Amine Physical Properties - Gas Amine Treating Unit

Glycol-Type Gas Dehydration Unit

A natural gas stream can be dehydrated by contacting the gas with glycol. This process (see Figure 1) is normally carried out at an elevated pressure in a vessel called a contactor or absorber. After absorbing the water, the glycol is reconcentrated by boiling off the water at atmospheric pressure in a regenerator. A pump is used to recirculate the glycol to the contactor.

Fig 1: Gas Dehydration Unit

Inlet Scrubber: An inlet scrubber is required, either integral with the contactor or as a separate vessel upstream, to remove free liquids from the gas stream going to the contactor. The mist extractor in this vessel removes larger droplets entrained in the gas.

Contactor: The contactor vessels may be categorized as to the manner in which the absorption process is accomplished. One type uses trays equipped with bubble caps, valves, other devices, to maximize gas-to glycol contact. The action of the gas flowing upward through the glycol layer on each tray creates a froth above the tray, where most of the absorption takes place. The other type of contactor is referred to as a packed tower. It is filled with packing, which has a large surface area per unit volume. Glycol flowing downward wets the entire packing surface. Absorption takes place as the gas flows upward through the packing, contacting the wetted surface. In either type of vessel, a mist extractor removes entrained glycol droplets from the dehydrated gas stream before it leaves the top of the contactor. On larger units, an optional residue gas scrubber may be justified. Rich (wet) glycol is directed from the bottom of the contactor to the regeneration system.

Gas/Glycol Heat Exchanger: Absorption is improved with lower temperature glycol. A gas/glycol heat exchanger is required which uses dehydrated gas to cool the lean (dry) glycol before it enters the top of the contactor.

Regeneration System: The regeneration system consists of several pieces of equipment. If glycol-gas powered pumps are installed, energy from the high pressure rich glycol along with a small amount of gas is used to pump the lean glycol. If an optional reflux coil in the still column is provided, the rich glycol flows through it before entering the glycol/glycol heat exchanger. The glycol/glycol heat exchanger serves two purposes: 1) to cool the lean glycol to a temperature as recommended by the pump manufacturer, and 2) to conserve energy by reducing the heat duty in the reboiler.

Gas-Condensate-Glycol Separator:  A frequently used option in regeneration systems is a gas-condensate glycol separator, and should be included when the inlet gas contains condensate. It may be located upstream or downstream of the glycol/glycol heat exchanger and usually operates at a pressure of 25-75 psig. It removes condensate from the glycol prior to the reboiler, which minimizes coking and foaming problems. The separator also captures flash gas that is liberated from the glycol and exhaust gas from the glycol-gas powered pumps, so that the gas may be used as fuel. Glycol is regulated from the separator to the reboiler by means of a level controller and dump valve. Condensate removal may be controlled automatically or manually.

Reboiler.:Rich glycol enters the reboiler through the stili column. It is then heated to 350-400°F, which causes the water that was absorbed in the contactor to vaporize. The reboiler is usually heated by combustion of natural gas, but may utilize other fuels, steam, hot oil or other heat sources. The regenerated lean glycol gravity feeds from the reboiler, through the glycol/ glycol heat exchanger, and into the pump suction for recirculation back to the contactor. Either electric, gas powered, or glycol-gas powered pumps may be used.

Still Column: Water and glycol vapors from the reboiler enter the bottom of the still column, which is mounted on top of the reboiler. The bottom section contains packing, while the top section of the still column may contain a reflux coil or external fins. Reboiier vapors are cooled and partially condensed to provide reflux, which improves the separation between glycol and water. The remaining water vapor leaves the top of the stili column and vents into the atmosphere.

Filters and Strainers: Regeneration systems contain various types of filters and strainers. A particle filter or fine mesh strainer is required to protect the pump. To reduce foaming, an activated carbon filter may be installed to remove heavy hydrocarbons from the glycol.

Some important factors to be considered on GDU Unit:

Firetube Heat Flux: The average heat flux shall be no higher than 10,000 BTU/hr.-sq. It. of exposed area.

Example: 8%‘‘ O.D. Sch. 20, 0.25” wall fire tube having 25.0 square feet of surface, 51.85 sq. in. cross sectional area and rated at 250,000 BTU/hr. heat duty.

Average Heat Flux = (Firetube Rating (BTU/hr))/ (Sq. Ft. of Firetube Surface) = 250000/25.0 =10,000 BTU/hr-sq. ft

Stack Height: The height of the stack shall be no less than required to provide draft sufficient to overcome the pressure drop in the firetube, flame arrestor, stack, returns. turbulators, dampeners, and stack flame arrestor if provided. The operating site elevation shall be considered in the draft calculations.

Process Considerations:

Inlet Gas Temperature: One of the key design and operating variables of a glycol-type gas dehydration unit is the temperature of the entering wet gas. For operation, this temperature should be maintained between 60°F and 120°F. At lower gas temperatures, glycol on the contactor trays will become very viscous, resulting in reduced tray efficiency, increased pressure drop, and glycol carryover. Higher Temperatures will increase the amount of water vapor to be removed, as well as require very pure lean glycol to meet the dehydration specification. Glycol vaporization losses will also increase at higher gas temperatures.

Gas/Glycol Heat Exchanger: It is important that the glycol entering the contactor be cooled to a 10°F to 30°F above the temperature of the gas stream. This is necessary because the equilibrium conditions between the glycol and the water vapor in the gas are affected by temperature. At higher temperatures, more water vapor will remain in the gas stream. A cooler glycol temperature will decrease the glycol vaporization losses but hydrocarbons may condense in the contactor.

Glycol Reboiler Heat Flux/Temperature:Glycol degradation should be minimized by designing the glycol reboiler firetube with an average heat flux of no higher than 10,000 BTU/hr/ft2. The normal range of heat flux is 6,000 - 10,000 BTU/hr/ftZ. Burner flame pattern and flame length should also be designed to avoid hot spots on the firetube. Bulk temperature for triethylene glycol should not exceed 400°F. The maximum tube wail temperature should not exceed 430°F

Circulation Rates: Typical glycol type gas dehydration units have glycol circulation rates from 2.0 to 3.0 gallons of glycol per pound of water removed- Varies depends on Unit Spec & gas quality.

Glycol Losses: For a properly designed gas dehydration unit during normal operation, the glycol losses should not exceed 0.1 gallon of glycol per million standard cubic feet of gas dehydrated.

GDU- CORROSION CONTROL:

Variables affecting Corrosion Potential: Stream compositions, operating pressure and temperature conditions, and design/fabrication details such as metallurgy, stress, welding procedures and heat treatment all have a part in the corrosion potential of a system. Since carbon steel is the major material of construction for typical glycol-type gas dehydration units, corrosive environments require special considerations.

Stream Compositions. Of primary concern is the presence of acid gases (carbon dioxide- CO, and/or hydrogen sulfide-H,S) and/or oxygen-02 in the flow streams.

Carbon dioxide partial pressures in the gas phase below 3 psia typically do not require corrosion control. Between 3 and 30 psia, some form of corrosion control may be required, such as pH control or inhibitor injection.

Corrosion resistant metals may also be needed. For carbon dioxide (CO,) partial pressures above 30 psia, design/operational corrosion control measures will be required. Hydrogen sulfide (H2S) and oxygen (O2) are corrosive at very low concentrations. In addition to corrosion, hydrogen sulfide (H,S) can lead to sulfide stress cracking (SSC)

INSTALLATION, START-UP, OPERATION AND MAINTENANCE

Installation:

All equipment must be installed on an adequate foundation. The equipment should be as level as possible for the most efficient operation. All items shipped loose should be installed on the unit. This may include the stack, still column, piping between the regenerator and contactor, and the vent line from the still column. Normally the still column vapors are vented directly to the atmosphere.

Vent piping should be kept to a minimum. It should be remembered that these vapors contain combustible hydrocarbons, corrosive components, and water which may condense and freeze. Therefore, consideration must be given to the location  assembled, all screwed and bolted connections should be checked for tightness.

 Start-up:

The unit should be inspected before start-up to make certain that all valves are closed and all regulators are backed off.

All relief valves and critical shutdown devices should be operational. Admit supply gas to the system and open isolation valves under all pressure gauges.

The contactor should be purged with natural gas to eliminate air. It then should be brought up to line pressure and checked for leaks.

Maintain the contactor pressure, but do not flow gas at this point. The flash tanks and piping should also be purged to eliminate air.

Open the cocks on the glycol surge tank level gauge and the valve in the line between the surge tank and the glycol/glycol heat exchanger.

Fill the reboiler with glycol until the level comes about half way up in the surge tank gauge. Allow approximately 25% of the surge tank for thermal expansion of the glycol.

The glycol circulation, including the return to the reboiler from the contactor, should be fully established prior to ignition of the main burner.

Light the pilot light and main burner as recommended. Heat the glycol until it reaches 390°F and set the temperature controller. Continue heating the glycol until it reaches 400°F and set the high temperature shutdown. These temperatures are typical: however, some manufacturers and operators prefer somewhat different temperatures.

Operating conditions can also sometimes require different operating temperatures. It is highly recommended that the glycol never be heated above 400°F because it starts decomposing at 405°F.

The glycol level in the surge tank should be brought to normal after circulation has been established. All gauge cocks should be open and level controls set at this time.

Gas flow may now be started through the contactor. The flow rate should be increased slowly to prevent losing

liquid seals and damage to the trays.

The unit is now ready for final adjustments. This includes checking the reboiler temperature setting, circulation rate, burner adjustment, valve function, level controller function, and glycol level in the sure tank.

It is very important to make sure that steam is coming out of the vapor outlet of the still column. The circulation rate should be in accordance with the process design specification.

Operation:

Routine operation of gas dehydration units primarily involves periodic visits to determine if everything is operating properly.

As a minimum, the following items should be checked:

a. inlet gas temperature and flow rate

b. contactor pressure

c. reboiler temperature

d. pump operation

e. steam from still column

f. level of glycol in surge tank

g. burner flame pattern and firetube appearance.

It is necessary to periodically add glycol to the surge tank because a certain amount of glycol  loss is normal.

Other than that, the units are designed for unattended operation as long as everything is functioning properly.

If the unit is designed for manual dumping of distillate from the reboiler and/or the glycol flash separator, it will be necessary to check these levels during the periodic visits.

There are numerous operating problems that can be encountered with these units. Some of the most common will be discussed here.

Two factors which greatly affect the ability of a unit to dehydrate gas are gas pressure and temperature.

Small changes from design in these variables can have a large effect on the water content of the gas. Gas flow rate has a somewhat smaller effect on equipment performance.

Cold outside air temperatures can render a unit inoperable. It can freeze instruments and controls, and can cause hydrates to form in scrubbers. If a unit is located in an area where this is a problem, precautions should be taken. Examples are heating coils in scrubbers, heating jackets on liquid discharge lines, cold weather shrouds on glycol/glycol heat exchangers, and housing the entire regenerator

Proper operation of a unit depends on the cleanliness of the gas being processed. Many times, it is necessary to install a coalescing filter separator immediately ahead of the unit. This will remove compressor lube oil fog, small solids, distillate, salt, etc. These impurities can plug equipment, coat packing, render the glycol less effective, and coat the firetube which will cause it to burn out.

  

Plugging in the still column or vent line can cause pressure to build up in the reboiler and surge tank. This pressure should be checked periodically. Caution should be used when opening connections: for example, to add glycol.

  

There are ways of removing distillate once it gets into the regeneration system. The surge tank may have a skimmer valve on it by which the distillate can be manually drained. If the glycol flash separator is designed as a three phase vessel, distillate may also be removed from the system at this point.

  

Maintenance:

It is necessary to check the pH of the glycol periodically. It should be a neutral solution. Values that vary from neutral can lessen the ability of the glycol to absorb water, and may cause foaming or corrosion.

The elements in all filters (coalescing, charcoal, sock, regulators, etc.) need to be checked periodically and replaced as necessary.

Pumps require routine maintenance and overhauling.

Dehydration units may become plugged and packing may get a coating buildup. When this happens, it is necessary that the system be thoroughly cleaned.

Steam Trap-Steam Distribution Piping System

A steam trap is an essential element of a steam distribution piping system. As steam flows through a pipe, it cools off due to heat losses and converts into hot water; this hot water is called condensate. The function of a steam trap is to bleed off hot water so that only steam remains in the system. In addition to condensate removal, a steam trap also performs air venting function, thereby increasing the thermal efficiency and reliability of the steam distribution system.

A typical steam trap assembly consists of a number of components which enable the successful operation of the system.

1.       Stop Valves: To control (stop or allow) the steam flow through the system.
2.       Strainer: To remove debris from the steam; if debris is not removed, it might damage the trap.
3.       Check Valve: It stops the condensate from flowing back to the system.
4.       Trap: To catch water and allow the steam to flow through.

In normal practice, strainer and check valves are built in with the steam trap. 

·         Under normal operation, bypass stop valve remains closed and the other two stop valves remain open. Steam flows through the trap, where condensate is removed and drained while the steam returns to the steam mains. In some plants, condensate is recovered and returned to the boiler feed water tank. This results in significant savings in terms of energy and water usage.

Measuring Hydrocarbon Dew Point of Natural Gas Fuel for Gas Turbine

Natural gas is used by a number of industries, most notably in power generation by gas turbines.

Gas turbine manufacturers will always provide specifications defining the quality of the natural gas fuel provided to the turbine - designed to prevent damage to the turbine and the additional problems that can result. These specifications can include a number of parameters, including pressure, flow, acceptable contaminant limits and gas temperature – frequently with the inclusion of the term ‘superheat’.

When operating modern DLN (Dry low NOx) turbines, the following of these guidelines is critical to avoiding severe damage to the turbine, and criteria such as superheat have been set up to help prevent this. Superheat is defined as the temperature 50°F (28°C) above the Hydrocarbon and water Dew Points of the fuel gas, so if the dew point of the gas is -12°C, then the gas should be heated to +10°C.

Prior to combustion, the gas is running at pipeline pressure, much too great for the gas turbine, therefore the gas must be expanded in order to be suitable for use. As the pressure of the gas drops, so does the temperature. If this Joule- Thompson effect drops the temperature below the HCDP, then liquids will condense inside the burner tubes of the turbine and the cans and nozzles coke up and become significantly less efficient, causing dramatically increased NOx emissions. If this situation is allowed to continue for a short time, the burner section will need to be rebuilt. This means a 3-5 day unplanned shut-down, a large crew on-site around the clock for the expensive rebuild and lost revenue and plant availability. This will dramatically impact the profitability of the plant.

Another seriously costly effect of condensation is flashback. This can be caused by hydrocarbon condensates, and the effect is for a flame to be held downstream of the burners, in the recirculation area. This region is not designed to withstand heat of this nature, and the metal temperatures will increase dramatically, frequently causing physical damage to the hardware.

Superheat is designed to help prevent either of these occurrences by ensuring that the gas never comes close to its HCDP. Natural gas fuel conditioning systems are most commonly used to heat the incoming gas, but this heat requires energy to generate, and if overheating due to a lack of awareness of the gas dew point occurs, then large costs can be incurred.

Measurement Techniques:

There are a number of different accepted methods for measuring HCDP,

1) The original technique being to use a cooled mirror dewscope. This requires a skilled operator to view a mirror over which the sample is flowed. The mirror is then cooled, and the temperature at which the first drops of condensation are viewed is noted.

2) Another method of determining the HCDP is by means of a gas chromatograph (GC). This method determines the concentrations of each hydrocarbon element (up to C12 in most cases), and, through an equation of state calculation, the condensing points of the quantities of each component present are identified and calculated to give a hydrocarbon dew point for the complete mixture. However, due to the limitations of the device, when analysing heavy hydrocarbon molecules the calculations of the HCDP can frequently be quite inaccurate, suggesting that the HCDP is drier than the actual value.

3) The alternative is to use an automatic, optical condensation dew-point analyser, such as the Michell Instruments Condumax II, Ametek. These devices functions in a similar manner to the Cooled mirror dewscope. The cell has an etched optical surface with a central conical depression which normally refracts light unevenly. An LED shines at this surface and a photo-detector looks at an image of the light shining back, which in dry conditions, appears as a ring of light. The photo-detector is focused on the light scattered into the centre of the ring. A thermoelectric peltier device cools the surface until condensates begin to appear. The condensates alter the reflective properties of the surface, with the circle of light around the perimeter intensifying, and the scattered light in the centre dispersing according to the amount of condensate on the mirror. The exact signal level can be accurately monitored by looking at the signal from the photodetector. The mirror temperature is recorded when the desired level of condensates are deposited. The setting of the device gives readings which are comparable to readings obtained by an experienced dewscope operator.

Centrifugal Pumps: Understanding Cavitation

Centrifugal Pumps: Understanding Cavitation

Operating a pump under the condition of cavitation for even a short period of time can have damaging consequences for both the equipment and the process.

 Continuous operation of centrifugal pumps at low flows i.e. reduced capacities, leads to a number of unfavorable conditions. These include reduced motor efficiency, excessive radial thrusts, excessive temperature rise in the pumping fluid, internal re-circulation, etc. A certain minimum continuous flow (MCF) should be maintained during the pump operation.

The condition of cavitation is essentially an indication of an abnormality in the pump suction system.

Cavitation is a common occurrence but is the least understood of all pumping problems. Cavitation means different things to different people. Some say when a pump makes a rattling or knocking sound along with vibrations, it is cavitating. Some call it slippage as the pump discharge pressure slips and flow becomes erratic. When cavitating, the pump not only fails to serve its basic purpose of pumping the liquid but also may experience internal damage, leakage from the seal and casing, bearing failure, etc.

In the context of centrifugal pumps, the term cavitation implies a dynamic process of formation of bubbles inside the liquid, their growth and subsequent collapse as the liquid flows through the pump.

Generally, the bubbles that form inside the liquid are of two types: Vapor bubbles or Gas bubbles.

Vapor bubbles are formed due to the vaporization of a process liquid that is being pumped. The cavitation condition induced by formation and collapse of vapor bubbles - Vaporous Cavitation.

Gas bubbles are formed due to the presence of dissolved gases in the liquid that is being pumped (generally air but may be any gas in the system)-Gaseous Cavitation.

Both types of bubbles are formed at a point inside the pump where the local static pressure is less than the vapor pressure of the liquid (vaporous cavitation) or saturation pressure of the gas (gaseous cavitation).

Vaporous cavitation is the most common form of cavitation found in process plants. Generally it occurs due to insufficiency of the available NPSH or internal recirculation phenomenon. It generally manifests itself in the form of reduced pump performance, excessive noise and vibrations and wear of pump parts.

Gaseous cavitation occurs when any gas (most commonly air) enters a centrifugal pump along with liquid. A centrifugal pump can handle air in the range of ½ % by volume. If the amount of air is increased to 6%, the pump starts cavitating.

Mechanism of Cavitation :

The phenomenon of cavitation is a stepwise process as shown in Figure 

The bubbles form inside the liquid when it vaporises i.e. phase change from liquid to vapor. But how does vaporization of the liquid occur during a pumping operation?

Vaporization of any liquid inside a closed container can occur if either pressure on the liquid surface decreases such that it becomes equal to or less than the liquid vapor pressure at the operating temperature, or the temperature of the liquid rises, raising the vapor pressure such that it becomes equal to or greater than the operating pressure at the liquid surface. For example, if water at room temperature (about 77 °F) is kept in a closed container and the system pressure is reduced to its vapor pressure (about 0.52 psia), the water quickly changes to a vapor. Also, if the operating pressure is to remain constant at about 0.52 psia and the temperature is allowed to rise above 77 °F, then the water quickly changes to a vapor.

Just like in a closed container, vaporization of the liquid can occur in centrifugal pumps when the local static pressure reduces below that of the vapor pressure of the liquid at the pumping temperature.

Valve Sizing and Selection

Valve Sizing and Selection

Sizing flow valves is a science with many rules of thumb that few people agree on. In this article I'll try to define a more standard procedure for sizing a valve as well as helping to select the appropriate type of valve. **Please note that the correlation within this article is for turbulent flow.

Step #1: Define the System

The system is pumping water from one tank to another through a piping system with a total pressure drop of 150 psi. The fluid is water at 70 °F. Design (maximum) flowrate of 150 gpm, operating flowrate of 110 gpm, and a minimum flowrate of 25 gpm. The pipe diameter is 3 inches. At 70 °F, water has a specific gravity of 1.0.

Key Variables: Total pressure drop, design flow, operating flow, minimum flow, pipe diameter, specific gravity

Step #2: Define a maximum allowable pressure drop for the valve

When defining the allowable pressure drop across the valve, you should first investigate the pump.  What is its maximum available head? Remember that the system pressure drop is limited by the pump. Essentially the Net Positive Suction Head Available (NPSHA) minus the Net Positive Suction Head Required (NPSHR) is the maximum available pressure drop for the valve to use and this must not be exceeded or another pump will be needed. It's important to remember the trade off, larger pressure drops increase the pumping cost (operating) and smaller pressure drops increase the valve cost because a larger valve is required (capital cost). The usual rule of thumb is that a valve should be designed to use 10-15% of the total pressure drop or 10 psi, whichever is greater. For our system, 10% of the total pressure drop is 15 psi which is what we'll use as our allowable pressure drop when the valve is wide open (the pump is our system is easily capable of the additional pressure drop).

Step #3: Calculate the valve characteristic

For our system:

At this point, some people would be tempted to go to the valve charts or characteristic curves and select a valve. Don't make this mistake, instead, proceed to Step #4!

Step #4: Preliminary valve selection

Don't make the mistake of trying to match a valve with your calculated Cv value. The Cv value should be used as a guide in the valve selection, not a hard and fast rule. Some other considerations are:

a. Never use a valve that is less than half the pipe size
b. Avoid using the lower 10% and upper 20% of the valve stroke. The valve is much easier to control in the 10-80% stroke range.

Before a valve can be selected, you have to decide what type of valve will be used (See the list of valve types later in this article). For our case, we'll assume we're using an equal percentage, globe valve (equal percentage will be explained later). The valve chart for this type of valve is shown below. This is a typical chart that will be supplied by the manufacturer (as a matter of fact, it was)

For our case, it appears the 2 inch valve will work well for our Cv value at about 80-85% of the stroke range. Notice that we're not trying to squeeze our Cv into the 1 1/2 valve which would need to be at 100% stroke to handle our maximum flow. If this valve were used, two consequences would be experienced: the pressure drop would be a little higher than 15 psi at our design (max) flow and the valve would be difficult to control at maximum flow. Also, there would be no room for error with this valve, but the valve we've chosen will allow for flow surges beyond the 150 gpm range with severe headaches!

So we've selected a valve...but are we ready to order? Not yet, there are still some characteristics to consider.

Step #5: Check the Cv and stroke percentage at the minimum flow

If the stroke percentage falls below 10% at our minimum flow, a smaller valve may have to be used in some cases. Judgments plays role in many cases. For example, is your system more likely to operate closer to the maximum flow rates more often than the minimum flow rates  Or is it more likely to operate near the minimum flow rate for extended periods of time. It's difficult to find the perfect valve, but you should find one that operates well most of the time. Let's check the valve we've selected for our system:

Referring back to our valve chart, we see that a Cv of 6.5 would correspond to a stroke percentage of around 35-40% which is certainly acceptable. Notice that we used the maximum pressure drop of 15 psi once again in our calculation. Although the pressure drop across the valve will be lower at smaller flow rates  using the maximum value gives us a "worst case" scenario. If our Cv at the minimum flow would have been around 1.5, there would not really be a problem because the valve has a Cv of 1.66 at 10% stroke and since we use the maximum pressure drop, our estimate is conservative. Essentially, at lower pressure drops, Cv would only increase which in this case would be advantageous.

Step #6: Check the gain across applicable flow rates

Gain is defined as:

Now, at our three flowrates:
Q_min = 25 gpm
Q_op = 110 gpm
Q_des = 150 gpm

we have corresponding Cv values of 6.5, 28, and 39. The corresponding stroke percentages are 35%, 73%, and 85% respectively. Now we construct the following table:

Flow (gpm)	Stroke (%)	Change in flow (gpm)	Change in Stroke (%)
25	35	110-25 = 85	73-35 = 38
110	73
150	85	150-110 = 40	85-73 = 12

Gain #1 = 85/38 = 2.2
Gain #2 = 40/12 = 3.3

The difference between these values should be less than 50% of the higher value. 0.5 (3.3) = 1.65 and 3.3 - 2.2 = 1.10. Since 1.10 is less than 1.65, there should be no problem in controlling the valve. Also note that the gain should never be less than 0.50. So for our case, I believe our selected valve will do nicely!

Other Notes

Another valve characteristic that can be examined is called the choked flow. The relation uses the FL value found on the valve chart. I recommend checking the choked flow for vastly different maximum and minimum flowrates. For example if the difference between the maximum and minimum flows is above 90% of the maximum flow, you may want to check the choked flow. Usually, the rule of thumb for determining the maximum pressure drop across the valve also helps to avoid choking flow.

Selecting a Valve Type

When speaking of valves, it's easy to get lost in the terminology. Valve types are used to describe the mechanical characteristics and geometry (Ex/ gate, ball, globe valves). We'll use valve control to refer to how the valve travel or stroke (openness) relates to the flow:

1. Equal Percentage: equal increments of valve travel produce an equal percentage in flow change
2. Linear: valve travel is directly proportional to the valve stoke
3. Quick opening: large increase in flow with a small change in valve stroke

So how do you decide which valve control to use? Here are some rules of thumb for each one:

1. Equal Percentage (most commonly used valve control)

a. Used in processes where large changes in pressure drop are expected

b. Used in processes where a small percentage of the total pressure drop is permitted by the valve

c. Used in temperature and pressure control loops

2. Linear

a. Used in liquid level or flow loops

b. Used in systems where the pressure drop across the valve is expected to remain fairly constant (ie. steady state systems)

3. Quick Opening

a. Used for frequent on-off service

b. Used for processes where "instantly" large flow is needed (ie. safety systems or cooling water systems)

Now that we've covered the various types of valve control, we'll take a look at the most common valve types.

Gate Valves:

Best Suited Control: Quick Opening

Recommended Uses:

1. Fully open/closed, non-throttling 2. Infrequent operation 3. Minimal fluid trapping in line

Applications: Oil, gas, air, slurries, heavy liquids, steam, noncondensing gases, and corrosive liquids

Advantages:

1. High capacity , 2. Tight shutoff  3. Low cost  4. Little resistance to flow

Disadvantages:

1. Poor control, 2. Cavitate at low pressure drops, 3. Cannot be used for throttling

Globe Valves

Best Suited Control: Linear and Equal percentage

Recommended Uses:

1. Throttling service/flow regulation 2. Frequent operation

Applications: Liquids, vapors, gases, corrosive substances, slurries

Advantages:

1. Efficient throttling  2. Accurate flow control  3. Available in multiple ports

Disadvantages:

1.High pressure drop 2. More expensive than other valves

Ball Valves:

Best Suited Control: Quick opening, linear

Recommended Uses:

1. Fully open/closed, limited-throttling 2. Higher temperature fluids

Applications: Most liquids, high temperatures, slurries

Advantages:

1. Low cost  2. High capacity  3. Low leakage and maint. 4. Tight sealing with low torque

Disadvantages:

1. Poor throttling characteristics 2. Prone to cavitation

Butterfly Valves:

Best Suited Control: Linear, Equal percentage

Recommended Uses:

1. Fully open/closed or throttling services 2. Frequent operation 3. Minimal fluid trapping in line

Applications: Liquids, gases, slurries, liquids with suspended solids

Advantages:

1. Low cost and maint.  2. High capacity  3. Good flow control 4. Low pressure drop

Disadvantages:

1. High torque required for control 2. Prone to cavitation at lower flows

Other Valves

Another type of valve commonly used in conjunction with other valves is called a check valve. Check valves are designed to restrict the flow to one direction. If the flow reverses direction, the check valve closes. Relief valves are used to regulate the operating pressure of incompressible flow. Safety valves are used to release excess pressure in gases or compressible fluids.

 References

Rosaler, Robert C., Standard Handbook of Plant Engineering, McGraw-Hill, New York, 1995, pages 10-110 through 10-122

Purcell, Michael K., "Easily Select and Size Control Valves", Chemical Engineering Progress, March 1999, pages 45-50