optimisation of cogeneration systems – combined production of methanol …€¦ · ·...

Optimisation of cogeneration systems – combined production of methanol and electricity

C. Werner & H. L. Estrada Hummelt Technische Universität Berlin, Germany

Abstract

This paper discusses an example of cogeneration, viz. the combined production of methanol and electricity. In this regard technical and economic criteria of a typical MegaMethanol plant (capacity: 5000 metric tons per day) and a gas-steam power plant on natural gas basis (capacity: 750 MW) are presented. A mathematical simulation model summarises the specific criteria of both systems. Aim of this study is the optimisation of the combined production of methanol and electricity. A specific approach to optimise the exergy and/or cost efficiency is applied. Therefore, the energy supply design of the MegaMethanol plant is analysed and evaluated in terms of combined thermodynamic and economic as-pects. The significance of different dimensioning parameters of the energy supply design is demonstrated by means of sensitivity analyses. These sensitivity analyses categorise the power plant design parameters in relation to the potential to affect the methanol and electricity costs. Accordingly the energy supply de-sign of the MegaMethanol plant is modified successively in an iteration process. The optimisation results in a gas-steam power plant design characterised by increased exergy efficiency and decreased cost efficiency. Recommendations for advanced optimisation studies of cogeneration concepts are made. Keywords: cogeneration, methanol, electricity, thermoeconomics.

1 Introduction

Parameters like fuel, energy and capital costs as well as the methods of financing qualify the degree of the rational use of energy in industrial processes [1]. Due to the latest development of the fuel and energy costs the interest in primary energy saving concepts increased. An option to reduce the primary energy consumption

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is the application of cogeneration systems. This paper discusses an example of cogeneration, a combined MegaMethanol plant and a gas-steam power plant on natural gas basis. The energy supply design of the MegaMethanol plant is analysed and evaluated concerning thermodynamic and economic aspects. Ob-jective of the study is the optimisation of the exergy and cost efficiency.

2 State of the art

The following sections refer to the state of the art and the development trends of methanol plants and gas-steam power plants on natural gas basis.

2.1 Methanol production

The first synthetic methanol was produced in 1923. Since then, the methanol production processes were developed continuously. The latest improvements are related to the catalyst system and the reactor particularly. These improvements resulted in a robust higher efficiency operation under larger scale conditions [2]. The actual global methanol demand is estimated at 38.1 million metric tons per annum (basis: 2007) [3]. The methanol produced is mainly processed to formal-dehyde, methyl-tertiary-butyl aether and acetic acid. Further applications are sol-vents, petrol and other chemicals. 82% of the actual production capacity is based on natural gas technology. Coal based methanol units account for 15% of the installed capacity. Further portions are represented by fuel oil and stranded natural gas based methanol units [3]. These investigations exemplify the natural gas based technology: A Lurgi MegaMethanol plant with a capacity of 5000 metric tons per day. Sections 2.1.1 and 2.1.2 describe the technical and economic parameters of this Lurgi MegaMethanol plant.

2.1.1 Technical parameters The Lurgi MegaMethanol technology (Figure 1) is characterised by the following process features [4]: - oxygen-blown natural gas reforming combined with steam reforming or auto-

thermal reforming, respectively, - adjustment of synthesis gas composition by hydrogen recycle, - double-stage methanol synthesis in water- and gas-cooled reactors.

autothermal reforming

pre-reforming methanolsynthesis

methanol distillation

methanolsulphur removal

natural gas

hydrogenrecovery

air air separation unit

Figure 1: Lurgi MegaMethanol technology with autothermal reforming [4].

The desulfurised and pre-reformed feedstock is converted autothermally into synthesis gas. Oxygen and medium pressure steam are required and high pressure steam is produced within the autothermal reforming. The reforming unit

412 Energy and Sustainability II



includes a heat recovery system to superheat this high pressure steam and the medium pressure steam generated in the methanol synthesis process upstream. After superheating the steam could be used to generate power required internally. Hydrogen is added to the synthesis gas to achieve the required gas composition for the methanol synthesis in the dual reactor system. The purification of the crude methanol is realised in a three-column distillation unit [4]. The distillation process demands low pressure steam. The technical parameters of the non-steam-self-sustaining operation of this plant are summarised in Table 1.

Table 1: Technical parameters of the MegaMethanol plant.

(1) 310 t/h / 100 bar / 500 °C steam production (reforming) (2) 160 t/h / 40 bar / 380 °C steam production (synthesis) (3) 75 t/h / 47 bar / 400 °C steam requirement (reforming) (4) 135 t/h / 6 bar / 159 °C steam requirement (distillation) (5) 110 MW electric power requirement

Moreover the operation of the MegaMethanol plant requires 510 t/h potable water as well as 35000 t/h cooling water (∆T=10 K).

2.1.2 Economic parameters The following economic analysis of the MegaMethanol plant is based on the parameters related to [5] and the data in Table 6 (Appendix). The Total Revenue Requirement Method (TRR-Method) is used to evaluate the economics. The cost composition of the MegaMethanol plant investigated is given in Table 2. The credit for the steam produced in the MegaMethanol plant is calculated in depen-dence on the value of the electricity achievable by the steam.

Table 2: Cost composition of the MegaMethanol plant.

capital cost 33.2% operation and maintenance cost 27.5% fuel cost 54.1% credit steam production - 14.8%

2.2 Electricity production

Gas-steam power plants are available on the market up to 1000 MW electric power [6]. An electricity yield of actual gas-steam power plants on natural gas basis of up to 60% is realised [6]. A further improvement of the electricity yield is expected. Therefore the latest research and development in the field of the power plant technology considers material, cooling, construction, combustion and fluid mechanic aspects [7–8]. Sections 2.2.1 and 2.2.2 outline the technical and economic parameters of the gas-steam power plant Seabank/UK on natural gas basis, which are used for these investigations.




2.2.1 Technical parameters Since 2000 the gas-steam power plant Seabank/UK is applied to the electric base and mid-load supply [9]. This power plant achieves an electric power output of 756 MW and an electricity yield of 57.8%. The power plant structure is shown in Figure 6 (Appendix). This power plant structure is characterised by two gas turbine systems/heat recovery steam generators (HRSG) and one steam turbine system. The actual operation mode of the gas-steam power plant Seabank/UK is electricity-oriented without any admission or extraction of steam. The option to pre-heat the natural gas of the gas turbine system is available according to Figure A.1 (Appendix). The unfired heat recovery steam generator includes three pressure stages and a single reheat. Table 3 illustrates the steam parameters at the entrance of the high, medium and low pressure steam turbines as well as the reheat steam parameters. The heat recovery steam generator is also used to pre-heat the condensate/feed water.

Table 3: Triple-pressure process and single reheat in Seabank/UK [9].

high pressure parameter 253.3 t/h / 110 bar / 550 °C medium pressure parameter 52.1 t/h / 30 bar / 320 °C low pressure parameter 36.2 t/h / 4.8 bar / 235 °C reheat parameter 247.6 t/h / 28.5 bar / 550 °C

2.2.2 Economic parameters The description of the economics of the power plant is based on cost equations according to [10–11] and the economic data in Table A.1 (Appendix). Table 4 documents the resulting cost composition of the gas-steam power plant calculated by the application of the TRR-Method.

Table 4: Cost composition of the gas-steam power plant.

capital cost 44.2% operation and maintenance cost 7.3% fuel cost 48.5%

2.3 Combination of the MegaMethanol plant and the gas-steam power plant

The combination of the MegaMethanol plant and the gas-steam power plant re-quires the transfer of energy and material between the subsystems according to Figure 2. Therefore the model of the gas-steam power plant discussed in section 2.2 has to be modified. For this purpose data of the KRAFTWERKSSCHULE E.V. [12] are used. Furthermore, the interfaces (1)-(5) to the MegaMethanol plant are added to realise the energy and material import/export between the subsystems (cp. Table 1 and Figure A.1 (Appendix)).




crudemethanolsyngas

steam

waterflue gasgas turbines steam turbines

reforming process

methanoldistillation

methanol synthesis

methanol

natural gas

power

high pressure steammedium pressure steam

HRSG

process steam low pressure steam

MegaMethanol plant

gas-steam power plant

air

air

flue gas

air separation unit hydrogen recovery

Figure 2: Cogeneration concept: MegaMethanol plant/gas-steam power plant.

3 Recent research

On the basis of thermoeconomics cost formation processes in a system are defin-able at component level, thermodynamic losses of components are valuable in terms of economic aspects and exergy based cost allocations for co- or trigeneration systems are feasible. Therefore, the results of the exergy analysis and the economic analysis are combined at component level according to eqn. (1): jjjjjj emcEcC ⋅⋅=⋅= (1) The cost balances of the component k (Figure 3) are presented in eqn. (2) and eqn. (3).

Figure 3: Balance of the component k [13].

component k

inkC ,,1

inkC ,,3

inknC ,,

inkC ,,2

OMk

CIkk ZZZ +=

1

3

outkC ,,2

outkC ,,1

outkC ,,3

2

1

3

outkmC ,, m n

2


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∑∑==

=++m

joutkj

OMk

CIk

n

jinkj CZZC

1,,

1,, (2)

( ) ( )∑∑==

⋅=++⋅m

joutkjj

OMk

CIk

n

jinkjj EcZZEc

1,

1,

(3)

The specific costs of the incoming streams n of the component k are commonly known from the investigation of downstream components or defined externally (e.g. fuel cost). A part of the cost balances is the exergy stream known from the exergy analysis. The cost balance of the component k considers the levelised capital cost (Figure 3 – superscript: CI) and the operation and maintenance cost (Figure 3 – superscript: OM) from the economic analysis (TRR-Method). To calculate the cost balances of the component k with m outcoming streams (m-1) auxiliary equations are required, cp. [13].

4 Simulations

The study of the MegaMethanol/gas-steam power plant concept requires the combination of the technical and economic parameters discussed. The investi-gations focus on the stationary nominal operation of both subsystems. The simu-lation software GateCycle is applied to describe the energy supply of the MegaMethanol plant. The software GATEX, MATLAB and Microsoft Excel is used for the thermoeconomic analysis.

5 Results

In the 0th iteration (base case cp. Table 5) an exergy efficiency of 54.84% is achieved by the gas-steam power plant combined with the MegaMethanol plant. The combined operation of the MegaMethanol plant and the gas-steam power plant results in methanol cost of 198.72 EUR/t and electricity cost of 3.67 ct/kWh. Figure 4 documents the correlation between the relative exergy destruct-tion and the relative specific cost of each component in the gas-steam power plant related to the 0th iteration. To improve the total exergy efficiency the optimisation approach according to [14] recommends an increase of the capital cost of components with medium-high relative exergy destruction values and low relative specific cost. This is ascertainable for the following components during the 0th iteration: combustion chamber, condenser, expander, compressor and low pressure steam turbine. The capital cost reduction of components with low relative exergy destruction values and medium-high relative specific cost is recommended to improve the total cost efficiency, respectively. The high pressure economiser and superheater, the low pressure evaporator, the pumps and the medium pressure steam turbine meet these criteria.




Each component is characterised by specific dimensioning parameters, which qualify the relative exergy destruction values and the relative specific cost. The following sensitivity analyses explain the significance of the efficiency of the combustion process affected by fuel pre-heat. The options to reduce the relative exergy destruction value by condenser pressure variations are exemplified. To specify the relative exergy destruction and the relative specific costs of the fluidic components (expander, compressor, low/medium pressure steam turbine and pumps) variations of the isentropic efficiency are presented. The interrela-tion of the minimal temperature difference of the high pressure economiser/ superheater as well as the low pressure evaporator and the relative specific cost of these components will be outlined. Figure 5 illustrates the sensitivity analyses of the MegaMethanol plant/gas-steam power plant concept using the examples of the methanol cost and electricity cost.

Figure 4: Relative exergy destruction vs. relative specific cost of the gas-steam power plant components (0th iteration – base case).

The variation of the component parameters in the range of ± 5% is less signi-ficant to the methanol cost compared to the electricity cost (Figure 5). The sensitivity analyses document the substantial influence of the gas turbine compo-nents expander (EX1/EX2) and compressor (C1/C2) to the production costs. The following iterative optimisation aims to increase the exergy efficiency of the energy supply of the MegaMethanol plant and the total cost efficiency. Table 5 summarises the multiple parameter variations of the components in the iterations 0-5. The iterations 1-3 consider the components with medium-high relative exergy destruction values and low relative specific cost to improve the exergy efficiency of the gas-steam power plant. The iterations 4-5 focus on the

0.00

2.75

5.50

8.25

0 2 4 6ED/ΣED in %

(Zk/E

D)/ Σ

(Zk/E

D) i

n %

mediumlow high

low

med

ium

high

combustion chamber CMB1/CMB2

condenser CND1

expander EX1/EX2

compressor C1/C2

low pressuresteam turbineST3

high pressure superheater HPSHT3/HPSHT23

high pressure economiser HPECO2/HPEC22

low/medium pressure pump PUMP 2/3

low pressure evaporator LPEVA/LPEVA2

high pressure pump PUMP 1

medium pressuresteam turbine

ST2

.

.




components with low relative exergy destruction values and medium-high relative specific cost to improve the total cost efficiency. Components charac-terised by low relative exergy destruction values and low relative specific cost remain constant in the iteration process (cp. Figure 4). The results of these parameter variations presented in Table 5 are related to the 0th iteration.

Figure 5: Sensitivity analyses MegaMethanol plant/gas-steam power plant.

The trend to increased exergy efficiency of the gas-steam power plant and increased electricity costs realised by advanced fuel pre-heat and decreased con-denser pressure is verified in Table 5 (iterations 1-2). Increasing isentropic effi-ciencies of the expander, compressor and low pressure steam turbine cause an in-crease of the exergy efficiency of the power plant and an increase of the methanol/electricity costs (iteration 3). An increasing minimal temperature difference of the high pressure economiser/superheater and the low pressure evaporator tend to result in decreased exergy efficiency along with decreased methanol/electricity costs compared to iteration 3. The further decrease of the exergy efficiency of the gas-steam power plant is ascertainable by trend due to the reduction of the isentropic efficiencies of the pumps and the medium pressure steam turbine. The resulting methanol/electricity costs in iteration 5 do not differ from iteration 4. After the 5th iteration of the multiple criteria opti-misation the exergy efficiency of the gas-steam power plant increased to 1.8% compared to the 0th iteration (base case). The production costs are increased to 0.2% (methanol) and 1.6% (electricity). The increased production costs caused by the modifications to increase the exergy efficiency in the iterations 1-3 can not be compensated by the modifications to improve the total cost efficiency in the iterations 4-5. In the scope of analyses variations of the exergy efficiency are

99

101

103

105

107

109

-5.0 -2.5 0.0 2.5 5.0

parameter variation in %

co

st va

riatio

n in

%

fuel preheating (CMB1/CMB2) condenser pressure (CND1)isentropic efficiency (EX1/EX2) isentropic efficiency (C1/C2)isentropic efficiency (ST2) isentropic efficiency (ST3)minimal temperatur difference (HPECO2/HPEC22) minimal temperatur difference (HPSHT3/HPSHT23)minimal temperatur difference (LPEVA/LPEVA2)

99

101

103

105

107

109

-5.0 -2.5 0.0 2.5 5.0parameter variation in %

cost

varia

tion

in %

methanol electricity




especially affected by modifications of the condenser pressure and the isentropic efficiencies of the expander, compressor and low pressure steam turbine. The methanol/electricity cost variations discussed tend to result from modifications of the isentropic efficiencies of the expander, compressor and low pressure steam turbine and the minimal temperature differences of the high pressure economi-ser/superheater and low pressure evaporator mainly.

Table 5: Optimisation parameters and results.

Iteration Parameter and results 0 1 2 3 4 5 Fuel preheating (CMB1/CMB2) [°C] 100 150 150 150 150 150

Condenser pressure (CND1) [mbar] 60 60 40 40 40 40

Isentropic efficiency (EX1/EX2) [%] 89 89 89 90 90 90

Isentropic efficiency (C1/C2) [%] 85 85 85 86 86 86

Isentropic efficiency (ST3) [%] 90 90 90 91 91 91

Minimal temperature difference (HPECO2/ HPEC22) [K]

8 8 8 8 15 15

Minimal temperature difference (HPSHT3/ HPSHT23) [K]

30 30 30 30 35 35

Minimal temperature difference (LPEVA/ LPEVA2) [K]

4 4 4 4 10 10

Isentropic efficiency (PUMP1/2/3) [%] 85 85 85 85 85 83

Isentropic efficiency (ST2) [%] 89 89 89 89 89 87

Exergy efficiency variation [%] ± 0.0 + 0.1 + 0.9 + 2.1 + 2.0 + 1.8

Methanol cost variation [%] ± 0.0 ± 0.0 ± 0.0 + 0.3 + 0.2 + 0.2

Electricity cost variation [%] ± 0.0 + 0.1 + 0.2 + 2.0 + 1.6 + 1.6




6 Summary and outlook

The focus of the preceding analyses is the optimisation of the exergy and cost efficiency of a cogeneration concept, a combined MegaMethanol plant and gas-steam power plant on natural gas basis. Therefore the energy supply of the MegaMethanol plant is analysed and evaluated concerning combined thermo-dynamic and economic aspects. Applying the optimisation approach according to [14] different components are determined to affect the exergy and/or cost effi-ciency. Sensitivity analyses present the significance of isentropic expander/com-pressor efficiency of the gas-steam power plant particularly in terms of the production costs. The implementation of the optimisation approach discussed results in a gas-steam power plant design characterised by increased exergy efficiency and decreased cost efficiency by trend. Recommendations for advanced studies are related to the application of combined optimisation methods including thermoeconomic approaches to improve the cost efficiency in particular and to investigations of further cogeneration concepts, e.g. combined production of hydrogen and electricity.

Acknowledgement

The authors gratefully acknowledge the support of the DAAD – German Acade-mic Exchange Service, KRAFTWERKSSCHULE E.V. and LURGI GMBH.

Appendix

Table A.1: Economic data of the cogeneration system (selection) [15].

life cycle 30 a annual utilisation period 7446 h interest rate 12% inflation 2.3% general escalation 0.7% fuel escalation 1.0% fuel cost 2.63 EUR/GJ cooling water 0.01 EUR/m³ potable water 0.11 EUR/m³







Gas

-ste

am p

ower

pla

nt S

eaba

nk/U

K a

ccor

ding

to [1

2].

Figu

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.1:

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