IR 05000498/1990018
| ML20043G701 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 06/12/1990 |
| From: | Joel Wiebe NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20043G700 | List: |
| References | |
| 50-498-90-18, 50-499-90-18, NUDOCS 9006210023 | |
| Download: ML20043G701 (19) | |
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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION ROION IV NRC Inspection Report:
50-498/90-18 Operating Licenses:
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Dockets:
50-498
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50-499 Licensee: Houston Lighting & Power Company (HL&P)
P.O. Box 1700 Houston, Texas 77251
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Facility Name:
South Texas Project (STP), Units 1 and 2 Inspection At:
STP, Matagorda County, Texas Inspection Conducted: May 1-31, 1990 Inspectors:
J. I. Tapia, Senior Resident Inspector, Project Section D Division of Reactor Projects R. J. Evans, Resident Inspector, Project Section D Division of Reactor Projects
. Approved:
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. Wiebe, Chief, Project Section D D&td vision of Reactor Projects Inspection Summary
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l Inspection Conducted May 1-31, 1990 (Report 50-498/90-18: 50-499/90-18)
Areas Inspected:
Routine, unannounced inspection which included plant status, onsite followup of events at operating power reactors, licensee action on previous inspection findings, onsite followup of written reports of nonroutine
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events at power reactor facilities, operational safety verification, engineered safety feature system walkdown (Unit 1), monthly maintenance ubservations, monthly-surveillance observations, and refueling activities (Unit 1).
Results: Within the areas inspected, one noncited violation (paragraph 7) and no deviations were identified. Good technical followup in response to events
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was noted. This included excellent engineering investigation and a high level of management involvement (paragraph 3). One violation (paragraph 4) and four Unit I licensee event reports (paragraph 5) are being closed out in this 9006210023 900610
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inspection report. Housekeeping was good in most areas of the plant; however.
. poor housekeeping was noted in the emergency operations facility diesel generator building (paragraph 6). The fuel oil storage and transfer system was determined to be operable, but numerous minor procedure discrepancies were noted (paragraph 6). A walkdown of. the component cooling water (CCW) system for
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Unit I revealed that one safety-related valve was missing its seal lock (a noncitedviolationofTechnicalSpecifications(TS)6.8.1)(paragraph 7).
Four maintenance activities (paragraph 8) and four surveillance activities
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(paragraph 9) were observed with no significant concerns identified. A review h.
of the outage scope for the Unit 1 second refueling outage showed that no
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significant-scheduled activities have been deferred (paragraph 10).
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persons Contacted
- M. A. McBurnett, Nuclear Licensing Manager
- A. C. McIntyre, Manager, Support Engineering
- W. J. Jump Maintenance Manager
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- J. R. Lovell, Technical Services Manager
- M. R. Wisenburg, Assessment / Nuclear Safety Review Board
- S. L. Rosen, Vice President, Nuclear Engineering
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- G. E. Vaughn, Vice President, Nuclear Generation
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- W. H. Kinsey, Plant Manager
- T. J. Jordan, General Manager, Nuclear Assurance
- A. W. Harrison, Supervising Licensing Engineer
- S. M. Shropshire, Central-Power and Light
- D. J. Denver, Manager, Plant Engineering
- J. W. Loesch, Manager, Plant Operations
- A. K. Khosia, Senior Engineer, Licensing
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In addition to the above, the inspectors also held discussions with various licensee, architect engineer (AE), maintenance, and other contractor personnel during this inspection.
- Denotes those individuals attending the exit interview conducted on June 1, 1990.
2.
Plant Status l
Unit 1 began this inspection period in Mode 6, refueling. At the close of this inspection period, the licensee was in Mode 5, cold shutdown, i
Unit 1 began this inspection period at 100 percent reactor thermal power.
On Ma/ 8, 1990, a Notification of Unusual Event (NOVE) was declared when the 'icensee discovered primary system leakage (see next paragraph).
After repairs were complete, Mode 1 (greater than 5 percent power) was again attained on May 21, 1990, and 100_ percent reactor thermal. power was l
reacred on May 23, 1990.
Unit 2 remained at that power level at the close of this inspection period.
3.
Onsite Followup of Events at Operating Power Reactors (93702)
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On May 8, 1990, the licensee declared a NOVE due to a Unit 2 TS-required i
shutdown. TS 3.4,6.2.a requires that no pressure boundary leakage from l
the reactor coolant system be allowed.
The licensee determined that a weld between a 3/4-inch steam generator bottom head drain line and a valve had begun leaking.
The 3/4-inch line has a 3/8-inch flow restricting orifice attached to a 3/4-inch tap on the steam generator primary side.
The valve is a KER0-test packless diaphragm valve.
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On April 22, 1990, the Unit R control room received a containment atmosphere radioactivity ala m.
A containment inspection was performed
but did not reveal the cause of the alarm.
On April 25, 1990, another containment inspection was porformed and water was found on the floor beneath the C steam generator.
Initial estimates indicated a leak of approximately 10 drops per msnute. This minute leakage was not detectable using normal RCS leakage detection techniques.
Tha licensee obtained a robot to attempt to identify the leakage source since the source of the leak was inside the biological shield in an area indicating about 20 R per hour. On Saturday, May 5, 1990, the robot located the source of the leakage as the steam generator drain line but was unable to verify the
exact leak location. On May 7, 1990, the licensee lowered a camera down the side of the steam generator and noted that the source of the leak appeared to be the weld on the upstream side of the drain line isolation valve.
In order to verify the source of the leak with certainty, the licensee lowered reactor power to 14 percent and sent an individual in to take photographs. The individual verified that an unisolable reactor coolant system leak existed and the licensee commenced a reactor shutdown.
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The licensee developed a repair procedure which required establishing a freeze seal between the drain valve and the steam generator, cutting the line above the affected weld, threading and capping the remaining stub, and seal welding the cap. After this repair was completed on the'
affected steam generator, the removed assembly was sent to Southwest Research Institute for root cause inalysis.
The results of that analysis
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indicated that the weld failure was due to high cycle fatigue.
The licensee enlisted Bechtel - San Francisco to determine the cause of the f a_ti gue. Bechtel found that a reactor coolant system flow induced vertical vibration coupled with the eccentric mass of the valve body
caused the weld to fail from hign cycle fatigue.
Based on this
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information, the licensee elected to remove the drain valves from the remaining three steam generators in Unit 2 and from all four steam generators in Unit 1, The seal-welded pipe caps are considered a short-term fix and the licensee plans to generate a permanent fix at a later date.
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On May 12, 1990, with Unit 2 in Mode 5 for repair of the steam generator drain lines, an intermittent " Train C SI Blocked" status window was observed in the Unit 2 control room during surveillance testing.
Troubleshooting performed under Work Request (WR) SP107843, revealed that there was an extra wire connected to the Train C SI block logic card.
This wire connected the output of the Steam Generator B high level reactor trip logic card (A309 Pin 3) to an input terminal of the Train C SI block logic card (A314 Pin 8).
This connection generated a Train C SI block signal when the reactor trip breakers were open (P-4) and Steam Gererator B water level reached the high level trip setpoint.
The output
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of the Steam Generator B high level reactor trip logic card was also connected to the correct point (A214 Pin 8) and, therefore, the high level reactor trip function was fully functional.
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The licensee obtained the services of Westinghouse to review the safety
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significance of the extra wire. The review concluded that this condition did not represent a safety concern because of the following:
the only accident postulated which may affect both safety injection and steam generator high level trip is a steam generator tube rupture.
The analysis of the steam generator tube rupture accident indicates that SI would be
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initiated by low reactor coolant system pressure 15-20 minutes before water level in the affected steam generator would reach the high level trip setpoint. Thus, if Steam Generator B had experienced a tube rupture, the blocking of Train C SI would occur 15-20 minutes after SI would occur and would not affect the course of the event.
Pin 8 of the Train C SI block logic card (A314) was unused according to the Westinghouse schematic diagrams and wire list. The extra wire has been removed. The wire color and termi-clips match the factory wiring in (
the bulk of the cabinet. Additionally, there are no records of any design change or repairs implemented which could have installed the extra wire.
It was concluded, therefore, that the wire was installed at the Westinghouse factory.
f The extra wire was on top of the correct wire on A309 Pin 3.
It is
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postulated that the correct wire was installed during initial cabinet wiring and then the wire list was misread during the continuity check.
If
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continuity were checked from A314 Pin 8, instead of A214 Pin 8, to A309 Pin 3, an open circuit would exist and a wire would likely have been added without any further documentation.
The continuity test from A309 Pin-3 to A214 Pin 8 would have been satisfactory since the correct wire was in place.
This wiring error was not detectable through the normal testing process and was only discovered while troubleshooting an unexplained indication.
The solid state protection system (SSPS) Train S cabinet in Unit 2 and both Trains R and S cabinets in Unit I were inspected and the wiring was found to be correct.
The licensee's action in response to these events showed a thorough approach in addressing the various technical aspects of each issue. There were indications of good interdepartmental communications, technically qualified staff, and responsiveness to NRC comments.
Plant management was very sensitive to safety significance placed on the issues and on the quality of their resolution.
4.
Licensee Action on Previous Inspection Findings (92701)
(Closed) Violation (498/8947-01; 459/8947-01):
Failure to Establish a Calibration Procedure for Heat Trace Control Circuits In a previous inspection, the NRC resident inspectors determined that written procedures were not established to accomplish TS Surveillance Requirements 4.1.2.1.a and 4.1.2.2.a.
The TS surveillance requirements involved verifying that boric acid flow paths were above a minimum i
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i temperature, however, procedures did not exist to verify the calibration
accuracy of the heat trace control circuits.
This was a violation of TS 6.8.1.
Procedure OPGP03-ZM-0016. " Installed Plant Instrumentation Calibration Verification Program," Revision 2, governed the performance of instrument calibrations by the preventive maintenance program. The original scope of the procedure did not include calibration requirements for the heat trace circuits, therefore, procedures were not developed to verify heat trace circuit calibration accuracy.
Corrective actions taken by licensee included calibration of the heat trace circuit controllers, revision of Procedure OPGP03-ZM-0016 to include the heat trace system circuits, and performing a review to determine if l
other calibration requirements were also omitted (none were found).
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preventive maintenance instructions have been developed to perform the
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circuit calibrations.
The inspector determined that the licensee's l
actions were satisfactory.
This item is closed.
5.
Onsite Followup of Written Reports of Nonroutine Events at Power l
Reactor Facilities (92700)
(Closed) Unit 1 Licensee event Report (LER) 87-02:
Containment Ventilation Isolation Ne to a loss of Sample Flow to a Containment hadiation Monitor
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On August 26, 1987, a containment ventilation isolation (engineered safety feature (ESF) actuation) occurred as a result of loss of sample flow to reactor containment building (RCB) purge Radiation Monitor RT-8012.
The supplementary purge system, which was in operation at the time, automatically isolated as designed.
The most probable cause of the event wcs unauthorized operation of controls or valves at the monitor sample skid or control room panel.
Corrective actions proposed by the licensee included:
(1) installation of caution signs in the control room and at
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local monitor skids; (2) installation of protective covers over control l
modules in the centrol room (this proposal was subsequently determined to be unnecessary); (3) training selected plant personnel on monitor l
operation; and (4) modifying the system logic so monitor failure (loss of sample flow or loss of power) would not cause an ESF actuation.
l This LER was reviewed during a previous inspection, and results were
documented in NRC Inspection Report 50-498/88-06; 50-499/88-06.
LER 87-02 l-was lef t open due to a pending revision to the LER.
Revisions 1 and 2 to the LER were subsequently issued by the licensee.
The corrective actions
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taken by the licensee were again reviewed and inspected.
Training was conducted on the radiation monitoring system. Also, a design change was issued and implemented to remove automatic ESF actuations due to monitor i
failures.
Caution signs were placed in the Unit 1 control room and locally at monitor skids. The signs read, " Warning: Depressing flow button when lit l
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will secure sample flow and cause ESF actuation." The wording of the warning signs was out of date and had two technical errors.
First of all, the ESF actuation circuitry was modified to remove automatic actuations when the monitors were inoperable, including loss of flow conditions.
Therefore, securing a sample flow would not cause an ESF actuation.
Second, the flow button was revised to read " Pump ON/0FF" at the control room panel.
These discrepancies were pointed out to the licensee. The
licensee issued a work request to remove the warning labels.
This LER is considered closed.
(Closed) Unit 1 LER 87-04:
Control Room Ventilation Actuation to
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Recirculation Mode Due to Loss of sample Flow to_a Control Room Radiation Monitor On September 3, 1987, an operator inadve/tently pushed the " FLOW" pushbutton for Monitor RT-8033 at Panel CP-023, which turned off the sample pump. A control room ventilation actuation to recirculation mode (ESF actuation) occurred as a result of loss of sample flow to control 90m ventilation Radiation Monitor RT-P033.
Corrective actions proposed eiicluded installation of protective covers over the push buttons, adding warning labels on the panels, providing training on radiation system operation, changing the name of the pushbutton, and modifying the system logic.
This LER was reviewed during a previous inspection, and results were documented in NRC Inspection Report 50-498/88-06; 50-499/88-06.
LER 87-04 was left open due to incomplete corrective actions.
The corrective
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actions taken by the licensee were again reviewed and inspected.
The actions taken included:
(1) training was noted to be conducted on the radiation monitoring system; (2) protective covers were installed over the
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push buttons (the covers were later determined to be unnecessary);
(3) warning labels were added to the control room panel (the labels were determined to be technically incorrect and out of datt, see LER 87-02
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inspection above); (4) the flow pushbuttons were changed-to read " Pump
ON/0FF"; (5) a niodification was incorporated to interlock the " Pump ON/0FF" button with a supervisory key lock switch; and (6) a modification was incorporated to remove automatic ESF actuations due to inoperable radiation monitors.
This LER is considered closed.
(Closed) Unit 1 LER 88-50:
Engineered Safety Feature (ESF)
Actuations Due to Failure of Radiation Monitors On August 27, 1988, ESF actuation signals were generated simultaneously by several radiation monitors (RT-8013, RT-8034, and RT-8036). The ESF actuation of the control room envelope, fuel handling building, and containment building heating, ventilating, and air conditioning systems-occurred simultaneously.
The ESF actuations were most likely caused by the momentary failure of the above three radiation monitors due to a power
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disturbance.
Corrective actions proposed by the licensee included g
revising the radiation monitor circuitry logic to remove the automatic ESF actuations due to inoperable radiation monitors.
This change was submitted to the NRC for review and was approved by the NRC. An ESF actuation would continue to be generated by detection of an actual high. radiation condition, however, a radiation monitor failure would result in an alarm only (TS action statements would still-be adhered
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to). This design change has been incorporated into the plant.
This LER is considered closed.
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(Closed) Unit 1 LER 89-06:
Partial Loss of Offsite Power Due-to Operator Error h
On January 21, 1989, with Unit 1 b Mode 5 (cold shutdown), an unlicensed-operator inadvertently depressed the test button on Phase B of the main generator circuit breaker.
A partial loss of offsite power occurred due to a trip of.the main transformer.
This resulted in a loss of power to ESF Train A.
Standby Diesel Generator 11 started and loaded as designed.
Corrective actions proposed by the licensee included:
(1) installation of
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caution labels near the test buttons-on each phase of the main generator circuit breaker; (2) installation of covers over the test buttons on each g
phast of the main-generator circuit breaker; and (3)-incorporating lessons learned from this event into the operator's requalification-program.
A review of_the licensee's corrective actions was performed.
Caution
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labels have been installed, covers over the push buttons have been installed, and training has been performed.
Corrective Action No. 2 h
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stated that covers would be _ installed over the main generator breaker test witches on both units by May 1,1989. The covers were actually installed
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Jane 1,.1989.
However, there was no safety significance associated with the delay in meeting the commitment.
One minor error was noted in LER 89-06.
In the "Cause of Occurrence" section,'one. sentence reads, "In an attempt to catch himself, he (the operator) reached overhead and his hand landed on the test switch which is
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accidentally struck the test switch in the cubicle he was working in, not n adjacent cubicle.
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-This LER is considered closed.
C.
Oyetational Safety Verification (71707)
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The purpose of this inspection was to ensure that the facility was being operated safely and in conformance with license and regulatory
,E requirements. This inspection also included verifying that selected
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activities of the licensee's radiological protection program were being implemented in conformance with requirements and procedures and that the licensee was in compliance with its approved physical security plan.
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P The inspectors visited the control rooms on a routine basis and verified that control room staffing, operator decorum, shift turnover, adherence to
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TS limiting conditions of operation (LCOs), and overall control room decorum were in accordance with requirements.
The inspectors conducted
tours in various locations of the plant to observe work operations and to.
ensure that the facility was being operated in conformance with license and regulatory requirements.
The following items were observed during routine plant tours and were
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reported to the licensee:
-l Very good housekeeping and loose object control was being maintained in the Unit 1 RCB.
Radiological controls were also being raintained in the Unit 1 RCB.
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Housekeeping was poor in the emergency operations facility (EOF)
diesel generator building.
Items found included dead insects, e
loosely rolled electrical cables and garden hoses on the floor, and i
aiscellaneous trash in the building, such as rags, plastic sheets, and paper. The building-has since been cleaned.
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The " Danger-No Smoking" sign was improperly displayed at the auxiliary fuel oil storage tank. The sign was undersized, weathered (faded paint), unsecured, and not in the most visible location.
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-The floor drain in the lighting diesel generator day tank building was noted. to be plugged.
Stagnant water was observed on the building l
floor.
Area drain was backed up.
Additionally, a pool of stagnant-J water t.as standing on the area drain grating of the auxiliary fuel oil storage tank-(tank located outdoors-inside a dike),
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i A " Danger High. Voltage" sign was. unsecured and was found out of sight on top of a fire hose box, in the lighting diesel generator building battery' room.
This area wcs not reutinely traversed by plant i
F personnel.
- Procedure IP0P09-AN-0001, Revision 0, provided instructions for responding to annunciator windows for the main generator breaker Local Annunciator Panel AN001. A controlled copy of the procedure t
'was located outdoors at the panel.
The controlled copy procedure and
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procedure binder were noted tc' be disintegrating due to exposure to the environment. The procedure should have been beti.or protected or replaced on a routine basis.
As part of the operational safety verification portion of the inspection, the fuel oil storage and transfer (FO) system was inspected to verify the operability and status of the system. The F0 system provided fuel oil
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from the auxiliary fuel oil storage tank (AFOST) or fuel oil tank trucks to:
(1) the standby diesel generator fuel oil storage tanks (DGF0ST);
-(2) balance of plant diesel generator fuel oil storage tanks; (3) fire pump fuel oil storage tanks; (4) lighting system diesel generator fuel oil
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storage tank; (5) technical support center (TSC) fuel oil storage tanks; (6) EOF diesel generator fuel tank; and (7) auxiliary boiler.
The system included both safety-and nonsafety-related equipment and was located in Units I and 2 and the yard of the plant.
The inapection included comparison of as-found control switch, power
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supply breaker,-and valve positions to those required by the operating procedure and piping and instrument diagrams (P& ids). A comparison of the operation procedure (OPOP02-F0-0001, " Fuel Oil Storage and Transfer,"
Revision 7) to design documents, including P& ids, was also performed.
Items noted during a technical review of the F0 system included:
Procedure OPGP0F-ZA-0039, Revision 9, " Plant Procedures Writer's t
Guide," Addendum 1, Step 9, provided instructions to include a Table
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of Co_ntents for lengthy procedures to highlight the major sections and i
to list the support documents. ' Procedure OPOP02-F0-0001 had 22 sections and 4 addenda.
Procedure OPOP02-F0-0001 did not have a Table of Contents.
- Step 2.1 listed P& ids used as references.
Step 2.1 had one P&ID reference (6Q160F00012) that was not necessary and was missing one necessary P&lD reference (5Q159F00045 #2).
- The procedure was missing an electrical lineup for key system components, including AF0ST fill and transfer pumps.
The electrical lineup was needed to verify that the pumps and other electrically
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supplied equipment were powered up prfor to system operation.
Sections 5.5,1 (fill AFOST with ~ fill pumps) and 5.5.2 (fill AFOST with truck mounted pump) provided essentially the same instructions, however,.Section 5.5.2 was missing a step to ver t the discharge line-using Vent Valve,0-FO-0195.
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The NOTE prior to Step 6.7 was noted to apply also to Step 6.1.
The NOTE should have been located prior to Step 6.1.
The NOTE prior to Step:15.6 was noted to apply also to Step 15.3.
The note should have been' located prior to Step 15.3.
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Many steps in the procecure, including Steps 8.6, 8.7, 9.6,.and 9.7, listed valves without the valve names.
To avoid confusion and aid in locating the valves, the valve names should have been provided.
- Steps 12.7, 12.14.1, 13.7, and 13.14.1 provide instructions to open, normally shut, Recirculation Valve 00-0152.
Clear instructions were not given to subsequently close this valve.
Step 11.6 provided instructions ~ to place a filtration skid in recirculation for 10-15 minutes.
Step 13.14 provided essentially the
.same instructions as Step 11.6, but the recirculation time was only 5-10 minutes.
The time of recirculation should have been consistent.
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- Step 7.15 provided instructions to vent a fuel oil filter skid twice to ensure that the skid was vented.
Section 13.0 also provided i
instructions on venting a fuel oil filter skid, but Section 13.0 only vented the skid once.
The two sections should have been consistent.
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The following valves were located on system P& ids but were not listed
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in the procedure valve lineup: -(1) 1-FO-0211, Unit 1 TSC diesel generator day tank drain valve; (2) 2-F0-021.1, Unit 2 TSC diesel generator day tank drain valve; and (3) 0-DL-0001, lighting diesel
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generator lube oil tank isolation valve.
Procedure Step 20.5.5 provided instructions to close and leave closed l
EOF Fuel Tank Fill Valve 0-F0-0178, however, the valve was shown as normally open on the system P&ID.
Oil Filtration Skid Valves00-142,
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-164, -145, -146, -162, and -151 were normally shut valves that were shown normally open on P&ID SQ159F00045 #1, Revision 14, i
Valve 2-00-0150 was incorrectly labelled 2-00-0158 on i
P&ID SQ159F00045 #2, Revision 13.
Valve 0-FO-0212 was incorrectly labelled 0-F0-065 on P&ID 6Q170F00011, Revision 14.
Valves 1-00-117, -118, -119, 2-D0-117, -118, and -119 were vent valves that were shown as: drain valves on the respective system P& ids.
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FSAR Section 9.5.4.4 stated that when the fuel oil is added directly to the DGF0ST from a supply truck, a sample will be taken and tested for the paiemeters identified in TS Section'4.8.1.1.2, Item C.
FSAR'
Section 9.5,4.3 stated that when emergency fill of the DGFOST was required, a sampling' point was provided to allow checking and flushing the fil1~line prior to filling operations.
Sections 18.0-and 19.0 provided instructions on how to perform an emergency fill of the Unit I and Unit 2 (respectively) DGF0STs.
Sections 18.0-and 19.0 were missing steps that ensured performance of FSAR 9.5.4.3 and 9.5.4.4 requirements.
A field change request was written to add the missing steps.
The emergency fill connections have not yet been used by the licensee.
' Items noted during the walkdown of the F0 system included:
Steps 6.6.2.3 and 6.11.1.1 provided instructions to place the transfer pumps' control switches into the AUTO positions.
However, the control switches did not have an AUTO position.
Step 14.9 provided instructions to close a valve when the associated B0P diesel generator tank level was greater than 39 inches.
The tank level gauges in both Unit 1 and 2 had no units and the point of 39 inches was not marked on the gauge.
A walkdown of the EOF fuel tank was performed. The positions cf q
Check Valve 0-F0-0179 and Isolation Valve 0-FO-0178 were noted to be reversed on P&ID 6Q170F00011, Revision 14.
The same P&ID showed j
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-12-Level Gauge 0-63-LG-0773, but none actually existed (Step 20.5.3 also
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referred to Level Gauge 0-DB-LG-0773). A yardstick was used
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measure the actual 'evel of the EOF fuel tank.
- Identification tags were missing from Valves 1-00-142, -157, and -162 and 0-F0-0178.
Int'-" rents 1-DO-PDIS-9120 and -9120B were noted to
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be leaking oil wi
...e oil filtration skid was in service.
The p
tags for instrument,oot valves for 2-DO-PI-9125 and -9125A were k
reversed. Also, Valve 0-F0-135 was tagged as 0-FO-1?7.
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P&ID 6Q170F00011, Revision 14, showed flexible tubing between the F0
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system and the three fire pump diesel drivers. The-connections were actually made of rigid tubing.
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- Nonsafety-related Valves 0-FO-125, Unit 1 balance-of plant diesel generator fill isolation, and 0-FO-0018, Unit 2 balance-of plant RI diesel generator fill isolation, were required to be normally open valves but were found shut. A field change request was written after this discrepancy was identified to change the pntitions from normally open to normally shut in the Procedure OPOP02-FD 101.
- DGFOST Recirculation Isolation Valves 1-00-0071, -0073, and -0075 were normally closed valves but were found locked closed. 'The
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padlocks were found on Unit 1 valves but not on the same valves in Unit 2.
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The items noted by the inspector did not appear to directly impact safe operation of the plant. All procedural observations were referred to the licensee for inclusion in the licensee's long-term program for procedure upgrade.
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No violations or deviations were identified in this area of the inspection.
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7-Engineered Safety Feature (ESF) System Walkdown (71710)
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A walkdown of the CCW system for Unit I was performed to independently verify the status of this ESF system. The inspection consisted of an operating procedure review, comparison of the operating procedure to plant drawings and TS, and a walkdown of the system to verify whether the system was properly aligned to support plant operation.
Specific items inspected in the plant included verifying the valve, control switch, and breaker y
positions, that housekeeping was being maintained, and the availability of support systems.
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Although Unit 1 was in Mode 5 operation (cold shutdown) during the inspection, the CCW system was in operation to support other systems, including the residual heat removal (RHR) and spent fuel pool cooling and
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cleanup systems. With the unit in Mode 5 operation, a walkdown of the CCW
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The inspector reviewed Operating Procedure IP0P02-CC-0001, " Component Cooling Water System," Revision 8.
The procedure lineups (valve, control switch, and electrical power supply positions) were compared to system
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P& ids.
The following observations made during the procedure review:
Errors were noted in CCW Valve Lineup Checklist IP0P02-CC-0001-1,
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including:
(1) the " Device Number" columns for Valves 1-CC-0416 and l
1-CC-725 were erroneously left blank; (2) the " Component Noun
'l Description" for Valve 1-CC-0099 was incorrect; (3); the required
position for Valve 1-CC-0871 was listed as " Loc' ed in Place,"
j however, the position to which the valve was-to be throttled (such as
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'30 percent open) was not designated; and (4) the " Location" columns
for 1-CC-0840 and 1-CC-0697 were incomplete (actual location of the valves were missing).
Errors were noted in the CCW Electrical Lineup Checklist 1 POP 02-CC-I
0001-6, including:
(1) the power supply for Valve 1-CC-MOV-0067 was-.
required to be locked in the off position per the locked valve
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. program; however, the checklist's required position was on (the power was found to be locked in the off position); and (2) the power supply for Valve 1-CC-MOV-0068 was required to be-in the on position; j
however, the checklist's required position was locked in the off-position (the power was found'in the on position).
Errors were noted in the CCW system P& ids including:
(1) Valves 1-CC-0084 and 1-CC-0224 were locked-open valves but were not designated as j
such on the P&ID; (2) Valve 1-CC-0227 was a locked-in place valve but i
was shown as=a full-open and unlocked valve on the P&lD;
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(3) Valve _1-CC-0791 was labelled Valve 1-CC-0719 on_the P&ID; and-
-(4) Valves 1-CC-846, -850, -854, and -858 were listed as drain valves in the valve lineup but were shown as test connection valves on the.
P& ids.
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Several nonsafety-related vent valves were observed to be missing from the Vent Checklist 1 POP 02-CC-0001-5.
The licensee was in the process of determining if they should be added to the checklist.
- Steps 8.3 and 8.11.5 provided instructions to open Vent
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Valve 1-CC-0096 to drain the chemical addition tank. Draining the tank was actually performed in Steps 8.4 and 8.11.4 when Drain Valve 1-CC-0095 was opened. A field change request was written to revise the steps.
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Observations made during a plant walkdown of the system and the operating procedure included:
- Selected heat exchanger flow rates were observed, including CCW flow to the spent fuel pool heat exchangers and RHR heat exchangers.
The observed flow rates were noted to be above the values listed in design documents.
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Pump 1B discharge drain, were noted to be leaking by slowly.
No
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maintenance work request (MWR) tags were attached to the valves.
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' MWRs have since been written for the leaking valves.
The handwheel for Valve 1-CC-0795, CCW supply drain, was noted to be l
installed so close to the floor that the valve could not be operated
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without removal of the handwheel.
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Procedure Valve Lineup-Checklist 1 POP 02-CC-0001-1 stated that the
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location of Valve 1-CC-0687 was at elevation 52' of the RCB, however, the valve was found at the 37' elevation of the RCB. The
identification tag for Valve 1-CC-445 was found loose on the floor.
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Procedure Electrical Lineup Checklist 1 POP 02-CC-0001-6 had several errors, including:
(1) the component descriptions for motor control
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center-(MCC) E1A2 Cubicle G1, MCC E1C2 Cubicle G2, MCC EIA1
Cubicle B1, and MCC E1C2 Cubicle P1 were incorrect; (2) the locations j
of MCC E181 Cubicle.T1, MCC E181 Cubicle X1L, MCC EIA1 Cubicle H2, i
.and MCC EIA1 Cubicle V3R were incorrect; and (3) the component
description for MCC E1C2 Cubicle P2 was incomplete, i
During the-inspection, a total of 10 of'77-system' valves were out"of position per CCW Valve Lineup Checklist IP0P02-CC-0001-1 as discussed
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1-CC-MOV-0137, -0149, -0199, and -0209 were Train B and C valves that supplied CCW or chilled water to the. reactor containment fan
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cooler (RCFC) cooling coils.
The valves were normally open valves, per the P&ID and CCW -valve lirieup checklist, but were found shut.
The valves were required to be shut when the associated chilled water chiller was secured. The MOVs were in the proper position to support plant operation.
The CCW procedure should' have specified that.the valves ~would-have been shut if a chiller was secured.
However, an MWR was outstanding on the motor
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operated valve.
1-CC-MOV-0235 and -0236 were supply valves to the boron recycle system.
These normally open valves were found to be shut.
The valves had been tagged out of service for maintenance.
The valves we,'e shut because the boron recycle system was not required at that time.
- 1-CC-FV-4540 and -4541 were supply valves to the postaccident sampling system (PASS).
These normally open valves were found to be shut. After discussions with Um:t 1 operators, the valves were returned to the open posfti rn.
There was no safety significance involved since the fail..
g. ations of the valves were shut and
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'the valves can be opened remotely from the control room if PASS operation was required.
Valves 1-CC-FV-4524, -4525, and -4526 were normally open valves that provide the CCW Trains A, B, and C inputs into Radiation Monitor _RT-8040. The CCW valve lineup (performed prior to venting)
required the valves to be shut.
The valves should be opened when tne
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associated train is placed in service. The procedure did not provide instructions on when to open the valves.
The CCW Valve Lineup IPOP02-CC-0001-1, requires position of Valve 1-CC-0031, CCW from Spent Fuel Pool Heat Exchanger IB, to be " Locked
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In Place 20% Open." The valve was found throttled in place, but the valve
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did not have a locking mechanism.
The valve was also listed in
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Procedure OPGP03-ZO-0027, " Locked Valve Program," Revision'7, as an s
administrative 1y locked valve. The valve was required to be seal locked-(key lock not required) in the interest of good engineering, practice.
The-
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required position of 1-CC-0031 per Lineup OPGP03-20-0027-8 was " Locked In Place." This valve was reported to the Unit 1 operations manager who.
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initiated corrective actions.
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The. failure to have Valve 1-CC-0031 locked as required by an approved Procedure Checklist OPGP03-Z0-0027-8 is a failure-to follow an; approved
procedure. The failure to follow procedures is an apparent violation of TS 6,8.1 (50-498/9018-01).
Th,s apparent violation of TS is not being cited because it meets the criteria established in Section V.A of-the general statement of policy and procedure for NRC enforcement actions (10 CFR 2, Appendix C).
Corrective actions taken by the licensee included
' replacement of the seal and issuance of a station problem report.
Additionally, the licensee has begun a program to review the locked valve program for accuracy and completeness.
In conclusion, none of the observations made appeared to have a detrimental impact on plant safety. Additionally, housekeeping was good.
in the areas inspected in Unit 1 during the system walkdowns. Despite the P&ID errors observed, the CCW P& ids were noted to be of higher quality than the system P& ids that were reviewed during previous. plant system walkdowns. All observations were reported to the licensee for inclusion into the licensee's long-term procedure enhancement program.
One noncited violation and no deviations were identified in this area of the inspection.
8.
Monthly Maintenance Observations (62703)
Selected maintenance activities were observed to verify whether the activities were being conducted in accordance with approved procedures.
The activities ~ observed included:
Work Request (WR) CN-92908, Replacement of Lighting Diesel Generator 125vde Batteries 7_
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WR DG-125406, Soldering of Potentiometer and Resistor on Diesel Generator No. 13 Governor Emergency Mode Circuit WR AM-79235, Investigate the AMSAC Panel Test Error
Preventive Maintenance (PM) EM-1-DG-88002248, Diesel Generator No. 13 generator control panel relay ~ tests The inspector verified that the activities-were conducted in accordance with approved work instructions and procedures, test equipment was within the current calibration cycles, and housekeeping was being conducted in an acceptable manner. All observations made were referred to the licensee for appropriate action.
WR CN-92908-was perfornied by electrical technicians on lighting diesel generator 125vde batteries, The electricians changed out ten batteries in the battery bank. The work consisted of obtaining new batter _ies, removing the old batteries and interconnections, installing new batteries and connections, torquing the connections, and performing postmaintenance testing.
No concerns were identified.
WR DG-125406 was. performed by electrica) technicians on the Diesel Generator No.13 governor emergency mode circuit. - The wnrk consisted of replacing a soldered potentiometer and resoldering a resistor's soldered connection. -The work was performed in accordance with Procedure OPMP07-ZJ-0001, Revision 1, " Fabrication and Evaluation of Hand Soldered Electrical and Electronic Connections." The technicians were observed using the correct solder, properly cleaning the connections, and soldering in accordance with procedure requirements. The soldered connections-were inspected and approved by a quality control inspector.
The technician performing the soldering appeared competent and very knowledgeable of procedural requirements.
No. concerns were identified.
WR AM-79235 was performed by instrumentation and controls technicians on the Anticipated Transient Without a Scram Mitigation System Actuation-Circuitry (AMSAC) panel. The panel was indicating a " Test Error" signal.
During performance of the WR, at Step 3.12, the test / maintenance processor apparently " locked up." -This was not expected by the technicians. The technicians, at the system engineer's instructions, varied slightly frore
- k instructions by trying to reset the processor by pressing the reset
> ton and turning power off and back on.
This action cleared the test error signal, but the processor was still locked up. Work was halted for further instructions. A new Processor Card (C2) was installed and the AMSAC system started functioning again. One voltage level (+15 volts DC)
was found out of tolerance during postmaintenance testing and was returned to within tolerance.
No concerns were identified.
PM EM-1-DG-88002248 was performed by electrical technicians on Diesel Generator No. 13 control panel relays. The work consisted of testing the Voltage Balance Relay No. 60 in accordance with Procedure OPMP05-ZE-0003,
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" Calibration of GE Type CFVB11B Relay," Revision 2.
The following items
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were observed and reported to the licensee:
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- Step 4,2 provided instructions to enter a note in the remarks section
- r of Data Sheet OPMP05-ZE-0003-1 if the relay was not tested in place.
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l The relay was removed for testing elsewhere but'no remarks were made i
in the data sheet. This was reported to the job foreman.
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Step 6.4.6 provided instructions to turn test equipment power off so L
the technicians could alter test wiring connections. There were no steps providing instructions to turn power back on to complete the test (the procedure has since been revised).
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Section 6.5 provided step-by-step instructions on how to perform an L
auxiliary telephone relay test.
During procedure performance, the test was suspended because the r acedure did not work as written. A field change request was written to change the section, and the test was then reperformed without further incident.
- Step 6.7.10 provided instructions to record data in the "As Left"'
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columns of Tables A, B, C, and D.
However, there was no such column f
on Tab 1'e C..
The required data was subsequently recorded in the l-procedure remarks section.
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Table C'provided blanks for recording telephone relay pickup and dropout voltages and relay time delays. The table also listed the optimum pickup and dropout time delay values that were to be expected-(200 milliseconds). A-review of the relay vendor manual'was performed.
The vendor manual did not list optimum value for pickup time delays and listed the optimum dropout values as greater than 200 mill _iseconds.
The Table C optimum values listed should have been more accurate.
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No violations or deviations were identified in this area of the
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inspection.
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9.
Monthly Surveillance Observations (61726)
Selected surveillance activities were observed to ascertain whether the surveillance of safety significant systems and components were being conducted in accordance with TS and'other requirements. The following surveillance tests were observed and the documents reviewed:
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IPSP06-PK-0004, "4.16kv Class 1E Undervoltage Relay Channel Calibration /TADOT - Channel 4," Revision 5
1 PSP 05-RC-0419, "RCS Flow Loop 1 Set 3 Calibration (F-0419),"
Revision 2
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IPSP03-CG-0001, " Containment Hydrogen Recombiner System Functional i
Test," Revision 3
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IPSP03-0G-0015, " Standby Diesel 13 Loop - ESF Actuation Test,"
Revision 4 Specific items inspected included verifying that as-left data was within acceptance criteria limits, test equipment used was within acceptance criteria limits and within current calibration cycles, and test performers were adhering to approved procedures.
In addition to observation by.the inspector of the surveillance activities, the procedures were reviewed for
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technical accuracy and for conformance to TS requirements, j
Surveillance Procedure 1 PSP 06-PK-0004 was performed by electrical
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technicians on the 4.16kv Class 1E Undervoltage relay on Electrical
- l Bus ElB. The-test consisted of performing a trip actuating device
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operational test (TADOT) on the Channel 4 undervoltage relay on Bus ElB.
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Step 7.4.3 instructed the technicians to close a relay knife switch and
reset the relay's target.
However, the technicians failed to reset the relay - Step 7.7.1 instructed the technicians to manually trip the relay locally to verify that the relay's red flag operates per design.
To perform Step.7.7.1, the technicians had to reset the relay. Although the-steps were performed slightly.out.of sequence, this.had no effect on final test results.
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Procedure 1 PSP 05-RC-0419 was performed by instrumentation and control technicians on the Reactor Coolant Flow Low Reactor Trip i
- Channel B1RC-F-0419. The caution statement prior to Step 7.4 of
- 1 PSP 05-RC-0419 referenced the wrong section number.
Flow j
Transmitter BIRC-FT-0419 was found out of calibration, the calibration was returned-to within required limits, and as-left data was noted to be
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within. required acceptance criteria limits.
Double asterisks (**) are
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used to denote steps within the procedure that require independent'
verification.
Step 7.7.2 required independent verification but was
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missing the double asterisks.
Step 7.14.6 instructed technicians to
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verify that a status light and annunciator was on if reactor coolant
system flow was less than 91.8 percent.
Step 7.14.7 instructed technicians to verify that the same indications were off if flow was above 91.8 percent. A condition of " normalization" was present at the time of the test (potentiometers were installed and adjusted to simulate normal i
plant cer41tions - a prerequisite for several survedilance tests).
Reactor coolant system flow was actually below 91.8 percent (Step 7.14.6 applied) but simulated conditions showed reactor coolant system flow as being above 91.8 percent (Step 7.14.7 conditions were present).
Since i
this procedure was normally required to be performed during refueling, a note to explain what to do during " normalization" may have been appropriate.
Procedure 1 PSP 03-CG-0001 was performed by Unit 1 operations personnel on Containment Hydrogen Recombiner 18. The test was performed following maintenance on the recombiner (postmaintenance test).
The test involved
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increasing recomMner power and verifying a power output of greater than 65 kilowatts and a thermocouple reading of at least 1000'F existed. The
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recombiner was tested and performed as designed.
Procedure IPSP03-DG-0015 was performed by Unit ~1 operations personnel on Standby Diesel-Generator No. 13.
T':e purpose of -this procedure was to verify that Train C ESF would actuate when a loss of offsite power to 4.16kv Bus E1C was simulated by opening the 13.8kv breaker supplying Auxiliary ESF Transformer E10. The inspector verified that the standby diesel generator started and that the generator was successfully loaded with the ESF loads.
10.
Refueling Activities (607101 A review was conducted of the completed outage scope for the Unit I second r
refueling outage-which is scheduled for completion on or about June 14, 1990.' The purpose of this review was to determine if any significant scheduled activities have been deferred. The licensee's original outage
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scope was reviewed and documented in NRC Inspection Report 50-498/90-09.
The licensee successfully completed all the major items listed in that
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inspection report. One minor item was deferred as a result of a t
particularly large amount of instrumentation and controls workload. A modification to the qualified display processing system (QDPS) to incorporate on-line parameter update (0LPU) capability was planned for installation 'during this refueling outage.
This modification is an enhancement to the maintenance capabilities of the system which will minimize the potential for spurious reactor trips when updating parameters by not requiring those channels to be taken offline and thus preventing partial trip conditions.
This modification is not needed to correct any QDPS problem or discrepancy and accurate operability of the QDPS is maintained either with or w'thout the modification installed.
The licensee is planning to complete the modifications in each unit during the next refueling outage for each respective unit.
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No violations or deviations were identified in this area of this inspection.
11.
Exit Interview The inspectors met with licensee representatives (denoted in paragraph 1)
on June 1, 1990. The inspectors summarized the scope and findings of the inspection.
The licensee did not identify as proprietary any of the information provided to, or reviewed by, the inspectors.
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