VELOCITY & PRESSURE DROP IN PIPE LINE

VELOCITY AND PRESSURE DROP IN PIPES:

Velocity

The velocity of hydraulic fluid through a conductor (pipe, tube or hose) is dependent on flow rate and
cross sectional area. Recommended fluid velocities through pipes and hoses in hydraulic systems are as
follows:
Service Velocity (ft/sec) Velocity (m/sec)
suction/intake 2 - 4 0.6 – 1.2
return 4 – 13 1.5 - 4
pressure/discharge 7 - 18 2 – 5.5
Use values at the lower end of the range for lower pressures or where operation is continuous. Refer to
the flow/velocity nomograms on pages four and five for more information, alternatively, fluid velocity
can be calculated using the following formula:
v = Q × 0.408
D²
Where
v = velocity in feet per second (ft/sec)
Q = flow rate in US gallons per minute (USgpm)
D = inside diameter of pipe or hose in inches (in)
In metric units
v = Q × 21.22
D²
Where
v = velocity in metres per second (m/sec)
Q = flow rate in litres per minute (L/min)
D = inside diameter of pipe or hose in millimetres (mm)

Pressure drop

Friction between the fluid flowing through a conductor and its inside wall causes losses, which are
quantified as pressure drop. Pressure drop in conductors is an important consideration for the designer
especially in systems where long pipe or hose runs are necessary. The pressure drop over a length of
pipe or hose can be calculated using the following formula, which for ease of calculation uses metric
units. Before proceeding to the pressure drop calculations, the following variables need to be known:
Flow rate in litres per minute (L/min) Q
Inside diameter of pipe or hose in millimetres (mm) D
Kinematic viscosity of fluid (at operating temperature) in centistokes (cSt) ν
Density of the fluid in kilograms per cubic metre (kg/m³) ρ
Length of the pipe, tube or hose in metres (m) L

1. Calculate fluid velocity:

v = Q × 21.22
D²
Where
v = velocity in metres per second (m/sec)
Q = flow rate in litres per minute (L/min)
D = inside diameter of pipe or hose in millimetres (mm)

2. Calculate the Reynolds Number (Re):

Re = 1000 × v × D
ν
Where
Re = Reynolds Number
v = velocity in metres per second (m/sec)
D = inside diameter of pipe or hose in millimetres (mm)
ν = kinematic viscosity of fluid (at operating temperature) in centistokes (cSt)

3. Calculate the friction factor (f)

The formula used to calculate the friction factor is dependent on the magnitude of the Reynolds
Number.
If the Reynolds Number is less than 2300, flow is laminar and the following formula is used to
calculate the friction factor:
f = 64
Re
Where
f = friction factor
Re = Reynolds Number < 2300
If the Reynolds Number is between 2300 and 4000, flow is transition and greater than 4000 flow is
turbulent. For Reynolds Numbers greater than 2300 and less than 100,000 the following formula can be
used to calculate the friction factor:
f = 0.3164 × Re - 0.25
Where
f = friction factor
Re = Reynolds Number > 2300 and < 100,000
In instances where the Reynolds Number is greater than 100,000, friction is highly dependant on the
roughness of the conductor’s inner surface. In these cases Colebrook’s equation, which considers pipe
roughness, is used to calculate the friction factor. However, due to the relatively low fluid velocities
and high fluid viscosities present in hydraulic systems, Reynolds Numbers of this magnitude should not
be encountered.

4. Calculate the pressure drop:

Finally, pressure drop can be calculated using the following formula:
Δp = v² × f × L × ρ
2D
Where
Δp = pressure drop in Pascals (Pa)
v = velocity in metres per second (m/sec)
f = friction factor
L = length of pipe or hose in metres (m)
ρ = density of the fluid in kilograms per cubic metre (870-890 kg/m³ for hydraulic oil)
D = inside diameter of pipe or hose in metres (m)
Conversions
SUS (32 – 99) cSt = 0.2253 × SUS – (194.4 ÷ SUS)
SUS (100 – 240) cSt = 0.2193 × SUS – (134.6 ÷ SUS)
SUS (> 240) cSt = SUS ÷ 4.635
US gallon × 3.785 = litre
inch × 25.4 = millimetre
inch × 0.0254 = metre
feet × 0.3048 = metre
lb/ft³ × 16.02 = kg/m³
Pascal (Pa) ÷ 100000 = bar
Pascal (Pa) × 0.000145 = psi

BOILER QUESTIONS & ANSWERS

 

BOILER QUESTION & ANSWERS

What is a flame safeguard system?

Answer:

Safeguard system is a set of controls used on a boiler to ensure safe burner operation. Primary functions include:

• A safe way of starting and shutting down the burner. This can be accomplished either automatically or manually.
• A flame safeguard system also starts the burner in the proper sequence. For example it will purge the combustion chamber of gas, light the pilot and then open the main gas valve.
• The flame safeguard system will also continually monitor burner operation when the boiler is on-line.
• The system will protect the boiler from excessive pressure or temperature conditions
• It will also regulate the firing rate according to the demand for heat or steam
• Finally, it will standby during down time, waiting for the signal to start the burner once again.

What is meant by Stoichiometric Combustion? 

Answer

Stoichiometric Combustion is the perfect combination of air and fuel that result in perfect combustion! Sounds good doesn't it? Unfortunately, it is impossible to achieve in burners that you would commonly find on a boiler.

So why toss this term about? For the simple reason that it gives us a target in which we might compare our combustion conditions against. For example if we supply too little air, the burner will run "rich". This means that not all the fuel was burned. Not only is this inefficient it also results in sooting that will decrease the heat transfer in the boiler.

Introduce too much air into the process and again, you reduce efficiencies. Not all the fuel is burned. This is why we strive for the perfect balance  - Stoichiometric Combustion.

Can you kindly elaborate on just how much air is required to get a good complete combustion? 

Answer

Thanks for the question. You are looking for that magical "Theoretical" air. The exact amount required to completely burn the fuel. The truth is that there has to be "excess air".  According to the John Zink Combustion Handbook, excess air is defined as "the amount of air needed by a burner which is in excess of the amount required for perfect or stoichiometric combustion. Some amount of excess air, depending on the available fuel/air mixing energy, is required to assure through mixing of the fuel and air for complete combustion."

To calculate Excess Air, % use the following formula:

  = (Air supplied - Theoretical air)  x 100
         Theroretical air

The theoretical air required will vary depending on the fuel that is being fired. I found a table in the ASHRAE 1985 Fundamentals Handbook (pg. 15.8) that lists these values. For example Natural Gas requires 9.6 lb of cu. ft.air/cu. ft of fuel, Propane  requires 24 cu.ft. of air/cu. ft. of fuel, No. 2 fuel oil requires 12.7 lb of air/gal of fuel.

As for a general rule of thumb...how about 0.9 cubic feet of air for 100 Btu of fuel.

What does "foaming" mean?           

Answer:

Foaming is a condition that occurs in boilers when there are high concentrations of soluble salts, suspended solids or organic matter. These create foam in the steam space of your boiler that actually look like the foam on a good glass of beer! Now foam on your beer is acceptable, foam in your boiler is not.

When these little foam bubbles pop, they create a liquid that, in turn form slugs of water. Not only does your steam quality suffer, so may your entire system. Remember steam can reach velocities of over 80 miles an hour. Push a slug of water through at that speed and you can seriously damage turbine blades, piping systems and actuators.

Please define turndown ratio and tell what the advantages are for a higher turn down. Are there any disadvantages? 

Answer:

First a definition: Turndown ratio is the ratio of maximum fuel input rate to minimum fuel rate of a variable input burner. Traditionally burners on firetube boilers operate in the 5:1 turndown ratio range depending on fuel and size. High turndown burners are considered those with ratios of 10:1 or greater.

Advantages of high turndown burners include:

• Reduction of standby losses
• Limiting thermal cycling
• Saves wear and tear of burner components

Disadvantages include:

• Initial cost and complexity
• Requires more maintenance
• Limitations of Boiler/burner system

The limitations include fuel/air mixing requirements, material temperature issues, flame shape characteristics, flow control limitations and pressure vessel limitations.

1.  What is the general construction for furnace refractory and the common defects found. 

2. Does the laying/installation of refractory bricks vary much from "similar to laying pavers"? 

Answer:

1.  Howard, For boilers, refractory is generally a harden brick type material orcastable cement that is designed to handle extreme heat. At one time this refractory had asbestos as the main component, but this has changed. I have included a link below to the Refractories Institute who will have more detailed information on the components of refractory. Some of the things we look for when servicing refractory in a boiler is for loose or broken tile along with flaking or chipping of refractory surfaces. These we repair immediately. 

2.  Re-bricking a boiler may be a little more difficult especially in firetube (marine) designs. The reason for this difficulty is found in the circular furnace. Make sure you have the right replacement brick and you follow the manufacturers instructions. Depending upon the manufacturer you may also have an inner door and a rear door that will require pouring new refractory. Remember, if you are doing refractory work, make sure the old refractory does not contain any hazardous material and that you have all the closing gaskets needed in order to close the boiler when you are finished. 

I observed that some industrial plants having small package boilers do not practice deaerator system.  What should be the boiler rating requirement to have deaerator.

Answer

We suggest using a deaerator when:

1. Your boiler plant operates over 75 psig
2. Any boiler plant with limited standby capacity
3. Boiler plants that use 25% or more cold make-up water
4. Any boiler plant that relies on continuous boiler operation

Remember the deaerator is a preventative maintenance tool. It really should be used in every boiler application with the exception of a hot water heating system that uses absolutely no make-up water.

I have a steam boiler and need to install a Boiler Feed system, how do I make sure that I have the right size tank?

Answer

General rule of thumb is to have at least ten minutes worth of water available at all times. Here is what you need to know to figure this one out. The size of your boiler (bhp) the fact that one bhp = 34.5 lbs./hr. and that one gallon of water weighs about 8.337 lbs. Take all of these facts and plug them into the following calculation:

BHP (Boiler Horsepower) X 34.5 / 8.337 / 60 X 10 = gallons of water needed

So, if you have a 500 bhp boiler your formula will be as follows:

500 x 34.5/ 8.337 / 60 x 10 = 345 gallons But wait, you can't operate a tank completely flooded so you will have to include a 1.5 safety factor. This will take you to about 517 gallons, so a 500 gallon tank will work.

Maybe an easier way is to plan for 1 gallon storage for every boiler horsepower.
500 bhp = 500 gallon tank
300 bhp = 300 gallon tank

But, be careful! Depending upon your particular process you may need a bigger tank. Especially if you are using your steam for process and large slugs of water are returned in an unpredictable manner! 

Is it legal to weld on a boiler burner?  fire tube boiler 150 hp. The air deflectors have cracked and either need welding or replacing.

Answer

Boiler pressure vessels require an A.S.M.E. certified welder. The burner does not, but be careful. Changes in the burner cause changes in performance and combustion. Safety of the weld is also a concern. Your safest bet would be to replace the cracked part. Any time work is done on a burner the combustion and safety controls should be checked as soon as possible after completion of the work.

If you provide us with your burner/boiler information we can help you locate what you need. Also, a digital picture is great when trying to figure out what part is actually need. I am betting what you are calling air deflectors is actually the burner's diffuser.

My question is, if my boiler has very high conductivity and or Alkalinity, can the boiler be safely blown down while it is under load? (Bottom blowdown).

Answer

Continuous surface blow down should be used to control boiler conductivity. The surface of the boiler water will have the highest concentration of dissolved solids along with any oil. The continuous surface blow down will be a very small flow that gets tweaked daily based on your chemical sample results. You did not mention the size of your boiler but a 1/2" throttle valve is usually sufficient and a 3/8" throttle valve will probably work also.

The bottom blow down is done at least daily (more often depending on boiler water conditions) to blow out scale and mud from the bottom of the boiler. If possible you should lower the firing rate of your boiler when you do the bottom blow down then return to normal firing rate after the blow down.

Our 1,200,000 lb/hr steam boiler normally operates at around 3% excess O2
or 15% excess Air. If it operated at 3% excess O2 what would be the approximate % boiler efficiency loss?

 

Answer

The term Boiler efficiency is a generic term that could mean many things. The best definition of your boiler's efficiency is the fuel-to-steam efficiency. After all you are paying for the fuel to produce the steam!
There are two pieces of information that you will need. The first is the stack temperature. Simply put, the lower the stack temperature the more heat you are transferring within the boiler. The second bit of information you will need is the amount of CO2 in the flue gas. High CO2 readings with no CO and very little O2 throughout your entire firing range indicate good burner control.

You are going to need some simple equipment to check your fuel-to-steam efficiency. This includes a flue gas analyzer, a stack thermometer, a room thermometer, charts for heat loss in the stack for the fuels you are firing and a correction chart for radiation and convection losses. (ask your boiler supplier for these charts if you do not have them)

Here is an example:
Stack Temperature = 340 degree F.
Room Temperature = 80 degree F.
Gas analyzer reports CO2 = 10% and CO = 0
Subtract room temp from flue gas temp. 340 - 80 = 260 deg. F.
From the Hays Chart, at 260 deg. F. and 10% CO2 you find a stack loss of 15.6% exiting the stack.
Add for radiation and convection losses (available from your boiler manufacturer). We will assume 1% in this example. So 15.6% = 1% = 16.6%
Now subtract that from 100% efficiency
100% - 16.6% = 83.4% Fuel-to-Steam efficiency.

How do you calculate boiler turndown. Is there a formula?

Answer

Boiler Turndown is a comparison of the Maximum Input of the boiler compared to the Minimum Input that the boiler will properly operate.

To calculate your actual Turndown you need to know what your actual input is at Maximum and Minimum firing rates. The easiest way to do this is meter the fuel usage be it either a flow meter on the fuel oil supply or a gas meter on the natural gas supply line.

Lets do an example:

Assume that at Maximum Input we clocked the Natural Gas meter and found that the meter clocked 1000 cubic feet (pressure corrected) per hour.

Note: You do not need to have the boiler at Maximum Fire for and hour. You can take the reading over a few minutes and correct to one hour.

So, 1000 cubic feet/hour X 1050 btu/ cubic foot = 1,050,000 btu/hr at maximum input

Minimum Input meter clocked is 100 cubic feet/hour

100 cubic feet/hour X 1050 btu/cubic boot = 105000 btu/hr at minimum input

1,050,000 = 10 giving us a 10 to 1 turndown in this case.
105,000 1

My assumptions: Natural Gas but value = 1050 btu/cubic foot

Why are manholes elliptical in shape ( advantages ) ?

Answer

Manways on boilers are elliptical because the cross section of a man is elliptical; well most men are. Most manways these days are 12" X 16". A 12" X 16" opening is significantly smaller than a 16" round hole. A smaller opening means smaller surface area of the backing plate so the smaller plate will have less over all force acting upon it.

Can you tell me the proper way to install flexitaulic hand hole and manhole cover gaskets? 

Answer

1. Make sure all seating surfaces are clean, this usually requires wire brushing.

2. Make sure threads on the nuts and bolts/studs are clean and nuts turn freely over the length of the threads.

3. The tricky part is to make sure the gasket is centered on the backing plate and the backing plate is centered in the manhole or handhole. Tighten (evenly where there is more than one bolt/stud involved) making sure the backing plate and gasket stay centered. Once you are sure everything is properly in place and snugged torque to the proper torque spec. for the size of the bolt/stud and materials that you are using or manufacturers recommendations if you have them.

Note: NEVER EVER TRY TO TIGHTEN A MANWAY OR HANDHOLE WHILE THE BOILER IS HOT AND PRESSURIZED! THE MANWAY OR HANDHOLE COULD MOVE CAUSING YOU TO BE SPRAYED WITH HOT WATER AND/OR STEAM!!!!!!!!

Dear

After major refractory replacement: Castable must be air-cured for a minimum of 24 hours. Some moisture will remain, so firing will have to be done at "low fire" rates on an intermittent basis so as to hold the stack temperature (as shown on the stack thermometer) to not over 150 F - that is to say, below the boiling point of water, since the generation of steam within the refractory material would destroy the strong bond, cause spalling, flaking and cracking.

After initial firing of a repaired read door, the door metal will become exceptionally warm or hot. This is due to water conduction of heat. This condition will exist until such time as all moisture has been driven out of the refractory.

The following heat curing schedule is recommended:

Operate burner for brief intervals at low fire, bringing the reading of the stack thermometer up to 150 F and hold this for six hours. The raise the stack temperature at a rate of 50 F per hour until normal operating temperature is reached and hold this for another 6 hours. The boiler may now be operated in the normal manner or shut down if desired.

The securing bolts around the heads should be tightened periodically as the temperature is equalized and when the boiler is at high fire. The tightness of the sight glass retainer should be checked and the retainer and sight glass should be examined for gas leakage. The air line from the front head of the boiler should be checked for possible blockage.

What are the disadvantages of boilers being cycled frequently? I saw a system of 3 boilers which are cycled every 10 minutes. Running a single boiler would meet their heating requirements. Is it advisable to cycle boilers so frequently or is it better to turn down the other 2 boilers and operate only one?

Answer:

Situations that require an absolute continuation of heat without any interruption even for a short period of time requires the additional boilers to be fired frequently so they remain hot and ready to go. A cold boiler takes time to properly warm-up and be placed in service.

If a loss of heat for 1/2 hour to 1 hours would not cause any problems then running only one boiler is the preferred method. In your case I would run only one boiler at a time. Have one boiler in standby fired every few hours just to keep warm and the last boiler completely off and isolated.

Now, everyone has their own opinion. The above is based on my experiences in the boiler field. Boilers that are turned on and off are heated/cooled/heated/cooled, this can shorten the life of the boiler refractory, cause condensation of flue gas, shorten motor starter contact life among other things. A boiler will last the longest with the least failures if its kept hot and cycled off as few times as possible.

I am having problems with chemical carry over and the site glasses are blowing out. This is a laundry operation that is running Monday through Friday in the am only. The site glass assembly is McDonald Miller. Can you explain what can cause this problem ? 

Answer:

The most likely cause for your chemical carryover is that your Total Dissolved Solids are too high (Boiler water Conductivity is another way to express TDS). TDS is controlled by your surface blow down and should be controlled to the recommendations of your chemical supplier (normally 4000 micro-mho plus/minus 400).

Another possibility for chemical carryover is that you are dropping too big of a load too fast onto the boiler which drops boiler pressure suddenly causing the boiler to suddenly boil excessively and carrying over into the steam line. This is a bit harder to fix but can be done.

Now, the gauge glass problem! I am assuming you have the hollow tubular 5/8" in gauge glass. These never hold up well on a high pressure boiler. They tend to erode from the top and start leaking steam. As long as you stay with the 5/8" tubular gauge glass you will have this problem. To eliminate this problem you need to change your gauge glass to a prismatic type gauge glass that uses a thick flat glass that is sandwiched into a strong metal housing. It will not fail! Our Parts Department will be happy to quote a prismatic gauge glass assembly to you. We will need the Center to Center dimension and pipe size of your gauge glass connections. We need to know the MAWP of your boiler also.

• 
  

SHAFT ALIGNMENT PROCEDURE

SHAFT ALIGNMENT - REVERSE DIAL 

SHAFT ALIGNMENT - REVERSE DIAL INDICATOR ALIGNMENT PROCEDURE

• In principle, Reverse Dial Indication (RDI) and Laser Alignment are identical alignment methods each capable of similar accuracy. Below we will cover Reverse Dial Indication method in detail as it explains all the concepts of these two methods in a more understandable graphical sense. If you understand RDI alignment, Laser Alignment method is easy to understand.

Reverse Dial Indication Alignment:

Step 1:  Refer to section IV for Pre-Alignment considerations 

Step 2:  Determine which piece of equipment is “fixed” and which piece of equipment is “moveable”. In general, you will only be moving one piece of equipment and it is typically, but not limited to, the drive motor.

Step 3: Equipment layout On a piece of graph paper, lay out the piece of equipment being aligned as shown in Fig. 10. The distances needed are: 

1. Distance from where the first indicator rides on the pump hub to where the second indicator rides on the motor hub. In the example shown below, this is 10-1/2 inches.
2. Distance from where the second indicator rides on the motor hub to the center of the front motor feet. In the example shown below, this is 2-1/2 inches. 
3. Distance from the center of the motor front feet to the center of the motor back feet. In the example shown below, this is 5-1/4 inches.

Step 4: Sweep pump hub readings With the indicator bracket attached to the motor hub reading off the rim of the pump hub, zero the indicator on the top and rotate shafts together in 90° increments and take readings.

Step 5: Correct bottom pump hub reading (Vertical solution) The bottom reading must be corrected for indicator sag, which from section IV we determined this to be negative -.005 inch. To correct the bottom reading you subtract the indicator sag from the bottom indicator reading. The bottom indicator reading was -.025 - (-.005) give us the corrected reading of -.020 as shown in Fig. 11.

Step 6: Plot the first point (vertical solution) The -.020 value is a TIR (Total Indicator Reading) and is two times the actual shaft to shaft distance ( - .020 ÷ 2 = -.010 ). Negative -.010 is the distance between the motor shaft extension centerline and the pump shaft centerline in the plane of the pump hub. A negative sign indicates the dial indicator stem extended at the bottom. With the pump being fixed, the only way this can occur is if the motor shaft is low with respect to the pump shaft. On your graph paper using a scale of small division equal to .001, plot this point as shown in Fig. 12.

Step 7: Reverse the indicator to read the motor hub and sweep readings Now reverse the indicator setup so the bracket is attached to the pump hub and is reading off the rim of the motor hub. As before, zero the indicator on the top and rotate shafts together in 90° increments and take readings.

Step 8: Correct bottom pump hub reading (Vertical solution) The bottom reading must again be corrected for indicator sag. Subtract the negative -.005 indicator sag from the bottom indicator reading of +.005 gives you a corrected bottom reading of +.010. [ +.005 - (- .005) = +.010 ] as shown in Fig. 13

Step 9: Plot the second point (vertical solution) The +.010 value is a TIR number that we divide by 2 to give us +.005, which is the distance between the motor shaft extension centerline and the pump shaft centerline in the plane of the motor hub.

•  A positive sign indicates the dial indicator stem was compressed at the bottom. With the pump being fixed, the only way this can occur is if the motor shaft is low with respect to the pump shaft. Plot this point as shown in Fig. 14.

Step 10: Determine vertical shimming required at front and back motor feet With the pump shaft fixed, these two points represent the location of the motor shaft with respect to the pump shaft. Draw a line thru these two points extending past the plane of the front and back motor feet as seen in Fig. 15. The vertical shim adjustments required to bring the two shafts into alignment can be read directly from the graph. In this example, .004 should be added to the front motor feet and .001 should be added to the back motor feet.

Step 11: Horizontal (side to side) solution Use the same procedure used for the vertical solution only you do not need to correct for sag as the side readings cancel. In the vertical solution you zeroed the top and read the bottom. For the horizontal, you can zero the “near” and read the “far” or vice versa. To zero a reading, simply subtract that reading from both side readings. 

• In our example, the side readings from the motor to the pump in Fig. 11 were negative -.005 (“near” or 9:00 o’clock) and negative -.015 (“far” or 3:00 o’clock). If you choose to zero the near and plot the far readings, subtract negative -.005 from both sides and your “near” reading is now zero and your “far” reading becomes - .010 [-015 - (-.005) = -.010.]

• SHAFT ALIGNMENT - FLEX ELEMENT ALIGNMENT

  SHAFT ALIGNMENT - FLEX ELEMENT ALIGNMENT PROCEDURE
  
  
  

  

  • When the distance between coupling flex elements is long, making use of indicator brackets impractical or where lasers cannot be targeted due to obstructions or beam interference, Across the Flex Element Alignment method can be used. 

  In this method, angular and axial misalignment will be checked as described below respectively:

  
  

  Angular alignment:

  
  

  Step 1: Squarely and firmly attach a dial indicator to the center member shaft and read across the flex element to the driver hub surface facing away from the indicator mounting as seen in Fig. 16.

  

  
  

  Step 2: With the dial indicator set to zero, rotate the shaft one revolution and record the maximum and minimum dial indicator readings. 

  
  

  Step 3: If the range between the maximum and minimum reading is at or below .010 inch, the angular alignment is acceptable. If the range is greater than .010 inch, the equipment should be realigned. 

  
  

  Step 4: Repeat steps 1-4 on the driven side flex element.

  
  

  Axial Alignment:

  • To establish the axial misalignment, you will measure the gap between the spacer flange and connected equipment hubs, on both flex points of the coupling, and compare with published coupling limits. 

  Step 1: Without rotating the coupling, take four gap readings at 3:00, 6:00, 9:00 and 12:00 o’clock between the driver and center member flanges as seen in Fig. 17.

  
  

  

  
  

  
  

  Step 2: Average these four readings. 

  
  

  Step 3: Consult the coupling installation instructions for the coupling size and style being installed to be sure the average reading are within acceptable axial installation limits. If the coupling being aligned is an Addax® coupling, the nominal gap for all sizes is .540 inches and should be between .530 and .550 inches. 

  
  

  Step 4: Repeat steps 1-3 on the driven side flex element.

ALIGNMENT - LASER ALIGNMENT METHOD

 ALIGNMENT - LASER ALIGNMENT METHOD

• The laser alignment method is considered a precision-based performance technique that provides a faster, more accurate way to align equipment.

• It is ideal for alignment of equipment over long distances, and it is less prone for user error. Because of the range of technology between various manufacturers, the steps for laser alignment are not discussed in detail in this article.

PROCEDURE:

• laser alignment system installed on a pump and electric motor. The system contains a laser diode and position sensor on one mounting bracket.

• The diode emits a pulsating, non-hazardous, laser beam that is directed at the opposite bracket. The opposite bracket contains a prism that redirects the laser beam back to the position sensor. Like other shaft alignment techniques, the shafts are rotated to determine the vertical and horizontal readings for angular and parallel misalignment.

• The shaft positions and readings are automatically provided to a small computer. The computer then calculates the relative movement required at the feet of the moveable machine.

• A major advantage of the use of laser alignment is the precise measurement of misalignment. Laser alignment can detect misalignment to ±0.00004”. In addition, with the use of laser alignment, bar sag concerns are eliminated.

• However, there are drawbacks and limitations to the laser alignment method. Laser alignment equipment typically costs more than $10,000. Service companies or those companies with many pumps or large pumps are the primary buyers of laser alignment equipment.

• The environment in which the laser alignment equipment is used is also a limitation. The atmospheric temperature must be between 32° and 131° Fahrenheit for the use of laser alignment. The environment must also be free of steam, dust, or air currents.

• These detractors will prevent the reading of the laser beam properly. However, it is possible to use a plastic pipe to shield the beam from the steam, dust, or air currents.

FINAL CHECKS AND WORK CLOSEOUT :

After the equipment has been aligned, some additional tasks and checks should be performed.

• Make sure that each shaft turns freely with the coupling hubs installed.

• The safety equipment should be removed and the equipment energized

• The driver should be “bumped” to check for proper rotation.

• Reinstall the safety precautions and complete the assembly of the coupling per the installation instructions.

• Rotate the coupled shafts to ensure they turn freely.

• Install the coupling guards per OSHA or applicable requirements.

• The safety equipment should be removed and the equipment energized.

• Once the pump is ready to operate, the pump and piping that has been drained should be filled. As the pump and the system piping is filled, observe for any piping distortion due to improperly supported piping. Poorly supported piping may cause misalignment.

• After the piping is installed, the pump unit is operated under normal conditions and is thoroughly warm, stop the pump unit to recheck alignment while it is warm. This also ensures that there is no additional pipe strain.

• If additional alignment is required of more than 0.002” from the pipe free condition, the additional piping strain should be corrected. Additional discussion on piping installation can be found in another article.

• For high energy and petroleum pumps, the pump and driver feet are drilled and doweled at two locations, near the thrust bearing end, after the final alignment is complete and meets the specifications.

• Documentation of the alignment is important to the installation and operation of the equipment. Make a record of the final alignment tolerance on an alignment form or data sheet. This should be placed in the equipment’s history file. This provides not only proof of final condition, but allows a starting point and historical data for the future.

• For work done in the future, this information will allow for the alignment to be done quicker and smoother, saving set up time. In will also provide a basis to allow for measurement of operational time.

• Reporting or recording sheets can be developed to include information on soft feet, pipe stress and strain, coupling and shaft runouts, installation conditions such as bolts being found loose, and specifying the initial, desired, and final alignment information.

• The sheet should also provide a location for identification of the persons completing the work to be documented. This places responsibility of quality work on individuals, and provides learning opportunities if a failure occurs.

• Reported data allows for troubleshooting and root cause analysis of equipment failures. The data can be used to compare the “as discovered” condition and the “as completed” condition. This can be particularly useful for equipment with chronic abnormal behavior.

• Another useful tool for recording data are digital photos. Pictures of the shaft, coupling, base, and foundation conditions can be stored. These could be used in the future during set up to determine any special needs or how the installation was left.

• Although alignment should not be scheduled to be rechecked with the frequency of preventative maintenance procedures, it should be rechecked when observations are made in regards to the settling of the base, foundation, or soils, changing of the piping system, process changes, or seasonal temperature changes.

• For a new installation, the alignment should be scheduled to be rechecked 3-6 months after the initial installation and alignment.

CARRY OVER IN BOILER

               

CARRY OVER IN BOILER

  Contents

1 Nomenclature and Definitions 2
2 Introduction 3
3 Scope 3
4 Mechanical Carryover vs. Total Carryover 3
5 Description of the Method 5
6 Use of Sodium to Determine Total Carryover 5
7 Sampling 6
8 Analytical Methods 6
9 Test Procedures 7
10 Test Conditions 7

1. Nomenclature and Definitions

Symbol Physical quantity Unit
T Total Carryover %
M Mechanical Carryover %
V Vaporous Carryover %
Cs Sodium concentration in saturated steam (ppm) mg kg−1
Cb Sodium concentration in boiler water (ppm) mg kg−1
Mechanical Carryover: fraction of boiler water droplets entrained in the steam (mass of drum water per mass of steam).
Vaporous Carryover: fraction of substances entrained from boiler water into the steam by the substance's volatility (mass concentration in steam per mass concentration in drum water).
Total Carryover: is the sum of mechanical and vaporous carryover, and is the measured carryover.

2. Introduction

Carryover from boiler water to steam is a path by which dissolved and suspended solids in boiler water can be introduced into steam. Steam drums are equipped with steam separation devices capable of mechanically reducing the moisture content of the steam. The total carryover into steam consists of two parts: a mechanical part and a vaporous part. The mechanical part (Mechanical Carryover) involves the carryover of boiler water droplets. The vaporous part (Vaporous Carryover) involves the partitioning of dissolved solids (salts, oxides, impurities and other chemicals) between water and steam and represents the physical volatility of the substance.
Only above a drum pressure of about 16 MPa (2300 psi) does vaporous carryover start to become significant for most of the solids dissolved in the boiler water. Below this pressure, it is nearly all mechanical carryover with the exception of a few substances like silica, the copper oxides/hydroxides, aluminum compounds and boric acid, which exhibit significant vaporous carryover even at relatively low pressures. For boilers below 18 MPa (2600 psi), vaporous carryover is typically less than 0.1 %.
There are two important and distinct aspects associated with carryover. The first, for the operators of drum units, is the concern about possible corrosion and fouling aspects in superheaters, reheaters and steam turbines associated with the total carryover. The second, for the boiler manufacturers, relates to the performance of a drum in relation to the efficiency of the steam/water separation components and in regard to mechanical carryover. Thus for operators, it is important to know and monitor the total carryover into steam. In contrast, manufacturers need to provide information on mechanical carryover. One rigorous methodology to determine the mechanical carryover is illustrated in a recent publication [1]. However, applying this methodology (described briefly in Section 4) has been found to be rather difficult because a complex computer code needs to be used to carry out the calculations [1]. So, some manufacturers have their own methods or use a default value of 0.1 % carryover for the vaporous component.

3. Scope

Provide a procedure for the measurement of total carryover, and a description of mechanical carryover from steam drums (fraction of boiler water droplets entrained in steam) and of vaporous carryover.

4. Mechanical Carryover vs. Total Carryover

The total carryover of boiler water impurities and conditioning chemicals in drum boilers determines the chemical purity of the steam. Carryover is a combination of two factors: vaporous carryover, due to the inherent volatility of the constituents in the boiler water, and mechanical carryover of droplets of boiler water into the steam. Once the total carryover is known, then boiler water limits can be set to limit the risk of initiating corrosion in the boiler, as well as steam limits to minimize the risk of initiating corrosion and deposition in the steam circuits, including the turbine. Thus, carryover needs to be measured to develop unit-specific cycle chemistry guidelines.
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Total carryover of sodium is determined as the ratio of the saturated steam sodium concentration to boiler water sodium concentration. Mechanical carryover is determined by subtracting the vaporous sodium carryover in the steam at high pressures.
T = Cs / Cb * 100 (1)
M = T − V (2)
Mechanical carryover is the entrainment of water droplets in steam exiting the boiler. It depends on the condition of the water/steam separators, drum level control, and steady-state operating conditions. Mechanical carryover is a function of the density difference between water and steam phases at a particular pressure. An example of how mechanical carryover varies with pressure is shown in Figure 1, which illustrates that mechanical carryover can be significant; for example, at a pressure of 17.2 MPa (2500 psi), it may be as high as 0.2 %. The boiler manufacturer can supply the actual design data to be used for the respective boiler and such an example is also shown in Figure 1.
Vaporous carryover occurs due to the inherent volatility of the compounds present in the boiler water. Some compounds, e.g., ammonia and amines, are deliberately added to the water/steam circuit as conditioning chemicals, because they are volatile and can protect various parts of the boiler water/steam circuit during operation and off-load conditions. Except for these plant conditioning chemicals and a few substances like silica, copper oxides/hydroxides, aluminium compounds and boric acid, vaporous carryover at pressures less than about 16 MPa (2300 psi) is negligible.
Molecular impurities in boiler water can evaporate with steam (vaporous carryover). The degree of vaporous carryover is expressed as a distribution ratio of concentration of the compound or impurities in the steam to that in the boiler water. The distribution ratio is a function of:
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boiler drum pressure
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boiler water dissolved solids concentrations, and
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boiler water pH and interactions between the species present.
Thus, information is required on the volatility of the salts and their corresponding acids and bases likely to be present in boiler water, such as sodium chloride, hydrochloric acid, sodium hydroxide, ammonia, ammonium chloride, sulfuric acid, sodium hydroxide, and sodium and ammonium sulfates and bisulfates, over the range of temperatures of interest. This can then be used to model the chemistry around the water/steam circuit under the chemical regime at any temperature, pH or composition of the boiler water. The allowable impurity concentrations in boiler water can then be calculated from those of the steam and the amounts of mechanical and vaporous carryover.
Previously, the vaporous content (V) of the total carryover was estimated from a distribution ratio diagram (commonly referred to as the “ray” diagram). However, monitoring in numerous plants showed that the “ray” diagram had severe shortcomings and a more rigorous method was required. After over 15 years of research initiated through IAPWS, most of the partitioning constants for the important boiler water compounds have been investigated. Figure 2 shows one such compilation with others being illustrated in references [1] and [2]. At the highest pressures, the vaporous carryover
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can be derived from the partitioning constants of the species using an appropriate set of equations. Manufacturers have their own methods for calculating the vaporous carryover or, because of the complexity of using the partitioning constants and a computer code to implement the equations, they simply use a default of 0.1 %.

5. Description of the Method

A sample of saturated steam is withdrawn through an isokinetic sample nozzle in the connecting links (off-takes) leading from the steam drum to the primary superheater. The steam sample is condensed and the concentration of sodium in the sample is measured. A sample of boiler water from the steam drum is obtained at the same time, and its sodium concentration is also measured. The steam sodium concentration divided by the boiler water sodium concentration represents the total carryover.
The boiler water sample is obtained from the continuous blowdown line that comes from the steam drum. The blowdown water is a fairly homogenous mixture of the feedwater (distributed along the drum length) and the returned water/steam mixture from the evaporator tubes/risers also distributed along the drum length. The fossil boiler steam drum is long and relatively narrow, so mixing hasn't usually been a problem. Drum internals and components can be installed improperly, but these problems are typically discovered and resolved during the commissioning process. Usually there are sampling devices that obtain water/steam samples above and below the water level. These are sometimes (and temporarily) installed in new units to calibrate or resolve problems with water level controllers. These can be used to obtain samples of water that is in more immediate contact with steam, but the difference in the carryover measurements has not been significant enough to warrant the permanent installation of these devices.

6. Use of Sodium to Determine Total Carryover

Sodium salts, such as Na3PO4 and/or NaOH, are used for boiler water treatment (primarily in fossil plants). These have good solubility in boiler water and a low volatility in steam, which makes them suitable tracers for determining the total carryover.
The sodium concentration is typically 1-5 mg/kg (ppm) for phosphate treated boilers and up to 1 mg/kg (ppm) for NaOH treated boilers. These levels are usually sufficient to permit the carryover measurements (primarily an accurate measurement of the trace sodium concentration in the steam), especially if the concentration is maintained toward the higher end of the range. Additional dosing of sodium is not required for boilers operated on NaOH or on phosphate treatments. For boilers on oxygenated treatment (OT) or all-volatile treatment (AVT), pressure-dependent sodium concentration should be stated as the maximum tolerable concentration of sodium in the boiler water. The experience base with these tests is large, mature and comprehensive.
Any hideout or other transient behavior associated with sodium addition should be normalized by performing the tests at stable and fixed operating conditions. In other words, the system is brought to steady-state conditions and then samples are obtained. If concerns arise as to the time lag in obtaining/analyzing samples, other options exist such as obtaining/analyzing samples at close proximity to the steam drum.
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In nuclear steam generators with All-volatile Treatment and low concentrations of alkali in the boiler water, radioactive tracers may be used. A common tracer is Na-24 in the form of Na2CO3 or NaNO3, applied in very low chemical concentration.
Other alkali such as lithium hydroxide could also be used, however there is a lack of information about the volatility of lithium species at high pressures. They would be selected on consideration of a low volatility (vaporous carryover).

7. Sampling

Drum boilers can have several steam purity sample nozzles (up to six off-takes) located in the connecting links between the steam drum and primary superheater inlet. These nozzles can be individually fitted with sample lines and isolation valves. For normal operation, the sample lines typically discharge into a collection header, and pass through a sample cooler to a single monitor in the chemical sampling/instrumentation panel.
The preferred procedure when evaluating steam purity (especially for the first time) is to separate the sample nozzle lines and analyze a sample from each line. The initial performance tests should include a characterization of the carryover behavior. Therefore, saturated steam samples should be obtained at least at each quarter point along the length of the drum. This will also help to establish sampling needs for future tests and requirements for the continuous steam purity sample. This permits the steam purity to be evaluated along the length of the drum, and helps to identify variations that may exist and may be the cause for these variations. A “switched” sampling device that can rotate around the various off-takes will ensure that a false impression is not provided by simply taking samples from only one off-take. Numerous examples exist of steam turbine and boiler feed pump turbine damage in such situations.
The steam nozzles should be designed for isokinetic sampling [3-7]. The nozzle sample flow must be controlled to provide isokinetic conditions at the nozzle inlet. This sample flow rate must be varied to match the steam velocity variation in the saturated steam link with boiler load.

8. Analytical Methods

On-line sodium analyzers for steam and boiler water samples have proven to be successful when sodium salts (or hydroxide) are used for boiler water treatment [7]. It is also possible to analyze by ion chromatography.
In a typical test, the sodium concentration in the boiler water is on the order of 1 to 5 mg/kg (ppm), and the sodium concentration in the steam is typically on the order of 2 to 10 μg/kg (ppb). In some cases, the sodium concentration in steam is as low as 0.4 to 2.0 μg/kg (ppb). In all cases, the sodium level should be in agreement with the pressure-dependent sodium levels in boiler water as specified in the applicable guidelines. Contamination of the samples by contact with ambient air, sample bottle walls, or through manipulation can give erroneous results. The advent of the selective ion electrode has 6
improved the measurement of these low concentrations. The sample can be withdrawn through tubing directly to the measurement station without significant contamination from external sources. A second improvement in the measurement ability is the connection of the measurement station to a PC data acquisition system that displays trends of the concentration with time, permitting the operator to determine that an equilibrium condition was achieved when deciding whether to include data as a test point.
The isokinetic sample flow usually does not match the flow required by a sodium analyzer. Generally, sodium analyzers typically require less sample than an isokinetic nozzle sample can deliver. For this reason, the sodium analyzer should be operated in a by-pass; the sample surplus can be sent to drain.
A second sodium analyzer is required for the boiler water sample from the steam drum. The residence time needs to be calculated for the sample line size and length to determine the drum sample time for water compared to the sample time for the saturated steam sample. These sample times should be within 5 minutes of each other. The sample flow for the boiler water and analyzer are similar to those of the steam sample thus requiring the same arrangement. It is also possible to analyze the sodium in the boiler water by other methods than an on-line analyzer, because the higher concentrations make the sample less susceptible to errors by contamination.

9. Test Procedures

In order to fully characterize the behavior of the boiler, samples should be taken over an extended period. For the first hour after establishment of a new operating condition (load, drum water level, etc.), the data may be subject to transient effects and may not be fully representative. Major changes in carryover can occur at steady load in some boilers; if this is observed, then thorough investigation of the cause will be required. Continuous flow selective ion analyzers will permit an observer to determine the exact flush time requirement. The samples should not be taken for one hour after setting the required boiler operating conditions to permit the unit to reach equilibrium. The sample flow rates should be adjusted to an isokinetic sample flow. If grab samples are used for the measurements, then the blowdown and steam samples should be flowing for at least three hours before the samples are taken.

10. Test Conditions

The performance of the steam drum internals (and total carryover) is primarily dependent on load (steam flow rate), operating pressure and water level. The steam flow rate and pressure affect the fluid velocity and thus the performance of the separators. Carryover is usually fairly low (considerably below design limit) and constant until the steam flow (for a particular design pressure) approaches full load conditions, at which point it begins to increase. This increase is usually progressive, but in some boilers it can occur suddenly and/or intermittently. It is important for the operators to be aware of the drum internals performance as a function of drum water level. An increase in water level above the normal level reduces the height between the water surface and final separators (dryers) thus reducing gravity separation of water droplets from the steam. This can have
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a detrimental effect on the effectiveness of the separators. Mindful of the water level (i.e., low water level) impact on boiler performance, the water level targets for the carryover tests should be selected to be well within safe boundaries established by level control alarms and experience.
A number of aspects about carryover need to be considered: a) a drum may show distinct periods lasting a few hours at a time when serious carryover is occurring, interspersed with periods of acceptable operation; b) small changes of load, burner pattern, or drum water level can all influence the performance of the drum; c) in long, narrow drums it is known that carryover taking place along part of the length can occur; and d) any chemicals present that influence surface tension can have a major effect on the carryover.
The steam purity tests can therefore be performed at various conditions. An example to show the impact of various factors is shown in Table 1. However, for the purpose of determining the design or predicted performance of the steam drum or separator system, the carryover tests should be performed at full load conditions.
Carryover testing conducted between every six and twelve months is a satisfactory interval for boilers not experiencing carryover-related problems. Greatly preferable is to perform continuous measurements using continuous on-line instruments, switched between off-take sampling points, especially during periods when load/pressure changes are occurring.