GAS DEHYDRATION BY LOW TEMPERATURE SEPARATION (L.T.S)

Written by Norrie

Refer to Figures: 16 & 17 as you read on.

Wet natural gas direct from the well streams, at about 1600 Psi, is first pre-cooled and separated from liquids in an 'Intermediate Separator' and cooled in a gas/gas exchanger, causing more liquids to separate out in the 'Choke KO Drum'. The liquids pass to other processes.

From the Choke KO drum, the gas passes through another gas/gas exchanger - the 'LTS Pre-cooler'. (The cooling medium for the gas/gas exchangers is cold dry gas from the Low Temperature Separator (LTS). The exchangers are of the 'Double-pipe' type).

The cooled feed gas from the LTS pre-cooler passes into the L.T.S. vessel, first passing through a Flow Control Choke valve. This is an angle type valve with a hardened plug to withstand the high velocity, erosive quality of the gas flow and the low temperature. Through the choke, the gas pressure is decreased from 1600 psi to about 700 psi and expanded into the low temperature separator (LTS) where the temperature decreases to as low as minus (-) 19 °F. (This temperature depends on the gas pressure and temperature before the choke).

The gas enters the LTS 'Spinner' section at a tangent. The tangential flow in the spinner imparts high speed rotation to the gas which decreases its velocity into the vessel and also causes some separation to take place due to the centrifugal force. The heavier components, water and condensate move downwards while the gas passes upwards.

A hot fluid coil in the spinner section ensures that the formation of 'HYDRATES *' does NOT occur at this point. (* Hydrates are complicated molecules of water and hydrocarbon liquid which are combined to form a semi-solid, icy sludge). (Normally, the formation of hydrates is to be avoided due to being a cause of blockages in equipment and piping. However, in the Low Temperature Separation method of dehydration, hydrates are required and are purposely made to form in order to separate the maximum amount of water from the gas.).

The hot fluid flow through the spinner coil is manually controlled by a globe valve in the inlet flow line. This valve is adjusted as required to maintain 100 to 110 °F coil outlet temperature. Further into the LTS vessel, the cooling of the fluids by expansion causes more water and condensate to form together with HYDRATES. The liquids and semi-solid hydrates flow down the length of the vessel bottom.

Warm, wet gas from the 'Classifier', (discussed later), also enters the LTS vessel near to the spinner. In order to convert these hydrates back into water and condensate, another hot fluid coil runs the length of the vessel bottom. As the liquids flow along the separator, the hydrates melt and separation of hydrocarbon condensate and water takes place and

form an interface. Near the end of the vessel, an insulating baffle and a surge baffle separate the cold section of the separator from the warmer end. At the end of the vessel, a hydrate screen is installed to prevent unmelted hydrates from passing into the liquid outlet streams.

Figure: 16 shows the LTS internals

Figure: 16

(The hot fluid system supply temperature is about 200 °F). The bottom temperature is controlled by a TIC/TICV, with the control valve located in the coil outlet line. The dry gas leaves the top of the separator before the insulating baffle and passes to the shell side of the two feed gas coolers.

(These exchangers have temperature control valves, TCV's. These are 3 - way valves (control valve and bypass), controlled by a TIC in the exchanger wet gas outlet line). The dry gas now passes to the Dry Gas Header via a metering unit and on to further processing. (Downstream of the metering unit Flow Element (FE), is a SDV which will close on a signal from the Shut-down system. Upstream of the FE, a PCV is set to vent excess

gas to flare during any operating pressure fluctuations. This valve however will open to flare on a signal from the Shut-down system). The separated water is piped from the bottom section of the LTS separator to the drain header, controlled by Interface Controller LCI & LCIV. (LCI = Level Control Interface). Condensate is piped via a flow element FE/FR and level control system (LIC) to further processing.

LOW TEMPERATURE SEPARATION (L.T.S) (DETAILS)

The principle of Low Temperature Separation is based on the 'Joules-Thomson Effect'. This is, when a high pressure fluid is expanded into a lower pressure, larger volume system, 'Auto-refrigeration' takes place causing a decrease in temperature. The degree of temperature drop depends on the amount of pressure drop and the increase in volume. This principle is used in LTS to achieve the removal of water from Natural Gas. The following simplified plant description covers a process used on Natural Gas that is produced directly from high pressure wells and therefore needs no compression before processing.

Fig.17

This process description covers a single LTS unit. Depending on the number of wells and amount of gas to be processed, the overall plant will consist of multiple units (or trains).

INLET MANIFOLDS (Figure: 18)

Each producing well is piped to the inlet shut-down manifold where it passes through a shut-down valve (SDV) which is operated by the automatic emergency shut-down system. Each SDV has a startup bypass and choke. From the shut-down valve, the well flow-lines pass to the inlet manifold where each line is fitted with a flow element to meter the gas flow rate. The gas then passes to the plant via a choke valve. At the inlet manifold the wells can be diverted to the 'Flow Splitter' Vessel V.1 as operating conditions require.

Fig 18

FLOW SPLITTER (V.1) (Figure: 19)

This vessel is spherical and serves to separate well liquids from the gas stream. The main purpose of the splitter is to divert all or part of a well stream fluid flow from its normal train to one or more trains, by operating a series of valves at the inlet manifold as production requires. Usually, a LTS system comprises a number of identical processing trains. Each train is fed by one or two wells to give the desired throughput of wet gas. The splitter system may be operated at, for example, 1700psi. The above diagram is showing

a single inlet flow line, the other inlets are identical and all may feed the flow splitter or go directly to one of the LTS trains.

Figure: 19

The pressure and temperature figures and equipment identification numbers used in this explanation are simply examples and not necessarily actual process data. The fluid flow from the inlet manifold and/or the flow splitter passes to a well-stream cooler at about 1700 Psi and up to 240 °F. In the flow line to the cooler, a shut-down valve - SDV - is installed which closes on activation of the shut-down system.

The well-stream cooler is an Air-fin type having two fans. The outlet temperature of the cooler is automatically controlled by a Temperature Controller (TIC) which adjusts the pitch of the fan blades to maintain an outlet of about 130 °F. During cold, winter weather, it may be necessary to shut down one fan to maintain the required temperature. A high outlet temperature will tend to decrease the dew-point depression in the LTS units, while a low temperature will cause premature formation of hydrates. The fluid flow from the cooler is piped to the Intermediate Separator (KO Drum V.2). (Fig: 20). This is a spherical 3-

phase separator vessel with a bottom liquid boot. However, hydrocarbon condensate is re-entrained in the outlet gas by a 'Stinger' mechanism which 'sucks' the gas condensate out with the gas.

The water phase is piped away from the boot to the drain header controlled by a Level Controller (LIC) which operates a Level Control Valve (LICV) in the drain line. The water which is dumped to the drain header is metered and recorded. Since it is likely that liquid 'slugs' will enter the plant from the wells, V.2 will serve to catch these slugs and lessen the problem of process upsets in downstream equipment.

The wet gas and condensate leave the top of the vessel and pass to the tube side of a gas/gas exchanger (# 1) at about 130 °F and is cooled by cold dry gas from the LTS to about 95 °F. In the line to the exchanger, a SDV is installed to vent fluids to flare on activation of the shut-down system. The tube-side wet gas outlet temperature of the exchanger is controlled by a Temperature Controller operating a control valve. This is a 3-way control valve incorporating a by-pass, placed in the cold gas line from the LTS to the shell-side of the cooler. A differential pressure indicator gauge - PDI - measures and indicates the Pressure Difference (PD) across the cooler and is used for periodical checks by operating personnel. Normal PD should be up to 15 psi and, if it begins to increase, may indicate the formation of hydrates or wax in the tubes. The cooled, wet gas passes into the Choke Knock-out vessel V.3.

CHOKE KNOCK-OUT DRUM V. 3 (Fig: 20).

This vessel is a 2-phase separator having a liquid boot. The cooled fluids enter the top of the drum and water and hydrocarbon condensate are separated out. The separated liquids pass from the bottom of the separator to the 'Classifier' vessel, V.4, under level control. High and low liquid level alarms are fitted which are enunciated in the control room. A Low Level Switch (LLS) will activate a shut-down on very low level in order to prevent gas from passing into the Classifier. From the choke knock-out vessel, V.3, the gas phase passes through a mist extractor, leaves the top outlet and passes through the tube side of a second gas/gas exchanger (# 2) where it is cooled to about 70 °F by cold, dry gas from the LTS. The gas then passes into the LTS via the inlet choke valve. The exchanger tube-side outlet temperature is controlled by a TC in the dry gas, shell-side flow, which controls the TCV - a 3-way valve incorporating a bypass.

INTERMEDIATE & CHOKE SEPARATORS (V.2 & V.3)

Figure: 20

CLASSIFIER V. 4 (Figure: 21)

The Classifier is a 3-phase separator vessel in which vapour is released due to the pressure decrease of the liquid from the choke knock-out drum. The gas is piped into the

LTS vessel. The temperature in the classifier is about 82 °F, (with no added heat), at about 730 psi. At these conditions there should be no danger of waxing or freeze-up in the classifier. As a precaution, a coil is fitted in the vessel which will circulate hot fluid at about 200 °F.

V.4. has a temperature sensing element located in the hydrocarbon liquid phase that controls the hot fluid outlet by a TIC which maintains the hydrocarbon phase at about 97 °F. If this temperature becomes too low, waxing could occur in the classifier and, if too hot, the gas dew point of the LTS outlet gas would increase. The TICV is connected into the shutdown system by a high pressure switch.

This system will close the TICV to prevent gas blow-through to the hot fluid system in the event of a line rupture in the heating coil allowing high pressure fluids to enter the system. Also, in the hydrocarbon liquid phase a temperature switch will activate high and low temperature alarms and a low temperature shutdown.

The water separated out in the classifier is piped to the drain header controlled by an interface controller and high and low water level alarms are fitted. Hydrocarbon liquid is controlled to the LTS condensate header by a LIC/LICV. Condensate goes on to further processing. The condensate flow is metered and recorded. Low and high condensate level alarms are also installed in the system. As stated earlier, wet, warm gas released in the classifier, is piped into the LTS vessel.

CLASSIFIER V. 4

Figure: 21

NATURAL GAS SWEETENING BY AMINE SOLUTION - INTRODUCTION

Many natural gases are produced from wells containing hydrogen sulphide, sulphur compounds and carbon dioxide. These gases are treated prior to sale or entry to a process plant. A gas which has high concentration of sulphur compounds is called 'Sour' gas. (Also called 'Acid' gas). The gas produced from some fields is 'Sour', because it contains a high concentration of hydrogen sulphide (H2S) and some carbon dioxide (CO2). The H2S and CO2

are known as acid gases, and are corrosive, if water or oxygen is present. The hydrogen sulphide H2S must be removed from the NATURAL gas before it can be used, due to the fact that it is highly corrosive and highly toxic. One of the main objectives of the plant is to remove H2S from the produced gas by using a chemical 'Amine' solution in an Absorption process.

The Amine solution selectively removes the H2S and sulphur compounds during the sweetening process; however, some of the CO2 is also absorbed. CO2 concentration in the gas is below the allowable concentration for the pipeline specification (less than 5%). (The processes of Absorption and Adsorption can be found in everyday life. In Industry, we use these processes to remove unwanted substances from process streams to clean and purify to help prevent corrosion and erosion of equipment).

AMINE PROCESS FOR GAS SWEETENING

There is a number of absorption gas treating processes, but the most common is the amine process in which acid gases react chemically. The 'rich' amine solution is heated under low pressure to regenerate the liquid by driving off the acid gases.

Several different amine solutions can be used.

• Methyl Di-ethanol Amine (MDEA)

• Mono-ethanol Amine (MEA)

• Di-ethanol Amine (DEA)

The sweetening process is similar for each of the amine solutions listed. The type of solution used in the process will depend upon the type and quantity of acid gas contained in the sour gas stream and the volume of sour gas to be treated.

SELECTION

There are no hard and fast rules determining which solution to use for a given sweetening operation. The process that is selected is usually designed for the specific sweetening application, and would not necessarily be the proper choice in another application.

Following are the general factors which are taken into consideration when selecting a sweetening process.

• Types of impurities in the sour gas stream.

• Acid gas concentration in the sour gas and degree of removal required.

• Preference of an acid gas to react with the solution (acid gas selectivity).

• Temperature and pressure at which the sour gas is to be processed.

• The total volume of sour gas to be treated.

• The cost of sweetening agents and plant costs.

PRINCIPLES OF GAS SWEETENING WITH AMINE SOLUTION

For this process description 'MDEA' is the amine solution selected. Gas sweetening with amine solution is based on the chemical reaction of weak alkaline with weak acid. The amine solution is alkaline and H2S & CO2 are acidic. The reactions involved are very complex, but the following summaries the basic processes. The reaction in the absorber is at constant pressure and a temperature range between 80 °F to 120 °F. It is a reversible reaction.

2RNH2 + H2S >>> (RNH2)2S

(Amine + hydrogen sulphide) >>> (Amine sulphide + heat)

2RNH2 + CO2 + H2O >>> (RNH2)2H2CO3

(Amine + Carbon dioxide + Water) >>> (Amine bicarbonate + heat)

The Regeneration reaction in the reboiler and stripper is at a constant lower pressure and a temperature range between 240 °F and 300 °F.

(RNH3)2S + Heat >>> 2RNH2 + H2S

(Amine sulphide) >>> (Amine + hydrogen sulphide)

(RNH3)2CO3 + Heat >>> 2RNH2 + CO2 + H2O

(Amine carbonate >>> Amine + Carbon dioxide + Water)

The H2S is removed by a chemical reaction that is reversible and dependent on the temperature change. The CO2 is physically absorbed. Because of this difference in reaction, MDEA is used to selectively remove H2S while leaving most of the CO2 in the gas leaving the amine absorber.

The H2S / Amine reaction is fast, while the CO2 / Amine reaction is slow. The longer the amine solution stays in the absorber, the more CO2 will be taken in by the amine solution.

The reaction governing H2S removal from the sour gas is temperature dependent and the direction of equilibrium is shifted by temperature changes. In addition to temperature, the partial pressure of the acid gases will also influence the equilibrium of the reaction.

The amine solution used is a mixture of 50% MDEA and pure water. The sulphide and carbonate salts that are formed as a result of the chemical reactions are dissolved in the amine solution. Thus the rich amine solution at the bottom of the amine absorber is a mixture of water, MDEA, amine sulphide & amine carbonate.

GENERAL PROCESS DESCRIPTION (See Figure: 22)

The incoming fluids from the wells are first passed into the production separator where water and liquid hydrocarbons are separated out. From here the gas is then further separated from liquids in the gas scrubber before going to the sweetening process in the Amine Absorber.

Fig 22

AMINE ABSORBER (Valve (or Ballast) type Tray Tower) (See Figure: 23)

The sour natural gas stream from the gas scrubber enters the bottom of the amine absorber tower. The lean Amine (MDEA) solution enters at the top tray of the absorber which contains 20 'Valve' or 'Ballast' type trays. As the gas flows upward through the absorber tower, it contacts the down-flowing lean amine solution. The H2S is absorbed from the gas by the MDEA solution flowing across the trays and downward through the tower.

As the gas passes through the valves on the trays, it is forced to bubble through the MDEA solution flowing across the tray. This bubbling gas-liquid contact promotes absorption, as the H2S rich gas is dispersed through the lean MDEA solution. The MDEA solution becomes more saturated ('Richer') with H2S as it passes across each tray and to the bottom of the absorber tower from where it is piped to the Amine Regeneration Section.

The sweet gas passes from the tower top via a mist extractor element and is piped to the dehydration section of the plant. The amine solution in the bottom of the absorber is called 'Rich' solution. The absorber tower amine level is maintained by a level control system (LCS). The rich MDEA solution flows from the bottom of the absorber through the LCV to the first stage of the regeneration process - the amine flash separator.

THE FLASH SEPARATOR

This separator is a two phase horizontal vessel operating at a lower pressure than the absorber. The pressure decrease causes dissolved gases to be flashed off from the amine - (like opening a can of 'Pepsi'). The gas which is flashed off in the separator contains H2S, CO2, and entrained hydrocarbons. This gas leaves the separator through a small, vertical column attached to the top of the separator called the 'Re-absorber', to either flare header or to fuel via a pressure control system which maintains the flash vessel pressure.

The column contains packing and receives a small flow of lean amine above the packing as a kind of 'reflux' to knock out any amine vapour from the rising gases and to re-absorb acid gases to prevent sour gas going to the fuel system. The rich amine solution from the flash separator flows to the rich/lean amine exchanger. The main purpose of this heat exchanger is to pre-heat the rich amine going to, and to cool the lean amine coming from, the regeneration reboiler.

From the exchanger, the rich amine solution flows into a cartridge filter to remove dirt, debris and solid particles before it enters the amine stripper.

AMINE STRIPPER

The amine stripper tower is a tray type tower used to remove absorbed acid gases from the rich amine solution. As the rich amine flows downward from the feed tray, it is contacted by rising hot vapours generated in the reboiler at the bottom of the stripper. This rising vapour effectively strips the H2S & CO2 from the rich amine solution.

The sour gases, hydrocarbons and water vapour leave the top of the stripper via a demister screen to a reflux condenser where the water vapour and any amine vapour are condensed to provide a liquid reflux back to the amine stripper. The acid gases (H2S & CO2) and HC's are vented through a pressure control valve (PCV) to the flare system.

The semi-lean amine that accumulates in the bottom of the amine stripper flows by gravity into the bottom of the amine reboiler.

SIMPLIFIED DIAGRAM OF GAS SWEETENING PLANT

Figure: 22

TOWER INTERNALS - VALVE TRAYS

Figure: 23 - Valve Tray Operation

AMINE REBOILER (See Figure: 24)

The purpose of the reboiler is to add sufficient heat to the semi-lean amine to complete the process of removing the absorbed gases from the solution. This is achieved by heating the amine by using a hot oil flow through the 'U' -tube type exchanger bundle in the reboiler. The reboiler temperature is controlled by a cascade TC/FC control system in the hot oil outlet from the reboiler. The reboilers is constructed with an internal weir, which maintains the amine level above the hot oil tubes giving the required residence time for maximum heat transfer rates and prevent overheating of the unit. The hot, lean amine flows over the weir into the draw-off section from where it is piped via a level control system to the rich/lean amine heat exchanger.

The hot vapours leaving the top of the reboiler consist of water vapour, acid gases, some HC's and amine vapour. This hot mixture of gases passes into the bottom of the amine stripper and, as it passes upwards through the contacting trays, strips out the absorbed gases from the down-flowing amine solution.

AMINE REGENERATION REBOILER

FIGURE: 24 -Typical Kettle Type Reboiler

The lean amine from the heat exchanger passes to the amine storage/surge tank from where it is picked up by the booster pumps to be circulated back to the system. (The storage vessel also provides a steady positive suction head pressure for the amine solution booster pumps). The surge tank is also used for the addition of make-up solution to maintain the correct amount and concentration of amine solution in the system. The amine booster pumps take suction from the surge tank and discharge the amine

through an air- fin cooler to the charge pumps which deliver the lean amine to the absorber top via a flow control system.

From the booster pumps discharge line, a small flow of amine (about 10%), is passed through a charcoal filter. This is such that, over a period of time, the total volume of amine will have been passed through the charcoal. This is used to adsorb hydrocarbons from the amine. Two extra charcoal 'towers' have been fitted into the system downstream of F.350 charcoal filter in order to ensure that all undesirable chemicals are removed from the amine. The towers are operated with one in service and one standby.

GAS SWEETENING EQUIPMENT AND OPERATING CONDITIONS.

The following are the major items of equipment in the gas sweetening system. (Amine System).

THE OPERATING PARAMETERS IN THIS DESCRIPTION ARE USED FOR REFERENCE ONLY. THEY WILL VARY ACCORDING TO PROCESS REQUIREMENTS.

• A. ABSORBER TOWER

• B. STRIPPER TOWER

• C. FLASH SEPARATOR

• D. REGENERATION SYSTEM

A. THE ABSORBER TOWER

The absorber has 20 valve type trays. The trays are numbered from the top down. The sour feed gas enters at the bottom of the tower. Three separate feed points for the lean amine solution are provided in the absorber. The top feed point goes to Tray No. 1, the middle feed point to Tray No. 5 and the lower point to Tray No. 9. The lower the feed point, the less contact time the amine has with the sour gas.

This low contact time allows the amine to absorb H2S while leaving most of the CO2 in the gas. The amine feed would be raised to the higher tray as the gas field gets older and the H2S concentration increases. The sweet gas leaving the amine absorber top, must have less then 4 ppm of H2S or, as per company specification.

Normal operating conditions of the absorber are 650 psig and 83 °F. The operating pressure is maintained by the plant back pressure control system located on the gas metering skid.

The absorber amine level is controlled by a LC/LCV.

The flow of lean amine solution to the absorber is controlled by a FC/FCV located in the discharge line from the amine charge pumps.

The temperature of the amine solution entering the absorber is very critical to the operation of the absorber. If the amine inlet temperature is below the sour gas inlet temperature, some gas condensate may form in the amine solution and cause 'Foaming' of the amine. This can lead to carry-over of amine from the system and other contacting problems giving rise to a poor sweetening process. In order to prevent the formation of liquid hydrocarbons, the lean amine solution entering the absorber should be 10-15 °F above the absorber inlet sour gas temperature. At the top of the absorber there is a steel mesh de-mister pad that coalesces mist like droplets of liquid into larger drops that will fall back down the tower. Its purpose is to help prevent amine losses. The amine absorber is designed is to handle up to 77 MMscf/d of sour gas and 333 GPH of 50% strength MDEA solution.

B. AMINE STRIPPER

The amine stripper is a vertical fractionation tower containing 20 single pass trays. The amine solution enters the tower between tray No. 3 and No. 4. The chemical reaction in the stripper reverts the amine sulphide and amine carbonate to amine and acid gas when heat and stripping steam are supplied. The stripping steam is generated in the reboiler from the water in the amine solution.

The chemical reactions in the stripper are as follows:

(Amine sulphide + Heat & stripping steam) ===> H2S + amine solution

(Amine carbonate + Heat & stripping steam) ===> CO2 + amine solution

The percentage of amine sulphide & carbonate that convert to acid gas and amine depends upon the amount of heat and stripping steam applied to the stripper tower. The stripping steam generated in the reboiler enters the stripper tower just below tray No. 20. As the stripping steam flows upward through the tower, it forces the valves on the trays to open and the vapour bubbles through the rich amine solution flowing across the tray. The hot stripping steam is the source of heat necessary to drive the acid gases out of the rich amine solution.

Reflux is introduced to the stripper at tray No. 1. at a temperature of 148 °F. Reflux is 99.9% water and 0.1% of dissolve gases with a small amount of MDEA. The liquid reflux serves to keep the amine from carrying over with the overhead product. This helps to minimize amine losses from the stripper.

Overhead reflux also helps to control the stripper top tray operating temperature at (217 - 228 °F).

At the top of the stripper tower there is a de-mister pad, which functions exactly the same way as the de-mister pad in the amine absorber tower. Normal operating pressure of the stripper is 18.5 psig. Stripper pressure is controlled by venting acid gases and HC's to flare by a PC/PCV located on the reflux drum.

C. AMINE FLASH SEPARATOR

The amine flash separator is a two phase horizontal vessel with a vertical, packed column attached to its top - called a 'Re-absorber Tower'. The column is filled with stainless steel pall rings. The purpose of the separator is to flash off the entrained gases from the MDEA solution leaving the absorber. Flash gas from the condensate coalescer/surge drum is piped to the base of the re-absorber column. The combined stream of the condensate flash gas and the gas from the flash separator flow up through the re-absorber packed section and out at the top. A small, measured stream of lean amine solution is fed into the top of the re-absorber contactor and, as the solution flows downward through the packing of the tower, it absorbs most of the acid gases from the up-flowing flash gas, in the re-absorber column. The gas stream leaving the re-absorber column is used for fuel in the hot oil heaters.

The solution which flows down through the re-absorber column falls into the flash tank to join the rich amine solution coming from the bottom of the amine absorber tower through a level control valve (LCV). The operating pressure of the amine flash separator is 75 psig, which is a very low pressure compared to the amine absorber operating pressure of 650 psig. Since the pressure of the rich amine solution leaving the absorber is reduced from the absorber pressure to amine flash separator pressure, most of the dissolved hydrocarbon and acid gases entrained in the amine solution, will be released. A pressure control system PC/PCV maintains the separator at 75 psig, by venting excess gas to the Fuel system feeding the hot oil heaters. The rich amine level is maintained in the bottom of the flash separator by a level control system located down-stream of the amine filters.

D. AMINE REGENERATION

The rich amine is regenerated (re-concentrated) by a simple, continuous distillation process that removes the absorbed acid gases and hydrocarbons from the amine. The process includes filtration for removal of other contaminants, degradation products, deposits, dirt, impurities etc. in order to restore the amine solution concentration for re-

circulation through the system. The Amine regeneration skid at the gas plant consists of the following equipment.

1. AMINE REBOILER

2. RICH/LEAN AMINE PLATE HEAT EXCHANGER

3. AMINE CARTRIDGE FILTER

4. AMINE REFLUX CONDENSER & ACCUMULATOR

5. AMINE CHARCOAL FILTER & TOWERS

6. LEAN AMINE COOLER

1. AMINE REBOILER (Refer back to Figure: 24)

This is a kettle type reboiler containing a stainless steel 'U' - tube bundle. The lean amine solution from the bottom of the stripper tower flows to the reboiler, the purpose of which is to 'Boil off' the remaining acid gases from the semi-lean amine solution. This process generates hot vapours which leave the top of the reboiler and flow to the stripper below the bottom tray, and then flow upward in the stripper tower. The up-flowing hot vapour effectively strips out much of the acid gases from the rich amine as it flows across the contacting devices on the trays.

To generate the hot vapour, the amine in the reboiler is heated to about 264 °F by hot oil flowing through the reboiler tube bundle at 490 -500 °F. The hot oil supply to the amine reboiler is regulated by a flow controller FC/FCV in the hot oil outlet line. This controller is cascaded with a temperature controller for reboiler temperature control. The reboiler has two sections separated by a weir that maintains the amine level above the hot oil tubes thereby minimising 'hot-spots'.

The amine solution flows from the stripper bottom and enters the reboiler heating section bottom and passes along the shell side of the tube bundle, and spills over the top of the weir into the containment section. The now 'Lean' amine solution collects in the containment section and leaves the reboiler under level control to the rich/lean amine plate heat exchanger .

2. RICH/LEAN AMINE PLATE HEAT EXCHANGER (See Figure: 25)

The rich/lean amine heat exchanger is a plate-type exchanger composed of a number of corrugated stainless steel plates compressed together. This type of heat exchanger gives a large amount of heat transfer in a compact space when counter- current flow is used.

The rich and lean amine plate segments are only separated by a gasket. The function of this heat exchanger is to transfer heat from the lean amine solution leaving the amine reboiler at 264 °F, to the rich amine solution coming from the flash separator at 130 - 140 °F.

From the exchanger, the lean amine solution flows to the amine surge tank at a temperature of 185 190 °F, while the rich amine flows to the amine stripper after passing through the amine filters at a temperature of 210 °F.

Figure: 25 -Amine/Amine Plate Heat Exchanger

3. AMINE CARTRIDGE FILTERS

(See Figure: 26) As the amine solution circulates in the system, it picks up dirt and debris, as well as products of corrosion. These solid particles can cause foaming in the amine stripper & absorber. The filters are designed to remove suspended solids of 10 microns and larger from the rich amine solution before it enters the amine stripper. Each filter is capable of filtering a stream of 450 GPM which is 120% of design stream at a clean pressure of 3 psi. One filter is in service handling the full flow of amine solution, while the other filter is in standby.

Figure: 26 -Cartridge Type Filter Units

4. STRIPPER REFLUX CONDENSER, ACCUMULATOR AND PUMPS

A. STRIPPER REFLUX CONDENSER (See Figure: 27)

The acid gases (H2S & CO2) stripped from the rich amine plus water vapour, flow from the amine stripper to the reflux condenser at a temperature of 217 - 228 °F. In the reflux condenser, the water vapour is condensed to provide a liquid reflux back to the amine stripper at a temperature of 148 °F.

The stripper reflux condenser is an air-fin type exchanger through which the amine tube bundle makes multiple passes. Air is moved over the tube bundles by electric motor driven fans. The "B" fan on the cooler has 'Variable Pitch' blades -meaning that the pitch (or angle) of the blades can be adjusted to increase or decrease the air flow from the fan. A Temperature Controller on the outlet of the reflux condenser gives a signal to the pitch control system to increase or decrease the blade angle thereby giving more or less cooling air flow across the tube bundles of the exchanger. Fan "A" has no pitch control. Both fans have to be started or stopped manually by a local ON/OFF switch. One reflux fan must be

running at all times. If both fans are off, the hot oil flow to the reboiler will automatically be stopped.

Figure: 27 - Air-fin cooler - One fan with controlled pitch blades

B. REFLUX ACCUMULATOR

The reflux accumulator is a vessel used to separate the liquid condensed in the reflux condenser from the gas. The incondensable acid gases and other vapours are released through a pressure control system to the low pressure flare system, thus maintaining the accumulator pressure at 10 psig. The liquid level in the accumulator is controlled by level controller located in the discharge line of the stripper reflux pumps

C. STRIPPER REFLUX PUMPS

The reflux accumulator provides a positive suction head pressure to the reflux pumps. The reflux liquid is 99.5% water with a small amount of dissolved gases and an insignificant amount of MDEA. One of two reflux pumps, (one standby), discharges 12 -20 gpm at 60 - 65 psig to the top tray of the stripper.

A strainer is installed in the suction line of each pump to remove debris, and, when discharge pressure drops below normal, it is a good indication that the strainer needs cleaning. The level control valve located on the combined discharge line of the pumps maintains the level in the reflux accumulator.

Note: The gas in the reflux accumulator contains the highest concentration of H2S gas in the plant which makes it the most toxic area to the personnel working on the gas plant. Any release of gas to the atmosphere must be dealt with, with great care.

5. LEAN AMINE COOLER (Same type as Figure: 27)

As mentioned earlier, the lean amine solution temperature entering the absorber should be close to the outlet temperature of the gas from the absorber. Generally the solution taken from the surge tank is too hot for use in the absorber. Hot amine solution will not remove as much acid gas as a cool solution. Therefore, it is important to cool the lean solution before it is fed to the amine absorber. The booster pumps take suction from the lean amine surge tank and discharge it to the cooler via the charcoal filter. Upstream of the cooler, a flow of lean amine is taken to the shell side of the amine/condensate heat exchanger to give pre-heat to the condensate stripping system. This amine is returns to the flow line to the cooler.In the cooler, the lean amine solution is cooled to a temperature of about 10 °F higher than the gas temperature entering the amine absorber.

(Maximum amine temperature should be held to 100 -105 °F).

The lean amine cooler is an air-fin exchanger in which the amine makes multiple passes in each of two parallel tube bundles. Air is moved over the tube bundles by two motor driven fans -'A' & 'B'. Fan 'B' is a variable pitch blade type. The blade pitch is controlled by a TC in the cooler outlet line, that varies the angle of the pitch of the blades thereby changing the mass air flow across the tube bundles. Both fans have to be started or stopped manually by a local ON/OFF switch. Fan 'A' is not controllable and is switched on or off manually as required. One amine fan must be running at all times.

If both fans are off, the amine circulation will automatically be stopped to prevent hot amine solution from going to the absorber. The amine outlet from the cooler flows to the three amine charge pumps upstream of which a small flow of amine is taken to the re-absorber tower on the amine flash separator.

About the Author

Norrie is a retired professional who has been working in Oil and Gas and LNG production in Marsa-el-Brega, Libya for 30 years.

Norrie used to be in the Training Dept. and prepared Programmes for Libyan Traine