IR 05000324/1989020
| ML20248A925 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 09/14/1989 |
| From: | Dance H, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20248A908 | List: |
| References | |
| 50-324-89-20, 50-325-89-20, NUDOCS 8910030052 | |
| Download: ML20248A925 (34) | |
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' UNITED STATES o
NUCLEAR REGULATORY COMMISSION
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REGION la -
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j 101 MARIETTA STREET.N.W.
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ATLANTA, GEORGIA 30323
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Report No. 50-325/89-20'and 50-324/89-20 Licensee: Carolina' Power and Light Company P. O. Box 1551
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Raleigh,.NC 27602-Docket No. 50-325 and 50-324 License No. DPR-71 and DPR-62 Facility Name:
Brunswick 1 and 2 Inspection Conducted: August 1 - 31, 1989 Inspector: IId I
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'f//df/89 V. H. Ruland (/
Date Signed Other Inspectors:
R. E. Carroll, Jr.
W. Levis D. J. Nelson R. P. Schin R. B. Gibbs Approved by:
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Y H.1C. Dance, SecTion Chief
[ Tate S'ignbd Division of Reactor Projects SUMMARY Scope:
This routine safety inspection by the resident inspectors involved the areas of maintenance observation, surveillance observation, operational safety verification,10 CFR 21 reperting, TI 2515/93 - diesel generator fuel oil quality assurance, non-routine reporting program, onsite Licensee ".vont Reports review, in office Licensee Event Reports review, Brunswick Improvement Program, evaluation of licensee self-assessment and capability, and action on previous inspection findings.
Results:
In - the areas inspected, ten violations were identified:
(1) the licensee failed to promptly identify and correct corroded service water pump lubricating water piping supports.
Unclear communication contributed to the problem, s9100 h. bb
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The licensee. stated that they had received previous guidance from Region II at least 5 years ago concerning this issue. That guidance, the licensee claims, supported their current position. The licensee could not provide any documentation, Technical Specification interpretation, or amendment request that records such previous
discussions.
In some cases, the TS 18 month surveillance "during shutdown" requirement appears to be misapplied. Licensee action is required to properly disposition these cases.
f.
Thermal Power Level Exceeded License Limit l
During routine control room observation on August 24, 1989, at approximately. 7:30 a.m., the inspector observed that the Unit 1 Performance Computer printout indicated that thermal-power levels had exceeded the license limit of 2436 MWt by a small amount for six of the last eight hours:
Time MWt 12:00 a.m.
2438 1:00 a.m.
2438 2:00 a.m.
2438 3:00 a.m.
2437 4:00 a.m.
2438 5:00 a.m.
2437 6:00 a.m.
2435 7:00 a.m.
2435 This data indicates that the average power level for the eight hour period exceeded 2436 MWt.
Power level data prior to 12:00 a.m. was not readily available. The inspector reviewed the 8:00 a.m. process computer P-1 printout which indicated thermal power was 2436 MW. The inspector informed the shift foreman who had just assumed day shift duties.
He stated that this was an unsatisfactory condition that should not have occurred. The two control operators on shift were
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also unaware of the previous shift's power levels.
One operator
stated that the nuclear engineer was responsible for monitoring
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thermal power output. The licensee later informed the inspector that
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hourly power levels for the five hours prior to 12:00 a.m. (i.e.,
i from 7:00 p.m. to 11:00 p.m. on August 23) also exceeded the license limit:
Time MWt l
7:00 p.m.
2437 8:00 p.m.
2437 9:00 p.m.
2438 10:00 p.m.
2438 s
11:00 p.m.
2437 i
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' Consequently, the unit operated eleven consecutive hours in excess of the license thermal power limit. The licensee stated that process computer P-1 calculations for. the same - time periods corroborate the unit performance computer calculations. The process computer and the performance-computer independently calculates various plant paramaters including core thermal power.
The highest recorded power level during. this period, 2438 MWt, represents l e'ss than 100.1% power.. The NRC does'. not consider operation over the license limit by this small amount to be' safety.
significant considering instrument tolerances and other variables involved in the-determination of actual power.. Additionally, per -
FSAR table 6.3.3-1, the LOCA analysis is performed using an' initial power level of 2531 MWt.
However, the NRC is concerned with this case from the-standpoint of-operator actions and responsibilities.
i The power level was consistently over the license' limit for almost an
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entire shift. Operators.on that shift were either unaware of or J
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chose not to correct the situation. Operators on the day shift were.
unaware of the previous shift's operation,: indicating that.the power -
level data was not reviewed 'during sh1ft turnover.
0perators must
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monitor ' reactor power level from all available sources and. assure that the~ average power level for any '8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period does not exceed
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the full steady-state licensed power. level. The licensee initiated action to include the thermal power level as a parameter to be'
formally monitored in the' operator's Daily Surveillance Record.
QA issued an NCR (S-89-076) for this issue on August 28,:1989.
The Unit I racility Operating License, DPR-71,. states that the licensee is authorized to operate the facility at steady-state reactor core po' er levels not in excess of'2436 megawatts thermal.
w The operation described above is not in accordance with the license and is therefore a Violation: Thermal Power Levels Exceeded License
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Limit (325/89-20-09).
Five violations were identified.
5.
10 CFR 21 Reporting (36100)
The purpose of this inspection was to determine if the licensee has established and = implemented procedures and controls to ensure the reporting of defects and noncompliance.
Regulatory Compliance Instruction 06.4, BSEp Compliance With 10 CFR 21, revision 4, is. the licensee's governing instruction for satisfyingi hese requirements. This t
procedure - provides posting requirements, screening requirements, an evaluation worksheet, controls to. ensure that a responsible officer and j-NRC are informed, when required,. along with the appropriate references, l
definitions and assignment of responsibilities.
The licensee posts Section 206 of the Energy Reorganization Act along with i
a description of 10 CFR 21 procedures, to whom to report defects and noncompliance, and the location of current copies of the regulations.
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l These items are posted ct bulletin boards in the Administration Building, the entrance to the t -v'.:e Building, and at the construction entrance.
The inspector verif &J che bulletin board postings.
The number and specific locations of the bulletin boards was adequate.
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The Regulatory Compliance organization screens all NRC report violations, NCRs, LERs, special reports, vendor / supplier nonconformance notifications,
plant incident reports and other items as determined by the director of
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Regulatory Compliance for Part 21 reporting applicability. The screening i
determines if evaluation is required for Part 21 purposes.
If the screening of the document determines that no evaluation is required and the reasons are not clearly understood as to why the item is not reportable, the rationale is documented and forwarded to Document Control.
If the screening determines that evaluation is required, the item is logged and tracked in the licensee's FACTS system.
The inspector reviewed two records of evaluated deviations where the j
licensee determined the items were not reportable under Part 21 i
requirements. The evaluations, contained in FACTS items 89B0239, 8980493, and 89B0335, were accomplished consistent with the licensee's procedures
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and appeared to be factual and complete.
The inspector determined that
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the licensee's conclusien with respect to deportability was logical based i
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The inspector also reviewed one I
evaluation where 'the licensee determined the defect was reportable.
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responsible officer was informed, but the Commission was not notified. In this case, it was clear that NRC was already aware of the defect ( and i
issued an Information Notice) and the licensee's rationale for not reporting was sound.
The inspector reviewed two purchase orders for Q-list equipment.
One purchase order was produced by computer and the other manually produced.
Both purchase orders clearly stated that the provisions of 10 CFR 21 were applicable. The licensee's records concerning their Part 21 review and documentation process were satisf actory.
They maintain records of all evaluations, notifications and all written reports. The records reviewed by the inspector were well tracked and easily retrieved.
Violations and deviations were not identified.
6.
Temporary Instruction 2515/93 (25593)
(OPEN) Temporary Instruction 2515/93, Inspection for Verification of QA Request Regarding Diesel Generator Fuel Oil Multi-Plant Action Item A-15.
In response to problems at other operating reactors concerning diesel generator fuel oil, the NRC issued a letter dated January 7, 1980, to all power reactor licensees requiring that diesel fuel oil be included in the
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licensee's QA program.
TI 2515/93 was issued to perform followup
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inspection of this requirement.
The licensee responded by letter dated April 29,1980, that diesel generator fuel is included in the Brunswick QA program..On February 8,1989,. the licensee's QA organization identified that diesel - fuel oil was listed as a Q-list consumable in the Plant Operating Manual, but was not' being procured. as such.
QA initiated Non-Conformance Report S-89-015 for this discrepancy.
In an-interim response to this NCR, the licensee stated that it is currently Cp&L policy to purchase - all - diesel oil through the fuel department's fossil fuel section. However, Technical Support agreed that diesel generator fue1~ oil should be. procured as safety-related. The licensee. justifies continued use of the current purchasing arrangement until a corporate-wide decision--
is reached on any necessary changes.
This justification is based on continued compliance with all Technical Specification sampling.
requirements for the diesel fuel. This issue will remain open pending completion of the licensee's NCR process.
Violations and deviations were not identified.
7.
Nonroutine Reporting Program (90714)
This inspection reviewed the licensee's procedures for compliance with NRC reporting requirements as specified in 10 CFR 50.72 and 50.73.
The inspector reviewed the licensee's procedures for reviewing Maintenance Work Requests (WR/J0s), Engineering. Work Requests, and Nonconformance Reports, including:
MMM-003, Corrective Maintenance (Automated Maintenance Management System), Revision 2 01-39, Handling of Work Request / Job Orders, Revision 013 OI-51, NRC 1-Hour, 4-Hour, and 24-Hour Reporting Requirements, Revision 003 ENP-20, Engineering Work Request, Revision 010 PLP-04, Corrective Actior Program, Revision 1 RCI-06.5, NRC Reporting Requirements, Rev. 8 01-51 and RCI-06.5 were compared with 10 CFR 50.72 and 50.73.
In addition, the inspector interviewed personnel responsible for performing deportability reviews in Operations, Technical Support, and Regulatory Compliance.
Also, he reviewed samples of WR/J0s and EWRs for which a i
deportability determination had been completed.
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The inspector found that WR/J0s 'are initially reviewed for deportability and safety importance by the shift foreman and the shift ' operations
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supervisor, with the exception of certain specified non-safety equipment that was exempt from this review.
The WR/JO format has a required checkoff for LC0 (Y/N). The LC0 format has a required checkoff for Red Phone (Y/N).
Thus the SF and SOS review WR/J0s for deportability and formally checkoff for all cases except those that do not require a red phone report.
In addition, Regulatory Compliance informally reviews operator logs for reportable conditions.
EWRs receive an initial review for deportability by a Technical Support engineering supervisor, and a checkoff for deportability (Y/N) is required. However, the engineers who perform this determination are not well qualified to do it, for they are not trained in deportability requirements, plant systems, or plant operations.
NCRs are reviewed for deportability by a Regulatory Compliance licensed operator.
However, no formal checkoff for deportability is done.
In conclusion, the licensee's procedures for compliance with NRC reporting requirements are adequate, but the EWR review should be performed by others more qualified to make a deportability determination. This item will be reviewed in subsequent routine NRC inspections.
Violations and deviations were not identified.
8.
Onsite Review of Licensee Event Reports (92700)
The below listed LER was reviewed to verify that the information provided met NRC reporting requirements.
The verification' included adequacy of event description and corrective action taken or planned, existence of potential generic problems, and the relative safety significance of the event.
Cnsite inspections _were performed and it was concluded that necessary corrective actions have been taken in accordance with existing requirements, licensee conditions and commitments.
I (CLOSED) LER 1-89-11, Failure to Perform Reactor Jet Pump Surveillance Testing Prior to Entering Operational Condition 2.
On April 4,1989, at 6:58 p.m., Unit 1 entered operational condition 2 during restart following an outage. At approximately 10:45 a.m. on April 5, 1989, an operator determined that jet pump operability surveillance required by TS 4.4.1.2.2
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had not been performed, as required, prior to entry into operational I
condition 2.
The surveillance was then satisfactorily performed at 11:00 a.m.
The licensee reported that the surveillance was missed due to oversight by control room personnel in the review of the control operator's Daily Surveillance Report.
Corrective action consisted of employee counseling and procedure revisions. The inspector reviewed the procedure revisions to General Plant Operating Procedure GP-1, Operating Instruction 01-3.1, and 01-3.2.
l The failure to perform the required surveillance constitutes a violation of Technical Specification 4.4.1.2.2, Reactor Coolant System Jet Pumps Surveillance Requirement This licensee identified violation is not being cited because criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied. Non-Cited Violation: Jet Pump Surveillance Not Performed Prior to Startup (325/89-20-10).
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One non-cited violation was identified.
9.
In Office Licensee Event Report Review (90712)
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The below listed LER was reviewed to verify that the information provided met NRC reporting requirements.
The verification included adequacy of event description and corrective action taken or planned, existance of potential generic problems, and the relative safety significance of the event.
(CLOSED) LER 1-89-12, Manual HPCI Isolation Due to Steam Leak Detection Instrumentation Operating Outside of Normal Range.
Violations and deviations were not identified.
10. Brunswick Improvement Program (92703)
This inspection was conducted to help NRC management determine whether the BIP order (EA-82-106, dated December 22, 1982) should be continued or rescinded.
As indicated in the DET report (dated August 2, 1989),
although short-term improvements in safety performance occurred at Brunswick following implementation of the BIP, there was a general failure on the part of CP&L corporate and site management to ensure those BIP-related improvements were sustained and broadened.
Accordingly, the approach of this inspection was to determine if the long-term BIP items (i.e., those which were to be on going to assure continued improvement)
were still in place and were effective. To facilitate this determination, the inspectors correlated the DET report findings to BIP action items.
The inspectors concluded that the below findings and BIP' areas were related:
DET Paragraph / Finding Related BIP Item 2.1.1.1 (3.1.1 and 3.1.2) - Delays VII-1:
Implementation of MAC in organizational changes (i.e.,
recommendations to enhance and CDO).
strengthen management control and organizational discipline 2.1.1.3 (3.1.3) - Inadequate necessary to provide for safe and corporate oversight, leadership reliable operation.
and direction.
2.1.1.4 (3.1.1 and 3.1.2) -
Traditional culture still prevalent despite recent corrective action measures.
2.1.1.5 (3.1.3) - Receitt actions towards meaningful wnrking goals; indications of improvement in team work and communications. (positive)
2.1.1.7 (3.1.4) - Inadequate corrective action program.
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paragraph 11. i. ; (2) an inadequate post-maintenance test was specified on a containment atmosphere dilution valve.
An adequate test would have revealed that the valve's manual override was shut, paragraph 11.j. (2); (3) two procedure problems -- incorrectly throttling a positive displacement pump discharge valve to a test tank, causing a relief valve to lift, paragraph 4.d; failure to include a manual valve override in a system operating valve lineup, paragraph 11.j.(1); (4) failure to adequately test secondary containment, such that the licensee operated outside the tested configuration twice (i.e., the inside railroad doors were left open, unlike the test that proved operability),
paragraph 4.b.; (5) an inadequate standby liquid control equipment clearance affected both systems' pumps, not just one pump as planned, paragraph 4.c.; (6)
during one 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift, Unit I was operated in excess of the license thermal limit without the operators taking effective action, paragraph 4.f. ; (7) a relief valve surveillance for the SLC system was done with Unit 2 at power, but-the Technical Specifications indicate that the test shall be done while shutdown, paragraph 4.e.; (8) the Onsite Nuclear Safety group is a member of the site incident investigation team, thereby failing to maintain its independence, paragraph 10; (9) the licensee stopped performing actions required by a Confirmatory Order (Brunswick Improvement Program) - quarterly nuclear saftey review meetings were not held, paragraph 10; and (10) a jet pump surveillance was not performed prior to startup.
This is a non-cited violation, paragraph 8.
The licensee's reporting programs were judged to be sound, with only a minor weakness in the qualifications of personnel who review. engineering work requests, paragraphs 5 and 7.
The licensee has started an infrared thermography examination program..This program significantly improves the licensee's ability to detect certain electrical / bearing problems before failure, paragraph 2.
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REPORT DETAILS 1.
Persons Contacted I
Licensee Employees K. Altman, Manager - Engineering Projects F. Blackmon, Manager - Operations l
- S. Callis, On-Site Licensing Engineer i
T. Cantebury, Manager - Unit I Mechanical Maintenance
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- G. Cheatham, Manager - Environmental & Radiation Control
- K. Chism, Shift Foreman
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M. Ciemnicki, Security R. Creech, Manager - Unit 2 I&C Maintenance W. Dorman, Manager - QA K. Enzor, Manager - Regulatory Compliance V. Grouse, Employee Relations
- J. Harness, General Manager - Brunswick Nuclear Project W. Hatcher, Supervisor - Security
- A. Hegler, Supervisor - Radwaste/ Fire Protection
- R. Helme, Manager - Technical Support l'
J. Holder, Manager - A. 'ge Management & Modifications (OM&M)
- M. Jones, Manager - On-Site Nuclear Safety - BSEP R. Kitchen, Manager - Unit 2 Mechanical Maintenance
- R. LaBelle, Shift Operating Supervisor
- J. O'Sullivan, Manager -- Training
- R. Poulk, Supervisor - Regulatory Programs W. Simpson, Manager - Controls and Administration S. Smith, Manager - Unit 1 I&C Maintenance
- R. Starkey, Project Manager - Brunswick Nuclear Project R. Warden, Manager - Maintenance B. Wilson, Manager - Nuclear Systems Engineering Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force members.
NRC Employees
- R. Holbrook, Region II License Examiner
- Attended the exit interview Acronyms and initialisms used in the report are listed in paragraph 15.
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2.
. Maintenance Observation (62703)
The inspectors observed maintenance activities, interviewed personnel, and reviewed records to verify that work was conducted in accordance with-approved procedures, Technical Specifications, and applicable industry codes and standards. The inspectors also verified. that redundantL components were operable; administrative controls were followed; tagouts were adequate; personnel were qualified; correct replacement parts were used; radiological controls were proper; fire protection was adequate;.
quality control hold points were adequate and observed; adequate.
post-maintenance testing was performed; and independent verification requirements were implemented. The inspectors independently verified that selected equipment was properly returned to service.
Additionally, outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenance.
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i The inspectors observed / reviewed portions of the following maintenance activities:
MI-16-585 Repair Seat Leak of SLC Valve C41-V2
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89-APKB1 1A Nuclear ~ Service Water Pump Mechanical Seal
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Replacement
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89-ASLB1 Filter Unit 2 HPCI Oil Sump 89-ATJC1 Diesel-Driven Fire Pump Starter Motor Replacement The inspector reviewed the licensee's program of predictive maintenance using infrared thermography.
The licensee purchased a portable system made by Thermoteknix.
The system provides the user with a real time display of an equipment's thermal signature and records the data on a video tape for later analysis. That analysis is supported by a software package that can generate custom color disp 1sys, histograms, graphs, and-i l
color photographs.
The licensee controls the program using, at this stage, an informal procedure issued July 3, 1989, by the technical support I
manager. A dedicated engineer runs the program and evaluates the data.
The licensee has included all major electrical transformers.and electrical equipment in the program with an initial quarterly periodicity.
The licensee retains tapes of operating equipment for future comparisons.
The licensee found a bus duct heater that was energized and a corroded Caswell Beach (non-safety) transformer connection using thermography. The inspector judged the licensee's program as a significant addition to their.
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overall preventative maintenance program, j
i Violations and deviations were not identified.
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3.
Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical Specifications. Through observation, interviews, and record review, the inspectors verified that tests ' conformed to Technical Specification requirements; administrative controls were followed; personr.el were qualified; instrumentation was calibrated; and data was accurate and complete. The inspectors independently verified selected test results and proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following test activities:
IMST-RPS24M RPS Reactor Vessel LLI Trip Unit Channel Calibration IMST-RPS42R RPS and PCIS Reactor Mode Switch Bypass Logic Test 2MST-RWCU22M RWCU Steam Leak Detection Channel Functional and Setpoint Adjust Violations and deviations were not identified.
4.
Operational Safety Verification (71707)
The inspectors verified that Units 1 and 2 were operated in compliance with Technical Specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records, and independent verification of safety system status.
The inspectors verified that' control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met. Control operator, shift supervisor, clearance, STA, jumper / bypass logs, and daily and standing instructions were reviewed to obtain information concerning operating trends and out of service safety systems to ensure that there were no conflicts with Technical Specification Limiting Conditions for Operations.
Direct observations were conducted of control room panels, instrumentation
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and recorder traces important to safety to verify operability, and that l
operating parameters were within Technical Specification limits.
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inspectors observed shift turnovers to verify that continuity of system l
status was maintained. The inspectors verified the status of selected control room annunciators.
The senior resident inspector held daily meetings with the plant manager l
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to discuss plant events and operations.
The inspectors attended daily coordination meetings once or twice a week to further evaluate management's control of plant activities.
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Operability of a selected Engineered Safety Feature division was verified weekly by ensuring that each accessible valve in the flow path was in its correct position; each power supply and breaker was closed for components.
that must activate upon initiation signal; the RHR subsystem cross-tie valve for each unit was closed with the power removed from the valve i
operator; there was no leakage of ma.jor components; there was proper
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lubrication and cooling water available; and a condition did not exist which might prevent fulfillment of the system's functional requirements.
I Instrumentation essential to system actuation or performance was verified operable by observing on-scale indication and proper instrument valve lineup, if accessible.
The inspectors verified that the licensee's health physics policies / procedures were followed.
This included observation of HP practices and a review of area surveys, radiation work permits, posting, and instrument calibration.
The inspectors verified that the security organization was properly manned and security personnel were capable of performing their assigned functions; persons and_ packages were checked prior to entry into the PA; vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo identification-badges; personnel in l
vital areas were authorized; effective compensatory measures were employed when required; and security's response to alarms was adequate.
The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, verified certain clearances, and verified the operability of onsite and offsite emergency power sources.
The inspector reviewed records of medical examinations of licensed operators.
This review was conducted to determine licensee compliance with Subpart C of 10 CFR 55, Medical Requirements.
Specifically, the inspector compared sampled medical records against the licensee's certification as documented for the NRC.
No discrepancies were found.
Specific items found:
a.
Valves Out of Position The inspector noted that the licensee found two valves out of position during the report period. On August 18, 1989, the shift foreman, while making his tour, found control building ventilation system valve 2-VA-U-V181/8 of a turn open instead of full open as required by the operating system valve lineup contained in OP-37, revision 17, Control Building Ventilation System Operating Procedure.
This valve is the instrument air dryer outlet isolation valve and supplies all the air for damper control in the control building
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ventilation system. If this valve were shut sufficiently to restrict all flow, the' Control Building Emergency Air Filtration system would be inoperable. The licensee is still evaluating how the valve-got -
partially shut. On August 25, 1989, the licensee performed SP-89-45,
- Control Building ' HVAC Damper Test With the 2-VA-U-V18 Throttled, demonstrating the operability of the system in the "as found" condition.
On July 16, 1989, at approximately 9:35; p.m., the C0 found
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l 1-CAC-SV-1260 indicating shut at the control board (RTGB) instead of open as required by the operating system valve lineup' contained in 1-0P-24, revision 32, Containment Atmosphere Control System Operating Procedure. 'This valve is the outboard sample inlet valve for the drywell ventilation radiation monitor - l-CAC-AQH-1260.
With this valve shut the radiation monitor was inoperable.
The. licensee determined that the valve was shut at about 9:30 a.m. that same day, while the HP personnel were changing out the~ filtersi for~ the radiation monitor.
Communication problems between the HP and the CD resulted in the C0 not reopening the valve after-the filter was -
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changed out.
During this time, other radiation monitors required by Technical Specifications were operable'.
The two occurrences of valves out of position, which -are discussed above, are not isolated cases.
As noted in the follow-up of. a previous inspection finding (see paragraph 11.j), the manualL override -
for 2-CAC-CV-2714, the B train vaporizer inlet valve, was-found shut.
This prevented the operators from placing.the B train CAD vaporizer in. service from the control room. The operating valve lineup for the system contained in OP-24 does not list this manual override.
Certain licensee personnel performed well in finding these valves out of position.
However, management must take appropriate action to prevent future mispositioned valves.
Further, all of ~ the above valves are subject to the independent verification requirements of the plant's Administrative Procedures.
b.
Railroad Doors The inspector found the Unit 1 inner reactor' building railroad door open on August 1, 1989, at approximately 11:00 a.m.
The unit was in operational condition 1 with fuel handling activities, associated with the loading of the fuel cask, in progress on the refueling.
floor. The inspector noted that a fire protection LCD was in effect due to an inoperable fire seal, but no LCO existed' for secondary-containment. When the licensee performs their secondary containment verification test, PT-15.4, revision 14, to verify that SBGT can maintain.25" of negative pressure in the reactor building at ' 3000 scfm, the tested configuration has all airlock doors shut.
The'
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6, inspector reasoned the licensee was operating outside the bounds of their tested configuration and felt the inner railroad door should be shut, especially with the fuel handling activities in progress. -The inspectoit informed the Unit 1 SF of his concern.
The SF had;the-inner door shut and informed -the inspector that the door had been
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opened _- to bring the fuel cask into the reactor building.
When upending the cask it is necessary to move the railroad cars, which requires that the inner door be open. After completing this effort,
.the licensee failed to shut the door.
E&RC-0582, revision. 0,
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Handling the IF-300 Cask, stated that the inner door could remain open during the entire evolution of raising, loading and lowering the cask with operations permission unless plant conditions require-closing. In this case, the operations personnel were unaware of the open door.
The door had-been opened on July 31, 1989, at approximately 1:30 p.m.
The inspector discussed the issue with the personnel in charge of the fuel handling evolution. They acknowledged the inspector's comments.
The licensee changed their procedures.to limit the time that the inner door-could be open to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, which coincides with the Action Statement requirement for Secondary Containment, Specification 3.6.5.1.
The' inspector also discussed the issue with the system engineer concerning the adequacy of their PT in demonstrating L
secondary containment integrity' with only one of the two doers shut.
The. inspector stated that the test was' inadequate. The seals must be I
tested individually if the licensee chooses to operate for extended periods with one door open. The system engineer. acknowledged the inspector's comments, but felt that one. seal was sufficient and satisfied the Technical Specification. requirement concerning the definition of secondary containment, which requires that only one of the two doors be shut..
On August 24, 1989, the inspector found the Unit 2 inner railroad door open with the unit in operational condition 1.
The Unit 2 SF-had the door shut after the inspector reported the problem.
The l
licensee found that the door had been open for about 17-hours to move equipment into the building for the upcoming refueling outage.
On August 23, 1989, operations issued a memorandum to the shift
,
l operating supervisors. requiring initiation of a secondary containment I
LCO and appropriate action whenever the railroad doors are expected
open for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The memo was in routing when the.
'
inspector found the second instance.
l The inspector determined that both railroad doors must remain shut
!
while unattended to ensure. that secondary containment integrity is.
i maintained. With either door open, the current surveillance test conditions for secondary containment are not duplicated.
However, l
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the safety significance of having one door open appears minimal. The inspector believes that SBGT will still maintain a negative pressure on the reactor building with only one ' door shut.
The inspector checked accessible portions of the Unit I and Unit 2 outer doors and found no gross. leakage paths.
Based'on these facts the inspector concluded that the secondary containment integrity was-maintained,
.
but that the test which demonstrates this condition, PT-IS.4, was inadequate.
This inadequate surveillance test is a Violation:
Inadequate Secondary Containment Integrity Test,. (325/89-20-05. and-
.
324/89-20-05).
c.
Insufficient Clearance Boundary on Standby' Liquid Control System On August 3,1989, with Unit 2 at full power, maintenance on the
.
standby liquid control system revealed that an insufficient clearance boundary had been established. While attempting to replace SLC pump-2A relief valve, 2-C41-F029A, water flowed from the valve discharge flange when the flange. was. loosened.
The maintenance personnel stopped the led by retightening the flange.
The leak ' occurred because clearance 2-886 neglected to shut the' common suction valve from the SLC storage tank to both pumps. 'Since the pumps' relief valves discharge to the pump suction, a flow path existed from the SLC tank to the relief valve. The clearance was intended to only remove the A SLC pump from service; but the personnel who determined and reviewed the clearance boundary-failed to recognize the common pump suction arrangement which requires removing both pumps from servit.e simultaneously. As a result,. both ' pumps became INOPERABLE, since the common suction pressure boundary had been disturbed. This placed the SLC system into an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> LCO Action. Statement in accordance with Technical Specification 3.1.5.
Subsequently, the relief valve flange was properly decertified and the LCO was cancelled.
Further evaluation by the licensee concluded that the B pump was not made INOPERABLE, therefore, the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Action Statement did not apply.
This conclusion was supported by previous calculations done by the licensee for a prior SLC draining issue (see L
URI 325/89-02-03 closed in inspection report 89-05)
l The licensee attributes the insufficient clearance to - personnel error, for the system drawings used were clear and. concise.
In addition, the clearance review process failed to detect the error.
The reviewer, a licensed senior reactor operator, stated he failed to.
detect the error because he had a mindset that the SLC pumps could be removed from service individually for the relief valve work.
Due to past clearance problems, the licensee had previously established a Clearance Center to remove the burden of clearance processing from control room personnel.
They felt that personnel whose sole responsibility was to process clearances were.less likely
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to commit errors.
The inspectors consider the Clearance Center concept to be sound; however, the insufficient SLC clearance discussed above demonstrates that further improvements are necessary.
The insufficient clearance constitutes a violation of Technical
)
'
Specification 6.8.1.a.
This is a Violation:
Inadequate Clearance (324/89-20-06).
d.
Leak at the SLC B Pump Suction Flange On August 4,1989, the SLC A relief valve was successfully replaced under the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Action Statement.
Entry into the Action Statement is required since the correct clearance requires the suction valve
!
common to both pumps to be shut. On August 6, 1989, the SLC B relief l
valve was likewise replaced.
During the subsequent fill and vent operation, a significant leak developed at the SLC B pump suction flange.
This occurred while the SLC A pump was running, taking suction from the demineralized water source and discharging to the SLC test tank. This operation is controlled by operating procedure OP-5, SLC System, Section 8.1, Filling and Venting, and is conducted locally at the SLC station.
During the initial valve lineup, but before the pump was started, a flow path was established from the SLC tank to the test tank. This action started to raise' level in the test tank. As the test tank filled, the operator attempted to slow the rate of fill by throttling shut the return-to-test-tank valve, C41-F017. The operator then started the SLC pump with F017 still throttled. Since the SLC pumps are positive displacement, throttling has no affect on flow rate but increased the pump discharge pressure.
Pressure increased to greater than the relief valve setpoint, causing the A relief valve to lift, thereby pressurizing the pump suction piping, since the relief valve discharges to the common pump suction.
The increased pressure was sufficient to cause a leak at the B pump suction flange.
However, no other joints leaked.
The actual increase in pressure was unknown, but is small because the running pump is recirculating the relief valve discharge. When the joint was disassembled for repair, it was evident that the gasket had not been properly compressed, thereby explaining the joint failure with relatively low pressure. The licensee stated that this flange probably had not been disassembled since original construction.
After reassembly of the flanged joint, the A pump was returned to service (within the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Action Statement time frame) based on the licensee's evaluation that an actual overpressurization of the suction piping did not occur.
The B pump was returned to service following testing of the reassembled joint.
The licensee's root cause analysis and any further corrective action concerning the improper assembled flange joint will be reviewed during future inspections.
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f.
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Operating procedure OP-5 contains instructions to provide sufficient volume in the test tank prior to starting the pump.
If the tank becomes too full, instructions are provided for draining.
The-operator's attempt to throttle the flow to the tank-is not in accordance with this procedure.
In addition, this action demonstrates a lack of; knowledge of the operation of positive displacement pumps. This is a Violation (first example): Failure to Follow SLC Operating Procedure (324/89-20-02).
SLC Relief Valve' Surveillance During Power Operation-e.
The licensee performed the SLC relief valve replacement discussed above to meet Technical. Specification surveillance requirement 4.1.5.c.3.
This requires SLC relief valve set points to be demonstrated to be 14501 50 psig, "At least once per 13 months during shutdown...." In this case, the licensee did not satisfy the
"during shutdown" requirement, in that Unit.2 was in power operation at the time.
The licensee stated that the "during shutdown" requirement appears in. numerous TS
month surveillance requirements, some of which cannot be met without a dual unit outage.
Diesel Generator Surveillance 4.8.1.1.2.d.1, Diesel Engine Inspection, is a good example of this since the diesels are common to both units. In some cases, "during shutdown" was interpreted to mean
"during system shutdown."
Other TS 18 month "during shutdown" surveillance clearly cannot be accomplished during operation or are constrained by other LCOs;4 such an example is the Drywell-Suppression Chamber Vacuum Breakers Surveillance 4'.6.4.1.c, Opening Set Point Verification, which requires torus entry, breeching primary containment, and, therefore, necessitates shutdown of the unit.
Still other TS 18 tnonth surveillance do not contain the "during shutdown" requirement.
In the case of SLC, relief valve testing requires valve removal since the system is not instrumented for in place testing. Valve removal requires entry into an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Action Statement.
The inspectors
-
concluded that it is reasonable to expect this surveillance to be performed with the unit shutdown instead of completely disabling the system during power operation.
Therefore, the "during shutdown" requirement is appropriate. The surveillance was due on March 22, 1989.
Considering the 25% overdue allowance granted by Technical Specifications, August 6 became the overdue date. ~ Unit 2 recently completed a forced outage that could have accommodated this surveillance while shutdown, The licensee stated that because of an error in the STSS data base, this surveillance was not flagged to.be accomplished during the forced outage. STSS indicated that an outage was not required for the performance of the surveillance. Conducting the SLC relief valve surveillance during power operation constitutes a violation of Technical Specification 4.1,5.c.3.
This is a Violation: Performing a "During Shutdown" Surveillance Test While at Power (324/89-20-08).
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2.1.1.9 (3.1.6) - Current ma w ement i
s team capable to establish safety j
culture and improve plant
performance. (positive)
2.1.5.2 (3.5.2) - Inadequate corrective action program.
2.1.6.12.a and b (3.6.2.2.1 and 3.6.1.1.2) - CD0 transition poor; instability of technical support unit.
2.2 - Lack of corporate support; inadequate corrective action program; CD0 poorly implemented.
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2.1.2.6 (3.2.3) - Cumbersome 11-2: Modify or develop necessary procedures; strict procedural plant trocedures; ensure clear, adherence not exhibited by unambiguous, precise, etc.;
several operators.
subject to PAM.
V-2:
Develop training program to cover the discipline of operations, procedural compliance and philosophy of conservatism with respect to regulatory compliance.
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2.1.4.4 (3.4.1.3) - PAM not 11-2:
(See DET 2.1.2.6 above.)
effectively implemented.
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2.1.4.6 (3.4.1.4) - Inadequate surveillance controls tt mermit I
proper evaluation of SW pump l
performance.
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2.1.2.14 (3.2.6.6) - RTT V-1:
Upgrade training in
excellent in areas of industry post-modification aspects of plant concerns and plant systems and components.
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I modifications. (positive)
V-5:
Upgrade training in industry-wide events, incidents,
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and operating experience reports.
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2.1.5.5 (3.5.5 and 3.4.1.2) -
VI-4:
Special investigative DNS not reviewing industry activities to include prompt advisories or efforts to reduce review of human factors summary personnel errors.
reports.
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2.1.4.1 (3.4.1.1) - STSS I-1:
Establish program for effective (positive); however, identifying, scoping, scheduling, no schedule to verify accuracy tracking, and closing all TS of TS Data Base.
surveillance requirements and regulatory commitments-and requirements.
II-3.A:
CNS to review surveillance procedures used to meet regulatory requirements for technical adequacy - (Data Base referred to in DET 2.1.4.1 originally verified under this item).
III-3 and 4:
QA to perform 100 percent review of TS every 3 years; corporate to periodically audit QA surveillance.
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2.1.4.2 (3.4.1.2) - Inadequate II-3.A and III-3 & 4:
(See DET TS interpretations regarding 2.1.4.1 above.)
offsite to onsite electrical distribution system.
2.1.4.3 (3.4.1.2) - Some CIVs not stroke time tested per TS.
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2.1.5.6 (3.5.4) - 100 percent III-3 & 4:
(See DET 2.1.4.1.
)
review of TS surveillance every above.)
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3 years by QA nnt properly implemented.
.______________._____________________
2.1.4.10 (3.4.3.2) - Failure to IV-1: Continue post-maintenance ensure adequate post-maintenance
. program to ensure maintenance testing on safety-related activities do not degrade or equipment.
render inoperable any component, system, or instrument.
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(Any NRC follow-up on the above BIP items will be performed during the post DET inspection effort.)
Based on the above correlation of DET findings to related BIP items, it was determined that six additional areas of the BIP warranted further inspection. The inspection results of these additional BIP related areas are summarized below.
BIP Objective III:
Increase Frequency and Scope of QC Surveillance
and Corporate Auditing Program Activities.
One of the DET findings in this area (paragraphs 2.1.5.6 and 3.5.4)
stated that QA was no longer performing a -100 percent review of TS requirements every three years as specifiec in BIP Item III-3. The DET report further indicated that the sampling method now being utilized by QA to review TS requirements (based on January 1983 corporate QA interpretation of BIP commitment) was flawed.
Accordingly, this finding put in question four other periodic reviews that were also addressed in the licensce's letter of October 26, 1987, as being modified from the original BIP commitments.
These other four periodic reviews involve:
(1) inservice inspection / Appendix J (BIP Item III-1); (2) commitment verification (BIP Item III-1); (3) TS amendments (BIP Item III-2); and (4) regulatory requirements changes (BIP Item III-2).
Like the QA review of TS requirements, periodic reviews (1) and (2) also utilize the same sampling process.
The effects of using this sampling process and any subsequent improvements, with respect to all three of these periodic reviews, will be addressed in the licensee's response to the DET report.
As indicated in the above referenced letter, periodic reviews (3) and (4) were subsequently captured by the routine QA surveillance program.
A review of related QA surveillance program procedures (QAP-303, Regulation Surveillance; QAP-302, Technical Specification Surveillance Program; and OQA-201, Surveillance Program) and documentation of related surveillance performance, indicates that the objective of BIP Item III-2 continues to be met.
BIP Objective V (Action Item 7):
Establish a Formalized System to Ensure That Timely Training Is Provided to Appropriate Personnel Regarding New Procedures and Procedural Revisims.
The current Administrative Procedures, Vol. I, Bk.1, Revision 121, requires that a procedure change summary for significant changes be routed to the Manager - Operations for inclusion in operations standing instructions. The Real Time Training unit, Operations Real Time Training, 01-33, Revision 7, section 4.5.3, requires review of operating manual revisions to identify procedure changes that thould be reviewed by on-shift cperators. The inspector concluded that the licensee continues to meet this objective.
- BIP Objective VI: More effectively utilize the technical expertise of-the 0NS and CNS staff in enhancing the safety and reliability of plant operations (Action Items 1-5).
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VI-1:
Reassign some of the
. independent ' review function responsibilities offsite to provide increased opportunity for direct plant observation.
This item was accomplished through the offsite-reassignment' of such independent' review functions as reportable events, unreviewed ' safety questions,-FSAR. changes, TS changes, etc.
Corporate Nuclear. Safety Procedure CNSP-1 (CNS section organization, responsibilities, and '
training) reflects the assignment of those review functions-offsite.
The inspector noted, however, that the DET report-(Paragraphs 2.1.5.5-and 3.5.5). identified that ONS was. not reviewing. all NRC/ industry-advisories as indicated in TS 6.2.3.2, but shared the responsibility with Regulatory Compliance and Technical Support. Any, followup of the shared responsibility issue will be addressed during the DET -
follovup.
-VI-2:
Initiate a program of periodic reviews of safety system challenges and reactor transients.
This item was accomplished through the -implementation of ONSI-3, Revision 3, (0NS Field Observations and Special-Investigations). The inspector verified, through documentation review, that DNS was and-continues to perform such reviews.
In light of the TS.6.2.3.2 requirement for DNS to provide " independent. verification", the inspector questioned the validity. of DNS being a member on the
,
plant's Site Incident ' Investigation. Team (SIIT) as specified in.
RCI-06.6 (Site Event Investigation Process). In the same light, the inspector was. informed that on two occasions (September 13, 1986 and October 21,1988) ONS filled in as the SIIT leader in the absence of Regulatory - Compliance.. In a hand-written message - to Regulatory Compliance, dated July 14, 1988, ONS expressed an " independence" concern with respect to - functioning as the SIIT : leader and recommended that the unaffected unit's operations engineer be designated as the backup team leader.
Although _ no.such-specific backup designation is reflected-in RCI-06.6, _.the SIIT leader / chairman, during the June 17, 1989 loss of offsite power event in Unit 2, was the Unit 1 operations ~ engineer.
The inspector
. concluded that with ONS as part of the formal SIIT, they were not free of start-up schedule pressures and not. sufficiently independent.
While the inspector. found no ~ specific. problem that ONS failed to identify due to the lack of independence, their. participation -as a SIIT member does not meet the current ~ Technical Specification
_
requirements.
There are no procedural controls in place to ensure -
ONS remains independent. This is a Violation: ONS Not Independent During Surveillance of Facility Activities, such as Post Trip Reviews (325/89-20-04 and 324/89-20-04).
The inspector recognizes that the CP&L ONS function has made positive-contributions to plant-safety in the-past (i.e.,
scram reduction program, PRA, initiation of the SIIT process, etc....) and is not a typical organizational group.in the Brunswick vintage Technical.
Specification.
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VI-3:
Increase emphasis on direct surveillance and walk through activities - to include frequent reviev of operation's logs, direct observation of individual actions, adv0nced identification of activities to be reviewed, and written reports which summarize i
activities and results, as well as noted de "iciencies and
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recommendations.
l This item was accomplished through the implementation of ONSI-3.
The inspector verified that ONS was and continues to perform such activities through review of ONS field observation ' quarterly reports and related open followup items list.
The inspector concluded that the licensee continues to meet this BIP item.
VI-4:
Increase effort on special investigative activities -- to include prompt reviews of incident and human factors summary reports with followup evaluations as needed; increased sensitivity to the conduct of special investigations as established by CNS or operations with followup reports and recommendations.
This item was accomplished through the implementation of DNSI-3.
The performance of special investigations by ONS was verified through review of related documentation.
The latest such investigation concerned the June 17, 1989 loss of offsite power event in Unit 2, which was performed in conjunction with INP0.
Upon inquiry, the inspector was informed that ONS no longer reviewed human factors summary reports, as the plant discontinued such reports as of July 18,1985.
Along the same lines, it should be noted that the DET report (Paragraphs 2.1.5.5 and 3.5.5) identified that ONS was not performing functions to reduce personnel errors as indicated in TS 6.2.3.2.
VI-5:
Hold quarterly Corporate Nuclear Safety Review Board meetings to discuss selected issues arising from the routine independent review program and ISEG (ONS) program.
Based on review of CNSRB meeting minutes and discussion with the Director - ONS, the inspector determined that the meetings were held l
quarterly until 1986.
However, the Board met only twice in 1987 and held their last meeting in September,1988.
Review of the minutes also indicated that the BIP established charter of the CNSRB was being met.
However, as of 1987, the CNSRB failed to meet quarterly as required, and have not met for almost a year.
The CNSRB was not i
formally disbanded although the issue was discussed at the December i
1987 meeting.
The licensee claims that the CNSRB functions have been i
replaced by other routine meetings and reviews already conducted.
This is a Violation:
Failure to Implement the BIP (325/89-20-07 and l
324/89-20-07).
1
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BIP Objective VII (Action Item 2): Initiate. Study to Reduce Outside
Demands on Plant Staff to Allow More Attenti.,n to Operations and Maintenance.
The inspector reviewed the Management Analysis Company study dated l.
January 10, 1983.
Based on the inspectors' observations of the -
l plant staff the past four years, the licensee remains sensitive to
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the issues raised by this report. Licensee actions in this area have included restricting zincoming phone calls to the control room, closing the control room window during shift tunrover, implementation of various computer administrative control systems, 'and pre-work review and. planning by. the site work force control group.
The inspector concluded that this BIP item continues to be met.
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BIP Objective VII (Action Item 3):
Commence INPO Assessment of l
Operational Activities, CNS, Corporate / Plant Interface, and PNSC Activities.
'
The inspector reviewed the available on-site documentation to verify completion of the audit and licensee action on the recommendations.
While no formal report was available for review, the inspector saw evidence of the visit and a compilation of recommendations.
Personnel were assigned completion responsibility.
The inspector concluded that certain issues raised by INPO still exist as-problems at Brunswick. However, the~ root cause of the issues are reflected in the findings of the DET. Therefore, no further followup or action on this BIP item is required by NRC.
- BIP Objective VII (Action Item 5):
Develop implementation schedule for appropriate recommendations of the Essex Corporation Human Factors Study.
The September 1, 1981'Essex Corporation Human Factors Study addressed in this item was done in accordance with the early guidance provided in NUREG/CR-1580.
Subsequent NRC guidance / requirements warranted further update of this study, which was performed _ under the BSEP Control Room Design Review Program Plan.
As this -- plan and its implementation has been reviewed / evaluated by NRR (onsite inspection
+
the week of May 15,1989), no further action regarding this BIP item is required.
Two violations were identified.
l 11. Action on Previous Inspection Findings (92701) (92702)
a.
(CLOSED)
Violation 324/88-15-01, Improper Change in Operational Condition. The inspector reviewed the licensee's response to the violation dated ~ August 24, 1988, the supplemental response dated
.
September 26, 1988, and reviewed the status of ~ licensee commitments l
made during a May 17, 1988 Enforcement Conference documented in a June 17, 1988 Enforcement Conference Summary letter.
The licensee has performed training on this event for all operations personnel and have included the lessons learned.into their present license training j
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program. The inspector verified that the appropriate procedures were revised to clarify when a mode switch change constitutes a change in operational condition and that additional instructions for ' returning the mode switch to shutdown following completion of testing requiring repositioning of mode switch were provided when necessary. Training for. SR0s as managers was also conducted to reiterate the management responsibilities of their position, b.
(CLOSED). Violation _324/88-18-03,: Control Rod Withdrawn During Condition 5 With Shorting' Links Installed. The. inspector read the licensee's response to-the Notice of Violation and verified that the corrective' actions taken were as stated. In response to NRC concerns involving operator inattentiveness, _the licensee has implemented logkeeping requirements for the ' control operator and provided training to both the operations personnel and plant supervisory personnel concerning the importance of observing and responding to trends as adverse conditions. The inspector has verified, through direct observations, that the logkeeping requirements coupled with the present licensee requirement to have an additional control operator on shift, have improved the licensee's ability to find and correct potentially adverse conditions indicated in the control room a re a'.
The number of deficient conditions found by the inspector in the control room area, which were not known by the operators, has decreased since these latest requirements were. imposed.
The inspectors will continue to closely monitor this area to ensure'that this trend continues.
c.
(CLOSED) Violation 324/88-18-04, Failure to Adequately Control RCS Temperature. The inspector reviewed the licensee's response to the Notice of Violation.
There were two major contributors. to this event.
Fi rst, the operators did not adequately monitor the appropriate plant parameters. When the reactor is shutdown, reactor coolant temperature is a plant parameter that must be known by the operators at all times.
As stated in the closeout of Violation 324/88-18-03 included in this report, the inspector has observed that i
the licensee has improved in their monitoring of plant status through the use of logkeeping and the stationing of an additional operator in the control room.
In addition, the. licensee has developed a dedicated ERFIS screen for shutdown conditions that displays the l
appropriate parameters to monitor while,the plant is in a shutdown.
condition.
The second contributor to the event.was the misapplication of a gateL valve. During low decay heat removal conditions, the licensee was t
i using the RHR Heat Exchanger Outlet Valve, a gate valve,-to throttle RHR flow to further limit cooldown.
To address this issue,. the licensee has provided more explicit directions in their RHR Operating.
Procedure for when and. how this valve can be used in throttle applications. The licensee will also replace these valves with one that is designed for throttle purposes by Refuel Outage 8 (1992).for Unit 1, and Refuel Outage 9 (1991) for Unit 2.
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(CLOSED)
Violation 325/88-45-01, Failure to Have SBGT Operable During Fuel Handling Operations.
The inspector reviewed the
.
licensee's response to the Notice of Violation dated April 17, 1989.
The licensee has modified the SBGT inlet and outlet valve position indication at the local control panel and on the RTGB to accurately reflect valve position. The indications, which are shared with both the inlet and outlet valves, will indicate open only if both valves are full open, and will indicate shut only if both valves are shut.
If either of the valves is intermediate, no indication will be provided. In addition, the licensee reviewed the RTGB to determine if other indications could provide misleading information to the operators. The technical support review of the operations' supplied list of pctential misleading indications determined that there were no additional modifications needed for improvement of RTGB indications. Technical support also concluded, in a separate review, that they would not change the initiation logic for the Unit 1 inlet and outlet valves to automatically open on system actuation.
The licensee has also labeled all MCCs in the reactor building, diesel building, and the service water building to reflect normal valve position or equipment conditions.
For valves, a red (open),
green (closed), black (deenergized) or white (either open or closed or throttled) dot is provided above the valves associated indicating light at the MCC to reflect normal valve position.
For equipment such as fans or motors, the same color dots will be used to reflect if the component is normally running, not running, deenergized or cycles on and off.
The inspector has verified through direct observation, that these dots are provided in the above locations.
The licensee also plans to label all remaining MCCs in other buildings in the plant with this same marking scheme.
The plant general manager conducted a briefing for each of the j
operations shifts concerning this event and the associated reactor
{
building damper event. The briefing described the circumstances of i
the events and provided personal guidelines for his expectations of the operations staff.
The inspector reviewed the outline of the briefing and verified through review of documentation, that each of the briefings was conducted.
The inspector also reviewed the training materials for secondary j
containment. The study guide for Secondary Containment, 15-2B, dated
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March 27, 1989, was updated in the Industry Events section to reflect i
the unrecognized loss of secondary containment. The inspector noted that on page 10 the material states that an automatic initiation of SBGT will open both the SBGT inlet and outlet isolation valves. As noted previously in Inspection Report 88-45, this is true for Unit 2
only.
The Unit 1 SBGT inlet and outlet isolation valves do not receive an automatic open signal.
This discrepancy was discussed with the training department who agreed that the material should be
changed to specify Unit 2 only.
The inspector verified that the correct information was supplied in the study guide for SBGT,15-2F, i
and that the correct information was presided in the System l
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Description for SBGT, SD-10, which is available.for the operations staff ~to use in the control room, e.
(CLOSED)
Violation 325/88-45-02, Failure to Have Reactor _ Building Secondary Containment During Fuel.Handl.ing Operations. The' inspector
,
l reviewed the licensee's response to the -Notice of-Violation dated
, April 17,1989 and the supplemental response dated June ' 26,1989.
The licensee modified their design for the Unit I reactor. building i
dampers such that the a'ir supply is divisionalized and a latching.
mechanism provides positive seating upon loss of air. The' Unit 2 ~
reactor building dampers are scheduled for this same modification during the upcoming refJeling outage beginning September 1989.
In the meantime, the licehsee has hung a caution tag on the Unit 2 instrument air valves which,-if shut, could cause. loss of air to the.
dampers without an alarm. A diesel air compressor in the switchyard would provide an emergency source of air to the dampers during a LOCA coincident with a Loss-of-Offsite Power. An auxiliary operator tests the air compressor daily.
A clearance error was a contributor to the event. As noted in the supplemental response, a clearance center has been established to resolve clearance and other work control issues.
As noted.in Inspection Report 88-14 and in paragraph 4.c of this report concerning the SLC issue, continued attention is sti11 warranted.in this area and NRC will continue to monitor it closely.
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(CLOSED)
Violation 325/88-45-03, Failu're to Have Secondary Containment During Fuel Handling Operations. This item collectiv,eiy
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grouped the inoperable SBGT and inoperable reactor building dampers l
as a ;oss of secondary containment integrity. The individual items
were inspected in the closecut of violations 325/88-45-01 and 325/88-45-02 addressed in this report.
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(CLOSED) Violation 324/89-05-03, Inadequate Surveillance of Stored-Pressure Dry Chemical Fire Extinguishers. 'The licensee's corrective
actions consisted of instruction.to involved ~ personnel and-
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appropriate disciplinary action.
The inspector. reviewed the
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licensee's assembled documentation and had no further questions.
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(CLOSED)
Violation 325/88-14-01, Missed Surveillance of Reactor l
Vessel Temperature and Pressure During Inadvertent Heatup.
This violation involved a January 25, 1988 inadvertent Unit I reactor coolant system heatup of about 90 degrees (120 degrees F to 210 degrees F). This heatup occurred over a.1.75 hour8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> period during which the reactor. vessel temperature and pressure were not determined
at least once per 30 minutes, as required - by TS 3.4.6.
The l
licensee's response, which was acceptable to the NRC, included three l
corrective actions:
(1) Establishment of requirements to monitor. the reactor vessel temperature evary 30 minutes when in shutdown cooling.
The inspector reviewed 01-03.4, Daily Check Sheets, Revision 018.
l The OI includes a Control Operator Daily Check Sheet, which
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l requires that, when in shutdown cooling, the reactor coolant
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temperature be recorded in the CO log every 30 minutes. For the RHR-logs in service, the' RHR. heat exchanger inlet and outlet temperatures are to be recorded.
In. addition, the reactor vessel shell temperature is required to be recorded-in the CO-log once each shift.
. (2) Development of a special display for the ERFIS/SPDS terminal as an. operator aid, which 'provides the key parameters in graphic form. The inspector' reviewed the SPDS. shutdown display, which displays RHR heat exchanger outlet temperature, : including a number, a bar chart, and a graph of.the last 30 minutes. This-temperature display actually monitors the higher of the RHR heat exchanger inlet or outlet temperatures for the RHR loop in service, as determined by flow and inlet valve position.
Upper and lower limits of 195 F and 100 F' are included, which, if exceeded, will change the display color of. the RHR temperature -
(number and bar chart) from green to red.
The shutdown display also.shows reactor. vessel pressure, water level, recirculation loop suction temperature, and cooldown/heatup rate. During normal shutdown cooling,'this cooldown/heatup rate is based on recirculation loop temperature.
The SPDS shutdown ' display aids the operator, but the inspector found, during interviews, that operators did not understand: the information being displayed. They did not know what instruments were used to provide the cooldown/heatup rate or the RHR heat exchanger outlet temperature.
This information was not available to them in the SPDS displays. In' fact, the-inspector found that only one person in the plant had this information, the person who designed the. shutdown-' display.
The cperators should be able to readily determine what their indications are'
telling them. The inspectors will review any licensee action to correct or improve the shutdown display during future routine inspections.
(3) Real-time training of appropriate operations personnel-on this i
event.
This training ' was reviewed 'and found acceptable-in
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Inspection Report 325,324/88-14.
In ' addition, the inspector i
reviewed daily Operations ' Standing Instructions from the~ June,
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1989 Unit I outage, and verified that a' reactor. coolant'
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temperature band to be maintained was specified, including upparz and lower limits (150 to 190 F). The inspector also reviewed
'l the.C0 log for that outage and verified that temperatures were
recorded as described in (1) above.
In the C0 log, the following
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temperatures were recorded every 30 minutes: RHR heat exchanger
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inlet, outlet, service water out, and vessel shell temperature,
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The inspector reviewed the drawings for both ' units' Residual Heat Removal System to determine the. location in the shutdown cooling flowpath of the. heat exchanger inlet and outlet temperature elements.
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In each case, the inlet temperature element is located between the RHR heat exchanger and its inlet isolation valve.
The. outlet temperature element is located downstream - of the heat exchanger outlet isolation valve and also downstream of where the heat exchanger bypass line ties in.
Thus, if the heat exchanger outlet valve became inadvertently closed (as it did in.this event), the inlet temperature element would see no flow and would give an erroneous indication of reactor vessel temperature. But, the outlet temperature element would still see flow, with the bypass valve normally open, and would give a good indication of reactor vessel temperature.
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(CLOSED)
Unresolved Item 325/89-07-02 and 324/89-07-02, Service Water Pump Lubricating Water Piping Support Operability. This item was unresolved pending the outcome of the licensee's seismic analysis of the corroded supports and further evaluation of the communications problem encountered among _the licensee's staff concerning the corrosion of the supports and their affect on operability of -the service water pumps. The licensee's seismic analysis of the lube water support structure with corroded supports was inspected by NRC as documented in Inspection Report 89-22. The inspection determined that the licensee's analysis, which demonstrated that the piping met their short term structural integrity requirements, was satisfactory.
The second part of this issue concerned the communication problem between plant management and the technical support staff, and the resultant lapse in evaluating and dispositioning the matter in a timely manner. To address this issue, the-licensee conducted a Human Performance Evaluation System review of the event.
Among the conclusions of the study were the following:
Sufficient information was available to write an NCR on March 31, 1989.
Communications were hampered by the acting technical support manager, who was unaware of the first two problem supports identified on March 7, 1989 and March 8, 1989.
The third pump with an identified lube water support corrosion problem, also had other supports with identified corrosion problems which were under evaluation for operability.
These other problems contributed to the confusion.
The evaluator could not conclusively determine what plant management was told concerning the status of the third pump.
Plant programs and procedures strongly support. the identification of problems. However, the perception exists that raising operability concerns is sometimes resisted.
The inspector concluded that an NCR should have been generated before April 5, 1989.
The first corrosion problem, 1 of 3 lube water supports broken, was identified by NRC on March 9, 1989, for NSW
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pump 2A.
On March 10, 1989, the licensee confirmed the inspectors:
finding and found an additional lube water support for.1B CSW pump broken. On March 15, 1989, the BESU seismic evaluation.of the broken j
support determined that the broken support rendered the associated
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service water pump inoperable. At this time, an NCR should have _been generated,; as this condition of corroded supports represented a significant. condition adverse to quality.
Certainly, on March 31, 1989, after identification of the third corroded support and the resulting potential inoperability of its associated pump, an NCR was required. It was not until April 5,1989, after questioning.by the inspectors, that an NCR was. generated.
Following issuance _of the NCR, the licensee took appropriate action to correct the corroded j
lube water supports.
In all,' 9 of the 10 service wahr pumps-had
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corroded,or severely corroded supports, some of which nad corroded in two.
The failure to promptly identify, evaluate, and resolve this.
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issue and its potential generic implications is a Violation:
Corroded
.1 Service Water Pump Lubricating Water Piping Supports, (325/89-20-01 and'324/89-20-01).
The inspector noted that the evaluator's comment concerning the resistance to report problems was also a comment' noted in the DET report.
In order for the plant's programs and procedures concerning the reporting of problems to be effective, licensee personnel must understand that-plant management supports _ and encourages the identification of concerns. _ If necessary, this concept must be reinforced.
This item was discussed with plant management.
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(CLOSED) Unresolved Item 325/89-14-05 and 324/89-14-05,. Mispositioned
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CAD Valve.
(1) Further investigation by the licensee determined that. the manual override valve for 2-CAC-CV-2714 was closed, which prevented 2-CAC-CV-2714 from opening as would be required for nitrogen j
injection into the drywell.
The valve was apparently _ shut I
i during repair activities associated with the rep'lacement of the
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actuator air accumulator for the CV-2714 valve. The clearance which covered this, 2-0660, did not specify this valve to be j
shut..
It did, however, reference EER 89-0127R0 which specified I
that the valve would need to be manually closed to ensure proper
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isolation of_the system. In addition, the valve lineup for the
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system contained in 1-0P-24, Containment Atmosphere Control j
System, Revision; 32, does not identify-this manual override.
The P&ID for the CAD system also does not show the manual j
override for this valve. The _ inspector could not determine how
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the valve was closed, and the licensee is still continuing their investigation.
Their response. date to the NCR which was generated on this issue is--September 9, 1989. The shutting of the manual override and. valve removed the remote operation
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capability from that division of the CAD system. The fcilure to reopen this valve following the maintenance work is the result of an inadequate clearance, improper work. controls, and an
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inadequate operating procedure ulve lineup.
This is a-j l
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Violation (second example):
Inadequate CAD Procedure (325/89-20-02 and 324/89-20-02).
(2) In addition to the problems noted above, the system was declared operable on June 7, 1989. The only retest requirement specified
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on WR/JO 89-AHGEl was to verify that.the system did not leak-following installation of the-new accumulator. This accumulator-is part of an " airlock fail-safe" system that ensures that valve CV-2714 will close upon loss 'of instrument air.
Upon loss.of instrument air, a pneumatic snap-acting relay switches. to a secondary air source which is the 180 cubic inch air accumulator tank. The secondary air source will automatically ensure that the valve is closed and remains closed. The retest, which only tested for. leak tightness, was not satisfactory.
With air removed during the course of the work, the slide valve would align such _that air would be shut to the close side of the valve from the accumulator.
If, after work was completed ' and the relay or pneumatic slide valve stuck, the CV-2714 valve could not be opened remotely.
A proper retest, therefore, would at the minimum cycle the valve to ensure the valve was operable.
In addition, the design feature of the accumulator itself, that ensures the CV-2714 valve remains shut on loss of instrument air, should also have been checked. Had the test been adequate,
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the shut manual override would have been discovered. This is a
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violation:
Inadequate Post Maintenance Testing of CAD System
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(325/89-20-03 and 324/89-20-03),
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(CLOSED)
IFI 325/87-03-04, _ Inadequate Board Walkdown and Review.
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This IFI involved an instance where, on February 13, 1987, valve 1-E11-F0078 (the Division II RHR minimum flow valve) was improperly left open through two shift turnovers. The licensee has incorporated the requirements of Standing. Instruction 87-014 for walkdown of the control board during shift. turnover into 0I-02, Shift Turnover Checklist, Revision 28. The inspector reviewed the current 01-02 (Revision 32), which ' requires the following board walkdown by the
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oncoming shift:
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(1) Control Operator walkdown prior to relieving the shift, with
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initials required.
l (2)' Shift Foreman / Senior Control Operator walkdown prior to relieving the shift, with initials required.
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(3) Shift Foreman, Senior Control Operator, or Shift Operating.
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Supervisor walkdown with the Control Operator after relieving i
the shift, with initials required, i
Walkdown (3) above is identified with an RI in the left margin of the procedure, which labels it as a commitment to the NRC.
Three violations and no deviations were identified.
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l 12.
Evaluation of Licensee Self-Assessment Capability (40500)
The module's objective, evaluate the effectiveness of the licensee's self-assessment programs, was completed through other evaluations. The Diagnostic Evaluation Team reviewed the licensee's organization, independent safety group, and problem resolution in detail. Further, the licensee contracted with CRESAP, a consultant, for a third party evaluation of their conduct of operations. No further inspection is required in this area during this SALP cycle. The follow-up of the DET and CRESAP findings will be performed next cycle.
Violations or deviations were not identified.
13. Design, Design Changes and Modifications (37700)
An evaluation of engineering design and technical support is included in paragraph 3.6 of Diagnostic Evaluation -Team (DET) Report.
Based on review of this section of the report - the inspection requirements of Inspection Procedure 37700 were adequately covered.
Credit for performing this inspection module is taken based on +he results of the DET report.
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14.
Exit Interview (30703)
The inspection scope and findings were summarized on September 1,1989, with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below. The licensee discussed the report findings with th? inspectors at length, and the plant general manager stated that they plan to deny
Violation 324/89-20-08. Proprietary information is not contained in this report.
Item Number Description / Reference Paragraph 325, 324/89-20-01 VIOLATION
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Corroded Service Water Pump Lubricating Water Piping Supports, (paragraph 11.1).
325, 324/89-20-02 VIOLATION - Failure to Follow SLC Operating
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Procedure and Inadequate CAD Procedure, l
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(paragraphs 4.d and 11.j.(1)).
325, 324/89-20-03 VIOLATION - Inadequate Post Maintenance Testing
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of CAD System, (paragraph 11.j.(2)).
325, 324/89-20-04 VIOLATION
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ONS Not Independent During Surveillance of Facility Activities, such as Post
Trip Reviews, (paragraph 10).
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325, 324/89-20-05 VIOLATION - Inadequate Secondary Containment Integrity Test, (paragraph 4.b).
324/89-20-06 VIOLATIEN Inadequate Clearance, (paragraph
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4.c).
325, 324/89-20-07 VIOLATION Failure to Implement the BIP;
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Quarterly Nuclear Safety Review Meetings Not Held, (paragraph 10).
324/89-20-08 VIOLATION - Performing a "During Shutdown" Surveillance Test While at Power, (paragraph 4.e).
325/89-20-09 VIOLATION - Thermal Power Levels Exceeded License Limit, (paragraph 4.f).
325/89-20-10 VIOLATION (Not Cited) - Jet Pump Surveillance Not Performed Prior to Startup, (paragraph 8).
Licensee management was informed that eight previous violations, two URIs, and one IFI discussed in paragraph 11 were closed during this inspection.
15.
Acronyms and Initialisms A0 Auxiliary Operator BESU Brunswick Engineering Sub Unit BIP Brunswick Improvement Program BSEP Brunswick Steam Electric Plant BWR Boiling Water Reactor CAD Containment Atmospheric Dilution J
CBEAF Control Building Emergency Air Filtration I
CD0 Central Design Organization CIV Containment Isolation Valve CNS Corporate Nuclear Safety CNSRB Corporate Nuclear Safety Review Board CO Control Operator CSW Conventional Service Water DET Diagnostic Evaluation Team DSR Daily Surveillance Report E&RC Environmental & Radiation Control EER Engineering Evaluation Report ERFIS Emergency Response Facility Information System ESF Engineered Safety Feature EWR Engineering Work Request
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F Degrees Fahrenheit
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FACTS Facility Automated Commitment Tracking System l
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GP General Procedure HP Health Physics HPCI High Pressure Coolant Injection HPES Human Performance Evaluation System I&C Instrumentation and Control IE NRC Office of Inspection and Enforcement IFI Inspector Followup Item INPO Institute of Nuclear Power Operations IPBS Integrated Planning, Budgeting and Scheduling ISEG Independent Safety Evaluation Group LER Licensee Event Report LCO Limiting Condition for Operation LIV Licensee Identified Violation LOCA Loss of Coolant Accident LOOP Loss of Offsite Power MAC Management Analysis Corporation MCC Motor Control Center MWt Mega Watts Thermal NCR Non-Conformance Report NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation NSW Nuclear Service Water
Operating Instruction ONS Onsite Nuclear Safety OP Operating Procedure P&IO Piping & Instrumentation Data PA Protected Area PAM Procedures Administration Manual i
PCIS Primary Containment Isolation System l
PNSC Plant, Nuclear Safety Committee PRA Procabilistic Risk Assessment psig Pounds per Square Inch Gauge PT Periodic Test QA Quality Assurance QC Quality Control RCS Reactor Coolant System RHR Residual Heat Removal'
RPS Reactor Protection System i
RTGB Reactor Turbine Gauge Board RTT Real Time Training SBGT Standby Gas Treatment scfm Standard Cubic Feet per Minute SF Shift Foreman SIIT Site incident Investigation Team
SOS Shift Operating Supervisor
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SPDS Safety Parameter Display System SRO Senior Reactor Operator STA Shift Technical Advisor j
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STSS Surveillance Tracking Scheduling System TI Temporary Instruction TS Technical Specification URI Unresolved Item WR/JO Work Request / Job Order
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