Energy & Fuels 2008, 22, 2687–2692
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Gasification of New Zealand Coals: A Comparative Simulation Study Smitha V. Nathen, Robert D. Kirkpatrick, and Brent R. Young* Department of Chemical and Materials Engineering, The UniVersity of Auckland, PriVate Bag 92019, Auckland Mail Centre, Auckland 1142, New Zealand ReceiVed NoVember 25, 2007. ReVised Manuscript ReceiVed April 14, 2008
The aim of this study was to conduct a preliminary feasibility assessment of gasification of New Zealand (NZ) lignite and sub-bituminous coals, using a commercial simulation tool. Gasification of these coals was simulated in an integrated gasification combined cycle (IGCC) application and associated preliminary economics compared. A simple method of coal characterization was developed for simulation purposes. The carbon, hydrogen, and oxygen content of the coal was represented by a three component vapor solid system of carbon, methane, and water, the composition of which was derived from proximate analysis data on fixed carbon and volatile matter, and the gross calorific value, both on a dry, ash free basis. The gasification process was modeled using Gibb’s free energy minimization. Data from the U.S. Department of Energy’s Shell Gasifier base cases using Illinios No. 6 coal was used to verify both the gasifier and the IGCC flowsheet models. The H:C and O:C ratios of the NZ coals were adjusted until the simulated gasifier output composition and temperature matched the values with the base case. The IGCC power output and other key operating variables such as gas turbine inlet and exhaust temperatures were kept constant for study of comparative economics. The results indicated that 16% more lignite than sub-bituminous coal was required. This translated into the requirement of a larger gasifier and air separation unit, but smaller gas and steam turbines were required. The gasifier was the largest sole contributor (30%) to the estimated capital cost of the IGCC plant. The overall cost differential associated with the processing of lignite versus processing sub-bituminous coal was estimated to be of the order of NZ $0.8/tonne.
1. Introduction The energy industry is currently faced with three intertwined challenges, namely energy security, environmental issues, and cost.1 Energy has a profound impact on society, being the driving force for almost all its daily functions. Energy commodities include electricity, fuel, and heat. Along with population growth in rapidly developing economies such as China and India, the achievement of higher standards of living is inevitably accompanied by an increase in demand for energy.2 A fossil fuel based economy is highly dependent on nonrenewable forms of energy such as oil and gas, which places a constraint on supply. Coal is a nonrenewable resource; however, the world’s coal reserves amount to twice the combined oil and gas reserves.3 This includes the coal abundant and oil and gas deficient countries such as China and India.2 Coal gasification technology with carbon capture and sequestration (CCS) presents an environmentally attractive potential solution to the problem of high carbon dioxide emissions associated with stationary power generation. Coupled with this is its application to a variety of other technologies and markets such as the power, chemicals, and hydrogen industry.3 * Corresponding author. E-mail:
[email protected]. (1) New Zealand Ministry of Economic Development. NZ Energy Strategy. http://www.med.govt.nz/templates/ContentTopicSummary____ 19431.aspx (accessed Sep 2006). (2) Oxburgh, R. Energy and Climate - Time to Act. Presentation at the University of Auckland, March 31st, 2006. (3) Higman, C. Van der Burgt, M. J. Gasification; Elsevier: Amsterdam, 2003.
In 2004, there were 385 gasifiers located globally.4 The Sasol plant in South Africa, the world’s largest gasification complex with 107 gasifiers (28% of the world’s total), is a pioneer in commercializing low rank coal into petroleum products and chemical feed stocks using the Fischer-Tropsch (FT) process, since 1955.3,4 Currently 24 coal and petroleum coke gasification projects have been planned in China to produce chemicals, methanol, and fertilizers.4 In 1997, the world’s largest integrated gasification combined cycle (IGCC) was built in Puertollano, Spain, generating 318 MWe of electricity.4 The high pressures and temperatures prescribed by thermodynamics for converting coal into a beneficial gaseous fuel are the key indicators for a high capital investment. New Zealand (NZ) also plays a role on the global stage by having coal resources equivalent to 30-40 times the size of Maui, its largest gas discovery with 100 000 PJ available.5,6 There is concern over NZ’s gas supply ten years from now.1 Moreover, at $70 USD/barrel, NZ spends about $2-4.5 billion per annum on imported hydrocarbons.1,7 An alternative solution embraced by Solid Energy, NZ’s largest coal miner, and recognized by the NZ Energy Strategy is gasification technology (4) United States, National Energy Technology Laboratory (NETL). A Current Perspective into the Gasification. http://www.netl.doe.gov/ publications/brochures/pdfs/Gasification_Brochure.pdf#search)%22sasol% 20gasification%22 (accessed Sep 2006). (5) Simbeck, D. SFA’s Pacific Insights and Overviews of Lignite Gasification. The New Zealand Lignite Symposium, Invercargill, New Zealand, March 10, 2005. (6) Elder, D. The Economy and Energy: are both sustainable? www. solidenergy.co.nz (accessed Sep 2006). (7) Clemens, T.; Gong, D.; Pearce, S. Study on suitability of NZ coals for hydrogen production. Int. J. Coal Geol. 2006, 65, 235–242.
10.1021/ef700704n CCC: $40.75 2008 American Chemical Society Published on Web 06/10/2008
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which is pertinent for conversion into transport fuels and as a mainstay driver for a possible future hydrogen economy.1,6 Accordingly, Solid Energy is currently exploring a NZ $1 billion plant for converting coal into petrol using the FT process. It is envisaged that this could supply a third of NZ’s petrol.8 2. Motivation and Objectives The aim of this study was to conduct a preliminary feasibility analysis of coal gasification with respect to its relevance to the processing of NZ lignite and sub-bituminous coals. A simple method of coal characterization was developed for simulation purposes. NZ lignite and sub-bituminous coal were compared in an IGCC application and associated preliminary economics estimated. The formal objectives of this study include: • To model the coal gasifier in HYSYS as a foundation for further simulation work. • To integrate this gasifier model into an IGCC flowsheet configuration. • To apply the simulation to estimate the differences in NZ lignite and sub-bituminous coals in an IGCC application. • To perform a preliminary techno-economic estimate of IGCC processing of NZ lignite coal versus sub-bituminous coal. 3. Methodology The specific analysis tool utilized was the HYSYS version 3.2 simulation software. The thermodynamic package most generally recommended for oil and gas applications at nonideal conditions such as the high pressure ranges (20-40 bar) is the modified Peng-Robinson model, PRSV. The distribution of products of coal gasification is governed first and foremost by the mass and energy balances applying to the system. It was demonstrated by Wei9 that the mass and energy balances, ahead of considerations of equilibrium thermodynamics, and independent of reaction kinetics and of the design and operation of the reaction space, can provide a general analysis of the feasible operating regions of all gasification reactions. Whether in the case of a moving bed reactor, in which devolatilization takes place at relatively low temperatures, ahead of combustion and gasification, or, in the case of simultaneous devolitilization, combustion and gasification occurring at high temperatures in an entrained flow reactor, the product distribution from efficient adiabatic operation is constrained by reaction stoichiometry and the thermal balance between the endothermic and exothermic reactions. On the basis that the gases produced from fixed carbon dominated the gases produced from volatile matter in volume, over the range of gasification system operating conditions, Wei9 considered that coal could be represented as a single component solid carbon system. 3.1. Coal Characterization. The main challenge with this study revolves around representing coal as a complex material, appropriately such that further studies can be performed. One possible method is by breaking it down into carbon, methane and water to represent the C, H and O ratios in the macromolecule. The ultimate analysis data can be suitably used here. However, several uncertainties arise here, since H can be derived from water or methane. Also, carbon can be derived (8) New Zealand mulls coal-to-petrol project. Chem. Eng. (TCE) 2005/ 2006, Dec/Jan, 8. (9) Wei, J. A Stoichiometric Analysis of Coal Gasification. Ind. Eng. Chem. Process. Des. DeV. 1997, 18 (3), 554–558.
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from C(s) itself or methane. Furthermore, the O values can represent those that are present in combustible volatiles (e.g., carbonyls), whereas by the above method, O derived from water suggests that it is noncombustible. An appropriate and convenient method to determine the elemental breakdown is by calibrating them through trial and error with the gross calorific value (GCV) of coal. Furthermore, an added advantage is seen here, as when using the proximate analysis data, the volatile matter component can be assumed to be composed of water and methane. This would better reflect its combustible value where methane can account for the combustible value in the volatile matter that water cannot. Average carbon, methane, and water molar compositional values for various different coals including lignite and sub-bituminous NZ coals were determined by this method. The entrained flow gasifier was selected for modeling the gasifier, and reasons for this will be discussed in the next section. The assumptions made in characterizing the coal in this manner were the following: • All coal compositions were determined on a dry, ash free basis. It can similarly be evaluated on an as-received basis. This is justified considering that coal is processed into a dried and pulverized form before it enters the gasifier (Shell dry feed, entrained flow gasifier). Hence in the drying and pulverization stage, moisture is easily driven off.3 Also, moisture data on an as-received basis can be quite variable given the coal could have been influenced by its environmental conditions such as rain. Bound moisture may or may not be driven off during pulverization, and it is assumed that even this bound moisture is driven off. The calorific data is also on a dry, ash free basis. • The volatile matter is composed of methane and water only. This may result in the overestimation or underestimation of hydrogen amount as there are four hydrogens for every carbon in a CH4 molecule. And, the organics that compose the volatile matter may be present at a lower or higher H:C ratio. Water has a zero (caloric value) CV, but methane has a finite CV of 890.57 kJ/mol (e.g., VMGSim, 2008). Thereby with a high volatile matter content and low CV, more water can be expected, whereas with high CV, more methane can be expected. In summary, the coal characterization is as follows: • The carbon, hydrogen, and oxygen (C, H, and O) content of the complex macromolecule is represented by a threecomponent vapor-solid system of carbon, methane, and water. • The coals have been mapped from their positions in a threedimensional C-O-H space, assigned by their ultimate analyses, to a three-dimensional C-CH4-H2O space, through simultaneously employing their dry, ash-free proximate analysis data on fixed carbon and volatile matter and their gross calorific values. • As far as the coals of this paper are of low rank, in the approach to coal characterization herein, account is taken of the high oxygen content relative to hard coals. • The effect is that Wei’s single-component representation of coal undergoing gasification9 has been relaxed somewhat, while a degree of analytical simplification has been adopted, which is appropriate to support a preliminary techno-economic feasibility assessment. 3.2. Modeling the Gasifier. As stated previously, the entrained flow gasifier was chosen for simulation. A thermodynamic approach was undertaken, neglecting the kinetics involved, due to the lack of available kinetic parameters and added complexity. This approach was chosen since the gasifier operated at sufficiently high temperatures that it can easily be
Gasification of New Zealand Coals
modeled using a Gibb’s minimization algorithm. This assumption has been confirmed through technical work in the literature.3,10 The reasons for the entrained flow gasifier selection include its high suitability to low rank coals (lignites) and the use of entrained flow gasifiers for an IGCC as the industrially preferred choice dictated through experience.5,10 Specifically, the Shell gasifier technology was employed for this study. This is due to the data availability of an IGCC base case for the Shell Gasifier and its particular suitability for lignites (as opposed to the Texaco gasifier).5 Another justification, in the choice of Shell over Texaco is relevant to this study’s coal characterization method; the Shell gasifier requires a dry feed, whereas the Texaco gasifier requires a slurry feed. This reinforces the dryfeed entrained flow gasifier as a basis of using dry ash free calorific value (as discussed in the previous section). The three different reactors in HYSYS are the conversion, equilibrium, and Gibb’s reactors. All three function on a different basis. The equilibrium and Gibb’s reactors will yield the same results. A conversion reactor requires a conversionspecified reaction set. The difference between the latter two is that an equilibrium reactor requires a specified reaction set, whereas a Gibb’s reactor can function without one. Note, however, that Gibb’s reaction pathways are limited by simulation component slate and all the components must have given values of Gibb’s free energies of formation. Coal gasification goes through many reactions. There are mainly three independent reactions by thermodynamic degree of freedom principles.11 The reactor is then specified with coal, oxygen, and steam as the feed rates. Verification was conducted to determine whether the gasifier produced a gas mixture that was thermodynamically credible, by employing the governing water-gas shift reaction in analyzing the outcomes at different pressures and temperatures. Then, different types of coal were simulated based on the data collated. The outlet compositions of CO and H2 of different coals were then verified against published data. The accuracies were also recorded and analyzed. The gasifiers would be modeled as adiabatic, because with entrained flow gasifiers the exothermic reactions supply the necessary heat for the endothermic reactions without any external heat input. 3.3. Modeling the IGCC Application. Once the gasifier was modeled with reasonable confidence, the complete flowsheet for an IGCC application was developed. Several models were developed, within which minor variant cases were also developed for investigative purposes. The two vital models include: • The Shell Gasifier base case using Illinois No. 6 coal. This also involved analyzing the gasifier output compositional data in verifying the method of coal characterization. • The Shell Gasifier base case using NZ lignite and subbituminous coals. As it will be discovered during simulations, the ratio of oxygen to steam for the Illinois coal (1st model above) was about 16:1. This was far less steam compared to the trial case (2nd model above). Hence, the variants of this case looked at refining the data. The model can be broken down into three sections, the gas turbine, heat recovery steam generator (HRSG), and the steam turbine with a simple condensate recycle. The HRSG was modeled as three different sections of preheat, vaporization, and superheat heat exchangers to simulate a boilertype scenario. (10) Furinsky, L.; Zheng, L. Comparison of Shell, Texaco, BGL and KRW gasifiers as part of IGCC plant computer simulations. Energy ConVers. Manage. 2005, 46, 1767–1779. (11) Abbott, M. M.; Smith, J. M.; Van Ness, H. C. Introduction to Chemical Engineering Thermodynamics; Mc-Graw Hill: Boston, 2001.
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Considering time constraints, a meticulous optimization of the gasifier and the IGCC model was not possible. However, using the Shell base case as a first point of reference, it was possible that an optimized case was already used. 3.4. Design Basis. Simplicity of the process design and model was the key to enable preliminary conclusions to be drawn and hence meeting the project objective. The design basis case was keeping the power generated for both cases constant at 400 MW. The gasifier outlet temperature (1200 °C) and gas turbine inlet (1200 °C) and outlet temperatures (750-600 °C) were also kept constant. By keeping these variables constant in the comparative study, a few variables are eliminated such as gasifier material of construction cost, class of gas turbine and its cost, and the subsequent heat recovery (steam) that can be extracted downstream. 3.5. Economics. Economics were analyzed using the 0.6 CAPEX capacity approach.12 The base capacity used was the Shell base case scenario. Comparative economics were studied, which provided the benefit of eliminating a few economic variables. The IGCC model was viewed as an overall business system with revenues and costs. Evidently, the power generated is the sole source of revenue and this was kept constant at 400 MW, pertinent to the scale of NZ’s electricity system. The cost stream is divided into capital expenditure (CAPEX) and operating expenditure (OPEX). The chief capital items were the gasifier, combined cycle (gas turbine, HRSG, and steam turbine), and the Air Separation Unit (ASU). CAPEX on an annual basis was divided by 6 for an internal rate of return (IRR) of 15%. This cost stream was also to be kept constant; hence, the total profits were also constant. Since the total cost was constant for comparative economics of the two coals, the difference in OPEX was set equal to the difference in CAPEX/6. This difference was then divided by the amount of lignite coal in tonnes, to obtain the decrease in the cost of lignite coal needed relative to sub-bituminous coals (to give the same profits for both coals). The feedstock cost was the main factor considered here, as this is the only operating cost that can be decreased. The other operating costs such as electricity are bound to be higher for lignite coal, and the electricity price cannot be controlled as such. Whereas, given the abundance of lignite in NZ, its raw material cost can be decreased. 3.6. Computational Summary. In summary, the computational approach taken was as follows: 1. Determine average carbon, methane, and water molar compositional values for various different coals including lignite and sub-bituminous NZ coals by calibrating them through trial and error with the gross calorific value (GCV) of coal. 2. Simulate the gasification process conducted in an entrained flow gasifier using Gibb’s free energy minimization. (As discussed in the following section, the H:C and O:C ratios of the New Zealand coals were adjusted until the simulated gasifier output composition and temperature matched the values associated with the base case. Errors (10% in the gasifier conditions versus the Shell base case data on Illinois No. 6 coal were rectified by decreasing the H:C and O:C ratios in the coal. Variants of the Shell Gasifier base case using NZ lignite and sub-bituminous coals were simulated to align the steam requirements of trial cases). 3. Simulate the complete flowsheet for an IGCC application. (12) Sinnott, R. K. Chemical Engineering Design; Elsevier: Amsterdam, 1999; Vol. 6.
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Table 1. Discrepancy Results between Published Entrained Flow Data and a Simulated Gibb’s Reactor for Various International Coals with Increased Oxygen Flow Rates, Resulting in Very High Gasifier Temperatures (>1500 °C) error in molar dry gas % region/country
coal rank
CO
CO2
H2
T (°C)
Rhein/Germany North Dakota/USA Montana/USA Illinois/USA typical Poland typical S. Africa Datung/China typical India typical Australia average error %
brown coal lignite sub-bit bit bit bit bit bit bit
-4 0 -3 0 1 0 0 1 -3 -1
54 12 303 303 18 230 246 169 494 197
0 3 2 -1 2 0 -2 -2 -1 0
2267 2294 1954 2178 1421 2100 2178 2186 2295
Table 2. Discrepancy Results between Published Entrained Flow Data and a Simulated Gibb’s Reactor for Various International Coals error in molar dry gas % region/country
coal rank
CO
CO2
H2
T (°C)
Rhein/Germany North Dakota/USA Montana/USA Illinois/USA typical Poland typical S. Africa Datung/China typical India typical Australia average error %
brown coal lignite sub-bit bit bit bit bit bit bit
-9 -4 -6 -8 4 -4 -3 -3 -9 -5
-22 -49 139 143 -77 -30 -72 -14 110 14
31 36 14 18 1 14 15 16 21 19
1500 1500 1500 1500 1500 1500 1500 1500 1500
4. Compare inside battery limits economics of the IGCC process based on NZ lignite and sub-bituminous coals. 4. Results and Discussion 4.1. Lignite and Sub-bituminous Coal Representation. The lignite and sub-bituminous coals were calibrated against their respective CV, using methane and water to represent the volatile matter fractions. It was evident that a lower rank coal exhibits all the attributes of having a lower CV by exhibiting a higher fraction of water, lower fraction of methane, and lower fraction of carbon. On average, NZ lignite coals have a dry-ash-free (DAF) gross calorific value (GCV) of 26 MJ/kg and NZ subbituminous coals have a DAF GCV of 30 MJ/kg. 4.2. Gasifier Simulation. 4.2.1. Shell Entrained Flow Gasifier Data for Coals. Another method of verification was explored using the Shell entrained flow gasifier for most of the international coals listed above. Available literature data provided by Higman and Van der Burgt3 was limited to output dry gas compositions. The main limitation was the lack of definite gasifier feed data; hence, the entrained flow gasification temperature of 1500 °C was taken as the simulation target parameter. It should be noted that this was not explicitly stated in relation to the data provided. Tables 1 and 2 display the results obtained. It is noted that the CO2 errors are significant for both trials. This is probably due to the CO2 composition being very small, ranging from 1-2% for higher rank coals and 8-10% for lignite coals. Hence considering that other minority gases such as H2S, argon, and nitrogen have not been accounted for, it is very sensitive, leading to large errors. For the purposes of this study, the CO2 content was neglected and only the CO and H2 compositions were compared. The CO composition has an average error of -5% overall and the H2 error is higher at 19%. A closer analysis reveals
that the average lignite H2 error was 34% and, for higher rank coals, it was 14%. The negative and positive errors corresponding to CO and H2 provide possible evidence of the role of the water-gas shift reaction, whereby CO and H2 are on the opposite sides of the reaction. The CO error is reasonable; however, the H2 error especially in relation to lignite coals is relatively significant. The reason for this can be due to the coal characterization itself, the uncertain gasifier feed data or the Gibb’s reactor model. On the basis of the limited gasifier feed data (that had been expressed in kilograms steam per output syngas) of the amount of steam added, it was discovered that considerably less steam was used for gasification. This would explain a possibility of overestimating the amount of water of the higher rank coals, in the simulations, during coal characterization. For lignite, the data provided showed no extra addition of steam to the gasifier. This is reasonable since lignite does contain a relatively high water composition, which means the water should vaporise at the high temperatures in the gasifier and provide for the steam requirement in gasification. Even with no steam input in the model, the amount of hydrogen in the output is overestimated by an average of 34%. This is also another clue to the possible overestimation of the water composition in characterizing lignite coal. At this stage, the amount of water in the coals could have been manipulated. However, since the gasifier steam data was not clear it was decided to proceed with keeping the ratio of CO:H2 of 2 for a Shell entrained flow gasifier as the target simulation parameter. In absolute terms, this was normally in the 60:30 molar percentage ratio. Methods of doing that, involved manipulating the oxygen and steam feed rates, which altered the gasifier temperature. Since combustion is an exothermic reaction, the temperature was raised by increasing the oxygen flow into the gasifier. The results provided excellent correlations with respect to the CO and H2 that had tight average errors of -1% and 0%, respectively. This meant that the CO:H2 ratios were obtainable under steady-state conditions and further confirm the water-gas shift reaction as the stated goVerning reaction. However, the major setback is the unexpected significant rise in gasifier temperature to above 2000 °C. This temperature rise is due to increased oxygen fed to obtain the desired CO:H2. Water was also present (at output) in the range of about 10-15% for the cases. Methane was absent, as is expected at high temperatures. An exception to both the tables presented is the coal from Poland. In Table 1, it did show the lowest discrepancy at a reasonable level of 4% and 1% for CO and H2, respectively. After adjustment of the feed rate, Table 2 shows that it did not have a huge impact on the temperature change. On inspection, the Polish coal did have the highest CV. Hence, it had the least amount of water among the other coals and most of its composition comprised of 68% carbon and 39% methane. There is the indication that the composition represented the correct H:C ratio generating the smallest errors. But, more importantly, the Polish coal had an ash content of 4.2%, whereas the others had a range of ash contents from 10-14%. In an entrained flow gasifier, the ash leaves the gasifier as particulate matter. Ash does hold a specific heat capacity, and this could potentially contribute to a lower temperature in the entrained flow gasifier than 2000 °C. In the data obtained from ref 3, they had simulated the ash latent heat of fusion as a heat loss. This reveals that the absence of ash compositions could be the potential source of explanation for the very high temperatures. This will need further investigation and will be
Gasification of New Zealand Coals
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Table 3. Discrepancy Results between the Shell Gasifier Base Case Data and HYSYS Generated Data Using the Initial Estimated Coal Composition (by the Calibration Method) variable gasifier outlet temperature gasifier input flow GCV of output gas gas turbine output steam turbine output overall efficiencies (GCV basis)
°C kg/h MJ/Nm3 MW MW %
Shell Gasifier base case (CGCU)
HYSYS model (current study)
difference (%)
1371 221120 11.5 272 189 45.7
1239 221121 13 242 104 38.5
-9.6 0 11.3 -11 -45.1 -15.7
Table 4. Discrepancy Results between the Shell Gasifier Base Case Data and the HYSYS Generated Data, after Manipulation of Coal Composition variable gasifier outlet temperature gasifier input flow GCV of output gas gas turbine output steam turbine output overall efficiencies (GCV basis)
°C kg/h MJ/Nm3 MW MW %
Shell Gasifier base case (CGCU)
HYSYS model (current study)
difference (%)
1371 221120 11.5 272 189 45.7
1361 221121 11.9 223 91 36.5
-0.7 0 3.5 -18 -51.7 -20.1
an area that will require future work. However, for the purposes of this study, NZ coals are known for being low in ash content. Hence on this basis, it is assumed not to have a major effect. Despite this, it was still unclear on the accuracy of the calibration method of coal characterization. This warranted further analysis with clear, reliable data of feed and output, such as the Shell IGCC base case. Hence, accounted below is a simulation case developed for the IGCC which included analysis into its gasifier. 4.3. IGCC Simulation Cases. 4.3.1. Shell Gasifier Model Using Illinois Coal. In verifying the usage of the HYSYS software for modeling IGCC technology, the Shell base case model was used as a reference. This also served as a means of verifying the gasifier model for Illinois No. 6 coal. The parameters used for comparison are listed in Tables 3 and 4. The expander and compressor adiabatic efficiencies of the gas turbine were determined to be 90% and 86%, respectively. The steam turbine efficiency was maintained at 75%. From Table 3, the upstream portion of the IGCC HYSYS model generated a difference of 9.6-11%. This suggests that the gasifier model is within a reasonable accuracy and justifies using the calibration method in characterizing coal. As previously mentioned, the significant hydrogen error must be due to the mischaracterisation of coal based on its calorific value. However, this IGCC base case simulation quantifies that, this method of characterization is viable with a reasonable average error of about 10%. A closer analysis of the gasifier model shows errors similar to those encountered previously. Given that the inlet oxygen, steam, and coal mass flow rates were simulated accordingly, the coal composition was manipulated and the changes in both gasifier temperature and output compositions were observed. The fraction of methane was reduced to 0.12, and consequently, the water and carbon fraction normalized to fractions of 0.2 and 0.68, respectively. Promising results were obtained; however, the gasifier temperature was too low at 1155 °C. This meant that excess water was added, and since it acts as a moderator, it resulted in excessive cooling. Despite its increase, the CO:H2 ratio was not approaching a 2:1 ratio of 0.6:0.3 (estimated from the average dry gas composition of the international coals3). Since steam and oxygen flow rates have been adjusted accordingly to obtain the different temperatures, this leaves the feed coal composition as a potential culprit. CH4 has four hydrogens associated with it, whereas C(s) has none. Hence if CO needed to be higher, to compensate for the high H2, the C(s) fraction was increased. And appropriately,
Table 5. Gasifier Feed Composition for Case 2 gasifier feed variables
Shell case (Illinois No. 6)
lignite
sub-bituminous
coal (mol fraction) oxygen (mol fraction) steam (mol fraction) gasifier temperature (°C)
0.72 0.26 0.02 1395
0.74 0.26 0 1402
0.7 0.28 0.02 1406
for H2 its two feed sources, CH4 or H2O, were adjusted to meet this ratio. It is clearly evident from Table 4 that, after manipulation, there is a significant improvement in the error generated. The gasifier temperature of 1361 °C also agrees well. This resulted in a change in the coal characterization. Water had remained about the same in its absolute value; however, methane was reduced most significantly at 29% and carbon was increased by 6%. Since Illinois coal has a macromolecular representation of CH0.83O0.08 (ignoring nitrogen and sulfur), this was compared to the two different compositions, of above. The first calibration method had a ratio of CH1.3O0.23 which clearly explains the reasons for the errors noticed above. The adjusted composition had a ratio of CH1.1O0.13, which is closer to its original value but it is still misrepresented by more hydrogen and oxygen elements. Despite this, its errors have been proven to be small on the overall gasifier. The Shell gasifier also uses nitrogen as a carrier gas, and although this was negligible as a feed fraction, it was incorporated into the simulations above. Subtracting this nitrogen feed, raised the temperature from 1361 to 1395 °C, which proves its insignificance. 4.3.2. Shell Gasifier Model Using NZ Lignite and Subbituminous Coals. Care should be taken in interpreting the above information, given the possibility of mischaracterizing the coal. It can mean overestimating the amount of total water (steam) or methane fed into gasifier. Case 1 refers to applying the Shell base case model to NZ lignite and sub-bituminous coals according to calibrated compositions. Case 2 (Tables 5 and 6) is analogous to case 1 but involves manipulating the methane fraction of NZ lignite and sub-bituminous coals according to the Shell base case to account for a possible overestimation of methane. Differences in results are shown in Tables 7 and 8. The methane fraction was reduced to about 0.12, and the water fraction was kept constant, while the carbon fraction varied. The amount of oxygen fed into the gasifier was determined by the gasifier temperature, which was maintained at about 1400 °C, as follows from the Shell case without nitrogen feed as the
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Table 6. Gasifier Outlet Composition for Case 2 case 2 component C O2 H2O CO CO2 H2 CH4 N2
lignite (mol %) wet gas
dry gas
0 0 13 52 7 28 0 0
sub-bituminous (mol %) wet gas
65 4 30
Table 7. Differences in Lignite Coal Feed Compositions for Cases 1 and 2 case 1
case 2
error (%)
0.27 0.18 0.55
0.27 0.12 0.61
0 -35 11
Table 8. Differences in Sub-bituminous Coal Compositions between Cases 1 and 2 sub-bituminous in mol fractions water methane carbon
NZ dollars
ASU CCGT GT HRSG ST (total)
1,020,000 -2,160,000 -680,000 1,860,000
gasifier gasifier (Shell CGCU) total (NZD) CAPEX (15% IRR) annual coal consumption (tonnes) NZ$/tonne lignite
6,140,000 6,180,000 1,030,000 1,330,000 0.8
a Negative suggests that lignite cost is higher, and positive suggests that lignite cost is less.
lignite in mol fractions water methane carbon
case 2
dry gas
0 0 6 61 4 29 0 0
60 8 32
Table 9. Capital Cost Differences in Lignite and Sub-bituminous Coals Expressed in NZ Dollars for Case 2a
case 1
case 2
error (%)
0.18 0.2 0.62
0.18 0.11 0.71
0 -43 14
carrier gas. This meant that lignite coal did not require any steam input, but, as expected, sub-bituminous coal required 5000 kg/h of steam. The results obtained were also a better reflection of that expected in a Shell gasifier, with a close 2:1 ratio in the molar (wet or dry) CO:H2 ratios. It is also noted that there is a high water content in the lignite output gas of 13% but only 6% in sub-bituminous gas. The macromolecular representation of NZ lignites is CHO0.35 (ignoring nitrogen and sulfur; reliable ultimate analysis data for sub-bituminous coals could not be sourced). But with the calibration method, the composition was CH1.7O0.37, and when adjusted, it was CH1.4O0.37. This clearly shows that in the adjusted compositions the amount of hydrogen needed to decrease, in order to obtain compositions that fairly matched a Shell gasifier. 4.4. Preliminary Economics. Lignite needs to be about $0.80 less per tonne in order to be competitive with subbituminous coal (Table 9). This is lower than the $1/tonne predicted by case 1. As mentioned previously, the OPEX component only considered has been the cost of coal (raw material). Given that lignite does contain a lot more water, in the initial coal preparation stage, drying costs will need to be accounted for. Since it does not require steam in its feed, this is an advantage considering that sub-bituminous coal will need 5000 kg/h of steam. However, 5000 kg/h in the scale of steam generation in an IGCC is insignificant. Furthermore, other detailed costing involving the logistics, in terms of the locations of coalfield, will need consideration. Overall, this economic costing is an approximation without taking into account the full-scale analysis. This was not necessary as the lignite cases did prove to show that a general trend existed in larger ASUs and lignite gasifiers compared to
the sub-bituminous cases. Although the combined cycle section shows that the sub-bituminous cases will cost more, 30% of the capital expenditure was owing to the gasifiers in both cases as shown. This is in agreement with expected capital costs for an IGCC.13 Hence, as shown, it is the major sole contributor to the large cost difference between the two coals at $6.2 million. The difference is due to the need for 16% more lignite coal than sub-bituminous coal in keeping a constant 400 MW IGCC power output. 5. Conclusions • Modeling coal gasification in HYSYS requires further work. In reality, a meticulous thermodynamic model is normally pursued. • An average error of (10% was quantified and was considered a reasonable preliminary method of representation. • Further adjustment or refinement of the calibration method was possible. For Illinois No. 6 coal, the H:C ratio was overestimated by a 29% decrease in methane content. For NZ lignite coals, a lower H:C ratio was also required. • With gasification data on various coals, it has been deduced that ignoring ash in the coal composition could be the cause to the discrepancies noticed in the energy balances. • 16% more NZ lignite coal was required compared to NZ sub-bituminous coal for a constant 400 MW IGCC power output. • The cost of lignite was $0.8/tonne higher that that of subbituminous coal. Hence, given the abundance of lignite in NZ, it may well overcome this barrier. It must be cautioned that this evaluation only looked at the major capital cost contributors and ignored the actual logistics and operational costs. • The gasifier was the sole major contributor to the high capital cost evident in an IGCC plant, accounting for 30%. The combined cycle and ASU accounted for 7% and 63% of the capital cost respectively. Consequently, the gasifier was also a chief player in the higher capital cost for the lignite case due to the 16% greater lignite coal required compared to subbituminous coal. Acknowledgment. The authors wish to thank Dr. Geoff Whitfield, for external advice as well as providing additional references. EF700704N (13) Van der Burgt, M. IGCC: Cost Reduction Potential EPRI/GTC Gasification Technologies Conference, San Francisco, CA, Oct 4–7, 1998, Netherlands, 1998.
