IR 05000461/1989034
| ML19354D985 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 01/17/1990 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML19354D984 | List: |
| References | |
| 50-461-89-34, NUDOCS 9001250134 | |
| Download: ML19354D985 (22) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION III
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Report No. 50-461/89034(DRP)
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t Docket No. 50-461 License No. NPF-62 l
i Licensee:
Illinois Power Company l
500 South 27th Street t
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Decatur, IL 62525
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Facility Name: Clinton Power Station Inspection At: Clinton Site, Clinton, Illinois i
Inspection Conducted:
November 1 through December 18, 1989
Inspectors:
P. G. Brochman S. P. Ray l
P. R. Pelke F. L. Brush D. H. Lei
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r Approved By:
M. A.
hief
/7 90
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Reactor Projects Section 3B Date l
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. Inspection Summary l
Inspection from November 1 through December 18. 1989 (Report l
No. 50-461/89034(DRP))
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Areas Inspected:
(1) Routine, unannounced safety inspection by the resident
inspectors and region based inspectors of licensee action on previous inspection findings; operational safety; event follow-up; headquarters-requests; radiation control; maintenance / surveillance; security;
engineering / technical support; licensee event reports; TMI action items; quality assurance effectiveness; management changes; and meetings.
(2) SIMS issue status:
(0 pen) 1.C.1; (Clo' sed) 1.G.I.
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Results:
No violations or deviations were identified,' three unresolved items of potential safety significance were identified. Additionally, one noncited
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violation was identified (failure to perform a surveillance paragraph 5.d)-
in accordance with 10 CFR 2, Appendix C Section V.G.I.
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DETAILS
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1.
Persons Contacted Illinois Power Company (IP)
- W. Kelley, Chairman and CEO
- D. Hall, Senior Vice President
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- J. Perry, Vice President
- J. Cook, Manager - Clinton Power Station
- R. Campbell, Manager - Quality Assurance i
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- D. Holtzcher, Acting Manager - Licensing and Safety E
- R. Wyatt, Manager - Nuclear Training
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Soyland
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J. Greenwood, Manager - Power Supply
a The inspector also contacted and interviewed other licensee and contractor personnel during the course of this inspection.
- Denotes those present during the management meeting on November 14, 1989.
- Denotes those present during the exit interview on December 18, 1989.
2.
Action on Previous Inspection Findings (92702)
a.
(Closed) Violation (461/87031-07):
Failure to Perform Post Maintenance Testing on Containment Ventilation Isolation. Valves.
This item was previously discussed in Inspection Report 461/87031, paragraphs 10.c.(1) and 10.c.(10).
The licensee also reported the
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events which led to the violation as LERs87-032 and 87-039.
The inspectors reviewed records which verified that all' corrective actions for the LERs and violation had been completed. The licensee issued Plant Manager's Standing Orders 46, 47, and 49 which contained instructions for control of work and post maintenance testing so that all required testing is completed prior to declaring a system operable after maintenance. The inspectors reviewed LERs and violations issued since this violation and noted that no similar events have been documented regarding failure to perform l
Based on the inspectors' verification of
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the corrective actions, this item is considered closed.
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b.
(Closed) Violation (461/88009-04):
Failure to Take Prompt
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Corrective Actions When Open Missile Cover Doors on Fuel Oil Fill Lines Were Identified.
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This item was previously discussed in Inspection Report 461/88009, paragraph 6.a.(8).
The inspectors noted that Operating Procedure 3506.01, " Diesel Generator and Support Systems (DG)," was revised to include a step to close and lock the fill line pit cover
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after filling the diesel fuel oil tanks. The inspectors have
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periodically observed the fill covers over the last 18 months since the violation was issued and have not seen the covers left open, at
any time. The inspectors have also reviewed various documents including night orders and memos from the Manager - Clinton Power Station reminding personnel to rapidly correct conditions adverse to cuality.
In addition, the licensee has recently reemphasized to all
personnel that immediate corrective actions for Condition Reports
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must be sufficient to prevent a recurrence of the problem.
Based on the inspectors' verification of corrective actions, this item is considered closed.
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(Closed) Violation (461/88014-01):. Failure to Have Procedures for (
Storage of Nitrogen Gas Bottles.in Containment.
This item was previously discussed in Inspection Report 461/88014, paragraph 2.b.
The violation involved a modification that was
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incorporated to install seismic supports for nitrogen bottles in containment but for which the required procedures to implement the modification's use were not written.
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The inspectors reviewed Operating Procedure CPS No. 3304.01,
"Cuntrol Rod Hydraulic and Control (RD)," which was revised on
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i July 19, 1988, to include detailed instructions for the storage.
of the nitrogen cylinders in the rack in containment. Routine
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L observations by the inspectors cince that time found that the cylinders and associated equipment were properly secured.
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addition, Nuclear Station Engineering Procedure D.55, " Modification
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and Configuration Change Control," was revised to require a written engineering evaluation of any required actions to support operations that are deferred.
The revision also required a walkdown of the modification be performed to identify operational problems.
Based
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on these reviews, this item is considered closed.
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d.
(Closed) Violation (461/88021-02):
Failure to Notify the NRC Within
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Four Hours After Notifying Other Government Agencies of an Event
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Relating to the Health and Safety of the Public or Onsite Personnel.
This item was discussed in Inspection Report 461/88021, paragraph 8.b.(4).
The event involved an acid spill'which was reported to the National Response Center, the Illinois Emergency Services and Disaster Agency, and the Illinois Environmental Protection Agency, but was not reported to the NRC within four hours as required by 10 CFR 50.72(b)(2)(vi).
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The inspectors reviewed Environmental Affairs Department Procedure H.1, " Reporting Hazardous Substance Releases," revision 11,
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and verified that it had been revised to include the requirements of
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In addition, training of appropriate personnel on the i
reporting requirements was accomplished.
The inspectors have noted
that on all subsequent similar events for which the licensee reported to another government agency or planned a news release, they also i
made the required report to the NRC. An example was discussed in
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Inspection Report 461/89026, paragraph 8.b.(3), concerning an oil spill. Based on these actions, this item is considered closed.
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(Closed) Violation (461/88023-02):
Failure to Properly Record and
Evaluate Diesel Generator Starts.
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This item was previously discussed in Inspection Report 461/88023, paragraph 10.
Based on the inspectors' review of the licensee's response to the violation and the reviews of the Unresolved Item in the paragraph below, this item is considered closed, f.
(Closed) Unresolved Item (461/89032-02):
Discrepancies in Nesel i
Generator Start Logs.
This item was previously discussed in Inspection Report 461/89032, paragraph 5.
The inspectors noted disagreements between the operations staff and the system engineer on the classification of
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several diesel generator starts.
For the division I diesel generator, the log listed 2 valid failures in the.last 20 start attempts and 5 valid failures in the last 100 start attempts, However, the system engineer indicated that he disagreed with the
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j l-classification of some of the starts.
In addition, there was no I
easy way to determine the number of valid failures and the number of start attempts without going back after each start to review all previous starts.
The licensee did a review of all past start attempts and classified them to the satisfaction of all parties including the inspectors.
One of the starts that had originally been classified as a valid failure was reclassified as an invalid test be:ause it was
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considered to be a troubleshooting start.
They also issued a revision to the start log index to make it easier to determine the number of failures and number of start attempts.
In addition, a management review and resolution of disagreements in start classifications will be required with logs corrected, if applicable, l
based on the resolution.
The inspectors noted that a recent audit by Quality Assurance had documented some minor discrepancies in the log and the inspectors-also noted additional minor discrepancies which they pointed out to
.the shif t supervisor. Overall, log keeping was improved and all recent starts had been properly classified and counted.
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these reviews, this item is considered closed.
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3.
Plant Operations
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t The unit operated at power levels up to 85% until November 12, 1989,
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when the unit was manually scrammed during a planned shutdown (see
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paragraph 3.b(1)). The unit was taken critical on November 18 and
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synchronized to the grid on November 19.
During power ascension, problems were encountered with "B" reactor recirculation flow control valve and the unit was placed in single loop operation. The unit operated
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in single loop at power levels up to 65% until December 11, 1989, when a
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controlled shutdown was conducted for a planned outage to repair the recirculation flow control valve and conduct other maintenance.
The unit was taken critical at 2:33 a.m. on December 16 and synchronized to the grid at 8:33 p.m. on the same day and operated at power levels up to 100% for the remainder of the period, a.
Operational Safety (71707)
The inspectors observed control room operation, reviewed applicable i
logs and conducted discussions with control room operators during November and December 1989.
During these discussions and observations, the inspectors ascertained that the operators were alert, cognizant of plant conditions, and attentive to changes in those conditions, and that they took prompt action when appropriate.
The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified the proper return to service of affected components.
Tours of the plant were conducted to observe equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenance.
The inspectors verified by observation and direct interviews that the physical security plan is being implemented in accordance with the station security plan.
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The inspectors observed plant housekeeping / cleanliness conditions
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and verified implementation of radiation protection controls.
The inspectors also witnessed portions of the radioactive waste system controls associated with rad-waste shipments and barreling.
The observed facility operations were verified to be in accordance with the requirements established under Technical Specifications,
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10 CFR, and administrative procedures.
(1) On November 22, 1989, while reviewing the Power Distribution Calculations (P-1) computer printouts, the inspectors noted that operator substituted values were being used for total core
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flow. The inspectors determined that the substituted value
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(46.00 million pounds-mass per hour (mlb/h)) had been used for
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the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> despite a power change of from 59% to 65%
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which had occurred during that time.
The inspectors also noted that on the previous day a power change from 61.4% to 52.4% had occurred over a seven hour period with no update in the i
substituted core flow value.
When the inspectors questioned l
the shift technical advisor (STA) about how often he updated the substituted value and how the value was selected and
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controlled, the answers indicated that the controls were not
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formalized.
j The licensee issued Condition Report ~1-89-11-058 to initiate an investigation and corrective actions. Operating Procedure i
CPS No. 3005.01, " Unit Power Changes," required that computer points which were using a substitute value be updated to reflect actual plant parameters every 5-1C% reactor thermal
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power change. Although the power changes discussed above were less than 10%, one was 9% and the substituted value for total
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core flow was correct for the high end of the power change.
Thus, the substituted value became significantly i
non-conservative for calculating power distribution and core
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thermal limits at the lower power, t
On December 7, 1989, the inspectors reviewed the P-1 computer l
runs for other recent power changes and noted that between 8:47 p.m. on November 20 and 2:25 a.m. on November 21, 1989, power was increased from 39.7% to over 55%, a change of over 15.8%, with no update in the substituted total core flow value of 42.1 mlb/h.
This was well beyond the limit stated in CPS 3005.01 for which the value should have been updated.
The inspectors suggested to the Manager - Clinton Power Station that
the resolution of Condition Report 1-89-11-058 should also address that transient.
In discussions with.the Supervisor -
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Nuclear, the inspectors were assured that during the transients l
discussed above, the shift technical advisors were aware of I
requirements to update the substitute core flow value but had
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determined that the flow had not changed enough to warrant an update. Most of that power change was accomplished with control rods rather than flow so core flow had remained relatively constant.
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The inspectors noted that a night order to the STAS was written
on the afternoon of November 22, 1989, detailing the method to be used to determine the correct value to be substituted for i
total core flow and instructing the STA to inform the shift-supervisor whenever the value was changed and to inform the I
shift at each shift change brief of the current value of all
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l substituted values. The inspectors considered that order an
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acceptable interim corrective action but concluded that permanent procedure changes will be needed to insure adequate control of manually substituted values important to computer
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calculations of core thermal limits.
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(2) On November 22, 1989, with. the reactor core isolation cooling I
(RCIC) system out of service for an oil change, the licensee discovered that the division III switchgear heat removal (VX)
t system had a low refrigerant pressure. The VX system was a
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support system for the high pressure core spray (HPCS) system
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switchgear. The licensee declared HPCS inoperable for a period l
of about 30 minutes until the refrigerant was recharged. A
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nonsafety-related ventilation system was operating in the i
switchgear room and temperatures were normal during that time
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period. Neither the RCIC nor HPCS Technical Specifications have an action statement for both systems being inoperable at.
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the same time.
Therefore the licensee was required to shutdown l
the plant in accordance with the " motherhood" Technical f
Specification 3.0.3.
No actual power reduction was implemented i
because of the short time that the plant was in-Technical Specification 3.0.3.
The licensee intended to submit an LER reporting the event.
f (3) On November 28, 1989, during a routine monthly surveillance, the licensee identified that one of the inner containment-to-drywell post LOCA vacuum relief check valves did
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not indicate that it stroked when tested from the main control
room.
In order to determine whether the problem was with the valve itself or only the position indication, the licensee.
proposed holding open the outer of the two series valves while watching the inner valve as it was stroked. After discussions between the licensee and NRC staff, it was concluded that the
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evolution would constitute a deliberate entry into the
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Technical Specification 3.03, " motherhood statement." The staff agreed with the licensee that the action was reasonable
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under the circumstances.
No actual power reduction was planned to be implemented during the short entry into the shutdown action
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statement of. Technical Specification 3.0.3.
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The outer valve was opened and two attempts were made to cycle
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the inner valve.
The inner valve was observed to cycle only partially. The actuator was removed from the inoperable valve and was replaced and tested satisfactorily. The licensee
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intended to submit an LER reporting the entry into Technical Specification 3.0.3 as operation in a condition not allowed by
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Technical Specifications.
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l (4) On December 12, 1989, the licensee determined that the cabling
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which connects the nuclear systems protection system (NSPS)
inverter IC715001B from its class 1-E battery did not meet
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design requirements.
l The original design calculations determined that two conductors l
(2/0 cable) per phase were necessary due to the distance between
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125 VDC motor control center MCC IB and inverter IC715001B.
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This was indicated on a document prepared by the
architect / engineer firm, Sargent & Lundy (S&L), on master i
diagram, sketch ES-10, page RP02. However, this information i
was not correctly incorporated into wiring diagrams
E03-IDC14E-002 and E03-IC71-P001B.
Consequently, while two
conductors per phase were installed in the conduit between the MCC and the inverter, only one conductor per phase was
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connected at each end. This condition had existed since original construction.
This problem was discovered during a review of the design
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documents by S&L, which had been requested by the licensee.
The design review had been requested by the licensee to help
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in resolving a problem with the inverter, wherein fuses on i
the DC power supply were periodically blowing and a cause
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could not be determined.
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As corrective action, the licensee connected the second
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conductor and directed S&L to review the notes section of the
other master diagrams to ensure similar omissions did not exist.
The licensee verified the that wiring diagrams and
design Specifications for the other three NSPS inverters only
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required one conductor. Additionally, the licensee requested
S&L to perform an analysis to determine if the inverter could have performed its design function had it been required to due so.
10 CFR 50, Appendix B, Criterion III requires that measures
shall be established to assure that design basis are correctly translated into specifications, drawings, procedures, and
instructions. The inspectors will. review the licensee's analysis on the ability of the inverter to perform its design l
function in a subsequent report and this will be followed as-
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unresolved item (461/89034-01(DRP))'
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No violations or deviations were identified; however, one unresolved item was identified.
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Onsite Event Follow-up (93702)
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The inspectors performed onsite follow-up activities for events which occurred during November and December 1989.
These follow-ups
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included reviews of operating logs, procedures, Condition Reports, Licensee Event Reports (where available) and interviews with
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licensee personnel.
For each event, the inspectors developed a chronology, reviewed the functioning of safety systems required by
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plant conditions, and reviewed licensee actions to verify l
consistency with procedures, license conditions, and the nature of the event. Additionally, the inspectors verified that the licensee's investigation had identified the root causes of equipment
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malfunctions and/or personnel errors and that the licensee had taken appropriate c3rrective actions prior to restarting the unit. Details j
of the events ad the licensee's corrective actions developed through
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inspector follow g are provided in paragraphs (1) through (4) below-J l
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At 11:50 a.m. on November 12, 1989, with reactor power at 214, the rod pattern controller (RPC) applied insert and withdrawal blocks to all control rods. At the time, operators were inserting control rods to reduce reactor power for a planned
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shutdown.
Operators were inserting control rods in accordance
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with CPS Procedure No. 2202.01, " Control Rod Sequence," when the RPC applied the rod blocks. The RPC controls the control
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rod pattern when reactor power is less than 20% power. This is to prevent excessive control rod worth, to protect the reactor core from a control rod drop accident.
Operators move control rods in accordance with the sequence.
given in Procedure No. 2202.01.
Below the low power setpoint (21%), the sequence of Procedure No. 2202.01 must match the-sequence which is hard wired into the RPC, or else the RPC will apply insert and withdrawal blocks. Above the low power setpoint, the actual control rod sequence can deviate from the sequence which is hard wired into the RPC. The control rod sequence must deviate from the RPC's to achieve the full power target rod pattern. Also, the target pattern changes over the operating cycle to accommodate fuel burnup and xenon.
transients. The point at which the target rod sequence departs from the RPC's sequence is called the " break point."
After the blocks were applied, the operators verified that the actual rod pattern matched the sequence procedure 2202.01.
The operators were at step 42 of the sequence. The nuclear engineers were called in and determined that the break point on
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the sequence was in the wrong location (step 52 instead of (
step 40).
Consequently, since the rod sequence did not match that contained in the RPC before power was reduced below the low power setpoint, insert and withdrawal blocks were applied.
After reviewing this information, operations department t
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management directed that the plant be manually scrammed, rather than attempting to bypass the RPC and then raise power above low power setpoint and then insert rods past step 40. A manual scram was initiated at 2:24 p.m.
The inspectors have reviewed the licensee's actions and agree that they were conservative.
On November 14, 1989, the licensee conducted a critique to review this event.
In addition to the improperly specified
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break point on the rod sequence, the licensee identified that the integrated CPS Procedure 3006.01, " Unit Shutdown", only i
required that reactor operators verify that the control rod pattern matches the sequence document at 35% power.
The procedure did not contain any requirements for the operators to
ensure that the sequence was past the break point before power
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dropped below the low power setpoint. Also, the reactor operators did not appear to have a good understanding of the
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roa sequence break point and what it meant.
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As corrective actions, the licensee briefed all operating crews
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on this event and operation of the RPC. The rod sequence was revised to specify the correct break point. A review of the RPC will be conducted to determine if there are any indications available to alert the operator that the rod sequence is inconsistent with the RPC. The integrated unit shutdown
procedure will be revised to provide more guidance to the operators to ensure that the rod sequence is past the break point before power is reduced below the low power setpoint.
These corrective actions are scheduled to be completed by
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February 26, 1990. The computer program that the nuclear engineers use to verify the control rod sequence will be
corrected to ensure that the break point is correctly
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(2) Engineered Safety _ Feature (ESF) Actuation
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At 10:07 a.m. on November 13, 1989, with the reactor in
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Operational Condition 3 (Hot Shutdown), an ESF actuation of
the reactor core isolation cooling (RCIC) group 6 division I
containment isolation valves occurred (outboard steam supply (1E51-F064) and suppression pool suction (1E51-F031) valves).
The event occurred while two technicians were performing Surveillance Procedure CPS No. 9532.18, "RWCV Differential Temperature Channel Functional (E31-N613A)."
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CPS 9532.18 specified that the technician connect an energized
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millivolt source to terminals 4 and 5 of 1H13-P715E, TB 18, i
following double verification by a second technician.
However, the technician performing the work looked away to double check the procedure, and then inadvertently connected the source to terminals 4 and 5 on the terminal board directly below TB 18.
Other contributing factors in this event were that the terminal board was located over the technician's head; the physical arrangement of the terminal boards in the cabinet was such that all are arranged vertically, close together, with the same color and terminal numbering system; there was only room for
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one technician to access the terminal boards; and the technicians performing the surveillance had performed it many
times.
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Proposed corrective actions included training all IP control
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and instrumentation, IP electrical, and Stone & Webster electrical personnel on the need to obtain a ladder / stool when necessary in order to work at eye level; applying colored tape to enhance terminal board recognition in all panels with the
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same configuration; and various procedure revisions to minimize the possibility of similar inadvertent actuations.
l The licensee reported the event to the NRC via the ENS on i
November 13, 1989, and issued LER 89-036 as a follow-up written
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report.
The inspectors will follow-up the completion of the i
licensee's corrective actions discussed in the LER.
f (3) Apparent Waterhammer in the "B" Residual Heat Removal System At 11:30 p.m. on November 14, 1989, with the reactor in Operational Condition 3 at 100 psig, an apparent water hammer occurred in the piping of the "B" train of the residual heat removal (RHR) system. The licensee had previously operated the
"A" RHR train in the shutdown cooling mode and had switched to
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the reactor water cleanup system (RWCU) system which provided
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sufficient cooling capability to maintain the reactor in Operational Condition 3.
While performing valve operability testing, operators opened valve IE12-F006B ("B" train RHR shutdown cooling suction valve) which allowed 300 degree F.,
100 psig coolant, contained in common piping between the RHR
"A" and "B" suction valves and the outboard shutdown cooling isolation valve to be connected to the "B" RHR system piping
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which was at ambient conditions. Additionally, portions of
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the "B" RHR system downstream of the. pump had been partially drained as a result of the previously ongoing valve operability
testing. A loud banging indicative of water hammer could be
heard in the containment and auxiliary buildings.
The licensee declared the "B" RHR system inoperable and performed walkdowns, valve operability testing, instrument checks, and "B" RHR pump tetting before declaring the system' operable at
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approximately 10:30 p.m. on November 15, 1989. The only equipment degradation identified which may have been caused by the water hammer was that the "B" suppression pool isolation I
valve would not stroke open due to possible pressure / thermal l
binding.
Subsequently, the valve was satisfactorily stroke i
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tested.
The inspectors attended the licensee's planning meetings to re-establish RHR "B" operability and the event
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critique. The inspector and Sargent & l. undy piping engineers performed a separate partial walkdown of the system on
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November 17, 1989.
No system damage was observed.
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(4) Engineered Safety Feature Actuation
[ENSNo.17223)
On November 29, 1989, an inadvertent isolation of instrument
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air to containment occurred due to a personnel error during a routine monthly channel functional surveillance on analog trip modules (ATM).
The reactor operator entered channel B21-N691E vice B21-N694E on the numerical key pad on the display and control (DAC) terminal.
Channel 694E was a one out of two twice logic channel for high drywell pressure containment isolation.
Channel 691E was a one out of two logic channel for
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reactor water level I containment isolation. The surveillance procedure required that shorting links be removed before calling up that channel on the DAC.
Entering the incorrect channel caused an automatic isolation of instrument air valves IA005 and IA008 to containment. The reactor operator knew immediately that he had entered the incorrect channel when he noticed that the " Cal" light came on
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on the wrong ATM.
He then selected the correct ATM.
However, the operator did not realize that he had caused an isolation
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until several minutes later when a low scram air header pressure alarm was received.
The operators then reset the
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isolation and opened the instrument air valves.
The critique of the event pointed out the need for improvements
in procedures, ATM labeling, attention to detail, and control
room indications of isolation signals.
The licensee reported the event to the NRC via the ENS on November 29, 1989 and intended to submit the follow-up written report as LER 89-35.
The inspectors will follow-up the licensee's corrective actions
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when the LER = is issued.
No violations or deviations were identified.
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Engineered Safety System Walkdown (71710)
The inspectors performed a walkdown of the "B" residual heat removal system (RHR) to verify its status.
The inspectors utilized the-system's valve, instrument, and electrical lineup checklists. The inspecters verified that valves, circuit breakers, and switches were in their correct position; hangers and supports were made up i
properly; housekeeping and cleanliness levels were appropriate; l
valves were operable and did not have excessive packing leakage; combustible and flammable materials were controlled; components were l
labeled and lubricated; instrumentation was installed, functioning,
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and calibration dates were current; locked valves were appropriately
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secured; and local and remote position indicators agreed.
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t During the walkdown, the following discrepancies were noted:
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A small oil leak was observed on the base of the RHR pump motor
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Loose insulation and other debris was observed in the 737'
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elevation of the "B" RHR hrat exchanger roon
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The inspectors discussed their observations with the shift supervisor
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and corrective actions were initiated.
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The inspectors inquired if a maintenance request (MR) had been initiated to_ repair the oil leak on the "B" RHR pump motor. The inspectors were informed that there were no MRs outstanding on the
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"B" RHR pump. The inspectors expressed a concern to operations
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department management over the failure of the unit attendants I
(auxiliary operators) to identify the oil leak, even though they tour the "B" RHR room three times a day.
From the quantity of oil on the
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i floor, the inspectors believed that the oil leak had existed for some
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time.
However, the oil level for the motor lower bearing was still
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in the operating range.
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No violations or deviations were noted.
d.
Follow-up on Headquarters / Regional Requests (60710) (71707)
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(1) The inspectors reviewed the licensee's evaluation of NRC Information Notice 89-51, " Potential Loss of Required Shutdown Margin During Refueling Operations," in response to a concern of the NRC Staff. The concern was in regard to the adequacy of analysis of intermediate fuel configurations during refueling.
The inspectors determined that the licensee had received the Information Notice and had conducted an appropriate review of
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the concerns. Nuclear Station Engineering Department (NSED)
memo Y-91904 dated July 21, 1989, stated the following:
"NSED has been aware of this possibility since early 1987
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[as indicated by referenced correspondence between the-
licensee and General Electric]. Nuclear Fuel Design and
i Analysis (NFD&A) took action to make the fuel vendor
perform analysis to assist the shutdown margin and to provide fuel movement requirements and restr.ictions to ensure that all intermediate fuel bundle configurations met Technical. Specifications during RF-1 [first refueling outage).
Similar action is being taken to provide this
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assurance during RF-2 (Purchase Requisition 9192527P).
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A requirement that shutdown margin during refueling be assessed in reload licensing analyses performed by fuel vendors has been incorporated into the draft Revision 2 of NSED Procedure F.0, " Nuclear Fuel Management", which is
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being tracked by NSED Engineering Programs, will ensure i
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future refuelings."
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The inspectors provided the above information to regional management.
(2) The inspectors reviewed the licensee's actions in response to various NRC and industry inforrration about problems with main steam isolation valves (MSIVs) not closing on. plants tiith ASCO model NP8323A20E dual acting solenoid valves.
The request was
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in response to a concern by the staff about a recent event at
River Bend Station.
l The inspectors determined that the licensee had reviewed NRC Information Notice No. 88-43: " Solenoid Valve Problems," as well.as General Electric's RICSIL No. 015, "ASCO Dual Solenoid Valve Sticking," and SIL No. 481, " Malfunction of ASCO Solenoid
Valves for MSIVs." The licensee determined that they have the model solenoid valves on t'neir MSIVs. discussed in the Information Notice.
They do not conduct =the special test
discussed in the Information Notice but test the solenoids every 18 months as required by Technical Specifications.
The latest information'from General Electric indicated that the cause of the failures at other plants was believed to be that the valves were exposed to temperatures higher than they were qualified for.
Clinton has experienced relatively low
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temperatures in the drywell and steam tunnel in the area of the MSIVs and has had no problems with MSIV closing. They have instituted procedure changes so that engineering will be notified to perform further analysis or testing if any.
temperature element in the vicinity of the MSIVs indicated
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greater than 140 degrees F.
In addition, the licensee has instituted preventative maintenance (PM) task PEMMSA067 to replace all elastomers on the solenoids every 1.7 years for inboard valves and every 2.5 years for the outboard valves.
This PM included replacement of the plug nut gaskets and the
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solenoid plungers. A step was added to the PM to ensure Dow Corning 550 Lubricant was put only on.the elastomers.
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The information above was provided to'the regional office, No violations or deviations were identified.
4.
RadiationControls(71707)
On December 5, 1989, an unplanned personnel exposure occurred when two workers entered a WE system filter pit to set up scaffolding for a job.
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Neither the Radiation Work Permit (RWP) for the job nor local posting at
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the site indicated that the sump was a high radiation area. A survey had not been conducted after the floor plug over the pit had been removed.
The inspectors attended a critique of the event _and discussed it with the Manager - Clinton Power Station and the Director - Radiation Protection.
The event included several mistakes in the control of work in radiation controlled areas resulting in a breakdown of the program. Additional follow-up of the event was conducted by a regional specialist and is
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documented in Inspection Report 461/89038(DRSS).
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5.
Maintenance / Surveillance (61726 & 62703)
Station maintenance and surveillance activities of the safety-related systems and components listed below were observed or reviewed to ascertain that they were conducted in accordance with approved
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procedures, regulatory guides, and industry codes or standards, and in conformance with Technical Specifications.
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The following items were considered during this review: the limiting conditions for operation were met while affected components or systems were removed from and restored to service; approvals were obtained prior
to initiating work or testing; quality control records were maintained; parts and materials used were properly certified; radiological and fire
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prevention controls were accomplished in accordance with approved
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procedures; maintenance and testing were accomplished by qualified personnel; test instrumentation was within its calibration interval;
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functional testing and/or calibrations were performed prior to returning components or systems to service; test results conformed with Technical Specifications and procedural requirements and were reviewed by personnel other than the individual directing the test; any deficiencies identified during the testing were properly documented, reviewed, and resolved by appropriate management personnel; work requests were reviewed to determine the status of outstanding joos and to assure that priority was assigned to safety-related equipment maintenance which may affect system performance. The following maintenance and surveillance activities were observed:
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Activity Title CPS 9080.01 Diesel Generator Operability (Division 1)
MWR D10644 Determinate Division II Diesel Generator Pressure
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Switch.
I MWR D14285 Startup Level Controller Repair MWR D19150 Drywell Vacuum Breaker Valve IHG011D Repair PMMDGQO37 Inspect Starting Air Compressor Valves
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Activity Title j
PEMDGM015 Division III Diesel Generator Annunciator Test i
PCIDGM527 Calibrate Division II Diesel Generator High Lube Oil Temperature Switch a.
Regarding surveillance 9080.01, on November 20, 1989, the division I i
emergency diesel generator failed to come up to rated speed within
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the required 12 seconds. This was considered to be a valid failure i
and brought the total number of valid failures for that engine to 2 in the last 20 valid tests and 5 in the last 100. The licensee initiated the accelerated test frequency as required by Technical
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Specification 4.8.1.1.2 and intended to report the failure in accordance with Technical Specification 4.8.1.1.3.
The cause of the failure was believed to be an improperly set governor and subsequent tests after resetting the governor were
successful.
However, on December 12, 1989, the division I diesel
again failed to meet its start time criteria.
This failure brought
the total number of failures on a nuclear unit basis to 7 in the
last 100 which required that the licensee report additional
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information in accordance with Technical Specification 4.8.1.1.3.
The licensee was still evaluating the rout cause of the slow starts e
on the diesel.
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b.
Regarding MWR D14285, the technicians found that an Agastat relay in the startup level control circuit was not working properly because of high resistance across the relay contacts.
The technicians buffed the contacts and the relay then worked properly. The licensee has previously experienced similar problems with Agastat relays of that model.
Inspection Reports 461/88014, 461/88021, and 461/88026 and LER.88-17 documented the licensee's evaluation of the
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problem and corrective actions. They intended to replace the
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affected relays with an improved model less susceptible to oxidation l
of the contacts,-but the new relays had not been obtained yet, c.
On December 12, 1989, while maintenance and operating personnel were discussing an upcoming surveillance in accordance with CPS No.
9434.02, "ATWS Reactor Pressure High Level B21-N401A(B,E,F) Channel Calibration," it was noted that step 8.1.14 of the procedure required that the test switch be placed in bypass which would have
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i caused an entire anticipated transient without scram recirculation pump trip (ATWS-RPT) trip system to become inoperable. There are two redundant ATWS trip systems in the plant each consisting of two reactor level and two reactor pressure instrument channels.
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Technical Specification 3.3.4.1. contained an action statement for
-one instrument channel being inoperable but no action for an entire r
trip system. Thus performance of the surveillance as written would have constituted a deliberate entry into the Technical Specification statement 3.0.3.
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A review determined that the procedure had already been performed twice before on December 6 and 7, In addition the procedure may have been performed on earlier occasions. There was some question on the part of the licensee concerning the intent of the Technical
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Specification. The Specification was only applicable in Operational Condition 1 and the surveillance was only required once per 18 months so the licensee suspended performance of the calibrations except when not in Operational Condition 1 while evaluating the situation. They intended to submit an LER documenting their evaluation of the event.
d.
On December 12, 1989, the licensee identified that a surveillance on high pressure core spray (HPCS) system valves that had been performed on November 3 was incomplete in that stroking of three required valves was not accomplished.
Surveillance Procedure CPS No. 9051.02, "High Pressure Core Spray Valve Operability Test,"
contained a note which allowed the operators not to perform section 8.1.1 of the procedure under certain circumstances.
When the surveillance was performed, the note was misinterpreted and the
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entire section 8.1 containing sections 8.1.1 through 8.1.6 was
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marked as not applicable. This resulted in three valves; IE22-F001 (HPCS suction from the storage tank), IE22-F015 (HPCS suction from the suppression pool), and IE22-F016 (suppression pool suction check valve) not being tested as required by Technical Specifications 4.0.5 and 4.6.4.3.
The test was a quarterly surveillance and went
beyond the allowed extension on December 3, 1989. Therefore the
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HPCS system and containment isolation function were inoperable until the surveillance was performed on December 12.
The surveillance performed on December 12 demonstrated that the valves had been in fact operable during the time that the previous surveillance interval had elapsed so the event was not considered
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safety significant.
The event will be reported by the licensee as an LCR.
Immediate corrective actions consisted of performing the missed steps of the surveillance, holding a critique of the event, and issuing an operating night order describing the event and the findings of the critique.
Longer term corrective actions included procedural revisions to eliminate the misleading note in the procedure and briefing of the operating crews on the importance of thorough reviews of completed surveillance packages.
These actions were being implemented by the licensee in a timely manner.-
Failure to perform the valve operability surveillance tests for the HpCS valves discussed above is a violation of Technical
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Specifications 4.0.5 and 4.6.4.3 (461/89034-02(DRP)).
However, this issue meets the tests of 10 CFR 2, Appendix C, Section V.G.1;
consequently, no Notice of Violation will be issued, and this matter
is considered closed.
Long term corrective actions will be reviewed when the LER is closed.
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e.
The licensee conducted two short maintenance outages during this period.
The first lasted from November 12 through November 19, 1989, and was primarily for the purpose of eliminating steam leaks.
The second lasted from December 11 through December 16, 1989, and
was primarily for the purpose of repairing the "B" reactor
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recirculation flow control valve and recovering the recirculation
loop.
The inspectors' observations of both outages indicated that they were well planned and executed... Scheduling and scope were rigidly controlled and communications among all participants were
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highly evident. Both outages met all required objectives and the licensee was also able to complete a significant amount of emergent and conditional work in each, One violation was identified; however, a Notice of Violation was not issued..
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Security (255104)
Temporary Instruction (TI) 2515/104 - Inspection of licensee's
Fitness-For-Duty (FFD) Initial Training Program.
The inspectors attended the licensee's FFD training for employees, i
escorts, and supervisors and evaluated the training against the guidance provided in TI 2515/104.
The inspectors will forward an evaluation of the course to region III and NRR'as required by the TI.
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No violations or deviations were identified.
7.
Engineering / Technical Support (93702) (71707)
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a.
During the maintenance outage in November, several environmental qualification (EQ) issues were identified. These included the
following:
Condition Reports 1-89-11-027 and 1-89-11-33 identified that some ASCO solenoid valvrs were not installed in the orientation identified in the EQ package and that some also did not' have exhaust
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ports protected by 90 degree elbows.
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Condition Report 1-89-11-036 identified that several Rosemount t
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transmitters were found with loose electronic housing covers and broken neck seals.
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Condition Report 1-89-11-047 identified that several Gould transmitters were found with damaged junction box o-rings and capillary armor pulled back.
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For all of the deficiencies, the licensee required that an engineering evaluation be performed and necessary repairs be
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completed before startup from the maintenance outage.
The
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inspectors reviewed the engineering evaluations of the above
condition reports for significant safety concerns and did not note
any concerns that would prevent startup.
The condition reports and l
engineering evaluations were forwarded to regional specialists for
further review.
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b.
On November 6, 1989, the inspectors informed the Manager - Nuclear Station Engineering Department (NSED) of a condition found at
another plant where the temperature setpoint nf fire protection system fusible links for sprinkler systems were lower than the i
setpoint for the leak detection system isolation for rooms containing systems connected to the reactor coolant system.
It was
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postulated that in the case of a steam break in one of the rooms, the fire suppression system could actuate and condense the steam from the leak such that the temperature setpoint of the leak detection system would never be reached and the system f QMi n.',
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assumed in the analysis for a loss of coolant accident might
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not occur.
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On November 9,1989, the Director - Design & Analysis Engineering informed the inspectors that they had evaluated Clinton's systems-
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and determined that there were no fusible links in fire protection systems in the same areas protected by the leak detection system except for the main steam crossover piping area.
In that area the
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setpoint of the fusible links was 212 degrees F. and the setpoint of the leak detection system was 142 degrees F.
Thus, actuation of the fire sprinkler system should not mask a steam leak, i
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NSED's response to the inspectors' information was considered very i
proactive and timely, c.
On November 16, 1989, the inspectors received a request for information from NRC headquarters on the system engineer program
utilized by the licensee.
The inspectors forwarded the information provided by the licensee to Region-III on November 21, 1989.
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No violations or deviations were identified.
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8.
Safety Assessment / Quality Verification Licensee Event Report-(LER) Follow-up (90712 & 92700)
a.
Through direct observation, discussions with licensee personnel, and t
review of records, the following LERs were reviewed to determine that the reportability requirements were fulfilled, immediate
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corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical
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Specifications.
Based on the inspectors' review, the following LERs are closed:
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LER No.
Title
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461/88009-LL Improper Use of an Impact Matrix Results in i
Instrument. Air Isolation.During-Load Driver Circuit Card Testing Due to Lifting. Wrong' Lead Wire to Preclude-Isolation.
i 461/88028-LL-. Main ' Power Transformer. Fault Results in Turbine Generator Trip and a Reactor Scram.
461/88032-LL Inoperable Containment Isolation Valves Due to-Incorrect Documentation of Equipment j
Qualification.
461/89018-LL Recessed Connector Center Pin Causes Intermittent'. Pin Contact of a Signal Lead During Troubleshooting Resulting in a High Flux Signal, and a Reactor.-Scram Signal.
Regarding LER 88-032 (461/88032-LL) above, the NRC issued a Notice'
f of Violation (461/89006-01) which included the issues reported by
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the LER.
The. LER is administrative 1y closed and corrective actions will be reviewed with those of the violation.
No violations or deviations were identified.
I b.
TMI Action Plan Requirement' Follow-up (25565)
(1) (0 pen) Item I.C.1 (461/85015-07):
Short Term Accident Analysis and Procedure Revision.
This item was last discussed in: Inspection Report 461/87002, paragraph 2.e.
The item remained open pending deve.lopment of Emergency Operating Procedures (EOPs) for post accident; hydrogen control in the containment. This issue is also being
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As stated.
in their response to Generic Letter 89-21, " Request for
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Information Concerning Status of Implementation of Unresolved Safety Issue (USI) Requirements"' (letter -U-601563 dated
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l November 27,1989), the-licensee has installed hydrogen control
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equipment and has hydrogen mitigation procedures in place.
L EOPs are being developed, however, final' review of the E0Ps can i
not be accomplished until the NRC issues their General Hydrogen
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Control Program Safety Evaluation Report (SER). The licensee'
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(2) (Closed) Item I.G.1 (461/87015-04):
Training During Low Power L
Testing.
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This item was previously discussed in Inspection Report i
461/87015, paragraph 5.
The item remained open pending the
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The inspectors reviewed training records which' verified that appropriate personnel had received training as required by the
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TMI item. The. personnel included all licensed operators and
l candidates, shift technical advisors, operator instructors, and
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other selected individuals.
This item is considered closed.
No violations or deviations were identified.
c.
Evaluation of Licensee's OA Prooram Implementation (35502)
The inspectors reviewed Quality Assurance (QA) Request for Corrective Action No. Q38-89-26-01 which discussed a finding that i
fire suppression sprinkler system drain flow tests were not being l
conducted as required by the licensee's commitment to NFPA 13 as L
stated in Technical Procedure CPS No. 3213.01, " Fire Detection-and l
Protection." The licensee's QA finding.further stated that the CPS Code Conformance Report addressing NFPA 13 noted that drain valves are in place and that IP is to install drain piping.
Apparently the.
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drain piping has never been installed.
A' recommendation to perform drain flow testing was made during QA Audit Q38-87-59 in 1987 and the recommendation was revisited in QA Audit Q38-88-46 in 1988.
No action had been taken.
Corrective actions taken by the licensee on
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this issue appeared to be inadequate to resolve it.-
The adequacy _of l
the corrective actions taken by the licensee in response to the QA-l audit will be followed as an unresolved item (461/89034-03(DRP)).
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A copy of Q38-89-26-01 was forwarded to a regional. specialist for review-of the fire protection aspects of-the issue; Completion of this review will be.followed as a separate unresolved item i
(461/89034-04(DRS)).
No violations or deviations were identified; however, two unresolved
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items were identified.
9.
Management Changes Effective on December 1, 1989, Mr. Donald P. Hall _,. Senior Vice President, left Illinois Power Company.
Mr. J. Stephen-Perry, Assistant Vice President, assumed the responsibility for,the licensee's nuclear operations.
Mr.. Perry will continue to report directly to the _ Chairman and CEO of Illinois Power. On December 5, 1989, the Illinois Power Company Board of Directors elected Mr. Perry as a Vice President of the
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u Unresolved items are matters about which more information is required _
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or deviations.
Unresolved items disclosed during the inspection are
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discussed in paragraphs 3.a(4) and 8.c (two items).
L 11.
Items For Which A " Notice Of Violation" Will Not Be Issued l
The NRC uses the Notice of Violation as a standard method fcr formalizing the existence of a violation of a legally binding requirement. However,
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because the NRC wants to encourage and support licensee initiative in the
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self-identification and correction of problems, the NRC will not
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generally issue a Notice of Violation for an issue that meets the tests of 10 CFR 2, Appendix C, Section V.G.I.
These tests are:
(1) the issue
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l was identified by the licensee; (2) the issue would be categorized as Severity Level IV or V violation; (3) the issue was reported to the_ NRC, if required; (4) the issue will be corrected, including measures _to
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prevent recurrence, within a reasonable time period; and (5) it was not a issue that could reasonably. be expected to have been prevented by the licensee's corrective action for a previous violation._ An. issue-involving the failure to meet regulatory requirements, identified during the inspection, for which a Notice of Violation will not be issued is discussed in paragraph 5.d.
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12. Meetings a.
Management Meetings'(30702)
On November 14, 1989, Mr. A. Bert Davis,. Regional Administrator, and members of his staff met in Region III with Mr..W. Kell _ey, Chairman
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l and CEO, Illinois power, and members of his staff denoted in pdragraph 1 of this report. This meeting was held to discuss NRC l
concerns related to the licensee's performance in maintenance and corrective actions; and to inform the NRC of the status'of environmental qualification testing, accreditation programs, and-outage schedules, b.
Exit Interview (30703)
The inspectors met with the licensee representatives denoted in paragraph 1 at the conclusion of the inspection on December 18,
1989. The inspectors summarized the purpose and scope of the inspection and the findings.
The inspectors also discussed the
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likely informational content of the inspection report, with regard'
to documents or processes reviewed by the inspectors during the
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inspection. The licensee did not identify any such documents or l
processes as proprietary,
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