IR 05000245/1986009
| ML20207C990 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 07/11/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207C986 | List: |
| References | |
| 50-245-86-09, 50-245-86-9, 50-336-86-09, 50-336-86-9, NUDOCS 8607210467 | |
| Download: ML20207C990 (12) | |
Text
,
_ _ _
_. _ _
.
.
U.S. NUCLEAR REGULATORY COMMISSION
~
REGION I
Report Nos:
50-245/86-09; 50-336/86-09
"~
Docket Nos:
50-245/50-336 License Nos.
Northeast Nuclear Energy Company Facility:
Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Units 1 & 2 Dates:
May 20, 1986 through July 7, 1986 Inspectors:
Theodore A. Rebelowski, Senior Resident Inspector Geoffrey E. Grant, Resident Inspector Approved By:
b
~7 /'I/ 9 (,
.
E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:
50-245/86-09; 50-336/86-09 (May 20 to July 7, 1986)
Areas Inspected:
This inspection included routine NRC resident inspection (309 hours0.00358 days <br />0.0858 hours <br />5.109127e-4 weeks <br />1.175745e-4 months <br />) of previously identified inspection items, plant operations, surveillance and maintenance, main turbine inspection, and static "0" ring differential pressure switches.
Results:
No unacceptable conditions were identified.
However, the Unit 2 operator
,
error in responding to faulty breaker indication and the accompanying plant trip
identified a need for operator attention to all available indications.
Also, bet-i ter assurance of indicator (lamp) operability should be considered.
i r
0607210467 060711
'
PDR ADOCK 00000245
-
G PDH i
'
.
- - - -
-
-
-
-
.
. - -
-
. - -
-
.
- -.
-
.
...
.
.
TABLE OF CONTENTS PAGE 1.
Summary of Facility Activities.......................................
2.
Previous Inspection Items............................................
3.
Emergency Diesel Generator Reliability...............................
4.
Observation of Surveillances (Units 1 & 2)...........................
5.
Unit 1 Reactor Scram.................................................
6.
Automatic Actuation of the Reactor Protection System.................
7.
Limitorque Motor Valve Operator Wiring Inspection....................
8.
Radiological Environmental Monitoring Program........................
9.
Standby Gas Treatment Automatic Initiation...........................
10.
Unit 2 Reactor Scram.................................................
.
11.
Differential Pressure Switches.......................................
12. Main Turbine Inspections.............................................
13.
Operational Checks...................................................
14.
Management Meetings..................................................
i
-
.
.
DETAILS 1.
Summary of Facility Activities Unit 1 operated at 100% power during this report period except for a planned shutdown on May 21-27 for turbine inspection.
Unit 2 operated at 100% power during the report period except for a planned shutdown on May 29 to June 1 for turbine inspection, and except for a trip from 15% power during a transfer between site input power transformers while starting up from the outage on June 1.
2.
Previous Identified Inspection Items 2.1 (Closed) Inspector Follow Item (50-245/85-13-01): Access control points.
The licensee has installed upgraded barriers at access control points.
The inspector has verified installation. Also noted was the licensee re-sponse that NRC comments on vehicle authorization has been reviewed and found consistent with site requirements.
2.2 (Closed) Inspector Follow Item (50-245/84-19-01): Lube oil supply to condensate booster pump bearings.
The lube oil pump control logic for all condensate booster pumps has been changed to allow the lube oil pumps to automatically restart when power is restored.
The logic change, im-plemented under PDCR 1-123-84, allows the "A" lube oil pump on the "A" and "B" condensate booster pumps to automatically restart upon restora-tion of power to MCC-C3 regardless of whether the "A" lube oil pump is selected as the lead or standby lube oil pump.
Inspector review of cir-cuit diagrams and modification testing found no inadequacies.
This item is closed.
3.
Emergency Diesel Generator Reliability Background The Emergency Diesel Generators (EDGs) provide an on-site source of power available if offsite power is lost to various plant safeguards systems.
Recent industry experience has shown that some EDGs are susceptible to de-
.
gradation under certain operating conditions.
The EDGs are Colt Industries, Fairbanks Morse Engine Division, diesel Model No. 3800TD8-1/8 using a turbo-charger and roots blower (in parallel with each other) scavenging air system.
The degradation occurs in tne roots clower after extended operation of the EDG uadei no-load or low load conditions.
In these EDGs, scavenging air for starting and light load operation is supplied to the cylinders by a positive displacement lobe type (roots) blower driven by a flexible drive from the upper crankshaft.
Under no-load or light load conditions, air is drawn in from the atmosphere, compressed by the roots blower, discharged through a pipe to the inlet air chamber beneath the inlet air check valve, and forced through the turbocharger impellers into the diesel.
If the engine load is great
.
_
_
_ _-
_
_
.
!
-
enough, the exhaust gas driven turbocharger further compresses the 3cee:ging
air.
As engine load increases, the increased exhaust speeds up the turbo-charger and creates a suction at its air inlet.
As this suction increases, it unbalances the inlet air check valve, causing it to gradually open and permit atmospheric air flow directly to the turbocharger inlet. As this occurs, the roots blower becomes unloaded because there is little discharge pressure.
Thus, under no-load or light load conditions, the roots blower experiences its largest pressure differential and sees its heaviest duty.
The degradations or failures of these roots blowers have generally followed extended periods of no-load / light load operations. Under these conditions, it is postulated that, due to the blower's heavy duty, it experientes thermal deformation causing accelerated internal wear or (under extreme conditions)
failure due to the close internal tolerances.
Vendor recommended measures to prevent blower failures include avoidance of no-load / light load operation
,
coupled with a preventive maintenance and inspection program.
The resident inspectors investigated the applicability of this problem to Millstone 1 & 2 EDGs and the extent to which the licensee has implemented the vendor's recommendations. The findings, by unit, are discussed below:
Unit 1 The EDG at Unit 1 is the model and type that is susceptible to blower related problems.
The Unit 1 EDG maintenance program includes the vendor recommended actions and inspections.
Unit 1 Operating Procedure (0P) 338 " Standby Diesel Generator" has recently been revised to specify that no-load operation should be held to a minimum with a maximum limit of five minutes.
Due to a lack of I
clear vendor guidance concerning the definition of what constitutes a " lightly loaded" EDG, currently no operational limitations exist to minimize the amount of time the diesel is run in this condition.
The licensee is pursuing reso-lution of this matter.
Unit 1 currently has a spare roots blower under re-furbishment at the vendor.
The refurbishment will include opening of internal clearances on the blower in order to make it less susceptible to this failure mode.
Unit 1 has installed a switch in the control room that allows the operator to bypass the Loss of Coolant Accident (LOCA) EDG start signal.
Normally, upon receipt of a LOCA actuation signal, the EDG will start and run unloaded in anticipation of a Loss of Normal Power (LNP).
Leaving the EDG running un-loaded for extended periods under these conditions was determined to be un-desirable.
The licensee installed a LOCA EDG start bypass switch giving the operator the ability to shutdown the EDG under these conditions.
Actuation of this switch and shutdown of the EDG does not inhibit the normal EDG re-sponse to a subsequent LNP signal.
Unit 2 The "A" EDG at Unit 2 is the model and type that is susceptible to blower related problems.
Although it is the same model, the "B" EDG has a different turbocharger-roots blower scavenging air system.
The Unit 2 EDG maintenance
__ _
a
.
-
program includes the vendor recommended actions and inspections.
Unit 2 OP 2346A, " Emergency Diesel Generator" is currently under revision.
As it exists now, OP 2346A contains general guidelines that tend to limit no load / low load operation of the EDGs. The intended revision will contain more explicit word-ing and will place definite limits on EDG operation in order to prevent blower related problems.
The revision is currently pending licensee review of how to address operation of the EDGs under conditions where a Safety Injection Actuation Signal (LOCA type signal) occurs without a concurrent LNP signal.
Similar to Unit 1, under these conditions the EDGs would start and remain running unloaded.
UnliLe Unit 1, Unit 2 does not have a LOCA EDG start bypass switch.
The resident inspectors are continuing to review the licensee's efforts to resolve remaining EDG operation cuestions and refine EDG operating procedures.
4.
Observation of Surveillances (Units 1 & 2)
a.
Unit 1 Low Pressure Coolant Injection (LPCI) System Operability Test i
On June 17, 1986 the inspector observed the conduct of SP 622.7, LPCI System Operability Test, from both the control room and equipment loca-tions (Reactor Building).
The surveillance included inservice inspection (ISI) data gathering for LPCI pumps.
The LPCI "A" Train pump operability test (pumps A & C) was obsersed from the control room.
The LPCI "B" Train pump operability test was observed from the Reactor Building corner room.
LPCI and Core Spray (CS) valve operability testing was observed from the control room, the motor control cabinets, and the valve loca-tions.
This surveillance operates pumps, determines flow rates, and exercises critical motor-operated valves.
Special inspector attention was given to review of the surveillance procedure for technical specifi-cation conformance, adherence to administrative controls, observation of the test, and review of completed test documentation.
Discussions with licensee personnel conducting the surveillance found adequate pre-paration and a high level of knowledge pertinent to the surveillance.
This was especially true of the control room operators.
During the conduct of the test it was noted that the Minimum Flow Bypass Valve for the "B" Train LPCI was modulating while the "D" LPCI pump was being tested.
The valve should have automatically shut and remained shut while the "D" LPCI pump test flow exceeded the system low flow setpoint.
The valve control flow switch was subsequently adjusted.
The inspector noted that the surveillance procedure does not call for recording the automatic response of the Minimum Flow Bypass Valve to various flow conditions but only for its response to remote manual (control room) open and close signals.
The licensee is researching this point.
The inspector will follow-up on this consideration during routine inspection.
No inade-quacies were identified in the LPCI operability surveillance results.
l
-
-
.
._-
_
.
~
Core Spray (CS) System Operability On June 17, 1986 the resident inspector observed the conduct of SP621.10, CS System Operability Test, from both the control room and equipment locations (Reactor Building).
The surveillance included ISI data gather-ing for the CS pumps.
This surveillance operates pumps, determines flow rates, and exercises critical system motor-operated valves. The inspector conducted an in-depth review of the surveillance similar to that con-ducted on the LPCI system test.
No deficiencies were identified.
b.
Unit 2 Turbine-Driven Auxiliary Feedwater Operability Test On June 20, 1986 the resident inspector observed the conduct of SP2610B, Turbine-Driven Auxiliary Feedwater Operability Test, from both the con-trol room and turbine locations.
Turbine pre-startup preparations, i
startup, and run-up to rated speed were observed at the turbine.
Turbine
'
operations and shutdown were observed from the control room.
This sur-veillance runs the turbine-driven auxiliary feedwater pump in a recircu-lation mode to verify satisfactory pump performance.
Particular inspec-tor attention was given to review of the surveillance procedure for technical specification conformance, adherence to administrative controls, observation of the test, and review of completed test documentation.
i Surveillance test personnel displayed adequate preparation and knowledge.
The control room operators exhibited an excellent grasp of system opera-tions and interrelationships.
No deficiencies were noted.
Quarterly ISI Testing of Main Steam System Valves On June 20, 1986 the resident inspector observed the conduct of SP21134, Quarterly ISI Testing of Main Steam System Valves.
This procedure tests the operability and performance of the Auxiliary Feedwater (AFW) turbine steam supply check valves, AFW turbine steam supply valves, AFW turbine speed control valve, Steam Generator (SG) blowdown sample control valve, containment outboard isolation valves, and the SG blowdown control valve containment outboard isolation valves.
Observations were made at the AFW turbine steam supply valve locations and in the control room.
The same level of inspector review was applied to this surveillance test as it was for the AFW Turbine Operability Test.
No deficiencies were noted.
Additional Surveillances observed were:
'Jnit 1 - SP408D, Discharge Volume High Water Level Scram - this surveil-lance functionally tests the Discharge Volume High Water Level switches and the Discharge High Water Level Bypass switch in-
,
cluding the high level scram switches, high level rod block switches, and the volume not drained alarm switches.
,
. _..
.
- Unit 2 - SP2610A, Motor Driven Auxiliary Feed Pumps and Regulator Valves Operability Test - this surveillance test runs the motor-driven auxiliary feedwater (AFW) pumps to verify satisfactory pump performance.
It also exercises the auxiliary feed control valves to verify valve operation performance.
Unit 2 - SP2601A, Borated Water Source and Flow Path Verification - this surveillance verifies the borated water sources and associated flow paths are operable and also test runs the boric acid pumps to verify satisfactory performance.
No deficiencies were identified during these tests.
5.
Unit 1 Reactor Scram A reactor trip was manually initiated from 10% power at 0214 May 21, 1986 due to rapid reactor pressure fluctuations.
The uait was in the process of down-powering for a planned shutdown to conduct a turbine inspection and perform miscellaneous repairs.
The planned repairs included refurbishment and ad-justment of the turbine control Mechanical Pressure Regulator (MPR).
The scheduled repair of the MPR was a result of its malfunction and subsequent reactor trip on February 5, 1986.
During that outage, the " Bean" (dampening)
valve, which dampens the regulator response, was adjusted.
Plans were made at that time to perform MPR modifications which have improved pressure stability at other BWR facilities.
The pressure control unit portion of the turbine control system is composed of two independent pressure regulators and the bypass valve opening jack.
One of the pressure regulators is of hydraulic-mechanical design and is de-signated the MPR.
The other regulator is of electro-hydraulic design and is designated the EPR.
Either regulator is capable of overriding the other.
The regulator which calls for the greatest combined opening of the control and bypass valves (corresponding to the lower set pressure) is the controlling regulator.
The MPR has a setpoint adjustment range of 150 to 1050 psig and is used during reactor startup to normal operating pressure.
The EPR has a setpoint adjustment range of 910 to 1010 psig and is normally the controlling pressure regulator when operating at or near normal pressure.
When the EPR is controlling, the MPR is in standby as a backup with its pressure setpoint adjusted above the EPR.
During pressure regulator controller transfer, both regulators momentarily control pressure as one gains control and the other has its pressure setpoint raised.
Effective and timely transition between regulators is necessary to minimize periods of dual regulator control.
On May 21, 1986, while at approximately 10% power and 990 psig, the MPR pres-sure setpoint was lowered until both the EPR and MPR control lights were lighted.
The EPR pressure setpoint was immediately raised to minimize transi-tion time.
The transition was smooth and the EPR setpoint was raised to 1010 psig.
Reactor power was decreased by control rod insertion.
The tendency for reactor pressure to decrease along with power should have been compensated for by MPR operation which shuts the bypass valves and/or control valves to
,
.
-
maintain the set pressure of 990 psig.
The MPR failed to function correctly.
Pressure dropped to 970 psig, at which point there was an unexplained increase to 1010 psig (probably a control system overshoot generated by the large con-trol error).
At this point the EPR began to share pressure control with the MPR as evidenced by both control indicating lights being lit.
Pressure dropped briefly and then increased rapidly to 1047 psig at which point the reactor was manually scrammed.
MPR repairs included replacement and modification of the rate stop adjustment screws to allow finer adjustment, and dismantling and cleaning of the " Bean" valve.
The " Bean" valve is believed to be the major contributor to the event.
The MPR was subsequently satisfactorily tested over its entire operating range.
The inspector had no further questions on this item.
6.
Automatic Actuation of the Unit 1 Reactor Protection System On May 24, 1986 while shutdown to conduct a turbine inspection, an automatic actuation of the Unit 1 Reactor Protection System (RPS) occurred while one
of the Source Range Monitors (SRMs) was being withdrawn.
As SRM 21 was being withdrawn, a noise spike was generated on Intermediate Range Monitors (IRMs)
12 and 16 causing trips of both A & B RPS channels on IRM Hi-Hi signals.
The licensee believed the noise spike was due to chattering SRM drive relays.
Subsequent attempts could not duplicate the conditions or IRM response.
The licensee committed to replacing the SRM drive relays during the scheduled 1987 refuel outage.
The resident inspectors will monitor licensee corrective ac-tions during routine inspection.
7.
Limitorque Motor-0perator Wiring Inspection In January 1986, IE Notice 86-03 notified the industry of potential generic deficiencies in environmental qualification of Limitorque motor-operated valve wiring.
The problems stem from the use of unqualified wiring inside the ac-tuators.
Unqualified wiring found inside the actuators was probably the re-sult of additions or modifications made to the actuators subsequent to ship-ment from Limitorque.
In response to IE Notice 86-03 and as part of the 10 CFR 50.49 environmental qualification program, the licensee visually inspected Unit 2 Limitorque motor-operators during the May 21-27, 1986 outage.
Due to continuous Unit 2 operation, this was the first opportunity the licensee had to make these inspections since the problem was identified.
The licensee developed an extensive procedural inspection checklist and ac-companying guide for use in conducting its environmental qualification program valve operator inspections.
Areas covered by the checklist and guide included:
--
Actuator nameplate data
--
Motor nameplate data
--
Limit switch type and condition
__ _ _____
.
--
Intermittent gearbox type and condition
--
Torque switch type and condition
--
Grease relief valve and T-drain presence
--
Electrical connection types and crimp conditions
--
Gasket condition
--
Lubricant type
--
Electrical wire and cable type The licensee inspected five valves out of the forty-two on their Master List of Limitorque Actuators.
The resident inspector accompanied the licensee on the inspection of 2-MS-201 (Steam Supply to Turbine Driven AFW Pump).
He found the licensee inspector to be knowledgeable of the required procedures and of the internal arrangements of Limitorque actuators.
No deficiencies were identified during this inspection, but minor problems were found in three of the other four valve actuators.
In one, a slight nick on the insulation of one of the field control cables was repaired.
In the second, one of the field control cables was relugged.
In the third, an electrical connection was wrapped with tape that could not positively be identified as qualified material. The connection was subsequently remade using qualified tape.
The resident inspectors will monitor future licensee inspections, scheduled for the next refueling outage, during routine inspections.
8.
Radiological Environmental Monitoring Program The inspector reviewed the licensee's Radiological Environmental Monitoring Program annual report for 1985.
This report summarizes the results of the sampling and analyses of environmental media to determine the radiological impact of station operations.
These environmental media include air, water, vegetation, and aquatic plants and animals.
In addition, direct radiation is moriitored by placement of thermoluminescent dosimeters at various locations around the station.
The inspector concluded that the licensee has generally complied with its Technical Specification requirements for sampling frequencies, types of measurements, analytical sensitivities, and reporting schedules.
Exceptions to the sampling and analysis program were explained, e.g., low air sample volume due to power failure.
The report included summaries of the laboratory quality assurance program and of the land use survey.
The analyses of environmental samples indicated that doses to humans from radionuclides of station origin were negligible.
9.
Unit 1 Standby Gas Treatment (SBGT) Automatic Initiation On May 31, 1986 at 1520 the Unit 1 steam tunnel ventilation radiation monitor tripped upscale, causing the steam tunnel and Reactor Building ventilation to isolate and the Standby Gas Treatment (SBGT) system to automatically in-
itiate.
At the time, the plant was operating at 100% powe.
o The Steam Tunnel Ventilation Monitoring system is designed to indicate abnor-mal radioactivity in the Steam Tunnel Exhaust Plenum, to initiate isolation of both the Reactor Building and Steam Tunnel Ventilation Systems, and to start the SBGT System. Two gamma sensitive instrument channels monitor the radiation levels in the steam tunnel exhaust ventilation.
Either channel reaching the trip setpoint causes the automatic action described above.
Technical Specification 3.2.E.3 requires the Steam Tunnel Ventilation radi-ation monitor trip setpoint to be less than or equal to 12 mR/hr.
Plant procedures conservatively set the trip setpoint at 11 (+/- 1) mR/hr.
Based upon local indication of normal radiation monitor levels of 9.5 and C.0 mR/hr, the SBGT system was secured and normal ventilation was restored.
Fur-ther investigation revealed that the
"A" channel steam tunnel ventilation radiation monitor had an out-of-adjustment potentiometer.
This misadjustment was a conservative one which caused the trip setpoint to be closer to the normal background radiation level.
The monitor was re-calibrated and the calibration procedure was revised to include a caution that the potentiometer is factory set and field adjustments are not to be made.
The inspector re-viewed the corrective actions and had no further questions.
10.
Unit 2 Reactor Trip A Unit 2 reactor trip was automatically initiated from 16% power at 1722 on June 1, due to Reactor Coolant Pump (RCP) underspeed. The RCP underspeed was caused by loss of electrical power to 6.9 KV Bus 25B, which supplies two of the four RCPs.
The loss of power was caused by a failure of the control room operator to effectively transfer bus supply power from the Reserve Station Service Transformer (RSST) to the Normal Station Service Transformer (NSST).
Normal transfer of power from the RSST to the NSST is accomplished by opera-tion of breaker control switch 2S2-258-2.
Placing this switch in the "close" position shuts the supply breaker from the NSST.
Releasing the switch and allowing it to snap back to the normal "after-close" position actuates con-tacts which initiate action to open the RSST breaker. This feature minimizes the time that Bus 25B is paralleled to two power sources.
Another feature that minimizes parallcl operation is an Agastat time delay relay which, if the RSST breaker has not opened, trips the NSST breaker 0.2 seconds after it closes.
During this power transfer, the operator placed breaker control switch 252-25B-2 in the close position.
The red "close" light failed to illuminate.
Other control panel indications showed that the NSST breaker had in fact I
closed, but the operator failed to observe these indications.
Believing that the NSST breaker was open, the operator slowly returned the control switch to the "after-close" position.
This action exceeded the 0.2 second time delay and the NSST breaker opened.
When the control switch reached the "after-close" position, the RSST breaker also opened, causing a loss of electrical power to Bus 25B.
If the operator had released the switch and allowed it to nor-mally spring return to the "after-close" position, an effective power transfer should have occurred.
l l
.
Upon loss of power to two RCPs, the Reactor Protection System initiated a reactor trip.
After the trip, the supply breaker from the RSST was reclosed in its normal shift sequence and power was restored to the RCPs. The control room operators performed Emergency Operating Procedure (EOP) 2525 (Standard Post Trip Actions) with satisfactory trip response.
11.
Differential Pressure Switches The inspector advised the licensee that certain differential pressure switches (DPSs), manufactured by Static "0" Ring (SOR), Incorporated, were of concern becau:,e a nuclear power plant had failed to scram due to failure of SOR DPSs to actuate on low water level.
NRC Information Notice IEN 86-47 was subse-quently issued on this subject.
Inspector follow-up found that the licensee had identified 45 DPSs in use or in stock at Unit 1 and 18 DPSs at Unit 2.
None of these were of the model and type identified as being of concern in IEN 86-47.
The inspector had no further questions on this item.
12. Main Turbine Inspections At a power plant outside the United States, a main turbine problem resulted in a trip from full power and in a fire in the generator exciter area.
In-spection found that the last stage turbine buckets had failed or cracked in the dovetail region.
The cause was assessed as high cycle fatigue.
Because the Millstone 1 and 2 turbines are similar, the turbine vendor recommended their inspection.
Units 1 and 2 were taken off-line separately for that in-spection on May 24 and May 29, respectively.
Ultrasonic testing found no defects in either unit's turbine.
Additionally, magnetic particle inspection of the turbine shafts identified no abnormalities.
The licensee is evaluating the need and schedule for the follow on torsional vibration i.esting recommended by the vendor.
NRC monitoring of such testing will be accomplished incident to routine inspection.
13.
Operational Checks Checks of both units were made to assess operational safety and conformance to NRC requirements.
This included daily and backshift checks of control room activities and shift turnovers, and discussions with personnel about items such as plant conditions and delivery of consumables (diesel fuel, oxygen, etc.).
Equipment conditions, radiological controls, fire hazards, and security were also addressed during facility tours.
At Unit 1, the checks included walk-down of part of the Standby Gas Treatement System and observation of emergency diesel operation at light load.
At Unit 2, the checks included observation of transformer line-up and the response to the reactor trip.
Licensee radiation survey information was consistent with readings taken by the inspector.
No unacceptable conditions were identified, but the following item was noted.
--
On June 10, the inspector observed a contractor worker receive a portal monitor alarm at the protected area exit boundary.
Health Physics survey found low level contamination on a small area of the worker's clothing.
,
f
.
l
That was removed.
The licensee traced the source to the refueling cask laydown area.
The worker was retrained in frisking requirements.
In-structions were posted at the exit portal monitors to clearly identify the actions to be taken when a monitor alarms.
The inspector had no further questions on this item.
14.
Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss findings.
No proprietary information was identi-fied as being in the inspection coverage.
No written material was provided to the licensee by the inspector.
-.