Causulty.txt

Card Set Information

Author:
pegwinn
ID:
60392
Filename:
Causulty.txt
Updated:
2011-01-17 21:15:35
Tags:
casualties operational procedures
Folders:

Description:
Plant Casualties
Show Answers:

Home > Flashcards > Print Preview

The flashcards below were created by user pegwinn on FreezingBlue Flashcards. What would you like to do?


  1. WHAT ARE THE FOUR GENERAL “THINGS TO DO” IN ALMOST ALL CASUALTIES?
    • 1. Put plant in safe condition: Immediate Actions
    • 2. Notify Supervisor get help on the way: Personal Call, or have Emergency Maintenance make the call while you are busy.
    • 3. Document: Update all logs with all the detailed information you have access to.
    • 4. Get the OP: Double Check your actions to be sure nothing was missed.
  2. HIGH BOILER WATER LEVEL HBWL SYMPTOMS:
    • 1. Water above +3” alarm
    • 2. Sudden decrease in automatic feedwater control signal
    • 3. Remote water level indicator or alarm indicates high water level
    • 4. Decrease in superheater outlet temperature
    • 5. Rumbling sound or vibration in steam piping
    • 6. Steam leak(s) at flanges, packing glands or turbine control devices
    • 7. Intermittent slowing down of turbine driven equipment. Unusual noise/vibration turbine (UNVT)
  3. HIGH BOILER WATER LEVEL HBWL IMMEDIATE ACTIONS:
    • 1. If level goes out of sight high, immediately trip the chiller, then the boiler
    • 2. Lower the water level by surface blow until water level is in sight.
    • 3. Check superheater drains for carryover
    • 4. Open drains on steam lines and headers
    • 5. Call supervisory personnel
    • 6. Perform thrust clearance checks on all affected turbines
    • 7. Insure all actions are logged in log book
    • CAUTION: DO NOT BOTTOM BLOW A STEAMING BOILER UNLESS DIRECTED TO.
  4. HIGH BOILER WATER LEVEL HBWL CAUSES:
    • 1. Loss of main feed control (LMFC)
    • 2. Inattention of personnel
  5. HIGH BOILER WATER LEVEL HBWL POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Water carryover into main steam lines, resulting in plant shutdown
    • 2. Loss of boiler
    • 3. Blown steam line gaskets, packing, seal rings, and valves
    • 4. Loss of the main feed pump resulting in loss of desuperheater temperature control
    • 5. Contamination of boiler superheater
    • 6. Turbine blade failure
  6. LOW BOILER WATER LEVEL LBWL SYMPTOMS:
    • 1. Sudden increase in automatic feedwater control signal
    • 2. Low water alarm sounds [-3”] or boiler trips off-line [-5”]
    • 3. Unusual drop in steam pressure
    • 4. Water level indication shows out of sight low or low water level
  7. LOW BOILER WATER LEVEL LBWL IMMEDIATE ACTIONS:
    • 1. Immediately trip the boiler
    • CAUTION: NEVER ATTEMPT TO RAISE THE BOILER WATER LEVEL BY FEEDING THE BOILER WITH FEEDWATER. SEVERE DAMAGE TO BOILER INTERNALS WILL RESULT.
    • 2. Lift the superheater vent valve until drum pressure is 200-300 psi below operating pressure. This will allow the water level to naturally rise and removes unwanted heat from superheater.
    • 3. Call supervisory personnel.
    • 4. Allow the boiler to cool to ambient.
    • 5. Prepare to place standby boiler online.
    • 6. Open and inspect the boiler for internal damage.
    • 7. Perform hydrostatic test on the boiler for tightness.
    • 8. Insure all actions are logged in the log book
  8. LOW BOILER WATER LEVEL LBWL CAUSES:
    • 1. Loss of main feed control (LMFC)
    • 2. Inattention of personnel
    • 3. Loss of the main feed pump
    • 4. Low water in the DFT
    • 5. Ruptured DFT or feedwater piping
  9. LOW BOILER WATER LEVEL LBWL POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Loss of boiler
    • ***** a. Distortion of heating surfaces
    • ***** b. Serious steam or water leaks
    • ***** c. Ruptured boiler tube
    • ***** d. Destruction of refractory
    • ***** e. Warping of boiler casing
    • 2. Loss of steam pressure
  10. RUPTURED BOILER GAUGE GLASS RBGG SYMPTOMS:
    • 1. Gauge glass cracks or disintegrates
    • 2. Steam escapes into plant
    • 3. Loud hissing noise
  11. RUPTURED BOILER GAUGE GLASS RBGG IMMEDIATE ACTIONS:
    • 1. Isolate the gauge glass by securing the top gauge glass cutout valve (via chain), then isolate the bottom gauge glass cutout valve. The bottom cutout valve has a ball check valve that prevents the spray of feedwater in the event the glass ruptures.
    • 2. Monitor the boiler water level from the remote water level indicators.
    • 3. If glass cannot be isolated or dangerous conditions exist, immediately trip the boiler off-line.
    • 4. Call supervisory personnel.
    • 5. Insure all actions are logged in log book.
  12. RUPTURED BOILER GAUGE GLASS RBGG CAUSES:
    • 1. Shock and/or vibration
    • 2. Improper installation
    • 3. Material fatigue
    • 4. Glass deterioration
  13. RUPTURED BOILER GAUGE GLASS RBGG POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Personal injury
    • 2. Loss of primary boiler water level indications
  14. RUPTURED BOILER TUBE RBT SYMPTOMS:
    • 1. Unusual drop in steam pressure
    • 2. Firebox filling with steam
    • 3. Steam emitting from the boiler stack
    • 4. Difficulty in maintaining boiler water level
    • 5. Excessive feedwater consumption
    • 6. Excessive chemical consumption
    • 7. Loud hissing noise and/or pop from the firebox
  15. RUPTURED BOILER TUBE RBT IMMEDIATE ACTIONS:
    • 1. Immediately trip the boiler off-line
    • 2. Lift boiler safety valves to 0 psi
    • 3. Continue to feed the boiler to maintain water level until boiler has cooled sufficiently, unless the ruptured tube was caused by a low water condition.
    • 4. Call supervisory personnel
    • 5. Insure all actions are logged in the log book
  16. RUPTURED BOILER TUBE RBT CAUSES: 1. Low water in the boiler [-5”]
    • 2. Excessive erosion of boiler tubes
    • 3. Fouled firesides/excessive erosion
    • 4. Fouled watersides
    • 5. Excessive rate or steam generation/over-firing
  17. RUPTURED BOILER TUBE RBT POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Personnel injuries
    • 2. Loss of steam pressure
    • 3. Loss of boiler
  18. HIGH SUPERHEATER TEMPERATURE HST SYMPTONS:
    • 1. Temperature gauge or controller indicates high superheater temperature @ 815°F.
    • 2. Low steam flow
  19. HIGH SUPERHEATER TEMPERATURE HST IMMEDIATE ACTIONS:
    • 1. Reduce the boiler firing rate/open superheater vents
    • 2. Lower air flow output on controller
    • 3. Ensure 02 analyzer is in “auto”
    • 4. If conditions worsen, trip the boiler
    • 5. Call supervisory personnel
    • 6. Insure all actions are logged in the log book.
  20. HIGH SUPERHEATER TEMPERATURE HST CAUSES:
    • 1. Excessive air
    • 2. Malfunction in automatic combustion controls
    • 3. Reduced steam flow through the superheater
    • 4. Sudden increase in boiler firing rate
    • 5. Superheater vents shut when raising steam pressure
    • 6. Low entering feedwater temperature.
    • 7. Dirty or scaled superheater steam sides
    • 8. Dirty superheater firesides
    • 9. 02 analyzer not in automatic control
  21. HIGH SUPERHEATER TEMPERATURE HST POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Ruptured boiler tube
    • 2. Superheater meltdown
    • 3. Material fatigue
  22. HIGH BOILER CONDUCTIVITY HBC SYMPTONS:
    • 1. Boiler uniloc indicates high conductivity
    • 2. Chemical analysis indicates high conductivity
    • 3. Boiler constantly surface blowing
    • 4. Excessive feedwater consumption
    • 5. Unstable chemical control
  23. HIGH BOILER CONDUCTIVITY HBC IMMEDIATE ACTIONS:
    • 1. Seek and isolate contamination source
    • 2. Surface blow boiler to lower conductivity
    • 3. Call supervisory personnel
    • 4. If conditions worsen, immediately secure the boiler
    • 5. Insure all actions are logged in the log book
  24. HIGH BOILER CONDUCTIVITY HBC CAUSES:
    • 1. Leaking heat exchanger (most likely source would surface condenser)
    • 2. Improperly aligned blowdown system
    • 3. Uniloc operating improperly
    • 4. Excessive chemical feeding of boiler
    • 5. High conductivity from campus
    • 6. Exhausted polisher
  25. HIGH BOILER CONDUCTIVITY HBC POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Corrosion of boiler watersides
    • 2. Boiler tube failure
  26. LOSS OF MAIN FEED CONTROL LMFC SYMPTOMS:
    • 1. Difficulty in feeding the boiler
    • 2. Unable to maintain proper boiler water level
    • 3. Low feedwater pressure alarm @ 625 psi
  27. LOSS OF MAIN FEED CONTROL LMFC IMMEDIATE ACTIONS:
    • 1. If water level is high: (OSH by sightglass) Trip chiller/trip boiler, trip all turbine-operated equipment
    • CAUTION: DO NOT BOTTOM BLOW A STEAMING BOILER UNLESS DIRECTED TO.
    • ***** a. Place feedwater control into manual; lower output signal to feedwater valve
    • ***** b. Surface blow steam drum to lower water level if needed
    • ***** c. If water level rises above +5” (#3 boiler) or +7” (#1, 2 boilers), trip the boiler
    • 2. If water level is low:
    • ***** a. Verify feedwater psi
    • ***** b. Place feedwater control into manual; raise output signal to feedwater valve
    • ***** c. Verify the feedwater station is properly aligned
    • ***** d. Verify the main feed pump throttle valve is open (throttling down on the recirculation valve will increase feed pressure)
    • ***** e. Ensure the main feed pump controller is in “auto”
    • ***** f. If water level drops below -5”, trip the boiler
    • 3. Call supervisory personnel
    • 4. Insure all actions are logged in the log book
  28. LOSS OF MAIN FEED CONTROL LMFC CAUSES:
    • 1. Failure of the automatic feedwater control components/valve
    • 2. Loss of control air supply
    • 3. Contamination of control air supply
    • 4. Loss of main feed pump
    • 5. Feedwater station valves misaligned
    • 6. Inattention of personnel
    • 7. Feedwater controller not in “Auto”
  29. LOSS OF MAIN FEED CONTROL LMFC POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Low water in the boiler
    • 2. High water in the boiler
    • 3. Loss of steam pressure
  30. LOSS OF CONTROL AIR LCA SYMPTOMS:
    • 1. Control air alarm sounds @ 80 psi (boiler control air trips at 60 psi)
    • 2. Loss of control on all air control valves
  31. LOSS OF CONTROL AIR IMMEDIATE ACTIONS:
    • 1. Verify air compressor is operational; restart or shift air compressors
    • 2. Verify system alignment
    • 3. If high steam temperature exists, verify desuperheater pump is operating properly.
    • 4. Call supervisory personnel
    • 5. Insure all actions are logged in the log book
  32. LOSS OF CONTROL AIR CAUSES:
    • 1. Air compressor failure
    • 2. Air line rupture
    • 3. Misalignment of system valves
    • 4. Loss of electrical power
  33. LOSS OF CONTROL AIR POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Loss of steam pressure to campus
    • 2. High steam temperature to campus
    • 3. Unable to maintain boiler water level
    • 4. If conditions worsen, secure steam flow to campus
    • 5. Call supervisory personnel
  34. HIGH DFT WATER LEVEL HDWL SYMPTOMS:
    • 1. Water level out of sight in gauge glass, or controller indicates high water @ 81”
    • 2. DFT rumbles loudly
    • 3. DFT shell pressure is low
    • 4. Water flowing from the DFT vent
  35. HIGH DFT WATER LEVEL IMMEDIATE ACTIONS:
    • 1. Stop the condensate transfer pump
    • 2. Manually lower DFT water level
    • 3. Ensure level controller is in automatic @ 70”
    • 4. Call supervisory personnel
    • 5. Insure all actions are logged in the log book
  36. HIGH DFT WATER LEVEL CAUSES:
    • 1. Failure of the automatic controls
    • 2. DFT level controller in manual
    • 3. Inattention of personnel
  37. HIGH DFT WATER LEVEL POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Improper deaeration of the feedwater
    • 2. Grounds in electrical motors and controllers due to water spillage
  38. LOW DFT WATER LEVEL LDWL SYMPTOMS:
    • 1. Main feed pump trips on overspeed due to feedwater flashing (Chacp 2)
    • 2. Low feedwater pressure alarm sounds @ 625 psi
    • 3. Water level out of sight in DFT gauge glass or controllers indicate low water @ 67”
    • 4. DFT shell pressure rises
  39. LOW DFT WATER LEVEL LDWL IMMEDIATE ACTIONS:
    • 1. Attempt to restore water level by introducing condensate slowly.
    • 2. If conditions worsen, or situation is unsafe, trip the boiler.
    • 3. Call supervisory personnel.
    • 4. Insure all actions are logged in the log book
    • CAUTION: SLOWLY INTRODUCE WATER TO THE DFT AFTER LOW WATER CONDITION. IF WATER ENTERS TOO RAPIDLY, A LOW PRESSURE (VACUUM) CONDITION OCCURS WHICH COULD CAUSE IMPLODING OF THE DFT SHELL.
  40. LOW DFT WATER LEVEL LDWL CAUSES:
    • 1. Make-up water misaligned to surge tank
    • 2. Failure of the condensate transfer pumps or line rupture
    • 3. Surge tank level low @ 35% or 25’ or ruptured
    • 4. DFT line or shell ruptured
    • 5. Failure of the automatic level controls
    • 6. DFT controller in manual
    • 7. High DFT shell pressure
    • 8. Loss of auxiliary exhaust
    • 9. Inattention of personnel
  41. LOW DFT WATER LEVEL LDWL POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Main feed pump failure
    • 2. Loss of boiler to low water condition
    • 3. High steam temperature to campus
    • 4. Damage to equipment (feed pump, desup pump)
    • 5. Flashing or quenching of the DFT
    • CAUTION: SLOWLY INTRODUCE WATER TO THE DFT AFTER LOW WATER CONDITION. IF WATER ENTERS TOO RAPIDLY, A LOW PRESSURE (VACUUM) CONDITION OCCURS WHICH COULD CAUSE IMPLODING OF THE DFT SHELL.
  42. LOSS OF NATURAL GAS LNG SYMPTOMS:
    • 1. Boiler trips off-line
    • 2. Loss of steam pressure
    • 3. Gauge or controller indicates loss of gas pressure
  43. LOSS OF NATURAL GAS LNG IMMEDIATE ACTIONS:
    • 1. Shut the manual gas valve to boiler
    • 2. If gas line has ruptured:
    • ***** a. Trip the plant
    • ***** b. Shut the main gas valve to the plant located in the fenced area
    • 3. Call supervisory personnel
  44. LOSS OF NATURAL GAS LNG CAUSES:
    • 1. Ruptured gas line
    • 2. Gas system valves misaligned
    • 3. Low gas pressure to plant
    • 4. High gas pressure to the burner
    • 5. Loss from gas supplier
  45. LOSS OF NATURAL GAS LNG POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Fire
    • 2. Loss of steam pressure to campus
  46. HOT BEARING HB SYMPTOMS:
    • 1. Bearing lube oil temperature exceeds 180° F
    • 2. A 50° F temperature differential between lube oil cooler outlet and the bearing outlet temperature
    • 3. Any unusual rise in temperature for any reason
    • 4. High bearing temperature alarm sounds @ 180 ° F
  47. HOT BEARING HB IMMEDIATE ACTIONS:
    • 1. Slow the turbine speed
    • 2. If conditions allow, verify the following:
    • ***** a. Lube oil temperatures, flows and pressures on all bearings
    • ***** b. Lube oil cooler outlet temperature
    • ***** c. Lube oil strainer differential pressure
    • ***** d. Lube oil cooler is cool to the touch
    • ***** e. Cooling water alignment
    • 3. Call supervisory personnel
    • 4. If conditions allow, perform the following:
    • ***** a. Apply cool rags on lube oil piping on inlet side of affected bearing
    • ***** b. Direct artificial ventilation onto bearing
    • ***** c. Place a steam deflecting shield to direct steam away from bearing
    • ***** d. Start additional lube oil pump, if necessary
    • 5. If conditions worsen, immediately trip the chiller:
    • ***** a. Ensure auxiliary lube oil pumps are “on”
    • ***** b. Take a lube oil sample
    • ***** c. Inspect bearing for damage
    • ***** d. Replenish sump with new lube oil
  48. HOT BEARING HB CAUSES:
    • 1. Insufficient lube oil pressure to bearings
    • 2. Obstructed bearing oil supply or return line
    • 3. Grit or dirt in oil
    • 4. Improperly fitted or aligned bearing
    • 5. Poor condition of journal bearing surface
    • 6. Bearing oil film lost due to water in the lube oil
    • 7. Steam seal leakage causing water in the lube oil
  49. HOT BEARING HB POSSIBLE ADDITIONAL CASUALTIES:
    1. Shaft damage
  50. UNUSUAL NOISE/VIBRATION IN TURBINE UNVT SYMPTOMS:
    1. Vibration or metallic noise from turbine upon start-up, normal operation or securing
  51. UNUSUAL NOISE/VIBRATION IN TURBINE UNVT IMMEDIATE ACTIONS:
    • 1. Slow speed of the turbine until noise/vibration stops
    • ***** a. Monitor oil pressures, temperatures and flows
    • 2. Immediately trip the turbine if conditions worsen:
    • ***** a. Take lube oil sample
    • ***** b. Perform thrust clearance checks
    • ***** c. Inspect bearings
    • ***** d. Inspect turbine blading
    • 3. Call supervisory personnel
    • 4. Insure all actions are logged in the log book
  52. UNUSUAL NOISE/VIBRATION IN TURBINE UNVT CAUSES:
    • 1. Water carryover from the boiler to the turbine
    • 2. Thrust or journal bearing failure
    • 3. Shaft out of alignment or balance
    • 4. Broken turbine blading or shrouding
    • 5. Bowed or damaged shaft
    • 6. Turbine operating at critical speed
    • 7. Excessively high hotwell level
    • 8. Loss of turbine lube oil pressure or temperature
  53. UNUSUAL NOISE/VIBRATION IN TURBINE UNVT POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Personnel injury
    • 2. Damage to affected and/or surrounding equipment
    • 3. Hot bearing
    • 4. Loss of condenser vacuum
  54. MAJOR STEAM LEAK MSL SYMPTOMS:
    • 1. Loud hissing noise
    • 2. Excessive steam buildup in plant
    • 3. Sudden increase in boiler steam flow
  55. MAJOR STEAM LEAK IMMEDIATE ACTIONS:
    • CAUTION: NEVER ATTEMPT TO LOCATE A STEAM LEAK USING YOUR BODY PARTS. HIGH PRESSURE STEAM IS INVISIBLE.
    • 1. Immediately trip the boiler and/or stop steam supply from LP&L Cogeneration plant
    • 2. Call supervisory personnel
    • 3. Evacuate plant if necessary
    • 4. Turn on exhaust fans and open the back door
  56. MAJOR STEAM LEAK CAUSES:
    • 1. Ruptured steam piping, gaskets, or valves
    • 2. Drain line open
    • 3. Failure or simmering relief valve
    • 4. Inattention of personnel
  57. MAJOR STEAM LEAK POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Personnel injury
    • 2. Boiler over-firing
  58. LOW CITY WATER PRESSURE LCWP SYMPTOMS:
    • 1. Pressure gauge indicates low city water pressure
    • 2. Make-up difficulties in chilled water expansion tank
  59. IMMEDIATE ACTIONS:
    • 1. Notify the city of Lubbock, Distribution Control, 775-3416, of the existing problem and look through the plant for a leak or ruptured line.
    • ***** a. Request an additional pump be started at #3 pump station
    • 2. Record the time of call, city of Lubbock operator on duty, and problem experienced 3. Insure all actions are logged in the Operators’ Daily Log.
  60. LOW CITY WATER PRESSURE CAUSES:
    • 1. Low city water pressure from the city of Lubbock
    • 2. Ruptured city water in plant or prior to the plant.
  61. LOW CITY WATER PRESSURE POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Loss of chilled water make-up
    • 2. Loss of make-up water for water treatment systems (RO system)
  62. COOLING TOWER HIGH PH CTHPH SYMPTOMS:
    • 1. pH repeatedly rises above 7.2
    • 2. pH rises above 7.2 and remains there
    • 3. pH rises without explanation
    • 4. Foaming of cooling towers
  63. COOLING TOWER HIGH PH IMMEDIATE ACTIONS: For pHs 7.3 – 8.0:
    • 1. Verify the pH discrepancy by lab meter, handheld meter, pH papers and so forth, using at least two different methods.
    • 2. If probe is in error, remove it and clean it with DI water and a kimwipe.
    • 3. If probe is still in error, notify chemistry personnel or instrumentation personnel about the condition.
    • Once pH discrepancy is verified,
    • 4. Contact Chemistry personnel and follow their instructions
    • 5. Check pump operation, output, power supply, prime, rate setting and valve lineups. Prime the pump. Adjust pump setting. Switch to another pump in the manifold or switch on an additional pump in the manifold.
    • 6. Log all evolutions and measurements in the Operator’s Daily Log.
  64. COOLING TOWER HIGH PH IMMEDIATE ACTIONS:
    • If pH does not return to normal within one (1) hour of making corrections, or if pH climbs above 8.0,
    • 1. Contact chemistry manager for instructions.
    • 2. Adjust cooling tower blow-down to reduce conductivity to 3000 µS or less.
  65. COOLING TOWER HIGH PH IMMEDIATE ACTIONS: If pH rises to 10 or above,
    • 1. Secure cooling tower bleed.
    • 2. Verify that cooling tower drain valves are shut.
    • 3. Secure all chemicals to cooling tower: DN-2105, bleach, and acid.
    • 4. Notify supervisors and chemistry manager.
    • 5. Log all evolutions, pH measurements and times. Document all phone calls.
  66. COOLING TOWER HIGH PH IMMEDIATE ACTIONS UPON INDTRUCTIONS FROM YOUR SUPERVISOR OR THE UTILITIES CHEMISTRY MANAGER:
    • 1. Notify Environmental Health and Safety: 2-3876.
    • 2. Notify the Wastewater Treatment Plant: 775-3234.
    • 3. Record the name of the person who took the call for the city of Lubbock.
    • 4. Begin neutralization procedures as per chemistry manager’s instructions.
    • NOTE: pHs above 9.1 will not occur naturally. A pH of 10 or above must be caused by some concentrated chemical in the system: an enormous overfeed (accompanied by foam) on a ruptured chemical tank.
  67. COOLING TOWER HIGH PH CAUSES:
    • 1. pH probes are dirty or out of calibration
    • 2. pH probes or transmitters have failed
    • 3. Sample line has been inadvertently isolated or sample flow has been otherwise interrupted.
    • 4. Acid pumps are unplugged or switched off
    • 5. Acid pumps are set too low
    • 6. Controller set-points have been improperly altered
    • 7. Low acid tank level
    • 8. Acid pump diaphragm or check valves have failed
    • 9. Acid pump power failure
    • 10. Lining up of sample flow to unrepresentative streams (as is possible at CHACP II).
    • 11. Obstructed acid line
    • 12. Ruptured acid line
    • 13. Acid lines are valved off to some or all of the basins
    • 14. Automatic acid isolation valves have failed shut on the CHACP I east towers
    • 15. Extreme chemical overfeed
    • 16. Acid pumps have lost prime
  68. COOLING TOWER HIGH PH POSSIBLE CASUALTIES: pH 7.2 – 8.0:
    • 1. Scale on condenser tubes
    • 2. Over-pressurized acid line (rupture potential)
    • 3. Acid leak hazards
  69. COOLING TOWER HIGH PH CTHPH POSSIBLE CASUALTIES: pH 8.1 – 9.9:
    • 1. Severe scaling of condenser tubes
    • 2. Over-pressurized acid line (rupture potential)
    • 3. Acid leak hazards
  70. COOLING TOWER HIGH PH CTHPH POSSIBLE CASUALTIES: pH 10 or above:
    • 1. Damage to city of Lubbock Wastewater Treatment Plant
    • 2. Unlawful discharge: subject to prison sentence or large fines (both personal and corporate)
  71. COOLING TOWER LOW PH CTLPH SYMPTOMS:
    • 1. pH repeatedly falls below 7.2
    • 2. pH falls below 7.2 and remains there
    • 3. pH falls without explanation
    • 4. Foaming of cooling towers
    • 5. Tower water turning a green color
  72. COOLING TOWER LOW PH CTLPH IMMEDIATE ACTIONS
    • 1. Insure the acid pumps are secured
    • 2. Contact chemistry personnel
    • 3. Contact supervisors
  73. COOLING TOWER LOW PH CTLPH CAUSES:
    • 1. Acid pumps not automatically securing
    • 2. Someone lowering the set point
    • 3. pH probes are dirty or out of calibration
    • 4. pH probes or transmitters have failed
  74. COOLING TOWER LOW PH CTLPH POSSIBLE CASUALTIES:
    1. Loss of copper tube thickness due to acid attack
  75. LOSS OF ELECTRICAL POWER LEP SYMPTOMS:
    • 1. Boiler alarm energizes
    • 2. Emergency diesel generator starts
    • 3. Plant lights go out
    • 4. AMP meter indicates 0 amp usage in plant
  76. LOSS OF ELECTRICAL POWER LEP IMMEDIATE ACTIONS:
    • 1. Ensure the following:
    • ***** a. Emergency diesel generator has started
    • ***** b. Emergency air compressor has started (either the 1250 or Sulair)
    • ***** c. Steam temperature to campus is in parameters
    • 2. If power is immediately restored:
    • ***** a. A waiting period of five (5) minutes is required for transfer of electrical load from the diesel generator to normal power
    • ***** b. Then commence normal restoration of plant
    • 3. If power is not restored:
    • ***** a. Call supervisory personnel
    • ***** b. Wait for power to be restored and/or seek out and isolate problem
  77. LOSS OF ELECTRICAL POWER LEP CAUSES:
    • 1. Overload on plant AMP consumption
    • 2. Loss of electrical supply from LP&L
    • 3. Transformer failure
    • 4. Inattention of personnel
  78. LOSS OF ELECTRICAL POWER LEP POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Electrical fire
    • 2. Loss of steam to campus
    • 3. Loss of chilled water to campus
  79. LOSS OF VACUUM LOV SYMPTOMS:
    • 1. Vacuum gauge indicates loss or decreasing vacuum
    • 2. Turbine speed decreases
  80. LOSS OF VACUUM LOV IMMEDIATE ACTIONS:
    • 1. Shift to idle set of air ejectors
    • 2. Verify pressure and temperature on air ejector
    • 3. Reduce the load on the chiller when the condenser vacuum reaches 15”
    • 4. Contact supervisory personnel
    • 5. When the condenser vacuum reaches 9”, reduce the load until on the governor. If vacuum decreases below 9”, trip the chiller.
    • 6. If conditions allow, verify the following:
    • ***** a. Verify all system alignments
    • ***** b. Allow hot condenser to cool
    • ***** c. Check loop seal charge
    • ***** d. Ensure gland seal is between .5 and 4 psi
    • ***** e. Call supervisory personnel
    • 7. If conditions worsen, trip the chiller off-line
  81. LOSS OF VACUUM LOV CAUSES:
    • 1. Excessive air leakage into the condenser:
    • ***** a. Insufficient gland seal pressure [.5 – 4 psi]
    • ***** b. Broken or leaking sight glass on hotwell
    • ***** c. Standby hotwell pump suction valve is open and/or packing gland leaks
    • ***** d. System valves open on (standby) air ejector
    • ***** e. Loose valve stem packing glands
    • ***** f. Loose or damaged gauge line fitting
    • ***** g. Leaking condenser exhaust valve (sky valve) and/or loss of water seal
    • 2. Air removal system malfunction:
    • ***** a. Insufficient steam pressure to air ejector
    • ***** b. Insufficient flow of condensate through air ejector condenser for cooling
    • ***** c. Loss of loop seal
    • ***** d. Flooded air ejector condenser
    • ***** e. Clogged, dirty or eroded nozzles
    • ***** f. Cracked or broken nozzle diffuser
    • ***** g. Misalignment of air ejector condenser
    • ***** h. Improper assembly of the air ejector condenser
    • ***** i. Dirty steam sides of the air ejector condenser
    • ***** j. Dirty condensate side of the air ejector condenser
    • ***** k. Clogged air ejector condenser tubes
    • 3. Excessive amount of condensate in the condensate hotwell:
    • ***** a. Malfunctioning hotwell pump
    • ***** b. Misaligned hotwell pump valves
    • ***** c. Improper alignment of the hotwell recirculating system
    • ***** d. D.I. water is aligned to the hotwell
    • ***** e. More than one hotwell pump operating or system valves aligned
    • ***** f. Flooded DFT or surge tank
    • ***** g. Misaligned condensate system
    • 4. Insufficient flow of condenser water:
    • 5. Loss of condenser water pump (s)
    • 6. Misalignment of condenser water system valves
    • 7. Jammed/damaged air operated control valves
    • 8. Plugged or restricted condenser water tubes
    • 9. Air-bound condenser
  82. LOSS OF VACUUM LOV POSSIBLE ADDITIONAL CASUALTIES:
    • 1. Hot condenser
    • 2. Damage to turbine
  83. INADVERTENT SPILL TO THE SEWER STS SYMPTOMS:
    • 1. Possible chemical odor from sumps or sewage pump.
    • 2. pH tests less than 5.1 or more than 9.9.
    • 3. Visible release of chemicals or oils.
    • 4. Unexplained change in bulk inventories
  84. INADVERTENT SPILL TO THE SEWER STS IMMEDIATE ACTIONS:
    • 1. Secure sewer pumps. Be sure you know which pump services which area of the plant.
    • 2. Notify supervisors and Utilities chemistry manager.
    • *Upon instructions from your supervisor or Utilities chemistry manager:
    • 3. *Notify Environmental Health and Safety: 2-3876.
    • 4. *Notify the Wastewater Treatment Plant: 775-3234.
    • 5. Record the name of the person who took the call for the city of Lubbock.
    • 6. Begin dilution, treatment or neutralization procedures, as per chemistry manager’s instructions
  85. INADVERTENT SPILL TO THE SEWER STS CAUSES:
    • 1. Inadvertent discharge of:
    • ***** a. Acid
    • ***** b. Lubricating oils
    • ***** c. Diesel oil
    • ***** d. Treatment chemicals
    • 2. Inattention of personnel
  86. INADVERTENT SPILL TO THE SEWER STS ADDITIONAL CASUALTIES:
    • 1. Damage to the city of Lubbock’s Wastewater Treatment Plant.
    • 2. Unlawful discharge: subject to prison sentence or severe fines (both personal and corporate).
    • 3. Administrative disciplinary action.
  87. REFRIGERANT LEAK RL SYMPTOMS
    • 1. Hissing sound.
    • 2. Decrease in suction and discharge pressure.
    • 3. Decrease in evaporator and condenser level.
    • 4. Increase in chill water outlet temperature.
    • 5. Decrease in condenser water temperature
    • 6. Refrigerant monitor alarm.
  88. REFRIGERANT LEAK RL IMMEDIATE ACTIONS
    • 1. Evacuate the plant.
    • 2. Trip the chiller offline.
    • 3. Drop the liquid refrigerant down to the pump down unit.
    • 4. Inform supervisory personnel.
  89. REFRIGERANT LEAK RL CAUSES
    • 1. Inattention of personnel.
    • 2. Seal failure.
    • 3. Tube leak (in the condenser or evaporator).
    • 4. Mechanical failure (seal pot heater, ruptured pipe, etc.)
  90. REFRIGERANT LEAK RL POSSIBLE ADDITIONAL CASUALTIES
    • 1. Freezing and rupturing of the tubes.
    • 2. Tripping the chiller offline.
    • 3. Evacuating the plant (the refrigerant will descend to the basement as it is heavier than air).
    • 4. Loss of cooling to campus.
    • 5. Could possibly cause damage to the compressor and the turbine.
  91. CHILLER TRIP CT SYMPTOMS
    • 1. Alarm sounds
    • 2. Boiler alarms for low drum level
    • 3. Increase in chill water supply temp
  92. CHILLER TRIP CT IMMEDIATE ACTIONS
    • 1. Determine the cause of the trip
    • 2. Acknowledge the alarm
    • 3. Insure boiler has handled the load swing
    • 4. Close the trip throttle valve
    • 5. Secure the 150# steam
    • 6. Get the procedure for starting the chiller and re-start the chiller
  93. CHILLER TRIP CT CAUSES
    • 1. Low suction trip
    • 2. Loss of chill or condenser water flow
    • 3. Loss of control air
    • 4. High bearing temp trip
    • 5. Overspeed trip
  94. CHILLER TRIP CT POSSIBLE ADDITIONAL CASUALTIES
    • 1. Boiler trip on low water
    • 2. Out of spec chill water temperature to campus

What would you like to do?

Home > Flashcards > Print Preview