IR 05000321/1993008
| ML20046B746 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 06/28/1993 |
| From: | Christnot E, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20046B701 | List: |
| References | |
| 50-321-93-08, 50-321-93-8, 50-366-93-08, 50-366-93-8, NUDOCS 9308060140 | |
| Download: ML20046B746 (25) | |
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UNITE D STATES j
o NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET.N.W.
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ATLANT A,CEORGIA 30323 g1 p
Report Nos.: 50-321/93-08 and 50-366/93-08
Licensee: Georgia Power Company
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P.O. Box 1295 Birmingham, AL 35201
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Docket Nos.: 50-321 and 50-366 License Nos.: DPR-57 and NPF-5
Facility Name: Hatch Nuclear Plant
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Inspection Conducted: May 09 - June 05, 1993
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Inspectors:
n Le nard fdWert, Jr'., Sr. Resident Inspector Date Signed
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hfdwardF.ChristngResidentInspector Date Signed Accompanying Inspec r:
Bobby Hol rook Approved by:
Lth M d~ i b~28'93
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Pierce H. Skinnef, Chief, Project Section 3B Date Signed Division of Reactor Projects
SUMMARY Scope:
This routine, announced inspection involved inspection on-site in the areas of operations including the review of two reactor scrams
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and a period of close monitoring of control room activities,
surveillance testing, maintenance activities, response to NRC Bulletin 93-02: Debris Plugging of Emergency Core Cooling Suction i
Strainers, and review of open items.
Results:
Three violations were identified:
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The first violation addressed inadequate functional testing after
extensive maintenance activities were completed on limit switch
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assemblies for the Unit 1 main steam isolation valves. The ability of the switches to correctly perform their function in the reactor protection system was not tested prior to reactor startup.
An unnecessary challenge to plant safety systems resulted.
(Violation 321/93-08-01:
Inadequate Functional Testing of Main Steam Isolation Valve Limit Switch Circuitry, paragraph 2b.)
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The second violation addressed a failure to perform TS required i
surveillance testing on the IB emergency diesel generator. This j
deficiency was one example of numerous missed TS surveillances identified over the last year.
(Violation 321,366/93-08-02:
Failure to Perform TS Surveillance Testing of the IB Emergency Diesel Generator, paragraph 3b.)
The third violation involved two significant examples of failure to follow procedures.
Independent verification was not being
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properly performed during surveillance testing of the turbine control valve fast closure function.
Electrical equipment was not verified to be de-energized prior to work activities. This is the second example of this deficiency in recent months. (Violation 321,366/93-08-03:
Examples of Failure to Follow Procedure, l
paragraphs 2d and 2b.)
Several examples of personnel errors and inadequate attention to detail on the part of control room ope mtors were identified during this report period. Two reactor scrams and an inadvertent Group I isolation occurred, all of which could have been prevented if the performance of control room operators had been up to NRC l
expectations. During a brief period of close control room j
monitoring, the inspectors noted examples of inadequate response
I to annunciators, insufficient questioning of indications and conditions, and poor communications. (paragraph 2e.) Licensee management initiated actions to correct the problem near the end of the inspection period. The inspectors observed prompt and appropriate actions on the part of operators responding to plant transients, including a main steam isolatica valve closure and the I
loss of both recirculation pumps.
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I REPORT DETAILS
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1.
Persons Contacted Licensee Employees J. Betsill, Unit 2 Operations Superintendent
- C. Coggin, Training and Emergency Preparedness Manager
- D. Davis, Plant Administration Manager
- P. Fornel, Maintenance Manager
- 0. Fraser, Safety Audit and Engineering Review Supervisor
- G. Goode, Engineering Support Manager
- H. Googe, Outages and Planning Manager J. Hammonds, Regulatory Compliance Supervisor
- W. Kirkley, Health Physics and Chemistry Manager i
- J. Lewis, Operations Manager
- C. Moore, Assistant General Manager - Plant Operations
- D. Read, Assistant General Manager - Plant Support P. Roberts, Outages and Planning Supervisor
- K. Robuck, Manager, Modifications and Maintenance Support
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- H. Sumner, General Manager - Nuclear Plant i
J. Thompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Ccepitance Manager
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- P. Wells, Unit 1 Operations Superintendent Other licensee employees contacted included technicians, operators, i
mechanics, security force members and staff personnel.
NRC Resident Inspectors
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- L. Wert E. Christnot
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Accompanying Inspector
- B. Holbrook
- Attended exit interview Acronyms and abbreviations used throughout this report are listed in the last paragraph.
2.
Plant Operations (71707) (92701) (93702)
a.
Operations Status Following the Unit I fourteenth refueling outage, a reactor -
startup was initiated at 10:10 p.m. on May 12, 1993. On May 14, 1993, at 6:35 a.m. an automatic reactor scram occurred when the operator placed the mode switch in RUN from the STARTUP position.
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Subsequently it was determined that the scram was due to several blown fuses in the MSIVs NOT FULL OPEN scram logic.
Paragraph 2b
of this report contains additional details.
The startup was j
resumed at 11:04 p.m. on May 14, 1993. The main generator was
tied to the grid at 2:29 p.m. on May 16, 1993. The unit reached
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100 percent RTP on May 18, 1993. With the exception of operation at about 50 percent RTP for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to conduct repairs to the "lB" RFPT and other plant equipment, operation was continued at full RTP for the remainder of the reporting period.
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Unit 2 began the reporting period at 74 percent RTP due to a small
fuel leak which had been identified in April.
The unit remained at this power level until May 21, 1993.
On that date the power
was lowered to 65 percent for turbine control valve testing.
During the performance of the test, both reactor recirculation
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pumps were tripped. An operator manually scrammed the reactor in
accordance with procedures.
It was determined that the tripping
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of the pumps was due to operator error during turbine control valve testing.
Paragraph 2d of this report contains additional details. A reactor startup was commenced at 3:24 p.m. on May 22.
i The generator was tied to the grid at 6:47 a.m. the following day.
Power was slowly increased to 85 percent RTP on May 30.
The unit remained at this power level for the remainder of the reporting period.
Several control rods remain fully inserted to suppress the neutron flux in the area of the suspected fuel leak. The licensee is continuing to closely monitor offgas radioactivity levels.
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The inspectors reviewed plant operations throughout the reporting
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period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative controls.
Control room logs, shift turnover records, temporary modification logs, LCO logs and equipment clearance records were reviewed routinely.
Discussions were conducted with plant operations, maintenance, chemistry, health physics, instrumentation and control (I&C), and nuclear safety and compliance (NSAC) personnel.
The inspectors also periodically monitored the ongoing SFP cleanup project.
Activities within the control rooms were monitored on an almost daily basis.
Inspections were conducted on day and on night shifts, during weekdays and on weekends. Observations included control room manning, access control, operator professionalism and attentiveness, and adherence to procedures.
Instrument readings, recorder traces, annunciator alarms, operability of nuclear instrumentation and reactor protection system channels, availability of power sources, and operability of the Safety Parameter Display system were monitored.
Paragraph 2e of this report contains additional details of deficiencies noted by ~rhe
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inspectors during a period of close CR monitoring following a Unit 2 scram.
Control Room observations also included ECCS system i
lineups, containment integrity, reactor mode switch position,
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scram discharge volume valve positions, and rod movement controls.
During the Unit I startup from a scheduled refueling outage, CR activities were frequently monitored.
Portions of several major operability surveillance tests were observed and reviewed. These tests involved the RCIC, ADS and HPCI systems. The verification of nuclear instrumentation overlap was observed by the inspectors.
The startup proceeded in a controlled manner until the reactor received an automatic scram.
Paragraph 2b contains a discussion of the scram.
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The inspectors attended training sessions that addressed design changes completed during the Unit I refueling outage which were provided to operations personnel prior to startup.
All significant plant changes that the inspectors were aware of were discussed. The inspector concluded that the training adequately informed the operators of pertinent equipment changes.
Several of
the modifications were reviewed to verify that necessary procedural changes had been implemented. All required changes
were in place.
- Several active safety-related equipment clearances were reviewed j
to confirm that they were properly prepared and executed.
Applicable circuit breakers, switches, and valves were walked down to verify that clearance tags were in place and legible and that
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t equipment was properly positioned.
Equipment clearance program requirements are specified in licensee procedure 30AC-0PS-001-05,
" Control of Equipment Clearances and Tags." No discrepancies were identified. Deficiencies noted involving caution tags are
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discussed in paragraph 2e.
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Selected portions of the containment isolation lineup were reviewed to confirm that the lineup was correct. The review
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involved verification of proper valve positioning, verification
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that motor and air-operated valves were not mechanically blocked and that power was available (unless blocking or power removal was
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required), and inspection of piping upstream of the valves for leakage or leakage paths.
Plant taurs were taken throughout the reporting period on a routine basis. The areas toured included the following.
Reactor Buildings
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Station Yard Zone within the Protected Area Turbine Building
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Intake Building Diesel Generator Building l
i Fire Pump Building Transmission Switchyard and Relay House
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During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observed. No significant deficiencies were noted.
Paragraph'5 of
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this report discusses the inspectors review of the licensee's
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I actions in response to NRC Bulletin 93-02: Debris Plugging of Emergency Core Cooling Sucticn Strainers.
N May 31, 1993, during work activities on the reactor building eievator, a worker was injured when he contacted an electrical component energized with 575 volts AC.
The worker is an experienced employee of a company contracted by the licensee to repair the elevator.
Prompt actions by other workers in the elevator " penthouse" area prevented more serious injury. The licensee's safety group is still investigating the incident. One of the inspectors discussed the incident with the involved worker.
The worker acknowledged that personnel error on his part had caused him to contact the energized circuitry. The error occurred during movement of an uninsulated temporarily connected voltage
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monitoring device.
This is the third incident in recent months in which personnel
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inadvertently contacted energized electrical equipment.
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been fortuitous that more serious personnel injury has not resulted.
In each of the cases, the workers involved were contract personnel. The first incident involved a worker cleaning
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a 4160V safety bus. Violation 321/93-05-01:
Examples of Failure to Follow Procedure, addressed several failures to follow procedure and inadequate work practices involved in that case.
The second incident involved an individual working in the low voltage switchyard. The inspectors have been informed of the results of the investigation into that event and the corrective l
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actions.
On June 2, one af the inspectors attended a special safety meeting at which these incidents and other recent electrical work deficiencies were discussed. The meeting was attended by about 200 personnel, primarily from the PMMS, maintenance, and
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engineering departments (work was stopped in those departments for the meeting).
It was conducted by safety department t
representatives as well as department managers and the AGM-PO.
Management's concerns in regards to the recent events and the
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importance of respect for the hazards of electricity were discussed. Emphasis was placed on the seriousness of the incidents including the potential for fatal injury. The inspectors will continue to follow the licensee's corrective actions and observe work activities for adherence to electrical safety requirements.
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b.
Unit 1 Reactor Scram At approximately 6:35 a.m. EST on May 14, 1993, Unit I received an automatic scram. One of the inspectors was in the control rtrem area at the time and observed the immediate actions and most of i
the recovery activities. The operators verified all rods in, reset expected alarm annunciations, and took additional actions.
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Post scram observations and reviews indicated that the reactor
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received an automatic scram instantaneously when the reactor i
operator moved the mode switch from the STARTUP position to the
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RUN position. As expected, reactor pressure decreased substantial sy following the scram due to a lack of decay heat.
This resulted in the closure of the MSIVs when the Group 1
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isolation occurred due to low steam pressure (850 psig). The required notification was made to the NRC operations center.
The licensee initiated an ERT to gather data and information on the scram. The inspectors were informed that several blown fuses i
had been discovered in the RPS system affecting the K3 relays l
which provide the MSIVs "NOT FULL OPEN" signals to RPS.
(When specific combinations of MSIVs indicate less than 97 percent full open, a scram signal is initiated in order to compensate for the expected positive reactivity due to the pressure increase which will occur if the MSIVs shut.) The inspectors closely observed additional troubleshooting activities cerformed by the plant electricians.
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The RPS "MSIV NOT FULL OPEN" logic consists of eight relays.
Four relays in each of the two RPS systems, and two per each of four RPS scram channels.
Each relay has two fuses aligned in series, for a total of 16 fuses. These circuits provide power to the K3 relay coils through two limit switches also aligned in series.
The limit switches are located r,n the four individual inboard and outboard MSIVs. The troubleshooting activities determined that 11 of the 16 fuses were blown.
It was noted early in the investigative process that a front panel annunciator should have clearly indicated that the K3 relays were not in the expected position.
CR panel 1Hll-P603 contains the
"MSIV NOT FULL OPEN TRIP" annunciator. Although one of the inspectors had observed the majority of the immediate operator actions following the scram, the inspector could not state with certainty if the MSIVs NOT FULL OPEN TRIP alarm was on and
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flashing immediately after the scram. The inspectors performed an
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independent review of the RPS and alarm drawings.
It was
determined that with 11 of 16 fuses blown and seven of eight K3 relays deenergized the alarm should have been actuated. Several operators involved in the scram recovery were confident that the alarm was not illuminated before the scram. During testing after the fuses were replaced, the annunciator functioned properly.
Additional reviews indicated that the fuses may have been blown when preventive maintenance activities were performed for replacement of the MSIV limit switches. The limit switches on the MSIVs provide signals to two different systems. The " fully open and fully closed" limit switches are powered from the PCIS (C61).
The "MSIVs NOT FULL OPEN" limit switches are powered by the RPS system (C71).
Followup reviews by the ERT indicated that when the MSIV limit switches were replaced, only the PCIS was placed under clearance and tagged. The circuitry associated with the RPS
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system remained energized.
Consequently, the not fully open
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limit switches were changed out while they were electrically
energized. The ERT concluded that this was the most probable
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cause of the blown fuses. The inspectors observed.several
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activities performed for the ERT which consisted replacing the
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blown fuses, opening the MSIVs one at a time, and verifyir.g the i
alarm function.
These activities verified that the conditions t
that caused the fuses to blow were no longer present and the
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annunciator functioned as expected.
j The inspector reviewed procedure 34G0-0PS-001-IS:
Plant Startup,
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and noted'that Attachment I required that all eight K3 relays be
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confirmed as energized. The procedure in use for the Unit 1 startup indicated that these relays were visually confirmed as being energized. The ERT questioned additional operators and
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concluded that personnel may not have understood how to verify the status of these relays. The inspectors attended training sessions
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conducted by the site training organization to review and discuss
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the different types of relays. An HGA and an HFA relay was used
to demonstrate to the operators what a relay looks like when it is l
energized or de-energized.and the correct methodology required to
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verify the relay status. The inspectors concluded that accurate verification of the status of these relays requires close and
careful observation. The operator must ensure that proper
lighting is used to inspect the relays and care must be exercised
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to ensure that the "b" contacts are not confused with "a" contacts
within the enclosure. The inspectors reviewed work activities
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performed on the alarm system.
It was noted that MW0s were submitted involving the alarm system, however, none involved the MSIVs NOT FULL OPEN TRIP alarm.
l The inspectors conducted an independent review of the work
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j packages associated with the MSIV limit switch work performed during the last refueling outage. This work activity was suspected of causing the fuses in the RPS circuity to blow. The
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work package consisted of MW0s 1-93-624 thru l-93-631, Procedure 52GM-MEL-007-OS:
Installation and Maintenance of NAMCO Limit.
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Switches, Procedure 52SV-B21-001-05: MSIV Limit Switch Inspection, and Procedure 52PM-B21-005-IS: MSIV Preventive i
Maintenance. The review of Procedure 52PM-821-005-IS indicated that some links for the MSIV's were identified and opened in the main control room panels. The MSIV limit switches were de-
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energized from the PCIS system by opening these links. However, i
electrical drawings indicated that the MSIV limit switches were
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not de-energized from the RPS system. The procedure failed to-
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identify the links that would perform this electrical isolation.
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Through discussions with electrical maintenance personnel,'it was confirmed that the workers did not properly verify that the
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required clearances were fully in place. Workers did not vertfy i
that all.of the required links were opened nor did they-verify i
that the equipment was electrically de-energized prior to beginning the work. Although the procedure should have more
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specifically identified the necessary links, verification that l
electrical equipment is de-energized before work is commenced is a
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critical requirement that could have identified the error. The inspector concluded that this work most probably resulted in the j
fuses being blown in the circuitry. - The inspectors were not able
to identify any other plausible cause for the. blown fuses.
j Supervision from the electrical maintenance department indicated i
that a procedure change request would be initiated. This change
request would identify and require the additional links to be open i
to electrically isolate the switches.
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Additionally, the inspectors conducted a review of the post
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maintenance testing performed on the MSIV's following the limit switch electrical work.
Procedure 52SV-821-001-05: MSIV Limit
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Switch Inspection, verified and allowed adjustments to the MSIV l
limit switch position settings to ensure the limit switch would i
j actuate at the correct valve positions during the valve stroke
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cycle. The limit switch must actuate (open contacts) in the RPS
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I circuit before the MSIV is less than 97 percent open.
This valve
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position provides part of the logic circuit for the RPS scram'
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function for MSIV closure. The inspectors determined that the procedure only tested continuity through the limit switches and
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t did not test any other part of the circuity. Therefore,-this i
procedure did not provide any post maintenance testing for the
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remainder of the RPS or PCIS circuit. The inspectors determined j
that the work package did not specifically identify which
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procedures should be performed to complete post maintenance
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testing that would reasonably verify operability for the complete circuit of PCIS and RPS.
Procedure 42SV-821-001-IS: MSIV LSFT I
had been completed satisfactorily on May 8,1993. This test l
procedure did test the MSIV trip logic (PCIS). However, the performance of this test did not require verification of the RPS l
relays in question. On May-10, 1993, procedure 345V-B21-003: MSIV Exercise Test, was satisfactorily completed.
This test would j
only require the verification of the K3 relays if the position indication of the MSIV's were to not illuminate or presented dual
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indication. A review of the procedure test date indicated that the MSIV position indication operated correctly and thus
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verification of the K3 relay status was not required.
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a The inspectors noted that Procedure 34SV-821-001: MSIV Closure l
Instrument F/T, requires the operators to visually confirm the K3 i
relays and LED's are energized.
However, TS requires this i
procedure be performed on a 3 month frequency (once every 92 days)
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and due to scheduling, this test was not performed prior to l
reactor startup on May 12, 1993.
The procedure was performed on
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May 14, 1993 in accordance with the normal schedule (after the
reactor scram). A review of procedure, 95IT-0TM-001-05:
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Maintenance Work Order Functional Test Guideline, indicated tirat
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personnel responsible for reviewing MWO packages for F/T i
requirements will determine the scope of testing required using a
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matrix in the procedure attachment. This matrix, for limit switch i
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repair replacement or adjustment, indicated that the valves should be stroke timed and a position indication check be performed.
A reminder also indicated that an LLRT may be required. The valves were stroke timed and checks of the limit switches were performed.
The inspectors questioned plant management concerning post maintenance testing requirements and the methodology used to determine the required post maintenance testing. Management indicated that personnel would use the matrix in the procedure and other sources as needed. It was unclear to' the inspectors as to the actual methodology used and what the other sources would be.
The inspectors concluded that the guidance provided in the matrix was not sufficient to adequately test the systems in light of the extensive maintenance that was performed.
The inspectors also concluded that a procedure was available to adequately test the circuits but was not performed.
If the procedure that was available had been identified and performed following the MSIY switch replacement, a reactor scram most likely would have been
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averted.
After completing additional review of the event, the inspectors
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discussed the event with the ERT leader. Although the final report of the ERT had not been issued, the conclusions did not contradict the results of the inspectors' reviews. The inspectors discussed with ERT personnel their concern that this was the
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second significant instance in which electrical equipment was not properly verified de-energized before work was started. (See VIO 321/93-05-01:
Examples of Failure to Follow Procedure.)
The inspectors concluded that the proper performance of any one of four separate requirements could have prevented the scram. A proper clearance was not in place before the maintenance activities were conducted, the equipment was not verified to be de-energized, a proper F/T was not conducted after the work, and the check of the MSIV limit switch relays was not properly performed.
The failure to perform proper functional testing of the MSIV circuitry following the extensive maintenance activities performed, is considered a significant deficiency. This issue is identified as Violation 321/93-08-01: Inadequate Functional Testing of MSIV Limit Switch Circuitry. The failure to verify the equipment de-energized is one example of Violation 321,366/93-08-03: Examples of Failure to follow Procedure.
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MSIV Closure At Power:
On May 21, 1993, at 4:15 pm EST, the Hatch Unit 1
"C" outboard MSIV went shut. The unit was operating at 100 percent RTP.
In accordance with MWO l-93-2870, the MSLRM setpoints were beintf-reset in preparation for placing the hydrogen injection system in service.
During work on the "B" MSLRM, "B" half scram and half Group I isolation signals were generated. Almost immediately,
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reactor high pressure, high APRM levels, and other annunciators were received. The operator noted that the "C" main steam line flow had decreased to about 0.5 E6 lbm/hr and the flow in the other 3 lines had increased.
Valve IB21-F028C ("C" outboard MSIV)
had dual position indications. The operator informed the I&C personnel doing the MSLRM work of the problem. The MSLRM was placed in the " operate" mode and the half scram / isolation signals were reset. The HSIV reopened immediately. One of the resident inspectors was at a CR back panel when the valve shut and observed some of the recovery actions. The inspector noted that reactor pressure peaked at about 1030 psig and the APRMs had spiked up to
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as high as 112 percent power.
The surveillance was halted and investigative actions were initiated.
The problem was traced to a malfunctioning dc powered solenoid in the IB21-F028C.
During the testing, the AC powered solenoid was cycled and with the de solenoid not functioning properly, the MSIV went shut.
A modification had just been completed which was intended to prevent this type of event. An LED indication of the status of the DC and AC solenoids for each of the MSIVs was added to a CR front panel. During testing evolutions, the operators could utilize these indications to prevent cycling one of the solenoids with the other solenoid not functioning. However, the dc solenoid
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LEDs were so dim that a de-energized LED is very difficult to detect. After the event, it was noted that the "C" MSIV solenoid i
LED indicator was not lit.
On May 24, power was reduced to 50 percent RTP and repairs were completed to the MSIV and the "B" "FP discharge check valve (steam leak). The de solenoid was found to be open circuited. Additional investigation to determine the cause
of the failure is in progress.
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Corrective actions for the dimly lit dc solenoid LED indicators will be completed after the necessary parts (different electrical
resistors) are received. The licensee informed the inspectors
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that the voltage level supplied to the de coils which had been affected by the modification to the LED indicators, was sufficient and did not play a role in the failure.
After additional review I
of the event on May 27, the licensee made a 10CFR50.72 notification to the NRC operation center due to the MSIV (an ESF
component) shifting position.
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The inspector noted that the actions of the involved operators
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following the MSIV closure were prompt and appropriate.
Communications which had been established for the testing (the
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radiation monitor panels are on a CR back panel) facilitated the
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responsive actions.
d.
Hatch Unit 2 Manual Scram on Loss of Recirculation Pumps
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At 8:39 pm EST, Hatch Unit 2 was manually scrammed from about 65 percent RTP after both recirculation pumps tripped. The pumps
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tripped during the performance of Procedure 34SV-C71-005-2S:
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i Turbine Control Valve (CV) Testing. The testing exercises the RPT circuitry. Testing to ensure the fast closure of the CVs generates a recirculation pump trip signal is required by TS.
The number 1 CV had been successfully tested. During the testing
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of the number 2 CV, the licensed operator performing the testing placed the "B" RPT channel out of service switch in the "inop" position instead of the
"A" channel out of service switch.
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switches are designated 2C71-S12A and 2C71-S12B and are located on
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CR back panels 2Hil-P611 and 2H11-P609. With the "A" RPT channel still in the " normal" position, testing of the number 2 CV resulted in tripping of the RPT breakers.
Following the trip of the recirculation pumps, the CB0 almost immediately announced "both recirculation pumps are tripped",
inserted a manual scram, and placed the mode switch in shutdown.
No other problems occurred during the immediate recovery actions.
The reactor water level decrease resulted in a Group II isolation and all valves responded correctly. The appropriate notification was made to the NRC Operations Center.
One of the resident inspectors was onsite for backshift coverage and responded to the CR to observe some of the recovery actions and portions of the post scram review process. Available information indicated that the manual scram was inserted within 5 seconds of the pump trip. The inspector concluded that the 1'
operators actions after the pump trip occurred were in accordance with Procedure 34AB-831-001-2S: Trip of One or Both Reactor
Recirculation Pumps, and were appropriate.
The pump trip was caused by the operator placing the incorrect RPT channel switch to "inop".
The inspectors noted that the switches
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which are located about 8 feet apart on 2 CR back panels, are clearly labeled (with a simple black label).
Step 7.3.4 of the procedure specifically required the correct switch to be manipulated.
During the post scram review of the procedure, it was noted that several independent verification steps had not been signed off
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despite the testing having progressed beyond those steps. The involved operators stated that the verifications were being performed as required and the intent was to sign the steps off after the test was completed. The steps which resulted in the pump trip are not required to be verified. The operator performing the testing was working with another operator during the testing. The manner in which this individual was verifying the steps was not independent of the cperator performing the testing.
Section 5.3.12 of Procedure 10AC-MGR-003-OS:
Preparation and Control of Procedures, defines independent verification and specifically requires that the verification 7ust be separated by distance and time from the performance of the activity. The individual completing the verifications did not have a copy of the procedure during the testing.
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indicated that the testing had been conducted with a less than
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appropriate level of formality. The inspectors noted that step
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4.3.2 of the testing procedure may have contributed to the operators decision that it was appropriate to document completion-of the verification steps at a later time.
Step 4.3.2 states "the i
VERIFIED part of any step requiring independent verification may be performed out of sequence any time after completion of the first sign-off". The inspectors questioned if this guidance is
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appropriate to procedures such as CV testing.
r The inspectors discussed their concerns regarding the verification steps with plant management.
It was noted that this deficiency may be indicative of the performance of other work activities by the involved operating shift.
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Due to the recent series of events at Hatch involving personnel errors or inattention to detail, the resident inspectors significantly increased their monitoring of CR activities during
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the subsequent recovery and startup activities.
Paragraph 2e discusses some of the inspectors observations as a result of the
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monitoring.
After conducting their review of the incident and observation of some of the immediate post scram review actions, the inspectors discussed the event with the ERT. The ERT also noted several areas in which the testing procedure could be enhanced to reduce the probability of such errors in the future. No contributing factors such as operator fatigue, schedule pressures, or distractions were identified.
The inspectors concluded that the cause of the scram was personnel error.
A major concern in this incident is that such testing was performed with an apparent lack of formality. Although the improper independent verification did not cause the scram, it is considered a significant deficiency due to the reliance on independent verification in critical activities. This issue is identified as another example of Violation 321,366/93-08-03:
Example of Failure to Follow Procedure.
(See paragraph 2b)
e.
Control Room Activities
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following the events discussed in paragraph 2d and due to similar operator performance concerns discussed in Inspection Report 321,366/93-06, the inspectors increased inspection activities and j
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control room observations during the period May 21 - May 23.
Major evolutions observed included the plant startup following the reactor scram that occurred on May 21, 1993.
Plant startup requirements, TS, surveillance requirements, and applicable startup procedures were reviewed to verify plant status for-startup conditions. There were no discrepancies identified in the startup requirements. The inspectors identified deficiencies in the areas of alarm response and caution tags during the
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monitoring. Additionally, numerous examples of informal communications during important evolutions were noted.
The inspectors observed several instances in which the response to CR alarms was not timely and in some instances, corrective actions for the alarms were not being initiated. An inspector noted that an alarm involving the fuel pool cooling system was in alarm for approximately 4 minutes before any member of the operating crew acknowledged and silenced the alarm.
An inspector noted that the annunciator for RFPT 2A, (in service providing feedwater to the reactor vessel with the 2B RFPT in a tripped condition) indicated high vibration. The inspector questioned the operators concerning the sibration alarm and determined some members of the operating crew were not aware of the alarm, others did not know the magnitude of the vibration or if the alarm was valid.
It was determined the magnitude of the vibration was just less than 4 mils.
It was learned that this
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alarm condition had originated during the previous night shift ("A" RFP was placed in service approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> earlier) but had not been discussed with all members of the day shift operating crew.
It was uncertain as to when the vibration alarm first actuated. The SOS stated he was not aware of any RFP problems.
The alarm response procedure (actuated at 3 mils)
required the operators to confirm the vibration, verify oil temperatures and if vibration was greater than or equal to 3 mils then reduce reactor
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power to less that 450 Mwe (the reactor was at approximately 120 Hwe).
If starting up the RFP the procedure required that oil temperatures be verified and if normal vary the RFP speed by 100 RPM's and if vibration has not decreased or increases, shutdown the pump.
Apparently none of the these actions had been performed by the operating crew. After discussions with the inspector, the alarm response procedure was utilized and corrective actions were initiated to correct the problem. Maintenance personnel verified vibration readings locally at the RFP.
It was later learned that the RFP was operating at its critical speed.
No change to the operating condition of the RFP was initiated. The inspectors noted that the alarm does not perform a safety related function.
Another alarm, 34AR-601-416-2S " Turbine Building Vent Filter Discharge Radiation Downscale," was in alarm for approximately two days. The inspector questioned the operating crew as to the cause of the alarm, if the alarm was a problem, and what had been initiated for corrective actions. The crew was unsure of the cause. One operator indicated he believed the alarm should be actuated. The alarm response procedure indicated that the cause could be a failed monitor or loss of power to one of the two monitors that provides input signals to the alarm.
Following discussions with the inspector I & C was notified to take
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corrective actions.
It was later learned that the alarm response procedure did not specify or indicate one additional monitor that provides an input to the alarm and that the downscale indication-j
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for the additional monitor should be reset. A procedure change request to update the alarm respont e procedure has been initiated.
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The inspectors reviewed the caution tags in place on the switches of the CR panels to verify the instructions to the operators were clear, legible and up to date as specified by plant procedures.
The inspectors found two caution tags that were on important equipment, one on RCIC and one on RHR, that were outdated. The caution tags had been placed on the equipment to track (or as a reminder) that DCR or maintenance work had been performed on these systems and testing would be required. The maintenance work and testing for these systems had been completed, the DCR had been closed out but the tags had not been removed.. One additional
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caution tag, on an MSIV hand switch, provided instructions to the operators that were not clear.
The instructions stated the equipment was under administrative hold and to call the system engineer.
Following discussions with the operating crew it was learned that the instructions on the caution tag were not-
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meaningful to the operators and they were not sure why the tag was
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in place. A review of the caution tag book provided no additional information. The operations personnel contacted the engineering l
staff to ascertain why the tag was in place.
Following these
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discussions additional information was recorded on the caution tag j
and in the caution tag log book to indicate that the DCR was not i
completed and additional work and testing would be required.
However, the additional information directed the operators to operate the equipment as necessary. Additional examples of a lack of proper questioning on the part of control room operators were noted.
The inspectors conducted several meetings with plant management to discuss operator performance, awareness and the general observations made by the inspectors during the time of increased inspection activities. The inspectors provided examples in which operator performance and awareness needed improvement and discussed in detail several specific concerns as indicated above.
Plant management held meetings with the operations supervisors to discuss these issues.
While the cause of the decrease in performance has not been conclusively determined, two potential factors were discussed.
In recent months, the Hatch site has conducted an unusually large number of evolutions over a sustained period, many necessitated by an unplanned dual unit outage. Additionally, there has been some concern on the part of Hatch employees regarding potential personnel reductions as efforts are made by management to reduce operating costs.
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During routine observation of operations shift briefings on the following days, it was noted that management expressed concerns pertaining to operator performance in light of the events that
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have occurred in the last few weeks. Additionally, the SOS read from recent NRC inspection reports both positive comments and examples where performance was less than desirable.
It was
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expressed that operator performance should always include self verification as required by the " SCOPE" program. Alarms should be attended to in a timely manner and the reason for the alarms should be determined or be under investigation.
The responsibilities of the CB0 were emphasized with a reminder that the CB0 would not eat lunch while assuming the CB0 position.
Operators were reminded of their duties and responsibilities to continually monitor the control board panels.
Emphasis was placed on the responsibilities of supervision. Overall, steps were initiated to increase professionalism in the CR.
On June 3, one of the inspectors attended a presentation on this subject made by the Hatch General Manager to the operating shift currently in requalification training. The General Manager intends to make the presentation to all shifts during the requalification training cycle. The inspector noted the session was strongly delivered and utilized convincing specific examples of recent performance problems. The inspectors will continue to monitor the effectiveness of the corrective actions.
Two violations were identified.
3.
Surveillance Testing (61726)
a.
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy.
The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification where required,
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handling of deficiencies noted, and review of completed work. The tests witnessed, in whole or in part, were inspected to determine
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that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems
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restoration was completed.
The following surveillances were reviewed and witnessed in whole or in part:
1.
345V-C51-002-2S: APRM Functional Test 2.
345V-C71-005-2S: Turbine Control Valve Fast Closure Instrument Functional Test
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3.
GE Numac Logarithmic Radiation Monitor Calibration
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4.
57SV-C71-003-IS: Turbine First Stage Pressure
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Permissive FT&C 5.
341T-0PS-003--OS: Security Power System Weekly Test
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6.
RCIC Pump Operability 150 PSIG Test t
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Relief Valve Operability j
8.
34SV-E41-005-1S: HPCI Pump Operability 165 PSIG i
b.
Missed TS Surveillance The inspectors documented in two previous inspections reports (321,366/92-34 and 93-02), their_ observations and concerns
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involving missed TS~surveillances.
IFI 321,366/92-34-02 was
issued in order to follow up the licensee's activities in I
correcting the issue.
It was documented in report 93-02 that the i
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licensee performed a review of missed TS surveillances over the past two years. As discussed in report 92-34, the inspectors
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performed an independent review of all surveillance testing
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problems identified over the past several years.
Part of the review included all LERs and inspection reports covering the last two years.
Several significant observations and conclusions were
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made.
It was noted that a total of 20 TS surveillances were --
missed over a 24 month period. The inspectors concluded that most
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of the causes for the 20 missed TS surveillances were personnel
errors and less than adequate procedures.
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On April 12, 1993, the licensee determined that the monthly
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j operability test for EDG 1B, which-is a shared EDG, had not-been t
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performed within the frequency specified by Unit 1 TS section-4.9.A.2.a.1 and Unit 2--TS section 4.8.1.1.2.a.
This event was discovered when site engineering personnel,~ compiling plant ~
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performance data for March, noted that EDG IB had not been run in that month.
Followup review by operations and TS surveillance i
scheduling personnel indicated that the test should have been
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performed by April 4, 1993. On May 10, 1993, the licensee submitted LER 50-321/93-03: Personnel Error Results in Missed
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Diesel Generator TS Surveillance. The LER attributed the problem
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to a scheduling error made during adjustments to the testing i'
frequency of the IB EDG.
The licensee identified the missed test, initiated some immediate corrective actions, and reported it to
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the NRC. The test was subsequently performed satisfactorily. The i
inspectors concluded that all the criteria for an NCV listed in j
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the Enforcement Policy were not met.
Corrective actions for i
previous instances of missed TS surveillances (as identified in
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LERs and NCVs), would reasonably have been expected to have j
prevented this violation.
Given the numerous instances of m1Tsed j
TS surveillance tests due to personnel error, it was reasonable to
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have expected the licensee to have initiated the necessary
corrective actions to strengthen the TS surveillance program.
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This item is identified as Violation 321,366/93-08-02:
Failure to Perform TS Surveillance on IB EDG.
One violation was identified.
4.
Maintenance Activities (62703)
l Maintenance activities were observed and/or reviewed during the
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I reporting period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that " s not within the skill of the trade.
Activities,
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procedures, and work requests were examined to verify; proper authorization to begin work, provisions for fire hazards, cleanliness, exposure control, proper return of equipment to
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service, and that limiting conditions for operation were met.
The following maintenance activities were reviewed and witnessed in whole or in part:
1.
MWO 1-93-2836:
Freeze Seal for Replacement of IG41-F041 l
2.
MWO l-91-059:
ASCO Electrical Air Solenoid Valves 3.
MWO 2-92-4918:
ASCO Electrical Air Solenoid Valves j
4.
MWO 1-93-0110:
Blown Fuses in CR Cabinets 1H11-l P609, 611 5.
MWO 2-93-1169:
Offgas Flow Indication Repair / Calibration One of the inspectors observed activities involved with the freeze seal utilized for corrective maintenance on 2 valves in the SFP makeup line. The motor operator and valve for IG41-F041 was replaced (DCR 92-127) and check valve IG41-F055 was repaired.
The inspector utilized the guidance provided in NRC Manual Chapter 9900: Technical Guidance, Mechanical-Freeze Plugs, to review the activities.
Procedure 51GM-MNT-031-OS: Freeze Seals, the
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equipment vendor guidance, and information in a specific technical i
l evaluation of the task were utilized to perform the work.
The PRB I
had reviewed and approved the associated safety evaluation and the
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procedures. The inspector reviewed the procedures and the
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evaluations with emphasis on preparations and contingency actions.
The inspector observed establishment of the freeze plug and held iiscussions with the involved workers and supervisors.
By reviewing the freeza seal equipment vendor guidance, the inspector estimated that approximately 100 lbs of CO would br
required to establish the freeze plug. Two 300 lb CO, tanks were connected to the seal jacket (through separate lines) and an
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additional 300 lb tank was staged nearby.
The involved workers understood the importance of closely monitoring the seal temperatures and were aware of contingency plans.
Equipment to be utilized for the work or if the seal failed was staged nearby.
Measures had been completed to contain any water should the seal fail during critical portions of the work.
The inspector noted that the vendor manual for the freeze seal equipment stated that water temperature should be less than 68 degrees F, particularly if the seal was to be applied on a vertical pipe.
The involved water temperature was approximately 80 degrees F.
The inspector was informed that a seal had been established (utilizing the same equipment and personnel) on a mockup pipe which had a similar configuration, diameter, and water temperature as the G41 piping.
The inspector also noted that the seal had only about 8 psig of static water pressure on it.
The inspector concluded that the licensee had thoroughly planned and prepared for the freeze seal work. The use of a " trial" freeze seal on a mockup and the extensive contingency preparations
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were particularly noted as strengths.
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No violations or deviations were identified.
5.
NRC Bulletin 93-02: Debris Plugging of Emergency Core Cooling Suction Strainers.
On May 11, 1993, NRC Bulletin 93-02: Debris Plugging of Emergency Core Cooling Suction Strainers, was issued.
Since Hatch Unit 1 was expected to startup from a refueling outage later that day,
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the inspectors discussed the information contained in a draft issue of the bulletin vith the licensee early on May 11. Copies of the bulletin were then provided to the licensee very shortly after it was signed. On the afternoon of May 11, the Hatch General Manager informed the inspectors that the bulletin had been reviewed and the licensee concluded that the unit could be restarted. The licensee had information indicating that no temporary sources of fibrous material were present in the drywell.
Additionally, tours of the Unit I drywell had been completed, and no fibrous material had been noted. The inspectors h&d also walked down the Unit 1 drywell several times just prior to the closecut and did not note any such material.
The inspectors routinely tour the drywell and the torus areas during outages, particularly during preparations for startup.
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During these tours, the inspectors have specifically looked for any foreign material which could get into the torus.
In Inspection Report 321,366/91-12, the inspector's identification of i
material in the downcomer legs is discussed. Since that issue,
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the licensee has conducted complete tours and clearing of thtr-interior of downcomer ring prior to startup of a unit after a refueling outage. Additionally, recent inspection tours of the torus and discussions with the divers working in the torus
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indicate that the torus was clear of any significant debris and emphasis continues to be placed on maintaining proper cleanliness.
Following the Unit 2 scram on May 21, 1993, the licensee discussed the bulletin (in regards to Unit 2) with the inspectors. The licensee stated that the removal from the drywell of temporary air filters used during the outage was documented. All available information indicated that no such fibrous material was present in the drywell. This information was discussed with regional management and it was concluded (in regards to restart of Unit 2)
that the licensee's actions met the requirements of the bulletin.
The licensee submitted an official response to the bulletin on May 25, 1993.
The response stated that an MWO documented removal of the fiiter material from the Unit 2 DW after the last outage and that the most recent Unit 1 DW closeout walkdown specifically documented that no loose filter material was in the DW.
No violations or deviations were identified.
6.
Inspection of Open Items (92700) (90712) (92701)
The following items were reviewed using licensee reports, inspections, record reviews, and discussions with licensee personnel, as appropriate:
a.
(Closed) IFI 321,366/92-34-02: Missed TS Surveillances. This IFI As discussed in paragraph 3b of this report, the programmatic weakness involving missed TS surveillances has been addressed as Violation 321,366/93-08-02: Failure to Perform TS surveillance on IB EDG.
b.
(Closed) LER 366/91-19:
Inadequate Design Results in Failure of PCIVs to Close, and LER 321/92-03:
Failure of Solenoid Valves Causes Loss of Emergency Equipment Room Coolers.
Both LERs involved failures of electrical solenoid operated pneumatic control valves, manufactured by Automatic Switch Company (ASCO),
which failed due to lubricant problems. The first event addressed the installation of lubricators in several solenoid valves at various locations in the plant. The second event adoressed an i
internal failure of two solenoid valves which was attributed to a breakdown (gelling) of a silicone based lubricant.
In the first event, lubrication was being admitted into solenoid operated valvos that were designed to Le used only with oil-free air.
In the second event the gelling of the lubricant could have caused the solenoid core to stick in the energized position when de-energized. The two LERs documented lubricant problems that impacted at least 12 solenoid valves installed in four systems.
The corrective actions for both items included additional rettews and evaluations, special operating orders to increase the testing of the valves, implementation of temporary modifications, and replacement of the affected valves as necessary.
Followup reviews i
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by the licensee identified four additional systems potentially impacted by the solenoid valve problems. The identification of the involved failure mechanisms required detailed review by NSAC personnel.
Efforts were coordinated with personnel from other utilities.
In addition to the LERs listed above, Inspection Report 321,366/92-12 contains a discussion of the valve failures and the licensee's corrective actions.
The inspector reviewed two special operating procedures, one for each unit, 34SP-042992-DC-1-IS and 2-2S.
Each procedure gave step by step directions for testing of the valves, the requirement for independent verification, and documentation of the completed
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staps. The inspector reviewed the licensee's activities involving the replacement of affect valves.
Several MW0s were initiated to
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remove the lubricators and to clean the gelling lubricant.
i Removal of the lubricators were governed by temporary
modifications, 2-92-84 through 2-92-91, pending a permanent DCR.
Additional reviews by the inspector indicated that two DCRs were i
initiated and approved for installation to replace all safety I
r' lated ASCO solenoid valves, DCR 92-155 for Unit I valves and DCR 92-160 for Unit 2 valves. The inspector was informed that i
installation of the Unit 1 modification would start prior to the end of this report period.
The inspector will review the design i
implementation.
Bcsed on this review and the review discussed in Inspection Report 321,366/92-12, and initiation and approval of these modifications this item is closed.
j c.
(Closed) LER 321/92-09:
Personnel Error Results in Low Reactor
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Water Level and a Reactor Scram. This LER addressed a March, 1992 scram which resulted when a SS mistakenly opened a 600V MCC supply breaker and momentarily de-energized portions of the RFPT control system.
Inspection Report 321,366/92-08 contains a discussion of the scram. Correction actions included counseling of the involved personnel and the revision of several procedures. The most significant direct changes involved requiring that danger tags be utilized prior to electrical breakers being racked out.
The inspectors verified changes were made to the procedures utilized to manipulate the 600 VAC breakers. Additionally, since this event, the licensee has initiated a cot.prehensive program to increase the use of self verification by plant personnel to prevent such occurrences.
Several representatives from the NRR human factors assessment branch, during a visit to the site in October, 1992, reviewed this issue and a similar scram which occurred on June 25, 1992.
NRC concluded that inattention to detail on the part of the involved operators was the root cause of
both incidents. Additionally, the inspectors noted that a TS amendment to lower the reactor. level scram setpoint by about 10 i
inches was approved by the NRC in August 1991, the scram setpoint has not been lowered yet.
Lowering this setpoint will provithr
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additional time for operators to react to such incidents and possibly prevent unnecessary scrams. The implementation of the change is also a priority issue of the Hatch Scram Frequency i
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Reduction Committee.
Based on the review discussed in Inspection Report 321,366/92-08 and this review of the licensee's actions, this LER is closed.
d.
(Closed) LER 366/92-09:
Dersonnel T.. or Results in an Automatic Reactor Scram. This LER addressed 4 scram which occurred due to an operator de-energizing a 600 V bus by inadvertently operating the incorrect CR panel switch.
Inspection Report 321,366/92-15
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discussed the inspector's detailed review of this scram. As discussed in the above paragraph, the licensee initiated a formal self verification program. This event was also reviewed by personnel from the NRR Human Factors Assessment Branch and concluded that inattention to detail on part of the involved operator was the root cause. The opening of the 600 V bus 2C breaker resulted in a loss of power to the 2C bus, essential
cabinet 2A, and RPS 2A. The loss of instrument bus 2A caused the control valves in the main recirculation lines for the condensate, condensate booster and main feed pumps to fail open. This caused
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a loss of feedwater flow and reactor water level decreased. The
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MFPs tripped on low suction pressure (sequentially, as designed)
due to the opening of the CBP minimum flow valves.
As noted by the ERT, the simulator did not accurately model the loss of power to 600 V 2C bus in that this scenario did not result in loss of HFPs. A modification was completed to the simulator to correct this problem. The inspectors and the ERT noted that the fact that all the minimum flow valves are powered from one bus is an apparent design weakness, which is not necessary due to electrical
loading or plant configuration requirements. This issue is considered a priority action item by the Hatch Scram Frequency Reduction Committee. DCR 2H93-16 has been written and approved for implementation during the 1994 Unit 2 refueling outage. The DCR will separate the power supplies for at least some of the minimum flow valves. No plans have been addressed for the similar Unit I vulnerability.
Based on the review discussed in Inspection Report 321,366/92-15 and this review of the licensee's actions, this LER is closed.
e.
(Closed) LER 321/92-20:
Setpoint Drift Causes Unplanned ESF Actuation. This LER addressed an actuation of the Main Control Room Environmental Control System when the CR intake radiation monitor tripped. The typical reading of the monitor is approximately.6 millirem /hr.
Investigation after the trip
identified that the monitor trip setpoint had drifted from
.9 millirem /hr to about.7 millirem /hr. The cause of the drift could not be determined and during subsequent checks after it was
reset, the setpoint had not drifted again.
Routine review of the operation of the area radiation monitoring equipment by the
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inspectors has not identified any addition.I problems.
Based on
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this review of the licensee's actions, this LER is closed.
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f.
(Closed) LER 366/92-06:
Personnel Errors and Inadequate Communications Resulted in Non-compliance with TS. This LER
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i addressed a missed composite liquid radwaste sample. A tank was
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discharged without the required sample for input to the composite
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sample being obtained. The sample was inadvertently discarded and
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due to a comunici.tions error, an additional sample was not taken
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before discharge of the tank. A gama isotopic analysis of the
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tanks had been performed and the results recorded. A chemistry technician had discovered the error and informed the foreman, who i
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misunderstood the technician. The foreman understood the discussion to be referring to a tank not yet authorized for-l discharge.
In Inspection Report 321,366/92-15, this issue was _
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addressed as an example of inadequate communications. An audit'
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recently completed by SAER, identified weaknesses in areas closely related to the factors involved in this case. Management has i
initiated corrective actions. Based on this review of the i
licensee's actions, this LER is closed.
g.
(Closed) LER 321/92-17:
Inadequate Procedures Result in Violation-i of TS Requirements. This LER addressed the identification that
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both channels (in the same trip system) of the RB and Refueling Floor exhaust ventilation radiation monitoring system had been i
rendered inoperable during testing by several inadequate
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surveillance testing procedures. TS require that one channel in a
trip system be maintained operable while the other is tested (or
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an LCO must be entered). The deficiencies were caused by procedure directed inappropriate use of jumpers during the
testing. The problems were identified by NSAC personnel'during
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preparation of LER 321/92-16. Additionally, it was identified
that the Unit 2 Refuel Floor Exhaust Radiation Monitors were not
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completely tested, because an internal trip contact was not
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directly tested. The imediate corrective actions included entry i
into the appropriate TS LCO for 2 inoperable radiation monitoring
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channels in one trip system. Modifications and procedure changes l
will be made, in the future, to allow testing without rendering 2
channels inoperable. NCY 321/92-18-03:
Inadequate Radiation J
Monitor Testing Procedures, addressed this issue. Details of the l
inspectors review of the significance of the issue are presented
in Inspection Report 321,366/92-18.
Based on the review discussed
in that report and this review of the licensee's actions, this LER
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is closed.
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7.
Exit Interview
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The inspection scope and findings were sumarized on June 8,1993 with
those. persons indicated in paragraph 1 above. The inspectors described
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the areas-inspected and discussed in detail the inspection findings.
l The licensee did not identify as proprietary any of the material
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provided to or reviewed by the inspectors during this inspection.
Item Number Status Description and Reference
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t 321/93-08-01 Open VIO-Inadequate Functional Testing of
~j Main Steam Isolation Valve Limit
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Switch Circuitry, paragraph 2b.
321,366/93-08-02 Open VIO-Failure to Perform TS r
Surveillance Testing of the IB
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Emergency Diesel Generator, paragraph 3b.
321,366/93-08-03 Open VIO-Examples of Failure to Follow Procedure, paragraph 2b and 2d 8.
Acronyms and Abbreviations
- Alternating Current ADS - Automatic depressurization System A/E - Architect Engineer
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AGM-PO-Assistant General Manager - Plant Operations AGM-PS-Assistant General Manager - Plant Support AHU - Air Handling Unit APRM - Average Power Range Monitor
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ASME - American Society of Mechanical Engineers ATWS - Anticipated Transient Without Scram BWR - Boiling Water Reactor BWROG-Boiling Water Reactors Owners Group
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CB0 - Control Board Operator
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CFR - Code of Federal Regulations CO2 - Carbon Dioxide
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CR
- Control Room CRD - Control Rod Drive
CST -
Condensate Storage Tank
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CV
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Control Valve dc
- direct current
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- Deficiency Card DCR - Design Change Request DW
- Drywell ECCS - Emergency Core Cooling System
EDG - Emergency Diesel Generator EHC -
Electro Hydraulic Control System ERT -
Event Review Team i
ESF - Engineered Safety Feature
EST -
Eastern Standard Time F
- Fahrenheit FSAR - Final Safety Analysis Report F/T -
Functional Test FT&C -
Functional Test and Calibration
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- General Electric Company HP
- Health Physics HPCI - High Pressure Coolant Injection System HVAC - Heating, Ventilation and Air Conditioning I&C -
Instrumentation and Controls
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IFI -
Inspector Followup Item IRM -
Intermediate Range Monitor IST -
Inservice Testing i
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lb
- Pound LC0 - Limiting Condition for Operation LED - Light Emitting Diode LER - Licensee Event Report LLRT - Local Leakrate Testing LSFT - Logic System Functional Test MCC - Motor Control Center MSIV - Main Steam Isolation Valve MSLRM-Main Steam Line Radiation Monitors Mwe - Megawatts Electric MWO - Maintenance Work Order NCV - Non-cited Violation Nuclear Regulatory Commission NRC
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NSAC - Nuclear Safety and Compliance PCIS - Primary Containment Isolation System
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PE0 - Plant Equipment Operator
'
P&ID - Piping and Instrumentation Drawing PMMS - Plant Modification and Maintenance Support PRB - Plant Review Board
'
PSIG - Pounds per Square Inch Gauge
,
PSW - Plant Service Water System RB
- Reactor Building
'
RCIC - Reactor Core Isolation Cooling System RFP - Reactor Feed Pump RFPT - Reactor Feed Pump Turbine RG
- Regulatory Guide
.
RHR - Residual Heat Removal RHRSW-Residual Heat Removal Service Water System RPS - Reactor' Protection System
,
RPT - Recirculatory Pump Trip RTP - Rated Thermal Power
!
RX
- Reactor SAER - Safety Audit and Engineering Review SCOPE-Stop, Consider, Observe, Perform, Evaluate
,
SFP - Spent Fuel Pool i
SOS - Superintendent of Shift (0perations)
SPDS - Safety Parameter Display System SRO - Senior Reactor Operator
,
STA - Shift Technical Advisor TS
- Technical Specifications i
-
-
,
i