# Simulation and Exergoeconomic Analysis of a Trigeneration System Based on Biofuels from Spent Coffee Grounds

^{1}

^{2}

^{3}

^{*}

## Abstract

**:**

## 1. Introduction

_{2}/CO/CO

_{2}ratios in order to optimize the process.

_{2}emissions in the CCHP system decreased by 2.95% compared to the non-integrated system.

_{2}emission, 0.9021 t/MWh. They also identified that the first and second highest exergy destruction rates were found in a combustion chamber and gas turbine.

- The application of the exergoeconomic analysis to the heating, cooling, and power generation system of an instant coffee plant in operation.
- The evaluation of the economic and technical feasibility to replace the fossil fuels of a factory with its own agro-industrial waste.
- The analysis of the economic and exergetic effects of replacing a non-integrated system for the generation of heating, cooling, and power with a trigeneration system in the instant coffee plant in operation.

## 2. Materials and Methods

#### 2.1. Conventional System Description

#### 2.2. CCHP System Description

#### 2.3. Process Simulation

^{2}and the heat transfer coefficient was 850 Js

^{−1}m

^{−2}K

^{−1}. The conditions of the absorber A-101, such as the temperature, pressure, and lithium bromide concentration, were taken from Somers et al. [28].

#### 2.4. Model Validation

#### 2.5. Exergetic Analysis

#### 2.6. Economic Analysis

^{3}[43] and $0.0756/kWh [44]. The cost of syngas and the biomass from SCGs were obtained from a previous study by the authors [45]. The fuel oil No. 6, lithium bromide, and ammonia costs were $0.257/kg, $0.30/kg, and $0.60/kg, respectively, which were obtained directly from different suppliers.

#### 2.7. Exergoeconomic Analysis

## 3. Results and Discussion

#### 3.1. Model Validation

_{2}and O

_{2}concentration of flue gases of the combustion chamber (CC-101), the outlet mass flow rate and temperature of flue gases, the thermal efficiency of the steam generator (HX-101), and the outlet temperature and LiBr concentration of the absorber are presented and compared.

#### 3.2. Exergetic Analysis

_{2}and SO

_{2}emissions are reported in Figure 4b. The results were obtained from the simulation of the combustion process. It is observed that the base case has the highest CO

_{2}and SO

_{2}emissions, while the systems based on biofuels have reduced CO

_{2}emissions by 61.1% and SO

_{2}emissions by 85%. These findings are in line with previous studies where high values of greenhouse gas emissions were observed when using fossil fuels in a CCHP system [49].

#### 3.3. Exergoeconomic Analysis

## 4. Conclusions

- The overall exergetic efficiency of the conventional system is 51.9% and the total exergy destruction rate is 8.5 MJ/s. Over 59.2% of the total exergy destruction rate in the conventional system occurs in the steam generator. The CCHP systems increased exergetic efficiency between 62.6% and 84.5%, and reduced the exergy destruction rate between 1.66 MJ/s and 6.81 MJ/s.
- The exergy destruction cost rate of the conventional system ($660.8/h) represents 78.5% of the total cost rate of the plant. Among all components, the condenser has the highest exergy destruction cost rate ($412.2 /h). By contrast, the CCHP system based on biomass obtained the lowest overall exergy destruction cost rate ($75.4/h).
- Furthermore, the CO
_{2}and SO_{2}emissions of the conventional system are 23,283 and 1.8 tons per year, respectively. However, the CCHP reduced the CO_{2}and SO_{2}emissions by 65.1% and 93.5%, respectively. - Compared with the conventional non-integrated system for the generation of steam, chilled water, and power, the results show that the proposed trigeneration system based on syngas and biomass-fueled GT cycle is more advantageous in terms of the exergy efficiency, the CO
_{2}and SO_{2}emissions, and the cost of services. - In addition, out of the four fuels screened through the trigeneration systems, biomass is considered economically feasible due to its lower investment and operating costs ($2.49 million and $8.04/h, respectively).
- Using biomass as fuel instead of syngas in the trigeneration system reduces the steam, chilled water, and power costs by around 37.8%, 21.5%, and 22.1%, respectively.

## Author Contributions

## Funding

## Data Availability Statement

## Conflicts of Interest

## Nomenclature

Symbol | |

A | ash mass fraction on a dry basis |

C | carbon mass fraction on a dry basis |

$\dot{\mathrm{C}}$ | the cost associated with an exergy stream ($/h) |

${\mathrm{C}}_{\mathrm{p}}$ | specific heat at constant pressure (kJ/kg-K) |

c | unit exergy cost ($/kJ) |

$\dot{\mathrm{E}}$ | exergy rate (kW) |

e | specific exergy rate (kJ/kg) |

$\overline{\mathrm{HHV}}$ | higher heating value (mol/kJ) |

H | hydrogen mass fraction on a dry basis |

h | specific enthalpy (kJ/kg) |

$\dot{\mathrm{m}}$ | mass flowrate (kg/s) |

N | nitrogen mass fraction on a dry basis |

n | lifetime of the system (years) |

O | oxygen mass fraction on a dry basis |

P | pressure (kPa) |

$\dot{\mathrm{Q}}$ | rate of heat (W) |

R | ideal gas constant (kJ/kmol-K) |

S | sulfur mass fraction on a dry basis |

s | specific entropy (kJ/kg-K) |

T | temperature (K) |

$\mathrm{v}$ | stochiometric coefficient |

$\dot{\mathrm{W}}$ | power (kW) |

x | mole fraction |

$\dot{\mathrm{Z}}$ | investment cost rate ($/h) |

Greek letters | |

$\mathsf{\eta}$ | exergetic efficiency (%) |

Δ | difference |

Superscript | |

CI | investment cost |

CH | chemical |

O&M | operation and maintenance |

PH | physical |

Subscript | |

cs | cold stream |

D | destroyed |

EP | electric power |

F | fuel |

hs | hot stream |

i | ith compound |

k | kth component |

L | loss |

P | product |

Abbreviations | |

A | absorber |

CCHP | combined cooling, heating, and power |

CC | combustion chamber |

C | compressor |

ELECNRTL | electrolyte NRTL |

FS | flash separator |

GT | gas turbine |

HX | heat exchanger |

GN | natural gas |

MX | mixer |

O&M | operation and maintenance |

PFI | plant–facilities investment |

P | pump |

PEC | purchase equipment cost |

SCGs | spent coffee grounds |

ST | splitter |

SG | syngas |

T | turbine |

V | valve |

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**Figure 3.**Comparisons of (

**a**) the exergy destruction rate and (

**b**) the exergy efficiency of the base case and the CCHP using different fuels.

**Figure 4.**Comparison of (

**a**) exergy destruction rate at a level component and (

**b**) CO

_{2}and SO

_{2}emissions from the CCHP system based on different fuels.

**Figure 5.**Comparison of (

**a**) Total investment cost of the plant and (

**b**) Exergy destruction, investment, and O&M cost rates of the CCHP system based on different fuels.

**Figure 6.**Exergy destruction cost rate of the CCHP system at a component level based on: (

**a**) Fuel oil No. 6, (

**b**) Natural gas, (

**c**) Biomass, (

**d**) Syngas, and (

**e**) Base case.

Scenario | Fuel | LHV (MJ/kg) |
---|---|---|

1 | Fuel oil No.6 | 44.9 [17] |

2 | Natural gas | 39.3 [18] |

3 | Biomass | 23.4 [19] |

4 | Syngas | 13.0 [20] |

Component | ${\dot{\mathbf{E}}}_{\mathbf{F}}$ | ${\dot{\mathbf{E}}}_{\mathbf{P}}$ |
---|---|---|

Pump (P-101) | ${\dot{\mathrm{W}}}_{\mathrm{P}-101}$ | ${\dot{\mathrm{E}}}_{2}-{\dot{\mathrm{E}}}_{1}$ |

Compressor (C-101) | ${\dot{\mathrm{W}}}_{\mathrm{C}-101}$ | ${\dot{\mathrm{E}}}_{4}-{\dot{\mathrm{E}}}_{3}$ |

Combustion chamber (CC-101) | ${\dot{\mathrm{E}}}_{2}+{\dot{\mathrm{E}}}_{4}$ | ${\dot{\mathrm{E}}}_{5}$ |

Turbine (T-101) | ${\dot{\mathrm{E}}}_{5}-{\dot{\mathrm{E}}}_{6}$ | ${\dot{\mathrm{W}}}_{\mathrm{T}-101}$ |

Steam generator (HX-101) | ${\dot{\mathrm{E}}}_{6}-{\dot{\mathrm{E}}}_{7}$ | ${\dot{\mathrm{E}}}_{9}-{\dot{\mathrm{E}}}_{8}$ |

Generator (HX-102) | ${\dot{\mathrm{E}}}_{7}-{\dot{\mathrm{E}}}_{10}$ | $({\dot{\mathrm{E}}}_{17}$ +${\dot{\mathrm{E}}}_{11})-$ ${\dot{\mathrm{E}}}_{16}$ |

Heat exchanger (HX-103) | ${\dot{\mathrm{E}}}_{11}-{\dot{\mathrm{E}}}_{12}$ | ${\dot{\mathrm{E}}}_{16}-{\dot{\mathrm{E}}}_{15}$ |

Condenser (HX-104) | ${\dot{\mathrm{E}}}_{17}-{\dot{\mathrm{E}}}_{20}$ | ${\dot{\mathrm{E}}}_{19}-{\dot{\mathrm{E}}}_{18}$ |

Evaporator (HX-105) | ${\dot{\mathrm{E}}}_{21}-{\dot{\mathrm{E}}}_{24}$ | ${\dot{\mathrm{E}}}_{23}-{\dot{\mathrm{E}}}_{22}$ |

Pump (P-102) | ${\dot{\mathrm{W}}}_{\mathrm{P}-102}$ | ${\dot{\mathrm{E}}}_{15}-{\dot{\mathrm{E}}}_{14}$ |

Absorber (A-101) | $({\dot{\mathrm{E}}}_{26}-{\dot{\mathrm{E}}}_{25})+{\dot{\mathrm{E}}}_{24}$ | ${\dot{\mathrm{E}}}_{13}-{\dot{\mathrm{E}}}_{14}$ |

Components | A | b | n | S |
---|---|---|---|---|

Evaporators | 330 | 36,000 | 0.55 | 0.36 (m^{2}) |

Pumps | 8000 | 240 | 0.9 | 2.22 (L/s) |

Heat exchangers | 28,000 | 54 | 1.2 | 3.15 (m^{2}) |

PEC Equation | Year | CEPCI | Equation No. |
---|---|---|---|

log_{10}(PEC_{T−101}) = 2.2476 + 1.4965 · log_{10}(A_{i}) − 0.1618 · [log_{10}(A_{i})]^{2} | 2001 | 397 | (10) |

${\mathrm{PEC}}_{\mathrm{c}-101}=\left(\frac{71.1\xb7\dot{\mathrm{m}}}{0.9-{\mathsf{\eta}}_{\mathrm{isen}.\mathrm{eff}}}\right)\left(\frac{{\mathrm{P}}_{\mathrm{out}}}{{\mathrm{P}}_{\mathrm{in}}}\right)\mathrm{ln}\left(\frac{{\mathrm{P}}_{\mathrm{out}}}{{\mathrm{P}}_{\mathrm{in}}}\right)$ | 1982 | 315 | (11) |

${\mathrm{PEC}}_{\mathrm{CC}-101}=\frac{28.98\xb7{\dot{\mathrm{m}}}_{\mathrm{air}}}{0.995\left(\frac{{\mathrm{P}}_{\mathrm{out}}}{{\mathrm{P}}_{\mathrm{in}}}\right)}\xb7\left(1+{\mathrm{e}}^{\left(0.015\left({\mathrm{T}}_{\mathrm{out}}-1540\right)\right)}\right)$ | 2003 | 402 | (12) |

${\mathrm{PEC}}_{\mathrm{HX}-104}=281\xb7\frac{{\dot{\mathrm{Q}}}_{\mathrm{HX}-104}}{2200\left[\frac{\left({\mathrm{T}}_{\mathrm{in},\mathrm{hs}.}-{\mathrm{T}}_{\mathrm{out},\mathrm{cs}.}\right)-\left({\mathrm{T}}_{\mathrm{out},\mathrm{hs}.}-{\mathrm{T}}_{\mathrm{in},\mathrm{cs}.}\right)}{\mathrm{ln}\left(\frac{{\mathrm{T}}_{\mathrm{in},\mathrm{hs}.}-{\mathrm{T}}_{\mathrm{out},\mathrm{cs}.}}{{\mathrm{T}}_{\mathrm{out},\mathrm{hs}.}-{\mathrm{T}}_{\mathrm{in},\mathrm{cs}.}}\right)}\right]}+746\xb7{\dot{\mathrm{m}}}_{\mathrm{out}}$ | 1982 | 315 | (13) |

Component | Fuel Cost |
---|---|

Average general inflation rate | 0.05 |

Average nominal escalation rate of all costs | 0.05 |

Average nominal escalation rate of fuel costs | 0.06 |

Plant economic life in years (n) | 20 |

Plant life for tax purposes in years | 15 |

Combined average income tax rate | 0.38 |

Average property tax rate (%PFI) | 0.015 |

Average insurance rate (%PFI) | 0.5 |

Average capacity factor | 0.85 |

Labor positions for O&M | 20 |

Average labor cost ($/h) | 18 |

Component | Fuel Cost | Product Cost | Auxiliary Equations |
---|---|---|---|

Pump (P-101) | ${\dot{\mathrm{W}}}_{\mathrm{P}\text{-}101}\xb7{\mathrm{C}}_{\mathrm{ep}}$ | ${\dot{\mathrm{C}}}_{2}-{\dot{\mathrm{C}}}_{1}$ | - |

Compressor (C-101) | ${\dot{\mathrm{W}}}_{\mathrm{C}\text{-}101}\xb7{\mathrm{C}}_{\mathrm{ep}}$ | ${\dot{\mathrm{C}}}_{4}-{\dot{\mathrm{C}}}_{3}$ | - |

Combustion chamber (CC-101) | ${\dot{\mathrm{C}}}_{2}+{\dot{\mathrm{C}}}_{4}$ | ${\dot{\mathrm{C}}}_{5}$ | - |

Turbine (T-101) | ${\dot{\mathrm{C}}}_{5}-{\dot{\mathrm{C}}}_{6}$ | ${\dot{\mathrm{W}}}_{\mathrm{T}-101}\xb7{\mathrm{c}}_{\mathrm{ep}}$ | - |

Steam generator (HX-101) | ${\mathrm{C}}_{6}-{\dot{\mathrm{C}}}_{7}$ | ${\dot{\mathrm{C}}}_{9}-{\dot{\mathrm{C}}}_{8}$ | ${\mathrm{c}}_{6}={\mathrm{c}}_{7}$ |

Generator (HX-102) | ${\dot{\mathrm{C}}}_{7}-{\dot{\mathrm{C}}}_{10}$ | ${\dot{(\mathrm{C}}}_{17}$ + ${\dot{\mathrm{C}}}_{11})-{\dot{\mathrm{C}}}_{16}$ | ${\mathrm{c}}_{7}={\mathrm{c}}_{10}$ |

Heat exchanger (HX-103) | ${\dot{\mathrm{C}}}_{11}-{\dot{\mathrm{C}}}_{12}$ | ${\dot{\mathrm{C}}}_{16}-{\dot{\mathrm{C}}}_{15}$ | ${\mathrm{c}}_{11}={\mathrm{c}}_{12}$ |

Condenser (HX-104) | ${\dot{\mathrm{C}}}_{17}-{\dot{\mathrm{C}}}_{20}$ | ${\dot{\mathrm{C}}}_{19}-{\dot{\mathrm{C}}}_{18}$ | ${\mathrm{c}}_{18}={\mathrm{c}}_{19}$ |

Evaporator (HX-105) | ${\dot{\mathrm{C}}}_{21}-{\dot{\mathrm{C}}}_{24}$ | ${\dot{\mathrm{C}}}_{23}-{\dot{\mathrm{C}}}_{22}$ | ${\mathrm{c}}_{21}={\mathrm{c}}_{24}$ |

Pump (P-102) | ${\dot{\mathrm{W}}}_{\mathrm{P}\text{-}102}\xb7{\mathrm{C}}_{\mathrm{ep}}$ | ${\dot{\mathrm{C}}}_{15}-{\dot{\mathrm{C}}}_{14}$ | - |

Absorber (A-101) | $({\dot{\mathrm{C}}}_{26}-{\dot{\mathrm{C}}}_{25})+{\dot{\mathrm{C}}}_{24}$ | ${\dot{\mathrm{C}}}_{13}-{\dot{\mathrm{C}}}_{14}$ | ${\mathrm{c}}_{25}={\mathrm{c}}_{26}$ |

Fuel | Component | Parameter | This Work | Literature | Relative Error (%) |
---|---|---|---|---|---|

Natural Gas | CC-101 | Outlet temperature of flue gases (°C) | 2252 | 2248 [27] | 0.18 |

CO_{2} (%mol) | 8.7 | 8.5 [27] | 2.35 | ||

Mass flow rate of flue gases (kg/s) | 1.85 | 1.90 [27] | 2.63 | ||

HX-101 | Outlet temperature of flue gases (°C) | 774.7 | 770 [27] | 0.61 | |

Thermal efficiency (%) | 89.0 | 94 | 5.3 | ||

Fuel oil No.6 | CC-101 | Outlet temperature of flue gases (°C) | 2338 | 2340 [24] | 0.08 |

CO_{2} (%mol) | 13 | 12 [24] | 8.30 | ||

Mass flow rate of flue gases (kg/s) | 1.82 | 2.01 [24] | 9.45 | ||

HX-101 | Outlet temperature of flue gases (°C) | 775.7 | 780 [24] | 0.55 | |

Thermal efficiency (%) | 81.8 | 93 | 12.0 | ||

Syngas | CC-101 | Outlet temperature of flue gases (°C) | 1987 | 1985 [23] | 0.10 |

CO_{2} (%mol) | 16.4 | 13 [23] | 20.7 | ||

Mass flow rate of flue gases (kg/s) | 2.11 | 1.47 [23] | 30.3 | ||

HX-101 | Outlet temperature of flue gases (°C) | 645 | 649.5 [23] | 0.69 | |

Thermal efficiency (%) | 94.4 | 95 | 0.6 | ||

Biomass | CC-101 | Outlet temperature of flue gases (°C) | 1908 | 1910 [21] | 0.10 |

CO_{2} (%mol) | 9.2 | 10.5 [21] | 12.4 | ||

Mass flow rate of flue gases (kg/s) | 2.17 | 1.5 [21] | 30.8 | ||

HX-101 | Outlet temperature of flue gases (°C) | 508.6 | 512 [21] | 0.66 | |

Thermal efficiency (%) | 91.1 | 95 | 4.1 | ||

- | A-101 | Outlet temperature (°C) | 32.7 | 32.7 [28] | 0 |

Outlet LiBr concentration (%) | 0.574 | 0.574 [28] | 0 |

Fuel | Steam Cost ($/GJ) | Chilled Water Cost ($/GJ) | Power Cost ($/GJ) |
---|---|---|---|

Base case | 24.60 | 30.20 | 89.92 |

Fuel oil No.6 | 17.97 | 40.35 | 29.41 |

Natural gas | 11.75 | 22.30 | 24.40 |

Syngas | 16.49 | 25.77 | 30.07 |

Biomass | 10.26 | 20.22 | 23.43 |

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## Share and Cite

**MDPI and ACS Style**

Tinoco Caicedo, D.L.; Santos Torres, M.; Mero-Benavides, M.; Patiño Lopez, O.; Lozano Medina, A.; Blanco Marigorta, A.M.
Simulation and Exergoeconomic Analysis of a Trigeneration System Based on Biofuels from Spent Coffee Grounds. *Energies* **2023**, *16*, 1816.
https://doi.org/10.3390/en16041816

**AMA Style**

Tinoco Caicedo DL, Santos Torres M, Mero-Benavides M, Patiño Lopez O, Lozano Medina A, Blanco Marigorta AM.
Simulation and Exergoeconomic Analysis of a Trigeneration System Based on Biofuels from Spent Coffee Grounds. *Energies*. 2023; 16(4):1816.
https://doi.org/10.3390/en16041816

**Chicago/Turabian Style**

Tinoco Caicedo, Diana L., Myrian Santos Torres, Medelyne Mero-Benavides, Oscar Patiño Lopez, Alexis Lozano Medina, and Ana M. Blanco Marigorta.
2023. "Simulation and Exergoeconomic Analysis of a Trigeneration System Based on Biofuels from Spent Coffee Grounds" *Energies* 16, no. 4: 1816.
https://doi.org/10.3390/en16041816