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EA-96-001 - Haddam Neck (Northeast Utilities Service Company)

May 12, 1997

EAs. 96-001, 96-286, 96-334, 96-337, 96-338, 96-339
96-340, 96-407, 96-440, 96-495

Mr. B. D. Kenyon - President
Nuclear Group
Northeast Utilities Service Company
Post Office Box 128
Waterford, Connecticut 06385

SUBJECT: NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTIES - $650,000 (NRC Inspection Report Nos. 50-213/95-27, 96-06, 96-07, 96-08, 96-11, 96-80, 96-201)

Dear Mr. Kenyon:

From November 21, 1995 through November 22, 1996, the NRC conducted numerous inspections at the Haddam Neck Plant in Haddam, Connecticut, to review several facets of plant performance. These inspections included a special team inspection by NRC headquarters staff focused principally on engineering performance; a special Augmented Inspection Team (AIT) inspection of a reactor vessel nitrogen intrusion event in August-September 1996 that led to lowering of the reactor vessel water level; an emergency preparedness inspection to observe your response during an emergency exercise in August 1996; and numerous resident inspections. All of the related inspection reports were previously sent to your organization.

Numerous violations, as well as several significant regulatory concerns, were identified during these inspections. One specific violation (the low pressure safety injection (LPSI) system flow rate being less than assumed in the accident analysis for a considerable period) was discussed at a predecisional enforcement conference in the NRC Region I office on February 12, 1996. Most of the other violations were discussed at a transcribed predecisional enforcement conference at the Millstone training building in Waterford, Connecticut on December 4, 1996. The December conference was open to the public. While the conferences were held to discuss the violations, their causes and your corrective actions, the December conference focused principally on the broader programmatic deficiencies underlying the violations that contributed to the problems at Haddam Neck. The violations related to the resident inspection completed on November 15, 1996, were not discussed during the December conference. However, Mr. T. Feigenbaum of your staff informed Mr. J. Rogge, Region I, on December 16, 1996, that you agreed that another predecisional enforcement conference was not needed to discuss these issues.

The specific violations are described in the enclosed Notice of Violation (NOV) and Proposed Imposition of Civil Penalties (Notice). The violations are grouped into a number of broad categories, namely, numerous longstanding deficiencies in engineering programs and practices, including plant design, design control, and engineering support, some of which led to significant safety equipment being inoperable or degraded for extended periods; numerous operational deficiencies, including inadequate procedures, failure to follow procedures, and inadequate corrective actions, which led to the "nitrogen intrusion" event; and inadequate implementation of the emergency preparedness program during the August 1996 exercise.

The engineering violations, which are set forth in Section I of the enclosed Notice, included the failure to assure that the plant was maintained as designed and specified in the Updated Final Safety Analysis Report (UFSAR); the introduction of additional design errors during design changes as a result of poor engineering; making design changes to the facility without performing adequate safety evaluations, including at least one instance where the change (removal of a flood protection floor block) involved an unreviewed safety question; not identifying or correcting adverse conditions that resulted from poor engineering, or the causes of those conditions; and not updating the UFSAR when required.

In many cases identified, applicable regulatory requirements and design bases were not correctly translated into specifications, drawings, procedures and instructions. Formal design calculations and analyses were, at times, based on incorrect assumptions, and were not sufficient to confirm that the systems would work as intended. These calculations, needed to assure that appropriate safety margins exist, frequently lacked technical rigor, thoroughness, and attention to detail. Overall, there was a general lack of understanding and appreciation for the relationship among NRC requirements, the design basis, the licensing basis, industry codes and standards, and your administrative procedures. Also, in these particular cases, engineering supervisors, independent design reviewers, and oversight committees generally failed to identify the deficiencies, or related root causes, or when identified, failed to ensure appropriate or comprehensive corrective action. Further, line management's responses to self-assessments, QA audits, and third party reviews were inadequate. A particularly egregious case involved the failure to initiate formal corrective actions for the LPSI design deficiency discussed during the February 1996 enforcement conference. Although you committed to a review of the licensing basis for a number of plant systems to ensure that similar deficiencies, if they existed, were identified and corrected, at the time of the special inspection team visit in April 1996, appropriate action had not yet been taken to follow-up on this commitment, and the commitment had not even been assigned to anyone for action.

As a result of these significant engineering failures, margins of safety for certain safety related equipment were reduced, at times, for extended periods. In some cases, inadequate engineering led to conditions contrary to technical specifications (TS), in that safety equipment would not perform its intended safety function if needed. For example, inadequate sizing of pipes from the containment sump to the Residual Heat Removal (RHR) pump suction resulted in insufficient net positive suction head (NPSH) to support RHR pump operation without relying on containment backpressure. Reliance on containment backpressure was inappropriate because it could result in RHR pump cavitation and pump failure if the predicted backpressure was not available. The significance of this violation was high, as you acknowledged during the enforcement conference, because the inadequate NPSH could result in the common mode failure of the long-term reactor recirculation function, and increase the projected core damage frequency as a result of this deficiency. Another example involved the inoperability of the recirculation phase flowpath needed to mitigate postulated Loss of Coolant Accidents (LOCA) because the containment sump screen mesh holes were larger than originally assumed in the analyses. This deficiency, for which several opportunities existed to identify and correct it over the years, could have resulted in the clogging of downstream ECCS components and rendering them inoperable during an accident. In a third example, all four Containment Air Recirculation (CAR) units were inoperable, in that engineering analysis showed that the structural limits on the piping for the service water system, a support system for the CAR units, would be exceeded due to waterhammer loads. After identifying this deficiency, you shut down the plant on July 22, 1996.

In addition to the engineering deficiencies, numerous operational concerns existed that were identified during the NRC AIT inspection of the inadvertent decrease of reactor vessel water level in August and September 1996 while the plant was shutdown. For approximately four days, control room operators were unaware that nitrogen gas was leaking into the reactor vessel, displacing reactor water, and causing reactor water level to decrease to approximately 3 feet below the reactor vessel flange. After they became aware of the leakage, management was slow to appreciate the significance and effectively respond, as described in the Notice. Further decrease in the water level could have challenged the function of the operating decay heat removal system. Several operations procedures failed to provide adequate details, or contained incorrect information, which contributed to both the nitrogen gas intrusion going undetected, and the inadvertent diversion of water from the reactor coolant system (RCS). Several events were exacerbated by plant operators' failing to follow plant procedures, conducting activities without procedural guidance, and making inappropriate decisions, such as not carefully accounting for the inventory while draining the reactor on August 29, or unisolating a reactor coolant loop on September 1 without taking appropriate boron samples. A lack of a questioning attitude led to not promptly identifying the nitrogen gas accumulation in the reactor vessel. Further, senior operators did not convey expectations to less experienced field operators during pre-job briefings, which led to inappropriate equipment manipulations that either directly caused or contributed to these events.

The nitrogen intrusion event further revealed other deficiencies at the facility. For example, the timeliness of maintenance activities to restore an inoperable RHR pump to service and to maintain several isolation valves was inadequate. Quality parts and vendor specifications were unavailable, and repeated post-maintenance test failures resulted in having only a single RHR pump available for at least 3 weeks. Several isolation valves were in poor material condition and leaked, allowing the nitrogen gas to inadvertently enter the reactor vessel and water from the RCS to be diverted to the containment sump. In addition, although the temporary reactor vent header was significantly degraded, management, over several years, failed to provide an effective response to previous plant staff concerns to improve the temporary vent system. The poor vent header design allowed nitrogen gas to accumulate in the reactor vessel during the event. Further, the absence of direct indication of reactor vessel water level masked the situation. Engineering, operations, and management did not fully evaluate and understand the vulnerabilities introduced by the decision to delay reactor disassembly while reactor water level instrumentation was disconnected. In effect, the licensee's support staff and management created conditions that set up the plant and control room operators for this event. Afterwards, management's overall response to the event was neither comprehensive nor timely as noted in Violation II.D. The related violations are described in Section II of the enclosed Notice.

With respect to the emergency preparedness activities, during the August 1996 exercise, your staff failed to recognize the need for an Alert declaration early in the exercise, and later, following declaration of a General Emergency, failed to implement appropriate protective actions for onsite personnel, and failed to recommend appropriate protective actions for areas outside the 10 mile emergency planning zone, based on the dose projections during the exercise. Overstaffing of key site emergency response organization (SERO) positions with two and three individuals very early in the exercise caused confusion and problems for other individuals initially assigned to the SERO. Due to the overstaffing, it was not possible to determine if the plan could be implemented with minimum staffing as specified in the plan. Two violations were identified as described in the proposal. The staff notes that it does not normally issue citations for exercise deficiencies. However, the NRC is issuing citations in this case, in accordance with the enforcement policy, because the exercise revealed recurring weaknesses in making protective action recommendations at Haddam Neck, as noted in Inspection Report 96-07, indicating that effective corrective action had not been taken. A civil penalty is not being issued for these violations.

Although the violations described in the enclosed Notice did not result in any actual consequences to public health and safety, these violations and underlying causes demonstrated significant departures from the defense-in-depth principles upon which nuclear power plants are designed, built, and operated, and upon which the NRC relies to ensure nuclear power plant operation does not jeopardize public health and safety. These events and inspection findings revealed significant deficiencies in several facets of the Haddam Neck operation. Many of these violations should have been identified and corrected sooner. In other cases, corrective action was not taken after the violations were identified. Many of the violations were caused by a lack of a questioning attitude by your staff. Also, managers should have conveyed high safety standards to the staff to seek, find, evaluate, and correct problems. This did not occur.

At the enforcement conference, you admitted the violations and you noted that a number of the violations would be applicable even with the reactor in a defueled stage. You also acknowledged that there were significant deficiencies at Haddam Neck that must be fully addressed before you could contemplate significant decommissioning efforts at Haddam Neck. Further, you described a number of corrective actions that had been either taken or planned to address the programmatic weaknesses. Among those actions were the establishment and communication of specific management expectations; implementation of new plant processes and programs; assignment of a dedicated manager to implement an effective corrective action program, and benchmarking the program against other plants.

Also during the December 4, 1996 conference, you announced that your Board of Directors had approved the decision to permanently shut down and decommission the Haddam Neck facility. Notwithstanding that decision, a number of these issues also apply to the shutdown condition, as you acknowledged at the conference, and it is imperative that the underlying flaws in management and staff performance, as already described herein, are corrected. Management must set high standards and expectations, and see to it that they are met.

Therefore, in consideration of (1) the high regulatory significance that the NRC attaches to these violations, (2) the importance of emphasizing the need for effective management and oversight during the decommissioning process, as well as effective management and oversight at your Millstone and Seabrook facilities, and (3) the importance of emphasizing to other reactor licensees the need for effective oversight of their nuclear power plants, I have been authorized, after consultation with the Director, Office of Enforcement, the Executive Director of Operations, and the Commission, to exercise enforcement discretion pursuant to Section VII.A.1 of the Enforcement Policy and issue the enclosed Notice of Violation and Proposed Imposition of Civil Penalties in the cumulative amount of $650,000 for the violations discussed above.

This penalty is based on $200,000 for the violations in Parts I.A-I.C of the Notice (programmatic engineering violations with a $50,000 civil penalty for each of the three functional areas in which the related violations are categorized with an additional $50,000 civil penalty for violation I.C.1.f because of the failure to have initiated by April 1996, the corrective actions committed to at a February 1996 enforcement conference regarding a design deficiency associated with the LPSI system); $150,000 for the violations in Part I.D ($50,000 penalty for each of three technical specification limiting conditions for operation violations caused by inadequate engineering); and $300,000 for the violations in Part II ($100,000 for the violations in the Sections II.A-B, $50,000 for the violation in Section II.C for failure to ensure adequate instrumentation, as well as $150,000 for the violations in Section II.D for management's failure to take appropriate corrective action - the $150,000 penalty is based on a penalty of $25,000 for each of at least six days that licensee management failed to ensure appropriate instrumentation and recognize and effectively respond to the scope of the event). Classified as Severity Level III in Part III, but not assessed a civil penalty, are the two violations associated with the recurring emergency exercise weaknesses. Certain other violations identified during the inspections were classified at Severity Level IV and are set forth in Section IV of the enclosed Notice. I note that, but for the decision to shut down the Haddam Neck facility, the penalty may have been higher.

Other matters involving Haddam Neck are currently under review that may result in further enforcement sanctions. In addition, the NRC is still considering escalated action regarding the Millstone facilities for numerous violations discussed at an enforcement conference on December 5, 1996. Enforcement action for these violations will be covered by separate correspondence at a later date.

You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. The NRC will use your response, in part, to determine whether further enforcement action is necessary to ensure compliance with regulatory requirements.

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and your response will be placed in the NRC Public Document Room (PDR). Your response may, as appropriate, make reference to the materials you provided at the enforcement conference on December 4, 1996. To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redaction.

Should you have any questions concerning this letter, please contact Mr. James Lieberman, Director, Office of Enforcement, at (301) 415-2741.

Sincerely, Hubert J. Miller Regional Administrator

Docket No. 50-213
License No. DPR-61

Enclosure:
Notice of Violation and Proposed Imposition of Civil Penalties

cc w/encl:
T. Feigenbaum, Executive Vice President and Chief Nuclear Officer
D. Goebel Vice President - Nuclear Oversight
F. Rothen, Vice President - Nuclear Work Services
J. Thayer, Recovery Officer, Nuclear Engineering and Support
J. LaPlatney, Nuclear Unit Director
L. Cuoco, Senior Nuclear Counsel
G. van Noordennen, Manager, Nuclear Licensing
R. Johannes, Director - Nuclear Training
J. Smith, Manager, Operator Training
W. Meinert, Nuclear Engineer
R. Bassilakis, Citizens Awareness Network
J. Block, Attorney for CAN
J. Brooks, CT Attorney General Office
M. DeBold, Town of Haddam
State of Connecticut SLO

NOTICE OF VIOLATION AND 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 EAs 96-001, 96-286, 96-334, 96-337 96-338, 96-339, 96-340, 96-407, 96-440, 96-495

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:

I. Violations Related to Inadequate Engineering

A. Errors in Design Basis Documents or Errors Introduced by Design Changes
10 CFR Part 50, Appendix B, Criterion III, "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. 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, drawings, procedures and instructions, or did not assure that activities affecting quality were correctly prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances as evidenced by the following examples, each of which constitutes an individual violation:
1.*⁽¹⁾ 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 O, 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 calculation, 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 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 factor. 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 during 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) performance for Cycle 19 operations. Thus, the licensee failed to 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 request, dated March 7, 1996, to the CAR fan surveillance testing acceptance criteria, did not appropriately consider the fan performance 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 was used in the analysis of the impact of leak sealant injection into the four feedwater regulating valves, used a design pressure of 1000 psi in the calculation even though the actual design pressure of the system 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 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 an inadvertent shutdown of the EDGs. (01112)
12.* Calculation Change Notices 1 through 5 were initiated for Calculation PA78-741-01-GE, "Diesel Generator Automatic Loading Analysis," 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 loading 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 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-059, dated January 1, 1996, to plant operators to address the impact of the loss of service water flow indication to the containment air 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 revised calculation determined temperatures could reach 252 degrees F under certain conditions, and as of April 26, 1996, the effect of the containment temperature changes on the operability of the RHR heat 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. 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 attached components. (01162)

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," which assumed the pumps would be turned off 10 minutes after the initiation of a large break loss of coolant accident (LOCA). However, the 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 hydrodynamic loading, and based the calculation on the assumption that the downstream vent valve was opened first during the venting sequence to prevent the impact of any fluid on a partially opened 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-I.3, "Response to Voids in Reactor Vessel," Revision 10, dated March 20, 1995 which was inadequate in that it directed the operators to open both reactor coolant system head vents in the same step. (01182)
19. On August 17, 1973, as part of plant modification Plant Design Change Request (PDCR) 156, Flooding Protection of Safeguards Equipment, 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 than 12 minutes (approximately 8 minutes). (01192)
B. Inadequate, or Lack of Safety Evaluations and Failures to Update the Final Safety Analysis Report
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 USQ.
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:
a. During the week of March 25, 1996, in order to facilitate 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 Figure 3.8-15. (01202)
b. PDCR 1411, completed on August 13, 1994, removed breathing air stations inside containment and changed the air connections to support the use of portable air units, even though these 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 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 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 control air system uses three air dryers that are of the activated 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 the control of secondary water chemistry, even though UFSAR Section 10.3.5, "Water Chemistry," states that secondary water chemistry is controlled using chemical feed equipment that adds hydrazine to the condensate system, and does not mention ETA. (01242)
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 licensee 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 Criteria," inaccurately described maximum snow loadings for safety-related structures as 60 lb/ft² although the original design specifications and as-built construction were for 40 lb/ft². As the safety related structures were not designed and constructed for 60 lb/ft² 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/ft² to 40 lb/ft², to agree with the original design specifications, without a safety evaluation to determine that the as-found condition did not constitute a USQ. (01252)
b. Prior 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 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 evaluation associated with PDCR 1435, "Replacing Battery Charger BC-1-1A," Revision 0, dated February 28, 1994, did not adequately assess the possibility of a malfunction of a different type than previously evaluated 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)
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 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.
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 regulating valve could not close under main steam line break conditions, even though UFSAR Section 15.2.9., states that the following functions provide the protection for a steam line rupture, "isolation of the main feedwater lines by two valves in series will occur on a safety injection actuation. This is done via closure of the feedwater isolation valve and the feedwater regulating valve after a short time delay." Thus, the licensee safety evaluations previously completed for modifications to the feedwater line isolation system were inadequate in that the existence of a USQ was not identified; namely, the safety evaluations for plant modifications per PDCR 423 in October 1981; the safety evaluations to support TS License Amendment No. 125 in 1991; and the safety evaluations for PDCR 1533 in February 1995. (01282)
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 each 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 6 months prior to the previous UFSAR update, as evidenced by the following examples, each of which constitutes an individual violation:
a. UFSAR Table 9.2-1, "Service Water Major Component Interface," lists the "approximate required" service water flow rate for the individual components such as the diesel generator, residual heat removal heat exchanger, and spent fuel pool plate heat 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 the "CY Service Water System GL 89-13 Item IV, Design Basis Summary Report," dated July 15, 1994, the UFSAR had not been updated as of April 26, 1996. (01292)
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 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 incomplete in that although high containment pressure is an input that 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 Crosstie Isolation Valves, which were installed in 1988 in accordance with PDCR 854, the UFSAR had not been updated as of April 26, 1996. (01312)
d. UFSAR Section 6.3.2.2, "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 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 April 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 hours 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 long-term sump recirculation is to be established at 1.5 hours, 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 valve lineups 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)
g. UFSAR Section 8.3.2.1.2, "Battery Chargers," states that during 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. Inadequate 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 determined and corrective action taken to preclude repetition.
1. 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 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)
b. The licensee identified in 1989 that instrument uncertainties had not been incorporated into the establishment of the EOP decision 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 review was completed in March 1994. However, as of April 26, 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 level instruments meet the criteria specified in Regulatory Guide 1.97. Northeast 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 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, 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 review the licensee's implementation of actions taken in response to the station blackout requirements in 10 CFR 50.63. The third party audit identified deficiencies in the licensee's implementation of the station blackout rule, including inadequate calculations for 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 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 procedure and TS. However, as of April 26, 1996, appropriate corrective action had not been taken in that the licensee had not revised the surveillance procedure or TS, resulting in the design basis 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 potential for screen mesh size to be different than designed based on such a finding at Millstone 2; however, the licensee did not identify that the containment sump screen mesh holes at Haddam Neck were .5 inches rather than .375 inches assumed in licensee 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 in the LER, and additional deficiencies that could have contributed to the surveillance failures were identified by the NRC during the week of April 15, 1996. (01442)
b. In March 1995, the licensee replaced battery charger BC-1-1A with a new solid state design. During testing and subsequent operation, the battery exhibited ammeter fluctuations as documented in trouble report 15-CY-14018 BC 1-1A, dated March 1, 1995. On November 2, 1995, ACR 95-433 was issued 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 I.A-I.C represent a Severity Level II problem (Supplement I). Civil Penalty - $200,000
D. Violations of Technical Specifications Caused by Inadequate Engineering
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 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) 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 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.
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 accident. (02022)
3. TS 3.6.2 requires at least four CAR units to be operable in Modes 1, 2, 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 hours or be in at least hot standby within the next six hours and in cold shutdown within the following 30 hours.
Contrary to the above, during all times when the reactor was in Modes 1, 2, 3, and 4 prior to July 22, 1996, all four CAR units were inoperable in that they could not have performed their intended function during LOCAs. Specifically, engineering analysis concluded that the service water piping structural limits would be exceeded due to waterhammer loads. The service water system is a support system for the CAR units and a part of the primary containment boundary. (02032)

These violations in Section I.D represent a Severity Level II problem (Supplement I). Civil Penalty - $150,000
II. Violations Associated with the Nitrogen 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-261A, 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)
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 required prior to opening the loop stop isolation valves. (03052)
6. On September 3, 1996, NOP 2.9-6, "Primary Vent Header Operation," required the installation of a vacuum pump to vent the reactor coolant loops. This procedure was not properly implemented in that during the NRC walkdown of the system, no vacuum pump installation connections were available to support venting the reactor coolant loops, and the 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-condensible 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 implementation.
Contrary to the above:
1. On August 28, 1996, and September 1, 1996, 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 prescribed by procedures appropriate to the circumstances, and shall 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 filled and vented condition from August 29 - September 3, 1996 was inadequate in that operators lacked the reactor vessel level and core exit 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 failures, 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 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)
2. Between August 31 and September 6, 1996, the licensee management and technical support responses to the nitrogen bubble and degraded 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; aligning 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)
3. Between September 1 and September 26, 1996, several avoidable delays were encountered in the licensee's corrective maintenance on the B RHR pump. These delays included a lack of quality replacement parts, inadequate vendor supplied information, lack of technical evaluations for floor block removal, 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 II represent a Severity Level II problem (Supplement I). Civil Penalty - $300,000
III. Violations Not Assessed a Civil Penalty Associated with Emergency Planning 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 failed 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 diagram and would have prematurely declared a General Emergency if they had not been corrected by other staff. (04013)
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 E of this part."
EPIP 1.5-43, Personnel Radiation Control and Dosimetry Issue During Nuclear Emergencies, requires consistent with 10CFR 50.54(q), in part, that guidance is provided for on site radiation exposure control for nuclear incident/accident 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, failed 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 facilities 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 III problem (Supplement VIII).
IV. Other Violations Not Assessed a Civil Penalty
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.'"
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)