natural gas dehydration 2

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17 April 2000

ADMA-OPCO

On-site Training Course

PRODUCTION

Module - 13

Gas Dehydration

Gap Elimination Program


Production

Module - 13

Gas Dehydration


Table of Contents 1. OVERVIEW

1.1 Introduction 1.2 Definitions

2. WATER HYDROCARBON SYSTEM BEHAVIOR

2.1 Water Content in Natural Gas 2.2 Water Dew Point 2.3 Dew Point Depression 2.4 Hydrates Control in Natural Gas System

3. GAS DEHYDRATION SYSTEMS. 4. ABSORPTION USING LIQUID DESICCANTS (GLYCOL DEHYDRATION)

4.1 Process Flow and Components 4.2 Process Operation 4.3 Process Variables 4.4 Operating Problems 4.5 Troubleshooting

5. HYDRATE INHIBITION IN LOW TEMPERATURE PROCESSING PLANTS

5.1 Glycol Type Selection 5.2 Flow Diagram 5.3 Injection Systems 5.4 Spray Patterns 5.5 Troubleshooting

6. HYDRATE INHIBITION IN GAS PIPELINES

6.1 Water Which Can Condense 6.2 Hydrate Temperature Reduction 6.3 Inhibitor Injection 6.4 Selection of Inhibitor

7. ADMA-OPCO GLYCOL DEHYDRATION SYSTEM


OBJECTIVES Upon completion of this module, the developee will be able to :-

• Explain the need for dehydration of natural gas and the effects of water in gas.

• Explain the principles of glycol dehydration including absorption, distillation

and heat transfer.

• Trace the flow of wet and dry gas, as well as wet and dry glycol, in a typical

dehydration system.

• Explain the purpose of each component of the process.

• Explain how each component in the system operates.

• Monitor the system and make necessary adjustments.

• Discuss the effects of process variables on natural gas dehydration.

• Perform routine operation of the system.

• Troubleshoot common problems affecting proper operation of the system.


1. OVERVIEW

1.1 Introduction Most natural gas streams leaving the reservoir contain water vapor. In many cases free water is also produced along with e natural gas. Natural gas cools as it travels up the wellbore to the surface due to pressure reduction and conduction of heat through the pipe to cooler formation walls. Since the ability of gas to hold water vapor decreases as gas temperature decreases, produced natural gas is nearly always saturated with water vapor when it reaches the surface. Additional cooling of saturated gas will cause free water to form. If the gas is further cooled, hydrates will form and serious equipment damage or flow restrictions will result. This is why it is so important to remove water vapor from natural gas. 1.2 Definitions 1.2.1 Water in Natural Gas All unprocessed natural gas contains water, either in liquid or vapor form. The presence of water in natural gas causes two major problems in transmission lines:

• Corrosion causes pitting and damage in pipelines. • Hydrates deposit on pipeline interiors and restrict the flow of gas.

1.2.2 Dehydration The process of removing water from a substance is called dehydration. Although there are several methods for removing water from gas, the most commonly used dehydration method utilises a substance known as Triethylene Glycol (TEG) or simply glycol.

1.2.3 Glycol Triethylene Glycol, TEG, and glycol all refer to the same substance. TEG is expensive so it is efficient to remove the water, recycling the TEG to be used over and over again.


1.2.4 Absorption

Much like a sponge, glycol is used to absorb water from natural gas. By mixing together the wet gas and glycol, water is absorber by the glycol, thereby removing it from the natural gas. 1.2.5 Distillation In distillation, water is separated and removed from glycol by boiling. Glycol does not begin to boil until approximately 435° F (224º C). Water boils at 212° F (100º C). Distillation of water from glycol involves heating the glycol-water mixture to a temperature between 212° F (100º C) and 400° F (204ºC) allowing water to separate as vapor. 1.2.6 Heat Transfer Condensation is the process by which heat travels through a substance. If two containers of water - one containing cold water, the other hot water - are brought into contact with each other, the temperature of the hot water container will decrease and the temperature of the cold water container will increase. The temperature changes result because of heat transfer from hot to cold.

FIGURE - 1 (CONDUCTION) By bringing together "cool" and "hot" glycol in heat exchangers, the process of heat transfer through condensation is accomplished allowing for temperature control of the dehydration Process. In glycol dehydration, it is important to maintain fluid temperatures within relatively narrow ranges, to optimise the efficiency of the process. Improper temperature control can cause glycol foaming.


1.2.7 Liquid Desiccants A number of liquids possess the ability to absorb water from gas. Yet, there are very few which meet the criteria for a suitable commercial process: are highly hygroscopic, do no solidify in a concentrated solution, are non-corrosive, do not form precipitates with gas constituents, are easily regenerated to a high concentration, can be separated easily, are essentially nonsoluble in liquid hydrocarbons, and are relatively stable in the presence of sulfur compounds and carbon dioxide under normal operating conditions. A liquid desiccant is any liquid which removes water from another substance when the two come in contact. Common liquid desiccants used in the oil and gas industry to dehydrate natural gas are methanol, ethylene glycol, diethylene glycol, triethylene glycol and tetraethylene glycol. Methanol, ethylene glycol, and diethylene glycol are commonly used in injection systems as hydrate inhibitors. DEG (Diethylene) is somewhat cheaper to buy and sometimes is used for this reason. But, by the time it is handled and added to the units there is no real saving. Compared to TEG, DEG has a larger carry-over loss, offers less dewpoint depression and regeneration to high concentrations is more difficult. For these reasons, it is difficult to justify a DEG unit, although a few units are built each year. TEG (Triethylene) is preferred for use in dehydration units because:

• It is more easily regenerated due to its high boiling point and other physical properties.

• It has a high decomposition temperature of 404°F (207°C) • It has lower vaporisation losses than other glycols • It has lower capital and operating costs than other glycol systems

TREG (Tetraethylen) is more viscous and more expensive than the other processes. The only real advantage is its lower vapor pressure which reduces absorber carry-over loss. It may be used in those relatively rare cases where glycol dehydration will be employed on a gas whose temperature exceeds about 50°C [122°F].


TABLE 1 PHYSICAL PROPERTIES OF HYDRATE INHIBITORS.


1.2.8 Basic Process There are two basic purposes of a glycol dehydration unit.

• To dry natural gas before puffing it into a pipeline. • To remove water from glycol so that it can be used over and over again in the

dehydration process.

FIGURE 2 BASIC PROCESS

The process, while it may seem somewhat complicated, is actually quite simple. Wet gas - that is, natural gas with water in it – has water removed from it in a dehydration process. Glycol literally soaks up the water, leaving dry gas. The wet glycol then goes through a process of distillation where the water is removed by boiling. The dry glycol is then sent back to function again in the dehydration of gas. In this manner, glycol is recycled.


2. WATER HYDROCARBON SYSTEM BEHAVIOUR 2.1 Water Content in Natural Gas All gases have the capacity to hold water in the vapor state. This is true for air, natural gases of any hydrocarbon mixture, nitrogen, carbon dioxide, hydrogen sulfide, hydrogen etc. This capacity to hold water is a function of the gas composition itself, but is also affected by the pressure and temperature of the gas. Salts dissolved in liquid water in equilibrium with natural gas reduce the water content of the gas. The presence of water in natural gas has a very little effect on the hydrocarbon phase behaviour but involves many troubles

a. Liquid water and natural gas can form solid , ice- like hydrates which plug equipment

b. Natural gas containing CO2 or H2S is corrosive.

c. Water vapor in natural gas may condense in pipeline which potentially causes

slugging flow conditions.

d. Water vapor increases the volume and decreases the heating value of natural gas which leads to reduced line capacity.

Water is essentially insoluble in hydrocarbon .As noted in (Figure 3), the solubility of water increases with increasing temperature and decreases as increasing pressure. Consequently , equilibrium is established when the partial pressure of water in the gas phase is equal to the vapor pressure of water at the temperature of the system . The dew point of water will therefore be different from the hydrocarbon dew point Water content as said is a function of gas composition , but it has been found that lean, sweet pipeline gases have a water content that is primarily a function of pressure and temperature , Figure 4 & 5 is widely used for saturated water content prediction . The water content of gas is expressed as pounds of water per million cubic feet of gas (Ib/ MMCf).


FIGURE - 3 SOLUBILITY OF WATER IN HYDROCARBONS


FIGURE 4 WATER CONTENT OF NATURAL GASES


FIGURE - 5 WATER CONTENT OF SATURATED NATURAL GAS


2.2 Water Dew Point When a gas has absorbed the volume of its water holding capacity at specific pressure and temperature , it is said to be saturated up to that point . Any additional water added at the saturation point will not vaporise , but will fall out as free liquid. Also at this point , if the pressure is increased and the temperature decreased ,the capacity of the gas to hold water will decrease and some water vapor will condense and drop out. This point is known as the water dew point which may be defined as the temperature at which the natural gas is saturated with water vapor at a given pressure. At the dew point , natural gas is in equilibrium with liquid water . 2.3 Dew Point Depression The difference between the dew point temperature of water in saturated gas stream and the stream after it has been dehydrated is known as the dew point depression . To illustrate the concept of dew point depression, suppose that the natural gas at 500 psia, and 60° F , at the saturation point contains 30 Ibm of water per million cubic feet. The dew point of this gas is 60°F. Suppose this natural gas is going to be transported in pipeline at 20° F. The saturation point will then be 7 Ibm of water /MMCf, the original 30 Ibm of water, if left in the gas, will exist in the from of 7 Ibm of water vapor and 23 Ibm of free water per million cf, if the pressure remains the same . This free water is a potential source of hydrates to form and plug the line . Suppose the natural gas is processed in a dehydration unit and the dew point is depressed 50° F . This means that no free water will exist in the gas until the temperature goes to 10° F or lower . Gas at 500 psia and 10° F contains about 5 Ibm of water vapor /MMC f, the dehydration unit must remove 25 Ibm of water from each 1 million cf, of gas in order to achieve the 50° F dew point depression.


2.4 Hydrates Control In Natural Gas System 2.4.1 Hydrates Hydrates are solid components that form as crystals and resemble snow in appearance. They are created by a reaction of natural gas with water. When formed, they contain about 10% hydrocarbon and 90% water. Hydrates have specific gravity of about 0.98 and will usually float in water and sink in hydrocarbon liquids. Water is always necessary for hydrate formation as well as some turbulence in the flowing gas stream. 2.4.2 Hydrate Structures A Hydrate is a water lattice with a series of open spaces in the interstices . It can only be a stable solid if enough of these spaces are filled by the gas molecules. These spaces are of two sizes . Smaller molecules (CH4, C2H6, H2S and CO2) form a body centred cubic structure. Larger molecules (CH3H8, I C4 H 10) form a diamond lattice structure with 17 molecules H2O per gas molecule. The chemical formulas for natural gas hydrates are

Methane CH4 – 7 H2O Ethane C2H6 – 8H2O Propane C3H8 – 18H2O Carbon Dioxide CO2 – 7 H2O

The composition of hydrates is such that free water must be present for their formation. For example, a typical methane hydrate (CH4-7H2O), this would require 126 Ibs of water for every 16 Ibs of methane. 2.4.3 Hydrate Formation Hydrate Formation is often confused with condensation . The distinction between the two must be clearly understood . Condensation of water from a natural gas under pressure occurs when the temperature is at or below the dew point at that pressure. Free water obtained under such conditions is essential to the formation of hydrates which will occur at or below the hydrate temperature at the same pressure. Hence, the hydrate temperature would be less than or equal to the dew point temperature.


During the flow of natural gas , it becomes necessary to define , and thereby avoid , conditions that promote the formation of hydrate . This is essential since hydrates may choke the flow string surface lines and other equipment The conditions that tend to promote the formation of natural gas hydrates are:

1. Natural gas at or below its water dew point with liquid water present . 2. High operating pressures which increase the " hydrate formation" temperature . 3. High velocity or agitation through piping or equipment . 4. Presence of a small seed (crystal of hydrate). 5. Presence of H2S or CO2 is conducive to hydrate formation since these acid gases

are more soluble in water than hydrocarbons. 2.4.4. Preventing Hydrate Formation The hydrate formation can be prevented by

• Heating the cold unprocessed well stream.

• Injection of inhibitors such as ammonias, brines, glycol and methanol to lower the freezing point of water vapor .

Methanol and glycol are the most inhibitors widely used . Usually methanol and glycol are used when hydrate problems arise so rarely that the installation of heater or dehydration equipment is not economically feasible.


3. GAS DEHYDRATION SYSTEMS Liquid water and water vapor are removed from natural gas for several reasons:

a. To prevent formation of hydrates in transmission lines. b. To meet a water dew point requirement of a sales gas contract; and c. To prevent corrosion caused by acid gas streams.

There are essentially four methods for dehydration of gases;

1. Absorption using liquid desiccants. 2. Absorption using solid desiccants. 3. Injection of hydrate point depressants. 4. Expansion refrigeration .


4. ABSORPTION USING LIQUID DESICCANTS (GLYCOL DEHYDRATION)

The glycol ability to readily absorb water is one of its characteristics that have led to their widespread use in the dehydration of natural gas. The use of glycol to dehydrate natural gas began in the 1930's and its use has steadily increase through the years. The first glycol plants obtained dew point depressions in the range of 20-50° F. Today after many years of experience and the increasing technical development, it is possible to design glycol dehydrations which will obtain dew point depressions of over 100° F. The early plants used diethylene glycol and triethylene glycol came into use in 1949. Most process units (Figure 6) using absorption for dehydration employ triethylene glycol (TEG) as the absorbent. Other glycols and glycol mixtures are used, but the relative number of such units is small and their design details are similar to a TEG plant.

FIGURE - 6 GLYCOL DEHYDRATION UNIT


4.1 Process Flow and Components 4.1.1 Components The efficient operation of a glycol dehydration system requires good understanding of the dehydration process and process variables as well as frequent monitoring of dew points. Better dehydration results, as well as significant savings, are experienced when systems are operated properly. The operation of individual components within the system must be understood to properly operate and troubleshoot the system. A typical glycol dehydration system is shown in Figure 7. It consists of the following components: contactor column, reboiler, glycol filter, pump, surge tank, gas-condensate-glycol separator and heat exchangers.

FIGURE 7 BASIC GLYCOL DEHYDRATION UNIT


A. Contactor Column The function of the contactor column (Figure 8) sometimes called an absorber, is to contact natural gas with the glycol, so that the glycol can remove water vapor from the natural gas. These vessels are designed to accommodate a certain gas volume and pressure. It should be noted that to exceed design specifications will increase glycol losses and outlet gas dew point.

FIGURE 8 TRAY CONTACTOR COLUMN

For large volumes of gas, the contactor is usually a tray column containing 4 to 12 trays on which up flowing gas bubbles through down flowing glycol, The number of trays in the contactor will affect the amount of moisture removed from the gas by the glycol; more trays mean more moisture removal.


Vapour Flow Through Bubble Caps


Rarely does the number of trays exceed ten. Each has a number of openings with bubble caps bolted over them to disperse gas through the glycol solution as the gas is forced to pass through these caps and bubble evenly through the glycol. The gas gives up water and becomes drier as it passes upward through each succeeding tray. The glycol becomes more saturated with water as it flows downward over each tray. Also found on the trays are weirs and downcomers. Weirs, which are dam-like devices, are used to maintain the level of glycol above slots in the bubble caps. Downcomers carry the glycol to the trays below.

FIGURE 9 FIGURE 10 TRAY WITH BUBBLE CAPS BUBBLE CAP

In smaller capacity units, that is, contactors having a diameter of 18 inches or less, random packing may be used instead of trays. The packing is metal, plastic, or ceramic structures that are designed to furnish a large surface area for the glycol solution to spread out and make better contact with the gas. Random packing is poured into the contactor onto a support gad. Four feet packing is usually standard and sufficient for dew point depressions up to 55°F to 65°F (13°C to 18°C). If higher dew point depressions are required, additional packing may be required.


Packed columns (Figure 11) utilise the same process as tray columns, that is, glycol flows down over the packing and gas flows up through the packing contacting the glycol. Packed columns are less expensive; however, the glycol tends to channel easier and have poorer flow distribution. Therefore, special attention must be given to the design of a glycol distribution header above the packing so that gas/glycol contacting will be continuous throughout the packing and the glycol will not channel.

FIGURE 11 PACKED CONTACTOR COLUMN

Contactors being designed today may contain structured packing (Figure 12) Structured packing is a group of corrugated metal sheets welded into a specific pattern and placed in the contactor on edge. Glycol coats these sheets and the gas flows between them. This type of packing is much more efficient than bubble caps or random packing. Structured packing is used in columns from six inches (15 centimeters) in diameter up to ten feet (three meters).

FIGURE 12 STRUCTURED PACKING


Before lean glycol enters the contactor, two things happen:

• The glycol is pumped up to contactor pressure • The glycol temperature is lowered to 10-15°F (5-7°C) above the inlet gas

temperature. This is done by passing the lean glycol through a heat exchanger where it is cooled by the dry gas leaving the contactor

It is best to have the glycol entering the contactor 10-15°F (5-7°C) warmer than the inlet gas. Cooler glycol causes condensing of hydrocarbon vapors which cause foaming, resulting in greater glycol loss. Warmer glycol reduces effectiveness of absorbing water from the gas. The glycol/gas heat exchanger is sized to give the correct glycol temperature and usually does not require attention. Incorrect glycol temperatures entering the contactor indicate an imbalance in the glycol to gas flow rate, a problem in the heat exchanger, or the reboiler temperature is out of adjustment. Above the top tray there is usually space for separation where most of the entrained glycol particles in the gas stream will settle out. Glycol not settling out will be removed by a mist eliminator (Figure 13) in the top of the contactor. This prevents liquid glycol from being carried out of the contactor and into the gas discharge line, commonly referred to as carryover.

FIGURE 13 MIST ELIMINATOR


Carryover (Figure 14) can result from foam build-up caused by glycol contamination; however, carryover can also be caused from a high gas rate. It will happen continuously when the gas rate is high enough to agitate the liquid on the top tray so that a foam forms that is too thick for the mist eliminator to handle. When this happens, the gas rate must be reduced to eliminate carryover.

FIGURE 14 GLYCOL CARRYOVER

Level control on the contactor is important in stabilising operation. The level controller should be adjusted to hold a uniform flow rate of glycol out of the contactor. It is more important to hold a constant flow of liquid and let the level in the contactor vary a few inches than to hold a constant level and let the flow fluctuate. Flow rate surges will cause the reboiler to operate inefficiently and may overload it.


B. Gas-Condensate-Glycol Separator This separator is also known as the flash tank or Glycol-gas separator (Figure 15). It is used to recover gas which dissolved in the glycol solution in the contactor as well as any liquid hydrocarbons (condensate) carried out of the contactor by the glycol solution. The G-C-G separator is simply a three phase separator in which gas, liquid hydrocarbons, and glycol are separated. The gas leaves the top of the vessel and is vented or may be used to supplement the fuel gas required for the reboiler. A pressure control valve maintains a back pressure on the vessel, usually 50 to 85 psig (345 to 587 kPa). Any excess gas is discharged through this back pressure valve.

FIGURE 15 GAS-CONDENSATE-GLYCOL SEPARATOR

Separating liquid hydrocarbons from glycol before they enter the reboiler reduces the load on the carbon filter and helps prevent carbon from building up on the reboiler firetube. Problems caused by hydrocarbons entering the still column are flooding, glycol loss and possible damage to the still column. Two level control systems are typically installed on gas-condensate-glycol separators. The upper system regulates flow of liquid hydrocarbon discharged from the vessel. The lower system regulates the flow of glycol from the vessel.


C. Filters Filters are installed in the glycol stream to remove solids and other contaminants which may cause plugging and foaming. There are two types of filters commonly used in gas dehydration systems: One type is used for solids removal and the other for dissolved contaminants removal. Solids Removal: Fine screen, sock type or cartridge filters are used for solids removal. Solid particles can cause erosion of pump pistons, valve seals and discs, plugging of equipment, and foaming. Sock filters are the most commonly used type for solids removal. Sock filters contain cylindrical elements that are replaced as they become coated. A pressure drop of 3-6 psig (21-41 kPa) usually occurs as glycol flows through the elements; however, the pressure drop increases as the elements remove solid material and become plugged. To measure the pressure drop across elements, a differential pressure gauge is installed. When the pressure drop rises to 15-20 psig (104-138 kPa), the elements should be replaced so that collapse of the elements or stoppage of glycol does not occur. Dissolved Contaminants Removal: Activated carbon filters are recommended for the removal of dissolved contaminants. They work well until their adsorption capacity is reached. In cases where the glycol contains appreciable quantities of light hydrocarbons, they must be changed or reactivated frequently. Most glycol systems cannot be operated successfully without carbon adsorption. There are two types of activated carbon filters. Most systems use a carbon canister; however, larger systems use a loose fill carbon vessel. When the loose fill vessel is used, care must be taken to trap carbon fines and keep them from entering the glycol dehydration system. This is especially important when a fresh carbon bed is put into service. Routing the glycol flow through the carbon bed prior to the particle filter is the usual method of trapping carbon fines. However, care must be taken to reroute the glycol flow to its proper order or the life of the carbon bed will be shortened. Carbon filters should be replaced anytime the level of contaminants in the glycol solution goes up. Monthly test should be run to determine the contamination level.


D. Regenerator and Still Column The regenerator (Figure 16) is a combination of the glycol reboiler and the still column. They operate together to regenerate the rich glycol, making it lean again and ready for use in the contactor column.

FIGURE 16 REGENERATOR

The reboiler is the vessel which supplies heat to separate glycol and water by simple distillation. Glycol is heated to a temperature between 380°F and 400°F (193°C and 204°C) to remove enough water vapor to regenerate the glycol to 98.5-99%. The temperature of triethylene glycol should not exceed 400°F (204°C) because TEG will begin to break down at higher temperatures. Reboilers can be direct fired or heated by steam or hot oil. The direct fired type, containing a removable fire box and firetube, is normally used. The heating element should be conservatively sized to insure long tube life and prevent glycol decomposition by overheating the glycol. Glycol level in the reboiler is maintained by an overflow weir. Excess glycol spills over the weir and flows downward into the surge tank by gravity. When glycol level is low in the surge tank, fresh glycol is added to the reboiler, so that it can be dried before going to the surge tank.


The still column, sometimes called a stripper, is the vessel located on top of the reboiler where distillation of glycol and water actually takes place. Still columns are normally packed columns and have finned condensers or reflux coils in the top to cool water vapor leaving the column and to recover entrained glycol.

The amount of glycol lost with the water vapor leaving the still column is controlled by the temperature of the water vapor, normally referred to as still column overhead temperature. This temperature should be set at the boiling point of pure water for the pressure in the top of the still column.

Normally the pressure will be atmospheric, 14.7 psia at sea level, and the temperature will be 212°F (100°C). Systems with back pressure will require higher temperatures. Systems operating above sea level will require lower temperatures due to the lower pressures.

If the still overhead temperature is above the boiling point of pure water, glycol carryover will occur and losses will be higher than normal. If the still overhead temperature is below the boiling point of pure water, too much water will be condensed and the reboiler heat requirements and fuel usage will increase.

Column flooding will result when glycol being fed to the still column has a high concentration of light hydrocarbons, which will distil out of the glycol and condense in the upper portion of the column. Flooding will also result if the glycol flow rate exceeds maximum design limits. Column flooding does not allow proper glycol/water separation and rich glycol can be lost through the vent line.

E. Surge Tank

This is the vessel (Figure 17) used to store regenerated glycol for pump suction. It is commonly positioned under the reboiler in the glycol dehydration system. The surge tank should be vented and the vent line kept unplugged. Vapors, which are trapped in the surge tank, could cause the circulation pump to vapor lock. The vent line should be piped away from process equipment.

FIGURE 17 SURGE TANK


F. Pumps Most small dehydration units use a fluid driven pump while larger units generally use an electrically driven reciprocating pump. In either case, the pump is a critical part of the unit because it has the only moving parts in the system. Before entering the pump, rich glycol passes through a strainer to remove large particles. Leaks can be a problem around glycol pumps. Proper packing gland maintenance and the use of manufacturer's recommended packing can minimise this problem. G. Heat Exchangers There are two types of heat exchangers used in a glycol dehydration unit: glycol to gas heat exchanger and glycol to glycol heat exchanger(s). Glycol/Gas Heat Exchanger. Dry gas leaving the contactor passes through this heat exchanger, where the temperature of the gas is raised slightly as it cools the incoming lean glycol. Thus, the final stage of lean glycol cooling is accomplished here. Incoming glycol is cooled to a temperature about 10-15°F (5-7°C) above that of the natural gas entering the contactor.

FIGURE 18 GLYCOL/ GAS HEAT EXCHANGER


On small dehydration units, this exchanger is often a double pipe heat exchanger, which is literally a pipe within a pipe. Lean glycol in the outer pipe flows around the outlet gas in the inner pipe. Larger units will utilise a shell and tube type of heat exchanger. Heat exchangers are subject to fouling by salt, coke, or gum deposits which can reduce the heat transfer rate and increase the lean glycol temperature. Glycol/Glycol Heat Exchanger(s): Hot, lean glycol leaves the surge tank and passes through a glycol/glycol heat exchanger (Figure 19), where the lean glycol is cooled by the rich glycol stream leaving the filters downstream of the G-C-G separator. A second glycol/glycol heat exchanger heats the rich glycol which leaves the reflux coil by the lean glycol stream leaving the first glycol/glycol heat exchanger.

FIGURE 19 GLYCOL/GLYCOL HEAT EXCHANGERS

Lean glycol, which leaves the surge tank at approximately 400°F (204°C), must be cooled prior to entering the contactor in order for it to absorb the maximum quantity of water from the gas. These heat exchangers cool the lean glycol to about 212°F (100°C). They are very important in the overall operating efficiency of the dehydration unit. These heat exchangers substantially reduce the amount of heat required by the reboiler.


4.2.2 Process Flow Description As shown in Figure 20 the wet gas enters the contactor through an inlet near the bottom . The gas, travelling upward in the contactor column, is forced through the openings below the caps and bubbles through the glycol. During the bubbling process, the gas gives up water vapor to the glycol. As gas passes upward through each succeeding tray it becomes drier. Before leaving the contactor, the dry gas passes through a mist extractor to remove any glycol that may be in vapor form. As the glycol particles collect and become heavier in the mist extractor, they drop back into the top tray and rejoin the glycol stream. The dry gas then leaves the contactor and passes through a heat exchanger where it cools the dry glycol entering the top of the contactor column. The dry gas is then ready for transmission. Dry glycol enters the contactor tower at an inlet near the top and flows across the top tray, then downward and across other trays. A level of glycol is maintained on a tray by means of a dam known as a weir. This level is above the slots in the bubble caps so the gas is forced to bubble through the glycol. The glycol flows over the weir through an opening known as a down comer and into the tray below. Maintaining the level of glycol on the next tray above the bottom of the down-comer prevents gas from bypassing the bubble caps. As the glycol spills downward through each succeeding tray, it becomes saturated with the water it has absorbed from the gas and collects in the bottom of the contactor. The wet glycol from the contactor then passes through a filter where any abrasive particles and tarry hydrocarbons are removed before entering the pump.


FIGURE 20 GLYCOL DEHYDRATION UNIT


FIGURE 21 CONTACTOR COLUMN

From the pump, the cool wet glycol flows through coils in the surge tank.

This allows for a heat exchange process to occur. The cool wet glycol is warmed by the hot dry glycol before it enters the gas-condensate-glycol separator.

At the same time, the hot dry glycol is cooled before it enters the contactor column. From the coils in the surge tank, the wet glycol enters the gas-condensate-glycol separator.


FIGURE 22 G-C-G SEPARATOR

Heat from the surge tank helps separate hydrocarbons from the wet glycol. The hydrocarbon condensate is skimmed off the glycol and any remaining gas vapors leave from the top. From the gas-condensate-glycol separator, the wet glycol flows through a tube in the reboiler. Here the glycol is heated to vaporise the water before entering the still column ("stripper") on the reboiler. The still column removes the water vapor from the glycol. Inside the still column is a section, known as a Packed column, filled with ceramic, stainless steel or carbon packing known as saddles or rasching rings. The glycol spreads out uniformly over the packing and drips down through the lower portion of the packed column. The water vapor rises to the top of the column.


FIGURE 23 STILL COLUMN From the packed column , the wet glycol drops downward into the bottom of the reboiler. A source of heat circulated through a tube in the lower section of the reboiler maintains the temperature of the glycol solution at approximately 370° to 400º F (188 to 204º C) which is just below the boiling and decomposition point of Triethylene Glycol. Waste heat from compressor or generator exhaust gases can be used as a heat source, but many installations also use a gas fired heater. The temperature of glycol in the reboiler is critical and must be controlled within this range. The remaining water boils out of the glycol solution and moves upward through the still column as vapor. Some hot glycol vapors also are mixed with the water vapor. As this mixture passes upward through the still column, it comes in contact with a cooler part of the column and the glycol vapors are condensed and dropped back down into the reboiler. The water leaves the top of the still column as vapor.


The glycol level in the reboiler is maintained above the heating tube by the location of the overflow tube. The dried, purified glycol spills into the overflow tube and flows into the surge tank.

FIGURE 23 OVERFLOW TUBE

From the surge tank the dry glycol flows to a pump. The pump raises the pressure of the dry glycol slightly above that of the contactor column. This dry glycol then passes through a heat exchanger which cools the glycol to near the temperature of the natural gas in the contactor. Proper temperature and pressure must be maintained in this system to prevent foaming. With the return of the glycol to the contactor column, the dehydration cycle is completed and another cycle begins.


4.2 Operation 4.2.1 Start up Prior to the initial start up of a new plant. The vessels and lines should be thoroughly washed out with water to remove debris and corrosion products that accumulated during construction. After the system has been cleaned, start up is accomplished in three phases:

1. Establish glycol circulation throughout the plant. 2. Apply heat to the reboiler and bring it up to operating temperature. 3. Open the wet gas stream to the contactor and begin dehydrating the gas.

In order to circulate glycol throughout the system, it will be necessary to pressurise the vessels in the system. Pressuring can be done with wet gas or dry gas. The contactor pressure should be raised to at least 10 bars (l50 psi) and the flash tank pressure should be raised to at least 3 bars (45 psi). When the vessels have been pressured, start up procedure is:

Fill the reboiler and surge tank with fresh glycol solution Also add to the flash tank. Pressure up the contactor column by very slowly opening the gas inlet valve. Prime and start glycol pump. When liquid appears at the bottom of the contactor put the bottom level controller in service so the glycol will flow to the flash tank. Put the flash tank level controller in service when liquid appears in the bottom, so that liquid will flow to the stripper. Keep surge tank level half full by adding glycol when needed. When desired circulation rate is established, light the reboiler or put the heat source in service and slowly bring reboiler temperature up to 250°F (121°C). Leave temperature at 250°F (121°C) until all water has been boiled out of glycol.

Recommended steps for safely lighting a gas-fired glycol dehydration unit:

Close pilot valve, gas burner valve, and main gas supply valve. Be sure all gas is vented from firetube and flame arrestor is in place. Make sure gas is off five minutes prior to lighting.

Be sure firetube is covered with fluid.


Stand to one side while inserting burning torch. This protects the operator from ignition of residual vapors.

Adjust torch position to ignite pilot. Open main Supply valve. Slowly open Pilot valve. Open burner valve after pilot is lighted and torch removed. Adjust gas and air mixture to obtain proper flame. Set fuel pressure as low as possible to maintain proper temperature.

Slowly switch gas stream through contactor column by opening the outlet line and slowly closing the by-pass line. Slowly raise the reboiler temperature to around 380°F to 400°F (193°C to 204°C). Inspect unit for leaks and other abnormal operating conditions. Check gas dew point after the unit has been operating for about four hours.

4.2.2 Routing Operation Routing operating checks include the following:

Check levels in each vessel and reset level controller as necessary. Check the pressure drop across the filter and replace the elements as required. Check the temperature of the lean glycol out of the glycol exchanger to see that the proper transfer rate is occurring in the exchanger.

Check the flow of glycol to the contactor and of stripping has to the reboiler. Check the pressure of the flash tank to see if it is at proper level. If water or air is used to cool the glycol prior to its entry into the contactor, check the glycol temperature in order to ensure that it is about 5°C to 7°C (10°F to 15°F) above the inlet gas temperature. Adjust the flow of air or water through the cooler as required.

Check the water content of the outlet gas to see that it is below the design limit.


4.2.3 Shut Down

This procedure is used to shut down a glycol plant: Block gas to contactor column, Shut off heat (leave pump running), When unit cools to safe temperature, 150°F (66°C), shut off pump. Drain glycol, if necessary.

4.3 Process Variables The degree of water removal is determined by several process variables which include: inlet gas temperature, inlet gas pressure, gas flow rate, inlet glycol temperature, glycol concentration, and glycol circulation rate. All are major factors which affect the efficiency of a glycol dehydration system.

4.3.1 Inlet gas temperature

Incoming gas temperature has a significant effect on the water content of the gas entering the contactor. At constant pressure, the water content of inlet gas increases as the gas temperature is increased. If in contact with free water, gas will absorb additional water vapor as the temperature is increased. If the gas contains more water vapor, the unit is required to remove more water in order to achieve the desired water content of outlet gas. Example: At 1000 psig (6900 kPa) inlet pressure, changing the gas temperature from 100°F to 120°F (38°C to 49°C) will double the amount of water vapor that will be carried by saturated gas. Inlet gas temperatures above 130°F (54°C) make normal glycol dehydration almost impossible.

FIGURE 24 WATER VAPOR CONTENT OF NATURAL GAS AT SATURATION


In cold weather, line heaters are used to heat the gas stream ahead of the dehydration unit to maintain minimum inlet gas temperature, which is 50°F (10°C). Minimum inlet gas temperature is set by the viscosity of the glycol being used. Depending on the composition and pressure of the gas, hydrates may form at temperatures well above 50° F (10° C), thus requiring a higher inlet gas temperature to avoid plugging problems. Low temperatures increase the tendency of glycol to foam which can create a significant operating problem.

4.3.2 Inlet Gas Pressure:

In the normal operating range of a glycol dehydration unit, pressure is not a critical factor. However, it is important to note that at constant temperature, gas can hold more water as the pressure is reduced. Therefore, water content of inlet gas will be high if the gas pressure is low.

4.3.3 Contactor Pressure:

Operating the contactor below design pressure of the system creates the following problems:

• At constant temperature, water content of inlet gas increases as pressure decreases, causing the unit to work harder to dry the gas • At constant gas rates, the gas velocity through the contactor increases as the pressure is lowered, causing carryover problems

4.3.4 Gas Flow Rate:

For a unit to operate efficiently, a specified range for gas flow must be maintained. If flow rate deviates outside these limits, problems can develop. Falling below the specified range will result in loss of efficiency and may result in increased dew point for outlet gas, depending on the design of the trays or packing in the contactor column.

If the flow rate rises above the specified range, reboiler overload occurs resulting in insufficient glycol regeneration and increased outlet gas dew point. The amount of glycol carried out with the dry gas will also increase. In fact, all the glycol can be carried out of the contactor column at one time if the gas flow rate is high enough.

A flow rate without rapid surges or changes is necessary to prevent a loss of seal in the contactor column downcomers. Seal loss allows gas to bypass the trays and results in high outlet gas dew points and high glycol loss with the outlet gas.


4.3.5 Inlet Glycol Temperature:

Inlet glycol temperature of 10-15°F (5-7°C) above the inlet gas temperature is recuired to prevent hydrocarbon condensation in the glycol. Hydrocarbon condensation increases foaming, reduces carbon filter life, and increases carbon build up on the reboiler firetube.

4.3.6 Glycol Circulation Rate:

If glycol circulation rate is increased without changing other variables, the outlet gas dew point can be decreased. However, it is desirable to maintain the lowest glycol circulation rate possible to produce the desired outlet gas dew point.

An excessive glycol circulation rate can result in the following problems:

• Increased fuel consumption

• Exceeded reboiler capacity

• Increased overhead glycol loss due to the higher temperature of lean glycol going to the contactor column

• Increased pump maintenance

4.3.7 Glycol Concentration: Changing the degree of glycol reconcentration (usually referred to as glycol purity) from the regenerator will produce the largest effect on dew point depression. Example: Assuming a contactor has six trays and a glycol circulation rate of three gallons per pound (24 litters per kilogram) of water vapor in the inlet gas, the highest dew point depression obtainable with 98.5% pure triethylene glycol is 67°F (19°C). Changing the concentration to 99. 1 %, the dew point depression becomes 75°F (24°C). Higher dew point depressions can be obtained with higher glycol concentrations ; however, stripping gas must be used to achieve these levels of glycol purity.

FIGURE 25 DEW POINT DEPRESSION VS. GLYCOL CIRCULATION RATE


Stripping gas is natural gas percolated through glycol being regenerated to help remove water that cannot be removed by the distillation process. In some systems, the gas is percolated through the glycol inside the reboiler. In other systems, there is a stripping column located between the reboiler and the surge tank. 4.3.8 Reboiler Temperature: This temperature controls the concentration of water in lean glycol; higher temperatures at constant pressure results in greater glycol purity. The range should be 380°F to 400°F (193°C to 204°C) for TEG. The temperature should NOT exceed 404°F (207°C) or glycol degradation will result. 4.3.9 Still Overhead Temperature: The still over-head temperature in the top of the still is very important. However, it is fairly easy to maintain an acceptable range for separation of water and glycol due to the wide difference in the boiling points of water, 212°F (100°C), and triethylene glycol, 546°F (286°C). The recommended range for the still overhead temperature is about 212°F to 215°F (100°C to 102°C) at sea level. A temperature too low can cause reboiler over-load and excessive fuel consumption. A temperature too high causes glycol loss due to vaporisation. 4.3.10 Regenerator Pressure: A build-up in regenerator pressure, which is normally atmospheric, usually indicates a plugging or flooding problem, most commonly in the still packing. An increase in regenerator pressure also prevents some water from boiling out of the glycol, requiring higher temperatures in the reboiler, which wastes fuel gas and can lead to degradation of the glycol. 4.3.11 Filter Pressure: A pressure drop of 3-6 psig (21-41 kPa) is normal as glycol flows through the elements; however, the pressure differential increases as the elements become plugged. When this differential increases to 15-20 psig (104-138 kPa), the element should be replaced. 4.3.12 G-C-G Separator Pressure: Operating pressure in the G-C-G separator is 50-85 psig (345-587 kPa). Back pressure is maintained by a pressure controlled regulator.


4.3.13 Heat Exchanger Temperature: Glycol temperatures taken both before and after passage through a heat exchanger indicates the condition of the exchanger surfaces. As the exchanger surfaces become more severely fouled, the temperature change or differential across the heat exchanger decreases and energy consumption for glycol regeneration goes up due to increased firing of the reboiler. 4.3.14 Reducing Glycol Losses The loss of glycol is a costly operating problem. Losses occur due to vaporisation, entrainment, and mechanical leaks. Typical locations for glycol losses are:

• Carryover with outlet gas leaving the contactor

• Vaporisation with water vapor leaving the still column

• Leaks at the pump or pipe fittings

• Removal of liquid hydrocarbons and/or gas from the G-C-G separator Conditions affecting glycol losses include:

• High still overhead temperature

• Contactor column operating at excessive gas rates

• Foaming

• Rapid changes in gas rate.

Note: Losses not exceeding one pound of glycol (or 0.1 U.S. gallon) per MMscf, of gas processed are generally acceptable. 4.3.15 Glycol Tests In order to prevent costly operating problems such as high glycol losses, foaming, and corrosion, it is essential that meaningful analytical information be collected to pinpoint areas of inefficiency. Maximum drying efficiency is achieved when sufficient data from glycol test results is known so that proper evaluation of system performance and correct adjustments can be made.


A. Glycol Weight Percentage This refers to the amount of glycol in the glycol solution. Lean glycol should contain about 98.5 to 99.9% a glycol. Rich glycol content varies from about 93-96% glycol. B. Water Content This refers to the amount of water in the glycol solution. Low water content in lean glycol is vital to good dehydration. The water content in lean glycol should not exceed 1.5 percent. A higher water content than 1.5 percent is usually an indication of a reboiler temperature that is too low and/or of a heater not operating properly. The water content in rich glycol should not be more than 5 or 6 percent. Water content spread refers to the difference in water content between lean and rich glycol. A spread which is too narrow (0.5 to 2 percent) usually means the glycol circulation rate is too high. The rate should be lowered to save energy, minimise glycol losses and improve dehydration. A spread over 4 to 6 percent is too wide and usually means the glycol circulation rate is too low and should be increased. A guideline for circulation rate is three gallons (11 litters) of glycol for every pound (0.45 kilogram) of water to be removed. C. Hydrocarbon Content This refers to the amount of oil, paraffin, or condensate in the glycol. It should be kept below 0.1 percent, otherwise it will cause problems such as foaming, plugging, or fouling which result in glycol losses and poor dehydration of the gas. Hydrocarbons get into glycol in two ways;

• Condensation which is caused when glycol enters the contactor colder than the incoming gas. This problem can be eliminated by maintaining a temperature for the entering lean glycol of 10-15°F (5-7°C) warmer than the incoming gas.

• Carryover of hydrocarbon contaminants from the inlet separator or gas D. Salt Content This refers to the amount of salt or chloride in the glycol. It should be kept below 0.01 percent by weight or 100 ppm. Salt has a solubility in glycols of about 650 to 700 ppm. A higher salt level usually results in an accumulation of salt on the firetube in the reboiler which leads to a decrease in heat transfer efficiency. Thus, it becomes more difficult to remove water from the glycol and poor dehydration usually results.


Salt contamination is a result of improper gas scrubbing; however, since salt usually travels in the gas stream in a fine mist, not even an inlet separator can effectively remove all salt. A coalescing or filter type separator is usually needed to remove salt from the gas stream. Problems which occur when the salt content reaches almost 0.1 percent by weight or 1,000 ppm include:

• Build-up of salt on the reboiler firetube, resulting in decreased heat transfer efficiency

• Corrosion which will eventually decay the firetube

• Hot spots on the firetube, resulting in thermal decomposition of glycol and holes in the firetube

E. Solids Content

This refers to the amount of suspended solids in the glycol. Suspended solids should be kept below 0.01 percent by weight. This can be done by filtration. Problems resulting from a high solids content include:

• Increased pump wear from abrasion • Accelerated corrosion and erosion • Increased fouling of firetube • Increased glycol loss due to foaming • Increased plugging problems

F. pH

This refers to the corrosiveness of the glycol, pH is a term used to express acidity or alkalinity. pH is based on a 0 to 14 scale.

Acidic = 0 to 6.9 , Neutral = 7.0 Alkaline = 7.1 to 14


As glycol pH decreases, equipment corrosion rate increase rapidly and troublesome corrosive compounds result. Examples include:

• Organic acids from oxidation of glycol • Thermal decomposition products • Acid gases picked up from the gas stream, such as CO2 and H2S

Glycol pH should be checked periodically and kept on the alkaline side by neutralising the acidic compounds with alkaline chemicals, such as monoethanolamine (MEA). A pH of about 7.3 is considered a safe level. Raising the pH above 8 to 8.5 is not desirable because of the tendency for an alkaline glycol solution to foam and emulsify more easily. G. Iron content This refers to the amount of corrosion products in the system, of which rust is the most common. Corrosion products either come in with the incoming gas or they are the result of a corroding glycol system. An iron content exceeding 10 to 15 ppm calls for corrosion prevention methods to be considered. 4.4. Operating Problems The operating problems most frequently encountered in a glycol plant are:

• Foaming • Degradation • Corrosion • Inadequate separation ahead of the absorber • Water/ vapor in Gas • Puking

All are inter-related to some degree. The usual symptoms of these problems are excess glycol make-up and / or lower normal dew point depressions.

4.4.1 Foaming

This is possibly the most common problem. Glycol tends to foam easily due to its viscosity. This tendency is promoted by liquid hydrocarbons (particularly aromatics), the presence of small solid particles, and contaminants. Poor tray design which uses too high vapor velocity through the bubble cap slots may be a contributing factor.


Drilling mud, corrosion by-products (iron sulfide) , glycol degradation products , and the like , promote formation of a stable foam. The main problems associated with foaming are:

• Improper gas dehydration

• Excessive glycol losses when the glycol foams out of the contactor

• Additional equipment problems downstream of the contractor from glycol carryover

To prevent glycol foaming, it is required:

• Use cartridge filter to keep glycol solution clean.

• An inlet gas separator to separate hydrocarbons entrainment.

• Use a foam inhibitor (trioctylphosphate is the most common foam inhibitor), too much foam inhibitor can promote foam.

• PH control are also very important. Foaming losses will be minimised by proper mist eliminators, in most cases two in series at least 6-8 inches apart, are recommended . A third one can sometimes show advantage. The first unit is really a coallescer for the foam so that the subsequent unit (s) can separate properly 4.4.2 Degradation Degradation is a natural occurrence and is accelerated in the presence of sulfur compounds. The answer is effective filtration. Degradation products contribute to foaming but they also are major sources of corrosion problems. The best filtration system uses a regular filter to remove the large "chunks" and then an activated carbon filter to remove hydrocarbons as well as fine contaminants that pass through the first filter. 4.4.3 Corrosion Glycol will react with sulfur compounds to form undesirable degradation products “gunk” which is very corrosive and glycol decomposition products are primarily acidic. This condition can be controlled by good filtration and glycol reclaiming.


The PH of the glycol solution should be maintained from 6.5 to 8.5 by suitable materials, small amounts of base chemicals such as amines may be used. Corrosion control chemicals used are:

a. Sodium mercaptobenzohiazole (sodium MPT) is usual used at 0.3 - 0.5 Wt.% concentration plus 1.5 Wt % dipotassium phosphate. The MPT concentration may be maintained by adding 1 quart of MPT to each 55 gallon drum of glycol.

b. Monoethanolamine (MEA) normally about 1% in solution. c. Coroval, usually used at about 40 PPm by weight.

4.4.4 Inadequate Separation Salt is a continuing problem. Good separation ahead of the absorber is mandatory. Any salt arriving at the regenerator deposits either in the still column or in the reboiler. It is common for packed still columns to plug up to the point glycol is lost overhead. If this does not occur, salt can plug the reboiler and cause failure. 4.4.5 Water Vapor in Gas The water vapor in gas is relatively fresh but is slightly saline. NaCl is soluble in TEG to some degree. At 50°C about 3.3 kg will dissolve in l00 kg of TEG. So, some salt is always present. The soluble salt hydrolyses to HCI and lowers the pH of the glycol. 4.4.6 Puking It is almost always caused by a slug of liquid hydrocarbons entering the stripper. The hydrocarbons will flow down the stripper as a liquid, and when they reach the reboiler, they will vaporise almost instantaneously. The vapor flow up the stripper with sufficient velocity to carry out most of the liquid in the tower. Liquid hydrocarbons should be removed from the rich glycol in the flash tank, or a similar vessel. 4.4.7 General

• Good operating procedures require the blanketing of the system to prevent entry of oxygen into the system.


• Oxygen will cause the glycol to oxidise to acidic materials and enhance the corrosiveness of the system.

• Charcoal absorbers can be used to remove the heavier hydrocarbons which frequently accumulate in the system.

• Any neutraliser used to raise the PH will cause soluble iron in the glycol to precipitate and possibly plug the pumps and filters. The neutraliser should be added slowly and the filter system should be observed closely for the first few days of neutraliser use.

• Cocking of regenerator fire tubes caused by presence of solids or heavy hydrocarbons or by overheating can cause hot spots and tube failure.


4.5 Troubleshooting Troubleshooting Guide:


Troubleshooting Guide (Cont.)


5. HYDRATE INHIBITION IN LOW TEMPERATURE PROCESSING PLANTS

5.1 Glycol Type Selection All of the glycol injection systems in operation now use ethylene glycol (EG). This choice has been made primarily on economic ground since all the glycols are effective inhibitors. The loss of glycol from the system is small but glycol is an expensive fluid so that careful attention to consumption is an important consideration. Glycol is lost by two means:

• Vaporisation.

• Slightly solubility

Vaporisation Loss is proportional to the vapor pressure which in turn decreases with increasing molecular weight. Solubility Loss on the other hand is a function of two factors, the molecular weight and the concentration of glycol in its water solution. The solubility increases with molecular weight and the concentration of glycol in its water solution which is just opposite the effect on vaporisation losses. With these factors in mind ethylene glycol is a very satisfactory compromise.


5.2 Flow Diagram The flow diagram for a typical glycol injection systems shown in Figure 26. The inlet wellstream enters the knockout with or without prior cooling. Just downstream from this knockout, prior to heat exchanger , the optimum amount of glycol is injected . This glycol then flows through the heat exchanger, across the choke into the separator with the wellstream gas. There it is separated with the condensate. The cold sales gas then proceeds to either the wellstream heat exchanger and or the stabiliser product cooler before entering the sales line. After being separated, the glycol is reconcentrated in a unit very similar to that used for absorption dehydration and reinjected into the line.

FIGURE 26 TYPICAL FLOW SHEET OF A GLYCOL

INJECTION SYSTEM


The concentration of glycol injected in the gas stream must be carefully controlled so that it will not freeze when it passes through the low temperature exchangers. Figure 27 indicate the freezing point of various glycol - water mixtures. As you can see from the freezing point curve, a glycol concentration of 95% will freeze at a temperature of -22°C (8°F) . A solution containing 38% glycol and the balance water will freeze at the same temperature. The concentration of glycol used for injecting in the exchangers to prevent hydrates from forming must fall somewhere between 38% and 95%

FIGURE 27 FREEZING POINT CURVE FOR GLYCOL-

WATER SOLUTIONS The glycol injected in an exchanger mixes with water that condenses from gas as it is cooled, consequently, the glycol is diluted as it mixes with water.


5.3 Injection Systems

Most glycol injection systems are designed for a lean concentration of 75-80 % glycol and 20-25 % water. The injection rate of 75 - 80% glycol must be sufficient so that the concentration does not drop more than 10% when it picks up the water that condenses from the gas. In other words, if the lean glycol concentration is 75% glycol and 25% water , the concentration of rich glycol removed in the low temperature separator should be at least 65% (75% - 10%).

The flow of glycol to the injection system will depend upon three factors:

1. The concentration of lean glycol injected into the gas stream which is regulated at the glycol reconcentrator.

2. The quantity of water which can condense from the gas as it is chilled in the exchangers.

3. The amount of the lean solution is diluted with water that condenses from the gas. Dilution = % lean solution - % rich ' solution (dilution is usually between 5 and 10%. )

In calculating the water that can condense in the exchangers we use the lowest possible temperature that the gas can reach in them. In the case of the gas exchanger, the gas is actually cooled to only -1°C (30° F). However, cold gas at - 29° C (5°F) is used to cool the inlet stream. It is possible for some of the inlet gas to reach the same temperature as that of the cold gas. Consequently, the glycol injection rate (Figure 28) must be calculated for the worst possible case that could occur in the exchanger.

FIGURE 28 GLYCOL INJECTOR IN EXCHANGER


5.4 Spray Patterns

In order for the glycol to be effective, it must be sprayed in each exchanger so that the entire tube sheet of the exchanger is covered with glycol. Hydrates will form in the tubes that are not in the spray pattern and they will quickly plug. Usually, the quantity of glycol required to completely cover the tube sheet of the exchanger is considerably more than the minimum required

The spray pattern from a nozzle is primarily dependent upon the pressure drop across the nozzle. As the pressure drop increases, the spray patter, enlarges.

Most glycol injection nozzles are designed for a pressure drop of 2 -4 bars (25 - 50 psi). A change in pressure drop will result in a different spray pattern. If the pressure drop across the nozzle increases, and the glycol flow remains constant, some of the holes in the nozzle are apparently plugged. A filter on the inlet glycol line will usually remove solid particles in the stream that could plug some of the nozzle openings.

A plugged nozzle can be cleaned by blocking in the flow of glycol and opening the valve in the back flow line to allow gas inside the exchanger to flow through the nozzle to the vent.

When the pressure drop across the nozzle decreases at a constant flow rate, the holes in the nozzle have enlarged. The stream out of the nozzle is probably in the form of drops rather than tube sheet. Increasing the glycol flow rate until the design pressure drop is indicated may temporarily solve this problem. However, the permanent solution lies in replacing the nozzle with a new one. Hydrates will form in the tubes of an exchanger, which are not within the spray pattern of the glycol. Since most tubes are fairly small, those beyond the spray pattern will usually plug completely it a short time. Once a tube has completely plugged with hydrate, increasing the glycol injection rate will be of no help in melting the hydrate because no gas is flowing through the tube to push the glycol to the point of the hydrate. In order to remove hydrates form tubes that are completely blocked, the exchanger must be heated above the hydrate formation temperature, or it must be depressurised to vaporise the hydrate, increasing the injection rate may melt some of the hydrates in tubes that are partially blocked, but it will be of no benefit in removing hydrates from tubes that are completely blocked. Hydrate build-up in the exchanger is detected from an increase in pressure drop across the exchanger. Most exchangers are designed so that the pressure of the gas leaving the exchanger is approximately 0.7 bars (10 psi) less than the pressure of the gas entering the exchanger.


In other words, the pressure drop through the exchanger is 0.7 bars (10 psi). As the hydrates begin to form, flow through some of the tubes will be restricted so that the entire gas stream has to pass through fewer tubes. Consequently, more pressure will be required to push the gas through the unplugged tubes and pressure drop through the exchanger will increase. Adjusting the glycol flow rate to each injection nozzle in an exchanger is a trial and error process that often requires months accomplishing. The most common approach to correcting a situation in which hydrates have formed is that of increasing the glycol flow rate.

FIGURE 29 INCREASE IN D.P GAUGE READING INDICATES

HYDRATE FORMATION IN TUBES

Again increasing the rate will increase the size of the spray pattern. This may result in most of the glycol being sprayed on the channel of the exchanger rather than on the tube sheet. In this case increasing the rate may do more harm than good.

“A” “B” “C” SPRAY PATTERN SPRAY PATTERN SPRAY PATTERN

AT PROPER GLYCOL AT HIGH GLYCOL AT LOW GLYCOL FLOW RATE FLOW RATE FLOW RATE

FIGURE 30 SPRAY PATTERN


The location of the nozzle or nozzles in an exchanger will also affect the spray pattern. If the nozzle is too close (Figure 31B) to the tube sheet, the pattern will not cover the entire sheet. Of course, if it is too far (Figure 31C) from the tube sheet, some of the stream will spray on the channel wall will be of no value in the exchanger. Nozzles in some exchangers can be moved closer to or away from the tube sheet while the exchanger is in service. SPRAY PATTERN WITH SPRAY PATTERN WITH SPRAY PATTERN WITH

PROPER NOZZLE NOZZLE TOO CLOSE NOZZLE TOO FAR LOCATION TO TUBE SHEET FROM TUBE SHEET “A” “B” “C”

FIGURE 31 HORIZONTAL MOVEMENT OF NOZZLE The injection nozzles on some exchangers can be moved vertical (Figure 32) or horizontal (Figure 31), or rotating (Figure 33).

NOZZLE CAN BE MOVED UP OR DOWN NOZZLE CAN BE ROTATED FIGURE 32 VERTICAL MOVEMENT FIGURE 33 ROTATED MOVEMENT

OF NOZZLE OF NOZZLE


Another factor which affects the spray pattern is that of the glycol concentration. As the glycol concentration increases, the liquid becomes more viscous, that is, it becomes thicker, and this more difficult to spray. Consequently, the lowest concentration which can be tolerated will usually result in a more uniform spray pattern. The temperature at which the glycol is injected also affects its viscosity. It will be less viscous, that is, it will flow more readily at a high temperature. Consequently, raising the temperature of the glycol being injected will often result in a more uniform spray pattern and less hydrate problems.

5.5 Troubleshooting

There are no hard and fast rules to determine the best operating conditions to prevent hydrate formation in an exchanger. When hydrate formation is a problem, it is important that only one condition be change at time in order to evaluate its effect. If several changes are made at the same time, the positive effect of one change may be offset by a negative effect from another and no conclusions can be from the changes.

Following is a suggested procedure for troubleshooting hydrate formation in an exchanger.

1. Back flow the nozzle to remove dirt that may have collect in it. 2. Increase the glycol flow rate 20 %. If the situation does not improve, increase by

another 20%. 3. If the above fails, reduce the glycol circulation rate 20 % below its original rate if

no improvement occurs, reduce it another 20 %. 4. If no improvement is noted from changing the flow rate, set the flow at its

original rate and reduce the glycol concentration by 5%, concentration can be reduced 5% by lowering temperature 4° C (7° F) in the reconcentrator.

5. If no improvement is noted with a reduction in concentration, repeat steps 2 and 3 at the lower glycol concentration.

6. If no improvement is noted set the flow at its original rate and increases the temperature of the glycol at the injection point, if possible. Hold the concentration at its low point. The temperature should be raised at least 20°C (30°F) . If no improvement is noted , change the flow rate as recommended in steps 2 and 3 at the lowest concentration and higher temperature.

7. If no improvement is noted, the nozzle should be moved or rotated in the exchanger. Set the flow rate at normal and maintain a high temperature and low concentration. Each, change in position should be made in small steps, if a position change does not result-in improvement , follow it with a change of the same magnitude in the opposite direction.


6. HYDRATE INHIBITION IN GAS PIPELINES As has been mentioned, hydrates will form in a gas stream when free water is present and the temperature and pressure of the gas is within the hydrate formation zone. Inhibition or prevention the formation of hydrates is done by injecting glycol or methanol. The amount of inhibitor (methanol or glycol) which must be added will depend upon two factors:

• The amount of water which can condense from the gas as it cools.

• The hydrate temperature reduction, which is the difference in temperature at which hydrates will start to form and the lowest temperature the gas can reach.

6.1 Water which Can Condense Most gas produced from a gas or oil well contains water vapor. In fact , it is almost always saturated with water which mean that , its relative humidity is 100%. As the gas cools, some of the water vapor condenses and falls to the bottom of the piping or vessels in which the stream flows. The water that condenses must mix with the glycol or methanol that is injected to prevent hydrate formation. The amount of inhibitor to inject will depend upon amount of water, which condenses. 6.2 Hydrate Temperature Reduction The hydrate temperature reduction which must be obtained by injecting inhibitor, equals the difference in temperature between the temperature at which hydrates first start to form and the lowest temperature expected in the gas stream. For example, if the hydrate formation temperature is 16°C (60° F) and the gas temperature could drop to 10° C (5° F), then inhibitor must be injected to reduce the hydrate formation temperature by 6°C (10° F). Addition of inhibitor to lower the hydrate formation temperature is similar to that of adding anti-freeze to an engine radiator to lower freezing point of the water contained in the radiator. Consequently, when we speak of hydrate temperature reduction, we are actually talking about lowering the freezing point of the water that condense from the gas.


FIGURE 34 METHANOL INJECTION RATE TO PREVENT

HYDRATE FORMATION


FIGURE 35 GLYCOL INJECTION RATE TO PREVENT

HYDRATE FORMATION


6.3 Method of Injecting Inhibitor

In order for the inhibitor to be effective , it must mix with water that condenses from the gas at the instant condensation occurs. If the inhibitor is flowing along the bottom of the pipeline , and water condenses on the wall of the pipeline , a hydrate may form before the water drops to the bottom of the line . In this case, the inhibitor is of very little value in preventing hydrates from forming. The flow of gas through the piping must be turbulent so that the inhibitor is continually mixed with the gas and has an opportunity to contact water the instant it condenses from the gas. As we mentioned, most of the methanol injected in the gas vaporises and becomes part of the gas itself. However, as the gas cools, some of the methanol will condense. In this situation, the methanol will condense at the same time that water condenses and the two will mix as they condense and no hydrates will occur.

Glycol, on the other hand, does not vaporise in the gas. Consequently, the gas flow must be turbulent when glycol is injected in order for the glycol to disperse throughout the gas so that it can contact water the moment it condenses.

In order to be sure the inhibitor thoroughly mixes with the gas, it must be injected so that thorough mixing occurs at the injection point. If liquid inhibitor is simply added to the pipeline, it may flow along the bottom of the pipeline even though the gas flow is turbulent. So long as the inhibitor is injected in a mist form in the gas, it will probably remain in that form as long as gas flow is turbulent in the piping. One way of assuring mixing at the point of injection is to add the inhibitor upstream of a choke or pressure control valve as shown in Figure 36. As the gas flows through the control value, its pressure is reduced and violent agitation occurs within the control value. The inhibitor and gas will thoroughly mix in the valve.

FIGURE 36 INJECTION OF HYDRATE INHIBITOR


If a control valve is not available for mixing , the inhibitor may be sprayed into the gas stream through a nozzle as shown below.

6.4 Selection of Inhibitor A number of factors must be considered in selecting methanol or glycol as the inhibitor to use to prevent hydrate formation. Methanol is a better inhibitor than glycol. It has a lower specific gravity, that is, it is lighter than glycol; and it is less viscous, that is , it will flow more readily than glycol . In addition, as we mentioned, some methanol will vaporise and condense as water condenses from the gas and prevent hydrate formation. Methanol is probably 5 times as effective as glycol in preventing hydrate formation. However, a considerable portion of the methanol that is injected vaporises and remains in a vapor form in the gas. This quantity represents a total loss of methanol. No glycol vaporisation occurs when it is injected into the gas. A separator is usually installed at the end of a pipeline to recover the inhibitor, so that it can be reused. Essentially all of the glycol can be recovered in the separator. Since part of the methanol is a vapor in the gas stream recovery in the separator, there will be only 40-60 % of total amount injected into the gas. Consequently, the cost for using methanol is considerably higher than the cost of using glycol because of the methanol loss due to it vaporisation. Quite frequently , the gas pipeline terminates at a processing plant, where it is chilled to a temperature of 18° C (0° F) or lower . Glycol is generally used for hydrate inhibition as the gas is chilled. In such cases , use of glycol as an inhibitor in the pipeline will be compatible with its use in the processing plant.

Glycol would probably be used to prevent hydrates from formation in gathering lines which is a number of gas wells that enter a single gas processing plant.


ADMA-OPCO GAS DEHYDRATION SYSTEM

Umm Shaif NGTP Gas Dehydration Train 1 The three gas dehydration trains on the NGTP are identical. This section will therefore concentrate on, and list tag numbers associated with, Train 1. The train consists of the following key items of equipment.

Gas scrubber 427-C-101

Glycol contactor 427-C-102

Gas glycol exchanger 427-E-101

Glycol regeneration Train 1

Reflux condenser 427-E-102

Glycol flash drum 427-C-103

Glycol filtration

Glycol/glycol heat exchanger 427-E-104

Fuel gas and burner controls

Lean glycol system

Gas Scrubber 427-C-101 Produced gas from the 30" header passes to the Train 1 scrubber where liquid droplets are removed from the gas by the cyclone action of the scrubber. These liquids fall by gravity and accumulate in the scrubber base. The accumulated condensate is drawn off through level control valve 427-LV-013 and passes into the 4" reader, 10" interconnector and then into the 18" export line.


A shutdown valve 427-XV-014 closes on a low low level signal from 427-LALL-014 to prevent the ingress of gas into the condensate export system. The scrubber is protected from overpressure by two interconnector 100% PSVs set at 93.1barg. Both high high and low low level alarms are installed which are linked to the ESD system. Both alarms cause a level 0 shutdown which closes both gas and condensate outlet. Glycol Contactor 427-C-102 The wet feed gas from the inlet scrubber, at 61barg (885psig) and 52.7°, enters the bottom of the contactor 427-C-102 and rises upwards through an internal demister which removes entrained liquid hydrocarbon droplets. Liquid removed accumulates in the base section of the contactor where it is drawn off and passes through level control valve 427-LV-025 which maintains a constant level in this section. Shutdown valve 427-XV-098 closes on low low level signal from 427-LALL-091. The incoming gas at the base passes up the vessel, firstly through a chimney tray and then through a packed section where the gas comes into contact with lean glycol TEG falling down through the packed section. Contact with the glycol reduces the water content of the gas from 2356mg/Nm3 at the inlet to 281mg/Nm3 at the exit of the vessel. From the packed section of the vessel the gas passes through a second demister which removes entrained TEG droplets, reducing carryover and TEG loss. The dried gas leaving the contactor is then routed into the Gas/glycol heat exchanger 427-E-101.


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Gas/Glycol Exchanger 427-E-101 Treated dry gas passes through the tube side of the gas/glycol exchanger which is close coupled to the contactor. The gas is heated from 53°C to 54°C (127°F to 130°F) by heat exchange with lean glycol from the regeneration unit. Lean glycol is cooled from 88°C to 60°C (190°F to 140°F) before being routed into the top section of the contactor. The treated gas from the outlet of the exchanger passes to the dehydrated gas manifold via flow control valve 427-FCV-005 before being exported to Das Island through the 46" gas pipeline. Note: - Shutdown valve 427-XV-080 downstream of 427-FV-005 closes on a glycol Train 1 shutdown signal. A water dewpoint analyser monitors the gas leaving the contactor, ensuring that export gas is kept at export specifications which are as follows: Water dewpoint 12.8°C (55°F) measured at 62.1barg (900psig) Glycol Regeneration Train 1 Following the absorption process in the contactor, the glycol is rich in absorbed water. The accumulated glycol/water mixture is passed from the chimney tray in the contactor to the regeneration unit. This flow is controlled by 427-LICA-023 which maintains a working level in the tray. A shutdown valve 427-XV-021 upstream of 427-LV-023 closes on a low low level signal from 427-LALL-024 to prevent total loss of the liquid level on the chimney tray which would result in high pressure gas passing into the regeneration unit. Reflux Condenser 427-E-102 Rich glycol from the contactor is routed to the reflux condenser located at the top of the regeneration unit still column.


The glycol passes upwards through the condenser shell and is preheated from 53°C (127°F) to 58°C (136°F) by heat exchanging with rising hot vapours from the still column. The rising vapour is partially condensed and the condensate, which contains any glycol recovered from the overhead vapour, is returned as reflux to the column. A manual bypass valve is provided between the glycol inlet and outlet lines at the reflux condenser. This bypass is adjusted as necessary to control process temperature conditions. Glycol Flash Drum 427-C-103 Preheated glycol from the reflux condenser flows to the glycol flash drum 427-C-103, which is a horizontal vessel with an internal weir. This weir provides a small overflow compartment at one end of the vessel which allows for the recovery of hydrocarbon liquids that may be present in he glycol. Hydrocarbons recovered at this point are routed to the close drain header via 427-LV-037 and shutdown valve 427-XV-029. The interface level between glycol and hydrocarbons is maintained by 427-LV-041. The flash drum is maintained at 4barg (58psig) by 427-PCV-117 which releases excess pressure to the HP flare header. On falling pressure, 427-PCV-118 opens which allows fuel gas into he vessel, thus maintaining steady pressure conditions. Glycol passes from the flash drum to the regeneration unit via the glycol filters. Shutdown valve 427-XV-030 at the outlet of the flash drum closes on a low low level signal from 427-LALL-040 to prevent total loss of liquid from the main flash drum compartment. Total loss of liquid would allow gas at 4barg into the regeneration unit. Glycol Filtration Glycol from the flash drum passes to the filtration package which is designed to remove particulate matter down to 10 microns. This achieved by the use of two cartridge type filters 427-Y-102. Normally only one cartridge filter is in service at a time. A manual bypass valve is supplied which, when adjusted, permits 80% of the glycol to bypass the carbon filter. The activated carbon removes traces of hydrocarbon which could cause foaming in the regeneration unit. All filters are protected from excess pressure by relief valves set at 18.3barg.


Glycol/Glycol Heat Exchanger 427-E-104 Following filtration, the glycol is heated from 58°C (136°F) to 164°C (327°F) by hot lean glycol in exchanger 427-E-104. The lean glycol is supplied from the regenerator reboiler 427-E-103. During heat exchange its temperature is lowered from 204°C (399°F) to 88°C (190°F) before passing to the glycol surge drum 427-C-104. Glycol Regenerator 427-E-103 The principle on which the regeneration of glycol is based is the difference in boiling points between water and the glycol (TEG) used in the system. The boiling point of TEG at specific pressure conditions is much higher than water in the dehydration process, therefore, the water boils off first when heated during regeneration. The regeneration unit consists of a vertical still column mounted on a horizontal cylindrical reboiler 427-E-103. The still column contains two sections containing structured packing. Rich glycol, high in water content, enters via a liquid distributor mounted between he two packed sections and passes downwards into the reboiler section. In the fired reboiler, vapour is generated which rises stripping water and some glycol from the falling rich glycol. The rising vapour passes through the upper packed section to the overhead condenser where part of the vapour is condensed and returned to the column as reflux. Any glycol in the vapour is recovered by contact with the flowing reflux and returns to the reboiler. The released water vapour passes to either the incinerator package for oxidising or a vent header located on the platform upper deck. The glycol reboiler is a cylindrical vessel, 1.5m in diameter and 4.8m long. It has an internal weir which maintains the liquid height at 1.35m.


Heat is supplied by a fired heater which has the burner, controls and combustion air fan located at one end of the vessel. Hot combustion gases make three passes through the vessel, ensuring effective heat exchange. The first pass is a single fire tube passing along the length of the vessel. The return pass is via a set of 46 tubes. Glycol Reboiler Fuel Gas Burner Controls The fuel gas supply to the unit is controlled at 6.9barg (100psig) but is reduced to 2.5barg (36psig) by pressure controller 427-PCV-053. The fuel gas is preheated with hot glycol in a coil in the reboiler before passing to the heater control system. Both fuel gas supplies to the pilot and main burner are controlled at 0.035barg (0.5psig) by pressure controllers 427-PCV-173 and 170 respectively. The pilot and main burner supplies have double block and bleed shutdown valve sets in which he section between the double block valve is vented to the upper deck vent header or incinerator on shutdown. A supply of stripping fuel gas is provided, however, under normal conditions this is not required. Lean Glycol System The regenerated glycol passes over the internal weir in the reboiler and passes through the glycol/glycol eat exchanger 427-E-104 where it is cooled from 204°C (399°F) to 88°C (190°F) by heat exchange with the rich glycol flowing to the still column. The cooled lean glycol passes to the surge drum 427-G-101A and B to the glycol contactor 427-C-102 via the gas/glycol exchanger 427-E-101. During normal operation one glycol pump is in service with the spare on auto start standby. Start-up of the spare pump is initiated by a low flow signal from 427-FIC-008. Two temperature controllers 427-TIC-003A and B measure the temperatures at two points within the reboiler and reset control valve 427-TV-003 which controls the fuel gas and air ratio to maintain the glycol temperature at 204°C (399°F).


Burner control valve 427-TV-003 regulates dampers in both gas and air streams to maintain the correct fuel/air ratio at all firing rates. Local control panels are provided with a duplicated panel in the local equipment room (LER) No. 1. Fire protection at the reboiler is installed and consists of a manually initiated carbon dioxide (CO2) injection system. Local handswitch 427-HS-013 opens valve 427-XV-118 which allows the injection of carbon dioxide into the burner fire tube.

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