ML20141D262
| ML20141D262 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 05/12/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20141D221 | List: |
| References | |
| EA-96-001, EA-96-1, EA-96-286, EA-96-334, EA-96-337, EA-96-338, EA-96-339, EA-96-340, EA-96-407, EA-96-440, EA-96-495, NUDOCS 9705200053 | |
| Download: ML20141D262 (26) | |
Text
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ENCLOSURE NOTICE OF VIOLATION l
AND l
PROPOSED IMPOSITION OF CIVIL PENALTIES Northeast Utilities Service Company Docket No. 50-213 Connecticut Yankee Atomic Power Company License No. DPR-61 Haddam Neck Plant EAs96-001, 96-286,96-334, 96-337 96-338,96-339, 96 340,96-407, 96-440,96-495 i
During several NRC inspections conducted from November 21,1995 to November 22,1996, violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," NUREG-1600, the NRC proposes to impose civil penalties pursuant to Section 234 of the Atomic Energy Act of 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular violations and associated civil penalties are set forth below:
1 1.
Violations Related to inadeauste Enaineerina A.
Errors in Desian Basis Documents or Errors introduced by Desian Chanaes.
10 CFR Part 50, Appei. dix B, Criterion Ill, " Design Control," requires, in part, that measums shall se established to assure that applicable regulatory requirements and the dasign basis for structures, systems, and components are correctly translated into specifications, drawings, procedures, and instructions.
These measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.
Design changes shall be subject to design control measures commensurate with those applied to the original design.
10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.
Contrary to the above, the licensee did not assure that applicable regulatory requirements and the design basis were correctly translated into specifications, j
drawings, procedures and instructions, or did not assure that activities affecting quality were correctly prescribed by documented instructions, procedures, or l
draw'ings of a type appropriate to the circumstances as evidenced by the
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following examples, each of which constitutes an individual violation l
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Enclosure 2
1.C Calculation No. PA91-LOE-1171-GE, Revision 2, dated February 21, 1992, which determined the design duty cycle of the 125 Vdc station batteries, did not assume the design basis event specified in the Updated Final Safety Analysis Report (UFSAR) Section 8.3.2, namely, a simultaneous accident and loss of off-site power. Therefore, the design basis calculation did not account for all of the loads that would be powered during the event. Further, the calculation did not determine the battery voltage profile, and, therefore, did not demonstrate that the battery voltage would remain above the minimum required voltage level.
(01012) 2.
Calculation No. 86-060-580GM, Revision 0, dated September 2,1986, which determined the minimum required net positive suction head for the high pressure safety injection pumps, used, as part of the calculathn, an incorrect elevation for the top of the suction nozzle, and also did not account for the expected instrument uncertainty. As a result, Emergency Operating Procedure (EOP) ES-1.3, " Transfer to Sump Recirculation," Revision 13, dated March 20,1995, which provides cautions to the operators to transfer high pressure safety injection (HPSI) pump suction to the containment sump before the refueling water storage tank (RWST) reaches a minimum level to prevent pump damage from cavitation, was inadequate in that the actual minimum level to preclude pump damage should have been 55,000 gallons instead of the 43,000 gallons as stated in the procedure. (01022) 3.
Calculation IC-CY-1134GE, " Uncertainties for RWST Level Instrument Channels L-1806A and L-1806B," Revision 0, dated November 5,1990, did not account for the errors associated with the change in hydrostatic head resulting from changes in tank water temperature and post-seismic effect, and resulted in inaccurate level indication. As a result, EOP ES-1.3, " Transfer to Sump Recirculation," Revision 13, dated March 20, 1995, was inadequate in that decision points for transfer to sump recirculation based on RWST indicated level did not account for these errors. (01032) 4.
Proto-Power Calculation 95-MDE-01252MY, "CY SW System - Analysis of Design Basis Hydraulic Conditions," Revision 0, dated May 19,1995, which was used to predict temperatures at the discharge of the CAR fan coils, did not accurately model system flow in that it did not model the
' Violations annotated with an astrisk (*) are violations occurring beyond the five year statute of limitations period for assessing civil penalties (28 USC 2462) or are violations for which definitive dates to establish their occurrence is unavailable to determine the statute of lunications* applicability, In either case. these violations were not considered for purposes of determining any civil penalties.
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Enclosure 3
transient two-phase flow conditions that were previously calculated to exist at this location, and which could adversely affect containment heat removal capability. (01042) 5.*
Calculations PA78-741-01-GE, " Diesel Generator Automatic Loading Analysis," Revision 3, dated January 21,1991 (including CCNs 1-5) and PA90-LOE-1167-GE, " Diesel Generator Manual Loading Analysis,"
Revision O, dated February 20,1991 (including CCNs 1-7) did not account for all of the applicable electrical loads. Specifically, the calculations did not incorporate cable power losses and power distribution transformer losses, and used a non-conservative diversity f actor. As a result, the margin of safety to emergency diesel generator (EDG) overload was less than identified in the licensee design analyses.
(01052) 6.
Calculation EQE-42094-C-009, " Diesel Generator Starting Air," Revision 0, dated March 29,1996, which established the seismic qualification for the diesel air start piping, incorrectly assumed that a qualified hose was installed. Although the calculation used a stiffness value of 10 pounds-per-inch to model the flexible hoses attached to the diesel, the installed flexible hoses had a less conservative stiffness value of 0.75 pounds-per-inch. A subsequent calculation determined that the air start piping displacement would exceed the vendor's acceptance limit dunng a design basis seismic event. (01062) 7.
Prior to July 24,1996, calculation C2-517-567-RE, " Uncontrolled Rod Withdrawal Transient Analysis" (which established the trip setpoints for the wide range nuclear instrumentation) did not account for channel uncertainties. As a result the channel uncertainties did not account for rack calibration accuracy, rack drift, rack temperature allowance and overall indicator accuracy. (01072) 8.*
Calculation CY-LPSI-89-RPS-700, "CY-LPSI Flow for Core Deluge Testing", Revision 0, dated August 29,1989 determined the LPSI pump flow and system flow for one LPSI pump injecting into a vented reactor through the core deluge valves. This calculation concluded that the low pressure safety injection (LPSI) system would deliver 3810 gpm to the reactor based on a pump flow of 4000 gpm. The calculation did not adequately account for system flow resistances and the pump curve was not conservative. On December 15,1995, the licensee documented its discovery (ACR 95-578) that LPSI injection flows could be as low as 3540 gpm, which was significantly less than the LPSI flow assumed in the safety analysis performed per 10 CFR Part 50, Appendix K to demonstrate satisfactory emergency core cooling system (ECCS) l performance for Cycle 19 operations. Thus, the licensee failed to l
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l Enclosure 4
l adequately translate the design basis into the testing program intended to demonstrate safety system performance in accordance with the accident analysis assumptions. (01082) 9.
Calculation 95-EWA-01-01323-DY, Revision 0, dated February 2,1996, which was used to support a technical specification (TS) amendment j
request, dated March 7,1996, to the CAR fan surveillance testing l
acceptance criteria, did not appropriately consider the fan performance l
capability.
Specifically, the amendment requested a minimum acceptable flow of 40,000 cfm, which was not supported by the vendor's fan performance curve, did not provide sufficient margin for potential filter fouling, and could have resulted in flows less than designed. (01092) 10.
Calculation 95-LKSL-1296-MY, Revision 0, dated May 19,1995, which l
was used in the analysis of the impact of leak sealant injection into the l
four feedwater regulating valves, used a design pressure of 1000 psiin the calculation even though the actual design pressure of the system i
was 1210 psi. This calculation had been reviewed by a second engineer, the engineering supervisor, and the Plant On-site Review Committee (PORC). (01102) 11.
Engineering evaluation CY-CD 1970, dated July 29,1992, which was l
prepared to support the replacement of EDG annunciator panel relays, indicated that the safety classification of the relays was "non-QA" and concluded that the alarm and control circuits would not be adversely affected by the change. The evaluation was incorrect in that failure of the devices could have resulted in aninadvertent shutdown of the EDGs.
(01112) i
- 12.
- Calculation Change Notices 1 through 5 were initiated for Calculation PA78-741-01-GE, " Diesel Generator Automatic Loading Analysis,"
1 Revision 3, dated January 21,1991 to revise the EDG loading tabulation in Attachment 4. However, the worst-case loading profile for EDG EG2B in Attachment 4 was not updated to be consistent with the revised loeding tabulation; as a result the margin of safety to EDG overload was less than identified in the licensee design analyses. (01122) 13.
Calculation Change Notice 6, dated June 19,1995, for Calculation PA90-LOE-1167-GE, " Diesel Generator Manual Loading Analysis,"
Revision O, dated February 20,1991, changed the LPSI pump load from 874 kW to 945.85 kW when a design modification changed a piping orifice size; however, a similar Change Notice was not initiated for related Calculation PA78-741-01-GE, " Diesel Generator Automatic Loading Analysis," Revision 3, dated January 21,1991; as a result, the c
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Enclosure 5-margin of safety to EDG overload was less than identified in the licensee design analyses. (01132) 14.
A licensee letter submitted to the NRC on July 7,1993, stated that containment isolation valves were not needed for the service water return from containment for the CAR system because the flow indication provided early assurance to the operators of detection of a service water line break. However, when the licensee issued TS Clarification C-TSC-l 059, dated January 1,1996, to plant operators to address the impact of the loss of service water flow indication to the containment air l
recirculation coolers, the clarification did not address the containment isolation function and incorrectly concluded that the flow indication was not necessary for system operability. (01142) 15.
NE-95 SAB-293, "CY Design Basis Containment Analysis For Large Break LOCA," dated July 21,1995, calculated a new design basis maximum containment temperature which was not correctly translated into the design basis for all of the affected components inside -
containment. Although the shell side of the residual heat removal (RHR) heat exchangers had a design basis temperature of 200 degrees F, the 3
revised calculation determined temperatures could reach 252 degrees F l
l under certain conditions, and as of April 26,1996, the effect of the containment temperature changes on the operability of the RHR heat 1
exchangers had not been determined. (01152) 16.
Calculation 93-00099-1064-DY, Revision 0, dated June 22,1994, which was prepared to support the upgrading in safety classification of 120 Vac lighting panels, did not adequately address the seismic qualification of the lighting panels in that:
i 1.
the as-built anchor bolt configuration had not been evaluated; ii.
anchor bolt capacities had been assumed with no documented bases; and iii.
the analyses had disregarded the centers-of-gravity for the l
attached components. (01162)
I 17.
Integrated Safety Evaluation CY-95-013, dated March 15,1995 was performed to evaluate a change to EOP ES-1.3, " Transfer to Sump Recirculation" (which moved a step that directs the operators to stop the LPSI pumps earlier in the procedure); however, an appropriate calculation was not used to provide the basis for the change. The evaluation used Calculation NE-93 SAB-017, "CY Sump Recirculation Times -
Justification for Turning LPSI pumps off at 10 minutes post-LOCA,"
o l
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s Enclosure 6
which assumed the pumps would be turned off 10 minutes after the initiation of a large break loss of coolant accident (LOCA). However, the f
procedure modification resulted in stopping the LPSI pumps in 7.8 minutes. (01172) 18.
Stone and Webster Calculations 15198-001 and 15198-002, dated March 21,1986, and April 29,1986, respectively, determined that the reactor coolant system head vents were susceptible to adverse j
hydrodynamic loading, and based the calculation on the assumption that
- the downstream vent valve was opened first during the venting t
sequence to prevent the impact of any fluid on a partially opened j
downstream valve.
However, this design assumption was not
(
maintained in plant procedures, in that a revision made in 1990 to the original 1986 procedure failed to maintain the required valve operating sequence.
Further, this design was not included in EOP FR-l.3, l
" Response to Voids in Reactor Vessel," Revision 10, dated March 20, 1995 which was inadequate in that it directed the operators to open l-both reactor coolant system head vents in the same step. (01182) l 19.
On August 17,1973, as part of plant modification Plant Design Change j
Request (PDCR) 156, Flooding Protection of Safeguards Equipment, i
carbon steel barriers were installed around floor openings on both levels of the primary auxiliary building to preclude internal flood water from reaching the RHR pumps. TS amendment 27 was issued based on a calculation that the assumed operator response time for the worst case internal flood in the primary auxiliary building was approximately 12 minutes.
However, this calculation was inadequate in that on October 23,1996, the licensee identified approximately 35 additional floor penetrations in the primary auxiliary building that were not modified with barriers and were not considered in the calculation of flooding time.
As a result, flood water could render the RHR pumps inoperable in less j
than 12 minutes (approximately 8 rr
.es) (01192) l B.
Inadeauste. or Lack of Safety Evaluations and ilures to Uodate the Final l
Safety Analysis Report l
1.
10 CFR 50.59, " Changes, tests and experiments," permits the licensee, in part, to make changes to the facility as described in the safety analysis report without prior Commission approval provided the change does not involve an unreviewed safety question (USQ). The licensee shall maintain records of changes in the facility and these records must include a written safety evaluation which provides the bases for the determination that the change does not involve a USO.
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Enclosure 7
Contrary to the above, the licensee made the following changes to the facility as described in the safety analysis report without performing a -
written safety evaluation for any of these changes to provide the basis for the determination that the changes did not involve a USQ, as evidenced by the following examples, each of which constitutes an individual violation:
l a.
During the week of March 25, 1996, in order to facilitate I-maintenance activities, the facility was changed by removing an
. internal flood protection floor block from the Primary Auxiliary Building pipe trench tunnel, and installing a temporary cover which could not provide adequate flooding protection, even though the flood protection floor blocks are shown in UFSAR L
Figure 3.8-15.(01202) b.
PDCR 1411, completed on August 13,1994, removed breathing air stations inside containment and changed the air connections l
to support the use of portable air units, even though these l
stations are explicitly described in UFSAR Section 9.3.1.2,
" Compressed Air System - System Description." (01212) c.
PDCR 1479, completed on March 22, 1994, removed two service water elbow tap flow indicators and the associated tubing and instrument valves for the measurement of flow to the RHR heat exchangers, even though UFSAR Section 9.2.1.4, " Service t
Water System - Instrumentation Requirement," specifically identifies the elbow tap arrangement in describing the instrumentation used to measure service water flow to the RHR heat exchangers. (01222) d.
PDCR 1520, completed on September 6,1995, changed system j
controls, dryer purge air supplies, and replaced the activated alumina desiccant with a molecular sieve desiccant for the control air system, even though UFSAR Section 9.3.1.2,
" Compressed Air System - System Description," states that the 1
control air system uses three air dryors that are of the activated l
alumina, automatically regenerated type. (01232) e.
PDCR 1448, completed on April 6,1996, added a tank, pump, and tubing to utilize ethanolamine (ETA) as well as hydrazine for j
the control of secondary water chemistry, even though UFSAR Section 10.3.5, " Water Chemistry," states that secondary water L
chemistry is controlled using chemical feed equipment that adds hydrazine to the condensate system, and does not mention ETA.
(01242)
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4 Enclosure 8
2.
10 CFR 50.59, " Changes, tests and experiments," permits the licensee, in part, to make changes to the facility as described in the safety analysis report without prior Commission approval provided the change does not involve a USQ. The licensee shall maintain records of changes in the facility and these records must include a written safety evaluation which provides the bases for the determination that the change does not involve a USQ.
10 CFR 50.71(e) requires the licensee to update the FSAR originally submitted as part of the application for the operating license to assure that the information included in the FSAR contains the latest material developed. The updated FSAR shall be revised to include the effects of, in part, all safety evaluations performed by the licensee in support of conclusions that changes did not involve a USQ.
10 CFR 50.9(a) requires, in part, that information provided to the NRC by a lice nsee or information required by regulation to be maintained by a licensee shall be complete and accurate in all material respects.
Contrary to the above, the description of the facility in the FSAR was not accurate in all material respects in that the FSAR did not match the facility, required safety evaluations were not performed, and the FSAR was not properly updated as evidenced by the following examples, each of which constitutes an individual violation:
a.
Prior to April 1994, FSAR Section 3.8.1.3, " Design Loading j
Criteria," inaccurately described maximum snow loadings for safety-related structures as 60 lb/ft although the original design 2
specifications and as-built construction were for 40 lb/ft. As the 2
safety related structures were not designed and constructed for 2
60 lb/ft maximum snow loads, the inaccuracy was material in that no evaluation existed to determine that the inaccuracy did not constitute a USQ nor was the FSAR updated to correct the inaccuracy. Following recognition of the discrepancy, FSAR Change Request (FSARCR) 94-CY-1 in April 1994 changed the description of the maximum snow loadings for safety-related structures in FSAR Section 3.8.1.3 from 60 lb/ft to 40 lb/ft, to 2
2 agree with the original design specifications, without a safety a
evaluation to determine that the as-found condition did not constitute a USQ. (01252) b.
Pdor to June 1994, FSAR Section 8.3.1,.1.5, " Emergency AC Power System Description," inaccurately described the non-emergency trips of the EDGs as including a " Generator - Loss of OFFICIAL RECORD COPY
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Enclosure 9
Field" trip.' As the facility EDGs did not have Generator - Loss of Field trips, the inaccuracy was material in that no evaluation existed to determine that the inaccuracy did not constitute a USQ nor was the FSAR updated to correct the inaccuracy. Following the discovery that the existing circuit did not provide this feature, FSARCR 94-CY-7 in June 1994 changed the description of non-emergency trips of the EDGs in Section 8.3.1.1.5 to delete the
" Generator - Loss of Field" trip without a safety evaluation to determine that the as-found condition did not constitute a USQ.
(01262) 3.
10 CFR 50.59, " Changes, tests and experiments," permits the licensee, in part, to make changes to the facility as described in the safety analysis report without prior Commission approval provided the change does not involve a USQ. A proposed change, test, or experiment shall be deemed to involve a USQ if, in part, a possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis report may be created.
Contrary to the above, the safety eMaation associated with PDCR 1435, " Replacing Battery Charger BC-: -1 A," Revision 0, dated February 28,1994, did not adequately assess tM possibility of a malfunction of a different type than pr3viously evalueted when replacing the battery charger with a new battery charger of a substantially different design.
Specifically, the safety evaluation did not consider the potential for degrading effects and failure modes on the 125 Vdc system due to the installation of the new battery charger. (01272) i 4.
10 CFR 50.59, " Changes, tests and experiments," permits the licensee, in part, to make changes to the facility as described in the safety analysis report without prior Comnission approval provided the change does not involve a USO. The licentes shall maintain records of changes in the f acility and these records must include a written safety evaluation which provides the bases for the determination that the change does not involve a USQ.
l.
Contrary to the above, on June 11,1996, the licensee discovered that no records existed to assure that the main feedwater regulating valves could close against the differential pressure anticipated during a main steam line break inside containment. Licensee engineering calculation (FCV-1301-1449-DY) on July 1,1996, concluded that the feedwater l
regulating valve could not close under main steam line break conditions, j
j even though UFSAR Section 15.2.9., states that the following functions provide the protection for a steam line rupture, " isolation of the main L
feedwater lines by two valves in series will occur on a safety injection I-i OFFICIAL RECORD COPY g:HADDAMM.NOV i
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actuation. This is done via closure of the feedwater isolation valve and the feedwater regulating vaive after e. short time delay." Thus, the j
licensee safety evaluations previously completed for modifications to the feedwater line isolation system were inadequate in that the existence of l
a USO was not identified; namely, the safety evaluations for plant
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l modifications per PDCR 423 in October 1981; the safety evaluations to l
support TS License Amendment No.125 in 1991; and the safety l
evaluations for PDCR 1533 in February 1995.(01282)
I 5.
10 CFR 50.71(e) requires the licensee to update the FSAR to assure that the information included in the UFSAR contains the latest material developed. Updates must be filed annually or 6 months after ea':h refueling outage. The updates must reflect all changes up to a maximum
{
of 6 months prior to the date of filing.
Contrary to the above, as of April 26,1996, the licensee failed to update the UFSAR to reflect plant conditions, which existed more than l
6 months prior to the previous UFSAR update, as evidenced by the l
following examples, each of which constitutes an individual violation:
(
a.
UFSAR Table 9.2-1, " Service Water Major Component Interface,"
L lists the "appro).imate required" service water flow rate for the individual components such as the diesel generator, residual heat j
removal heat exchanger, and spent fuel pool plate heat
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exchanger. Although these flow rates differ by up to 50 percent from the actual functional requirement flow rates, as listed in the Design Basis Document Package, dated September 1,1995, and L
the "CY Service Water System GL 8913 Item IV, Design Basis Summary Report," dated July 15,1994, the UFSAR had not been updated as of April 26,1996.(01292) i b.
UFSAR Section 9.2.1, " Service Water System," states that service water system valves SW-MOV-1 and SW-MOV-2 close on a high containment pressure signal. However, the Design I
Basis Document Package, dated September 1,1995, correctly identified that the valves closed on a Safety injection Actuation Signal (SIAS). As such, the UFSAR was inco';plete in that dthough high containment pressure is an input u.ot initiates a SIAS signal, it is not the sole input, yet the UFSAR had not been updated as of April 26,1996.(01302) c.
UFSAR Section 6.3.2.1, "ECCS - Schematic Piping and instrumentation Diagrams," lists four interlocks associated with ECCS operation. Although the list does not include the interlock associated with SI-MOV-901 and SI MOV-902, RHR to HPSI 1
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Enclosure 11 l
Crosstie Isolation Valves, which were installed in 1988 in i
accordance with PDCR 854, the UFSAR had not been updated as of April 26,1996.(01312) d.
UFS/Mcction F.3.2.2, "ECCS System Design - Equipment and Component Description," provides a description of the ECCS design and did not list valves SI-V-905, 906, 907, and 908
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associated with the HPSI discharge lines. Although these valves were installed in the HPSI discharge lines in 1988 in accordance with PDCR 854, the UFSAR had not been updated as of Anril 26, 1996.(01322) e.
UFSAR Section 6.3.2.8,"ECCS System Design-Manual Action,"
states that the ECCS will be realigned for long-term sump recirculation after 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following a loss of coolant accident.
Although EOP E-1, " Loss of Reactor Coolant or Secondary Coolant," Revision 13, dated March 20,1995, specifies that l
long-term sump recirculation is to be established at 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the UFSAR had not been updated as of April 26,1996. (01332) f.
UFSAR Section 6.3,
" Emergency Core Cooling System,"
describes system valve lineups for injection and sump recirculation. Although the short-term and long-term recirculation valvo !ineups differ from EOP E-1, " Loss of Reactor Coolant or Secondary Coolant," Revision 13, dated March 20,1995, the UFSAR had not been updated as of April 26,1996.(01342) i g.
UFSAR Section 8.3.2.1.2, " Battery Chargers," states that dunng normal operation the 125 Vdc safety-related train A and train B battery chargers are operated in a float condition to maintain charger output voltage at 130 Vdc. Although the float voltage setting was revised from 131.8 Vdc to 132 Vdc following setpoint change request No. 94-17, dated May 5,1994, the UFSAR had not been updated as of April 26,1996.(01352)
C.
Inadeauate Corrective Actions 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Actions," requires,in part, that measures be established to assure that conditions adverse to quality are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is l
determined and corrective action taken to preclude repetition.
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Contrary to the above, the licensee did not assure that conditions adverse to quality were promptly corrected, as evidenced by the following examples, each of which constitutes an individual violation:
a.
Adverse Condition Report (ACR)95-467, dated November 13, 1995, identified conditions adverse to quality, namely that l
instrument loop errors may exist in the EDG kilowatt meters used for TS surveillance tests, and that similar instrument loop errors may exist for other instruments used to meet TS surveillance requirements. However, as of April 26,1996, an uncertainty calculation had not been prepared, and an investigation into the generic implications had not been completed. (01362) j b.
The licensee identified in 1989 that instrument uncertainties had not been incorporated into the establishment of the EOP decision l
point for initiating containment spray, and reported the issue in Licensee Event Report (LER)89-005, dated May 11,1989. The licensee determined that instrument uncertainties and the effects of adverse environments should be reviewed for the EOP decision points, and incorporated where appropriate. The licensee's j
review was completed in March 1994. However, as of April 26, 1
1996, the licensee had not accounted for instrument uncertainty in the RWST level instrument decision points in the EOPs.
(01372) c.
UFSAR Section 7.5.2 states that RWST levelinstruments meet the criteria specified in Regulatory Guide 1.97. No-theast Utilities memorandum No. NE-90-SAB 230, dated September 18,1990, identified that RWST level instruments were not correctly classified in UFSAR Section 7.5.2.
In addition, Material l
Equipment and Parts List (MEPL) Determination CY-CD-2130, dated May 5,1994, identified that the RWST level instruments were not correctly classified in accordance with Regulatory Guide 1.97. However, prior to April 12,1996, action had not been taken to correct the RWST classification discrepancies. (01382) d.
Quality and Assessment Services Audit Report No. A25098, dated November 30,1994, identified that plant information reports (PIRs) had remained open well beyond the procedurally-specified time limit without receiving an extension approval. This weakness was a repeat occurrence - of a previous audit deficiency. A later audit, No. A62001, dated July 3,1995, concluded that the corrective actions to improve procedural compliance were not effective. However, as of April 26,1996, OFFICIAL RECORD COPY g:HADDAMR6.NOV
Enclosure 13 adequate actions had not been taken to correct this recurring program deficiency in that numerous ACRs (to which PIRs had
. been converted in 1995) remained open beyond specified time limits. (01392) e.
A third-party audit entitled, " Station Blackout Assessment,"
Report No. 24-00116, dated October 1994, was performed to reviewthelicensee'simplementation of actionstakeninresponse i
to the station blackout requirements in 10 CFR 50.63. The third party audit identified deficiencies in the licensee's implementation j
of the station blackout rule, including inadequate calculations for j
alternate AC loading, voltage drop, and battery sizing. Other deficiencies involved the adequacy of EDG reliability programs and discrepancies in the analysis of safe shutdown scenarios.
However, as of April 26,1996, the licensee had not taken 1
corrective actions to address all of the deficiencies identified in the audit. (01402) f.
The root cause investigation report for ACR 95-577, dated January 15,1996, recommended 19 corrective action items to address the condition regarding actual LPSI flow rates following a LOCA being less than that assumed in the safety analysis. The event was the subject of an NRC enforcement conference on February 12, 1996.
The recommended corrective actions included safety system impact evaluations, design document revisions, a self-assessment initiative, and numerous procedure reviews and revisions. However, as of April 26,1996, the corrective actions had not been initiated. (01412) g.
Calculation Change Notice 2, dated November 23,1992 for Calculation No. PA-76-633-0040-GE, Revision 5, revised the degraded voltage protection system calculations, in response to an NOV from NRC Electrical Distribution System Functional Inspection, inspection Report 50-213/91-80. In addition, the licensee committed to revise the associated surveillance l
procedure and TS. However, as of April 26,1996, appropriate corrective action had not been taken in that the licensee had not l
revised the surveillance procedure or TS, resulting in the design l
hasis calculation inconsistent with the TS and surveillance procedure. (01422) h.
While performing an operability evaluation for the containment sump screen mesh size on February 26,1996, as part of ACR 96-201, the licensee did not identify and correct a condition adverse to quality. Specifically, ACR 96-201 documented the I
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l Enclosure 14 potential for screen mesh size to be different than designed bcsed on such a finding at Millstone 2; however, the licensee did not identify that the containment sump screen mesh holes at l
Haddam Neck were.5 inches rather than.375 inches assumed i
in licenssa analyses, thereby potentially rendering downstream ECCS components inoperable during an accident. (01432) 2.
Contrary to the above, the licensee did not assure that the causes of conditions adverse to quality were determined, and corrective action taken to preclude repetition, as evidenced by the following examples, each of which constitutes an individual violation:
a.
Licensee investigations into CAR fan surveillance failures reported in PIR 95-042, dated February 1,1995, and LER 95-04, Revision 1, dated July 31,1995, did not assure the causes of the failures were determined. Specifically, test results were not consistent with the root causes stated ;n the LER, and additional deficiencies that could have contributed to the surveillance failures were identified by the NRC during the week of l
April 15,1996. (01442) b.
In March 1995, the licensee replaced battery charger BC-1-1 A with a new solid state design. During testing and subsequent I
operation, the battery exhibited ammeter fluctuations as documented in trouble report 15-CY-14018 BC 1-1 A, dated March 1,1995. On November 2,1995, ACR 95-433 wasissued to enter the condition into the corrective action program.
However, as of April 25,1996, effective corrective action had not been taken to determine the cause of the fluctuations and the condition adverse to quality remained uncorrected. (01452)
These violations in Sections 1.A-l.C represent a Severity Level ll problem (Supplement 1).
Civil Penalty - $200,000 D.
Violations of Technical Soecifications Caused bv Inadeauate Enaineerina l
1.
TS 3.5.1.a.6 requires two ECCS subsystems to be operable during Modes 1,2, and 3 with an operable flow path capable of taking suction from the containment sump during the recirculation phase of operation.
Contrary to the above, prior to July 22,1996 during operation in Modes 1,2, and 3, under certain conditions, the long-term recirculation phase flowpath for ECCS systems needed to mitigate postulated loss of coolant accidents was inoperable. On August 1,1996, the licensee i
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Enclosure 15 determined that the original 10 inch and 8 inch diameter piping from the containment sump to suction for the RHR pump resulted in insufficient NPSH to support RHR pump operation without relying (inappropriately) l on containment backpressure.
Specifically, EOP ES-1.3 provided instructions to the operator to operate an RHR pump through a single sump suction valve (RHR-MOV-22 or RHR-V808A) when transferring the ECCS to sump recirculation mode of operation following a postulated accident. In the configurations allowed by ES-1.3, adequate NPSH could not be assured for the range of possible conditions as the containment cooled and depressurized following an accident. Inadequate NPSH l
would result in RHR pump cavitation, vapor binding and eventual pump failure. (02012) 2.
TS 3.5.1.a.6 requires two ECCS subsystems to be operable during Modes 1,2, and 3 with an operable flow path capable of taking suction from the refueling water storage tank and manually transferring suction to the containment sump during the recirculation phase of operation.
l Contrary to the above, prior to July 22,1996 during operation in Modes 1, 2, and 3, the recirculation phase flowpath required to mitigate postulated loss of coolant accidents was inoperable. Specifically, after the reactor was shutdown on July 22,1996, the licensee identified on July 26,1996, that the (1) the containment sump screen mesh holes were larger than the.375 inch value assumed in licensee analyses, and (2) there was a 3 inch by 2 foot hole in the screen, thereby rendering
(
the downstream ECCS components potentially inoperable during an l
accident. (02022) l 3.
TS 3.6.2 requires at least four CAR units to be operable in Modes 1,2, l
3, and 4. The TS action statement requires that with only three CAR units operable, the inoperable CAR unit be restored to an operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least hot standby within the next six hours and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Contrary to the above, during all times when the reactor was in Modes l
1,2,3, and 4 prior to July 22,1996, all four CAR units were inoperable l
in that they could not have performed their intended function during l
LOCAs. Specifically, engineering analysis concluded that the service i
water piping structurallimits would be exceeded due to waterhammer loads. The service water system is a support system for the CAR units l
and a part of the primary containment boundary. (02032) 4 These violations in Section I.D represent a Severity Level 11 problem (Supplement 1).
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Enclosure 16 11.
Violations Associated with the Nitroaen Intrusion Event A.
TS 6.8.1 requires, in part, that written procedures and/or administrative policies shall be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A requires procedures for filling and venting the reactor coolant system; and for the startup, operation, and shutdown of the shutdown cooling system and the chemical and volume control system (including the Letdown / Purification System). The instructions in these procedures should include changing the mode of operation in the reactor coolant system.
Contrary to the above, written procedures and/or administrative policies were either not established or not implemented, as evidenced by the following examples, each of which constitutes an individual violation:
1.
On August 22,1996, Normal Operating Procedure (NOP) 2.7-4, "RHR Purification System Operation," Attachment 4, Step 1.4, which requires that the RHR purification pump suction valve from the RWST, PU V-261 A, be closed, was not properly implemented in that the valve was not closed. As a result, there was a diversion of approximately 500 gallons of reactor coolant to the RWST. (03012) 2.
On August 28,1996, Surveillance procedure (SUR) 5.1-159B, " Boron injection Flow Path Verification and Metering Pump Test," step 6.1.2, which requires the operator to verify each component in the flowpath is in its specified position on the valve lineup checklist, and step 5.1.1, which requires the operator to immediately notify the shift supervisor and not proceed if a component is not found in its specified position, were not properly implemented in that an operator repositioned valve BA-V-355 from closed to open upon determining that the valve was not in its specified position without notifying the shift supervisor. This action resulted in water and nitrogen addition into the reactor coolant system. (03022) 3.
On August 29,1996, NOP 2,4-3, " Shutdown of an Individual Loop,"
was inadequate in that no instructions existed to preserve overpressure protection of an isolated reactor coolant system loop so as to preclude exceeding design stress levels in an isolated loop. (03032) 4.
On August 31,1996, NOP 2.9-1, " Placing the Residual Heat Removal System In Service," was inadequate in that it did not have instructions to shift RHR pumps, vent the RHR pumps, isolate RHR heat exchangers, and place limitations on maximum RHR flow through the heat exchangers. (03042)
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l Enciosure 17 5.
On August 31,1996, NOP 2.4-7, " Return of a Loop to Service with the Plant Shutdown," was not properly implemented in that isolated loop boron concentrations and loop temperatures were not determined as i
required prior to opening the loop stop isolation valves. (03052) 6.
On September 3,1996, NOP 2.9-6, " Primary Vent Header Operation,"
13 quired the installation of a vacuum pump to vent the reactor coolant loops. This procedure wa-s not properly implemented in that during the NRC walkdown of the system, no vacuum pump installation connections g
were available to support venting the reactor coolant loops, and the
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system configuration as depicted in NOP 2.9-6 did not match the field installation. In addition, this procedure was not adequately established in that no procedural controls existed to periodically verify the operation of the vent system.
The procedural deficiencies contributed to ineffective venting of non-conderisible gases within the reactor coolant system and the reactor vessel. (03062)
' B.
TS 6.8.2 requires that each procedure required of TS 6.8.1 shall be reviewed by PORC and approved by the Vice President - Haddam Neck prior to implemente' ion.
Contrary to the above:
1.
On August 28,1996, and September 1,199S, the licensee vented and refilled portions of the charging system with instructions that were not reviewed by PORC and approved by the Vice President - Haddam Neck prior to implementation.
2.
On August 29,1996, the licensee drained the reactor coolant system with instructions that were not reviewed by PORC and approved by the Vice-President - Haddam Neck prior to implementation. (03072)
C.
10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be preser; bed by procedures appropriate to the circumstances, and shau be accomplished in accordance with the procedures.
Procedures shall include ' appropriate qualitative acceptance criteria for determining that activities - affecting quality have been satisfactorily accomplished.
Contrary to the above, normal operating procedure (NOP) 2.3-4, Shutdown from Hot Standby to Cold Shutdown and procedure steps developed under ACP 1.'2-5.3, Evaluation of Activities / Evolutions Not Controlled by Procedures, used to drain the reactor on August 29,1996 and to operate the reactor in a partially j
filled and vented condition from August 29 - September 3,1996 was l
inadequate in that operators lacked the reactor vessel level and core exit I
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l Enclosure 18 thermocouple instrumentation used to verify that level was acceptable and that draining and fill evolutions are satisfactorily accomplished. The instrumentation had been disconnected during a period of extended operation in a partially filled and vented condition due to a change in the refueling plan and schedule that had not been thoroughly reviewed for impact on shutdown risk. This lack of review and planning resulted in the plant being placed in a vulnerable configuration, with only limited instrumentation and indications available to the operators. (03082)
D.
10 CFR Part 50, Appendix B, Criterion XVI(Corrective Action), requires, in part, that measures shall be established to assure that conditions adverse to quality,
')
such as failures, deficiencies, and deviations, are promptly identified and corrected.
Contrary to the above, measures had not been established to assure that conditions adverse to quality, such as f ailures, deficiencies, and deviations, are promptly identified and corrected, as evidenced by the following examples, each of which constitutes an individual violation.
1.
Between August 28,1996, and September 5,1996, a condition adverse to quality existed, namely nitrogen gas from the volume control tank l
entering the reactor vessel as a result of a failure to adhere to a procedure. The gas leakage continued even after the licensee believed that the leak was isolated, resulting in a displacement of reactor coolant to a level approximately three feet below the vessel flange. During this time period, various unexplained indications existed, such as reactor coolant system level anomalies and unexplained increase in nitrogen use, that could have alerted the operators to -this condition. However, licensee personnel were ineffective in identifying and correcting the full extent of the gas intrusion into the reactor coolant system, a condition adverse to quality, until September 5,1996, when, the licensee isolated the nitrogen gas leak and restored reactor vessel level. (03092) l l
2.
Between August 31 and September 6,1996,the licensee management l
and technical support responses to the nitrogen bubble ard de;;raded RHR subsystem events were fragmented and protracted, resulting in untimely corrective actions for significant conditions adverse to quality.
The untimely responses were reflected in the failure to fully appreciate the significance of the event, resulting in delays in initiating an integrated event response; establishing actual reactor vessel level; reestablishing control room indications for reactor vessel level and temperature;_ cligning a reactor coolant pump for service; and establishing and implementing an independent review team. Also, the actions to monitor the operating A RHR pump, following the B RHR pump failure, were not comprehensive or timely. (03102) 1 OFFICIAL RECORD COPY g:HADDAMR6.NOV i
Enclosure 19 t
l-l 3.
Between September 1 and September 26,1996, several avoidable delays were encountered in the licensee's corrective maintenance on the l
D flHR pump. These delays included a lack of quality replacement parts, inadequate vendor supplied information, lack of technical evaluations for floor block ramoval, and absence of appropriate vent locations.
However, this condition adverse to quality was not promptly corrected during this time. (03112) 4.
ACR 96-1106, dated September 26,1996, identified that approximately 600 gallons of unborated water was diverted to the reactor coolant system during a makeup to the refueling water storage tank. This event was caused by leak-through of a two inch chemical and volume control system manual globe valve (BA-V-367).
Prior to this event, five additional ACRs were prepared in September 1996, identifying various chemical and volume control system valves with leak-through, however, the diversion of the unborated water was not identified. (03122)
These violations in Section 11 represent a Severity Level 11 problem (Supplement 1).
Civil Penalty - $300,000 lll.
Violations Not Assessed a Civil Penalty Associated with Emeraency Plannina Deficiencies A.
10 CFR 50.54(q) states, in part, "A licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b) and the requirements in Appendix E of this part."
The licensee's Emergency Plan, Section 6, and Emergency Plan implementing Procedures (EPIP) 1.5.-1, Revision 29, Emergency Assessment Using EAL Tables, requires consistent with 10CFR 50.54(q), in part, the declaration of an Alert event, under TA2, Destructive Phenomena, Visible Damage to Structures or Equipment Affecting Safe Shutdown.
Contrary to the above, during an emergency exercise on August 14,1996, licensee personnel f ailed to make an Alert declaration early in the exercise, even though such a declaration was warranted because of simulated damage to the intake structure that could have affected safe-shutdown of the reactor (the Alert declaration was subsequently prompted by the lead controller), also, licensee personnel demonstrated confusion with the use of emergency action level (EAL) tables prior to the declaration of the General Emergency in that key decision makers incorrectly interpreted the barrier failure logic disgram and would have prematurely declared a General Emergency if they had not been corrected by other staff. (04013) 1 1
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1 Enclosure 20 l
B.
10 CFR 50.54(q) states,in part, "A licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b) and the requirements in Appendix i
E of this part."
EPIP 1.5-43, Personnel Radiation Control and Dosimetry issue During Nuclear l
Emergencies, requires consistent with 10CF7 50.54(q), in part, that guidance is provided for on site radiation exposure cont of for nuclear incident / accident l
emergencies; and Emergency Preparedness Operating Procedure (EPOP) 4428G, Revision 0, Protective Action Recommendations (PARS), requires, in part, that areas beyond the 10 mile emergency planning zone can be addressed on an ad hoc basis if the area is threatened by the plume.
Contrary to the above, during the emergency exercise on August 14,1996, the licensee, in responding to the exercise scenario, f ailed to implement protective actions based upon dose projections for the site emergency response organization at the emergency operations facility (EOF) and for personnel on site, and also failed to consider PARS beyond the 10 mile emergency planning zone which was threatened by the plume. Specifically, the licensee, in the exercise, did not make provisions for evacuating emergency operating f acilities and site personnel due to potentially high projected dose rates. (Because dose projections based on the scenario exceeded the protective action guideline of 10 rem for residents beyond the 10 mile radius, the PAR should have been extended to include those residents projected to receive greater than 1.0 rem.)
(04023)
These violations are classified in the aggregate as a Severity Level lll problem (Supplement Vill).
IV.
Other Violations Not Assessed a Civil Penaltv A.
TS 6.8.1 requires, in part, that written procedures be established, implemented and maintained in accordance with the provisions contained in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Procurement Engineering Group (PEG) Departmental Instruction PEG 6.05,
" Vendor Interface for Key Safety Related Components," provides the instruction to implement the Northeast Utilities commitment for vendor interface for key safety related components, as described in the licensee's response, dated April 19,1991, to NRC Generic Letter (GL) 90-03, " Relaxation of Staff Position in Generic Letter 83-28, item 2.2 Part 2, ' Vendor Interface for Safety-Related Components.'"
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Enclosure 21 Section 5 to PEG 6.05 requires that once per calendar year, the individual assigned responsibility will develop a list of key safety related components for the Connecticut Yankee and Millstone Units 1, 2, and 3 (sub-section 5.1);
identify the vendors for the key equipment (sub-section 5.1); review the file for each vendor, noting any audit findings, new design announcements, or related information (sub-section 5.4); develop a list of generic questions for each vendor (sub-section 5.5); and call each vendor and try to get the questions answered (sub-section 5.6).
Contrary to the above, the licensee did not execute PEG 6.05 during the calendar years 1994 and 1995 and therefore did not initiate vendor contacts during these years, consistent with the licensee response to GL 90-03 for key safety-related components. (05014)
This is a Severity Level IV violation (Supplement 1).
B.
10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality be prescribed by documented procedures.
10 CFR Part 50, Appendix B, Criterion XV, " Nonconforming Materials, Parts or Components," requires, in part, that measures be established for nonconforming materials, parts and components, which include procedures for disposition.
Contrary to the above, as of April 26,1996, the licensee did not provide procedural guidance for dispositioning non-conformance reports pertaining to non-QA materials that had been installed in safety-related applications. (06014)
This is a Severity Level IV violation (Supplement 1).
C.
10 CFR Part 50, Appendix J, Section ll.G, defines Type B tests, in part, as tests intended to measure leakage across leakage limiting boundary for primary reactor containment penetrations, including piping penetrations fitted with expansion bellows. TS 4.6.1.2.d states that containment leakage rates shall be demonstrated in conformance with the criteria in Appendix J of 10 CFR Part 50, and that Type 9 tests shall be conducted at intervals not greater than 24 l
months and at a pressure not less than Pa,39.6 psig.
l l
Contrary to the above:
1.
Penetration P-50, fuel transfer tube bellows assembly, has never been tested in accordance with the requirements of 10 CFR Part 50, Appendix J.
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Enclosure 22 2.
Containment penetration CN-2, hydraulic tubing that is part of the air lock door operating mechanism, has never been tested in accordance with Appendix J. (07014)
This is a Severity Level IV violation (Supplement I).
D.
10 CFR 50.72(b)(2)(iii)(B) requires the licensee to report within four hours of its l
occurrence an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat.
l Contrary to the above, the accumulation of nitrogen in the reactor vessel, which could have prevented the removal of residual heat, was discovered at 9:00 a.m.
l on September 1,1996 but was not reported until September 11, 1996.
(08014)
This is a Severity Level IV violation (Supplement 1).
l E.
TS 3.1.2.1 requires during reactor operations in Mode 5 that at least one boron injection flow path be operable.
l Contrary to the above, on August 28,1996, with the reactor in Mode 5, at least one boron injection flow path was not operable. Specifically, while attempting to establish a boron injection flowpath from the boric acid mix tank l
through a charging pump to the reactor in accordance with SUR 5.1-1598, a valve lineup error allowed nitrogen gas to be introduced into the charging system, rendering the boron injection flow path inoperable. The licensee failed to declare the boration flow path inoperable as nitrogen continued to leak into the charging system and the reactor from August 28,1996 until September 1, 1996.(09014)
This is a Severity Level IV violation (Supplement 1).
F.
10 CFR Part 50 Appendix B, Criterion lil, " Design Control." requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for structures, systems and components are correctly translated into specifications, drawings, procedures and instructions.
i Contrary to the above, as of September 27,1996, the results of design basis calculations for safety-related instrumentation setpoints were not translated into the plant TS and instrumentation calibration procedures as evidenced by the following examples:
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i Enclosure 23 l
1.
Setpoint calculations did not assure that the design basis requirements were translated into the TS allowable values for safety-related instrumentation. Specifically, incorrect allowable values were calculated 1
' for calculations that were performed to support a 24-month fuel cycle l
operation, including the following specific calculations:
l PA 90-013-321EY, Revision 1, " Uncertainty Calculation For Steam Flow Loops F-1201-1B,-1C,-2B,-2C,-38,-3D,-48,-4D and Setpoint Calculation For Steam Flow /Feedwater Flow Mismatch" x
PA 90-013-0341EY, Revision 1, " Uncertainty and Setpoint l
Calculation For Steam Line Break Flow F-1202-1,-2,-3,-4" 95-01262EY, Revision 0, " Uncertainties and Setpoints for RCS Flow Loops F-401 A, C, D 402A, C, D; 403A, C, D; 404A, C, D" 2.
The results of design basis calculations for instrumentation setpoints l
were not translated into instrumentation calibration surveillance procedure acceptance criteria. Specifica'ly, the instrument uncertainty l=
results of calculation PA 90-013-26EY Rev. 2, " Uncertainties and Setpoints for Steam Generator Narrow Range Level L-1301 1 A/C/D, i
2A/C/D, 3A/C/D, 4A/C/D," were not translated into appropriate calibration acceptance criteria in SUR 5.2-6.1, " Steam Generator #1 Narrow Range Level Channel Calibration," resulting in non-conservative.
acceptance criteria. (10014)
This is a Severity Level IV violation (Supplement 1).
G.
10 CFR Part 50 Appendix B, Criterion XVI, " Corrective Action," requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measuses shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.
Contrary to the above, during instrument calibrations performed in February 1995, Instrument Calibration Review Forms (ICRs)95-009,95-011,95-23,95-l 24, and 95-025 documented instrumentation calibration acceptance criteria failures and the licensee did not identify the cause of the failures or implement L
corrective action to prevent repetition. (11014)
{
This is a Severity Level IV violation (SLpplement 1).
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Enclosure 24 H.
TS 3.1.2.1 and 3.1.2.2 require that boron injection flow paths be operable during operation in Mode 5 & 6 and Modes 1 through 4, respectively, including i
a flow path from the boric acid tank to the metering pump. TS 4.1.2.1.a and 4.1.2.2.a require the temperature of the heat traced portion of the flow path from the boric acid tank to be greater than 140 degrees F.
Contrary to th'e above, during plant operation in Modes 1 through 6 prior to October 10,1996, certain locations in the boron injection flow path had temperatures which.were below the required minimum of 140 degrees F, rendering the associated portions of the boration system inoperable. On October 10, temperatures were measured to be as low as 120 degrees F in the gravity fead line to the metering pump, and 90 degrees F at the suction of the charging pumps at the junction of the discharge from the boric acid pumps.
(12014)
This is a Severity Level IV violation (Supplement 1).
l.
TS 6.8.1 requires, in part, that written procedures and/or administrative policies shall be established, implemented, and maintained covering the activities as recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A, Section F.25 requires procedures to be established to combat significant events such as irradiated fuel damage during refueling.
Contrary to the above, written procedures had not been established, implemented, and maintained in that prior to October 24.1996, a procedure to combat a significant event such as irradiated fuel damage during refueling did.
not exist. -(13014)
This is a S6 verity Level IV violation (Supplement 1).
J.
TS 3/4.9.12 requires the Fuel Storage Building Air Cleanup System to be operable and in operation during operations involving movement of fuel wi hin t
the storage pool or crane operation with loads over the storage pool with a flowrate of 4,000 + /- 10% cubic feet per minute (cfm). The TS action ctatement states with the Fuel Storage Building Air Cleanup System inoperable, or not operating, all operation with loads over the fuel storage pool are to be suspended.
Contrary to the above, between May 27 and June 14,1993, and between L
February 6 and February 28,1995, during fuel movement within the fuel l
storage pool, the Fuel Storage Building Air Cleanup System was inoperable, in that the system flowrate was less than 4,000 cfm + /-10%, and fuel movement l
operations were not suspended. (14014)
This is a Severity Level IV violation (Supplement 1).
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Enclosure 25 1
Pursuant to tne provisions of 10 CFR 2.201, Northeast Utilities Service Company (Licensee) is hereby required to submit a written statement or explanation to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice j
of Violation and Proposed Imposition of Civil Penalties (Notice). This reoly should be clearly marked as a " Reply to a Notice of Violation" and should include for each alleged violation:
(1) admission or denial of the alleged violation, (2) the reasons for the violation if admitted, and if denied, the reasons why, (3) the corrective steps that have been taken and the results l
achieved, (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an Order or a Demand for Information may be issued as to why the license should not be modified, suspended, or revoked or why such other action as may l
be proper should not be taken. Coni,ideration may be given to extending the response time l
for good cause shown. Under the authority of Section 182 of the Act,42 U.S.C. 2232, this response shall be submitted under oath or affirmation.
Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalties by letter addressed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable to the Treasurer of the United States in the cumulative amount of the civil penalties proposed above, or may protest imposition of the civil penalties, in whole or in part, by a written answer addressed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified, an order imposing j
l the civil penalties will be issued. Should the Licensee elect to file an answer in accordance l
with 10 CFR 2.205 protesting the civil penalties, in whole or in part, such answer should be clearly mariced as an " Answer to a Notice of Violation" and may: (1) deny the violations listed in this Notice, in whole or in part, (2) demonstrate extenuating circumstances, (3) show error l
in this Notice, or (4) show other reasons why the penalties should not be imposed. In addition to protesting the civil penalties, in whole or in part, such answer may request remission or mitigation of the penalties.
in requesting mitigation of the proposed penalties, the factors addressed in Section VI.B.2 of l
the Enforcement Policy should be addressed. Any written answer in accordance with 10 CFR l
2.205 should be set forth separately from the statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g., citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing civil i
penalties.
Upon failure to pay any civil penalties due which subsequently have been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalties, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Section 234(c) of the Act,42 U.S.C. 2282c.
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Enclosure 26 l
l The response noted above (Reply to Notice of Violation, letter with payment of civil penalties, l
and Answer to a Notice of Violation) should be addressed to: Director, Office of Enforcement, l
U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.
)
l 20555 with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission, l
Region I, and a copy to the NRC Resident inspector at the facility that is the subject of this l
Notice.
)
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Because your response will be placed in the NRC Public Document Room (PDR), to the extent possible, it chould not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redaction. However, if you find it necessary to include such inf ormation, you should clearly indicate the specific information that you desire not to be placed in the PDR, and provide the legal basis to support your request for withholding the information from the public.
Dated at King of Prussia, Pennsylvania this 12th day of May,1997 OFFICIAL RECORD COPY g:HADDAMR6.NOV