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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.

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