors and found to be sufficient to 1 close this violatio (Closed) Violation (257/8829-01): Failure to Follow Procedure - A clearance tag with an incorrect clearance number was found on the wrong .

valve. Maintenance workers htd removed the tag and hung it on an adjacent I valve when a helium bottle was moved for access. The tag was subsequently corrected and properly hung. The craftsmen involved were reprimanded and reinstructed on proper handling of clearance tags and removable equipmen Followup interviews indicated that the craftsmen correctly understood the requirements for clearances. No similar occurrences have been observed oy the inspectors. This item is close No violations or deviations were identified in the review of this program are . Followup of Open Item (92701}

(Closed) Open Item (278/8813-03): No Analysis Which Includes Cable Losses in Determining Minimum Required DC Voltage at the Individual Loads

- The licensee provided a diagram to the inspector showing cable sizes for all DC loads and the ratings of their overload protection devices. The inspector determined that the cables were adequately sized to provide minimum required voltages for all DC loads. This item is close No violations or deviations were identified in the review of this program l

area.

[ 6. Review of the 10 CFR Part 21 Reports (36100)

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The inspector reviewed evaluations performed by the licensee for deviations, conditions, or circumstances identified by users, vendors, or suppliers. The evaluations were performed to determine the applicability of the identified problem to the safe operation of.the facilit The evaluations reviewed by the inspector are listed below:

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88-13 Morrison-Knudsen Generator field breaker trip during testing 88-18 Limitorque Reduced starting torque at ,

elevated ambient temperatures J

89-19 Limitorque Melamine torque switch failures f No violations or deviations were identified in the review of this program are ;

7. Review of Licensee Action on Generic Letter 83-28 (25591)

Generic Letter 83-28 required licensees to perform online functional testing of the reactor trip system. NRR reviewed the licensee's previous testing and plans to revise the testin NRR found the licensee's acceptable and documented this in a safety evaluation report (SER) datedplans 3 June 29, 1989. The licensee has submitted and the NRC has issued TS 4 amendments to LC0 4.4.1 (plant protective system) and SR 5.4.1, implementing the licensee's proposed associated surveillance requirements for improved reactor trip system testing. This matter is close No violations or deviations were identified in the review of this program are . Operational Safety Verification (71707) I Control Room Activities The inspectors made daily tours of the control room during normal  !

working hours and at least once per week during backshift hour Control room staffing was verified to be at the proper level for the plant conditions at all times. Control room operators were observed to be attentive and aware of plant status and annunciator indications. The inspectors observed the operaturs using and adhering to approved procedures in the performance of-their dutie A sampling of these procedures by the inspectors verified current revisions and legible copies. During control room tours, the inspectors verified that the required number of nuclear instrumentation and plant protective system channels were operabl The operability of emergency AC and DC electrical power, meteorological, and fire protection systems was also verified by the inspectors. The reactor operator and shift supervisor logs were reviewed daily along with the TS compliance log, clearance log, operations deviation report (ODR) log, temporary configuration report (TCR) log, and operations order book. Shift turnovers were observed at least once per week by the inspectors. Information flow was consistently good, with the shift supervisors soliciting comments

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-7-or concerns from the reactor operators, equipment operators, auxiliary tenders, and health physics technicians. The licensee's '

station manager, operations manager, and superintendent of operations .

were observed to make routine tours of the control roo _j The reactor operators and senior reactor operators performed well in a variety of situations during this inspection period. During the first two thirds of the period, the reactor ran steady state at 80 percent power. This resulted in July 1989 being the highest net electrical generation month in plant histor This inspection period was the first time that the plant operated with no control rods fully inserted. During Cycle 3, the plant j achieved 294 effective full power days of fuel burnup, but did this !

at 70 percent power, while the plant has been running at 80 percent {

power during Cycle j l

During the final third of the inspection period, the control room staff supported a variety of nonroutine maintenance activities throughout the plant. The control rod drive problem was identified by the reactor operators while performini routine, weekly,10-inch scram time tests of all control rods not fully inserte b. General Plant Areas The inspectors made tours of all eccessible areas of the plant to assess the overall conditions and verify the adequacy of plant equipment, radiological controls, and security. During these tours, particular attention was paid to the licensee's fire protection program, including fire extinguishers, firefighting equipment, fire j barriers, control of flammable materials, and other fire hazard l A walkdown of the control rod drive, reserve shutdown, and feedwater l systems was performed by the inspectors. Valve and breaker positions

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were verified where possible. When affected by a clearance, the i valves or breakers were verified to be positioned in accordance with the clearance requirements. Power supplies for components in these systems were verified, but were also subject to clearances in some cases. During these system walkdowns, the inspectors verified the operability of standby or backup equipment when components or portions of systems were inoperable due to clearance c. Health Physics The inspectors observed health physics technicians performing surveys and checking air samplers and area radiation monitors. Contamination levels and exposure rates were posted at entrances to radiologically controlled areas and in other appropriate areas and were verified to be op to date by the inspectors. Health physics technicians were present to provide assistance and perform radiological surveys when workers were required to enter radiologically controlled area The

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inspectors observed workers following the instructions on radiation work permits concerning protective clothing and dosimetry and using proper procedures for contamination control, including proper removal of protective clothing and whole body frisking upon exiting a radiologically controlled area.

l Security

The inspectors randomly verified that the number of armed security l officers required by the security plan were present. A lead security officer was on duty to direct security activities on each shift.- The inspectors verified that search equipment, including an x-ray machine, explosive detector, and metal detector, were operational or a 100 percent hands-on search was conducte The protected area barrier was surveyed by the inspectors to ensure that it was not compromised by erosion or other objects. The inspectors observed that vital area barriers were well maintained and not compromised. The inspectors also observed that persons granted access to the site were badged and visitors were properly escorte No violations or deviations were identified in the review of this program are . Onsite Followup of Events (93702)

! Stuck Control Rod l The resident inspectors, assisted by region-based inspectors including a health physics specialist, closely monitored licensec  ;

efforts to recover an apparent stuck control ro Following the discovery of the problem with the Region 19 control rod drive (CRD) during surveillance testing described in paragraph 8 of !

this report, the licensee performed troubleshooting in an attempt to determine the nature of the problem. These tests indicated some binding and releasing of the absorber strings, cables, or drive mechanism. Following these tests, the licensee declared the Region 19 CRD inoperable and commenced a plant shutdow With the reactor shut down and the Region 19 CRD at 56 inches ,

withdrawn, the licensee performed additional tests in an atte:,ipt to either fully withdraw or fully insert the control rod pair. On the first attempt, after approximately 5 to 7 inches of outward motion, the rod drive motor power increased from 85 watts (normal) to 225 watts. This outward motion was continued while monitoring the motor power, which remained at 225 watts until a rod height of approximately 74 inches (outward motion of approximately 18 inches)

was reached when motor power began oscillating between 350 watts and greater than the 500 watts meter scale. Outward rod motion was then stopped with the rods at 75 inches. The next attempt was inward

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-9-motion in which the rod drive motor drew approximately 20 watts (normal) until a slack cable alarm was received at 69 inches and inward rod motion was stopped. The CRD was then moved in the outward

' direction approximately 0.4 inches where the slack cable alarm cleared and rod motion was again stopped. Further attempts to pull the rod pair resulted in no rod motion and no current being drawn by the rod drive moto At this point,,the licensee stopped testing the Region 19 CRD and proceeded with plans to remove the CRD from the core. Since the absorber strings could not be retracted, the auxiliary transfer'

cask (ATC) could not be utilized to remove the CRD from the reacto The ATC is a shielded cask with internal grapple designed to move CRDs and sized for CRDs with absorber strings fully retracted. The j licensee proposed to evacuate the area, shield a crane operator '

located on the crane trolley atop the reactor building crane, and lift CRD 19 and attached absorber strings from the core, depositing the assembly in the hot service facility. The licensee considered this to be similar to the exposed rod removed in 1984 (NRC Inspection-Report 50-267/84-25) but entailing higher dose rates and without the shielding provided by the AT The inspectors reviewed the licensee's dose calculations and safety '

analysis of the proposed CRD movement. The licensee projected a contact dose rate of 2000 R/hr at the absorber string shock absorber, the component of the absorber string with the greatest activation potential (cobalt-60)..

The inspectors questioned the licensee's projections. The 2000 R/hr figure was simply a doubling of the highest dose rate observed from a i previous FSV control element radiation survey taken during the 1985

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refurbishment project. At the inspectors' request, the licensee attempted to project a dose rate based on elemental composition of j the absorber string, position of the absorber string in the core, and power history. These calculations resulted in dose rates of ,

prohibitive magnitude and uncertaint j The licensee then removed CRD 15 from the core and placed it in the j hot service facility. CRD 15 is identical to CRD 19 physically, and 1 has seen the same neutron fluence. The licensee measured the dose rate (at 6 inches from the two absorber strings) along the entire I length of the CRD and absorbers. Near the top of the ab'sorber, 2160 r/hr was measured. The absorber strings averaged together at 6 inches distance 1830 R/hr. Measurements were made with high range ion chamber type dose rate measurement equipment. The licensee utilized the highest dose rate measurement (2160 R/hr'at 6 inches)

in their shielding and personnel dose rate calculations. The inspectors found this acceptabl l The licensee, while making preparation for removing CRD 19 without the ATC, attempted to retract the control elenents into the CRD 19-

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-10-I guide tubes, thus allowing for a normal CRD removal utilizing the ATC. The licensee lifted CRD 19 approximately 6 feet (using fuel '

Handling Procedure Work Packet No.154)'so that the motor and cable drive assembly rested on a stand above the reactor head allowing mechanics to inspect the assembly and attempt to retract the control elements manually. No unusual dose rates were identified during this maintenance work. Doses were less than 10 mr/hr in the general area u of the CRD upper end assembl l A dynometer between the bailding crane and the sling attached to CRD 19 indicated that no abnormal lifting force was required to lift the assembly from the reactor cor No binding was observed in setting the assembly back in the core. This indicated that the stuck control element was binding within the drive tube and not within fuel or reflector block Inspection of the cable and cable drum used to raise and lower the absorber strings showed these parts of the CRD to be in excellen condition. A review of surveillance tests of CRD 19 conducted prior to each reactor criticality since 1985 indicated no problem and no negative trend in performanc At this point, the licensee cut the cables attaching the two absorber strings to the CRD and attempted to manually' retract the absorber strings into the CRD guide tubes using a chain-lift and in-house -

crane. One absorber string moved freely up or down. The other absorber string could not be moved. Each absorber string weigh approximately 120 pounds. The licensee applied 850 pounds of force via the reactor building crane to the. stuck absorber string and could not move it. At this time, the absorber string cables were clamped to maintain their relative position to the CRD, and CRD 19 was lowered back into the upper head of the reacto A plan was devised to free-pull CRD 19 from the reactor into a specially made shield canister.using the reactor building cran This configuration and plan received extensive review by the NRC-staff both at NRR and in Region IV. The main components of the plan included a specially fabricated shield canister into which the CRD was to be withdrawn utilizing the reactor building crane auxiliary hook. The shield canister consisted of two concentric steel pipes welded together with the annular space filled with lead shot (equivalent 'to 2 inches of. solid lead). A reactor isolation valve mounted in Region 19 was remotely operated to allow its closure as  ;

soon as the CRD was withdrawn. Video cameras allowed remote viewing i'

and operation. The removed CRD would then be transferred to the hot

. service facility for examination and determination of the failure mechanis j i

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The licensee had their. full health physics staff supporting the .

Control Rod 19 removal effort. The final ALARA (as low as reasonably achievable) program was detailed, conservative, and effective. The

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canister (transporter) to be 86 R/hr on contact and 3.1 mr/hr at the guard house approximately 185 feet awa The security staff worked well to support plant operations during the removal of the control rod drive and absorber elements from Region 19. Security management contacted NRC Region IV and reviewed their plans for security during the control rod move with region based security specialist Exposure rates from the control rod were predicted to make some vitel^

area doors inaccessible and make others difficult to reach. All personnel on site were accounted for and the protected area' perimeter was sealed off prior to the control rod being removed from the cor The licensee performed a dry run on a spare CRD utilizing the procedures, equipment, and personnel to be used for the actual lift.

l The procedure (Fuel Handling Procedure Work Packet No.153) was modified immediately af ter the dry run to reflect refinement o technique identified in the dry run, and the actual movement 'of CRD 19 from the reactor' core to the hot service facility was accomplishe Some loose contamination was spilled during the transfer (1,000 to 16,000 disintegrations per minute) but was quickly cleaned up by the licensee. .The crane operators (two) and the HP technician in the transfer area received less than 5 mr exposure per pocket ion chamber during the transfer. Dose ratesiat the guard house were measured at less than 0.4 mr/h A9 sequent inspection of the stuck absorber train on CRD 19 revealed a string of dents on several absorber cans. The head of the bolt attaching the absorber string to the cable clevis from the CRD had broken off and fallen into the guide tube. -This bolt head jammed between the absorber string and the guide tube immobilizing the absorber strin Nineteen of the 37 CRDs utilize absorber string to clevis bolts of the same material as the broken bolt on CRD 19. These were installed

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as part of the CRD refurbishment in 1985. The licensee attempted to l inspect the bolt on the free moving absorber string.of CRD 19. It l was found that the head of this bolt was also broken off and missing, presumably in the reactor. Additional information concerning this

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operation is discussed in NRC Inspection Report 50-267/89-19.

l b. Steam Generator Rino Headers While the reactor was shut down for the stuck control rod, the licensee's maintenance staff worked items accumulated on a list of maintenance projects not so serious as to require' shutdown, but requiring shutdown conditions to be worked. One of these maintenance projects was an observed water drip below a steam generator modul . _- _________

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-12-The drip was condensed steam and had previously been identified as originating from a valve packing leak. The mechanics assigned to this job after the plant was shut down determined that the leak was coming from a steam generator module main steam ring header and that i there was no valve in the area of the lea j

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FSV has 12 steam generator modules, each with 54 tubes in the main steam section (there is also a reheat steam section in each steam generator module duplicating a fossil fired steam cycle). These 54 tubes collect into 18 nozzles, 3 tubes to a nozzle exiting the steam generater equally spaced around the shell. These 18 nozzles feed 1 into a 3-inch. Inside diameter ring header of 3/4-inch wall thickness j inconel 800. Steam conditions at this point are nominally 2400 psig i and 1000 The maintenance workers removed the insulation from the I leaking ring header and found a through wall crack in the vicinity of l one of the nozzles. Dye penetrant examination subsequently revealed cracks near 37 of the 216 nozzles on the 12 steam generator module ring header Metallurgical examination by the licensee's specialist revealed tertiary creep cracking in these ring headors. . A region-based '

metallurgist dispatched to the site concurred in the licensee's findings. This is documented in NRC Inspection Report 50-257/89-1 The creep cracking rendered all 12 steam generator modules inoperable. Additionally, the indication of elevated temperatures beyond that for which the ring headers were designed appeared to require redesign as well as replacement of these ring header The licensee is planning to repair the ring headers sufficiently to rate them for condensate conditions of 400 psig and 300 Results

The combination of the CRD failure and the inoperability and low probability of satisfactory repair of the steam generator ring headers has caused the licensee to cease further attempts to operate the plan The licensee announced August 29, 1989, that no attempt to restart the plant would be made. The plant had shut down on August 18, and at that point cooldown towards defueling was initiate No violations or deviations were identified in the review of this program are i

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10. Monthly Surveillance Observation (61726) )

The licensee performed RT-500, " Core Stability Testing," on August I and 2, 1989. This test was performed in accordance with Procedure T-359- ,

to ensure the reactor exhibits no abnormal behavior, temperature i

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-13-fluctuations, or redistributions as core differential pressure is increased. Steam generator module temperatures, core region outlet temperatures, and the linear power channels are monitored to ensure no adverse changes occur as core differential pressure is increased. A maximum core differential pressure of 4.7 psig was reached before testing was suspended. This provided a sufficient operating margin for the present cycle of operation. The inspectors reviewed the test procedure and observed portions of the actual test.

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On August 2, an inspector entered the control room to observe control room

' operation at approximately 4 a.m. (MDT). RT-500 testing was still in progres It occurred to the inspector that this testing was being conducted by the same personnel as when the inspector left the site the previous day. Inquiries of the reactor engineering supervisor revealed that the reactor engineering supervisor and two reactor engineers had worked a normal day on Tuesday, August 1, starting work at approximately 7-7:30 a.m. These three had continued working around the clock until .

the inspector observed them working in the control room 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> late A fourth individual, a consultant from General Atomic, the reactor vendor, had worked Tuesday, August 1, in San Diego and traveled that afternoon to FSV and worked throughout the night with the reactor engineer At 5 a.m. the plant manager called the shift supervisor to check the plant status. The shift supervisor informed the plant manager of the reactor engineering group's continued presence, of the inspector's presence, and of the inspector's concern regarding individuals working around the clock on safety-related activities. The plant manager directed the reactor engineering supervisor and one of the engineers to go home and get some rest so that they could return later and relieve the other engineer and the consultan The inspector returned to the control room at 10:30 a.m. August 2 and found the engineer and consultant still working, now approximately 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> straight. The inspector informed the operations manager who interviewed the individuals, terminated testing, and sent the individuals home to res Interviews with licensee management revealed that the reactor engineers had exceeded the TS limit of 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24-hour period. The licensee's TS allow this limit to be exceeded with prior management review and approval. Licensee management did not approve exceeding the TS limit Reactor engineers performing safety-related tests of core parameters while working in excess of TS limits is an apparent violation of TS requirements (267/8916-01).

On August 17, 1989, while performing weekly 10-inch scram tuts in accordance with Procedure SR 4.1.1.B.1-2-w, a slack cable alarm was received on the Region 19 CRD. The scram time and analog and digital position indications were all acceptable. The slack cable alarm cleared l

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-14- 4 at approximately the same rod height as it alarmed, which was approximately 1 inch into the core from the presurveillance test height of l 56 inches withdraw A slack cable alarm on a CRD indicates the drive mechanism is unbalanced, which can be caused by one or both absorber strings either becoming bound or loosened. Troubleshooting following the discovery of the slack cable alarm indicated one absorber string was somehow bindin Further act.Mns are explained in paragraph 9 of this repor It should be noted that the Region 19 CRD was in the last rod group to be withdrawn from the reactor. Thus, it had not undergone weekly 10-inch

! scram tests since it was fully inserted, with the exception of the previous week's test which showed satisfactory performance. The weekly i 10-inch scram test is required on all rods not fully inserted and was implemented following the 1989 control rod drive event via interim T One apparent violation was identifie . Monthly Maintenance Observation (62703)

The inspectors observed activities on Station Service Request (SSR) 89502241' preparing CRD 1201-26 for installation in Core Region 19 to_ replace the apparently defective CRD installed in that regicn. CRD 1201-26 was removed from the core following the reserve shutdown actuation earlier this year. The refurbishment activity consisted of instclling a new graphite rupture disc and filling the CRD reserve shutdown hopper with boronated graphite ball This work was done in accordance with Procedure MPF-1057, Issue 2, "CRD0A:

Reserve Shutdown Material Replacement." This procedure was referenced by the SSR. The inspector noticed that just before Step 5.5.3 of the procedure there was a note that stated: " Fill hopper from bottom by inserting fill tube on fill through to bottom of hopper." Licensee maintenance personnel explained that this was to prevent inadvertent rupture of the graphite rupture disc by the graphite balls falling from the top of the hopper on to the rupture dis The inspector watched as the mechanics filled the hopper. The fill tube plugged with the graphite balls. This material is weighed and the weight of material in each hopper is specified in the licensee's TS. The material being used was contaminated as it was recovered from the reactor core following the reserve shutdown actuation. The mechanics cut up the fill tube to recover the stuck graphite balls. The fill tube was a piece of rubber hose claniped to the fill trough nozzla. The mechanics then completed the fill of the hopper using another trough with no fill tub The inspector inquired about this apparent deviation from procedure. The licensee's maintenance personnel infonned the 1nspector that they always start a hopper fill with the fill tube to protect the graphite rupture

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I disc. Once a layer of graphite balls covers the rupture disc and can absorb the shock of falling balls, a faster fill trough is used without a I l

fill tub The inspector discussed this with the plant manager and concluded that what he observed was normal plant practice. The procedure did not fully reflect normal plant practice. There was no safety significance to this procedural deficiency. The poor quality of licensee maintenance procedures has been documented several times in SALP reports, maintenance inspections, and in the operational safety team inspectio Other maintenance activities observed during this inspection period are j documented in paragraph 9 of this report, "0nsite Followup of Events."

No violations or deviations were identified in the review of this program are . Exit Meeting (30703) {

An exit meeting was conducted on August 30, 1989, and attended by those <

identified in paragraph 1. At this meeting, the inspectors reviewed the scope and findings of the inspection. The licensee did not identify any  ;

proprietary information to the inspector j i

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