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Performance and optimization of an HTR cogeneration system
Nuclear Engineering and Design 251 (2012) 297–300
Contents lists available at SciVerse ScienceDirect
Nuclear Engineering and Design journal homepage: www.elsevier.com/locate/nucengdes
Performance and optimization of an HTR cogeneration system J.R. Geschwindt a,∗ , L.J. Lommers b , F.H. Southworth a , F. Shahrokhi a a b
AREVA, 3315 Old Forest Road, Lynchburg, VA 24501, USA AREVA, 2101 Horn Rapids Road, Richland, WA 99354, USA
a r t i c l e
i n f o
Article history: Received 17 January 2011 Received in revised form 12 September 2011 Accepted 12 September 2011
a b s t r a c t This paper assesses performance of a high temperature reactor (HTR) coupled with a Rankine cycle cogeneration plant which simultaneously produces moderate temperature steam and electricity for a process heat application. Understanding the trade-offs of configurations on the performance and complexity of an HTR cogeneration application will help further HTR commercialization. Results indicate that the trade-off between process steam and electricity production is nearly linear. For a 300 ◦ C process steam production temperature every 1 kg/s increase in steam production leads to a 1 MWe reduction in electricity production. For pure electricity production an acceptable cycle efficiency of 46% is achieved. When steam-to-steam reheat is added, cycle efficiency marginally improves to 46.2%, but low pressure turbine exhaust quality dramatically improves from 78% to 95%. The application of an HTR for a cogeneration plant appears feasible, but a more detailed extension of this analysis is required. Future work should include a more complete cogeneration plant with additional feedwater heaters, moisture separators, and high pressure and low pressure reboilers. © 2011 Elsevier B.V. All rights reserved.
1. Introduction A cogeneration plant is an important near-term application of a high temperature reactor (HTR). The moderate temperature process heat market is large. So, understanding the trade-offs of configurations on the performance of a cogeneration application will help further HTR commercialization. This medium temperature application provides a path to development of higher temperature HTR applications. The objective of this study is to understand trade-offs of different cogeneration configurations, such as reheat vs. no reheat and optimal steam extraction conditions to feed the reboiler and how these affect electricity/process steam production. A possible plant layout for the cogeneration configuration is shown in Fig. 1 below. A Rankine cycle steam plant is used because of its technical maturity and adequate cycle efficiency at these moderate temperatures. A steam generator (SG) in the primary helium loop transfers energy to the secondary steam side. The steam side can produce both electricity, via the turbine and generator set, and process heat via the reboilers. The reboilers provide steam on the tertiary side to supply heat to a process as it provides protection of the steam generator from any contaminants on the process side. High
∗ Corresponding author. Tel.: +1 434 832 4686. E-mail address: [email protected] (J.R. Geschwindt). 0029-5493/$ – see front matter © 2011 Elsevier B.V. All rights reserved. doi:10.1016/j.nucengdes.2011.10.029
pressure (HP) and low pressure (LP) reboilers provide process steam to process heat applications over a wide operating range. 2. Model description A Microsoft ExcelTM steady-state heat balance model was developed for a simplified cogeneration plant (shown in Fig. 2) to gain insight into possible cogeneration plant configurations. This simplified model eases analysis effort while still maintaining enough fidelity to get an understanding of the configuration trade-offs. 2.1. Assumptions/simplifications The following assumptions and simplifications have been made for the heat balance model in Fig. 2 as follows: (1) Steam properties were computed using (IAPWS, 1996). (2) 100% electrical and mechanical efficiency for generator and pumps. (3) 100% thermodynamic efficiency of pumps and turbines. (4) Steam-to-steam reheater effectiveness of 90%. (5) There are only two feedwater (FW) heaters. In reality there would be a train of FW heaters, typically five to eight FW heaters. (6) Open feedwater heaters are modeled (steam extraction mixes with feedwater). The actual plant would most likely use closed FW heaters with steam extraction condensate flowing back to the condenser. A closed feedwater heater system avoids the
298
J.R. Geschwindt et al. / Nuclear Engineering and Design 251 (2012) 297–300 Water/steam headers to other reactor modules Steam isolation valves Primary Loop
Steam turbine Generator
SG
Rx core
HP Process Steam/Water Circulator
LP Reboiler
Feedwater Heaters
LP Process Steam/Water
HP Reboiler
Condenser
He Water/steam
Process Condensate Return
Process Water Cleanup
Process water/steam
Makeup
Fig. 1. Generic cogeneration plant system configuration.
40
Steam-toSteam Reheater 10
11
12
13
13a
14
15
16 17
stage 2
stage 1
stage 3
stage 4 generator
3
50 (FW extraction)
30b SG 18a 30a 30c
30d
reboiler 18c 18b
2 41
1 FW Pump
22
21 booster pump 2
FW Heater 2
100a
From Process heat
20 FW Heater 1
19 booster pump 1
Condenser
100b
To Process heat
Fig. 2. Simplified cogeneration model featuring one reboiler and two FW heaters.
J.R. Geschwindt et al. / Nuclear Engineering and Design 251 (2012) 297–300
(7) (8) (9)
(10) (11) (12)
need for booster pumps between FW heaters, thereby increasing overall plant efficiency at the cost of larger FW heaters because there is no intimate mixing of the extraction steam and feedwater. Also, in a closed FW heater system the main FW pump can operate further upstream at lower operating temperatures (pumping cooler water). Steam-to-steam reheat heat exchanger (reheater) is assumed to have an effectiveness of 90%. Reheater modeled as a simple counterflow heat exchanger. This model contains only one reboiler with four possible extraction points supplying it. Only one extraction is used at a time. So depending on extraction conditions this reboiler can operate over a large temperature and pressure range. Reboiler is modeled as a simple counterflow heat exchanger. Reboiler effectiveness is 100%. Reboiler hot side exhaust is sent straight to the condenser. Actually, this exhaust energy could be used to make the entire plant more efficient depending on operating conditions. For instance, the reboiler exhaust could be sent to FW heaters before going to the condenser.
299
pressure differentials from the reboiler hot side to cold side (steam supply side to process steam side). 2.4. Model limitations (1) Only one steam extraction at a time is allowed to go to the reboiler. (2) The solver routine in Microsoft ExcelTM was not always robust enough to find a local optimum let alone a global optimum solution. Different initial guesses provided different “optimal” or converged solutions, which implies that a global optimum may not have been found for each case. Convergence was only problematic for the lower temperature process steam cases. Generally, though, the differences between these local optimums were minimal which gives confidence that a global optimum was achieved. (3) Some inflexibility in adjusting relative extraction locations of reheater and FW heaters. 3. Results
2.2. Fixed parameters The following parameters are fixed for the analysis: (1) 630 MWth SG heat duty. (2) 200 ◦ C SG inlet temperature (controlled by FW extraction and reheater flow). (3) 566 ◦ C SG outlet temperature. (4) 16.7 MPa SG outlet pressure. (5) 7.6 MPa SG steam side pressure drop. (6) Condenser pressure of 0.01 MPa. (7) 50 ◦ C process return water temperature. (8) Tertiary process steam pressure: 16.7 MPa for 500 ◦ C process (tertiary) steam conditions; set to saturation pressure for 100 ◦ C and 300 ◦ C process (tertiary) steam conditions (0.1 MPa and 8.6 MPa, respectively). (9) Process (tertiary) steam temperature (set to 100 ◦ C, 300 ◦ C, and 500 ◦ C for various runs). (10) Process flow rate (reboiler cold side flow) (different fixed values depending on desired mix of process heat/electricity production). 2.3. Optimized parameters For each case gross cycle electrical efficiency is maximized (given the above fixed values) by varying: (1) 3 turbine stage outlet pressures (4th stage is fixed at condenser pressure). (2) Reheater flow rate. (3) Extraction steam flow rate to FW heater. (4) Extraction steam flow rate to reboiler. (5) Extraction steam pressure to supply the reboiler. Differential pressure across the reboiler needs to be considered. The reboiler design is shell and tube which generally can withstand relatively high pressure differentials. Temperature differentials across the reboiler from hot side to cold side (thermal-stress) as well as temperature differentials in approach temperatures (required heat transfer area) need to be considered for the reboiler design. Reboiler operational issues need to be considered, in terms of the temperature differentials (approach temperatures) and
A range of operating conditions was considered from all electric to all process heat production, for three temperature levels of process steam production (reboiler tertiary side): 100 ◦ C, 300 ◦ C, and 500 ◦ C. For each of these three temperature levels, the reboiler load (flow rate to process heat system) was increased from zero (100% electricity production) to a near maximum flow rate (0% net electricity production) while attempting to optimize system parameters for each case. Therefore steam production rates up to 200 kg/s were reported at these temperature levels. In general, as reboiler load is increased, steam extraction flow rate and temperature (pressure) to the reboiler need to increase, thus reducing electricity production. Table 1 below shows key output for the three selected reboiler steam supply temperatures of 100 ◦ C, 300 ◦ C, and 500 ◦ C at varying reboiler loads. It should be noted that for the 100 ◦ C and 300 ◦ C cases, converged solutions (let alone optimal solutions) were increasing difficult to achieve as pure process heat production rates were approached (convergence discussed in Section 2.4). The net electrical efficiencies of the two “all electric” cases, cases 1 (reheat) and 2 (no reheat) in Table 1, are 46.2% and 46%, respectively. This comparison reveals that the steam-to-steam reheater adds about 0.2% net electric efficiency compared with no reheat. For cases 1 and 2 the LP turbine exit quality is 95% and 78%, respectively. Therefore it is not clear whether the small increase in efficiency justifies the use of a reheater, but the improvement in LP turbine steam quality is a clear advantage of the cycle with reheat. Reheat adds increased cost and complexity, so these trade-offs must be considered. For all other cases in Table 1, besides case 1, the reheater is not used or used very little. This could be due to several reasons such as the relative location of extraction point of the reheater steam supply vs. FW heater. Also, if additional FW heaters were used and the location of the reheater was optimized (relative to extraction points) then the reheater’s usefulness may improve in terms of increased cycle efficiency. Comparing cases 3 and 1 shows that to produce 100 kg/s of 500 ◦ C steam a reduction in electrical production of 130 MWe occurs (from 290 MWe to 160 MWe). Comparing cases 3 and 4, an additional 100 kg/s of 500 ◦ C steam production (100–200 kg/s) requires a reduction in electricity production of 160 MWe. About 1.4 MWe electricity production is given up for every 1 kg/s of 500 ◦ C superheated steam production at these conditions. Similar comparisons can be made when looking at other steam production temperatures. Comparing cases 1, 5, and 6 shows electricity production dropping off at about 1 MWe for every 1 kg/s of 300 ◦ C
300
J.R. Geschwindt et al. / Nuclear Engineering and Design 251 (2012) 297–300
Table 1 Reboiler steam and electricity production for several process steam temperatures. Case
1b 2b , c 3 4d 5 6 7 8 a b c d
Process steam supply conditions (reboiler process steam side outlet)
Steam extraction conditions (reboiler extraction side inlet)
Extraction to FW heater 1
Production rates
T (◦ C)
P (MPa)
Quality
P (MPa)
T (◦ C)
Flow rate (kg/s)
Flow rate (kg/s)
Reboiler process steam side flow rate (kg/s)
Process heat (reboiler heat duty) (MWth)
Net electricala (MWe)
NA NA 500 500 300 300 100 100
NA NA 17 17 8.6 8.6 0.1 0.1
NA NA 1.8 1.8 1 1 1 1
NA NA 12 16 3.4 3.7 1.3 2.2
NA NA 500 560 310 320 200 250
NA NA 98 190 18 180 24 180
44 59 59 48 59 59 59 57
NA NA 100 200 20 200 25 200
0 0 310 620 51 510 61 490
290 290 160 0 270 110 270 130
After deducting electricity to run pumps. 100% electricity production (no process heat). No reheat. 100% process heat production. Steam Production Vs. Electricity Production (for Several Process Steam Production Temperatures)
Net Electricity Production (MWe)
300
250
200 500°C
150
300°C 100°C
100
50
0 0
50
100
150
200
Steam Production (kg/sec)
Fig. 3. Trade-off of steam production and electricity production.
saturated steam production. Comparing cases 1, 7, and 8 reveals that on average 0.8 MWe production is given up for every 1 kg/s 100 ◦ C saturated steam production. Fig. 3 below shows the nearly linear relationship of net electricity generation vs. process heat production for the three process heat temperature levels considered (500 ◦ C, 300 ◦ C, and 100 ◦ C). 4. Conclusions/future work The trade-off between process steam production and corresponding electricity production is nearly linear, as Fig. 3 illustrates, for several process steam production temperature levels (100 ◦ C, 300 ◦ C, and 500 ◦ C). The average electricity to steam production trade-off was 1.43 MWe, 1 MWe, and 0.8 MWe for 500 ◦ C superheated steam, 300 ◦ C saturated steam, and 100 ◦ C saturated steam,
respectively, for a given unit (1 kg/s) increase in steam production rate. Also, comparing the first two cases from Table 1 reveals that the steam-to-steam reheater increases efficiency by only about 0.2%, but the steam quality at the LP turbine exit is greatly improved (95% vs. 78%) using the reheater. The application of an HTR for a cogeneration plant appears feasible, but a more detailed extension of this current analysis is needed. Any future work may want to include a more complete cogeneration plant, i.e. additional FW heaters, moisture separators, additional reboiler (HP and LP), and use of closed feedwater heating instead of open feedwater heating. Also, a closer study of reheat options may want to be made. The steam-to-steam reheater does not appear to improve cycle efficiency significantly, but does greatly improve LP turbine inlet quality conditions leading to better LP turbine performance. Reheat adds additional cost and complexity so the trade-offs must be weighed. The relative location of the reheater with the feedwater heaters could be made more flexible possibly allowing the reheater to provide a larger cycle efficiency gain. If reheat is chosen, steamto-steam reheat is the preferred choice because it allows the reactor module to be applied over a wide range of process heat applications. SG reheat will not be as flexible because several different SG designs may be needed to accommodate a range of process heat applications. Also, attempting a more robust, rigorous, and automated solution technique to finding a true global optimum solution for each case should be considered. Reference IAPWS, 1996, September. Release on the Formulation 1995 for the Thermodynamic Properties of Ordinary Water Substance for General and Scientific Use. The International Association for the Properties of Water and Steam, Frederica, Denmark.
Contents lists available at SciVerse ScienceDirect
Nuclear Engineering and Design journal homepage: www.elsevier.com/locate/nucengdes
Performance and optimization of an HTR cogeneration system J.R. Geschwindt a,∗ , L.J. Lommers b , F.H. Southworth a , F. Shahrokhi a a b
AREVA, 3315 Old Forest Road, Lynchburg, VA 24501, USA AREVA, 2101 Horn Rapids Road, Richland, WA 99354, USA
a r t i c l e
i n f o
Article history: Received 17 January 2011 Received in revised form 12 September 2011 Accepted 12 September 2011
a b s t r a c t This paper assesses performance of a high temperature reactor (HTR) coupled with a Rankine cycle cogeneration plant which simultaneously produces moderate temperature steam and electricity for a process heat application. Understanding the trade-offs of configurations on the performance and complexity of an HTR cogeneration application will help further HTR commercialization. Results indicate that the trade-off between process steam and electricity production is nearly linear. For a 300 ◦ C process steam production temperature every 1 kg/s increase in steam production leads to a 1 MWe reduction in electricity production. For pure electricity production an acceptable cycle efficiency of 46% is achieved. When steam-to-steam reheat is added, cycle efficiency marginally improves to 46.2%, but low pressure turbine exhaust quality dramatically improves from 78% to 95%. The application of an HTR for a cogeneration plant appears feasible, but a more detailed extension of this analysis is required. Future work should include a more complete cogeneration plant with additional feedwater heaters, moisture separators, and high pressure and low pressure reboilers. © 2011 Elsevier B.V. All rights reserved.
1. Introduction A cogeneration plant is an important near-term application of a high temperature reactor (HTR). The moderate temperature process heat market is large. So, understanding the trade-offs of configurations on the performance of a cogeneration application will help further HTR commercialization. This medium temperature application provides a path to development of higher temperature HTR applications. The objective of this study is to understand trade-offs of different cogeneration configurations, such as reheat vs. no reheat and optimal steam extraction conditions to feed the reboiler and how these affect electricity/process steam production. A possible plant layout for the cogeneration configuration is shown in Fig. 1 below. A Rankine cycle steam plant is used because of its technical maturity and adequate cycle efficiency at these moderate temperatures. A steam generator (SG) in the primary helium loop transfers energy to the secondary steam side. The steam side can produce both electricity, via the turbine and generator set, and process heat via the reboilers. The reboilers provide steam on the tertiary side to supply heat to a process as it provides protection of the steam generator from any contaminants on the process side. High
∗ Corresponding author. Tel.: +1 434 832 4686. E-mail address: [email protected] (J.R. Geschwindt). 0029-5493/$ – see front matter © 2011 Elsevier B.V. All rights reserved. doi:10.1016/j.nucengdes.2011.10.029
pressure (HP) and low pressure (LP) reboilers provide process steam to process heat applications over a wide operating range. 2. Model description A Microsoft ExcelTM steady-state heat balance model was developed for a simplified cogeneration plant (shown in Fig. 2) to gain insight into possible cogeneration plant configurations. This simplified model eases analysis effort while still maintaining enough fidelity to get an understanding of the configuration trade-offs. 2.1. Assumptions/simplifications The following assumptions and simplifications have been made for the heat balance model in Fig. 2 as follows: (1) Steam properties were computed using (IAPWS, 1996). (2) 100% electrical and mechanical efficiency for generator and pumps. (3) 100% thermodynamic efficiency of pumps and turbines. (4) Steam-to-steam reheater effectiveness of 90%. (5) There are only two feedwater (FW) heaters. In reality there would be a train of FW heaters, typically five to eight FW heaters. (6) Open feedwater heaters are modeled (steam extraction mixes with feedwater). The actual plant would most likely use closed FW heaters with steam extraction condensate flowing back to the condenser. A closed feedwater heater system avoids the
298
J.R. Geschwindt et al. / Nuclear Engineering and Design 251 (2012) 297–300 Water/steam headers to other reactor modules Steam isolation valves Primary Loop
Steam turbine Generator
SG
Rx core
HP Process Steam/Water Circulator
LP Reboiler
Feedwater Heaters
LP Process Steam/Water
HP Reboiler
Condenser
He Water/steam
Process Condensate Return
Process Water Cleanup
Process water/steam
Makeup
Fig. 1. Generic cogeneration plant system configuration.
40
Steam-toSteam Reheater 10
11
12
13
13a
14
15
16 17
stage 2
stage 1
stage 3
stage 4 generator
3
50 (FW extraction)
30b SG 18a 30a 30c
30d
reboiler 18c 18b
2 41
1 FW Pump
22
21 booster pump 2
FW Heater 2
100a
From Process heat
20 FW Heater 1
19 booster pump 1
Condenser
100b
To Process heat
Fig. 2. Simplified cogeneration model featuring one reboiler and two FW heaters.
J.R. Geschwindt et al. / Nuclear Engineering and Design 251 (2012) 297–300
(7) (8) (9)
(10) (11) (12)
need for booster pumps between FW heaters, thereby increasing overall plant efficiency at the cost of larger FW heaters because there is no intimate mixing of the extraction steam and feedwater. Also, in a closed FW heater system the main FW pump can operate further upstream at lower operating temperatures (pumping cooler water). Steam-to-steam reheat heat exchanger (reheater) is assumed to have an effectiveness of 90%. Reheater modeled as a simple counterflow heat exchanger. This model contains only one reboiler with four possible extraction points supplying it. Only one extraction is used at a time. So depending on extraction conditions this reboiler can operate over a large temperature and pressure range. Reboiler is modeled as a simple counterflow heat exchanger. Reboiler effectiveness is 100%. Reboiler hot side exhaust is sent straight to the condenser. Actually, this exhaust energy could be used to make the entire plant more efficient depending on operating conditions. For instance, the reboiler exhaust could be sent to FW heaters before going to the condenser.
299
pressure differentials from the reboiler hot side to cold side (steam supply side to process steam side). 2.4. Model limitations (1) Only one steam extraction at a time is allowed to go to the reboiler. (2) The solver routine in Microsoft ExcelTM was not always robust enough to find a local optimum let alone a global optimum solution. Different initial guesses provided different “optimal” or converged solutions, which implies that a global optimum may not have been found for each case. Convergence was only problematic for the lower temperature process steam cases. Generally, though, the differences between these local optimums were minimal which gives confidence that a global optimum was achieved. (3) Some inflexibility in adjusting relative extraction locations of reheater and FW heaters. 3. Results
2.2. Fixed parameters The following parameters are fixed for the analysis: (1) 630 MWth SG heat duty. (2) 200 ◦ C SG inlet temperature (controlled by FW extraction and reheater flow). (3) 566 ◦ C SG outlet temperature. (4) 16.7 MPa SG outlet pressure. (5) 7.6 MPa SG steam side pressure drop. (6) Condenser pressure of 0.01 MPa. (7) 50 ◦ C process return water temperature. (8) Tertiary process steam pressure: 16.7 MPa for 500 ◦ C process (tertiary) steam conditions; set to saturation pressure for 100 ◦ C and 300 ◦ C process (tertiary) steam conditions (0.1 MPa and 8.6 MPa, respectively). (9) Process (tertiary) steam temperature (set to 100 ◦ C, 300 ◦ C, and 500 ◦ C for various runs). (10) Process flow rate (reboiler cold side flow) (different fixed values depending on desired mix of process heat/electricity production). 2.3. Optimized parameters For each case gross cycle electrical efficiency is maximized (given the above fixed values) by varying: (1) 3 turbine stage outlet pressures (4th stage is fixed at condenser pressure). (2) Reheater flow rate. (3) Extraction steam flow rate to FW heater. (4) Extraction steam flow rate to reboiler. (5) Extraction steam pressure to supply the reboiler. Differential pressure across the reboiler needs to be considered. The reboiler design is shell and tube which generally can withstand relatively high pressure differentials. Temperature differentials across the reboiler from hot side to cold side (thermal-stress) as well as temperature differentials in approach temperatures (required heat transfer area) need to be considered for the reboiler design. Reboiler operational issues need to be considered, in terms of the temperature differentials (approach temperatures) and
A range of operating conditions was considered from all electric to all process heat production, for three temperature levels of process steam production (reboiler tertiary side): 100 ◦ C, 300 ◦ C, and 500 ◦ C. For each of these three temperature levels, the reboiler load (flow rate to process heat system) was increased from zero (100% electricity production) to a near maximum flow rate (0% net electricity production) while attempting to optimize system parameters for each case. Therefore steam production rates up to 200 kg/s were reported at these temperature levels. In general, as reboiler load is increased, steam extraction flow rate and temperature (pressure) to the reboiler need to increase, thus reducing electricity production. Table 1 below shows key output for the three selected reboiler steam supply temperatures of 100 ◦ C, 300 ◦ C, and 500 ◦ C at varying reboiler loads. It should be noted that for the 100 ◦ C and 300 ◦ C cases, converged solutions (let alone optimal solutions) were increasing difficult to achieve as pure process heat production rates were approached (convergence discussed in Section 2.4). The net electrical efficiencies of the two “all electric” cases, cases 1 (reheat) and 2 (no reheat) in Table 1, are 46.2% and 46%, respectively. This comparison reveals that the steam-to-steam reheater adds about 0.2% net electric efficiency compared with no reheat. For cases 1 and 2 the LP turbine exit quality is 95% and 78%, respectively. Therefore it is not clear whether the small increase in efficiency justifies the use of a reheater, but the improvement in LP turbine steam quality is a clear advantage of the cycle with reheat. Reheat adds increased cost and complexity, so these trade-offs must be considered. For all other cases in Table 1, besides case 1, the reheater is not used or used very little. This could be due to several reasons such as the relative location of extraction point of the reheater steam supply vs. FW heater. Also, if additional FW heaters were used and the location of the reheater was optimized (relative to extraction points) then the reheater’s usefulness may improve in terms of increased cycle efficiency. Comparing cases 3 and 1 shows that to produce 100 kg/s of 500 ◦ C steam a reduction in electrical production of 130 MWe occurs (from 290 MWe to 160 MWe). Comparing cases 3 and 4, an additional 100 kg/s of 500 ◦ C steam production (100–200 kg/s) requires a reduction in electricity production of 160 MWe. About 1.4 MWe electricity production is given up for every 1 kg/s of 500 ◦ C superheated steam production at these conditions. Similar comparisons can be made when looking at other steam production temperatures. Comparing cases 1, 5, and 6 shows electricity production dropping off at about 1 MWe for every 1 kg/s of 300 ◦ C
300
J.R. Geschwindt et al. / Nuclear Engineering and Design 251 (2012) 297–300
Table 1 Reboiler steam and electricity production for several process steam temperatures. Case
1b 2b , c 3 4d 5 6 7 8 a b c d
Process steam supply conditions (reboiler process steam side outlet)
Steam extraction conditions (reboiler extraction side inlet)
Extraction to FW heater 1
Production rates
T (◦ C)
P (MPa)
Quality
P (MPa)
T (◦ C)
Flow rate (kg/s)
Flow rate (kg/s)
Reboiler process steam side flow rate (kg/s)
Process heat (reboiler heat duty) (MWth)
Net electricala (MWe)
NA NA 500 500 300 300 100 100
NA NA 17 17 8.6 8.6 0.1 0.1
NA NA 1.8 1.8 1 1 1 1
NA NA 12 16 3.4 3.7 1.3 2.2
NA NA 500 560 310 320 200 250
NA NA 98 190 18 180 24 180
44 59 59 48 59 59 59 57
NA NA 100 200 20 200 25 200
0 0 310 620 51 510 61 490
290 290 160 0 270 110 270 130
After deducting electricity to run pumps. 100% electricity production (no process heat). No reheat. 100% process heat production. Steam Production Vs. Electricity Production (for Several Process Steam Production Temperatures)
Net Electricity Production (MWe)
300
250
200 500°C
150
300°C 100°C
100
50
0 0
50
100
150
200
Steam Production (kg/sec)
Fig. 3. Trade-off of steam production and electricity production.
saturated steam production. Comparing cases 1, 7, and 8 reveals that on average 0.8 MWe production is given up for every 1 kg/s 100 ◦ C saturated steam production. Fig. 3 below shows the nearly linear relationship of net electricity generation vs. process heat production for the three process heat temperature levels considered (500 ◦ C, 300 ◦ C, and 100 ◦ C). 4. Conclusions/future work The trade-off between process steam production and corresponding electricity production is nearly linear, as Fig. 3 illustrates, for several process steam production temperature levels (100 ◦ C, 300 ◦ C, and 500 ◦ C). The average electricity to steam production trade-off was 1.43 MWe, 1 MWe, and 0.8 MWe for 500 ◦ C superheated steam, 300 ◦ C saturated steam, and 100 ◦ C saturated steam,
respectively, for a given unit (1 kg/s) increase in steam production rate. Also, comparing the first two cases from Table 1 reveals that the steam-to-steam reheater increases efficiency by only about 0.2%, but the steam quality at the LP turbine exit is greatly improved (95% vs. 78%) using the reheater. The application of an HTR for a cogeneration plant appears feasible, but a more detailed extension of this current analysis is needed. Any future work may want to include a more complete cogeneration plant, i.e. additional FW heaters, moisture separators, additional reboiler (HP and LP), and use of closed feedwater heating instead of open feedwater heating. Also, a closer study of reheat options may want to be made. The steam-to-steam reheater does not appear to improve cycle efficiency significantly, but does greatly improve LP turbine inlet quality conditions leading to better LP turbine performance. Reheat adds additional cost and complexity so the trade-offs must be weighed. The relative location of the reheater with the feedwater heaters could be made more flexible possibly allowing the reheater to provide a larger cycle efficiency gain. If reheat is chosen, steamto-steam reheat is the preferred choice because it allows the reactor module to be applied over a wide range of process heat applications. SG reheat will not be as flexible because several different SG designs may be needed to accommodate a range of process heat applications. Also, attempting a more robust, rigorous, and automated solution technique to finding a true global optimum solution for each case should be considered. Reference IAPWS, 1996, September. Release on the Formulation 1995 for the Thermodynamic Properties of Ordinary Water Substance for General and Scientific Use. The International Association for the Properties of Water and Steam, Frederica, Denmark.