Article pubs.acs.org/EF
Investigation of Alternative Strategies for Integrating Postcombustion CO2 Capture to a Natural Gas Combined Cycle Power Plant Chechet Biliyok,† Roberto Canepa,‡ and Dawid P. Hanak*,† †
Combustion and CCS Centre, Cranfield University, Bedford MK43 0JN, United Kingdom Ansaldo Energia, Via Nicola Lorenzi 8, 16152 Genova, Italy
‡
ABSTRACT: With increasing urgency for global action toward climate change mitigation, this study is undertaken to evaluate integration options for post-combustion CO2 capture (PCC) on gas-fired power plants. High-fidelity models of a natural gas combined cycle power plant, a PCC plant, and a CO2 compression train are integrated for a 90% CO2 capture level. Three options to provide steam for solvent regeneration are explored: extracting steam from the intermediate-pressure (IP)/lowpressure (LP) crossover, using a gas-fired package boiler, and extracting steam from the LP drum. The effect of pressure losses because of steam extraction, a factor ignored in previous analyses, is also considered. The integrated plant net efficiency is 47.8, 40.4, and 44.9%, respectively, for the aforementioned scenarios. Next, supplementary firing of gas turbine exhaust is employed to generate an ample amount of steam to preserve plant net output under a sliding pressure scenario and meet solvent regeneration requirements. It is observed that the net plant efficiency converges to a value of 43.5% for the options considered.
1. INTRODUCTION 1.1. Background. In 2010, the global average temperature and specific humidity were observed to have risen by 0.5 °C and 4%, respectively, compared to 20th century averages, causing a dramatic increase in the frequency, intensity, and duration of floods, droughts, and heat waves globally.1 A recent report by the Intergovernmental Panel on Climate Change (IPCC)2 identifies greenhouse gas emissions, with 95% certainty, as the dominant cause of this global warming effect. The combustion of fossil fuels, to provide energy for a variety of human activities, is the chief source of these emissions. Coal and gas have met 80% of the new energy demand globally over the past decade3 and are projected to continue to do so.4 Hence, CO2 emissions, which amount to 80% of global greenhouse gas emissions,5 are expected to rise, causing a 6 °C increase in global temperatures by 2050 without firm global action to address this climate change.6 In most credible emission reduction scenarios, CO2 capture from large stationary emitters, such as power plants and refineries, accompanied by sequestration of CO2 underground [i.e., carbon capture and storage (CCS)] is expected to play a significant role, with the International Energy Agency (IEA)6 projecting that it would contribute to 17% of emission cuts by 2050. Because power plants currently account for a quarter of the global emissions,5 these are the prominent target for CCS implementation. In particular, the proliferation of hydraulic fracturing technology in the U.S. over the past few years, enabling the production of natural gas from shale formations, highlights the significance of gas in the global energy mix. In comparison to coal-fired power plants, a natural gas combined cycle (NGCC) power plant has the following advantages: (1) lower capital outlay, (2) about half of the emissions, i.e., CO2 per MWh, along with lower NOx and particulates, (3) lower environmental profile, i.e., less than a quarter of the footprint, (4) high operational flexibility and easily handling cyclic © 2015 American Chemical Society
loading, (5) smaller number of staff requirement and, hence, lower operating costs, and (6) reliability, leading to lower risk and, hence, cost of capital. With unconventional gas production leading to a glut and, hence, cheap gas in the U.S., there has been a substantial increase in the number of operational gas-fired power plants, in addition to a recent approval of liquefied natural gas (LNG) exports by the U.S. government.7 Thus, the use of gas for power generation is expected to increase globally, with the U.K. energy policy that is encouraging a dash for gas being a prime example of this. 1.2. Motivation. The integration of a post-combustion CO2 capture (PCC) plant in a NGCC power plant has been explored by a number of authors.8−20 In these studies, the steam that is used for solvent regeneration in the PCC plant is extracted from the intermediate-pressure (IP)/low-pressure (LP) turbine crossover, as shown in Figure 1. This approach is primarily driven by studies performed for the integration of PCC plants in coal-fired power plants, where this has been proven to be the most energy-efficient method of providing steam to the reboiler in the PCC plant.21 Jordal et al.22 also considered partial steam extraction from a LP superheater and partial integration of a PCC plant reboiler in the heat recovery steam generator (HRSG), both accompanied by steam extraction from the IP/LP crossover to meet the remaining regeneration duty requirement. Mores et al.23 investigated the effect of supplying the heat for solvent regeneration through an IP/LP steam supplemented with a LP steam generated in the auxiliary boiler on the CO2 emission mitigation cost and found that the cost increases with the amount of steam supplied from the boiler. Unfortunately, no effect on the process performance Received: April 15, 2015 Revised: June 15, 2015 Published: June 15, 2015 4624
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
Figure 1. Flow diagram of integrated NGCC, PCC, and compression plant.
integrating the PCC plant to the power plant increases complexity, which erodes plant reliability significantly. With a future energy mix expected to include an ample proportion of intermittent renewable energy, such as wind and solar, the ability to load-balance huge amounts of unpredictable supply with unpredictable demand via NGCC plants is vital. Therefore, using a PCC integration approach that maintains such an operational advantage at minimum efficiency losses, with easy accessibility and reduced complexity, is highly desirable. 1.3. Novelty. In this work, three options for integrating a PCC plant in a NGCC power plant are analyzed and compared, which mainly differ in how solvent regeneration duty is satisfied: (a) extracting steam from the IP/LP crossover (conventional approach), (b) using a gas-fired package boiler to generate steam solely (standalone boiler), and (c) extracting steam from the LP drum in the HRSG (alternate approach). The alternate approach of extracting steam from the LP drum potentially mitigates the operational challenges of IP/LP steam extraction. It has not been explored previously and is, therefore, rigorously analyzed in this study. The standalone boiler option is included in the analysis for comparison to a “best case” scenario of operational flexibility and minimal complexity. Supplementary firing (SF) of the gas turbine exhaust, to boost integrated plant output, is then explored under a retrofit scenario. A key feature of these integration studies is that the pressure drop because of steam extraction is accounted for using Stodola ellipse law to provide improved efficiency estimates compared to previous studies. 1.4. Outline. A brief description of model development is provided in section 2. In section 3, the approaches used in integrating PCC and compression to the NGCC power plant are described. Attention is given to the detailed analysis of the impact of integration resulting from the different approaches in section 4. Operational SF is investigated in section 5, along with a comparison of all scenarios considered. Finally, the
was analyzed. Hence, as the configuration of the steam cycle in a NGCC plant presents different opportunities of extracting steam from alternate locations, a rigorous analysis of such integration approaches is required, along with the option of using a separate gas-fired boiler to generate steam for solvent regeneration. It is imperative that the advantages of investing in a NGCC power plant as opposed to a coal-fired power plant (listed earlier) are maintained when a PCC plant is integrated to it. It has been shown that adding PCC and compression increases capital costs by 60% while also increasing operating costs substantially.16 In addition, the footprint of an integrated plant is expected to be much greater than that of the reference NGCC power plant. However, the approach through which integration is implemented will influence the operational flexibility of the plant, i.e., how quickly fluctuating power demands can be satisfied with ramp ups and downs in power output as well as plant operational range. Operational flexibility of the NGCC is a valuable feature that allows for easy adjustment of the power plant load to meet the current energy demand. This will be especially important in terms of not only the market competitiveness over the coal-fired power plants17 but also balancing the intermittent nature of increasing the share of the renewables in the energy portfolio. The IP/LP crossover location for steam extraction introduces significant operational challenges in the power plant because of the downstream impact on LP turbine.24 There are significant pressure losses caused by the reduction in the steam flow rate that results in additional efficiency losses, which are not usually accounted for in integration studies. The location also causes plant layout complications, because piping arrangement for the extracted steam may be convoluted, requiring numerous bends, which, in turn, introduces additional pressure drop that results in steam of a lower quality arriving at the reboiler. Because reboiler duty requirements remain unchanged, a higher quantity of steam would be needed to satisfy it, leading to a greater overall parasitic load on the power plant. Furthermore, 4625
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels conclusions drawn from this work and recommendations for future studies are explained in section 6.
Table 3. Compression Train Design and Operation data
2. MODEL DEVELOPMENT A detailed description of the models used in this study is provided in a previous publication.16 A high-fidelity 440 MW NGCC power plant model, which consists of an Ansaldo AE94.3A gas turbine and a three pressure level steam cycle with reheat, is built in Aspen HYSYS V8.0. This is a commercially available configuration25 based on a heavy-duty gas turbine, to which CO2 capture can be applied in the near future. Important model input and design data are given in Table 1.
description
value 15.69 974.5 43.76 1425 20.68 124.00 28.65 4.45 0.04 565 558 11 15 27
The PCC plant model, using monoethanolamine (MEA) solvent, is developed using the rate-based column to model the absorber and regenerator, with chemical reactions also taken into account. This model has been validated previously with pilot plant data.26 The model is then scaled up under pressure drop considerations,27 and details are provided in Table 2.
ṁ in = ṁ in0
Table 2. Alternate PCC Plant Design and Operations design data
operations/performance
absorber column number absorber diameter (m)
3 10
absorber packing height (m) regenerator column number regenerator diameter (m) regenerator packing height (m)
25
value 5 78.0−83.5 40 6000 99.5
3. PROCESS INTEGRATION 3.1. Conventional Integration Approach (IP/LP Crossover Steam Extraction). This integration procedure is described in a previous publication16 and shown in Figure 1. There are four key integration points. First, the exhaust gas is pretreated to remove NOx gases, and its temperature is reduced to 40 °C, before it is fed to the PCC absorber. It is assumed that oxygen inhibitors are used to limit MEA solvent degradation. Second and crucially, steam for solvent regeneration is extracted from the IP/LP crossover at 4.5 bar pressure via a throttle valve to limit pressure losses, with an attemperator used to control the temperature by spraying condensate to ensure that the temperature remains just above saturation. Third, with pressure losses occurring over the transfer line and the reboiler tubes, it is assumed that the steam condenses at 3 bar (at a temperature of 134 °C) and the condensate is returned to the power plant condenser. Lastly, CO2 from the regenerator is sent to the compression train, where it is compressed to its supercritical state. To quantify the reduction in the power generated because of pressure losses caused by the steam extraction, the Stodola ellipse law28 is used to determine a new IP/LP crossover pressure. A simplified form of the law, which was presented by Xu et al.,29 is implemented in the model
Table 1. NGCC Plant Input and Design Data fuel gas flow rate (kg/s) fuel lower heating value (kJ/mol) air/gas combustion ratio (wt) turbine inlet temperature (°C) gas turbine pressure ratio HP turbine inlet pressure (bar) IP turbine inlet pressure (bar) LP turbine inlet pressure (bar) condenser pressure (bar) superheated steam temperature (°C) reheated steam temperature (°C) HRSG minimum approach (°C) ambient temperature (°C) cooling water exit temperature (°C)
description number of compressors compressor efficiency range (%) aftercooler exit temperature (°C) compressor rotational speed (rpm) CO2 purity (wt %)
90.00 0.2700
1
capture level (wt %) lean loading (mol of CO2/mol of MEA) rich loading (mol of CO2/mol of MEA) flue gas inlet temperature (°C)
9
absorber pressure (bar)
1.013
15
regenerator pressure (bar)
1.500
pin 2 − pout 2 0 2 pin0 2 − pout
Tin0 Tin
(1)
where min is the steam inlet mass flow rate, pin is the steam inlet pressure, Tin is the steam inlet temperature, pout is the steam outlet pressure, and the superscript 0 indicates parameters at the initial conditions. 3.2. Standalone Boiler for Solvent Regeneration. As opposed to extracting steam from the power plant for solvent regeneration in the PCC plant, a gas-fired package boiler is introduced to generate steam to meet the reboiler requirements, eliminating one integration point and leaving steam flow rates in the power plant unchanged. Natural gas of the same composition, and, hence, the same heating value that is fired in the gas turbine is used in the boiler. Boiler specifications and performance are given in Table 4. Saturated LP steam is produced for solvent regeneration. The hot exhaust gas exiting the boiler is used to preheat the boiler feedwater to a
0.5075 40.00
A compression train, comprising centrifugal compressors, aftercoolers, and scrubbers, is also sized and used to compress the captured CO2 to 110 bar, where it is at a supercritical state. A maximum fluid head of 3050 m is enforced at each compression stage. Additionally, a maximum compressor discharge temperature of 120 °C is imposed, which then ensures that the number of stages in a single compressor without intercooling is limited to 2. The design and operation data of the compression train are listed in Table 3. A reduction reactor for removing oxygen and a molecular sieve for CO2 dehydration for conditioning CO2 for pipeline transport are added. Finally, a pump capable of boosting the supercritical/dense-phase CO2 pressure to 175 bar is also provided.
Table 4. Boiler Specifications and Performance
4626
description
value
boiler thermal efficiency (%) excess air (%) fuel gas flow rate (kg/s) boiler exhaust gas temperature (°C) boiler exhaust gas CO2 content (mol %) steam pressure (bar)
82.0 10.0 5.51 247.6 9.01 4.5
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
Figure 2. Flow diagram of alternate integrated NGCC, PCC, and compression plant.
temperature just below saturation, boosting efficiency to about 90%, on the basis of a lower heating value (LHV). Finally, the exhaust from the boiler feedwater preheater/economizer is combined with the HRSG exhaust and sent to the desulfurisation unit and, eventually, to the PCC plant. A combined exhaust gas stream is considered to avoid the need of an additional capture plant (albeit a smaller plant) dedicated to the boiler. 3.3. Alternate Steam Cycle Integration (LP Drum Steam Extraction). Similar to the conventional approach, there are four key integration points for the proposed alternate approach. The difference is that steam for solvent regeneration is drawn from the LP drum of the HRSG, as opposed to the crossover of the IP and LP turbines (Figure 2). The steam is slightly above its saturation temperature at a pressure of 4.5 bar. To generate an adequate amount of LP steam in the HRSG for solvent regeneration, less high-pressure (HP) and IP steam is produced to allow for ample thermal energy in the exhaust gas to reach the LP section of the HRSG. The implication of this is that there is less HP and IP steam entering the steam turbines, which results in less power being generated from the plant. Under this scenario, a sliding pressure control is implemented, which results in a different pressure distribution in the steam cycle. This change in pressure levels is quantified by the Stodola ellipse law, as described in section 3.1; hence, the impact on efficiency that results from such a large flow rate variation is rigorously addressed. In altering the steam cycle operation to generate more LP steam, the tube arrangement in the HRSG remains unchanged. However, additional economizer tubes for the LP section are added to the end of the HRSG (a common practice), because more heat exchange area is needed, along with a larger/an additional LP steam drum to meet the requirements of the PCC plant reboiler.
Table 5. Process Performance Comparison
plant net output (MW) power loss (%) plant net efficiency (%) cooling water (tonne/s) cooling water rise (%) exhaust gas flow rate (kg/s) exhaust gas CO2 content (%) HRSG gas outlet temperature (°C) total steam (kg/s) HP steam produced (kg/s) reboiler steam rate (kg/s) LP turbine steam rate (kg/s) HP steam pressure (bar) LP steam pressure (bar) absorber L/G ratio solvent circulation rate (kg/s) duty/CO2 captured (kJ/kg) PCC plant demand (MW) CO2 capture rate (kg/s) compression power (MW) net emission (kg of CO2/MWh)
4. DISCUSSION OF RESULTS From Table 5, it is clear that using a standalone boiler to generate steam for solvent regeneration introduces the lowest parasite load among the three options considered. For the PCC plant design employed, plant net output drops by 17.4, 5.7, and 4627
NGCC plant only
conventional integration
standalone boiler
alternate integration
440.6
364.1
415.7
342.0
59.62
17.36 47.81
5.65 40.40
22.38 44.92
7.72
9.37
15.01
9.88
21.37
94.43
27.98
693.6
693.6
800.8
693.6
3.99
3.99
4.67
3.99
99.5
130.5
107.2
115.0
103.8 76.22
106.6 75.6
213.2 76.22
133.2 39.6
71.6
109.4
83.9
103.8
35.42
103.8
48.61
124.0
124.0
124.0
63.2
4.45
1.52
4.45
2.13
1.48 812.7
1.72 1086
1.47 800.9
4634
4599
4700
6.11
7.16
6.11
38.76
52.33
38.75
13.37
18.04
13.36
42.1
51.6
45.0
354.5
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
tively. This is due to the 35% additional gas consumed in the boiler. In conclusion, the cooling water demand when a standalone boiler is used is almost double the reference power plant requirement, a summation of the individual condensation duties of the power, PCC, and compression plants. It is only 30 and 38% greater when the conventional and alternate integration approaches are employed, respectively, because substantial condensation occurs in the PCC plant reboiler. The demand for the alternate approach is greater as a result of a larger power plant condenser load, because there is more steam at the LP turbine outlet.
22.4% for the conventional integration, standalone boiler, and alternate integration scenarios, respectively. This is because no steam is taken from the steam cycle when a standalone boiler is used, unlike in the other two scenarios. More importantly though is net efficiency of the plant, with respect to gas LHV, which is estimated to be 47.8, 40.4, and 44.9% for the aforementioned scenarios, respectively. Using the standalone boiler results in such a low efficiency because of the additional gas burnt in the boiler, which is 35% of the gas consumed by the gas turbine. Although the efficiency (with respect to LHV) of regenerating solvent with steam produced in the boiler approaches 90%, none of this steam is used for power generation. Hence, the plant output remains high at a low efficiency, because only the compressor, gas blower, and solvent pump power demands account for the parasitic load on the power plant. On the other hand, the conventional and alternate approaches to integration require no additional gas consumption, but the conventional approach performs better in both net output and efficiency. This is a consequence of the amount of HP steam (higher quality) available for power generation in the HP turbine. Only about half of the HP steam produced via the conventional approach is generated in the alternate approach, although more steam is generated overall. Altering the HRSG operating parameters to generate more LP steam for solvent regeneration comes at the expense of HP steam that is used for power regeneration. The extraction of LP steam also results in a pressure drop of steam fed to the turbines. Because LP steam is extracted from the IP/LP crossover pipe in the conventional approach, the pressure at the LP turbine inlet drops to 1.52 bar, amounting to an additional 1% efficiency loss compared to the case when such a drop is not taken into account. For the alternate approach, the reduced steam flow rate in a sliding pressure operation results in inlet pressures of 63.29, 14.93, and 2.13 bar to the HP, IP, and LP turbines. Under the same PCC plant configuration and operating parameters, the reboiler duty requirement is the same for the conventional and alternate integration scenarios, yet more steam is required for solvent regeneration in the alternate integration. This is as a result of the temperatures at which the 4.5 bar steam is extracted, because superheated steam is extracted at 302 °C from the IP/LP crossover pipe in the conventional approach, while saturated steam is extracted at 148 °C from the LP steam drum in the alternate approach. A minor benefit from this alternate steam extraction is a more efficient heat transfer in the HRSG, as evidenced by the lower temperature of the exhaust gas. The standalone boiler scenario requires a higher L/G ratio to meet a 90% capture level, because of the higher CO2 concentration in the gas, which is a mixture of exhaust gases from the HRSG and the boiler with CO2 concentrations of 3.99 and 9.01%, respectively. This also results in less energy required to liberate 1 kg of captured CO2 from the solvent than in the other two scenarios, because of higher mass transfer in the absorber.16 In addition, a greater CO2 capture rate is also achieved, with higher affiliated compression and solvent circulation duties. The compression train capacity is sufficient for the increased flow rate of captured CO2, although it approaches its maximum capacity. Finally, a higher net specific emission of 52 kg of CO2 for each MWh of power generated is obtained in comparison to values of 41 and 45 kg for the conventional and alternate approaches to integration, respec-
5. SUPPLEMENTARY FIRING AS AN OPERATIONAL STRATEGY 5.1. Considerations. As explained in the previous section, the reason behind lower efficiency of the alternate approach
Figure 3. SF of exhaust gas in integrated plant operations.
Figure 4. CO2 concentration in exhaust gas versus SF rate.
proposed in this study is the 48% fall in the amount of HP steam generated in comparison to the reference NGCC, which is a result of altering the HRSG operating parameters to generate more LP steam. Therefore, the performance of the alternate approach can be improved by implementing measures to increase the heat available for HP steam generation. SF, while rare in NGCC power plants in the U.K., is sometimes used in combined cycle co-generation applications, where steam demand varies or power boosts are required. Its application in an integrated NGCC−PCC facility has to be 4628
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
Figure 8. HP, IP, and LP versus SF rate.
Figure 5. Net power output versus SF rate.
Figure 9. Net specific emission versus SF rate.
Figure 6. Plant efficiency versus SF rate.
Figure 7. Steam generated versus SF rate.
Figure 10. Cooling water demand versus SF rate.
investigated for efficiency and economic advantages. Because the integration of PCC and compression to a NGCC power plant results in reduced output as a result of additional steam requirements and parasitic loads, an alternative to separate package boilers for producing steam for solvent regeneration while maintaining output is to use SF. If this proves viable, with minimal efficiency losses, such an approach would be particularly attractive for retrofit scenarios, which can also use the alternate integration configuration. SF has been previously considered under a design scenario,14,16 where the HRSG is redesigned to extract more
thermal energy from the exhaust gas. As the amount of additional gas being fired is increased, the pressure of the steam being generated could be increased. In this analysis, however, steam pressures and the HRSG tube arrangement are unchanged but more LP economizer tubes are added to the end of the HRSG, along with a larger/an additional LP steam drum, as described for the alternate integration approach. The objective of the operational SF is to return the steam cycle to its full capacity while, at the same time, providing enough LP steam to meet reboiler duty requirements for solvent regeneration in the PCC plant. 4629
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
Figure 14. Capture rate and compression duty as a function of the SF rate.
Figure 11. Exhaust gas temperature versus SF rate.
the excess oxygen. (4) A minimum approach temperature of 11 °C is maintained in evaporators. (5) Pressure drops are constant in the HRSG tubes. Although ample oxygen remains in the turbine exhaust gas for higher SF rates, the amount of gas fired in the burner is limited to 4 kg/s, about 25% of the gas that is burnt in the gas turbine combustor. This ensures that temperatures at the HRSG inlet remain below 800 °C to mitigate thermal stress on HRSG tubes. The exhaust gas oxygen concentration falls from 12.4 to 10.3% at a SF rate of 4 kg/s. The flow rate of the exhaust gas exiting the HRSG increases marginally; however, its CO2 concentration increases significantly, as illustrated in Figure 4. The compression train is easily able to handle the increased flow rate of captured CO2. 5.2. Discussion of Results. In Figure 5, as expected, it is observed that SF boosts the output of the integrated plant under both approaches of integration, at a rate that is proportional to the amount of additional gas fired, i.e., SF rate. However, Figure 6 reveals that net plant efficiency falls with an increasing SF rate for both approaches. SF is more beneficial under the alternate integration approach, because for every kilogram of additional gas fired in the burner, more power is generated with smaller efficiency losses compared to the conventional approach. As a result, at a SF rate of 3.1 kg/s, both integration approaches produce the same output of 402 MW at 44% net efficiency. This is a consequence of the operational objective of SF, to produce enough steam to simultaneously return the steam cycle at its full capacity and meet reboiler duty requirements for solvent regeneration. As seen in Figure 7, an increasing SF rate results in an increasing HP steam generation in the alternative integration approach, while HP steam generation is maintained at the full-load HP turbine capacity in the conventional approach. As the amount of HP steam generated increases, the inlet pressures into the turbines also increase, as shown in Figure 8. LP steam generation increases under both approaches, because more steam is required to meet the reboiler duty required to regenerate the solvent from the increasing amount of CO2 being captured. Also, it is inferred from Figure 7 that the rate of increase for LP steam generation is slightly greater for the conventional integration approach, with the additional LP steam sent to the LP turbine to replace what is drawn from the IP/LP crossover pipe. In the end, more LP steam is generated in the alternate approach. As explained earlier, this is due to the temperature at which steam is extracted to meet reboiler duty requirements, with saturated steam drawn from
Figure 12. Solvent circulation as a function of the SF rate.
Figure 13. Reboiler duty as a function of the SF rate.
Therefore, SF is implemented (Figure 3) under unchanging operating conditions for the conventional and alternate integration approaches, with the additional thermal energy being used to increase steam generation. This would allow for operating the HRSG closer to its design conditions by restoring the steam pressure levels in the system, particularly in the alternate approach. The gas is fired in a burner located in the gas turbine−HRSG connecting duct, under the following assumptions: (1) Complete combustion of additional natural gas is reached because of the excess oxygen available. (2) There is negligible energy loss to the environment because of the burner location. (3) Flame stabilization is achieved because of 4630
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
Figure 15. Net plant efficiency losses because of integration.
Assuming that all of the fuel used in an integrated plant is available for power generation at the baseline efficiency of the reference NGGC plant, efficiency losses (on the basis of gas LHV) in the two SF scenarios with a SF rate of 3.1 kg/s are then compared to the cases explored in the previous sections. For clarity, the six distinct cases considered are as follows: case 1, NGCC plant only; case 2, integrated NGCC−PCC with IP/ LP crossover extraction (conventional); case 3, integrated NGCC−PCC using a standalone package boiler; case 4, integrated NGCC−PCC with LP drum extraction (alternate); case 5, integrated NGCC−PCC with IP/LP crossover extraction (conventional) plus SF; and case 6, integrated NGCC−PCC with LP drum extraction (alternate) plus SF. It is clear from Figure 15 that solvent regeneration energy requirement remains the dominating parasitic load on a power plant and must be reduced to improve integrated plant performance.
the LP steam drum and superheated steam taken from the IP/ LP crossover in the alternative and conventional approaches, respectively. A similar convergence trend is observed for the net specific emission (Figure 9), cooling water demand (Figure 10), and exhaust gas temperature (Figure 11). Although the flue gas CO2 concentration is the same for both, irrespective of the approach used (Figure 4), the specific emission rises with an increasing SF rate at a faster rate for the conventional approach than for the alternate approach, converging at a value of 46 g of CO2/MWh at a SF rate of 3.1 kg/s. Likewise, at a SF rate of 4 kg/s, the difference in cooling water requirements between the two approaches vanishes from an initial value of 650 kg/s with no SF, because of the narrowing difference in power plant condensation duty. Finally, the exhaust gas temperatures narrow to within 5 °C for the two integration approaches at a SF rate of 4 kg/s, with the alternate approach attaining 84 °C, an appropriate level to avoid low-temperature corrosion, and is a result of comparable heat-transfer efficiency from the increased saturated LP steam generation. As more heat is available to the LP economizer and evaporator sections of the HRSG, additional saturated LP steam is generated in the alternate approach compared to the conventional approach, where all generated LP steam is superheated. This explains the slight deviation after a SF rate of 3.1 kg/s observed in Figure 11 and is also the cause of similar minor slope changes observed for the alternate approach in Figures 5 and 6. To maintain a 90% capture level as the CO2 concentration increases with an increasing SF rate, the solvent circulation rate is increased at a constant lean loading, subsequently increasing the L/G ratio, as illustrated in Figure 12. With an increased solvent circulation and CO2 capture rate, the duty required for solvent regeneration also increases. However, it is observed in Figure 13 that as the SF rate increases, less steam is required to liberate 1 kg of CO2 from the solvent. This is due to the increasing CO2 concentration in the exhaust, which is known to enhance capture efficiency.16 Finally, as the CO2 capture rate increases with the SF rate, the compression duty proportionally increases to compress the higher amount of captured CO2 (Figure 14). The interaction between the falling steam requirement per kilogram of CO2 solvent regeneration and the increasing compression requirement explains the minor oscillations in net specific emissions with an increasing SF rate, as observed in Figure 9.
6. CONCLUSIONS AND RECOMMENDATIONS The study was carried out to evaluate options for integrating a NGCC power plant, a PCC plant, and a CO2 compression train. High-fidelity models of a 440 MW power plant, a PCC plant, and a compression train were integrated for a 90% CO2 capture level. As opposed to the conventional IP/LP crossover steam extraction for solvent regeneration, two other options are explored, using a standalone boiler to produce steam and an alternate steam extraction from the LP steam drum. These two approaches are expected to provide operational flexibility and avoid plant layout problems, which are difficulties that have been identified in the conventional approach to integration. The effect of pressure losses because of steam extraction are also taken into account. For the PCC plant design used, integrated plant output is observed to drop by 16, 6, and 22% for the conventional, standalone boiler, and alternate integration scenarios, respectively. However, crucially, net efficiency is 47.8, 40.4, and 44.9% for the aforementioned options, a consequence of the additional gas burned in the boiler, which keeps net output high but erodes efficiency. Net output is lowest in the alternate approach as a result of reduced HP steam generated, because thermal energy is diverted to produce additional LP steam to meet the reboiler duty for PCC solvent regeneration. Furthermore, cooling water demands increase for all three options, with net specific emissions of 41, 52, and 45 g of CO2 per MWh. 4631
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels
(7) Galuszka, P. U.S. Gears Up To Be a Prime Gas Exporter; The International Herald Tribune: New York, Oct 1, 2013. (8) Ciferno, J. P.; Litynski, J. L.; Plasynski, S. I. DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap; National Energy Technology Laboratory (NETL): Pittsburgh, PA, 2010; http://www. netl.doe.gov/technologies/carbon_seq/refshelf/CCSRoadmap.pdf (accessed Aug 2011). (9) Berstad, D.; Arasto, A.; Jordal, K.; Haugen, G. Parametric study and benchmarking of NGCC, coal and biomass power cycles integrated with MEA-based post-combustion CO2 capture. Energy Procedia 2011, 4, 1737−1744. (10) Botero, C.; Finkenrath, M.; Bartlett, M.; Chu, R.; Choi, G.; Chinn, D. Redesign, optimization, and economic evaluation of a natural gas combined cycle with the best integrated technology CO2 capture. Energy Procedia 2009, 1 (1), 3835−3842. (11) Amrollahi, Z.; Ystad, P. A. M.; Ertesvåg, I. S.; Bolland, O. Optimized process configurations of post-combustion CO2 capture for natural-gas-fired power plantPower plant efficiency analysis. Int. J. Greenhouse Gas Control 2012, 8, 1−11. (12) Sipöcz, N.; Tobiesen, F. A. Natural gas combined cycle power plants with CO2 captureOpportunities to reduce cost. Int. J. Greenhouse Gas Control 2012, 7, 98−106. (13) Peeters, A. N. M.; Faaij, A. P. C.; Turkenburg, W. C. Technoeconomic analysis of natural gas combined cycles with postcombustion CO2 absorption, including a detailed evaluation of the development potential. Int. J. Greenhouse Gas Control 2007, 1 (4), 396−417. (14) Li, H.; Ditaranto, M.; Yan, J. Carbon capture with low energy penalty: Supplementary fired natural gas combined cycles. Appl. Energy 2012, 97, 164−169. (15) Canepa, R.; Wang, M.; Biliyok, C.; Satta, A. Thermodynamic analysis of combined cycle gas turbine power plant with postcombustion CO2 capture and exhaust gas recirculation. Proc. Inst. Mech. Eng., Part E 2013, 227 (2), 89−105. (16) Biliyok, C.; Yeung, H. Evaluation of natural gas combined cycle power plant for post-combustion CO2 capture integration. Int. J. Greenhouse Gas Control 2013, 19, 396−405. (17) Sanchez Fernandez, E.; Goetheer, E. L. V.; Manzolini, G.; Macchi, E.; Rezvani, S.; Vlugt, T. J. H. Thermodynamic assessment of amine based CO2 capture technologies in power plants based on European Benchmarking Task Force methodology. Fuel 2014, 129, 318−329. (18) Lindqvist, K.; Jordal, K.; Haugen, G.; Hoff, K. A.; Anantharaman, R. Integration aspects of reactive absorption for post-combustion CO2 capture from NGCC (natural gas combined cycle) power plants. Energy 2014, 78, 758−767. (19) Canepa, R.; Wang, M. Techno-economic analysis of a CO2 capture plant integrated with a commercial scale combined cycle gas turbine (CCGT) power plant. Appl. Therm. Eng. 2015, 74, 10−19. (20) Xiaobo, L.; Meihong, W.; Jian, C. Heat integration of natural gas combined cycle power plant integrated with post-combustion CO2 capture and compression. Fuel 2015, 151, 110−117. (21) Lucquiaud, M.; Gibbins, J. Effective retrofitting of postcombustion CO2 capture to coal-fired power plants and insensitivity of CO2 abatement costs to base plant efficiency. Int. J. Greenhouse Gas Control 2011, 5 (3), 427−438. (22) Jordal, K.; Ystad, P. A. M.; Anantharaman, R.; Chikukwa, A.; Bolland, O. Design-point and part-load considerations for natural gas combined cycle plants with post combustion capture. Int. J. Greenhouse Gas Control 2012, 11, 271−282. (23) Mores, P. L.; Godoy, E.; Mussati, S. F.; Scenna, N. J. A NGCC power plant with a CO2 post-combustion capture option. Optimal economics for different generation/capture goals. Chem. Eng. Res. Des. 2014, 92 (7), 1329−1353. (24) Lawal, A.; Wang, M.; Stephenson, P.; Obi, O. Demonstrating full-scale post-combustion CO2 capture for coal-fired power plants through dynamic modelling and simulation. Fuel 2012, 101, 115−128. (25) Gas Turbine World. GTW Handbook; Pequot Publishing: Guilford, CT, 2012; Vol. 29.
As opposed to using a standalone boiler to maintain integrated plant output, SF is implemented with the objective of producing an adequate amount of steam to return the steam cycle of the power plant to its full capacity while still meeting reboiler duty requirements for solvent regeneration. It is observed that the net output, plant efficiency, net specific emission, and cooling water requirements converge to the same value for both conventional and alternate integration approaches, with an increasing SF rate. At a SF rate of 3.1 kg/s gas, which is a 24% increase on the reference NGCC plant full load, net output for both integration approaches converge to 402 MW. This proves that, under a retrofit scenario, the alternate integration strategy of steam extraction from the LP drum is viable, with operational and plant layout benefits, when it is implemented with SF. To improve integrated plant performance further when the alternate approach is used, two recommendations are made. First, jet pumps/ejectors should be employed to extract steam from the HP steam drum and combine it with steam from the LP drum. This means that the HP steam can be used to meet PCC plant reboiler duty, resulting in the generation of more HP and less LP steams, altering the HP/LP steam ratio in a manner that increases net plant output. Second, a co-generation configuration, where the PCC plant reboiler is integrated into the HRSG, would also be beneficial to integrated plant net output, particularly with SF implementation.
■
AUTHOR INFORMATION
Corresponding Author
*E-mail: d.p.hanak@cranfield.ac.uk. Notes
The authors declare no competing financial interest.
■
ABBREVIATIONS CCS = Carbon Capture and Storage HP = High Pressure HRSG = Heat recovery Steam Generator IP = Intermediate Pressure L/G = Liquid to Gas LP = Low Pressure MEA = Monoethanolamine NGCC = Natural Gas Combined Cycle PCC = Post-combustion CO2 Capture SF = Supplementary Firing
■
REFERENCES
(1) Miller, P. Weather gone wild. National Geographic Magazine; National Geographic Society: Washington, D.C., Sept 2012. (2) Intergovernmental Panel on Climate Change (IPCC). Summary for policymakers. Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change; Cambridge University Press: Cambridge, U.K., 2013. (3) International Energy Agency (IEA). Clean Energy Progress Report; IEA: Paris, France, 2011. (4) U.S. Energy Information Administration (EIA). International Energy Outlook; EIA: Washington, D.C., 2011; DOE/EIA-0484. (5) World Resources Institute. World GHG Emissions Flow Chart (Sankey Diagram); World Resources Institute: Washington, D.C., 2008; http://www.wri.org/chart/world-greenhouse-gas-emissions2000 (accessed Aug 2011). (6) International Energy Agency (IEA). Technology Roadmap Carbon Capture and Storage; IEA: Paris, France, 2013. 4632
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
Article
Energy & Fuels (26) AspenTech. Rate-Base Model of the CO2 Capture Process by MEA Using Aspen Plus; AspenTech: Burlington, MA, 2008; Knowledge Base ID 122271, http://support.aspentech.com/ (accessed Oct 2012). (27) Kister, H. Z.; Scherffius, J.; Afshar, K.; Abkar, E. Realistically predict capacity and pressure drop for packed columns. Distillation 2007, 28−38. (28) Cooke, D. H. Modelling of Off-Design Multistage Turbine Pressures by Stodola’s Ellipse; Bechtel Power Corporation: Houston, TX, 1983. (29) Xu, G.; Yang, Y. P.; Ding, J.; Li, S.; Liu, W.; Zhang, K. Analysis and optimization of CO2 capture in an existing coal-fired power plant in China. Energy 2013, 8, 117−127.
4633
DOI: 10.1021/acs.energyfuels.5b00811 Energy Fuels 2015, 29, 4624−4633
