Hybrid Optimisation Model for the Synthesis of Centralised Utility System in Eco Industrial

Hybrid Optimisation Model for the Synthesis of Centralised utility system in Eco–Industrial Park

Kai Yuan Teoa, Tze Yee Nga, Cze Min Waua, Jason T. S. Liewa, Viknesh Andiappan b,*, Denny K. S. Nga

aDepartment of Chemical and Environmental Engineering/Centre of Sustainable Palm Oil Research (CESPOR), The University of Nottingham Malaysia, Broga Road, 43500 Semenyih, Selangor, Malaysia.

bEnergyand Environmetal Research Group, School of Engineering, Taylor’s University, Lakeside Campus, No. 1 Jalan Taylor’s, 47500 Subang Jaya, Selangor, Malaysia.

*

ASupporting Information Sheet

A.1.Material and Energy Balance

Resources i () is sent to potential technology j with flow rate .

/ / (A.1)

In technology j, resources i () is then converted to primary product p () with the mass conversion fraction of .

/ / (A.2)

The total production rate of primary product p is given as:

/ / (A.3)

Next, primary product p can be further process to produce end product p’ via potential technology j. The splitting constraint of primary product p is given as:

/ / (A.4)

The end product p’ () can be produced by converting primary product p with the mass conversion fraction of via the technology j’.

/ / (A.5)

Apart from material conversions, technologies j and j’ also generated energy e with the energy conversion fractions and respectively during the production of primary product p and end product p’. The total energy generated () by technologies j and j’

/ / (A.6)

Besides generating energy, some technologies in the CUS require energy to drive the process. Based on the energy consumption fractions, and for technologies j and j’ respectively, the total energy consumption () is determined via Equation (A.7).

/ / (A.7)

The energy demand from all participating IA () is then determined via Equation (A.8).

/ / (A.8)

A.2.Economic Analysis

The design capacities in the market for each equipment are usually available in discrete or nominal values (e.g., steam turbines, gas engines, etc.). Based on the work developed by Andiappan et al. (2015), CAPEX can be determined based on the design capacities of the selected technologies j and j’ to resemble the real life situation. The selection of the design capacities can be performed via Equations (A.9) and (A.10).

/ / (A.9)
/ / (A.10)

where and represent the design capacities available for purchase for technologies j and j’ respectively. Moreover, zjn and zj’n’ are positive integers which represent the number of units of design capacity n and n’ respectively. Note that these design capacities can be revised according to current market availability in order to produce an up–to–date economic analysis.

Based on the number of units (zjn and zj’n’), design capacities (and ) and selected technologies (j and j’), CAPEX of CUS can be determined via Equation (A.11).

/ / (A.11)

The total capital cost is then annualised by introducing CRF. CRF converts the present value of each unit into a stream of equal annual payments over a specified operation lifespan, and discount rate r. This can be calculated via Equation (A.12).

/ / (A.12)

Aside from CAPEX, Equation (A.13) is included in the model to determine general expenses of each technology j and j’ which includes start–up, maintenance, manpower, installation, etc.

/ (A.13)

where and are the operating cost of technologies j and j’, respectively.

A.3.Costing

Table A.1Price of non–seasonal raw materials and products.

Item / Price (USD)
Non–seasonal raw materials
Natural gas
Coal
Water
Electricity (Import) / 30.40/t
58.70/t
0.018/t
140/MWh
Products
High pressure (HP) steam
Medium pressure (MP) steam
Low pressure (LP) steam
Cooling Water
Chilled Water
Compost
Electricity (Export) / 26/t
17/t
12/t
0.090/t
0.62/t
100/t
90/MWh

Table A.2Operating cost of each technology (Ng and Ng, 2013).

Description / Price
Demineraliser / USD 12.5/(t/hr demineralised water)
Cooling tower / USD 1.00/(t/h Cooling water produced)
Boiler and direct drive steam turbine / USD 20.00/(1 MW electricity)
Boiler and mechanical drive steam turbine / USD 15.00/(1 MW electricity)
HRSG and gas turbine / USD 30.00/(1 MW electricity)
Digester and gas engine / USD 105.00/(1 MW electricity)
Mechanical chiller / USD 18.00/(t/hr Chilled water produced)
Absorption chiller / USD 11.00/(t/hr Chilled water produced)
POME treatment in pond system / USD 25.00/(50 t/hr POME)
Compost production / USD 55.00/(1 t/hr compost)

Table A.3Capital costs for each technology based on available design capacity (Andiappan et al., 2015).

Technology / Unit / Design capacity (Unit) / Capital Cost (USD)
Cooling tower / kg/hr / 90,000
108,000
180,000 / 15,532
17,762
25,867
Water tube boiler / kg/hr / 144,000
252,000
302,400 / 2,211,185
3,353,655
3,841,076
Biomass boiler / kg/hr / 144,000
252,000
302,400 / 2,211,185
3,353,655
3,841,076
Mechanical–Drive Medium Pressure Steam Turbine / kW / 200
250
500 / 82,180
90,549
122,380
Mechanical–Drive High Pressure Steam Turbine / kW / 250
500
1000 / 90,549
122,380
165,401
Direct–Drive Medium Pressure Steam Turbine / kW / 50
75
100 / 20,545
30,818
41,090
Direct–Drive High Pressure Steam Turbine / kW / 75
100
150 / 30,818
41,090
61,635
Gas turbine / kW / 250
500
1000 / 117,451
179,647
274,778
Gas engine / kW / 315
400 / 77,077
93,828
Heat recovery steam generator / kg/hr / 43,200
144,000 / 902,498
2,211,185
Fire tube boiler / kg/hr / 21,600
36,000
43,200 / 538,753
787,974
902,498
Mechanical chiller / kW / 250
300
350 / 42,518
48,926
55,092
Absorption chiller / kW / 250
300
350 / 133,365
139,053
144,742
PSA / kg/hr / 100
200
500 / 309,321
618,642
1,546,605
Amine scrubber / kg/hr / 200
500
700 / 904,784
2,261,960
3,166,744
Membrane separator / kg/hr / 70
100
180 / 194,877
278,395
501,111
Physical scrubber / kg/hr / 100
250
500 / 889,250
2,223,125
4,446,250
Demineraliser / Based on available flow / 2.6/(kg/hr water)
Compost production / Based on available flow / 800/(kg/hr compost)
Anaerobic digester / Based on available flow / 11.9/(kg/hr POME)

A.4.Conversion Factors

Technology
j and j’ / Conversion / Inlet / Product/
By–Product
Cooling Tower / Air required = 20.1 kg/kWh
Cooling load = 42 kJ/kg Water / Hot water (40oC)
Air / Cool water (30oC)
Demineraliser / Efficiency = 75% / Water / Demineralised water
Mechanical Chiller / COP (Hondeman, 2000) = 6.1 Output kW/Input kW
Cooling Water (AHRI, 2000) = 7.247 kg/kWh
Chilled Water (AHRI, 2000) = 0.00722 kg/kWh / Cool water (30oC)
Electricity / Chilled water (7oC)
Absorption Chiller / COP (CIBSE, 2012) = 0.7 Output kW/Input kW
Flue gas enthalpya = 799.12 kJ/kg
Cooling Water (AHRI, 2000) = 7.247 kg/kWh
Chilled Water (AHRI, 2000) = 0.00722 kg/kWh / Cool water (30oC)
Flue gas (600oC) / Chilled water (7oC)
Flue gas (30oC)
Biomass Boiler / Moisture content of inlet biomass = 40%
Efficiency = 50%
Steam enthalpy (30 bar, 360oC) (Rogers and Mayhew, 1995) = 3139.0 kJ/kg
Water enthalpy (1 bar, 30oC) (Rogers and Mayhew, 1995) = 125.8 kJ/kg
Heating value (EFB) (Nasrin et al., 2008) = 18838 kJ/kg
Heating value (PMF) (Nasrin et al., 2008) = 19068 kJ/kg
Heating value (PKS) (Nasrin et al., 2008) = 20108 kJ/kg / Water (30oC)
Palm biomass
Air / HPS (30 bar, 360oC)
Flue gas
Water Tube Boiler / Efficiency = 75%
Steam enthalpy (30 bar, 360oC) (Rogers and Mayhew, 1995) = 3139.0 kJ/kg
Water enthalpy (1 bar, 30oC) (Rogers and Mayhew, 1995)= 125.8 kJ/kg
Heating value (Anthracite coal) (Singh, 2010) = 35600 kJ/kg / Water (30oC)
Anthracite coal
Air / HPS (30 bar, 360oC)
Flue gas
Gas Turbine / Efficiency = 35%
Heating value (Natural gas) (Chandra, 2006)= 56900 kJ/kg
Heating value (Bio–methane) (Bonomi et al., 2015) = 22000 kJ/kg / Natural gas
Bio–methane
Air / Flue gas
Electricity
Gas Engine / Efficiency = 45%
Heating value (Natural gas) (Chandra, 2006)= 56900 kJ/kg
Heating value (Bio–methane) (Bonomi et al., 2015) = 22000 kJ/kg / Natural gas
Bio–methane
Air / Flue gas
Electricity
Fire Tube Boiler / Efficiency = 85%
Heating value (Natural gas) (Chandra, 2006)= 56900 kJ/kg
Heating value (Bio–methane) (Bonomi et al., 2015) = 22000 kJ/kg
Steam enthalpy (20 bar, 280oC) (Rogers and Mayhew, 1995) = 2976.0 kJ/kg
Water enthalpy (1 bar, 30oC) (Rogers and Mayhew, 1995)= 125.8 kJ/kg / Water (30oC)
Natural gas
Bio–methane
Air / MPS (20 bar, 280oC)
Flue gas
Heat Recovery Steam Generator / Efficiency = 35%
Flue gas enthalpya = 2076.29 kJ/kg
Steam enthalpy (30 bar, 360oC) (Rogers and Mayhew, 1995) = 2858.0 kJ/kg
Water enthalpy (1 bar, 30oC) (Rogers and Mayhew, 1995)= 125.8 kJ/kg / Water (30oC)
Flue gas / HPS (30 bar, 360oC)
Flue gas
Mechanical–Drive Medium Pressure Steam Turbine / Steam enthalpy (30 bar, 360oC) (Rogers and Mayhew, 1995) = 2858.0 kJ/kg
Steam enthalpy (20 bar, 280oC) (Rogers and Mayhew, 1995) = 2976.0 kJ/kg
Efficiency = 80% / MPS (20 bar, 280oC) / LPS (2 bar, 150oC)
Electricity
Mechanical–Drive High Pressure Steam Turbine / Steam enthalpy (20 bar, 280oC) (Rogers and Mayhew, 1995) = 2976.0 kJ/kg
Steam enthalpy (2 bar, 150oC) (Rogers and Mayhew, 1995) =2768.7 kJ/kg
Efficiency = 80% / HPS (30 bar, 360oC) / MPS (20 bar, 280oC)
Electricity
Direct–Drive Medium Pressure Steam Turbine / Steam enthalpy (30 bar, 360oC) (Rogers and Mayhew, 1995) = 2858.0 kJ/kg
Steam enthalpy (20 bar, 280oC) (Rogers and Mayhew, 1995) = 2976.0 kJ/kg
Efficiency = 43% / MPS (20 bar, 280oC) / LPS (2 bar, 150oC)
Electricity
Direct–Drive High Pressure Steam Turbine / Steam enthalpy (20 bar, 280oC) (Rogers and Mayhew, 1995) = 2976.0 kJ/kg
Steam enthalpy (2 bar, 150oC) (Rogers and Mayhew, 1995) =2768.7 kJ/kg
Efficiency = 43% / HPS (30 bar, 360oC) / MPS (20 bar, 280oC)
Electricity
Anaerobic Digester / COD in POME (Salmiati et al., 2007) = 0.062 kg/kg POME
Bio–methane production rate (Chin et al., 2013) = 0.25 kg/kg COD
CO2 production rate (Chin et al., 2013) = 0.13 kg/kg COD
H2S production rate (Chin et al., 2013) = 0.0006 kg/kg COD
Anaerobic sludge (Chin et al., 2013) = 0.06 kg/kg POME / POME / Bio–methane
CO2
H2S
Anaerobic sludge
Pressure Swing Adsorption / Purification rate of bio–methane (Bauer et al., 2013) = 0.98 kg/kg raw bio–methane
Removal rate of CO2 (Bauer et al., 2013) = 0.99 kg/kg raw CO2
Removal rate of H2S (Bauer et al., 2013) = 0.99 kg/kg raw CO2
Power required (Bauer et al., 2013) = 0.46 kWh/kg biogas / Biogas
Electricity / Bio–methane
CO2
H2S
Amine Scrubber / Purification rate of bio–methane (Bauer et al., 2013) = 0.99 kg/kg raw bio–methane
Removal rate of CO2(Bauer et al., 2013) = 0.99 kg/kg raw CO2
Removal rate of H2S (Bauer et al., 2013) = 0.99 kg/kg raw CO2
Power required (Bauer et al., 2013) = 0.27 kWh/kg biogas / Biogas
Electricity / Bio–methane
CO2
H2S
Membrane Separation / Purification rate of bio–methane (Bauer et al., 2013) = 0.80 kg/kg raw bio–methane
Removal rate of CO2(Bauer et al., 2013) = 0.98 kg/kg raw CO2
Removal rate of H2S (Bauer et al., 2013) = 0.99 kg/kg raw CO2
Power required (Bauer et al., 2013) = 0.25 kWh/kg biogas / Biogas
Electricity / Bio–methane
CO2
H2S
Water Scrubber / Purification rate of bio–methane (Bauer et al., 2013) = 0.98 kg/kg raw bio–methane
Removal rate of CO2(Bauer et al., 2013) = 0.98 kg/kg raw CO2
Removal rate of H2S (Bauer et al., 2013) = 0.99 kg/kg raw CO2
Power required (Bauer et al., 2013) = 0.46 kWh/kg biogas / Biogas
Electricity / Bio–methane
CO2
H2S
Co–Composting / Moisture content in final matured compost (Samsu Baharuddin et al., 2010) = 51.8%
Compost production rate (Samsu Baharuddin et al., 2010) = 0.80 kg/kg anaerobic sludge
EFB consumption rate (Samsu Baharuddin et al., 2010) = 1.20 kg/kg compost / EFB
Anaerobic sludge / Compost

aBased on ASPEN HYSYS simulation.

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