Selective removal of CO2 from a contaminated gas stream

1
Selective removal of CO2 from a contaminated gas
stream
United Arab Emirates University College of
Engineering

• Graduation Project (I)

Saber Mohammed AL-Ammari 199900156 Bassam
Mohammed AL-Hedhani 199900146 Faris AbuBaker
AL-Ameri 980711333
Faculty Advisor Dr. Mohamed Al-Marzouqi
2
Introduction

• Carbon dioxide (CO2) is commonly found in natural
  gas streams at levels as high as 3.5 .
• Typical composition of the gas in UAE oil gas
  industry

Components Mole Fraction
Nitrogen 0.001
Carbon Dioxide 0.0339
Hydrogen Sulphide 0.0697
Methane 0.6754
Ethane 0.0393
Propane 0.1192
Water 0.0615
ADMA/OPCO Lab Manuals.
3
Introduction

• There are several technologies for removal of CO2
  from a gas mixture such as adsorption, cryogenic,
  absorption and membranes. Each technology has
  it's own advantages and disadvantages.
• absorption is widely used for CO2 removal,
  especially in the United Arab Emirates.
• the main drawback of the absorption process is
  the need for the high amount of amine along with
  the high regeneration cost.

4
Introduction

• In order to overcome this drawback, we propose
  membrane contactors for CO2 removal from a gas
  mixture.
• The advantages of membrane contactors are
• lower capital and operating cost
• operational simplicity and high reliability, high
  flux, high mass transfer rate
• high CO2 removal efficiency
• environmentally friendly.

5
Material Balance
6
Material Balance

• Tube side

Boundary conditions at z 0, CA 0, CB
CB initial at r 0,
(Symmetry)

at r R1,
7
Material Balance

• Membrane

Boundary conditions at r R1,
at r R2,
8
Material Balance

• Shell side

Boundary conditions at z L,
CAg CAinitial at r R2,
at r R3,
(Symmetry)
9
Modeling Results

• Femlab was used to solve the set of non-linear
  differential
• equations.

10
Modeling Results
11
Modeling Results

• Factors affecting carbon dioxide removal
  efficiency and total flux
• Solvent Concentration
• Solvent Average Velocity
• Feed CO2 Concentration
• Pressure Gradient in the shell side (-A
  )

12
Solvent Concentration
13
Solvent Average Velocity
14
Feed CO2 Concentration
15
Pressure Gradient in the shell side (-A)
16
CO2 Flux values in shell and tube (shell at r
0.000297, z 0.00298) (Tube at r 0.00004, z
0.000298)
Total flux (mol/m2.s) Reaction flux (mol/m2.s) Convection flux (mol/m2.s) Diffusion flux (mol/m2.s) CO2 Location
7.70E-03 0 1.10E-09 7.70E-03 Shell
4.03E-02 4.00E-02 3.00E-04 9.60E-06 Tube
CO2 Flux values in shell and tube (Shell at r
0.000297, z 0.00003) (Tube at r 0.00004, z
0.00003)
Total flux (mol/m2.s) Reaction flux (mol/m2.s) Convection flux (mol/m2.s) Diffusion flux (mol/m2.s) CO2 Location
1.15E-02 0 2.70E-11 1.15E-02 Shell
1.69E-02 1.67E-02 2.00E-04 6.70E-06 Tube
The diffusion flux is the dominant flux in the
shell side while the reaction term is dominant
in the tube side
17
Membrane and solvent membrane Selection
Solvent PTFE PP PVDF PES PS
Water v v v v v
Propylene carbonate v v X X X
Selexol x X X X X
N-methyl pyrrodilone X X X X X
Dimethyl formamide X X X X X
Tributyl phosphate X X X X X
Glycerol triacetate v X X X X
n-Formyl morpholine v v X X X
18
Membrane and solvent membrane Selection
Solvent CO2 solubility (m)a Surface tension (mN/m) Viscosity (cP) Selectivity CO2/CH4 Vapor pressure (Pa)
Propylene carbonate 3.5 41.5 2.5 26.31 11.33
Selexol 3.6 33.5 5.8 14.92 0.097
N-methyl pyrrodilone 4.56 34.4 1.7 13.88 53.33
Dimethyl formamide 4.86 30.2 0.8
Tributyl phosphate 2.5 27.5 3.4 25
Glycerol triacetate 3.7 35.8 3.5 20.55 0.13
n-Formyl morpholine 3.15 49.1 6.7 869.31
Water 0.82 72.3 1 23.5 3167.2
a m (CL/CG)equilibrium . a m (CL/CG)equilibrium .
19
EXPERIMENTAL SET-UP

• A laboratory-scale unit was specially constructed
  to study CO2-CH4 separation through membrane
  contactors.

Membrane contactor.
Experimental set-up.
20
Membrane Contactor

• The gas mixture was pumped through the shell side
  of the contactor whereas propylene carbonate
• Solvent was pumped through the fibers in a
  counter-current flow.
• Helium is used as a sweep gas to carry the
  desorbed CO2 to the online gas chromatograph for
  analysis.

21
Experiment result

• Data generated (area under the curve vs. time) by
  gas chromatograph (GC).

time (min) Area CH4 Area CO2
20 14273 20136
50 14079 18432
70 13934 18120
90 13744 18000
120 13762 17980
150 13605 17510
180 13565 17120
210 13550 16963
240 13480 16920
Area under curve vs. time generated by gas
chromatograph.
22
Based on these data, the calculation of CO2 total
flux and percentage removal are explained as
followsThe percentage removal and CO2 flux are
calculated
removal
CO2 Flux

6.610E-6
23
Conclusion of experiment

• The CO2 flux is less than the value reported in
  the literature and predicated by modeling .
• This discrepancy may be due to the problems in
  desorption part since the complete removal of CO2
  in desorption section was not possible using the
  current set-up.
• the propylene carbonate was not free of CO2 as it
  was circulated through the system. Therefore, it
  reduced the transport rate, due to smaller
  concentration difference and as a result reduced
  the CO2 flux and removal efficiency.

24
Design Consideration

• Many process parameters can be adjusted to
  optimize performance depending on the customer
  and application needs.
• Some typical requirements are
• Low cost
• High reliability
• High on-stream time
• Easy operation
• High hydrocarbon recovery
• Low maintenance
• Low energy consumption
• Low weight and space requirement

25
The Scaling Procedures

• Requirements
• Gas mixture flow rate (from industry)
• The flux from experiments or (article)
• Outlet flow rate (estimated)
• removal (from industry)
• Area of the membrane (estimated)
• Tube and shell diameter of the membrane contactor
  (estimated)

26
Tube Side Calculation
Mwt. CO2 (g/mol) Removal Co2 Composition (Feed) Mix flow rate (cm3/s) Mix flow rate (ft3/s)
44 0.88 0.05 1911600 67.5
Flux (mol/m2.sec) R (cm3.atm/mol.K) P (atm) T(K) T(oC)
0.0009 82.057 2 303 30
27
0.0035 The density of CO2 (g/cm3)
7.688 Feed flow rate (mol/s)
6.766 Outlet flow rate (mol/s)
7517.6 Area of the tube side (m2)
28
Standard Specification
0.016 Inner Diameter (m)
0.02 Outer Diameter (m)
5 Length (m)
Final Results
0.314 Area of one tube (m2)
23941.4 Number of tubes
29
Shell Side Calculation

• Using 1.25 square pitch

Number of basses n1 K1
1 2.207 0.215
COULSON RICHARDSONS, Chemical engineering
design, R K Sinnot.
30
Where Nt number of tubes do tube outside
diameter
Bundle Diameter (m) 3.87
Clearance (m) 0.05
Shell Side Diameter (m) 3.92
31
Amine Treating Unit

• The amine treating unit consist of six major
  equipments depend on an information from ADNOC
  company.

32
Heat Exchangers Capital Cost
The Unit Area (m2)
Lean/Rich DEA solution heat exchanger 429
Lean DEA solution cooler 335
DEA Reboiler 247
Condenser 147
33
Materials for the Heat Exchangers
The Unit Tube Shell
Lean/Rich DEA solution heat exchanger Stainless Steel (A1S1 304L) Carbon Steel
Lean DEA solution cooler C.S C.S
DEA Reboiler S.S (A1S1 304L) C.S
Condenser S.S (A1S1 304L) C.S
34
Shell and Tube Heat Exchanger Purchase Cost Figure
The purchase cost (bare cost from figure)
type factor pressure factor
35
The Purchase Cost of the Heat Exchangers
The Unit The Purchase Cost ()
Lean/Rich DEA solution heat exchanger 178500
Lean DEA solution cooler 51000
DEA Reboiler 136000
Condenser 85000
36
CO2 and Regenerator Vessels Purchase Costs
The Unit Height (m) Diameter (m)
CO2 Absorber 45.738 3.353
Regenerator 42.492 4.267
The type for both vessels is packed bed. The
packing size 50 mm, (pall rings, stainless
steel). The packing height is 35 m. The material
that the both vessels consist of is carbon steel.
37
Vessels Purchase Cost Figure
The purchase cost is 270000 for the CO2
absorber and 320000 for the regenerator.
38
Packing Cost
The Unit The Packing Cost ()
CO2 Absorber 420240
Regenerator 680680
39
The Final Purchase Cost of Amine Treating Unit
The Unit The Purchase Cost ()
CO2 Absorber 690240
Regenerator 1000680
The total purchase cost (PCE) the purchase
cost for (CO2 Absorber Regenerator Lean/Rich
DEA solution heat exchanger Lean DEA solution
cooler DEA Reboiler Condenser) 2141420
40
The Final Capital Cost of Amine Treating Unit
41
Item Factor
ƒ1 Equipment erection 0.4
ƒ2 Piping 0.7
ƒ3 Instrumentation 0.2
ƒ4 Electrical 0.1
ƒ5 Building None required
ƒ6 Utilities Not applicable
ƒ7 Storages 0.15
ƒ8 Site Developments Not applicable
ƒ9 Ancillary Buildings None required
ƒ10 Design and Engineering 0.3
ƒ11 Contractors Fee None
ƒ12 Contingencies 0.1
Total Capital Cost Total Purchase Cost (1
ƒi( Total investment cost _at_ 2005 5371570
1.04 9007264
42
The Operating Cost of the Amine Treating Unit
Utility The amount
Steam 22871 (Kg/h)
Cooling Water 897000 (Kg/h)
Electrical Power 2150 (KJ/s)
Solvent Loss 342 (Kg/d)
43
Summary of Production
Costs
44

• Variable Costs
• Raw materials, solvent make up 342 kg/d 347
  d/yr 1.35 /kg 160210
• Miscellaneous materials, 10 of maintenance cost
  4124200.1 41242
• Utilities Cost
• Steam, at 12/t 128328(22871/1000) 2285636
• Cooling Water, at 0.01/t 0.018328(897000/1000
  ) 74702
• Power, at 0.023/MJ (2150/1000)0.02336008328
  1482550
• Shipping and packaging, not applicable.
• Fixed Cost
• Maintenance, take as 5 of fixed capital
  82484110.05 412420
• Operating labour, say 25000
• Laboratory costs, take as 20 of the operating
  labour 250000.2 5000
• Supervision, 20 of the operating labour 5000
• Plant overheads, 50 of the operating labour
  250000.5 12500
• Capital charges, 15 of the fixed capital
  82484110.15 1237261
• Insurance, 1 of the fixed cost 82484110.01
  824841
• Annual Operating Cost at 1998 4044340 2522022
  6566362

45
Membrane Cost
The area is 30070 m2. The fibers cost is 92.96
Euro/m2 (from literature search). The cost of the
tube side (fibers) of the membrane contactor will
be (in dollars) 30070 92.96 1.3 3633899.
The shell side is calculated as a vessel, using
the previous figure for shell and tube purchase
cost figure.
The Unit Length (m) Diameter (m)
Shell Side of the Membrane Contactor 5 0.78
Membrane contactor purchase cost _at_1998 3633899
9000 3642899
46
The cost index must be used after the purchase
cost was estimated, because it is in 1998 and now
we are in 2005. So, the purchase cost in 2003
for the process will be
Allowing 4 inflation from 2003 to 2005, so the
final purchase cost of the project _at_ 2005
3930496 1.04 4087716
47
Item Factor
ƒ1 Equipment erection 0.4
ƒ2 Piping 0.7
ƒ3 Instrumentation 0.2
ƒ4 Electrical None required
ƒ5 Building None required
ƒ6 Utilities Not applicable
ƒ7 Storages 0.15
ƒ8 Site Developments 0.05
ƒ9 Ancillary Buildings None required
ƒ10 Design and Engineering 0.3
ƒ11 Contractors Fee None
ƒ12 Contingencies 0.1
Total Capital Cost Total Purchase
Cost(1ƒi) Total Capital Cost for the Membrane
Contactor _at_ 2005 14020866 701043 14721909
48
The Operating Cost of the Membrane Contactor

• Fixed Costs
• Maintenance, take as 5 of fixed capital
  140208660.05 701043
• Operating labour, say 25000
• Laboratory costs, take as 20 of the operating
  labour 250000.2 5000
• Supervision, 20 of the operating labour 5000
• Plant overheads, 50 of the operating labour
  250000.5 12500
• Capital charges, not applicable.
• Insurance, 1 of the fixed cost 140208660.01
  140209
• Variable Costs
• Raw materials, solvent make up, not required.
• Miscellaneous materials, 10 of maintenance cost
  7010430.1 70104
• Utilities Cost using table (..)
• Steam, not required
• Cooling Water, not required
• Power, not required
• Shipping and packaging, not applicable.

49
Cost Comparison

• The main objective of our project is to reduce
  the cost (specially the operating cost) of the
  gas separation process in the oil fields, by
  replacing the amine treating unit by a membrane
  contactor.

Cost type Amine treating Unit Membrane Contactor Two Membrane Contactor
Capital cost () 9.00E06 1.47E07 2.94E07
Operating Cost () 7.37E06 1.07E06 2.14E06
Total Cost () 1.64E07   3.15E07
Total Cost (after 20 years) 1.56E08   7.22E07
The total cost difference between the two
processes after 20 years is 84.2 million dollars
50
Environmental impact

• The good thing in membrane contactor system
  comparing to other system of removing that CO2
  removal collected where the other possess release
  it to atmosphere.
• The removal carbon dioxide that collected was
  storage it to use in to other applications such
  as in the soft drinks industry or fire protection
  or inject it in oil reservoir to enhance oil
  recovery.

Membrane Contactor injection or storage of
carbon dioxide.