IR 05000245/1988005
| ML20154J748 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 05/12/1987 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20154J731 | List: |
| References | |
| 50-245-88-05, 50-245-88-5, NUDOCS 8805270119 | |
| Download: ML20154J748 (15) | |
Text
, -
,
..
.
.
.
.
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-245/88-05 Docket No.
50-245-License No.
OPR-21 Licensee:
Northeast Nuclear Energy Company Facility:
Millstone Nuclear Power Station, Unit 1 Inspection At: Waterford, Connecticut Dates:
' March 22, 1988 through April 25, 1988 Inspectors:
William Raymond, Senior Resident Inspector Lynn Kolonauski, Resident inspector Jin Chung, Reactor Engineer, Special Test Programs Reporting Inspector:
Lynn Kolonauski s
Approved by:
cme. C A M. ),
5"/12 /P7 E. C. McCabe, Chief, Reactor Projects Section 18 Date Inspection Summary: Inspection from March 22 - April 25, 1988 (Report No.
50-245/88-05)
Areas Inspected: This inspection included routine NRC resident and specialist in-spection of previously identified items, plant operations, physical security, potential fouling of the ECCS suction strainers by fibrous insulation, the August 1987 Containmerit Integrated Leak Rate Test (CILRT) results, surveillance, Temporary
,
Instruction 2515/90, licensee event reports, and committee activities.
Results: The inspection identified no unsafe plant conditions.
Further licensee and/or inspector followup is warranted on: (i) application of 10 CFR 50.72 and 50.73 reporting requirements (Section 3.3); (ii) recent actions involving locked high radiation areas (Section 3.4); (iii) resolution of the ECCS suction strainer issue (Section 6.0); and (iv) remaining items from TI 2515/90 on the scram dis-charge volume (Section 9.0)
!
l G805270119 880517 PDR ADOCK 05000245 Q
.
.
.
.
.
.
<
TABLE OF CONTENTS Page 1.0 Persons Contacted....................................................
2.0 Summary of Facility Activities.......................................
~
3.0 Status of Previous Inspection Findings...............................
3.1 UNR 88-02-01: Revision to OP-310, "Fuel Pool System"............
3. ' UNR 87-33-02: Remaining Items from TI 2515/90, "Scram Discharge L
Volume Capability"................................
3.3 VIO 87-33-01: Failure to Report APR Check Valve Failures per 10 CFR 50.72......................................
2-3.4 UNR 88-03-01: Unlocked High Radiation Area (HRA) Doors..........
4.0 Facility Tours and Operational Status Reviews........................
4.1 Safety System Operability.......................................
4.2 Review of Plant Incident Reports (PIRs).........................
4.3 Standby Gas Treatment Walkdown.................................
5.0 Security.............................................................
6.0 Potential Fouling of ECCS Suction Strainers..........................
7.0 August 1987 Containment Integrated Leak Rate Test (CILRT) Results....
8.0 Surveillance.........................................................
9.0 Update to UNR 87-33-02: Remaining Items from TI 2515/90, "Scram Discharge Volume Capability".........................................
10.0 Licensee Event Reports...............................................
11.0 Plant Operations Review Committee.....................
...........
12.0 Management Meetings..................................................
i
.-
-
.
.
DETAILS 1.0 Persons Contacted J. Stetz, Unit 1 Superintendent R. Palmieri, Operations Supervisor P. Przekop, Instrumentation and Controls Supervisor D. Odland, Maintenance Supervisor W. Vogel, Engineering Supervisor N. Bergh, Assistant Operations Supervisor The inspectors also contacted other members of the Operations, Radiation Pro-tection, Instrumentation and Control, Production Test, Maintenance, and Engi-neering departments.
2.0 Summary of Facility Activities Millstone 1 operated at nominal full power throughout the inspection, with normal power reductions for routine surve.illance activities and main condenser backwashing. A power reduction was also conducted on March 24 to plug main condenser tubes.
3.0 Status of Previous Inspection Findings (93702)
3.1 (Closed) UNR 88-02-01: Revision to OP-310, "Fuel Pool System." During follow-up on the spent fuel pool overflow event of January 29, 1988, the inspector determined that difficulty in using OP-310 (due to the number of interim changes attached to the procedure) contributed to the event's cause. The inspector expressed this concern to the Operations Supervisor,
'
who later initiated revisions to both OP-310 and OP-260, "Biennial Review of Operations Procedures." The latest revision of OP-310 has not yet been issued, but the Plant Operations Review Committee (PORC) reviewed and approved the proposed revision on April 23.
By reviewing the PORC-approved revision to OP-310, the inspector determined that incorporation of the interim changes would help prevent future spent fuel pool over-flows.
l To avoid future confusion caused by interim changes, the revised OP-260
requires that all operations procedures and data sheets be revised if any interim change is written against the OP. The previous issue only required that the procedures be reviewed; it did not require the reviewer to consider the impact of interim changes in determining whether a pro-cedure should be reissued.
The inspector concluded that revised OP-260 will reduce the potential for confusion caused by interim changes in (
operations procedures.
The inspector had no further questions, l
l l
l l
l
r_______
_ _ _ _ _ _ _ - _
. _ _ _ _ - _ _ _ _ _ _ _ _ _ _ -.
._
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ - - _ _ _ _ -
--
_ _ _ _ _ _
,.
.
'
,
3.2 (0 pen) UNR 87-33-02: Remaining Items from Temporary Instruction (TI)
2515/90, "Scram Discharge Volume Capability."
Three criteria from the TI (E, F, and K, as presented in NRC IR 50-245/87-33) remained open fol-lowing the original inspection.
Each has been addressed by further in-spection (see Section 9.0) but the item remains open.
3.3 (0 pen) VIO 87-33-01: Failure to Report APR Check Valve Failures per 10 CFR 50.72. This item was previously reviewed in Inspection 88-03. The inspector met with licensee management and technical personnel on various occasions during this inspection to discuss the reporting criteria and its bases in view of the guidance provided in NUREG 1022. No resolution was achieved.
The NRC evaluation has been that the intact but seismically unqualified (at.the time) headers were not operable for a design basis event, and that the check valve leakage was reportable because design basis oper-ability was not assured based on available information. The licensee position, as provided in his November 20, 1987 letter, remained that the APR check valve failures were not reportable since the APR valves were not inoperable in the "as found" condition in November 1985, and since the nitrogen supply lines to the accumulator headers were intact.
The licensee stated further that he did not review the check valve degrada-tion in light of postulated accidents since that was the usual approach taken to address reportability under 10 CFR 50.72(b)(2)(iii).
Postulated accidents were only considered when reviewing deficiencies for report-ability under 10 CFR 50.72(b)(2)(1).
However, during a telephone con-ference with NRC Region I management on March 24, 1988, the licensee deferred to the staff's position and stated that a report would be made for future events of the type cited in the violation.
The licensee responded to the violation by letter dated April 14, 1988.
The management position on reporting was discussed in a meeting between the Vice President - Nuclear Operations and the Station and Unit Super-
,
l intendents.
The licensee stated that, as a result of the discussions
'
i with the NRC staff, if a similar plant condition is found to exist in the future, the NRC would be promptly notified pursuant to 10 CFR 50.72.
The licensee's sensitivity to issues of significance similar to that of the failed leak test discussed in the notice of violation will be re-
viewed on subsequent routine inspections.
Other licensee actions taken
!*'
for this item, as described in his November 20, 1987 letter, were re-viewed and found acceptable in Inspection 81-33.
A further example of the difference in the NRC's and licensee's approach to the 50.72 reporting criteria was identified during this inspection (see Section 6.0).
During a meeting between NRC and licensee senior management on April 28, it was determined that further review of this issue is warranted.
This item remains open pending further review of the respective positions to understand the bases for the differences and to achieve agreement on reporting criteria.
l
.
, _ _.. _ _ _ _ _ _. _. _ _ _ _ -.
_..., _ _. - _ -
..
.
l
3.4 (Open) UNR 88-03-01: Unlocked High Radiation Area Doors. As discussed in Section 9.0 of NRC IR 50-245/88-02, Millstone 1 uses contact readings for obtaining whole body dose rates for the designation of locked high radiation areas (HRAs). Millstone 3 Technical Specifications (TSs)
specify that these dose rate readings be taken at 18 inches; the Mill-stone 1 and 2 TSs do not specify a measurement distance.
The licensee provided this information to the NRC by letter dated April 22, 1988, and also stated that the use of 18-inch readings would be implemented imme-diately at Millstone 1 and 2.
The licensee had previously presented this issue to the resident inspectors and regional Facilities Radiation Pro-tection (FRP) inspectors; both agreed with the licensee's decision.
The 18-inch readings will require fewer plant areas to be designated as locked HRAs.
The licensee indicated that the reduction in the amount of locked HRA doors will decrease the number of HRA doors left unlocked.
The letter also acknowledged that, while the Millstone 1 and 2 TS do not preclude the use of 18-inch readings, a TS amendment request would be submitted to make the Millstone 1 and 2 TSs consistent with the Millstone 3 TSs.
The inspectors will continue to follow the issue of HRA door control.
4.0 Facility Tours and Operational Status Reviews (71707)
Control instrumentation was inspected for correlation between channels, proper functioning, and conformance with Technical Specifications (TSs). Alarm con-ditions in effect and alarms received were reviewed and discussed with the operators. Operator awareness and response to off-normal conditions were reviewed; operators were found to be cognizant of plant conditions and indi-cations. Operating logs and Plant Incident Reports (PIRs) were reviewed for accuracy and adherence to station procedures.
Posting, control, and the use of personnel monitoring devices for radiation, contamination, and high radi-ation areas were inspected.
Plant housekeeping controls were observed, in-cluding control of flammable and other hazardous materials. Backshift in-spections of the control room were conducted on April 9 at 5:30 pm and April 24 at 3:30 pm.
All shift personnel were found to be alert and attentive to their duties.
No unacceptable conditions were identified.
The following activities were also addressed.
4.1 Safety System Operability (71707)
Standby emergency systems were reviewed to determine system operability and readiness for automatic initiation.
The following systems were re-viewed: feedwater cuolant injection, automatic pressure relief, low pressure coolant injection, core spray, and standby gas treatment.
The status c7 the control rod drive hydraulic control units, emergency diesel generator, gas turbine, and isolation condenser was also inspected.
The reviews considered, as applicable, proper positioning of major flow path (
valves, operable normal and emergency power sources, proper operation
'
of indications and controls, and proper cooling and lubrication.
Refer-l
- _.. - - __ _ - -_--_ _
-___
-
.
.
~
,
ences used for the review included the Updated Final Safety Analysis Re-port, and system diagrams and operating procedures.
No inadequacies were identified.
4.2 Plant Incident Reports (71707)
Selected plant incident reports (PIRs) were reviewed to (i) determine the significance of the events, (ii) review the licensee's evaluations, (iii) verify the licensee's response and corrective actions, and (iv) verify whether the licensee reported the events as required. No inadequacies were identified.
The following PIRs were reviewed: 1-88-12 (see Section 9.0, LER 88-02), 1-88-16 (see Section 6.0),1-88-17,and 1-88-18.
The following item warranted inspector followup.
The suction valve for the "D" Low Pressure Coolant Injection (LPCI) pump (1-LP-20) failed to fully open during a LPCI system operability test on March 22 (PIR 1-88-17).
The valve was returned to service on March 23.
Based on the valve's history of similar failures, two electricians were assigned to clean and adjust the 1-LP-2D torque switch on March 30.
Once the maintenance was completed, the electricians requested that the valve be stroke tested.
Because 1-LP-20 and 1-LP-2B are both located in the northeast corner room of the reactor building, the electricians were able to hear the stroke of the opposite pump suction valve.
They realized their error and contacted the control room.
The initial Auth-orized Work Order (AWO) for 1-LP-20 was cancelled. A new AWO was written to cover the work done on 1-LP-28.
A third AW0 was written to reinitiate work for 1-LP-20.
1-LP-20 was returned to service on March 31.
The inspector reviewed the AW0s and discussed the event with members of the maintenance, operations, and Human Performance Evaluation System (HPES) departments.
The inspector lcarned that the valve's power supply at the motor control center (MCC) was properly tagged and verified prior to the job start.
However, 1-LP-2D was not tagged, which is consistent with normal maintenance practices at Millstone.
The stenciling on the valve body was the only local valve identification, and the metal tags which normally identify plant equipment were missing. Additionally, it
is not possible to work on the valve and see the valve body label.
The electrician working on the torque switch wore rubber gloves and was not injured.
HPES recommendations to avoid future similar events include stenciling component identification numbers on both the motor-operator covers and the motor-operator bodies, surveying for other missing or illegible identification tags, and tagging the actual component requiring maintenance.
The inspector plans to follow the corrective actions and the consideration given to the HPES suggestions during future routine maintenance inspections.
!
.
-.
. -.-.
. -...
-...-..,,..._m.,_
-- _ -
m,
. -,, _ _
. - - - - - _ -. _.
_-
- - -..
_.--
-
.
.
.
.-.
..
,.
.
.
,
4.3 Standby Gas Treatment (SBGT) Walkdown (71710)
On April 8, the inspectors walked down the SBGT. system, using the system valve lineup (Rev 3 of OPS Form 329-1). The inspectors verified that all accessible valves were in their proper position, and that no inade-quacies in housekeeping or in the physical condition of valves, valve operators, or instrumentation were apparent.
Control room indications agreed with the actual valve positions, and no conditions adverse to system operability were noted.
The following discrepancies were noted during the inspection; each was identified to the Operations Supervisor on April 8, and the inspector verified the prompt implementation of satisfactory corrective actions on April 11. The inspectors had no further concerns.
--
The inspectors verified that the metal valve tags matched both the plant number and the Architect Engineer (AE) numbers as given on Form 329-1, but found that the redundant plastic tags did not.
For SBGT valves 1-SG-2B through 1-SG-7A, the plant and AE numbers dis-agreed.
The original SBGT tags were removed and replaced with ac-curate metal tags, which were verified by the inspector on April 11.
--
The inspectors noted that the bodies of the valve operators for the SBGT cooling air inlet and fan discharge valves had confusing posi-tion indications.
For example, in some cases, the OPEN and CLOSE iadication as cast in the operator 'ody was crossed out with per-c manent marker arid written in elsewhere. The operator casings were repainted and pointers were installed to indicate valve positton using the cast OPEN and CLOSE indications.
--
The. inspectors observed that 1-SG-9, the downstream sample point,
!
had no end cap and therefore provided only a single barrier to a l
potential source term release.
On April 11, the inspector verified
i that the pipe was end capped.
--
The inspectors identified that the Operations Critical drawing for the S8GT system was not in the control room.
It appears that the original composite drawing that contained SBGT was updated, but the i
!
new SBGT drawing was not entered on the station form containing the operations critical drawings (SF 328-1).
SF 328-1 has since been
,
updated to include the SBGT drewing, and the inspector verified its l
addition to the control roon file.
The licensee's inspection of the control room drawings revealed that three additional drawings were missing: site plan, fire detection
,
l and protection, and nitrogen supply system.
All four drawings have
'
since been placed in the control room file.
The inspector learned that there are no formal administrative controls or requirements for ensuring that all operations critical drawings are maintained
-.. _.
_. __ _
_ _ _ _ _ _ _, _
- _ _ _ _ _ _
._
.._-__ _,_ _... ~.. _. _
_ _ _ _
- _ - _ _ _ _ _ _
,.
.
.
.
in the control room.
The inspectors recognize the need to supply the operators with complete and accurate control room drawings and references, and will review this area in future routine inspections.
'
When leaving the turbine deck, which is designated as a locked high
--
radiation area, the inspectors noted that the elevator door had a sign designating the location of the frisker, but did not have a sign that explicitly stated that a hand and foot frisk was required prior to leaving the area. While no regulatory requirement exists for such a posting, it is consistent with good contamination control practices to post frisking requirements at the exit of contaminated areas. The inspectors brought this concern to the attention of the Health Physics Supervisor, who had an appropriate sign posted, as was verified by the inspector.
5.0 Security (81064)
During station tours, the inspectors verified proper implementation of selected aspects of the station-security program.
These included site access controls, personnel searches, compensatory measures, adequacy of physical barriers, reporting of security events, guard force staffing, and response to alarms and degraded conditions. No inadequacies were identified.
6.0 Potential Fouling of ECCS Suction Strainers (71707)
The licensee informed the inspector on March 18, 1988 of an item found to be reportable under 10 CFR 50.73(a)(2)(v) and described in Plant Information Re-port 1-88-16 dated March 18. Based on engineering evaluation by Northeast Utilities Service Company (NUSCO), there is a potential for fouling of emer-gency core cooling system (ECCS) pump suction strainers by insulation debris following a loss of cooling accident (LOCA).
The NUSCO study of drywell in-sulation was completed per Integrated Safety Assessment Program (ISAP) Topic 1.47 using the methodology of Regulatory Guide 1.82.
The results of the en-gineering evaluation were summarized in a report entitled "Drywell Insulation Acceptability Study" dated March 18, 1988. The inspector reviewed the licen-see's engineering evaluations and calculations, and discussed the licensee's assessment of the issue on plant safety with licensee and NUSCO personnel.
The low pressure ECCS, comprised of two trains of core spray and two trains of low pressure coolant injection and containment cooling, provides reactor core and containment cooling following a postulated LOCA. Mitigation of the design basis accident, as described in Final Safety Analysis Report (FSAR)
Section 15.7.4, depends upon long term success of the core and containment cooling functions.
Low pressure ECCS cooling takes suction on the torus via the ECCS suction header.
The ECCS suction header is attached to the torus
!
via three suction lines.
Suction strainers are provided to keep debris out l
of the ECCS pumps and piping.
The ECCS pumps are designed to operate at full capacity with one of the three suction strainers completely blocked, l
l l
L
..
.
,.
.
.
.
Three types of insulation are used on piping inside the drywell: a reflective mirror type, a foam insulation, and blanket-type fibrous insulation.
The fibrous insulation at Millstone Unit 1 is manufactured by Clearmont Products and has the brand name Tempmat.
It consists of a fiberglass core with a pro-tective outer cover of high density glass cloth.
In the study completed per ISAP 1.47, it was assumed that the water and steam blowdown from the break location impinge upon and damage the fibrous insulation to create debris capable of being transported from the drywell to the torus, and thence to the submerged suction strainers.
The purpose of the engineering study was to estimate, using conservative assumptions, how much debris would collect on the ECCS suction strainers by accounting for the types and amounts of insula-tion used inside the drywell, and assuming the worst case break location and the worst case operating configuration for the ECCS systems.
The study concluded that the ECCS suction strainers would be plugged by in-sulation debris to an extent that adequate ECCS pump net positive suction head (NPSH) requirements could not be assured.
It was assumed that the jet im-pingement from a 28-inch diameter recirculation pipe break in the lower ele-vations of the drywell created 17.0 cu.ft. of insulation debris, of which 5.1 cu.ft. was transported to the torus. All 5.1 cu.ft, of the debris in the torus-was assumed to collect on the strainers during the recirculation phase, which would become totally covered to a depth of 8.8 cm.
The calculated suc-tion strainer differential pressure for that debris bed depth was 14.6 feet of water, greater than the required NPSH of 6.0 feet for the assumed flow conditions of 25,200 gpm. Thus, minimum pump NPSH margins was not assured for long term operation of the ECCS system.
lhe licensee developed a second engineering evaluation using engineering judgement and assumptions considered more realistic (based on empirical data),
than those based on Regulatory Guide 1.82.
The second engineering etaluation, summarized in a Justification for Continued Operation (JCO) dated March 18 and revised on March 30, showed that ECCS pump NPSH margins were met.
The JC0 concluded that continued plant operation was justified based on the low probability of a LOCA during the remainder of the current fuel cycle (based on characteristics of the stainless steel material used in the recirculation piping, and the inspections and repairs completed to correct for intergranular stress corrosion cracking), and on the results of the revised calculations which show that the impact of the debris was less severe.
The revised calculations accounted for buoyancy of the insulation debris, the duration of turbulence in the torus following the LOCA, the flow velocities of the blowndown water / steam streams, and the plant specific configuration that impedes transport of the debris.
Using the revised assumptions, 1.65 cu.ft, of insulation would be deposited on the strainers, reducing the cor-responding pressure drop to 4.7 feet of water.
Thus, a 1.3 foot margin to the minimum NPSH requirement would exist.
Rather than complete further cal-culations to better define the impact on a plant specific basis, the licensee
, -. - - - _.
.,, -,.
- - -
- - -....-. - - - -..
- - ---
_ _ _ _ _ _ - _ _ _ - - - _ _ _ _ _ _ _ _ _ _ _ - _ - _ - _ _
- _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
._ _
_ - _.
_ _ _ _ - _ _ _ ___ _ ____
'
.
.
-
,
intends to replace the suction strainers per a schedule developed under ISAP.
The modified suction strainers would have a larger surface area which would further reduce the depth of the debris bed.
.The inspector reviewed the licensee's assumptions and calculation and identi-fied no inadequacies. Continued operation of the plant for the interim is acceptable based on the low probability of the LOCA and based on the accept-able results of the revised calculations.
However, additional NRC staff re-view of the calculation results is warranted to determine whether relaxation of the Regulatory Guide 1.82 assumptions is acceptable.
This matter has been referred to NRC:NRR for review and is unresolved pending completion of the staff review (UNR 88-05-01).
The licensee reported this item as LER 88-04 dated April 12, 1988 as required by 10 CFR 50.73(a)(2)(v).
The inspector reviewed the LER and concluded that it accurately described the issue and met the 50.73 reporting requirements.
The licensee also made an ENS call to the HQ:00 on March 23, which was 5 days later than the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification required by 50.72(b)(2)(iii), using March 18 as the start date when site personnel were notified of the engineering study results.
The licensee stated that the ENS report was not made sooner since the 50.72 criteria was deemed not applicable since an actual event had not occurred.
The ENS call was made because of the licensee's increased sensitivity to reportability issues as a result of recent discussions with the NRC staff (refer to Section 3.3 of this report).
This is an example of the difference between the licensee's and NRC's approach to the 50.72 report-ing criteria.
The inspector had no further comment on the licensee's per-formance relative to the 50.72 reporting for this event; however, this issue will be reviewed further with the licensee in subsequent routine inspections and is tracked as VIO 87-33-01.
7.0 August 1987 Containment Integrated Leak Rate Test (CILRT) Results (70323)
!
The inspector reviewed the licensee's August 1987 CILRT results documented
'
in accordance with 10 CFR 50 Appendix J paragraph V.B.3.
These results were summarized in a technical document entitled "Reactor Containment Building i
Integrated Leak Rate Test" and were attached to the licensee's letter dated November 20, 1987 to the NRC.
The report contains a test summary and general
'
l test description, presentation of test results, and other data such as de-scriptions of plant and computer sof tware, and data analysis techniques.
I The total time calculation method of Bechtel Nuclear Topical Report BN-TOP-1 for reduced duration tests was utilized.
This method is acceptable per 10 CFR 50 Appendix J requirements which stipulate that all Type A tests be con-ducted in accordance with the provisions of the American National Standard N45.4-1972, Leakage Rate Testing of Containment Structures for Nuclear Reac-tors.
The purpose of the test was to demonstrate that leakages through the primary containment building and systems penetrating containment do not exceed that allowed by plant technical specifications.
The test was conducted with con-i
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ - _ _ _ _ _ _.
_ - _ _ _ - - _ _ _ _
__
__
_.
. _ _ - _
. _ _ _ _
--
- .
'
-
.
- tainment. isolation valves and containment pressure boundaries'in an "as-left" condition. The containment could not meet the leakage criterion in the "as -
found" condition due to excessive local leakage. The test was witnessed by an NRC region-based inspector and was followed by a successful verification test.
Inspection findings are documented in USNRC Region I Inspection Report No. 50-245/87-18.
Results are presented below:
A.
Type A Test Parameters 1.
Test Method Absolute 2.
Calculational Method Total Time (per BN-TOP-1)
3.
Test Duration:
Stabilization Period 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Data Gathering for Leakage Calculation 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Verification Leak Rate Test 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4.
Test Pressure 43 psig (full pressure test)
B.
Test Results wt %/ day 1.
Acceptance, Maximum Allowable Leakage Rate 0.9
,
2.
Measured Leak Rate, Lam, In "As-Lef t" Condition 0.3395 3.
Leak Rate at the Upper Bound of the 95%
Confidence Limit plus penalties 0.441 4.
Conclusion Acceptable in "As-Left" Condition l
The inspector concluded that, based on a review of the results, the contain-
'
ment has met its acceptance criteria for leakage in the "as-lef t" condition.
,.
Failure in the "as-found condition has been acceptably reported on by the licensee. A proposed revised CILRT schedule is required in this case and remains to be submitted by the licensee.
8.0 Surveillance (61726)
On April 12, the inspector observed the following surveillance tests for con-duct in accordance with current approved procedures, for test result compli-ance with technical specification and administrative requirements, and for deficiency correction in accordance with administrative requirements.
,
l
,_
_ _ _
_.__ _
_.
.
.
....
-..
.
.
.
_ _ _ _ _
--
.__
_ _ _ _
_
'
...
SP4080, "Scram Discharge Volume (SDV) High Water Level Functional and
--
Calibration Test" SP408J, "Condenser Low Vacuum Scram Functional and Calibration Test"
---
For both surveillances', the inspector verified that the proper approvals were obtained prior to the test start and that calibrated testing equipment was used.
The inspector observed effective communications between the test team members and the control room; the technicians were able to maintain clear communications during SP408J in spite of the high noise level on the Turbine Deck.
The inspector observed the technicians' awareness of ALARA measures, which included the use of a motorized hand tool during SP4080 to quickly open and close hand-operated valves to reduce stay time in the high radiation areas containing the SDVs.
The inspector also observed efficient use of independent verification in system restoration.
No inadequacies were identified.
During SP4080, the inspector observed that the gate to the north SDV area did not have a chain and padlock, as the south SDV gate did.
The licensee imple-mented chains and padlocks (in addition to the original gate locks) to help prevent personnel from accidentally leaving HRA gates unlocked.
The inspector reviewed radiation surveys of the SDV and learned that a survey completed on February 5, 1988. indicated that all contact readings were less than 1000 mrem /hr.
The area was therefore not required to be locked, and the chain and padlock were removed.
The area was appropriately posted and the gate's original lock was still operable to restrict access.
The inspector also verified that the surveys conducted after the March 12, 1988 scram did not have contact readings in excess of 1000 mrem /hr.
Tha inspector had no further questions.
9.0 Update to UNR 87-33-02: Remaining Items from TI 2515/90, "Scram Discharge Volume Capability (25590)
Three separate items remained open at the close of NRC inspection 50-245/87-33; each has been reinspected and is discussed below.
The items in Sections 9.1 and 9.2 have been closed, but the issue in Section 9.3 remains open, pending further inspector review.
9.1 Vent and Drain Valves System Interface o
Criterion: Vent and Drain functions shall not be adversely affected by l
other system interfaces.
The objective of this requirement is to pre-l clude water backup in the scram instrument volume, which could cause a spurious scram.
Results: Section 4.6.1.2.5 of the Millstone 1 Updated Final Safety An-alysis Report (UFSAR) states: "a twe inch piping connection at the bottom of the Scram Discharge Instrument Volume (SDIV) prosides drainage of the SDIV and SDV via sloped drain lines with a minimum one-eighth inch per foot slope." The inspector verified the : loped drain lines by visual inspection. As discussed in the UFSAR, both SDIVs drain to the Reactor l
i
-.. - - _.
.
.
-- - - -
~.-
. - - -
.
.
_
.
_
_
_
._
_ _
.
.
,
.
,
Building Equipment Drain Tank (RBEDT). Another feature preventing back flow to the SDIVs are the floor penetrations.
Each drain line is equipped with a scupper fitting such that any back flow in the drain line would drain onto the floor, rather than backup into the SDIV. -The in-spector had no further questions on this item.
9.2 Vent and Drain Valves Close on loss of Air Criterion: The power-operated vent and drain valves shall close under loss of air and/or electric power.
Valve position indication shall be provided in the control room.
Results: The inspector verified the closure of the power-operated vent and drain valves on loss of air and control room valve position indica-tion as reported in IR 50-245/87-33.
The remaining item was the closure cf the vent and drain valves on loss of electric power.
Section 4.6.1.2.5 of the UFSAR states that, when both RPS logic channels are deenergized, both scram dump pilot valves open to vent control air from the vent and drain valve operators, permitting them to close.
The in-spector reviewed licensee drawing 25202-26024 which showed that valves 1-SD-1S, 25, 3S, 45, IN, 2N, 3N, and 4N all fail closed (FC) on air failure. Additionally, circuit wiring diagram (CWD) 25202-31001 Sheets
,
562 and 592 show that electric power is required to open the vent and drain valves, which close on spring pressure.
This item is closed.
9.3 Periodic Testing of Operability of the Entire System Criterion: The operability of the entire system as an integrated whole shall be demonstrated periodically and during each operating cycle by demonstrating scram instrument response and valve function at pressure and temperature at approximately 50% control rod density.
'
Results: As discussed in NRC IR 50-245/87-33, the licensee responded to this item in a March 20, 1981 letter to the NRC concerning IE Bulletin 80-17. The licensee committed that, at least once during each operating cycle, the operability of the system will be demonstrated after a reactor scram by verifying that the SDIV level trips occur, the vent and drain valves close, the system can be reset, and that the system drains ade-quately.
The licensee also stated that the unit would not be scrammed
,
for the sole purpose of demonstrating the operability of the system.
While such testing was noted to have been accomplished, the inspector was unable to locate documentation of NRC acceptance of this position or incorporation of the commitments of the March 20, 1981 letter in facility procedures.
This item remains open.
.. - _ _.
., _ _ - - -.. _. - _ - _ _ _.. _ _ _... - _
.
..
.
..
- -, _
-
.
..
,
.
10.0 Licensee Event Reports (92700)
Licensee Event Reports (LERs) 88-02 and 88-03 were reviewed to assess LER accuracy, the adequacy of corrective actions, compliance with 10 CFR 50.73 reporting requirements and to determine if there were generic implications or if further infornation was required.
LER 50-245/88-02: "Missed In Service Inspection (ISI) Surveillance." During a routine audit of ISI surveillances on March 10, 1988, the licensee dis-covered that the "C" service water pump had not been tested at double the normal test frequency, as required by IWP-3220 of the ASME Boiler and Pressure Vessel Code, when its vibration was discovered in the alert range (as speci-fied by the surveillance procedure) on August 31, 1987.
Further licensee review revealed that the test was satisfactorily completed on November 13, 1987, about one month later than required.
The surveillance was missed due to personnel error.
To prevent recurrence, the licensee plans to reissue the ISI surveillance schedule form to more clearly define surveillance completion requirements.
The form will indicate increased testing frequencies and the associated reason.
The inspector re-viewed the proposed form, determined that it appears to adequitely address the error, and will evaluate the use and success of the form in preventing missed ISI surveillances in future routine inspections.
Although the missed surveillance represents a violation of TS 4.13, the lic-ensee identified the event, reported it as required by 10 CFR 50.73, there were no consequences to plant operation, the violation was not found to be avertable by corrective action on previous violation, and the corrective action to prevent recurrence appears sufficient. Therefore, no enforcement action is being taken at this time.
LER 50-245/88-03: "Reactor Scram an Low Water Level." The scram itself, in-cluding the licensee's investigation, evaluation, and reporting of the event was reviewed in NRC Inspection Report 50-245/83-03.
The corrective actions implemented to allow safe restart and planned corrective actions to prevent recurrence were also reviewed at that time.
The LER accurately described the above information in sufficient detail, and no inadequacies were noted.
11.0 Plant Operations Review Committee (40700)
The inspector attended Plant Operations Review Committee (PORC) meetings on March 23, 30 and April 5, 3, 20, and 25.
Technical Specifications 6.5 re-quirements for committee quorum were met.
The meeting agenda included reviews of Plant Incident Reports (PIRs), Plant Design Change Requests (PDCRs), rou-tine procedure revisions, Technical Specification amendments and interim changes to procedures.
The inspector noted that the committee discharged their functions in accordance with regulatory requirements, and observed thorough PORC discussions with safety emphasis. No inadequacies were iden-tifie n___-_____-____
_
_ _ _ _ _ _ _ _ _ _
- 0
,-
13 12.0 Management Meetings (30703)
Periodic meetings were held with station management to discuss inspection findings during the inspection period.
A summary of findings was also dis-cussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspection.
No written ;aaterial was provided to the licensee by the inspectors, l
l l
t
[