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The project is aimed to design Amine Treating Unit for natural Gas (from a natural repository or related to an crude production ) can contain acid gas (H2S as well as CO2). The Gas Sweetening Process expects to evacuate part or the majority of the acid gas that the common gas contains for various reasons as takes after:

For security reason, to expel the H2S substance of the normal gas stream. To fulfill a Business Gas detail : H2S substance of the Business Gas must be below 4 ppm V (around 5.7 mg of H2S/Sm3 of gas or 0.25 grains of H2S/100 SCF of gas).

Amine plants for gas treatment are notable procedures to expel a progression of mixes either upstream some plant operations especially sensitive to these chemical species or before sending to vent/stack a procedure stream in order to coordinate environmental regulation . There is a long involvement in the design of amine plants and in their run of the configuration of energy incorporated absorber and stripper. In any case, the design and the unit operations of current amine forms specifically originate from plausibility concentrates in light of relentless state recreations and a progression of process control contemplations can be called pointed to by methods for the procedure dynamic.

Action Plan

Duaration Description
Week 1 We visited Orpic to get more information about our topic.
Week 2
We meet up together and discuss on what are we going to do for phase 2 and how we will do it.
Week 3 We did a research about the topic.
Week 4 We had a meeting with Orpic engineer, he explained the procees and we prepared for the midterm.
Week 5 We did a research deeply about the topic, meet Orpic engineers and learned how to to do the calculations.
Week 6 Again we visited Orpic for the dimentions and diamter length of the column etc.
Week 7 We got the resullts of the experiment and analyzed the data.
Week 8 Starting preparing for the report by searchng the information from different resources.
Week 9 We prepared the power point.

1.1: Definition of Natural gas:
natural gas is an actually happening hydrocarbon gas blend comprising essentially of methane, however generally including fluctuating measures of other higher alkanes, and a little rate of carbon dioxide, nitrogen, hydrogen sulfide, helium. It is shaped when layers of breaking down plant and creature matter are presented to serious heat and pressure t under the surface of the Earth more than a large number of years. The energy that the plants initially got from the sun is put away as chemical bonds in the gas.
1.2 History of Natural gas:
The initially popularized natural gas happened in England. Around 1785, the English utilized common gas delivered from coal to light houses and streets s. In 1816, Baltimore, Maryland utilized this sort of fabricated natural gas to wind up distinctly the first city in the Unified States to light its boulevards with gas.
Normally happening natural gas was found and distinguished in America as ahead of schedule as 1626, when French adventurers found locals lighting gasses that were saturating and around Lake Erie. In 1821, William Hart burrowed the principal effective natural gas well in the U.S. in Fredonia, New York. In the end, the Fredonia Gas Light Organization was framed, turning into the principal American natural gas distribution organization.

In 1836, the City of Philadelphia made the principal municipally claimed natural gas dispersion organization. Today, U.S. public gas system number more than 900, and the Philadelphia Gas Works is the biggest and longest working open gas framework in the U.S.

Amid a large portion of the nineteenth century ,natural gas was utilized only as a source of light, yet in 1885, Robert Bunsen’s innovation of what is currently known as the Bunsen burner opened tremendous new chances to utilize natural gas. Once compelling pipelines started to be inherent the twentieth century, the utilization of natural gas extended to home warming and cooking, machines, for example, water radiators and stove ranges, assembling and handling plants, and boilers to produce power.
1.3: The uses of Natural gas:
natural gas is a fossil fuel utilized as a source of energy for warming, cooking, and power era. It is additionally utilized as fuel for vehicles and as a substance feedstock in the fabricate of plastics and other financially critical natural chemicals. It is a non-renewable asset.
1.4: where the natural gas found:
natural gas is found in profound underground rock developments related with other hydrocarbon stores in coal beds little inns methane clathrates. Petroleum is another asset and fossil fuel found in closeness to and with natural gas. Most natural gas was made after some time by two instruments: biogenic and thermogenic. Biogenic gas is made by methanogenic living beings in marshes, landfills, and shallow silt. More profound in the earth, at more prominent temperature and weight, thermogenic gas is made from covered natural material.

1.5: Range of natural gas composition:

Figure 1 Range of Natural Gas Composition.


Based on experiment done in Contaminants in Amine Gas Treating By Randy HawsCCR.

With regards to amine contaminants, the areas of disarray that still exist fundamentally need to do with phrasing and measurement Remember that heat Stable Salts are just a single kind of contaminant that may exist in your amine system, and may not be the most troublesome one. Amine debasement items can be extremely risky moreover. When contrasting your amine examination with amine quality rules, regardless of whether gave by your provider or found in technical literature , make sure that you are looking at on a similar estimation basis The most ideal approach to get the most out of your amine system is to practice great general amine cleanliness. Anything that is not amine or water is a contaminant, and sooner or later could bring about frothing, fouling, erosion or loss of amine quality. While asking for an amine investigation, at any rate occasionally demand that all parts be measured and reported, including debasement items and direct estimation of the water.


Methyldiethanolamine, MDEA
Kohl and Riesenfield(1985) showed that MDEA has a larger capacity to react with acid gases because it can be used in higher concentrations. This preferred standpoint is upgraded by the way that it is responding with the greater part of the H2S and small part of CO2. MDEA additionally conveys energy funds by diminishing reboiler duties and bringing down overhead condenser duties.
MDEA as an absorption solvent of evacuating acid gasses is generally utilized today in natural gas processing in light of the fact that it has the attributes, for example, higher H2S selectivity, greater assimilation limit, bring down recovery energy, littler hot degradation and lesser corrosive.. MDEA has several distinct advantages over primary and secondary amines. These include lower vapor pressure, lower heats of reaction, higher resistance to degradation, fewer corrosion problems and selectivity toward H2S in the presence of CO2.


Qatar gas (2002) Acid gas is component of natural gas that contains huge amounts of (H2S),(CO2), or similar contaminants. Small amounts of hydrogen sulfide occur in crude petroleum, but natural gas can contain up to 90%. If there are more than 5.7 miligram of h2s per cubic meter of natural gas ,the natural gas considered as sour
which is equal to 4 ppm by volume. Table of composition of natural gas mixture of Qatar which contain quite large amount of sour gas.

M. Reeid& C. Updegraff 1950) H2S is a colorless, flammable, extremely hazardous gas with a ‘rotten egg’ smell. There are other names for H2S are sewer gas, stink damp, swamp gas and manure gas. It occurred naturally in natural gas and it is created by bacterial breakdown of organic materials and human and animal wastes. H2S has an unsavory scent, as well as is exceptionally noxious, being nearly as lethal as hydrogen cyanide and five to six circumstances harmful as carbon monoxide.
H2S is insignificantly heavier than air; a mix of H2S and air is insecure. H2S is dissolvable in water and goes about as a weak destructive. H2S in water is at first clear then after time it will turns shady. The reason are the moderate response of H2S with the oxygen broken down in water, yielding natural sulfur which encourages out. After burning it will produces sulphur dioxide (SO2), which is also corrosive. Its presence in chemical gases which causes catalyst poisoning and product contamination .


Nordenkampf( 2003) we can treat corrosive gas in different ways from characteristic gas. Which can include :
‘ concoction solvents
‘ physical solvents
‘ adsorption forms half and half dissolvable
‘ physical detachment (layer).
For The fundamental process we can depend on retention. selectivity of the dissolvable as for corrosive gasses also depends on a liking of the concoction or physical sort.

Process description

The light gases from the upstream units contain high concentration of H2S and CO2 that are considered as undesirable in the gas product. The feed gas to the ATU contains liquid droplets of water. This is to be removed in the Inlet Knockout Drum V-01. The gas is then feed to Amine Absorber, where a chemical of MDEA (Methyldiethanolamine) is used to remove the unwanted acid gas impurities from the system feed gas.

The sweet gas from the Absorber (C-01) is then sent to the downstream units for usage. The rich amine solution (with H2S & CO2), is continuously re-circulated to a regeneration section where the acid gas is removed from the amine solution. The amine solution is then routed back to the Absorber. The Figure 1.1 provides a simplified view of the process flow .

Figure 2.1, ATU Process flow diagram (PFD)
The sweet gas out is fed to another plant called gas dehydration plant to remove the water that leads to lower the dew point and avoid occurring of hydration in pipeline and then will be sent to the downstream units. The acid gas is fed to a plant called SRU (sulfur recovery unit) for sulfur further treatment.

3.1The major equipment required for successful treatment:
‘ Inlet scrubber (V-01)
‘ Amine contactor tower (Absorber, C-01).
‘ Lean amine/rich amine heat exchanger (E-01).
‘ Stripping column (C-03).
‘ Reflux condenser (E-02)
‘ Reflux vessel (V-02).
‘ Reflux pump (P-01A/B)
‘ Reboiler (E-03).
‘ Amine circulation main pump (P-02A/B)
‘ Full flow Carbon Filter for rich solvent (S-01A/B)

3.2 Design Capacity

Treated gas from absorber: 1000000 kg/d which is equivalent to 1000 Ton/d.

3.3 Feed gas specifications

Temperature: 26”C
Pressure: 20 bar

3.4 Composition Feed Stock.

Component RMM kg/day mole fraction
CH4 16.0425 916870 0.91687
C2H6 30.0690 30480 0.03048
C3H8 44.0956 7000 0.00700
C4H10 58.1222 2600 0.00260
C5H12 79.1721 2900 0.00290
H2S 34.0819 2500 0.00250
CO2 44.0095 11980 0.01199
N2 28.0135 24980 0.02498
H2O 18.0153 690 0.00069
Total 1000000 1.00

Table 2.1 Natural gas compositions to be treated.

3.5 Treated gas Specification:

CO2 content 0.05mol%
H2S content 0.02% (0.6 g/100 std m3)


Mass Balance

A mass balance (likewise called a material balance) is an application of conservation of mass to the investigationof physical systems. By accounting for material entering and leaving a system, mass flows can be distinguished which might have been obscure, or difficult to measure without this technique. The exact Conservation law used in the analysis of the system depends on the context of the issue but all revolve around mass conservation, i.e that matter can’t vanish or be made suddenly. .
4.1 Inlet Knockout Drum (V-01) Mass Balance.
We consider no significant change occurs in this vessel as we know from our background that the knock out drum purpose is only to remove the liquid from the gas stream which is water in our feed. The liquid amount in the inlet of scrubber is always low and because of that so many scrubbers liquid level is manually controlled.

Figure 4.1 Inlet knock out drum flow diagram.

‘ Mass balance:

At P = 20 bar and T = 26”C

RMM Feed Gas out Liquid out
kg/d kg/d kg/d
CH4 16.0425 916870 916870 0
C2H6 30.0690 30480 30480 0
C3H8 44.0956 7000 7000 0
C4H10 58.1222 2600 2600 0
C5H12 79.1721 2900 2900 0
H2S 34.0819 2500 2500 0
CO2 44.0095 11980 11980 0
N2 28.0135 24980 24980 0
H2O 18.0153 690 0 690
Total 1000000 999310 690
Table 3.1 illustrate the mass composition at inlet.

4.2 Absorber (C-01) Mass Balance:

Figure 3.2 Absorber
‘ Absorber components and overall mass balances:
Gas in = Gas out = 916870kg/day.
Assumed that the amount which is absorbed by lean amine is very low and can be negligible.
Gas in = Gas out = 30480kg/day.
Assumed that the amount which is absorbed by lean amine is very low and can be negligible.
Gas in = Gas out = 7000kg/day.
Gas in = Gas out = 2600kg/day.
Gas in = Gas out = 2900 kg/day.
Gas in = Gas out = 24980 kg/day.
Gas in = 2500 kg/day. Gas out = 12.5 kg/day (0.5% of the total H2S)
Lean amine = 0 kg/day. Rich amine = 2500 ‘ 12.5 = 2487.5 kg/day.
Lean Amine that is needed for the process is mixed with water and then goes to the absorber at flow of 250000 Kg/day (lean Amine 45% of that which is equivalent to 112500 Kg/day whereas the water is 55% which is equivalent to 137500 Kg/day).
Lean amine = Rich amine = 112500 kg/day
Gas in = 0kg/day. Gas out = 0 kg/day. (Removed in knock out vessel)
Lean amine = 137500kg/day
Rich amine = 137500 kg/day
Note: kg/RMM = kmol

4.3 Stripper (C-03) Mass Balance:

Figure 3.3 Stripper flow diagram.

‘ Stripper overall Mass balance.
Component Rich MDEA solution (S-11) Acid Gas Out
(S-14) Lean MEA solution (S-16)
kg/d kg/d kg/d
H2S 2487.5 2425.755 61.745
MDEA 112500 0 112500
H2O 137500 5206.56 132293.44
Mol of unstripped H2S/mol MDEA as per MDEA available Data 0.003706

4.4 Reflux Drum (V-03) Mass Balance:

Figure3.4 Reflux Drum flow diagram.

Table 4.4 Reflux drum overall mass balance (V-03)
Component Feed (S-13) Acid gas outlet (S-14) Liquid outlet (S-15)
RMM kg/d kmol/d Mol fraction kg/d kmol/d Mol fraction kg/d kmol/d mol%
H2S 34.0819 2425.755 71.3 0.198 2377.24 69.8 1.0 48.52 1.41 0.0049
H2O 18.0153 5206.56 289.25 0.802 0 0 0 5206.56 289.25 0.995
Total 7632.315 360.56 1.0 2377.24 69.8 1.0 5255.08 290.66 1.0

Energy balance

Table 5.1 Stripper composition calculations:
Component RMM

g”mol’1 Feed kg/day Feed kmol/day Temperature of the feed Inlet
Component Specific heat
J K’1 g’1
Stream-11 Stream-14 Stream-16
CH4 16 0 0 298.15K
366.48K 311.15K 388.65K
C2H6 30 0 0 Cpm Cpm Cpm Cpm
H2S 34.08 2487.5 73.162 H2S 1.003 34.18 34.68 34.30 34.83
H2O 18 137500 7638.89 H2O (Liq) 4.186 75.348 75.87 74.44 76.40
MDEA 61.0831 112500 1841.7533 MDEA 2.91 178 182.35 160.44 189.74

Molar Heat capacity, at constant pressure Cpm:
‘ FOR H2S at ambient temperature 298.15K (25”C) = 1.003 J K’1 g’1
‘ At 366.48K= 1.0176 J K’1 g’1

The heat energy for each component is: Q=m cp (T2-T1)
Where T1= 25C + 273.15=298.15 K , and T2 fr each stream is mentioned below:
Q=m Cp” T
T= 366.48 K T= 311.15 K T= 388.65 K
Component Rich MEA in (S-11)
” T=68.33 K Acid gas out (S-14)
” T= 13 K Lean MEA out (S-16)
” T= 90.5 K
Kmol/d Cpm (kJ/kmol.K) ‘H (kJ/day) Kmol/d Cpm (kJ/kmol.K) ‘H (kJ/day) Kmol/d Cpm (kJ/kmol.K) ‘H (kJ/d)
H2S 73.162 34.68 173370.85 71.35 34.30 31814.965 1.816 34.83 5724.241
MDEA 1841.7533 182.35 22948201 0 160.44 0 1841.7533 189.74 31625611.54
H2O 7638.89 75.87 39601511.39 289.25 74.44 279913.01 7349.636 76.4 50816853.23
Total 259915 62723083.24 360.60 311727.975 9193.205 82448189.01
Table 5.2.Stripper Streams energy balance.

5.1 Reboiler duty:

Steam rate = 0.9 lb/gallon
Total MDEA circulation flow-rate (for absorbers, C-01) = 250,000/(3.79*24*60)=45.81gpm.
(1 US gallon of water = 3.79 kilograms)
Total steam mass flow-rate = 45.81 gal/min of MEA ‘ 0.9lb/gal of steam
= 41.23lb/min’ 0.45359kg/lb=18.7 kg/min = 26929.53 kg/day
Latent heat at 121.1’C = 2199.3kJ/kg.
QR = 26928.53′ 2199.3 = 59223116 kJ/day.
QR after reduction of 3% of heat looses = 59223116’0.97 = 57446422.5 kJ/day.

HRA, heat entering with rich amine solution = 62723083.24 kJ/day.
HLA, heat leaving stripper in lean solution = 82448189.01 kJ/day.
To release the acid gas from reacted gas in liquid phase requires same amount of heat released during the absorption process
= kg/day of stripped H2S ‘ heat of reaction (kJ/kg) = 71.35’34.08′(311727.975/2487.5)=304723.7kJ/day
Partial pressure of water in the acid gas = water molar fraction ‘ total pressure
= (289.25/ 360.6) ‘ 1.38 = 1.11 bar.
Latent heat of vaporisation at 1.0 bar (from the steam table) = 2409 kJ/kg.
Heat of vaporization = 289.25 kmol/day ‘ 18.015 ‘ 2409 = 12542458.5 kJ/day.
Heat leaving with acid gas = 311727.975 kJ/day.
HAG = heat leaving with acid gas + heat absorbed to release acid gas + heat of vaporisation
HAG = 311727.975 + 304723.7 + 12542458.5 = 13158910.2 kJ/day.

5.2 Condenser duty:

QC, Condenser duty = (HRA + QR) ‘ (HAG + HLA)
= (62723083.24+ 57446422.5) ‘ (13158910.2 +82448189.01)
= 24562406.53 kJ/day.

Process Design

6.1 Inlet knock-out drum Design (V-01)

Figure 6.1 Inlet knock-out drum flow diagram.

Liquid hydrocarbons and entrained solids frequently can enter the plant with the sour gas stream. Also there are some other materials such as corrosion inhibitors, drilling mud and well acidizers can be associated the sour gas stream. This can cause many problems in amine plant operations such as foaming, corrosion and reboiler tube burn-out. To overcome such problems, the inlet knock-out drum is needed. This vessel is equipped with knitted mesh demisting pads to improve the performance.
6.2 Design calculation
Table 5.1.feed compositions mass and molar flow-rates.
At P = 74 bar and T = 26”C

RMM Feed Gas out Liquid out
kg/day kg/d kg/d
CH4 16.0425 916870 916870 0
C2H6 30.0690 30480 30480 0
C3H8 44.0956 7000 7000 0
C4H10 58.1222 2600 2600 0
C5H12 79.1721 2900 2900 0
H2S 34.0819 2500 2500 0
CO2 44.0095 11980 11980 0
N2 28.0135 24980 24980 0
H2O 18.0153 690 0 690
Total 1000000 999310 690

Mass flow-rate of dry gas = 1000,000 kg/day.
Mass flow-rate of water = 690 kg/day.
Liquid density = 1009 kg/m3 (density at 38C)

Vapour density = 52.37 kg/m3

ut = settling velocity ,m/s
= liquid density, kg/m3
= vapour density, kg/m3

This. equation is used to estimate the settling velocity of the liquid droplets, for the design of separating,,vessels.

we prefer to equip the vessel with demister pad to ensure most of the liquid that could associate the sour gas and can cause a problem to be captured. is not necessarily, hence
Vapour volumetric flow-rate=
Minimum vessel allowable diameter,

Liquid volumetric flow-rate=
Allow a minimum of 10 minutes hold-up.
Volume held in vessel =
Liquid depth required,

‘The height of the vessel outlet above the gas inlet should be sufficient to allow for disengagement of the liquid drops. A height equal to the diameter of the vessel or 1m, whichever is the greatest, should be used. Recommended liquid depth =0.3 m for installing a level controller in the liquid outlet.The ratio between the height and the diameter is almost 2:1 which is acceptable as by looking to the shape of the separator is almost within this ratio.

Schematic Diagram

The layout and typical proportions of a vertical gas – liquid separator are shown in Figure below.

Figure 6.2. Reflux drum dimensions

‘ Rich/Lean amine Heat Exchanger Design (E-01)

Duty of the exchanger = heat gained by cold fluid or heat lost by hot fluid
= heat gained by rich amine = (59582229 ‘ 21494111)
= 38088118kJ/h = 10580kJ/s = 10580kW.

The temperatures of rich amine inlet, rich amine outlet and lean amine inlet are known and the amine outlet temperature is obtained using energy balance and goal seek program.

Overall coefficient:

The water is the main component in the fluid compositions (around 85%). Accordingly, the first assumption for overall heat transfer coefficient will be 800W/m2’C.

6.3 Exchanger type and dimensions

A significantly number of tube passes is normally favored as the inlet and outlet nozzles will be at a similar end of the exchanger which streamlines the pipework. .
Start with one shell pass and 2 tube passes

where: = log mean temperature difference,
T1 = hot fluid temperature, inlet,
T2 = hot fluid temperature, outlet,
t1 = cold fluid temperature, inlet,
t2 = cold fluid temperature, outlet.

“The standard practice in the plan of shell and tube exchangers is to gauge the “true temperature difference ” from the logarithmic mean temperature by applying a correction element to take into account the takeoff from true counter-current stream”

Where = true temperature difference, the mean temperature difference for use in the design ,,equation.
Ft = the temperature correction factor.
The correction factor is a function of the shell and tube fluid temperatures, and the number of tube and shell passes.. It is normally correlated as a function of two dimensionless temperature ratios.

The Ft of one shell pass and two or more even tube passes can not be acquired because the S and R values do not intercept on the figure. In this case the two shell passes with four or multiples of four tube passes is used

Figure 5.3: Temperature correction factor: two shell passes; four or multiples of four tube passes.

Ft = 0.81
”Tm = 22.58 ‘ 0.81 = 18.29 ‘C

Heat transfer area:

Q = UA’Tm
‘A =
Layout and tube size:
Using a split-ring floating head exchanger for productivity and ease of cleaning. As the rich amine fluid is corrosive, the stainless steel is preferred to be used for the tube. The carbon steel with corrosion allowance can be used.

Pipe dimensions Mm M
Outside diameter 20 0.02
Inside diameter 16 0.016
Length 5000 5

Number of tubes:
Area of one tube (neglecting thickness of tube sheets).
Tube surface area
Number of tubes, , say 2302
Tube arrangement of square is preferred as it has less pressure drop
Therefore a 1.25 square Pitch will be used.
Tube cross-sectional area =
Total tube area = 2302 ‘ 0.0002 = 0.463m2.
Put high pressure stream (lean amine in tube)
The velocity for one pass:
This velocity is too less to make effective use of the allowable pressure drop, try 8 passes.
The velocity is satisfactory, between 1 to 2 m/s.

Bundle and shell diameter:
Kern’s method will be used.
From the table below, for 8 tube passes,
K1 = 0.0331, n1 = 2.643

Constants that used for bundle diameter calculation.

For spilt-ring floating head exchanger the typical shell clearance from Figure 3.14 by extrapolating is 0.082m.

Ds = 1.36 + 0.082 = 1.442m.
Tube side heat transfer coefficient:

Reynolds number, Re =
Prandtl number, Pr=
Where, kf= fluid thermal conductivity, W/m’C.

From the figure below, jh factor = 0.004

Figure6.4 .Tube-side heat-transfer factor

Nusselt number, Nu =
Inside heat transfer coefficient, hi =

Shell-side heat transfer coefficient

Take 25% cut baffles.
Take baffle spacing as 1/2 shell diameter (Ds)
Baffle spacing, lB = 1.442/2 = 0.721m.
Area for flow, As, will be half as there are two shell passes.
Tube pitch,(Pt) = 1.25do = 1.25 ‘ 0.02 = 0.025m

Where: Gs = shell-side mass velocity, kg/m2.s
Ws = fluid flowrate on the shell-side, kg/s.

, satisfactory, shell-side velocity for liquid 0.3 to 1m/s

The shell-side equivalent diameter (hydraulic diameter), for square pitch arrangement:

From Figure 3.16, jh= 0.006

Figure6.5. Shell-side heat-transfer factors, segmental baffles

Shell heat transfer coefficient, hs=

Overall coefficient:

Fouling factor for organic liquid = 0.0002m2’C/W and for cooling water = 0.0003 to 0.00017m2’C/W, so the fouling factor for the mixture is taken as 0.0002m2’C/W.

Well above the initial estimate of 800 , so design has adequate area for the duty required.

Pressure drop:


Re = 17,758
From Figure 3.17, jf= 0.0041

Neglecting the viscosity correction


Re = 8587
From Figure 3.18, js= 0.05

With a divided shell, the path length = 2 ‘ (L/lb) = 2’ (5/0.721) = 13.87m.
Neglecting the viscosity correction

This is acceptable because the rich amine which is flowing through the shell-side will be flashed in the stripper where the pressure is 1.38bar. In addition, this fluid is not forced by power which can cause a load waste and increase in the operating cost.

6.4 Stripper design C-03.
Packed column is used for designing of stripping column.

Table 5.4 Physical properties for the mini absorber packed column streams.
Component T= 378.15 K T= 366.45 K
Gas out Liquid in
kg/d ‘ (kg/m3) ‘ (cp) kg/d ‘ (kg/m3) ‘ (cp)
CH4 84 0.71 1.4E-02 83.66 0.73 1.34E-02
C2H6 9 1.33 1.2E-02 9.03 1.37 1.16E-02
H2S 10870 1.50 1.5E-02 12349 1.55 1.47E-02
CO2 64247 1.94 1.9E-02 149208 2.00 1.84E-02
MEA 0 983.45 1.1E+01 774281 923.55 4.34E+00
H2O 241031 0.58 1.2E-01 4386378 953.48 3.00E-01
Total/ average 316240 0.89 9.6E-02 5322309 920.23 8.79E-01

Gas flow-rate =
Liquid flow-rate =
Select 76mm (3 in) ceramic Intalox saddles.
Packing factor, Fp = 72 m-1.
Gas density at 105’C = 0.89 kg/m3.
Liquid density = 920 kg/m3.
Liquid viscosity = 0.00088 Ns/m2.
(The component densities and viscosities are obtained from the HYSYS program and then used to calculate the average density/viscosity of the steams)

Design for a pressure drop of 20 mm H2O/m packing
K4 = 0.48
At flooding K4 = 1.2
Percentage flooding =

Column area required =
Diameter =
Packing size to column diameter ratio =
This is satisfactory as the recommended size ranges are

In Rosen’s original article, he also recommended the use of 20 actual trays on 24 inch spacing in the stripper of 54 inches inside diameter. (Ref.9, P-59). This can be used to estimate our stripper height which has 74 inches inside diameter.
The height of the column = 0.6m (spacing) ‘ 20 trays ‘1.2 = 14.4 m ‘ 15 m.
Packed height = 11m (leaving 4 meters of spacing at the top and bottom, for reflux and reboiler streams connection).
‘ Reflux Pump Design (P-01).
The water flows with stripped gases is condensed in the condenser at 38’C. the condensed water is collected in the reflux drum and then pumped back to the stripper as a reflux. There are two identical pumps used for this purpose, one in duty and the other one kept stand by.
There are many factors influence the selection of the pump type,
‘ The quantity of fluid to be pumped
‘ The head against which the liquid is to be pumped
‘ The nature of the fluid to be pumped.

Liquid is water.
Mass flowrate = 2.755 kg/s.
Vessel pressure =1.35bara.
Temperature = 38oC
Density at 38oC = 998kg/m3
Viscosity = 0.677mNs/m2
Pipe material = carbon steel.
Length from flash vessel to the pump = 4m.

Estimation of pipe diameter required:
Typical velocity for liquid = 1-3 m/s
Volumetric flow =
Optimum diameter for carbon steel pipe can be obtained using the following equation:

where: G = mass flowrate in kg/s, ‘ = liquid density in kg/m3.

Optimum velocity
Pressure drop calculation:-

Friction loss per unit length, ‘f1,

The absolute roughness for commercial steel pipe, e=0.046mm
Relative roughness e/d = 0.046/39 = 0.0018
Friction factor from pipe friction graph, f= 0.002625
‘pf= 8f(L/di)
Where: ‘pf= pressure drop,N/m2
F= friction factor
L= pipe length m
di=pipe inside diameter, m
”= fluid density kg/m3
u= fluid velocity, m/s

Design for a maximum flow-rate of 20% above the average flow.
Miscellaneous losses
There are many variables that can impacts the liquid pressure , for example, bends, valves, holes, tee intersection, and so forth. This drop in pressure should be figured to come over it.

Take as proportionate pipe diameter. All curves will be taken as 90o standard range elbow.
Line to pump suction:

At the inlet of the pump

Velocity heads.
Velocity head = of liquid.
Head loss = velocity head ”nK = 0.274’ 0.85 = 0.233m
As pressure = h’g = 0.233 ‘ 9.8 ‘ 998 = 2281N/m2.
+ Pressure loss due to fittings.
= 8.32 + 2.2 = 10.6kPa.

The most imperative thing is to check the NPSH accessible. It is essential that the segment pressure does not fall beneath vapor pressure of the fluid being pumped; generally an air pocket will frame creating pump cavitation which could harm the inward parts of the pump.

where: NPSH = net positive head available
P = the pressure above the liquid in the feed vessel, N/m2.
H = the height of the liquid above the pump suction, m.
Pv = vapour pressure of the liquid at the pump suction. N/m2.
g = acceleration of gravity, 9.8m/s2.
where: = A,B,C = the Antoine coefficients.
T = in K.
The fluid is water.

As general guide, the NPSH should be above 3m for pump capacities up to 100m3/h, and 6m above this capacity.
Our pump capacity is (2.755/998)*3600 = 9.9m3/h, so the NPSH is satisfactory.

Entry loss=
At maximum design velocity= kpa
The pipe length from the pump discharge to the inlet of stripper is 19m.

Control valve pressure drop, allow normal 140 kPa
Maximum = (140’1.22) = 201.6 kPa
Orifice, allow normal 15 kPa
Maximum = 15’1.22 = 21.6 kPa.

Design for a maximum flow-rate of 20% above the average flow.
Friction loss= 27.43 ‘1.22 = 39.5 kPa

Velocity heads.
Velocity head = 0.274 m of liquid (calculate at earlier stage).
Head loss = velocity head ”nK = 0.274’ 4.2 = 1.151m
As pressure = h’g = 1.151 ‘ 9.8 ‘ 998 = 11257N/m2.
Pressure loss due to pipe friction and pipe fittings = 39.5 + 11.26 = 50.76kPa.

Total discharge line pressure drop = 50.76 + 201.6 + 21.6 = 273.96kPa equivalent to 28

Health & Environment impact of hydrogen sulfide

7.1 Public health statement for hydrogen Sulfide :
This Public Health Statement summarizes what is known about hydrogen sulfide such as possible health effects from exposure and what you can do to limit exposure.
7.2What is hydrogen Sulifide ?
Hydrogen sulfide (H2S) is a combustible, dreary gas that odors like spoiled eggs. Individuals more often than not can notice hydrogen sulfide at low concentration in air, extending from 0.0005 to 0.3 sections hydrogen sulfide for every million sections of air (ppm). At high fixations, a man may lose their capacity to notice it. This is critical in light of the fact that a man may erroneously believe that hydrogen sulfide is do not present anymore; this may build their presentation hazard to air levels that may bring about serious health impacts.
The U.S. Environmental Protection Agency (EPA) identifies the most serious hazardous waste sites in the country. These sites make up the National Priorities List (NPL) and are sites targeted for long-term federal clean-up exercises. U.S. EPA has found hydrogen sulfide in at least 34 of the 1,832 current or former NPL sites. The total number of NPL sites assessed for hydrogen sulfide is not known. But the possibility remains that as more sites are assessed, the sites at which hydrogen sulfide is found may increase. This Critical data because these future sites may be sources of exposure, and exposure to hydrogen sulfide may be harmful.
On the off chance that you are presented to hydrogen sulfide, many elements figure out if you’ll be hurt. These incorporate the amount you are presented to (dosage), to what extent you are uncovered (duration), and how you are uncovered (route of expsure). You should likewise consider alternate chemicals you are exposed to and your age, sex, slim down, way of life, and condition of wellbeing.
Hydrogen sulfide happens both actually and from human-made procedures. It is in the gasses from volcanoes, sulfur springs, undersea vents, swamps, stale waterways, and in unrefined petroleum and common gas. Hydrogen sulfide is additionally connected with metropolitan sewers and sewage treatment plants, swine control and fertilizer taking care of operations, and mash and paper operations. Other mechanical wellsprings of hydrogen sulfide incorporate petroleum refineries, regular gas plants, petrochemical plants, coke .
7.3Public health statement :
oven plants, nourishment preparing plants, and tanneries. Microorganisms found in your mouth and gastrointestinal tract deliver hydrogen sulfide amid the absorption of nourishment containing vegetable or creature proteins.
Hydrogen sulfide is utilized basically in the generation of sulfur and sulfuric corrosive. It can likewise be utilized to make different chemicals, for example, sodium sulfide and sodium hydrosulfide, which are utilized to make an assortment of items.
7.4What happens to hydrogen sulfide when it enter the environment?
The majority of the hydrogen sulfide discharged to air originates from common sources, for example, bogs, marshes, and volcanoes. Hydrogen sulfide can likewise be discharged from mechanical sources, for example, petroleum refineries, regular gas plants, kraft paper factories, fertilizer treatment offices, squander water treatment offices, and tanneries. Hydrogen sulfide air fixations from characteristic sources run in the vicinity of 0.00011 and 0.00033 ppm. In urban territories, the air fixations are for the most part under 0.001 ppm. Hydrogen sulfide stays in the air for roughly 1’42 days, contingent upon the season. It can change into sulfur dioxide and sulfates noticeable all around.
7.5 How might I be exposed to hydrogen sulfide?
Your body makes small amounts of hydrogen sulfide. Hydrogen sulfide is produced by the natural bacteria in your mouth. It is also produced when some types of proteins are broken down by bacteria in the intestines.
Hydrogen sulfide may be discharged to water in fluid misuse of a modern office or as the aftereffect of a characteristic occasion. It can be actually present in well water. Hydrogen sulfide fixations in surface water are generally low since it promptly vanishes from water. It can likewise be available in groundwater. Groundwater convergences of hydrogen sulfide are by and large under 1 ppm; be that as it may, measured sulfur focuses in surface and waste waters have extended from somewhat under 1 to 5 ppm.
Hydrogen sulfide can enter soil through environmental testimony or from spills. In soil, hydrogen sulfide is devoured by microscopic organisms, which transform it to sulfur. The levels of hydrogen sulfide in air and water are ordinarily low. Family unit exposures to hydrogen sulfide can happen through abuse of deplete cleaning materials. Hydrogen sulfide can be found in well .
7.6 Public health statement :
water and can be shaped in boiling hot water warmers, giving faucet water a spoiled egg smell. Tobacco smoke and outflows from fuel vehicles contain hydrogen sulfide. The all inclusive community can be presented to lower levels from unplanned or consider arrival of outflows from mash and paper plants; from characteristic gas penetrating and refining operations; and from territories of high geothermal movement, for example, hot springs.
ndividuals who work in specific businesses can be presented to more elevated amounts of hydrogen sulfide than the overall public. These businesses incorporate rayon materials assembling, mash and paper factories, petroleum and characteristic gas boring operations, and waste water treatment plants. Specialists on ranches with excrement stockpiling pits or landfills can likewise be presented to more elevated amounts of hydrogen sulfide than the overall public. As an individual from the overall population, you may be presented to higher-than-typical levels of hydrogen sulfide on the off chance that you live close to a waste water treatment plant, a gas and oil boring operation, a ranch with excrement stockpiling or domesticated animals control offices, or a landfill. Introduction from these sources is fundamentally from breathing air that contains hydrogen sulfide.

7.7How can hydrogen sulfide enter and leave my BODY?
Hydrogen sulfide enters your body fundamentally through the air you relax. Significantly littler sums can enter your body through the skin. Hydrogen sulfide is a gas, so you would not likely be presented to it by ingestion. When you inhale air containing hydrogen sulfide or when hydrogen sulfide comes into contact with skin, it is retained into the circulatory system and disseminated all through the body. In the body, hydrogen sulfide is essentially changed over to sulfate and is discharged in the pee. Hydrogen sulfide is quickly expelled from the body.
7.8 Hoh can hydrogen sulfide affect my health?
You are not likely to have health effects if you are exposed to typical environmental concentrations of hydrogen sulfide. You can have respiratory and neurological effects if you are exposed to higher concentrations of hydrogen sulfide, at least 100 times higher than typical environmental levels. The effects can include:
‘ Eye irritation ‘ Nose irritation ‘ Throat irritation ‘ Difficulty breathing in people with asthma ‘ Headaches
7.9 Public health statement :
‘ Poor memory ‘ Tiredness ‘ Balance problems
If you are exposed to very high concentrations of hydrogen sulfide, you may have severe problems breathing even if you do not have a pre-existing respiratory condition. You could lose consciousness if you are briefly exposed to very high concentrations (more than 1 million times higher than the amount typically found in the environment). If this happens, you may regain consciousness without any other effects. However, some people may have longer lasting effects such as headaches, poor attention span, poor memory, and poor motor function.
Hydrogen sulfide has not been appeared to bring about disease in people, and its conceivable capacity to bring about growth in creatures has not been examined completely. The Bureau of Wellbeing and Human Administrations (HHS) and the Universal Office for Exploration on Growth (IARC) have not ordered hydrogen sulfide as to its cancer-causing nature. EPA has established that information for hydrogen sulfide are lacking for cancer-causing evaluation.
7.10 How can hydrogen sulphide Affect children?
This section discusses potential health effects of hydrogen sulfide exposure in humans from when they’re first conceived to 18 years of age.
There is almost no data on conceivable medical issues in kids who have been presented to hydrogen sulfide. Kids presented to hydrogen sulfide may have impacts like grown-ups. Be that as it may, we don’t know whether youngsters are more touchy to hydrogen sulfide than grown-ups
We do not know whether hydrogen sulfide causes birth defects in humans. Studies in laboratory animals suggest that exposure to low concentrations of hydrogen sulfide during pregnancy does not cause birth defects.
7.11 How can families reduce the risk of exposure to hydrogen sulphide?
If your doctor finds that you have been exposed to significant amounts of hydrogen sulfide, ask whether your children might also be exposed. Your doctor might need to ask your state health department to investigate.
ARE THERE Medicinal TESTS TO Figure out if I HAVE BEEN Presented TO HYDROGEN SULFIDE? Hydrogen sulfide and its breakdown items, for example, thiosulfate can be measured in blood and pee. Be that as it may, the location of hydrogen sulfide or its metabolites can’t foresee the sort of wellbeing impacts that may create from that presentation. Since hydrogen sulfide and its metabolites leave the body reasonably quickly, the tests should be led not long after introduction.

7.12 What recommendations has the federal government made to protect human health?
The government creates controls and proposals to secure general wellbeing. Directions can be upheld by law. Government offices that create directions for lethal substances incorporate the Natural Insurance Organization (EPA), the Word related Wellbeing and Wellbeing Organization (OSHA), and the Nourishment and Medication Organization (FDA). Suggestions give profitable rules to ensure general wellbeing however are not enforceable by law. Government associations that create suggestions for Hydrogen sulfide is part of the natural environment; the general population will have some exposure to hydrogen sulfide. How much hydrogen sulfide you are exposed and for how long are two factors that could determine whether you get sick. Families can be exposed to more hydrogen sulfide than the general population if they live near natural or industrial sources of hydrogen sulfide, such as hot springs, manure holding tanks, or pulp and paper mills. However, these exposure levels are generally not high enough to make you sick.
Families can decrease their introduction to hydrogen sulfide by evading zones that are wellsprings of hydrogen sulfide. For instance, people of families that live on ranches can dodge fertilizer stockpiling territories where high convergences of hydrogen sulfide.


This project is aimed to remove H2sfrom the natural gas by using amine treatment unit (ATU). When we removeH2s from the natural gas we save our environment, people’s lives, and use H2s as byproduct for manufacturing battery and other thing. We chose amine treatment unit (ATU) because it has many benefits compare to other methods.
The following table indicates the final specification of the products to be produced when the ATU operates at normal design feedstock and conditions:
Specification Unit Limit
Sweet gas H2S content Mol-ppm 25 max
Lean amine (MDEA) concentration Wt.% 45
H2S/MDEA mole-ratio in lean amine – 0.01
Acid gas H2S content Mol% 90 min

Amine Treatment Unit (ATU) project is one of the most important technologies that make a significant improvement in three major parts Environmental and health impact where the main aim of our project is to stop releasing of hazardous acid gases to the atmosphere that may lead to environmental pollution.
Save people from the dangers of H2S (silent killer) by H2S treatment and sulphur recovery in the Sulphur Recovery Unit (SRU).

This project contributes in improving the quality of the produced fuels by removing the sulphur and other hazardous compounds

‘ Chemical Engineering, Green, D.Wand Maloney, J.O.(1997) (Eds.), Perry`s.
‘ Safety,Health,and Environmental concepts (for the process industry, ichael Speegle , Cengage Learning, (2012 2nd edition ) , ISBN : 1133013473, 9781133013471.
‘ Orpic document,
‘ Chemical Engineering Design, Ray Sinnott& Gavin Towler , (5th edition) , Elsevier, 2009 , ISBN : 0080942490, 9780080942490.
‘ Process Technology Equipment & systems, Charles E. Thomas , (2th edition) , Cengage Learning, 2010 , ISBN : 1435499123, 9781435499126.
‘ McGraw-Hill Education, .
‘ Process technology plant operations, Michael Speegle , Delmar Cengage Learning, 2014 , (2nd edition) , ISBN: 1133950159, 9781133950158.
‘ Process Heat Transfer, Donald Quentin Kern , McGraw-Hill, 1950 , ISBN : 0074632175, 9780074632178.
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