ARTICLE pubs.acs.org/EF
Dry Gasification Oxy-combustion Power Cycle Michael E. Walker,*,† Javad Abbasian,† Donald J. Chmielewski,† and Marco J. Castaldi‡ †
Department of Chemical and Biological Engineering, Illinois Institute of Technology, 10 West 33rd Street, Chicago, Illinois 60616, United States ‡ Department of Earth and Environmental Engineering, Columbia University, 500 West 120th Street, New York City, New York 10027, United States
bS Supporting Information ABSTRACT: Proposed within this work is a novel coal conversion process, dubbed the “dry gasification oxy-combustion” (DGOC) power cycle. In the unique two-stage conversion process, feed coal is partially oxidized at high pressures in an oxygen-blown, fluidized-bed gasification unit, using recycled flue gas as a gasification agent (≈61% CO2 and 32% H2O). In addition, the reducing environment of the gasifier provides an opportunity to perform pre-combustion sulfur removal through sorbent-based capture. The second stage, oxy-combustion, also uses recycled flue gas, for temperature moderation, while providing the energy to raise steam for power generation. The process effluent is concentrated in CO2 and at high pressures, which enables the use of ambient cooling to flush out the water from the process stream. Full condensation of the remaining CO2 in a high-purity liquid stream requires the inclusion of a refrigeration cycle. The resulting stream is ready for further compression, drying and pipelining for sequestration. Analysis of a preliminary design was carried out using process simulation models developed in Aspen Plus. Results suggest that DGOC can achieve carbon capture and sequestration (CCS) goals with a 4.9% higher thermal efficiency over the estimated 29.3% for current CCS technologies based on oxy-combustion. This is due to benefits gained by shifting sulfur removal from the flue gas desulfurization (FGD) recycle loop to the gasifier, as well as recovery of CaS oxidation heat. Furthermore, recoverable latent heat is available as a result of high-pressure operation and is provided primarily from the condensation of water contained in the flue stream. Results also suggest that DGOC will remain competitive against the integrated gasification combined cycle (IGCC) process, in terms of fresh water consumption.
’ INTRODUCTION Forecasts of the power generation spectrum in the coming quarter century indicate that the world will be increasingly dependent upon fossil fuel sources for electricity production.1 The reasons for this are complex and include issues with the storage, transmission, and use of renewable energy sources. The underlying dilemma is the sheer abundance and affordability of fossil sources, such as coal, however.2 This outlook has caused increased concern over the large amount of CO2 emitted from thermoelectric production sources. For example, the United States emitted 5.8 billion metric tons of CO2 in 2008 as a result of energy consumption.3 Emissions from the use of coal account for 37% of this total. The combined CO2 effluent of fossil-fired stacks is on par with those of combustion engines, and together, these emissions represent the largest yearly contribution to greenhouse gases. One possible avenue toward the reduction of CO2 emissions is carbon capture and sequestration (CCS). This involves separation of CO2 from the flue gas stream of a plant, compression, and injection into an underground geological formation. CCS technologies at the forefront of the literature include amine-based CO2 removal from flue gas, dual-stage Selexol cleaning of fuel gas, and oxy-combustion. Amine-based solvent CO2 capture is handled in a typical absorber and stripper configuration. Such a setup is appropriate for an air-fired combustion unit but has a severe negative impact on overall efficiency, on the order of 1213% of the thermal input.4 For gasification systems, the r 2011 American Chemical Society
synthesis gas produced from the gasifier must be shifted over a catalyst bed with additional steam to obtain the appropriate composition (all H2 and CO2). An illustration of the gasification process configured with a watergas shift bed and dual-stage Selexol train is shown in Figure 1. This setup is also detrimental to efficiency, but the U.S. Department of Energy (DOE) currently estimates that integrated gasification combined cycle (IGCC) technologies fitted with CCS can achieve the highest thermal efficiency of any alternatives at 32.5%.5 An oxy-combustion system operates by combusting coal with pure oxygen; however, the flame temperatures reached in this configuration require recycling cooled flue gas back to the combustor for moderation. In this setup, a stream consisting of mostly CO2 and H2O is produced, from which H2O can be removed prior to further compression of CO2 for pipelining. The efficiency sink in this process comes from the large air-separation unit duty required to generate the large volumes of high-purity oxygen needed to run the oxy-combustion unit.4 As a result, estimates of oxy-combustion cycle efficiency are in the area of 29.3%. Figure 2 depicts the oxy-combustion process; note that flue gas desulfurization (FGD) towers are necessary within the flue gas recycle loop to prevent sulfur buildup that could Received: February 8, 2011 Revised: April 20, 2011 Published: April 20, 2011 2258
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Figure 1. Pre-combustion CCS in the IGCC process.
Figure 2. Post-combustion CCS in the oxy-combustion process.
otherwise damage sensitive process equipment, such as heatexchange surfaces. Another important environmental issue in thermoelectric power production is freshwater usage. Withdrawal for U.S. thermoelectric power generation was 886.5 billion liters per day (BLD) in 2000.6 This represents approximately 45% of the total water withdrawals for the nation. Of the withdrawn water, roughly 13.6 BLD of water is consumed, that is, not returned to the source body.7 This represents approximately 3% of the total water consumption for the nation. However, an average 6364 BLD of water remains on U.S. soil from rainfall.8 At a glance, this seems to indicate that there is nowhere near a water shortage, because this value is roughly 14 times the national consumptive usage. The problem lies in the uncertainty and variability of rainfall. For example, the vast majority of the U.S. west of the Mississippi has spent >10% of the past century in severe to extreme drought. Furthermore, the withdrawal of freshwater for once through systems, while innocuous on the surface, involves several factors that are environmentally detrimental. First, the intake of freshwater sources may directly damage species living in the source body; also, if these species are detrimental to heat-exchanger performance, it has been customary to introduce harmful biocide agents to handle them.
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Figure 3. DGOC power cycle.
In addition, the direct thermal pollution to the source body can be damaging to the local ecology.9 The fact that the power generation sector places such a large stress on water resources, especially in areas of the country where water is scarce, has negative implications toward the widespread adaptation of CCS technologies. This is because commercially available CCS strategies can be very water intensive. This is especially true in the case of pulverized coal (PC) technologies, where CCS can increase water consumption by nearly a factor of 2.4,5 Because the environmental implications of CCS and water usage minimization are positive, it is important to consider the application of both to current and emerging technologies. Process Description. The partial oxidation of carbonaceous feedstock for the production of synthesis gas is a process that has been around for many decades. Nevertheless, gasification remains a topic of widespread interest because these systems are adaptable for zero-emission power production and co-production operation. This paper presents a novel, zero-emission power production scheme, the dry gasification oxy-combustion (DGOC) power cycle. This process is best described as a hybrid between gasification and oxy-combustion systems; that is, DGOC incorporates the pre-combustion sulfur capture options available in gasification, as well as the CO2 capture and power production strategies central to oxy-combustion. In this process, recycled, CO2-rich flue gas is fed to the gasification unit as a reducing agent, as well as to the oxy-combustion chamber to moderate flame temperature. Figure 3 presents a graphical flow diagram of the DGOC process. In the first-stage, feed coal is pressurized to 6.0 MPa and introduced to a fluidized-bed gasifier operating at 1093 °C, along with fresh sorbent (limestone, Ca/S molar feed ratio = 2), oxygen, and recycled flue gas (∼61% CO2, ∼32% H2O, ∼2% N2, and ∼2% O2). Within the oxygen-lean, reducing environment of the gasifier, the production of syngas is governed by the same principle reactions that define conventional gasification. However, the primary gasification agent within the DGOC system is CO2. This is in contrast to typical gasification operation in which steam is used for this purpose and is the source of the moniker “dry gasification” because process steam is not injected into the gasifier as part of the DGOC operation. The predominant form of sulfur within the produced gas is H2S. This species readily reacts with calcium oxide (lime) under 2259
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Energy & Fuels gasification conditions to yield H2O and solid CaS, which can be removed with the solid ash particles. The unstable calcium sulfide byproduct can then be oxidized to form a stable waste product, CaSO4. Further, the energy released from the exothermic oxidation step can be reintegrated to heat boiler feedwater and add to process efficiency. Synthesis gas from the gasification stage is sent to the oxycombustion stage, where it is combusted with high-pressure oxygen. The energy produced from combustion of the syngas is used to raise steam in a Benson-type boiler, similar to conventional boiler operation. To avoid excessive flame temperatures in the combustor, recycled flue gas is used as a moderator. A unique and advantageous aspect of the DGOC process is the fact that the flue gas is recycled at the same temperature as the outlet of the boiler economizer. This is in contrast to current oxy-combustion configurations that employ FGD spray towers within their flue gas recycle loops. Because DGOC uses pre-combustion sulfur capture, the inclusion of FGD towers (and the associated loss of sensible heat within the recycle loop) is avoided. The adiabatic flame temperature of an air-blown PC boiler, as specified in the literature,4 is estimated to be about 2065 °C. To maintain a temperature in this range, about 70% of the flue gas must be recycled to the DGOC system. This can be portioned between the gasifier and combustion units in any combination while still achieving temperature specifications in the combustor. However, the temperature of the gasification unit is affected by the amount of recycle, which can have implications on sulfur removal. In the evaluations to follow, a gasification agent/carbon molar feed ratio [(H2O þ CO2)/C] of 1 was targeted. This corresponds to a system configuration wherein approximately 28% of the recycled flue gas is fed to the gasifier (28% 70% = 20% of the total flue gas). A gassolid separation cyclone is used to remove entrained solid particles from the flue stream. The solid particles, consisting of unconverted coal fines and fly ash, are recycled back to the gasifier, providing an opportunity for further conversion or removal. The non-recycled portion of the flue gas, destined for sequestration, is sent to an oxygen preheater unit, where sensible heat from the flue gas is transferred to the high-pressure oxygen feed. This oxygen is produced from ambient feed air in an air separation unit (ASU) and is fed to the system at 95% purity. The cooled outlet flue gas is then sent to a series of cooled condensers. The first condenser is water-cooled and operates at 93 °C, at the process pressure of 6.0 MPa; this allows for the condensation/recovery of 96% of the water contained in the hot flue gas. The heat recovered in this condensation step is significant and can be used to heat boiler feedwater. A second condenser uses ambient cooling water to bring the flue gas temperature down to 40 °C. The small amount of water that is produced from the flue gas passing through the second condenser is mixed with that from the first, for a total process water recovery of 99%. The gas that exits the second unit is predominantly CO2 (∼90%); however, the remaining water must be removed via a drying process prior to pipelining. A liquid desiccant, such as triethylene glycol (TEG) is used for this purpose. Finally, the dry CO2 stream is compressed to pipeline pressure (15.3 MPa)4 and can be transported for sequestration. Literature Review. Research using CO2 as a gasification medium has been conducted with coal samples. Performance is typically measured against steam gasification, to understand the impact on kinetics and reactivity. Ye et al.10 found that CO2 gasification had lower activation energy than steam and overall
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reactivity was higher with steam for low-rank coal samples. Furthermore, the group found catalytic effects to be significant in the CO2 gasification of coal chars, where the mineral components were chemically bound to the functional groups of the hydrocarbon feedstock. Zhang et al.11 found a similar performance for anthracite coal. They determined that char reactivity with steam gasification was significantly higher than with CO2 and concluded that CO2 gasification was more dependent upon catalytic effects from the mineral content in the coal. Messenbock et al.12 examined the enhanced reactivity of coal char subjected to gasification temperatures, using CO2 to facilitate the burnout of the thermally resistant, unreactive surface layer. Their scanning electron micrographs demonstrated a distinct pore structure, with the development of an extensive microporous network when they used CO2. This pore structure was not observed when using H2O. Kinetic studies were carried out to determine the effect of CO2 on coal gasification. Wang et al.13 determined through pressurized thermogravimetric analysis (TGA) studies that gasification rates increase proportionally to the 0.1 power of the CO2 partial pressure. The results in several works1014 also indicate that an increased operating temperature increases the rate and extent of fixed carbon conversion during CO2 gasification. Specifically, the results shown in the work by Ye et al.10 demonstrate that an observed gasification rate with steam, at 1028 °C, can be matched by CO2 gasification operating at about 1093 °C. It should be noted that these and many other studies examined char that was produced via heat treatment in a nitrogen atmosphere prior to their investigations. For example, the anthracite coal char was produced by a 900 °C heat treatment for 0.5 h, and the low-rank coal char was formed from a 600 °C heat treatment for 15 min. These heat treatments result in the removal of moisture and volatile hydrocarbons that significantly contribute to the pyrolysis reactions during the gasification of raw coal. Therefore, a char produced under an inert environment compared to the char produced during gasification with different reactive media (i.e., steam or CO2) is expected to be very different. Castaldi et al.1417 have found that increased CO2 levels provide a more reactive medium at elevated gasification temperatures, resulting in a more complete conversion of the char to volatile products. Further, they demonstrated that opportunity exists to adjust the ratio of H2/CO in the syngas produced, by selecting the concentration of CO2 fed into the reactor system, resulting in operational and economic advantages. This group has also performed research into the utility of CO2 gasification to drive a steam-reforming reactor for the production of hydrogen. Several other groups have also investigated the use of CO2 as a gasification agent on coal1820 and biomass/waste samples, such as plant husks21 and cardboard.22 Further, Kale et al.23 investigated the dry, autothermal reforming (with partial oxidation) of glycerol with CO2. Oxy-combustion technology is regarded as a possible CCS option for power generation.4 Designed to produce concentrated, sequestration-ready CO2 as an effluent, oxy-combustion uses oxygen instead of air for coal conversion. Increased operating pressure has been shown to increase oxy-combustion cycle efficiency.24 As described by Hong et al., this is because a greater amount of heat is available for recovery, the result of a larger percentage of process water condensing out of the vapor phase at flue outlet temperatures. They explain that proper integration of this heat requires the use of an acidgas condenser and high-pressure deaerator. Further, the group points out an additional compression benefit from high-pressure operation, because of 2260
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Table 1. Steam Cycle Parameters steam cycle description
supercritical, single reheat
Table 2. Case Study Matrix for DGOC Efficiency Benefit Analysis
steam cycle pressure (MPa)
24.2
case
system
oxidant to
steam cycle temperature (°C)
599
number
setup
boiler
reheat temperature (°C)
621
1
PC boiler
air
0.1
FGD
no CCS
2
PC boiler
oxygen
0.1
FGD
oxy-combustion
3
DGOC
oxygen
6
gasifier DGOC without
4
DGOC
oxygen
6
gasifier DGOC without flue
5
DGOC
oxygen
6
gasifier DGOC
extraction of more water from the flue, which leaves less material to compress for CCS. The viability of in situ sulfur removal using calcium-based sorbent has been verified for fluidized-bed gasifiers at high temperatures and pressures.2535 In the reducing environment of the gasifier, sulfur released from feed coal forms H2S and COS, with H2S as the predominant species. Abbasian et al.28 investigated the reaction of limestone and dolomite with H2S, operating at 2.03.1 MPa and 6001050 °C in a gasification environment. Work by Goyal et al.36 displayed the application of this methodology at the pilot scale, up to pressures of 2.76 MPa. The results of studies conducted in this area show that, under proper conditions, up to 90% sulfur removal is possible. Because previous studies have not investigated the feasibility of in situ removal in the range of 6.0 MPa, this work will include an evaluation of the thermodynamic implications of operation at this pressure. Further work by Abbasian et al.37 was carried out to investigate the oxidation of the unstable CaS byproduct. Their work affirmed the feasibility of CaS conversion to stable CaSO4, suitable for disposal.
’ METHODOLOGY Analysis of the DGOC system was focused in three key areas: process streams, water usage, and overall efficiency. Process unit operations and streams were modeled using Aspen Plus. The focus of these preliminary investigations was the following: (1) evaluate DGOC process performance, (2) assess feasibility of sulfur removal in the gasifier, (3) evaluate DGOC effluent quality, (4) evaluate water usage of DGOC relative to conventional power production with and without CCS technologies, and (5) evaluate DGOC efficiency relative to conventional power production with and without CCS technologies. Process modeling software, such as Aspen Plus, has been widely used for the simulation of gasification systems in the literature.3844 The simulation employed in this study used a chemical reaction equilibrium description of the gasification unit based on a minimization of Gibbs free energy. This unit does not take into account the detailed complexity of the gasification system, in terms of kinetics and fluid dynamics. However, the gasification product gas composition is generally close to that predicted by an equilibrium reaction model. The remainder of the process, including the combustion unit and Benson boiler heat recovery steam generator (HRSG) are also modeled using Aspen. Efficiency results were set against a baseline of an air-blown PC power plant (case 1). Steam cycles used for all cases have consistent parameters as listed in Table 1. The case study matrix is presented in Table 2. Case 2 is offered as a carbon capture baseline and corresponds to an oxy-combustion configuration with CCS. Cases 35 are all representative of the DGOC process and provide a step by step evaluation of the process configurations unique to DGOC. Case 3 represents a DGOC setup that does not take advantage of the process heat recovery options available. Case 4 is similar to the previous case but incorporates recuperation of CaS oxidation heat to boiler feedwater. Case 5 builds off cases 3 and 4 by including recuperation of the latent heat in the effluent flue to heat boiler feedwater. Illinois No. 6 coal was used in all cases for this analysis, and process parameters for all DGOC cases are as described above (6.0 MPa and
system
sulfur
additional
pressure (MPa) handling
notes
heat integration gas latent heat
Table 3. Coal Composition, Ultimate Analysis (Illinois No. 6) coal composition
% (as received)
C
63.75
H
4.50
O
6.88
N S
1.25 2.51
Cl
0.29
ash
9.70
moisture
11.12
1093 °C). The properties of the Illinois No. 6 strain used are listed below in Table 3. Also, note that the thermal efficiency of a power production process is defined as the amount of work produced divided by the thermal input rate. Therefore, efficiency percentage points refer to 1% of the thermal input rate [higher heating value (HHV)]. This efficiency description is common in power production literature.
’ RESULTS AND DISCUSSION DGOC process efficiency results are compared against two baseline cases, to highlight the impact of CCS on overall efficiency as well as the benefits of DGOC configuration. DGOC feed parameters, such as coal and oxygen flow rates were adapted from the second of these baseline cases, which represents an oxycombustion process. Scaling the DGOC system to that of the oxy-combustion baseline in this manner allows for a fair comparison between the cases. This allows for a firm accounting of auxiliary power considerations. An itemized description of case study results and auxiliary considerations is provided in Table 4. For each case, including the baselines, steam turbine output was determined from Aspen-based process models. Appropriate auxiliary considerations were then applied for each particular case, and net process efficiency is calculated. The efficiency values obtained for the baseline cases agree with those reported in the literature.4,5 After process auxiliaries were taken into account, net plant efficiency for baseline case 1 (an air-fired supercritical PC power plant) is 39.4% and baseline case 2 (an oxy-combustion system with CCS) achieves 29.3%. This efficiency drop-off is due to the large increase in parasitic power to the oxy-combustion system, arising from the compression duty in ASU and CCS process steps. As such, it can be seen that there are large opportunities for improvement in these areas. 2261
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Table 4. DGOC Efficiency Benefits: Case Study case
case 1
case description
air-fired supercritical PC
case 2
case 3
case 4
oxy-combustion
DGOC without
DGOC without flue
with CCS
heat integration
gas latent heat
case 5 DGOC
pressure (MPa)
0.1
0.1
6.0
6.0
as-received coal feed (kg/h)
185249
249235
249235
249235
6.0 249235
limestone sorbent feed (kg/h)
18386
39004
39004
39004
power summary net turbine power (kWe)
580200
785900
793040
812146
864284
430
500
1220
1220
1220
2330
2330
2330
1000
1000
1000
auxiliary load summary (kWe) coal handling coal milling limestone handling and reagent preparation
890
1210
pulverizers
2780
3740
ash/slag handling and dewatering
530
720
1200
1200
1200
1000 125680
1000 125680
1000 125680
1000 125680 60468
air separation unit auxiliaries air separation unit main air compressor oxygen compressor
60468
60468
fan/recycle compression duty
10120
10520
3330
3330
3330
baghouse and SCR
80
90
90
90
90
FGD pumps and agitators
2960
4050
CO2 compression
72110
10050
10050
10050
condensate pump
790
1050
900
900
900
circulating water pumps cooling tower fans
4650 2720
6200 3620
6200 3620
6200 3620
6200 3620
steam turbine auxiliaries
400
400
400
400
400
miscellaneous balance of plant
2000
2000
2000
2000
2000
transformer loss
1820
3000
3000
3000
3000 222490
total auxiliaries (kWe)
30170
235890
222490
222490
net power (kWe)
550030
550010
570550
589656
641794
thermal input (kWt)
2210668
1878619
1878619
1878619
1878619
net plant efficiency (%) comparison (%)
39.40
29.30
30.37 1.07 versus case 2
31.39 1.02 versus case 3
34.16 2.78 versus case 4
The remainder of Table 4, cases 35, is intended to build insight into the unique process configuration of DGOC. Case 3 represents the DGOC system without either of the heat integration options that are addressed in the following two cases. The 1.07% points of efficiency gained in adopting the configuration in case 3 results from the retention of sensible heat within the flue gas recycle loop. A typical oxy-combustion setup requires the inclusion of FGD towers to manage SO2 concentrations to acceptable levels; however, the saturation of process gas and subsequent loss of water in the FGD process results in the aforementioned loss of sensible heat. When sulfur removal is shifted to the gasification step of the DGOC system, this loss is avoided. In addition to the retention of sensible heat in the flue gas recycle loop, case 4 incorporates CaS oxidation energy for heat integration. In this case, the heat available from the CaS oxidizer is used to heat boiler feedwater. As can be seen from the resulting model output, such a configuration provides 1.02% points of efficiency benefit. Case 5 represents a similar integration configuration for the heating of boiler feedwater; however, heat is provided in this case by the condensation of water from the flue gas. This hightemperature condensation is made possible by the high-pressure operation maintained in DGOC. Specifically, the condensation
Figure 4. Efficiency benefits of the DGOC process versus atmospheric oxy-combustion with CCS.
step is carried out at 93 °C, and at this temperature, 96% of the water in the flue gas is condensed out, providing a 2.78% point benefit to efficiency. 2262
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Table 6. Wet CO2 Sequestration Stream wet CO2 sequestration stream sequestration temperature (°C)
21.1
sequestration pressure (MPa)
15.3
total effluent (mass %)
83
composition (mol %)
Figure 5. Sulfur removal efficiency versus steam addition.
Figure 6. Sulfur removal efficiency versus gasification agent (CO2 þ H2O) addition (DGOC case).
Table 5. Total H2O Effluent Stream
H2O
0.2
CO2
89.5
SO2
0.1
N2 O2
2.3 3.0
Ar
4.7
Figure 7. Water usage in various power production technologies.
Sulfur removal by calcium-based sorbent proceeds through the following reactions in the reducing environment of a gasifier:
total H2O effluent stream flash temperatures (°C)
93/40
total H2O removal (%) total effluent (mass %)
99 17
composition (mol %) H2O
99.85
CO2
0.14
SO2
0.007
N2
0.0004
O2
0.001
HCl
0.002
The three DGOC process configurations incorporated in cases 35 are depicted graphically in Figure 4. The benefits of each configuration, as detailed above, are also shown in the figure. Through comparison of the fully integrated DGOC net system efficiency (case 5) to that of the baseline cases, it can be seen that DGOC achieves CCS goals with 4.86% points increased efficiency over oxy-combustion (case 2) and only 5.24% points lower than a typical air-fired supercritical PC system (case 1). Sulfur Capture. Sulfur capture within the gasification unit is an integral part of the DGOC process. As shown above, it allows for operation of the oxy-combustion unit without the efficiency sapping FGD spray towers in the recycle loop. Sulfur handling is necessary because high levels of SO2 encourage the formation of acid deposits and thereby decrease the lifetime of process equipment. SO2 levels corresponding to DGOC operation with and without sulfur handling are 1006 and 9068 ppmv, respectively.
CaCO3 T CaO þ CO2
ð1Þ
H2 S þ CaO T H2 O þ CaS
ð2Þ
H2 S þ CaCO3 T H2 O þ CO2 þ CaS
ð3Þ
From these reaction equations, it is apparent that increased levels of CO2 can adversely affect sulfur capture in gasification systems. It is therefore necessary to analyze the thermodynamic implications of running a system that is highly concentrated in CO2. Figures 5 and 6 depict sulfur removal efficiency as a function of gasification agent addition for the case of steam gasification as well as DGOC. Data for three temperatures are included: 871, 982, and 1093 °C. All data are representative of operation at 6.0 MPa and a sorbent feed rate that provides a Ca/S molar feed ratio of 2. Note that, for both gasification agents, the thermodynamic limitation of sulfur removal efficiency drops off as the system temperature drops to 871 °C and the behavior of the removal curve is different from that at higher temperatures. This is because the thermodynamic equilibrium is governed by reaction 3 at lower temperatures. Further, a drop off in removal is observed for all cases as gasification agent addition is increased. This can be attributed to the effect that increased H2O and CO2 concentrations have on the equilibrium of reactions 13. It is observed that adequate (above 83%) removal efficiency is obtained for runs in the area of 9821093 °C and a gasification agent/carbon ratio e1. At the proposed operating condition of 1093 °C and gasification agent/carbon ratio of 1, thermodynamic 2263
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Table 7. Breakdown of Water Usage in Various Power Production Technologies water use (L/MWh)
supercritical PC
supercritical PC
IGCC
IGCC
oxy-combustion
DGOC estimate
CCS?
N
Y
N
Y
Y
Y
total (net)
1707
3199
1121
1798
2373
1763
cooling tower
1484
2873
920
1344
2316
1968
223
326
FGD
57
WGS
185
gasifier recovered
201
269 205
Figure 8. Process efficiency for various systems with carbon capture, on a HHV basis.
limitations of removal efficiency have been predicted to be 88.9%. It is necessary to note that the equilibrium concentration of H2S in the product gas is defined by the composition and temperature of the gas, and therefore, coals with higher sulfur content will undergo a greater percentage removal, down to the equilibrium concentration (assuming enough sorbent to react with H2S). Furthermore, practical processing issues, arising from kinetic limitations, may prevent conversion to the thermodynamic limit. The calcium sulfide byproduct that results from sulfur removal within the reducing environment of the gasifier must be oxidized to a stable form prior to disposal. This is because small amounts of CaS may react with atmospheric moisture to release H2S, which is both noxious and toxic. The oxidation proceeds according to reaction 4 and is exothermic, which offers the heat integration options mentioned above. CaS þ 2O2 T CaSO4
ð4Þ
Effluent Considerations. The impurities that remain in the flue gas stream, small amounts of nitrogen, oxygen, sulfur dioxide, etc., are expected to either flush out with the water or remain in the sequestration stream. As can be seen from the results of the principle component analysis in Table 5, the water effluent streams that evolved from the first and second flue condensers contain only a small percentage of impurities. Of course, it must be taken into consideration that metallic species or a similarly problematic unaccounted for compound may end up in the H2O effluent streams. It is therefore possible that recovered process water may require additional cleaning before being repurposed. The remaining sequestration stream, as shown in Table 6, still contains a small amount of water that must be removed through the application of a drying process, such as TEG. This step is necessary to inhibit corrosion of the transport pipeline, especially because of the presence of SO2. The resulting dry CO2 stream is
subsequently pumped to pipeline pressure (15.3 MPa). To demonstrate the system efficiency of DGOC as a zero emission technology, the dry CO2 stream is compressed and sequestered without venting or further purification. The effluent stream of the oxy-combustion baseline (case 2) is handled in the same manner. It should be noted that the total post-ASU compression requirement of the DGOC process (60.5 þ 10.0 = 70.5 MW) is on par with that of the oxy-combustion process (72.1 MW), as can be seen in Table 4. Water Consumption. An important aspect of the DGOC process is the performance of the system in terms of water consumption. The total water consumption of an air-fired PC power plant, running a supercritical steam cycle without CCS, is 1707 L/MWh (net). For comparison, the same air-fired supercritical PC plant with CCS would require 3199 L/MWh (net). Similarly, the IGCC process with and without CCS has water consumption rates of 1121 and 1798 L/MWh (net), respectively. Oxy-combustion units (in which CCS is inherent) require the use of 2373 L/MWh (net). These values are summarized in Figure 7, along with the calculated water usage in the DGOC system at 1763 L/MWh (net). The water reduction benefits for DGOC are readily apparent over conventional PC CCS methodologies, as well as oxy-combustion technology, while it remains competitive with the IGCC process. Note that the estimated cooling tower water requirement for DGOC was adapted from the oxy-combustion case and adjusted for process efficiency. This estimate is sound because of the similarity of the steam cycles and the fact that the DGOC system is scaled to the oxy-combustion baseline. The recovery of water from the DGOC process is determined by the model output water flow rate and process net energy output. At 205 L/MWh, the recovered water flow rate is about 10% of the water consumed in the cooling tower. A breakdown of the water usage in each system is given in Table 7. Process Efficiency. Calculated DGOC process performance compares favorably against estimates of other power production technologies fitted with CCS. Process efficiency estimates of comparative technologies are taken from recent U.S. DOE reports.4,5 Air-fired supercritical PC plants fitted with Econamine systems for CCS achieve an estimated 28.3% net efficiency, while oxy-combustion plants can attain the same process goals at 29.3% net efficiency. The IGCC system, on the other hand, has the highest reported process efficiency for systems with CCS at 32.5%. This particular collection of estimates is very useful because of the similarity of scale and efficiency-accounting procedures used in their derivation. In the current study, particular care was taken to follow a similar methodology. Process efficiency for the DGOC configuration has been estimated at 34.2%, 1.68% points higher than the leading alternative, IGCC. Figure 8 2264
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Energy & Fuels illustrates the efficiency comparison; all values are given on a HHV basis. Process Economics. Because DGOC is a hybrid between gasification and oxy-combustion and the DGOC configuration presented in this paper is baselined to a similar coal throughput as the power production systems given in the literature,4,5 preliminary estimates of DGOC economic performance can be based off of the economic performance of the systems presented in the literature. In a comparison against IGCC, which achieves the best economic performance for power production technologies that include CCS, it can be safely estimated that the DGOC process will remain competitive in terms of process economics. This is because the DGOC system will not contain capitally intensive units, such as a dual-stage Selexol gas cleanup system, watergas shift catalyst beds, combustion turbine, or Claus plant. These savings will be offset by larger ASU, HRSG and steam turbine, limestone costs, CaS oxidizing unit, and TEG system but will be supplemented by the continuing benefit of lower fuel usage, which results from the higher process efficiency of DGOC. In summary, this preliminary analysis reveals no “show-stoppers” in the expected process economics of DGOC.
’ CONCLUSION This work presents the DGOC power production process, a novel coal conversion concept that has been estimated to achieve CCS goals with increased efficiency over the leading conversion options. The efficiency benefits arise from the unique nature of DGOC process configuration, including pre-combustion sulfur capture, operation at high pressure, and use of recycled flue gas as a gasification agent and oxy-combustion temperature moderator. Process efficiency is estimated using Aspen-Plus-based process simulation models of the gasification, combustion, and boiler HRSG systems. After auxiliary power requirements are taken into account, the DGOC system is shown to achieve CCS goals with a net process efficiency of 34.2%. Pre-combustion sulfur removal was shown to be thermodynamically viable at the operating temperature and pressure of the DGOC system. Further, effluent stream evaluation results indicated that 99% of water contained in the flue gas would be recovered in the DGOC system, with minor impurities. The remaining sequestration stream was dried and subsequently captured without venting, thereby making the DGOC configuration presented a zero-emission process. The molar composition of the dried sequestration stream is primarily CO2 (89.7%) but contains 2.3% N2, 3.0% O2, and 4.7% Ar. The performance of the DGOC process against leading power production technologies fitted with CCS was evaluated in terms of process efficiency and water consumption. Results indicate that the DGOC process can attain CCS goals with increased process efficiency over these technologies, by 1.68% in the case of IGCC and 4.86% in the case of oxy-combustion. Results also indicate that the DGOC process is competitive with IGCC in terms of water consumption. ’ ASSOCIATED CONTENT
bS
Supporting Information. Mass and energy balance detail on the flow sheets represented in Figures 13, as well as the configurations presented in Table 4. This material is available free of charge via the Internet at http://pubs.acs.org.
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’ AUTHOR INFORMATION Corresponding Author
*E-mail:
[email protected].
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