Control Valve Position Instability

Total control valve stem position mechanical stability is the total absence of valve stem movement when the signal to the actuator is constant. Position instability that is valve stem movement is not an absolute phenomenon. It occurs in many control valves to some degree. In most applications where it exists it is not noticeable or does not exceed the acceptable limit for the application.

Measure the maximum amplitude of the unstable motion when the signal to the actuator is constant. The amplitude measurement technique may be that which is deemed appropriate for the application such as a linear scale dial-indicator or motion transducer.

To determine the instability percentage use the following equation to calculate the percentage of the rated valve travel that is unstable:

Instability Percentage = (Maximum unstable motion amplitude*100)/ (Rated travel)

Example:

Rated Travel = 50 mm

Unstable Motion Amplitude = 2.5 mm

Instability Percentage= (2.5 *100)/ 50  = 5

Pump Cavitation Q & A

Q: Cavitation is typically classified into two general categories – inertial and noninertial cavitation. What is the difference between inertial and noninertial cavitations?

A: Cavitation in general terms is used to describe the behavior of voids or bubbles in liquid. Any time a flowing liquid falls below its vapor pressure, vapor bubbles can form. If the flowing liquid is then subjected to pressures above the vapor pressure, these bubbles can implode causing damage, which is called cavitation. Cavitation is usually divided into two classes of behavior: inertial (or transient) cavitation, and noninertial cavitation. Inertial cavitation is the process where a void or bubble in a liquid rapidly collapses, producing a shock wave. Noninertial cavitation is the process in which a bubble in a fluid is forced to oscillate in size or shape due to some form of energy input, such as an acoustic field.

Q: What are the typical causes of cavitation in and around pumping systems? What are the typical end results of cavitation in pumping systems?

A: The cause of cavitation in pumps is usually due to insufficient NPSH (Net Positive Suction Head) energy on the suction side of the pump. NPSH is the energy required to push the liquid into the pump. This can be caused by:

             Having the pump at too high of a distance above the fluid source

             Having too small of a diameter of suction pipe

             Having too long of a distance of suction pipe

             Having too many fittings on the suction pipe

             Handling a liquid with a low vapor pressure

             Running the pump too fast.

The end result of cavitation is the collapse of the vapor bubbles inside the pump, which can cause several problems. The first problem is a reduction in the pumping capacity of the pump. If the pump is unable to keep up with the incoming flow, then an overflow situation may occur. Cavitation also causes damage to the pump. The collapsing vapor bubbles can cause excessive vibration, which can cause rotating parts, such as the impeller, to contact non-rotating parts, such as the wear plates or wear rings, causing damage. Excessive vibration may also cause premature failure to mechanical seals and bearings. Cavitation can also damage the wetted components themselves from contact with the imploding vapor bubbles. In these instances, the energy that is released when the vapor bubbles implode causes pieces of the metal to break off and collide with other moving parts. The damage typically occurs to the impeller and can severely reduce the operating life of the pump. The collapse of vapor bubbles inside a pump can cause severe cavitation damage on the impeller, resulting in negative process conditions such as vibration, decreased flow, and noise.

Q: What are some common warning signs that may signal the end-user that their pumping system is experiencing cavitating conditions?

A: If the pump is cavitating, it will typically vibrate, deliver less flow and make a noise that sounds like marbles going through the pump. The sound may start out at a low level and increase in intensity over time as material is chipped away and the surface of the parts becomes rougher. This is due to the additional energy required by the drag (friction) on the fluid from contacting the rough internal surfaces of the pump.

Cavitation is often confused with another phenomenon called air entrainment. Air entrainment occurs when air is allowed to enter the pump on the suction side and expands as it enters the impeller eye. This can often reduce the flow of the pump and cause vibration from disrupting the laminar flow stream through the pump. Air entrainment can cause similar damage to bearings and seals. Unlike cavitation, however, this problem can be easily remedied by simply identifying air leaks and fixing them.

An interesting point about cavitation and air entrainment is that some experienced pump users have actually injected small amounts of air into pumps that were cavitating to attempt to stop cavitation. By injecting air into a pump that is cavitating, the air bubbles cushion the impact of the imploding vapor bubbles and reduce the NPSHr of the pump, thus lessening the cavitation. This technique, however should only be used by skilled pump technicians, as too much air can cause priming problems and further  adding air typically reduces the pump’s capacity, which could cause an overflow condition.

Q: Why is cavitation so prevalent in and around the pumping system as compared to other segments of the process line? What other segments of the process line are particularly susceptible to cavitating conditions?

A: Cavitation frequently occurs in pumps because of the varying pressures in pumps. Centrifugal pumps operate from the principle of creating a low pressure at the eye (center) of the impeller, and atmospheric pressure forces the fluid to the eye to fill the void. As the fluid approaches the eye of the impeller, the pressure drops, and if the pressure drops below the vapor pressure of the particular liquid, it will boil and cause vapor bubbles to form. As the fluid leaves the impeller eye, it is now exposed to higher pressures (due to the rotation of the impeller inside the casing), which can rise above the vapor pressure of the liquid, causing the vapor bubbles to implode.

Cavitation can also occur in valves where the pressure drops suddenly and there is a chance for the fluid to drop below its vapor pressure. This can often occur in throttling type valves, such as gate valves or ball valves. If the pressure differential from one side of the valve to the other becomes too great, the fluid can vaporize across the valve and implode on the downstream side of the valve. The way to avoid cavitation in valves is to size them properly for the proper velocities. Valves are typically sized for velocities less than 15 feet per second to avoid the possibility of cavitation.

Q: What are some common best practices end-users can employ to prevent cavitation in and around their pumping systems?

A: Always calculate the NPSHa (Net Positive Suction Head available) from the system, and compare it with the NPSHr (Net Positive Suction Head required) by the pump. The NPSHa should always be one to two feet above the NPSHr of the pump to prevent cavitation.

The NPSHr is a function of the pump design and cannot be changed. The NPSHa is a function of the system parameters and can be changed. Included in the NPSHa is the atmospheric pressure, vapor pressure of the liquid being pumped, static height from the water level to the pump, and friction losses. The atmospheric pressure is related to the altitude. At higher altitudes, the atmospheric pressure is less and subsequently there is not as much energy available to push the liquid into the pump. The vapor pressure varies by the type of liquid and the temperature of the liquid. If the liquid is allowed to cool before the pump, it can often be pumped easier. Regarding the static height from the fluid level to the pump, it is often possible to move the pump closer to the fluid to increase the NPSHa. To reduce the friction losses, larger diameter pipes can often be employed to increase the NPSHa and thus prevent cavitation.

If it is not possible to increase the NPSHA as described above, then the pump user should search for a larger pump or pump that runs at a lower speed with lower NPSHr.

Q: From a technology perspective, are there any systems end-users can employ to help them more effectively diagnose and mitigate cavitation in and around their pumping systems?

A: The most effective solution is to listen to the pump and to evaluate the flow. Flow can best be determined using flowmeters, and there are several types commercially available, depending on the type of fluid being moved. Listening to the pump can be accomplished by the naked ear by trained personnel or by using suitable noise level meters. More sophisticated vibration measuring equipment can also be employed to detect cavitation. These portable devices can connect to the pump bearing housings to detect movement (displacement).

Q: How were these cavitation issues resolved? 


A: Among the most common applications that are susceptible to cavitation are applications that have high-suction lifts with little-to-no discharge heads, as is the case with bypassing sewage from manholes. In these applications, the duty point does not fall on the typical performance curve because there is insufficient discharge pressure. In these applications, it is called operating “too far to the right of the curve.” The way to fix this is to put artificial pressure on the discharge of the pump. This can be accomplished by using smaller-diameter discharge hose or placing a throttling valve in the discharge line.

Combustion Equation - Air to Fuel Ratio / Gaseous Fuels

      Applications of the Combustion Equation

(1)          Stoichiometric proportions for finding the correct air supply rate for a fuel
(2)          Composition of the combustion products is useful during the design, 

               commissioning and routine maintenance of a boiler installation

On site measurements of flue gas composition and temperature are used as a basis for calculating the efficiency of the boiler at routine maintenance intervals.

   Combustion Air Requirements: Gaseous Fuels

Calculating the air required for gaseous fuels combustion is most convenient to work on a volumetric basis.The stoichiometric combustion reaction of methane is: 

CH₄ + 2O₂ → CO₂ + 2H₂O

which show that each volume (normally 1 m³) of methane requires 2 volumes of oxygen to complete its combustion.

•          If we ignore the components which are present in the parts per million range, air consists of about 0.9% by volume argon, 78.1% nitrogen and 20.9% oxygen (ignoring water vapor). Carbon dioxide is present at 0.038%.

•          For the purposes of combustion calculations the composition of air is approximated as a simple mixture of oxygen and nitrogen: oxygen 21% , nitrogen79%

•          The complete relationship for stoichiometric combustion:

CH₄ + 2O₂ + 7.52N₂ → CO₂ + 2H₂O +7.52N₂ 

       as the volume of nitrogen will be 2×79÷21=7.52.

•          A very small amount of nitrogen is oxidized but the resulting oxides of nitrogen (NO_X) are not formed in sufficient quantities to concern us here. However, they are highly significant in terms of air pollution.

•          It can be seen that the complete combustion of one volume of methane will require (2+7.52=9.52) volumes of air, so the stoichiometric air-to-fuel (A/F) ratio for methane is 9.52.

•          In practice it is impossible to obtain complete combustion under stoichiometric conditions. Incomplete combustion is a waste of energy and it leads to the formation of carbon monoxide, an extremely toxic gas, in the products.

      Excess air is expressed as a percentage increase over the stoichiometric requirement and is defined by: 

•   Excess air will always reduce the efficiency of a combustion system.

         It is sometimes convenient to use term excess air ratio, defined as:

Where sub-stoichiometric (fuel-rich) air-to-fuel ratios may be encountered, for instance, in the primary combustion zone of a low-NO_X burner, the equivalence ratio is often quoted. This is given by:  

Flue Gas Composition-Gaseous Fuels

•          The composition of the stoichiometric combustion products of methane is:

 1             volume CO₂
7.52        volumes  N₂
2              volumes H₂O

•          Given a total product volume, per volume of fuel burned, of 10.52 if water is in the vapor phase, or 8.52 if the water is condensed to a liquid.

The two cases are usually abbreviated to “wet” and “dry”.

•          The proportion of carbon dioxide in this mixture is therefore

•          The instruments used to measure the composition of flue gases remove water vapor from the mixture and hence give a dry reading, so the dry flue gas composition is usually of greater usefulness.     

                     

Considering the combustion of methane with 20% excess air, the excess air (0.2×9.52) of 1.9 volumes will appear in the flue gases as (0.21×1.9)=0.4 volumes of oxygen and (1.9-0.4)=1.5 volumes of nitrogen

•          The complete composition will be:

            constituent                        vol/vol methane
                CO₂                                        1
                O₂                                           0.4
                N₂                                           9.02
                H₂O                                        2

giving a total product volume of 12.42 (wet) or 10.42 (dry).

•          The resulting composition of the flue gases, expressed as percentage by volume, is:

       Constituent     % vol (dry)     % vol (wet)
                CO₂           9.6                     8.1
                O₂              3.8                    3.2
                N₂             86.6                  72.6
                H₂O           –                       16.1

•          Example :

A gas consists of 70% propane (C₃H₈) and 30% butane (C₄H₁₀) by volume. Find:

(a) The stoichiometric air-to-fuel ratio and
(b) The percentage excess air present if a dry analysis of the combustion products shows 9% CO₂ (assume complete combustion).

Solution:

The combustion reactions for propane and butane are

(a) Stoichiometric Air Requirement

On the basis of 1 volume of the fuel gas, the propane content requires 0.7 × (5 + 18.8) = 16.7 vols air and the butane requires0.3 × (6.5 + 24.5) = 6.3 vols air. Hence the stoichiometric air-to-fuel ratio is 23:1.

  

(b) Excess Air
                The combustion products (dry) will contain

                (0.7 × 3) + (0.3 × 4) = 3.3 vols CO₂
                (0.7 × 18.8) + (0.3 × 24.5) = 20.5 vols N₂

                plus υ volumes excess air, giving a total volume of products of (23.8 + υ ).

Given that the measured CO₂ in the products is 9%, we can write: 

•          hence   υ  = 12.87 vols

The stoichiometric air requirement is 23 vols so the percentage excess air is:  55.9 %

Calculation of Power Required For Pumping

Flow Rate , Q= 83.33 kg/sec

Density of Medium, l= 1000kg/m3

Pump Head Required, H= 25m

Pump Efficency, η=0.75

Pump Power Required, P = (Flow Rate *Required Pump Head)/(Efficiency) 

=(83.33*25)/0.75  =2777.667 kg m/sec  =37.00 hp

HCDP (HYDROCARBON DEW POINT)

Principles of Hydrocarbon Dew Point

Dew point is defined as the temperature at which vapor begins to condense. We see it in action every foggy morning. Air is cooled to its water dew point and the water starts condensing and collects into small droplets. We also see it demonstrated by a cold glass "sweating" on a humid day. The cold glass lowers the air temperature below the water dew point temperature and the water condenses on the sides of the cold glass. Water dew point is relatively simple and easy to predict since it is a single component system. It is easily removed using conventional techniques, primarily TEG (Triethylene Glycol) dehydration units.

Hydrocarbon dew point (HDP) is similar to the water dew point issue, except that we have a multi-component system. Natural gas typically contains many liquid hydrocarbon components with the heavier components found in smaller amounts than the lighter gaseous ends. It is the heaviest weight components that first condense and define the hydrocarbon dew point temperature of the gas. The dew point temperature also moves in relation to pressure.

One of the first questions we are asked by producers with a hydrocarbon dew point issue is:

"How can my hydrocarbon dew point be so high?"

By definition, a production separator separating oil from gas operates at vapor-liquid equilibrium. Therefore, the gas leaving the separator is in equilibrium with the oil. In other words, the gas leaving the separator is at its hydrocarbon dew point that equals the separator operating temperature (and pressure.) If the separator is operating at 100°F, then the gas has a 100°F dew point at separator pressure. As the gas leaves the separator and cools flowing through the piping system, liquids condense and the dew point decreases as the heavy ends condense. The TEG dehydration unit will remove some heavy hydrocarbons, in addition to water, and further reduce the hydrocarbon dew point. At the sales meter, (without a conditioning unit) the hydrocarbon dew point is usually close to the lowest temperature the gas has achieved on the location before it was sampled, at operating pressure.

Why Control Hydrocarbon Dew Point?

The gas transportation companies have come to the realization that managing hydrocarbon dew point reduces system liabilities, opens up new gas markets and generates operating revenue. By managing hydrocarbon dew point, hydrocarbon condensation can be prevented in cold spots under rivers and lakes where the liquids collect in the low areas and then often move as a slug through the system, over pressuring the pipe, and overpowering liquid handling facilities, flowing into compressors and end user sales points.

Most importantly, liquids in burners and pilots onsite and at end user locations, can cause fire and explosion hazards. Also, removing pipeline liquids helps prevent pipe corrosion in the low areas where water is trapped under the hydrocarbon liquid layer and slowly destroys the pipe integrity. Proper managing of gas dew point can also prevent liquids from forming as the gas cools while flowing through pressure reduction stations that feed end user supply systems. Controlling dew point is also necessary to qualify the pipeline to market gas to high efficiency gas turbine end users that require a dry and consistent quality fuel.

Specifications for HDP

Pipelines use two main methods to specify contractual natural gas hydrocarbon dew points.

1.     Limit on C5+ or C6+ components by analyzing for:

o    GPM (gallons of liquid per thousand SCF)

o    Mole %

2.     Specifying an actual HDP by:

o    Setting a hydrocarbon dew point temperature maximum at operating pressure

o    Setting a maximum cricondentherm hydrocarbon dew point

In addition, typical pipeline specifications or tariffs almost always specify a maximum GHV (Gross or Higher Heating Value), which is greatly affected by heavy hydrocarbons contained in the gas stream.

Cricondentherm Temperature

The cricondentherm temperature is the highest dew point temperature seen on a liquid-vapor curve for a specific gas composition over a range of pressure, e.g. 200-1400 psia. When you look at a hydrocarbon gas dew point temperature curve (phase envelope,) the curve bends with pressure. Shown below is a dew point curve, after conditioning, for a south Texas gas analysis. The transporting pipeline requires a 20°F cricondentherm temperature. At the time this sample was taken, the cold separator on the gas conditioning equipment was operating at 9°F and 875 psig.

Hydrocarbon Gas Dew Point Curve

The temperature shown in the HDP curve represents the gas dew point at the corresponding pressures.

A cricondentherm specification at first seems like the best way a pipeline can protect its assets. The transporting pipeline operator knows if it sets a cricondentherm temperature restriction below the lowest temperature seen in its system, it can raise and lower the gas pressure in the pipeline transportation system, and not have to worry about liquid condensation.

The problem a pipeline operator has in using a cricondentherm specification is in the calculation of the cricondentherm temperature. The cricondentherm temperature is calculated by obtaining an extended gas analysis and then inputting the analysis data into a software package, using equations of state to predict the dew point temperatures at the range of pressures.

However, many gas-transporting companies tend to collect gas composition data using on-line chromatographs or composite samples with a grouped C6+ component. The C6+ component does not provide any information on the heavier hydrocarbon (C7+) components that determine the gas hydrocarbon dew point. To calculate a cricondentherm the pipeline operator must make some assumptions. It is these assumptions that are causing problems. The pipeline operator must decide how to distribute the C6+ component for his calculation. The most commonly used distribution assumptions are the Daniels/El Paso distribution (i.e. 48% C6; 35% C7; 17% C8+) and the GPA distribution (i.e. 60% C6, 30% C7, 10% C8+).

Gas Processing- Rich/Lean Amine Loading

Rich/Lean Amine Loading - Amine loading, the amount of acid gases contained within a given amount of amine is critical in the operation, maintenance and performance of an amine plant.

Rich Amine Loading (RAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Contactor. This is typically represented in a mol ratio ((mol of CO2 + mol H2S)/mol amine). Generally speaking, this measurement is almost impossible to accurately measure in the field or in a lab so plant simulations are often times used to determine the RAL and adjust amine circulation rates and concentrations to meet desired results.

As RAL increases above a value of 0.40 mol AG/mol amine, several detrimental effects may be encountered  especially in an all CO2 acid gas system. These effects may include higher corrosion rates, higher temperature bulges within the Contactor and lower recovery of the acid gases due to slower reaction kinetics and capacity.

Thus, if the Rich Amine Loading exceeds recommended limits acid gas breakthrough may occur, process piping may erode/corrode (resulting in piping failures) and equipment may fail. For these reasons it is recommended employing stainless steel materials in the most critical areas of the plant.

Lean Amine Loading (LAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Regenerator and is measured in the same manner as the RAL described above. This is a much easier and more reliable measurement.

LAL values will vary, depending on the type of amine being used. For MEA which is one of the most corrosive amines a LAL of up to 0.15 mol/mol may be seen while in an MDEA system (one of the weakest and least corrosive amines) a LAL of 0.005 mol/mol is not uncommon.

Lean Amine Loading will be affected by the reboiler duty, reflux ratio and the number of fractionation stages within the Amine Still. If the lean amine is not properly maintained, the acid gases corrosion may be encountered in the hot portions of the plant specifically the Amine Still Reboiler and associated piping. Also if the LAL is too high, the ability of the amine to remove the acid gases from the inlet gas stream in the Amine Contactor may be diminished and product specifications may not be met. This is especially true of MDEA systems that try to meet a very low level H2S specification.

Therefore, when designing and operating an amine plant care should be given to making sure the system is large enough to avoid overloading the amine with acid gases (high RAL) and ensuring that the amine regenerator has sufficient capabilities to properly strip the acid gases from the amine (low LAL).

The Tank Blanketing Technique

Tank blanketing, also known to as tank padding, is the procedure of smearing a gas to the empty space in a storage tank or container (the term storage container refers to any container that is used to store products, regardless of its size). This techinique is used for a variety of reasons and typically involves using a buffer gas to protect products inside the storage container. Some of the benefits of blanketing include a longer life of the product in the container, reduced hazards, and longer equipment life.

Control board Pressure regulator Flow switch Magnetic level control Pressure / Vacuum Relief Valve

History

Appalachian Controls Environmental (ACE) in In 1970 was the first company to announce a tank blanketing valve. There are now many ready-made systems available for acquisition from a diversity of process equipment companies. It is also possible to piece together your own system using a variety of different equipment. Regardless of which method is used, the basic requirements are the same. There must be a way of allowing the blanketing gas into the system, and a way to vent the gas should the pressure get too high.

Since ACE introduced its valve many companies have engineered their own versions. Though many of the products available vary in features and applicability, the fundamental design is the same. When the pressure inside the tank drops below a set point, a valve opens and allows the blanketing gas to enter. Once the pressure reaches the set point, the valve closes, as simple as that.

As a safety feature, many systems include a pressure vent that opens when the pressure inside exceeds a maximum pressure set point. This helps to prevent the container from rupturing due to high pressure. Since most blanketing gas sources will provide gas at a much higher than desired pressure, a blanketing system will also use a pressure reducing valve to decrease the inlet pressure to the tank.

Practices

The most popular gas used in blanketing is nitrogen; it is widely used due to its inert properties, as well as its availability and low cost. This system is used for a diversity of products including cooking oils, flammable products, and pure water. These techniques also cover a wide variety of storage tanks, ranging from as large as a tank containing millions of liters of vegetable oil down to a quart-size container or smaller.

The use of an inert blanketing gas for food products helps to keeps oxygen levels low in and around the product because the product help to reduce the amount of oxidation that may occur, and increases shelf life. In the case of cooking oils, lipid oxidation can cause the oil to change its color, flavor, or aroma. It also decreases the nutrient levels in the food and can even generate toxic substances. Tank blanketing strategies are also implemented to prepare the product for transit (railcar or truck) and for final packaging before sealing the product.

When considering the application for flammable products, the greatest benefit is process safety. Since fuels require oxygen to combust, reduced oxygen content in the vapor space lowers the risk of unwanted combustion.

Tank blanketing is also used to keep contaminants out of a storage space. This is accomplished by creating positive pressure inside the container. This positive pressure ensures that if a leak should occur, the gas will leak out rather than having the contaminants infiltrate the container.

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.