IR 05000029/1987011
| ML20149M174 | |
| Person / Time | |
|---|---|
| Site: | Yankee Rowe |
| Issue date: | 02/19/1988 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20149M170 | List: |
| References | |
| 50-029-87-11, 50-29-87-11, IEB-80-08, IEB-80-8, NUDOCS 8802250387 | |
| Download: ML20149M174 (36) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-29/87-11 Docket No.
50-29 Licensee No.
DPR-3 Licensee:
Yankee Atomic Electric Company 1671 Worcester Road Framingham, Massachusetts 01701 Facility Name:
Yankee Nuclear Power Station Inspection at:
Rowe, Massachusetts Inspection Conducted: July 21_- October 26, 1987 Inspectors:
Harold Eichenholz, Senior Resident Inspector David G. Ruscitto, Resident Inspector, Seabrook e~ M 2/M/JP Approved By:
audA DonaldR.Haverkamp, Chief,RgyttorProjectsSection3C Date
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Inspection Summary: Inspection on July 21 - October 26, 1987 (Report No. 50-29/87-11)
Areas Inspected:
Routine onsite regular and backshif t inspection by two resi-dent inspectors (254 hours0.00294 days <br />0.0706 hours <br />4.199735e-4 weeks <br />9.6647e-5 months <br />). Areas inspected included licensee action on pre-vious inspection findings, operational safety verification, bimonthly safety system verification, radiological controls, events requiring telephone notifi-cation to the NRC, plant events, maintenance observations, surveillance obser-vations, check valves inspection program (licensee response to INPO SOER No.
86-3), plant in forma tion reports, Regional Administrator's facility tour, licensee response to NRC Bulletins, bulk containment temperature limits and experience, arsnual retraining, attentiveness to licensed duties, and inspection of GE Type AK-F-2-25 breakers.
Results: No violations or deviations were identified. However, two unresolved items were identified regarding: (1) licensee-identified failure to provide personnel monitoring reports in accordance with 10 CFR 20.408 and 20.409 (Section 6), and (2) the acceptability of using a low span gas to perform a Technical Spectitcation (TS) calibration on the high range of the post-accident Bendix hydrogen analyzers (Section 10).
In addition, seven open items of concern were identified regarding: (1) clari-fications needed for TS Sections 3.5.2 and 4.5.2 (Section 4.a(5)); (2) appro-priate performance of preventive maintenance inspections of pump discharge check valves (Section 9); (3) the need to provide operators with a clear de-finition of "associated flow paths" of emergency feedwater pumps as specified 9802250307 880219 PDR ADOCK 05000029 G
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in TS 3,7,1.2 (Section 9); (4) poor or lacking documentation, in implementing procedures, of identified deficiencies that resulted from performance of sur-veillance (Sections 9 and 10); (5) inadequacies of procedure OP-5751, "Heat Tracing," with respect to maintaining the proper setpoint relationship between thermostats (Section 10); (6) appropriate documentation in the control room log of the initiation and completion of TS-required surveillance testing (Section 10); and, (7) untimely supervisory review by the instru;nent and controls (I&C)
department following completion of TS-required surveillances (Section 10).
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DETAILS 1.
persons Contacted Yankee Nuclear Power Station B. Drawbridge, Assistant Plant Superintendent T. Henderson, Technical Director N. St. Laurent, Plant Superintendent The inspector also interviewed other licensee employees during the instac-tion, including members of the operations, radiation protection, chemistry, instrument and control, maintenance, reactor engineering, security, train-ing, technical services, and general office staffs.
2.
Summary of Facility and NRC Activities At the completion of the last resident inspection period on July 20, 1987, the plant was at 100% of rated power.
Plant conditions remained stable until July 31, 1987. On that date, a planned load reduction to the start-up mode (Mode 2) was initiated to repair a small steam leak on the high pressure turbine impulse chamber drain line.
The generator was phased to the grid late in the day on August 1,1987 and the plant achieved 100% of rated power on August 4, 1987.
Another planned load reduction to the startup mode was conducted on August 6,1987 to enable repair activity as a result of a body-to-bonnet steam leak on the No.1 steam generator blow down line check valve.
The generator was phased to the grid on August 7, 1987.
The plant achieved 100% of rated power on August 10, 1987, and remained at that power level until September 18, 1987. On that date, an emergency load reduction to 73% of rated power was initiated by the plant operators in response to a packing failure on the No. 1 feedwater heater drain pump.
The plant returned to normal full power operations on September 20, 1937.
Subsequently, on September 28, 1987 the plant operators initiated a planned load reduction to 73% of rated power to repair a packing leak on the No. 1 feedwater heater drain pump. The plant was returned to 100% of rated power later on that day, and remained at that power level until October 14, 1987. On that date, a planned load reduction to the start-up mode was initiated to enable repair activity as a result of a body-to-bonnet steam leak on the No. 4 steam generator blowdown ' ? ie check valve.
An emergency load reduction was implemented approximately six hours into the load reduction due to a blown gasket on the main condenser steam dump valve. The generator was phased to the grid on October 15, 1987 following repairs to the plant however, it became necessary te remove the plant from the grid and reduce power to the startup mode on October 16, 1987 to facilitate repair of a packing leak on the No. I main steam line non-return valve.
Following phasing the generator to the grid on October 16, 1987, the plant achieved 100% of rated power on October 19, 1987, and remained essentially at that pover level through the remairder of the inspection period.
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Early in the current operating :ycle the dose equivalent iodine (DEI)
concentrations of the main coolaiiit system indicated that the current fuel load had experienced cladding failure. On October 15, 1987, following the plant being returned to power operation and the generator phased to the grid, the DEI concentration was found to be 1.23 microcurias per gram, a value that is in excess of the Technical Specif1 cations (TS) limit of 1.0 microcurie per gram.
By October 17, 1987, the DEI concentration in the main coolant system had returned to pre-shutdown levels of between five and seven percent of the TS limit.
An NRC Region I (NRC:RI) specialist inspector completed an inspection in the area of nonlicensed staff training during the period of August 10-14, 1987 (Inspection Report No. 50-29/87-12).
During the period of August 30 to September 2,1987, NRC:RI specialist inspectors completed reviews of the emergency preparedness program (Inspection Report No. 50-29/87-13) and the licensed operator training program (Inspection Report No. 50-29/87-14).
Additional resident inspector coverage was provided for five days in August 1987 by the resident inspector of Seabrook Station, Unit 1,
Seabrook, New Hampshire.
3.
Licensee Action on Previous Inspection Findings a.
(Closed) Unresolved item 87-04-02: Using a special order in lieu of the approved procedure change process.
On February 11, 1987 special order No. 87-18 was issued that effectively instructed the plant operators to disregard the 40 MVAR limit in a precautien statement of procedure OP-2107, Rev. 12, Changing Generator Load. The special order also included an engineering evaluation documenting the basis for no longer requirirg the limit. Tne inspector determined that the licensee practice of effectively changing a procedural requirement by the use of a special order was contrary to the intent of procedures AP-2006 and AP-0001.
Powever, the actions in this particular case did not raise any safety significant issues.
In May, 1987, procedure OP-2107, Rev. 13, was issued that officially removed the subject limitation.
During the prior SALP period (SALP Report 50-29/85-98), the NRC specified the need for the licensee to insure that the special orders were not being used in lieu of approved procedures.
The inspector has been reviewing on a continual basis all special orders to detect recurrence of poor licensee performance in this area. No additional inadequacies have been identified.
The inspector's observations supports the operations department management's claim that they have reviewed their practices, are properly sensitized to the issue, and have implemented effective corrective actions to preclude recurrence.
This item is close.
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b.
(0 pen) Violation 86-17-01:
Quality assurance program ' deficiencies.
The licensee responded to this violation on February 18, 1987 in letter FYR 87-017.
This response identified corrective action and
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time schedules for completion of such action.. The NRC closure of i
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this violation and related violation 85-01-04 will be composed of two separate reviews. During this reporting period, procedure revisions, organizational changes and training records were reviewed.
In' a follow-on inspection, actual maintenance request (MR) and quality
control (QC) records will be reviewed to determine the status of implementation of the programmatic changes made as a result of these violations.
The inspector reviewed Revisions 1 and 2 to procedure OQA-X-5,
"Quality Control Inspections". The responsibilities of the quality l
services manager, quality assurance supervisor and the quality con-trol inspectors were adequately addressed.
The QC forms have been
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revised and QC implementing instructions are being written. A review of the QC -instructions completed to date was conducted.
The method-ology employed in the development of the instructions was effective in providing specific guidance to the QC inspectors. Notable changes
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were made in the area of MR reviews. This task has been assigned to
the quality services grcup of the Yankee Atomic Electric Company nuclear services division (YNSD).
New guidelines, specifically with regard to holdpoints and design changes, have been expanded to pro-vide a more useful reference document. Additionally, the inspector revieweJ revisions to the following procedures:
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AP-0205, Revision 11, Maintenance Request AP-0209, Revision 9, Inspections OP-5103, Revision 8, Inspection, Maintenance and Testing of Safety / Relief Valves The documentation of discrepancies is another area in which the QA procedure has been revised.
Establishment of a deficiency /observa-
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tion report (00R) and a request for information record provides a prioritization of discrepancies and inspector inquiries iden ified c
during inspections.
The minimum distribution on a 00R includes the appropriate level of management.
Discussion with licensee QA engi-neers and supervisors indicates that efforts in program improvement
are properly directed and that progress is being made. Although it appears that programmatic controls have been improved, these two i
violaHons shall remain open pending additional review of recently
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completed and in progress MRs and QC inspection records.
In response to Item No. 1 of the violation, the licensee committed, i
in part, to revise procedure AP-0205 and provide training for appro-priate maintenance and operations personnel.
These corrective
measures were to be completed by May 1, 1987. Although the procedure
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revision was reviewed and approved at PORC on April 30, 1987, it was i
not issued for use until May 28, 1987.
This revision to procedure i
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AP-0205 added guidance and clarification on.the adequacy of detail necessary when initiating, performing, completing and cancelling an
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MR. According to licensee records, the training occurred in June.and.
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July, 1987.
The inspector noted that with regard to this training, the. licensee did not involve the training department in 1) developing the appropriate method of training. and 2) providing an assessment of training effectiveness. The training implemented involved personnel of the maintenance and operations departments' reviewing a memorandum from the quality assurance supervisor that provided information about I
the violation and an -outline of revisions to procedure Ap-0205.
During the period May 2 through-July 2, 1987, the plant was in a refueling status.
The NRC Inspection Report 50-29/87-06 (IR 87-06)
documented inspector observations during.that period, some of which involved deficiencies associated with licensee failure to adhere to requirements of procedure AP-0205.
There appears to have been a causal. relationship between those deficiencies and the untimely and
ineffective corrective measures associated with revising the proced-ure.
However, as documented in IR 87-06, the licensee had already
adequately addressed the need for further short-term and long-term j
corrective actions. Among the short-term measures identified was the
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need to conduct special training - sessions for maintenance groups, operations and training personnel, and QA department personnel that
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included the following:
1) review recent significant events in-
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volving poor maintenance performance; 2) review -the basis for the procedural steps of AP-0205; 3) a discussion of.the proper use-of the
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Safety Class Manual; 4) a discussion with the supervisors on proper
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assignment of jobs and proper close out of jobs; 5) a discussion of proper job planning and briefing prior to work; 6) a discussion with i
supervisors en observation of job performance; 7) a discussion of
quality in work practices; and 8) a discussion of maintenance de-partment personnel responsibilities versus QA department responsi-bilities.
The special training sessions were conducted by the assistant plant superintendent and were completed by September 21, 1987.
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Additional reviews were conducted by the inspector to determine the underlying reasons for the licensee's failure to provide timely and i
effective corrective actions involved with Item No.1 of the viola-
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tion. Part of the reason appears to have been the inability of plant l
personnel to be responsive to the commitments at the time they were
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involved in preparing for and conducting outage related activities.
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Although the Project Commitment Tracking and Responsibility (PROCTR)
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System specified a due date of May 1, 1987 for completion of the j
i revision to procedure AP-0205, the technical services department
j-closed the item on May 1,1987 using the PORC review and approval as
the basis that the item was complete.
There were no entries in the PROCTR system to track the licensee's commitment for training on the
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i revised procedure.
On March 16, 1987 the quality assurance depart-ment was requested to monitor licensee commitments associated with
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i this violation. The QA department assigned a completion date of May 8,1987 to review the status of the licensee commitment associated with Item No.
1.
According to their May 8, 1987 review, as docu-
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mented in licensee Memo QAD 87-393/1.2.A, the procedure issuance i
would not be accomplished for two to three weeks, and at that time, no training had been performed on the procedural changes. A similar memo, QAD 87-454/1.2.14, reported on June 8,1987 that the procedure
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AP-0205 was revised, however, no training was provided to date. Both temoranda were distributed to corporate and site personnel, however, tris identification of implementing deficiencies did not result in any additional management attention to correct the condition. Addi-tional corrective actions by the licensee to address the apparent breakdown in commitment tracking and control, and inadequate manage-
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ment oversight, are warranted.
4.
Operational Safety Verification
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Daily Inspection During routine facility tours, the inspector checked the following items:
shift manning, access control, adherence to procedures and limiting conditions for operations (LCOs), instrumentation, recorder traces, protective systems, control rod positions, containment tem-
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perature and pressure, control room annunciators, radiation monitors, i
radiation monitoring, emergency power source operability, control
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room and shift supervisor log, tagout log, and operating orders.
l Based upon a review of licensee activities in this area the inspector noted the following:
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(1) During a plant tour on July 21, 1987, the inspector observed out
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of date calibration stickers on various plant instruments. Sub-I j
sequent to bringing the specific information to the attention of the I&C supervisor, the inspector verified that the licensee i
corrected the condition in a timely manner, and that instruments j
were currently calibrated.
The inspector was informed by the l
I&C supervisor that because this was a recurring problem, and that the stickers were not used to control calibration activity, the licensee planned on deleting the use of calibration stickers on all installed instruments calibrated by the I&C department.
In August 1987, tne licensee revised the applicable procedure to l
delete the use of calibration stickers.
The inspector had no further questions on this item.
(2) While inspecting the plant vent stack radiation monitor on August 18, 1987, the inspector discovered two tygon temporary sample tubes connected to quick-disconnect fittings on the in-lets to each sample chamber.
These lines were open to atmos-
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i phere and since they are located in the suction lines to the vacuum pumps, air could be drawn into the major sample lines.
At the time, the plant was operating at full power with the
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stack monitor on line as required by the Technical Specifica-tions.
The inspector discussed the system configuration with the on-duty radiation protection (RP) technician who investi-gated the lineup. The RP manager subsequently ordered the tem-porary tubing removed and conducted a dilution calculation to analyze the potential effect on gaseous effluent release date.
These calculations revealed that although a dilution path did exist, the maximum error was 1.0%.
While not a significant amount, the effluent release data will be revised to more accur-ately reflect total activity released.
It is estimated that this system anomaly had remained undetected since May 1,1987 when the last grab sample was taken on the PVS monitor. The RP manager indicated that the sampling procedure, OP-8041, would be revised to ensure that the temporary hoses will be disconnected following future samples. Based upon the magnitude of the dilu-tion and responsive licensee corrective action, the inspector had no further concerns.
(3) At the beginning of this inspection period the licensee assigned the four recently licensed reactor operators to temporary shif t duties as spare control room operators.
On August 16, 1987, these four individuals were promoted to control room operators.
At that time, a temporary roster expansion to fourteen control room operators was effected.
Each of the spare control room operators was assigned to a shift (of which there are five),
which will allow these licensed operators to be integrated into the segmented operator licensing requalification program.
On September 27, 1987, the licensee transferred one of their senior reactor operator licensed instructors to the operations depart-ment to facilitate his assignment as a senior control room oper-ator. At the end of the inspection period, there were six shif t supervisors and six senior control room operators assigned to shift duties.
The inspector noted that the licensee has placed a high priority in developing overall depth of licensed operator
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staffing levels.
The observations noted above are indicators that the licensee is starting to make progress in achieving their licensed operator staffing goals.
No inadequacies in the
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area of shift manning were identified.
(4) On July 22, 1987, the inspector noted the existence of two
"Instrument In Test" stickers affixed to control room annunci-ators.
The inspector discussed the use of these stickers with control room operators and learned that one was inadvertently left in place following the completion of a surveillance test, and the other sticker should more appropriately have been a "Not Operating" sticker.
Corrective actions were initiated by the
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operators to resolve these discrepancies.
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During a control room tour on August 11, 1987, the inspector observed that incorrect recorder paper was installed on two con-trol room recorders.
The licensee controls' this activity in accordance with OP-Memo 20-1 Rev. 1, Changing and Marking of Plant Circular and Strip Charts. This procedure specified that plant operators are to insure that the new chart is a correct one for the recorder as part-of' changing of strip charts.
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inspector reviewed the computer printed label for the charts in use and noted that the charts were installed on August 2 and 3, 1987 for the two recorders ~1n question.
It appears that none of the control room personnel noticed -the discrepancies for approximately nine days until discovered by the inspector. When discovered, the inspector informed a-con-trol room operator of the discrepancy and correct strip charts were installed.
The abos a two observations point out the need for 'the control room operators to be more attentive to details associated with activities involving the control room annunciators and recorders.
Addif unally, the observation involving the recorders was dis-cussed with the assistant plant operations manager, who acknow-ledged the inspectors comments and concerns. On August 13, 1987, the operations department issued Special Order 87-92 to all operating personnel, which reaffirmed the importance that the licensee places on the need to insure that the correct - charts are installed.
(5) The inspector noted an August 31, 1987, 10:00 a.m. control room log entry that the charging flow indicator CH-FI-2 was not in-dicating flos, that maintenance request (MR) 87-1438 was issued, and that the indicator was declared out of service. This entry also made reference to Technical Specification 4.5.2.b.8 and
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that the indicator was returned to service at 3:30 p.m. the same day.
Thf s surveillance requirement involves the ECCS Subsystem and specified that the charging header flow metering instrument l
is to be determined operable by observing charging flow rate at
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least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
To meet this TS surveillance require-i ment, the licensee records on an hourly basis on Rowe Station Log No. 2 the charging flow indicator reading.
Prior to the inoperability, the last reading recorded was at approximately 9:30 a.m.
This indicator appears to provide, in part, informa-
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tion about the operability of the ECCS long term hot leg in-jection subsystem.
I As a result of reviewing TS Section 3.5.2 and 4.5.2 the inspec-tor determined that:
1) there are no action statements associ-ated with inoperability of either the ECCS recirculation or long term hot leg injection subsystems (TS 3.5,2.b and C, respec-l tively); and 2) the use of only the Oi-FI-2 instrument as an
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indicator _ of long ' tera hot leg injection subsystem operability,
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as far as determining tut the flow path is operable, is overly-
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restrictive.
Given the e:xisting TS, and assuming the loss of the subject instrument for greater than a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> period,'it is not clear how the licenset.would, or should, respond to this-situation.
The inspector reviewed past l_icensing actions involving the sub-ject TS requirements (i.e., the original May 1976 TS ' sections, and Amendment No. 52 to the Facility Operating Licer:se issued on November 14,1978), and learned _that both the ECCS recirculation and long term hot leg injection subsystems were. upgraded to -
utilize the pumping : capabilities of the ECCS safety injection subsystems.
The original recirculation and hot leg subsystems relied upon the purification pumps and fixed speed charging.
pumps, respectively. Also, the original TS 3.5.2.b and c spec-ified an action statement to be in hot shutdown with main cool-ant pressure less than 1000 psig within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> upon the total inoperability of either subsystem.
The inspector discussed the issues and apparent need to clarify the ' subject TS with the plant operations manager and the technical director.
They
agreed that the issues raised. warranted further licensee atten-tion.
This matter requires further review and evaluation and is considered to be an open item (50-29/87-11-01).
(6) Throughout the inspection. period, there were only two annunci-ators (breathing air compressor No. 1 or No. 2 common trouble, breathing air accumulator low pressure) which were categorized as continuous alarms.
Leaving these annunciators in an alarmed state, when the equipment is not routinely utilized, or is sub-ject to long term maintenance activity, appears to be a depar-ture from the licensee's program of maintaining meaningful alarm parameters and reducing any unnecessary continuous alarm condi-tions.
No violations or deviations were identified in the. review of this program area.
b.
System Alignment Inspection Operating confirmation was made of selected piping system trains.
Accessible valve positions and status were examined.
Power supply and breaker alignments were checked.
Visual inspections of major components were performed. Operability of instruments essential to system performance was assessed.
The following systems were checked during plant tours and control room panel status observations:
Motor driven emergency feedwater pumps standby status verified
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Emergency diesel generator (EDG) unit stand 5y verified during
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tours of the EDG rooms and control room board status review.
Non-return valves (NRV) verified during tours of the NRV plat-
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form and during control room equipment cabinet review.
Low pressure and high pressure injection systems.
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Low pressure accumulator system
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No violations or deviations were identified in the review of this program area, c.
Biweekly and Other Inspections (1) During plant tours, the inspector observed shift turnovers, compared boric acid tank samples and tank levels to Technical Specifications requirements, and reviewed the use of radiation work permits and radiation protection procedures.
Area radia-tion and air monitor use and operational status were reviewed.
Verification of tagouts indicated the action was properly con-ducted.
Based upon a review of licensee activities in this area the inspector noted the following.
On July 22, 1987, the chemistry department reported that
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the boric acid mix tank (8AMT) concentration was 12.6 per-cent by weight boric solution.
Since this condition is outside the Technical Specification 3.1.2.11 allowable i
range of 12.0 to 12.5 percent, the plant operators correc-l ted the situation by adding demineralized water to the BAMT and arranging for re-sampling.
The inspector determined that corrective actions were implemented within the allow-able action statement time limits. The inspector noted that the concentration limits for the BAMT were also out of specification limits on August 12 and 26, 1987.
The occurrence of out of specification concentration events appears to be increasing in frequency.
This matter was discussed with the chemistry manager, who acknowledged the inspector's comments and concerns, and indicated that the problem is currently believed to be the result of operating within a very tight concentration limit.
The chemistry manager agreed to review operation of the BAMT system and
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trend sample analysis results to insure that there are no j
other causes for this condition to be occurring.
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(2)
Fire Protection and Housekeeping No inadequacies were noted regarding licensee housekeeping or fire protection practices. A strong commitment to proper house-keeping conditions and practices by the plant staff is routinely observed by the inspector.
Performance in this area continues to be viewed as a licensee strength.
No violations or deviations were identified in the review of this program area.
(3) Observations of Physical Secut-ity Selected aspects of plant security were reviewed during regular and backshif t hours to verify that controls were in accordance with the security plan and approved procedures.
The inspector reviewed on August 10, 1987 the licensee's response to Security Recordable Events87-131 and 87-132, which involved, respectively, the failures to control a security key on August 6, 1987 and to insure that an access control area barrier was properly secured on August 7, 1987.
These events were discussed with cognizant NRC Region I personnel.
These events will be reviewed as part of a future routine regional safeguards and security inspection.
However, the inspector noted that prompt and adequate compenshtory measure were imple-mented, and that appropriate corrective actions to preclude recurrence were pinnned by the licensee in response to these
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events.
Regarding the licensee's identification of a moderate
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loss of physical security effectiveness involving ID/ key card control, which is documented in Section 7 of this report, the
inspector observed angressive licensee management involvement in identifying the causes of the event and insuring that appropri-ate short and long term corrective actions were identified.
Improvements in station management oversight of security activ-ities continue to be observed by the inspector.
Items that reflected an improving trend in their concern for security were:
The issuance on July 21, 1937 of operations department
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special order No. 87-83 thau 1) reinforces the importance
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of the security function; 2) specifies the need for adher-
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ence to security requireraents; and 3) directs the plant
shift supervisor to respond in a timely manner to conditions
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that warrant maintenance departments attention for degraded
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security equipment.
In addition, on August 10, 1987, special order No. 87-91 was issued to all operating depart-ment personnel, to ensure their cooperation as part of
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corrective measures that were implemented in response to recent security events.
The inspector noted that the
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special order was requested by the manager administrative services on August 10, 1987 in a memorandum to the assis-tant plant superintendent, who responded to the request in a timely. manner.
On August 10, 1987, the manager, administrative services
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established duty and call officers for security events.
This action was taken to ensure that all security events or occurrences receive iminediate licensee management attention.
During this inspection period, the licensee installed new
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x-ray, explosive, and metal detector machines in the gate-house as part of their efforts to upgrade security systems and equipment.
On November 13, 1987, the plant operations review committee
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reviewed a YNSD design change plan for closed circuit TV (CCTV) coverage modifications.
The proposed modifications are to be implemented to resolve findings noted by the NRC Regulatory Effectiveness Review that was conducted July 28 through August 1, 1986.
The licensee expects the imple-mentation period to be June through October, 1988.
The manager, administrative services continued to provide
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the vice president and manager of operations with. monthly progress reports on their security program improvement initiative.
The licensee completed the installation of a dedicated
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weapons firing range at a location near the site.
The licensee solicited proposals from contractors to per-
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form a security program assessment.
The secpe of work is to include:
security planning documents, security proced-ures, security training, compensatory measures, license /
security force contractor interface and oversight and security system. The assessment report would contain: an identification of major problem areas, recommendations for resolution, and schedule for phasing corrective actions.
No violations or deviations were identified in the review of this program area.
d.
Backshift Inspection The inspector conducted backshif t, weekend, or holiday inspections on August 11, 17, 25, 31, September 21, October 9, 13, 14, 19 and 21.
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Operators and shift supervisors were alert and attentive and responded appropriately to annunciators and plant conditions, i
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5.
Bimonthly Safety System Verification i
i The inspector independently verified the operability of a selected engi-l neered safety features system by performing a complete walkdown of the accessible portions of the system to.
confirm that the licensee's system lineup procedures match plant'
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drawings and the as-built configurations; identify equipment conditions and items that-might degrade i
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performance; inspect interior of cabinets for abnormal conditions;
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verify instrumentation lineup and calibration; and,
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verify prerer valve position, availability for function and position
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indication.
The emergency diesel generator system was reviewed.
No violations. or
,
safety concerns were identified.
l 6.
Radiological Controls Radiological controls were observed on a routine basis during the report-
.
l ing period. Standard industry radiological work practices and conformance
to radiological control procedures and 10 CFR Part 20 requirements were i
observed. Independent surveys of radiological boundaries and random sur-
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veys of nonradiological areas throughout the facility were taken by the t
inspector.
l
.
Based upon a review of licensee activities in this area the ' inspector l
noted the following Inspection Report 50-29/87-09 identified weaknesses in the licensee's i
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administrative controls for High Radiation Exclusion Area (HREA)
i keys.
The licensee submitted the planned corrective actions to address the NRC concerns in a August 11, 1987 letter, FYR 87-85. On September 3,
1987 the radiation protection manager informed the inspector that one of the stipulated corrective actions was being modified to reflect a more conservative approach. The licensee plans-on maintaining the control and issuance of a HREA key routinely used by the primary side auxiliary operator at the radiation protection control point, in lieu of the control room key locker. The inspector discussed this explicit change with the cognizant NRC:RI specialist inspector and management personnel, who agreed that the licensee intended action was acceptable. Documentation of this matter in this inspection report precludes the need for the licensee to submit further correspondence to the NR _.
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Oa October 9, 1987, the radiation - protection department generated
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L nonconformance report (NCR) 87-38.
This NCR described the failure
to provide personnel monitoring reports in accordance with 10 CFR t
20.408 and 20.409. This event involved a total of 37 personnel who
,
terminated their work assignment at the plant and were not sent the
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required reports within the prescribed time frame.
Further review
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q of this licensee-identified condition, as well as a determination as
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to the acceptability of their corrective actions, will be conducted
by an NRC:RI specialist inspector during a future radiation protec-
tion inspection (Unresolved Item 50-29/87-11-02).
Surveys and radiation work permits (RWPs) issued by the licensee to
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control work in the cubicle areas of-the primary auxiliary building i
were reviewed by the inspector on October 19, 1987.
The RWP 87-03258, dated October 17, 1987, was issued to control the week's
,
activities of general decontamination and housekeeping duties asso-
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,
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ciated with primary plant operation and traintenance. The inspector compared this RWP with cubicle corridor survey OPF-8101.11, dated
'
a October 19, 1987, and noted that the survey showed an eighty mR/hr
,
radiation field in the purification pump room, but the RWP specified
,
a range of one-to-fifty mR/hr for all areas within the - cubicle
,
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corridor,
>
The inspector discussed this observation with a radiation protection (RP) department engineer, who indicated that the discrepancy is j
,
probably due to the fact that the survey was updated subsequent to j
the issuance of the RWP. When new surveys are issued, there does not
appear to be a procedural control that requires RP personnel to
determine the appropriateness of existing RWP requirements. To some
,
i degree this situation is compounded by the licensee's practice of routinely not attaching a copy of the survey to the RWP. Based upon
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inspector comments and concerns, the RP department will be reviewing
their current practices and will revise procedure OP-8101, Rev.12,
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Plant Radiological Surveys and OP-8415, Rev.14, RWP Issue, Update,
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and Closecut to address the inspector's concerns. The inspector had no further questions of the licensee on this item.
,
,
i j'
were identified in this program area.
Except as described above, no violations or radiological safety concerns
]
7.
Events Requiring Telephone Notification to the NRC
.
The circumstances surrounding the following events, which required NRC
]
notification via the dedicated ENS-line, were reviewed. A summary of the i
inspector's review findings follows or is documented elsewhere as noted
{
below:
J
)
At 3:48 p.m. on July 27, 1987, the NRC was notified in accordance
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j with 50.72(b)(1)(v) that the safety parameter display system (SPDS)
was declared inoperable at 1:41 p.m.
Earlier in the day, control
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room operators noted an SPDS equipment problem that involved failure of the system to update the CRT display screens.
Following initial maintenance efforts the condition was resolved. However, the problem returned and an outside service contractor was required to be called in. The system was returned to an operable status at 11:50 a.m. on July 28,1987.
At 1:35 a.m.
on August 5,1987, the NRC was notified in accordance
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with 50.72(b)(1)(v) that a major loss of emergency communications capability had occurred at 1:25 a.m.
as a result of tne Ames Hill (Marlboro, Vermont) section of the Public Notification System (pHS)
being out of service. In accordance with OP-Memo 2U-5, PNS, the con-trol room personnel notified the Massachusetts and Vermont state police organizations about the event.
Following repairs to the pri-mary and secondary transmitters on the Ames Hill section of the PNS by the licensee's contractor, the system was returned to service at 8:30 a.m. on August 5, 1987.
,
On August 12,1987 at 10:07 a.m., the licensee made a 24-hour notifi-
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cation to the NRC via the ENS line in accordance with 10 CFR 73.71 that an event involving loss of effectiveness of ID/ key card control had been discovered on August 11,1987 at 11:05 a.m.
The licensee submitted to NRC Region I the five-day written report describing the event on August 14, 1987. At the time of occurrence, the inspector discussed the event details and licensee actions with cognizant NRC
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Region I personnel.
This event and the licensee response actions will be reviewed as part of a future routine regional safeguards and security inspection.
At 9:15 a.m. on August 25, 1987, the NRC was notified in accordance
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with 50.72(b)(1)(v) that the SPDS would be out of service for a period greater than eight hours.
This condition resulted from a
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defective power supply within the SPDS.
On September 8, 1987 at 11:30 a.m.,
the licensee made a 24-hour
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notification to the NRC via the ENS line in accordance with 10 CFR 73.71 that an event involving a major loss of security system effec-tiveness which was properly compensated had occurred at 11:00 p.m. on September 7, 1987. This event involved a vital area. In addition to a rapid compensatory response to the event in the security organiza-tion, the licensee instituted proper verification actions to ensure that the vital area was not compromised.
I At 9:40 p.m.
on September 18, 1987, the NRC was notified in accord-
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ance with 50.72(b)(1)(v) that the SPOS was determined to be inoper-i
able at 6:20 p.m.
Following repairs, the system was returned to
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service at 1:45 p.m. on September 19, 1987.
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At 2:45 p.m. on September 25, 1987, the NP.C was notified in accord-
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ance with 50.72(b)(1)(v) that a major loss of emergency communica-tions capability had occurred at 2:05 p.m. as a result of the dis-covery that the siren encoder, a portion of the PNS, was Wperable.
Within the Yankee Nuclear Power Station Emergency Planning Zone, the Massachusetts towns of Charlemont, Clarksberg, Colrain, and North Adams utilize a total of ten sirens as part of the PNS. The NRC was notified at 5:50 p.m.,
the same My that the licensee contractor had repaired the siren encoder and the siren portion of the PNS was operable.
No violations or deviations were identified in this program area.
8.
Plant Events a.
High Pressure Turbine Impulse Chamber Drain Line Steam Leak On July 30, 1987, with the plant at 100*4 of rated power, a senior control room cperator performing a plant tour discovered a steam leak in the high pressure turbine impulse chamber drain pipe.
The leak was in a weld that attaches the drain pipe to the turbine casing.
Since the leak was not repairable with the turbine in operation, a plant shutdown to Mode 2 (startup) was scheduled to be initiated ar,
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8:00 p.m.
on July 31, 1987.
Licensee plans for the brief outage included:
(1) maintaining the reactor critical at low power to facilitate hot leak inspections; (2) repacking seals on the No. 2 boiler feedwater pump; and, (3) performing load capability testing on the No. I heater drain pump.
Subsequent to the leak identification, and until the turbine generator could be removed from service, the operations department issued special order No. 87-86 to provide guid-ance to the operators on performing shiftly inspection of the leak and appropriate operator response, should catastrophic failure of the
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drain line occur.
A detailed shutdown and work plan was issued to the operators on July 31,1987 as part of special order No. 87-88. At 5:53 a.m.,
on August 1, 1987 the turbine generator was offline.
The hot leak inspection was conducted within the vapor container, and as a result, a body-to-bonnet leak was discovered on the No. I steam generator (SG) blowdown check valve, VD-V-1149, with MR 87-1222 being issued to l
effect repairs.
This valve could not be isolated because of excess-ive packing leakage on its isolation valve.
Maintenance department personnel torqued the check valve cover bolts to 120 ft-lbs., but the leakage could not be stopped.
No additional maintenance was per-formed or, this valve during the plant shutdown.
At 10:40 p.m. on August 1,1987, the generator was phased to the grid.
The plant was returned to full power operation on August 4,193.
,
b.
Steam Leaks on Steam Generator Blowdown Line Check Valves The plant operators noted leakage into the vapor container drain tank (VCOT) in excess of 60 gallons per day (GPD) on August 4,1987. The i
vapor container temperatures were also noted to be higher than nor-mal. The licensee investigated these conditions and determined that they were due to the increasing body-to-bonnet leakage from the No. 1 SG blowdown check valve, VD-V-1149 (see Section 8.a).
On August 6, 1987, at 4:00 p.m., a plant load reduction to Mode 2 was initiated.
At that time, the leakage into the VCDT was at a rate of 640 GPD.
The turbine generator was offline at 6:30 a.m.
on August 7,1987.
Repairs to valve VD-V-1149 necessitated isolation of the blowdown line.
The inspector verified that the control room operators were aware that this condition would result in an eight hour action re-quirement per TS 3.3.3.1, Table 3.3.4.
However, the isolated blow-down line precluded the operability of the process line effluent r.:onitor and the alternative monitoring requirement of the TS action statement. The repairs were completed and the blowdown line returned to service at 5:15 p.m.
The TS Limiting Condition for Operation for the affected radiation monitoring instrumentation was not exceeded as a result of having the blowdown line returned to service within the eight-hour time frame. At 11:10 p.m. on August 7, 1987, the gener-ator was phased to the grid.
Subsequently on October 9,1987, an increasing rate of leakage into the VCDT again was noted. The leakage rate then was 65 GPD, and by October 13, 1987, the rate had increased to 180 GPD.
The source of the leakage was determined to be from the body-to-bonnet seal on the No. 4 SG blowdown line check valve, VD-V-1152.
An MR 87-1699 was initiated to control repair activities.
A body-to-bonnet leak was also noted on the No. 2 SG blowdown line check valve, VD-V-1150, and MR 87-1700 was initiated.
To perform repairs on these valves, a
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plant shutdown to Mode 2 was scheduled to commence at 12:00 midnight
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on October 14, 1987.
Additional work scheduled for the maintenance department included the replacement of fuel and hydraulic lines on the emergency diesel generators.
The licensee maintenance activity
on the diesel generator was in response to the NRC:RI Regional Administrator's observation on a plant tour, as documented in Section i
12 of this report.
l Following the identification of several body-to-bonnet leaks, a main-
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tenance support department engineer, who has responsibility for the
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in-service inspection program at the plant, contacted the manufac-turer for recommended torque values for the body-to-bonnet bolts. A value of 175 ft-lbs. was specified as the amount of torque applied to the bolts prior to leaving the factory. The plant contacted YNSD to insure that the manufacturer's recommended torque value was appro-priate.
The YNSD provided calculations to the plant that demon-j strated that the recommended torque value was equivalent to 75% of the bolt material tensile strength, i
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At 5:45 a.m.
on October 14, 1937, during the load reduction, which was being performed at 10% of rated load per hour, the steam dump to condenser valve, MS-PCV-402, developed a blown gasket. Control room operators responded to this event by initi ating procedure OP-3003, Rev. 12, Emergency Controlled Plant Load Reduction.
This action resulted in a thermal change of greater than 15% of rated thermal power occurring within a one-hour period.
The TS 4.11.2.1.2, Table 4.11-2, Note c requires that a grab sample for noble gases from the primary vent system be obtaineM within eight hours and analyzed with-in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a thermal power change that is greater than 15% of rated thermal power in one hour. At 6:25 a.m., the radiation protec-tion shift technician was notified of the power change, and initiated Section A of procedure OP-8041, Rev. 5, Special Sampling of Primary Vent Stack Effluent, which controlled the required sampling activity.
The plant was placed in Mode 2 at 7 30 a.m.
By 10:50 a.m. the No. 4 SG blowdown line was isolated, erit ry into the applicable TS action statement was documented in the control room log, and repairs to valve VD-V-1152 were initiated.
By 3:05 p.m., repairs were complete and the No. 4 SG blowdown line was placed in service, The body-to-bonnet bolts were turqued to 175 ft-lbs.
The licensee initiated and completed on October 14, 1987 MR Nos.
87-1711, 87-1712, and E7-1713 to torque the body-to-bonnet bolts to 175 f t-lbs on the Nos.1, 2, and 3 SG blowdown check valves, respec-tively.
Inspector observations associated with the SG blowdown line check valves is discussed further in Section 11 of this report.
9.
Maintenance Observations The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administration and main-tenance procedures, codes and standards, proper QA/QC involvenent, safety tag use, equipment alignment, jumper use, rursonnel qualification, radio-logical controls for worker protection, fire protection, retest require-nents and reportability per Technical Specifications.
The following activities were included:
Maintenance request (MR) 87-1151, EBF-MOV-557, thermal overloads trip
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when operating valve MR 87-1184, EBF-MOV-556, replace torque switch
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FR 87-1188, EBF-MOV-555, replace torque switch
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MR 87-512, P35-1 fire pump operating at minimum capacity
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MR 87-1400, fire pump discharge check valve, FS-V-601, inspection
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MR 87-1222, No.1 steam generator (SG) blowdown check valve VD-V-1149
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flange leak
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MR 87-1400, No. I fire' pump discharge check valve. inspection
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MR 87-1699, No. 4 SG blowdown check valve, VD-V-1152, body-to-bonnet
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leak l
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I MR 87-1711, No.1 SG blowdown check valve, V0-V-1149, torque bonnet
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bolts
MR 87-1712,' No. 2 SG blowdown check valve, VD-V-1150, torque bonnet
)
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bolts MR 87-1713, No. 3 SG blowdown check valve, VD-V-1151, torque bonnet
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bolts
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MR 87-1749, BAMT (boric acid mix tank) heat trace
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Based upon a review of. licensee activities. in this area the. inspector
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noted the following:
_
Regarding MR 87-512, the inspector witnessed field maintenance
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activity on one of the electric driven. fire pumps, P35-1, on August 24, 1987.
Procedures noted to be in use were: OP-5628, Rev.
a 6, Maintenance of the Fire System Pressure Maintenance Pump (FS-P-36)
and Fire pumps FS-P-35; and OP-5756, Rev. 7, Inspection and Mainten-
ance of Electric Motors. A QC inspector was observed to be reviewing
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activities at the job site and was utilizing visual inspection pro-E cedure II M-1, Rev. 1, Attachment B, A3.0, Ex mination of Pump. and Valve Internal Pressure Boundary Surfaces.
In the past, the inspec-
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l tor questioned maintenance department representatives about their
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frequency for inspecting pump discharge check valves, and they
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j informed the inspector that inspections are generally performed when-
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ever pump maintenance is conducted.
The inspector questioned the
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I maintenance personnel working on pump P35-1 about their plans for l
inspecting the pump discharge check valve FS-V-601, and learned that j
there was no scheduled activity in this area.
'
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A review of maintenance department equipment history cards for the i
fire protection syste valves and piping showed no evidence that
!
inspections or maintenar.ce were ever performed on this check valve.
l
Subsequent discussions between licensee representatives and' the i
inspector resulted in issuance of MR 87-14'J0.
As a result 'of this j
inspection, erosion was found on the valve clapper arm. -The main-
'
tenance support department reviewed the inspection results, deter-mined that continued operation with the as-four.d conditions was
<
I acceptable, and initiated action to result in either the replacement of the valve internal parts or the entire valve. Inspector concerns
',
about the laxness in performing routine preventive maintenance
]
inspections on this check valve at the time the pump was being over-
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j hauled were discussed with the plant maintenance manager.
The
inspector considers that further action on the part of the mainten-i
!
i a
i a
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-.-,.
m.n-
,-.,,n.-
., - -,. - -. -
-,,, - - - -, -,.,, -.... -,. _ -,.,
.
.
,
ance department is warranted to provide management controls that will insure that preventive maintenance inspections will be performed on pump discharge check valves at the appropriate time. Pending review of licensee response to the inspector's concern during a subsequent routine resident inspection, this matter is considered an open item (50-29/87-11-03).
The in pector reviewed the conditions that resulted in the issuance
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of MR 87-1749 and the licensee corrective actions for the loss of the BAMT heat tracing discussed in Section 10 of this report. Although the plant operators utilized procedure OP-4214 to perform the retest, this fact was not documented on the MR.
Licensee documentation in-adequacies of this nature, associated with the retest portion of the MR process, reflects a lack of attention ta detail that is of a continuing concern to the NRC, and which is being closely followed during routine resident inspections.
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During the performance of a routine surveillance test with the plant in Mode 1 on July 21, 1987, plant operators discovered that control
'
room-operated, emergency feedwater alternate flow path motor-cperated valve EBF-MOV-557 had tripped on its thermal overload when exercised.
The operators were performing Attachment 8 to procedure OP-4211. The attachment provides operability testing of the motor-driven emergency feedwater pumps and associated valves on a monthly basis.
The MR 87-1151 was issued to investigate the valve problems and noted that the tripping on thermal overload had occurred twice.
The inspector determined that the condition was identified before 12:00 noon on the da; of the event.
No entry was made in the control room log as to she status of operability of the system.
Subsequently on July 24, 1987, at 8:30 a.m., the plant operators removed valve EBF-MOV-557 from service to initiate the investigation into the valve problem.
The control room log entry noted that the flow path to the blowdown header was manually operable per TS LC0 3.7.1.2.
The inspector discussed the operability of this valve and its impact on the emergency feedwater system with supervisory control room personnel, who informed the inspector that the valve is access-ible in the lower prima ry auxiliary building and can be manually operated. Therefore, they concluded that there was no inoperability in the emergency feedwater system. The assistant operations manager substantiated the shift supervisor's determination.
The TS LCO 3.7.1.2 specifies that at least two independent emergency feedwater pumps and associated flow paths shall be operable in Modes 1-3.
In Inspection Report 50-29/86-09, the NRC documented an inspec-tion to review the circumstances associated with the installation of undersized trip coils in circuit breakers for motor operated valves located in two plant systems.
One of these systems involved valve
.
E3F-MOV-557 in the alternate emergency feedwater system.
The NRC
'
then determined that the failure of this valve tc perform its I
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intendec' function using the motor operated feature from the control l
room constituted an inoperability of the flow path to the steam
generator blowdown lines. Operating with the condition of one of the
!
]~
associated flow paths inoperable is contrary to the requrements_ of TS 3.7.1.2, which was identified as being a violation.
The inspection
_
report noted above provided the basis for the NRC determination, with the licensee September 18,.1986 response to the Notice of Violation
!
concurring with the inspection findings.
j i
The inspector discussed the issue and concerns associated with fall-
<
i ing to declare the system inoperable with the plant ' operations l
,
manager.
At 11:30 a.m. on July 24, 1987, the licensee declared the
!
system inoperable per TS 3.7.1.2.
The TS 3.7.1.2 action statement
'
i specifies that with one emergency feedwater pump inoperable, the licensee has 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore the required two emergency feedwater pumps to operable status. At 4:45 p.m. on July 24, 1987, the licen-
see completed the maintenance activity on the valve, declared the
valve operable, and determined that they were no longer in the TS l
action statement.
t
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Subsequent to the initial problem noted with the valve EBF-MOV-557,
,
later on July 21, 1987 plant operators were able to fully cycle the I
valve within the time' limits established in procedure Op-4211. As a
'
result of performing the maintenance on the velve on July 24, 1987,
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the maintenance department determined there was excess free play on the valve torque switch which could cause high seating torque, that-
,
then could cause high current during subsequent valve operation,
resulting in the observed thermal overload trips.
A new torque switch was installed on the valve.
Torque switches were also re-placed on valves EBF-MOV-555 and 556 under the control of maintenance
requests 87-1184 and 1188 on July 27 and 28, 1987, respectively.
i The inspector discussed with the technical director the licensing l
issues associated with the term "associated flow paths" and the i
apparent lack of knowledge by the licensed operators as it pertains j
to this term.
On August 5, 1987, the plant issued service request
'
No. 87-55 to YNSD to propose a change to the Technical Specifications i
to define this term.
Notwithstanding this licensee action, the
licensee needs to provide the licensed operators with a clear de-i finition of the "associated flow paths" to ensure that their response to malfunctioning equipment will reflect the intent of existing TS l
requirements.
This matter is considered an open item (50-29/87-11-04).
The inspector noted that the plant operators had failed to document i
the initial surveillance test results found in valve EBF-MOV-557, as well as the manner in which the deficiency was resolved.
As de-scribed in Section 10 of this report, another example of improper documentation of deficient or unacceptable surveillance test resuits was identified by the inspector.
Both observations involve opera-
)
...
^
s
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tions department performance.
Licensee management attention is war-ranted to provide corrective action to resolve the inspector's con-cern. This is considered an open item (50-29/87-11-05).
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10.
Surveillance Observations The inspector observed tests or parts of tests to assess performance in accordance with approved procedures and LCOs, test results (if completed),
removal and restoration of equipment, and deficiency review and resolu-tion, The following tests were reviewed.
OP-4601, Rev. 19, Nuclear Instrumentation Channels Functional Test
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OP-4210, Rev.18, Attachment A - Fire System Weekly Operability Check
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OP-4211, Rev. 21, Attachment B - Motor Driven Emergency Feedwater
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Pump (EFP) Operability Test During Plant Operation OP-4630, Rev. 9, Accumulator Time Delay Actuation Verification
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OP-4623, Rev.12, V.C. Post Accident Hydrogen Analyzer HV-GA-1 Cali-
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bration and Functional Test OP-4214, Rev. 12, Chemical Shutdown System Operability Check
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OP-4238, Rev. 7, Test of the Control Room Ventilation Emergency Shut-
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down System and CREACS Fans OP-4200, Rev.11, Main Coolant System Leak Inspection or ISI Pressure
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Test OP-4261, Rev 5, Main Steam Non-Return Valve (NRV) Operability Test
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OP-4716 Rev.
6, Vapor Container Personnel Hatch and CA-V-755 Leak
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I OP-8041, Rev.
5, Special Sampling of Primary Vent Stack Effluent
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Based upon a review of licensee activities in this area, the inspector l
noted the following:
I During the performance of procedure OP-4601 on September 3,1937 the I
--
inspector held a discussion with the two I&C department technicians about system operation and performance characteristics.
Both indi-
)
viduals demonstrated an excellent knowledge level of the nuclear i
inttrumentation channels.
One of the individuals was in training, j
,
and the inspector noted that the licensee program of using more
!
experienced personnel and providing a field training environment is
'
generally effer,tive.
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As a result of reviewing the August 7, 1987 surveillance test results
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for the leak rate determinations on the vapor container personnel hatch, the inspector noted the difficulty in determining that the test is conducted within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of initiating a vapor container entry.
Thi: test requirement is specified in TS 4.6.1.3 and 10 CFR 50, Appendix J-III.D.2(b)(iii).
Subsequent to discussing this con-cern with an on-duty shift technical advisor, the licensee incor-porated steps in procedure OP-4716 to record the date and time of initiating a vapor containment entry and initial pressurization of the personnel hatch.
The licensee timely response and cooperative attitude on this issue is typical of the manner in which they respond
-
to NRC recommendations or initiatives.
,
During the performance of procedure OP-4214 on October 21, 1987,
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plant personnel determined that the chemical injection line from the BAMT was at 148 degrees F.
The TS Surveillance Requirement (SR) 4.1.2.3.a.2 requires the heat traced portion of this flow path to be
!
at a temperature that is greater than or equal to 150 degrees F.
Because of this condition, the BAMT flow path was declared inoperable in accordance with TS LCO 3.1.2.3 at' 2:45 p.m.
At that time, MR 87-1749 was issued to initiate an investigation into the occurrence.
Conditions were corrected by maintenance department personnel, who readjusted one of the two heat trace thermostats that was found to be below the appropriate setting.
Following verification of achieving and maintaining the temperature above the required value, the system was declared operable at 6:50 p.m. on October 21, 1987.
According to the MR, the occurrence was attributed to the performance on October 19, 1987 of procedure OP-5751, Rev.
9, Heat Tracing Inspection. At that time, thermostat E109-2 was adjusted to measure circuit current, but following the inspection the thermostat was set too low by not being within five degrees F of thermostat E109-1.
Procedure OP-5751 does not specify the importance of maintaining a proper setpoint relationship between the two thermostats.
The
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inspector discussed the matter with the plant maintenance manager,
,
who agreed to review procedure OP-5751 and determine the appropriate-
'
ness of generating a revision to provide additional instructions on maintaining the proper setpoint relationship between the thermostats.
Pending review of licensee response to the inspector's concerns re-gardirg procedure OP-5751 inadequacies, this matter is con.idered an
.
open item (50-29/87-11-06).
Additionally, the inspector noted that the remarks section of pro-cedure CP-4214 did not contain information about the failure to main-tain the temperature at the TS limit.
Inspector concerns about the poor documentation in the procedure for an identified deficiency that resulted from performance of the surveillance was discussed with the plant operations manager.
This matter is considered another example of open item 50-29/87-11-05, discussed in Section 9.
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On October 20, 1987, the I&C depart'nent initiated the performance of
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procedure OP-4623. An I&C department supervisory review of the com-pleted surveillance procedure was '.cnducted on October 22, 1987.
This review determined that the I&O technician who performed the surveillance had inadvertently left the as-found hydrogen ana1924r low range indication at a value that exceeded the procedure accept-ance criteria limit.
The I&C supervisor itmediately informed the shift supervisor of this error. Since the HV-GA-1 analyzer, which is the Bendix analyzer located in tN turbine building switchgear room, is one of the two independent containment hydrogen monitors required to be operable by TS 3.6.3.1, the shift supervisor entered Action Statement A of the TS at 10:15 a.m. on October 22, 1987. The loss of operability of one of the two monitors allows continued plant operation for a thirty-day period.
At 2:00 p.m. the same day, the Bendix analyzer was recalibrated to meet the acceptance criteria that the 0-5% hydrogen range is within plus or minus 1.0*4 of full scale.
The inspector had the following comments and concerns as a result of reviewing this activity:
1.
There was no entry in the control room log on October 20, 1987 that the TS SR 4.6.3.1.b required quarterly calibration per procedure OP-4623 was performed.
Additional operations de-partment attention is warranted to provide assurance that im-portant activities, such as the initiation and completion of TS-required surveillance testing, are documented in the control room log.
2.
The supervisory review by the I&C department following the com-pletion of the performance of procedure OP-4623 was not done in
a timely manner.
In addition, the inspector noted that it would be si.propriate for the licensee to review the procedure to insure that the amount of error that is considered unacceptable will be clear to the I&C technicians.
3.
The inspector noted that in Attachment B of operations depart-ment procedure OP-2658, Rev. 19, Operation of the Post Accident Vapor Container Hydrogen Control Monitoring System and Sampling
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Systems, the operators are instructed to select the desired
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range (high range 0-20% hydrogen; low rMge 0-5% hydrogen) on
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the Bendix hydrogen Analyzer.
However proceMre OP-4623 spec-
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ifies to use a nominal 5% hydrogen calibratian standard for the span gas.
This 5% hydrogen span gas is used to calibrate both low and high ranges of the analyzer.
The second post accident hydrogen analyzer is a unit manufactured by Cousip Inc., also a dual range unit that covers the ranges of 0-10% and 0-20%
hydrogen, According to procedure OP-4665, Rev. 10, Comsip Model K-III Post Accident Hydrogen Analyzer (HV-GA-2) Calibration and Functional Test, the use of a 19.9% hydrogen span gas is spec-
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ified.
Plant personnel were unable to explain to the inspector
why both hydrogen analyzers used different methudology when
conducting the respective unit's span calibration.
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Pending review of licensee response to the inspector's concerns re-garding (1) appropriate docunentation in the control room log of the initiation and completion of TS-required surveillance testing, and (2) untimely supervisory review by the I&C department following the completion of TS-required surveillances, these matters are considered open items (50-29/87-11-07, and -08).
The acceptability of using a low span gas to perform a TS calibration on the high range of the post accident Bendix hydrogen analyzer requires further NRC resident and regional specialist review and evaluation and is considered to be an unresolved item (50-29/87-11-09).
Except as described above, no violations or safety concerns w_re iden-tified in the review of surveillance activities.
11.
Check Valves Inspection Program (Licensee Response to INPO SOER No. 86-3)
Maintenance activities associated with SG blowdown isolation valve leakage events were reviewed in Section 9 uf this report. The inspector performed additional review in this area and noted that during the Cycle XVIII-XIX refueling outage, the licensee conducted internal inspections on each of i
the four SG blowdown line check valves. Maintenance requests Nos.87-664, 87-731,87-732, and 87-733 were issued to conduct the inspections that were being performed as part of a licensee program established to respond to INPO Significant Operating Experience Report (SOER) No. 86-3.
This SOER described recurring industry problems with check valve misapplica-tion, failure and degradation.
Upon receipt of the 50ER, the licensee processed the document into the Evaluation of Operating Experience Program as controlled by Procedure AP-0020.
The 50ER reflected industry experi-ence that included the San Onofre, Unit 1, loss of feedwater transient.
As a result of initial plant staff review, plant service request No. 86-72 was issued that requested YNSD to evaluate SOER 86-03 for its applicabil-ity to the Yankee Nuclear Power Station.
The YNSD was to:
1) provide a review of systems, to identify valves subject to severe operating condi-ons, that would be used in developing a preventive maintenance test and i
.pection program; and 2) perform a design review for a?1 identified heck valves to verify proper installation and application.
The YNSD memorandum YRP 363/87, dated April 22, 1987, was developed to document the engineering evaluation for the above request.
This memorandum identified
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117 valves that should be included in the licensee program.
For each of these valves, the evaluation provided the maintenance history, if any, its design application, and whether the particular valve is subject to the
50ER or is to be monitored and inspectec in the future. The design review
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performed determined that a number of check valves installed are oversized I
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.and vulnera' le to "tapptr.g", however, operational and maintenance history i
u indicated that no known problems have existed with -many of these valves
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for years.
In addition,,YNSD provided a lict ~ of 15 additional check valves which were recommended fo. ir.spection per the SOER guidance in - the Cycle XVIII-XIX refueling outage.
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l During the refueling outage a total ~ of '28. check valves were inspected.
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According to the licensee July 10, 1987 response 'to an. INP0 -survey' on efforts to add"ess check valve degradation and failure, only two valves were found degraded (but still operable).
The survey - response outlined
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the licensee actions to date concerning the SOER, and noted that the
licensee has been aggressively pursuing an effective check valve'mainten-ance and inspection program to eliminate the potential for check valve
failures at the plant.
Further program development in this. area will
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occur from experience gained froni internal inspections and issuance of an
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industry developed application guide.
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12..lant Information Reports
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I The plant information reports (PIRs) prepared by the licensee per AP-0004
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were reviewed.
The inspector determined whether the conditions ' were
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reportable as defic.ed in the TS and whether the licensee's system of
problem identification and corrective action is being effectively
utilized.
The following PIRs were reviewr:d:
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PIR No.
Occurrence Date Report Date Subject i
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87-01 05/04/87 06/15/87 Inadvertent release of icw pressure surge tank cover gas l
via vapor container-purge
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system
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l 87-03 05/22/87 08/20/87 Potential overexposure of. a j
t worker during steam generator
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channel head entry
87-05 06/12/87 06/18/87 Asbestos insulation spill in
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the turbine hall
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87-06 07/08/87 09/23/87 Improper solenoid valve l
installed in the No. 1 emerg-
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ency diesel generator fuel
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oil system
Except for the following comments, the inspector had no further questions.
PIR 87-01:
Following venting of the oressurizer in accordance with pro-cedure OP-2105, Rev. 29, Plant Cooldt.,2n From Hot Standby, which was being performed as part of preparing the plant for refueling activities, an increase in the readings of the primary vent stack monitors occurred.
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r Plant operators investigated the occurrence, and. following. a noted de-crease in 'the low pressure surge tank (LPST) gas pressure, they isolated the safety valve discharge header isolation valve, PR-TV-214, to stop the release.
During the inadvertent release, approximately 3.5 curies ~ were released to the vapor container (VC) atmosphere and then to the environ-ment.
The release was within the rate specified by the licensee release.
permit.
This permit addressed venting the-LPST cover gas, which had been performed-in accordance with procedure OP-2159, Rev. 15, Removal Of The-Hydrogen Blanket From The LPST.
The release to the VC atmosphere was due to:
1) reverse flow through the power operated relief valve, PR-50V-90, which allcwed gases'from the LPST to enter the pressurizer; and 2) venting the pressurize to a poly / filter bottle which releases. to the VC (as allowed for by the existing nrocedure OP-2105). Subsequent to this event, maintenance was performed on valve PR-S0V-90.
Licensee corrective action
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consists of. revising venting instructions in procedure OP-2105.
The inspector noted that procedure OP-2159 should also be revised, with the
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technical services man &ger acknowledging the inspector's comments ' and indicating that the matter would be reviewed further.
.The inspector verified that the PORC reviewed and approved. recommendations to preclude recurrence were incorporated in the licensee's Project Commitment Tracking and Responsibility System.
PIR 87-03:
This event was described in Inspection Report 50-29/87-06, (Section 5).
This PIR is considered closed, since further NRC revie'w of the event and the licensee's evaluation is the subject of Unresolved Item 50-29/87-06-01.
PIR 87-06:
This event was reviewed in Inspection Report 50-29/87-06, Section 8.
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Except as related to Unresolved Item 50-29/87-06-01, the inspector iden-tified no violations or deviations regarding the. licensee actions asso-ciated with these events.
For each PIR the licensee determined the cause of the occurrence and specified appropriate short-term and long-term corrective actions.
L 13.
Regional Administrator's Facility Tour i
Mr. William Russell (NRC Region I Regional Administrator), the resident inspector and the plant superintendent completed a tour of the facility on
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September 16, 1987. Several items noted during the tour warranted follow-up, which are described in Attachment I to this report and were identified to the licensee for review and action as necessary.
Subsequent to the facility tour, the inspector reviewed the licensee cor-rective actions for those items requiring followup. The inspector's re-view verified that all items were either corrected prior to the completion of the inspection period, or rad been assigned to designated licensee individud s for appropriate disposition.
No violations or deviations were identified in the review of this araa.
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14. Licensee Response To NRC Bulletins The licensee response to IE Bulletin (IEB) No. 80-08 was reviewed.
This review included: adequacy of. the response to IEB requirements, timeliness of the response, completion of identified corrective actions and timeli-ness,of completion.
The IE Bulletin No. 80-08, Examination of Containeunt' Liner Penetration Welds, dated April 7,1980 was primarily designed to - gather informatio.n and details of the plant fabrication and installation practices associated with the subject welds.
The NRC review of the itcensee response to this bulletin was documented in Inspection Report 50-29/82-01, Section 5 which left the bulletin open pending a determination of technical adequacy by the NRC.
In 1984, the NRC Office of Inspection and Enforcement issued NUREG/CR-305, Closecut of. IE Bulletin 80-08.
This cocument stipulated that the licensee facility has no containment penetration butt welded joint of the type addressed in the bullet N.
This bulletin is closed.
15. Bulk Containment Temperature Limits and Experience On August 28, 1987, the inspector was directed. by the NRC:RI Division of Reactor Projects to gather information concerning the plant containment temperature as part of a regional initiative to determine if a generic issue is prevalent with Region I plants.
This action was in response to Arkansas Nuclear One being operated for an extended period of time with bulk containment temperature in excess of the design' limit specified in their Final Safety Analysis Report (FSAR).
As a result of conducting interviews with licensee representatives, and reviewing applicable licensee documents.the inspector noted the following:
A 120 degree F limit on containment average temperature is specified
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in the TS 3.6.1.5 Limiting Condition for Operation.
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Procedure OP-4700, Rev. 11, Vapor Container Ontinuous Leak Rate Monitoring, provides for a once per-24-hour determination of contain-ment average air temperature.
This procedure establishes a 120 degree F limit as part of its. acceptance criteria, and implements the surveillance requirement of TS 4.6.1.5.
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The facility has not been operated above the 120 degree F limit pre-scribed for containment temperature.
No violations er deviations were identified in the review of this area.
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16. Annual Retraining The inspector completed the Yankee General Plant Training (GPT) Requalifi -
cation Program on October 21, 1987, which is described in procedure AP-0501, Rev.14, General Plant Training Program.-
The inspector deter-mined that the program was 1) implemented in accordance with the proced-ural requirements; and 2) adequate to insure that _ personnel allowed unes-corted access to the plant maintain a satisfactory level of proficiency in the GPT area.
Currently, the licensee training department is assessing the program ele-ments in an effort to provide er.hancements that will result in improved program effectiveness.
The training manager informed the inspector that the licensee plans to achieve this goal by utilizing input from their established Training Advisory Committee and by stressing the relationship between the process requirements.and personnel performance.
No violations or deviations were identified in tM review of this program area.
17. Attentiveness to Licensed Duties On March 31, 1987, the NRC issued 'a shutdown order to the licensee of the l
Peach Bottom facility as a result of inspection findings concerning licen-sed operator inattentiveness.
Subsequently on May 11, 1987, the NRC issued Information Notice (IN) No. 87-21 to describe the circumstances involved and to reaffirm the principle of high standards of control room-professionalism and operator attentiveness.
In response to NRC concerns in this area, the licensee initiated the following actions: 1) incorporated the IN in the evaluation of the oper-ating experience program controlled by procedure AP-0020; 2) provided proper distribution on May 19, 1987 of the information contained in the IN to licensed operators via special order No. 87-55 and 3) issued on July 13,1987 special order No. 87-77 that provided additional guidance on control room conduct.
The actions rein forced a mamorandum issued on April 13, 1987 by Mr. L. Heider, Vice President and Mahager of Operations, which reiterated to the entire plant staff the continuing need for pro-fessionalism and decorum in all work performed.
At the request of NRC:RI, the inspector discussed with the plant superin-tendent the NRC guidance on reporting of events involving sleeping staff.
This discussion occurred on August 26, 1987, and resulted in the inspector determining that:
1) licensee senior plant management were properly sensitized to the impact of allegations of sleeping employees in light of the Peach Bottom order; 2) there were no known or suspected sleeping /-
irnttentiveness on the part of anyone at the station; and 3) the licensee would utilize the NRC guidance on implementing a reporting threshold for sleeping / inattentiveness problems to the senior resident inspector. -On September 11, 1987, the plant superintendent issued to his senior station
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managers a memorandum that directed their - participation in weekend and backshift plant visits.
This memorandum also incorporated the' NRC reporting guidance.
The' ir.spector noted. that no instances of. inattentiveness to licensed duties have been observed during routine and backshif t ~1nspection' at the station, based on inspector observations of. control room activities during
"unannounced" entrances into the room, and on operator awareness of plant status indicators as displayed on control. room recorders and indicators.
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No violations. and deviations were identified in the ~ review of this area.
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18.
Inspection of General Electric (GE) Type Ak-F-2-25 Breakers The inspector was directed by NRC:RI Division of Reactor Projects to per-form an inspection pertaining to the use of GE Type Ak-F-2-25 breakers ut the Yankee Nuclear Power Station. Region I Temporary Instruction No.
RI-86-02, dated September 19, 1986 was used as guidance in performing this inspection.
As a result of this inspection it was determined that GE type Ak-F-2-25 '
breakers were not used in functions that are important to safety at the plant. However, the inspector noted that the NRC subsequently issued on February 13, 1987 Information Notice (IN) 87-12, Potential Problems with Metal Clad Circuit Breakers, General Electric. type Ak-F-2-25.
Inspector review and findings pertaining to IN 87-12, as well as the relationship of
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tne subject breaker to Ak-2 series breakers used in safety related appli-cations at the plant, i s discussed in Inspection Report 50-29/87-06, Section 8.
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19.
Unresolved Items
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An unresolved item is a matter about which more informattor. is required to avertain whether it i s an acceptable item, a deviation, or _a viola-tit Two unresolved items are discussed in Sections 6 and 10 -of this report
20. Open Items An open item is a matter that requires further review and evaluation by the inspector, including an item pending specific action by the licensee i
and a previously identified violation, deviation, unresolved ~ item, and
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programmatic weakness. Open items are used to document, track, and ensure adequate followup by the inspector.
Seven open items are discussed in Sections 4.a(5), 9, and 10 of this report.
21. Management Meetings During the inspection period, the folicwing management meetings were conducted or attended by the inspector as noted below:
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The inspector attended an information meeting held on July 21, 1987, by the NRC:RI Division of Reactor Projects branch chief with the plant superintendent to discuss issues of mutual interest which included the licensee planned corrective actions in the maintenance area.
The inspector attended on exit meeting held on August 14, 1987, by a
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region based specialist at the conclusion of Inspection 50-29/87-12, review of the nonlicensed staff training program.
The inspector attended an exit meeting held on September 2,1987, by
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a region-based specialist at the conclusion of Inspection 50-29/
87-13, emergency preparedness program review.
The inspector attended an exit meeting held on September 2, 1987, by
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a region-based licensing examiner at the conclusion of Inspection 50-29/87-14, review of the licensee's operator licensing requalifica-tion training program.
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The inspector attended meetings on July 21 and August 26, 1987 held by the cognizant NRC:RI branch chief and section chief, respectively, with the plant superintendent to discuss the NRC inspection program and items of mutual interest.
On September 16, 1987, the inspector attended exit meetings at the
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facility and the licensee corporate headquarters conducted by the NRC:RI regional administrator at the conclusion of his facility tour.
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At periodic intervals during the course of the inspection period, meetings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspecto.
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Attachment I IR 87-11'
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UNITED. STATES NUCLEAR ~ REGULATORY COMMISSION YANKEE ATOMIC POWER STATION RESIDENT OFFICE PO BOX 28 MONROE BRIDGE, MA 01350
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September 18, 1987 MEMORANDUM FOR:
Norman St. Laurent, Plant Superintendent, YNPS FROM:
Harold Eichenholz, Senior Resident I nsp ec tor, YNPS SUBJECT:
FACILITY TOUR FINDINGS - SEPTEMBER 16, 1987'
Tho observations resulting f rom the f acility tour of YNPS on September 16, 1987 by the NRCIRI Regional Administrator are provided in Attachment 1 to this msmorandum for your review and actions as necessary.
These items will be
included in the current routine resident inspection report (50-29/87-11).
Thank you for the helpful assistance provided by both yourself and your staff i
during the tour of the facility.
Sincerely, j
Harold Eichenholz j
cc W.
Russell
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Elsasser j
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ATTACHMENT 1 FACILITY TOUR FINDINGS AND OBSERVATIONS SEPTEMBER 16. 1987 1.
Valve maintenance.
A strong program associated with valve maintenance was evident.
The number of coolant leaks observed was minimal, and equipment was found to be in good condition.
It was noted that in this very important area the licensee was clearly a top performer.
Collection devices were noted to be in use to channel known leakage to drains as part of cantamination control.
A single exception was a minor leak from a capped drain line in the No. 3 charging pump cubicle of the primary auxiliary building (PAB).
This condition appears to be caused by leakage past the seat of the pump discharge drain valve CH-V-693.
2.
Test, vent, and drain line caps.
Facility tour observations indicate that caps are being replaced following operation and maintenance activities.
An isolated observation was a cap that was not reinstalled on the CH-V-627 drain valve f ollowing recent maintenance on the No. 3 charging pump's suction strainer.
3.
Rotating electrical machinery maintenance.
Equipment condition and cleanliness was observed to be excellent, which is indicative of a good planned program.
In this area the licensee has demonstrated excellent performance.
4.
Coordination of maintenance disciplines.
Equipment condition observations of pumps, valves, limit switches, and other control system components uncovered no evidence that would suggest insensitivity exists between the various maintenance disciplines that could result in improper equipment performance.
5.
Housekeeping, maintenance, and radiation protection items.
On an overall basis the plant cleanliness and equipment material conditions provided a positive impression that activities were being done well at the facility.
Area conditions reflect proper removal of supplies, tools, and equipment at the completion of maintenance activities.
However, there is always room for improvement.
The following items suggest the need for additional attention to detail in the aforementioned areas.
Some of these items, in addition to items mentioned above, warrunt licensee followup to ensure that proper corrective actions were implemented.
Two radiation protection survey maps located at the control point
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existed for the north and south decontamination room that were dated September 9 and 16.This resulted in questioning the accuracy of the maps as they pertained to the existence of highly contaminated areas.
Subsequent clarification was provided by a lead radiation protection technician, who was very knowledgeable of the existing conditions.
No inadequacies in the actual surveys were identified.
A survey dated August 12, 1987 was found posted outside of the decontamination rooms.
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Inside the south decontamination room the f ollowing conditi' ens were
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noted: the area was also being used extensively as a storage areal a signiffcant roof leak was evident that was adding an unnecessary burden to the radwaste systems; the roll up door to the outside area was not fully secured, leaves were inside the room near the door, and the inside area near the door was highly contaminated.
The door was left open to facilitate the use of plasma cutting equipment located in the outsido yard area.
However, no use of this equipment was being made at the time of the tour.
A HEPA filter locaf:ed in an outside area was used to filter the air from within a contamination control tent inside the room.
Inclement weather had loosened the tape used to attach a ventilation duct to the filter.
Under the blowdown tank in the lower level of the PAB it was noted
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that rags, leaves, and conduit covers were lying about.
Cigarette butts were found under the skirt of the low pressure
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accumulator of the ECCS system.
Florescent bulbs removed as part of a relamping effort were lying
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against a wall in the post incident cooling building.
Three small cans of terminal coating grease were being stored on a
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conduit above the No. 3 station battery located in the safety injection building.
One of the level indicators on the No. 1 low pressure safety
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injection pump was observed to be below the operating mark.
A small oil leak on a bearing drain plug was observed.
Separation wat observed between the compression type fittings and
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the hoses for the fuel oil return line and the engine oil pressure switch on the No. 2 emergency diesel generator.
A flarblight and pipe wrench were left lying near the shaft coupling
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on a pump in the primary drain collecting tank cubicle.
Masonry debris leftover from an SEP block wall modification was
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observed under steam generator blowdown piping in the upper PAB.
The speaker in the post accident sampling system room was plugged
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with a cloth glove and the battery operated clock normally taped to the wall was lying on the floor and appeared to be inoperable, j
Personnel inside the switchgear room conducting surveillance of fire
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detectors were observed to be using the area on top of one of the UPS inverters as a countertop.
Since those inverters have only grating at their top, there is the potential for any work being performed above them to allow small sized items to fall inside the inverters and affect operability.
Three pipe plugs were found lying under the skid of the diesel
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generator in the safe shutdown building.
They appeared to items removed from the equipment as part of it's installation.
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In the area between the control room panels, an electrical jumper
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was observed to be attached to one of the terminals of lock out'
relay 87-TS-2XA..
The other eno of the jumper.was hanging loose within the wiring area.
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The general cleanliness and contamination levels in.the No. 3
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Charging pump; cubicle appears to reflect the routine existence of
. leakage past the pump's cylinder packing. Consideration should be given to 1) investigate the applicability of temperature monitoring of the packing glands as employed at the Calvert Cliffs facility to extend. packing life and 2) cc,1 duct an evaluation.to determine if'
other corrective measures are available to extend packing life.
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