H2S and CO2 capture from gaseous fuels using nanoparticle membrane

Accepted Manuscript H2S and CO2 Capture from Gaseous Fuels using Nanoparticle Membrane

Hamed Abdolahi-Mansoorkhani, Sadegh Seddighi PII:

S0360-5442(18)32328-4

DOI:

10.1016/j.energy.2018.11.117

Reference:

EGY 14215

To appear in:

Energy

Received Date:

18 August 2018

Accepted Date:

25 November 2018

Please cite this article as: Hamed Abdolahi-Mansoorkhani, Sadegh Seddighi, H2S and CO2 Capture from Gaseous Fuels using Nanoparticle Membrane, Energy (2018), doi: 10.1016/j.energy. 2018.11.117

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ACCEPTED MANUSCRIPT

H2S and CO2 Capture from Gaseous Fuels using Nanoparticle Membrane Hamed Abdolahi-Mansoorkhani a, Sadegh Seddighi a* a

Department of Mechanical Engineering, K. N. Toosi University of Technology,

Tehran, Iran * Corresponding emails: [email protected]

Abstract This work investigates the simultaneous removal of CO2 and H2S from natural gas by a novel PVDF membrane structure using CaCO3 nanoparticles aiming at increasing the efficiency of separation process. This work presents to what extent the CaCO3 nanoparticles improve the separation efficiency; proposes the optimum range of nanoparticle share in the membrane for achieving maximum separation in increased flow rates; and finally evaluating the effects of operational conditions such as temperature, flow velocity and species concentration on the system performance. A mathematical finite element model is developed to simulate the gas removal using a membrane module including both mass transfer equations and chemical reaction mechanism. A good agreement has been achieved between the modeling results and the measured data. It is found that 20% CaCO3 nanoparticle share in membrane gives the highest separation efficiency and any higher or lower nanoparticle concentration reduces the gas separation efficiency. Gas and fluid velocities have a high impact on separation efficiency. For example, increase in gas velocity from 5 m/s to 20 m/s leads to reduction in CO2 removal efficiency from 82% to 42% and H2S efficiency from 100% to 60%. Keywords CO2 Separation; H2S Separation; Membrane; Nanoparticles; Carbon Capture

1.

Introduction

Carbon dioxide (CO2) is a key cause of man-made climate change as an imminent threat to the planet earth. Atmospheric emission of CO2 have elevated rapidly since 1950 leading to global warming [1]. Fossil fuel combustion used for power generation and energy conversion has been a main source of the CO2 emission. CO2 accounts for almost 80% of 1

ACCEPTED MANUSCRIPT the greenhouse gases while more than half of the emitted CO2 is from fossil fuel combustion in industries [2]. The main roadmap for long-term clean energy is the largescale utilization of renewable energy sources such as solar cells [3-5], bio solar cells [6, 7] and wind energy [8, 9]. However, vast resources of fossil fuels and the slow-changing energy industry makes it unlikely to phase out the fossil fuel in the near future. Thus reducing the emitted CO2 can be pursued in parallel using two main methods of 1) utilizing carbon capture and storage via oxy-fuel combustion [10-15], chemical looping [16, 17] or post combustion capture [18, 19] and 2) to use fossil fuels with low carbon to hydrogen ratios (C/H) such as natural gas [20, 21]. CO2 and H2S are the main impurities of the natural gas streams and should be removed from gases using proper technologies. Natural gas reserves contain CO2 in addition to considerable amounts of the extremely hazardous hydrogen sulphide (H2S) gas. Only 1000 ppm of H2S causes instant death for the humans while even smaller doses of H2S is very corrosive to the equipment and causes severe health damages. H2S helps the formation of acid rains and damages the industrial equipment. Sulphur emissions in general are highly corrosive and damage the environment and health and therefore must be minimized using various methods such as flue gas desulfurization [22, 23] or by fuel cleaning membranes [24] . The separated CO2 in especial can be an asset for enhanced oil recovery (EOR) [25] and enhanced gas recovery (EGR) [26] applications. The similarities in the molecular structure and size of the CO2 and H2S molecules facilitate simultaneous separation of these two molecule types from the main gas stream. Three main technologies for separating gas species from main gas streams are chemical absorbents, physical absorbents, cryogenic methods [27] and surface absorption. Typical method for separating CO2 and H2S are: 1- Chemical absorption: separation in this method is performed via exothermic reaction between CO2 and the chemical absorbent at low temperatures. 2- Sweetening alkanolamines: this method which is utilized in separation columns uses streams of sour gas and amine solution in the column where amine absorbs the CO2 and H2S from the gas stream leading to a clean outgoing gas stream [28]. 3- Rectisol process: In this approach cold methanol acts as a solvent that removes gas impurities such as hydrogen cyanide, H2S and CO2. 4- Sulfinol process: this process simultaneously removes CO2 and H2S from gases and benefits from solvents such as sulfolane, Diisopropanolamine (DIPA) and 2

ACCEPTED MANUSCRIPT water to make a process combining physical and chemical absorbent properties [29]. 5- Membrane processes: membranes have been used vastly during the last couple of decades for various purposes. Membranes act as a selective boundary that control which species can pass and which species are to be blocked. Easy operation and flexibility in design and construction made membranes a rapidly growing technology for gas separation. One of the emerging membrane methods for separating gases is hollow fiber membrane contactor (HFMC). In HFMC’s, membrane enables the contact between gas and fluid for mass transfer without a complete mixing. So in this method fluid and gas are streaming in different sides of the membrane contactor. The contact surface between gas and fluid is in the membrane pores. Easy control of the gas and fluid flow rates and high surface area per unit contactor volume even at varying flow rates have led to further utilization of this method [30]. Cussler [31] has been among the first groups in evaluating HFMC who used sodium hydroxide (NaOH) for separating CO2. Membrane wettability, membrane type, absorbent type and operational parameters such as temperature and pressure are the key parameters affecting the performance of the HFMC. Major absorbents used for CO2 separation from gases are methyl diethanolamine (MDEA), monoethanolamine (MEA), NaOH, Triethanolamine (TEA), Aminoethylethanolamine (AEEA), 2-amino-2-methyl-1propanol (AMP) and Potassium hydroxide (KOH) [32-36]. Simultaneous separation of H2S and CO2 from the gas flows has also attracted the research and development teams due to it’s industrial importance. Mandal et al. [37] investigated the H2S separation from a gaseous mixture of H2S and CO2 using MDEA and AMP in a wet column. Faiz and ElMarzouqi [38] investigated simultaneous separation of H2S and CO2 from methane (CH4) in ambient temperature and pressure using MEA as absorbent. Since the membrane is in contact with the fluid, hydrophobicity is a key factor in choosing the membrane type for separation purposes. Membranes such as Polypropylene (PP), Polyethylene (PE), Polytetrafluoroethylene (PTFE) and Polyvinylidene fluoride (PVDF) are among the main candidates as the membrane material. Fluoride membranes typically have high hydrophobic capability and have a better resistant to wetting in contact with fluids with low surface tension leading to a better performance in separation. PTFE is among the most hydrophobic and stable membranes used for separation in the presence of the fluids. 3

ACCEPTED MANUSCRIPT However PTFE has relatively high costs due to the complicated construction [39]. Dindor et al. [40] found that PVDF and PP have better consistency with varying absorbent types. Khaisri et al. [41] compared the performance of three hydrophobic membrane type of PP, PTFE and PVDF to separate CO2 using MEA absorbent concluding PTFE has the dominating separation performance and has the highest stability among the three membrane material types. Researchers are actively seeking new methods for boosting the efficiency of separation in membrane systems. For instance, separation of CO2 and H2S under high pressure conditions shows the importance of pressure for CO2 and H2S separation from synthetic biogas [42]. Rostami et al. [43] used ionic liquids and water to separate CO2 from gas stream concluding ionic liquid significantly improves the water performance for CO2 separation. Nakhjiri et al. [44] used HFMC to separate CO2 from natural gas showing the superior performance of potassium argininate compared to potassium glycinate and sodium hydroxzide. Cao et al. [45] studied the performance of a PTFE membrane for separating CO2 concluding that the increased liquid phase temperature and amine concentration leads to an enhance CO2 separation performance. Nakhjiri et al. [46] used PP as the membrane and found that the performance of MEA as an absorbent is 30% better than TEA absorbent. Saidi[47]

used methyl diethanolamine (MDEA) and

piperazine (PZ) finding addition of PZ to MDEA absorbent improves the CO2 separation performance. Addition of nanoparticles to the absorbent is also shown to improves the CO2 separation efficiency [48]. The addition of Carbide-derived-carbon (CDC) has also showed to improve the thermal stability of the membrane while increasing the separation efficiency of CO2 from natural gas [49]. Looking at the literatures published in membrane separation such as those published in [49-52], one can see that the main focuses has been the geometry of membrane module, absorbent composition for achieving a new absorbent with good separation performance, the effects of the operational conditions on the process efficiency and producing new membrane types for better separation performance. This work uses a HFMC membrane type for simultaneous separation of H2S and CO2 from natural gas stream. The selection of HFMC as the membrane for this work is based on HFMC’s excellent porosity, permeability and thermal stability. Material selection is a critical step for the design of membrane systems since any shortcoming in membrane permeability or wettability leads to failure in proper gas separation performance. Fluoride 4

ACCEPTED MANUSCRIPT membranes such as PVDF and PTFE have better hydrophobicity, permeability and thermal stability compared to membranes such as PP and PE. However, the high costs associated with production of PTFE [53] leads to industrially accepted PVDF membranes. It is found that there is an inverse relationship between permeability and selectivity of polymer membranes [54, 55]. Addition of inorganic materials to membranes is a solution for producing membranes with high mechanical strength, excellent chemical properties and good permeability [56, 57]. Thus, this work chooses a PVDF-based membrane strengthened with CaCO3 nanoparticles. The originality of this work lies in increasing the efficiency of separation process by proposing a new PVDF structure using CaCO3 nanoparticles. In particular, this work aims at: 1) presenting to what extent the CaCO3 nanoparticles improve the separation efficiency; 2) proposing the optimum range of nanoparticle mass share in the membrane for achieving the maximum separation in high flow rates; and 3) evaluating the effects of operational conditions such as temperature, flow velocity and species concentration on the system performance.

2.

Modeling

A two dimensional computational fluid dynamics model based on finite element approach is used in this work. The model is part of comprehensive in-house modeling tools, developed by the authors, for clean combustion technologies with various publication outputs such as in [22, 25, 58-63]. The modeling procedure in this work is based on the main subroutines of shell side modeling, membrane side modeling, tube side modeling and reaction kinetics, each described briefly in this section. The subroutines are solved together and the equations are coupled. The modeling covers radial and axial flow inside the module while the gas flows inside the shell and the fluid flows inside the tube. Since the penetration resistance is less for gas compared to fluid, it is assumed that the membrane holes are filled with gas instead of fluid. Thus the model is developed assuming dry membrane model which is an assumption pursued by other modeling work such as in [64]. The gas is assumed to follow the ideal gas law. The incoming gas flow consists of 80% methane, 10% H2S and 10% CO2. MEA is used as the absorbent fluid. Figure 1 shows a schematic of separation process used in this work. Figure 2 gives the concept of gas separation technique using a membrane contactor, a shell and a tube. As seen, absorbent in tube side flows in the opposite direction of the gas flow in the shell 5

ACCEPTED MANUSCRIPT side with the membrane separating the shell and tube as can be seen in Figure 3. The properties of the modeled membrane contactor module are given in Table 1 and Table 2.

Figure 1: Schematic of the membrane system

b)

a)

Figure 2: The schematic of the HFMC shown in a) geometrical configuration and b) separation schematic

6

ACCEPTED MANUSCRIPT

Figure 3: The schematic of the membrane contactor

Table 1: The properties of the modeled membrane contactor module according to [65]

The membrane parameter

Value

Module length (mm)

270

Fiber O.D. (mm)

850-970

Fiber I.D. (mm)

630-690

Number of fibers

5

Effective fiber length (mm)

175

Table 2: The physical properties of the modeled membrane according to [65]

%CaCO3 / PVDF

Mean pore size(μm)

Porosity

Water contact angle (°)

0%

0.036

0.77

88.31

10%

0.029

0.79

99.49

20%

0.027

0.81

100.66

30%

0.026

0.79

101.53

7

ACCEPTED MANUSCRIPT The continuity equation for each specie is given as below: ∂𝐶𝑖 ∂𝑡

= ‒ ∇.𝐽𝑖 + 𝑅𝑖

(1)

where Ji is flux, Ci is concentration, and Ri is the rate of reaction each for specie i. The flux is calculated according to Fick’s law: 𝐽𝑖 = ‒ 𝐷𝑖∇𝐶𝑖 + 𝐶𝑖𝑉𝑧

(2)

Where Di is the diffusivity of specie i and Vz is the velocity in the direction of the module. Combining the equations of continuity and diffusivity, the general mass balance equation is found as below: ∂𝐶𝑖

= ‒ ∇.( ‒ 𝐷𝑖∇𝐶𝑖 + 𝐶𝑖𝑉𝑧) + 𝑅𝑖

∂𝑡

(3)

Shell side modeling: The continuity equation for CO2 and H2S in shell side written as below where Ri is removed since there is no reaction in the shell side:

𝐷𝐶𝑂

𝐷𝐻

[

2

∂ 𝐶𝐶𝑂

2 ‒ 𝑠ℎ𝑒𝑙𝑙

2

2 ‒ 𝑠ℎ𝑒𝑙𝑙

2

∂𝑟

[

2𝑠 ‒ 𝑠ℎ𝑒𝑙𝑙

2

∂ 𝐶𝐻

]

∂𝐶 ∂ 𝐶𝐶𝑂 ‒ 𝑠ℎ𝑒𝑙𝑙 ∂𝐶𝐶𝑂 ‒ 𝑠ℎ𝑒𝑙𝑙 1 𝐶𝑂2 ‒ 𝑠ℎ𝑒𝑙𝑙 2 2 + + = 𝑉 𝑧 ‒ 𝑠ℎ𝑒𝑙𝑙 2 𝑟 ∂𝑟 ∂𝑧 ∂𝑧

2

2𝑠 ‒ 𝑠ℎ𝑒𝑙𝑙

2

∂𝑟

(4)

]

∂𝐶 ∂ 𝐶𝐻 𝑠 ‒ 𝑠ℎ𝑒𝑙𝑙 ∂𝐶𝐻 𝑠 ‒ 𝑠ℎ𝑒𝑙𝑙 1 𝐻2𝑠 ‒ 𝑠ℎ𝑒𝑙𝑙 2 2 (5 + + = 𝑉 𝑧 ‒ 𝑠ℎ𝑒𝑙𝑙 2 𝑟 ∂𝑟 ∂𝑧 ∂𝑧 )

Happel’s free surface model [66] is utilized to calculate the velocity distribution in hollow fibers. The laminar parabolic velocity profile outside the hollow fiber is given as below:

8

ACCEPTED MANUSCRIPT

[

() () 2

𝑟

3

‒

𝑅2 𝑅3

2

+ 2ln

𝑅2

()

2

𝑟

[ ( )] ( ) ( ) ( )

𝑉𝑧 ‒ 𝑠ℎ𝑒𝑙𝑙 = 2𝑢 1 ‒

𝑅2 𝑅3

2

×

𝑅

3+

𝑅2

4

‒4

𝑅3

𝑅2

2

+ 4ln

𝑅3

𝑅2 𝑅3

]

(6)

where u is the average velocity in shell side, R3 is the radius of free surface, R2 is the outer radius of fibers (see Figure 3). The radius of free surface can be calculated as below:

𝑅3 = 𝑅2 1/(1 ‒ ∅)

(7)

where φ is the volume fraction of the void inside the membrane contactor. Boundary conditions in the shell side is given as below. 𝑧=𝐿

𝐶𝑖 ‒ 𝑠ℎ𝑒𝑙𝑙 = 𝐶𝑖𝑛𝑖𝑡𝑖𝑎𝑙

𝑟 = 𝑅2

𝑖 = 𝐶𝑂2 𝑎𝑛𝑑 𝐻2𝑆

(8)

𝐶𝑖 ‒ 𝑠ℎ𝑒𝑙𝑙 = 𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒

∂𝐶𝑖 ‒ 𝑠ℎ𝑒𝑙𝑙

𝑟 = 𝑅3

∂𝑟

(9)

=0

(10)

Membrane side modeling: Assuming the pores are filled with gas, inside the membrane can be assumed to have only one phase that is gas. Thus the steady state continuity equation for CO2 and H2S in membrane can be written according to the dispersion as below:

𝐷𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒

[

2

∂ 𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 2

∂𝑟

2

]

1 ∂𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 ∂ 𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 + + =0 2 𝑟 ∂𝑟 ∂𝑧

(11)

Where Di-membrane is the diffusivity coefficient of CO2 and H2S in the membrane which is dependent on the porosity and tortuosity. The boundary conditions for solving the membrane equation are given below:

9

ACCEPTED MANUSCRIPT

𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 =

𝐶𝑖 ‒ 𝑇𝑢𝑏𝑒

𝑎𝑡 𝑟 = 𝑅1

𝑚𝑖

(12)

where mi is solubility of CO2 and H2S in MEA that achieved from henry’s law.

𝐶𝑖 ‒ 𝑠ℎ𝑒𝑙𝑙 = 𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒

𝑎𝑡

𝑟 = 𝑅2

(13)

Tube side modeling: The steady state continuity equation for transport of CO2 and H2S while reacting with MEA in the tube changing the specie composition is given below where convection, dispersion (using Fick’s law) and reaction are included.

𝐷𝑖 ‒ 𝑡𝑢𝑏𝑒

[

2

∂ 𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 2

∂𝑟

2

]

∂𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 1 ∂𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 ∂ 𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 + + + 𝑅 = 𝑉 𝑖 𝑧 ‒ 𝑡𝑢𝑏𝑒 2 𝑟 ∂𝑟 ∂𝑧 ∂𝑧

(14)

where Ci is the concentration, Di is diffusion coefficient and Ri is the reaction term. Only axial convective mass transfer is assumed [67] since the radial convection is small compared to the axial convection. The velocity distribution is assumed to follow laminar velocity profile as below.

[ ( )]

𝑟 𝑉𝑧 ‒ 𝑡𝑢𝑏𝑒 = 2𝑣 1 ‒ 𝑅1

2

(15)

where 𝑣 is average velocity in tube side. Boundary conditions on tube side are given as below:

𝑎𝑡 𝑧 = 0 ,

𝑎𝑡

𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 = 0

𝑟=0 ,

∂𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 ∂𝑟

,𝐶𝑀𝐸𝐴 ‒ 𝑡𝑢𝑏𝑒 = 𝐶𝑖𝑛𝑖𝑡𝑖𝑎𝑙

= 0 (𝑠𝑦𝑚𝑚𝑒𝑡𝑟𝑦)

10

(𝑖 = 𝑎𝑙𝑙 𝑠𝑝𝑒𝑐𝑖𝑒𝑠)

(𝑖 = 𝑎𝑙𝑙 𝑠𝑝𝑒𝑐𝑖𝑒𝑠)

(16)

(17)

ACCEPTED MANUSCRIPT 𝑟 = 𝑅1 , 𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒 = 𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 × 𝑚𝑖

(𝑖 = 𝐶𝑂2 𝑎𝑛𝑑 𝐻2𝑆)

(18)

Diffusion of CO2 in MEA is found according [68] to as below:

(

𝐷𝐶𝑂 ,𝐻

(𝐷𝐶𝑂 )𝑀𝐸𝐴 = 𝐷𝑁 𝑂,𝑀𝐸𝐴 𝐷 2

2

2

2𝑂

𝑁2𝑂,𝐻2𝑂

)

(19)

where 𝐷𝐶𝑂 ,𝑀𝐸𝐴 is diffusivity of CO2 and 𝐷𝑁 𝑂,𝑀𝐸𝐴 is the diffusivity of N2O in MEA 2

2

solution. 𝐷𝑁 𝑂,𝑀𝐸𝐴 in is found via the following equation [69]. 2

𝐷𝑁 𝑂,𝑀𝐸𝐴 2

‒2

= (5.07 × 10 + 8.5 × 10 ‒ 2371 + ( ‒ 93.4𝐶𝑀𝐸𝐴) ) 𝑇

‒3

𝐶𝑀𝐸𝐴 + 2.78 × 10

‒3

2

𝐶𝑀𝐸𝐴) × exp ((20 )

Diffusivity of CO2 and N2O in water is found as below [68]:

(𝐷𝐶𝑂 )𝑤𝑎𝑡𝑒𝑟 = 2.35 × 10 ‒ 6 exp ( ‒

2119 ) 𝑇

(21)

(𝐷𝑁 𝑂)𝑤𝑎𝑡𝑒𝑟 = 2.35 × 10 ‒ 6 exp ( ‒

2371 ) 𝑇

(22)

2

2

The Henri coefficient, which is an important factor in gas stripping, is found as below:

(

𝐻𝐶𝑂 ,𝐻

(𝐻𝐶𝑂 )𝑀𝐸𝐴 = 𝐻𝑁 𝑂,𝑀𝐸𝐴 𝐻 2

2

2

2𝑂

𝑁2𝑂,𝐻2𝑂

)

(23)

The parameters of Eq (23) is found as below: 6

𝐻𝐶𝑂 ,𝐻 = 2.82 × 10 exp 2

2𝑂

11

( ) 2044 𝑇

(24)

ACCEPTED MANUSCRIPT

𝐻𝑁

6 = 8.55 × 10 exp 2𝑂,𝐻2𝑂

(2284 𝑇 ) (25)

The Henri coefficient for N2O to MEA is found according to as shown below:

(

5

𝐻𝑁 𝑂,𝑀𝐸𝐴 = 1.207 × 10 exp ‒ 2

)

1136.5 𝑇

(26)

Where 𝐻𝐶𝑂 ,𝑀𝐸𝐴 and 𝐻𝑁 𝑂,𝑀𝐸𝐴 are the Henry’s constant of CO2 and N2O in MEA, 2

2

correspondingly. Reaction Kinetics: Table 3 gives the chemical properties of parameters used in modeling. The reaction between CO2 and MEA is given as below: CO2 + 2MEA→MEA

+

+ MEACOO

‒

(27)

The reaction rate of Eq. (27) is given as below [70]: 10.99 ‒ 3

𝑘𝑀𝐸𝐴(𝑚 𝑚𝑜𝑙

‒1 ‒1

𝑆

)=

10

2152 𝑇

1000

(28)

The reaction between H2S and MEA, given below, is modeled according to [71]. 𝐻2𝑆 + 𝑀𝐸𝐴→𝑀𝐸𝐴𝐻

+

+ 𝐻𝑆

‒

(29)

The rates of reaction occurred in absorption of CO2 and H2S are given below according to [38]. 𝑅𝐶𝑂 =‒ 𝑘𝑀𝐸𝐴[𝐶𝑂2][𝑀𝐸𝐴] 2

12

(30)

ACCEPTED MANUSCRIPT

𝑅𝐻 𝑆 =‒ 𝑘𝐻 2

(

2𝑆 ‒ 𝑀𝐸𝐴

[𝑀𝐸𝐴][𝐻2𝑆] ‒

𝑅𝑀𝐸𝐴 =‒ 2𝑘𝑀𝐸𝐴[𝐶𝑂2][𝑀𝐸𝐴] ‒ 𝑘𝐻

𝑅𝑀𝐸𝐴 + = 𝑘𝑀𝐸𝐴[𝐶𝑂2][𝑀𝐸𝐴] + 𝑘𝐻

(

2𝑆 ‒ 𝑀𝐸𝐴

(

2𝑆 ‒ 𝑀𝐸𝐴

[𝐻𝑆 ‒ ][𝑀𝐸𝐴 + ] 𝐾𝑒𝑞

[𝑀𝐸𝐴][𝐻2𝑆] ‒

[𝑀𝐸𝐴][𝐻2𝑆] ‒

)

[𝐻𝑆 ‒ ][𝑀𝐸𝐴 + ] 𝐾𝑒𝑞

[𝐻𝑆 ‒ ][𝑀𝐸𝐴 + ] 𝐾𝑒𝑞

𝑅𝑀𝐸𝐴𝐶𝑂𝑂 ‒ 1 = 𝑘𝑀𝐸𝐴[𝐶𝑂2][𝑀𝐸𝐴]

𝑅𝐻𝑆 ‒ = 𝑘𝐻

(

2𝑆 ‒ 𝑀𝐸𝐴

[𝑀𝐸𝐴][𝐻2𝑆] ‒

[𝐻𝑆 ‒ ][𝑀𝐸𝐴 + ] 𝐾𝑒𝑞

𝐷𝐶𝑂 𝐷𝐶𝑂

(𝑚 𝑆

)

2 ‒1

2 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒

𝐷𝐶𝑂 𝐷𝐻 𝐷𝐻

2 ‒1

2 ‒ 𝑠ℎ𝑒𝑙𝑙

2 ‒ 𝑇𝑢𝑏𝑒

(𝑚 𝑆

(𝑚 2𝑆 ‒ 𝑠ℎ𝑒𝑙𝑙

Reference

1.8 ✕10-5

[72]

𝐷𝐶𝑂

(𝜀/𝜏)

2 ‒ 𝑠ℎ𝑒𝑙𝑙

-

2 ‒1

)

Eq. (19)

[72]

2 ‒1

)

2 ✕10-5

[72]

(𝑚 𝑆 𝑆

(𝑚 2𝑆 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒

𝐷𝐻

)

Value

(𝑚 2𝑆 ‒ 𝑇𝑢𝑏𝑒

2 ‒1

𝑆

)

2 ‒1

𝑆

)

𝐷𝐻

(𝜀/𝜏)

2𝑆 ‒ 𝑠ℎ𝑒𝑙𝑙

𝐷𝐶𝑂

2 ‒ 𝑇𝑢𝑏𝑒

13

-

)

)

(32)

(33)

(34)

)

Table 3: The chemical properties of parameters used in modeling

Parameter

(31)

(35)

ACCEPTED MANUSCRIPT 2 ‒1

𝐷𝑀𝐸𝐴 ‒ 𝑡𝑢𝑏𝑒 (𝑚 𝑆 𝑚𝐶𝑂 (𝑚𝑜𝑙.𝑚𝑜𝑙

)

‒1

)

2

𝑚𝐻 𝑆 (𝑚𝑜𝑙.𝑚𝑜𝑙

‒1

2

3.

)

9.3*10-10

[73]

0.81

[68]

2.3

[38]

Validation

Grid independence is performed to assure that the cell size is not affecting the results in this work. The grid independence and solution stability is checked by CO2 removal result in various cell sizes as shown in Figure 4. Number of cells varied from 73452 to 289054 when the cell number of 104464 is chosen according to Figure 4.

CO2 Removal efficiency (%)

80

75

70

65

60

CO2 Removal

55

50 0

5e+4

1e+5

2e+5

2e+5

3e+5

3e+5

Number of cells Figure 4: The grid independence using CO2 removal for various number of cells ‒𝟑 ‒𝟏 ‒𝟏 (CaCO3/PVDF=20%, 𝑪𝑴𝑬𝑨 = 𝟏𝟎𝟎𝟎 𝒎𝒐𝒍𝒎 , 𝑽𝒍𝒊𝒒𝒖𝒊𝒅 = 𝟎.𝟓𝒎𝒔 , 𝑽𝒈𝒂𝒔 = 𝟏𝟎𝒎𝒔 ).

The model validation of this work is divided to two parts. The CO2 removal is validated using the work by [74] which used various absorbents for removing CO2 from gaseous fuels in a dry membrane. The H2S removal in the model is validated using [38] where they removed H2S from gas using MEA. The rate of mass transfer is found as below [75]:

14

ACCEPTED MANUSCRIPT 𝐽𝐶𝑂2 = (𝑄𝑖𝑛 × 𝐶𝑖𝑛 ‒ 𝑄𝑜𝑢𝑡 × 𝐶𝑜𝑢𝑡) × 273.15 ×

1000 22.4 × 𝑇𝑔 × 𝑆

(36)

where JCO2 is the CO2 mass transfer rate, Qin and Qout are incoming and outgoing gas flowrates respectively, Cin and Cout are incoming and outgoing CO2 volume concentration respectively, Tg is the gas temperature and S is the contact surface between gas and liquid. Figure 5 Comparison between the modeled flux of CO2 absorption and the experimental data of Yan et.al [74]. As seen, the results of modeling this work is capable of capturing both the trend and the values of experimental CO2 flux. As the fluid velocity increases, the boundary layer thickness decreases and consequently, more gas can enter to liquid. This is in agreement with the previous results such as those form [76] . Figure 6 shows the comparison between the modeled H2S removal efficiency and the results reported by Faiz and al-Marzuqi [38] where a good agreement between the results of this work and the results of Faiz and al-Marzuqi [38] can be seen. As expected, with the increase in the gas flow velocity the residence time of the reactants decreases leading to lower efficiency of H2S removal.

CO2 Flux (mol/m2.h)

2.6

2.4

2.2

2.0

1.8

Model Exp.(Yan et.al)

1.6 0.00

0.02

0.04

0.06

0.08

0.10

0.12

Liquid velocity (m/s) Figure 5: Comparison between the modeled flux of CO2 absorption and the experimental data of ‒𝟏 Yan et.al [74] (𝑽𝒈𝒂𝒔 = 𝟐.𝟏𝟏 𝒎𝒔 ; 𝑻𝒈 = 𝟐𝟗𝟖 𝑲)

15

ACCEPTED MANUSCRIPT

H2S Removal efficiency (%)

100

80

60

40

20

Faiz and Al-Marzouqi This work

0 2

4

6

8

10

12

14

16

18

20

22

Gas velocity (m/s) Figure 6: Comparison between the modeled 𝑯𝟐𝑺 removal efficiency and the results reported by Faiz and al-Marzuqi [38]. Type of membrane (PP), 𝑳 = 𝟐𝟐 𝒄𝒎, 𝑪𝑯 𝑪𝑴𝑬𝑨 ‒ 𝒊𝒏𝒍𝒆𝒕 = 𝟏𝟎𝟎𝟎 𝒎𝒐𝒍𝒎

4.

‒𝟑

𝟐𝑺 ‒ 𝒊𝒏𝒍𝒆𝒕

, 𝑽𝒍𝒊𝒒𝒖𝒊𝒅 = 𝟎.𝟔𝟕 𝒎𝒔

‒𝟏

= 𝟒𝒎𝒐𝒍𝒎

‒𝟑

,

.

Results and Discussion

Figure 7 shows the removal efficiency for CO2 (fig a) and H2S (fig b) in two conditions of parallel flow and counter flow. As described in modeling section, gas flows in the shell side and the absorbent fluid flows in tube side. As seen in Figure 7 the removal efficiency is better when using counter flow leading to lower concentration of H2S and CO2 in the outgoing flow when using counter flow comparing to parallel flow. The main reason for the better performance of counter flow compared to parallel flow is that the concentration difference between two side, which is a driver for gas dispersion in the membrane, is stronger in counter flow compared to parallel flow. The results show that the counter flow configuration gives 3% more removal of H2S and CO2 Separation compared to the parallel flow configuration.

16

ACCEPTED MANUSCRIPT 86

H2S Removal efficiency (%)

CO2 Removal efficiency (%)

75

70

65

60

55

Counter flow Parallel flow

84 82 80 78 76 74

counter flow parallel flow

72 70

50 0.0

0.5

1.0

1.5

2.0

2.5

0.0

3.0

0.5

1.0

1.5

2.0

2.5

3.0

Liquid speed (m/s)

Liquid speed (m/s)

Figure 7: The removal efficiency for 𝐶𝑂2 (fig a) and 𝐻2𝑆 (fig b) in two conditions of parallel flow and counter flow (%

𝐶𝑎𝐶𝑂3 𝑃𝑉𝐷𝐹

= 20 ,𝑣𝑔𝑎𝑠 = 10𝑚𝑠

‒1

, MEA Concentration

3

=1000 𝑚𝑜𝑙/𝑚 )

Figure 8 shows the schematic of the membrane module modified using nanoparticle. In addition, the surface of the membrane after the addition of nanoparticles is presented in Figure 8. The addition of nanoparticles lead to surface modification in a way that more roughness and consequently more contact surface becomes available on the membrane surface improving the reaction rates.

17

ACCEPTED MANUSCRIPT

Figure 8: The schematic of the membrane modified with nanoparticle addition

Figure 9 shows the flux CO2 and H2S at varying concentrations of nanoparticle in the membrane. As seen, the flux of CO2 and H2S increases with the increase in nanoparticle concentration. The maximum flux occurs at nanoparticle concentration of %

𝐶𝑎𝐶𝑂3 𝑃𝑉𝐷𝐹

= 20

where the CO2 flux reaches 0.0093 mol/m2s and H2S flux reaches 0.012 mol/m2s. The reason for higher CO2 and H2S flux at higher nanoparticle concentration is the improved surface conditions due to that the membrane porosity increases from 0.77 to 0.81. Also the contact angle between gas and fluid increases from 88° to 100° [65]. Increased porosity leads to better dispersion of gases to the membrane while higher gas-fluid contact angle leads to higher resistance to membrane wettability and better gas dispersion. However increasing the nanoparticle concentration from 20% to 30% leads to reduction in the gas flux in the membrane which can be motivated by the anti-nucleating properties which reduces the contact surface between gas and the surface reducing the gas flux.

18

ACCEPTED MANUSCRIPT 0.014

2

Flux (mol/m .s)

0.012 0.010 0.008 0.006 0.004

CO2 Flux H2S Flux

0.002 0.000 0

5

10

15

20

25

30

35

Weight percent ; CaCO3/PVDF Figure 9: Effect of mass fraction of nanoparticle on flux of 𝑪𝑶𝟐 and 𝑯𝟐𝑺 . 𝑽𝒈𝒂𝒔=10𝒎𝒔 𝒎𝒔

‒𝟏

; MEA Concentration =1000 𝒎𝒐𝒍/𝒎

𝟑

‒𝟏

𝑽𝒍𝒊𝒒= 0.7

Figure 10 shows the effect of nanoparticle mass fraction on removal of CO2 and H2S. As seen, the share of removed H2S and CO2 increases with the increase in the nanoparticle concentration in membrane. The maximum gas removal occurs in %

𝐶𝑎𝐶𝑂3 𝑃𝑉𝐷𝐹

= 20 leading

to 83% removal of H2S and 67% removal of CO2. Increased share of nanoparticles leads to the increased surface area of the membrane and increased share of the passing gas through the membrane (see Figure 8) leading to enhanced removal of H2S and CO2. Since %

𝐶𝑎𝐶𝑂3 𝑃𝑉𝐷𝐹

= 20 is found in this work to have the maximum separation efficiency, the

modeling in the rest of this work is based on this nanoparticle concentration.

19

ACCEPTED MANUSCRIPT

Figure 10: Effect of nanoparticle mass fraction on removal of 𝑪𝑶𝟐 and 𝑯𝟐𝑺, 𝑽𝒍𝒊𝒒= 0.7𝒎𝒔 Concentration =1000 𝒎𝒐𝒍/𝒎

‒𝟏

; MEA

𝟑

Figure 11 shows the Effect of liquid velocity on Removal of CO2 and H2S. Gas and liquid velocities have key importance in commercializing the gas separation technology since they control the flow rate of cleaned gases and the flow rate of absorbent consumption. As seen, the removal efficiency increases with the increase in the liquid velocity which is due to the higher probability of the contact between the clean MEA and the gases. With the increased MEA flow velocity, the MEA which has already reacted with CO2 and H2S leaves the module faster making the room for the new absorbent for new reactions. Thus, the rate of removal of CO2 and H2S increases with the increase in the MEA flow velocity. Recent results published in [46] and [50] verify our conclusion and show that the increase in the absorbent velocity leads to an enhanced separation of CO2 from gas stream.

20

ACCEPTED MANUSCRIPT

Figure 11: Effect of liquid velocity on Removal of 𝑪𝑶𝟐 and 𝑯𝟐𝑺: 𝑽𝒈𝒂𝒔 = 𝟏𝟎𝒎𝒔 MEA Concentration =𝟏𝟎𝟎𝟎𝒎𝒐𝒍𝒎

‒𝟏

;%

𝑪𝒂𝑪𝑶𝟑 𝑷𝑽𝑫𝑭

= 𝟐𝟎;

‒𝟑

Figure 12 shows Effect of Gas velocity on Removal CO2 and H2S. As seen, the removal efficiency reduces with the increase in the gas velocity. The increased gas velocity reduces the contact time between the gas molecules and the membrane leading to a reduced probability of the gas molecules diffusing into the membrane reacting with MEA. The modeling results of Figure 12 are in line with findings of [44, 46, 50] in that the increased gas velocity and flow rate leads to a lower mass transport through the membrane and consequently lower separation of the H2S and CO2.

21

ACCEPTED MANUSCRIPT

Figure 12: Effect of Gas velocity on Removal 𝑪𝑶𝟐 and 𝑯𝟐𝑺 ; 𝑽𝒍𝒊𝒒𝒖𝒊𝒅 = 𝟎.𝟕𝒎𝒔 MEA Concentration =1000 𝒎𝒐𝒍𝒎

‒𝟏

;%

𝑪𝒂𝑪𝑶𝟑 𝑷𝑽𝑫𝑭

= 𝟐𝟎;

‒𝟑

Figure 13 shows the effect of the MEA concentration on the outgoing concentrations of H2S and CO2. As seen, increased MEA at low MEA concentrations lead to better capture of CO2 and H2S due to the higher probability of meeting between the MEA and CO2 and H2S assuming the same mixing rate. Yet when MEA concentration is high, there is already a high probability of reactant collision and further MEA concentration addition would have minimal impacts on the removal efficiency and one can assume a saturation of MEA in the fluid mixture. These results are in line with the results found in [45] and [77] pinpointing that when surpassing absorbent concentration beyond a certain level, further increase in absorbent concentration have minimal impact on separation performance.

22

ACCEPTED MANUSCRIPT

Figure 13: effect of MEA concentration on outlet concentration of 𝑪𝑶𝟐 and 𝑯𝟐𝑺 ; . 𝑽𝒈𝒂𝒔=10 𝒔 = 0.7𝒎𝒔

‒𝟏

; 𝐂𝐎𝟐𝒊𝒏𝒍𝒆𝒕 = 𝟒 𝒎𝒐𝒍𝒎

‒𝟑

, 𝐇𝟐𝑺 𝒊𝒏𝒍𝒆𝒕 = 𝟒𝒎𝒐𝒍𝒎

‒𝟑

‒𝟏

; 𝑽𝒍𝒊𝒒

Figure 14 shows the effects of feed temperature on the removal of H2S and CO2. The temperature changes affects various physical and chemical properties such as dispersion coefficient given in Eq. (20) and solubility. Also increase temperature increases the partial pressure of CO2 (as also concluded by [78]) leading to enhanced solubility of CO2 in the MEA solution and consequently higher removal of CO2 and H2S. Increased removal of CO2 from the membrane module at higher temperature also reported experimentally by [44, 79] and numerically by [80]. Considering the similarities between size and structure of CO2 and H2S, it is concluded in this work that the increased temperature also enhances the solubility of H2S molecules in the MEA solution increasing the removal efficiency of H2S in the membrane module.

23

ACCEPTED MANUSCRIPT

Figure 14: Effect of temperature on 𝑪𝑶𝟐 and 𝑯𝟐𝑺 Removal. ; . 𝑽𝒈𝒂𝒔=10 𝒎𝒔 MEA Concentration =1000 𝒎𝒐𝒍𝒎

5.

‒𝟑

‒𝟏

;𝑽𝒍𝒊𝒒𝒖𝒊𝒅= 0.7 𝒎𝒔

‒𝟏

;

Conclusion

A mathematical finite element CFD model is developed in this work capable of modeling the gas removal using a membrane module. The model includes both fluid dynamics (Navier Stokes and mass transfer) and chemical reaction mechanism. A good agreement has been achieved between the modeling results and the measured data. Major outcome of this work can be described as below: 1- This work has proposed a new membrane structure based on addition of nanoparticles. This modified membrane structure has used nanoparticles with the aim of increasing the porosity of membrane and increasing the contact area leading to higher efficiencies for removal of CO2 and H2S. 2- Addition of up to 20%mass CaCO3 nanoparticles to the membrane can raise CO2 separation up to 9% and H2S separation up to 8% compared to the case where membrane contains no nanoparticle. 3- Modeling results show that the counter flow arrangement (gas flow in opposite direction of the absorbent) can give more than 3% more separation performance compared to parallel flow arrangement.

24

ACCEPTED MANUSCRIPT 4- The gas and fluid velocities have a high impact on separation efficiency. For example, increase in gas velocity from 5 m/s to 20 m/s leads to reduction in CO2 removal efficiency from 82% to 42% and H2S efficiency from 100% to 60%. 5- The increased concentration of MEA from 300 mol/m3 to an optimum 2000 mol/m3 also increased H2S separation efficiency from 77% to 85% and CO2 removal from 50% to 69%. However further increase in the MEA concentration above the optimum level would have minimal effects on the removal efficiency. 6- Elevated liquid absorbent velocity has a positive impact on the separation performance. Increased absorbent velocity from 0.5 m/s to 3 m/s increased H2S separation from 78% to 82% and CO2 separation from 66% to 72%. 7- The results show that the enhanced absorbent temperature improves the separation efficiency and removal of CO2 and H2S from the gaseous mixture.

6.

Symbols and Notations 𝐶𝑖

concentration of any species (𝑚𝑜𝑙𝑚

‒3

)

𝐶𝑖 ‒ 𝑠ℎ𝑒𝑙𝑙

concentration of any species in the shell (𝑚𝑜𝑙𝑚

𝐶𝑖 ‒ 𝑡𝑢𝑏𝑒

concentration of any species in the tube (𝑚𝑜𝑙𝑚

‒3

)

‒3

)

𝐶𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 concentration of any species in the membrane (𝑚𝑜𝑙𝑚 ‒ 3) 𝐶𝑀𝐸𝐴

initial MEA concentration in the liquid phase(𝑚𝑜𝑙𝑚

𝐶𝑖𝑛

volumetric gas flow rate in the shell inlet (𝑚 𝑠

𝐶𝑜𝑢𝑡

volumetric gas flow rate in the shell outlet (𝑚 𝑠

𝐷𝑖

‒3

)

3 ‒1

)

3 ‒1

)

2 ‒1

diffusion coefficient of any species (𝑚 𝑠

)

𝐷𝑖 ‒ 𝑠ℎ𝑒𝑙𝑙

diffusion coefficient of any species in the shell (𝑚 𝑠

𝐷𝑖 ‒ 𝑡𝑢𝑏𝑒

diffusion coefficient of any species in the tube (𝑚 𝑠

2 ‒1

2 ‒1

)

)

𝐷𝑖 ‒ 𝑚𝑒𝑚𝑏𝑟𝑎𝑛𝑒 diffusion coefficient of any species in the membrane (𝑚2𝑠 ‒ 1) 𝐷𝐶𝑂 ,𝑀𝐸𝐴 2

diffusivity of 𝐶𝑂2 in MEA solution (𝑚 𝑠

𝐷𝑁 𝑂,𝑀𝐸𝐴

diffusivity of 𝑁2𝑂 in MEA solution (𝑚 𝑠

𝐷𝐶𝑂 ,𝐻2𝑂

diffusivity correlations of 𝐶𝑂2 in water (𝑚 𝑠

𝐷𝑁 𝑂,𝐻2𝑂

diffusivity correlations of 𝑁2𝑂 in water (𝑚 𝑠

2

2

2

𝐻

2 ‒1

)

2 ‒1

)

2 ‒1

)

2 ‒1

3

Henry’s constant, 𝐾𝑃𝑎𝑑𝑚 𝑚𝑜𝑙

25

‒1

)

ACCEPTED MANUSCRIPT 𝐻𝐶𝑂 ,𝑀𝐸𝐴 2

Henry’s constant of 𝐶𝑂2 in MEA solution (𝐾𝑃𝑎𝑑𝑚 𝑚𝑜𝑙

𝐻𝑁 𝑂,𝑀𝐸𝐴

Henry’s constant of 𝑁2𝑂 in MEA solution (𝐾𝑃𝑎𝑑𝑚 𝑚𝑜𝑙

𝐻𝐶𝑂 ,𝐻2𝑂

Henry’s constant correlations of 𝐶𝑂2 in water (𝐾𝑃𝑎𝑑𝑚 𝑚𝑜𝑙

𝐻𝑁 𝑂,𝐻2𝑂

Henry’s constant correlations of 𝑁2𝑂 in water (𝐾𝑃𝑎𝑑𝑚 𝑚𝑜𝑙

2

2

2

𝐽𝑖 𝐾𝑒𝑞

diffusive flux of any species (𝑚𝑜𝑙𝑚

3

‒1

3

‒1

‒1

3

‒1

)

‒2 ‒1

)

𝑠

equilibrium constant for the 𝐻2𝑆 reaction with MEA rate constant for the reaction of 𝐶𝑂2 and MEA(𝑚 𝑚𝑜𝑙

𝑘𝐻 𝑆,𝑀𝐸𝐴

rate constant for the reaction of 𝐻2𝑆 and MEA (𝑚 𝑚𝑜𝑙

3

3

𝐿

length of the fiber (𝑚)

𝑚𝑖

gas solubility in the absorbent liquid (𝑚𝑜𝑙𝑚𝑜𝑙

𝑄𝑖𝑛

Gas flow rate at the inlet (𝑚 𝑠

𝑄𝑜𝑢𝑡

Gas flow rate at the outlet (𝑚 𝑠

3 ‒1

)

3 ‒1

)

𝑟

radial coordinate (𝑚)

𝑅1

inner tube radius (𝑚)

𝑅2

outer tube radius (m)

𝑅3

inner shell radius (m)

𝑅𝑖

reaction rate of any species (𝑚𝑜𝑙𝑠

𝑆

total surface area of the membrane (𝑚 )

𝑇

Temperature (𝐾)

𝑇𝑔

temperature of the gas (𝐾)

𝑢

average velocity in the shell side (𝑚𝑠

𝑣

average velocity in the tube side (𝑚𝑠

𝑉𝑧

Axial velocity in the module (𝑚𝑠

‒1

) 2

𝑉𝑧 ‒ 𝑠ℎ𝑒𝑙𝑙

axial velocity in the shell (𝑚𝑠

𝑉𝑧 ‒ 𝑡𝑢𝑏𝑒

axial velocity in the tube (𝑚𝑠

𝑧

)

3

𝑘𝑀𝐸𝐴 2

)

‒1

Greek letters ∅

void volume inside the module

𝜏

Tortuosity

𝜀

Porosity 26

)

‒1

Axial coordinate(𝑚)

‒1

)

)

‒1

‒1

)

)

‒1

)

‒1 ‒1

𝑆

)

‒1 ‒1

𝑆

)

)

ACCEPTED MANUSCRIPT

7.

References

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ACCEPTED MANUSCRIPT

H2S and CO2 Capture from Gaseous Fuels using Nanoparticle Membrane Hamed Abdolahi-Mansoorkhani a, Sadegh Seddighi a* a

Department of Mechanical Engineering, K. N. Toosi University of Technology, Tehran, Iran

* Corresponding emails: [email protected]

Highlights



Efficiency of separation increased by a new PVDF structure using CaCO3 nanoparticles



Maximum gas removal occurs in



Effects of operational conditions on gas removal efficiency are investigated.

𝐶𝑎𝐶𝑂3 𝑃𝑉𝐷𝐹

= 20%.