Gas Plant 2

Eni Corporate University G

R

O

U

P

TRAINING PROGRAM MINISTRY OF OIL OF IRAQ JUNIOR PRODUCTION ENGINEER

GAS PLANTS 2 Lecturer: Eng. Romano Bianco

BOOKLET N° 2 Code: IMG017-E-A0

Rev.: 02

Date : 30/07/2004

Pages number: 94

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 2 of 94

GENERAL INDEX

1 NATURAL GAS

BOOKLET N° 1

2 NATURAL GAS PROCESSING

BOOKLET N° 1

3 SURFACE WELL EQUIPMENTS

BOOKLET N° 1

4 COLLECTION AND TREATMENT CENTRE

BOOKLET N° 1

5 TREATMENT LINE

BOOKLET N° 2

6 GLYCOL DEHYDRATION SYSTEM

BOOKLET N° 2

7 COOLING TREATMENT PLANTS

BOOKLET N° 2

8 SOLID BED NATURAL GASOLINE PLANT

BOOKLET N° 2

9 LPG PLANT

BOOKLET N° 2

10 PROPANE DEHYDRATION

BOOKLET N° 2

11 COS TREATING

BOOKLET N° 2

12 MERCAPTAN TREATING

BOOKLET N° 2

13 SWEETENING

BOOKLET N° 2

14 SULPHUR RECOVERY PLANT

BOOKLET N° 2

15 TAIL GAS TREATMENT

BOOKLET N° 2

16 COMPRESSION UNITS

BOOKLET N° 3

17 DEHYDRATION BY SOLID BEDS

BOOKLET N° 3

18 SOUR WATER STRIPPER PLANT

BOOKLET N° 3

19 FLARE SYSTEM

BOOKLET N° 3

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 3 of 94

20 NITROGEN PRODUCTION

BOOKLET N° 3

21 COMPRESSED AND INSTRUMENT AIR SYSTEM

BOOKLET N° 3

22 FUEL GAS SYSTEM

BOOKLET N° 3

23 WATER TREATMENT SYSTEM

BOOKLET N° 3

24 FIRE FIGHTING SYSTEM

BOOKLET N° 3

25 POWER SUPPLY SYSTEM

BOOKLET N° 3

26 ALARM AND SHUT-DOWN SYSTEMS IN GAS PLANT BOOKLET N° 3

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 4 of 94

BOOKLET INDEX 5 TREATMENT LINE 5.1 GENERAL

6 GLYCOL DEHYDRATION SYSTEM

6 6 7

6.1 GENERAL

7

6.2 SCHEME AND FUNCTIONING

7

6.3 STRUCTURE AND FUNCTIONING OF: 6.3.1 Dehydration column 6.3.2 Circulation pumps 6.3.3 Calculation of the glycol flow 6.3.4 Regeneration 6.3.5 Vacuum glycol regenerators 6.3.6 Heat exchangers

12

6.4 OPERATION

27

7. COOLING TREATMENT PLANTS

12 15 17 20 24 27

28

7.1 GENERAL 7.1.1 Cooling by expansion (Joule-Thomson effect) 7.1.2 Operation

28

7.2 LIQUID HYDROCARBON RECOVERY BY MEANS OF COOLING

36

7.3 SCHEME AND FUNCTIONING 7.3.1 Refrigerants 7.3.2 Compressor 7.3.3 Condenser 7.3.4 Evaporator 7.3.5 Economizer. 7.3.6 Stabilizer column 7.3.7 Operation

38

8. SOLID BED NATURAL GASOLINE PLANT

28 35

40 42 42 43 43 46 48

49

8.1 GENERAL

49

8.2 SCHEME AND FUNCTIONING

49

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 5 of 94

8.3 STRUCTURE AND FUNCTIONING OF: 8.3.1 Adsorbers 8.3.2 Air Coolers 8.3.3 Filters

9. LPG PLANT 9.1 SCHEME AND FUNCTIONING

10 PROPANE DEHYDRATION 10.1 GENERAL

11 COS TREATING 11.1 GENERAL

12 MERCAPTAN TREATING

53 53 55 55

57 57 62 62 64 64 67

12.1 GENERAL

67

13 SWEETENING

69

13.1 SCHEME AND FUNCTIONING

74

13.2 DESCRIPTION AND FUNCTIONING OF: 13.2.1 Absorption Column 13.2.2 Gas Scrubber 13.2.3 Regeneration Column 13.2.4 Re-boiler 13.2.5 Reflux Drum 13.2.6 Operation

79

14. SULPHUR RECOVERY PLANT 14.1 SCHEME AND FUNCTIONING CLAUS PROCESS

15 TAIL GAS TREATMENT 15.1 GENERAL

79 79 80 80 81 81

88 88 93 93

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 6 of 94

5 TREATMENT LINE 5.1 GENERAL After having undergone temporary treatments, the natural gas is delivered from the production wells to the gas treating centre where it is processed to meet the users’ specifications. In general, the natural gas has to be processed to eliminate or reduce the content of the following constituents. 1. Reducing water through: -

Dehydration with liquid absorbents

-

Dehydration with solid adsorbents

-

Dehydration through cooling expansion

2. Reducing the content of heavier hydrocarbons through: -

Adsorption

-

Cooling and heavier hydrocarbons recovery

3. Reducing the content of hydrogen sulphide and carbon dioxide through: -

Sweetening

These treatments are carried out by the use of the correct type of process units, according also to the natural gas composition as described below.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 7 of 94

6 GLYCOL DEHYDRATION SYSTEM 6.1 GENERAL The dehydration of natural gas to meet the water dew point specification, is usually obtained by glycol absorption. The glycol unit is the most commonly used dehydration system for gas treating, since it is practical and easy to operate. The type of glycol can be di-ethylene glycol (DEG) or tri-ethylene glycol (TEG). The glycol units can have two types of configurations: - Closed circuit systems. - Open circuit systems. In the first configuration, the contactor is connected to its regeneration system only. It is a “rigid” system, as the plant has to be stopped in case the regenerator has some problem. In the open circuit configuration, on the contrary, there are two or more regenerators common to all the contactors. This is a more commonly used solution and compared to the first configuration, it allows a more flexible operation. This system requires only the installation of two tanks, one for the storage of the exhausted glycol and the other for the storage of the regenerated glycol. (Fig. 6.1, 6.2, 6.3). 6.2 SCHEME AND FUNCTIONING The glycol plant is composed of: a) An absorption column; called also contactor b) A regenerator, composed of: -

Flash Drum

-

Re-boiler;

-

Distillation tower with reflux;

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 8 of 94

-

Filters;

-

Glycol circulation pumps.

The wet gas enters into the bottom of the absorption tower, and flows upwards through a certain number of trays, usually valve type or bubble cap type. Regenerated glycol is circulated by means of a pumping system at the top of the contactor and flows downwards. The gas flows through the trays and bubbles through the glycol, that removes by absorption the water contained in the gas. Gas flows from one tray to another, up to the top of the contactor, while the glycol is collected in the bottom of the absorber, diluted due to the amount of water removed from the gas. The diluted glycol stream is called RICH GLYCOL (rich in water). The level of glycol in the tower bottom, is maintained by a level controller that operates a control valve on the rich glycol outlet line. The gas coming out from the top of the absorber is dehydrated at the required water dew point. The rich glycol from the bottom of the contactor, is sent to storage, and then to the regenerator where, at a high temperature, it is re-concentrated. The regenerated glycol stream is called also Lean Glycol. The lean glycol is then pumped to the regenerated glycol tank and, from there,

is

pumped

again

to

the

top

of

the

contactor.

(Fig.6.1)

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 9 of 94

Figure 6.1 – Glycol dehydration plant Open circuit with Rich and Lean Glycol Tanks Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 10 of 94

Fig. 6.2 - Gas Dehydration Unit - Closed circuit alternative Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 11 of 94

Fig. 6.3 Gas dehydration and Dew Point Control Process Flow Diagram

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 12 of 94

6.3 STRUCTURE AND FUNCTIONING OF: 6.3.1 Dehydration column Water is eliminated from the gas stream in the dehydration column, which is composed of the following elements (Fig. 6.4). • A separator at its bottom, whose task is to remove any liquid phase from gas, mainly liquid hydrocarbons that could cause foaming in the upper part of the contactor. • A chimney tray, is located between the bottom separator and the absorbing upper section. It collects the rich glycol so that it does not mix with the liquids collected in the bottom separator. • The upper part of the column is used for water absorption by the lean glycol. This section is equipped with trays, bubble cap or valve type, or with a packing, random or structured type. Sometimes, in the small units, a gas/glycol heat exchanger coil is located above the top tray to ensure the cooling of the lean glycol entering the column. In the top of the column, there is demister (a mist eliminator) whose function is to limit the loss of glycol due to gas carry-over. The volumes of the bottom and head sections depend on the amount of circulating liquid and on the flow rate of the gas. The height of the upper section of the contactor is determined by the number of trays or the packing height. Usually, with a gas speed within the column of 0,20-0,30 m/sec, the distance between the trays is of 0,60-0,80 m.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 13 of 94

Figure 6.4 – Dehydration column with bubble cap trays

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 14 of 94

Bubbling cap or valve trays The number of trays depends on the operating temperature, gas flow rate and the dew point required. Usually, the absorbers have from 4 to 12 trays. With regard to the bubble cap tray, each tray is composed of a punched plate with bells mounted on the holes with risers (Fig. 6.5) and with slots in the peripheral wall of each bell, located so as to drive the gas through the glycol, whose level on the tray is maintained by the weirs. The glycol flows across each tray and, passes to the outlet weir, and goes to the lower tray. The rich glycol is collected on the chimney tray. Inside each bubble cap the direct contact between glycol and gas takes place.

Figure 6.5 – Bubble cap Tray

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 15 of 94

6.3.2 Circulation pumps The lean glycol circulation pumps are usually reciprocating type, due to the rather high delivery pressure (the glycol is sent to the contactor top ) and the relatively low flow rate. There is a system of pumps, as a minimum one in operation and one on stand-by, to take lean glycol from the storage tank and the top of the contactor. The rich glycol goes to the downstream parts of the unit, driven by the pressure in the column itself. Normally, the reciprocating circulation pumps are driven by electric motors and have more than one pumping head, provided with an adjustable stroke system. (Fig. 6.6a, 6.6b, 6.7, 6.8)

Fig. 6.6a Reciprocating pump

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 16 of 94

Fig. 6.6b Reciprocating Pump dimensions and performance data

Fig.6.7 - Reciprocating pump

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 17 of 94

Fig. 6.8 Typical reciprocating pump unit

6.3.3 Calculation of the glycol flow Using the diagram of Fig. 6.9, for the known pressure and temperature of the gas saturated with water, it is possible to calculate the amount of water contained. Since a usually required water dew point is -12 °C at the operating pressure, that gives a typical content of water equal to 50 mg/Nm3, it is possible to obtain the amount of water that needs to be removed in the glycol unit. For example: If the gas is water saturated at a pressure of 60 bar and a temperature of 15 °C and the gas flow rate is 1,000,000 Nm3/d, the required information is how much glycol needs to be circulated in order to have a dew point of -12 °C at 60 bar.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 18 of 94

From the diagram, it can be seen that at 60 bar and a temperature of 15 °C, saturated gas contains about 300 g/1,000 Nm3, of water, therefore: Water content = 300x1.000.000/1000= 300.000 g/d = 300 Kg/d of water. From the same diagram: at -12 °C and 60 bar the saturation water content is around 50g/1,000 m3 therefore: Water content, at required gas flow rate, is 0 50x1.000.000/1.000= 50.000 g/d = 50 Kg/d The difference gives the amount of water to be removed by glycol dehydration, i.e.: 300 - 50 = 250 Kg/d of water Experimental data shows that, in order to eliminate 1 Kg of water, 25 Kg of glycol are needed; as a result the required capacity of the pump is: Q= 250x25 = 6250 Kg/d of glycol Expressed in litres: 6250/1,118= 5590 lt/d where 1,118 is the specific weight of glycol

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 19 of 94

Figure 8

Fig. 6.9 Water contents of natural gases with corrections for salinity and relative density

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 20 of 94

6.3.4 Regeneration The glycol regeneration system can be mounted on a skid and installed far from the absorption tower in the “fire area” of the plant. The unit shown on Fig. 6.10 is a typical regenerator of a small unit, where the flash drum is integral with the Lean glycol accumulator.

Figure 6.10 – Regenerator (typical arrangement for a small unit)

A more common arrangement for a high capacity dehydration unit, usually installed in a multiple-train gas treating plant, with two or more glycol contactors, is described below. Rich glycol from the bottom of the absorption tower, is firstly sent to a Flash Drum, operated at a lower pressure, e.g. 4 bar, where absorbed hydrocarbons are released from the gas and separated as liquid by gravity. Then the rich glycol, under automatic liquid level control in the flash drum, is sent to a storage tank. From the storage tank, the rich, i.e diluted glycol, is sent to the regeneration section. Firstly by means of a transfer pump,

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 21 of 94

usually centrifugal type, it is sent to the filtering system and then to a coil located inside the top of a distillation column, usually called a Still Column. The purpose of the coil is to create, by cooling, a water reflux stream inside the still column. The heat to partially condense the vapours that flow upwards inside the still column is transferred to the rich glycol, which at the coil outlet has a higher temperature. Then, the rich glycol. goes to the heat exchanger train where it is heated by the hot regenerated glycol, and, finally, through a control valve, operated to control the flow rate, enters the regeneration column. The filtered and hot glycol at about 160 °C, enters the regeneration column. Inside the column, usually, there two sections of packing elements, such as Pall rings or equivalent, that act respectively as a rectification section, the upper one, and stripping section, the lower one. In the lower packed section, the water is stripped out from the glycol stream that flows downwards and in the upper packing, the water reflux reduces the glycol content of the upward flowing vapours, so as to reduce the glycol losses. The still column is usually connected by a body flange to the re-boiler, horizontal installed above the accumulator vessel, also horizontal. The reboiler can be heated by a fire tube system or by M.P steam. The operating pressure is almost atmospheric and the concentration of the regenerated glycol depends on the type of glycol and the temperature of the re-boiler. Typical performance data and operating temperatures are as follows: a) With Di-ethylene Glycol (DEG) at 164 °C (maximum allowed temperature in the re-boiler), the achieved purity is 96 % by weight (the rest is water). b) With Tri-ethylene Glycol (TEG) at 204 °C (maximum allowed temperature in the re-boiler), the achieved purity is 99 % by weight (the rest is water).

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 22 of 94

The vapours leaving the top of the still column are mostly steam with other components, which depends on the nature of gas to be dehydrated and has come in to contact with the lean glycol in the absorber. The temperature of the overhead vapours is around 100 °C. The hot regenerated glycol flows from the reboiler to the heat exchanger train, where it is cooled against the rich glycol and then, by means of pumps, usually centrifugal type, through a final cooler either by air or water where a temperature of 50 °C or so is reached, before being sent to the lean glycol storage tank. From the tank, the regenerated glycol is sent, by means of the reciprocating pumps mentioned earlier, to the absorption tower (Contactor).

Fig. 6.11 - Glycol gas dehydration - Typical arrangement of a skid-mounted unit

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 23 of 94

Fig. 6.12 - Glycol Storage tank system

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 24 of 94

6.3.5 Vacuum glycol regenerators To improve the purity of lean glycol, as the temperature cannot be increased in the reboiler higher than the values said before, due to the glycol decomposition at higher temperatures, so alternative, ways to reduce the pressure of the regenerators have been adopted. The more common systems are: 1) VACUUM PUMP (Fig. 6.13) 2) INJECTOR/EJECTOR (Fig. 6.14) The vacuum pump is connected to the top of the still column and creates a certain degree of vacuum in the system, still column and reboiler. In the other solution, the ejector uses steam as power fluid.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 25 of 94

Figure 6.13 – Glycol regenerator with vacuum pump Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 26 of 94

Fig. 6.14 Glycol regenerator with injector/ejector Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 27 of 94

The improved regeneration can lead to glycol purities in the order of 99.0 wt % for DEG and 99.6 wt % for TEG.

6.3.6 Heat exchangers As said earlier, the temperatures of glycol, streams are very important in both parts of the glycol unit, i.e. the absorbing section and the regeneration section. In the contactor the key temperature is that of the gas entering the contactor. Usual operating temperatures are in the order of 30 °C to 55 °C. At higher temperatures, the glycol purity required is very high and not easily achieved. In addition it is always good practice to feed the lean glycol to the top of the contactor, at a temperature close, but at least 5 C higher, than the gas temperature to reduce the amount of heavy hydrocarbons absorbed in the liquid glycol.

6.4 OPERATION For the operation of the glycol units, in order to reach the required gas dew point, the following parameters must be kept under control: a) Flow rate of circulating glycol to the absorber. b) Lean glycol temperature at the absorber inlet. c) Concentration of glycol, depending on the reboiler temperature. The proper filtering of the lean glycol stream is also an important factor in keeping high the performance of the system. As far as the concentration of glycol is concerned, apart from special solutions that allows the regenerator to operate under vacuum, another rather common solution is the one based on the use of stripping gas. Usually, as stripping gas, fuel gas or dehydrated feed gas are used.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 28 of 94

The simpler way is to inject by means of a spraying device, e.g. a perforated pipe, the stripping gas inside the re-boiler itself. This is a simple way, but not very effective. A better, and the only really valid way, is to install a usually small diameter , contact column with packing inside, on the outlet of the re-boiler. Usually this column is between the re-boiler and the accumulator. The regenerated glycol flows from the top of the column and the stripping gas enters the bottom of the column. With this arrangement, the purity of glycol can be improved significantly. For example, in case DEG is used, the purity can reach 97-97.5 wt % and for TEG the purity can be 99.4 wt %.

7. COOLING TREATMENT PLANTS 7.1 GENERAL A method for the dew point reduction of a gas stream is by cooling it so as to obtain the condensation of part of the water and the heavier hydrocarbons, followed by the separation of the liquids. The most common systems applied to obtain the cooling are described below. 7.1.1 Cooling by expansion (Joule-Thomson effect) The method is based on the behaviour of a real gas which, under most common conditions, cools down if its pressure is reduced through a throttling device such as a valve or a restriction orifice (Joule-Thomson effect). In this method, also called LTX or LTS (Low Temperature Separator) system, after the cooling is obtained as said above, the removal of the liquids is by gravity, in a separator located downstream of the expansion valve.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 29 of 94

Functioning scheme of the system (Fig. 7.1): The gas stream, that has to be at a rather high pressure, is pre-cooled in a coil submerged inside the Low Temperature Separator (LTS), then flows through a heat exchanger, where it is further cooled by the cold treated gas. It then enters a high pressure pre-separator, and finally expanded through a valve. Then the two-phase stream enters the separator, where the liquids are separated by gravity from the gas phase. The separator can be either horizontal or vertical type (Fig. 7.2, 7.3). If the temperature required to obtain the specified dew point is rather low and hydrates can form, the injection of an inhibitor is to be considered. Usually, in this type of applications, glycol (DEG) is used. In case of glycol injection upstream of the throttling valve, the aqueous phase in the low temperature separator is a glycol–water mixture that has to be sent to a regeneration system.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 30 of 94

Figure 7.1 – Dehydration through cooling by expansion Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 31 of 94

WATER

GASOLINE DEHYDRATED GAS OUTLET

GAS FROM FREE WATER SEPARATOR AT 20°C

(PRE-COOLING COIL) SATURATED GAS OUTLET AT 40°C

SATURATED GAS INLET AT 50°C WATER OUTLET

GASOLINE OUTLET

LIQUID AT 20 – 30 ° C

Figure 7.2 – Horizontal low temperature separator

DEHYDRATED GAS OUTLET

(PRE_COOLING COIL)

GAS FROM FREE WATER SEPARATOR

SATURATED GAS OUTLET GASOLINE

GASOLINE OUTLET SATURATED GAS INLET WATER OUTLET WATER

Figure 7.3 – Vertical low temperature separator

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 32 of 94

The function of the coil in the bottom of the separator, is to pre-cool the gas stream. The gasoline, referred to also as hydrocarbon condensate, comes out of the separator through a valve operated by the level controller that maintains the gasoline level in the separator, while the water or the diluted glycol comes from the lowest part of the separator, also under automatic interface level control. The cold vapour leaving the separator is saturated with heavier hydrocarbons and water (in case glycol is injected upstream of the separator, then the vapour is under saturated, because the mixing with glycol leads to a certain degree of dehydration.). This vapour stream from the separator is heated in the upstream heat exchanger, exchanging heat with the inlet gas. .The temperature of the dehydrated gas at the outlet of the heat exchanger, is restored to a value close to ambient. After that, usually the gas is sent to a compression station to increase the pressure up to the value required for its transportation through a pipeline, with the correct dew point as water and hydrocarbons. An additional hydrocarbon recovery, through a refrigeration method is also part of the treatment, to obtain commercially valuable products such as condensate and LPG. The graphics of Fig. 7.4 show quantities (expressed in percentage), referred to the condition of each component of the liquid hydrocarbons, recovered at a constant pressure 35 bar in the low temperature separator. Fig. 7.5 shows the relationship between the pressure and temperature of the gas and the gasoline recovery. The efficiency of a dehydration unit based on cooling, greatly depends on the temperature and pressure of the gas to be treated and in the LTS.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 33 of 94

Figure 7.4 - Percentage of hydrocarbons recovery in a low temperature separator

Figure 7.5 - Hydrocarbons recovery according to temperature and pressure

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 34 of 94

Experimental data are shown in Fig. 7.6, which will allow, once temperature and pressure, upstream of the throttling valve and the pressure in the separator has been defined, it is possible to obtain the corresponding values for the temperature of the separator. The low temperature dehydrating method offers the following advantages: -

rather high liquid recovery (water and hydrocarbons). The amount of water left in the treated gas going to the distribution pipelines, can be adjusted by changing the pressure in the separator.

-

the system is based on simple and easily automatically controlled operations and a low number of adjustments to be made to meet the changes in the feed gas.

-

The method has low operation costs.

On the other hand, the method shows the following disadvantages, limiting its application: - It can be used only with high pressures at the wellhead (normally higher than 85 bar); A lower pressure of the well produces a decrease of the cooling through the expansion valve, to the point that an external refrigeration unit could be required; -

If the design does not include the re-compression unit, the differential pressure across the throttling valve is bound and limited by the pressure that is required for the treated gas at the beginning of the distribution pipeline.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 35 of 94

Figure 7.6- Operating temperatures and Pressures, upstream and downstream of the throttling valve

7.1.2 Operation The plant operation is based on gas expansion, which causes a temperature decrease. The pressure to temperature ratio is 3:1, that means that to each 3 bar of pressure reduction corresponds to a 1°C decrease in temperature. Therefore, the pressure upstream of the expansion valve is very important in order to get the highest decrease in gas temperature and accordingly higher vapour condensation. The temperature of the gas at the inlet of the expansion valve is also important. As a matter of fact, this temperature should be in principle such that after the expansion there is no formation of hydrates, on the other hand if a lower temperature is required to meet the dew point specification, then the injection of a hydrate inhibitor is to be considered.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 36 of 94

7.2 LIQUID HYDROCARBON RECOVERY BY MEANS OF COOLING The condensation of heavy hydrocarbons is obtained by means of gas cooling, obtained with a refrigerating unit. A simplified scheme of a refrigerating unit is shown in Fig. 7.7. Typically, a refrigerant unit includes the following parts: •

COMPRESSOR

•

CONDENSER

•

EXPANSION VALVE

•

EVAPORATOR

Compressor can be centrifugal, screw or reciprocating type, depending on the capacity of the refrigerant unit, i.e. high capacity ones use centrifugal machines, intermediate capacity ones are based on screw compressors and small units have reciprocating compressors.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 37 of 94

Figure 7.7 – Refrigerating unit typical process flow diagram.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 38 of 94

7.3 SCHEME AND FUNCTIONING With reference to Fig. 7.7, a typical scheme is as follows The compressor receives the cold vapour from the evaporator, where the process gas is cooled. At the compressor discharge, the hot gas is sent to the condenser where it is totally liquefied, usually by means of air in air coolers exchangers or by water in shell & tube exchangers and flows into the receiver, called also accumulator. (not shown in the figure). Another scheme is shown on Fig. 7.8, where the compressor is a lubricated screw type. In Fig. 7.11 a picture of a skid-mounted unit is shown, while Fig. 7.12 shows a process unit with a refrigerant unit. The main parts are: •

LUBRICATED SCREW COMPRESSOR (K – 1)

•

LUBE OIL SEPARATOR (S – 2)

•

CONDENSER (EA – 1)

•

ACCUMULATION TANK (S – 3)

•

ECONOMIZER (E – 1)

•

EVAPORATOR (E – 2)

•

SEPARATOR FOR THE RECOVERY OF LUBE OIL (S – 4 AND

S – 5) •

COMPRESSOR SUCTION SEPARATOR (S – 1)

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 39 of 94

Fig. 7.8 Refrigerating Unit with economizer and lubricated screw compressor

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 40 of 94

7.3.1 Refrigerants Generally, the substances used as refrigerants have a low normal boiling point. In particular, the selection of the proper refrigerant for a specific application has to consider a fluid with a boiling point lower than the temperature to which the process fluid has to be cooled. The normal boiling points, i.e. the evaporation temperature at atmospheric pressure, of some common refrigerants are shown in the following Table 1. REFRIGERANT

CHEMICAL FORMULA

NAME

BOILING POINT AT ATMOSPHERIC PRESSURE °C

Methane R50)

CH4

-160

Ethylene (R1150)

CH2-CH2

-100

Propane (R290)

CH3-CH2-CH3

-40

Ammonia (R717)

NH3

-34

R13B1

CBrF3

-58

R22

CHCIF2

-41

R12

CCI2 F2

-30

Table 1 – Boiling points of common refrigerants.

The code starting with R in the table above is according to the classification of refrigerants by ASHRAE (American Society of Heating, Refrigerating, and Air-conditioning Engineers). The most common refrigerant in petrochemical units is propane. In the process units where very low temperatures are required, e.g. the .LNG plants or the NGL plants, proprietary process schemes can be applied, often based on the use of mixed refrigerant fluids. The mixed refrigerants are defined so as to have an evaporating curve such that can fit rather closely to the condensing curve of the process fluid to be cooled down.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 41 of 94

The reason for this design feature, is that close condensing and evaporating curves allow to have narrow temperature approaches in the main heat exchangers, that, in turn, correspond to a high thermodynamic efficiency, i.e. lower compression power for the refrigerant units. Mixed refrigerants are mostly used in the LNG plants.

Fig. 7.9 Propane P-H diagram

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 42 of 94

7.3.2 Compressor The compressors used in the gas cooling plants can be rotary type, such as screw type. (Fig. 7.10)

Fig. 7.10 Propane Compressor Screw Type

7.3.3 Condenser The condenser is where the refrigerating fluid, after compression, is totally condensed. These coolers can be of different types, but usually they use as a condensing agent either air or water.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 43 of 94

According to the type of condensing medium, the refrigerant condenser will be an air cooler or a shell & tube heat exchanger. 7.3.4 Evaporator The evaporator is the heat exchanger where the process fluid is cooled down. Usually they are of kettle type, with the refrigerant, e.g. propane, in the shell and the process fluid in the tubes, as shown in the picture of fig. 7.11. In particular, the liquid refrigerant, e.g. propane, at the inlet of the evaporator flows through a throttling valve, where the pressure is reduced and so the refrigerant is partially vaporized and cooled at the outlet of the valve and enters the evaporator as a two-phase cold fluid. The refrigerant in the vaporizer is at a temperature 5 or 10 °C lower than the temperature of the process fluid. As a result, heat is transferred from process fluid to the refrigerant fluid which vaporizes while the process fluid is cooled down In the scheme shown in Figure 7.8, two evaporators are shown, one is the process gas cooler, i.e. the main exchanger of the unit, while the other one is called economizer and is described below.

7.3.5 Economizer. In the scheme of Fig. 7.8, the main vaporizer is:E2, where the process fluid is cooled down, while the other heat exchanger, E1, is a pre-cooler of the refrigerant fluid, called also economizer, that is included to improve the performance of the unit. In fact, in E1, the liquid refrigerant coming from the accumulator is sub-cooled, so that the refrigerant, after the expansion valve, enters the evaporator E1 with less vapour phase and, as a result, the flow rate to the compressor is lower than that in the case without the economizer.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 44 of 94

Of course, some vapour is going to the compressor from the economizer, but a higher pressure so that, in total, the unit with the economizer have lower power needs.

Fig. 7.11 Model of propane evaporator (Kettle type)

Fig. 7.12 A Skid Mounted Refrigeration Unit

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 45 of 94

Fig. 7.13 Typical utilization of a refrigeration Unit in a process plant

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 46 of 94

7.3.6 Stabilizer column A product complies with a refinery sales regulations, when at 100 ° F = 38 °C its vapour pressure is lower, than the atmospheric one, so that the vaporisation in the atmospheric storage tank is limited. The usual required vapour pressure, denoted also as Reid Vapour Pressure (RVP) ,shall be in the range 8-12 psia. The stabilizer column is commonly used to obtain the required RVP for the product, either condensate or crude oil, to be sent to the storage tanks. The cold hydrocarbon feed enters the column either at the top, if the column has not a condenser, or into a tray below the top, to be decided via an optimisation study. The liquid flows downwards inside the column, (Fig. 7.14). While descending, it warms up, exchanging heat with the hot vapour streams that are travelling upwards. Besides the exchange of heat, on the trays of the column, the composition changes take place too, so that the light ends stripped out from the bottom e.g. ethane, propane, will go mostly in the overhead gas, while the heavier components will go in the bottom product. Finally, the bottom product, will be cooled and sent to storage. In order to have high efficiency for the exchange of heat and matter, the column has, bubble caps or packing elements such as Pall rings or equivalent. The tower is equipped with: -

a level regulator that operates the control valve on the bottom product outlet line.

-

a level indicator;

-

a temperature controller that operates the heating medium control valve;

a pressure regulator that operates the control valve on the column top.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 47 of 94

Figure 7.14 Stabilizer column

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 48 of 94

7.3.7 Operation For the operation of a gas treating plant, it is necessary to verify that all parts of the unit are working regularly and in a stable manner. In particular, the operation of the compressors have to be verified and watched with special attention. Some aspects of the operating conditions of a compressor must be continuously observed . For example, for a lubricated screw compressor the oil circuit is very important, as it ensures the correct running of the system in terms of cooling and sealing of the rotating parts of the machine, It has to be kept in mind that the oil, in this type of compressor, is in contact with the refrigerating fluid and therefore, must then be separated with a high efficiency, at the compressor discharge in the oil separator. On the shells of the evaporator and the economizer, the drain valves should be periodically opened to check whether oil is present and discharge it, if it is found, as, otherwise, it can create a film on the free side of the refrigerant that will limit the evaporation and make the cooling capacity lower. Usually, the temperature of the process fluid is controlled at the cooler outlet by means of a controller that operates a valve on the vapours going to the compressor suction. Through this valve the pressure within the evaporator varies, increasing or decreasing

the

evaporation

temperature

of

consequently, the temperature of the process gas.

the

refrigerant

and

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 49 of 94

8. SOLID BED NATURAL GASOLINE PLANT 8.1 GENERAL The partial removal of heavier hydrocarbons from a gas stream, can be obtained together with the removal of water through a series of separators of proper sizes and configurations. Technical and economic analyses could indicate different solutions to obtain a higher recovery of heavier fractions, which often are present in the natural gas. This extraction process is known as stripping and requires special plants. The reasons leading to this method are mainly economic. Such economic reasons are essentially based on the difference between the prospective profits that can be obtained from selling the various hydrocarbons together with the gas and those obtainable from the separate selling of liquid hydrocarbons and gas. Of course, the determination of such profits is done through accurate evaluations of operation costs that must be met in the various cases.

8.2 SCHEME AND FUNCTIONING It is a fully automated plant (Fig. 8.1a, 8.1b), highly indicated for the recovery processes of heavier hydrocarbons. An additional task carried out by the plant is the gas dehydration. The adsorbent is a standard or Sovabead, also used in the gas dehydration plants. Its working principle is the same of the long cycle plant, with the only difference that the first is equipped with 3 adsorber instead of 2, one of which is cyclically used in the adsorbing process, one in the heating and the other in the cooling process. On average, each cycle lasts about 25 minutes. Natural Gas coming from the field with some condensate and free water, is fed to the separators located at the plant inlet in order to separate the liquid phases.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 50 of 94

The gas then proceeds to the plant separator (S1), whose task is to remove the liquid carry-over from the gas streams. Then, the gas is sent to a FCV, Flow Control Valve, which automatically regulates the flow-rate of the regeneration gas. With this kind of control, the gas flow is split into two streams: Main Gas Stream Regeneration Gas Stream a) The main stream goes to the adsorber (V1) containing 90% of standard Sovabead and 10% (W) Sovabead, the latter placed in the top part of the adsorber. The gas enters through the top, flows downwards and leaves the bottom of the adsorber de-hydrated. and with less heavy hydrocarbons. The removal of heavier hydrocarbons (stripping) and water (dehydration) are performed by means of capillary attraction through the several superficial holes scattered all over the adsorbing material. When the gas comes out of the plant, it is filtered by means of acyclone gas washers and bag filters, passes through a flow meter and is sent to the pipeline. b) The regeneration gas stream (about 20% of the total gas), taken upstream of the flow control valve, through the measurement flange and the two valves (FC V 4) and (FC V 5) , enters the top of the absorber (V2) and, flowing downwards, it cools down the Sovabead to a temperature that is quite similar to that of the main gas stream being in the adsorbing stage at the same time. The operating temperature for an efficient adsorption shall be in the range between 10 and 50 °C. The regenerated gas had previously been pre-heated thus becoming undersaturated. In such conditions, the gas passes through the shut-down SOV 1 and goes to the molten-salt HEATER (R1) where it is further heated to a temperature which allows the re-generation of the adsorbing material inside the absorber (V3) during the heating phase.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 51 of 94

The adsorbent material (Sovabead) is to be considered re-generated when the temperature of the outgoing gas from (V3) has stabilized at about 275°C for at least 5’. Before entering (V3) part of the gas is used in the stabilizer (C1) in order to heat the hydrocarbons up to a given temperature to accomplish its stabilization process. The three-way shut-down valve SOV1 by-passes the regeneration gas flow from the adsorber, cutting the flow from the HEATER when: a) Long shutdowns of the HEATER b) Heater Flow-line and backflow failures. The three-way-valve is also operated in case of low temperature of the gas coming from the HEATER, which should never be under 270°C. The gas coming out the (V3) is rich in H2O and hydrocarbons in vapour state passes through the three-way valves FCV7 and FCV6 and enters the exchanger E2. At this point, the gas is cooled down and reaches the same temperature of the gas coming from the main flow. Due to this cooling, some water and hydrocarbons will condense and are separated, in the separator S2. After the separation of these liquids, the gas, joins the main gas stream. Once the cycle in the adsorbing tower is completed (V1), a timer controls the cycle switching. After this switching process, (V1) the regenerating process, (V2) the adsorbing process and (V3) the cooling process start.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 52 of 94

Figure 8.1a Solid bed stripping plant Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 53 of 94

8.3 STRUCTURE AND FUNCTIONING OF: 8.3.1 Adsorbers They consist of vertical columns, built with two shells. One is internal and thin that supports the insulation placed in the gap between the inner and the outer steel-shell, the other has proper thickness in order to withstand the maximum operating pressure of the tower. (Fig. 8.2). The inner built insulation layer inside the column saves heat during the regenerating process. During each regenerating process of the dehydrators contained in the tower, the huge steel mass of the outer shell (70 Kg/cm2) is not heated up, because it is thermally isolated from the hot gas. Just over the lower bottom of the tower there is an open grid that holds the adsorbent bed. In order to avoid the dehydrating material clogging the grid, and subsequently an increasing in flow resistance between the incoming and outgoing gas in the tower, the bottom is fitted with a wire net covered with a larger sized ballast than the dehydrating material.

Fig. 8.1b Solid Adsorbent System

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 54 of 94

Fig. 8.2 Adsorber

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 55 of 94

8.3.2 Air Coolers They are usually made of a finned tube bundle, topped by a fan that allows air circulation through the tube bundle, thus extracting heat to the fluids inside the tubes. (Fig. 8.3). From a structural point of view, the fan could also be placed under the tube bundle, and in this case the cooler is defined FORCED CIRCULATION air cooler, while if the fan is placed on top of the tube bundle it is called INDUCED CIRCULATION air cooler. The air cooler fins are located directly on the tube, where the hot fluid circulates, so that there is a higher exchange surface with the same overall dimensions. The control of the process fluid outlet temperature is obtained by means of a temperature controller that varies the pitch of the blades in the fan and therefore the flow of cooling air to the tube bundle, or the flow of the forced air by closing or opening some windows to allow air circulation.

8.3.3 Filters The processed gas coming from the plant and going to the Solid Bed Stripping plant (dry frack) is filtered through a group of filters (Fig. 8.4), which are composed as follows: - Grid Filter - Cyclone Gas Washer - Bag filter This set of filters has the purpose of retaining the sovabead dust caused by the breaking of this solid material due to contact with gases and to the repeated heating-cooling processes.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 56 of 94

Fig. 8.3 Air cooler. Conceptual diagram

Fig. 8.4 Filters set

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 57 of 94

9. LPG PLANT 9.1 SCHEME AND FUNCTIONING The gas plant consists of three distillation towers connected in series. The following description refers to one example of LPG process plant with annexed the relevant process flow diagram. (Fig. 9.1a, 9.1b, 9.1c) The feed gas enters the Deethanizer feed surge drum. The surge drum has a water boot for the withdrawal of any free water that settles out. From the feed surge drum the liquids are pumped forward, via a feed coalescer to remove traces of free waters, and combined with the Reformer overhead liquids before entering into the Deethanizer column. The feed Gas from the surge drum is compressed in a two-stage compressor, with an intercooler and also fed into the Deethanizer column. The Deethanizer column is reboiled by LP steam in a thermosyphon re-boiler. A water draw drum removes water that settles out in the Deethanizer column at tray 26. Overheads from the Deethanizer are mixed with a recycled ‘Lean oil” stream taken from the Debutanizer bottom products, and the mixture partially condensed against cooling water before entering the overhead accumulator drum.

Liquids from the overhead accumulator are totally

refluxed into the Deethanizer column. The off-gas forms the primary source of fuel gas for the refinery. The lean oil re-circulation is used to minimize losses of valued LPG components into the fuel gas system. The bottoms product from the Deethanizer flows under pressure difference into the second column of the distillation train, the Debutanizer. The Debutanizer is a 34-tray column also re-boiled by LP steam in a thermosyphon reboiler. The Debutanizer column overhead gas is condensed with cooling water and flows into the overhead accumulator, which provides column reflux and overheads liquid product. The overheads liquid product is a LPG stream, i.e. contains both Propane and Butanes. The LPG stream is fed to the LPG treater for removing the mercaptans and then enters the third distillation column, the C3 / C4 Splitter.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 58 of 94

The bottoms product from the debutanizer column is stabilized light Naphtha (LSR). This product is cooled in an air fin fan cooler and then with cooling water before being fed to the LSR Merichem Treater section, also for removal of mercaptans. After treatment, the LSR is routed as product rundown into the gasoline blending pool. The LPG stream returning from the treater section is preheated with the Butane product and enters the 30-tray C3 / C4 Splitter column. A 150# steam, thermo-syphon re-boiler, also re-boils this splitter column. Overhead Propane from the splitter column is condensed against cooling water into the overhead accumulator. Liquids from the accumulator provide reflux for the splitter column and the finished Propane product rundown to storage bullets. The bottoms Butane product is first cooled against the incoming splitter column feed, and then against cooling water before leaving the units as the product rundown to the storage spheres.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 59 of 94

Fig.9.1a Process flow diagram feed drum and de-ethanizer

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 60 of 94

Fig. 9.1b Process flow diagram debutanizer system

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 61 of 94

Fig. 9.1c Process flow diagram debutanizer system

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 62 of 94

10 PROPANE DEHYDRATION 10.1 GENERAL Quite often a hydrocarbon stream needs to be separated into each component. This process is called fractionation. The fundamental principle for fractionation is that each component has a different boiling point . The usual order is to remove the lighter product first. The line of treatment starts with ethane, then propane, then butane (iso then normal) and finally condensate. Fractionator towers are usually named with reference to the overhead product, e.g. a deethanizer implies that the top product is mainly C2 with a low content of propane.

Depropanizer The feed gas goes in the depropanizer column. This tower separates the propane from the rest of the butane and heavier hydrocarbons. The propane is separated from the column head and goes first, through the condenser, to the accumulator and then with pumps towards the storage. A fraction of the produced propane is refluxed through the pump in the head – column. The bottoms product enters, after the heating in the reboiler, the debutanizer column. The final step is to separate butane from condensate. (Fig. 10.1)

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 63 of 94

Fig. 10.1 Depropanizer and Debutanizer Process flow diagram

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 64 of 94

11 COS TREATING 11.1 GENERAL Carbonyl sulphide (COS) This substance is produced as a combination of carbon dioxide (CO2) and hydrogen sulphide (H2S) that are present in the raw gas. Carbonyl sulphide is present in small quantities in raw natural gas, and sometimes is produced during the dehydration step in gas treating if the molecular sieves used are not selected appropriately. Carbonyl sulphide concentrate in the propane or LPG product in a natural gas processing unit. If there is a total sulphur specification on the propane product, carbonyl sulphide may need to be removed in order to meet the total sulphur limitation. On the other hand, the removal of carbonyl sulphide may be advisable because, carbonyl sulphide and water at ambient temperature react almost quantitatively to from H2S and CO2. H2O + COS → H2S + CO2 This reaction can be the reason why there are a number of instances where “sweet” propane “turned sour” in storage or transport. While COS is not itself corrosive, the hydrolysis product H2S is corrosive, especially in the presence of water. This corrosivity is reflected in the failure of the ASTM D1838 copper strip corrosion test, and is thought to be a major problem in the liquefied petroleum gas industry. There are several processes that are used to remove the COS. This is carried out by a two stage process which involves the hydrolysis of the COS and the subsequent absorption of the H2S which is produced by this reaction. A scheme of a potassium hydroxide/Methanol process unit for removing COS from a propane stream is shown in Fig. 11.1 The potassium hydroxide is contained in a simple vertical vessel as shown in (Fig 11.1) and methanol is injected into the sour hydrocarbon liquid.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 65 of 94

Fig. 11.1 COS treating Conceptual flow sheet

Potassium hydroxide and methanol are consumed by the removal of COS. Mick reports that for 7,000 barrels per day of propane containing 20 ppm COS approximately 150 Lbs of potassium hydroxide and 100 gallons of methanol are consumed per day. McClure and Morrow and Weber report the use of diglycolamine (DGA) for removing COS. The schematic flow diagram of the liquid – liquid contact unit is shown in Fig. 11.2. The only difference in this unit and a regular amine sweetening unit is the coalescer and water wash that must be used to recover entrained DGA from the hydrocarbon liquid.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 66 of 94

Fig. 11.2 Malaprop process Conceptual flow sheet

Synetix reports that they have a catalytic process using their PURASPEC products that removes COS. There are three PURASPEC catalysts which can be used to destroy COS. Two of these (PURASPEC 2070 and PURASPEC 2075) are capable of carrying out both the hydrolysis and absorption reactions while one product (PURASPEC 2312) acts only as a catalyst for the COS hydrolysis reaction. They report efficient destruction of low levels of COS by hydrolysis with only a modest molar excess of H2O. This process is operable over a wide temperature range and in many gaseous process streams to cover most COS hydrolysis needs.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 67 of 94

12 MERCAPTAN TREATING 12.1 GENERAL The Merox process is a catalytic process for conversion of mercaptans to disulfides. It operates as either a mercaptan extraction process or a sweetening

process

where

the

disulfides

are

removed

from

the

hydrocarbon. Either of these functions can be carried out independently or in combination. When only the extraction is used, the process is referred as Merox extraction. When operated to sweeten only (converting mercaptans to disulfides) it is referred to as Merox sweetening. The combination operation is applicable to all gasoline and lighter hydrocarbon materials. The process was developed by Universal Oil Products Company. There is a competitive process similar to Merox licensed by Merichem. The dual method of operation is accomplished through the use of a catalyst. The catalyst promotes direct oxidation of mercaptans to disulfides at ambient temperature using atmospheric oxygen. When used for mercaptan extraction the mercaptans are extracted by caustic soda. Instead of regeneration through steam the Merox process regenerates caustic by blowing with air. The disulfides formed by the regeneration reaction are insoluble in the caustic and can be separated. Fig. 12.1 shows a combination Merox process. Sour feed entering the bottom of the mercaptan extractor flows upward in counter-current contact with the caustic containing the Merox catalyst. Mercaptans are extracted from the feed which flows to a caustic settler for final caustic removal. It then-flows to the sweetening tower where it contacts more caustic containing Merox catalyst to convert higher molecular weight mercaptans to disulfides.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 68 of 94

Fig. 12.1 Schematic flow sheet for mercaptan process

Air is injected with the hydrocarbon – caustic stream entering the sweetener to promote the conversion. From the sweetener the hydrocarbon – caustic mixture flows to the settler tower where caustic and hydrocarbons are separated.. The caustic containing the extracted mercaptans flows from the bottom of the extractor tower to the caustic regenerator where it is regenerated by air and the mercaptans are converted to disulfides. The disulfides are insoluble in the caustic- water solution and are decanted in a separator before the regenerated caustic is re-introduced to the mercaptan extraction tower. Low molecular weight hydrocarbon liquids require only extraction because they contain negligible amounts of high molecular weight mercaptans. Heavier stocks such as kerosene and fuel stocks require sweetening because the disulfides, which remain in the treated stock, do not cause problems for those products. Merox units usually have lower operating costs than steam generated caustic units. A Merox has trivial steam consumption, low power costs and

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 69 of 94

no cooling costs. The 60-70% of the operating cost is the cost of the Merox catalyst. The mercapfing is a fixed bed liquid phase catalytic process in order to convert mercaptans to disulfides. In mercapfing, the disulphides are not removed

but

remain

in

the

hydrocarbon

stream.

Conversion

is

accomplished through the oxidation of the mercaptans with air. Though the sulphur remains in the hydrocarbon, the hydrocarbon effluent from the unit passes the copper strip corrosion test. Catalysts must be periodically regenerated because of the plugging with oxidation products.

13 SWEETENING Natural gas may contain high quantities of hydrogen sulphide H2S and/or carbon dioxide CO2. The presence of these compounds renders the gas a sour gas. This is specially because sulphur has such negative effects on the quality of the produced gas, that the concentration of both components have to be reduced from the gas flow before being put into the distribution conducts for the users. The regulations allow a maximum of H2S equal to 0,002 gr./Nmc (1,31 PPM).The amount of CO2 in the gas produced will depend in the amount required by the regulations. Typical values allow a maximum concentration of carbon dioxide and other inerts to 4% molar of the gas. If the content of CO2 is within these values the process selected to remove the hydrogen sulphide has to avoid the removal of the carbon dioxide. The necessity of a efficient natural gas sweetening process is due to the following reasons: -

the toxicity of the hydrogen sulphide.

-

sulphur dioxide is formed after the gas combustion;

-

the corrosive action of sulphur compounds in metals especially with the presence of water even under the form of steam.

-

the corrosive action of carbon dioxide

-

the problem of hydrogen embrittlement of the vessels containing the gas

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 70 of 94

-

to reduce corrosion in pipelines and processing equipment

-

for economic transportation of gas over long distances

Normally, the natural gas desulphurization processes can be grouped into 9 technology categories. These technology categories are as follows: 1 Chemical Solvents 2 Physical Solvents 3 Combination Chemical and Physical Solvents (Hybrids) 4 Fixed Beds (Adsorption) 5 Cryogenic Distillation 6 Membranes 7 Direct Conversion (Liquid Redox) 8 Scavenging technology 9 New Processes - Hybrid (Membrane and Amine, Liquid Redox and Amine) The first six are used for bulk removal of acid gas and can be tailored to a wide range of outlet concentrations, direct conversion is used for low amounts of H2S and scavenging is used for small throughputs or trace removal. A combination of processes can be used to full fill particular processing requirements. Chemical solvent processes involve the absorption by chemical solutions at preferably high pressure and near ambient temperature. The solvent in an aqueous solution, bonds with the acid gas component and removes them from the feed gas, the sour gas components are then released when the temperature of the solvent is increased or/and the pressure is reduced. Common chemical solvents include aqueous solutions of amines, inorganic salts or mixtures of them. The amines more commonly used are Monoethanolamine (MEA), Diethanolamine (DEA), Methyldiethanolamine (MDEA) and Diglycolamine (DGA). The inorganic salts are mostly basic carbonate solutions and caustic soda.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 71 of 94

In general, selection of a proper gas treating process involves consideration of the following factors: - Gas composition, including CO2, H2S and trace sulphur components - Inlet pressure and temperature - Treated gas purity specification.

Avoid removing more CO2 than

required to meet specs - Need for selectivity - Co-absorption of hydrocarbons - Process Capital and Operating costs including cost of solvents and their availability - Process royalty fees if any - Corrosion/Metallurgy Requirements - Process experience with similar treating requirements. - Chemical degradation and evaporation losses - Process support from the licenser, availability of chemicals/spares at location - Environmental performance, disposal of effluents - Water content for raw and treated gas

Process Advantages and Disadvantages Chemical Solvent Process

Monoethanolamine (MEA) Process Advantages - High reactivity - Low solvent cost - Good thermal stability - Ease of reclamation - Low hydrocarbon content of acid gas produced - Lower plant investment compared to other amine processes

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 72 of 94

Disadvantages - Inability to cope with and gas containing O2, CS2 - Will remove all the CO2 - Higher vaporization losses than DEA, MDEA - Ineffective for removing mercaptans - High residual acid gas concentration in lean amine - Non-selectivity for removing H2S in the presence of CO2 - Higher utilities than hot pot and most physical solvent processes - Most corrosive amine - Freeze point 50oF - Transportation of 15% water solution may be required (Freeze point 9oF) - If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas. This is a general point for amines.

Diethanolamine (DEA) Process Advantages - Resistance to degradation by COS and CS2 - Lower vaporization losses and regeneration energy required - Less corrosive Disadvantages - Lower reactivity - Higher recirculation rates - Higher solvent costs - In CO2 only services it will degrade and be very corrosive - Lack of selectivity for H2S and CO2 - If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas - Freeze point 80oF - Transportation of 15% water solution may be required (Freeze point 28oF) - Difficult to reclaim - Vacuum distillation, ion exchange

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 73 of 94

Methyldiethanolamine (MDEA) Advantages - High selectivity of H2S over CO2 - High acid gas loading per mole of solvent - High solvent concentration - Low regeneration energy - Low solvent circulation - Low degradation due to contaminants - Selectivity not affected by low pressure Disadvantages - Higher solvent cost - Loss of selectivity for H2S over CO2 as the concentration of H2S is increased - Little increase in allowable loading with increase of pressure - Tends to be foamy due to hydrocarbon co-absorption - If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas - Reclamation process more complicated

Diglycolamine (DGA) -Econoamine Advantages - High reactivity - Solution is resistant to freezing better for cold climates - Effective in removing RSH components - Very high concentration solution, lower circulation rates

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 74 of 94

Disadvantages - Absorbs heavy or aromatic hydrocarbons (an advantage in processes were traces of heavy hydrocarbons will cause problems i.e. Benzene removal for LNG production) - Proprietary process - If gas is not saturated reverse osmosis water or equivalent is needed to maintain amine concentration, it will re-hydrate dry gas

13.1 SCHEME AND FUNCTIONING In a chemical solvent process, the acid gas components are chemically attached to the solvent. With chemical solvents, a CO2 rich gas can be treated to low levels of CO2 without deep regeneration of the solvent. However, there is a limit to the CO2 removal capacity of these solvents. This limit is independent of CO2 partial pressure, as it is determined by stoichiometry and corrosion prevention. The reaction rate H2S with amine is much faster due to its higher acidity and is readily removed from the feed gas. Chemical solvents are most suitable for handling gases with relatively low partial pressures of CO2 or where a very low level of CO2 in the treated gas is required. Usually, energy requirements for chemical solvents are relatively higher. Most chemical solvent sweetening processes involve absorption by chemical solutions at high pressure and at low temperature. A solvent in the aqueous solution will react with the acid gas components to form a complex. The solvent bonds with the acid gas components in a chemical manner until the temperature of the solvent is increased and/or the pressure is reduced at which time the complex is decomposed and the sour components released.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 75 of 94

A sweetening plant operation on amine consists mainly of two pieces of equipment, i.e.: - the packed absorber or plate absorber where the gas is washed with an absorbent; - the distillation column (de-absorber) where the absorbed substances (hydrogen sulphide, carbon dioxide) are separated from the absorbent until regeneration. With reference to the scheme, (Fig. 13.1) the gas containing hydrogen sulphide and carbon dioxide enters the lower part of the absorption tower whereas the aqueous amine solution enters at the top in a counter current fashion. The sweet gas comes out of the tower top, whereas the amine rich solution, now saturated with hydrogen sulphide and/or carbon dioxide, is gathered at the bottom of the tower. The rich solution is warmed up the heat contained in the regenerated solution, its pressure reduced to allow the removal of the acid gases and then is sent to the top of a distillation tower The rich solution is regenerated with the steam developed by the re-boiler. After the regeneration process, the solution of amine passes, as mentioned before in heat exchangers where it is cooled. Then it goes back into circulation through a pump. To cool the solution to an ideal absorption temperature, a water or air exchanger is installed between the pump and the absorption tower. The acid gases, that is hydrogen sulphide and/or carbon dioxide, exit at the top part of the regeneration tower and after having been cooled off, in a water or air exchanger. After the cooling water is formed, and , is pumped into the regeneration tower to create reflux to limit the losses of amine. Figures 13.2 and 13.3 show the process diagram of the glycol-mine sweetening and of amine storage.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 76 of 94

Fig. 13.1 Glycol-Amine sweetening Unit Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 77 of 94

Fig. 13.2 Glycol-Amine sweetening Unit Process flow diagram

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 78 of 94

Fig. 13.3 Amine storage process flow diagram

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 79 of 94

13.2 DESCRIPTION AND FUNCTIONING OF: 13.2.1 Absorption Column The absorption column is a piece of equipment capable of removing acid gas. This occurs through the plates with allow an intimate contact between the absorbent liquid and the gas that to be treated. This type of column operates better at high pressure. The quantity and nature of the acid compound present in natural gas determines the quantity and composition of the absorbent in circulation. Ethanolamines are most commonly used, mono-ethanolamine and diethanolamine are more effective for the contemporary removal at H2S and CO2 from natural gas. and triethanolamine which is highly selective towards H2S. Some mixtures of these amines can also be used, for instance formulated amines. Whatever the nature of the liquid absorbent, it is fed at the top of the sweetening column, then flows down through a series of contacting plates. The absorbent flows towards the bottom of the column absorbing the H2S and/or CO2 present in the gas. The gas flows counter currently towards the top and is forced to bubble in the liquid present in each plate where the reaction and absorption of the acid gases to the amine occur. For this type of absorption, several contact stages are necessary. Typically there are around up-to 50 plates installed in an absorption column. 13.2.2 Gas Scrubber Normally, a separator called gas scrubber is located upstream the sweetening column and its task is to hold any possible absorbent carryover that is in the gas. To improve the separation effect, a DEMISTER or a liquid removal pack is installed on the separator.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 80 of 94

13.2.3 Regeneration Column The regeneration column has typically 30 contacting plates and operates at low pressure. The acid solution enters near the top of the column and goes counter current the acid stream generated in the re-boiler that goes up towards the top of the column. This stream originates from the boiling that occurs on the re-boiler and is mainly composed of water vapour (caused by the water present in the solution) and acid gases (H2S and/or CO2). In the tower the rich amine solution gets warm and releases the acid gases that had absorbed becoming a lean solution (low H2S and/or CO2) that can be reused to extract more acid gases. In the top of the column a reflux of cold liquids, mainly condensed water, helps to condense the heavier fractions (MEA-DEG) minimizing any solvent losses. The regeneration of the solution is facilitated by low pressure and high temperature, on the other hand the absorption is facilitated by high pressure and low temperature. In the regeneration column, the pressure is atmospheric or slightly superior, whereas the temperature is linked to the type of absorbent. In the case of glycol-amine (75% GDE, 20% MEA, 5% H20) the regeneration temperature is of 155 °C whereas in the specific case of MEA the temperature is of 105 ÷110 °C. This is due to the low boiling temperature of MEA. Care should be taken no to heat the amine solutions above their recommended maximum operating temperature to avoid thermal degradation of the amine. 13.2.4 Re-boiler The re-boiler is that piece of equipment capable of heating the amine solution at the above-mentioned temperature values so that the water present evaporates capturing H2S and/or CO2 present in the rich amine solution.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 81 of 94

The acid gases and steam form in the re-boiler exit the re-boiler and go back into the regeneration column to strip H2S and/or CO2 from the amine solution which comes down from the top of the column. The regenerated solution goes out of the re-boiler with low amounts of carbon dioxide and hydrogen sulphide (lean solution) and is gathered at the bottom of the regeneration column where it is pumped, filtered, cooled and re-injected once again into the absorption column. 13.2.5 Reflux Drum Acid gases, H2S and CO2 exit at the top of the regeneration tower and are cooled in a water or air cooled exchanger, there the water present is condensed and is collected in an appropriate separator. This water is reinserted, through a pump, in the re-generation column to create a reflux capable of avoiding or at least limiting amine solution losses. Acid gases H2S and/or CO2 are sent to flare or, if the quantity justifies this, to a plant for the production of sulphur to meet environmental requirements. 13.2.6 Operation The pressure and temperature parameters for a sweetening plant are specific for each individual plant, but some common criteria remain. As it has been stated, to have a good operation, it is necessary to operate the absorber at a relatively low temperature, and that the pressure in the adsorber column is as similar as possible to the design pressure. The temperature has to be regulated so as the amine solution is always hotter than 15÷20 °C to the gas temperature to avoid hydrocarbon condensation and foaming in the absorber. This kind of temperature regulation is carried out by operating gas inlet exchanger. The concentration of the lean amine absorbent has to be as pure as required by design after the regeneration, this is fundamental for the absorption of hydrogen sulphide and/or carbon dioxide to the required levels.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 82 of 94

To reach a good regeneration of the amine solution, low operating pressure equal to or slightly above the atmospheric pressure and high temperature have to be created in the regenerator column. Amine regeneration occurs through heating and stripping in the regeneration column. The temperature profile in the regeneration column is set by the reboiler temperatture and it depends on the type of absorbent solution used. For example, for an aqueous solution of MEA (80% H2O 20% MEA) the regeneration temperature has to be 105÷110 °C, but by adding DEG to the solution a regeneration temperature of 145÷150 °C is needed to remove the H2S that otherwise would remain in the amine solution. In the regeneration column it is important not only to control the bottom column temperature (regeneration temperature) but also the overhead temperature, because the higher this temperature, the greater the losses of amine solution due to evaporation. This temperature cannot be different from the boiling temperature of water, so the head temperature must be around 95-100 °C. The heating of the amine solution can cause the decomposition of the amines, and also some impurities will react with the amines producing the formation of salts. These salts can be corrosive and reduce the absorbing power of the amine solution, therefore a process is needed to eliminate these salts, and generally a small distillation unit is installed to remove these salts. To avoid any further decomposition vacuum distillation is employed to avoid overheating the amine solution. In this type of plant the vacuum level is fundamental and it must always stay at about –680 mm H2O. The temperature depends on the concentration of water and the type of amine used. To eliminate a greater quantity of H2S from the amine solution, STRIPPING GAS can be used in the regeneration column, but this is not recommended when the sour gas is sent to a sulphur recovery unit. By using sweet gas counter current to the rich amine solution, part of the acid gas present in the

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 83 of 94

solution is eliminated and the concentration of the solution is improved at a lower operating temperature. During plant operation iron sulphide may form due to a chemical reaction between the acid gases and the metal of the vessels and piping of the unit. This can be prevented by using non-corrosive amines or amines with corrosion inhibitors. If iron sulphide is formed its removal is very important because it will cause foaming and eventually plug some of the exchangers. To control this impurity, appropriate filters must be installed and during maintenance must

be carefully serviced since iron sulphide is highly

inflammable and when it burns it develops high concentrations of H2S and SO2, both very dangerous for the personnel. As a consequence filter maintenance has to be carried out with appropriate flame retardant equipment and personnel must wear masks for protection. Different types of sweetening plants (Figs. 13.4, 13.5, 13.6, 13.7) are shown in the following pages, each of these plants uses different amine solutions, but the functioning principles are substantially the same.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 84 of 94

Fig.13.4 – Sweetening plant

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 85 of 94

Fig. 13.5 Sweetening plant

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 86 of 94

Figure 13.6 Sweetening plant. Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 87 of 94

Figure 13.7 Sweetening plant. Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 88 of 94

14. SULPHUR RECOVERY PLANT 14.1 SCHEME AND FUNCTIONING CLAUS PROCESS The process uses the acid gas rich stream from the sweetening process as feed to produce liquid or solid sulphur. The process is widely known as the "Claus" process. Developed about 1890 it is applicable for production of sulphur from acid gas streams containing about 20% to 100 H2S. The original Claus process comprised oxidation of hydrogen sulphide with air over bauxite or iron or catalyst in a single reactor. According to Gamson and Elkins the first significant advance was made in 1937 by I. G. Farbenindustrie. Instead of burning the H2S directly over the catalyst, they burned 1

/3 of the H2S to sulphur dioxide in a waste heat boiler. The sulphur dioxide

was then reacted with the remaining H2S over bauxite at 700-750° F. The primary advantage of this arrangement is that the total heat of reaction evolved in the catalytic converter is greatly reduced thus allowing for better temperature control. Another development attributed to I. G. Farbenindustrie was the high temperature (up to 1,000° C) non-catalytic combustion of H2S with air, to produce sulphur directly. This non-catalytic conversion of H2S to sulphur produces yields that are asserted to range as high as 90%. Chemistry of Claus Process The process chemistry can be summarized in the following reactions: Thermal

3 H2S

+

3/2 O2

=

SO2

+ 2 H2S

Catalytic SO2

+

2H2S

=

3/n Sn + H2O

Overall

+

3/2 O2

=

3/n Sn + H2O

3 H2S

Sulphur exists in several forms (S4,S6,S8), so the modern practice is to use Sn. In the Claus process Only a certain amount of air is admitted to the furnace to allow enough SO2 to be produced so that the ratio of H2S and SO2 for conversion to sulphur is 2:1. This is a non-reversible combustion of H2S that produces large quantities of heat. The catalytic reaction takes place over a bauxite catalyst at a fairly low temperature (but high enough to keep the sulphur liquid).

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 89 of 94

In chemical equilibrium reactions there are several factors that may influence their completeness and the resulting production of sulphur. They are as follows: - Concentration of H2S and SO2 - Temperature of the reaction - Pressure of the reaction The concentration of H2S and SO2 are important because the catalyst works within certain limits. If the concentrations drop below 2%, the molecules become too distant to allow the reaction to occur within the time the gases remain in the converter. Similarly, concentrations over 25% would result in excess heat, water, and sulphur forming which may overload the catalyst. Alternate Flow Process The recovery of sulphur from hydrogen sulphide has led to the development of several processing methods, all of which are based on the Claus reaction principles. The following two basic variations of the Claus sulphur process account for the design of most of the commercial Claus plants: 1. Straight-through process (over 50% H2S in feed gas) 2. Split-flow process (lower than 50% H2S in feed gas) The process selected for a particular plant will depend, as a general rule, on the H2S concentration in the acid gas and the volume of gas handled The primary difference between the different processes is the way in which heat balance is maintained in the process. Fig. 14.1 shows a "once through" Claus unit process flow scheme using hot gas by-pass for reheat. The acid gas feed is combined with stoichiometric air to burn 1/3 of the total H2S to SO2 and all hydrocarbons to CO2. Combustion of the H2S takes place in the burner and reaction chamber. The high temperature combustion mass flows to the waste heat boiler where heat is removed from the combustion gases. A part of the hot gas from the waste heat boiler is by passed in order to reheat the gas from the sulphur condenser to reaction temperature before it is introduced to the catalyst beds in the converters or reactors. Condensed

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 90 of 94

sulphur is withdrawn from the first sulphur condenser. The cool gas leaving the first sulphur condenser is combined with the first hot gas by-pass stream and fed to the first reactor. Sulphur must be removed from the condenser at a temperature in the 320° F. range. Because of a composition change which occurs at about 320° F,. the viscosity of liquid sulphur increases very rapidly above that temperature. Consequently, the temperature of the sulphur must be kept below 320° F. or the sulphur will be so thick and viscous that it is very difficult to remove from the condenser. Preferred temperature for inlet to the catalytic converters or reactors is in the 450° F range. However, it must be above the sulphur dew point to avoid condensation of liquid sulphur on the catalyst bed. Any condensation will cause plugging and catalyst deactivation. This explains the necessity for the hot gas bypass to maintain a satisfactorily high temperature level at the reactor inlets. The mixture of hot gas and cooled stream flows downward through the first catalytic converter and then into the condenser where the temperature is once more lowered to the 300° F. range and liquid sulphur removed. Cooled gases are then combined with the second hot gas bypass flow to balance temperature at the inlet of the second reactor, further conversion of H2S and SO2 to sulphur is accomplished in the second reactor bed and the gases are cooled again for sulphur removal. Use of the once through process is highly desirable from a sulphur recovery standpoint. If the once through process can be used, approximately 2/3 of the total sulphur production will come from the condenser immediately following the waste heat boiler. Goar has shown a sketch of a typical waste heat boiler in a once through process. The sketch by Goar is shown in Fig. 14.2. Typically the gases leave the combustion chamber at about 2300° F in their first pass through the waste heat boiler. On the second pass they are cooled to the range of 550° F before flowing to the first sulphur condenser. The hot gas bypasses are withdrawn from the furnace at approximately 1100° F.

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 91 of 94

Fig. 14.3 shows a modification of the once-through process which is used when the acid gases entering the plant are low in H2S, below approximately 25%. In these cases there is not sufficient heat of reaction to raise the entire acid gas stream to satisfactory temperature levels.

Fig. 14.1 Claus “once through” process flow

Fig. 14.2 Typical reaction furnace and waste heat boiler

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 92 of 94

Consequently, only the portion of the gases to be burned is mixed with air and introduced to the burner. They flow through the waste heat boiler as before, with a portion of the gases being combined with the un-combusted 2

/3 of the acid gas before being introduced into the first reactor. A hot gas

bypass is utilized for temperature control at the inlet of the second reactor. As in the once-through process, the split stream process utilizes stoichiometric air to burn 1/3 of the H2S to S02 and all of the hydrocarbons to CO2. Sulphur recovery varies for different process configurations, and for the number of catalytic stages used.

Typical sulphur recovery for different

process are given below. •

•

Number of catalytic stages 2 stages

95-96%

3 stages

96-97%

Tail gas treatment

99.8%

There is a practical limit to the number of catalytic stages that can be installed to improve total sulphur recovery, and for that reason above 97% sulphur recovery, another type unit has to be installed to treat the Claus tail gases, the tail gas treating unit.

Fig. 14.3 Claus “split stream” Conceptual flow sheet

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 93 of 94

15 TAIL GAS TREATMENT 15.1 GENERAL As shown in Fig. 15.1, the Tail gas treating is a process subdivided in three basic steps: heating and reducing all sulphur compounds to H2S; cooling and quenching; and H2S absorption, stripping and recycle. The tail gas from the Claus unit is heated and reacted with a reducing gas, commonly hydrogen or a mixture of hydrogen and carbon monoxide, over a catalyst bed cobalt-molybdate or alumina bauxite to reduce the sulphur and sulphur dioxide. The hydrogen rich gas is obtained by auto-thermal reforming of natural gas with air. The gas from the reactor is cooled next in a downstream heat exchanger and a cooling tower to remove all the heat from the gas. Quenching of the gas takes place at about atmospheric temperature. Water vapour in the process gas is condensed and condensate is sent to a sour water stripper. After the gas is cooled the gas is treated with a selective amine or triethnolamine to remove the H2S from the gas stream with absorption of little or no CO2. The H2S is then stripped from the absorbing solution and recycled to the feed inlet to the Claus sulphur unit. Since the catalytic hydrogenation is carried out at temperatures in the range of 570.°F the gas must be cooled before they are contacted with the alkanolamme solution. The treated gas from the top of the absorption column contains small enough quantities of H2S that can be burned in the standard Claus incinerator. (Fig. 15.1)

Gas Plants CODE IMG017-E-A0 Rev. 02- 30/07/2004 Page 94 of 94

Fig. 15.1 Tail gas treating plant