Hella Tokos

Zorka Novak Pintari

Peter Glavi

Energy Saving Opportunities in Heat Integrated Beverage Plant Retrofit

Keywords: heat integration, polygeneration, batch processes, retrofit, industrial application

This paper presents practical applications of mathematical programming for energy integration in a large beverage plant. The opportunities of heat integration between batch operations were analysed by a Mixed Integer Linear Programming (MILP) model, which was slightly modified by considering specific industrial circumstances. The feasibility of combined electricity, heating and cooling production was studied using a simplified MILP model, developed for the selection of an optimal polygeneration system. The superstructure includes cogeneration systems with different prime movers (steam turbine and gas turbine), and a trigeneration system with a back-pressure steam turbine. The proposed heat integration scheme and the selected cogeneration system may improve a company's economic performance and reduce its environmental impact.

Introduction

The current drive towards environmental sustainability and the rising costs of utilities has forced process industries to search for additional opportunities regarding energy savings in existing plants, by using process integration. This includes heat integration of existing operations as well as installation of more efficient systems for the production of several energy forms, from a single primary energy source.

Earlier heat integration studies of batch processes relied on methods developed for continuous processes. The Time Average Model assumes that the streams exist simultaneously as if the process were continuous, i.e. the time schedule is ignored and the heat flows are averaged over the batch cycle time [1]. The time dependence of batch processes is included in later studies, by dividing the time horizon into time intervals [START_REF] Kemp | Energy and process integration in continuous and batch processes[END_REF]. Time Pinch Analysis treats time as the primary constraint, while temperature driving forces are treated as secondary constraints [START_REF] Wang | Time pinch analysis[END_REF]. The concept of Pinch Analysis in combination with energy storage system design was used for thermal integration of batch processes applying time decomposition approach [START_REF] Pourali | Time decomposition in batch process integration[END_REF]. Lee and Reklaitis [START_REF] Lee | Optimal Scheduling of cyclic batch processes for heat integration -I. and II[END_REF] developed a mixed integer linear programming (MILP) mathematical model for the maximisation of heat recovery in batch processes involving no intermediate storage (NIS). This model assumes cyclically operated single-product campaigns and one-to-one matches between streams. Further development in the heat integration of cyclically operated batch processes was based on cascade analysis and includes the NIS policy with residence time, in the case of multiple streams matching [START_REF] Zhao | Heat integration for batch processes, Part I and Part II[END_REF]. Mathematical model for detailed design of multipurpose batch process facilities was developed as MILP program with incorporated heat integration [START_REF] Barbosa-Póvoa | Optimal design of heat-integrated multipurpose batch facilities: a mixed-integer mathematical formulation[END_REF]. The continuous-time mathematical formulation was used for optimization of direct heat integration in cases of variable and fixed batch sizes [START_REF] Majozi | Heat integration of multipurpose batch plants using a continuous-time framework[END_REF]. A mathematical programming approach based on the superstructure was developed for design and optimization of indirect thermal storage systems in order to minimize the consumption of external utility [START_REF] Ch | Design and optimization of indirect energy storage systems for batch process plants[END_REF]. An evolutionary process integration technique was developed for synthesizing a cost optimal heat exchanger network for batch processes including minimum unit targeting [START_REF] Ch | Minimum units targeting and network evolution for batch heat exchanger network[END_REF]. In general, mathematical models assume that the production scheduling is known and optimal. In open literature, a small number of articles consider the scheduling and heat integration in batch processes, simultaneously [START_REF] Adonyi | Incorporating heat integration in batch process scheduling[END_REF].

On the other hand, a great number of articles deal with the design and analysis of polygeneration systems [START_REF] Mavromatis | Hardware composites: A new conceptual tool for the analysis and optimisation of steam turbine networks in chemical process industries, Part I: principles and construction procedure[END_REF][START_REF] Bassols | Trigeneration in the food industry[END_REF][START_REF] Calva | Thermal integration of trigeneration systems[END_REF][START_REF] Onovwiona | Residential cogeneration systems: review of the current technology[END_REF][START_REF] Godefroy | Design, testing and mathematical modelling of small-scale CHP and cooling system (small CHP-ejector trigeneration)[END_REF][START_REF] Temir | An application of trigeneration and its economic analysis[END_REF], along with their influence on the environment [START_REF] Minciuc | Fuel Savings and CO2 emissions for tri-generation systems[END_REF][START_REF] Wu | Assessing and optimizing the economic and environmental impacts of cogeneration/district energy systems using an energy equilibrium model[END_REF].

International projects, e.g. EDUCOGEN, OPTYPOLYEN etc., provide valuable information about technical data, the production parameters of polygeneration systems, and the data bases of existing polygeneration systems [START_REF] Fisk | Cogeneration Application Considerations[END_REF]. Combined heat and power integration in batch and semi-continuous processes was also presented in the literature [START_REF] Puigjaner | Extended modeling framework for heat and power integration in batch and semi-continuous processes[END_REF] including a general procedure for utility generation and utility system design optimization by means of mixed integer nonlinear programming problem (MINLP).

In this paper, a large beverage plant has been studied in order to analyse the possibilities: 1) of heat integration between batch operations in order to maximize heat recovery and, 2) installation of a polygeneration system in order to produce electricity, and heating and cooling at the site. In order to achieve the first goal, a MILP mathematical model for the heat integration of batch processes [START_REF] Lee | Optimal Scheduling of cyclic batch processes for heat integration -I. and II[END_REF] was applied and

Heat integration retrofit

MILP formulation for the heat integration of cyclically operating single-product campaigns, with nonzero holding time and no intermediate storage [START_REF] Lee | Optimal Scheduling of cyclic batch processes for heat integration -I. and II[END_REF] was chosen as a basic mathematical model. Cocurrent contacting was assumed between the batch units as in the process under study, the batches must remain in their tanks during heat exchange. This article assumes the reader is familiar with the basic model and, therefore, only the modifications of this model are briefly described in the next section.

Mathematical model for heat integration retrofit

Selected MILP formulation determines the operating schedule for maximum heat integration between the batch units. Heat integration is performed simultaneously by rescheduling the initial operating schedule, which is determined by the linear programming problem. The minimum cycle time without considering heat integration is the upper bound for the cycle time of the final schedule. This enables an adjustment of the schedule of batch processes without increasing the production time. The selected model was applied almost straightforwardly for retrofitting the existing process, only three small modifications were introduced.

a) Operations without heat transfer

Several operations in the studied plant are carried out without temperature change (e.g. lautering process). These operations were included in the model along with the heat transfer operations, in order to fit the existing operating schedule.

b) One-to-two matches

In the process under study, heat integration is desired between one unit operating in an inphase manner and several other units. As the basic model allows only one-to-one matches, the option of multiple integration of such units was introduced by dividing the operation into two out-of-phase stages inside the in-phase stage, as shown in Figure 1.

The ending time of the first out-of-phase operating unit,

+ + + + = + = = ∈ (1)
where , 1

I i j t + /h is the starting time at which batch i enters out-of-phase unit j+1, 1 P j t + /h is the fixed processing time of out-of-phase unit j+1, N is the number of batches over which heat integration is considered, and J IP is a set of input streams of the first units on inphase stages. In the case studied brewery, vapour generation during boiling process represents such in-phase unit. One part of vapour stream is used for preheating the next batch through thermal storage system while the unused part is rejected despite of its heating potential. Vapour generation was thus divided into two out-of-phase operations.

Heat integration opportunities of unused vapour stream were explored by including Eq. 1 into original mathematical model for cocurrent heat exchange.

c) Economic objective function

In the basic formulation [START_REF] Lee | Optimal Scheduling of cyclic batch processes for heat integration -I. and II[END_REF], the objective function is defined as a fraction of the utility savings to the utility required per individual batch without heat integration. In order to introduce an economic trade-off between the utility savings and investment costs of the heat exchanger' s area, the objective function was transformed into a net present value function which includes annual savings in utility costs, and the annual investment cost of the heat exchangers.

The area of the heat exchanger is defined by equation:

, , , , , ln

i j k j k j k j k A U T φ ≥ ⋅ (2)
where , , i j k φ /kW is the amount of heat exchange between unit j in i-th batch and unit k in the first batch, , j k A /m² is the heat exchange area, k , j U /kW/(m²⋅K) is the overall heat transfer coefficient, and , ln j k T /K is the logarithmic mean temperature difference [START_REF] Chen | Letter to the editor: Comments to improvement on a replacement for the logarithmic mean[END_REF].

In the retrofit study, the existing process places some additional restrictions on the predicted matches. The calculated heat exchange area is limited by the size of the production vessel on which a jacket or half-pipe coil jacket could be installed.

VESSEL , j k A A ≤ (3)
where VESSEL A /m² is the available heat transfer area of the jacketed vessel.

The investment of the heat exchanger is calculated from equation:

, , , , j k j k i j k i I r A s Y = ⋅ + ⋅ (4)
where k , j I /EUR is investment in heat exchanger, r and s are the variable and fixed parameters, respectively, of the heat exchanger investment cost. Equation 4 represents linear investment cost approximation which was derived from the regression of the installed cost data obtained by Aspen Icarus [START_REF]Aspen Icarus Process Evaluator 12.1, User's Guide[END_REF] for the exchanger area within the range 20 m²-60 m².

The differential cash flow of retrofitted solution is defined by equation:

( ) ( ) (
)

1 d HU H CU C C t , , , , t , , , , , , d d 1 1 1 1 n i j k i j k j k n i j k i j k j k r F r P P r I r r φ φ - + - = -⋅ ⋅ + ⋅ + ⋅ ⋅ ⋅ + (5)
where C F /(EUR/year) is the differential cash flow, HU P and CU P /(EUR/kW year) are the prices of hot and cold utilities, respectively, H , , i j k φ /kW and C , , i j k φ /kW represent decreases in hot and cold utility consumptions, d r is a discount rate, n is the depreciation period, and t r is the tax rate. The objective function, obj F , maximizes the net present value of the invested capital for heat integration retrofit:

( ) (
)

1 d d obj , C , d 1 1 1 n j k n j k r r F I F r - ⋅ + = - + ⋅ + - (6)

Results of heat integration retrofit

In the studied beverage plant, the specific heat consumption per m 3 of beer sold is 1.17 GJ/m 3 . According to the Reference Document on Best Available Techniques in the Food, Drink and Milk Industries [START_REF]Reference Document on Best Available Techniques in Food, Drink and Milk Industries[END_REF], the specific heat consumption needs to be within the range 0.85-1.20 GJ/ m 3 , which indicates the need for additional energy savings.

A heat integration study was performed in the brewhouse, which is the largest heat consumer in the plant. Figure 2a presents a block diagram of production in the brewhouse. Processes in the brewhouse mainly consume heat energy. The mashing process consists of several precisely defined heating and holding steps, during which the starch converts to fermentable sugar. Wort boiling is the largest consumer of heat. The hops and trub are separated from the wort in the whirlpool, and the wort is then cooled down to fermentation temperature. In the studied beverage plant, part of the waste vapour formed during boiling is used for the production of hot water, which is stored in an intermediate storage tank and used for wort preheating in the next batch (dashed line in Figure 2a). The remaining vapour is discharged. Heat released during the cooling process is used to prepare process water for the next batch.

In the first step, data acquisition and adjustment were performed in order to obtain suitable information for the applied mathematical formulation. Each temperature increase was defined as a specific stage. Altogether, the single-product batch process in this study The heat transfer of the second match could be accomplished by the heat transfer fluid (water) in the jacketed mash tun, however, the available heat exchange area of the tank's jacket is insufficient for the required heat transfer. The maximum available area would suffice for preheating the mash by hot water, while further heating during processing stage should be accomplished by the steam supplied to the jacketed bottom.

The additional utility saving would be 175,471 EUR/year, nevertheless, the second match was rejected by the company, because it can not satisfy the total heat demand of the mashing stage and operation splitting is not allowed. At the moment, low temperature utility produced by whirlpooling can not be used elsewhere during production. An increase in the exchange time is impossible, because rescheduling is disallowed. The final schedule and repeated heat integration pattern are shown in Figure 3.

On the level of the entire company, the overall specific heat consumption would be reduced from 1.17 GJ/m 3 to 1.15 GJ/ m 3 with the proposed heat integration match in the brewhouse. This indicates that high level of heat integration is already achieved in this section, and therefore, it could not contribute significantly to the reduction of overall heat consumption below the upper BAT level. In fact, the actual technology for beer production does not allow significant savings, because the main part of the vapour generated during boiling process is already integrated within the process. Recently, research is under way to analyze heat integration potential in another section of the company, i.e. the packaging area, which should indicate whether specific the heat consumption could be further reduced.

Polygeneration

Polygeneration is a combined production of mechanical or electrical, thermal, and cooling energy using the same primary energy source. This enables remarkable energy savings and more efficient operation compared to those systems which produce electricity, heat, and cooling energy, separately. In addition to decreased fuel consumption, polygeneration results in a decrease of pollutant emissions (carbon dioxide, sulphur dioxide, and oxides of nitrogen). Currently available prime movers for polygeneration systems include: steam turbines, gas turbines, combined cycle gas/steam turbines, reciprocating internal combustion engines, stirling engines, and fuel cells.

Mathematical model for polygeneration

The industrial plant being studied produces single product with significant seasonal variations in demand. The plant is a large consumer of low pressure steam which is produced in a conventional manner (steam boilers). However, there is an intention to produce electricity and cooling energy besides the thermal energy at the site, as the brewery consumes all three.

The superstructure of alternative polygeneration systems (Figure 4) includes a cogeneration with a back-pressure steam turbine at three pressure levels (i = 1, 2, 3), and a cogeneration system with back-pressure steam turbine at three pressure levels, and higher heat production during heating season (i = 4, 5, 6). In this way, the influence of inlet pressure and steam flow rate on electricity production in the cogeneration system with a steam turbine is taken into account. The model also includes a cogeneration system with a gas turbine (i = 7) and a trigeneration system with a back-pressure steam turbine at The optimal polygeneration system is selected by maximizing the net present value:

10 obj NP 1 i i F V = = (7)
where obj F /EUR represents the objective function, i V NP /EUR is the net present value of polygeneration system i. The net present value of alternative i is calculated by equation:

( ) (
)

1 d d NP C d 1 1, ,10; 1 1 n i i i n r r V I F i r - ⋅ + = -+ ⋅ = + - (8)
where i I /EUR is investment in polygeneration system i, i F C /(EUR/year) is differential cash flow. The logical constraint for the selection of optimal polygeneration system is:

10 1 1 i i Y = = (9)
where i Y is a binary variable for selection of the optimal polygeneration system for the company. Additional economic criteria were calculated for the alternatives after optimization. Internal rate of return, IRR i r , is defined by equation, from which it is calculated iteratively:

( ) ( ) 1 IRR IRR C IRR 1 1, ,10; 1 1 n i n i i i i r r I i F r - ⋅ + = = + - (10)
Payback period, PB i t /year, is defined as:

PB C 1, ,10;

i i i I t i F = = (11)
The constraints of the mathematical model describing different polygeneration systems are presented in the continuation.

a) Cogeneration system with back-pressure steam turbine

The cogeneration system with back-pressure turbine has the simplest configuration (Figure 5). The electricity produced depends on steam pressure reduction through the turbine. The higher the turbine inlet pressure, the greater the electricity output. The actual outlet steam condition is dictated by the required temperature during the process.

According to the highest steam flow rate, as measured in the studied brewery, the following pressure levels were selected: 42.4 bar, 59.7 bar and, 101 bar. Because of seasonal production, index j is introduced to define monthly productions of heat and electricity. The latter is calculated based on the current heat consumption:

; 3 2 1 ; 12 2 1 P , , i , , j Y c Q E i i j j , i = = ⋅ ⋅ = ( 12
)
where P j , i E /(kW h) is the monthly electricity production in polygeneration system i, j Q /GJ is monthly heat consumption and i c /((kW h)/GJ) is a conversion factor for electricity production by the polygeneration system i. As already mentioned above, heat production is constant for options i=1, 2, 3. The annual electricity production, a P, i E /((kW h)/year), is:

12 P, a P , 1 1, 2,3; i i j j E E i = = = (13)
The annual heat consumption, a q /((kW h)/year) is defined by equation:

12 a 1 j j q q = = (14)
where j q /(kW h) is the heat consumption in month j.

The fuel consumption (natural gas) in polygeneration systems is higher compared to the conventional heating system because of additional electricity production. Increase in fuel consumption is presented by the factor for fuel consumption increase:

( ) P,a a ADD a
1, 2,3;

i i i i i f E Y q F F F Y i q ⋅ + ⋅ ⋅ = -⋅ = ( 15
)
where ADD i F /(m³/year) represents the additional annual fuel consumption for polygeneration system i, F/(m³/year) is the current fuel consumption and i f /(kW h) th /(kW h) e is factor for fuel consumption increase, where subscript th refers to the thermal energy, and subscript e to electricity.

Companies that invest in polygeneration systems are eligible for tax relief on the reduced carbon dioxide emission. The latter is calculated as a difference between CO 2 released before and after polygeneration installation:

i i i m u Y q u E i = ⋅ ⋅ - ⋅ = (16) where 2,
CO i m /(g/year) is the annual decrease in carbon dioxide emission for polygeneration system i, C u /(g/(kW h) th is the specific emission of carbon dioxide from industrial steam boilers, and CG u /(g/(kW h) e is the specific emission of carbon dioxide from the polygeneration system with steam turbine.

The cash flow is defined by equation:

( ) ( ) ( ) ( )
= -⋅ ⋅ + ⋅ - ⋅ - ⋅ + - + ⋅ ⋅ = ⋅ + (17)
where E P /(EUR/(kW h)) is the price of electricity, EN P /(EUR/g) is the carbon dioxide emission tax, M P /(EUR/(kW h)) is the price of maintenance, and F P /(EUR/m³) is the price of natural gas.

The investment in polygeneration systems is calculated from equation: [START_REF] Minciuc | Fuel Savings and CO2 emissions for tri-generation systems[END_REF] where i K /(EUR/kW) e is the investment parameter for polygeneration system i, and MAX /(GJ/h) is the maximum heat flow rate required in the plant. The latter is calculated from the maximum mass flow rate of steam, measured at the boiler' s outlet.

; 3 , 2 , 1 MAX = ⋅ ⋅ ⋅ = i Y c K I i i i i

b) Cogeneration system with back-pressure steam turbine -increased heat production during heating season

Besides the inlet pressure, electricity production can also be increased by increasing the steam mass flow rate and, thus, increasing heat production. In the studied brewery plant it was estimated that the maximum allowable increase in steam production during the heating season is 50 % above the current production level. The monthly electricity production during the heating-season months is limited by constraint: P ADD, HEAT ,

j i i i j j i i Q c Y E Q c f i j JH ⋅ ⋅ ≤ ≤ ⋅ ⋅ = ∈ = 4,5,6; 1, 2, 10, 11, 12;
where ADD, HEAT i f is the optimization variable of heat production increase and JH is the set of heating-season months. The upper bound of this increase is determined by inequality:

; 6 5 4 UP HEAT, ADD, HEAT ADD, , , i f Y f i i i = ⋅ ≤ (20)
where UP HEAT, ADD, i f is the maximum allowable increase in heat production, which is defined by the company according to identified outside consumers of heat energy and amounted to 1.5. The differential cash flow in this case is defined by equation:

( ) ( ) ( ) ( )
i i i j j jH i i i n i n i E P P f Y q F r m P E P F P r r I i r r ∈ - ⋅ + ⋅ -⋅ + = -⋅ ⋅ - ⋅ - ⋅ + - + ⋅ ⋅ = ⋅ + (21)
where H P /(EUR/(kW h)) is the price of heating for external consumers.

Investment in the polygeneration system is defined by:

; 6 , 5 , 4 HEAT ADD, MAX = ⋅ ⋅ ⋅ ⋅ = i Y c f K I i i i i i (22)
Equations 13-16 remain unchanged.

c) Cogeneration system with open-cycle gas turbine

The cogeneration systems with gas turbines produce electricity primarily, and secondarily the heat from the hot gases by a heat recovery system, Figure 6. The electricity production would exceed the company's current demand by applying the cogeneration system with a gas turbine at the current steam production level. The surplus energy could be sold as "green energy" into the public electricity network at the, so called, feed-in tariffs.

( )

12 S P D , 1 7; i i i j j j E Y E E i = = ⋅ - = (23)
where S i E /(kW h/year) is the annual electricity for sale and D j E /(kW h) is the monthly electricity consumption of the company. The differential cash flow in this case is defined by equation:

( ) ( ) ( ) ( ) ; 7 1 1 1 1 1 d d d t F ADD M a P, GE S E D t C = + ⋅ - + ⋅ ⋅ + ⋅ - ⋅ - ⋅ + ⋅ ⋅ - = - i r r r I r P F P E P E P E r F n n i i i i i i (24)
where GE P /(EUR/(kW h)) represents the price of "green energy". High additional fuel consumption prevents tax relief on carbon dioxide emissions. Equations 12-15 and 18 remain unchanged.

d) Trigeneration system with back-pressure steam turbine

In the case of the trigeneration system, cooling energy is produced along with heat and electricity. According to the classical concept of trigeneration, the heat is transformed into cooling energy by an absorption chiller during summer, when there is no need for heating. This concept can not be applied in the studied plant because of simultaneous consumptions of heat and cooling energy. Peak season production takes place during the summer, when the demands for both, heating and cooling, are the highest. Yet another possibility is to connect the refrigeration compressors to the steam turbine, thus avoiding the transformation of energy from mechanical work to electricity (Figure 7). In this case, the steam turbine operates over a speed range, depending on the compressor' s load.

The equations are the same as for the cogeneration system with the back-pressure steam turbine 12-18, with the exception of the conversion factors for electricity production, (Table 1).

Results of polygeneration

In the case studied Brewery the annual heat consumption was 127.2 MJ and the annual electricity consumption 13.58 GW h. The Brewery generates steam for its own needs using a conventional boiler, while electricity is purchased from the vendors. The wort preparation process is the largest consumer of heat, while the highest need for cooling energy is during fermentation and maturation operations.

Equations 7-24 represent a MILP model for selecting the optimal polygeneration system. The parameters of the model are given in Table 1. The model selects the optimal polygeneration system based on the economic objective function. In addition, the increase in heat production during the heating season is optimized for alternatives i = 4, 5, 6. The results of analysis are shown in Table 2.

The size of the applied model is app. 200 constraints, 200 continuous variables and 10 binary variables. The CPU time was less than 1 s.

It is evident from Table 2, that electricity production increases with inlet pressure in cogeneration system with a back-pressure steam turbine (i=1, 2, 3). The highest electricity production would be achieved at an inlet pressure of 101 bar (i=3), P 3 E = 7.59 GW h, which represents 56 % of current electricity consumption. However, the net present value, the internal rate of return, and the payback period decrease with the pressure level, as the investment, maintenance costs and fuel consumption increase.

In the case of higher heat production during the heating season by cogeneration system with back-pressure steam turbine (i=4, 5, 6), the highest electricity production would also be achieved at an inlet pressure of 101 bar, (i=6), P 6 E = 9.10 GW h or 67 % of the current company's demand. The optimal heat production during the heating season is 50 % higher than the current consumption, which represents the upper limit approved by the Brewery. From the economic point of view, the cogeneration systems with back-pressure steam turbine and additional heat production during heating season is the most favourable option. The net present value and the internal rate of return are higher and the payback period shorter, but the company would become dependent on outside consumers.

Electricity production by the cogeneration system with open-cycle gas turbine (i=7) would exceed the current electricity demand by 9.03 GW h. The electricity surplus could be sold in public electricity network as a "green energy". In spite of these results, this cogeneration system is unacceptable for this brewery. The net present value is negative because of an overdimensioned cogeneration system induced by low steam production.

In the case of trigeneration systems with a back-pressure steam turbine (i=8, 9, 10), the highest electricity production is P E 10 = 8.20 GW h or 60 % of the current electricity consumption. No additional compressors were assumed in the economic analysis. If the new compressors were installed, the net present value would become negative, because of high investment costs (estimated at 1,173,600 EUR).

The optimal solution selected by the model is the cogeneration system with backpressure steam turbine at the pressure level of 42.4 bar (i=4). During the heating season, heat production should increase by 50 % above the current level. Electricity production would cover 42 % of the company's requirements. The net present value is 934,467 EUR and the payback period 3.2 years. The disadvantage of this solution is that the brewery would become dependent on smaller consumers of surplus heat.

It should be noted, that economic calculations were based on the electricity price negotiated on a long-term basis between the Brewery and electricity distributor.

However, the economics of polygeneration systems is quite sensitive on changes in electricity prices, e.g. an increase of 10 % would increase the optimal net present value by 18 %, and reduce the optimal payback period from 3.2 years to 2.9 years. As electricity prices are expected to increase in the future, polygeneration technology would become even more favourable.

Conclusions

Possibilities of heat integration, and combined electricity, heating, and cooling production in a beverage plant were analysed by application of mathematical programming optimization models. The mathematical model for the heat integration of batch processes [START_REF] Lee | Optimal Scheduling of cyclic batch processes for heat integration -I. and II[END_REF] was slightly modified in order to correspond to industrial circumstances. Two matches were predicted in the brewhouse by this model. The first one is between waste vapour from wort boiling and adjunct mash heating processes. The second match integrates the heat released at wort clarification with the mash heating process. The resulting savings on utilities would be significant, however, only the first match was acceptable to the company. The second match supplies only part of the heat required by the mash heating process and was, therefore, rejected.

A simplified MILP model was developed for the feasibility analysis and selection of the optimal system for combined electricity, heating, and cooling production in the plant with significant seasonal variations in demand. The set of alternatives included steam and gas turbines at three pressure levels, and a trigeneration system with a back-pressure steam turbine. The option of heat production increase above the company's demand was optimized. The optimal polygeneration system for the brewery was selected according to the economic criteria considering the company's constraints. The cogeneration system with a back-pressure steam turbine at a pressure level of 42.4 bar has the highest net present value. Heat production would be increased during the heating season by 50 %.

Electricity production would cover 42.5 % of the current brewery's consumption. The net present value is positive and the payback period is 3.2 years. The disadvantage of this solution is that the plant would become dependent on external consumers of surplus heat energy.

Nomenclature

Sets binary variable for match between unit j in batch i and unit k

, 1 E

 1 i j t + /h, is equal to the input time of the second one,

  variable for existence of match between unit j in i-th batch and unit k in the first batch. The sum of Y i,j,k in the original model is set to one, therefore, fixed costs are accounted only once.

consisted of 19

 19 units, from which three parallel units were used in mixed, in-phase and out-of-phase manner. The minimum cycle time obtained by the linear programming problem was 3.33 h, which coincided well with the existing production (3.75 h to 4 h, depending on the season).Processes in the brewhouse are based on sensible biotransformations with a precisely defined processing time, and the batches must remain within their vessels during heat exchange. Therefore, in the second step, optimal heat integration was studied using the mathematical model for cocurrent heat exchange, which was accomplished by heating and cooling media. The price of hot utility was HU P = 183 EUR/kW year and price of cold utility CU P = 63 EUR/kW year. The variable parameter of the exchanger investment cost was r = 91.4 and the fixed parameter s = 7,183. The size of the applied MILP model was app. 6,700 constraints, 5,000 continuous variables and 1,200 binary variables. The model was solved by GAMS solver Cplex [25], using 1 s of CPU time at the PC (P4, 2.6 GHz and 512 MB RAM). The integrality gap was 7.69 %. Two matches were predicted by the optimization model: 1) heating the adjunct mash by the waste vapour produced during boiling and 2) heating the mash by the heat released during wort clarification in whirlpool (dotted lines in Figure 2b). The heat exchange of the first match can be accomplished by a half-pipe coil jacket on the adjunct mash tun. This would result in utility savings of 434,690 EUR/year. The required heat exchange area was estimated to be 59 m², and the corresponding investment cost amounted to 12 590 EUR. The net present value is positive at discount rate of 10 %, and the payback period is very low, around 11 days.

  three inlet pressure levels (i = 8, 9, 10). It should be noted that steam production in options i =1-3 and 7-10 should exactly fulfil the current demand of heat in the factory, while the additional production of heat is optimized in the options i = 4, 5, 6 assuming regular demand of external consumers.

Figure captions:Figure 1 .

 1 Figure captions:

Figure 2 .

 2 Figure 2. Schematic diagram of production in the brewhouse before heat integration

Figure 3 .

 3 Figure 3. Result of heat integration in the brewhouse.

Figure 4 .

 4 Figure 4. Superstructure of mathematical model for selecting the optimal polygeneration

Figure 5 .

 5 Figure 5. Cogeneration system with back-pressure steam turbine.

Figure 6 .

 6 Figure 6. Cogeneration system with open-cycle gas turbine.

Figure 7 .

 7 Figure 7. Trigeneration system with back-pressure steam turbine.

Figure 1 .

 1 Figure 1. Schematic diagram of in-phase and out-of-phase manner operating units.

Figure 2 .

 2 Figure 2. Schematic diagram of production in the brewhouse before heat integration

Figure 3 .

 3 Figure 3. Result of heat integration in the brewhouse.

Figure 4 .

 4 Figure 4. Superstructure of mathematical model for selecting the optimal polygeneration system.

Figure 5 .

 5 Figure 5. Cogeneration system with back-pressure steam turbine.

  consumption increase ((kW h) th / (kW h) e )[START_REF] Stefan | Energy Efficiency Centre, Review of cogeneration equipment and selected installations in Europe, Femopet[END_REF] carbon dioxide from industrial steam boiler (g/(kW h) th )[START_REF] Cogen Europe | The European Association for the Promotion of Cogeneration[END_REF] C u = 225.55 Specific emission of carbon dioxide from polygeneration system (g/(kW h) e )[START_REF] Cogen Europe | The European Association for the Promotion of Cogeneration[END_REF] CG u = 808.16 Economic data Price of electricity (EUR/kW h) E P = 0.06468 Price of "green energy" (EUR/kW h) GE P = 0.07094 Price of natural gas (EUR/m³) F P = 0.291 Price of heat (EUR/kW h) H P = 0.025Price of maintenance (EUR/kW h)[START_REF] Negoi Escu | A Study Regarding the Performances of Trigeneration Systems[END_REF]

Table captions :Table 1 .

 captions1 Data for the industrial case study.

Table 2 .

 2 Results for polygeneration.

Table 1 .

 1 Data for the industrial case study.

	Model parameters
	Conversion factor (kW h/GJ) [21]

Table 2 .

 2 Results for polygeneration.

	Polygeneration system, i	i = 1	i = 2	i = 3	i = 4	i = 5
	Pressure level (bar)	42.4	59.7	101.0	42.4	59.7
	Annual electricity production (kW h)	4,701,732	5,667,266	7,595,791	5,635,133	6,792,348
	Savings by electricity production (EUR/year)	304,108	366,559	491,296	364,480	439,329
	Saving by additional heat energy production (EUR/year)	0	0	0	175,328	175,328
	Investment (EUR)	680,064	819,720	1,098,664	1,020,096	1,229,580
	Maintenance cost (EUR/year)	14,105	17,002	22,787	16,905	20,377
	Additional fuel consumption cost (EUR/year)	174,151	209,914	281,346	208,724	251,587
	Savings by relief on CO 2 emission tax (EUR/year)	64,027	54,268	34,775	54,593	42,896
	Payback period (year)	4.2	4.6	5.2	3.2	3.6
	Net present value (EUR)	318,900	278,822	198,772	934,467	854,755
	Internal rate of return (%)	18.86	16.13	12.63	27.74	23.44
	Polygeneration system, i	i = 6	i = 7	i = 8	i = 9	i = 10
	Pressure level (bar)	101.0	11.4	42.4	59.7	101.0
	Annual electricity production (kW h)	9,103,728 22,614,365 5,078,278	6,120,139	8,203,861
	Savings by electricity production (EUR/year)	588,829	1,519,213	328,463	395,850	530,626
	Saving by additional heat energy production (EUR/year)	175,328	0	0	0	0
	Investment (EUR)	1,647,996	2,453,226	734,528	885,224	1,186,616
	Maintenance cost (EUR/year)	27,311	113,072	15,234	18,360	24,611
	Additional fuel consumption cost (EUR/year)	337,200	1,116,841	188,098	226,688	303,869
	Savings by relief on CO 2 emission tax (EUR/year)	19,534	0	60,221	49,690	28,629
	Payback period (year)	4.2	-	4.3	4.7	5.3
	Net present value (EUR)	695,741	<0	303,270	260,024	173,532
	Internal rate of return (%)	17.88	-	17.68	15.13	11.84

www.cogen-europe.eu/Downloadables/Projects/EDUCOGEN_Tool.pdf, Accessed: 28. 12. 2007.

Figure 6. Cogeneration system with open-cycle gas turbine.

Figure 7. Trigeneration system with back-pressure steam turbine.


Mohamed Kanniche
email: mohamed.kanniche@edf.fr

René Gros-Bonnivard

Philippe Jaud

Jose Valle-Marcos

Jean- Marc Amann

Chakib Bouallou
email: chakib.bouallou@ensmp.fr

Pre-combustion, Post-combustion and Oxy-combustion in thermal power plant for CO 2 capture

Keywords: CO 2 capture, pre-combustion, post-combustion, oxy-combustion

This paper presents a summary of technical-economic studies. It allows evaluating, in the French context, the production cost of electricity derived from coal and gas power plants with the capture of CO 2 , and the cost per ton of CO 2 avoided. Three systems were studied: an Integrated Gasification Combined Cycle (IGCC), a conventional combustion of Pulverized Coal (PC) and a Natural Gas Combined Cycle (NGCC). Three main methods were envisaged for the capture of CO 2 : pre-combustion, post-combustion and oxy-combustion. For the IGCC, two gasification types have been studied: a current technology based on gasification of dry coal at 27 bars (Shell or GE/Texaco radiant type) integrated into a classical combined cycle providing 320 MWe, and a future technology (planned for about 2015-2020) based on gasification of a coal -water mixture (slurry) that can be compressed to 64 bars (GE/Texaco slurry type) integrated into an advanced combined cycle (type H with steam cooling of the combustion turbine blades) producing a gross power output of 1200 MWe.

Syngas: synthetic gas produced by the gasification

Introduction

The industrial feasibility of separating the CO 2 contained in a gas mixture no longer needs to be demonstrated: for example, the ammonia industry uses many hydrogen production units derived from natural gas, in which the final step is CO 2 /H 2 separation. Similarly, in the field of natural gas production, excess CO 2 contained in the gas in some deposits has to be extracted so that methane can be marketed efficiently.

In the case of exhaust gases from electrical power stations, other handicaps include firstly the presence of impurities, and secondly the dilution of CO 2 by nitrogen in the combustion air: in general, CO 2 represents only 5% (for the NGCC system) to 15% (for the PC system) of the volume of exhaust gases. If it is required to separate the CO 2 efficiently, it is obviously tempting to remove the nitrogen from the air in order to make the capture process easier. For the IGCC process, this option was necessary even before the emergence of the CO 2 / greenhouse effect problem, mainly for economic reasons related to the reduction in the volume of installations and therefore the resulting savings in materials, the savings being particularly important when the gasification pressure is increased. For other processes, the use of oxygen as an oxidant requires that exhaust gases should be recycled to maintain conventional temperature levels and thus avoid the need to completely change the sizes of all combustion systems (boilers for PC and combustion chambers for NGCCs). However, note that for NGCC the problem of the expansion turbine arises because it's not adapted to a working fluid composed mainly of CO 2 when it's designed for N 2 as mainly working fluid.

Different CO 2 capture processes

Our studies 1-4, present more technical details as well as bulky bibliography concerning the three systems targeted by CO 2 capture operation: Integrated Gasification Combined Cycle (IGCC), Natural Gas Combined Cycle (NGCC), and combustion of Pulverized Coal (PC). For the IGCC, two gasification types have been studied: firstly an existing technology based on gasification of dry coal at 27 bars (Shell or Texaco radiant type) integrated into a conventional combined cycle producing an output of 320 MWe (referenced here as IGCC-300) and a future technology (planned for about 2015 -2020) based on gasification of a coal-water mixture (slurry) that can be compressed up to 64 bars (GE / Texaco type) integrated into an advanced combined cycle (H type with cooling of the combustion turbine blades by steam) with a gross power output of 1200 MWe (referenced here as IGCC-1200). The technology on which most experiments have been carried out at the moment is of the Radiant type, although it cannot yet be considered as being mature. Its efficiency is better than the slurry technology (by more than 2 percentage points), because there is less water to be evaporated in the gasification operation. However, it is limited to 30 bars by coal pressurization levels, and its cost is higher than the slurry technology for which the coal can be pressurized up to 64 bars. For PC, two types of power stations were studied: a sub-critical power station with a gross power output of 600 MWe (Q600 not presented in this paper) and a super-critical power station with a gross power output of 1200 MWe (referenced here as PC-1200). Two combined cycles were studied for NGCC: a combined cycle based on a 9H type combustion turbine line associated with an evaporation boiler line and a single shaft steam turbine line, the assembly providing a gross power of 480 MWe (referenced here as NGCC-480), and another combined cycle with twice the gross power, composed of two 9H type combustion turbine lines associated with two evaporation boiler lines and one steam turbine line (not presented here as the scale effect is not so interesting).

The results presented in this work are applicable to a small number of cases, namely: two IGCCs: the Radiant type IGCC (IGCC-300) and the Slurry type IGCC (IGCC-1200); the supercritical PC-1200 and the NGCC-480. It can be considered that these are the most representative systems of the installations that will be used to replace existing fleets: the radiant type IGCC remains the reference (technology similar to that proposed by Shell), but the Slurry type process is included because its production cost is lower than the radiant type, even if its efficiency is lower. The PC-1200 can be constructed at the present time and there is a significant benefit from the scale effect and its efficiency is better than the Q-600 that is not presented herein. There are no advantages with the 920 MWe NGCC at the current price of natural gas, especially if it will be required to operate in semi-base or in peak, and therefore it was decided to present only the 480 MWe NGCC.

Three main methods can be envisaged for the capture of CO 2 with these three systems (see Figure 1):

1)

pre-combustion capture: to capture CO 2 in a synthesis gas after conversion of CO into CO 2 ;

2) post-combustion capture: to capture CO 2 in the exhaust gases once the fuel has been fully burned with air;

3) capture in oxy-combustion: consisting of combustion in oxygen with recycling of exhaust gases (therefore composed mainly of CO 2 and water) and purification of the CO 2 flow, to eliminate incondensable gases.

Various processes can be envisaged for separation of the CO 2 contained in a gas mixture. They are based on chemical, physical or hybrid absorption, adsorption, membranes separation or cryogenic separation [START_REF] Romeo | Integration pf power plant and amine scrubbing to reduce CO 2 capture costs[END_REF][START_REF] Van Loo | The removal of carbon dioxide with activated solutions of methyl-diethanol-amine[END_REF][START_REF] Descamps | CO 2 capture study by physical absorption in power production systems based on Integrated Gasification Combined Cycle[END_REF][START_REF] Figueroa | Advances in CO 2 capture technology -The U.S. Department of Energy's Carbon Sequestration Program[END_REF][START_REF] Hwang | A membrane-based reactive separation system for CO 2 removal in a life support system[END_REF][START_REF] Amelio | Integrated gasification gas combined cycle plant with membrane reactors: Technological and economical analysis[END_REF]: Romeo et al. [START_REF] Romeo | Integration pf power plant and amine scrubbing to reduce CO 2 capture costs[END_REF] pointed out the high energy penalty in post-combustion using absorption with typical amines solvent.

They investigate some process integration variants in order to minimize both the energy penalty and the cost of avoided CO 2 in post-combustion for coal power plant. Peeters et al. [START_REF] Peeters | Techno-economic analysis of natural gas combined cycles with post-combustion CO 2 absorption, including a detailed evaluation of the development potential[END_REF] developed similar studies than the formers dedicated however to post-combustion in NGCC systems. van Loo et al. [START_REF] Van Loo | The removal of carbon dioxide with activated solutions of methyl-diethanol-amine[END_REF] are preferred when the partial pressure of CO 2 is genuinely very low (less than 1 bar), while chemical processes based on tertiary amines such as MDEA (methyldiethanolamine) are preferred when the partial pressure of CO 2 is slightly higher; MDEA is actually easier to regenerate under these conditions and its lack of reactivity is compensated by the addition of a kinetic absorption activator such as piperazine or MEA. The absorption capacity of amines increases with the partial pressure of CO 2 and begins to saturate at a partial pressure of 8 bars; beyond this limit, the performance of physical absorption improves and increases linearly with the partial pressure of CO 2 (Henry's law) [START_REF] Descamps | CO 2 removal from an IGCC power plant. Comparison of the capture options[END_REF].

Application to the capture of CO 2 for different thermal power station systems

Not all systems are compatible with all capture methods: the IGCC system can only be envisaged with the pre-combustion capture method [START_REF] Descamps | CO 2 capture study by physical absorption in power production systems based on Integrated Gasification Combined Cycle[END_REF] (the high pressure is used to separate CO 2 by physical absorption), the PC system can be adapted to postcombustion capture and oxy-combustion, and the NGCC system can be adapted to the three capture methods, even though the pre-combustion capture option (reforming of methane and then capture of CO 2 on synthetic gas after conversion of CO into CO 2 ) is economically fairly expensive compared with the other two methods (this method should only be attractive in special cases, for example when hydrogen is necessary for a refinery).

Sensitivity and optimization studies were carried out for each of the options envisaged for the three systems. For post-combustion and pre-combustion capture, we considered the optimization of the CO 2 content in the solvent, the theoretical number of plates in absorption and regeneration columns, the solvent flow, the reflux ratio in the regeneration column, the regeneration heat and obviously the CO 2 capture ratio itself.

For oxy-combustion, we considered optimization of the level of purity provided by the Air Separation Unit (ASU), the degree of purity of the CO 2 produced, the degree of leak tightness of the exhaust gas circuit (in the case of PC) and a study on the influence of these parameters on the CO 2 capture rate.

Basic assumptions

The results presented herein are all based on the same ISO ambient conditions (15°C, 1.013 bars and 60% relative humidity). This is particularly important for the energy performances of the studied processes. The pressure and the relative humidity have a significant impact on the performances of combustion turbines, and the ambient temperature imposes a vacuum at the condenser and therefore controls the performances of steam turbines. Concerning fuels, the coal used is a standard international quality steam coal (LHV  26 MJ/kg, 7% humidity, 15% ash and 1% sulfur). The annual operating times used (operation in base) are 8000 hours for NGCC, 7800 hours for PC and 7500 hours for IGCC. Installations are amortized over 30 years for all systems. The maintenance item for NGCC was reinforced to justify this minimum operating duration.

For availability, we assumed 92% for NGCC, 90% for PC and 85% for IGCC.

The economic estimates in our studies have been produced on consistent bases using exactly the same assumptions for each of the different systems and the different capture processes; they can thus be used to make fairly accurate comparisons between the different systems studied (except for uncertainties in the estimates that are far from being negligible); on the other hand, their absolute values may be quite inaccurate compared with 2008 prices 1 ; It's why the absolute costs are not given in this paper, but only relative costs to Pulverized coal power plant without CO 2 capture (used as reference). All relative costs mentioned in this work exclude transport and storage costs of CO 2 . For engineering and management of installations, we increased equipment costs by 8% for PC and NGCC, and by 10% for IGCC. We also allowed for contingencies equal to 5% for PC and NGCC, and 8% for IGCC. The results presented herein are based on a discount rate of 11%, considered to be the most probable in the medium and long term and construction times were fixed at 2 years for NGCC, 4 years for PC and 5 years for IGCC. The discount rate and the construction period are of overriding importance for interest during construction. Any delay in construction will substantially increase this type of expense. We also assumed parity between the American Dollar (USD) and the Euro (EUR).

We used the following reference values for the purchase prices of coal and natural gas:

1) for coal: 60 EUR/tonne, equivalent to 2.26 EUR/GJ HHV. This price is composed of 46 EUR per tonne of coal CIF ARA (including Cost, Insurance and Freight to one of the ports of Amsterdam, Rotterdam or Antwerp), plus 14 EUR/tonne for transport from the port to the power station;

2) for natural gas: a price of 6.29 EUR/GJ HHV. This price originates from the price of natural gas delivered to the procurement point at the frontier of the country equal to 230 EUR/1000 Nm 3 , equivalent to 22 EUR/MWh or 5.84 EUR/GJ HHV, plus 1.19 EUR/MWh for the TICGN tax (Taxe Intérieure de Consommation sur le Gas Naturel -Internal Tax on Consumption of Natural Gas) and 0.43 Euro/MWh for transport from the procurement point to the power station.

Results

Pre-combustion capture

Pre-combustion capture relates to the treatment of a synthetic gas composed principally of CO and hydrogen. Gasification of coal or reforming of natural gas with oxygen leads to a mixture composed principally of CO + H 2 (on dry), and then after conversion of CO with steam, to a mixture of CO 2 + H 2 . CO 2 can then be separated using a physical absorbent (which is less expensive as an investment and less penalizing for the efficiency than if the exhaust gases are treated, because the gas is under pressure and there is no nitrogen); CO 2 is sent to the compression unit while hydrogen is used as input to a combined cycle to produce electricity. The IGCC concept was no so far presented by the American DOE as being the "clean coal" power station of the future in a context in which something else other than electricity has to be produced from the coal (for example synthetic fuels). However, this system is still handicapped by low availability and high investment and production costs.

The optimum separation process will be chosen as a function of the partial pressure of CO 2 in the gas to be treated. In the case of pre-combustion capture, the partial pressure of CO 2 depends on the IGCC process chosen for coal, or the pressure of the reforming process chosen for natural gas. However, the increase in pressure is not a free operation, and it must be assured that the gain in capture due to the high pressure is not cancelled out by the additional energy that has to be supplied.

The first case that we studied was pre-combustion capture in a Puertollano radiant type IGCC operating at 27 bars (Figure 3). The partial pressure of CO 2 provided by this system is about 8 bars which, as mentioned earlier forms a ceiling (saturation) for the performances of chemical processes and which is the threshold beyond which physical processes become more attractive.

The quench type gasification (Figure 4), other alternative studied here, has gasifier operated at 64 bars, and is fed with a mixture of coal and water (slurry), the shift conversion is inserted immediately downstream the gasification system as the synthetic gas contains enough water to convert CO into CO 2 .

After a first selection, three processes were finally selected and studied in detail: a physical absorption process using methanol, another physical absorption process (the Selexol process) for which the solvent is based on dimethylether of polyethylene glycol (DPEG) and a process using an active amine-based chemical solvent, MDEA.

In addition to the equipment necessary for CO 2 capture (absorption and desorption columns, pumps, heat exchangers, expansion tanks, etc.), we included the following in the process:

-a catalytic reactor, used to convert CO into CO 2 before the separation ("shift conversion"); -a cooling system for the process with methanol in order to maintain an optimum temperature of -30°C in the absorption column;

-a downstream methanol vapor recovery system to limit losses of absorbent;

-a device for lowering the water content in CO 2 produced to less than 20 ppm (by mass) to prevent acid corrosion in the transport network;

-a CO 2 150 bar compression station associated with a gas cooling system (final temperature < 40°C) to satisfy the specifications for the CO 2 transport network.

Furthermore, after optimization, the CO 2 capture ratio was chosen to be equal to 85% for the three separation processes. This ratio results from combining the CO to CO 2 conversion ratio (90%) and the efficiency of the CO 2 separation itself (about 95%).

Finally, the methanol-based process was found to have the best performances in terms of the energy penalty [START_REF] Descamps | Efficiency of an IGCC power plant including CO 2 removal[END_REF] (reduction in the electrical efficiency of the power station), the production cost per kWh and the cost per tonne of CO 2 avoided, even if in the case of Puertollano type IGCC, the difference observed with the other two capture processes is not very high. This methanol process was also selected for the Texaco IGCC-slurry (see Figures 3 and4) and for reforming of natural gas, both operating at high pressure, equal to 64 bars for the IGCC and more than 70 bars for reforming of natural gas.

Under these conditions, the modeling results show (Figure 7) that the global efficiency of the power station drops to 32.5% net on the LHV basis with a methanolbased capture process for IGCC-slurry, and to 33.5% for the Puertollano radiant type IGCC. This efficiency is about 9 percentage points less than the efficiency of the reference power station without capture for the IGCC-slurry, and more than 10 points lower for the radiant type IGCC, which therefore represents a relative reduction in the efficiency of 22%. The main items responsible for this loss of efficiency are the capture station with its refrigeration system (methanol and exhaust gases), and the CO 2 compression station, the consumption of the two being approximately equal. However, note that the auxiliary with the highest consumption for both reference and capture plants is still the ASU, accounting for 44%.

In the case of the NGCC with reforming of natural gas, the relative penalty on efficiency is of the same order of magnitude as in the case of the IGCC: the efficiency drops from about 60% without capture to less than 46% with pre-combustion capture, which represents a relative drop of 23%.

As can be seen in Figure 7, capturing CO 2 costs a great deal of energy, which causes a large drop in the global efficiency of the power station. Therefore, more fuel has to be consumed to produce the same amount of electricity. In other words as shown in Figure 2 below, a power station with capture produces actually more CO 2 per kWh than a power station without capture, but more than 85% of the CO 2 is captured.

Therefore the quantity of CO 2 actually "avoided" in the atmosphere is not the amount that is captured, but is the difference between the quantity that the reference power station would have emitted without capture, and the quantity emitted by the power station with capture. The quantity of "CO 2 avoided" is obviously less than the quantity of "captured CO 2 " due to the reduction in the net production efficiency. This is why it is important to make a clear distinction between "CO 2 captured" and "CO 2 avoided".

Post-combustion capture

Post-combustion capture consists of treating exhaust gases on the output side of the PC or NGCC (see Figure 5 for the case of PC). As mentioned earlier, technologies based on chemical absorption appear to be best adapted to this separation. Other technologies, adsorption, membranes and cryogeny, are even less suitable for postcombustion capture than for pre-combustion capture, mainly for the following two reasons:

-a much lower partial pressure of CO 2 in post-combustion exhaust gases than in synthetic gas originating from a gasifier or a reformer: about 50 mbars in NGCC exhaust gases and 100 mbars in PC exhaust gases compared with 8 bars (for the Puertollano type IGCC) to more than 16 bars (for the Texaco IGCC-slurry and NGCC before reforming) in synthetic gas;

-the presence of larger quantities of dust, impurities such as SO x and NO x and incondensable gases, particularly oxygen (which do not exist or exist only in very small quantities in synthetic gas).

The choice of the absorbent is guided by the partial pressure of CO 2 in the gas to be treated. As mentioned above, the very low levels of CO 2 partial pressures in exhaust gases impose chemical absorption.

Chemical absorption (processes with amines, Benfield process with potassium carbonate) is an industrial technology and has been used for decades, but in the past it has only been used to treat very clean gas mixtures containing no or few impurities such as dust, SO x , NO x , oxygen (ammonia industry and fertilizer industry, separation of CO 2 from natural gas), or containing only very small quantities of them. Therefore, chemical absorption will have to satisfy two challenges before it can be applied to the capture of CO 2 in exhaust gases from coal power stations, firstly related to its strong energy demand for the regeneration of the absorbent (increasing with decreasing of CO 2 partial pressure), and secondly degradation of the absorbent by impurities contained in the exhaust gases to be treated. Degradation of chemical solvents will be treated subsequently in the chapter concerning technical limitations.

Oxy-combustion

In the previous sections, we described the importance of the partial pressure of CO 2 in the gas to be treated, for separation processes. The principal advantage of oxycombustion is that it increases very significantly the partial pressure of CO 2 in the exhaust gases from combustion, because it avoids the dilution of exhaust gases with nitrogen in air. Obviously, an air separation unit is necessary to provide almost pure oxygen to the boiler. A PC oxy-combustion diagram is shown in Figure 6. Combustion is made using pure oxygen (up to 97% purity), but in which a small amount of nitrogen and argon remains. A big part of the exhaust gases are recycled in the boiler to maintain the usual temperature levels of PC without capture. This avoids full resizing of the boiler and its associated exchangers. The flow of uncycled CO 2 still contains water vapor, impurities (particularly some NO x and SO x amounts that remain in the exhaust gas of scrubbing systems) and incondensable gases such as oxygen, nitrogen and argon.

These latter are originating from the ASU and parasite air entries due to the lack of seal of the PC cycle (combustion chamber, deduster, gas -gas heater, etc.). The content of CO 2 in these exhaust gases is of the order of 75% on wet gas. The next step is to condense the water and purify the CO 2 until 99% pure so that it can be transported in the supercritical state. The presence of incondensable gases in the CO 2 flow transported by pipeline in the supercritical state can cause vibrations and shock loads in the pipe, which can cause mechanical damage. However, no known study has attempted to specify critical concentrations of these incondensable gases. All that is agreed upon unanimously is the concentration of water and most works published on this subject agree upon a fixed limit of 20 ppm by mass (50 ppm by volume). Thus in our study, a dehydration system using triethylene glycol (TEG) followed by a cryogenic impurity separation device are integrated into the CO 2 compression / liquefaction step.

Comparison between different capture processes

The calculations (see Figure 7) show that the highest efficiency with capture is obtained for NGCC with post-combustion capture, with an efficiency of 50% compared with 60% without capture. The next highest is the oxy-combustion in PC, with an efficiency of almost 35% compared with 45% without capture, and then IGCC-Puertollano 2 with pre-combustion capture with an efficiency of the order of 33.5% compared with 44% without capture. The lowest efficiency is obtained with postcombustion capture in PC, equal to 30% which is 15 points less than PC without capture (if MEA is used). Therefore, from a purely energetic point of view without considering economic Figures, it would be recommended to only consider pre-combustion capture in IGCC, post-combustion in NGCC and oxy-combustion in PC. Nevertheless, postcombustion capture in PC, although its efficiency seems to be lower than oxycombustion PC, is now seen inevitable if it is required to be able to retrofit coal-fired power stations that will be built between now and 2020 (which accounts for more than 1000 GW). For NGCC, oxy-combustion is not a possibility for all current combustion turbines, their compression and expansion systems are not suitable for CO 2 as main working fluid; oxy-combustion of natural gas could only become technically viable if innovative cycles such as the Graz cycle are adopted, and provided that they can be brought into an industrialization phase in order to reduce the cost.

Concerning investment (see Figure 8), the least expensive technology comparatively to PC investment cost which is given 100 as reference, remains NGCC with or without capture, 40% of the PC for NGCC without capture and 83% for NGCC with post-combustion capture. PC and IGCC-slurry (GE / Texaco) are in second position at 169% for PC with oxy-combustion, 101% for IGCC-slurry without capture but only 164% for the IGCC-slurry with pre-combustion capture. The radiant type IGCC is more expensive than IGCC-slurry and PC, at 122% for the Puertollano type IGCC without capture and 185% for the pre-combustion option. However, it will be noted that the additional investment costs induced by capture are much higher for NGCC (110% greater than NGCC cost without capture) than for radiant type IGCC (52% greater than IGCC-300 cost without capture), IGCC-slurry (62% greater than IGCC-1200 cost without capture) or oxy-combustion in PC (69% greater than PC-1200 cost without capture).

The lowest production costs (see Figure 9) are obtained with oxy-combustion PC (148% of PC without capture) and IGCC-slurry with pre-combustion capture (154%).

The production cost of radiant type IGCC with capture in pre-combustion is of the same order of magnitude as NGCC with post-combustion capture (162%).

On the other hand, the lowests costs per tonne of CO 2 avoided are obtained with pre-combustion capture in IGCC-slurry (65% of the cost of CO 2 avoided in PC with post-combustion capture), oxy-combustion in PC (71%) and the radiant type IGCC with capture in pre-combustion (73%) (see Figure 10). The highest cost per tonne of CO 2 (234%) is obtained using pre-combustion capture in NGCC.

Limitations of the different capture processes

As mentioned above, in carrying out our studies, we obviously assumed that the processes and equipment used work as we would like them to do, although this remains to be demonstrated experimentally and on the industrial scale. In this chapter, without attempting to be exhaustive, we will summarize the assumptions that form limitations to the conclusions of our evaluations, limitations concerning technical and economic aspects.

Technical limitations

We have assumed that the specific problems that will be encountered in coal power stations with capture have been solved, although this is obviously not the case at the moment: problems remain with oxy-coal combustion boilers, hydrogen turbine for IGCC with CO 2 capture, degradation of amines, separation of incondensable gases in oxy-combustion (what about impurities in a cryogenic system?), etc. These main limitations are indicated in the table 1.

Economic limitations

The economic estimates presented in this balance are relevant for a comparison between the different systems, but their absolute values may vary significantly as a function of the cost of metals, the price of fuels, tension on the equipment market (availability of construction and supervision teams), etc. For example, prices of metals Similarly, if the discount rate changes, it will have a significant impact on all economic estimates: the investment cost, the production cost and the cost per tonne of CO 2 avoided. As we have seen, the fuel cost also has an important impact on the production cost and on the cost per tonne of CO 2 avoided, particularly for NGCC for which it represents more than 70% of the production cost. In some cases, our estimates are very similar to estimates made by our American and Canadian colleagues, although the structure (breakdown) is significantly different. Fuel, equipment and installation prices are usually lower in North America, but discount rates may be higher than in Europe [START_REF] Biggs | Economic Modeling of CO 2 Capture and Sequestration[END_REF][START_REF]Potential for improvements in gasification combined cycle power generation with CO 2 capture[END_REF][START_REF]Updated Cost and Performance Estimates for Fossil Fuel Power Plants with CO 2 Removal[END_REF].

Concerning IGCC, it is clear in our studies that dry pressurization of coal is one of the key elements that can significantly improve the technical and economic performances of this technology. Progress on dry coal pressurization pumps is necessary, to avoid firstly the complex lock systems in the case of a Puertollano type IGCC, and the mixture of coal with water in the case of the IGCC-slurry; the recent announcement about development of such a pump capable of achieving a pressure of 40 bars suggests a potential improvement for this type of technology.

Finally, the question about operation at low loads, at semi-base or at peak-load should be considered. In theory, all systems could operate at a minimum load of 50%

and for a number of hours corresponding to operation in semi-base or in peak-load.

However, efficiencies at low load are seriously degraded and production costs, that are already high for CO 2 capture operations, increase significantly if the power station does not operate at base load. Thus, for an annual operation of only 3750 hours instead of 7500 hours, the cost of an IGCC-slurry with capture increases by almost 60%, which is more than double the cost of the IGCC-slurry without CO 2 capture. The same calculation for PC gives a production cost with oxy-combustion capture increased by 63% for 3900 hours of operation per year, compared with the cost of production for 7800 hours of operation per year. The impact on the production cost of operation in semi-base for NGCC is lower than for IGCC and PC because the proportion of the investment in the production cost is lower, and the cost increases by 24% in NGCC with post-combustion capture when operating for 4000 hours per year instead of 8000 hours per year.

Conclusions

The technical and economic estimates presented in this work are not the only parameters in determining the choice of a system for the capture of CO 2 . Constraints related to resources such as fuel and water may also influence this choice. Therefore, it appears difficult to make a once-and-for-all decision about the "best CO 2 capture process"; however, the results of our studies suggest that pre-combustion capture by physical absorption (methanol) should be used for IGCC, oxy-combustion should be used for PC and post-combustion capture (amines) should be used for NGCC.

However, these recommendations are based on a number of assumptions that may be more or less "dependable" depending on the process. For example, capture processes are supposed to operate reliably, which remains to be demonstrated on an industrial scale, at least for post-combustion and oxy-combustion capture. On the other hand, precombustion capture on synthetic gas is industrially mature, but the IGCC system into which it must be integrated still has availability problems. The studies that we have carried out assume that the specific problems that we will encounter for coal-fired power stations with capture have been solved, which is not the case at the present time:

coal combustion boiler with oxygen, hydrogen turbine for IGCC with CO 2 capture, degradation of amines, separation of incondensable gases in oxy-combustion (and what about impurities in a cryogenic system?), etc. Finally, it is quite clear that the evaluation studies that we have carried out are no more than a first phase and must be continued with other more detailed pre-feasibility studies, particularly in engineering, to enable a

  type delivering 1200 MWe as gross power output IGCC-300: IGCC of radiant type delivering 300 MWe as gross power output NGCC: Natural Gas Combined Cycle NGCC-480: advanced NGCC delivering 480 MWe as gross power output PC: Pulverised coal power plant PC-1200: PC delivering 1200 MWe as gross power output HHV: High Heating Value (total calorific value of fuel) LHV: Low Heating Value (HHV less latent heat of the water of using dimethylether of polyethylene glycol (DMPEG)

  have increased continuously since 2002 -2003, to double by 2007 -2008, which obviously has a large impact on the final investment and production cost, but should not modify relative costs between different systems.

Figure 1 :

 1 Figure 1: the three CO 2 capture processes

Figure 2 Figure 4 : 2 Figure 5 Figure 7 :

 24257 Figure 2: "Captured CO 2 " and "CO 2 avoided" per kWh produced

Figure 8 : 2 captureFigure 9 : 2 capture

 8292 Figure 8: Investment cost of the different systems with and without CO 2

Cost per tonne of CO 2 avoided for the different CO 2 capture processes Cost of avoided CO2 relatively to PC (11% interest rate)

		'construction'	'fuel'	'O&M'
		250	192
	Cost of Electricity relatively to PC Cost of avoided CO2 relatively to PC	w/o capture IGCC-300 IGCC-1200 Without capture w/o capture NGCC-480 123 117 111 Pre-comb. Pre-comb. capture w/o PC-1200 IGCC-300 IGCC-Pre-comb. Pre-comb. 1200 100 163 154 With 85-90 % CO2 capture Pre-comb. Oxy-comb. NGCC-480 NGCC-480 174 Pre-comb. Oxy-comb. Oxy-comb. IGCC-300 IGCC-1200 NGCC-480 NGCC-480 PC-1200 Figure 10: 73 65 234 168 71 0 50 100 150 200	Oxy-comb. PC-1200 NGCC-Post-comb. 480 148 162 Post-comb. NGCC-480 130	Post-comb. PC-1200 165 Post-comb. PC-1200 100

Table 1 :

 1 The main limitations for studied systems

In our study, the efficiency of the Puertollano IGCC has been calculated using a conventional combined cycle. The efficiency could be better in the case of an advanced cycle (H cycle).