ML20151E983

Forwards Rept Summarizing NRC Actions Re Restart Following Licensee self-imposed Shut Down on 880419

ML20151E983
Person / Time
Site:	Hatch
Issue date:	07/14/1988
From:	Reyes L, Varga S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), Office of Nuclear Reactor Regulation
To:	Murley T Office of Nuclear Reactor Regulation
References
NUDOCS 8807260284
Download: ML20151E983 (35)

Text

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s Ju'ly 14, 1988 Docket Nos.: 50-321/366 MEliORANDUM FOR: Thomas E. Murley, Director Office of Nuclear Reactor Regulation J. Nelson Grace, Regional Administrator.

Region II FROM: Steven A. Varga, Director Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Luis A. Reyes, Director Division of Reactor Projects Region II

SUBJECT:

HRC STAFF ACTIONS RELATING TO RESTART OF THE EDWIll I. HATCH NUCLEAR PLANT, UNITS 1 AND 2 Enclosed is a report sunnarizing NRC actions relating to restart of the Hatch nuclear plant following the licensee's self-imposed shutdown on April 19, 1988 after the INP0 evaluation. As noted in the report, the results of HRC inspections indicated that subsequent to licensee corrective actions there were no significant safety issues that would offer an impediment to restart of the Hatch units upon completion of the licensee's self-imposed shutdown. The NRC inspection results formed the basis for the staff decision to allow the units to restart when the licensee was ready.

Original signed by:

Steven A. Varga, Director Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Luis A. Reyes, Director Division of Reactor Projects Region II

Enclosure:

As stated DISTRIBUTION:

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NUCLEAR REGULATORY COMMISSION UNITED STAT'Es l} WASHING TON, D. C. 20555 a e 9.....f July 14, 1988 Docket Nos.: 50-321/366 MEliORANDUM FOR: Thomas E. liurley, Director Office of Nuclear Reactor Regulation J. Nelson Grace, Regional Administrator Region II _

FROM: Steven A. Varga, Director Division of Reactor Projects - I/II Office of Naclear Reactor Regulation Luis A. Reyes, Director Division of Reactor Projects Region II

SUBJECT:

NRC STAFF ACTIONS RELATING TO RESTART OF THE EDWIN I. HATCH NUCLEAR PLANT, UNITS 1 AND 2 Enclosed is a report summarizing NRC actions relating to restart of the Hatch nuclear plant following the licensee's self-imposed shutdown on April 19, 1988 after the INP0 evaluation. As noted in the report, the results of NRC inspections indicated that subsequent to licensee corrective actions there were no significant safety issues that would offer an impediment to restart of the Hatch units upon completion of the licensee's self-imposed shutdown. The NRC inspection results formed the basis for the staff decision to allow the units to restart when the licensee was ready.

, e Division of Reactor Pr icts - 1/II Office of, Nucle React Regulation

,/ ,/ 41 4 I Luis A. Reyes, D cter Division of R or Projects Region II t

Enclosure:

As stated

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- . 1 NRC STAFF ACTIONS l RELATING TO RESTART OF EDWIN I. HATCH NUCLEAR PLANT, UNITS 1 AND 2

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• o TABLE OF CONTENTS l

PAGE OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . 1 BACKGROUND . . . . . . . . . . . . . . . . . . . . . . . . 1 DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . 2

1. Operations . . . . . . . . . . . . . . . . . . . 3

2. Organization and Administration. . . . . . . . . 11 __.

3. Maintenance. . . . . . . . . . . . . . . . . . . 16

4. Technical Support. . . . . . . . . . . . . . . . 19

5. Training and Qualification . . . . . . . . . . . 22

6. Radiological Protection. . . . . . . . . . . . . 24

7. Chemistry. . . . . . . . . . . . . . . . . . . . 25 8.- Operating Experience Review. . . . . . . . . . . 28

SUMMARY

.........................30 CONC LUS ION . . . . . . . . . . . . . . . . . . . . . . . . 30 APPENDICES A. Inspection Report 88-11, Monthly Resident Inspection (3/26/88-4/22/88),

issued 5/16/88.

8. Inspection Report 88-12, E0P Team Inspection, issued 7/6/88.

C. Inspection Report 88-13, Plant Chemistry, issued 5/17/88. ,

D. Inspection Report 88-14, Monthly Resident Inspection (4/23/88-5/20/88),

issued 6/10/88.

E. Inspection Report 88-15, Operational Performance Assessment, issued 6/17/88.

F. Inspection Report 88-16, Radiological Protection, issued 5/25/88.

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NRC STAFF ACTIONS RELATING TO RESTART 9f HATCH NUCLEAP. PLANT, UNITS 1 AND 2 OVERVIEW The staff's decision to permit. restart of the Hatch Nuclear Plant relied upon staff inspections conducted during the plant shutdown. These inspections )

included examination of all the areas of the INP0 findings (and the licensee's n I corrective action) relevant to safe reactor operation and public health and l safety and are documented in inspection reports included herein as appendices.

While most of these inspection efforts were scheduled prior to the announcement of the INP0 findings, each of these inspection efforts was modified as neces-sary to include specific consideration of all the areas of INP0 findings that were identified as a result of meetings with the licensee regarding the INP0 findings and proposed actions, a site visit by the staff to review INP0 field l notes then in the possession of the licensee, an NRR/ Region II management visit to INPO, and the May 4, 1988 letter frca the licensee. The INP0 report transmitted to the NRC by the licensee on May 11, 1988 added details to the staff'srunderstanding of the INP0 findings as obtained through the meetings M th the licensee and INP0 and the review of the INPO field notes.

The staff concluded that the results of these inspection efforts disclosed no impediments to plant restart.

The INP0 findings, together with the IflP0 recomendations, the licensee's responses, and a summary of the staff's inspection and assessment of these issues are included herein.

BACKGROUND The Institute of Nuclear Power Operations (INPO) conducted an evaluation of the Edwin I. Hatch Nuclear Plant, Units 1 and 2, during the weeks of March 13 and 20, l

1988. Results of the evaluation were presented orally to the licensee, Georgia Power Company (GPC), at an exit briefing on April 15, 1988. INP0 had given the plant an overall Category 5, which is the lowest INP0 evaluation rating. On April 19, 1988, the NRC was advised by the licensee that it was shutting down.

the Hatch units pending completion of corrective actions in response to the INP0 findings.

On April 19, 1988, Region II management net with GPC to discuss the INP0 findings and the licensee's proposed actions to make improvements. On April l 21-22, the Region II Director of Reactor Projects visited the Hatch site for I further discussions and to review the INP0 field notes then in the possession f of the licensee. On April 25, NRR and Region II management visited INP0 to discuss the results of the INP0 evaluation. A May 4 letter from R. P. Mcdonald (GPC) to T. E. Murley (NRC) summarized the "(INP0) - identified weaknesses in

, several operational areas" and described the licensee's corrective actions.

l This letter limited its discussion to those "operating conditions and indications

of performance that warranted priority attention and upgrading prior to continuation of normal plant openations." However, the NRR/ Region II meetings with the licensee and INP0 and examination of the INP0 field notes had provided additional information related to all of the INP0 findings.

The NRC conducted an Emergency Operating Procedures (EOP) inspection at Hatch during the period May 2-10 and an Operational Performance Assessment (0PA) during the period May 9-20. In addition, an inspection regarding plant chemistry was conducted during the period April 18-20, and a radiological protection inspection was conducted during the period May 9-11. Regular inspections by the Hatch resident inspectors were conducted during the periods _..

March 26-April 2.?. and April 23-May 20. Except for the May 9-10 radiological protection inspection, each of these inspection efforts had been scheduled before the announcement of the INP0 findings. However, in view of the actions taken by the licensee and with the knowledge of the INP0 findings gleaned from the April 19 meeting with the licensee, the site visit by the Director of Reactor Projects, and the NRR/ Region 11 management visit to INPO, these inspection efforts were modified, as necessary, to include specific consideration of all the problem areas identified by INP0. The radiological protection inspection was a direct reaction to the INP0 findings. The reports of these inspections are included as appendices to this report.

The licensee tTansmitted the INP0 report to NRC by letter of May 11, 1988.

The report confirmed the operational considerations discussed in Mr. Mcdonald's May 4 letter and added oetails to the staff's understanding of the INP0 findings as obtained through the meetings with the licensee and INP0 and the NRC review of the INP0 field notes. To this extent, the NRC staff relied on the INP0

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report in reaching its judgement regarding the acceptability of the licensee's decision to restart. However, the agency's regulatory decision to permit restart was based on the results of the inspection report findings, primarily the E0P and OPA inspections, which disclosed no impediments to plant restart.

DISCUSSION INP0 findings were made in the following eight areas: Operations, Organization and Administration, Maintenance, Technical Support, Training and Qualification, Radiological Protection, Chemistry, and Operating Experience Review. At the times of the NRC inspections, the licensee had already started or completed actions designed to correct deficiencies noted by INP0. The NRC inspections included evaluation of the adequacy of the corrective actions taken or planned to respond to the INP0 findings as well as an overall evaluation of the licensee's programs and activities in place or underway. Each of the INP0 findi~ngs and the licensee's responses to the findings are quoted below, followed by a sumary of the NRC staff action and findings with references to the particular inspection report (Appendices A through F) that discusses the issue.

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1. Operations l

a. INP0 Finding During a plant startup and heat-up, the monitoring and control of the reactor and behavior in the control room were not up to industry professional standards. Supervisory personnel were present during these observations but took no action to correct the problems.

INP0 Recommendation Improve control room personnel monitoring and control of the reactor.

Establish and maintain a professional environment in the control room.

Control the number of personnel in the control room and the conduct of activities to minimize distractions during critical plant periods. Hold cperations supervisors accountable to routinely correct problems such as those noted above.

Licensee Response The following immediate actions are to be completed prior to startup on or about May 14, 1988.

a. Arrange and hold reviews and discussions about the principles of professionalism in the control room involving the following:

1. shift supervisor

2. operations supervisor

3. operations superintendent

4. manager of operations

5. plant manager

6. vice president Plant Hatch

7. executive vice president, Nuclear Operations

8. chairman of Board, CEO, president of Georgia Power Company

b. Implement augmented procedures for control board access control.

c. Develop, using operator input, a code of conduct to be followed by control room personnel and others entering the control room.

d. Clarify and emphasize responsibilities and role of operators on the reactor control panel as well as the supervisor's role.

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• NRC Actions The OPA team specifically evaluated operator professionalism and related matters pertainino to control room operatinns. Discussions of these areas are presented in Sections 2.a and 3.a of Inspection Report 88-15.

The team found that a Code of Conduct had been developed by the operators that addressed clear communications, tne monitoring of panels, the response to alarms, control room access, and other issues. Discussions with plant operators revealed that they were knowledgeable of the code, which is more like a code of ethics than a formal procedure. During frequent tours of -

the control room, team inspectors observed that the items in the code were being followed.

The meetings and discussions with corpora'.e and senior plant management were held in accordance with the licenser 's com:nitment to INP0. Additional seminars were scheduled for shift supervisors, operations supervisors and superintender.ts up through the Operations line management. The inspectors reviewed documents that outlined the topics discussed during these meetings and the listed persons attending.

The inspectors performed extended observations of control room activities (including' back shif ts), observed shif t turnovers, and reviewed applicable operator logs. The inspectors monitored operations personnel performance, including their awareness of plant status, their use of procedures, and their maintenance of required station logs and status boards. Startup operations for both units were observed. For each unit, equipment problems were encountered, but in each case the operating staff was thorough and proceeded cautiously until the problems were resolved. Positive control room demeanor and operating staff professionalism were noted by the inspectors.

Long-term followup observation of control room operations and operator professionalism and demeanor will be made as part of the routine resident inspection program.

b. INP0 Finding The operator's ability to diagnose plant probleins ad direct corrective actions is impaired by continuously lighted annunciators and nuisance alarms. Many annunciators are continuously lighted due to equipment abnormalities and design deficiencies. Most annunciators do not have a reflash feature and interim actions are often not initiated to compensate for the loss of annunciation. As a result, emergent plant conditions that could impact on plant safety may be overicoked. For example, there is a continuous alarm for a leaking safety valve. An increase in the present leakage or leakage from another safety valve would not be quickly detected by control room personnel.

It is recognized that design changes are under development to resolve some of these problems.

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INP0 Recommendation Implement corrective actions to return control room annunciators to an operable status. Emphasize the import 6nce of implementing effective interim actions when annunciators without a reflash feature are continuously alarming.

Licensee Response The following irinediate actions are to be completed prior to startup:

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a. Establish a policy and the necessary procedures which allow the removal of single point inputs from multiple point alarms, the removal of annunciator cards from limited input annunciators, along with the necessary compensatory actior:s and control mechanisms until appropriate corrective action can be completed.

b. Establish a policy and the necessary procedures which allow the operations personnel on shift to conditionally disable temporarily nuisance type annunciators until such time that the operational status of the plant would cause the annunciator to provide valic information or the annunciator is modified through the normal design process,

c. Initiate changes to correct problems that are causing inappropriate or invalid annunciators to be lighted in the control room.

d. Implement a procedure for prioritizing maintenance and repair of malfunctioning instruments and equipment which contribute to nuisance alarms and inappropriately lighted annunciator points.

Additionally, alarms will be reviewed for their functional purpose and design to initiate design changes where practical to reduce nuisance conditions by August 1988.

NRC Action The status of the control room annunciators was reviewed by the OPA team during its May 9-20 inspection. The results are discussed in Section 2.b of Inspection Report 88-15. The inspector concluded that the licensee was correcting annunciator problems in accordance with plant procedures. 'No violations or deviations were identified. The resident inspector will follow up on long-term corrective action and verify its adequacy,

c. INPO Finding Numerous equipment clearances have remained in effect for several years and could impact on the operator's ability to determine plant status.

Many of these clearances are outstanding due to pending procedure

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l For example, changes, completion of maintenance, or engineering support.

clearance 3-85-54 is in place to ensure the electro-hydraulic control 1 bypass valves installed under DCR-83-174 remain open to prevent a plant trip. This clearance could be removed by adding these valves to the locked valve list. Longstanding clearances of this nature can rcduce the significance :.f and/or respect for danger tags.

IHP0 Reco:nmendation Review longstanding equipment clearances for continued applicability and determine work necessary to remove the clearance. Complete procedure 1 changes, work orders, or provide engineering support in a timely fashion to allow removal of equipment clearances.

Licensee Response The following immediate actions are to be completed prior to startilp:

a. Implement procedures for reviewing open clearances %

continuing applicability every three months.

b. Implement other control mechanisms where tporopriate to avnid

- -the use of clearances for long term conditions or problems.

Only those long term clearances specifically approved by the Executive Vice President will be continued for startup.

Additionally, by September 1988, design changes will be initiated where applicable to eliminate remaining long-term clearances.

NRC Action The status of the licensee's corrective actions regarding clearance tagging was reviewed by the resident inspector and is discussed in Section 13 of Inspection Report 88-14. The inspector found that the licensee had taken effective action to reduce dependence on equipment clearances for configuration control and to reduce the number of long-standing equipmeat clearances. Procedures had been revised to require review of clearances that have been in effect for six months or longer. The licensee's Executive Vice President had approved the limited number (37) of long-standing clearances that were still in effect at the time of plant restart.

The resident inspector will follow up on the the licensee's long-term corrective action.

The OPA team also examined the area of equipment clearance tagging, as described in Section 3.1 of Inspection Report 88-15. The OPA evaluation found that tagging was being adequately conducted in accordance with approved procedures. The team found no violations or deviations.

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d. INPO Finding The ability of shift crews to respond to plant transients as demonstrated on the simulator needs significant improvement. The complexity of the emergency operating procedure (E0P) flowpath physical size and charts required continuous concentration on the part of the shift supervisor.-

The shift supervisor must hold the chart close to his face to determine the correct flow path on the chart. This creates a barrier in keeping visual track of the plant and the crew. In one case the shift supervisor directed HPCI to be started when it had been running for some time. In another case the shift supervisor thought RCIC was running when it had 1 been shutdown earlier. Sometimes the crew took action without the knowledge of the shift supervisor, for example, placing the residual heat removal in suppression pool cooling. In addition, a shift supervisor directed action independent of the E0P's order to place the plart in a stable condition during an actual plant scram.

INP0 Recommendation Improve the operating crew's ability to use the E0Ps to effectively handle plant emergencies. Revise the E0Ps to reduce their complexity, simplify the presentation of information, and correct technical inadequacies. Provide additional operator training on the revised procedures. It is recognized that these efforts may take significant time to complete; therefore, interim action should be taken to a:sure that control room actions will be appropriate in response to plant transients.

Licensee Response The followino immediate actions are to be completed prior to startup:

a. Completion of a technical review and evaluation against the Boiling Water Reactor Owners Group Emergency Procedure Guidelines and correction of signifisant identified deficiencies.

b. Establish a task for:e with the long-range objective of upgerding emergency operating pr cedures. A schedule for comp.eting the modifications and retraining the operations staff will be prepared.

c. Establish a schedule for upgrading identified human factor areas in the E0Ps.

d. Retrain the present licensed operators individually and as a team in the use o' the emergency operating procedures,

e. Use senior operations management and technical experts as necessary to evaluate the performance of individual operators and each operating shift as a team, using scenarios involving extensive use of the emergency operating procedures.

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o-Additionally, an E0P simplificrtion effort will be accomplished by October 1988. This process will address human factor improvement items such as the following:

consolidation or elimination of fire notes, cautions, system restorations, and system operations minimization of steps operator language improvements 1 ..

print size expansion to improve readability Work plans to achieve long-range objectives established through the task force as stated in (b) above will be provided in the six-month status report.

NRC Actions The sole purpose of the NRC's E0P inspection team was to evaluate the adequacy of the plant E0Ps and the ability of the plant operators to use the E0Ps. The results of that inspection are presented in Inspection Report 88s12. The E0P team concluded that the E0Ps at Hatch need improvement, including a need for adequate justification of the differences between the E0Ps and the Emergency Procedure Guidelines (EPGs); correction of human factor deficiencies; better procedures development, validation and verification; additional operator training; and improved procedures to implement primary and secondary containment and radiation release control. By the time of the E0P inspection, the licensee had had an opportunity to initiate both retraining on use of the E0Ps and corrective actions regarding the human factors deficiencies with the E0P flow charts. Based upon the system walkdowns and the plant simulator exercises, the E0P team concluded that the Plant Hatch personnel could carry out the E0Ps as constructed and tha't the (then) current E0Ps could get the plant to a safe condition if needed.

The OPA inspection team also examined the matter of E0P adequacy, as described in Section 2.c.(1) of Inspection Report 88-15. Specificall the OPA team examined the results of a General Electric Company (GE) y, review of the E0Ps that had been performed following the INP0 evaluation, but before the NRC OPA team inspection. The GE review concluded that there were no significant technical deficiencies with the E0Ps, but that the E0Ps contained numerous differences from the EPGs, that there were human factor deficiencies, and that the E0P flow charts were unnecessarily complicated. By the time of the OPA inspection, short term corrective action had been taken to make the flow charts more usable and to cause the operator to consult the End Path Manuals for instructions regarding primary and secondary containment earlier in the flow chart procedure sequence.

The licensee is committed to a major critical review of the E0Ps in the near future, although the time for coupletion of the review is still under consideration. Revisions will include simplification of the flow charts, with human factors improvements (e.g., enlarged print size, improved language, removal of extraneous procedural steps), and justification of plant-specific differences from the EPGs. This longer-term 1mprovement will be reviewed further and is carried as inspection followup item 321, 366/88-15-01. -

Section 2.c.(2) of Inspection Report 88-15 addresses operator upgrade training on use of the E0Ps. This training consisted of simulator drills n to improve operator response to transients and to sharpen their use of the E0Ps. The training included an evaluation of the operators by an independent group from GE and private contractors who were knowledgeable 3 of industry practices and standards for operatur licensing. As a result J of this upgrade training, seven operators were found to be deficient in E0P knowledge and skills ind were removed from licensed duties pending additional retraining. Following the additional training and successful evaluation by the licensee, they will be returned to licensed duties. The independent reviewers determined that the upgrade training was effective, considering the short time constraints, and concluded that the operators' performance was acceptable,

e. INP0 Finding Many instruments, panel components, and plant equipment are not identified with permanent labels. A formal plant program does not exist to periodically verify that labels previously installed have not fallen off, been removed, or damaged. Human performance studies have shown that deficient labeling often contributes to human error.

INP0 Recommendation Implement a formal ongoing labeling program to labe4 plant components and periodically verify and replace missing 'abels.

Licensee Response The following immediate actions are to be completed prior to startup:

a. Walk down systems and identify curre~nt labeling which does not comply with procedures and schedule the corrective actions.

The executive vice president will approve the scope of corrective action to be completed prior to startup.

b. Review current labeling procedures and revise as necessary to ensure that the procedure adequately addresses maintenance of the labeling systen.

Additionally, remaining corrective actions referred to in (a) above will be ccmpleted by December 1988.

s f NRC Action The OPA inspection team evaluated plant labeling, as described in Section 2.d of Inspection Report 88-15. The team found that the licensee had taken short-term corrective actions, including th development of an interim special purpose procedure and a permanent administrative procedure to control system and component lateling, assignment of specific responsibilities for proper labeling, training for appropriate plant personnel to ensure proper implementation of the labeling program, and correction of labeling deficiencies. The licensee had mada plant walkdowns to identify unlabeled plant equipment dnd locations so that corrective n action could be taken in accordance with the labeling proced"res. The OPA team concluded that the licensee's action plan and procedural controls should adequately ensure proper plant equipment labeling.

3 Long-term followup of this matter will be ccnducted as a part of the resident inspection program,

f. INP0 Finding Housekeeping and cleanliness in some less traveled areas of the plant need improvement. Several equipment oil leaks throughout the plant require large amounts of absorbent toweling to control the leakage. In some cases, the toweling is saturated with oil and needs to be replaced. In addition, there were several areas where oil, water, and resin was not wiped bp by the operators as required by plant procedures.

INP0 Recommendation Enforce high standards for maintaining plant housekeeping and cleenliness.

Hold personnel accountable for area cleanup following work activities.

Licensee Response The authority and responsibility for establishing and maintaining high standards of plant housekeeping and cleanliness in less traveled as well as other areas of the plant will be reemphasized as requiring continuing managerial, supervisory, and hands-on worker performance. A followup comprehensive management inspection for effectiveness will be completed by August 1988.

NRC Actions Inspection of lic6nsee housekeeping is a part of the regular resident inspection program. Section 5 of Inspection Report 88-11 and Section 5 of Inspection Report 88-14 discuss plant housekeeping matters. In addition, the OPA team examined plant housekeeping, as discussed in Section 3.f of Inspection Report 88-15. Although specific housekeeping discrepancies were noted, the OPA team noted that tours of the plant showed the facilities to be in generally good condition with the major s

pieces of equipment clean and having few oil leaks. Licensee personnel were observed to be critical and thorough in documenting housekeeping deficiencies, and prompt folicwup action was taken on reported deficiencies.

The inspector concluded that continued emphasis on housekeep ng of the less frequently toured areas of the plant was needed.

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As noted earlier, long-term followup on the plant housekeeping is a part of the regular resident inspection program.

2. ORGANIZATION AND ADMINISTRATION

a. INP0 Finding Management assessment, direction and follow-up have not been effective in resolving a number of important issues. Problems continue to exist in the areas of drawing control, radiological work practices, chemistry, equipment labeling, plant thermal performance, and operating experience ~_

review. When problems are observed, adequate investigation, corrective action, and follow-up are often not accomplished.

INP0 Recommendation Upgrade maragement assessment activities to identify and correct problems including those noted above. Ensure adequate investigation, initiation of corrective actions, and follow-up is taken to correct recurring problems.

Licensee Response We will focus management attention and energy to continuously search for and to identify plant problems of all types, to determine their root and contributing causes, to develop proper corrective actions, to implement such actions in a timely manner, and, in follow-up, to verify the adequacy of corrective actions. The actions to accomplish this objective will be in place by August 1988.

NRC Actions Observation of licensee management, organization and administration is a part of the normal inspection program of the resident inspectors, who interact daily with plant management personnel. Comments, as deemed appropriate, are made in the monthly inspection reports, including Inspection Reports 88-11 and 88-14. The OPA team specifically examined the licensee organization for shift operations (Section o.g), management involvement in maintenance (Section 4.h), engineering support to maintenance activities (Section 4.1), and eleven areas of management control (Section 5), as discussed in Inspection Report 88-15.

While a number of weaknesses ir. management controls were noted, as discussed in Section 5 and the Summary of Inspection Report 88-15, neither the OPA team nor the resident inspectors are aware of significant weaknesses in licensee management, organization, or administration. It is noted that INP0 findings in this area are largely a compilation of specifics discussed elsewhere in the INP0 report.

All inspection activities-at the plant include continuing observation of licensee organization and management and management controls.

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b. INP0 Finding A number of longstanding existing and potential equipment performance and testing problems have not been resolved in a timely manner. Implementation of corrective actions to prevent an occurrt...ce or recurrence has not been timely and in some cases has not been thorough or complete.

INPO Recommendation Determine why the type of equipment problems noted have been allowed to exist for extended periods of time. Take action to thoroughly address n potential and known equipment problems in a timely manner.

Licensee Response We will focus management attention and energy to continuously search for and to identify plant problems of all types, to determine -their root and contributing causes, to develop proper corrective actions, to implement such actions in a timely manner, and, in follow-up, to verify the adequacy of corrective actions. Action to accomplish this objective will be in place by August 1988 and will include the specific examples noted.

NRC Actions Examples of problems noted by INP0 included: (1) diesel generator testing; (2) recurring problems with check valves; (3) recurring problems (spurious spikes on intermediate range monitors and cverage power range monitors; and (4}) delay in correcting a surveillance test procedure relating to testing of the turbine governor control.

Testing of the diesel generators was being performed in accordance with previously approved plant technical specifications. An amen # ment to the technical specifications was approved in 1987 that reduced the required number of cold, fast starts for test purposes. These changes'had not been implemented at the plant at the time of the INP0 evaluation because of a question regarding the definition of operability for the dtesel generators.

This issue was resolved and is discussed in Section 13 of Inspection Report 88-14.

The OPA team examined the matter of check valve failures (Section 1.f of Inspection Report 88-15) and agreed with the INPO findirg that the licensee had not addressed this issue aggressively.

The licensee thinks that the spiking problem with the neutron monitors is caused by moisture in the cables. It is not addressed in the OPA team inspection report.

As noted in the INP0 findings, the procedure revision for the turbine governor control testing was accomplished in early 1988. This issue was examined by the OPA team and is discussed in Section 4:3'tf Inspection Report 88-15.

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c. INP0 Finding Hecessary support has not been provided to ensure the operators can readily determine plant status and respond to plant conditions. The following problens were noted: {

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(1) A large number of common annunciators exist in the control room  !

in an alarmed state that causes distractions and precludes the annunciation of additional alarming conditions.

(2) Critical drawings in the control room designated for operator -

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use are not updated in a usable manner to allow operators to quickly assess plant status.

(3) Many instruments, controls, and gauges in the plant are not

, labeled so the operator can determine their function or system application..

(4) The emergency operating procedures cannot be readily used to respond to plant transients.

INP0 Recommendation Provide strong and imediate management support to ensure the operators have the ability to determine plant status and respond to plant conditions.

Licensee Performance Corrective actions to the problems noted above are described in the responses to the respective specific findings in other sections of the report. In addition, management will frequently review operations to ensure similar conditions do not recur.

Both the immediate upgrade and long-term actions will be completed by the following dates for the respective problems noted:

(1) August 1988 l

j (2) September 1988 l

(3) December 1988 (4) October 1988 NRC Action (1) The OPA team specifically examined the status of lighted control room annunciators and the licensee's actions to correct deficiencies noted by INP0. Results are reported in Section 2.b of Inspection Report 88-15.

The licensee had. initiated a progran and developed a procedure aimed at achieving near 100% reliability and availability of annunciators. Problem

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annunciators and instruments had been assigned corrective action priorities and entered on schedules for correction. The inspector concluded that problems with annunciators were being addressed in accordance with plant instructions. No violations or deviations were noted.

The resident inspection program will include long-term followup to verify the adequacy of corrective actions.

(2) Licensee control of drawing's used in the control room was examined by the OPA team and the results of the review are reported in Sec'.fon 2.e of Inspection Report 88-15. The licensee had recently upgraded the i controls on control room drawings to simplify the operator's role in the drawing update process. The revised drawing control program consisted of the establishment of a "blue line" stick file of drawings in eacn control room. System changes referencing the appropriate As-Built Scices or Work Completion Notices are entered as "red lines" on the drawings. A revised list of critical drawings has been developed and was reviewed by the inspector. Training had been given to site engineering personnel on the new drawing program. No violations or deviations were no,ed.

The resident inspection program will include followup verification of the adequacy of long-term corrective actions.

(3) The OPA team reviewed the licensee's actions to correct plant labeling deficiencies. The results are reported in Section 2.d of Inspection Report 88-15. A special purpose interim procedure and a permanent administrative procedure had been developed to delineate the requirements for identifying and maintaining labels for plant equipment and locations. Plant walkdowns had been conducted to identify labeling deficiencies, responsibilities for proper labeling had been assigned, and training of appropriate plant personnel had been conducted. No violations or deviations were identified.

The resident inspection program will include followup action to verify the long-term adequacy of the labeling program.

(4) The E0P inspection examined the adequacy of the plant E0Ps, as reported in Inspection Report 88-12. The E0P team noted deficiencies in the emergency procedures, and pointed out specific areas where the procedures need improvement. However, the overall conclusion of the team was that the procedures were usable to respond to plant transients, that they would accomplish their intended purpose, and that plant personnel knew how to use the procedures.

The OPA team also examined the adequacy of the E0Ps, as discussed in Section 2.c of Inspection Report 88-15, reaching conclusions similar to those of the E0P team. The general feeling of the OPA team was that the E0P deficiencies were the most serious deficiencies observed during the inspection. However, the team felt that while improvements were needed, the procedures as they existed were usable.

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s Long-term followup of-the E0P upgrade program will be followed as

-inspector followup item 321, 366/88-15-01.

d. INP0 Finding Further emphasis on improving radiological work practices and stronger s support of the health physics progran is needed to minimize the spread of contamination to personnel, equipment, and clean plant areas. Additionally, supervisors often do not c0rrect improper radiological Work practices of their workers and frequently make similar mistakes.

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INPO Recommendation Hold supervisory personnel accountable for the radiological performance of their workers. Increase supervisory monitoring of radiological wurk and provide on-the-spot correction of noted improper radiological work practices. Re-emphasize the need for all plant and contract employees to follow established radiological protection policies and procedures.

Licensee Response Corrective actions to address the finding are as follows:

a. The concurrent authority and responsibility of management and supervision for radiological performance of their line function work will be clearly expressed and pursued as a matter of policy by November 1988.

b. The requirement for plant and contract employees to follow radiological protection procedures and policies will be re-emphasized in training and, where appropriate, through terms and conditions of contracts by December 1988.

NRC Actions A special radiological protection inspection, as discussed in Inspection Report 88-16, examined the licensee's radiological protection training program. The inspector also examined the licensee's program for control of radioactive materials and contamination. No violations or deviations were noted. The inspector considered that the license had adequately responded to the INP0 findings,

e. INPO Finding Certain aspects of the industrial safety program need improvement to '

minimize the potential for personnel injuries. Deficiencies were noted in contract personnel work practices and the identification and correction of potentially hazardous conditions.

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d INPO Recommendation Strengthen the industrial safety program by correcting deficiencies including those identified above. Enforce contract personnel adherence to safe work practices. Emphasize to all personnel the need to identify and Correct industrial safety hazards. Hold managers and supervisors accountable for their people in order to improve industrial safety performance and conditions.

Licensee Response

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The Hatch Safety Training Observation Program (STOP) will be used to re-emphasize the requirement for correcting existing and emergency industrial safety defenses and hazards.

The line responsibility for industrial safety performance and conditions will be reiterated periodically.

Industrial safety performance criteria has been added to 'the terms and conditions of new contract documents, thus increasing contractor awareness and accountability.

The above actions will be completed by December 1988.

NRC Actions The NRC has no requirements regarding, and does not normally inspect, industrial safety matters. As a result, none of the inspections examined industrial safety.

3. MAINTENANCE

a. INPO Finding Improvement is needed in the identification and correction of many oil leaks on major plant components.

INPO Recommendation Identify and correct oil system deficiencies and document them in the work control system. Following corrective maintenance on oil systems, perform post-maintenance inspections at normal system pressure.

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Licensee Response The following actions address oil leaks on major components:

a. A complete plant walkdown will be performed to identify oil  !

leaks. A special team has been formed to track repairs of the l identified items to completion. Oil system deficiencies will be documented in the work control system. All non-outage work will be completed by December 1988.

b. Enhancements will be made to routine housekeeping and _..

inspection plans to help prevent recurrence. A post-maintenance test procedures enhancement will be implemented by June 1988, which includes a check for leaks at normal system pressure.

NRC Actions Identifying oil leaks from plant equipment is part of the resident inspection program of observing general housekeeping at the plant.

Section 5 of Inspection Report 88-14 presents the resident inspector observations on oil leakage. In addition, Section 3.f of Inspection Report 88-15, discusses observations of the OPA team during tours of the plant. fleither report identified any significant problems with oil leakage. The normal resident inspection program will provide for long-term followup of licensee corrective actions,

b. INP0 Finding Post-maintenance testing is not consistently specified, performed, or documented for some equipment imputant to safe and reliable plant operation.

(1) Appropriate post-maintenance testing was not specified or performed after completion of several work activities.

(2) A comprehensive document that provides guidelines for post-maintenance testing requirements on a component level is not available. As a result, post-maintenance testing for similar components is often inconsistently specified.

INPO Recommendation Upgrade post-maintenance testing by specifying, performing, ard' documenting all required tests. Develop a post-maintenance test guideline to provide a comprehensive end c'onsistent selection of test l requirements for plant equipment. INPC 87-028 (Good Practice MA-305),

Post-itaintenance Testing, could be of assistance in this effort.

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Licensee Response An upgraded post-maintenance testing procedure that comprehensively addresses post-maintenance testing requirements will be developed and in place by August 1988. This procedure will serve as a guideline for specifying, performing and documenting required post-maintenance testing.

NRC Actions The OPA team examined the Maintenance Work Order Functional Testing Assignment Log which had been developed to provide basic post-maintenance _

testing requirements for specific types and applications of equipment.

The document appeared to be adequate. Results are discussed in Section 2.h of Inspection Report 88-15. The OPA team also examined a sample of MW0s for appropriate post-maintenance testing. No problems were noted during this review. Licensee scheduling of post-maintenance testing was reviewed by the OPA inspection team and is discussed in Section 3.k of Inspection Report 88-15. The inspector concluded that the scheduling of post-maintenance testin; was satisfactory.

This matter was also addressed by the resident inspectors and is discussed in Section 5 of Inspection Report 88-11. The licensee reviewed 400 inaintenance work orders (HW0s) that had been completed during the recent Unit 2 outage to ensure that there were no discrepancies regarding post-maintenance testing. The licensee had established additional administrative controls to ensure that-Local Leak Rate Test (LLRT) requirements are properly addressed in MWO preparation, and added an MWO review sheet to the MWO package to ensure compliance and proper documentation. A new procedure was being developed to provide for separate checks of LLRT applicability on initial review of MW0s, and an existing maintenance procedure was being revised to improve the 1.LRT component review form and to strengthen the requirements to contact the LLRT coordinator before and after maintenance.

Followup on long-term implementation and verification of the adequacy of licensee corrective actions will be handled as a part of the resident inspection program.

c. INP0 Finding Materials management needs to be upgraded in the areas of engineering equivalency reviews, spare parts associated with design changes, and information in the warehouse computer. Problems in these areas have resulted in maintenance activity delays.

INPO Recommendation Modify the engineering part equivalency review process to address all components for a sir.gle stock rumber vice a single component at a time.

Cunsider performing a systematic engineering equivalency review of all like components instead of waiting for the need to arise. Review design changes to ensure appropriate maintenance spares are identified,

incorporated in the materials management computer program, and the required levels of stock are procured and maintained. Additionally, develop and implement a validation program of spare parts information currently in the plant computer system usino the existing computer system capability. Reinforce with warehousing personnel the need for accuracy in entering data into the computer system.

' Licensee Response l The following actions will be taken to address problems in material management:

a. Consideration will be given to how to most cost effectively use equivalency and dedication of commercial parts and to other  !

processes to enhance the availability of parts needed for '

maintenance. This will include involvement in similar industry efforts. A course of action will be determined by December 1988.

b. The design change process will be enhanced by appropriately adjusting the inventory of involved components as part of the process. This will be completed by June 1988.

NRC Actiorrs The INP0 finding and the licensee response are primarily involved with the economics of plant operation rather than plant safety. The OPA team did, however, briefly examine the status of the licensee actions, as reported in Section 4.i of Inspection Report 88-15. Engineering equivalency reviews were being simplified and the applicable engineerinp procedure was being modified to eliminate duplicate equivalency reviews, l change the approval review process, and allow replacement part approval for l an "intended use" instead of only for a single specific use. No violations or deviations were identified.

l l No specif.ic followup action was identified.

4 TECHNICAL SUPPORT

a. INP0 Finding j Revisions of plant drawings, including critical drawings, need to be more I

timely so the plant configuration can be readily determined. The operator's ability to determine plant status is significantly impaired by

, the lack of revision to these critical drawings.

INP0 Recommendation Update drawings used for plant operations in a tinely manner, and resolve problems associated with determining plant configuration through ABN use. Establish controls to make accurate information regarding critical drawings readily available to the operations staff. Resolve ABN tracking inconsistencies to enable plant staff to determine status of individual drawings, individual ABNs, and the ABN backlog.

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Licensee Response The following imediate actions are to be completed prior to startup:

a. Correct deficiencies associated with critical drawings and ensure that drawings are correctly marked-up to reflect the as-built condition and are available to the operations personnel.

b. Augment and implement the procedures to ensure that critical drawings in the control room are maintained up-to-date. _..

Additionally, ABN tracking inconsistencies will be resolved by September 1988 to enable plant staff to determine status of individual drawings, individual ABNs, and the ABN backlog.

NRC Actions 1

Drawing control deficiencies and licensee corrective actions were reviewed by the OPA team and are discussed in Section 2.e of Inspection Report 88-15. The licensee's revised program for drawing control was outlined in two plant procedures which appeared to be adequate except that thei did n~ot assign specific responsibility for accomplishing the "red lining" on the control room drawings and did not establish when the "red lining" was to be accomplished. The site Engineering Manager committed to revising the procedures to specify these matters. A revised list of critical drawings had been developed, and the inspector was satisfied that adequate controls were in place to establish the critical drawing lists.

Training for site engineering personnel on the new drawing control program appeared to be. adequate and, except for personnel on extended absence,

' had been completed.' "Blue line" stick files had been established for each control rocm.

Long-tern followup of drawing control enhancements will be conducted as part of the resident inspection program,

b. INP0 Finding Testing practices regarding the emergency diesel generators (EDG) are not consistent with optimization of engine lifetime, performance, and reliability.

INPO Recomendation Implement changes as necessary to the EDG controls and procedures required to allow gradual starting and loading of the EDGs during monthly tests. Address vendor recommendations concerning barring the engine over after operation. Review temporary modification controls to preclude the unauthorized use of temporary level indicators and other such temporary installations.

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Licensee Response I

Testing practices for the emergency diesel generators will be upgraded as follows:

a. . Procedures will be changed to provide gradual starting and loading of the EDGs for monthly tests by June 1988.

b. Procedures will be revised to include barring over the EDGs after runr.ing in accordance with vendor recommendations by June l

1998. 1

c. Compliance with temporary modification controls will be stressed with responsible supervisors and managers and will be complete by June 1988.

NRC Actions This issue is discussed in Section 13 of Inspection Report 88-14 The inspector found that the licensee had taken action to reduce the number of fast starts of the emergency diesel generators in an effort to prolong engine life and improve reliability. Test procedures were being revised to provide for slow starts and for barring over the engines subsequent to operation. The revised test procedures were to be The in effect for inspection resident all five of the emergency diesel generators by June 1, 1988.

program will verify the adequacy of the corrective actions when completed.

c. INPO Finding Thermal performance monitoring data is not being effectively used to optimize plant performance.

INP0 Recommendation Address thermal performance deficiencies through a comprehensive program that includes reestablishment of the design heat balance, analysis of component operating data, and evaluation of data as the basis for improving plant efficiency. .

Licensee Response I

! A continuing heat rate performance monitoring and optimization process will be established. Design heat balance data will be determined and or derived, whichever is most cost effective. Analyses and inspections will be performed to determine problems and develop corrective action. This process will be established by September 1988.

HRC Actions This issue is of economic interest to the licensee, but has no safety significance. The NRC has no requirements regarding thermal performance monitoring. Therefore, no inspection effort was devoted to this matter.

d. INP0 Finding Appropriate reviews and analyses have not been conducted to identify the cause of some recurring check valve failures or to preclude the failure of check valves that industry experience indicates are likely to have problems. Although the. plant response to recommendation 2 of SOER 86-3, "Check Valve Failure or Degradation," stated that a design review of check valves with recurring degradation would be performed on an as required basis, no indication of any such reviews could be identified.

INP0 Reconnendation -..

Perform appropriate reviews and implement corrective actions to preclude failure of check valves in systems important to plant safety and reliability. This review should take into account those systems identified in SOER 86-3 and should also include other systems based on failure experience at the plant. EPRI Report NP-5479 Application Guidelines for Check Valves in Nuclear Power Plants, could be of assistance in this effort.

Licensee Response A design verification of check valves in systems important to plant safety wil1 be conducted. Specific valves.to be reviewed will be identified by one or more of the following:

a. recurring failure of check valves at Plant Hatch with an identifiable root cause for the failures

b. check valves in those systems as identified in SOER 86-3 The design verification program will be completed by December 1989.

NRC Actions The OPA team reviewedThe this matter team aswith agreed discussed in Section that the INP0 assessment 2.f of Inspection Report 88-15.

the licensee had been tardy in responding to the INPO SOER.

Long-term followup of the licensee's design verification program will be performed by the resident inspectors.

5. TRAINING AND QUALIFICATION

a. INPO Finding The General Employee Training (GET) program does not develop and maintain some practical skills necessary to effectively implement radiological protection practices. Radiological protection practices noted during The content plant observations contributed to personnel contamination.of the 1

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INPO Recommendation Revise the General Employee Training (GET) program to correct problems such as those noted above. INP0 87-004, Guidelines for General Employee 1

l Training, and INP0 Good Practice,85-018,~ Conduct of Practical Exercises During General Employee Training, should be of assistance in this effort.

Licensee Response The General Employee Training'(GET) program will be upgraded to develop and maintain knowledge and practical skills necessary to effectively _.

implement radiological protection and industrial safety practice. The upgrading will include demonstrations and/or practical exercises of contamination control, radioactive waste control, and exposure control.

Performance standards will be provided for practical exercise checklists to ensure consistent evaluation of personnel. Topics such as those noted above will be included in the program. This will be implemented in training by June 1988.

NRC Actions This issue was addressed during the NRC inspections and is discussed in Section 2 of Inspection Report 88-16. The licensee has initiated changes to improve the practical aspects of health physics training for facility personnel, including development of a videotape covering personnel dressout requirements and techniques for transferring materials between contaminated and non-contaminated areas at the plant. The use of detailed mockups to train personnel regarding radiological hazards and good practices associated with selected jobs was under consideration.

Specific criteria had been developed and were being used to evaluate each step of the GET dressout exercise. No violations or deviations were identified,

b. INPO Finding The shift technical advisor (STA) training and qualification program does not effectively develop and maintain certain job-related knowledge and skills. Licensed STAS are only evaluated in their license roles and are not periodically evaluated in their STA role. Additionally, about forty percent of the simulator exercise guides for abnormal and emergency conditions used in STA training do not contain learning objectives specific to STA duties and responsibilities.

INPO Recommendation Revise training material to contain learning objectives that support knowleoge and skill requirements as identified by operations, procedures, and job responsibilities. Evaluate licensed STAS in their STA role during simulator training exercises.

Licensee Response Training material for STAS will be revised to include learning objectives that support STA knowledge and ski.ll requirements. Whether licensed or not, STAS will be periodically evaluated as STAS in simulator exercises. Thir will be implemented by September 1988.

NRC Actions ,

The OPA team inspected the STA training program. Results are reported in Section 2.g of Inspection Report 88-15. The inspector found that a -

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program was underway to revise the simulator training guides to include STA learning objectives. The instruction on simulator documentation requirements hed been revised to require that each licensed STA be evaluated in both the SR0 2nd the STA position. No violations or deviations were identifieo.

Long-term followup of corrective actions regarding STA training will be performed by the resident inspection program.

6. RADIOLOGICAL PROTECTION INPO Finding The radiological protection program requirements need strengthening in the areas of personnel contamination reporting, response checking of contamination monitoring equipment, and extremity exposure monitoring.

INP0 Recommendation Continue to improve the radiological protection program by implementing the following actions:

a. Document and trend all personnel contaminations greater than 100 counts per minute that are not attributable to noble gas contamination,

b. Scurce check RM-14 friskers daily when in use. Source check PCM-1s and tool monitor daily until sufficient data is available to justify a different testing frequency,

c. Perform a study that compares the wrist TLD to a finger TLD on the same jobs until sufficient data is available to render a sound decision on this method of extremity monitoring.

Licensee Response The following upgrades will be included in the radiological protection program,

a. Personnel contamination greater than 100 cpm's, as detected by a hand held frisker, not attributed to noble gas will be documented and trended.

b. Source checks of RM-14 friskers (when in use) PCM-1s and tool monitors will be performed dail/ until less frequent checks can be justified by trending.

c. Both finger rings and wrist dosimetry will be used on the same jobs to collect sufficient data to support use of wrist dosimetry only. (Until such justification is available, finger

rings will be used for extremity monitoring of . hands and forearms.)

These actions will be implemented by May 1988. _

HRC Actions NRC inspection of these issues is documented in Sections 3 and 4 of Inspection Report 88-16. A directive now requires documentation of all centamination events exceeding 100 cpm / probe area. Source checks of RM-14 friskers, PCH-1s, and tool monitors are conducted daily. The licensee reinitiated use of finner ring TL0s in April 1988 and has undertaken a comparative study of extrenity exposures as measured by finger rings in comparison to wrist-mounted TLDs. No violations or deviations were identified.

Long-term followup to verify the adecuacy of corrective action will be i

conducted by specialists and resident inspectors.

7. CHEMISTRY

a. INPO Finding Increased management attention is needed to correct identified chemistry problems in a timely manner.

INPO Recommendation increase nanagement attention to correct longstanding problems.

l Licensee Response l

All observed significant chemistry problems will be clearly identified and tracked through steps involving analyses of the problems, development of corrective actions, implementation of currective actions and monitoring for effectiveness of corrective actions. Management including the Executive Vice President will be included in the problem management This problem process to ensure adequate and timely attention and energy.

management process for chemistry reinted problems will be initiated by July 1988.

c NRC Actions NRC inspection activities related to this INP0 finding are reported in Section 5 of Inspection Report 88-13 and in Section 14 of Inspection Report 68-14. The out-of-service chlorine gas monitor icentified by IhPO has been repaired and returned to service. The licensee plans to discontinue using chlorine gas in favor of using sodium hypochlorite, The inspector did not identify which is less toxic and easier to handle.

any violations or deviations during the inspection. He verified that the Technical Specifications pertinent to chemistry control had been met.

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b.- INPO Finding Chemistry control in the reactor building chilled water system and in the reactor and recombiner closed cooling water systems is not effective, as indicated by the chemistry parameters being frequently outside specified limits. Lack of prompt action to correct problems has resulted in In addition, increased corrosion rates, radwaste, and chemical usage.

the plant is not assessing the corrosion rates in closed cooling water systems.

INPO Recommendation Upgrade the closed cooling water chemistry control to minimize corrosion in these systems. Identify and correct leakage and equipment problems in these systems in a timely manner. Establish a program to assess the Evaluate the need for copper effectiveness of corrosion control.

inhibitor and biocides in these systems.

Licensee Response The following actions will be implemented to correct the problems noted above:

a. The leakage and equipment problems in the reactor plant closed cooling water systems will be resolved as scon as practical and corrosion control chemistry will be restored. This is expected to be achieved by July 1988.

b. A method will be developed and implemented to assess the effectiveness of the corrosion controls presently in use by September 1988.

c. The need and availability of additional or other inhibitors such as biocides and a copper inhibitors will be assessed by November 1988.

NRC Actions This matter was examined during the NRC inspection .and is reported in Section 14 of Inspection Report 88-14 and Section 5 of Inspection Report 88-13. The inspector confirmed the problems that had been identified by

l INP0. The licensee hao chosen to tolerate the potential corrosion problems rather than to add corrosior inhibitor and face the certain difficulty of disposing of an increa!,ed volume of liquid containing tne. inhibitor. The inspector concluded that the licensee had a good understanding of corrosion mechanisms and industry approaches to corrosion prevention. No violations or deviations were identified.

c. INPO Finding Some station chemistry practices detract from the protection of personnel and equipnent. Problems noted are as follows: _

(1) The chlorination building chlorine gas monitor has been inoperable for the past five months. As a result, a potential chlorine gas leak can go undetected locally or by the control room.

(2) Sample hoods in the laboratories, reactor sample stations, feedwater and condensate sample stations, and radioactive waste sanple stations do not tave air flow indication. In addition, none of the power lights that indicate the operation of the fan blower for the hoods are functional. Safe practice is to

- -provide indication that adequate hood ventilation exists.

(3) Explosion-proof light covers located in the chemical storage building and several sample hoods are not in place. These covers reduce the hazards of explosions or electric shock.

(4) The desiccant in the bulk acid storage tank vent is expended.

Expended desiccant allows meisture to enter the storage tank and cause accelerated corrosion. A routine inspection of desiccant has not been scheduled.

INPO Recommendation Strengthen the chemistry safety program by correcting the problems noted above and take appropriate action to prevent recurrence.

Licensee Response The Chlorination Building chlorinc gas monitor has been repaired.

Additionally, the chemistry safety program will be strengthened by correcting the other identifiec problenis and taking appropriate management action to prevent recurrence. This will be completed by August 1988.

NRC Actions The NRC inspection activities included an examination of these issues identified by thP0. Results are reported in Section 14 of Inspection Report 88-14. The chlorine gas monitor has been replaced, and the licensee is considering the use of sodium hypochlorite rather than

chlorine gas. The licensee was acquiring flow meters for the fume hoods and a shield had been installed around the light in a fume hood. The inspector identified no violations or deviations.

The resident and specialist inspectors will provide long-term followup of corrective actions to verify their adequacy,

d. INPO Finding The plant lay-up program needs to be expanded to include several essential elements such as dry lay-up methods, implementing procedures, _

and program assessment.

INP0 Recomendation Implement a comprehensive lay-up program that includes the items noted.

EPRI document NP-5106, The Plant Layup and Equipment Preservation Sourcebook, may provide useful guidance.

Licensye Response Actions to expand the plant lay-up program will be implemented as follow:

a. A lay-up program will be established using techniques presently known at Plant Hatch with oresent equipment configuration as practical under normal refueling outage conditions. This will be established by August 1988.

b. Georgia Power Company will work with other industry organi:ations including EPRI to identify and plan for other lay-up techniques that are considered cost effective. This effort is expected to be completed by September 1989 as judged by other industry progran history.

NRC Actions ,

NRC inspection effort related to this finding is discussed in Section 14 of Inspection Report 88-14. The licensee had been in contact with the BWR Owners Group and other licensees and was in the process of developing procedures necessary for plant lay-up. No violations or deviations were noted. Corrective actions will be followed by the resident and specialist inspectors.

8. OPERATING EXPERIENCE REVIEW

a. INPO Finding The plant has experienced recurring problems that may have been prevented through more thorough event invest'igation and in-depth root cause analysis.

INPO Recommendat L Upgrade the event investigation process to include a standardized approach to the analysis of each event. Set clear standards and expectations for the conduct of event investigations. Train personnel involved in the investigation process on the various methods of root-cause determination available in the industry. Conduct event investigations in a manner that will ensure all pertinent facts are collected and analyzed.

Licensee Response

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The significant event investigative process will be upgraded to use a prove., standardized investigative approach and to determine the root causes and contributing causal factors of each event. Personnel will be trained to use the standardized process effectively. This will be in place by December 1988.

NRC Actions The OPA team inspected the licensee's program for conduct of root cause '

analyses of significant events. Results are reported in Section 3.j of Inspection Report 88-15. Root cause determinations are performed by an Even't ReviBw Team (ERT) in accordance with an administrative guideline which requires a formal report to plant management. Corrective actions are recommended and tracked. However, the inspector noted a weakness in that no formal review of corrective actions is made for adequacy and timeliness, nor is a formal closecut report made to plant management, the ERT leader, or the Plant Review Board. Lo g-term followup of improvements to the event review program will be handled as part of the resident inspection program.

b. INPO Finding The plant has experienced events for which industry precursors existed.

I INP0 Recomendation Prioritize, Review operating experience corrective actiuti backlog.

schedule, and implement timely corrective action.

Licensee Response The operating experience corrective action backlog will be reviewed in order to prioritize and schedule the implementation of outstanding corrective actions. The prioritization will be completed by July 1988.

Increased management attention will be given to scheduling and implementing corrective actions in a timely manner.

1 IIRC Actions The INP0 findings were directed at the licensee's response to IllPO-generated SOERs. The t1RC inspectors chose not to coment on these matters, but did examine the licensee's handling of operating experience information which came frc.3 the NRC. Results of the inspection are discussed in Section 5.h of Inspection Report 88-15.

The inspector concluded that the licensee's program was functioning in accordance with plant procedures and that it met the intent of the requirements regarding feedback of operating experience. The program -

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ensured that pertinent information was transmitted to affected departments while it concurrently screened out extraneous or repetitive information. No violations or deviations were identified. No followup to this issue is contemplated.

SUtVtARY The various NRC inspection efforts included examination of all of the areas of the INPO findings except for those several areas for which the NRC has no requirements because of lack of relevance to reactor safety (e.g., system heat balances and industrial safety). While some deficiencies were noted as discussed in the inspection reports, in no case did the HRC inspectors encounter situations or problems which cast any significant doubt on the ability of the Hatch units to be operated safety.

The most significant safety-related NRC finding concerns the Emergency Operating Procedures, which were excessively detailed and difficult to use, had human factors deficiencies, and contained plant-specific differences from the Emergency Procedures Guidelines that have been inadequately justified. However, the NRC inspectors also concluded that the procedures could be used to safely shut down the plant and that the operators knew how to use the procedures.

Thus, while the licensee takes action to correct deficiencies in the E0Ps, the plant still may be operated safely.

The NRC inspection activities included a review of the corrective actient taken or planned by the licensee in respense to the INP0 findings, but went consicerably beyond the areas evaluated by INP0, as documented in the inspection reports (primarily Inspection Report 88-15), in no case did the inspection efforts reveal any matters which would cast doubt on the licensee's ability to safely operate the plant.

CONCLUSION The NRC staff concludes that the results of the inspections support continued, safe, plant operations and that no problems were encountered during the inspections that posed an impediment to restart of the Hatch units on a schedule agreeable to the licensee following the licensee's self-imposed shutdown to take corrective actions following the It4PO evaluation. The findings and views of the OPA inspection team members were communicated on a daily basis to Region 11 and fiRR management and formed the basis for the NRC decision to not interpose objections to restart of the Hatch units.

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APPENDIX A

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A May 16, 1988 Docket Nos. 509-321 and 50-366 License Nos. OPR-57 and NPF-5 Georgia Power Company ATTN: -Mr. R. P. Mcdonald Executive Senior Vice President-Nuclear Operations P. O. Box 4545 Atlanta, GA 30302 _

Gentlemen:

SUBJECT:

NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-321/88-11 AND 50-366/88-11)

This refers to the Nuclear Regulatory Comission (NRC) inspection conducted by Messrs. P. Holmes-Ray, J. Menning, and R. Musser on March 26 - April 22, 1988.

The inspection included a review of activities authorized for your Hatch facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed Inspection Report.

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Areas ex'amined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

The inspection findings indicate that certain activities appeared to violate NRC requirements. Violation 321,366/88-11-01, references to pertinent require-ments, and elements to be included in your response are presented in the enclosed Notice of Violation. Additionally, because all of the criteria for categorization of licensee-identified violations were met with regard to item 366/88-07-02, a second violation is not being cited. The details pertaining to this licensee-identified violation are described in the enclosed Inspection Report.

In accordance with Section 2.790 of the NRC's "Rules of Practice," Part 2 Title 10, Code of Federal Regulations, a copy of this letter and its enclosures will be placed in the NRC Public Document Room.

The responses directed by this letter and its enclosures are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No.96-511.

G& \

88 w m sea m ADOCK 05000321 9 u PCR Q DCD

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Georgia Power Company 2 May 16, 1988 Should you have any questions concerning this letter, please contact us.

Sincerely, Original Signed by Virgil L. Brownlee Virgil L. Brownlee, Chief Reactor Projects Branch 3 Division of Reactor Projects _

Enclosures:

1. Notice of Violation

2. NRC Inspection Report cc w/encis:

J. T. Beckham, Vice President, Plant Hatch H. C. Nix, Plant Manager

0. M. Fraser, Site QA Manager .

L. Gucwa, Manager, Nuclear Safety and Licensing

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bec w/encls:

NRC Resident Inspector DRS, Technical Assistant Hugh S. Jordan, Executive Secretary Document Control Desk

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MSilkule

/88 05/))/88

O ENCLOSURE 1 NOTICE OF VIOLATION Georgia Power Company Docket Nos. 50-321 and 50-366 Hatch Units 1 and 2 License Nos. DPR-57 and NPF-5 During the Nuclear Regulatory Comrei ssion (NRC) inspection conducted on March 26 - April 22,1988, a violation of NRC requirements was identified.

In accordance with the "General Statement of Policy and Procedure for NRC ~

Enforcement Actions," 10 CFR Part 2, Appendix C (1987), the violation is listed below:

Criterion 57 of Appendix A of 10 CFR Part 50 requires that each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere have at least one containment isolation valve which shall be either automatic, or locked closed, or capable of remote operation.

Contrary to the above, prior to February 1988, torus to drywell vacuum breaker test solenoid valves (T48-F342A-L) were incapable of holding pr'ssure' e during required local leak rate testing due to design deficiencies. Therefore, these valves were incapable of performing a containment isolation function as r'equired by Criterion 57 for a closed system.

This is a Severity Level IV violation (Supplement 1).

Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby required to submit a written statement or explanation to the Nuclear Regulatory Commission, ATTN: Document Control Oesk, Washington, D.C. 20555, with a copy to the NRC Resident Inspector, Hatch Nuclear Plant, within 30 days of the date of the lletter.'s transmitting this Notice. This ' reply should be clearly marked as a "Reply to a Notice of Violation" and should include: (1) admission or denial of the violation, (2) the reasons for the violation if admitted, (3) the corrective steps which have been taken and the results achieved. (4) corrective steps which will be taken to avoid further violations, and (5) the date when full pepliance will be achieved. Where good cause is shown, consideration Y

OOOEO7AOU M OS1A PUR ADOCK 05000321 Q DCD

~ a Georgia Power Company 2 Docket Nos. 50-321 and 50-366 Hatch Units 1 and 2 License Nos. DPR-57 and.NPF-5 will be given to extending the response time. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken.

FOR THE NUCLEAR REGULATORY COMMISSION M.1 '\ __

Virgil (L.Brownlee, Chief ~

Reactor Projects Branch 3 Division of Reactor Projects Dated at Atlanta, Georyia this /g day of May 1988 e e l > ~. . . .: '

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UNITED STATES l

- /,,ps

• eth 'o, NUCLEAR REGULATORY COMMISSION

.'# $ REGION 11 TLAN GEORGI A b32 l

..... May 16, 1988 l l

l Report Numbers: 50-321/88-11 and 50-366/88-11 Licensee: Georgia Power Company P. O. Box 4545 Atlanta, GA 30302 Docket Numbers: 50-321 and 50-366

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License Numbers: OPR-57 and NPF-5 -

Facility Name: Hatch 1 and 2 Inspection Dates: March 26 - April 22, 1988 Inspection at Hatch tg near_Baxle , Georgia inspector :

ePeter-tttrl 21 C4 Wh Ra M esident Inspector Ibh8 Date Signed

/

}fJohn E. Menning,

.. h9Resident be Inspector W// l 8 ?

Da te/ Signed Accompanying Personnel: Randall A. Musser Approved by: e M.

Marvin V. 'Sinkule, Chief, Project Section 38

'3 Date Sisned (k

Division of Reactor Projects

SUMMARY

Scope: This routine inspection was conducted at the site in the areas o' Licensee Action on Previous Enforcement Matters, Operational Safety Verification, Maintenance Observations, Plant Modification, Surveillance Testing Observations, ESF System Walkdown, Radiological Protection, Physical Security, Reportable Occurrences, and Operating Reactor Events.

Results: One violation was identified involving improper design of torus to drywell vacuum breaker test solenoid valves.

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REPORT DETAILS

1. Persons Contacted Licensee Employees T. Beckham, Vice Pr dent - Plant Hatch C. Coggin, Training and Emergency Preparedr:ess Manager

• 0. Davis, Manager General Support _

J. Fitzsimons, Nuclear Security Manager -

• P. Fornel, Maintenance Manager

• 0. Fraser, Site Quality Assurance (QA) Manager

• M. Googe, Outages and Planning Manager

• H. Nix, Plant Manager

• T. Powers, Engineering Manager

• 0. Read, Plant Support Manager H. Sumner, Operations Manager

• S. Tipps, Nuclear Safety and Compliance Manager R. Zavadoski, Health Physics and Chemistry Manager Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personnel.

NRC Resident Inspectors

! P. Holmes-Ray l *J. Menning

• R. Musser NRC management personnel on site during inspection period:

L. Crocker, Projcet Directorate II3, NRR/ORP L. Reyes, Director, Division of Reactor Projects, Region II M. Sinkule, Chief, Project Section 38, Region II l

• Attended exit interview

2. ExitInterview(30703)

The inspection scope and findings were sumarized on April 25, 1988, with those persons indicated in paragraph 1 above. The inspectors described l

the areas inspected and discussed in detail the inspection findings listed i below. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection. The licensee acknowledged the findings and took no exception.

Item Number Status Description / Reference Paragraph 321,366/88-11-01 Opened VIOLATION - Design of Test Solenoid Valves (paragraph 5).

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(cor.t ' d)

-Item Number Status Description / Reference paragraph 366/88-07-01 Closeo UNRESOLVED ITEM * (URI) - Design and Installation of Vacuum Breaker Air Test Lines (paragraphs 3.a and 5) 366/88-07-02' Closed URI - Post Maintenance Leak Rate i Testing (paragraphs 3.b, 5, and _

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321,366/88-05-02 Closed URI - Leak Testing of Test Solenoid Valves (paragraphs 3.c and 5)

3. Licensee Action on Previous Enforcement Matters (92702)

a. (Closed) URI 366/88-07-01, Design and Installation of Vacuum Breaker Air Test Lines

. This.URI was opened following the licensee's discovery that portions of the Unit 2 torus to drywell vacuum breaker air test lines had not

. been designed and installed as described in the Final Safety Analysis Report (FSAR). As discussed in paragraph 5, this matter was determined to be a licensee-identifed deviatien, and the deviation was not cited.

b. (Closed) URI 366/88-07-02. Post Maintenance Leak Rate Testing This URI was opened to track two instances in which primary containment penetrations had not been local leak rate tested following maintenance. As discussed in paragraph 5, this matter was determined to be a licensee-identified violation after further review. The violation was not cited because the requirements specified in 10 CFR Part 2, Appendix C, Section V, were satisfied.

c. (Closed)URI 321,366/88-05-02, Leak Testing of Test Solenoid Valves This URI was opened following the licensee's discovery that torus to drywell vacuum breaker test solenoid valves T48-F342A-L would not hold pressure during local leak rate testing when pressurized on the accident side. As discussed in paragraph 5, this matter has been determined to be a violation of technical specification requirements and will now be tracked as violation 321,366/88-11-01.

• An unresolved item is a matter about which more information is required to determine whether it is acceptable or may involve a violation or deviation.

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4. Unresolved Items No URI's were identified during this reporting period.

5. Operational Safety Verification (71707) Units 1 and 2 The inspectors kept themselves informed on a daily basis of the overall plant status and any significant safety matters related to plant operations. Daily discussions were held with plant management and various members of the plant operating staff. The inspectors made frequent visits. _

to the control room. Observations included instrument readings, setpoints -

and recordings, status of operating systems, tags and clearances on

. equipment, controls and switches, annunciator alarms, adherence to limiting conditions for operation, temporary alterations in effect, daily journals and data sheet entries, control room manning, and access controls. This inspection activity included numerous informal discussions with operators and their supervisors. Weekly, when on site, selected Engineering Safety Feature (ESF) systems were confinned operable. The confinnation was made by verifying the following: accessible valve flow path alignment, power supply breaker and fuse status, instrumentation, major component leakage, lubrication, cooling, and general condition.

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General plant tours were conducted on at least a weekly basis. Portions of the control building, turbine building, reactor building, and outside areas were visited. Observations included general plant / equipment conditions, safety related tagout verifications, shift turnover, sampling program, housekeeping and general plant cor.ditions, fire protection equipment, control of activities in progress, radiation protection controls, physical security, problem identification systems, missile hazards, instrumentation and alarms in the control room, and containment isolation.

On April 4,1988, the licensee predicted. that continued operation of Unit 1 would cause the drywell floor drain leakage to exceed the rate of 5 gpm specified in the Unit 1 Technical Specifications. Therefore, at 2204 on April 4,1988, the licensee comenced a controlled reactor shutdown.

At 0908 on April 5, 1988, the main generator was removed from the line and at 1103 the reactor was manually scrammed. During this outage, the licensee repaired leaking valves in the drywell, replaced the "F" and "X"

. Safety / Relief Valves (SRV), and visually inspected certain areas inside

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the torus. As discussed in NRC Inspection Report Nos. 50-321/87-26 and 50-366/87-26, unusual sounds were noted coming from the Unit' 1 torus in the vicinity of the "K" SRV discharge line and T quencher on September 26, 1987. Because the sounds stopped when torus spray was operating, the Residual Heat Removal (RHR) system was operated continuously in the torus spray mode subsequent to that . time. The team investigating these sounds recommended inspections of the "K" SRV discharge line vacuum breaker, discharge line, and neighboring torus internals during the next Unit 1 shutdown of sufficient duration. These recommended inspections were conducted during the shutdown that commenced on April 4, 1988. An NRC inspector accompanied licensee personnel on the torus inspections. No ~

damage was observed. The replacement of the "K" SRV obviated the need for continued operation of RHR in the torus spray mode. Criticality was again achieved in Unit I at 0705 on April 11, 1988. Rated power was achieved on April 15, 1988.

On April 15, 1988, the licensee experienced difficulties returning the Unit 2 "A" hydrogen recombiner system to operable status prior to the expiration of a~ 30-day limiting condition for operation (LCO). Repair work on this system had required cutting and rewelding of a line. The licensee realized that required radiographic examination of the weld and system pressure and functional testing could not be completed prior to 1500, wheh a 30-day LCO associated with Technical Specification 3.6.6.2.a was due to expire. Discretionary enforcement action was requested from Region II to provide additional time to complete these required activities. Region II subsequently granted an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for return of the system to operable status. The required examination and testing were satisfactorily completed and the "A" hydrogen recombiner system was declared operable at 0135 on April 17, 1338.

As discussed in NRC Inspection Report Nos. 50-321/88-05 and 50-366/88-05, VRI 321,366/88-05-02 was opened following the licensee's discovery that torus to drywell vacuum breaker test solenoid valves T48-F342A-L would not hold pressure during local leak rate tests (LLRT) when pressurized on the accident side. - Testing prior to February 1988 had been performed with pressure applied on the side of the F342 valves away from accident pressure. These test solenoid valves are considered outboard containment isolation valves. Investigation by the licensee revealed that the valves in Unit I would remain closed up to an accident side pressure of 35 psig.

The valves in Unit 2 had weaker springs and would open at a lower level of accident side pressure. Since the licensee is required to LLRT these valves at 59 and 57.5 psig for Units 1 and 2, respectively, the design of the valves was inadequate. Criterion 57 of Appendix A of 10 CFR Part 50 requires that each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere shall have at least one containment isolation valve which shall be either automatic, or locked closed, or capable of remote operation. The. inadequate design of valves T48-F342A-L is a violation of this requirement in that the valves were incapable of performing a containment isolation function as demonstrated by required LLRT. Accordingly, URI 321,366/88-05-02 is closed, and this matter will now be tracked as violation 321,366/88-11-01, Design of Test Solenoid Valves.

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5 As discussed in NRC Inspection Report Nos. 50-321/88-07 and 50-366-88-07, URI 366/88-07-02 was opened to track two instances ~ in which primary containment penetrations had not been LLRTd following maintenance. More specifically, High Pressure Coolant Injection system turbine exhaust line penetration number 214 and electrical penetration 2T52-X105C had not been LLRTd following maintenance during the recent Unit 2 outage. Subsequent LLRTs on these penetrations yielded acceptable results. In responding to these discrepancies, the licensee entered appropriate LCOs and made required reports to the NRC. The licensee also reviewed 400 Maintenance Work Orders (MWO) that had been worked during the Unit 2 outage and affected primary containment penetrations. No additional LLRT ._.

discrepancies were identified in this review. Investigation has shown that both discrepancies were caused by weaknesses in the administrative control system that enforces review of LLRT components and ensures that all LLRTs are performed.

In the case of penetration 214, a MWO (No. 2-87-4342) was processed through the administrative system without ceing identified as involving LLRT requirements. The MWO was erroneously not marked with a stamp indicating . "Contact LLRT Coordinator before starting any maintenance /

adjustment work and agair., if required, af ter work before signing off clearance." In the case of electrical penetration 2T52-X1050, the LLRT requ'irement was identified on the MWO (No. 2-88-743), but LLRT personnel were not infonned to perform the required testing. The licensee has taken the following steps to ensure that all maintenance-related LLRTs are performed as required in the future:

• The Nuclear Plant Management Information System (NPMIS) computer data l base has been updated to include Unit 2 LLRT components that have Master Parts List (MPL) numbers. This data base is used in the preparation of MW0s.

• By letter dated March 28, 1988, the licensee established additional administrative controls to ensure that LLRT requirements are properly addressed on MW0s. An MWO review sheet will be added to MW0s to ensure compliance and proper documentation.

The NPMIS data base for Unit 1 has been checked to ensure that it identifies all LLRT components that have MPL numbers.

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• The stamp specifying, "Contact LLRT Coordinator before starting any maintenance / adjustment work and again, if required, after work before signing off clearance" was modified to delete the "if required."

l The following additional steps are planned to prevent similar LLRT discrepancies:

• A new procedure wil.1 be issued to provide separate checks for LLRT applicability on initial review of MW0s, and for a method for

updating the NPMIS system LLRT component list.

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• Maintenance procedure 50AC-MNT001-05, "Maintenance Program," will be revised to improve the LLRT component review form and strengthen the requirements to contact the LLRT coordinator before and after maintenance.

• Methods to enter LLRT components without MPL numbers into the NPMIS data base will be investigated.

7achnical Specification 3.6.1.2.b specifies a maximum combined leakage rate for penetrations and valves subject to Type B and C tests. The specified leakage rate cannot be exceeded for primary containment 1 integrity to exist. The failure to conduct post maintenance LLRTs on penetration number 214 and electrical penetration 2T52-X105C appears to be a violation of Technical Specification 3.6.1.2.b in that the licensee did not have test data available to demonstrate compliance with the leakage requirement. However, since all the requirements specified in 10 CFR Part 2, Appendix C, Section V, were satisfied, this licensee-identified violation is not being cited. Additionally, URI 366/88-07-02 is closed.

As discussed in NRC Inspection Report Nos. 50-321/88-07 and 50-366/88-07, URI 366/88-07-01 was opened following the licensee's discovery that Unit 2 tor,us to drywell vacuum breaker air test lines had not been designed and installed as described in the FSAR. The air test lines in question are the individual, stainless steel lines between test solenoid valves 2T48-F342A-L and the air operators for vacuum breakers 2T48-F323A-L. Note 18 of Taole 6.2-5 in the Unit 2 FSAR describes these lines as being Seismic Category 1 and Class 2 per Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. The licensee discovered that these lines had in actuality been designed and installed to comply with American National Standards Institute (ANSI) 831.1, "Standard Code for Pressure Piping, Power Piping." These lines were '

subsequently modified to be Seismic Category 1. The licensee also proposed to the NRC that the subject lines be treated as ANSI B31.1 upgraded to Class 2 for ASME Section III, with Section XI inspection and testing requirements. The licensee's proposal was subsequently approved by the NRC. Failure to design and install the air test lines as described in the FSAR represents a deviation from a licensee comitment. However, in consideration of the safety significance of this matter, the timely reporting and corrective actions taken by the licensee, and the apparent uniqueness of this matter, this licensee-identified deviation is not being l cited. Therefore, URI 366/88-07-01 is closed.

l The licensee announced on April 19, 1988, that Units i and 2 would be l voluntarily shutdown for a 30-day period in order to ovaluate and correct problems identified as a result of a recent Instituta of Nuclear Power Operations (INP0) evaluation. Prior to this announcement, Unit 1 was operating at 100 percent power and Unit 2 was in hat shutdown and preparing to startup afte.r recovering from a reactor 3 cram on April 17, 1988. Unit 1 subsequently scramed at 0902 on April 19, 1988, following a 1

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turbine trip. This reactor scram is discussed in paragraph 13. Unit 2

. achieved cold shutdown at 2240 on April 19, 1988. Unit 1 reached cold  :

shutdown at 1818 on April 20, 1988. 4 One violation was identified.

6. Maintenance Observations (62703) Units 1 and 2 During the report period, the inspectors observed selected maintenance activicies. The observations included a review of the work documents for -

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adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, observation of all or part of the actual work and/or retesting in progress, specified retest requirements, and adherence to the appropriate quality controls. The primary maintenance observations during this month are sumarized below:

Maintenance Activitiy Date

a. Repair of Reactor Core Isolation Cooling 03/31/88 (RCIC) system valve 1E51-F045 per MWO 1-88-1310 (Unit 1)

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b. Appendix R equipment sealing in Unit 2 RCIC 04/13/88 corner room per MWC 2-88-1780 and Design Change Request.86-223-E002 (Unit 2)

c. Trouble shooting on "A" Hydrogen Recombiner 04/14/88 system per MWO 2-88-2027 (Unit 2)

No violations or deviations were identified.

7. Plant Modification (37700) Units 1 and 2 The Design Change Requests (DCR) listed below were reviewed to determine whether the provisions of 10 CFR 50.59 applied or whether changes to the technical specifications or unreviewed safety questions were involved: '

OCR No.

I 80-101 83-243 86-192 Rev. 1 86-208 86-283 Rev. 1 86-284 87-078 87-099 87-100 The safety evaluations for each of the above OCRs were found to adequately address the questions of:

Does the design change increase the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety, as previously evaluated in the updated FSAR?

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• Does the design . change create a possibility for an accident or malfunction of a different type than any evaluated previously in the updated FSAR?

Does the design change reduce the margin of safety as defined in the basis for any technical specification?

It was noted that DCRs86-192 Rev. 1,86-283 Rev. 1, and 86-284 required changes to the technical specification. The licensee requested such changes in accordance with 10 CFR 50.90, and license amendments were _

issued by the NRC. It was also noted that all of the OCRs had been -

reviewed by the Plant Review Board. Each DCR had also been reviewed for impact on the fire protection plan and had received a QA review. The DCRs included reference lists of procedures governing the work to be performed as well as procedures to be used for acceptance testing. Acceptance values or performance requirements were included. Where appropriate, the DCRs included drawings or sketches of the work to be performed. Each of these DCRs was included in a listing of completed DCRs submitted in the licensee's "Annual Operating Report for 1987" on February 29, 1988.

No violations or deviations were identified.

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8. Surveillance Testing Observations (61726) Units 1 and 2 The inspectors observed the performance of selected surveillances. The observation included a review of the procedure for technical adequacy, confonnance to technical specifications, verification of test instrurer.t calibration, observation of all or part of the actual surveillances, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the acceptance criteria. The primary surveillance testing observatiens during this month are sumarized below:

Surveillance Testing Activity Date

a. Core Spray system Pump Operability 03/31/88 testing per procedure 345V-E21-001-25 (Unit 2)

b. Standby Liquid Control Pump Operability 04/08/88 testing)per (Unit 1 procedure 345V-C41-001-15

c. Diesel Generator 2C Monthly Test 04/19/88 per proceoure 34SV-R43-003-25 (Unit 2)

d. Average Power Range Monitor Instrument 04/21/88 Functional Test and Calibration testing per procedure 345V-C51-002-15 (Unit 1)

No violations or deviations were identified.

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9. ESF System Walkdown (71710) Unit 1 The inspectors routinely conducted partial walkdowns of ESF systems.

Valve and breaker / switch lineups and equipment conditions were randomly verified both locally and ir, the control room to ensure that lineups were in accordance with operability requirements and that equipment material conditions were satisfactory. Accessible portions of the Plant Service Water system in the Unit i reactor building were walked down in detail.

Within the areas inspected, no violations or deviations were identified. _

10. Radiological Protection (71709) Units 1 and 2 The resident inspectors reviewed aspects of the licensee's radiological protection program in the course of the monthly activities. The perfomance of health physics and other personnel was observed on various shifts to include: involvement of health physics supervision, use of radiation work permits, use of personnel monitoring equipment, control of high radiation areas, use of friskers and personal contamination monitors, and posting and labeling.

No yiolati,,ons or deviations were noted.

11. Physical Security (71881) Units 1 and 2 In the course of the monthly activities, the resident inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was obsermd in the conduct of daily activities to include: availability of supervision, availability of armed response personnel, protected and vital access controls, searching of personnel, packages and vehicles, badge issuance and retrieval, escorting of visitors, patrols, and compensatory posts.

The inspector verified the absence of obstructions in the isolation zone area on each side of the protected area fence that could conceal an unauthorized entry or interfere with the capability of the detection / assessment system. The adequacy of illumination in the protected area was also verified. On April 14, 1988, the inspector visited the central and secondary alarm stations and detemined that 4 surveillance equipment was functioning properly.

No violations or deviations were noted.

12. Reportable Occurrences (90712 & 92700) Units 1 and 2 A number of Licensee Event Reports (LER) were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate. Events which were reported imediately were also reviewed as they occurred to determine that technical specifications

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consideration.

Unit 1: 88-03 Spurious Ground Fault Trips Main Turbine and Generator Resulting in Reactor Scram.

The events of this LER concern the Unit I reactor scram on February 26, 1988. This matter was discussed in NRC Inspection Report Nos. 50-321/88-07 and 50-366/88-07, and this LER is closed. _

Unit 2: 88-06 Procedure Deficiency Causes Scram and One Valve Fails to Close on Group 1 Isolation.

The events of this LER were discussed in NRC Inspection Report Nos. 50-321/88-07 and 50-366/88-07 and resulted in the identification of violation 366/88-07-05. This LER is closed. .

88-09 Personnel Errors Cause Missed Tests Resulting in Condition Prohibited by Technical Specifications.

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The events. of this LER were initially identified as URI 366/88-07-02. As discussed in paragraph 5, this matter is now considered a licensee-identified violation. This LER is closed.

13. Operating Reactor Events (93702) Units 1 and 2 The inspectors reviewed activities acsociated with the below listed reactor events. The review included determination of cause, safety significance, performance of personnel and systems, and corrective action.

The inspectors examined instrument recordings, computer printouts, operations journal entries, and scram reports and had discussions with operations maintenance and engineering support personnel as appropriate.

At 0255 on April 17,1988, Unit 2 automatically scrammed during the performance of procedure 345V-C71-005-25, "Turbine Control Valve Fast-Closure Instrument Functional Test." ihe No. 2 Control Valve had been closed, giving the anticipated trip of Reactor Protection System (RPS) channel A. An apparently spurious trip of RPS channel B then occurred, resulting in the full reactor scram. No annunciator or computer alarms associated with the RPS channel B trip were received. Following'the scram, the reactor feed pumps restored vessel water level which decreased to a low point of approximately minus 20 inches indicated. Both l

recirculation pump motor-generator (MG) set scoop tubes were locked at the time of the scram due to previous MG set controller problems. Both scoop tubes were unlocked following the scram to allow recirculation pump runbacks to occur. The "A" recirculation pump failed to run back as

11 anticipated. Following verification that run back did not take place, the "A" recirculation pump was manually tripped. Control room personnel also noted that scram discharge volume isolation valve 2C11-F035A did not close on the reactor scram as expected.

Investigation of the cause of the RPS channel B trip involved testing of the nuclear instrumentation associated with the channel, reperforming procriure 345V-C71-005-2S, and testing each channel B input. Since these effor :s did not reveal the source of the trip signal, the licensee decided to monitor all RPS channel B inputs with a recorder to identify the source (s) of any future spurious trips. Investigation into the "A" n recirculation pump runback problem showed that the MG set scoop tube was binding up at the upper and lower ends of its range, requiring mechanical repairs. The improper functioning of valve 2C11-F035A was found to be caused by_ deteriorated packing, requiring change out of the packing. As noted in paragraph 5, Unit 2 restart was delayed in view of the licensee's decision on April 19, 1988, to shut down both Hatch units for a 30-day period.

At 0902 on April 19,1988, Unit 1 automatically scramed due to a turbine trip. The turbine trip, in turn, was caused by a thrust bearing wear detector trip. At the time of the scram Unit I was operating at 100 percent power. Plant personnel were performing a clearance to switch turbine lube oil cooling from cooler "A" to cooler "B" so that maintenance could be perfonned on the "A" cooler. Reactor vessel level decreased to a minimum level of plus 11.5 inches indicated following the scram. The turbine trip caused an instantaneous spike in reactor pressure to 1085 psig, which resulted in 10 of the 11 SRVs opening. Initial review of this event indicates that plant systems functioned properly. It was determined that the turbine trip was caused by an air bubble in the lube oil system which caused low lube oil pressure to be sensed by the thrust bearing wear detector pressure switch. It appears that the air bubble was present in the "B" lube oil cooler and entered the icbe oil system when that cooler was placed in service.. Unit I was brought to cold shutdown following this scram, consistent with the licensee's decision on April 19, 1988, to shut dor both listch units for a 30-day period.

Within the areas inspected, no violations or deviations were. identified.

0 UNITED STATES APPENDIX 8

) g Kf0 94

. NUCLEAR REGULATORY C'OMMISSION

REGION ll

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.g j 101 MARIETTA STREET.N.W.

d -t ATLANTA, GEORGI A 30323 July 6,1988 k+..../

Docket Nos. 50-321, 50-366 License Nos. OPR-57., HPF-5 Georgia Power Company ATTN: Mr. W. G. Hairston, III Senior Vice President -

Nuclear Operations P. O. Box 4545 Atlanta, GA 30302 _..

Gentlemen:

SUBJECT:

EMERGENCY OPERATING PROCEDURE TEAM INSPECTION (NRC INSPECTION REPORT NOS. 50-321/88-12 and 50-366/88-12)

This refers to the Nuclear Regulatory Coninission (NRC) inspection conducted by an NRC team led by Mr. Donald J. Florek on May 2-10, 1988, at Hatch Units 1 and 2. The inspection included a review of Emergency Operating Procedures for your Hatch facility. At the conclusion of the inspection, the findings were discussed with Mr. J. T. Beckham, Jr. and other members of your staff' identifidd in the enclosed Inspection Report.

Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities .in progress.

The inspection findings identified several items that require actions to be taken on the Emergency Operatir,9 Procedures, associated supporting documenta-tion, and training. At the exit, your ' staff indicated that a well cisciplined approach would be taken to correct the findings and that a plan would be developed and provided to the NRC. We also consider that a well disciplined timely approach to resolve the inspection findings is required. Please formally transmit your plans and schedule to Region II within 30 days of receipt of this letter.

Although numerous deficiencies were identified, the Emergency Operating Procedures were found to be adequate for continued operation of the tacility.

While none of the individual deficiencies observed during this inspection and documented in this report are identified as violations or deviations, the large number of them reduces the margin of safety by placing unnecessary demands on the operators. To restore this margin of safety, prompt corrective action is appropriate. As discussed during the exit meeting following the inspection, we understand that Georgia Power Company will review the individual deficiencies noted in this report and take prompt corrective action to resolve them on a QM k

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Georgia Power Company 2 July 6,1988 prioritized schedule. This review and corrective action will specifically address identification and elimination of potential programatic weaknesses.

In addition, we understand that the technical bases for differences between the BWR Owners Gropp Emergency Procedure Guidelines and Emergency Operating Procedures are not documented. Your corrective action should include estab-lishing this documentation. As we have discussed, you will meet with us in Atlanta in the near future to discuss four progress and schedule for completing this action, in accordance with Section 2.790. of the NRC's "Rules of Practice," Pari. 2, Title 10, Code of Federal Regulations, a copy of this letter and its enclosure ~ _.

will be placed in the NRC Public Document Room. .

The responses directed by this letter and the enclosure are not subject to the clearance procedures of the Office of Management and Budget issued under the Paperwork Reduction Act of 1980, Pub. L. No.96-511.

Should you have any quastions concerning this letter, please contact us.

Sincerely,

[J.NelsonGrace

" Regional Administrator

Enclosure:

NRC Inspection Report cc w/ encl:

R. P. Mcdonald, Executive Vice President, Nuclear Operations J. T. Beckham, Vice President, Plant Hatch H. C. Nix, Plant Manager

0. M. Fraser, Site Quality Assurance

( (QA) Supervisor L. Gucwa, Manager, Nuclear Safety l

and Licensing i

l l

0 af00 UNITED STATES jd r!

o,^ NUCLEAR REGULATORY C'OMMISSION REGION 11

' i

• [ 101 MARIETTA STREET, N.W.

ATL ANTA, GEORGI A 30323 t

%, . . ,, . . f U.S. NUCLEAR REGULATORY COMMISSION REGION I Report Nos.: 50-321/88-12 and 50-366/88-12 Licensee: Georgia Power Company P.O. Bcx 4545 Atlanta, GA 30302 _

Docket Nos.: 50-321 and 50-366 ,

License Nos.: DPR-57 and NPF-5 Facility Name: Plant Hatch Inspection Dates: May 2-10, 1988 Inspection At: Hatch site near Baxley, Georgia Team Members: B. Evans, Reactor Engineer, Region IV W. Hansen, Consultant, NRC R. Musser, Resident Inspector, Plant Hatch C. Sisco, Operations Engineer, Region I A. Sutthoff, Human Factors Specialist '

Team Leader.: b D. J. Florek, SrU, Operationti' Engineer

~~

Date Division of Reactor Safety, Region 1 Aporoved by:

R. M. Gallo, Chiefj Operations / Branch

!W ' Date'

~~

Division of Reactd'r Safety, Rdgion 1 Inspection Sumary: Inspection on May 2-10, 1988 (Report No. 50-321/88-12 and 50-366/30-12)

Areas Inspected: Special announced team inspection of the Emergency Operating Procedures (EOPs) to include a comparison of the E0Ps with the BWR Owners Group Emergency Procedure Guidelines and the Plant Specific Technical Guidelines for technical adequacy, reviews of the E0Ps through control room and plant 1 walkdowns, evaluation of the E0Ps on the plant simulator, human factor analysis I of the E0Ps, E0P training, on-going evaluation program for E0Ps, QA measures, I quality of the control room drawings and an evaluation of the containment venting provisions.

Results: See Executive Summary in report.

,W 7 oQ J{J 'Kbqgr '

3b\ c

2 Executive Summary Following the Three Mile Island (TMI) accident, the Office of Nuclear Reactor Regulation developed the "TMl Action Plan" (NUREG-0660 and NUREG-0737) which required licensees of operating reactors to reanalyze transients and accidents and to upgrade emergency operating procedures (E0Ps) (Item I.C.1). The plan also required the NRC staff to develoh a long-term plan that integrated and expanded efforts in the writing, reviewing, and monitoring the plant procedures (Item I.C.9). NUREG-0899, "Guidelines for the Preparation of Emergency Operat-ing Procedures," represents the NRC staff's long-term program for upgrading _

E0Ps, and describes the use of a "Procedures Generation Package" (PGP) to prepare E0Ps. The licensees formed four vendor type owner groups corresponding to the four major reactor types in the United States, Westinghouse, General Electric, Babcock & Wilcox, and Combustion Engineering. Working with the vendor company and the NRC, these owner groups developed Generic Technical Guidelines (GTGs) which are generic procedures that set forth the desired accident mitigation strategy. These GTGs were to be used by the licensee in developing their PGP. Submittal of the PGP was made a requirement by Confirmatory Order dated February 21, 1984. Generic Letter 82-33, "Supplement 1 to NUREG-0737 - Requirements for Emergency Response Capability" requires each licensee to submit to the NRC a PGP which includes:

i. Plant-specific technical guidelines with justification for difforences from the GTG ii. A writer's guide iii. A description of the program to be used for the validation of E0Ps iv. A description of the training program for the upgraded E0Ps.

Frem this PGP, plant specific E0Ps were to have been developed that would provide the operator with directions to mitigate the consequences of a broad range of accidents and multiple equipment failures.

Due to various circumstances, there were long delays in achieving NRC approval of many of the PGPs. Nevertheless, the licensees have impicmented their E0Ps.

To determine the success of the implementation, a series of NRC inspections are being performed to examine the final product of the program, the E0Ps.

On May 2-10, 1988, an NRC team of inspectors consisting of two reactor inspec-tors, a reactor system consultant, an operator licensing examiner / inspector, a human factors specialist, and the resident inspector conducted an irspection of the Emergency Operating Procedures at Hatch Units 1 and 2. Hatch is a BWR-4 with a Mark I containment. The objectives of the team were to determine if:

the E0Ps are technically correct, the E0Ps can be physically carried-out in the plant, and the E0Ps can be performed by the plant staff.

3 The objectives would be considered to be met if review of the following areas were found to be adequate: comparison of the Emergency O (E0P) with the Plant Specific Technical Guidelines and(PSTG)perating the BWR Owners Procedur Group Emergency Pro.cedures Guidelines (EPG), review of the technical adequacy of the deviations from the EPG, control room and plant walkdowns of the E0Ps, re.al time evaluation of E0P usage by running E0P exercise scenarios on the plant simulator, evaluation of the lichnsee program on continuing improvement of the E0Ps and performance of human factor analysis of the E0Ps. The inspec-tion focused on the adequacy of the end product and did not depend on review of the process to develop E0Ps. However, because of the complexity of the Hatch E0Ps a review of the E0P development process was performed. In addition, 1 containment venting provisions were reviewed. Containment venting provisions for all BWRs with Mark I containments are being performed across the country as an NRC inspection initiative.

Due to the complexity of the Hatch flow charts, prior to the site visit the inspection team had difficulty in utilizing the flow charts. Once the facility explained the flow chart, how it is set up and how the flow charts are used, the team could then begin to effectively review the E0Ps as implemented at Plant Hatch.

The inspection findings appear to have a common source namely, the facility considered the PSTG as a guideline whereas the NRC considered the PSTG as the technical basis upon which to develop the Emergency Operating Procedures and upon which their technical adequacy is judged. ,

The facility had developed the PSTG from the vendor guidelines with essentially no deviations. However, the E0Ps developed from the PSTG have many deviations from the PSTG. Documentation was not available to justify the deviations taken from PSTG. Examples of the deviations taken include the values in the proce-dure and logic of the procedures. These are discussed in Section 4 and 5 of the report. The QA organization on site had also identified that differences from the PSTG existed in the E0Ps. The facility responded to the specific QA items, but did not aggressively pursue the root cause for the differences.

The independent technical review recently performed by General Electric also identified differences between the E0Ps and PSTG.

Since the NRC considers the PSTG the technical basis for the E0Ps, the proce-dures that satisfy the PSTG requirements similarly are considered by the NRC to be a necessary part of the Emergency Operating Procedures. At Plant Hatch, the procedures that satisfy the PSTG requirements include selected Alarm Response Procedures (ARP), abnormal operating procedures (A0P), flowcharts, end path i manuals (EPM) and to seme extent the Emergency Plan - Emergency implementing Procedures, in practice the facility only considered the E0Ps to include the flow charts and end path manuals. Development, technical adequacy, administra-tive, training and quality concerns regarding the ARP, A0P portion of the E0Ps ,

were identified (See sections 3, 4, 5, 7, 8, 9, 11, and 12). I

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4 The primary concern identified from the walkdowns was the inconsistency between plant labels and the procedures. The control of jumpers / tools and the indica-tion that local equipment is E0P related was quite good. The procedures were judged to be able' to be physically carried out in the plant. (See Section 6).

NRC review of the development program concluded that, whereas a team approach in the development, validation and vefification was attempted, human factors involvement was not sufficient. Verification activities were essentially conducted by one individual with team involvement only in the differences identified (see Section 3).

The primary human factors concern identified in the Plant Hatch E0Ps is the overall complexity of the flowcharts. This high level of complexity is caused by the interaction of a number of human factors concerns contained in the flowcharts, resulting in procedures that are . difficult to use, understand, and read.

The high level of flow chart complexity dominates the human factor concerns.

Human factor concerns were also identified in the other procedures that imple-ment the E0Ps. Section 8 discusses the human factor analysis.

The simuJator portion of the inspection was the key to understanding the Plant Hatch E0Ps. Due to the complexity of the E0Ps, the team developed simulator scenarios based on the logic of the PSTG to achieve desired end points. The simulator exercises resulted in the desired end points being achieved by the procedures, with the procedures directing the actions to be taken when required. The simulator exercises provided confirmation that the plant staff can use tha procedures, and pointed out weaknesses in the procedures for con-current actions on primary and secondary :ontainment control.

In summary, the team concluded that the E0Ps at Plant Hatch need improvement.

The facility lackc adequate justification for differences between the EPG and E0Ps. The procedures do contain human factor concarns in areas that affect operator performance. The development, validation, verification Training program did in E0P entry not fully implement a multi-discipline team approach. Procedures to better imple-conditions otner than a plant scram is required.

ment primary and secondary containment and rad release control entry conditions are needed. However, based on the walkdowns and plant simulator exercises, the teams concludes that the Plant Hatch personnel can carry out the E0Ps and that the current E0P$ can get the plant to a safe condition if called upon.

REPORT DETAILS

1. Persons Contacted Licensee Emplo'yees

• J. T. Beckham, Jr., Vice President, Plant Hatch

• S. Bethay, Nuclear Safety and Compliance Supervisor

• J. Betsill, Operations Support Superintendent

• L. Byrnes, Senior Nuclear Engineer

• C. Coggin, Training and EP Manager _.

G. Czech, Senior Plant Engineer

• P. Fornel, Manager, Maintenance

• 0. M. Fraser, QA Site Manager

• R. Hayes, Deputy Manager of Operations .

R. King, Engineering Supervisor R. Knoble, Consultant C. Lane, Consultant

• H. Nix, Plant Manager

• D. Read, Plant Support Manager

• 0. Self, Oglethorp Power Company

• L. S,umner,_ Manager of Operations

• S. Tipps, Nuclear Safety & Compliance Manager

• 0. Vidal, Shift Technical Advisor

• R. Zavadoski, Manager, HP/ Chemistry The inspectors also contacted other licensee personnel including senior reactor operators, reactor operators, training personnel, shift technical advisors and other plant and engineering staff.

NRC

• L. Crocker, Project Manager, Hatch, NRR ,

• M. Ernst, Deputy Regional Administrator, Region 11

• W. Hehl, Deputy Director, Division Reactor Projects, Region 11

• C. Julian, Chief, Operations Branch, Region 11

• G. Lainas, Assistant Director for Region 11 Reactors, NRR

• D. Lange, Chief, BWR Section, DRS, Region 1

• J. Menning, Senior Resident inspector, Plant Hatch

• C, Patterson, Project Engineer, Region 11

• W. Regan, Chief, Human Factors Assessment Branch, NRR

• M. Sinkule, Project Section Chief, Region 11

• W. Troskowski, E00, Region 11 Coordinator, NRC HQS

• Denotes those present at exit meeting on May 10, 1988 t

2

2. E0P Development In mid-1983 an E0P implementation team was fonned at Plant Hatch. The team was staff.ed by contractors, six engineers and a project manager. In addition, Plant Hatch operations personnel participated in a rotational capacity in development activities and in contractor oversight. Four Plant Hatch shif t supervisors participa'ted in development activities including simulator testing and desk top review of the many iterations of the early E0Ps.

A human factors review was conducted by a contractor during May-September, 1 1984. The review consisted of interviews with two operators, review of '

Plant Hatch emergency procedure documents, observation of simulator exercises, interviews with personnel at Brunswick Station about their experiences with similar flowcharts, and. review of a sample of early Plant Hatch flowcharts.

The E0P implementation team development activities continued through early 1986, including simulator and plant walkthrough validation.

Pre-implementation training began in early 1986, consisting of 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of glassroom study of the philosophy, content and use of the new proce-dures. Following the classrocm component of the training, 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of simulator exercise were conducted. Operator coments were solicited during the simulator training for possible integration into the E0Ps. These coments were evaluated by the E0P inplementation tdam staff, in consul-tation with Plant Hatch management, and a response was provided each operator on the resolution of his coment.

Currently Revision 2 of the. flowcharts is in effect.

Findings Several concerns have been generated by a review of the Plant Hatch E0P development process. There was an inadequate team approach in the develop-ment, validation and verification of the E0Ps. Human factors involvement was lacking in the fundamental development phase of the E0Ps. After basic development of the E0Ps was completed, human factor involvement was very limited.

The verification activities were conducted primarily by one STA, with limited support from other STAS. The only evidence of a team approach in the verification was review by other operations personnel of STA verifica-tion of proper plant nomenclature in the E0Ps.

The supporting documentation for the E0P development process and formal validation is under contractor control, not under Georgia Power control.

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3 The formal validation done on those steps not exercised in the simulator was done by table top analysis and did not include a walkdown of the procedures in the plant.

E0P validation and verification on those ARPs and A0Ps that implement the PSTG was minimal. ,

3. Basic E0P/BWR Owners Group Emergency Procedure Guideline (EPG) Comparison A comparison of revision 3 of the EFG and the E0Ps was made to ensure that ~

the licensee had procecures as indicated in the EPGs. This comparison --

was made difficult by the unique and complex nature of the implementation of the E0Ps at Plant Hatch. The EO)s as implemented at Plant Hatch are contained in a group of procedures. The E0Ps at Plant Hatch consist of the following procedures: -

a. Alarm Response Procedures (34AR Series)

b. Abnormal Operating Procedures (34AB Series)

c. Flow Charts

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d. End Path Manuals (EPM)

e. Emergency Plan Implementing Procedures (EPIP) ,

Each group of procedures listed above contains precedural guidance from the ERG. All of the above listed procedures are required to implement the symptom based E0Ps at Plant Hatch.

Pre-scram EPG directed operator actions are contained in Alann Response Procedures (34AR Series). These procedures direct immediate operator actions, and direct the operator to Abnormai Operating Procedures (34AB).

These procedures contain procedural guidance from the EPG, and direct the operator to manually scram the reactor, at which time the flowcharts are entered.

The flowcharts are entered following ANY scram, or failure to scram.

These imediate procedural steps are contained on 5 complex flow charts, with subsequent operator actions contained in text procedures, called End Path Manuals. The Primary Containment Control and Secondary Containment Control are identified in the flow charts to be executed concurrently and the instructions to control these items are contained in the End Path Manuals. Radiation Release Control instructions are also contained in the End Path Manual but are not directed as a concurrent instruction.

The Emergency Plan Implementation Procedure was also identified by the licensee documents as a source of instructions for radiation release control but. the facility was unable to identify the specific instruction in the EPIP which address EPG steps.

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l The flow charts are so structured to allow the operator to pick any flow chart, follow the instructions given, and be guided to the appropriate flow chart based upon the answers given to a series of simple questions.

The flow charts direct the operator to the appropriate End Path Manual af ter the imediate operator actions are taken.

There are four End Path Manuals. ' These manuals also contain the contin-gency procedures:

a. ' Level Restoration c.

b. Emergency Depressurization

c. Alternate Depressurization

d. Alternate Pressure Control

e. Alternate Shutdown Cooling

f. Reactor Vessel Flooding

g. . Alter.pate Water Injection

h. Group Isolat. ion

i. Reference Leg Fill The End Path Manuals, as well as portions of the flowcharts, contain the procedural guidance from the EPG for the contingency procedures.

The team reviewed the procedures listed in Attachment A. The team concluded that the family of procedures listed above will address the EPG requirements. The team identified that the procedure control for radiation release did not address radiation release at the alert level pre-scram that may occur as an unmonitored release. Specific comments on the procedures were noted as described in the following sections.

4. Independent Technical Adequacy Review of the Emergency Operating Procedures The Hatch E0Ps in Attachment A were reviewed to assure that the procedures are technically adequate and accurately incorporate the BWR Owners Group EPGs. A comparison of the Plant Specific Technical Guidelines (PSTG) to the EPG and E0Ps was also performed. Differences between the EPG and PSTG were assessed for adequate technical justification. Selected specific values from the procedures were reviewed to dei. ermine that the values were correct.

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a. PSTG/EPG The facility had indicated in prior correspondence to the NRC that they were. taking no deviations with the EPG except for inserting the site specific values into the PSTG and not including systems in the PSTG that do not exist at Plant Hatch. The nomal vent and purge system to control cont'ainment pressures wa.s not utilized by the facility as was allowed by the EPG. No technical discrepancies were identified in this area.

b. PSTG/EOP Comparison 1.

This comparison found many inconsistencies between the two documents.

These inconsistencies were apparently caused by the licensee belief that the PSTG is a guidance document and was not the technical basis for the procedure development.

The comparison between flow charts and the PSTG revealed several concerns with the details of the Plant Hatch E0Ps. As the flowcharts are designed to provide the operator with detailed procedural check-off lists of specific actions to take while proceeding through them,

, they ,contain many steps which are not included in the PSTG. While not necessarily a problem in concept, it was found that in several cases (which.are considered to be representative of the flow charts in general), these additional operator actions varied frcm the logic of the PSTG and introduced delays in mitigating the casualty as rapidly as possible. In some cases the logic of the PSTG was changed b.y a rearrangement of steps in the transition from the ARP or A0P to the flowcharts and EPMs. In addition, the values for parameters involving action steps in the E0Ps are often not the same as those specified in the PSTG. In the E0Ps these values are often alam set points while the PSTG specifies a calculated value or one which was obtained from the technical specifications.

Examples of these variances are contained in the following paragraphs:

Example 1. The Reactor Pressure Vessel (RPV) Control guideline in the PSTG is to be entered when RPV water level falls below +10.0 inches, the low level scram set-point. The action step RC/L calls for the monitoring and control of RPV water level. The next sub-step, RC/L-1 calls for the confirmation of or initiation of any of the following: 1. Isolation, 2. ECCS, 3. Emergency diesel genera-tor. The next step calls for restoration and maintenance of RPV water level between +10.0 and +56.5 in, with one or more of the systems capable of refilling the RPV. The final step calls for proceeding to the cold shut down condition.

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Comparing the mitigation of a low level entry condition on Path 3 of the E0P flow charts (the nomal SCRAM procedure) with the Level response of the PSTG above shows the following: The procedure asks

( if a group 2 or 5 isolation auto initiation signal is present and-if it is, directs the operator to a series of steps to determine if isolations have occurred, but not if the isolations should have occurred. 'Then the status of the pneumatic system in the Drywell is checked and corrected if wrong. There is no reference to a potential level problem at this juncture, and there is no reference to the confirmation of ECCS or emergency diesel initiation. Forty three steps later (in the direct flow path without deviation for other _.

actions) the flow path asks the operator if level can be maintained above +12 inches and if not directs him to Path 4. In Path 4, the various potential sources of water to the RPV are addressed in a serial manner, with deviation notes to check for fire conditions and system line-ups prior to initiation of water supply to the RPV.

The level limits specified in this example are +10 and +56.6 inches in the PSTG and +12 and +50 inches in the E0P.

Example 2: The PSTG entry condition for RPV pressure control is 1054

~psig. If any Safety Relief Valve (SRV) is cycling, SRVs are to be manually opened until RPV pressure drops to 927 psig. Pressure is then to be controlled below 1090 psig with the main turbine bypass valves which may be augmented by one or more of several additional systems. When all control rods are inserted be' yond position 02, the RPV is to be depressurized and the cooldown rate maintained below 100 degrees F/hr. Then shutdown cooling is initiated using RHR, systems used for depressurization, or if that does n:* work, Alternate Shut-down Cooling. The entry question on Flow Path 3 for RPV Pressure control is Reactor Pressure above 1042 psig. If it is, you are directed to &ctivate low low pressure set by momentarily opening an SRV and then maintaining pressure be. tween 850 and 1040. It appears that the low low set activation step is the equivalent of the cycling SRV steo in the PSTG because its activation prevents cycling. If the pressure cannot be maintained in this range, then the flow path directs the operatar to an "SRVs stuck open" question. This is an action which is not required by the PSTG. If a valve is stuck open, t

the operator is directed to take action to shut the valves thus l diverting his attention from maintaining reactor pressure control in accordance with the PSTG. Following the "SRVs stuck open" quastion, a block on the flow chart states "use SRVs as necessary to maintain reactor pressure below 927 psig." The PSTG states at this point that the SRVs may be used to augment the main turbine bypass valves but only when suppression pool water level is above 58 in. A flowchart question relating to the use of turbine bypass valves for pressure control does not appear until 14. steps later. If available, the operator is to maintain pressure below 927 psig using the bypass valves. The other pressure control augmentation methods are found l' in the EPMs af ter proceeding through many other steps on the flow-chart and within the EPMs. Note that the values used as control points again vary between the PSTGs and the E0Ps.

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Example 3: The entry condition for the monitoring and control of reactor power in the PSTG is a condition which requires reactor scram, and reactor power above 3% or cannot be determined. The actions which are to fellow are: Confirm or place the reactor mode switch in SHUTDOWN (RC/Q-1); if the main turbine-generator is on-line and the MSIVs are open, confirm or iM tiate recirculation flow runback to minimum (RC/Q-2);' trip the recirculation pumps if reactor power is above 3% or cannot be determined (RC/Q-3); boron injection is required with Standby Liquid Control (SLC) and automatic initia-tion of Automatic Depressurization System (ADS) is prevented if the reactor cannot be shutdown before suppression pool temperature 1.

reaches 110 degrees F.

The E0P flow path response, starting with Path 3, takes the operator to the top of Path 1 if the Nuclear. Engineer cannot confirm negative reactivity insertion sufficient for cold shutdown which is a time consuming action not called for in the PSTG. Ir, Path 1, instead of imediately reducing recirculation flow to minimum followed by recirculation pump trip, the E0Ps send available operators to execute sequence insensitive rod insertions, line up recorders, verify or initiate alternate rod insertion, continue to try and insert rods, check _ power supplies, and if the suppression pool is not above 110 degrees F, start checking out the process computer. All these steps are being done before recirculation pumps are run-back or tripped.

The step to check the suppression pool temperature is also done prior to recirculation pump trip. Accomplishing these sequential steps is different than the logic of the PSTG which is based on the insertion of negative reactivity into the reactor as rapidly as possible.

in the boron injection phase, the E0Ps call for the operator to attempt SLC injection and if not successful, try to repair the standby liquid control systems. The PSTG logic required the opera-tors to imediately attempt the alternate methods of boron injection.

As the event progresses and power control by level reduction is required, the E0Ps call for level to be maintained at the point of MSIV closure while the PSTG calls for the reduction in water level to the top of active fuel if necessary to control level.

Exemple 4: For RPV flooding the PSTG Indicates that the first step is to close the Main Steam Isolation Valves (MSIVs) and drains as well as High Pressure Coolant injection (HPCI) and Reactor Core Isolation Cooling (RCIC) steem lines. The facility uses the HPCI and RCIC as alternate boron injection system if SLC should fail. The facility implementation of RPV flooding accounts for the provision to not isolate HPCI and RCIC if being used for boron injection even though this action is in apparent conflict with the PSTG.

Examole 5: The entry condition into Primary Containment Control on suppression pool Hi-Level is 150 inches as stated in the PSTG, SP/L-3. However, End Path Manual 5.121, paragraph 3.1 does not require operator action until levei has risen to 152 inches.

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l Example 6: Flow Chart 1, Caution 21 requires entry into Primary Containment Control at a drywell hydrogen concentration of 2%. This entry condition is not listed in the PSTG.

Example f: Flow Chart 1, Grid B-2 asks if suppression pool tempera-ture is above 110 degrees F. If so, inject SLC. Tne PSTG requires the initiation of SLC before'110 degrees F is reached.

Example 8: Entry condition into Secondary Containment Control is required at 0 pounds DP as stated in the PSTG. This entry condition is not included in either End Path Manual 4.126 or 4.127. _..

Example 9: PSTG Caution #14 requires that the operator not depres-surize the RPV below 100 PSIG (HPCI low pressure isolation setpoint) unless motor driven pumps sufficient to maintain RPV water level are running and available for injection. End Path Manual 4.125, step 3.12 lists 128 PSIG as this value.

Example 10: In the Primary & Sicondary Centainment Control Proce-dures both pre-scram and in the End Path Manual, concurrent control of all containment parameters (i.e. Suppression Pool Temperature,

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Suppression Pool Level, Containment pressure etc.) was not proce-durally required whenever an entry condition existed as provided for in the PSTG..

The above are examples of inconsistencies between the PSTG and E0Ps.

j Occumentation to support the variances was lacking. Inconsistencies

' s,imilar to the above examples were identified throughout the flow-charts and in the EPMs.

In situations where the PSTG entry conditions exist without scram,

' the licensee relies en Alann Response and Abnonnal Operating Proce-dures to accomplish the emergency mitigating actions. The inspection team traced several of these proccdures to determine if the logic

- of the PSTG was preserved. These procedures were found to be under revision making tracing difficult. The torus high temperature Abnonnal Operating Procedure was found to still refer to the Scram procedure which was cancelled by the E09 Procedure. Several Alarm Respor.se Procedures were found to be "dead ended." If the mitigating l

action called for in the procedure was not successful, there was no path to direct the operator to an Abnormal Operating Procedure. The affected Alarm Response Procedures included Suppression Chamber Level High, 34AR-601-127-2S; Suppression Chamber Level High "RCIC",

34AR-602-230-2S; Torus Water Level High/ Low, 34AR-654-080-25; Primary Containment High Pressure Trip, 34AR-603-106-25.

l l

The licensee did not prepare a deviation document between the EPG/

PSTG, when in f act, as the E0Ps were implemented, they are taking deviations from the EPGs. Since the facility only considered the PSTG as a guidance document and not a technical directive upon which l

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9 the technical adequacy of the procedures can be based, the facility only assessed that the intent of the PSTG was being met. The facility did not prepare technical justification for the differences between the PSTG/.EOPs. Technical justification for the deviations of the E0Ps from the EPG is needed.

c. Administrative Controls for Alam Response ProceMs and Abnormal Operating Procedures that Implement PSTG Requirmem.

The inspectors inquired if the administrative controls on the Alarm Response Procedures (ARP) and Abnonnal Operating Procedures (A0P) _

that implement the PSTG requirements were the same as the flowcharts

• and EPMs. The facility responded that those A0Ps and ARPs that implement the PSTG requirements were not reviewed and controlled like the flow charts and EPM. The facility is in a major rewrite of the A0Ps and ARPs. The facility management imediately directed its staff that until further notice, all ~ARPs and AOPs and changes will be reviewed by the E0P Group before implementation to assure that the PSTG requirements are met. This is a temporary action until the licensee fomalizes the administrative controls for these procedures.

5. Control Room and Plant Walkdowns The inspectors walked down selecte'd E0Ps to confirm that the procedures can be accomplished. The purpose of the walkdowns was to verify instru-ments and controls as designated in the procedures are consistent with the installed plant equipment, ensure that the indicaters, controls, annunicators referenced in the procedures are available to the operator, and ensure that the task can be accomplished. Detailed coments identified are noted in Attachment 8. General .coments and observations are discussed below:

The most significant general coment is that the plant labeling and procedure nomenclature do not agree. This a gaars to be the result of the verification activities which did not have clear guidance regarding this area (See Section 3).

The flowcharts in the control room are located in an appropriate place.

However, as discussed in Attachment C, adequate table space for concurrent use of the procedures and EPM is lacking.

The facility control of tools / jumpers for E0P use is considered quite effective and knowledge of plant personnel on these specialized tools /

jumpers is widespread.

Whereas the team did find labeling inconsistencies, the facility has taken care to. assure that key relays and fuse locations and other equipment are appropriately marked to distinguish them as E0P equipment. This is quite evident throughout the f acility. .

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10 .

The teams considered that in spite of items identified during the walk-downs, 'the procedures were able to be performed by the staff at Plant Hatch.

6. Simulator Five scenarios were run on the plant specific sir"'ator with two teams of licensed operators. The first team consisted of both staff and current on-shift licensed operators. The second team consisted of the current on-shift crew in training for the week. The team utilized different numbers of personnel to conduct these scenarios. Scenarios were run -

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- with 2-SR0s, 2-R0s, and STA (minimum Tech Spec crew as well as minimum administrative procedure crew) and 2-SROS,3-R0s, and the STA (normal shif t crew size). The simulator scenarios pr'ovided information on real time activities. .

The purpose was to determine that the procedures provide operators with sufficient guidance such that their responsibilities and required actions during the emergencies, both individually and as a team are clearly outlined, verify that the procedures do not cause operators to physically interfere with each other while performing the E0Ps, verify that the procedures did not duplicate operator actions unless required (i.e.,

Inde~ pendent Verification) when a transition from one E0P to another E0P or other procedur.e is required, precautions are taken to ensure that all necessary steps, prerequisites, initial conditions, etc., are met or completed; and, operators are knowledgeable about where to enter and exit the procedure.

Due to' the complex nature of the Hatch E0Ps the team initially had diffi-culty in the understanding of how to use the E0Ps when the simulator scena'. 45 were being developed. As a result the team developed the scenarios based upon the logic of the PSTG to achieve a desired end point.

If the procedures being utilized by the operator achieved the desired endpoint, the team would conclude that the E0Ps ware capable of bringing the plant to a safe condition. The scenarios were designed to evaluate the E0Ps during various plant upset conditions, both before snd after a reactor scram. Following each scenario, detailed discussions were held with the operating crew.

The conclusions and observation of the team follow:

The ECPs utilized took the simulator to the desired er.d point.

The operators were observed to effectively use the procedures, even in reduced lighting situations.

The procedures directed the actions of the operators in a time frame that was generally in agreement with the scenario development.

The Safety Parameter Display System (SPDS) was effective in assisting the information needs to respond to the scenarios.

11 The concurrent execution of Primary, Secondary, and Radiation Release Controls are not procedurally required when entry conditions for these exist. The training program also does not address concurrent entry into these controls With a staffing level of 2-5R0s, 2-R0s and 1 STA the team observed the SR0s being required to operate the controls. With a level of 2-SR0s, 3-R0s and 1 STA the SR0 did not have to operate the controls. This is a concern on the adequacy of the minimum staff.ing level requirements of the administrative procedures and technical specification requirements.

The team concluded the E0Ps can mitigate and control plant upset condi-tions, and place the plant in a safe condition.

7. Human Fac'. ors Analysis ,

As a result of the human factors analysis of the Plant Hatch E0Ps, a list of specific concerns has been generated (see Attachment C). An initial desktop review of the E0Ps was conducted prior to the on-site inspection.

Observation of simulator exercises, interviews with Plant Hatch staff, and plant walkdowns were used to both corroborate those problems noted during the desktop review and to identify additional concerns.

Findings .

The primary human factors deficiency identified in the Plant Hatch E0Ps is the overall complexity of the flowcharts. This high les11 of com-plexity is caused by the interaction of a number of human fac; ors concerns contained in the the flowcharts, resulting in procedures that are diff! cult to use, understand, and read.

The major contributing factor to the complexity of the Plant Hatch flow-charts is the high level of detail in the procedures. The large amount of information has led to several specific concerns in the procedures for example: extensive movement, lengthy action steps, placement of cautions, reduced print size, and overall small size of the flowcharts. Activities required to correct concerns within the E0Ps include an evaluation and reduction of the amount of information contained in the procedures.

The technical concern toulting from the high level of detail can generally be divided c '; two categories: (a) those with a strong relationship to potential human error (areas 1 through 5) and (b) those less directly related to potential human error but which also affect useability and cederstandability of the procedures (areas 6 through 8).

A summary of concerns in each of these areas, including those found in the EPMs, follows.

a. Movement (Transitions)

Movement (also known as transitions) wit" - and between procedures is of ten required of an operator during D e execution of E0Ps. An operator may be directed to concurrently perform more than one flow

12 path, or more than on procedure, or to completely exit the procedure being executed and move to a different E0P. An operator may also be required to reference tables, charts, supplemental information, or non-E0P procedures. Movement within and between E0Ps can be disrup-tive, confusing, and cause unnecessary delays and error. Therefore it is particularly important that these transitions be minimized.

When movement cannot be avoided, it is important that the transition directions to the operator be clearly ard consistently structured.

Throughout the Plant Hatch flowcharts and EPMs, many transitions are required of the operator. Not only is the movement extensive, but 1 the transition directions to the operator are indicated in multiple, inconsistent, and sometimes unclear methods. The number and types of transitions required in the Plant Hatch E0Ps make the procedures more difficult to use and hold potential,for error.

b. Decisions When individuals are subjected to emotional or environmental stMss, such as those which may be present during the ur.e of E0Ps, diffi:ul-ties may be experienced in a number of cognitiva areas. For example,

, infonnation drawn from long term memory may be incomplete or inaccu-rate, short term memory capacity may be reduced, and the ability to accurately assess the importance of details may be degraded. Any or all of these problems will lead to difficulty in decision-making.

Because decisions can be extremely important to the execution of E0Ps, it is critical that they be clearly, consistently, and approp-r.iately made.

In the Plant Hatch E0Ps, numerous types of decisions are required.

Because these many decisions are also inconsistently structured, they can be difficult for operators to use in emergency situations with a potential for error,

c. Memory Requirements As mentioned above, difficulties may be experienced with both long and short tenn memory when individuals must perfonn under stressful conditions. During execution of E0Ps, operators must draw upon their experience and training (long ter.n memory). In addition steps and information within the procedures, such as time dependent or recurrent steps, depend upon the use of shor'. b nn memory. When procedures are designed to include multiple demt.nds upon operator memory, the potential for operator error is increased.

The Plant Hatch E0Ps evidenced numerous demands upon operator memory. While some reminders and backup systems are provided to i assist operators, the Plant Hatch E0Ps as a whole appear to place a unnecessarily large burden upon the operator and could lead to error.

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d. Cautions and Notes Cautions are used to describe hazardous conditions that can cause injury or, equipment damage. They should describe the consequence cf the hazard. Notes are intended to provide supplemental informa-tion to the operator. Neither cautions nor notes should contain directions to the operator. ' Because of the critical nature of the information contained in cautions, it is particularly important that cautions be emphasized in a way that distinguishes them from notes and that they be located where operators will not overlook them.

The human factors analysis revealed a number of concerns related to format, structure, location, and labeling of cautions and notes in -

the Plant Hatch E0PS. Thase deficiencies in the treatment of both critical and supplemental information could lead to delay or operator error,

e. Graphics A number of aspects of the graphics used in the Plant Hatch flow-charts have contributed to difficulty in readability. These include

, inadequate print size, lack of sufficient white space, light glare off l'aminate, and low contrast color use. It should be noted that the ex+.ent and number of graphics inadequacies in the Plant Hatch flowcharts are such that this category is likely to have a greater relationship to potential error than is usually attributed to graphics issues in procedures,

f. S'entence Structure Both the Plant Hatch Writer's Guide and NUREG-0899 indicate that sentences should be short, simple, including one idea per sentence, and should avoid the use of imprecise adverbs. It was found that steps throughout the Plant Hatch E0Ps were written in a complex manner, using multiple action verbs, imprecise adverbs, supplement:1 infonnation, and inconsistent structure. The numerous examples of overly complex steps identified in the Plant Hatch E0Ps could lead to operator error.

g. Writer's Guide In order to prepare clear, consistent E0Ps that will aid the operator and help minimize errors that can occur when operators execute procedures during emergencies, a complete and clear writer's guide is necessary. A number of inadequacies were identified in the Plant Hatch Writer's Guide. These deficiencies result in a writer's guide which does not provide the guidance necessary for consistent produc-tion and revision of high quality procedures.

14 It should also be noted that, due to the extensive use of ARPs, A0Ps, and EPIPs in conjunction with the E0Ps, guidance for their preparation and revision was not included in the writer's guide for E0Ps. Be.cause they are part of the E0P system, it is critical that format be consistent throughout these procedures and that the quality of the documents be controlled as strictly as that of the flowcharts and EPMs.

h. Miscellaneous A number of other miscellaneous inadequacies in the Plant Hatch E0Ps _

were identified through the human factors analysis. For example, abbreviations and acronyms were used inconsistently throughout the E0Ps. Placekeeping spaces in the EPMs were located on the right side of the steps, not at the step number. References to the flowcharts were inconsistent through E0Ps and satellite procedures, ranging from "the flowcharts" to 31ED-EOP-001-15. Other miscellaneous inadequa-cies are detailed in Attachment C.

8. E0P Training Discussions were held with the Director of Training and Emergency Pre-par'edness~ and senior staff instructors. Froa these discussions and a review of LT-IH-20101-00 INTRODUCTION TO EMEi .; ICY OPERATING PROCEDURES, the team concluded that the training organ-

• ion demonstrated weakness in the proper training of the entry conditions into the E0Ps.

Plant . Hatch utilizes an unique method of implementing the E0Ps. They are a group of procedures, made up of:

a. Alarm Response Procedures o Abnormal Operating Procedures l c. Flow Charts i d. :nd Path Manuals l e. Emergency Implementing Procedures As currently instracted, the operating staff considers only the Flowcharts and End Path Mar.uals to be the E0Ps. As currently instructed, the operat-ing staff er.iers the E0Ps (the Flow Charts and End Path Manuals) only on the following conditions:

a. Manual Scram

b. Auto Scram

c. Failure to Auto Scram These instructions are inadequate and represent a weakness in the E0P construction. Primary Containment Control, Secondary Containment Control l and Radiation Release Control Guidelines are required in the PSTG to be entered, and executed concurrently when any condition .as specified in the PSTG, are met. These entry conditions can be met, irrespective of a reactor scram.

15 Due to the highly complex nature of Plant Hatch flowcharts, they are considered difficult to use, in order to provide operators the famili-arity and understanding necessary to use the flowcharts, a large burden is placed on training. Observation of operators in the simulator and discussion with personnel during this inspection provided the following information:

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a. Operators are provided the training and familiarity necessary to use the flowcharts,

b. In order to provide the needed training, the training department must _

devote substantial time and effort to E0P training. ~;

c. Simplification and reduction of level of detail of the flowcharts would reduce the burden on training,

d. Operators believe that, (a) the flowcharts provide more detail than they require to perform the procedures and, likewise, (b) their overall training is sufficient to allow the reduction of level of detail within the flowcharts.

9. Ongolng Evaluation of E0Ps Ongoing evaluation of Plant Hatch E0Ps consists of three different evalua-ion activities. ,

First, an annual review of all E0Ps is conducted in accordance with Admini.strative Procedure 10AC-MGR-003-05, Preparation and Control of Procedures, section 8.4.13. These annual reviews are tracked by the Administrative Control Department, and in the case of E0Ps are initiated by the Manager of Operations. The reviews are conducted by operators while undergoing requslification training and are documented using the Procedure Review form, as described in Administrative Guideline AG-ADM-14-1184N, Administration of Procedure Reviews. The Procedure Review Form contains the number of procedures reviewed, revision number, date of review, an indication of acceptance or non-acceptance, and relevant remarks. The form is signed by the Manager of Operations or his deputy.

No indication of the actual reviewer or review methods used is listed on the form. Plant Hatch representatives indicated that there is no method for tracking how or by whom the reviews were actually conducted.

The second methed for ongoing review of E0Ps is through operator comments recorded during regular training. This method is used for all types of procedures. An interoffice memorandum form is used to describe the operator comment and is placed in a binder in the training office. These comments are then forwarded to an operations supervisor, who refers comments about E0Ps to the supervisor of the E0P project. No proactive effort is made to solicit these contents, f

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16 The third method used for ongoing review of E0Ps is informal comunication used by operators to relay their comments when not undergoing training.

The supervisor of the E0P project reports that this is a comon method for him to receive, cporator input about the E0Ps, however, the largest source of coments is through operator training.

A formal method for requesting changes to any type of Pl&at Hatch pro-cedure is through the Deficiency Control Svstem, as described in 10AC-MGR-004-05. Plant Hatch staff indicated that this system is rarely used for E0Ps, and it is therefore not discussed in this section.

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Findings .

The methods used for ongoing evaluation of E0Ps at Plant Hatch have several weaknesses. They are: ,

a. The Specific review methods used for the annual review are not noted on any document. Because of the documentation used, it is not possible to track what type of review was conducted. Therefore, it is not possible to assess the adequacy of the annual review of E0Ps.

b. operator training as a source of operator input on the E0Ps is

,Using,d a goo method. However, it would be improved by actively soliciting operator coments on the procedures during training, rather than simply taking coments as they are offered.

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c. Relative to the informal comunication method of obtaining ongoing operator input on the E0Ps outside of training, more active solicita-tion of operator input coments would improve the system.

10. QA Involvement in the E0P Program The team inspected the QA organization invcivement in the programatic l approach of the E0P Program. The inspection focused on the planned and periodic audit of the E0P development and implementation process.

Discussion were held with the QA Site Manager, and Quality Assurance Audit of Operations 87-P0-2A, dated October 15, 1987 was reviewed. The scope of the E0P audit included the Flow Charts and End Path Manuals. The audit report had findings in areas of:

a. Inconsistencies between plant labeling and E0Ps

b. PSTG and E0P differences

c. E0Ps not written in accordance with Writer's Guide l

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0 17 The audit report contained findings similar to the findings of the NRC team. Licensee management corrected the specific inconsistencies contained in the QA audit report and did not do an in-depth review to determine the , root cause of these findings, nor did it do a followup assessment to determine if the concern was as widespread as the NRC team has identified. The differences between the PSTG and E0Ps found by the QA audit did not include the difference in logic between the PSTG and E0P Flowcharts. (Detailed in section 5.0 of this report.)

Because E0P implementation by Plant Hatch includes Alarm Response and Abnormal Operating Procedures, the inspector determined that QA did not -

audit the entire group of procedures that fully implement the E0Ps to ensure compliance with the PSTG and the Writer's Guide.

11. Quality of Control Room Drawings and Procedures The purpose of this inspection was to review the methods utilized to ensure the critical plant P&lD drawings in the Control Room reflect the as-built condition of Plant Hatch.

Discussions were held with the Superintendent of General Engineering and Support, procedures Design Control 40BC-ENG-003-05, and DCR Processing 42EN'-ENG-001-05 were reviewed. The inspector also reviewed the critical plant drawings in, the ContrH Room.

Corrections to the drawings in the Control Room are made by hand following plant modifications. This is deemed necessary by the licensee, and in accordance with procedures, due to the lead time necessary to update the drawings. The inspector reviewed these changes and found them to be legible and made neatly. Each change was properly documented on the drawings. From discussions held, procedures and drawings reviewed the inspector found no unacceptable conditions.

The following items regarding the quality of the control room E0Ps were identified.

a. Overall poor upkeep of EPIP and non-upgraded ARPs. (Facility responded to items during. inspection)

- torn pages

- poor xerox quality

- lack of tabs or labels

- broken binder

b. A0P and ARP E0Ps lacked appropriate emphasis (e.g., binders were not labeled or colored in a manner that easily distinguishes them from non-EOP-related procedures),

c. Expired TCH noted in 34AB-0PS-015-25 (expired 4/18/88), was replaced with extension to 6/5/88, rather than correct procedure,

d. Poor xerox quality noted in EPMs; e.g., EPM 2, Unit 1.

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12. Containment Venting Plant Hatch is a two unit facility, utilizing GE Mark I primary contain-ment configurttions. The Mark I containment design consists of a light bulb shapped drywell and a doughnut shaped torus. The drywell is inter-connected to the suppression pool by downcomers which submerge into the suppression pool water. Vacuum breakers are provided in the interconnec-tions between the drywell, torus and Reactor Building. The containment atmosphere is inerted with nitrogen during normal plant operation. Both the drywell and suppression pool chamber are designed to withstand a maximum of 62 psig internal pressure.

Containment venting is accomplished using comporents of the Primary Containment Purge and Inerting system and the Standby Gas Treatment system. Venting the drywell or torus can be performed in one of two ways.

The first path utilizes two 18 inch lines which are generally used for containment purging and startup inerting. The second path uses redundant 2-inch lines which are used to vent excess pressure during plant heatup and normal operation. Regardless of the vent path used, the volume vented from the drywell or torus is routed to the Standby Gas Treatment system and released via the plant stack. The 120 meter tall plant stack assures ele,vated vent gas releases to the environment.

Each of the two 1,8-inch lines (one line is connected to the torus and the other is connected to the drywell) have two butterfly air operated valycs (A0V) that perfonn containment isolation functions. > Each of the four 2 inch lines (two lines are connected to the torus and two connected to the drywel.1) have two globe A0Vs that perform containment isolation functions, and one valve that is used for vent flow control purposes. The A0Vs in the 2 inch lines receive air from the non-interruptable air supply system.

All A0Vs fail closed on loss of air supply. The containment vent piping and valves have a design pressure of 150 psig, i

The vent flow control valves in the 2 inch lines receive signals from l

controllers located in the main control room. The valves The are throttled vent flow to vent at the desired flow rate and downstream pressure.

control valves are air operated in Unit 2 and hydraulically operated in Unit 1. If any of the Unit 2 A0Vs lose air supplies, the valves will fail closed. The valves can then be operated manually by connecting portable air or nitrogen bottles to the valves locally. The electro-hydraulic valves in Unit I will fail closed on loss of power or hydraulic pressure.

l If this occurs, alternate vent paths (possibly using the 18-inch purge

' lines) have to be used, because the manual handwheels were not purchasej

with the valves. The valves that perform containment isolation functions are environmentally qualified, but the 2 inch flow control valves are not.

Operator access to the valves could be limited during certain accident conditions, due to potentially high radiation levels present in the vicinity of the valves.

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4 19 The Unit 1 containment purge lines (18 inch lines) have normally closed, manually operated valves downstream of the two containment isolation A0Vs. Unit 2 does not have these' manual valves. Another difference in design between Unit 1 and Unit 2 containment venting is the number of penetrations. The Unit 2 system has three drywell and three torus penetrations, one for each vent line. The Unit I system has only one drywell and one torus penetration. In Unit 1, the 2 inch lines are connected to the two 18 inch lines penetrating the drywell and torus.

All vent lines discharge ir. o a single 18 inch line that is connected to the suction of the Standby Gas Treatment system (SGTS). Excess flow _

isolation dampers are installed in the line leading to SGTS. The isola- -

tion dampers prevent high pressure from a LOCA from reaching SGTS if the 18 inch purgelines are open. The dampers will shut on excessive vent flow, and will route the flow through a.2 inch bypass line to SGTS. The isolation dampers protect SGTS filter trains from overpressure (SGTS plenum design pressure is 2 psi) and possible rupture. The rupture of SGTS could result in an uncontrolled release of radioactivity, steam or hydrogen into secondary containment. This condition could preclude operator access to essential safety equipment and complicate post accident recovery efforts.

For emergency venting of containments, the BWR owners group recomended the following in Revision 3 of the EPG (guidance step PC/P-7):

"If suppression chamber pressure exceeds the Primary' Containment Pressure Limit, vent the containment in accordance with the (procedures for containment venting) to reduce and maintain pressure below Primary Containment Pressure Limit".

At Plant Hatch, the instructions on when and how to vent the containment during an emergency are provided in the End Path Manuals, Containment Control Guideline, Drywell Pressure and Temperature Control, Procedure Number 3.123. The procedure provides instructions to start SGTS and open the drywell 2 inch vent valves if suppression chamber pressure exceeds the Primary Containment Pressure Limit. The Primary Containment Pressure Limit varies between 53 to 62 psig, depending on primary containment /

suppression pool water levels. Instructions are also provided to close the drywell 2 inch vent valves when suppression chamber pressure can be maintained below the Primary Contasee Dressut ? Limit. Therefore, the Plant Hatch procedures follow EPG, Revision 3, guidance step PC/P-7 recomandations.

Venting at Plant Hatch is performed only through the two 2 inch drywell vent lines. In this flow path, the drywell pressure is vented through two 2 inch lines to the SGTS. Pressure in the torus is vented to the drywell through twelve torus to drywell vacuum breakers. The vacuum breakers operate at a differential pressure of 0.5 psi. Torus to Reactor Building differential pressure is protected by two additional vacuum breakert !f

20 the pressure in the drywell is excessive (above 62 psig), high flow may result in the vent line to the SGTS. The high flow could close the excess flow isolation dampers in the 18 inch SGTS line, resulting in flow through the single 2 i,nch bypass line around the isolation dampers.

An alternate vent path, using the 18 inch purge line was not used primarily because of the excess fiow isolation dampers. The flow through the 18 inch line would probably be excessive if drywell or torus pressure was 62 psig, resulting in excess flow isolation damper closure. With isolation damper closure, the flow would be directed to the 2 inch damper bypass line, in an attempt te protect SGTS integrity. However, the use of -

drywell purge for containment pressure control is allowed by EPG guidance step PC/P-7.

Another alternate vent path, via the two 2 inch torus vent valves, also was not used by Plant Hatch procedures. Venting through the torus is not used in case of RPV f.looding from external sources (filling the containment with water from sources outside the containment). Under this condition, the possibility of filling the 2 inch torus vent lines with water exists. If the RPV flooding condition did not exist or suppression pool level was acceptable, venting through the torus is the preferred method. By venting through the torus, the primary containment atmosphere will be skubbed in the suppression pool _ prior to venting to the environ-ment. In this way, the offsite exposures would be generally restricted to noble gases only.

Several potential problems exist with the current Plant Hatch design for emergepey venting. For example, the 2 inch drywell vent lines may not be physically capable of venting the primary containment at the flow rate needed to deal with the expected severe accident challenges of containment overpressurization. The vent lines may be inadequate for the rate of steamflow associated with dissipation of decay heat following reactor shutdown.

If fast containment venting is required, the 18 inch purge line could not be used effectively because of potential rupture of the SGTS filter trains. Also, the 2 inch excess flow isolation damper bypass line would limit the flow out of containment. Additionally, if the 2 inch drywell vent lines were used concurrently w'.th high drywell pressure, the pressure l at SGTS filter train may exceed thrt design pressure of 2 psi anyway, in conclusion, the current design and procedures used to emergengy vent the containment requires further icensee review. The vent path through the torus is considered the preferred path, with the drywell vent path as l an alternate on high water levels nside containment.

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13. Exit Interview At the conclusion of the-inspection on May 10, 1988, an exit meeting was conducted with, those persens indicated in paragraph 2. The inspection scope and findings were sumarized. The licensee did not identify as proprietary any of the meterials provided to or reviewed by the inspectors during the inspection. At the exit meeting, the licensee was requested to discuss the corrective ac'. ion to be taken as a result of the inspection findings. The licensee indic3ted that based on the NRC identified areas as well as those previously identified by other organizations as well as in their own organization that a disciplined approach would be taken to -

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address all concerns. The facility indicated that an approach would be developed, with some actions already initiated, such as contacting other utilities to determine their method of E0P usage and then a plan would be finalized. The plan will be furnished to the NRC.

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l ATTACHMENT A Documents Reviewed Flow Charts & End Path Manuals ,

31E0-E0P-001-25 REV 00 EPM 2 -

31E0-E0P-001-2S 00 EPM 3 -

31E0-E0P-001-25 00 EPM 4 -

31E0-EOP-001-25 00 EPM 5 - Section 50 __

31E0-E0P-001-2S Flow Chart 1 01 & 02 Path 1 Flow Chart 31E0-E0P-001-2S Flow Chart 2 01 & 02 Path 2 Flow Chart 31E0-E0P-001-25 Flow Chart 3 01 & 02 Path 3 Flow Chart 31E0-EOP-001-2S Flow Chart 4 01 & 2 Path 4 Flow Chart 31E0-EOP-001-25 Flow Chart 5 01 & 2 Path 5 Flow Chart 31E0-E0P-001-25 Max 00 Max Section for EPM 2 3 4 & 5 31E0-E0P-001-25 x.00 02 Cover Procedure / EPM 2 3 4 & 5 - Section 0 31E0-EOP-001-25 x.120 CCG/Supp. Pool low water control

-2.120 3.120 4.120 & 5.120 31E0-EOP-001-2S x.121 CCG/Supp. Pool high water control

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-2,121 3.121 4.121 & 5.121 31E0-E0P-001-2S x.122 CCG/Supp. Pool temp control - 2.122 3.122 4.122 & 5.122 x= Manuals 2, 3, 4 5 ,

31E0-E0P-001-25.x.123 02 CCG/Orywell press & temp control -

. 2.123 3.123 4.123 & 5.123 31E0-EOP-001-2S x.124 00 CCG/H2 control - 2.124 3.124 4.124 & 5.124 31E0-E0P-001-2S x.125 CCG/ Secondary cont temp control - 2.125 3.125 4.125 & 5.125 31E0-EOP-001-25 x.126 CCG/ Secondary cont water level control

-2.126 3.126 4.126 & 5.126 31E0-E0P-001-2S x.127 00 CCG/ Secondary cont rad control - 2.127 31E0-E0P-001-2S x.80 00 Contingencies / level restoration - 2.80 3.80 4.80 & 5.80 31E0-COP-001-2S x.81 01 Contingencies / Emergency Depressurization - 2.81 3.81 4.81 & 5.81 31E0-E0P-001-2S x 82 01 Contingencies / Alternate

' Depressurization - 2.82 3.82 4.82 & 5.82 31E0-E0P-001-25 x.83 01 Contingencies / alternate pressure control -

2.83 3.83 4.83 & 5.83 31E0-E0P-001-2S x.84 00 Contingencies / alternate shutdown cooling - 2.84 3.84 4.84 & 5.84 31E0-EOP-001-2S x.85 00 Contingencies / reactor vessel flooding -

2.85 3.85 4.85.& 5.85 31E0-E0P-001-25 x.86 00 Contingencies / alternate water injection 2.86 3.86 4.86 & 5.86 31E0-E0P-001-25 x.87 00 Contingencies / group isolation - 2.87 3.87 4.87 & 5.87 31E0-E0P-001-25 x.88 00 Contingencies / reference leg fill - 2.88 3.88 4.88 & 5.88

O Attachmer.t A 2 Alarm Response Procedures 34AR-601-302-2S--Drywell High Pressure Initiation 34AR-601-127-2F--Suppres:icn Chamber Level High 34AR-601-306-2S--Drywell High Pressure Initiation 34AR-602-144-25--Containment High Rad Or Inop 34AR-602-230-2S--Suppression Chamber Level High "RCIC" 34AR-654-080-2S--Torus Water High/ Low Level 34AR-650-233-2S--Drywell/ Torus High Pressure.

34AR-603-115-25--Primary Containment High Press.

34AR-603-106-2S--Primary Containment High Press. Trip _

Abnormal Operating Procedures 34AB-0PS-002-2S--Small Break Inside Primary Containment 3449 0PS-034-25--Torus Temperature Above 95 deg.

34AB-0PS-007-2S--SRV Stuck Open Miscellaneous:

Human Engineering Difficiencies Summary from the DCRDR Resp'onses to V & V Document Comments Other Documents s

.DI-0PS-22-0287N Temporary E0P Flow Chart Change. Rev 0, 5/4/87, 10AC-0PS-004-05 Emergency Procedures (Writer's Guide). Rev 1. 2/14/88.

30AC-0PS-006-05 E0P Verification Procedure. Rev 0.10/17/85. Plant Hatch.

30AC-0PS-007-0S Emergency Operating Procedures Revision Requirements.

Rev. 2. 5/29/87. Plant Hatch.

AG-ADM-14-1184N Administration of Procedure Reviews. Rev 1. 4/8/88.

Plant Hatch.

ATM-0012 Rev. O Procedure Review Forms dated 1/7-8/88. Annual review of Unit 2 E0Ps.

E0P Implementation Plan for Emergency Response Capability Project. Rev 1.

8/2/85. Plant Hatch.

Meeting Summary on Information Presentation to NRC, EPRI, INP0 on Georgia Power Company - Plant Hatch Emergency Operating Procedures Upgrade Program and overhead projection transparencies. April 25, 1935.

Paul Springer, Ill. Georgia Power.

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Attachment A 3 Human Factors Review of Plant Hatch 'EOP Flowcharts. Status Report.

November 15, 1984. General Physics Corporation, Columbia, Maryland.

Edwin I. Hatch Nucicar Pcwer Plant Control Recm Emergency Operating Procedures Validation Report. January 17, 1986. General Physics Corporation, Columbia, Maryland. ,

Response to Plant Hatch E0P Validation Study Coninents. C. Land and R. Knoble. March 24, 1986. Georgia Power interoffice correspondence to J. R. Jordan.

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31E0-EOP-001-25, Emergency Operating Procedure Inside Control Room Unit 2, Containment Control Guideline Drywell Pressure and Temperature Control, Procedure 3.124, Revision 2.

31E0-E0P-001.15, Emergency Operating Procedure Inside Control Room Unit 1, Containment Control Guideline Drywell Pressure and Temperature Control, Procedure 3.124, Revision 2.

34S0-E41-001-25, High Pressure Coolant Injection (HPCI) System, Revision 5 34S6-E51-60:.-25, Reactor Core Isolation Cooling (RCIC) System, Revision 6 .

y- .e .. - -

, _4 _ , _ , . .-. . - - , - _ _ _ - - _ _ _ . , _ _ _,,r , _w .

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o ATTACHMENT B Plant Walkdcwn Ccmments A. E0P Equipment Cabinet ,

An inspection of the Unit 2 Emergency Operating Procedure (EOP) equipment cabinets was performed. One normally locked filing cabinet was noted to contain emergency procedures, end path manuals, jumpers filed by component to be jumped, phone, bolt cutters, and several rings of keys, including 1.

keys to the remote shutdown panels. The two equipment cabinets (large tool boxes) contained hoses, fittings, tools and meters required to perform emergency system manipulations. Also noted in the vicinity of the cabinets were tables and ladders needed .to support emergency operations.

The cabinets were noted to be wire sealed, organized and contained only equipment (identified by the color pink) necessary for use in an emer-gency. The NRC inspector expressed a concern over the security of the keys in the filing cabinet. The operators stated that the filing cabinet (a standard office type cabinet with a single lock in the upper right hand corner) was located in a vital area (security controlled access area) and the ,cabine_t lock was sufficient security. The operator also stated the cabinet was inspected weekly for inventory of contents.

B. End Path Manuals ,

A walkdown was performed en the procedures written to vent the containment during.an emergency. Containment Control Guideline, Drywell Pressure and Temperature Control (Procedure 3.123), provides instructions on contain-ment venting. Both Unit 1 and Unit 2 procedures were reviewed. The Unit 1 procedure is generally identical to Unit 2, but only Unit 2 procedure consnents are listed below.

1. In Procedure 3.123, the purpose of step 3.26.2 (determine hydrogen-and oxygen concentrations) prior to containment venting was not clear.

2. Step 3.26.5 instructs the operator to override all signals to all valves, including valves that will not be used. The step 3.26.5 does not clearly indicate which valves will by bypassed.

3. Step 3.26.6 instructs the operator to reset the Group 11 isolation signal. This is an unnecessary action to open the valves (step 3.26.7). The step 3.26.6 appears to be inappropriately located near step 3.27.4, when the valve override signals are removed.

4. Step 3.5.1 instructs the operator to lift leads at an electrical bus.

The bus frame numbers were not listed in step 3.5.1.

5. Step 3.27.1 tells the operator to place a bypass switch in the NORMAL position. The switch is actually labelled AUT0-BYPASS.

1

. 2 l

1 i

6. EPM 4.122 steps 3.1.1-3.10.5 are not required in E0Ps. l

7. When the EPMs are used in a real situation, they are signed and marked upon. The facility does not have procedures or processes formally ia place to assure the manuals are restored to their original content after use ,

C. Operating Procedures Flow Path 1 instructs operators to inject boron into the RPV using HPCI _.

and RCIC, if available, on failure of Standby Liquid Control. The two procedures, 3450-E41-001-25, HPCI system, and 34S0-E51-001-25, RCIC '

system, were reviewed and walked down to assure the procedures could be performed.

1. Several plant labels were noted to be different from the procedure steps. For example, the valve 2G31-F106 (HPCI procedure step 7.4.8.9.1) is called the RWCU Precoat Pump Suction Valve in the '

procedure, but is labelled the Precoat Tank Outlet Valve Z on the local panel.

2. HPCI step 7.4.8.3 incorrectly lists.2E41-R612 as 2E41-K615,

3. HPCI step 7.4.7.10 incorrectly lists 2H11-P601 as 2H11-P602.

4. A comparison of HPCI to RCIC procedures identif'ied several inconsis-tencies. RCIC step 7.3.9.8.13 lacked the statement "using one of the following valves" to agree with HPCI step 7.4.8.9.13. In the HPCI procedure, the 2C41-F034 valve is assumed to be a locked closed valve, while the parallel valve is not locked in the RCIC Procedure.

The same logic step in HPCI (step 7.4.8.19) and RCIC (step 7.3.9.17) sends the operator to different steps in the RCIC or HPCI Procedures.

The RCIC pror,edure (steps 7.3.8.14 and 7.3.9.14) has a note to turn valve power off, while HPCI procedure (steps 7.4.7.16 and 7.4.8.16) does not have the same note.

5. The HPCI procedure requires operators to throttle valves to initiate boron flow. Step 7.4.8.16 throttles 2E41-F041 while step 7.4.7.16 throttles 2E41-F042.

6. RCIC procedure step 7.3.8.8.5 does not list 2C41-F015 as a valve to throttle to maintain baron level.

7. RCIC steps 7.3.8.12, 7.3.8.18.1, 7.3.9.12 and 7.3.9.23.1 list the wrong electrical frame numbers.

8. RCIC steps 7.3.9.20 and 7.3.9.21 list wrong steps to be repeated.

9. The precoat level instrumentation was not restored in HPCI step 7.4.8.25 and RCIC step 7.3.9.26.

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Attachment B 3

10. Instructions were not found to flush HPC1/RCIC following boron injection.

D. Fluw Charts The most outstanding concern noted throughout the flow chart was associ-ated with plant labelling. Numefous discrepancies between wording and actual plant labels were noted, including: certain switch positions were described as OPEN-CLOSED, but actual positions are NORMAL-SCRAM in the control room; system designators for 2B21 switches are labelled as B21B in the control room; and uses the words suppression pool while the m.

same items are called torus in the control room.

Path 1

1. The statements "If installed" shou 1d be deleted from steps in Note 30, grid A-3 and grid J-7.

2. Pump 2E21-C003 is incorrectly listed as 2E21-B003 in grid F-5.

3. Steps in Note 16 are misnumbered (missing step 2.b).

4. In Note 16, step A.1, change system I/II to A/B.

5. Frame locations are missing in step B.1.b for locations of jumpers /

lifted leads to be installed.

6. In Note 4, only the TB1-12 tennination has to be lif ted to allow 2P70-F005 to fail open.

7. The numerical value the operator may have to read on analog meters is more precise than meter increments will allow. For example, 76 psig or 88 psig has to be read on the wide range pressure meter, which has 20 psi increments on the meter scale. Temperatures of 157 degrees or 58 degrees F have to be read on the suppression pool temperature meter which has 5 degree increments. Reactor vessel levels of 31 inches and 97 inches are to be read off a meter which has 10 inch increments. If SPDS or the process computer are available, the numerical values of the above readings can be observed in digital form. If not available, the operator reading of analog meters would result in approximate values.

8. Steps in grids F-1 and H-8 instructs operators to install pressure gauges on either RPS rack, if necessary. The step appears unneces-sary since each rack already has pressure gauge meters installed on them.

9. Step in grid C-8 instructs operator to close or verify closed valves without telling the operator the valves are operated locally only.

4 Attachment B

10. The NRC inspectors observed the operator searching to find specific diagnostic screens on SPOS. Adding the specific SPDS screen numbers to Path 1 steps that refer operators to diagnostic displays would aid the opera. tors in an emergency.

11. Notes 3 & 4 do not include the CRD as per the PSTG.

12. The Top of Fuel Level was not plainly indicated or easily determin-able on the Control Room recorder.

Path 3

1. Valves listed in procedure as "2T48-F026" and "2T48-F027" were on the panels as "2T48-MOV-F026" and "2T48-M0V-F027." This was found in other cases on Path 3. .

2. Grid 1-J, an example of an inconsistency was found in that various valves listed in the procedure (ie 2E11-F047, 2E11-F003...) have the number "2" at the beginning of the valve no. (The "2" stands for Unit 2). The values in the above grid did not have the "2" in front of the valve number on the panel.

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3. ' Grid 1-X, procedure step states: "energize steam pressure reducing valve pilot solenoid 2E11-F051 by placing mode switch on"

- The switch has open/close positions in lieu of as indicated in the procedure

- The switch is labeled as E11-F051,53 in lieu of "2E11-F051".

4. Group 3E isolation valves 2C51-J004A, B, C, D are not labeled on the TIP drawers.

Path 4

1. Grid C4, the E0P flow chart instructs the operator to "Place switches for all stuckopen SRV's to open then close. This is inconsistent with Abnonnal procedure 34AB-0PS-007-25, which does not call for this action. There is no close position on ADS SRVs, only "open" and "auto."

2. Grid C-3, the SRV cycling sequence used in the E0P is not the same as the sequence specified on the SRV panel in the control room.

Specifically, the "E" and the "H" SRVs are not listed on the control room panel.

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ATTACHMENT C Human Factors Analysis Examples The following examples are provided to clarify the types of concerns identified in the eight areas of human factors concerns described in section 8 of this report. These examples are not intended to be viewed as an inclusive list of all such concerns found in the Plant Hatch E0Ps, but rather as examples of the types of inadequacies identified through the human factors analysis.

2 (1) Movement (Transitions)

(a) Excessive transitions The Plant Hatch E0Ps were found to"contain transitions so numerous that the resultant movement within and between procedures increases the possibility of error by operators exercising the E0Ps. For example, within any flowchart operators are required to (1) move through flowpaths that include extremely long flowlines between columns; (2) scan the entire flowpath before beginning to perform

, actions in order to check for sequence insensitive steps; (3) move to the right and left sides of the flowchart to read notes and l cautions ref.erenced in the flowpaths; (4) move backward in flowpaths to monitor key parameter steps; (5) move backward in flowpaths to monitor path specific parameter steps; and, (6) move within and between flowcharts and EPMs as directed by referencing and branching instructions.

(b) Excessive number of transition methods Transitions are indicated through multiple methods. For example, EPM 4.40 includes seven different methods of directing transitions. No differentiation between th~i different methods is provided in the writer's guide nor are they clear from their use. Within flowcharts, movement is also indicated through the use of path-to-path arrows and directives within action steps.

(c) Unclear transition methods Movement through flowcharts is directed through extremely long flow-lines, running parallel with other flowlines tha.t do not share the same destination. No direction indication is given, and the lines are so close that it is difficult to remain on the correct line.

When different color flowlines run parallel, contrast is sometimes insufficient to aid in differentiating the two lines.

Attachment C 2 (2) Decisions (a) Excessive number of decisions Within th'e Plant Hatch E0PS, required decisions are indicated by two types of decision symbols, along with sequence sensitive action steps, sequence insensitive &ction steps, notes, cautions, and logic sequences within EPMs action steps and flowchart action steps. Within Path 4, approximately 40 percent of all steps require decisions. In addition, decision symbols on the flowcharts must be remembered and decision making repeated, should conditions change. n (b) Inconsistent decision formats The decision directives within these steps and symbols are written in inconsistent famats. In decision symbols, sometimes the decision is worded as a question, other times it is worded as a statement. Logic terms such as IF, WHEN, and THEN, are used in the flowcharts in a manner inconsistent with that defined for use in the EPM (e.g., Path 4, area 7-D). Not only is this use of logic statements within action steps on the flowcharts inconsistent with that in the EPM, but it

, fails,to utilize the decision symbols provided for use in the flow-charts.

(3) Memory Requirements ,

(a) Excessive memory requirements The Piant Hatch E0Ps contain many steps that require the operator to remember step content for all or part of the execution of the procedure.

For example, all key parameter decision steps must be remembered while in the E0F system, that is, the flow chart and any EPMs referenced. In addition, all path specific parameters must be remembered throughout the path in which they are included. All sequence insensitive steps must be remembered after an initial scanning, so that they can be executed at any time prior to their location on the flowline. Cautions and notes are reported to often be used through memory alone.

(4) Cautions and Notes (a) Inadequate fonnat distinction between cautions and notes l

Because of the critical nature of information contained in cautions, it is particularly important that they be (1) properly emphasized to catch the operators attention, and (2) distinguished from the non-l l critical information contained in notes. In the Plant Hatch E0Ps, cautions and notes in the flowcharts are emphasized in exactly the same manner. Within the EPMS, cautions are bordered on top and bottom by a solid line, in contrast to a dotted line used to encircle l

l l

Attachment C 3 notes. In neither case is the distinction between notes and cautions considered adequate, in the flowcharts, placement of some cautions along the perimeter of the flowchart with the notes could also lead to them being overicoked by the operator.

(b) Incorrect content ,

' Cautions are intended to contain critical infonnation relating to potential injury or equipment damage. Notes are intended to contain supplemental information that may be of use to the operator. Neither are to contain operator actions. Throughout the Plant Hatch E0Ps, n.

cautions and notes are found to (1) contain operator actions (e.g.,

Path 4, cautions 17 and 20; notes 23 and 24) and (2) be mislabeled (e.g., cautions as notes; notes as cautions. See Path 4, cautions 1, 2, and 20. In addition, most cautions or notes containing cautionary information did not identify the potential hazard.

Also, relative to the problem of excessive detail in the procedures, some information included in notes and cautions was so basic that it appeared unnecessary to include in the procedure.

(5) Grap,hics ,

Graphics methods . employed in the production of the Plant Hatch flowcharts have contributed a number of problems. For example, print size on the mid-sized flowcharts is estimated to be apprcximate>ly one-third of the minimum size required by application of human factors engineering princi-ples. .The use of color is not only reported to be of no use to operators, but entails colors which do not provide adequate contrast and, in fact, make the flowcharts more difficult to read. Use of all capital letters not only is more difficult to read, but eliminates the use of all caps for emphasis. The type of laminate.used on the flowcharts causes glare, requiring operators to flex the flowchar.ts in order to read them. In addition as observed in the control room the reproduction quality of the EPMs was poor and in conflict with the Plant Hatch Writer's Guide and NUREG-0899, since the quality of the copies was not equal to the quality of the originals.

(6) Sentence Structure Structure of steps within the Plant Hatch E0PS include a number of problems which contribute to difficulty in understandability, useability, and the excessive level of detail, in addition, these problems are generally in conflict with guidance provided in NUREG-0899. For example, many stops are written in an overly complex structure, including supple-mental phrases that are unnecessary for the execution of the action (e.g.,

Path 4 section L-1, K-5, X-9, caution 17). Related to this issue, many Plant Hatch staff indicated that complete sequences of steps within the procedures were unnecessary for execution of the actions required.

I l

l

4 Attachment.C In conflict with the Plant Hatch Writer's Guide, imprecise adverbs (e.g.,

slowly, rapidly) and terms (e.g., as required, if installed) are.used within the procedures (e.g. , Path 1, sections K-16, B-14). Sentence structure is a.lso used inconsistently throughout the E0Ps. For example, logic tenninology is sometimes used incorrectly (e.g., Path 4, sections N-2,N-3). Sentences sometimes begin with the action verb, but in other cases the acticn verb-is buried within the sentence or completely missing (e.g., Path 4. section K-2, Path 5, sections 0-1, 0-3),

(7) Writer's Guide The Plant Hatch Writer's Guide does net provide sufficient nor adequately

• restrictive guidance to result in consistently prepared and revised, high-quality E0Ps. For example, the guidance provided in Section 8.3 for preparation of the EPMs and cover procedures contains guidance on general writing techniques. However, Section 8.2, Organization of Flow Charts, does not include guidance on the writing of individual steps. . As noted above, this is a problem area within the E0Ps. In addition, the guidance that is provided is in some places is vague and non-restrictive. For example, writers are directed to use language "such as," (go to), to indicate branching within an EPM. This lack of restriction has led to incpnsistqnt use of multiple indications to the operator that a transition is to be made. Related to writer's guide inadequacies, the acronyms and abbreviations proyided in the PSTG are not consistently applied within the E0PS.

The nature of the Plant Hatch E0P system requires that ARPs, A0Ps, and EPIPs .be used during execution of E0Ps. The writer's guide does not provide guidance for consistent fonnatting, structure, and control of the entire family of E0Ps and related procedures. As currently managed, these procedures are not maintained properly for use during emergencies. Torn pages, missing tabs, and insufficiently emphasized binders make the ARPs, A0Ps, and EPIS inadequate for easy access and use by operators.

(8) Miscellaneous A number of miscellaneous inadequacies were identified in the Plant Hatch E0P system. Some are:

(a) Physical aspects of the control room and EPMs Current physical structure of the control room does not provide adequate desktop space for use of the flowcharts.and EPMs, along with the satellite procedures required during their use. During simulator exercises, binders were piled upon each other and flowcharts were propped against the tabletop, promptly falling to the floor. This condition could lead to delay and error during execution of the E0P.

l l

Attachment C 5 The binder used for the EPM is designed in a manner that results in part of the book sitting on top of a telephone in the control room, which is awkward and could lead to problems in using the procedures.

In additi.cn, the EPM binder in its current form includes two sections which open backwards and include sections that are numbered back-wards. This is in conflict with comon Western use and experience and could lead to delay and error.

(b) Acronyms and abbreviations, in addition to deviating from those listed in the PSTG, were used inconsistently throughout the E0PS.

(c) References to the flowcharts were inconsistent, ranging frem "the flowcharts" to "31E0-E0P-001-05."

(d) Placekeeping spaces provided in the EPMs were placed on the right side of the steps, rather than at the step number. When a step is longer than one line, this method could lead to confusion about exactly which step had been performed.

(e) The writer's guide lacked a sufficiently complete list of approved action verbs.

(f)" Yes/no exits from decision symbols on the flowcharts were incon-sistently plAced. .

G

/

y _ _ _ .

@@M@M C .

MAY 1'T 1983 .

Docket Nos. 50-321, 50-366 License Nos. OPR-57, NPF-5 G9ergia Power Company MTTN: Mr. George F. Head Senior Vice President-P. O. Box 4545 Atlanta, GA 30302 Gentlemen: ~.

SUBJECT:

NRC INSPECTION REPORT NOS. 50-321/88-13 AND 50-366/88-13 This refers to the Nuclear Regulatory Comission (NRC) inspection conducted by W. J. Ross on April 18-20, 1988. The inspection included a review of activities authorized for your Hatch facility. At the cunclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed inspection report.

Areas examined during the inspection are identified in the report. Within these , areas .the ' inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

Within the scope of the inspection, no violations or deviations were identified.

In accordance with Section 2.790 of the NRC's "Rules of Practice," Part 2, Title 10, Code of Federal Regulations, a copy of this letter and its enclosure will be placed in the NRC Public Document Room.

Should you have any questions concerning this letter, please contact us.

Sincerely, Douglas M. Collins, Chief Emergency Preparedness and Radiological Protection Branch Division of Radiation Safety and Safeguards

Enclosure:

Inspection Report -

cc w/ encl: (See page 2) x\ \

d'db , b U1 a oco ,.

x . - __

Georgia Power Company 2 ce w/ encl:

tJ_ ,. '. Beckham, Vice Presiden',, Plant Hatch M C. Nix, Plant Manager MM. Fraser, Site Quality Assurance (QA)

Supervisor W. Gucwa, Manager, Nuclear. Safety and Licensing bc3 w/ encl:

4tfC Resident Inspector DRS, Technical Assistant -

t)Rfgh S. Jordan, Executive Secretary Document Control Desk State of Georgia I

RI! RII RII do7s hKe MSinkule ff/I)/88 3713/88 4/[)/88 4

. UNITED STATES

• [po *t s,'*t, NUCLEAR AEGULATORY COMMISSION -

.s

• t REGION il

j. 1 .: j to1 MARIETTA STREET. N.W.

• ATLANTA. G EORGI A 3o323

, g

s ' '..../ MY 171988 Report Nos.: 50-321/88-13 and 50-366/88-13 Licensee: Georgia Power Company P. O. Box 4545 Atlanta, GA 30302 Docket Nos.: 50-321 and 50-366 License Nos.: OPR-57 and NPF-5

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Facility Name: Hatch 1 and 2 ~

Inspection Conducted: April 18-20, 1988 Inspector:

M'

^

W. J. Ross

?)( l 5 S//)

Date Signed Approved by: 'M M l c_/ I J. Bf Kanie, Sect 16n Cntef s 7/JG Date Signec Otvision of Reactor Safety SUK%RY Scope: This routine, unan'nounced inspection was conducted in the areas of 4

hydrogen water chemistry and plant chemistry control.

Results: No violations or deviations were identified. ,

i l

, eem7m g7 77w,,

FDR ADOCK 05000321' O DCD

I

. s REPORT DETAILS ,

1. Persons Contacted Licensee Employees B. Arnold, Chemistry Supervisor R. Bryant, Staf f Chemist R. Dedrierson, Assistant to the Vice-President / Hatch _

B. Feimster, Chemistry Foreman "W Kirkley, HP/ Chemical Engineering "V. McGowan, Chemistry Supervisor W. Rogers, Chemistry Superintendent S. Shipman, Systems Engineer R. Tracey, Systems Engineer "P. Read, Plant Support Manager

• 0. Self, Nuclear Superintendent Other Organizations M. Terrell, General Electric Company NRC Resident Inspectors P. Holmes-Ray, SRI .

"J. Menning, RI

• R. Musser, R1

• Attended exit interview

2. Exit Interview The inspection scope and findings were summarized on April 20, 1988, with those persons indicated in Paragraph I above. The inspector described the areas inspected and discussed the inspection results. No dissenting comments were received from the licensee.

In response to a request by the inspector for clarification of actions taken in response to findings by the Institute of Nuclear Power Operations (INPO), the licensee provided information that was considered proprietary to INPO. This subject is not included in this report.

3. Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspection.

L

s 2

4, Hydrogen Water Chemistry This phase of the inspection was a review of actions taken by the licensee since the last inspection in this area (see Inspection Report Nos. 50-231; 366/87-03 dated February _11,1987) to implement a hydrogen water chemistry (HWC) program to control initiation and/or growth of intergranular stress corrosion cracking (IGSCC) in the reactor coolant recirculating piping.

This review consisted of discussions with personnel from the licensee's Chemistry Department and Systems Engineering Department as well as with the General Electric contractor who was operating the current hydrogen and oxygen injection system in Unit 1. In addition, the inspector walked down ~

the current system and the proposed pipe runs for permanent injection systems for both units,

a. Status of HWC for Unit 1 Beginning in February 1987 the I censee had performed a second HWC test for approximately ten weeks ;o establish optimum conditions for preventing IGSCC while minimizing radiation icvels caused by carry over of volatile nitrogen-16 spec.ies with the steam. Likewise, beginning September 1987 Unit 1 had been operating in the current fuel cycle using HWC control. As occurred in the initial feasibility tests, the results of the second test we.re inconclusive in that a stable corrosion potential between stataless steel and the reactor coolant could not be established through the reduction of dissolved oxygen by a hydrogen flow rate as high as 44 SCFM.

At a rate of 44 SCFM of hydrogen the radiation level at critical parts of the plant was as much as four times the levol under normal (non-HWC) conditions. Consequently, during most of the test and during the current fucl cycle the injection rate of hydrogen had been reduced for 22 SCFM. At this rate the radiation levels were as much as twice normal background. Also, at this injection rate the concentrations of dissohqd oxygen in the feedwater and recirculatory water were 220 ppb and 6 ppb resNetively. The electrochemical potential of stainless steel stabiitzed within the range of 10 millivolts versus a standard hydrogen electrode (SHE). This electrochemical potential is considerably more positive than the 230 iny range recommended by the BWR owners group for prevention of IGSCC.

The inspector was informed that a permanent HWC procedure was being developed based on an injection rate of 22 SCFM with the expectation that crack initiation or crack growth will be significantly hindered even *. hough optimum conditions are not attainable. In the interim, Special Purpose Procedure "Hydrogen Injection and Control" was being followed to govern the addition of hydrogen to reactor feedwater.

This procedure also covered the addition of oxygen into the common offgas line downstream of the third stage Steam Jet Air Ejector to assure an oxygen-rich mixture in the recombiner. This interim procedure also provided for personnel requirements, coordination with

3 I

the Operations Department, as well as for operating and safety precautions and authorization. The injection system was being monitored and operated by General Electric contract personnel.

The inspector verified that Technical Specifications (Tables 3.2-1 and 3.2-8) nad been revised to allow the trip setting of the Main Steam Line Radiation Monitor to be maintained at 53 times normal full background under the following conditions:

"Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the planned start of the hydrogen ,

injection test with the reactor power at greater than 20% rated power, the normal full power radiation background level and associated trip setpoints may be changed based on a calculated value of the radiation level expected during the test. The background radiation level and associated trip setpoints may be adjusted during the test based on either calculations or measurements of actusi radiation levals resulting from hydrogen injection. The background radiation level shall be determined and associated trip setpoints shall be set within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of re-establishing normal radiation levels af ter completion of

, hydrogen injection and prior to establishing reactor power

. - levels below 20% rated power."

An operations standing order had been implemented to assure that these setpoints were properly coordinated with power level.

The inspector walked down the lines of the current HWC injection system from the skids for hydrogen and oxygen cylinders to the penetrations for the hydrogen lines at the suction of the three condensate booster pumps. Injection flow was being controlled at a panel in the Unit 1 Turbine, and hydrogen was being injected at a rate of 24 SCFM and oxygen of 12 SCFM. Hydrogen could be manually isolated if the reactor tripped or was isolated, or if the injection rate exceeded 35 SCFM. The isolation valve panel was being monitored by hydrogen analyzers that would also isolate hydrogen flow if the 3 atmospheric hydrogen concentration exceeded two percent. Finally, hydrogen flow would also be isolated if the concentration of oxygen in the discharge of the hydrogen-oxygen recombiner in the condenser air ejection system is <5%.

b. Permanent HWC System The inspector reviewed the licensee's plans for installing a permanent HWC injection system and established the following facts:

Plans for initiating HWC on Unit 2 were being postpone" until the effectiveness of IGSCC control in Unit I could be established.

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• i 4

Designs for a permanent injection system were being developed by Southern Company Services and construction was to begin in June 1988. These designs are based on recommendations published by the Electric Power Research Institute (EPRI) and appropriate fire protection codes.

Use of the permanent system is scheduled to begin after the next Unit I refueling outage in the fourth quarter of 1988.

• Hydrogen will be stored as a liquid in.a 20,000 gallon tank and -

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oxygen will be stored in a 9000 gallon tank. These tanks are to be located outside the Protective Area fence at the southeart corner of the plant site, approximately 1000 yards from the power block.

Both hydrogen and oxygen will be pumped as gases through stainless steel lines (1h inch for oxygen and 1 inch for hydrogen) buried below the frost line (i.e. ~18 inches deep) in a single trench from the cryogenic tanks to the west cableway at the south end of the plant's . turbine building. The hydrogen line will be enclosed in a carbon steel guard pipe whenever the

. . line passes under a road or rail road. Within.the west cableway the lines will be reduced to 3/4 inch diameter and routed to the existing isolation panels and then to existing penetrations at the suction n' ondensate booster pumps and at the air ejector lines. Hydet monitors are to be installed in the guard pipes that will enci. a the hydrogen lines throughout the unventilated cableway. '11 joints will be welded.

Purge valves will be installed at the condensate booster pumps so that hydrogen lines can be purged in a backwards direction if required.

The license'e's plans were considered to be consistent with guidance provided by the NRC (see letter dated July 13, 1987 from James E. Richardson, Office of Nuclear Reactor Regulation to l

Mr. G. H. Neils, Chairman Regulatory Advisory Committee, BWR Owners

Group II for IGSCC). However, the inspector reemphasizcd the need to l take maximum precautions to design and operate the hydrogen and oxygen injection systems so as to minimize leaks and to maximize surveillance for leaks, especially in regions of the plant with poor ventilation.

As part of the permanent HWC installation the licensee had also acquired a Crack Arrest Verification (CAV) system which will be used l to monitor the effect of HWC on three representative stainless steel coupons, and, thereby, monitor the effectiveness of HWC control. In addition, two new inline monitors for dissolved oxygen had been installed to increase the licensee's capability to determine and to ,

trend the oxygen concentration in the condensate and feedwater. I Finally, in a ef fort to establish the effect of metals (dissolved and

5 soluble) c1 HWC, three inline corrosion product samples had been installed to monitor water in the hotwell (especially for corrosion products from the brass condenser tubes), in the condensate polisher effluent, and in the feedwater. As will be discussed later, the instability of the electrochemical potentials observed in the recirculating water when hydrogen was injected into the feedwater had been attributed, in part, to the presence of metallic species in the reactor water and recirculating water.

5. Plant Chemistry n.

Through discussions with cognizant plant personnel and through an audit of chemistry control data the inspector reassessed the licensee's ability to prevent degradation of the reactor coolart pressure boundary. This part of the inspection consisted of a review of the design and operation of key components of the reactor water system and the implementation of the licensee's water chemistry program,

a. Plant Design and Operation During the fif teen month interval since the last inspection in this area, both units had operated in stable modes except during refueling outages (April - June 1987 for Unit 1 and January - April 1988 for Unit 2). Except for four brief (1-2 days) shutdowns, Unit I had operated at 100% power and, most of the time, with hydrogen water chemi stry control . Although Unit 2 only had three short shutdowns, the licensee had decreased the power level of this unit to 90% in l May 1987, and to lower levels since October 1987, because of fuel iailure problems.

l Althouch air '11eakage had remained higher than desired (~15-40 SCFM in Unit 1 and ~15-20 SCFM in Unit 2) the main condensers had provided effective barriers against ingress of condenser coohng water. Only one tube leak had occurred, and' this leak had been caused by mechanical damage rather than by corrosion mechanism. The licensee attributed the integrity of the main condensers, in put, to a

program of visual and eddy current tests performed during refueling outages.

l The principal concern with the main condensers was still the continual loss of metal from the condenser tubes as soluble and/or

'asoluble species of copper and zinc. In an effort to prevent these metals, especially copper, from being transported to the reactor, the l

licensee had attempted to enhance the efficiency of the condensate polishers in Unit 2 by increasing the length of the filter-demineralizer tubes from 70 inches to 80 inches. Also, ' body-feed' technique of continually adding thin layers of ion-exchange resins to the filter-demineralizer elements was still in use. This technique had extended the intervals between proecoating (complete

, removal and replacement of resin from the tubes) to approximately three weeks; thereby, conserving water, resin, and manpower.

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6 However, an audit of analyses of effluents from the polishers, as well as analyses of feedwater samples, showed that measureable amounts of cooper (~0.3 ppb) were still pa. sing through the demineralizers and into the reactor, where the copper i s a concentrated by a factor of ~100.

Both Hatch units have experienced fuel rod failure as the result of corrosion and embrittlement of zircaloy cladding attributed to

' copper crud' (see Inspection Report 50-321;366/84-06 dated March 23, 1984). The presence of easily reduced species of copper has been considered by the licensee to also contribute to the instability of ~1_

the electrochemical potential of the reactor water and the recirculating water when hydrogen is injected to reduce dissolved oxygen (see Paragraph 4a of th s report). Consequently, the licensee has an ongoing program to reduce the concentrations of both soluble and insoluble copper in the feeawater.

From the audit of control and diagnostic chemistry variables the inspector observed that trace (0.1-1.0 ppb) amounts of soluble iron, zinc, and nickel were also being . transported into the feedwater.

This magnitude of iron and nickel is not considered to be a significant contributor to the loading of the reactor with oxide sludge. Recent investigations by EPRI have shown that the presence of trace amounts of zinc in the reactor water acutally is beneficial to the maintenance of low ex-core radiation levels throughout the reactor coolant system and does not pose a corrosion hazard.

The Chemistry Groups's capability for monitoring general corrosion'of the brass condenser tubes as well as carbon steel and stainless steel pipe throughout the reactor coolant system had been enhanced by the installation of corrosion product samplers for Fotwell water, polisher effluents, and feedwater.

The inspector alsc established that although the licensee had not encountered micro or macro cialogical problems in the Service Water systems, two intrusions of raw river water into closed cycle cooling systems had occurred through ceat exchancers cooled by Service Water.

One of these leaks contarinated the Unit 1 Recombiner Closed Cycle Cooling Water System.

The other leak contaminated the water in the Suppression Pool of Unit I with approximately 0.5 ppm cf chloride and 300-400 ppb of silica; thereby, exceeding administrative limits of <50 ppb chloride and <100 ppb silica. At the time of this inspection the licensee had not begun to reduce the levels of these contaminants. The inspector was informed that the reason for the delay was because an efficent cleanup method had not been settled on. The radwaste system had a capacity of about 2000 gallons per week while thc. Torus water volume was over 600.000 gallons. The licensee was considering the use of a demineralizer system that could be used to cycle and cleanuo this volume of water. Although the walls of the carbon steel Torus were v- , . - y- ++----a e -, -,.,w n ~w-

. 7 supposed to be coated with paint, the inspector emphasized the potential for corrosion when carbon steel is exposed to water with dissolved oxygen, detectable chloride concentrations, neutral pH, and, especially, in a stagnant condition.

Finally, the inspector was informed that the discrepancies in the cont;entrations of corrosion inhibitor (sodium nitrite) in the Reactor Building Closed Cycle Water (RBCCW)(as shown on the HP/ CHEM Daily Report) was caused by leaks in pump seals that depleted the treated water. Because of difficulties involved with the cleanup or disposal _

of nitrite-containing water, the licensee had chosen to discontinue ~

addition of the corrosion inhibitor until the pump problem was corrected. The licensee was aware of the potential for degradation of the carbon steel pipe in the RBCCW unless all dissolved oxygen in the cooling water was eliminted.

b. Water Chemistry Program The inspector reviewed the following elements of the licensee's water chemistry program

, _ Staffing Training Physical Facilities Quality Control Program (1) Staffing -

Since the last inspection in this -area the organization reporting to the Manager-Health Physics / Chemistry had been modified so that th en Superintendents (Health Physics, Chemistry and HP/ CHEM Support) provide a secondary line of supervision. The Chemistry Group was divided under two Supervisors, one for instrumentul analysis and the second responsible for all other r hemistry activities. The analytical staff, eight foremen and thirty-four technicians, was divided into five rotating shif ts and one day shift. The inspector was informed that the rotating shifts would soon be of twelve hours duration rather than the current eight hours.

The professional staff under the Superintendent / Support included chemists 'and chemical engineers who not only provided daily support but who also had responsibilities for upgrading capabilities and initiating HWC.

(2) Training - The stability of the Chemistry staff continued to improve during the interval since the last inspection in this area. Consequently, the licensee had been able to continue with its formal training (classroom) programs as well as with the on-the-job qualification program. - An average of two weeks out of every ten was being dedicated to training.

8 (3) Physical Facilities - By means of a walkdown of sampling rooms and laboratories the inspector reassessed the facilities available to perform the respansibilities of the water chemistry p r'og ram. During the last year the licensee had developed an instrument laboratory separate from the existing hot laboratory.

This additional space permitted more effective use of the ion chromatography systems, but, because of inefficient venting, could not be used for atomic absorption spectrometric analysis.

As mentioned earlier, the sampling rooms for both Units had been upgraded with inline monitors for oxygen, conductivity, and __

corrosion products. -"

(4) Quality Control - This element of the water chemistry program was reviewed through observations and discussions with the Instrument Supervisor, Instrument Foreman, and technicians in the Instrument Sub Group while these personnel were involved in the analysis of a series of unknown standards that had been provided by the inspector. These standards consisted of aqueous solutions of the key chemistry ionic variables that have been identified for the control of. BWR chemistry by the BWR Owners Group (i.e., chloride, sulfate, . silica, iron, copper, nickel,

. . chromium, and sodium). These solutions were prepared in ppm concentrations for the NRC by the Brookhaven National Laboratory and were to be analyzed by the licensee!s usual procedures after dilution to concentrations similar to routine control and diagnostic values. ,

Although some analyses had been completed and evaluated by the inspector before the end of the inspection, the results of all analyses will be presented in a supplemented Inspection Report.

IFI 50-321/88-13-01; 50-366/88-13-01 (5) Conclusions Violations or deviations were not identified during any phase of this inspection. The inspector verified that the Technical Specifications pertinent to chemistry control had been met. The steps being taken to implement HWC, to upgrade the design and operation.of key plant components related to chemistry control, and to further improve control and diagnostic capabilities were considered to be acceptable and to indicate a commendable understanding of corrosion mechanisms and industry approaches to this prevention. -

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. UNITEO ST ATES NUCLEAR REGut.ATORY c0MMisSION

[MesonD e,3 ,

CeGION il 101 M ARIETTA STREET, N.W.

I El ATLANTA, QtoRGI A 30323

• • "*' JUN 16 1989 Oceket Nos. 50-321, 50-366 License Nos. OPR 57, NPF-5 Georgia Power Company ATTN: Mr. R. P. Mcdonald Senior Vice President- -

Nuclear Operations ~

P. O. Box 4545 Atlanta, GA 30302 Gentlemen:

SUBJECT:

NOTICE OF. VIOLATION n (NRC INSPECTION REPORT NOS. 50-321/8814 AND 50 366/8814) H This refers to the Nuclear Regulatory Commission (NRC) insactions conducted by Mr. W. J. Ross on April 18-20, 1988, anc by The Messrs. P. Ho'nes-Rey, inspections includedJ.a Henning'f review o and R. Musser on April 23 - May 20,1988.

activities authorized for your Hatch facility. At the conclusion of the second inspection, the findings were discussed with those members of your staff iden-tified in the enclosed Inspection Report. The report doctmenting the first inspection (50-321/88-13 and 40-366/88-13) was sent to you by letter dated May 17, 1988.

Areas examined during the second inspection are identified in the enclosed report. Within these areas, this inspection consisted of selective examina-tions of procedures and representative records, interviews with personnel, and ,

observation of activities in progress. l The inspection findings indicate that certain activities violated NRC l requirements. The violations, references to pertinent requirements, and elements to be included in your response are presented in the enclosed Notice of Violation.

In accordance with Section 2.790 of the NRC's "Rules of Practice," Part 2, Title 10, Code of Federal Regulations, a copy of this letter and its enclosures will be placed in the NRC Public Occument Room.

The responses directed by this letter and its enclosures are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No.96-511.

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2 JUN 101988 -

Georgia Power Company Should you have any questions concerning this letter, please contact us.

Sincerely, j '

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Virgi L. Brownlee, Chief ReactorProjectsBranen3 DivisionofReactorProjects -

Enclosures:

1. Notice of Violation

2. NRC Inspection Report a w/encis:

J. T. Beckham, Vice President, Plant Hatch '

H. C. Nix, Plant Manager O. M. Fraser, Site QA Manager L. Gucwa, Manager, Nuclear Safety and Licensing

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ENCLOSURE 1 NOTICE OF VI0'.ATION Georgia Power Company Docket Nos. 50-321 and 50-366 Hatch Units 1 and 2 License Nos. OPR-57 and NPF-5 During the NRC inspection conducted on April 18-20 and April 23 - May 20, 1988, ~

violations of NRC requirements were identified. In accordance with the --

"General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1988), the violations are listed below:

A. Technical Specification 6.8.1.a requires that written procedures be established, implemented, and maintained as recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2, February 1978.

Section 9.4 of Aopendix "A" of Regulatory Guide 1.33 recommends that maintenance that can effect f.h performance of safety-related eouipment be performed in accordance with written procedures, documented instructions, or' drawings appropriate to the circumstances.

Contrary to the above, on April 10, 1988, plant personnel backfilled the instrumen't reference leg for Unit I reactor water level transmitters 1821-N080C and IB21-N0800 without specific instructions or procedural guidance. A full Reactor Protection System actuation occurred, and the Primary Containment Isolation System Group 2 outboard valves closed as a result of this backfilling operation. Since Unit I was in cold shutdown at the time of this event, an actual scram did not occur.

This is a Severity Level IV violation (Supplement I).

B. Unit 2 Technical Specification 3.6.1.1 requires that primary containment integrity be niaintained while the unit is in Operational Conditions 1, 2, or 3. Without primary containment integrity, primary containment integrity is required to be restored within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit is required to be in at least Hot Shutdcwn within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Cold Shutdown within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Contrary to the above, on Ap il 15,1988, Unit 2 primary containment integrity was inadvertently s ialated for approximately 1-3/4 hours during functional testing.of the "A' Hydrogen Recombiner System lwiile Unit 2 was in Operational Condition 1. Containment isolation valves 2T49-F002A and 2T49-F004A were upened for functional testing before the integrity of system piping had been demonstrated. A portion of the system's piping had previously been cut and welded to remove an oostruction.

This is a Severity Level IV violation (Supplement I).

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4 Georgia Power Company 2 Docket Nos. 50-321 and 50-366 Hatch Units 1 and 2- License Nos. DPR-57 and NPF-5 Pursuant to the provisions of 10 CFR 2.001, Georgia Power Company is hereby required to submit a written statement or explanation to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555, with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector, Hatch Nuclear Plant, within 30 days of the date of the letter transmitting this Notice. This reply shoulo be clearly marked as a "Reply to a Notice of Violation" and should include for each violation: (1) admission or denial of the violation. (2) the reasons for the violation if admitted, (3) the corrective steps which have been taken and the results achieved, (4) corrective steps which will be taken to avoid further violations, and (5) the date when _

full compliance will be achieved. Where good cause is shown, consideration -

will be given to extending the response time. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be mudified, suspended, or revoked or why such other action as may be proper should not be taken.

FOR THE NUCLEAR REGULATORY COMMISSION Virgil L. Brownlee, Chief Reactor Projects Branch 3 Division of Reactor Projects Dated at Atlanta, Georgia this day of"June 1988 i

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NUdl. EAR REGULATORY COMMISSION WASHINGTON, o C. 20$55 s

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Report Numben : 50-321/88-14 and 50-366/88-14 Licensee: Georgia Power Company P. 0. Box 4545 Atlanta, GA 30302 Docket Numbers: 50-3,?! and 50-366 License Numbers: OPR-57 and NPF-5 -..

Facility Narne: Hatch 1 and 2 Inspection Dates: April 18-20 and April 23 - May 20, 1988 Inspection at Hatch site near Baxley, Georgia Inspectors:

~~~Diis 5IghiT -

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NIEr RBYnii!Rij!~5enioF~ Resident Inipictor

. ToETE. Henning, EITdini fEspector - DitT 31ghed -

97 J. R5ii~~C5iiiiiiirj~Thipector - DiiT 5Tgned Accompanying Personnel: Randall Musser Approved by:

Rirvi T V! 3Inlfdli ChliT Pr63Eci~5ectI3T W ~ ~~ DiiT 3Ighi T -

Division of Reactor Projects

SUMMARY

Scope: This routine inspection was conducted at the site in the areas of Licensee Action on Previous Enforcement Matters, Operational Safety Verifi-Cdtion, Maintenance Observation. Surveillance Observation, Radiological Protection, Physical Security, Reportable Occurrences, Operating Reactor Events, Review of Licensee's Operational Upgrade Efforts, and Recent Chemistry Initiatives.

Results: Two violations were identified. One violation was for backfilling an instrument reference leg without specific work instructions or procedures. The other violation was far violating primary containment integrity durina hydrogen recoctilner system testing. One unresolved item was also identified involving improper drywell pneumatic system valve lineup.

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REPORT DETAILS

1. Persons Contacted Licensee Employees T. Beckham, Vice President, Plant Hatch C. Ccggin, Training and Emergency Preparedness Manager

• 0. Davis, Manager General Support __

• J. Fitzsimmons, Nuclear Security Manager P. Fornel, Maintenance Manager

• 0. Fraser, Site Quality Assurance Manager

• M. Googe, Outages and Planning Manager H. Nix, Plant Manager

• T. Powers, Engineering Manager

• 0. Read, Plant Support Manager H. Sumner, Operations Manager S. Tipps, Nuclear Safety and Compliance Manager

• R. Zavadoski, Health Physics and Chemistry Man 69er Other licensee emoloyees contacted included technicians, operators, mechanics, security force members and office personnel.

NRC Resident Inspectors P. Holmes-Ray

• J. Menning

• R. Musser NRC management on site during inspection period:

M. Ernst, Deputy. Regional Administrator, Region II '

G. Lainas, Assistant Director for Region II Reactors, Office of Nuclear Reactor Regulation (NRR)

C. Julian, Chief, Operations Branch, Region II W. Pegan, Chief, Human Factors Assessment Branch, NRR X. Brockman, Chief, Operator Licensing Section 2, Region II C. Hehl, Deputy Director, Division of Reactor Projects, Region II M. Shymlock, Chief, Operational Programs Section, Region II M. Sinkule, Chief, Reactor Project Section 35 Region II

0. Lange, Chief, Boiling Water Reactor (BWR) Section, Region I

• Attended exit interview l

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2. Exit Interview (30703)

The inspection scope and findings were sumarized on May 23, 1988, with those persuns indicated ja paragraph 1 above. The inspectors described the areas inspected and discussed in detail the inspection findings listed below. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection. The licensee acknowledged the findings and took no exception.

Item Number Status Description / Reference Pargraph M-321/88-14-01 Opened VIOLATION - Backfilling of Instru-n.e nt Reference Leg Without Specific Work Instructions or Procedures (paragraph 11) 366/88-14-02 Opened VIOLATION - Violation of Primary Containment Integrity During Hydrogen Recombiner System Testing (paragraph 11) 321/88-05-04 Closed VIOLATION - Inadequate Maintenance Work Order for Vacuum Breaker Maintenance (paragraph 3) 321/88-14-03 Opened UNRESOLVED ITEM * (URI) - Improper Drywell Pneumatic System Valve Lineup (paragraphs 4 and 12)

3. Licensee Action on Previous Enforcement Matters (92702)

(Closed) Violation 321/88-05-04, Inadequate Maintenance Work Order for vacuum breaker maintenance which resulted in the failure of several Unit I torus to drywell vacuum breakers to test properly during monthly oper-ability testing.

The licensee's letter of responsa dated March 29, 1988, was reviewed.

functionally Corrective action involved correcting wiring discrepancies,(ABN) testing the vacuum breakers, and generating As-Built Notice 88-23 to reflect the proper wiring configuration. The inspector observed functional testing and reviewed ABN 88-23. Since the actions to correct the specifics of this violation have been completed, this item is closed, l

'AK UREiBWEB Itein is a miHii i55utlBich more information is required to determine whether it is acceptable or may involve a violation or deviation.

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3 4 Unresolved Items (0 pen) URI 321/88-14-03, Improper Drywell Pneumatic System Valve Lineup.

As ciscussed in paragraph 12, a URI has been opened as a result of an improper drywell pneumatic system volve lineup in Unit 1. This improper valt e lineup resulted in the unexpected closing of the inboard Main Steam Isolation Valves (MSIV) and subsequent reactor scram on liay 20, 1988.

5. Operational Safety Verification (71707) Units 1 and 2 _

The. Inspectors kept themselves informed on a daily basis of the overall plont status and any significant safety matters related to plant oporations. Daily discussions were held with plant management and various menbers of the plant operat:ng staff. The inspectors made frequent visits to the control room. Observations included instrument readings, setpoints ard recordings, status of operating systems, tags and clearances on equipment, controls and switches, annunciator alarms, adherence to 1 miting conditions for operation, temporary alterations in effect, daily journals and data sheet entries, control room manning, and access controls. This inspection activity included numerous informal discussions wl.th ope,rators and their supervisors. Weekly, when on site, selected Engineering Safety Feature (ESF) systems were confirmed operable. The confirmation was made by verifying the following: accessible valve flow path alignment, power supply breaker and fuse status, instrumentation, najor component leakage, lubrication, cooling, and general condition.

General plant tours were conducted on at least a weekly basis. Portions 3f the control building, turbine building, reactor building, and outside are6s were visited. Observations included general plant /eouipment condi-tions, safety related tagout verifications, shif t turnover, sampling program, housekeeping and general plant conditions, fire protection equipment, control of activities in progress, radiation protection controls, physical security, problem identification systems, missile hazards, instrumentation and alarms in the contrul room, and containment isolation.

In the ares of housekeeping, the following discrepancies were observed by l the inspector and brought to the attention of licensee personnel:

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• On April 28, 1988, an obstructed floor drain was observed in the Unit 2 reactor building in the vicinity of the Standby Liquid Control l system pumps. Spilled chemicals were also observed in the Unit 2 reactor building on the floor adjacent to the Reactor Building Closed Coolirg Water system Chemical Addition Tank.

• On April 29, 1988, wood scaffolding was found in the Unit 2 reactor i

building that apparently. had not been removed following maintenance

! activities. The material was found on elevation 96 in the southeast I diagonal.

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• On May 7,1988, an accumulation of oil and fuel was observed in the fire pump house under the diesel for diesel driven fire pump No. 3.

The diesel was not operating at the time of this observation and nu leaks wera observed.

On May 11, 1988, a significant accumulation of water was observed on the floor in front of Liquid Sample system Panel 2P33-P102 on elevation 185 in the Unit 2 reactor building. The water appeared to be draining from this panel which displayed a sign indic3 ting that the panel was contaminated inside, n

During this reporting period, the inspector reviewed the licensee's controls on overtime of personnel who perform safety-related functions.

Section 6.2.2 9 of the Technical Specifications establishes requirements for the control of such overtime and Section 8.4 of licensee procedure 30AC-0PS-003-05, "Plant Operations," provides implementing instructions to support the . technical specification requirements. The inspector reviewed a Maintenance Department Overtime Report for the month of March and determined that the requirements of 30AC-0PS-003-0S and the technical specifications had been met. Particular emphasis was placed on conformance with the requirement that overtime deviations be approved .in advance by the Plant Manager.

At the start of this reporting period, both Hatch units remained shut down to implement portions of the licensee's operational upgrade program. This program is discussed in paragraph 13. At 1825 on May 14, 1988, startup comenced in Unit 2 following the completion of certain upgrade activities that the licensee had decided to complete prior to startup. Criticality was achieved in Unit 2 at 0634 on May 15, 1988. However, startup progress was subsequently feedwater (delayed pumps RFP) and due to equipment feedwater injectionproblems with the UnitThe volve 2N21-F006B. 2 reactor "2A" RFP turbine would not roll when started. Investigation revealed that the motor speed changer was burned. The "2B" RFP started but was tripped by the operator when a low lube oil pressure condition'was ' indicated and alarmed. Investigation revealeo that a heater strip in the bottom of a circuit breaker compartment had ccme in contact with and shorted 5 power cables to the " A" lube oil pump. The shorting resulted in a f alse indication of low lube oil pressure. Lube oil pressure did not actually drop during the event. Valve 2N21-F006B would not open by positioning of its control switch. ~ Initial indications were that the valve's disc was separated from the stem. The value was subsequently disassembled, revealing that all four lobes on tcp of the disc had broken off. At the close of this inspection period, Unit 2 remained critical with the reactor pressure at od0 psig pending completion of repairs on valve 2H21-F006B.

Startup of Unit I comenced at 1545 on May 18,1988. Criticality was achieved at 1705 on that day. At 0216 on May 20,1988, Unit 1 automatic-ally scramed from approximately 20 percent power during startup operations.

The scram resulted from the unexpected closing of the "B" and "C" inboard MSIVs. This event is discussed in paragraph 12. Just prior to this scram, l

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plant personnel discovered a leak in a Reactor Water Cleanup (RWCU) system line. The leak was found to be coming from a 2-inch crack in weld metal at a "T" which joins the two 3-inch discharge lines f rom the "A" and "C" RWCU pumps. At the close of this inspection period Unit I remained in hot shutdown pending the completion of repairs to the RWCU system weld.

On May 11,1988, the inspector was advised that a leak had apparently developed in the liner of the Unit I spent fuel pool. Although the leak rate had been variable and difficult to precisely determine, the licensee estimates that it was no greater than 8 gallons per minute. The inspector reviewed the licensee's plan for locating and repairing the source of the N leak. The liner will be inspected with a video camera af ter areas of the fuel pool are vacuumed. A repair strategy will be developed depending upon the nature of the flaw causing the leak. The licensee has initiated several Design Change Requests to enhance monitoring of fuel pool level and of the liner leakage flow rate. A dip stick will be installed to provide a more positive pool level indication. Additionally, a flow meter indicator will be installed in the leakage detection system. The inspector will monitor the licensee's progress in locating and repairing the source of the fuel pool liner leakage.

No viola,tions or deviations were identified.

6. Maintenance Observation (62703) Units 1 and 2 During the report period, the inspectors . observed selected maintenance activities. The observations included a review of the work documents for adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, observation of all or part of the actual work and/or retesting in progress, specified retest requirements, and adherence to the appropriate quality controls. The primary maintenance observations during this month are sunnarized below:

Maintenance Activities Date

a. Balancing of Refueling Floor Exhaust 04/27/88 Fan 1T41-C005A per Maintenance Work Order (MW0) 1-88-00087 (Unit 1)

b. Filtration and Demineralization of 04/27/88

Torus Water per Special Procedure 63SP-042588-X0-1-0H, "Torus Water Cleanup" (Unit 2) 1

c. Repair of Standby Liquid Control 04/28/88 system Pump 2C41-C001B per HWO 2-88-2168 (Unit 2)

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d. Installation of Circuit 80crds in 05/19/88 Panel 1Z43-P400 per liWO 1-87-0177 and Work Process Sheets 84-019-E007 (Unit 1)

No violations or deviations were 1oentified.

7. Surveillance Testing Observations (61726) Units 1 and 2 ~.

The inspectors observed the performance of selected surveillances. The observation included a review of the procedure for technical adequacy, conformance to technical specifications, verification of test instrument calibration, obse?vation of all or part of the actual surveillances, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the accept-ance criteria. The grimary surveillance testing observations during this month are suninarized below:

Surveillance _BsMnoActivig O_ag

a. Calibration of Differential Pressure 05/11/88 Transmitter IE21-N0038 er Procedure 57CP-cal.-103-15 (Unit i

b. Standby Gas Treatment System -ilter 05/13/88 Train 2T46-0001B Testing per Procedure MWO 2-88-2411 (Unit 2)

c. Monthly Operability Testing of the 05/19/88 "2C" Diesel Generator per Procedure 34SV-R43-003-2S (Unit 2)

No violations or deviations were identified. ,

8. ESF System Walkdown (71710) Unit 2 The inspectors routinely conducted partial walkdowns of ESF systeins.

Valve and breaker / switch lineups and equipment conditions were randoml/

verified both locally and in the control room to ensure t:1at lineups were in accordance with operability reouirements and that equipment material I conditions were satisfactory. The Unit 2 High Pressure Coolant injection  !

system was walked down in detail. l Within the areas inspected, no violations or deviations were identified.

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9. Radiological Protection (71709) Units 1 and 2 l The resident inspectors reviewed aspects of the licensee's radiological protection program in the course of the monthly activities. The perfor-mance of health physics and other personnel was cbserved on various shifts to include: involvement of health physics supervision, use of radiation work permits, use of personnel monitoring equipment, control of high radiation areas, use of friskers and personal contamination monitors, and l posting and labeling.

No violations or deviations were noted. ~ ..

10. Physical Security (71881) Units 1 and 2 in the course of the monthly activities, the resident inspectors included a review of the licensee's physical security program. The performance of various shif ts of the security force was observed in the conduct of daily activities to include: availability of supervision, availability of armed response personnel, protected and vital access controls, searching of personnel, packages and vehicles, badge issuance and retrieval, escorting of visitors, patrols, and compensatory posts.

Nb vioistions or deviations were noted.

11. Reportable Occurrences (90712 and 92700) Units 1 and 2 A number of Licensee Event Reports (LER) were reviewed for potential generic impact, to detect . trends, and to determine whether corrective actions appeared appropriate. Events which were reported ininediately were also reviewed as they occurred to determine that Technical Specifications were being met and the public health and safety were of utmost ccnsideration.

Unit 1: 88-02 Personnel Error During Backfillinc of Instrument Reference leg Causes low Level Scrain The events of this LER occu'rred in Unit 1 on April 10.

1988, when Instrumentation and Control personnel were.

backfilling an instrument reference leg to correct the output of Feedwater Control System reactor water level transmitter IC32-N004B. Reactor water level transmitters IB21-N080C and 1B21-N0800 share the same reference leg as tronsmitter IC32-N004B. The two 1821 l

' level transmitters provide low reactor water level input to Reactor Protection System (RPS) channels A2 and B2. They also provide low reactor water level input for the isolation logic for the outboard isola-tion valves of Primary Containment Isolation System l

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(PCIS) valve Group 2. During the backfilling cf the common reference leg. transmitters IB21-N080C and 1821-N0000 sensed a f alse low reactor water level signol. A full RPS actuation . occurred, ano the PCIS Group 2 outboard valves closed. Since Unit I was in cold shutdown at the time of this event, an actual scram did not occur. The backfilling of the common reference leg was performed under MWO 1-88-1531 which provioed no specific instructions or guidance for this operation. Technical Specification 6.8.1.a requires that written procedures be established, implemented, ~

and maintaineo as recommended in Appendix " A" of Regula tory Guide 1.33, Revision 2, February 1978.

Section 9.a of Appendix "A" of Regulatory Guide 1.33 states that m3intenance that can effect the perform-ance of safety-related eauipment should be performed in accordance with written procedures, documented instruct ons, or drawings appropriate to the circum-i stances. This event is considered a violation of Technical Specification 6.8.1.a in that the common reference leg was backfilled without the use of specific work instru.ctions or procedures. This matter will be tracked as violation 321/88-14-01, Backfilling of Instrument Reference Leg Without Specific Work Instruction or Procedures. Review of this LER is closed.

88-04 Drain Line Fails Due to Fatigue Causing High Tempera-ture Condition and Valve Isolation This event was caused by a fatigue-induced crack in a 3/4-inch diameter, 3-inch long section of drain piping connecting the "A" RWCU pump and a drain to the clean

- radioactive waste system. The drain line was replaced. Review of this LER is closed.

Unit 2: 88-13 Personnel Error Allows Valve to be Opened Resulting in

. Primary Containment Violation The events of this LER occurred on Apri.1 15, 1988, and involved the opening of primary containment isolation valves in the " A" Hydrogen Recombiner System f or testing purposes prior to demonstratind the integrity of system piping. A portion of the system's piping had previously been cut and welded to remove an obstruction. The licensee elected to operability test the system prior to performing radiographic examina- )

tions, local leak rate testing, and hydrostatic I

i

s*

9 testing on the weld and piping. Consequently, at i.

1030, isolation valves 2T49-F002A ' and 2T49-F004A were opened as required by plant test procedure 345V-T49-001-25. It was suosequently discovered that these actions had resulted in a violation of primary containment integrity. The operability test was then terminated and a 1215 isolation valves 2T49-F002A and 2T49-F004A were closed. At the time of the event Unit 2 was in Operational Condition 1 at approximately 100 percent of ratec pcwer. Technical Specification - 3.6.1.1 requires that primary cuntainment integri ty ~-

be maintained while in Operational Condition 1. This event is considered a violation of the technical specification requirement in that the primary contain-ment isolation valves were opened prior to demonstrating the integrity of the system piping. Review of this LER is closed and this matter will be tracked as violation 366/88-14-02, Violation of Primary Containment Integrity During Hydrogen Recombiner System Test'ing.

88-11 Equipment Failure in Conjunction with Surveillance

. . Causes Scram The events of this LER concern the Unit 2 automatic scram on April 17, 1988. This scram was discussed in NRC Inspection Report Nos. 50-321/88-11 and 50-366/88-11. Review of the LER is closed.

1 l Two violations were identified.

12. Operating Reactor Events (93702) Unit 1

, The inspectors reviewed activities associated with the below listed The review included determination of cause, safety reactor event.

significance, performance of personnel and systems, and corrective action.

The inspectors examined instrument recordings, computer printouts, l operations journal entries, scram reports and had discussions with

! operations maintenance and engineering support personnel as appropriate.

l

! On May 20, 1988, Unit 1 automatically scrammed f rom approximately 20 percent power during startup operations. At the time of this scram.

the turbine steam chest. was being warmed and plant personnel were preparing to operability test the High Pressure Coolant Injection system.

l The automatic scram resulted from the unexpected closing of the "B" and "C" inboard MSIVs. Reactor vessel level decreased from plus 37 to plus 12 inches indicated during the transient. Reactor pressure decreased from 920 to 630 psig. Plant systems responded properly during the transient.

's 10 Prior to this event, plant personnel had switched the supply to drywell pneumatic loads from instrument air to backup nitrogen. The switch was accomplished by removing an eouipment clearance that involved the closing of valves IF70-F029 and F053 and the opening of valves IP7C-F027 A ar.d F0278. Plant personnel were unaware that 2 valves in the backup nitrogen supply lines (IP70-F025A and F0258) remained closed. Consequently, neither instrument air nor backup nitrogen were available for drywell pneumatic loads after the clearance was removed. Pressure in the inboard itSly accumulators gradually dropped, resulting the closure of all inboard MSIVs. Although the scram resulted from the closing of the "B" and "C" inboard MSIVs, the "A" and "0" inboard MSIVs closed approximately 1 6 minutes later, it appears that this event was caused by personnel error. Plant personnel relied on the equipment clearance to accomplish to switch of drywell pneumatic supplies rather than using the appropriate procedure. The switch from instrument air to backup nitrogen is covered by Data Package 5 in procedure 34S0-P70-001-1S, "Drywell Pneumatic System." A review of this Data Package by the inspector showed that it is technically correct and specifies the proper valve manipulations for this operation. Pending more detailed review by the inspector, this matter will be tracked as UR1 321/88-14-03, Improper Drywell PncJmatic Systen Valve Lineup.

One URI was identified.

, 13. Review of Licensee's Operational Upgrade Efforts - Units 1 and 2 On April 19, 1988, the licensee voluntarily initiated shutdown of both Hatch units to upgrade certair spects of operational performance. During this reporting period, the inspector reviewed the licensee's operational upgrade efforts in several areas.

Reviews of upgrade ef forts in other areas are discussed in NRC Inspection Report Nos. 50-321/88-12 and 15 and 50-366/88-12 and 15. The resident inspectors will review longer term operational upgrade efforts as related activities are completed.

Clearance Tagging Prog"m: The licensee has taken steps to reduce 3ependence on equipment clearances for configuration control and reduce the number of long-standing equipment clearances. Periodic clearance review requirements have been modified to provide for review or ecuipment clearances that are active for six months or more to confirm the need for the clearances.to remain active. The Manager of Operations is now respon-sible for appropriate followup action on clearances that are active for six months or more. These revised clearance review requirements are contained in Section 8.13 of licensee procedure 30AC-0PS-001-05, Rev. 4, "Control of Equipment Clearances and Tags." The licensee also formed a team to identify active, long-standing clearances and initiate clearance

s 11 removal actions where possible. On May 6, 1988, the inspestor reviewed the- team's prooress and held discussions with the team leaoer.

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The inspector determined that 97 clearances had been identified for review.

This incluoed essentially all outstanding clearances that had been initiated prior to 1988. As of May 6, 1988, 39 of the 97 clearances had been eliminated. The inspector subsecuently reviewed clearance documen-tation in the control room and confirmed that the 39 clearances had been removed.

The inspector confirmed that outstanding long-term equipment clearances were reviewed and approved by the Executive Vice President on May 11, 1 1988, prior to Unit 2 startup. At the time of this review, 20 long-term clearances remained active in Unit 1 and 17 long-term clearances remained active in Unit 2. The inspector reviewed ecuipment clearance records in the control room on May 13, 1988, and noted the significantly reduced number of long-term active clearances.

Event Review Program: The licensee is taking steps to enhance the Hatch event review and resolution program. A new procedure is being prepared that will provide for 4 classifications of events. Specific team leaders and members will be identified for scrams and events identified as complex. This new procedure will be identified as 10AC-MGR-012-02, "Plant Event An~alysis and Resolution Program." Program training is also planned for involved individuals. The licensee anticipates issuin,g this procedure and ccmpleting related training by the end of June 1988.

Nuclear Plant Reliability Data System (NPRDS) Review: The licensee has Ei55Teted a review oTWRIi!I rs1Ture 7e~pTrts tTitlid been coded as cause unknown. The review included reports generated since 1984 Of the 251 reports reviewed f or Unit 1,138 had cause codes changed from unknown to Other more appropriate codes. Of the 247 reports reviewed for Unit 2, 130 had cause codes changed from unknown to other codes. The licensee has resubmitted the affected rv vts, l

i Emeroency Diesel Generator Testino: The licensee has taken action to reduEef the nun 6c7oT emergency c1esel generator f ast starts in an effort to prolong engine life and improve reliability. Fore specifically, the methodology for conducting monthly operability testing is being changed.

In the past, the diesel generators were fast started; i.e., synchronous speed was achieved in a maximum of 12 seconds. The licensee is currently revising the monthly operability test procedure to provide for slow j

starting of the diesels in accordance with the technical specifications and. provide for burning over the engine subsequent to operation. That is, the diesels will come up to 500 revolutions per minute (rpm) when started.

Synchronous speed (900 rpm) will then be achieved by manually increasing speed at a rate of approximately 50 rpm per minute. Under the new testing methodology, controlled loading of the diesel generators will be performed essentially the same as before. On May 16, 1988, the inspector reviewed l

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these testing changes with the cognizant engineer. A draft of the revised I test procedure for the "2A" diesel generator was reviewed at that time. l Revised testing requirements for the "2A" diesel generator will be imple- '

mented by Revision 7 to proceoure 34SV-M3-001-25. The inspector deter-mined that the licensee plans to issue appropriate revisions to the monthly operability test procedures for all 5 emergency diesel generators by June 1, 1988.

No violations or deviations were identified.

14. Recent Chemistry Initiatives - Units 1 and 2  %

The following items were inspected by W. J. Ross on April 18-20, 1988.

a. Installation of Corrosion Monitors in the Reactor Building and Recombiner Building Component Cooling Water Systems As discussed in Inspection Report Nos. 50-321/88-13 and 50-366/88-13, recent leaks in the seals of Reactor Bulding Component Cooling Water System (RBCCW) pumps in Unit 2 had resulted in continuous loss of water from this closed cycle system. While obtaining replacement

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seals, the licensee had provided demineralized water as makeup for RBCtW ' inventory. However, the licensee chose not to add makeup solutions of sodium nitrate to provide corrosion protection through reduction of dissolved oxygen in the RBCCW. This decision was based on the difficulty involved in the disp 0 sal of the increase in volume of water containing sodium nitrite that was leaking f rom this system and being processeo to meet National Pol'.ution Discharge Elimination System disposal regulations. The absence of an adequate corrosion inhibiter could increase the possibility for corrosion of the carbon steel pipe.

The NRC inspector was informed that a decision to install corrosion monitors had not been made as yet, in the belief that the problem had been resolved by the installation of leakproof pumps and subsecuent dddition of sodium nitrite solution to achieve a typical value of 500-2000 parts per million.

Also, the Recombiner Building Component Cooling Water System (RCBCCW) had been contaminated with raw river water through leakage of Service Water through as RCBCCW heat exchanger. The possibility for corrosion within the carbon steel pipe of the RCBCCW may have increased by the ingress of contaminants. Consecuently, the Institute of Huclear Power Operations inspectors believed that corrosion monitors should be installet on this system also.

The NRC inspector was informeo that sodium nitrite was no longer being added to the RCBCCW in an effort to reduce the amount of sodium nitrite in the radwaste. The hole in the RCBCCW will not be repaired until the next refueling outage for Unit 1.

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b. Shielding of a Light in a Fume Hood in One of the Chemistry Labora-

' tories Against Possible Damage by Fumes .

l Normally, such lights are protected with a glass cover to reduce the possibility of being broken by deposition of condensate, etc., or trom being physically struck by some object. The NRC inspector was informed that a shield had been installed around the bare light bulb.

c. Monitoring the Ficw of Air Through the Fume Hoods During his inspection, the NRC inspector observed that fume hoods windows had stickers that identified the most recent inspection date for the flow measurement. These measurements haya been made on a periodical schedule established and implemented by plant maintenance personnel. The NRC inspector was informeo that the licensee was attempting to acquire flow meters for each hood so that personnel using the hoods could always be assured of sufficient air flow to provide an acceptable level of safety from fumes.

d. Chlorine Gas Monitor in the Chlorine Building The licensee injects chlorine gas into river water used for condenser

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cooling to minimize fouling and corrosion of condenser tubes by micro and macro organisms. Since chlorine gas is toxic, the environment in the vicinity of the gas storage and injection points should be continually monitored for the presence of chlorine gas. In March 1988, the licensee's monitor was inope'rable. Subsequently, the f aulty monitor has been replaced. Also, the NRC inspector was inforn.ed that, in the near future, the use of chlorine gas as a biocide will be discontinued in favor of using sodium hypochlorite, a less toxic and more easily handled form of chlorine,

e. Long Term Chemistry Control During the last two years, the need for plans and procedures to protect safety and non-safety related components of nuclear power plants f rom degradation during long-term outages has been recognized by the industry. Recommendations for wet layup during short outages have been developed by the BWR Owners Group. The licensee had discussed this subject with other nuclear power plant licensee's and is in the process of developing the needed procedures.

Nu violations or deviations were identified. -

. 8 "ov APPENDIX E

. .lP i UNITED STATES g g NUCLEAR RECULATGRY COMMISSIGN o,  ! REGION li l g *,,,e 101 MARIETTA ST., N.W.

ATLANTA, GEoRQlA 30323 June 17, 1988 Docket Nos. 50-321,"50-366 License Nos. DPR-57, NPF-5 l

Georgia Power Company ATTN: Mr. R. P. Mcdonald Executive Vice President -

Nuclea: Operations 1 l

P. O. Box 4545 Atlanta, GA 30302 -

l Gentlemen:

)

SUBJECT:

NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-321/88-15 AND 50-366/88-15)

This refers to the Nuclear Regulatory Comission (NRC) Operational Performance Assessment (OPA) conducted by C. Julian and team on May 9 - 20 1988. The

nspection evaluated the effectiveness of the Operations group and other plant groups in supporting safe plant operations at your Hatch facility. The findings of the inspection were discussed with those members of your staff identified in the inclosed inspection report on June 1 1988.

Areas examined during the inspection are identified in the report. Within taese areas the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

This was a performance based team assessment of plant Hatch which ideiitified significant operational strengths and weaknesses, rather than a compliance Oriented inspection. However, during the course of the inspection certain activities were noted which appeared to violate NRC requirements. The viola-tions, references to pertinent requiremer.ts, and elements to be included in your response are described in the enclosed Notice of Violation. There is also an unresolved item identified in the inspection report which will be pursued during future inspections.

We believe that substantial enhancements were made to plant operations during the recent shutdown which improve safety and enhance the ability of the Operations staff to perform its job effectively. These enhancements include extensive training on the Emergency Operating Procedures (EOPs), improving the readability of the E0Ps, consolidating drawing changes with the engineering drawings in the control room, improving plant labeling, decreasing the number of lighted annunciators, and emphasizing the need for operator professionalism.

We strongly support these and other near-tenn improvements and we encourage aggressive implementation of your longer tenn enhancements. ,

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. i Georgia Power Compar,y 2 June 17, 1988 I We also encourage more aggressive management attention to site quality improve-  ;

ment actinns. We are concerned that you had failed to flag a number of Oualit e Assurance audit findings as significant. These findings included weakr uses  !

regarding professtonal conduct in the control room, excessive administrative workload on the Shift Supervisor, timely incorporation of as-built-notices into the drawings available in the control room, technical deviations in the E0Ps from the Energency Procedure Guidelines (EPGs), the complexity and read-ability of the E0Ps and fire brigade traini'19 A fully effective Quality Assurance program and management followup would havo resulted in more timely licensee-initiated programs to correct.the above weaknesses. _

In the area of E0Ps we note that the technical bases for differences between the Hatch E0Ps and the General Electric Owners Group EPGs are still not documented and the present E0Ps are still complex and difficult to follow.

Action should be taken on a priority basis to simplify the E0Ps and to establish documentation of deviations. Your plans fnr completing this work will be discussed with the NRC in a management meeting in the near futur_e.

In accordance wit.'1 Section 2.790 of the NRC's "Rules of Practice" Part 2 Title 10 Code of Federal Regulations a copy of this letter and its enclosures will be placed in the NRC Public Document Room.

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The responses directed by this letter and its enclosures are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980 Pub. L. No.96-511.

Should you have ary questions concerning this letter, please contact us.

Sincerely, J. Nelson Grace Regional Administrator

Enclosures:

Notice of Violation 1.

2. NPC Inspection Report cc w/ enc 1s:

J. T. Beckham, Vice President, Plan! Hatch H. C. Nix, Plant Manager

0. M. Fraser, Site Quality Assurance (QA) Supervisor L. Gucwa, Manager, Nuclear Safety and Licensing l

,.__ ._,,,_._._._...,,____.,_.m. . _ _ . _ _ , , - , _ . - _ _ _ . . . _ , . . - _ , _ _ _ . _ , . . . _ . . _ . _ - _ - _ . . _ . _. _ . . . . .

ENCLOSURE 1 NOTICE OF VIOLATION Georgia Power Company Docket Nos. 50-321, 50-366 Hatch Units 1 and 2 License Nos. DPR-57, NPF-5 During . the Nuclear Regulatory Comission (NRC) inspection conducted on May 9 - 20, 1988, violations of NRC requirements were identified. In _.

accordance with the "General Statement of Policy (and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C 1988), the violations are listed below:

A. 10 CFR 50, Appnndix B, Criterion III, Design Control, requires that measures shall be established to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. The licensee established procedure 52GM-MEL-011-05, Installation and Maintenance of Automatic Switch Company (ASCO) Solenoid Valves, Rev. 1, to ensure that appropriate quality standards are established and maintained for the installation of ASCO so'lenoid valves. Procedur? 52GM-MEL-011-05,Section I .1.b. , Mounting, states, "The following valves must be mounted vertical and upright:

NP8323 (Solenoid A), 206-380, 206-381 and 206-832." This requirement implements the vendor mounting requirements for maintaining environmental qualification of the valves.

Contrary to the above, the licensee failed to maintain the appropriate quality standards for installation of Model 206-380 ASCO solenoid valves in that, on May 16, 1988, an NRC inspector determined that the Model 206-380 ASCO solenoid valves for control of Unit 1 standby gas treatment system suction valves 1T41-F032A and -F032B were mounted in an orienta-tion which violates the requirements of Procedure 52GM-MEL-011-05.

This is a Severity Level IV violation (Supplement 1).

B. 10 CFR 50, Appendix B, Criterion VI, Document Control, requires that measures be established to control the issuance of documents, such as instructions, procedures, and drawings, including changes thereto, which prescribe all activities affecting quality. In addition, Criterion VI requires that the measures shall assure that changes are distributed to the location where the prescribed activity is performed. The licensee established administrative control procedure 20AC-ADM-001-05, Document Distribution and Control, Rev. 2, to accomplish this requirement. This procedure required the recipient of controlled documentation to remove superseded documentation and file the current issue document in its appropriate place. 7 d

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'Qtt (

• l Georgia Power Company 2 Dockst Nos. 50-321, 50-366 '

s Hatch Units 1 and 2 License Nos. DPR-57, NPF-5 Contrary to thrabove, on May 15, 1988, an NRC inspector found that copy number 2 of the Unit 2 Technical Specifications located at the Shift Supervisor's desk in the control room contained eight pages which were l either missing or had been superseded. Further licensee review revealed l

additional examples of controlled documents in the control room that were  ;

not current.

. This is a Severity Level IV violation (Supplement 1). (Unit 2 only)

Pursuant to the provisions of 10 CFR 2.201, Georgia Power Company is hereby _

required to submit a written statement or explanation to the Nuclear Regulatory Comission, ATTN: Document Control Oesk, Washington, DC 20555, with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector, Hatch Nuclesr Plant within 30 days of the date of the letter transmitting this Notice. This reply should be clearly marked as a "Reply to a Notice of Violation" and should include (for each violation]: (1) Idmission or denial of the violation, (2) the reason fo- the violation if admitted, (3) the corrective steps which have been taken and the results achieved, (4) the corrective 3teps which will be taken to avoid further violations, and (5) the date when full compliance will be achieved. Where good cause is shown, consideration will be given to extending the response time. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked or vehy such other action as may be proper should not be taken.

Security or safeguards information should be submitted as an enclosure to facilitate withholding it from public disclosure as required by 10 CFR 2.790(d) or 10 CFR 73.21.

F0A THE NUCLEAR REGULATORY COMMISSION

- N^ ,

' J. Nelson Grace k Regional Administrator Dated at Atlanta, Georgia this 17th day of June 1988

. .p ;fcp UNITED STATES 2 #o NUCLEAR REGULATORY COMMISSION

,y n RE!!oN il y j tot MARIETTA STREET.N.O.

U J ATLANTA. GEohGI A 3o323

%,...../

Report Nos: 50-321788-15 and 50-36U88-15 Licensee: Georgia Power Company P.O. Box 4545 Atlanta, GA 30302 Docket Nos: 50-321 and 50-366 License Nos: OPR-57 and NPF-5 Facility Name: Hatch 1 and 2 -

Inspection Conducted: May 9 - 20, 1988 Team Manager: -

C. Julian,< thief N

O' ate $1gned Operations Branch Ui ision of Reactor Safety -

t Team Leader: o / -

M 8cP E Shymlodk. C fef Oaft Signed Operstional Proc rams Sec cion

,Divis,on of Re.,ctor Safsty Inspectors: R. Butcher L. Crocker, NRR R. Gibbs J. Konklin, NRR A. Morrongiello, Region III T. "Connor C. Patterson D. Starkey L. W t [l 3 f

/l [8(}~Df

% )

Approvec by: e s t/

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A. G*tson, Director Oate Signed Division of Reactor Safety

SUMMARY

Scope: This was an announced Operational Performance Assessment (OPA). The OPA assessed the effectiveness of various plant groups including 0;:erations, Maintenance, Quality Assurance, Engineering and Training, in supporting safe i

plant operations. Plant management awareness of, involvement in, and support of safe plant operation were also evaluated.

The assessment was coincidently performed subsequent to a shutdown mandated by Georgia Power Company (GPC) to implement certain recent Institute of Nuclear Power Ope. rations (INPO) recommendations. GPC advised the NRC of I the INPO recommendations and planned actions in a May 4, 1988, letter from

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R. P. Mcdonald, Executive Vice President, Nuclear Operations, GPC, to T. E. Murley, Director, Office of Nuclear Reactor Regulation. The objectives of this OPA which are set forth in a May 4, 1988, charter entitled, "Matrix and Operatiocal Assessment, Hat.ch U11ts 1 and 2," as directed by the Regional Administrator (Appendix A), were broadened in this case to include an evalua-tion of the operational enhancements made by the licensee in response to the recent INPO findings, in addition to the planned assessment.

The inspection was divided into four major areas including Operational Enhancements, Operations, Maintenance Support of Operations, and Management Controls. Emphasis was placed on numerous interviews of personnel at all 1 levels, observation of plant activities and meetings, extended control room observations, and plant and system walkdowns. The inspectors also reviewed plant deviation reports and Licensee Event Reports (LERs) for the current Systematic Assessment of Licensee Performance (SALP) evaluation period, and evaluated the effectiveness of the licensec's root cause identification; short term and programmatic corrective actions; and repetitive failure trending anc related corrective actions.

Results: In general, the licensee's programs in the areas inspected were found to be adequate with a nutber of strong features. Weaknesses were identified in some programs as indicated below. The licensee committed to evaluate these areas a'd n take appropriate actions to enhance performance in these areas.

Substantial enhancements had been made to plant operations during the recent shutdown. Certain of these enhancements were reviewed by the inspection team as discussed in paragraph 2 of this report. The inspection indicated that the short-term objectives described in the licensee's May 4, 1988, letter to the NRC (Appendix B) had been met and plans were in place and were being imple-mented to achieve tne long-term goals.

The NRC was concerned, however, that some of the concerns identified by INPO and the NRC in the Operations a ea had been previously identified in Quality Assurance audits (see paragraphs 3.h and 5.j). In addition, the concerns regarding the readability and congestion of the Emergency Operating Procedure flowcharts were brought to the attention of licensee management in a Jur.e 22, 1987, NRC Examination Report (321/0L-87-01) and again during the NRC Quality Verification Function Inspection (QVFI) conducted in December 1987, (NRC Inspection Report No. 321, 366/87-31). The QVFI also identified the lack of Operations experience in the QA organization as a potential weakness and encouraged the licensee to staf f tr.a QA organization with more personnel experienced in Operations to enable the QA organization to perform more meaningful activities in monitoring plant activities. Although the QVFI indicated that the Hatch quality verification organization's performance had been generally effective; based on the weaknesses identified in the QVFI and these additional findings, the NRC believes that additional management attention is warranted to assure that the scope of findings in the Operations area are identified, adequate corrective cions are promptly taken, and QA expertise is available to evaluate tt e adtouny of these actions, d

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3 Strengths and weaknesses are summarized below:

Strengths:

In the area of Operations, strengths included:

The licensee had recently created a shift foreman position in the Operations crew to supervise plant equipment operators and control clearances.

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Recent initiatives, including a Code of Conduct, were instituted to -

upgrade operator professionalism. The continuing practices of operator identification by the wearing of uniforms and badges, formal shift turnovers, and detailed logs and record keeping, were noteworthy.

The use of systems engineers to support plant operations during surveillance testing and maintenance activities led to the early resolution of problems.

The following strengths were ldentified in the area of Maintenance Support of Operations:

Th'e expe~rience level of maintenance managers, supervisors, and foremen, was high and management communication of responsibilities and goals to employees was evident.

In addition to those walkdowns performed by Operations, the Maintenance Department's rasponsibility for good plant material condition was reinforced by the use of maintenance craftsmen and supervisors to perform routine plant walkdowns to ensure equipment was properly maintained.

The work planning process in the maintenance area contained the necessary elements to support the maintensnce program and was well understood by the supervisory personnel involved.

The licensee's maintenance training program was comprehensive including placing the majority of the maintenance staff through the enhanced program with little "gran.ifathering." Training involved generic skills training, plant specific skills training, and specialized skills training.

Independent verification was included. The three maintenance training programs were accredited by INPO in April 1987. Overall control of the training process was maintained by a Training Review Board.

An aggressive attitude toward predictive / preventive maintenance was improving equipment reliability and availability.

QC performed independent reviews of all meterials used in meintenance activities.

4 Weaknesses: ._

Weaknesses in Operations included:

The technical bases for differences between the Hatch Emergency Operating Procedures (EOPs) and the General Electric Owners Group Emergency Procedure Guidelines were not documented. In addition, the present E0Ps are complex and difft.: ult to follow. These issues were previously identified in the recent NRC E0P team inspection as documented in NRC Inspection Report 321, 366/88-12. .

Management attention should be directed to the completion of procedure upgradis for annunciator response proceduret and abnormal operating procedures which support the Emergency Opersting Procedures.

The methods used to control the roster of qualified fire brigade leaders and members were informal. Four examples were found where quarterly leadershir training was apparently missed.

Additional management attention is needed to close out review of Event Review Team Reports to ensure corrective actions were timely and adequate.

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- An excessive administrative burden was placed on the Shif t Supervisor because temporary procedure changes were not incorporated into permanent changes in the 30-day span allowed, resulting in repeated reissue of the temporary procedure changes. The method to make permanent changes was l-difficult, requiring a separate form to be processed by the shift Supervisor.

Weaknesses in the Management Controls area included:

The protracted nature of the corrective actions to the Site Quality Assurance Report 87-p0-2A findings reflected adversely on management support of plant operations. In addition, Quality Assurance failed to flag these findings as significant. These findings included: (1) less than optimum professional conduct in the control room; (2) possible excessive administrative workload on the shift supervisor; (3) problems i with timely incorporation of as-5uilt-notices on drawings available in I the control room; (4) technical deviations between the Emergency Procedure Guidelines and Emergency Operating Procedures; and, (5) problems with the Emergency Operating Procedure flow charts due to the plastic covering and l congestion which made the charts difficult to follow.

l Within the arcas irspected the following violations were identified:

i

' - Failure to meet environmental qualifications for orientation of ASCO l solenoid valves for the control of the suction valves for the Unit 1

! standby gas treatment subsystems. (paragraph 4.e) l l

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Failure to control updates to a Unit 2 control room copy of Technical Specifications- (pa agraph 5.k)

One unresolved . item was tientified involving apparent failure to complete quarterly fire origade leadveship training. (paragraph 3.h) mee e i

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b TABLE OF CONTENTS Page Number,

1. Persons Contacted ............................................. 1

2. Inspection of Operational Enhancements ........................ 2

a. Operator Professionalism .. .............................. 2

b. Lighted Control Room Annunciators ........................ 4

c. Operator Response to Transients .......................... 6 (1) Emergency Operating Procedures ...................... 6 (2) Emergency Operating Procedure Upgrade Training ...... 7_-

(3) Upgrade of Standby Liquid Control System Simulator Modeling .......................................... 8

d. Plant Labeling ........................................... 8

e. Drawing Control Deficiencies ............................. 9

f. Check Valve Failures .................................... 11

g. Shift Technical Aovisor (STA) Trrining Program Improvements .......................................... 11

h. Post-Maintenance Testing .. ............................. 12

3. Operations ........... . ..................................... 12

a. Control Room and Local Plant Operations ................. 13 (1) Control Room Demeanor .............................. 13 (2) Status of Control Board and Local Instrumentation .. 14 '

(3), Control of Temporary Equipment ..................... 15 (4) Logs ani. Records ... ............................... 15 (5) Technical Speci fication Compliance . . . . . . . . . . . . . . . . . 16 (6) Shift Turnover Process ............................. 17 (7) Local Plant Operations ............................. 17

b. Temporary Procedure Deviations .......................... 18

c. Surveillance Testing .................................... 19 l

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d. Overtime ................................................ 20 l

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e. Training ,............................................... 20

f. Housekeeping ............................................ 20

g. Organization ............................................ 22

h. Fi re Brigade Organization and Training . . . . . . . . . . . . . . . . . . 22

1. Tagging . ............................................... 25

j. Ev en t Rev i ew Te am Repo rt s . .' . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 _

k. Post Mainten&oce Testing ................................ 28

1. Annunciator Response Procedures (ARPs) and Abnormal Operating Procedures (AOPs) ........................... 28

4. Pa i ntenance Support of Operation s . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

a. Review of Licensee Event Reports and Deficiency Cards Related to Maintenance Activities ..................... 29 b .- Review of the Work Planning Process . . . . . . . . . . . . . . . . . . . . . 31 -

c. System Walkdowns . ...................................... 31

d. Maintenance Work Order Review ........................... 33

e. Observation of Maintenance in Progress .................. 34

f. Review of the Maintenance Training Program .............. 35

g. Predictive Maintenance .................................. 36

h. Review of Management Involvement and Maintenance Work Controls ..........................,.................... 37

1. Engineering Support to Maintenance ...................... 38

j. Utilization of the Nuclear Plant Reliability Data System (NPROS) ..... .................................. 38

k. Review of Maintenance Work Order Backlog ................ 39 11 i - _ - , . . - _ _ . _ , _ . _ _ _ _ _ , , . _ _ _ _ _ _ , _ _ , . . . . _ _ _ _ , , , _ . , _ .- . _..__e

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5. Ma n a g ement Co n t ro l s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

a. Revi ew of Deficiency Card System . . . . . . . . . . . . . . . . . . . . . . . . 40

b. Design Change Request (DCR) ............................. 41

c. Independent Safety Engineering Group .................... 41

d. Plant Review Board ...................................... 42

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e. Engineering Support Departme'nt .......................... 44 ~-

f. Plant Status Meetings ....... .......................... 44

g. Performance Indicator Program ........................... 45

h. Operating Experience Program ............................ 46 .

1. Commitment Tre;(ing ............. ....................... 49

j. D';nc Mesponse to QA Audits ............................. 50 k .' Procedure and Drawing Control ........................... 51

6. Licensee Action on Previous Enforcement Matters .............. 51

7. Exit Interview ............................................... 53

8. Acronyms and Initialisms ..................................... 54 APPENDIX A -

MATRIX AND OPERATIONAL ASSESSMENT, HATCH UNITS 1 AND 2 APPENDIX B -

HATCH OPERATIONAL VPGRADE (May 4, 1988, Letter from R. P. Mcdonald, Executive Vice President, Nuclear Operations, GPC, to T. E. Murley, Director, Office of Nuclear Reactor Regulation) iii

q-REPORT DETAILS

1. Persons Contacted Licensee Employees

• T. Beckham, Vice President - Plant Hatch

• 0. Bennett, Plant Training Superintendent

• J. Davis, Manager, General Suppor.t

• R. Davis, Audit Supervisor, Quality Assurance (QA) ~ _..

• J. Fitzsimmons, Security Manager

• P. Fornel, Maintenance Manager

• 0. Frase , Site QA Manager

• M. Googe, Outages and Planning Manager

• J. Hammonds, Independent Safety Engineering Group (ISEG) Supervisor

• R. Hayes, Deputy Manager of Operations

• J. Heidt, Manager, Nuclear Licensing

• 8. Keck, Reactor Systems Engineering Superintendent

• H. Nix, Plant Manager

• 0. Read, Plant Support Manager

• L. Sumner, Operations Manager

• S.*Tipps~ Nuclear Safety and Compliance Manager

• E. Toupia, Senior Nuclear Projects Engineer

• R. Zavadoski, Health Physics and Chemistry Manager NRC Representatives

• M. Ernst, Deputy Regional Administrator

• P. Holmes-Ray, Senior Resident Inspector

• C. Julian, Chief, Operations Branch

• G. Lainas, Assistant Director for Region II Reactors., NRR

• J. Menning, Resident Inspector

• R. Musser, Resident Inspector

• M. Shymlock, Chief, Operational Programs Section

• M. Sinkule, Projects Section Chief W. Troskoski, Regional Coordinator, Office of Executive Director for Operations -

Other Personnel

• 0. Self, Oglethorpe Power Corporation Other licensee employees contacted included technicians, operators, engineers, mechanics, and office personnel.

• Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.

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2. Inspection of Operational Enhancements An Institute of Nuclear Power Operations (INPO) evaluation completed on April 18, 1988, identified deficiencies at the Hatch facility which led to a decision by the licensee to shut down both uniu to expedite corrective action. The NRC was advised ofR.the INPO findings by the P. Mcdonald, Executive licensee in a May 4, 1988, letter from Vice President, Nuclear Operations, Georgia Power Company (GPC), to T. E. Murley, Director, Office of Nuclear Reactor Regulation, NRC (Appendix B). The INPO report was transmitted to the NRC by letter dated ~

May 11, 1988, from R. W. Scherer, Chief Executive Officer and President --

GPC, to L. W, Zech, Chairman, NRC.

The OPA team reviewed the status of certain of the licensee-identified operational enhancements which the licensee had committed to implement prior to startup of the Hatch units. Discussions of the reviews of these items are provided below. The NRC reviews of the status of. other enhancements are documented in NRC Inspection Report Nos. 321, 366/88-12; 321, 366/88-13; 321, 366/88-14; and, 321, 366/88-16. In addition, the N'4C perfornted independent assessments of many of these areas. Discussions of these assessments are located in paragraphs 3, 4 and 5 of this report.

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a .' Operator Professionalis'm As described in the GPC letter of May 4, 1988, the operators at Hatch had developed a Code of Conduct for control room operations.

The inspecters reviewed the document and agreed with its content.

The document was distributed to each licensed operator and will be posted in the control room and other plant locations after it is printed. The Code of Conduct addressed clear communications, l

j monitoring of panels, response to alarms, control room access and l

other issues. The Code, developed and endorsed by the Operations Department, will provide a high standard for control rcom conduct.

The code is provided below:

CONTROL OF OPERATIONS IN THE MAIN CONTROL ROOM (1) The Operations "Line of Command" will be followed at all times l

in the conduct of operations, except in emergencies.

l Amplification - Self explanatory.

(2) Control room personnel will routinely tour the Control Room panels.

Amplification - Minimum once per hour front panels and once psr four hours back panels.

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3 (3) Contr_o1 Room front panels will be monitored at all times.

Amplification - A licensed member of the shift will be at the front panels at all times with no concurrent outy to distract from monitoring these panels.

(4) Only personnel on official business will be allowed in the main control room, as determined by the Shift Supervisor or plant Operator.

Amplification - The total number and the limiting number of 1.

non-shif t personnel will be monitored and authorized by these individuals - no one is exempt from these limits or authority.

(5) All personnel in the Control Room will conduct their business in a professional manner.

Amplification - Applicable to all personnel not just operators

- the control room is not a break area.

(6) The Control Room will be maintained clean and orderly at all

, times.

Amplification - Self explanatory.

(7) Control Room personnel will respond promptly to alarmed condi-tions utilizing appropriate procedures as required.

Amplification -

Responding to an alarm means to react to a condition, not silencing an audible as fast as possible -

responding promptly means as quickly as can reasonably be achieved except where the alarm is anticipated as a result of other operator action.

(8) Control room communications will be maintained as orderly as possible. Oral instructions will be verified to be clear as to actions to be taken. Written instructions will be ' clear, concise and legible.

Amplification -

The clarify and verify philosophy using position titles or personal names is the expected standard.

Legibility and proper closure of items in logs is the expectation.

(9) All personnel in the Operations Department support and endorse the "Excellence in Every Endeavor" philosophy of Plant E. I.

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The Code of Conduct was developed by the operators and was not intended to be a formal procedure to follow but rather similar to a

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code of ethics. Discussions with plant operators revealed that the operators were' knowledgeable of the Code of Conduct. During frequent tours of the control room, inspectors observed that the items in the Code were being followed.

The licensee stated in their May 4, 1988 letter to the NRC that a series of plant meetings would be held on plant professionalism. The President, CEO, and Chairman of the Board of GPC, had met with plant personnel to explain GPC's expectations for professionalism in the ~ _.

work place. The Executive Vice President had held professionalism philosophy discussions with plant supervisors and managers. The Vice President, Plant Manager of Operations, and other managers had held reviews and discussions regarding professionaliso. Additional seminars had been scheduled for shift supervisors, operations super-visors, and superintendents up throug.h Operations line management to the Vice President. The inspectors reviewed documents that outlined the topics covered in these meetings and the persons attending.

These actions were apparently performed successfully.

No violations or deviations were identified,

b. Lighted Control Room Annunciators Plant Hatch recently initiated a program for correcting problems with control room annunciators. A departmental directive was issued on May 2, 1988 titled, Control Room Instrumentation Policy. This policy stated that control room instrumentation and annunciator system availability and reliability should be maintained at or near 100 percent. The policy, although not a "black board concept" here the plant is operated normally with all annunciators cleared, is similar to a "black board concept". The directive called for an operations administrative control procedure to be issued to implement the directive.

Accordingly, procedure 30AC-0PS-009-05, Control Room Instrumentation, was issued Mt 6, 1988. This procedure provided the method by which Operations personnel were to control, track, and correct problems with all annunciators; track removal from and return to service of main control room instruments for corrective maintenance; and, provide tracking of compensatory monitoring actions.

Problem annunciators and instruments -were assigned a corrective action priority. Main control room front panel annunciators and instruments were given a high priority and placed on the immediate scheduling list. Back panel annunciators and instruments were given Local a lower priority and placed on the prompt scheduling . list.

panel problems were plai:ed in routine scheduling.

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l The inspector reviewed the annunciator log maintained at the shif t l supervisor's desk in each control room. This log contained an index of problem annunciators and an annunciator control sheet for each lit annunciator. Also, there was a compensatory action log index and a compensatory action sheet for annunciators where compensatory action such as increased monitoring was deemed necessary.

For Unit 1, a number of annunciators were deactivated for the drywell to torus differential pressure system since this system is no longer used. A computer orintout of action to be taken for problem annunciators was reviewed. Most of the problem annunciators _.

were being repaired prior to plant sta tup. The list was reviewed to determine if any alarm setpoint ci,anges had been made. The inspector reviewed design change request (DCR)88-101 which changes the alarm setpoints of the drywell temperature recorders. The OCR was approved by the Plant Review Board in meeting number 88-56 on April 14, 1988. The change was approved recognizing that the plant ~

Technical Specifications required that the drywell temperature be calculated every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as a volumetric average of temperatures at specific points in the drywell and does not provide any limits for annunciation functions.

The inspector concluded that the problem annunciators were being addressed for Unit 1 in accordance with plant instructions.

For Unit 2 the inspector reviewed the compensatory action log and found two items of concern. Item 2-88-5 requi ed that, during Reactor Core Isolation Cooling (RCIC) operation, 'n operator locally monitors the RCIC turbine coupling end bearing te iperature due to a f ailed temperature switch. The inspector questioied the staffing of this local monitoring position and whether RCIC c)uld be considered operable per the operability definition in the tt chnical specifica-tions. The licensee repaired this annunciator prior to taking the reactor critical.

Similarly, the compensatory action item 2-88-2 stated that during testing of Diesel Generator 2A, a local operator should be stationed when the oil temperature high alarm is lit. Discussions with Opera-tions personnel revealed that the alarm was occurring at 178 degrees rather than the desired setpoint of 220 degrees. The compensatory action was intended to be a precaution and there was no operability question concerning the diesel; therefore, the inspector's concerns were resolved.

The inspector concluded that the procedure for problem annunciators for Unit 2 was implemented and being followed.

No violations or deviations were identified.

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c. Operator Response to Transients (1) Emergency Operating Procedures In the May 4, 1988 GPC letter to the NRC, the licensee stated that a "ttchnical review has been performed to compare the Hatch Emergency Operating Procedures (EOPs) to the BWR Owners Group Emergency Procedure Guidelines (EPGs). The EPGs are the standard from which all plants develop site specific E0Ps. The review was conducted .by GPC and General Electric Company representatives and revealed no significant technical ~_.

deficiencies. Minor technical deficiencies were resolved."

During this inspection the results of the GE review were examined to confirm successful completion of the action-An NRC inspection team performed an independent assessment of the Hatch E0ps on May 2-10, 1988, to confirm adequacy. The results of that inspection are documented in NRC Inspection Report 321, 366/88-12. That report contains the detailed analyses of the E0Ps and concluded that the E0Ps are acceptable for continued operation of Hatch. It also concluded, however, that the present E0Ps contained numerous human factor weaknesses

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and were not totally consistent with the industry generic EPG strategy.

The GE review was performed prior to the NRC team inspection and concluded that the E0Ps were acceptable for continued operation but contained rumerous differences from the EPG. GE noted that the E0P flow charts are very complicated and contain much information and action direction that is not needed for basic accident mitigation. There might be some delay in taking some of the generic EPG actions due to the one path design of the E0P flow charts. Also some of the important EPG actions were conteined in prose procedures called End Path Manuals which were usually entered only at the completion of the flow charts. Thrs GE review also observed human factor deficiencies and recommended that further human factor studies be made of the E0Ps.

In the May 4, 1988 letter to NRC, the licensee stated that human factor improvements will be made. A short term improvement was made prior to restart by rephotographing the flow charts for better clarity and enlarging them for readability. In addition, a step was added early in the flow

(: hart to cause the operator to enter the end path manual for primary and secondary containment earlier in the chart. The inspector confirmed that these actions were complete and resulted in significant improvement in the flow chart readability.

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The licensee plans to complete a major revision of the E0Ps in the near future. The time required to accomplish this review is still under consideration. This revision will include a simplification of the flow enarts to consolidate or remove directions that are not part of the accident strategy. It will also minimize the number of steps, improve the language for operator use, and enlarge print size to make the charts more readable.

The licensee committed. to the NRC to perform a major critical review of the E0Ps and complete a major revision in a timely 1 ..

manner. Sufficient time should be allowed to ensure that a quality job is done, but due to the inherent importance of the E0Ps, priorities should be assigned. This finding is in agreement with the GE review and the NRC E0P team findings, documented in NRC Inspection Report 321, 366/88-12, that the Hatch EOPs differ significantly from the EPG in format, priority and accident mitigation strategy. The licensee should make a detailed critical comparison of the E0Ps and the EPG and either adopt the EPG philosophy or prepare an analysis to justify the differences between the two. The justification of plant specific differences was supposed to be an objective of the E0P

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development process that has been in progress for the last four years. That objective was not met and the licensee should perform priority work on this item. This matter will be reviewed further and is identified as inspector followup item 321, 366/88-15-01.

(2) Emergency Operating Procedure Upgrade Training The inspectors reviewed the documentation resulting from the operator retraining on Emergency Operating Procedures (EOPs) as committed in the licensee's letter of May 4, 1988 to the NRC.

This training consisted of simulator drills to improve the operator's response to transients and to sharpen .their use of the E0Ps. As a result of this training, seven operators (four Senior Reactor Operators and three Reactor Operators) were found to be deficient in E0P knowledge and skills and were removed from licensed duties. These seven individuals will be given additional retraining and af ter successful evaluation by the licensee will be returned to licensed duties. The inspector confirmed that these actions and plans were documented.

The licensee had an independent group of individuals from General Electric and private contractors, who were knowledge-able of the industry's practices and standards for operator.

licensing, evaluate the operators. The evaluation consisted of simulator drills using the E0Ps. The inspector reviewed the results of this evaluation by interviews with evaluators, b

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8 training department managers and review of documentation. The independent reviewers thought that the upgrade training was effective considering the short time conscraints and concluded that the operators' performance was acceptable. Several suggestions for improvements in future E0P training were made to the Training Department. The independent group thought that the crew response was at the industry average following training.

They stated that improvements could be made in the supervisor performance of control room command. The licensee plans to ,

factor these recommendations into future training. l The independent review group was critical of the Hatch E0P flow chart scheme. They commented ; at the series approach of performing steps in a fixed sequence slowed the crew response to deteriorating plant conditions. They commented that they ,

observed much operator frustration with E0Ps as presently l configured but that the operators could understand and use them much better following upgrade training.

(3) Upgrade of Standby Liquid Control System Simulator Modeling

. . During 'the Unit 2 refueling outage in the spring of 1988, the Standby Liquid Control System was modified such that a new concentrated boron, enriched in baron 10, is now used. Enriched boron provides an equivalent injection rate of 86 gpm (normal pump capacity .is approximately 43 gpm) with a single Standby Liquid Control pump in operation. Because of this inplant change, the Unit 2 simulator was modified (DCR 8803021) to reflect the use of the new boron concentration. The simulator modification was completed and functionally tested on April 15, 1988. The licensee had estimated that the modification package would be closed out by June 3, 1988, which would allow time for simulator performance to be trended against calculated data being provided by the Southern Company.

No violations or deviations were identified,

d. Plant Labeling The licensee had initiated an Action Plan designed to correct items associated with equipment labeling and labeling procedures. This i action plan included the development and implementation of interim I special purpose procedure 31SP-042088-1-05, System and Component

~ Labeling, Rev. O, and permanent administrative control procedure, 30AC-0PS-008-05, System and Component labeling, Rev. O. These procedures delineated the requirements for identifying and maintain-ing labels for plant eauipment and locations. Plant walkdowns were conducted in accordance with the action plan by Instrumentation &

Control (I&C) Maintenance, Operations, and Health Physics / Chemistry for the purpose of identifying unlabeled plant equipment and locations.

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The licensee corrected labeling deffeiencies in accordance with special jiurpose procedure 31SP-042088-1-05. Additionally, the itcansee completed the labeling of column locations. Training had been conducted for accropriate plant personnel in order to ensure the proper implementation of the system and component labeling program. To further ensure that proper labeling of plant equipment was maintained, the licensee had issued a Department i Instruction DI-MNT-26-0588N, Maintenance Department Responsibilities ,

for Labeling plant Equipment, Rev. O. The department instruction established the maintenance and I&C foremen as the individuals L responsible for ensuring that the plant equipment their crew / team works on, is properly labeled in accordance with 30AC-0PS-008-05.

The inspector concluded that the licensee action plan and procedural controls should adequately ensure proper plant equipment labeling.

No violations or deviations were identified. .

e. Drawing Control Deficiencies The licensee's program for maintaining control room drawings was reviewed. The licensee had recently upgraded control room drawing controls due to concerns identified by INPO. The licensee's old program was accomplished by maintaining control room drawings on aperture cards. Changes to these drawings occurring as a result of plant modifications, problems found during system walkdowns, etc.,

were accomplished by issuance of a separate document called an As-Built Notice (ABN). Long-term revision of drawings was and is accomplished by the architect engineer (A/E) by incorporation of ABNs in a revision to the aperture card, in the short-term, however, several ABNs could be issued against a drawing before a revision was issued. As a result, in order for a plant operator to ensure that he was reviewing the latest plant system configuration, he had to research the drawing and all of the issued ABNS, which in some cases could be a very time consuming and complicatt cask. In order to relieve the operator from this burden, the licensee initiated corrective actions to develop a new program which simplified the operator's role in the drawing update process. The licensee's new program consists primarily of the establishment of a "blue line" stick drawing file in each control room with system changes entered as "red lines" on the drawings by site engineering, referencing the appropriate ABN or Work Completion Notice (WCN). Review of licensee corrective actions in this area and the controls and implementation of the new program was the subject of a portion of this inspection.

The inspector reviewed the following attributes of the program with the following results:

(1) The licensee's new program was outlined in two site procedures:

01-ENG-31-048SN, Processing Work Completion Notice or As-Built Notice for Single Line, Elementary and/or P&ID Orawings -

Maintaining Control Room File, Rev. 1, and, 42EN-ENG-002-05, Work Completion and As-Built Notices, Rev. 2.

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1 10 Review of these procedures determined that an. adequate program had been established with two exceptions: neither of these two procedures specifically addressed who will accomplish "red lining" of the control room drawings nor when this action will be accomplished. Discussion of these two issues with the site engineering manager indicated that the "red lining" had been and

' will be accomplished by site engineering. -The goal for comple-tion of "red lining" would be prior to declaring the system operable after modification, but in no case would this action take longer than 30 days af ter the ABN/WCN package was issued. i The site Engineering Manager stated that he would generate revisions to the above procedures to address these two issues.

(2) As a result of the control room drawing concerns, a list of critical drawings was developed by the licensee. The latest revision of the drawing list was included in two memoranda from the A/E: File HXT 18 EWO 3569AK - Log SS-GP-8-4-545, E. I. Hatch Nuclear Plant Units 1 and 2 Critical Drawing Blue Line Copies, dated April 27, 1988; and, File HXT 18-1 -

EWO 3569AK -

Log SS-GP-8-4-546, E. I. Hatch Nuclear Plant Units 1 and 2 Control Room Elementary Blue Lines, dated

. . April 27, 1988. These lists consist of approximately nine hundred critical drawings which are to be maintained. The inspector reviewed these lists, and also discussed their development with site engineering personnel. The lists of critical drawings were established in a joint effort between the A/E, site engineering, site operations and site management.

Th1 inspector concluded that controls for establishment of the critical drawings lists were adequate.

(3) The inspector reviewed the training given to site engineering personnel on the new drawing program. The inspector determined the training to be adequate and also, determined that the training had been completed for all personnel (except those on extended leave) prior to plant startup.

(4) The inspector verified that the blue line stick files had been established for each control room.

(5) The inspector selected 20 drawings from the critical drawings lists for a more detailed review. The inspector verified, by comparison of Document Control records to the drawings in the control room, that the latest revisions of drawings were in the control room; and, that the applicable ABNs had been red lined on the latest revision.

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1 One administrative problem was discovered involving nine of the drawlngs above. In two cases, the blue line stick files in the control room had later revisions to drawings than uhat Document Control nad indicated was the latest revision.

Licensee personnel determined that this was caused by the fact that aperture cards and updated drawings are mailed by the A/E to two different site groups (i.e., aperture cards to site Document Control and revised drawings to site engineering) and therefore, drawing updates to the Document Control and the control room blue line stick files could occur at different -..

times. As a temporary correction to this problem, the licensee committed that all drawings and aperture cards would temporarily be mailed to site engineering who would ensure that the control room blue line stick files and Document Control aperture card file were updated at the same time. A meeting between site personnel and the A/E is to be conducted at a later date to determine a permanent corrective action for this problem.

No violations or deviations were identified.

f.. Check Valve Failures Based on INPO Significant Operating Experience Report (50ER) 86-03, Check Valve Failure or Degradation, the licensee developed a program to address the recommendations in the 50ER. This program will implement all the recommendations of the SOER. One of the recommen-dations included the performance of a design review for check valves in particular systems identified in the SOER.

This SOER was issued in October 1986, but recommendations in the report were not addressed until recently. This long delay does not indicate aggressive management attention to an important issue within the industry. The licensee currently plans to accomplish this design review by December 1989.

No violations or deviations were identified.

g. Shift Technic &l Advisor (STA) Training Program Improvements The inspector interviewed Training Department personnel concerning improvements to be made to the STA training program. The Training Department had a program underway to revise simulator guides to include STA learning objectives. The licensee had set September 1, 1988 as the goal for the completion of these revisions.

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12 The licensee had also revised DI-TRN-24-0885N, Simulator Documenta-tion Requtrements, Rev. 2, to require that each licensed STA be evaluated in both the SRO and the STA position at the completion of segment requalification training and on annual simulator examinations.

No violations or deviations were identified.

h. Post Maintenance Testing With regard to the post maintenance testing and surveillance of 1 plant equipment, the inspector reviewed the Maintenance Work Orde>

Functional Testing Assignment Log, dated April 30, 1988, which was developed by the licensee to provide casic post maintenance testing requirements for specific types and applications of equipment. The document, which appeared to be adequate in approach and general content, was scheduled for issuance as a controlled procedure in August 1988 as described in the May 4,1988 letter from GPC to NRC.

The success of this program will be evaluated during future inspections.

No yiolations or deviations were identified.

3. Operations (71707)

The inspectors performed extended observations of control room activities (including back shif ts), observed shift turnovers, and reviewed applicable operator logs. The inspectors monitored Operations personnel performance, awareness of plant status, use of procedures, and the maintenance of required station logs and status boards.

l The inspectors observed startup operations for Unit 2 on May 14-15,1988, and for Unit 1 on May 18, 1988. The inspectors observed control room activities as the plant operators took the units critical in accordance with General Operating Procedure 34GO-OPS-001-25, Plant Startup, Rev. 4.

During each startup equipment problems were encountered, but in each case the operating staff was thorough and proceeded cautiously until the situations were resolved. Positive control room demeanor and operating staff professionalism were noted by the inspectors during both startups.

Interviews were conducted with licensed operators and plant equipment operators during control room observations, system walkdowns, plant tours, observations of surveillance and post-maintenance testing, and tagging and removal of equipment from service.

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13 The following procedures were reviewed:

- 10AC-MGR-005-05, Operating Experience Program and Corrective Action Program, Rev. 3

- AG-MGR-27-0687N, Root Cause Determination, Rev. 1

- 42EN-ENG-011-05, Scrar/ Transient Reporting,~Rev. 3

- 30AC-0PS-003-05, Plant Operations, Rev. 5

- 31GO-OPS-007-05, Shift Logs and Relief of Personnel, Rev. 2

- 30AC-0P5-009-05, Control Room Instrumentation, Rev. O It was apparent that control room activities had received management --

attention. Examples of enhancements included the annunciator program, the program to limit access to the "at controls area" and procedure updates. These enhancements should contribute to safe plant operations.

a. Control Room and Local Plant Operations (1) Control Room Demeanor Control room activities were carried out in a professional manner. Reactor operators were attentive to control room

. . conditions, responsive to annunciators, and made use of procedures. When leaving the "at controls area" operators made certain that a qualified relief was obtained.

The shift supervisors were knowledgeable of plant conditions and displayed the same positive qualities that the unit operators displayed. Additionally they maintained a positive control over access to the "controls area." In general, control room operations was noted as'a strength.

Two concerns arose regarding the Shift Supervisor position.

First, it became apparent that the Shift Supervisor had a large administrative burden in addition to his prime function of being cognizant of his unit's status. While some duties must remain (e.g., authorizing work to begin, dispensing high radiation area keys, etc.), other clerical duties, such as maintaining a file on all work orders, radiation vork permits, and clearances could be eliminated or reassigned. The licensee stated that a third Shif t Supervisor may be utilized in the future to reduce some of the administrative burden.

The second concern involved the Shift Supervisor leading the fire brigade. The Shift Supervisor should remain in the control l room to assess situations. Others, such as the Shift Foreman, l could lead the fire brigade. This concern is addressed in more  !

detail in paragraph 3.h. l l

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14 (2) Status of Control Board and Local Instrumentation A walkdown of the control room operating panels revealed the following problems:

panel Instrument Discrepancy 1H11-P601 1821-623B Scale discolored with black ink marks - difficult to read scale.

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1H11-P601 1821-LR-R615 a. Labeled as "Reactor Vessel --

Level / Pressure." Actually only recorded level,

b. Scale was difficult to read,

c. Recorder paper units were difficult to read.

d. Two additional identification labels referred to blue pen as either "spare" or "percent,"

however, the bitt pen was not used on this reco,' der.

Blue pen not used, but liweled as 1H11-P601 1E11-P608A "percent."

1H11-P601 1E11-P608B Same as 1E11-P608A.

IN62-P600 N62-P604 Scales on recorder had increments of 2.1 on black pen and 50.2 on red pen. Unusual increments made recorder difficult to read.

1H11-P657 T48-R631A Drywell to Torus OP Chart scale was readable but no units were noted, i.e., psig, inches of water, psid, etc.

The inspector identified two electrical breakers which had been improperly labeled with the use of a black marker. The hand written labels proved to provide the correct information; however, D1-OPS-05-1084N, Control of Operator Aids, Rev. 1, l prohibited the independent labeling of components or systems in the plant. These examples were not typical of plant labeling practices and when brought to licensee's attention were promptly corrected.

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15 (3) Control of Temporary Equipment The licensee had a program to identify temporary equipment that was approved to remain in the plant for a designated period of time. This equipment was identified with a yellow Equipment Utilization Tag (EUT) and was controlled by AG-MNT-01-1184N, Use of Equipment Utilization Tags, Rev.1. Each department manager was responsible for designating which equipment required an EUT and to periodically perform field checks and update tags as expiration dates were reached. _

During plant walkdowns, the inspectors noted that many EUTs had exceeded the expiration date. Procedure AG-MNT-01-1184N states that this is not considered a deficient condition; however, it would appear that department managers were lax in maintaining a good tracking system for temporary equipment as evidenced by the numerous examples of past due expiration dates. -

(4) Logs and Records Logs and records, located in the control room, were reviewed.

A standing order book was available for use by plant operators.

The inspector reviewed the standing order for control rod movement, 50-0PS-03-0488, issued April 25, 1988. It stated that only one licensed operator shall be designated to move control rods, and shall have no other control duties other than rod movement. This operator shall either perform or direct rod l

movement until properly relieved by another licensed operator.

This standing order clearly provided the responsibilities for l

operators for pulling control rods. This standing order had l been incorporated into procedure 42FH-ENG-010-15 and -25, Control Rod Movement, Rev. 3.

Temporary wires / jumpers were handled as temporary modifications covered by plant procedure 30AC-0PS-005-05, Temporary Bypass, Jumper, and Lifted Lead Control, Rev. 1. The temporary modification log (wire / jumper log) w4s maintained in the control room. Twenty-four items were outstanding for Unit 2.

The plant procedure required a safety evaluation for each modification over 90 days old and a design change request for each item over one year old. Each of the items, where required, had the applicable evaluation or design change request attached or referenced.

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t 16 (5) Technical Specification Compliance During the startup of Unit 2, the inspector conducted a review of the Unit 2 Limiting Conditions for Operation (LCO) log to determine if LCOs were being properly dispositioned and closed out prior to changing unit Conditions. This review revealed that the appropriate closecuts were being tracked and closed out by operations; however, one "tracking" LCO was of interest and was reviewed in detail. LCO 2-86-514 was issued by plant operations to track the reinstallation of a residual heat ~

removal (RHR) system relief valve which had been removed in ~

November 1986 (the piping connection had been blank flanged at that time). The design section of the American Society of Mechanical Engineers (ASME) Code includes a requirement that all pumps must have a relief valve installed on their suction and  ;

discharge piping sections to provide overpressure protection {

unless there is a warning device installed to warn the operator i of an overpressure condition. Investigation of the above LCO revealed that no violation of Code requirements had occurred due to the following:

. .- The relief valve which had been removed and blank flanged was in the piping which is used in the steam condensing mode of RHR.

Other relief valves are installed or the suction and discharge sides of the RHR pumps which protect against an overpressure condition.

- The portion of this piping system which included the blanked off relief valve connection had been isolated from the rest of the system by Operations under their clearance system thereby preventing use of the steam condensing mode of RHR.

1 Once it was determined by the inspector that no violation had occurred, additional investigations were conducted to verify proper administrative controls were.in place to ensure system safety. The inspector investigated the following areas. i

- Reviewed the associated MWO, temporary modification and I the temporary ABN for the work.

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- Reviewed the 10 CFR 50.59 evaluation for the temporary i modification.

- Verified that the clearance isolating the steam condensing mode piping was still in effect.

- Verified that the clearance . tags were in place on the MOV electrical operators at the motor control centers and on the isolation valves themselves.

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- Verified that the temporary ABN had been "red lined" by

~ site engineering on the control room blue line stick file drawing.

(6) Shift Turnover Process Shift turnovers were conducted in a professional manner.

Checklists were utilized by the Shift Supervisor, the reactor operator and the STA to ensure that sufficient information was transferred regarding plant cor.ditions. Turovers included panel walkdowns and review of logbooks. A shift briefing was n conducted by the OSOS with Shift Supervisors in attendance.

Plant conditions and other items of importance (e.g., new procedures, temporary procedures) were also mentioned.

One concern was noted with the Shift Supervisors' turnover. The turnover was interrupted by phone calls and personnel. It would be useful to establish a "quiet time" during which the turnover can be conducted without interruptions. All plant personnel could be instructed not to make non-emergency calls to the control room during turnover period.

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(7)~ Local Plant Operations The inspector accompanied Plant Equipment Operatora (PEOs) (non-licensed operators) as they performed their rounds. Rounds were observed of both Unit 1 and Unit 2 "inside PEOs" and the "outside PEO " The "outside PE0" was responsible for equipment associated with both units but walkdowns were focused outside the main power block buildings. The PEOs observed were thorough and knowledgeable of equipment in their assigned area.

They immediately reported any equipment discrepancies to the control room and did not hesitate to ask questions of the control room operators when warranted. They maintained a professional attitude toward the performance of their duties.

The rounds sheets used by PEOs to record data concerning plant i equipment status reflected the previous eight-hour shift schedule log as far as frequency of data taken. Within recent weeks, shift personnel had gone to a 12-hour shif t schedule.

In a discussion with the Deputy Manager of Operations, the I

inspector learned that work had not yet begun toward revision of rounds sheets nor has a timetable been set for such revisions.

No violations or deviations were identified. ,

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b. Temporary Procedure Deviations Interviews with plant operations personnel indicated that an administrative burden was being placed on the pla~nt operators in processing temporary changes to plant procedures. Temporary changes were only valid for 30 days. Instead of being incorporated into permanent procedure changes within 30 days, the tempurary procedure change was processed again every 30 days. Temporary proceoure changes are ' administratad by plant procedure 10AC-MGR-003-05, Preparation and Control of.. Procedures, Rev. 7. A change required ~

approval by an SRO. This approval was the responsibility of the --

affected unit shift supervisor. The repeated processing of temporary changes appeared to be distracting the shift supervisor from monitoring other plant, activities.

Since a procedure upgrade program (PUP) was in progress, there was a tendency not to make permanent procedure revisions because the changes would be in the upgraded procedure. Also, a separate form was required to be filled out to initiate a permanent procedure change.

As an example, the inspector selected surveillance procedure 57ST/-SUV-010-1 from the temporary procedure change log index and ated several recent changes. Temporary procedure changes88-633 cated May 17, 1988,88-518 dated April 15, 1988, and 88-377 dated March 11, 1988, were made for this procedure. In each change one of the items was to change panel P921 to panel P924. Other repetitive patterns were noticeable in the temporary procedure change index.

The inspector concluded that the problem noted by most of the operators interviewed was valid. The extent of the problem was verified when it was discovered that six hundred and thirty-seven temporary procedure changes had been processed so far in 1988. This item was noted as a weakness. Also, the method to make a permanent procedure change was an extra burden requiring an extra form to be completed.

The inspector reviewed 18 recent temporary changes to approved procedures. All changes were prepared as directed by procedure 10AC-MGR-003-05 except for the minor discrepancies noted below:

(1) Surveillance Procedure 34GO-SUV-002-15, Surveillance Checks, Rev. 6, with Temporary Change 88-551. Page 17 of 32 had the originator's initials and date but lacked the Shif t Supervisor's initials and date. Also, the document control Temporary Change Number and Expiration Date were missing. This did not agree with paragraphs 8.7.1.3 and 8.7.1.5 of procedure 10AC-MGR-003-05.

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19 (2) Operating Instruction 3450-E11-010-15, Residual Heat Removal System, Rev.1, with Temporary Change 88-546. Attachment 1, page 3 of 4, step 7.1.43 revised valve 1E11-F022 from "open" to "close." The control room copy was not clear and only one initial and date for the changes was visible. The "open" still appeared unaffected on the control room copy. A review of the master copy of the change showed the change was made correctly in red ink but did not reproduce clearly.

The individual discrepancies were not safety-significant and were brought to the attention of the licensee for correction, however, _

the discrepancies could be indicators of lack of attention to detail in the temporary procedure deviation process which shoulc be evaluated by management.

No violations or deviations were identified.

c. Surveillance Testing The inspector reviewed 34GO-SUV-002-15, Shif t Surveillance Checks, in the control room. This procedure included numerous shift checks required by Technical Specifications such as leak rate checks. The

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operator denoted any problem areas identified during the surveillance by a red circle around the item with an explanation of the condition.

No problems were noted in reviewing this procedure.

On May 17, 1988, the inspector observed performance of the Reactor Core Isolation Cooling (RCIC) pump operability procedure, 345V-E51-002-25, RCIC Pump Operability. This procedure was performed at a power level of 16 percent. The procedure performed was done in four parts which included: RCIC system monthly test; RCIC ~,7p rated flow; RCIC pump inservice inspection test; and turbine data. One problem was noted when an annunciator was received for "RCIC turbine inlet drain pot high level." Manual valves on the drain pot were opened and only steam came out.

The RCIC system engineer was in the centrol room for the test and stated that a float type alarm actuator in the system had recently been replaced with a resistance temperature detector (RTD) alarm actuator. The RTD was apparently being af fected by steam in the drain pot. The shift supervisor stated the alarm would be resolved prior to declaring RCIC fully operable. The tests were performed in accordance with procedure. The inspector noted that the presence of the system engineer led to early identification and resolution of problems. The practice of using system engineers to support plant operations was noted as a strength.

The inspectors observed 345V-R43-006-15, Diesel Generator 1C Semi-Annual Test, Rev. 1, and 345V-E51-002-25, RCIC Pump Operability, Rev. 3. In each case the operators who ' participated in the surveillance, diligently followed the procedures. The procedures appeared to be adequate and easy to follow.

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l Performance of procedure 575V-C32-002-25, Reactor Pressure for Level Density Correc cion , was observed from the Unit 2 control rcom.

Surveillance procedures were located in the control room and et the field position. Communication between the instrument techni:ic- .9 the unit operator and between the instrument technicians was gv Oata was properly gathered (as found and as left) and a mechanisi.,

existed for noting out-of-spec-parameters.

No violations or deviations were identified.

d. Overtime n, The inspector reviewed overtime records for Operations perscnnel to ensure compliance with Technical Specification guidelines. The time periods selected for review were January 1988 when l' 't 2 was in a refueling outage and April 1988 when no outage was i ' ogress.

l Prior to the Unit 2 outage in January 1988, the Manager of Operations requested (letter LR-0PS-005-0183) that the Plant ".enager approve an outage shift schedule for Operations personnel, ihat shif t schedule required 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> to be worked in a 7-day period which exceeded tne Technical Specification guidelines of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> wifhin a 7-day period and therefore, required Plant Manager apptoval. Approval of that work schedule was granted by the Plant Manager as documented in licensee letter LR-MGR-004-188.

During tho month of April 1988, no operations personnel exceeded Technical Specifications overtime guidelines.

No violations or deviations were identified.

c. Tr- ing The inspector reviewed how new plant procedures were introduced to ,

the plant operators. At the shift turnover meeting, the shift technical advisor (STA) conducted a brief training sestion on new procedures, procedure revisions, or industry eve.as. Training involving procedure revisionc involved highlighting only the changes.

The inspector reviewed the beginning of shift log training shcets for the past atonths. Thirty-eight procedures plus industry events were covered during the past months. The STA stated that the procedures were also covered again in requalification tr41ning. The inspector felt the training provideJ by the STA was effective and timely.

I No violations or deviations were identified,

f. Housekeeping Tours in the Turbine 9uilding and. Reactor Building were conducted.

The results of these tours showed the facilities to be in generally good candition. The major pieces of equipment appeared clean a nd-had few oil leaks.

s 21 Cn May 12, 1988, the inspector toured the recombiner building and diesel generator with plant personnel on a routine housekeeping tour. A housekeeping inspection form was completed in accordance with plant procedure 30AC-OPS-002-05, Plant Housekeeping and Cleenness Control.

For the recombiner building, non-acceptable *atings were identified for "trash or debris buildup" and "housekeeping satisfactory". The following deficiencies were identified:

Gas bottle not in storage rack, tied off with one piece of rope ~ _..

Scaffolding leaning against statiwell and not tied off Cable rolled and laving on top of cabinet 1011-P003A

- Loose insulation stacked on tup of coatrol panel for electric boiler 1N62-0530 1N62-F507 leaking around pipe to valve connection Non-labeled breaker on IR 23-S015 is racked out with no tag attached to the breaker For the diesel generator building non-acceptable ratings were identified for "trash or debris buildup"; "er.ui pment properly and clearly identified where applicable"; "smoking evidence in non-3moking arear"; and "housekeeping satisfactory". The deficiencies identified were as follows:

IC Diesel Generator (0/G) drop cord in switchgear room next to 4160 volt tas 1A D/G wire and chain laying in fire protection louver area 1A 0/G 4160 vcit 1E switch gear room had a spare breaker in the middle of the floor with no equipment utilization tag 1A D/G 4160 1E switchgear room, valve 1P41-F317A has no positive indication Cigarette butts in the hallway and D/G butiding in a "No Smok-ing" area Battery tester on top of 1X43-P006A in the hallway

- One set of fira louvers shut by outside door in 4160 volt 1E switchgear room, all others are open 18 0/G switchgear room, 0-200 amp meter for 1E11-C00200 had loose glass which is held together by tape

- 2C O/G room, conduit covers missing on X41-C028B and X41-C0300 louver door.

- 2C D/G "add lube oil here" information plate no longer attached to D/G 4160 volt 2F switchgear room fluorescent light fixture by outside door required bulb replacement 2A O/G electrical outlet cover missing 2A 0/G switchgear room 2P41-F315A had no positive indication 2A 0/G switchgear, circuit breaker control for core spr.ay pump "2A" (2E2-1-C001A) had no light indication "0/G - 135" label plate found on hallway floor

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22 The plant _ personnel were critical and thorough in documenting def t-

} ciencies and the inspector later observed that prompt cleanup action oserved during other was taken. Other areas of the plant were inspection' activities. Areas of the plant such as the reactor building which were frequently toured were neat and orderly. Signs of the plant's age were evidenced by rusted components. The inspector concluded that continued emphasis on housekeeping of the less frequently toured areas and generai material preservation was needed.

No violations or deviations were identified. _..

g. Organization The on-shif t Operations crew at Hatch is headed by an Operations Supervisor on Shif t (0505) who holds an SRO license, and two Shift Supervisors, eacn an SRO, who oversee each unit. The crews are on a twelve hour shift (7:30 - 7:30) with' fivs operating crews. Plant operators wear uniforms and identification badges. Plant procedure 30AC-OPS-003-0S, Plant Operattoas, provided the administrstive controls for Operations personnel. This procedure discussed the f o_llowing:

- Conduct of Operations Conduct of Personnel in tne Main Cortrol Room

- Manipulation of Controls Overtime Shift Relief and Turnover Manning of the Control Room Shift Logs Shift Records

- Recall of Off Duty Personnel

- Notifications and Reporting Shift Technical Advisor Duties

- Required Procedures

- Maintenance Support During Outages

- Reset of Lock-out Relays and Relay Targets

- Secondary Contain ent Access Review of Data The inspector reviewed this procedure and determined that bssed on control room observatinns, plant operations appeared to be conducted in a disciplined manner in accordance with the procedure.

No violations or deviations were identified.

h. Fire Brigade Organization and Training Procedure 40AC-ENG-008-05, Fire Protection Program, Rev. O, para-graph 8.2.2.. 3, stated that the Unit 2 Shift Supervisor will act as Fire Brigade Le'ader curing a fire provided he is a qualified Fire

. 1 23 Brigade member. If he is not qualified, then he will be replaced by the On-Shift Shif t Supervisor that is quaiified. Attachment 5 to the above procedure illustrated the Shift Supervisor as the Fire Brigade Leader. Although TechnicC Specifications permit the Shift Supe

• visor to leave the control room to lead the Fire Brigade, it did not appear to be prudent to remove the Shift Supervisor from the control room when he aight be needed as a consequence of the fire.

The licensee concurred with the inspectors' concerns and stated that in the near future, they hope to qualify the SF' f t Foremen as Fire Brigade leaders and remove the Shift Supervisors . om that duty. It ~

is recognized that this change would require changes to the fire --

hazards analysis.

The inspectors reviewed the training records of selected fire brigade members as listrd on the fire brigada roster dated April 25, 1988. The training records were reviewed to determine compliar.:e with the requirements of Procedure 40AC-ENG-008-05, paragraphs 8.2.2 and 8.2.3. The following discrepancies / concerns were noted:

(1) Procedure 40AC-ENG-008-OS did not define the required interval between training sessions for fire brigade quarterly retraining

. _ or annual burn training. \ fire brigade member can take quarterly training on the last day of a given quarter and then take the 'ame training on the first day of the folicwing quarter. This was also true of the annual burn training. I n-acdition, the start of quarters or annual period was not defined. The licensee stated that quarterly trai.ning started July 1 and annual training was by calendar year.

(2) One individual completed initial quarterly classroom training on June 22, 1987, completed initial quarterly drill practice on July 3,1987, and then completed his initial leadership training on October 28, 1987. The individual was placed on the qualified fire brigade leader roster on July 31, 1987, prior to completing his leadership training. Although his initial training spanned three different Quarterly pericds, required quarterly retraining for topics covered in the first part of the initial training was apparently not ccmpleted.

l (3) One individual had been certified as a Fire Brigade leader each quarter since the first quarter of 1987. No record of the individual having completed his qvarterly ' leadership training '

for the first three quarters of 19d7 could br. found.

(4) Anocher individual had been certified as a Fire Brigade Leader since the first quarter of 1987 but did not .ccomplish quarterly leadership training for any quarter of 1987. To make up some of the previous missed leadersh~1p training, the individual l

completed three leadership courses on the same date (March 23,

! 1988) during the first ouarter of 1988. 40AC-ENG-008-05, l aaragraph 8.2.3.3.7. allows a fire brigada member to attend a 1

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24 make-up class the following quarter to retain qualification, however, if the member misses two quarterly classes he becomes unqualified and must take the initial 64 hour7.407407e-4 days <br />0.0178 hours <br />1.058201e-4 weeks <br />2.4352e-5 months <br /> training to become requalified.

(5) One individual failed to take quarterly drill and leadership training during the second quarter of 1987. The individual took a make-up quarterly drill during tne third quarter of 1987, but failed to take the make-up leadershio training.

A Quality Assurance audit (87-Fp-J', dated September 2,1987, was conducted to meet TS 6.5.2.8 (j). Tnis audit identified the problem that new Fire Brigade Leaders were appointed prior to receiving their leadership training. This finding addressed part of the discrepancies noted by the inspector and corrective actions have been taken. Also, interviews with Operations indicated that a list of qualified Fire Brigade Leaders or fire brigade members was not available to all personnel. If the Operations Department was notified by Training that someone was unqualified, that individual was verbally informed of the loss of his certification. A current list of qualified individuals should be readily available to shift personnel.

Although the QA audit had identified a problem regarding leadership training, the inspector was concerned thet the controlling procedure was not precise enough to prevent abuses of the intent of quarterly training and that training was neglected to meet other operational needs. Licensee representatives stated that a training procedure l

l was recently put in place to control this trair ing, but the old I

procedure is still in force. This discrepancies should be resolved.

The licensee is reviewing this matter and looking for additional training records to resolve the discrepancies identified above. This matter will be considered unresolved pending further review during a future NRC inspection. (URI 321,366/88-15-02)*

The informal methods used to control the roster of qualified fire brigade leaders and members and the imprecise administrative instruction controlling training was considered to be a weakness.

No violations or deviations were identified.

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" An unresolved item is a matter about which more information is

! required to determine whether it is acceptable or may involve a violation or deviation.

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1. Tagging ._

The inspectors observed several tagging . operations and reviewed procedure 30AC-0PS-001-05, Control of Equipment Clearances ano Tags, Rev. 4. That procedure clearly stated the controls used for tagging activities. The procedure was noted as having a well defined definition of "independent verification." The inspector observed that "independent verification" is conducted by strict interpretation of "verification must be separated from the activity by time and distance" as stated in the procedure.

On May 12, 1538, the inspector accompanied a plant equipment operator (PEO) to tag out the "B" train of the standby gas treatment system for surveillance testing. Clearance 2-88-1077 was performed in accordance with clearance procedure 30AC-OPS-001-05. The PE0 performed the first verification of the tagout by himself. Then the clearance sheet was given to another PE0 for second party verifica-tion. The PEOs and other operators all stated that independent verification was performed "separated by time and distance." The inspector noted no problem during performance of the clearance.

. Since several tagouts were reviewed which included electrical break-ers, it was noted that most of those clearances list only the motor contrcl center (MCC) or switchgear number with a word description of the breaker to be tagged. Seldom does the clearance include the actual breaker number. Lack of this information requires the PE0 to search the entire MCC to find a particular breaker. The inspectors were informed that an updated electrical load list is being prepared in conjunction with the plant labeling program. The completion of a revised electrical load list would be an opportune time to consider

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adding breaker location information to each electrical tagout.

Procedure 30AC-OPS-001-05 required that equipment clearance sheets and the index/ audit sheets be reviewed by the shift supervisor on a monthly basis. Also, all extended clearances were 'to be physically verified quarterly for proper placement of tags and proper position-ing of tagged equipment. A review of tagging records for 1988 indicated that the licensee had performed those required audits within the allotted time.

Within the last few months, the position of shift foreman has been created in the Operations Department. The shift foreman is a licensed reactor operator (RO) who is respor.sible for directing the activities of PEOs. As such, he is aware of all tagouts and those surveillance activities supported by Operations personnel (PEOs).

The creation of this position should relieve the Shift Supervisor of direct supervision of PEOs involved in tagging operations. The creation of the foreman position was observed to be a strength. In general, those activities associated with tagging appeared to function smoothly.

No violations or deviations were identified.

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26 J. Event Review Team Reports Major operating events such as reactor trips and plant transients were given a detailed review and analysis by an Event Review Team (ERT) as specified in procedure AG-MGP-31-0787N, Event Investigation Instruction. The review team provided a formal report to plant management. Included in the report was a root cause determination according to administrative guideline AG-MGR-27-0687N, Root Cause Dete rmination . Corrective actions were recommended and tracked.

The inspector sviewed the ERT report log for 1987 and 1988. From n-this review it was difficult to tell which reports were open and which reports were closed. Only by reviewing the tracking forms for the corrective action items for a particular report could the determination be made. Af ter all items are considered completed no formal review of the corrective actions for timeliness and adequacy was made. This was noted as a weakness. Proper closeout should include a letter back to plant management, the ERT leader, or the Plant Review Board, that all actions were completed.

The inspector reviewed ERT report 88-3 concerning exceeding the cooldown rate of 100 degrees per hour and possible main steam line fl5oding. TLis event was reported to NRC by the licensee in Special

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Report 88# During the event, the water level continued to increase , the upper scale of the control room water level indi-cators (ou inches). There is one water level indication, termed the flood-up indicator (recorder 2821-R605), which is used when the vessel head is off and the vessel is flooded. The flood-up indicator was inoperable. This indicator is not required by plant Technical Specifications. However, this indicator was inoperable during the entire event, depriving the operating staf f of their major diagnostic tool in recognizing the cause of the excessive cooldown. The instrument was inoperable due to an air bubble in the reference leg.

This was stated to be a chronic condition due to improper sloping of the reference leg. ERT report 88-3 recommended correction of the reference leg problem.

On May 17, 1988, a tour of the Unit 2 reactor building was conducted  ;

to inspect the instrument lines from water level instrument 821-N027 I to the drywell penetration. The instrument line appeared to have an upward slope until reaching a point in front of the reactor water cleanup heat exchanger room on elevation 158. At this point, the i inspector noted a six-foot vertical drop in the line followed by an upward slope until the line entered the drywell . The six-foot vertical segmen'. contained a vent valve and drain valve in the line.

The vertical segment appeared to be the problem identified in ERT report 88-3. Plant drawing 2821-127 showed the six-foot vertical drop. Also, on the drawing was a note that tubing should be sloped

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27 a minimum of one quarter-inch per foot. Using this water level instrument when flooding up the vessel with the head off would seem acceptable provided that venting of the vertical segment was completed prior to use. However, using the instrument at other times under varying water levels, temperatures, and pressures, air bubbles may occur causing inaccurate readings.

Unit 1 instrument lines were traced out and the lines contained no vertical drop and had appropriate slope to the lines. Plant operators stated that no problems had been experienced with the Unit 1 level indication. 1 The flood-vo indicator is calibrated for cold conditions and thus is not accurate for hot operating conditions. There is an operation's ccncern that this instrument cannot be relied on for hot conditions. The inspector reviewed a letter from Engineering to Operations dated April 8, 1988, concerning the shutdown flooding instrumentation. This letter proposed an extrapolation formula and chart to be used for an approximation of reactor vessel water level beyond plus 60 inches during the hot operating condition. The letter indicated that utilizing this method was both the short-term and long-term solution. The inspectors recommended to plant management that the ERT report recommendation to correct the reference leg problem be implemented.

In addition, among other recommendations, the ERT recommended that light check capability be provided for the full core display if possible. Following a scram, the operators had difficulty deter-mining "all-rods-full-in" due to burned out light bulbs. The inspector reviewed a letter dated March 23, 1988, to the licensing division stating that no known vendors supply a lamp test :ystem. A program of preventive maintenance to insure valid indication from the full core display should include changing the light bulbs regularly. The final resolution of this item could not be determined.

The inspector noted that during the Unit 2 reactor startup on May 14, 1988, that after withdrawal of four out of the first eight control rods, the reactor startup was delayed until the control rod "full out" burned out light bulb could be replaced.

These two examples of the water level indication problems and full core display burned out light bulbs point to a need for a detailed review and closecut of the event report. This event occurred on January 13, 1988, but the status of the corrective actions was still not definitive as of May 1988.

No violations or deviations were identified.

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k. Post Maintp ance Testing The method by which functional testing is scheduled was reviewed by the inspector. Typically, the requirements for post maintenance tests are determined by the Maintenance Planning Department. Prior to performing any functional test, Operations reviews the testing requirements to ensure adequacy. Daily, each shift supervisor is given work packages that require post maintenance testing. That testing is conducted based on plant status and availability of equipment. The system cf scheduling post maintenance testing ~~

appeared to work satisfactorily.

Twelve maintenance work orders (MW0s) were reviewed for post-maintenance testing. Each MWO received a review for quality control hold points, local leak rate re-test requirements, and equipment qualification. MWO 2-88-2067, dated April 18, 1988, was being held for an operability test. This MWO concerned the recirculation motor generator set "A" scoop tube positioner. The scoop tube actuator was found to be binding mechanically causing erratic tube movement.

The thrust bearing was bad and was replaced. No problems were noted during the reviews.

No violations or deviations were identified.

1. Annunciator Response Procedures (ARPs) and Abnormal Operating Procedures (A0Ps)

The copies of ARPs and AOPs in the control room were reviewed for Different formats for the procedures were noted. For adequacy.

example, procedure 34AB-0DS-022-15, Inadvertent Initiation of ECCS, effective April 5, 1988, was formatted as follows:

1.0 Conditions 2.0 Automatic Actions 3.0 Immediate Operator Actions 4.0 Subsequent Operator Actions 5.0 References Procedure 34AB-OPS-033-1, Inability to Move a Control Rod, dated September 6, 1985, was formatted as follov3:

A. Conditions B. Automatic Actions C. Operator Actions D. Subsequent Operator Actions The inspector learned that the ARPs and AOPs were part of the proce-dures upgrade program (PUP) which started in January 1986. The AOP, Inadvertent Initiation of ECCS, had been upgraded as part of the PUP program and while the ACP, Inability to Move a Control Rod, had not been upgraded.

Y 29 Out of 2000 ARPs and AOPs, about 850 had been upgraded. The rest were scheduled for completion in late 1988 or early 1989. Since ths emergency operating procedures (EOPs) are coupled to the AOPs and ARPs, the AOPs and ARPs should have been completed when the EGPs were completed. Although these procedures are scheduled to be upgraded, priority should be placed on completion of the ARPs and AOPs which are coupled to E0Ps. Also, the commitment for completion of the PUP program needs to be firm.

The inspector noted that. AOP 34AB-FPX-053-25, Fi re Procedure, Rev. 3, concerning fire protection for Unit 2 was not with the other _.

AOPs. The procedure was found in a notebook under the computer in the control room. In Unit 1, the procedure was in a red notebook.

The licensee stated this procedure for Unit 2 would be placed in a red notebook similar to the Unit 1 procedure.

One positive initiative was noted. The licensee was moving the annunciator response instructions, n'ow located in notebooks behind the operators desk, to individual notebooks placed in clear plastic holders located at each applicable panel. This will make the instructions more readily available and easier to locate.

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No violations or deviations were identified.

4. Maintenance Support of Operations (62700, 62702, 71710)

The inspectors reviewed station administrative controls; conducted inter-views with workers and supervisory personnel; and reviewed work packages, work requests, deficiency cards, the maintena9ce planning process, the maintenance backlog and the preventive / predictive maintenance program to ascertain whether the licensee was implementing an effective program relative to maintenance activities. The review included the maintenance organization work procedures, maintenance programs and the interf ace with operations. Interviews were conducted with maintenance supervisors, the i

l planning supervisor, and a number of craftsmen, foreman and supervisors in the mechanical, electrical, and instrumentation and controls areas.

Interviews indicated an overall good knowledge and understanding of main-tenance duties and responsibilities.

I a. Review of Licensee Event Reports and Deficiency Cards Related to Maintenance Activities The inspector reviewed LERs issued during 1987 and 1988. Of the LERs reviewed, eleven were found to have inadequate maintenance as a contributing factor. The inspector also reviewed the licensee's listing of significant-Deficiency Cards issued during the past year, and selected 100 of the items for further evaluation. Of those l items, 22 appeared to be caused by inadequate maintenance, and an additional 25 had elements of maintenance involved in the event causes.

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30 Four of t.he LERs which involved maintenance personnel were selected s

for review. The inspector verified, through review of the associated documentation and discussions with supervisory maintenance and train-ing personnel, that adequate root cause determinations had been mada for the documented deficiencies, and that ap ropriate corrective actions had been specified. The inse -tor noted that, in some of the other LERs, the root causes were incorrectly specified, however, in each of those cases, the event cause discussion in the LER was sufficiently thorough and well explained that the actual root cause was apparent. The inspecter.also verified that root cause training is being provided to the appropriate maintenance personnel. _

From the listing of deficiency cards (DCs), the inspector selected two cases of repetitive equipment failure for further review: a series of ten OCs which involved excess flow check valves (EFCVs) exhibiting double indication or lack of indication; and, a series of 11 DCs which involved spiking and erratic behavior of intermediate range monitors (IRMs). The inspector discussed the corrective actions taken for the two specific series of repetitive failures with the I&C Superintendent and the Plant Engineering Supervisor.

The trending of deficiencies and the ways in which changes are made in PM testing and surveillance requirements as a result of repetitive deficiencies was also discussed.

With regcrd to the repetitive EFCV indication problems, all of the deficiencies were identified as the result of surveillances during plant outages. Since repetitive indication problems had not occurred during operation, no corrective action had been planned by the licensee other than to fix the individual failures as they occurred.

The IRM spiking and erratic behavior pioblems appeared to involve temperature / humidity effects on connections. The licensee's correc-tive actions have been to clean or replace the defective connections. The licensee indicated that longer term corrective actions, such as installation of now cabling, had been discussed, but that no long-term corrective actions had been scheduled or  !

engineered.

As a follow-up to the review of repetitive deficiencies, the inspec- l tor reviewed the licensee's trend analysis program, specifically as it related to equipment f ailures and maintenance histories. At the j Maintenance Department level, a series of systems reviews, each of which surveys a two year period of corrective maintenance of a selected system, was initiated in early 1988. The I&C organization had also recently begun trending equipment failures in that area.

The inspector reviewed one example, a May 9,1988 report on repeti-tive failures of specific Barton Delta P indicating switches. At j the plant level, the Nuclear Safety and Compliance Department I trended deficiency cards and LERs. In that connection, the inspector reviewed LER Trend Report No. 88-1, dated March 9, 1988, which trended events occurring from January 1987 through December 1987.

4 c 31 The inspector's review of the licensee's trend analysis pr) gram, as related to maintenance activities, resulted in the conclusion that the program, as presently constituted, provides meaningful data on equipment failures and maintenance histories. -This ~ data is beginning to be used widely to specify service, surveillance and testing requirements to minimize repetitive or continuing deficiencies.

No violations or deviations were ider.tii f ed,

b. Review of the Work Planning Process _..

In reviewing the work planning process as it related to the maintenance area, the inspector interviewed the Manager of Maintenance, the Plant Engineering Supervisor, the Planning and Controls Superintendent, and the Supervisor, Planning & Control.

The inspector also reviewed and discussed with the appropriate personnel the Nuclear Plant Maintenance Work Order (MWO) form and Administrative Control Procedure 50AC-MNT-001-07, Maintenance Program, Rev. 7. Procedure 50AC-MNT-001-07 established the requirements and responsibilities for the control of maintenance acU vities, including the initiation, preparation and issuance of MW0s and work packages.

The inspector verified through the above discussions and reviews that the maintenance work planning process at Hatch adequately provided for the preparation and prioritization of work orders and work packages, the proper interf ace among Planning, Operations, and Maintenance personnel, the assurance that Technical Specification and post-maintenance testing requirements were met, and the periodic review of overdue work requests. The work planning process in the maintenance area appeared to contain the necessary elements, to be well understood by tha supervisory personnel involved, and to be a -

strong point of the licensee's maintenance program.

No violations or deviations were identified.

c. System Walkdowns During the assessment, the inspectors conducted system walkdowns of the Unit 2 control rod drive hydraulic (CRDH) system and the high pressure coolant injection (HPCI) systam with the site ' systems engineers responsible for the systems. The walkdowns were conducted using piping and instrumentation drawings H-26006, Rev. 13, and H-26007, Rev. 21, for tne CRDH system and system operating procedure 34S0-E41-001-15, Rev. 4, for the HPCI system. The walkdown verifieJ proper labeling of components, proper locking of locked valves, instrumentation operability, maintenance, housekeeping, and scaf-folding control. In addition, operating procedures andAll surveillance attributes procedures for the systems were audited for adequacy.

were verified to be satisfactory.

L 32 One problem occurred during the CROH system walkdown which indicated a weakness in the responsiveness of Health Physics personnel to clothing contamination problems which may occur in the plant, During walkdown of the CROH flow control station, the inspector noticed a puddle of water under the stction which was coming from a leaking valve in the station. Before the water was noticed, the site systems engineer had stepped in the water. Upon exiting the reactor building, the hands and feet frisker alarmed when the systems engineer frisked prior to entering the control room area. The engineer went immediately to the Health Physics station where it was determined that his shoes had been contaminated. Inspector followup

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of this problem with the systems engineer, maintenance personnel, health physics personnel and reinspection of the affected area revealed the following:

- There was an existing deficiency card (DC) and an MWO on the leak (DC 2-88-2317 and MWO 2-88-2494).

- The systems engineer issued DC 2-88-2355 on the leak because he believed that the leak was coming from a different valve than that described on DC 2-88-2317.

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- ~ It took site decontamination personnel end Health Physics personnel over twenty hours to gain proper control over the area by cleaning up the water and installing a funnel and tubing to the nearest floor drain.

Discussion of this problem with Health Physics personnel determined that Health Physics had looked for the spill on the day it was reported, however, the spill had not been located. Only additional followup by the systems engineer, the next day, resulted in proper control of the area. Site management should take action to improve the response time to this type of contamination control problem.

During the walkdown of the HPCI system, the inspector found looIe untaped cables on the HPCI turbine. A temporary modification tag, labeled 81-174-80, was attached to one of the loose wires. Further review indicated that during implemantation of Design Change Request (DCR)81-174, a vibration transducer had been removed from the HPCI turbine that was not included in the OCR. The purpose of DCR 81-174 was to move various HPCI instrumentation to a milder environment.

The vibration transducer fed a control room vibration meter that was not safety-related and was not currently in use; therefore, there was no safety significance to the error. However, work was not appropriately controlled on the OCR. Failure to tape and tag the loose cables was also a poor practice.

33 In addition, during the HPCI review, the inspector noted that the suppression pool area temperature monitor, wh4:h provided a trip of the HPCI turbine on high suppression pool area temperature, had a 30 minute timer in the trip circuit with a reset switch available in the control room. A review of Technical Specification 3.3.2 indicated that although the TS specified that the trip functior. c "'.d be generated at 169*F, there was no required response time for the trip function. Interviews with licensed operators revealed that both emergency operating procedures and annunciator response procedures addressed the control of the timer reset to assure operation of the -

HPCI when required. The inspector had no further questions. --

No violations or deviations were identified,

d. Maintenance Work Order Review During the assessment, completed .naintenance work order packages were reviewed by the inspectors to verify the effectiveness of maintenance program implementation. This review verified the following attributes, as applicable, to each work package:

_ The MWO was reviewed for proper completion and close-out.

- The description of actual work performed was reviewed for the scope of the work and was con pa red to the applicable maintenance procedure to assure all work performed was properly authorized.

- The data sheets from the appropriate maintenance procedures were checked for proper sign off and recording of required data.

- The maintenance procedure was reviewed against the vendor's manual, where appropriate, to verify that all vendor require-ments and recommendations had been included in the procedure.

Material records were reviewed to assure that certified material had been installed where required. Additionally, a sampling of receipt inspection records were reviewed to verify material acceptability.

- The technical bases for torquing requirements were verified, where appropriate.

- Proper use of in-date calibrated instruments was verified.

- Proper sign-off of quality control hold points was verified.

- Post-maintenance testing procedures and data were reviewed to verify proper completion of post-maintenance testing and functional testing.

34 The following maintenance work orders were included in this review.  ;

All concerns developed from the review were referred to licensee persornel. All concerns were adequately resolved by the licensee. l (1) MWO 2-88-1240, Repack of RCIC Valve 2E51-F008 (2) MWO 2-888-1325, Stem Replacement of RCIC Valve 2E51-F007 (3) MWO 2-88-3973, Replacement of ASCO Solenoid Valves for MSIV 2821-F022A (4) MWO 2-88-2240, MSIV 2821-F022A Air Leak (5) MWO 2-88-2235, MSIV 2B21-F0022A Failed to Close in 5 Seconds (6) MWO 2-86-7887, PM Involving Overhaul of HPCI Pump ~ _.

(7) MWO 2-88-0704, Replacement of Main Steam Relief Valve l No violations or deviations were identified.

e. Observation of Maintenance in Progress The following work packages for jobs in progress were reviewed and observations of work in progress conducted:

a. MWO 2-88-2581, MAC Testing of RCIC Valve 2E51-F045

b. , MWO 2-88-2349 and 1-88-2350, Reorientation of ASCO Solenoid Valves (to the Vertical Position) for Standby Gas Treatment Valves 1T41-F032A and 1T41-F0328

c. Functional Test on Unit 1 IRM C51-X601C

d. MWO 2-88-2135,, RHR Service Water Pump Motor Oil Leak and Pump Mechanical Seal Replacement

e. MWO 1-88-2290, RHR Flow Recorder Circuit Card Replacement and Calibration During a field inspection, NRC observed that the ASCO solenoid valves to the air operators of the suction valves, 1T41-F032A and IT41-F032B, on the standby gas treatment system were not oriented in the vertical and upright position as required by procedure 52GM-MEL-011-05, Installation and Maintenance of ASCO Solenoid Valves, Rev. 1,Section I.l.b and by the vendor instructions for a model 206-380 ASCO solenoid valve. It was determined that the orientation did not meet the environmental qualification requirements for the solenoid valves. The failure to maintain the quality standards for installation of the Model 206-380 ASCO solenoid valves is a violation of 10 CFR 50, Appendix B, Criterion III, Design Control. (Violation 321,366/88-15-03)

As a result of the inspection, the site issued deficiency card 1-88-2140 and MW0s 1-88-2349 and 1-88-2350 to corre t the

. orientation of the valves. In order to properly orient the valves, the air line from the regulator to the solenoid valve had to be broken at the regulator and a new fitting had te be installed.

Additionally, the air line from the solenoid valve to the two connection points had to be broken and the solenoid valve had to be

35 relocated at the opposite end of the valve operator to facilitate "T" and elbow fittings were removed, cleaned, proper orientation.

inspected, and reinstalled to accomplish this work. During the Quality Control (QC) inspector's inspection of the work, the QC inspector found the ground strap from the junction box to the valve operator was broken off et the operator for valve IT41-F0328. This condition was also corrected during work on the MWO. All work on the above was accomplished in accordance with site procedure 52GM-MEL-011-OS ed the engineer's instructions on the MWO. All personnel at the job site. were knowledgeable of the work and procedural requirements. The inspector verified proper material _

control was employed and reviewed the completed work packages to ensure that the work was properly documented and data sheets were properly filled out. Additionally, the inspector verified that adequate post-maintenance testing was performed.

During the field observations of maintenance activities .the inspectors noted that QC inspectors reviewed all materials used in maintenance activities. This practice was considered to be a strength and provided independent verification that appropriate materials were utilized for each MW0. Prior to use, each MWO was reviewed by QC and QC holdpoints specified. QC involvement in au81 ting documentation and field implementation of maintenance

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activities was evident.

f. Review of the Maintenance Training Program The inspector's evaluation of the licensee's training program for maintenance personnel included discussions with the Plant Training Superintendent, the Plant Engineering Supervisor and the I&C Super-intendent; review of the basic course content for the Electrical, Mechanical, and I&C training series; and review of the class roster and training status for a class of approximately 70 I&C personnel.

The licensee is currently putting all apprentices and journeymen, which includes all personnel at the plant when the new program was initiated in 1986, and all new hires since that time, through the program. Waivers of specific parts of the program had been allowed for experienced personnel.

The Mechanical, Electrical and I&C training programs consisted of phases involving generic skills training, specific skills training (specific to the plant), and specialized skills training.

Classroom, laboratory, and on-the-job training were included in the course content. Independent verification was included as an item in the skills training. The three training programs were accredited by INPO in April 1987. Overall control of the training process was maintained by a Training Review Board made up of senior plant managers, a Training Advisory Committee, and a Certification Review Committee.

36 Based on the above discussions and reviews, the inspector concluded that the Ticensee's training program for maintenance personnel is a strength.

No violations or deviations were identified.

g. Predictive Maintena.' e i

The inspector reviewed the licenset's predictive maintenance program 4

in an effort to try to determine management initiatives to improve ,

the availability of equipment for service. This review determined -

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that a significant predictive maintenance program is in place at ,

Hatch. The predictive maintenance program consisted of vibration and oil analysis on rotating equipment, infrared inspection to determine overheating of electrical equipment, and motor-operated valve actuator characterization (MAC) testing of motor operated valves. All of these techniques are aimed at detecting equipment problems before there is a catastrophic f ailure. The advantages of this type of testing / inspection included maximization of equipment availability, allowance of time to plan equipment maintenance, minimization of equipment damage caused by a failure, and reduced maintenance costs. As previously stated, these programs at Hatch were significant. The vibration analysis program included-approximately 350 piems of equipment which was a significant increase over the 130 items in the pregram in 1985. The lube oil analysis program included approximately 230 pieces of equipment.

The licensee estimated that in the last two years twenty major l

equipment failures have been prevented by their predictive analysis program. In addition, the licensee estimated that 2 days of genera-tion and 15,000 man-hours of maintenance had beer saved and approxi-mately 40 safety system outages had been prevented. In addition to the above, a live load valve packing program had been initiated and approximately 175 critical valves had been repacked using this spring load packing technique which prevents packing leaks by maintaining spring pressure on the packing. Efforts had also been undertaken to improve site performance in the repair of electrical motors which resulted in only two major motor failures during 1987.

! The' ratio of predictive / preventive maintenance to corrective maintenance had shown improvement with the percentage increasing from f slightly less than 40 percent (which is the industry average in 1986) j i

to nearly 50 percent in 1987 and 1988. This trend and the reduction of outstanding maintenance work orders were positive indicators and, additionally, indicate that the aggressive attitude toward i predictive / preventive maintenance was improving equipment reliability and availability.

No violations or deviations were identified.

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h. Review of Management Involvement and Maintenance Work Controls Interviews with maintenance personnel at all levels indicated that maintenance managers were well respected and that the quality of maintenance work had improved due to management initiatives.

Maintenance managers had estabiished specific goals for et 2 employee related to safety, quality and performance. Sa.ary increases and performance ratings were tied to meeting the specific goals. These goals appeared to be well understood by maintenance personnel. Employees indicated that the goals promoted clear understanding of management's expectations and had resulted in ~.

improved performance.

Responsibilities for maintenance activities appeared to be well understood. Three maintenance supervisors were utilized by the licensee to screen KW0s for completeness and special requirements prior to issuance to the craf t for work. This practice elintinated administrative work on the field supervisors and foremen allowing more time f:r direct field supervision. One maintenance supervisor n i assigned to control erection and disassembly of scaffolding and removal and reinstallation of insulation which allowed prompt handling of these activities. During the i rispection , managers, supervisors and foremen were observed to be actively involved in field supervision and control of work activities. Work assignment and scheduling controls were effective. Routine meetings, called "tool box meetings", held between supervisors and craf tsmen, were used to provide operational experience feedback.

The experience level of maintenance managers, supervisors, and foremen, and management's effective communication of responsibili-ties and goals were noted as strengths in the maintenance area.

The licensee had establisned a system for maintenance craft walkdowns of plant equipment (CARDEX system). The CARDEX system identified problem equipment, preventive surveillances and general walkdowns to ensure equipment was well maintained. In addition, maintenance foremen were assigned responsibility for material condition in specific plant areas and therefore conducted walkdowns to ensure good equipment condition. Specific emphasis had been placed on correction of labeling deficiencies and identification of oil leaks. Use of the maintenance craftsmen and supervisors tc perform plant walkdowns in addition to those performed by Operations was noted as a strength.

Computer printouts of Kdos sorted by master parts list (MPL) were l available in the maintenance shops ard were used by maintenance l foremen to research previous equipment problems / repairs. A com;;re-hensive equipment locator list was available. The equipment locator i list also included pertinent informatien on qiality levels of  !

components and identified vendor manual references in the mechanical equipment list. i i

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38 The inspector noted that the licensee processed work requests and required ~1he same work and material controls for most balance-of-plant equipment as those controls used for safety-related equipment.

New maintenance procedures were being validated by craf t/ maintenance engineers. About half of all maintenance procedures have been enhanced. The goal f o s' completion of safety-related maintenance procedure upgrades was 0ecember 1988. Routine procedure revisions, previously processed in the Procedure Upgrade Program, were now processed within the maintenance department to expedit revisions.

No violations or deviations were identified.

i. Engineering Support to Maintenance The maintenance department had seven engineers. Special programs had been specifically assigned to the engineers for implementation.

These programs included lube oil analysis, vibration analysis, infrarad analysis, breaker / motor and electrical reviews, preventive maintenance oversight, computer support, and motor operated valve analysis.

The system engineering group was active in plant maintentoce reviews and observations. Systems engineers were present for many of the maintenance activities on their systems and were kept informed of tests, maintenance and problem areas.

Engineering equivalency reviews for substitution of replacement parts were being simplified in response to INP0 comments. The inspector reviewed proposed revisions to procedure 42EN-ENG-009-05, Equivalency Determination of Reple. cement Parts, Rev. 3. The revisions included eliminating duplicate equivalency reviews for the same component when it is applicable to a similar component with a different MPL number, changing the approval review process, and allowing replacement part approval for an "intended use" instead of a single specific use.

No violatior.s or deviations were identified.

J. Utilization of the Nuclear Plaat Reliability Data System (NPROS)

Improvements had been made in the processing of NPROS data and additional staf f had been added to evaluate the information. The NPROS computer system had been linked with the MWO processing data base allowing quick dissemination and review of MWO data. During recent months, these efforts had promoted the extensive use of computerized NPROS data to identify problems, provide input to system and maintenance engineering, and provide industry contacts

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39 for problem resolution. The NPROS group was scheduled to provide a presentatfon of their capabilities to the system engineering staff in the near future. Also, computerized "real time" repetitive failure analysis capabilities were to be added in the fall of 1988.

No violations or deviations were identified,

k. Review of Maintenance Work Or:ter Backlog The inspectors reviewed the. Plant E. I. Hatch Backlog Report, dated ~

April 26, 1988, which included the current status of all open MW0s and plant indicators in the maintenance area in order to determine the status of the plant maintenance backlog and overall performance.

All areas reviewed indicated improvement in performance. The correc-tive MWO backlog in 1986 averaged approximately 3335 outstanding MW0s. In 1987 the average number of outstanding MW0s was reduced to an average of 2390 and for the first part of 1988 the average was 1690. Additionally, the number of MW0s outstanding for over twelve months in 1986 averaged 260. In 1987, the number increased to 285.

However, the current average of 183 was a significant reduction, although still large compared to some other sites.

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No violations or deviations were identified.

5. Management Centrols (40700, 92700, 92720)

The licensee's commitment to firm management control of activities was avidenced by the assignment of a corporate officer, the Vice President -

Plant Hatch, as the senior individual on site. Reporting to the VP-Hatch were the Plant Manager, the Plant Support Manager, the Nuclear Safety and Compl'iance Manager, and the Plant Training and Energency Preparedness Manager.

The Plant Manager directed the activities of the Opetations, Maintenance, and Health Physics and Chemistry Departments; while the Plant Support Manager was responsible for the activities of the Gutages and Planning, Engineering Support, General Support, and Nuclear Security Departments, as well as for the Procedure Upgrade Program and the Quality Concern Program.

Interviews with senior managers indicated that the interfaces among the various plant departments worked well. The overall goal of safe plant operation was a shared concern for which all managers felt responsibility.

Observation of personnel participation in plant activities confirmed this shared attitude. The working relationship among the participants appeared to be on a high professional level. Notewort iy in this regard is the relationship of the Quality Assurance group, which reports directly to the corporate QA Manager, to the other groups on site. QA appeared to be accepted as an integral part of the organization necessary for the proper functioning of the plant. One of the QA employees recently was designe.ted "Employee of the Month" even though QA was not a part of the pla.it.

organization.

1 40 Goals and objectives for the plant were set or adjusted by plant manage-ment to ensure they were realistic, and had been broken down into sub goals for individual plant groups and supervisors. Performance in attaining the plant goals was a part of the annual employee appraisal program, thereby providing assurance that each employee had a personnel interest in attaining the goals. As noted elsewhere in this report, progress toward attainment of goals had been made readily available to all employees through the Performance Monitoring Program.

The plant had experienced a relatively low personnel turnover, averaging about 5 to 6 percent per year in the recent past. This low turnover rate -

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indicates high employee morale and job satisfaction. The dedication, capabilities, and positive attitudes of personnel at all levels of the plant organization were evident throughout the inspection.

Evaluations of particular aspects related to management controls are presented in the following sections.

a. Review of Deficiency Card System The licensee had in place a deficiency card (DC) system governed by administrative control procedure 10AC-MGR-004-05, Deficiency Control System, Rev. 1. This system provided the licensee's staff with a mechanism for reporting deficient conditions. All duly reported DCs were reviewed by the Shift Supervisor for immediate action or reportability. Further review was performed by members of the Nuclear Safety and Compliance (NSC) department to determine if the ,

deficiency was significant.

NSC utilized department instruction procedure DI-REG-08-1285N, DC, SOR and LER Determination of Significance, Reportability and Trending Program, Rev. 2, to determine those deficiencies which warranted the initiation of a Significant Occurrence Report (50R). SORS were then

' forwarded to the appropriate department for root cause determination and long term corrective action, The NSC department issued trend reports which analyzed trends associated with OCs and SORS and also tracked the items until closure. The DC system and associated SORS provided the licensee with a very ef fective method for identifying, I

correcting, and trending conditions adverse to quality.

The licensee issued approximately 3700 DCs for Units 1 and 2 in 1987 and approximately 4000 OCs for Units 1 and 2 by the end of April 1988. The marked increase in number appeared to be due to a l

l management decision to write a DC for each maintenance work order.

In light of the increased number of OCs being generated, the NSC department is currently examining the deficiency card program, to i

ensure that the proper level of attention and escalation, where I appropriate, is provided to conditions adverse to quality, l

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I 41 The inspettor reviewed SORS in the final closure stages and OCs af ter the NSC department had performed their initial review. No discrepancies were noted. The corrective action taken by the licensee for SORS reviewed appeared appropriate and timely, with delays for corrective action adequately justified where appropriate.

The inspector also reviewed those DCs and SORS associated with Licensee Event Reports (LERs) issued in 1988. The details of the LERs accurately reflected the corrective actions taken by the licensee, and indicated a strong desire by the licensee to accurately and thoroughly determine root causes and avoid similar occurrences. 1 No violations or deviations were identified.

b. Design Change Request (DCR)

The inspector reviewed DCR 86-235, Alternate Rod Insertion System, and DCR 87-008, High Pressure Core Injection (HPCI) Drain Pot Level Switch Replacement. These OCRs were reviewed in conjunction with the requirements specified in Engineering Service Procedure 42EN-ENG-001-05, Rev. 4, and Department Instruction 01-ENG-25-0886N,

. Design Change Request Implementation User's Guide, Pav. O.

The safety evaluations prepared for DCRs86-235 and 87-008 were thorough, and addressed the potential impact of the proposed change on plant design and operation. Members of the engineering staff recognized the importance of thorough safety evaluations, expressing their continuing efforts to improve on the safety evaluations.

The DCRs contained all necessary documentation, as required by procedure, and were presented in a manner which was auditable and understandable to a reviewer. Additionally, the DCRs appeared to identify all pertinent procedures and drawings requiring revision, as specified by DI-ENG-25-0886N.

No violations or deviations were identified.

c. Independent Safety Engineering Group An Indspendent Safety Engineering Group (ISEG) was established for the plant in April of 1986. The ISEG is not required by the plant Technical Specifications, but was added voluntarily by the licensee.

Authorized staf fing consisted of a supervisor, four engineers and a clerk. Until recently, the ISEG reported off-site to the corporate office with a coordination line to the Plant Manager. At the time of the inspection the reporting channels were in transition such that the ISEG now will report to the Vice President, Plant Hatch.

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3 42 Plant procedures governing ISEG activities do not now exist, and actual stiffing of the ISEG at the time of the inspection consisted only of the ISEG supervisor and the clerk. The engineers previously assigned had been released to attend SRO training. Restaffing efforts were in progress.

In addition to interviewing the ISEG supervisor, the inspector examined the reports of ISEG activities. Monthly reports have been issued since May of 1986 in addition to 26 special reports (SEH-2 through SEH-27) issued between May 1987 and February 1988. _

The ISEG provided an additional level of safety oversight, examining areas of interest to the ISEG, as well as conducting special reviews requested by the Plant Manager. The ISEG had not been involved in any sign off function. C3nsiderable emphasis had been placed on reviewing LERs to ensure they were complete and the root cause had been identified. The ISEG performed independent reviews of industry events to determine applicability to the plant and mor.itored plant

-activities, making recommendations for improvement when deemed appropriate. For example, the January 1987 monthly report contained recommendations regarding: (1) assigning Plant Equipment Operators (PEOs) to designated areas to enhance their feeling of "owning" the assigned systems; (2) improved equipment labeling and maintenance; (3) improving the plant response to operating experience reports; and (4) establishing a formal policy for event reviews. The October 1987 monthly report recommended improvements to the professionalism of operators in the control room.

While the ISEG had no formal charter, it appeared to have been effective in identifying areas of plant activities where improvements could be made. Since the ISEG is not required by the NRC, its establishment and use at the plant must be considered a positive indicator of mtnagement interest in improving plant performance.

No violations or deviatio'es were identified.

d. Plant Review Board The activities of the Plant Review Board (PRB) were reviewed to determine if it was functioning in accordance with the plant Technical Specifications (TSs), ' providing adequate interf ace with various plant disciplines, and performing adequate safety reviews.

The review consisted of an interview with NSC Manager, review of TS Section 6.5.1, review of administrative procedure 10AC-MGR-002-05, Plant Review Board Administrative Procedure, Rev.1, observation of a PRB meeting, and review of selected minutes of PRB meetings.

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a-e 43 The requirements for the PRB are delineated in Section 6.5.1 of the TSs f5r both Units 1 and 2. Amendments to the TS (#145 for i Unit 1 and #80 for Unit 2) issued in the fall of 1987 changed J the PRB membership and reduced from nine to six the number of I required PRB members. These changes were not yet reflected in the I plant administrative procedure which was under revision at the time )

of the inspection. l The TS specify a meeting frequency of at least once per calendar i month. In fact, the PRB . met regularly every Thursday plus additional meetings as called by the PRB Chairman. Any PRB member ~.

could request a meeting. Membership on the PRB was at the supervisor level or higher from the Operations, Maintenance, Quality Control, Health Physics, NSC and Engineering Support Departments.

Agenda items for each PRB meeting were placed in a special reading room in advance of the meeting so that individual members could review the material at their leisure prior to the meeting. Comment sheets were provided so that each member could indicate his or her concurrence or questions. This pre-review helped expedite the conduct of the actual meetings where each item was brought up for discussion and vote. Provisions were made to have non-voting consultants assist the PRB on matters where special expertise was required. The administrative, procedure also provided for meetings to be conducted by telephone in unusual cases, such as late at night. According to the NSC Manager, such telephone meetings were held sparingly, generally only when the possible need for such a meeting had been known in advance such that all members could be aware of and discuss the issues ahead of time, and always were confirmed at a later PRB meeting with members present.

The administrative procedure also provided for the use of subcommit-tees by the PRB, At the time of the inspection there were four such subcommittees in existence, handling matters pertaining to Design Change Requests, FSAR changes, Emergency Operating Procedures, and inservice inspection. A fi f th subcommittee to handle Document Change Requests was about to be formed. In each case, the subcommittee chairman was a PRB member and other subcommittee members, as a minimum, were trained in 10CFR 50.59 evaluations and reporting requirements. Subcommittee reviews were presented to the full PRB for discussion and vote.

The PRB was accomplishing its mission and performing adequate safety reviews. The use of subcommittees and consultants e.nhan%d Gie ef fectiveness of PRB activities. The PRB membership assured that interested plant departments have input to and are aware of PRB activities.

No violations or deviations were identified.

1 44

e. Engineering Support Department The Engineering Support Department consisted of approximately 108 engineers including system engineers, quality control, and engineers responsible for the implementation of DCRs. A majority of the major  ;

l plant modifications implemented by DCR were designed by Southern Company Services. The impetus for most design changes was the )

replacement of obsolete equipment, operational enhancements, or i

replacement of high maintenance equipment.

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The Engineering Support Department planned to increase its current _

staffing levels. In order to accommodate these increases and ensure that system engineers were thoroughly trained, the licensee was developing a system engineering qualification checklist. The l qualification checklist addressed three major areas: system theory and operation, administrative procedures, and maintenance activities. l These three areas included provisions for thorough training in. system operation, system relationships, and operating parameters; plant administrative controls, engineering, and health physics procedures; anc electrical, I&C and mechanical maintenance activities. The NRC

considers the thorough training of system engineers of paramount imBortance to the proper modification and maintenance of plant systems. The licensee's training program was oriented toward obtaining this goal.

Interviews with various members of the Engineering Support Department indicated a high degree of accessibility to the Southern Company Services design engineering staff. Their accessibility and quick response to design problems was evidenced when the licensee requested and received assistance in the removal of an exhaust fan heating coil from the refueling floor ventilation system.

Goals expressed by the Manager of Engineering Support included the expansion of the system engineering staff, completion of the system engineer training program, and other items associated with improving plant availability and the minimization of outage duration.

Additionally, the manager expressed satisfaction with the cooperation and support received from Southern Company Services.

No violations or deviations were identified.

f. Plant Status Meetings Various plant status meetings were attended to determine whether day-to-day plant activities and planned future activities were being adequately disseminated to the applicable staff.

s There was good interface between plant groups and participation by personnel-in plant status meetings. Overall, members of the plant management staff were cognizant of plant status, ongoing or planned maintenance and/or testing activities, and general problem areas.

There was good management control at the meetings and adequate multi-di sciplinary attendance. The level of attention to detail displayed during plant status and planning meetings helped to ensure that individuals were well aware of their specific responsibilities and assisted in the dissemination of information. The inspectors noted a proficient level of comm.unications between members of the plant management which would greatly assist their ability to handle various 1 situations.

No viol hions or deviations were identified.

g. Performance Indicator Program The Performance Indicator Program is the responsibility of the Plant Performance Engineer assigned to the General Engineering Section of the Engineering Support Department. Procedure AG-ENG-04-0288N, Plant Performance Indicator Program, Rev. O, established the responsibilities for collection, review, and reporting of data.

Data acquisition regarding plant parameters was controlled by procedure 42EN-PPM-001-ON, Plant Performance - Data Acquisition, Rev. O.

Plant parameters were collected on a daily and weekly basis, while overall performance indicators were collected monthly. The daily data collection included circulating water temperature, condenser vacuum, temperature and dewpoint, and gross megawatts thermal and electric. Weekly data collection was more extensive, including sufficient plant data to calculate heat balances around the system.

The monthly data collection included plant operational data, but also included data from Engineering, Maintenance, Health Physics and Chemi stry, Nuclear Safety and Compliance, Quality Assurance, General Support, and Plant Training and Emergency Preparedness. The parameters monitored and reported on a monthly basis were oriented toward the data desired by INPO, which were reported quarterly.

The data were also submitted to the corporate office each month and used for preparation of monthly and annual reports to the NRC.

Actual plant status was posted da.ily in prominent locations outside j the cafeterias in the service building and in the simulator building, affording each employee up-to-date information regarding the plant. The monthly performance indicator dats forwarded to the corporate of fice were converted to graphics indicating how the plant performance compared to the goals established for the plant. These graphic displays were returned to the plant and were posted

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46 prominently so that each employee could judge how the plant was performing. A bi-weekly employee newsletter provided occasional data regarding plant performance, together with comments by senior plant management regarding plant performance and goals.

Performance indicators are incorporated in annual employee appraisals .

based on how well their department performed in meeting established plant goals. Outstanding individual performance was recognized by  ;

an "Employee of the Month" award which was reported in the plant i newsletter and which carried with it the award of a special medallion, the temporary assignment of a preferred parking space, and n ..

dinner for two at a local restaurant.

Overall, the performance indicator program appeared to be working as designed. It provided useful data for management decisions regarding the plant as well as data for individual departments at the plant. The wide dissemination of the data allowed each employee to monitor plant performance and to judge how his or her own performance had contributed to the total.

No violations or deviations were identified.

h'. Operating Experience Program The Operating Experience Program was reviewed to determine whether it was effective in providing industry operating experience feedback to affected plant departments and personnel as intended by item I.C.5 of NUREG-0737.

The program was conducted in accordance with procedure 10AC-MGR-005-05, Operating Experience Program and Corrective Action Program, Rev. 3. Responsibility for execution of the program was assigned to the Nuclear Safety and Compliance (NSC) Manager who, in turn, had charged the Safety Engineering Supervisor with program impl errentati on . The inspector reviewed the governing procedure, interviewed the NSC Manager, the Safety Engineering Supervisor and a member of the latter's section and examined completed packages for four Inspection and Enforcement Notices (IENs) issued during the last 18 months. The inspector also reviewed the licensee's actions in response to five INPO Significant Operating Experience Reports (SOERs).

The plant operating experience program was applicable to Inspection and Enforcement Bulletins (IEBs), IENs, Generic Letters (GLs),

SOERs, Significant Event Reports (SERs), Nuclear Network Information (NNI), GE Service Information Letters (SIls), and plant generated Licensee Event Reports (LERs) and Design Change Requests (OCRs).

The Corrective Action Program as a minimum tracked responses to NRC and INP0 findings and to Quality Assurance Audit Finding Reports (AFRs).

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V 47 Incoming industry experience information was screened for applic-ability t6 the plant, accumulated, and on a monthly basis was forwarded as an Operating Experfence Assessment Report (0 EAR) to Operations, to the Training Department, and to other plant departments if applicable. Information that could potentially affect current plant operations was transmitted immediately to plant management and to the appropriate plant departments. The screening was conducted by at least two NSC personnel who together agreed on which information should be included in the OEAR and which plant departments should receive the information. The screening process was designed to assure that pertinent information was brought to the _.

attention of af fected plant personnel, while concurrently assuring that the interested personnel were not inundated with extraneces, repetitive or conflicting information. Review of the logs of incoming INPO operating experience information indicated that about 90 percent of the information was screened out as being inapplicable to the plant. A much higher percs.itage of SERs was included in the data transmitted to the plant departments.

The program provided for tracking plant responses to incoming NRC and INPQ information. INPO SOERs require a formal response from the plant a.nd NRC IEBs may be responded to by the plant or corporate SERs and IENs do not require a response to INPO or the NRC, staff.

but a plant response to the corporate office on these items was required.

Th'e program provided for tracking each item to ensure that the response hed the concurrence of affected plant departments prior to being approved by plant management and that it was responded to in a timely manner. Any commitments contained in the plant responses were. entered into the Action Item Tracking system to ensure follow-up to completion.

An audit program war in place to ensure that any appropriate infor-  :

mation was incorporned in the plant training program. This audit i activity was being expanded to check on how the various plant l departments were oisseminating the information to their personnel. l A random selection of four IENs from the past 18 months was revfewed .

to determine the adequacy of the licensee'r review, the response, and the training of individuals performing the reviews. IENs selected were:

IEN 87-08 Degraded Motor Leads in Lirritorque Direct Current Motor Op6rators, February 4, 1987 l l

IEN 87-31 Blocking, Bracing, and Securing of Radioactive (

Materials Packages ir. Transport, July 10, 1987 l

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s 48 IEN 87-54_ Emergency Response Exercises, October 23, 1987 IEN 87-57 Loss of Emergencv Boration Capability Due to Nitrogen I Gas Intrusion, November 6, 1987 For IEN 87-08, the licensee internal response was deted February 12, 1987 and concluded that the motor on valve 1E41-F001 was the only one affected. The evaluation concluded that the degraded leads were not an immediate problem with this motor operator, and noted that the motor was seneduled to be replaced by June, 1987. The motor replace- _

ment was completed on May 3, 1987, under r4WO 1-87-02871. The licensee's evaluation was timely, thorough and responsive, and the corrective action was taken as committed. The short time batween the date of the IEN (February 4, 1987) and the evaluation respor:sa

( February 12, 1987) is probably due to the fact that the licensee had been notified directly by the Anchor / Darling Valve Company on January 20, j987, that the particular motor could have a problem.

For IEN 87-31, .the licensee internal response was dated October 7, 1987. The evaluation addressed each of the concerns expressed in the IEN, compared these conr< ns with existing procedures that

- govern radioactive materials shipments, and concludsd that each concern was already adequately addressed by the existing procedures.

A copy of the IEN was forwarded to the Health Physics and Chemistry Department for in 'ormation. The evaluation was thorough and respon-

. sive to the IEN.

Th< licensee's internal evaluation of IEN 87-54 was completed on Octuber 30, 1987. It concluded that the biennial emergency exercise scenarios "or the Hatch plant typically progress to a General Emergency such that there was amole opportunity for state and local officials to participate in the exercises. The evaluation concluded that no changes to the Hatch Emergency Exercise scenarios were required. The licensee's evaluation was timely, thorough and responsive.

The licensee's internal evaluation of .N 87-57 was dated Oa. ember 4, 1987. The ovcluation considere<1 the . 71 ant systems that possibly could be impacted as described 11 the tcN, but concluded that there were no systems at Hat-h where aroblems as described in the IiN could l

actually occur. As a consequence, no changes or corrective actions were recommenced. The licensee's evaluation was timely and thorough.

A nc 4 ' "thy use of the operational experience information is the orou ', - of short descriptions of errors that have occurred at v ,, s . These one page dercriptions, labeled "WHOOPS", were

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bulletin board" where employees could read about errors i 'e . made and, hopefully, avoid such errors at Hatch.

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49 Overall , _the inspector concluded that the licensee's program for feedback of operational experience information met the intent of Item I.C.5 of NUREG-0737 and that it was functioning in accordance with tre plant procedures. It ensured that pertinent information wn transmitted to affected departments while it concurrently screened out extraneous or repetitive information.

No violations er deviations were identified.

i. Commitment Tracking .

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Plant responses to the incoming information from the Operating Experience Program of ten resulted in modifications or commitments by the various plant departments to take specified corrective actions.

The licensee's program for tracking these and other commitments was reviewed for adequacy.

The mechanism for keeping track of these commitments was the Action Item Tracking ( AIT) system which vat controlled by administrative guideline AG-ADM-11-0283, Action Item Tracking, Rev. O. The Action Item Tracking ( AIT) system provided a mechanism for tracking the status of all commitments and activities at the plant. In addition to commitments made in response to NRC and INPO identified concerns,

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the AIT system also tracked the status of other plant activities such as those resulting from Plant Review Board and Safoty Review Board reviews, QA identified concerns, regulatory commitants, proposals / quotations, inquiries, mail requiring followup action, and other items as desired by plant management.

The AIT system assigned a unique commitment number to each action, and included information regarding the originating department, the type of action, references to the source of the requirement, the action required , the due date, and the responsible department and assigned individual for completing the action. -

Print-outs from the AIT listing overdue action items were provided to each department on a daily basis. Progress on the responses was tracked by the Nuclear Safety and Ccmpliance (NSC) cepartment, which also reviewed the final actions for adequacy.

Tna AIT system as it wa r, functioning appeared to be working, although NSC personnel felt that is was cumbersome to use. Efforts ,

were underway to computerize the system to makt it more usable. l The licensee also maintained a separate, computerized system in accordance with administrative procedure 40AC-REG-004-05, Commitments and Requirements Identification and Tracking System, Rev. 1. This system was a listing of all known requirements and I commitments pertaining to Hatch from all sources (e.g., FSAR, Technical Speciffcat W s, Regulatary Guid(*., induttry standards).

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50 Provisions were made to incorporate any changes or commitments

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resulting from the actions taken in resconse to NRC or INPO items.

In addition to being an up-to-date record of all commitments and requirements for use as necessary, the system was being used by the Procedure Upgrade Program (PUP) to assure that the upgraded procaoures in fact account for these commitments and requirements.

The inspector concluded that the sp tem in place for tracking [

commitments was adequate. The data base in the Commitments and Requirements Identification and Tracking System should be particularly helpful to the licensee. ~ _._

No violations or deviations were identified.

J. Plant Response to QA Audits The inspector reviewed the requirements of Technical Specification 6.5.2.8 on the scope and frequency of audits in c"njunction with the 4

1988 annual audit planning matrix and schedule. The inspector confirmed that the planning metrix and schedule addresses all TS requirements. The QA Deptrtmeat also performs surveillances which encompass all aspects of plant operations. The in:pector attended

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audit finding presentations by the QA Departmert. Audit findings and concarns ware presented in a professional manner. Communications by the participants ensured that the issues were understood and revised if provided with additional information. Di sc.uss 'en with individuals in the QA Department and other members of the' plant staf f revealed positive attitudes towards the QA Department noting that the QA Department findings were generally well receiveci.

Cn October 15, 1987, the Site QA Manager issued report 87-PO-2A documenting the results of an audit of plant operations. Included in this report were items relating to the failure to documert deviations between the EPGs aac E0Ps, less than optimum professional conduct in the control room, problems with the E0P flow charts due to the plastic covering and congestion which make the charts difficult to follow, possible excessive administrative work load on the shift supervisor, and problems with timely incorporation of ABNs on drawings available in the control room. QA did not flag these items as sign'ficant and the corrective actions and further reviews to determine the scope of the problems we: e protracted. The protracted nature of the corrective actions reflected adversely on management support of plant operations.

No violations or deviations were identified.

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k. Procedure _and Orawing Control The inspector checked 17 procedures in the Unit 2 control reom to the current revision in document control . Some of the procedures dated back to 1985 and all of the procedures were the same revision that existed in document control. Plant operators stated that the on-shift clerk maintained the plant procedures current.

A cursory review of the Unit 2 St ift Supervisor's copy of Technical Specifications on May 15, 1988, ind1cated that eignt pages were _

either missing or had the incorrect revision number. A further -

review by the licensee indicated that an additional eleven pages were affected. Further licensee review revealed additional examples of controlled documents in the control room that were not current. The licensee took prompt action to correct these items.

Administrative control procedure 20AC-ADM-001-05, Document Distri-bution and Control, Rev. 2, required the recipient of controlled documentation to remove superseded documentation and file the current issue document in its appropriate place, however, this requirement had not been implemented in all cases. The failure to control the issuance of documents, including changes thereto, which prescribe activities affecting quality and to assure that changes are distributed to the location where the prescribed activity is performed is a violation of 10 CFR 50, Appendix B, Criterion VI, Document Control . (V.i ol a tion 366/88-1;-04)

6. Licensee Action on Previous Enforcament Matters (92701, 92702)

a. (Closed) Violation 321, 366/86-22-03, Failure to assure that the torque multiplier was properly calibrated or adjustad to maintain accuracy within necessary limits. The Maintenance Department issued general maintenance procedure 51GM-MNT-OS3-05, Torquing Procedure, Rev. O. This procedure acequately addressed instruction for the use of calibrated torquing equipment and tools.

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b. (Closed) Violation 321, 366/86-30-01, r ailure to follcw and have adequate procedures. This violation had three examples. Each will be addressed separately. The licensee responded to each example on December 31, 1986, and again in a revised response date.d June 23, 1987.

(1) The licensee failed to provide adequate procedures to control test activities on the 2C emergency diesel generator on Monday, October 6 and Wednesday, October 8,1986. Appropriate correc-tive action was taken to resolve this v iel4 tion by revising special purpose procedure, 5259-100386-1E-1-25, Diesel Generator 2C Low Speed Run, and oy counseldag personnel concerning the use of special purpose procedures and associated pre-test briefings.

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52 (2) On October 9,1986, a contractor was observed exiting the RCA at control point C-52 without using the personnel monitor.

The HP technician on duty at C-52 failed to ensure that the contractor was monitored which was a violation of procedure 62RP-RAO-017-05, Release Surveys for Trash and Materials Leaving Operating Buildings.

The licensee was unable to either admit or deny the violation.

tiowever, procedure 62RP-RAO-017-OS was revised to include additional clarification of responsibilities for the proper use of personnel contamination monitors. A departmental directive -

was also sent to all Health Physics technicians instructing them to re-read and follow the procedure.

(3) In August 1986, the licensee f ailed to perform the required limit switch adjustments in accordance with preventive maintenance procedure 52PM-MNT-005-05, Limitorque Valve Operator Inspection.

The corrective action taken was to revise 52PM-MNT-005-OS to clarify the requirements for performing limit switch adjust-ments. That requirement states that "If limit switches do not

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make or break as required, limit switch adjustment'. must be made per approved plant procedure."

c. (Closed) Violation 321, 366/86-30-02, Failure to stroke time test power-operated valves from initiation of the actuating signal to the end of the actuating cycle. The licensee did. not stroke time test power operated valves as required by Technical Specifications and ASME Section XI. The licensee's practice was to steoke tir.;e test those valves based on a light-to-light timing measurement rsther than from initiation of the actuating signal to the end of actuating cycle timing method as required by Technical Specifications and ASME Section XI.

In response to t,hi s violation, the licensee be.s adopted the NRC interpretation of switch-to-light stroke time testing for power-operated valves. Appropriate personnel were notified of the new interpretation for full stroke time testing. New stroke times have been determined for all power-operated valves based on switch-to-light stroke time testing. Data for Unit 1 valves wts submitted to the NRC in early 1988 for consideration of a Technical Specification change,

d. (Closed) iFI 321, 366/86-31-02, Review of annual diagnostic exami-nation for licensed personnel. An annual diagnostic examination is given by the licensee to all licensed personnel. A previous inspection report had identified a concern resulting from the review of that diagnostic exam. The Training Department had not interf aced with the Operations Department to analyze the results of the diagnostic exam to cetermine if re-training or additienal training was required.

o 53 The Training Department now makes it a practice to review the diagnostic examination, especially any weak areas, with the Operstions Department to determine training needs. Also, Procedure 72TR-TRN-002-05, Licensea Requalification Training Program, Rev.1, now describes how ret-aining will be conducted.

7. Exit Interview (30703)-

The inspection scope and findings were summarized on June 1,1988 with those persons indicated in paragraph 1 above. The inspectors described the inspection findings 2nd discussed in detail the inspection findings

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below. Dissenting comments were not received from the licensee. The licensee indicated that the INPO report transmitted to the NRC by letter of May 11 is proprietary information.

Item Number Status Description / Reference paragraph 321, 366/88-15-01 Open IFI -

Comparison of the E0Ps and the EPGs and justification of plant specific differences. (paragraph 2.c.1) 321, 366/88-15-02 Open URI - Apparent failure of individuals to complete required periodic fire brigade leadership training. (para-graph 3.h) 321, 366/88-15-03 Open V'i ola tion - ASCO solenoid valves to the air operators of suction valves 1T41-F032A and 1T41-F032B on the standby gas treatment system did not meet the environmental qualification requirements. (paragraph 4.e) 366/88-15-04 Open Vfolation - Copy Number 2 of the Unit 2 Technical Specifications located at the Shift Supervisor's desk in the control room contained pages which were either missing or had been superseded and had not been replaced with the current page. Unit 2 only. (paragraph 5.k) 321, 366/86-22-03 Closed Violation - Failure to . assure that the torque multiplier was properly cali-brated. (paragraph 6.a) 321, 'S6/86-30-01 Closed Viols n - Failure to follow and have adeqt .. procedures in that: (1) inad-equate procedures were in place to control testing of emergency diesel

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54 generator; (P.) monitoring procedures

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were not followed by an HP technician; and, (3) required limit switch set-tings were not perfo rmed. (paragraph 6.b) 321, 366/86-30-02 Closed Violation - The licensee failed to adequately stroke time test power-operated valves. (paragraph 6.c)

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321, 366/86-31-02 C1csed IFI - Training Department to review diagnostic examination with licensed operators. (paragraph 6.d)

8. Acronyms and Initialisms ABN As-Built Notice A/E architect engineer AFR Audit Finding Report AIT Action Item Tracking AOP abnormal operating procedure ARP. annunciator response procedure ASCO Automatic Switch Company ASME American Society of Mechanical Engineers BWR Boiling Water Reactor CEO Chief Executive Officer CRDH control rod drive hydraulic system DC deficiency card DCR Design Change Request 0/G diesel generator EFCV excess flow check valve E0P Emergency Operating Procedure EPG Emergency Procedure Guideline EUT Equipment Utilization Tag ERT Event Review Team FSAR Final Safety Analysis Report GE General Electric GL Generic Letter GPC Georgia Power Company HPCI High Pressure Coolant Injection System I&C Instrumentation and Controls IEB Inspection and Enforcement Bulletin IEN Inspection and Enforcement Notice IFI inspector followup item INPO Institute of Nuclear Power Operations IRM intermedia'e range monitor ISEG Independer, Safety Engineering Group i LCO Limiting Condition for Operation LER Licensee Event Report l

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- 55 MAC motor operated valve actuator characterization MCC motor control center MOV Motor Operated Valve MPL master parts list MSIV main steam isolation valve MWO Maintenance Work Order NPROS Nuclear Plant Reliability Data System NRC Nuclear Regulatory Commission NRR NRC Office of Nuclear Reactor Regulation NSC Nuclear Safety and Compljance ~

OEAR Operating Experience Assessment Report -

OPA Operational Performance Assessment 0505 Operations Supervisor On Shift PE0 Plant Equipment Operator P&ID piping and instrumentation drawing PM preventive maintenance PRB Plant Review Board PUP Procedure Upgrade Program QA Quality Assurance OC Quality Control RCIC Reactor Core Isolation Cooling System RHR , Residual Heat Removal System -

RO reactor operator RTD resistance temperature detector SALP Systematic Assessment of Licensee Performance SER Significant Event Report SIL Service Information Letter 50ER Significant Operating Experience Report SOR significant occurrence report SRO senior reactor operator STA shift technical advisor TS . Technical Specification URI unresolved item VP Vice President WCN Work Completion Notice 0

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'[ t UNITED STATES

, j" ] NUCLEAR RECULATCAY C2MMISSIGN REGION N E 101 MARETTA ST. M.W. APPENDIX A ATuMTA, GaORGIA 30323

%.***. (Page 1 of 2)

May 4, 1988 MEMORANDtM FOR: Albert F. Gibson, Director Division of Reactor Safety l

FR,0M:

J. Nelson Grace, Regional Administrator )

SUBJECT:

MATRIX A2 OPERATIONAL ASSESSMENT. HATCH UNITS 1 AND 2 -

Enclosed for your implementation is the charter for the Hatch Operational ._

Assessment Team inspection to be conducted this month. The objectives of this inspection are to evaluate the effectiveness of plant operations and the adequacy of corrective actions taken by the licensee in response to INPO findings. Regional and Headquarters management will be kept informed of any l

significant issues identified during this assessment.

If you have any questions regarding these objectives or the enclosed charter, please do not hesitate to contact either me or Mal Ernst.

f J. Nelson Grace .

Enclosure:

Charter for Matrix and Operational Assessment cc's/ enc 1:

M. Ernst, ORA L. Reyes, DRP W -Hehl, DRP .

E. Merchof f. DRS

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APPENDIX A ENCLOSURE ,

(Page 2 of 2)

HATCH UNITS 1 AND 2 CHAkTERFORMATRIXANDOPERATIONALASSESSMENT

1. Evaluate the licensee's corrective actions for the INPO findings and the findings of the NRC E0P Inspection Team.

2. Evaluate the effectiveness of plant operations by intarviewing plant staff members, observing licensed, activities, and reviewing records as follows: _

a. Review past performance, operability and maintenance of equipment .,

which is important for maintaining core integrity.

b. Evaluate control room operations and demeanor,

c. Evaluate interface between Operations and support organizations.

d.. Evaluate procedures and other administrative programs that contribute to proper performance of operational evolutions, e.' EvaTuate surveillance and maintenance activities actually being performed during the assessment.

- f. Determine adequacy of training and retraining of Operations and support personnel (with emphasis on current corrective action training).

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E,[d N'.'.u. APPEN0!X 8 e .a Gen ns (page 1 of 10)

Georgia Power

= ** omr= . .. . . , .

SL-4628-a 3684N X7GJ17-H230 May 4,1988 U. S. Nuclear Regulatory Comissidn 1 ATTH: Mr. Thomas E. Murley, Director Office of Nuclear Reactor Regulation Washington, D. C. 20555 PLANT HATCH - UNITS 1, 2 NRC 00CKETS 50-321, 50-366 -

OPERATING LICENSES OPR-57, NPF-5 HAICH OPERATIONAL UPGRADE Gentl emen:

- On April 19, 1988 Georgia Power Company initiated shutdown of both Hatch units to upgrade certain aspects of operational perfomance. The principal basis for this unilateral action was an evaluation by the Institute of Nuclear Power Opyations (INPO) completed on April 18, 1988 that identified weaknesses in several operational areas. '

The purpose of this letter is to provide you with additional information regarding the problems and our planned upgrade actions. This additional infomation is provided in the enclosure as follows:

Enclosure (1): A sumary of the specific operational issues at Hatch.

Attachment (A): Our operational upgrade plan with dettiled actions that This address the issues listed in Enclosure (1).

enclosure also shows the current status of each action.

The operational upgrade plan focuses on areas that will be addressed prior to plant restart. Most of the additions will he completed prior to restart while some

. of a less imediate nature will be subsenuently -

addressed.

_ Attachment (B): Schedule for the restart of Hatch.

The action to shutdown Hatch was initiated by Georgia Power Cocpany solely in response te lhPO findings in the operational area and our own industry supported knowl edge of our situation (INPO is a non-profit organization wnose mission is to promote exce'ilence in nuclear plant safety and reliability). Our conservative action in this matter was taken

L APPENDIX B (Page 2 of 10)

U. S. Nuclear Regulatory Comission May 4, 1988 -

Page Two independent of the regulatory process, and is based on the standard of However, we fully excellence established by the industry through INPO.

recognize the NRC's interest and statutory responsibility for assuring operational safety and reliability. Accordingly, the infomation in this letter and its accompanying enclosure are provided. .

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In addition to the material in this letter and infomation to be provided at our scheduled meeting on May 9,1988, we will infonn you when we have detemined that the plant is ready for start-up.

Sincerely, .

I R. P. Mcdonald

• Executive Vice President Nuclear Operations RPM /do '

Enclosure:

Plant Hatch Operational Upgrade c/w: (see next page) c: Georgia Power Comoany Mr'. J. T. Beckham, Jr.

GO-NORMS

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U. S. Nuclear Regulatory Comission, Washington Mr. L. P. Crocker, Licensing Project itanager - Hatch U. S. Nuclear Regulatory Comission, Region II Dr. J. N. Grace, Regional Administrator Mr. P. Holmes-Ray, Senior Resident Inspector - Hatch -

9

'. APPENDIX B

, (Page 3 of 10)

ENCLOSURE i PLANT HATCH - UNITS 1, 2 NRC 00CKETS S0-321, 50-366 OPERATING LICENSES DPR-57, NPF-5 PLANT HATCH OPERATIONAL UPGRADE in reviewing the results of the recent evaluation of Plant Hatch by the Institute of Nuclear Power Operations, Georgia Power identified a narrow but important set of operating conditions and indications of perfomance that wa rranted priori ty attention and upgrading prior to the continuation of nomal plant operations. They are as follows:

1. The ability of shift cred to respond to plant transients as derconstrated in the simulator needs significant improvement.

2. During a plant startup and heatup, the monitoring and control of the reactor and behavior in the control room were not up to industry professional standards. .

3. The capability of control room personnel to determine plant status and respond to plant conditions in an optimum manner is impaired by administrative and equipment conditions as follows:

a. Critical drawings in the control room designated for operator use are not updated in a usable manner to allow operators to quickly assess plant status,

b. Many instrument panel components and plant equipment are not identified with permanent labels.

c. Under routine conditions, there are numerous annunciators that are continuously lighted and alams that frequently recur due to either the present design or equipment / system abnomalities.

d. Numerous equipment clearances have remained in ef fec t for several years.

l We have placed the plant in cold shutdown in order to concentrate attention to these areas. The upgrade is desired in order to increase the existing margin of safety upon which we base our strong confidence in nuclear power 3694N SL-4628-a E-1 May 4, 1988

APPENDIX 8 .

(Page 4 of 10, ENCLOSURE (Continued)

_ PLANT HATCH - UNITS 1, 2 NRC 00CKETS 50-321, 50-366 OPERATING LICENSES OPR-57, NPF-5 PLANT HATCH OPERATIONAL UPGRADE Attachment A provides our detailed plan for upgrading actions with the current status of each indicated. Upon completion of these actions, INPO will provide a follow-up evaluation to help u:; verify the effectiveness of our actions. When we are confid(nt that we have achieved our objective, we - ~

will resume operations. Attachment 8 provides an estimated restart schedule.

Attachments:

Attachment A: Plant Hatch Plan and Operational Upgrade Status Report Attachment 8: Plant Hatch Estimated Restart Schedule l

3684N SL-4628-a E-2 tiay '4,1988 l

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APPENDIX B .

(Page 5 of 10)

PLANT HATCH PLAN AND OPERATIONAL UPGRADE STATUS REPORT

1. Emergency Operating Procedures and Operator Skills in the Use of These Procedures Upgrade Actions Status

a. Completion of a technical Technical review has been performed to review and evaluation against compare the Hatch Emergency Operating the Emergency Procedure Guidelines Procedures (EOP) to the BWR Owners Group and correction of significant Emergency Procedure Guidelines (EPG). The_

identified deficiencies. EPG's are the standard from which all plants-develop site specific E0P's. The review was conducted by GPC and General Electric Company representatives and revealed no significant technical deficiencies. Minor technical deficiencies were resolved.

b. Establish a Task Force wich long The task force has been established and range objective of upgrading a charter issued. Example Emergency Emergency Operating Procedures. A Operating Procedures from similar .

schedule for Completing the modifica- plants have been collected on-site for l tions and retraining the operations detailed study. A revision leading to a staff must be prepared. simplified set of Emergency Operating e Procedures has been initiated with human factor improvements as one of the major considerations. Retraining is scheduled between July 25, 1988 and September 29, 1988 l to address the Emergency Operating Precedures revisions,

c. Establish a schedule for upgrading Human factor improvements are scheduled identified human factor areas, for completion. The initial response was to take minor improvements and enhance tra i n.i ng. These improvements included better photographic techniques, and making certain steps "sequence insensitive." A major revision is scheduled to be completed in July 1988. Many sources will be used as icputs to the E0P Task Force for the procedure revi si on. These sources include:

- INPO Assist Visit (April 1988) Comments

- General Electric Technical Review

APPENDIX B .

8 (Page 6 of 10) .

1 Emergency Operating Procedures and Operator Skills in the Use of These Procedures (Cont'd) l Upgrade Actions Status

c. (cont'd) _ - General Electric Human Factor Review l

, - Licensed Operator and Instructcr Coments l

d. Retrain the present ifcensed  ! mediate operator retraining began on April operators individually and as 8,1988 and will be completed by May 6,1988 a team in the use of the Emergency to address specific INPO concerns. This Operations Procedures. training focused on improving the operators' ability to respond to transients, with _

special emphasts on timely execution of ~

containment control actions. Training is scheduled between July 25, 1988 and September 29, 1988 to introduce the revised E0P's af ter human factor improvements are made,

e. Use senior operations management Senior operations management and and such technical experts as independent technical experts will necessary to evaluate the perforTnance be used to evaluate operators in the use of of individual operators and each Emergency Operating Procedures, both operating shif t as a team, using individually and as an operating shift team scenarios involving extensive use of prior to the team being used for power the Emergency Operating Procedures , operations. This evaluation is scheduled to start on May 7,1988.

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e i--- APPENDIX B (page 7 of 10)

S Conduct of Operations Within the Control Room Upgrade Actions Status

a. Arrange and hold reviews and The President, CEO, and Chairman of the Board discussions about the principles of of the Georgia Power Company has met with professionalism in the control room plant personnel to explain his expectations involving the following: for professionalism in the work place.

1. Shif t Supervisor The Executive Vice President has held

2. Operations Supervisor professionalism philosophy discussions with

3. Operations Superintendent plant supervisors and managers. The Vice

4. Manager of Operations President, Plant Manager, Manager of

5. Plant Manager Operations, and other managers have held

6. Vice President Plant Hatch -

f.eviews and discussions regarding _.

7. Executive Vice President, professionalism! Additional seminars have -

Nuclear Operations been scheduled for shift supervisors,

8. Chairrin of Board, CEO, operations supervisors, and superintendents Presioent of Georgia Power Company up through Operations line management to the Vice President.

b. Implement augmented procedures for Control room entry restrictions control board access control. have been strengthened to ensure unnecessary personnel are denied access with particular limitations on access to the main control boards.

~ :. Develop, using operator input, a codtt, Licensed operators and supervisors, of conduct to be followed by control have developed a standard for control room personnel and others entering the room conduct. This standard has been control room. implemented in the control room and has

. resulted in increased professionalism.

d. Clarify responsibilities and role of Control board walkdowns, monitoring and operator on the reactor control relief have been emphasized with licensed panel, operators and their supervision. Additional e operating personnel are assigned to duty stations, which in most cases, are external to the nain control room operating area.

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3, Operatn _' ' is and Control Mechanisms

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Uprgrade Actiou $tatuy, .~

a. Correct deffciencies associated Deficiencies associated with critical with critical @ewings and ensure that drawings have been corrected and copies of drawings are correctly marked-up to critical drawings placed in the control room, reflect the as-bui11 condition and are available to the operations personnel.

b. Augment and implement the procedures Procedures are in effect to maintain to ensure that critical drawings the critical drawings in the control room in the control room are maintained up-to-date.

up-to-date.

c. Walkdown systems and ideritify current T plant walkdown has been performed.

labeling which does not comply with Host deficiencies identified have been procedures and schedule the corrective resolved. The Executive Vice President actions. The Executive Vice president will review the status of remaining will approve the scope of corrective corrective actions prior to start-up.

action to be completed prior to start-up.

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d. Peview current labeling procedures Plant procedures are in effect to l

and revise as necessary to ensure z.aintain plant labeling . These that the procedure adequately addresses procedures now provide feedback maintenance of the labeling system, mechanisms to replace missing or damaged labels.

e. Establish a policy and the necessary

• The policy has been established and procedures which allow the removal procedures draf ted to address annunciators of single point inputs from multiple in a constant alann state. The policy point alanns, the removal of addresses conditionally disabling annunciator cards from limited input annunciators, compensatory measures, and annunciators, along with the necessary control mechanisms as required. The compensatory actions and control procedure will be in place prior to start-up, mechanisms until appropriate corrective action can be completed.

f. Establish a policy and the necessary The policy has been established and procedures which allow the operations procedures draf ted to address annunciators personnel on shift to conditionally in a constant alarm state. The policy disable temporarily nuisance type addresses conditionally disabling ,

annunciators until such time that the annunciators, compensatory measures, and l operational status of the plant would control mechanisms as required. The I cause the annunciator to provide valid procedure will be in place prior I infonnation or the annunciator is to start-up.

l nofified through .the nonnal design l proces s.

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, APPENDIX B j (Page 9 of 10) 3 Operational Aids and Control Mechanisms (Continued)

g. Initta'.e chasias that are causing A review cf control board annunciators inappropriate or invalid that were in a continuously lighted annunciators to be lighted in the condition during steady state operations was control room, conducted to determine the actions necessary to place the annunciator in the non-lighted condition. Design changes have been i initiated for those annunciators that could l be placed in the non-lighted state by an  ;

appropef ate set point change.

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h. Implement a procedure for prioritizing

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X new operations procedure will be -

maintenance and repair of instruments implemented by 5/7/88 to improve prioritiza-and equipment which contribute to tion of maintenance action for control room nuisance alarms and inappropriately instruments and annunciators.

If ghted annur.,f ator points.

f. Implement procedures for reviewing The review program for clearances has been open clearances every six months. enhanced such that when clearances reach an age of six months they are reviewed by

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operations management for consideration of continued use of the clearance procedure or whether they should be moved to other control mechanisms.

j. Implement other control mechanisms Increased emphasis has been placed on where appropriate to avoid the use of engineering support, procedure changes, and clearances for long term conditions or performance of work orders that allcw ,

problems. Only those long term removal of longstanding equipment clearances specifically approved by cleara nces. Outstanding long-term clearances tr.e Executive Vice President will be will be reviewed and approved by the cantinued for start-up. Executive Vice President prior to start-up.

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PUUIT HATCH ESTIMATED RESTART SCHEDULE Follow-up Evaluation by IHP0 May 12-13,1988 Completion of Upgrade Action May 13,1988 Georgia Power Company Deter 1nination of Readiness to Operate ,

May 13, 1988 Unit 2 Enter Condition 2 From Condition 4 May 14,1988 6 Hours From -

Unit 2 Critical Leaving Condition 4 ,

Unit 2 Reach 50% Power ,

May 18, 1988 Unit 1 Enter Condition 2 From Condition 4 May 18,1988 i

6 Hours From Unit 1 Critical leaving Condition 4 Unit 1 Reach 50% Power May 22,1988 Each unit is expected to be at 100% approximately 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> after reaching 505 power.

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7 MAY 2 5 G83 Docket Nos. 50-321, 50-366 License Nos. DPR-57, NPF-5 Georgia Power Company ATTN: Mr. R. P. Mcdonald Executive Vice President -

Nuclear Operations P. O. Box 4545 Atlanta, GA 30302 _

Gentlemen:

SUBJECT:

NRC INSPECTION REPORT NOS. 50-321/88-16 AND 50-366/88-16 This refers to the Nuclear Regulatory Comission (NRC) inspection conducted by G. B. Kuzo on May 9-11, 1988. The inspection included a review of activities authorized for your Hatch facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed inspectic.1 repori..

Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

Within the scope of the inspection, no violations or deviations were identified.

In accordance with Section 2.790 of the NRC's "Rules of Practice," Part 2, Title 10 Code of Federal Regulations, a copy of this letter and its enclosure will be placed in the NRC Public Document Room.

Should you have any questions concerning this letter, please contact us.

Sincerely, Douglas M. Collins, Chief Emergency Preparedness and Radiological Protection Branch Division of Radiation Safety and Safeguards

Enclosure:

Inspection Report ec w/ incl: (See page 2)

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Goergia Power Comp 3ny' 2 cc w/ enc 1:

J. T. Beckham, Vice President, Plant Hatch H. C. Nix, Plant Manager

0. M. Fraser, Site Quality Assurance (QA)

' Supervisor L. Gucwa, Manager, Nuclear Safety and Licensing bec w/ enc 1:

NRC Resident Inspector _

DRS Technical Assistant --

Hugh S. Jordan. Executive Secretary IE Mail and File Central Files Document Control Desk State of Georgia 4

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cat 04. k i EtGKuzo CHosey MSinkule 5/,,/88 5 0 /88 5/g/88

jp% 9 g6 k UNITED STATES 3

je NUCLEAR RECULATORY COMMISSION REGION 11

1. 101 MARIETTA ST., N.W.

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• • ATLANTA. GEORGIA 30323 MAY 2 5 M Report i!os.: 50-321/88-16 and 50-366/88-16 Licensee: Georgia Power Company P. O. Box 4545 Atlanta, GA 30302 Docket Nos.: 50-321 and 50-366 License Nos.: OPR-57 artd NPF ~

Facility Name: Hatch 1 and 2 -

Inspection Conducted: May 9-10, 1988 Inspector: 06: f) b I S I4::.. lNS G. B. Kuzo g Date] Signed Approved by: M13/S?

C.14. Hosey, Sectidn Chief Date Signed Division of Radiati'on Safety and Safeguards

SUMMARY

Scope: This special, unannounced inspection of radiation protection activities l involved review of recent changes to general einployee training, radiation l instrument performance checks, personnel contamination monitoring, and extremity exposure evaluations.

Results: The licensee's actions in the program area reviewed provided improved radiation protectiori training and initiated proper evaluations of recent changes regarding radiation protection ac;ivities.

No violations or deviations were identified in the areas inspected.

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PDR ADOCK 05000321 o DCD

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x REPORT DETAILS

1. Persons Contacted Licensee Employees

• S. Bethay Supervisor, Nuclear Safety and Compliance M. L. Link, Supervisor, Health Physics _

B. A. Morris, Dosimetry Foreman -

R. W. Ott, Supervisor Health Physics / Chemistry Training

• D. Smith, Superintendent, Health Physics

• R. W. Zavadoski, Manager. Health Physics and Chemistry Other licensee employees contacted included engineers, technicians, and office personnel.

Nuclear Regulatory Comission

• J. Menning, Resident Inspector

• At' tended' exit interview

2. Training and Qualifications (83723) 10 CFR 19.12 requires the licensee to instruct all individuals working in or frequenting any portion of the restricted area in health protection aspects associated with exposure to radioactive material or radiation, in precautions or procedures to minimize exposures, and in the purpose and functions of protective devices employed, applicable provisions of Commission regulations, individual responsibilities and the availability of radiation exposure data.

Licensee changes to general employee training (GET) regarding practical aspects of radiation protection instructional presentations and subsequent training evaluations were discussed and reviewed. The licensee has initiated changes to improve practical aspects regarding health physics training for workers at the facility. A recently developed training videotape outlining proper radiation protection practices was reviewed and discussed with licensee personnel. The videotape was developed to stress personnel dressout requirements and the techniques utilized for transfer of materials when moving between contaminated and non-contaminated areas at the facility. Licensee representatives stated that the film would be included in all GET training by June 1988. In addition, the licensee was evaluating the use of detailed mockups depicting specific facility conditions to train personnel regarding radiological hazards and good practices associated with : elected jobs.

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2 In addition to the increased attention to the proper use of protective clothing "dressout" and practical factors training, the licensee has specified evaluation-criteria for each step of the GET dressout exercise requirement. From review of the Georgia Employee Training Instructor Handbook, Medi6 No. GE-!H-101165-00, Radiation Protection Training -

Protective Clothing Exercise for Initial Training, the inspector noted that each step of the removal of protective clothing was further subdivided into specified point standard criteria based on detailed actions by the trainee, for example, sequence of activities, poor practices, improper disposal of materials, etc. From discussion with _

licensee personnel and review of licensee GET records the inspector -

l verified that the reported changes in evaluation criteria were implemented y I

for the training program. Review of initial test rcsults indicated that ~

employee scores have remained consistent using the new evaluation criteria.

No violations or deviations were identified.

3. Externa 1 Exposure (83723) 10 CFR 20.101 requires that no lionsee shall possess, use or transfer licensed material in such a manner as to cause any individual in a

! re'stricted area to receive in any period of one calendar quarter a total occupational duse in excess of 18.75 rems to the hands, foreanns, feet and l ankles.

In October 1987, the licensee initiated the use of wrist mounted thermo-luminescent dosimeters (TLDs) to monitor extremity expo t res when required

, for personnel conducting specific activities at the facility. Prior to l

October 1987, all extremity expcsures were conducted using finger ring TLDs. Licensee representatives stated that the rationale for the change was to decrease the frequency of losing the finger ring dosimetry when removing protective clothing while still using dosimetry acceptable to provide accurate extremity dose measurements. When the change was initiated the licensee had nat conducted any studies to verify the adequacy of the wrist mounted dosimeters to monitor extremity exposure.

Beginning April 1988, the licensee reinitiated the use of finger ring TLDs l

and also began a subsequent study of extremity exposures measured by finger ring compared to wrist mounted TLDs. Initial comparative results were reviewed and discussed with licensee representatives for personnel conducting work on piping associated with a reactor water cooling unit (RWCU) pump, Radiation Work Permit -(RWP) No. 188-0341, and control rod drive (CRO) maintenance and support work, RWP No. 288-1059. The inspector noted that extremity exposure as 'neas"red by the finger ring TLD ranged from similar results to exposure v11ues 2.3 times greater thLn values reported for the wrist mounted dosimetry. Discussions with licensee representatives knowledgeable of the personnel and their assigned work indicated that the variability in measurements between the wrist mounted and finger ring TL0s was associated with the type of job conducted. For example, the largest differencu were reptrted for welders work' g on the

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RWCU piping. Licensee representatives indicated that the comparative study was continuing and would be utilized to address the feasibility for the use of wrist mounted dosimetry in lieu of finger rings for specific job categories. The inspector noted that a review of the results and the licensee's evaluation was considered an inspector followup item (IFI) and would be reviewed during a subsequent inspection (50-321,366/88-16-01).

The inspector reviewed licensee extremity exposure data for the months, October 1987 through March 1988, when only wrist mounted TLDs were utilized for extremity exposure monitoring. Highest exposure values were N recorded for CRD work conducted during January, highest values ranging from approximately 600 to 750 mrem. Adjusting these results based on the highest bias for the finger mounted re'ative to wrist mounted TLDs noted for RWCU pump maintenance and weldine activities, that is, 2.3 times greater, the 'nspector determined thac 10 CFR Part 20 limits were not exceeded. Licensee representatives agreed to review in detail all extremity exposures, verify the assigned exposure, and, where applicable, make the appropriate adjustments to the assigned personnel exposure.

No violations or deviations were identified.

4 Coritrol oY Radioactive Materials and Contamination, Surveys and Monitoring (83726)

a. Survey Icstrument Performance Checks The. licensee discussed changes implemented regarding performance checks of personnel radiation contamination detection instrumentation. Performance checks conducted have been increased from a weekly to daily frequency for the contamination survey instruments located within or at the boundaries of the radi6 tion control areas (RCAs). This change affected the frequency of performance checks conducted for the following instrumentation; RM-14s, PCM-Is, PCM-6s, hand and foot monitors, and tool monitors.

For those instruments having multiple detectors, for example, the PCM-1s, all detectors associated with each instrument, are checked daily. -

The inspector verified that the daily perfomance checks for RM-14 instrumentation were perfomed as detailed in Health Physics Instrumentation Procedure, G2HI-0CB-016-05, Radiation Monitor RM-14 Operation and Calibration, Rev. 2, dated May 9, 1988. In addition, the licensee discussed Special Purpose Procedure 62-SP-040788-YL-101N,

. dated April 26, 1988, which was developed to provide a data base regarding the necessary frequency for radioactive source checks of the monitoring instrumentation, excluding the RM-14 instrumentation.

Licensee representatives stated that the self-monitoring capabilities of these "smart" instruments, that is, the capabilities to detect high and/or low background, and any interruption of gas flow to the detectors could allow reduced frequency of perfortnance checks and

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this was being evaluated by the special procedure. During tours of the facility the inspector verified that daily performance checks were being conducted for all contamination survey instrumentationas outlined in the special procedure.

b. Prior to the most recent refueling, bad fuel in the Unit 2 reactor had resulted in high noble gas activity in selected locations of the radiation control area. The high levels of noble gas resulted ir.

noble gas decay products, mainly Cesium 138 and Rubidium 89 to accumulate on the clothing- of workers entering the RCA. During -

exiting from the control area many workers alarmed the exit monitors ~

as a result of the buildup of noble gas daughter products on their clothing. These personnel then were surveyed by health physics technicians and required to wait until contamination levels decayed to background levelt, that is, less than 100 counts per minute (cpm) per HP-210 probe area .aove background, prior to being allowed to exit. Detailed guidance for the health physics technicians to conduct the surveys required to properly assess the source of contamination was not provided. In addition, a personnel contamination report was not issued unless contamination levels exceeded 500 cpm per probe area above background.

The licensee outlined changes to assessments of potential personnel contaminations identified at the facility. The inspector reviewed a Department Directive regarding contamination identification, dated April 22, 1988. The directive includes a flow chart and noble gas decay curve for use to logically evaluate potential contamination.

An assessment of a potentially contaminated individual included verification of monitor alarms, review of areas visited, location of the contamination on the person, and determination if change: in contamination levels follow the expected noble gas decay products half-life (approximately 30 minutes) through time. In addition, the directive now requires the completion of a personnel contamination report (PCR) for all contamination events exceeding 100 cpm / probe area. Currently a procedure is being reviewed for approval which when implemented would provide detailed guidance for the evaluation and reporting requirements associated with contamination events.

No violations or deviations were identified.

5. Exit Interview (30703)

The inspection scope and findings were summarized on May 11, 1988, with those persons indicated in Feragraph 1. The inspector discussed the areas ,

inspected and noted that the licensee's evaluation of results for  ;

extremity exposure monitoring as measured using finger ring compared to 1 wrist mounted thermal luminescent dosimeters (TLDs) would be considered an inspector followup item. The licensee did ret identify as proprietary any of the material provided to or reviewed by the inspector during'this inspection. Dissenting comments were not received from the licensee.

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