IR 05000309/1989080
| ML20247N108 | |
| Person / Time | |
|---|---|
| Site: | Maine Yankee |
| Issue date: | 03/24/1989 |
| From: | Kelly G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247N107 | List: |
| References | |
| 50-309-89-80, NUDOCS 8904060198 | |
| Download: ML20247N108 (60) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Report No.:
50-309/89-80 Docket No.:
50-309 Licensee:
Maine Yankee Atomic Power Company 83 Edison Drive Augusta, Maine 04336 Facility Name:
Maine Yankee Nuclear Power Station Inspection At:
Wiscasset, Maine and Bolton, Massachusetts l
Inspection Conducted:
January 9 through February 10, 1989 Inspection Team Members:
Team Leader:
J. Kaucher, Project Engineer, Region I, DRP l
Operations:
J. Macdonald, Resident Inspector, Vermont Yankee S. Barr, Reactor Engineer, Region I, DRP Engineering / Design Control:
D. Prevatte, WESTEC (Mechanical Systems)
T. White, WESTEC (Mechanical Systems)
G. Morris, WESTEC (Electrical Power)
G. Tenenbaum, WESTEC (I&C)
Surveillance:
J. Golla, Reactor Engineer, Region I, DRS Maintenance:
H. Gregg, Senior Reactor Engineer, Region I, DRS Quality Assurance:
T. Shedlosky, Senior Resident Inspector, Haddam
- Approved By;
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Gene 4(elly, Chief
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Date Technical Support StWff Division of Reactor Projects
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8904060198 890327 PDR ADOCK 05000309 Q
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SUMMARY A Team.of NRC inspectors and contractor personnel inspected the component cooling water (CCW) and supported. systems. This inspection was of broad scope in that it examined the engineering required to support ' design changes, operational occurrences, surveillance activities, maintenance avi quality program activities that were focused on the CCW system.
The licensee's 'self-initiated Safety System Functional Inspection (SSFI)
program, the initiation of a design basis reconstitution program, a know-ledgeable and dedicated staff, the plant simulator and development of probabilistic risk assessment (PRA) initiatives were strengths observed by the Team.
The Team's assessment of certain findings indicate weaknesses in several areas. -These include:
(1) An inconsistent safety perspective exemplified by your approach to resolving several longstanding problems such as:
the root cause of the failures associated with valves PCC-43. and SCC-165 (Sections 3.1.1 and 3.1.4); the lack of ~ control of instrument setpoints and a formal program to address instruments found out of calibration (Se'ctions 3.3.1 and 2); and, the role of Maine Yankee's QA audit pro-gram in identifying certain of those programmatic findings identified by the SSFI team.
(2) Technical Specifications or other administrative controls which do not address the ability to cross-tie direct current- (dc) buses 1 and 3, thus allowing a common mode failure to render both diesel gener-ators inoperable, and that do not place any restrictions on the removal from service of all de buses when shut down (Section 3.2.5).
(3) Short circuit protection on the dc buses and motor thermal protection in general (Section 3.2.5).
(4) The inability to determine CCW system capability to perform its intended safety function because of questions regarding: the effects of thermal shrink and swell (Section 3.1.6); air accumulator capacity to isolate non-essential loads (Section 3.1.3); performance testing of the RHR heat exchanger and new CCW heat exchangers;.and, the lack of a complete CCW system heat balance (Section 3.1.2).
(5) Tir apparent use of component replacement (Section 7.2) when the rigor of the design process is more appropriate (Sections 3.2.4 and 5.1).
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The Team found that the operational activities described in Section 4 associated with the CCW system were acceptable.
The Team observed good practices as well as a professional atmosphere in the control room.
The Operations staff were found to be alert and knowledgeable.
Component labeling was identified as an issue warranting further management atten-tion, particularly for those design evolutions requiring manual operator action (Sections 3.1.7 and 4.1).
The Team found that the plant was being effectively maintained and the material condition of the CCW system was good. Inconsistencies were found in the preventive maintenance requirements for certain valves, in that similar valves were not being consistently maintained (Section 5.4.1).
Maintenance personnel were found to be motivated, well managed and com-petent.
In Section 6, the Team concluded that the surveillance testing program was generally adequate, but several check valves were found that should have been included in the In-Service Testing Program (Section 3.1.5).
The post-maintenance check valve reliability program was found to be an innovative and effective program.
Performance-based audits that included detailed technical findings were evident in QA/QC activities associated with the CCW system (Section 7.4).
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2.0 INSPECTION OBJECTIVES The objective of the Safety System Functional Inspection (SSFI) at Maine Yankee was to assess the operational readiness of the component cooling water (CCW) system and its auxiliary support systems by determining whether:
a.
The CCW system was capable of performing the safety functions I
required by its design bases.
b.
Testing was adequate to demonstrate that CCW would perform all
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required safety functions.
Maintenance was adequate to ensure reliable system availability under c.
postulated accident conditions.
d.
Human factors considerations related to CCW (e.g., accessibility and labeling of valves) and the system's supporting procedures were ade-quate to ensure proper system operation under normal and accident conditions.
Quality program activities related to CCW were effective in identify-e.
ing safety issues and in assuring their resolution.
To accomplish this objective, the Team reviewed modification packages and reference documentation and examined the available calculations which sup-ported CCW design.
System operating procedures were evaluated to assess the detail, accuracy and adequacy of direction provided to operators. The Team observed control room activities throughout the course of the inspec-tion, and reviewed maintenance procedures and programs related to CCW.
Additionally, the Team performed system walkdowns to verify that system configuration was in accordance with design documents. Finally, the Team assessed the overall design control program as applied to the CCW system.
The principal findings pertaining to the operational readiness of the CCW system and auxiliary support systems, and the effectiveness of programs to ensure continued safe operation, are summarized in the Executive Summary of Section 1.
The following sections provide detailed findings, including both strengths and weaknesses, in each of the functional areas inspecte _ _ _ _ _ _ _ _ _ _ _
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3.0 SYSTEM DESIGN AND DESIGN CONTROL.
The design portion of the SSFI focused on a review of the design basis of the component cooling water system and its components to assess the ade-quacy of the design or to clarify the original design intent.
Figurer 1 and 2 attached to this report depict simplified schematics of the PCCW and SCCW systems.
The licensee's self-initiated functional assessment of two safety systems, the initiation of a design-bases reconstitution project, and the experi-ence of engineering staff were strengths observed in the design area. The team identified a number of weaknesses in several engineering activities.
These observations include (1) missing or inadequate design analyses; and (2) lack of sufficient documentation to demonstrate the adequacy of the class 1E electrical system protection for the service water and component cooling water system motors. The following is a description of observa-tions in each discipline which contributed to the Team's conclusions.
3.1 Mechanical System Design In the mechanical system area, the Team reviewed the original design and installation of the component cooling water (CCW) systems to assess system functionality. The CCW systems consist of two separate subsystems:
the primary component cooling (PCC) system and the secondary component cooling (SCC) system. The review consisted of an i
evaluation of system design documents, including original engineering l
calculations and design change modification packages, safety evalua-i tions, and a system walkdown to verify as-built configuration of the
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CCW system and all interfacing systems.
i The Team identified the following areas where there appeared to be inadequacies in the design or in documentation to support the design.
3.1.1 CCW System Motor Operated Valve Failures Motor operated valves SCC-M-165 and PCC-M-43 are the isola-tion valves for the component cooling water to the RHR heat exchangers. They differ from typical motor operated valves in that the operators are not mounted directly on the valves, but instead are separated from the valves and con-nected by very slender reach rods. The safety function of these valves is to open to allow the plant to enter the recircu stion phase of cooldown after a loss of coolant accident (LOCA).
Unless they open, decay heat cannot be transferred from the core and the containment to the ultimate heat sink.
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The Team discovered that these valves have a long history of failures, including failures to open upon demand and breakage of components in the valve operators. Many of the problems with these valves have been associated with the reach rod feature of the design.
Plant documents indicate I
that the original design match of the operator to the valve did not include consideration of the reach rods and that,
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when they were subsequently added, they were not properly
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designed.
From. these same documents,' it appears that the causes of these problems and the solutions were formally identified as early as 1983.
The causes of the problems appear to have been:
The reach rods were not properly designed in that they a.
far exceed the manufacturers' maximum slenderness ratio, and as a result, they experience large lateral deflections whenever high torque is applied.
b.
The operator-to-valve match was not adjusted to accom-modate the additional torque that would be required due to the transmission losses that would be incurred with the reach rods.
When this adjustment was made, it further exacerbated the lateral deflection problems.
The solutions identified by the licensee included two modifications:
a.
Change the valves from torque seating to position seating so that excessive torque would not be required to unseat the valves.
b.
Add an. intermediate span bearing to the reach rod to reduce the slenderness ratio and eliminate the excessive lateral deflection.
These causes and solutions were identified in at least ten separate documents spanning the period from 1983 through 1988, including two memos, one outside consultant report, two Operational Assessment Recommendations, one engineering design change request (EDCR 83-511) to perform these modif-ications (subsequently cancelled), and two licensee event reports (LERs83-017 and 83-033) in which a commitment was made to the NRC that the position seating modification would be done and the long-term solution would be per-formed.
To date, this commitment has not been carried out although the licensee has expressed an intent to modify the closing circuits, install the mid-span bearings, and con-duct MOVATS testing.
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During this SSFI, the licensee replaced the pins. and inspected _ the bearings and. linkage of the reach rods. Al-though these actions addressed some of the symptoms asso-ciated with the reach rod failures, they did not address the root causes of the problem.
It is evident from the documentation over the past five years that the reliability of these valves is low, and that the licensee has been' aware of this problem and its poten-tial solutions for some time.
The Team considers the reliability of these valves to be a concern which ' requires prompt licensee attention.
3.1.2 CCW System Heat Balance Design Basis The licensee was unable to provide verifiable up-to-date information showing that the CCW system can perform its design safety function. The safety function of the PCC and SCC systems is to provide an intermediate heat transfer path between safety-related heat loads and the ultimate heat sink following postulated plant accidents.
A number of calculations addressing various facets of the required analyses were provided.
However, all of the cal-culations provided were either incomplete, contradictory, or based on inputs for which the source could not be iden-tified -or confirmed.
In particular, no analyses were available to show that, after initial operation os the emergency core cooling system (ECCS) with only one divis-ion of CCW operating, heat could be transferred from the reactor core and containment to the ultimate heat si n k-at least at the rate at which it was being generated-while simultaneously cooling other required safety-related loads without exceeding system temperature limitations.
Other examples of similar calculation shortcomings are:
a.
When the plant license was amended to allow stretching-the rated thermal power from 2440 MW to 2630 MW, no updated analyses were cor pleted to verify CCW system capabilities at this new rating.
The licensee has submitted a current license amendment proposal to the NRC to stretch power to 2700 MW. Again, no updated system heat balance analyses have been performed in support of that change.
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b.
On occasion, the licensee has ' experienced river water temperatures (the ultimate heat sink) as high as 73 F.
All plant analyses to date have been based on tempera-tures no greater than 70 F.
There has been no complete quantitative analysis done to determine pos-sible system degradation under these conditions.
EDCR 86-04 replaced CCW heat exchangers E-4A (PCC) and c.
E-5B (SCC).
The new heat exchangers have an added heat transfer capability due to increased area. How-ever, this is offset by the use of titanium tubes instead of copper-nickel tubes as were in the original heat exchangers.
The safety analysis concluded that the new heat exchangers had a 20*s higher heat transfer capability based on preliminary calculations.
How-ever, calculations of the as-built configuration of the new heat exchangers had not been performed until prompted by this inspection. The preliminary calcula-tions had been based on 22 BWG tube wall thickness tubes, while the actual tubes were 20 BWG (thicker).
An as-built calculation performed during the inspec-tion determined that the actual heat transfer capacity increase is 17%; less margin than originally assumed.
d.
Many inputs, assumptions, and results in the original analyses are inconsistent, or unsubstantiated as follows:
(1) The residual heat removal (RHR) heat exchanger overall heat transfer coefficient U value us not consistently documented.
A spectrum of values for all of the critical parameters, used to envelope the limiting cases of system operation, do not appear to have been chosen for that pur-pose and, in some cases, are non-conservative.
At least two limiting cases should have been addressed:
verification that the core and con-tainment heat loads can be carried with U values corresponding to the worst-case fouling factors, and verification that with the best-case fouling factor on the RHR heat exchanger, the CCW temper-ature will not cause degradation of the perform-ance of the other safety-related components.
U values found ranged from 219 to 484 BTU / hour, sq ft, degree F.
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l (2) When the Team discussed with the licensee the-lack of viable heat transfer coefficient data,
.the response was that no U values were available l
other than the guaranteed value (227) supplied by
the manufacturer. When the team pointed out that
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the actual U value could be calculated from test data, the licensee responded that the test data available was inadequate for such a determination and that such testing could not be performed.
From this, it appears that the RHR heat exchangers' performance has never been verified by a valid test.
(3) Two heat load calculations for the diesel gener-ators were found with bases for the 2000-hour rated power of 2000 kW and 2300 kW. The actual 2000-hour rating is 2850 kW, although the system should be capable of carrying the heat load for the 2000-hour rating.
(4) Various values were used in the system calcula-tions without identifying the conditions when the values would be appropriate.
Seven different U values for the CCW heat exchangers were found ranging from 213 to 335.
Three different values for CCW flow were used:
5000 gpm, 5866 gpm, and 6000 gpm.
(5) Two values for service water flow were used:
10,000 gpm and 15,000 gpm.
(6) Ten different values for total accident heat load on the CCW heat exchangers were found ranging from 106.5 million BTV/ hour to 198 million BTU /
hour.
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(7) Three values for RHR accident heat load were found ranging from 100 million to 170 million BTV/ hour.
(8) The control room heat load ranged from 244 thou-sand to 455 thousand BTV/ hour.
(9) The cold side CCW accident temperature ranged from 102.5 F to 112 F.
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The above questions related to CCW system capability i
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have. potentially.significant ramifications for core-i and containment response in the design basis.
The Team found that the design analyses which should be controlled and verified 'by. testing to demonstrate the capability of.the-CCW system to perform its safety i
functions were. incomplete, lacking in rigor, and-did'
not.' accurately. represent the plant design in either its original or current configuration.
The. licensee could not provide the team with any valid test results.
to substantiate the design. Therefore, the ability of the system to perform its safety functions.could not
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During - the. exit meeting on February 10, ' the licensee committed to perform a current heat balance analysis to verify that system design is adequate.
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3.1.3 SCC Isolation Valve Backup Air Accumulator EDCR 80-45 installed a 60 gallon instrument air accumulator as a backup air supply for SCC valves SCC-A-460 and SCC-A-461. The valves are required to close upon loss of suction pressure to the SCC-pumps to isolate the non-safety-related portion of the system from the safety-related portion.
These valves require air pressure to close, and spring-return. to the open position.
The manufacturer's informa-tion available at the time that the modification was per-formed indicated that 80 psig was required.to hold them in the closed position.
The sizing of the accumulator was performed in calculation EDCR-80-45-CAL-2 and was based on assumptions of one opera-tion of the valves, leakage over a 24-hour period, and cooldown in the area of the accumulators from 80 F to 40 F.
The 24-hour requirement was based upon the expectation that within that time period the operator would manually isolate the non-safety piping.
Two of the assumptions used in the calculation, the start-inq pressure for the accumulator and the starting tempera-ture, are considered by the Team to be incorrect, and in a non-conservative direction.
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The starting pressure used.for the backup accumulator was 99 psig. This -is considered by the. Team to be too high.
Per the licensee, the lead compressor of the' instrument air system normally cycles between 90 and 100 psig; the lag compressor cycles between 85 'and 95 psig (These' pressures may be even less due. to the controlling-pressure switch
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setpoint. tolerances). -'Therefore, with a low demand condi-tion requiring only one compressor, the pressure at the.
main system accumulators. may be as low as 90 psig_ and as high as 100 psig.
For the high system demand situation, the second compressor would begin to cycle and the main accumulator-pressure would vary between - 85 psig and. 95 psig.
However, between the main accumulators and the-back-up accumulator are system filters,' dryers, and piping which will reduce the supply pressure to the backup accumulator even further, especially for the high demand situation.
In addition, the backup accumulator is appropriately isolated from the non-safety-related portion of the instrument air system by two spring-loaded, soft seat ' check valves in series to prevent.back leakage. Each of these check valves requires'one psid to open.
Therefore, assuming a finite leakage from the backup' accum-ulator, the accumulator pressure at the beginning of an accident will be the main accumulator pressure minus the losses between the main accumulators and the backup accum-ulator, which for the high demand situation could be very.
significant.
The starting temperature assumed in the calculation was 80 F, and it was assumed to decrease 40 F in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as the plant cooled down following a LOCA. However, the team measured the actual temperature of the area at the accumu-lator at 93 F.
Using this starting temperature and the other assumptions used by the licensee, the team calculated that the starting air pressure required in the ~ backup
accumulator is 97.4 psig. With the possible system opera-ting conditions that may exist in the instrument air system as described above, it is unreasonable to expect that this pressure can be maintained at all times.
Therefore, the Team considers that the design of the. backup air supply is inadequate.
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The intent of the design of the backup air supply.modifica-
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tion was to assure that whenever isolation of the safety-related portion of the SCC system from the non-safety-related portion was required, there would be a reliable source of air to maintain the isolation valves closed.
Such an isolation would be required if there were a break in the non-safety related portion. If the isolation valves
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were not held shut, the SCC system may be drained and it would cease to function.
This could leave the plant with no means of post-LOCA cooling from the SCC system.
i During the SSFI, the licensee installed a temporary high pressure air source to increase the amount of air available for this valve and increased operator monitoring of accumu-(
lator pressure. The licensee has stated that the manufac-l turer for SCC-A-460/461 has recently indicated that a sig-
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nificantly lower pressure is required to hold these valves closed.
The licensee committed to take this into account when the accumulator design is reevaluated.
3.1.4 Drawing Control Maine Yankee does not have a controlled print or other source document which shows the reach rod assembly for the RHR heat exchanger stop valves (PCC-M-43/ SCC-M-165) with the location of the roll pins installed or the material used for these pins. These reach rods have a history of repeated failure of the universal coupling roll pins dating back at least to 1983.
During each of these failure events, the pins were replaced with commercial grade mate-rial due to the lack of the specific material requirements for the original pins.
The RHR heat exchangers must be available for post-LOCA cooldown of the reactor and containment.
A recirculation actuation signal causes these valves to open, allowing CCW system flow through these heat exchangers.
The Team was concerned that the roll pin material information was not
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available and, considering the safety-related nature of these valves combined with historic low reliability, that a
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thorough engineering review of material requirements had not been performed.
In response to the Team's concerns, an engineering evalua-tion was completed by the licensee to find an appropriate replacement material.
The licensee decided, based on the ability to withstand a maximum torque of 250 ft-lb, to replace the installed pins with pins made of A-193 Gr. B7.
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DR-0618-89 installed these pins in February 1989. However, there is currently no controlled print documenting this change.
If at some future time a pin replacement is required, the material type information will not be readily available.
This information will only be : located if the valve maintenance history records are researched. The team considers it essential that a controlled document be avail-able indicating the correct material and sizing specifica-tions for these pins so that effective repairs can be made to maintain the highest possible state of RHR system readiness.
The Team agreed with the licensee's intent to develop a controlled print of the reach rod assembly showing the pins and indicating the material used.
3.1.5 Check Valve Design and Testing There are numerous check valves in the PCC and SCC systems which must function in both the open and closed directions in order for the systems to perform their design functions.
Many of these valves function routinely in both directions as a part of normal system operation. Therefore, any fail-ure would be quickly detected.
However, some of these valves are never required to function in the closed direc-tion except during accident conditions.
Therefore, unless they are tested, their ability to function is not known, and an undetected failure can exist.
One such failure together with a single failure in the opposite division I
could render both the PCC and SCC systems inoperable.
Recognizing the significance of safety-related check valves, the licensee has established a program for "> ting critical check valves in the plant. However, the following PCC system check valves have not been incorporated in the program and, in one case involving two valves, no provis-ions have been made in the design to allow testing:
PDCR 4-73 installed check valves PCC-455 and PCC-446
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to isolate the non safety class portion of the PCC system from the safety class portion.
Neither of these valves is surveillance tested, and neither valve has design provisions for testing.
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PDCR 4-73 installed check valves PCC-455 and PCC-446 to isolate the non safety class portion of the PCC systen from the safety class portion.
Neither of these valves is surveillance tested, and neither valve f
has design provisions for testing.
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L EDCR 80-51 added check valves PCC-508 and PCC-509. to
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the. return side of the containment heat loads which were considered to be vulnerable.to high energy pipe break effects. Their purpose was to limit the loss of water inventory from the PCC system to prevent losing the level in the surge tank.
Neither of these valves is in the check valve surveillance program.
The licensee.has stated that test procedures will be developed. and these check valves will be ' included into their already established testing-program for critical check valves.
3.1.6 Secondary Component Cooling Water Design Calculation MY-EDCR 80-45-CAL-1, Secondary Component Cool-ing Water Isolation -on Low Suction Prescure, was performed to show that with a break in the non-safety-related portion of the SCC system, the isolation valves would close in time to prevent 'a loss of cooling water inventory that would cause failure of the system. Although this was a detailed -
calculation, it failed to account for an important factor:
the swell and shrink of the water in the system as it heats up from the normal operating temperature to the maximum
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LOCA temperature and then cools down to the post-LOCA tem-perature.
Since the results of the original calculation were. marginally acceptable, this new consideration could possibly show an unacceptable inventory loss when the cal-culation is reevaluated by the licensee.
An additional exacerbating factor is the surge tank vent valve which closes upon detection of high radiation in the SCC system.
Such a condition might be expected.to exist, post-LOCA. With the closure of this valve, the swell in the system may push water out of the tank overflow line into the aerated drain tank. This would be a further loss in system water inventory.
If the water level in the sys-tem becomes too low, it may cause cavitation of the pumps and/or the creation of voids in the components being cooled, which would reduce the heat being transferred at these components.
Either of these situations would con-stitute a failure of the system to perform its safety func-tion, and could cause the plant to be without means of adequate post-LOCA cooling.
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The licensee completed a preliminary review of the SCC sys-
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. tem during this - inspection and has' indicated that system
. operability'will not be adversely affected.. by shrink and swell during a design basis event. _ The licensee committed to a more' formal system re-analysis.
3.1.7 Emergency Operating Procedures
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Th'e Team believes that the current post-LOCA CCW system emergency operating procedures (EOPs) may result in inade-J quate service of safety related heat loads in certain sys-tem lineups.
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Cooling water is supplied to the primary and secondary component coolers by the two divisions of the service water system (SWS).
This system is normally ' lined up such that each SWS division is connected to both. the primary and secondary component coolers -through the normally open man-ual crosstie valve SW-32.
Therefore, complete division separation does not exist. Only one CCW heat exchanger in each division is normally in service, with the outlet valve of the out-of-service heat exchanger closed. However, with abnormally high heat. load and high' service water tempera-ture conditions, both heat exchangers -in.each division may be in service.
During a LOCA with concurrent loss of offsite power and failure.of one division of emergency power, the flow from the remaining division of service water would be divided between both divisions (i.e., PCCW and SCCW) of component cooling water. One CCW division would still be lined up, but would not be in. operation due to the loss of power.
Therefore, the operable. division of component cooling water-would be receiving only half the available flow.
The licensee has shown that one division of service water is capable of supplying the required heat transfer, with one pump running and without exceeding net positive suction head (NPSH) or motor current limitations until the plant enters the recirculation mode. On entering this mode, the addition of the heat load from the RHR system may cause the CCW system to exceed the design capability. The licensee has stated that the reason for operating with both divis-ions of service water crosstied is to increase operational reliability and to reduce the probability of inadvertent plant trips. If the SWS divisions were separated, the loss l
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of.a single service' water pump during ' normal operation
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would cause loss of cooling to all operational loads in (
that division which would have a high probability of _caus-
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ing ~a plant trip.. By'having the SWS divisions crosstied,
. the operating pump in the opposite division would continue to supply the heat loads in both divisfons 'until a second
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pump in' the af fected ' division could. be manually started by the operator.
The Team concurs with the objective of minimizing chal--
lenges to plant systems imposed by inadvertent plant trips.
However, the. lack of formal guidance in plant E0Ps concern-ing cross-tied service water divisions lineup leaves the plant in a vulnerable condition which may not necessarily I
be rectified manually by an operator within' an appropriate time frame.
The licensee committed that the E0P will be modified to require isolation - of both heat exchangers in the inoperable CCW system. if only one service pump is available.
The Team notes that the area where the valves that 'are to be manipulated are located has a post-LOCA radiation level of about 3 R/ hour.. Although these valves-are accessible just outside of the control room, this oper-ator. action would increase the operator's overall radiation exposure and.should be thoroughly reviewed within the ALARA principles.
Also, valve labeling for SWS and CCW compo-nents should be considered in'this regard.
3.2 ' Electrical System Design In the electrical discipline, the team reviewed modifications asso-ciated with the component cooling' water (CCW) systems and the asso-ciated electrical support systems. The review consisted of an evalu-ation of the electrical schematics associated with the CCW system
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I control circuits to verify adequate control functions, correct power supply associations, and the electrical protective devices associated with pump and valve motors.
The Team also reviewed the adequacy of the power supplies associated with the CCW systems.
The review included the installation of the new batteries, ac and dc short circuit and voltage studies, breaker coordination, and diesel generator loading.
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3.2.1 Selection of Electrical Protective Devices-3.2.1.1 4000-Volt Motor Protection The Team reviewed the motor data available for the PCC.and SCC pump motors and the settings for the overcurrent relays. The motors for both sets of pumps are identical 350 horsepower _,1.15 ser-
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vice factor units.
The only data available on these units came from a motor data sheet included with the Stone and Webster specification file for these pumps.
This data sheet gave the motor.
running and locked rotor currents and conflicting information concerning the number of permissible starts per hour.
Neither Maine Yankee, Yankee Atomic Electric Company (YAEC), nor Stone and Webster could locate any motor thermal-capability curves or pump motor acceleration data.
The overcurrent protection consisted of a com-bination of a replica relay to alarm on small overloads and a three-unit overcurrent relay used to ' alarm and trip on large overloads and faults.
Apparently, these relay setpoints were selected based solely on the full load running and locked rotor currents. There was no apparent basis for the selection of the time dial (delay time) set-ting.
The time dial that was selected will per-mit a sustained locked rotor current for 10 seconds. Without thermal damage information from the manufacturer, no conclusion can be drawn as to whether this setpoint is conservative.
3.2.1.2 460-Volt Motor Protection The overcurrent relays for the safety-related service water pump motors and other 460 volt loads are being replaced with new solid state overcurrent devices.
These devices provide bet-ter coordination and are more stable than the original overcurrent units.
Again, the only motor characteristics available were motor full load and locked rotor currr.nt from the Stone and Webster data sheets.
In the case of the service
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water pump motor prote : tion, the time delay set-ting on locked rotor was 5 seconds.
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f 3.2.1.3 Motor Operated Valves The Team reviewed modification package EDCR 80-51, which replaced the actuator on valve PCC-M-219 so that this isolation valve would close faster. This replacement required a larger size motor than what was originally installed.
As part of this modification package, the thermal overload relay heaters were resized by YAEC. The results of this analysis concluded that the installed overload heaters were adequate for the new larger motor because they had originally been sized too large. The Team reviewed the analysis that resized the heaters for the new motor asso-ciated with PCC-M-219 and agreed with the size selected.
Maine Yankee stated that a service request had been issued to recalculate all other MOV over-loads.
This work had not yet been performed.
The Team reviewed the existing overload protec-tion for the remainder of the PCC and SCC motor operated valves and found them adequate or slightly oversized.
3.2.2 Short Circuit Studies
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3.2.2.1 DC Short Circuit Batteries 1 and 3 feed the dc buses that supply control power to the safety-related 4160-volt switchgear. This switchgear, in turn, powers the PCC and SCC pump motors. The original batteries supplied for Maine Yankee contained lead-antimony cells.
These type cells age quickly and require increased maintenance as they age.
These cells were replaced in 1987 under EDCR 86-02 with lead calcium cells.
DC buses 1 and 3 consist of an array of molded case circuit breakers. The main incoming breaker is a non-automatic breaker used only as a discon-nect switch. All the remaining breakers, except the tie breaker between the two buses, have pub-lished de short circuit interrupting ratings of 10,000 amperes.
It appears from the original (pre-1970) calculations that additional cable resistance was added between the batteries and the dc buses to limit the short circuit current to under 10,000 amperes.
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In 1985, Stone and Webster formally issued calcu-lation E-1, DC Short Circuit Calculation. Revis-ion 4 to this calculation was issued in January 1988.
This calculation was not updated to show the new type cells nor were any acceptance cri-teria given for the acceptable short circuit at dc buses 1 and 3.
The calculation identified a
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short circuit at these buses of 13,000 amperes with the old batteries, 3000 amperes above the original design basis.
This calculation also assumed that the battery i
electrolyte temperature was 77 F.
Because bat-teries are electrochemical devices, their capa-city is affected by temperature.
Temperatures above 77 F will increase their short circuit potential.
A review of the bimonthly battery surveillance revealed temperatures as high as 92 F.
The Team estimated that when the calculation is corrected for the new cells and temperature is factored into the equation, the short circuit potential at the dc buses will be well above 15,000 amperes.
3.2.2.2 AC Short Circuit Calculation E-5, Rev.
2, Medium Voltage Switch-gear Short Circuit Study, was issued in February 1987 and identified a concern that the interrupt-ing duty of the 4160-volt circuit breakers ex-ceeded their ratings.
This subject was again raised by YAEC in February 1988 after it was identified as an open item in NRC Inspection Report 50-309/87-12.
This 1988 memo concluded that, when Seabrook Station was removed from the 345-kV system contribution and credit was taken for delayed tripping of the motor circuit breakers, the circuit breakers associated with the PCC and SCC pump motors would not be sub-jected to short circuits above their interrupting rating.
The Team reviewed the original calculation and discovered that the 345-kV system contribution was taken at 1.0 per unit, i.e.,
the system volt-age used was exactly 345 kV.
System voltage af-fects the amount of current it will contribute to the short circuit.
System voltage will also af-fect the voltage of the 4160-volt switchgear.
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The maximum' interrupting capability. of circuit breakers is related to the prefault voltage seen by the circuit breaker and decreases as the volt-' -
age. increases.
The Team contacted' the Central Maine Power dispatcher and was told-that the sys-tem voltage could range up to.362. kV.
The com-puter data. log. in' the control room was reviewed for' the month of. January 1989.and up to.
February 8, 1989, and this - confirmed that the system voltage did in. fact ' vary' over a ' range of 15 kV over that period.of 39 days. The Team also noted.that the voltmeters in the control room for the-345-kV system did not agree with the computer data, again varying from 10 to 15 kV difference.
Preliminary review by the. licensee indicated a potential error of approximately' 2% for the computer transducer.
The Team estimated that when the system maximum permitted voltage is taken into account, the cir-cuit breakers for the PCC and SCC pump motors (and other 4160-volt motor circuit breakers)-
could see a short circuit approximately 4% above their rating.
3.2.3 Power Supply Capability 3.2.3.1 Diesel Generator Loading Voltage Terminal The Team reviewed the diesel generator loading calculation, MYC 107, Rev.1, September 4,1987, to confirm the loading of the PCC and SCC pumps.
This calculation established the response of the electrical system with a three-step sequential loading of each diesel generator following a com-l bined accident and loss of offsite power.
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The calculation results showed that during the voltage transient which followed each step load,
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the voltage could dip to as low as 57.5% at the
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generator terminals.
The calculation acknow-i ledged that this voltage dip could result in l
motor control contactors dropping out, but con-l cluded that this was not a problem because the
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voltage would quickly recover and reenergize the l
contactors and the driving motors.
However, the b_ _ _
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.20 calculation - failed to evaluate 'the effect of having multiple starts on individual motor con-trol center loads which would stop and must re-
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start each time their contactor drops out on low voltage. These multiple starts would also affect-
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the response of the motor thermal overload protection.
l The Team also questioned the source of the gener-ator's voltage recovery curve, ACD 67-41, which was used in the calculation to establish the
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magnitude of the voltage transients.
The team
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was informed that this curve came from the origi-nal Stone and Webster calculation.
The calcula-tion, in fact, states that the source. of the voltage recovery curve is from the original-diesel generator proposal data package.
It does not appear that the voltage recovery curve has ever been verified for the as-installed Maine Yankee diesel generators.
3.2.3.2 Safety-Related Battery Capacity The Team reviewed the battery sizing calcula-tions, MYC 104, Rev.1, July 18,1982, to' confirm that sufficient vo.ltage would be available during loss of a battery charger to provide sufficient power to operate the pCC and SCC de control circuits.
These calculations had not been updated to show the reduced battery capacity when the 60-cell batteries were replaced with 59-cell batteries.
This difference in one cell could result in as much as a loss of 8% capacity in a 2-hour dis-charge.
The calculations also appeared to use nominal inverter loads taken from normal opera-ting data.
The inverters normally operate with 130 volts dc; however, because they are constant kVA devices, they will draw higher than normal de currents when the dc voltages -drop during battery discharge.
The inverters account for a substantial portion of the 2-hour battery load and the decrease in voltage could easily increase this load by 15%.
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In spite of these errors, the 1982 calculation showed that batteries had more than enough spare capacity to account for the resulting increase in required capacity estimated by the Team.
Also, despite the lack of a de voltage study, the Team estimated that sufficient margin would be avail-able at the 4160-volt switchgear dc control power bus to ensure operation of the PCC and SCC de control circuits.
3.2.4 Design Control Problems 3.2.4.1 Safety-Related Battery Replacement The Team's revies of the replacement of the safety-related batteries identified three areas of concern:
(a) Failure to update related design calcula-tions prior to installation of the new bat-tery designs was considered to be poor engineering practice.
(b) Batteries 2 and 4 were replaced as component substitutions instead of design modifica-tions in spite of the fact that the batter-ies were a different manufacturer, a differ-ent cell type, contained fewer number of cells per battery, required'different seis-mic mounting, required changes to the FSAR, and required changes to the maintenance and test procedures.
The team considers this beyond the scope of " component substitution."
(c) The acceptance test of the cells for batter-ies 2 and 4 at both the manufacturer's facility and following installation at Maine Yankee used the wrong discharge rate for the stated test length.
This was considered a failure of Quality Control to veri fy the correct test requirement _ _ __
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3.2.4.2 Component Numbering. System The Team reviewed the, electrical. schematics for the PCC and SCC system and found a component num-bering system that was.'different than the com-ponent numbers used on the plant equipment. The Team foord that the. electrical schematics used a l numbering ~ system established by Stone'and Webster during - the. original design of. the plant.
The licensee supplied a duplicate set of P& ids and a cross-reference list to enable the electrical reviewers to correlate between the electrical schematics and the as-installed equipment.
The Tew consicers this a poor practice which could rc ult in confusion by Operations per anel.
3.2.4.3 Control of Calculations The Team obtained some electrical calculations-from YAEC at the beginning of the inspection.
When the Team obtained the same calculations from Maine Yankee, it found that one of these calcula-tions was a different revision (the Maine Yankee copy being 6 years out of date).
In an attempt to determine what was the latest official calcu-lation, the Team found that the Maine Yankee document cont ro'l center did not maintain copies of the "MYC" series calculations, and did not even have a list of these calculations. The Team obtained a list of these calculations from YAEC-and found that many of the calculations of interest did not identify the latest revision of the calculation by number or date.
Therefore, the only method found to identify the. latest YAEC generated MY calculations was to ask the supervising engineer at YAEC.
3.2.4.4 Electrical Loaa Tra Aing Safety-related modification packages (EDCRs) are either performed by YAEC or reviewed by YAEC. As part of this review, an electrical load tracking i
form (Form 1A) is completed by YAEC to control
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the loads on the electrical system.
Non-safety-related modifications not performed by YAEC and plant changes that do not come under the EDCR l
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process are not required to be reviewed by YAEC; therefore, no formal reviews of these electrical load changes 'are required. The. Team was informed that an informal procedure existed between ~ the.
Maine Yankee electrical engineer and the YAEC -
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Electrical engineer to identify these electrical'
load changes. The Team concluded that 'a111elec-trical load changes should be formally tracked.
3.2.4.5 Alarm Coordination The Team concluded two instances of minor dis-crepancies in the alarm response procedures.
(a) The de low voltage alarms at 120 volts
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according to Alarm Response Procedure A0P-
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2-36, pages 17 and 26. However, the elec-trical training document PGS-18, Chapter 33 states on pages '116 and 129 that the low de voltage alarms at 115 volts.
(b) The Stone and Webster 4000-volt motor pro-tective device setpoint guidance. explicitly identifies the need to manually shut' down the component cooling pumps on motor over-load as soon as possible.
However, the alarm response procedures that address 4000-volt motor overloads fail to identify any specific action, applicable to the component cooling pump motors, nor do they indicate any special concern with ovarloads on these motors.
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3.2.5 Vague Technical. Specifications The Team's review of the electrical systems revealed a potential problem of electrical system lineups which could substantially reduce the reliability of Maine Yankee's
electrical power distribution.
3.2.5.1 Neither DC Bus 1 or Bus 3 Operable Technical Specification 3.12 requires only one of the two major dc buses (Bus 1 or Bus 3) be oper-able for plant operation above 210 F/400 psig.
By corollary, whea the plant is below the 210 F or 400 psig threshold, neither battery would be required.
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The safety evaluation associated with EDCR 86-02 stated in part, "In accordance with TS 3.0(B),
(C), 3.6 and 3.12(B), when below 210/400 neither battery 1 or 3 is required...."
The Team believes that, in this condition, any number of single failures could result in loss of the ability to maintain reactor residual heat i
removal.
3.2.5.2 Potential to Operate with a DC Bus Tie Closed Normally open bus ties are provided between safety-related de buses 1 and 3 and also between de buses 2 and 4.
Abnormal Operating Procedure A0P 2-13 directs the operator to close these bus ties upon loss of its redundant dc bus.
When these ties are closed, the operation of both redundant diesel generators and both redundant connections to offsite power depends upon the f
availability of a single battery. This condition should be restricted by plant Technical Specifi-cations or other suitable administrative controls such that the plant is constrained by a Limiting Condition of Operation.
3.3 Instrumentation and Control System Design The Team reviewed the licensee's instrumentation and control design as it is being used to reconstitute the Maine Yankee design basis through the creation of loop diagrams and setpoint calculations, as well as its use in the calibration program and for the detection of poorly performing instruments.
Design modifications were evaluated to see how the design basis was being preserved, or how well it was analyzed if changed. The Team performed a functional review of CCW which included an evaluation of engineering calculations, procedures, procedural data sheet records, schematic diagrams, safety evalua-tions, unusual operating reports, a field walkdown to verify equip-ment installation, and a comparison of the above to system opera-bility and performance requirements.
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The Team reviewed the proposed setpoint methodology and sample calcu-lations as to how this methodology would be applied to the CCW sys-
. tem.
Calibration procedures, historical records for CCW instruments, component cooling water, and instrument loop accuracy uncertainties applied to Regulatory Guide 1.97 post-accident instrumentation were assessed. ' The. practicality of alarm response procedures, whether responses to relevant industry problems were correctly applied _to the CCW system, and the process used to change the system design valve also reviewed, with focus on the adequacy of proposed methodology, accuracy of design data, and the validity of the design assumptions used in the calculations.
The Team identified design inadequacies for the instrumentation and control system, and inadequate documentation to support the design.
The findings are discussed in the following Sections.
3.3.1 Substantiation and Documentation of Setpoints The Team reviewed system descriptions, procedures, adminis-trative operating procedures, and chemistry surveillance procedures in an effort to discover how setpoints were generated and controlled.
The Team discovered conflicting setpoint values.
This was attributed to the fact that there were no controlling documents, such as a formal set-point index, or any calculations or analysis of instrument variables.
Yankee Atomic (YAEC) produced several examples of calcula-tions illustrating the methodology for CCW. The examples were a serious effort to provide the total loop accuracy under the various conditions of operations the instruments would experience, and to present this information as the degree of uncertainty that would be evidenced at the main control board. However, the Team expressed concerns about:
the way certain variables were handled; the error effect from input to output; determination of dependent or inde-pendent variables; the data base for analyzing the distri-bution of sampled variables; the determination of the level of confidence used; and, the method of calibrating a ' loop.
Instrumentation information available and presented to operators should be in the Team's estimation, conservative but realistic; otherwise, the information becomes of ques-tionable value to the operator and generates a general dis-trust of the instrument.
The licensee has committed to
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produce a setpoint basis document and plans to complete the document by the end of the year.
YAEC personnel are re-reviewing the setpoint generation program, and analyzed setpoints are expected to be available for the Maine Yankee 1990 refue. ling outage.
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3.3.2 Loop Calibration Technique-The Team reviewed loop _ calibration verification testing procedures.
The licensee currently calibrates a: loop by calibrating the components-serially.
The procedure involves: putting a known calibrated input into the sensor input port; measuring the ' output at the output port; cali-
.brating the sensor to ' an-acceptable output value; and, using that value as the input to the next component in the loop.
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The above method:
introduces greater calibration errors; J
does not test the component interfaces (i.e.,
cables, seals, terminal blocks, miswiring) nor the impact on adja-cent channels (RFI/ EMF); and does not. allow for compensa-ting cyclical deviations. Calibration verification testing is typically done on a complete loop, or at least in an overlap fashion, to assure the inclusion of all potential failure mechanisms.
The licensee intends to modify the calibration procedures to incorporate an overlap calibra-tion technique by the 1990 refueling outage.
3.3.3 Formal Review of As-Found Calibration Discrepancies A review of the preventive maintenance calibration records revealed that, despite obtaining as-found calibration read-ings that were beyond the instruments' acceptability cri-teria, several safety-related instruments were recalibrates and returned to service without further corrective actions.
The licensee failed to address the root cause for these higher than acceptable deviations.
Evaluation of the his-tory of certain of the ont-of-calibration instruments-revealed that deviations had occurred several times before, and some instruments were even in service beyond the acceptability criteria. The licensee does not have a for-mal program to historically check past performance, trend, increase calibration frequency, or do a root cause analysis for PM activities.
The licensee intends to add a formal review of as-found conditions during the current cycle.
3.3.4 Containment Pressure Instrumentation u
Regulatory Guide 1.97 requires that containment pressure instrumentation provide verification that safety functions are working to maintain reactor coolant system and contain-ment integrity.
For Maine Yankee, this would require a range of -5 to 55 psig with the area of concern at 5 psig and 20 psig.
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Regulatory Guide 1.97 also requires indication of potential breaching or. actual. breaching of barriers to fission pro-duct releases.
For Maine Yankee with a concrete contain-ment pressure boundary, the. instrument would require a
. range. of -5 to 165 psig with the area of concern at the
'high end of the range.
Regulatory Guide 1.97 further requires ~ that the. instruments
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should have sufficient range to. keep the indication on scale at all times and that the sensitivity and accuracy of the instrument be within acceptable. limits for monitoring -
the extended range.
Separate instruments should be used where there is a -loss of. instrument accuracy and sensitiv-ity :in.' the operating range required to indicate and verify the system functions during and following the accident.
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Yankee Atomic calculation MYC 948 suggests that the present main control board indicator could be inaccurate by as mu as 8.11 psi under normal operating conditions and by as much as 11.37 psi under LOCA conditions.
Containment pressure transmitter PT0212, with a range of 0 to 200 psia, is used to indicate and verify the system functions (trend--
ing and actual initiation) in. the bottom 2 1/2% of its range, where the possible error is greater than its signif-icant reading.
This instrument also supplies actual
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breaching information at approximately 165 psig.
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The use of a single instrument with an extended range con-
tributes, in large part, to the unacceptable loss of sensi-l tivity and accuracy where the instrument is most needed.
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3.3.5 Coordination Between Alarm and Trip Settings for Low SCCW Pressure
. Pressure switch 1706 provides an alarm at 80 psig when the SCC water accumulator TK110 reaches low pressure.
The 80
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psig (according to the information available) is required I
to operate both SCC water 16-inch trip. valves (SCC-A-460/
461) should the plant air system fail. The valves are nor-
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mally open, air-to-shut and fail open on loss of power or
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I air.
The valves will automatically trip shut if the suc-tion pressure of the SCC. pumps drops to 5 psig for 3 seconds. The tripping of the valves will provide isolation of the SCC non-safeguard loads from the safeguard loads.
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The. accumulator has to provide enough air to cycle err.h
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valve one time and hold each valve closed for 24 ho t. c s.
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A failure to' remain isolated would place the ' safeguard loads on CCW in jeopardy. Providing an alarm and-a trip at
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the same value does not allow sufficient time for operator response to rectify the situation.
The.. licensee committed-to raise the alarm setpoint to 85 psig and was continuting to evaluate the isolation of non-essential CCW loads (see Section 3.1.3) at,the end of this inspection.
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'3.3.6 Generic Industry MOV Problems'
Several CCW motor operated valves (all installed using a two-rotor limit switch design) have encountered problems due to setting the torque and limit switches, maintaining settings and design limitations of the control circuit.
Motor-operated valves use limit switches for control and position indication purposes. A limit switch assembly con-tains multiple electrical contacts grouped on rotors. The rotors are gear driven by the motor operator and are set so that the contacts will operate at a desired point in the valve's cycle. Rotor settings are adjustable, and all' the contacts on a rotor will either open or close at the estab-lished setting.
Therefore, the options available for set-tings at various points in the valve's cycle 'are dependent upon the number of rotors in the limit switch assembly.
Generic design problems reported by the NRC and industry were:
(a) remote position indication in which existing limit switch settings can result in a closed indication while the valve is actually partially open; (b) the torque switch bypass is not effective. while the disk is still on the valve seat; and, (c) the torque switch set too low for operation with the high differential pressure that might be encountered during valve operation for both normal and abnormal events within the design basis.
Four motor operated valves used on the CCW systems (PCC-M-
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43, PCC-M-90, PCC-M-150 and SCC-M-165) are required to operate with the recirculation actuation signal to provide cooling during the design basis event, and PCC-M-219 is required to operate with the containment isolation signal to isolate non-safeguard loads, i
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Maine Yankee Index No.
101-88, Operations Department
. Unusual Occurrence Report, dated October 31, 1988, stated
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that the PCC-M-43 valve did not tully stroke under pressure differential.
It was thought that the valve had either a limit switch problem or a torque switch problem. A pre-vious report index No.172-8'7 (VOR) dated December 1,1987, recorded a failure of PCC-M-43 (RHR HX cooling water) to.
reseat; the root cause was not determined, but the report states that after the~ valve was moved in the opposite direction (close), it was then able to respond normally to the open signal. The valve was retested but not under high differential pressure conditions.
Also, Index No. 106-87 (UOR) reported on July 2,1987, that valve SCC-M-165 (out-let isolation to E3B RHR HX) failed to cycle.
CCW system valves are all wired as two-rotor. limit switch designs and are required to either open or close in the tripped condition.
The two-rotor control circuit design introduces concerns about improper indication, valve leak tightness, and the ability of the valve ito change' its position.
The concerns about the above valves appear similar to those addressed by NRC Bulletin 85-03 which dis-cusses MOV common mode failures during plant transients due to improper switch settings. The licensee's responses have acknowledged the desirability of a four-rotor design over the two-rotor design as far back as 1985.
Valve PCC-M-219, purchased in 1982 with a four-rotor assem-bly, was installed using a two-rotor control circuit design despite evidence of industry problems and Maine Yankee problems with this control circuit design.
PCC-M-219 is required to shut.within 20 seconds so as to limit the maxi-mum water inventory loss to approximately 1000 gallons dur-ing a postulated high energy line break (HELB) that could occur in containment as a result of a LOCA.
Failure of
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this valve would impact the cooling ability of the PCC i
system.
This valve's reliability should not be in question
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due to either improper indication or ineffective torque
i switch or limit switch settings because of a poorly
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designed control circuit.
The licensee intends to change l
the control circuit to utilize the four-rotor design by 1991.
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3.3.7 St'ati on Radiation Monitoring System Design Modification During the last cycle of operation, the radiation monitor-ing system was placed out of service for an extended period of time. Significant work activities, including the change
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to different sensors and power.upplies, were accomplished-under the component replacement program.
The ' component
.i replacement program as defined in Procedure 17-201, Pro-cessing Repair Orders, was-used to change sensors and power supplies manufactured by different-vendors with different characteristics.
Several sensor lead ' shielding designs were a' -)
changed.
All. of the primary calibrations were
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redone, including new sensitivity values. This action was prompted. after several ' devices failed their surveillance tests and there was a genaral lack of confidence in the system.
The station radiation monitoring system at Maine Yankee consists of an area radiation monitoring system that warns persunnel of increasing radiation and radioactivity in plant areas', and gives early warning of possible plant mal-
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functi o n's.
The system consists of eleven active sensors
'1 and several provide automatic actions such as shutting'down fans and closing supply and exhaust dampers on high alarm signals.
The system also contains process radiation mon -
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itors that give early warning of plant malfunctions, warn personnel of increasing radiation which could result in a radiation health hazard, and record and control discharges of radioactive fluids into the environment.
The system consists of 15 active sensors and two of these automatic-ally close valves on high activity.
The basis for the radioactive liquid and gaseous effluent
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instrumentation, as described in Technical Specification - Section 3.28, is to monitor and control the releases of radioactive materials in liquid or gaseous effluents during releases.
.The alarm / trip setpoints for these instruments are to ensure that the alarm / trip will occur prior to exceeding the limits of 10 CFR Part 20; therefore, the Technical Specifications require assurance of the opera-l bility of the radioactive effluent monitoring systems to-perform their design functions.
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l If the'. above sensor,. power supply and other changes had bean performed under the EDCR program, the EDCR would have required a greater degree of up-front analysis, planning, and approval. including the impact 'on Technical Specifica-tion items and the. substitute measures taken to-meet Tech-
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. nical Specification.s intent.
Procedure 17-21-1, Permanent Plant Modifications, indicates that permanent plant design -
changes shall be documented by'an engineering design change
- request- (EDCR) and, as' such, shall. contain ' calculations, analysis, safety analysis, evaluation for unreviewed safety questions, functiona1 verification of the permanent plant design. change, and go-through a. multi-layered review process.
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4.0 OPERATIONS The Team conducted an in-depth operational assessment of the primary component cooling water (PCCW) and secondary component cooling water (SCCW) systems including:
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Review of operating parameters with respect to system design basis as described in the FSAR.
Review of the PCC and SCC material condition, outstanding maintenance
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deficiency reports (DR),
component labeling and general plant housekeeping.
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Review of operating procedures (0P), abnormal operating procedures (AOP) and emergency operating procedures (EOP).
Review of the operational impact of temporary modifications.
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Routine plant tours, attendance at morning meetings, and interviews
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with Operations Department personnel.
4.1 Facility Material Condition In order to assess the PCC and SCC system material condition, the inspectors performed several plant tours and system walkdowns.
The tours and walkdowns were conducted in the Plant Auxiliary Building and the Turbine Hall during normal operations at full power, and no major discrepancies were noted.
The physical equipment of the plant appears to be well maintained.
The licensee policy of assigning responsibility for the upkeep of a system to a specific operating crew has produced positive results.
All working areas were well lighted, and system components were readily accessible to plant operators. PCC and SCC system components and piping appeared to have been recently painted, and plant cleanli-ness was maintained at an adequate level. One noted exception was a small pool of chromate-treated water at the base of PCC pump 99 caused by a small, intermittent pump gland seal leak. This leak had been identified by the plant staff and documented by DR.
System or component DRs are initiated by the operating crew that dis-covers the problem, tracked by the plant Outage Department, and rectified by the Maintenance Department. The inspectors reviewed the current list of open plant DRs and found that there were no defici-encies in the PCC or SCC systems that required a high priority
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status, as described in the licensee DR prioritization procedure.
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During the review the Team concluded that an informal DR log was maintained in the - plant control room for operator reference.
Upon examination, however, the inspectors determined that the log was
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neith~er complete nor wholly accurate; deficiencies were, missing from the log and~ others entered incorrectly.
In discussing the ' matter with the Team, the licensee expressed a desire to retain this infor-mal log and agreed to update it from the Outage Department master DR list and implement procedures to maintain the log _ current.
While performing PCC and SCC system walkdowns, the inspectors verif-ied proper system valve lineup.
With the plant operating at full power, actual: PCC and SCC valve positions and system lineups were compared with Primary Operating Procedure 1-15-1, Atta:hment A, "PCC System Normal Valve Alignment" and Primary Operating Procedure 1-15-2, Attachment B, " SCC System Normal Valve Alignment." All nor-mally accessible portions of the two systems were inspected, and no
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deviation from the procedures was observed. The actual system line-ups duplicated the required lineup, and the PCC and SCC systems were aligned for all anticipated accident scenarios. The only discrepancy noted was the temporary modification implemented in emergency diesel generator cooling cross-tie between the fire main and PCC and SCC systems, which is described in further detail in Section 4.3.1 below.
An additional aspect of the system walkdowns conducted by the inspec-tors was an assessment of PCC and SCC system component labeling.
The inspectors compared actual component labeling to the requirements stipulated in licensee procedure 1-200-7, " System and Component Labeling." The painting and color coding of major system components appeared recently and properly accomplished.
The metal tagging of all system valves, however, minimally complied with the procedure.
All inspected valves were correctly identified when referenced to plant control drawings, but many of the metal tags were physically deformed, painted over or located in an awkward position and, thus, difficult to read.
While no instances of operator error have occurred as a result of valve identification problems, the licensee informed the inspectors that a new re-tagging program was being formulated.
4.2 Procedure Review 4.2.1 Normal Operating Procedures The Team reviewed Primary Operating Procedures OP 1-15-1,
" Primary Component Cooling System", Revision 20 and OP 1-15-2, " Secondary Component Cooling System", Revision 18.
The procedural format was consistent with plant procedure writing guidance.
The procedures referenced the l
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appropriate ' technical' specification requirements as well as
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FSAR-design basis specifications. The inspectors verified the validity of the procedures via independent and licensee accompanied walkdowns of accessible' portions of the PCC and SCC systems. -No discrepancies were identified.
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4.2.2 Abnormal Operating Procedures The Team reviewed the alarm response procedure A0P 2-36,
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"Panalarm Response".,- ' revision 16 with respect to the PCC and SCC systems.
The procedure individually identified ~
each annunciator alarm, the alarm safeguards categoriza-tion, the component setpoint-and alarm condition as well as initial and supplemental operator actions.
In general, the panalarm responses appropriately directed operator actions to mitigate the alarm condition.
However, the inspectors noted weaknesses in panalarm responses and subsequent ab-normal operating procedure -(AOP) ' direction with espect to the identification.and isolation of'a PCC or SCC high surge tank level alarm resultant from system in-leakage.
The PCC and SCC systems are designed such that, with the exception of the PCC and SCC heat exchangers, all interfac-
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ing system. leaks would result in in-leakage-to the PCC and SCC systems.
Therefore, increasing PCC or SCC: inventory from an interfacing system failure is an. operational scen -
ario for which procedural response is necessary.
The PCC and SCC surge tank high level panalarm response procedures failed to develop specific instruction to identify sources of system in-leakage.
Of particular concern was the PCC interface with the reactor coolant pump (RCP) seal water heat exchangers.
This interface presented a direct path for reactor coolant system (RCS) leakage at elevated tem-perature, pressure and radiation levels to the PCC. Alarm l
response procedures should provide instruction to promptly I
identify PCC system in-leakage from the RCP..
In responte to this concern, the licensee initiated an immediate temporary procedure change to the PCC surge tank high level panalarm response procedure providing appropri-ate instruction to expeditiously identify RCS in-leakage to the PCC.
New procedural direction included checks for elevated PCC radiation levels; performance of an RCS leak l
rate calculation and directed entry into the appropriate AOP to mitigate the alarm condition.
In conjunction with enhancements to the panalarm response procedure, A0P 2-25
"High Radiation Levels", was revised to include guidance to expedite the identification of RCS in-leakage to the PCC, following receipt of a PCC high radiation surge tank vent isolation.
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The licensee implemented ' prompt corrective actions -in f
response to this concern.
Procedural revisions enacted
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identifie'd probable initial indications of RCS in-leakage
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to the PCC. and provided appropriate operator actions to respond to the observed parameters effectively.
4.2.3 Emergency Operating Procedures i
The Team identified a service water (SW) system alignment which may adversely impact PCC and SCC system performance i
durin'g a design bases accident (DBA) scenario. The SW sys-tem is a two train system which supplies the heat sink for both component cooling water (CCW) systems.
However, the t
SW discharge header manual crosstie valve, SW-32, is nor-mally positioned open, defeating train separation by per-mitting direct process communication between trains.
Nor-mal plant operations with the 'W system crosstied increases unit reliability, in that a single SW train failure would not result in the loss of the associated CCW train and a plant trip, as would be the case if the SW trains were separated.
Refer to Figures 1 and 2 for system flow diagrams.
However, during a DBA scenario, a loss of coolant accident with concurrent loss of offsite power and subsequent fail-ure of an emergency diesel generator would be experienced.
In this limiting condition a single SW and CCW train would remain operable.
The operable SW train would continue to supply SW flow to both the operable and inoperable CCW trains through the open crosstie valve.
Therefore, the
operable CCW train heat exchangers would receive essen-tially only half of the SW system flow available.
The inspectors questioned the ability of a ' single SW train to reject half the system flow to the inoperable CCW train
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I heat exchangers while maintaining sufficient capacity to remove the design bases heat load from the remaining oper-able CCW train heat exchangers.
In response to this concern, the licensee determined that i
the SW system should be isolated from the inoperable CCW j
train during design bases accidents.
A procedural change
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was initiated to E0P E-0, " Emergency Shutdown From Power or Safety Injection," to require the isolation of the inoper-able CCW heat exchangers with only one SW train (pump)
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The licensee's immediate operational resolution 'of.- the SW crosstie concern - was appropriate.
However, final dispo-
'sition of this concern should include an engineering evalu-
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ation to.' determine the impact on design bases-a'nalysis of-operation with SW trains crosstied and SW flow through all CCW heat exchangers during a' DBA'. ' The~ inspectors had. no further' questions with respect to this issue.
4.3. Control of Temporary System Alterations The Team reviewed the implementation of temporary modifications which altered PCC or SCC system alignments or impacted normal or,erator actions.
4.3.1 Loss of PCC and SCC Separation
'In May of 1987 the licensee identified a design deficiency in the CCW systems, that upon a loss. of the instrument air system, would cause the PCC and SCC systems to be crosstied via the fire main system.
The crosstie between the CCW systems would occur at the emergency diesel generator (EDG)
alternate fire main cooling water header. Each EDG is nor-mally cooled by a separate CCW train but the alternate fire main cooling header is common to both CCW trains. Normally closed air operated valves, supplied by instrument air, maintain the fire main header isolated from the CCW trains.
However on a loss of instrument air the valves fail open effectively crosstieing the CCW trains.
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The licensee implemented a temporary system alteration that mechanically locked the' fire main discharge valves closed and locked the CCW EDG jacket water cooler discharge tem-perature control valves open.
The Team independently verified the proper field installa-tion of this alteration.
The PCC and SCC normal operation procedures detailed the alteration and identified the pro-
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per sequence to manually establish alternate fire main
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cooling to the affected EDG upon loss of a CCW train.
The panalarm response to an EDG hot engine alarm directed the-cperator to align the alternate fire main cooling in ac-cordance with the appropriate CCW normal operation proced-
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ure. However, the instruction contained in A0P 2-32, " Loss j
of SCC" and AOP 2-33, " Loss of PCC" failed to establish the I
alternate fire main flowpath to the affected EDG.
The l
licensee issued the appropriate AOP procedural changes following notification by the inspectors of the deficiency.
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The Team interviewed selected: operators and determined the operations staff was cognizant of the system alteration and could. properly establish' alternate cooling to the EDGs as necessary.
In addition, -the Team determined if system -
alterations had.been properly' incorporated into CCW lesson plans. Training with regard to this system alteration was determined-to be adequate. The Team concluded that the A0P-
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error was an isolated administrative error in an otherwise
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properly implemented temporary system alteration which, based on the diversity of procedural guidance,. would not have prevented proper alignment of the alternate cooling.
system for the EDGs.
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Isolation of Non-Safeguards SCC Loads 4.3.2
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The SCC system supplies safeguards as well as non-safe-g ua rd s ' l oads.
In order to prevent a. loss of SCC system inventory resulting from a pipe rupture of the non-seismic portion of the system, two air operated' butterfly valves, SCC 460 and SCC 461, were installed to isolate the non-safeguards portion of the system.
The valves isolate on low SCC pump suction pressure. The Team identified a con-cern with the ability of the associated instrument air receiver to maintain the valves closed as designed for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following a DBA.
The licensee could not immediately verify the design bases capacity of the air receiver and therefore implemented a temporary system alteration which positioned a supplemental air bottle supply by the re-ceiver..The bottle assembly was to remain in standby and was only to be aligned to the receiver via the accumulat
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vent valve to restore receiver pressure to between 120-1A psig.
During review of the field installation, the. Team noted that, contrary to operator instruction, the air bottle assembly was. connected to the receiver while in standby.
The Team brought this condition to the attention of the shift supervisor who immediately dispatched an auxiliary operator (AO) to properly restore the system. Direct oper-ation of SCC, with the air bottle assembly connected, was not impacted.
Following' interviews with various shift personnel, which revealed strong knowledge of the altera-tion order, the inspectors determined the system misalign-ment was the result of an isolated error by an A0 in the interpretation of the temporary alteration order.
However, additional guidance was provided to the oncoming operators during ensuing shift turnovers to ensure compliance with the direction of the temporary alteration.
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The Team concluded that Operational -Department personnel were cognizant of' temporary alterations _ affecting the CCW systems.- The temporary alterations reviewed were properly
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evaluated and implemented. Operators were well trained in the bases for the modifications and in the -compensatory actions required to restore, system design capabilities in the event that abnormal operating conditions were encoun-tered.
However, the minor deficiencies discussed above.
indicate that incre'ased licensee attention is appropriate to ensure comprehensive training and fully invasive'
analysis of system alterations is performed prior to implementation.
4.4 Management Operations Meetings The. Team attended several daily morning meetings.
The meetings detailed the previous day of operations, critical. plant parameters, upcoming activities and continuing plant issues.
All plant disci -
plines were represented.
The meetings were well directed and con-ducted ' at a brisk pace.
Discussions were concise and encouraged professional dialogue.
Issues were well developed and ownership responsibilities were clearly defined.
The quality of the _ meetings was impressive.
The meetings appeared to.be a very effective nan-agement tool in insuring general plant awareness and inter-depart-mental communications as well as promoting early identification and resolution of potential problems.
4.5 Conclusions J
Overall, the ' licensee demonstrated a strong orientation 'toward safe plant operation, with good management involvement and oversight. The Operations Department exhibited professional attitudes, and technical and operational competence with respect to CCW system operation.
Notwithstanding these conclusions, improved attention to the areas of component labelling and initial support of temporary modifications implementation are warranted to ensure continued strong operational performance.
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5.0 MAINTENANCE
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The Team reviewed maintenance attivities relating to components associated with the PCC and SCC systems. A review-was made of maintenance documenta-tion, including preventive maintenance (PM) and corrective maintenance:
(CM) procedures, maintenance history records, maintenance scheduling, dis-
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crepancy reports (DR). and repair orders (RO).
This review provided both
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general information - regarding the conduct of maintenance and specific j
information concerning component repair activities.
The Team also held
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discussions with your staff, performed walkdowns of the systems and wit-
nessed work being performed.
The Team findings are discussed in the following paragraphs.
f 5.1 Battery Replacements
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The Team reviewed the maintenance of the four recently installed i
station batteries, These new batteries contain lead calcium celi
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and are different than the lead antimony cells of the replaced bat-i teries. Batteries Nos. I and 3 were replaced in the spring of 1987 l
and batteries Nos. 2 and 4 were replaced at the end of 1988. Main-tenance of the new batteries was of particular interest to the team
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from the perspective of maintenance requirements due to the different
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cell material, j
(a) The Team determined that procedures for weekly pilot cell sur-veillance, bi-monthly surveillance of all cells, and the rated load discharge test, as required by the Technical Specification (TS) 4.5.B, were modified with procedure change report (PCR)
attachments to incorporate the new lead calcium cells.
The
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updating was considered satisfactory.
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(b) The Team found that the preventive maintenance requirements E-5-Q-D for batteries Nos. 2 and 4 did not include a quarterly torque check of the terminal connections.
From a review of the vendors manual, the team determined that batteries 2 and 4, a
different model than batteries 1 and 3, also requires torque checks of the terminals.
Further, the vendor manual cautions the user in bold print to perform quarterly terminal torque checks. In reviewing the matter further, it was noted that bat-teries 2 and 4 were installed as a component substitution and not as an Engineering Design Change which may have contributed to this omission.
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(c) The Team noted that the preventive maintenance schedule did not list the terminal torque check for batteries 2 and 4.
It was also noted that the scheduled preventive maintenance improperly listed the equalizing charge time as 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> for batteries 1 and 3, and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for batteries 2 and 4 instead of the pro-cedurally required 74-hours.
5.2 Corrective Maintenance 5.2.1 SCC Pump P-10B Repair
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During plant walkdowns, the Team noted that SSC pump P-108 had an axial shaft motion of approximately 3/16 inch. The licensee had also identified the excess shaft motion and a discrepancy tag was on the pump. A review of the mainten-a.nce history card for this pump revealed that a complete teardown and rebuilding of this pump had just been com-pleted in June 1988 under OR 33-88. The team requested and was provided information obtained from the vendor concern-ing the pump shaft motion.
On February 7, 1989, during another walkdown, the Team observed the current repair being made to the pump to elim-inate the shaf t motion.
This repair was being performed with a maintenance issued PCR to reassemble the pump end housing without a 0.010" gasket.
Further review by the Team determined that elimination of the gasket circumvented the technical intent of the repair procedure 5-9-5 and ven-dor requirements to maintain a small axial clearance of the outer shaft bearing race.
This action of circumventing technical intent is also not in accordance with procedure 0-62-2 for making procedure changes and points to a pos-sible void in engineering communicating important vendor requirements to the maintenance department.
5.2.2 PCC and SCC Partial Flow Filters The Team reviewed the maintenance history card record for the partial flow filters PCC-FL-67 and SCC-FL-68 that were installed in 1974.
The filters at initial installation were a 10 micron size that were quickly changed to 50 microns until 1987 and then changed back to the original 10
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micron size.
Change of the filters is performed when a i
defined maximum differential pressure across the filter is reached.
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In 1985, an analysis was~ performed to identify the contents of the filter sludge.
It. was a one time analysis that
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identified the' solids as predomir:ately. ferrous corrosion products.
Approximately 150 filter change-outs have been performed on each filter.since their installation.
Filter replacement was deemed effective.
5.3 Control Room Panel Wiring The. Team found several improperly terminated and unidentified leads in the back of the main control room panels. Specific discrepancies observed by the team were: Panel "A" had 4 leads hanging out approx-
imately 8 inches.
Panel
"B" has a pull tape hanging loose from the overhead and an old audible annunciator alarm wire hanging from the overhead.
At the rear wall, two wires of a Femco connection were cut and unidentified; and two wires marked spare ICS36 and 38 were hanging loose.
Panel "C" had one loose ils foot wire that was unmarked and improperly terminated. On -the back wall, two wires were improperly terminated; one was identified the other wasn't.
These inappropriate terminations were not in accordance with the Maine Yankee Wire and Cable Installation / Removal Standard MYSTD-ELEC-1.
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i The Team found a layer of dust in the back of the control room panels.
It was determined that a panel cleaning program doesn't exist and that the panels were cleaned in 1986 because of a mainten-ance identified dust problem.
The team further determined that the
" Low Voltage Electrical Distribution Closecut Plan" action items to develop and implement a control room panel cleaning program has not been done.
5.4 Valve Programs 5.4.1 Check Valve PM Inconsistency The Team determined there was an inconsistency in the PM Program between gland leakoff collection tank check valves PCC-72 and SCC-4. Valve PCC-72 is included in the program and has a PM action to disassemble, inspect and repair every 5 years. Valve SCC-4, a similar valve, does not have a PM requirement.
The licensee agreed to achieve consis-tency in the maintenance of these valves.
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4 5.4.2 Heat Exchanger Flow Temperature Control Valves During system walkdowns, 'the team noted the unusual ccnfig-uration of valves PCC-T-19 and 20, and SCC-T-23 and 24.
These were a two-valve arrangement with one actuator and positioner and a mechanical linkage to operate both valves;-
one valve opens as the other closes.
These valves were selected for maintenance review because of their unusual configuration and operational requirements.
A review of the entire maintenance history of each of the valves back to 1973 revealed no significant problems. Fur-ther observations of the installed valves were made and the team appraised the two valve single actuator arrangement as innovative, simple and effective.
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5.4.3 Review of Open Discrepancy Reports l
The Team reviewed the current open DR listing of work to be
performed on PCC and SCC components.
The list was rela-
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tively short but did contain several items of particular interest to the Team.
The first, concerned seat leakage of valves PCC-M-43 and SCC-M-165 that had been repaired in 1987.
From subsequent
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review of this repair, it was determined that internal l
parts may not have been available during the 1987 repair, and further work is scheduled for the 1990 outage. From a history review of these valves and discussions with main-tenance personnel, a chronic history of failures of reach rods and inability to obtain consistent motor torque read-ings during testing was noted.
This issue more appropri-ately related to design, and is discussed in Section 3.1 of this report.
The second item of interest related to DR's for safety and relief valves.
Further review determined that the plant has recently instituted a PM program for all plant safety and relief valves.
The Team determined that 4 PCC and 13 SCC relief valves were satisfactorily tested under this program during the 1988 outage.
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l 5.5 Conclusions i
i General housekeeping during and after mainten a activities was observed during plant walkdowns and while witnessing maintenance
being performed.
It was noted that work was performed in a neat i
manner and the work area was clean when the job was complete.
On jobs in process that could not be completed, the work areas were roped off, parts and equipment were clearly marked, and small attach-ment-bolting was carefully stored.
The Team's conclusion, even with the issues identified above, was I
that the material condition of the PCC and SCC system components was being effectively maintained. Maintenance personnel were found com-petent and responsive to each of the team findings.
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6.0 SURVEILLANCE TESTING
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During the inspection, the Team evaluated the licensee's surveillance test program, in-service testing (IST) program, post-maintenance functional testing, and other component reliability programs.
The Team reviewed these programs to ensure that the component cooling water system and interfacing -systems components were. being-properly tested and that test methodology and frequency is in compliance with the applicable version of -
the ASME Code Section XI for inservice testing. The general conclusion of-the Team was that the licensee's IST program is being effectively implemented.
The Team reviewed the licensee's current IST pump and valve program and I
held discussions concerning the program with cognizant IST personnel. It was determined that the Maine Yankee IST Program is a controlled document, and the applicable version of the ASME Code is the 1980 Edition as amended to the Winter of 1980.
6.1 Procedure Review During the course of the inspection, the Team reviewed surveillance and in-service test procedures, which reflected thorough administra-tive control of activities and good technical content.
Test proced-ures typically contain a discussion of the test objective, technical specification of ASME Code requirement to be satisfied, format of the test procedure including instructions for recording test data, and test precautions and prerequisites.
It was also evident that the
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I procedures reflected good human factors involvement.
They are clearly written, have adequate " white" space, and are easy to read.
l Eye focus is directed to framed caution statements and informational j
notes. The licensee's procedure preparation and format is considered l
a strength.
.The Team also noted that the IST hydraulic circuit lineup for ECCS pumps, containment spray pumps, diesel generator fuel oil pumps, ser-vice water pumps, and emergency and auxiliary feedwater pumps is stated in the procedures and lined up in the " Recirculation Normal Service Throttled" configuration for testing. This means that during
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I in-service testing, a pump is supplying rated flow throughout much of its associated system piping and components.
For example, the Team noted during the post-maintenance in-service test of SCCW pump P-10B on February 9, 1989, that the system was aligned to provide flow through its respective RHR heat exchanger.
This methodology
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establishes hydraulic conditions for testing which are as close as practical to those under which the system would be called on to per-form its safety function during an accident. This is considered good engineering practice.
No unacceptable conditions were identified within the scope of this
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review.
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6.2 Test Witnessing Members of the Team witnessed the following in-service and post-
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maintenance tests during the course of the inspection:
On January 24, 1989, quarterly in-service test of SCCW Pump
P-108 tested in accordance with Procedure No. 3.17.6.6, "In-Service Testing of Safeguards Pumps",
Revision 11, dated October 5, 1988.
On January 24, 1989, quarterly in-service test of Service Water
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Pumps P-29A, B, C, D tested in accordance with Procedure No.
3.17.6.6, "In-Service Testing of Safeguards Pumps," Revision 11, dated October 5, 1988.
It was noted that the test personnel performed competently and were familiar with procedures and how to implement them. A problem was encountered, however, with the utilization of the ultrasonic flow measuring equipment during the quarterly in-service test of service water pumps P-29B and P-29D on January 24, 1989.
A newly purchased flow instrument (Controlotron System 960 Wide Beam Ultrasonic Flow Meter) was utilized for the test.
Pump differential pressure for P-29B and P-290 was higher than usual due to high discharge pressure.
The high discharge pressure was a result of the pumps discharge but-terfly valves being throttled closed too much.
Pump motor current was lower than normal indicating lower than normal test flow.
All other test parameters were within normal limits.
It was concluded by the licensee that the pump discharge valves were throttled closed too much because the flow meter was giving an erroneous indication due to the flow transducers being mounted incorrectly.
These transducers are part of a new ultrasonic flow measuring system recently purchased by the licensee. This system which has a different mode of operation than the instrument it replaced (shear mode vs. wide beam operation)
requires placement of its transducers in a different arrangement.
The transducers were mounted correctly for pumps P-29A and P-29C but were required to be placed differently for pumps P-29B and P-290.
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This Lis. because the discharge butterfly valves for these pumps are mounted differently and therefore throttle differently.
The incor-rect placement of the' flow transducers for pump tests P-298~and P-29D influenced the flow readings.
At this point, _ the pump was still considered operable because the differential pressure was not in the required action range. The following day, the licensee ran the tests
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again with the transducers in the correct orientation.
All pump parameters were acceptable.
Pump vibration measurements were taken with a state of the art instrument (Palomar International Model 6100 Microlog) which measures displacement velocities.
The locations of measuring points were clearly defined by the procedure. In the case of the primary and secondary CCW pumps vibration measurement points were clearly marked on the pump casings.
The test personnel were i
thoroughly familiar with this piece of test equipment and its use.
The inspectors verified that the test instruments utilized met.the instrument accuracy requirements of ASME Code Section XI and were in current calibration.
The inspectors determined through a review of
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records that the licensee is meeti.ng surveillance frequency require-ments for in-service testing of pum'ps and valves in the program.
6.3-Administrative Control of Testing It was noted by the Team that the licenses is keeping good control-of recorded test results. Also, the licemee has made use of infor-mation gained from performance trending of pump parameters and engi-neering reviews of valve test results to initiate preventive mainten-ance for selected components.
The inspectors reviewed several examples of maintenance packages (Discrepancy Reports) where this has-taken place for valves. Other similar information was reviewed which documented preventive maintenance for pump bearings and shafts.
The Team verified the proper usage of baseline data (reference values) for hydraulic and mechanical parameters of pumps and valves in the IST program.
This is done in conformance with ASME Code Section XI requirements.
The Team discussed the requirements for determining valve stroke time degradation with the licensee.
It was noted that the licensee's maximum stroke times, where appropriate, were derived from actual valve performance plus a reasonable factor.
This is consistent with the NRC position that the.IST limit be derived from actual valve performance.
The Team verified that adequate controls were in place which ensure component testing upon completion of work performed under discrepancy reports, i.e., post-maintenance testing.
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6.4 Functional Testing
>The Team evaluated the post-maintenance functional testing of the PCC/ SCC System ' Monitoring Upgrade (EDCR No. '88-52) 'and the Service Water Heat Exchanger Replacement (EDCR No. 86-04).
In both of these cases, valid test methods were used_ and thorough analyses were performed.
The PCC/ SCC System Monitoring Upgrade was installed'and tested during the 1988. refueling ~ outage.
The reason for the upgrade was to met Regulatory Guide 1.97 requirements.to monitor component cooling water flow to ESF systems.
The design change provides the operator with the ability to monitor system supply' flow to the component cooling
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water heat exchangers in the PCC and SCC-systems.
Indication for each systems flow was added to the main control board. Additionally, instrumentation for bypass line flow around the heat exchangers was provided_for both-systems. Ultrasonic. flow meters were used in both systems.
This type of flow meter was selected so that no penetra-tions to the system piping would be required.
The functional test included continuity testing, functional loop check, and indicator accuracy and flow computer verification checks. Test evaluation and documentation was presented well.
The service water heat exchanger modification replaced SW heat ex-changers E-4A and E-58.
Functional testing proved the acceptability of both units based on the test critt *ia of "better than or equal to".
That is, the new units proved to provide better heat transfer, and lower service water side and component cooling water side press-ure drop than the old units. The inspectors noted that a thorough test evaluation of good quality was performed for this test also.
6.5 Reliability Program 6.5.1 Check Valve Reliability program In response to INPO SOER 86-3, " Check Valve Failures or Degradation," Maine Yankee committed to develop a compre-hensive check valve reliability program.
The inspectors discussed with the licensee, the ob!" tives of the program and details concerning its implemenn in.
The program objectives to provide predetermined plan on a priority basis, with the intent to reduce the potential for check valve failures that would have an adverse impact on Nuclear Safety, Station Availability, and Personnel Safety.
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The ' program will identify check valves that because of their _ design, materials of construction,- system operating parameters, location within the piping system, and history warrant additional attention to promote increased reliabil-ity. The inspectors reviewed materials which reflected an -
extensive effort thus far_in developing the program.
The development of this program reoresents a positive atti-tude and willingness ' of the licensee;dto engage resources in new areas which are geared towar improving nuclear safety.
6.5.2 Supplemental Equipment Reliability Program The ' Supplemental Equipment Reliability Program (SERP) is.
part of Maine Yankee's effort to produce maximum plant out-put by maintaining and improving the reliability of major vital plant equipment.
SERP provides a method to detect equipment degradation and initiate corrective action before a vital equipment failure occurs.
The intended result of this pr_ogram is to maximize total power production by min-imizing expensive equipment failures, plant outages, and load reductions.
The Team discussed with the licensee the above stated objectives and reviewed test records for two major ~ areas covered by SERP. These were accumulator check valve test-ing and emergency diesel generator testing.
While it is recognized that this program also represents added initia-tive by the licensee, it was evident from a review of the above records that it may need to be strengthened if sig-nificant improvements in equipment reliability are to be realized.
Recordkeeping for accumulator check valves was disorderly and, for both accumulator check valve and emerg-ency diesel generator testing under this program, little or no test results evaluation was performed.
The Team feels that this program is a worthwhile effort, but a revitaliza-tion of SERP may be warranted.
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'7.0 QUALITY ASSURANCE / TRAINING / MANAGEMENT 7.1 Station Modification and Configuration Control The' Team reviewed. station procedures which address system design'
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configuration control.
Of particular interest during this Safety
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System Functional Inspection were the management systems developed to I
insure that the varicus ' safety related functions of systems, struc-tures and components are maintained during the development and implementation of design changes.
Permanent plant modifications are directed through a Quality Assur-ance (QA) Plan implementing procedure (Procedure No. 0-03-1) and a series of Plant Engineering Department procedures.
Functional requirements for the control of design calculations, design verifica-tion, safety analysis, installation instructions and post modifica-tion functional testing are also stated in Plant Engineering Depart-ment procedures.
The Team' concluded that adequate controls are in place to manage the design change process and address various aspects important to main-taining control over safety related system configuration.
Likewise, temporary modifications are authorized through a procedure which seeks to maintain design control and conformance with 10 CFR 50.59.
During these reviews, the inspector noted the following:
The licensee has a program in place to recover safety system
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design basis summary documents.
A draf t report, covering the Reactor Containment Spray System was reviewed.
There is an obvious need for the information contained in that report to maintain a strong system design configuration control program -
and support the evaluation future modifications. The team views
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this as good initiative to organize valuable design documents.
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The licensee has committed to improvements needed to strengthen the management and procedural controls under which substitute replacement components are allowed. This is a concept used to
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assist the procurement effort for replacement parts used in l
maintenance and provides an engineering basis intended to insure that replacement parts which are not identical are at least equal to or better than the original.
The licensee indicated that they are examining the Electric Power Research Institute (EPRI) draft Guideline for Technical Evaluation of Replacement Items in Nuclear Generating Stations.
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The Plant Engineering Department procedure for preparing Safety
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Evaluations does not establish requirements for a standard con-tent and format for documentation of those evaluations.
There is no established procedure for plant engineering and
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other support groups to provide information to.the Nuclear
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Safety Engineering Group for their evaluation of deportability, i
root cause analysis and Human Performance' Evaluation System study.
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The Final Safety Analysis Report (FSAR) has not yet been updated to' reflect the installation of new Primary and Secondary Closed Cooling Water heat exchangers. The FSAR presently describes the
. material of the original heat exchangers. This was an apparent administrative over sight.
7.2 Component Substitutions Component substitution is process used to support the procurement effort for parts used in plant maintenance.
It is intended to pro-vide engineering assurance that items which are not identical are at
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least equal to or better than the original.
This is an important concern when faced with repairs involving obsolete or unavailable parts.
The Team found potentiel weaknesses within the procedural controls for these actions and also discovered several examples in which the licensee performed component substitutions for actions considered by inspection team members to be plant modifications.
The process for component substitution is implemented at the Maine Yankee Plant through an Engineering Department procedure (Procedure No.17-201).
Engineering support to maintenance and repair activ-ities, as well as to some (Design Grade 2) permanent plant modifica-tions is addressed through that procedure. It allows substitution of components equal to or better than original quality which may affect plant controlled drawings.
The Team member's concluded _ that this procedure does not adequately limit actions performed as component substitutions such that unauth-orized plant modifications are prevented.
Team members questioned allowing the replacement, as a component substitution, of station batteries and their seismic support racks from one type and manufac-turer to another when their electrical characteristics and number of cells differed.
lhe replacement of radiation detectors with a dif-ferent type requiring shielding changes was also questioned.
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In examining the 'present procedural requirements, the Team concluded that there was no established requirement for documented engineering evaluations to a standard appropriate to support the decision that the component substitution was ' valid.
Specifically, there was no requirement to document the need for the component substitution. The decisions as to the scope of the review and the need to implement the engineering 1 procedure for performing ' safety analysis (Procedure' No.
17-21-7). were di scretionary.
There was no requirement to establish the appropriate design basis and design margins; and, no requirement to document the effects of the change on any safety related compo-j nents, systems and structures. There did'not appear to be an ade-
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quate management review of the process.
The Team identified possible problems in the use of component sub-stitutions instead of the design change process for the replacement of station batteries (with their seismic support racks) and also with the replacement of radiation detectors.
In addition to questions regarding the analysis attempting to support these changes, Team members identified potential problems regarding installation testing and preventive maintenance actions (Sections 5 and 6).
It was the Team's opinion that the plant modification process, with its addi-tional controls, may have prevented these problems.
The licensee has committed to re-examine the process for component substitutions.
7.3 Design Basis Summary Program The licensee is implementing a program for developing design basis summary documents. Each is a summary of the design basis for a plant system which is to include source references for requirement and limitation.
The documents are intended to provide the background technical information which is needed to support 10 CFR 50.72 evalua-tions and process plant modifications.
The program will not develop new data; and is however limited to the identification of existing source documents.
A Nuclear Service Division procedure (Procedure No. MY-DBD-1) is in place to describe the program.
It establishes a thorough list of documents to be searched for pertinent design basis information, and recommend 3 document search strategies. Document format, as well as review and approval and revision requirements, are established by the procedure.
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Reports have been completed and issued for the Auxiliary Feed Water System.
Reports for High and Low Pressure Safety Injection Systems, Reactor Containment Spray and Control Room Ventilation have been com-
.pleted and were within the multi-discipline engineering review during the inspection period.
Service Water, Primary and Secondary Closed Cooling Water Systems, and the Instrument Air System are scheduled for review later this year.
The Team reviewed a draft copy of the Design Basis Summary Document for the Reactor Containment Spray System.
The format was clear and presented a compilation of valuable information.
The nine sections of the report addressed the following:
System Functional Capabilities - This section describes system
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components, controls and support requirements along with a description of normal and accident mitigation functions.
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External Events - A comprehensive section identifies applicable seismic and environmental qualifications, fire protection re-quirements imposed by 10 CFR 50, Appendix R.
Electrical separa-tion requirements and Class 1E electrical portions are to be identified.
It also describes requirements and studies pre-viously performed concerning high energy line break and jet impingement, flooding tornado, tornado and turbine missiles, single failure, radiation heavy loads.
Containment isolation and testing requirements are addressed as applicable.
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Historical Narratives of System Modifications and their Analysis.
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Synopsis of System and Component Testing - A description of tests performed to demonstrate the systems ability to meet its design basis.
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Piping System Seismic Analysis of Record - A reference listing.
System Set Point Summary - References to set point calculations
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and instrument accuracy calculations to provide a
safety analysis basis for each instrument set point.
Calculation Listing - Calculations other than seismic or those
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associated with modifications addressed elsewhere.
Component Summary of Design Conditions - Consolidated attributes
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required for each component.
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References - Both a reference list and copies of reference docu-ments previously not easy to retrieve.
The compilation of these documents appeared to the Team to be a valuable and noteworthy effort.
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7.4 - Engineering Safety Analyses and Deportability Procedures Safety Analyses which are written to support the completion of per-manent or temporary plant modifications, Discrepancy Reports, Repair Orders, and Material Purchase Requests are performed in accordance with Plant Engineering Department Procedure No.17-21-7. The proced-ure provides guidance as to the type of reference material to be reviewed in order to determine the design basis for the existing com-l ponent or system arrangement. It also provides a list of items from which the assigned engineer is to determine design inputs.
However, the procedure did not set a standard for the documented con-duct of the analysis.
Moreover, there were no requirements to:
(a) document the basis for the existing design, and to identify its failure modes; (b) documentation of the impact of the modification on
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either the system or component, its design basis and failure modes; (c) conduct these reviews in specific engineering disciplines; and, (d) management review and approval of the analyses.
Members of the licensee's Nuclear Safety Section are responsible for
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assisting the Plant Shift Superintendent in the determination of l
reportaSility under 10 CFR 50.72.
That Section also provides the evaluations needed for drafting Licensee Event Reports and is also responsible for recommending follow-up actions, providing root cause analysis and supporting the Institute of Nuclear Power Operations (INPO) Human Performance Evaluation System (HPES).
The Team members observed the actions taken by the plant staff in response to operational events, including the discovery of inspection cover plates missing from the A Emergency Diesel Generator documented in Unusual Occurrence Report 13-89. Although these events appeared to be addressed adequately, the Team was concerned with the overall time needed to evaluate an issue which involved the size and config-uration of the CCW isolation valve operator air accumulator. Although this evaluation was completed in a reasonably prompt manner once received by the Nuclear Safety Section, the technical description of the potential deportability issue was not' forwarded from the Plant Engineering Department within the time expected to support the requirements of 10 CFR 50.72 and 50.73.
The licensee is considering the establishment of a procedure for plant engineering and other sup-port groups to provide information to the Nuclear Safety Section for deportability evaluation.
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7.5 Quality Assuraneg The Team reviewed Quality Assurance Implementing procedures for Audits and Evaluations (Procedures No. 0-18-1 and 0-18-2) along with those concerned with the maintenance of the plant design basis and design changes.
The Team also reviewed _ reports of selected Quality Assurance. (QA) Audits, Evaluations, Quality Control (QC) Inspections and Nonconformances.
Selection was made to provide reports repre-
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'sentative of QA/QC coverage of maintenance, modifications, surveil-
lance and operations of the Primary and Secondary Closed Cooling Water Systems, the Service Water System and the interfacing _ elec-trical systems.
These reports concerned activities conducted within the past three years and generally reflected a good working' knowledge of the main-tenance, surveillance and installation process by the auditor. They contained well documented findings which -reflected detailed reviews.
There was an obvi_ous attempt to conduct performance-based audits.
.l The Team noted a single questionable comment within Audit Report MY-88-07 which detracted from otherwise good reports.
Within a review of EDCR 86-02, Replacement of the No. I and 3 Station Batter-
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ies, the auditor noted that, since the replacement was limited to an
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equal to or better than replacement, the work could have been per-formed under the Discrepancy Report / Repair Order (DR/RO) System.
This audit report did not reflect knowledge of regulatory require-ments for _the design change process beyond those of the plant procedures.
The licensee's use of a DR/R0 instead of the design change process for the replacement of the No. 2 and 4 Station Batteries has been questioned by the Team members and identified as a concern in Section 1.0.
7.6 Station Training and Simulator Configuration Control The Team examined the application of the Station Training program to
',arious aspects of the Pr : mary and Secondary Component Cooling Water Systems and their support and interfacing systems. This extended the review to training involving the Service Water System, the Emergency Diesel Generators and the Compressed Air Systems.
The reviews in-
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cluded Lesson Plans, Plant Simulator Exercise Guides and On the Job Training Exercise Guides used for qualification and requalification training of Senior and Licensed Operators, non-licensed operators and members of the Plant Engineering Department.
To support these re-views System Operating, Emergency Operating and Abnormal Operating Procedures and Training System Descriptions were reviewed.
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The Team verified that several broad areas of concern were addressed within the preplanned. training program.
These included operator response to off normal conditions such as loss of normal cooling water supply to the Emergency Diesel Generators and manual operation of Secondary Component Cooling Water non-safeguards piping isolation valves., Team members verified that operators were knowledgeable in-the training provided within these areas.
The Team found that technical training provided to Plant Engineering Department. personnel involved with Inservice Testing of Pumps and Valves did not include training-on the use of ultrasonic flow mon-itoring equipment. These devices are in use at the Main Yankee Plant for the performance of certain tests.
The Team took the position that personnel should be trained in use of these instruments prior to testing. This type of ultrasonic' equipment was also installed as a
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permanent plant modification to provide the post accident monitoring instruments for Component Cooling Water system flow required by NRC Regulatory Guide 1.98.
The Team members noted 'that technical train-ing is not provided to the Instrumentation and Control Technicians -
responsible for the equipment maintenance and surveillance.
The Team reviewed the management systems in place to maintain the configuration of the plant simulator representative of the actual
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plant design. These controls are implemented through Training Depart-ment Procedures. The Team also reviewed the computer. listing which track Plant Engineering Design Changes to Simulator Work Orders and also the listing of open Simulator Work Orders.
The Team concluded that the licensee was meeting their own administrative requirements for the identification of potential Simulator modifications and was tracking the status of these modifications.
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I 8.0 MANAGEMENT MEETINGS l
Regular meetings were held with both corporate and station management throughout the course of the inspection to clarify and discuss findings and concerns. An exit meeting was conducted on February 10, 1989. Attend-ance at the exit is listed below.
Preliminary findings,- assessment of
strengths and weaknesses, and conclusions were presented at the exit and
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are summarized in Section 1.0 of this report.
8.1 Principals Contacted R. Arsenault, Maine Yankee, Maintenance Supervisor F. Baxter, YAEC, Electrical Engineering G. Bradley, YAEC, Mechanical Engineer E. Boulette, Maine Yankee, Plant Manager R. Crosby, YAEC, Licensing J. Garrity, Maine Yankee, Vice President, Licensing and Engineering J. Hebert, Maine Yankee, Manager, Plant Engineering W. Hendries, YAEC, Lead Mechanical Engineer L. McCabe, Maine Yankee, Licensing Engineer, MY Team Coordinator G. Pilsbury, Maine Yankee, Assistant Manager, Technical Support R. Prouty, Maine Yankee, Maintenance Manager R. Radash, Maine Yankee, I&C, Group Head D. Soule, Maine Yankeee, Operations R. Turcotte, YAEC, Mechanical Engineer A. Wade, YAEC, Lead Engineer, I&C D. Wittier, Maine Yankee, Manager, Licensing & Nuclear Engineering D. Curtiss, Mechanical Maintenance Supervisor B. Higgins, I&C Supervisor G. Le'iovillier, Mechanical / Electrical Maintenance Section Head 5. Morrison, Electrical Maintenance Supervisor 8.2 SSFI Issues Summary A summary of issues identified during the course of the inspection was developed and maintained by the licensee, and referenced to by the Team as the SSFI progressed.
The listing was a useful and excellent initiative and formed a basis for clear prioritization and resolution of concerns, and agreement on preliminary commitments by the licensee.
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