Design of Membrane Contactor Process for the Removal of H2S from Natural Gas

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Design of Membrane Contactor Process for the
Removal of H2S from Natural Gas
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• Objective
• Introduction
• Available Technologies
• Proposed Technology
• Membrane Contactor Design
• Cost Estimation and Comparison
• Environmental Impact
• Conclusions Recommendations

OUTLINE
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The aim of our project is to remove Hydrogen
Sulfide (H2S) from natural gas using membrane
contactors
OBJECTIVE
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INTRODUCTION
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The United Arab Emirates possesses one of the
worlds largest natural gas reserves 250
trillion cubic feet
INTRODUCTION
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Natural gas is a combustible mixture of
hydrocarbon gases and acid gases. Properties
of pure natural gas Colorless Shapeless Odorle
ss
INTRODUCTION
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Typical Composition of Natural Gas Typical Composition of Natural Gas Typical Composition of Natural Gas
Methane CH4 70-90
Ethane C2H6 0-20
Propane C3H8 0-20
Butane C4H10 0-20
Carbon Dioxide CO2 0-8
Hydrogen sulfide H2S 0-5
Oxygen O2 0-0.2
Nitrogen N2 0-5
Rare gases A, He, Ne, Xe trace
INTRODUCTION
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Available Technologies
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• Adsorption
• Clinoptilolite fixed bed Adsorption
• Pressure Swing Adsorption (PSA)
• Absorption
• Chemical Absorption
• Pressure swing Sorption (PSS)
• Membrane contactor

Available Technologies
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Comparison of the available technology
Technology Efficiency Capital Cost Operating Cost
Clinoptilolite X O O -
PSA X X X
Chemical Absorption O O O O O
PSS X - X
Membrane Contactor O O O X
Very High o o High o Low x
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Proposed Technology
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Difference between absorption unit and membrane
contactor
Figure 1 Absorption unit
Figure 2 Membrane unit
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Membrane Contactors
Similar to shell and tube heat exchanger Gas
mixture flows on one side of the membrane
module while the solvent is introduced to the
other side
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Membrane Contactors
Where A H2S , B natural gas components and C
lean solvent
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Membrane Contactors
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Material Balance

• Membrane contactor consists of
• Tube side
• Membrane
• Shell side

Figure 3 Schematic diagram for flow in the
membrane contactor
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Material Balance (Tube side)

• Steady state material balance (Convection
  Diffusion)
• Boundary Conditions

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Material Balance (Membrane)

• Steady state material balance (Diffusion)
• Boundary Conditions (Diffusion)

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Material Balance (Amine H2S )

• Steady state material balance (Convection
  Diffusion)
• Reaction rates
• Boundary Conditions

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Modeling Results Results
Solubility of H2S in Amine 0.91
Diffusivity of H2S in MDEA (m2/s) 8.00E-10
Diffusivity of H2S in Methane (m2/s) 1.86E-05
Diffusivity of H2S in Membrane (m2/s) 1.86E-05
Diffusivity of MDEA in solution (m2/s) 4.00E-10
Forward Rate Constant (m3/mol.s) 1.00E06
Reversed Rate Constant (m3/mol.s) 38461
Initial Concentrations of H2S and MDEA (mol/m3) 40 8750
R1 (m) 0.00011
R2 (m) 0.00015
R3 (m) 0.000265
L (m) 2
T (C) 25
Shell
Tube
Membrane
Figure 4 H2S concentration profile in tube,
membrane and shell side
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Factors affecting hydrogen sulfide removal
efficiency and total flux
Solvent concentration Solvent flow rate Gas
flow rate
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Solvent concentration (CAmine)
Figure 5 Effect of solvent concentration on
effluent H2S concentration
Figure 6 Effect of solvent concentration on H2S
total flux
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Solvent flow rate
Figure 8 Effect of solvent flow rate on H2S
total flux
Figure 7 Effect of solvent flow rate on effluent
H2S concentration
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Gas flow rate
Figure 10 Effect of gas flow rate on H2S total
flux
Figure 9 Effect of gas flow rate on H2S
effluent concentration
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Membrane Contactor Design
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Design Considerations

• Process parameters needed to optimize the
  performance of any process
• Low cost
• High reliability
• High on-stream time
• Easy operation
• Low energy consumption
• Low weight and space requirement
• The design engineer must therefore balance
  the requirements against one another to achieve
  an overall optimum system.

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Membrane Scale-up
For high H2S percentage removal, High membrane
area is required
D. Dortmundt K. Doshi, Recent Developments in
CO2 Removal Membrane Technology UOP LLC, 1999
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Fluid Configurations

• Two configurations were tested for the final
  selection of the most effective and economical
  option
• Gas in the shell / Solvent in the tubes
• Solvent in the shell / Gas in the tubes

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Scaling Procedure
Parameters used in COMSOL
Diffusivity, (m2/s) Diffusivity, (m2/s)
H2S in MDEA 8.00E-10
H2S in CH4 3.27E-07
H2S in membrane 3.826 E-08
MDEA in solutions 4.00E-10
   
Tube radius, (m) 0.0004
Membrane thickness, (m) 0.0001
Shell radius, (m) 0.0009
Length, (m) 4
kf ,(m3/mol.s) 1.00E06
kR , (m3/mol.s) 3.85E04
CH2So , (mol/m3) 206
CMDEAo , (mol/m3) 3880
Gas flow rate, (kmol/hr) 1.75E04
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Testing Results

• 1st test (Gas in the shell / Solvent in the tube)
• The flux of H2S from membrane to solvent was
  found to be
• 2nd test (Solvent in the shell / Gas in the tube)
• The flux of H2S from membrane to solvent was
  found to be

• From the results, it is clear that the second
  configuration leads to
• higher flux ? lower membrane area ? lower
  capital cost.
• The second configuration is chosen for
  separation

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Design Results Discussions

• The total area of tubes ? 43,881 m2
• Number of tubes ? 3,490,956
• Bundle diameter ? 3.36 m
• Shell diameter ? 3.463 m
• Due to the large diameter size, it is
• recommended to use two modules operating
• in parallel with smaller diameter ? 2.48 shell
• diameter.
• Amine required for sweetening 54 kmol/hr

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Design Results Discussions

• The results show that using membrane
• contactor will save 98 of the solvent
• required for sweetening with respect to the
• absorption tower which requires 2800 kmol/hr
• of amine.

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Cost Estimation Comparison
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• Membrane Contactor Capital Cost ? 29 million
  dollars
• Absorption Tower Capital Cost ? 15.5 million
  dollars
• The above results shows that the membrane
  contactor
• capital cost is 50 higher than the absorption
  tower.

Capital Cost
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Membrane Contactor Operating Cost ? 316,848/yr
Absorption Tower Operating Cost ?
16,741,300/yr The above results shows that the
membrane contactor Operating cost is 98 less
than the absorption tower.
Operating cost
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Comparison
Figure 11 Cost Analysis between absorption unit
and membrane contactor unit
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Money saved from using membrane contactors
instead of absorption units was estimated to be
around 310 million if the fibers are not
replaced and 200 million in the case if
replacing the fibers every 5 years
Comparison
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Conventional vs. Membrane Contactors
Absorption Unit
Membrane Contactor
Absorption unit occupies much large area than
membrane contactor
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Environmental Impact
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H2S Problems
H2S is Corrosive H2S Deactivates
Catalysts H2S is Highly Toxic
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Effect of H2S on Human
1 ppm Can be smelled
10 ppm Allowable for 8 hours
100 ppm Kills sense of smell in few minutes, burn eyes and throat
1000 ppm Unconscious at once and death if not rescued promptly
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Conclusions Recommendations
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• Two membrane contactors are proposed to remove
  1237 kmol/hr of H2S from natural gas.
• The capital cost of the membrane contactor is 50
  higher than the absorption tower.
• The operating cost of the membrane contactor unit
  is 98 less than the absorption unit.
• It is recommended to divide the membrane
  contactor to several sectors, where fresh amine
  will be introduced to each module

Conclusions
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Conclusions Recommendations
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