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engine CHP applications in challenging environments
Fuel 267 (2020) 117303
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Making coal relevant for small scale applications: Modular gasification for syngas/engine CHP applications in challenging environments
T
Charles Warda, Harvey Goldsteinb, Rolf Maurerc, David Thimsenc, Brent J. Sheetsa, Randy Hobbsd, Frances Isgrigga, Russel Steigera, Diane Revay Maddene, Andrea Porcuf, ⁎ Alberto Pettinauf, a
University of Alaska Fairbanks, Fairbanks, AK, USA Worley ltd., Reading, PA, USA c Hamilton Maurer International, Inc., Hudson, IL, USA d Hobbs Industries, Palmar, AK, USA e U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA, USA f Sotacarbo S.p.A., Carbonia, Italy b
A R T I C LE I N FO
A B S T R A C T
Keywords: Biomass Coal Combined heat and power Fixed-bed gasification Syngas engine
Small-scale coal gasification technology, coupled to a reciprocating engine generator, has the potential for making coal a cost competitive resource for meeting the flexible energy needs and resiliency requirements of utilities across the United States. To maintain grid stability and reliability, electrical generation must be regulated to match the load at the proper voltage and frequency. With the expansion of intermittent sources into the grid, such as wind and solar, frequency and voltage regulation become increasingly important and challenging. This work presents the results of a Front End Engineering Design (FEED) effort to detail the engineering and preliminary economics of a small-scale, air blown, fixed-bed gasification process, operating at near-atmospheric pressure, with gas cleanup to provide syngas and pyrolysis liquid fuels for use in reciprocating engine generators for combined heat and power at the University of Alaska Fairbanks. A very detailed assessment of capital and operating costs allows the evaluation of a levelized cost of electricity of 208.06 $/MWh, which can be reduced through the selling of by-products (steam for heating purposes and pyrolysis liquids to be used for power generation in an existing diesel engine). A combined sensitivity analysis, based on the Monte Carlo approach, has been carried out to evaluate the effects of the uncertainties (capital and operating costs and plant annual availability) on the LCOE.
1. Introduction To maintain grid stability and reliability, electrical generation must be regulated to match the load at the proper voltage and frequency. The diffusion of intermittent renewable sources (mainly wind and solar) makes grid regulation increasingly challenging because utilities must balance ever changing electrical loads with ever changing, non-programmable generation [1]. Small-scale gasification technology, coupled to a reciprocating engine generator (gaseous or liquid fueled), has the potential for making coal and biomass a cost competitive resource for meeting the flexible energy needs and resiliency requirements of utilities [2–4]. Several recent studies on potential applications of gasification technologies in rural and remote areas [3,5–8] consider fixed-bed
⁎
down-draft technologies for small-scale (up to 700 kWth) power generation from waste biomass (and sometimes from local coal), but few studies also consider bubbling [9] or circulating fluidized-bed [10] gasification processes for small- and medium-scale applications. With respect to these technologies, up-draft gasification allows a better conversion efficiency [11] but typically involves higher co-production of pyrolysis liquids (oils and tar). This issue limits the application of this technology to power generation units that include a diesel engine generator since the co-produced liquid fuels cannot burned as is in conventional gas engines. Alternatively, the pyrolysis liquids can be sold locally to nearby oil firing consumers. Several authors presenting the results of experimental studies on biomass and waste gasification technologies for small-scale power generation [12–16], but only a few studies [1] consider the possible application of fixed-bed up-draft
Corresponding author. E-mail address: [email protected] (A. Pettinau).
https://doi.org/10.1016/j.fuel.2020.117303 Received 31 May 2019; Received in revised form 28 December 2019; Accepted 1 February 2020 0016-2361/ © 2020 Elsevier Ltd. All rights reserved.
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Nomenclature BEC CFB CHP COE ECM EPA EPC FEED HRSG LAER
LCOE LHV MIFGa NETL
bare erected cost circulating fluidized bed combined heat and power cost of electricity engineering, construction management U.S. Environmental Protection Agency engineer-procure-construction front end engineering design heat recovery steam generator lowest achievable emission rate
NSPS O&M SCR TPC UAF ULSD WESP
levelized cost of electricity lower heating value Mining and Industrial Fuel Gas project U.S. Department of Energy’s National Energy Technology Laboratory new source performance standard operation and maintenance selective catalytic reduction total plant cost University of Alaska Fairbanks ultra-low sulfur diesel wet electrostatic precipitator.
Consequently, PM2.5 and precursors of PM2.5 (NOx, SO2, volatile organic compounds, and ammonia) will be regulated under the nonattainment New Source Performance Standard (NSPS) [24,25]. Thus, the design for the pilot plant includes technologies for lowering SOx and NOx emissions to allow for operating the reciprocating engine generators on syngas and pyrolysis liquids. NSPS may not be necessary for other jurisdictions, but if the pilot plant is built in Fairbanks, then it will provide valuable cost and performance information for designing a system that meets Lowest Achievable Emission Rate (LAER) criteria. LAER is required on major new or modified sources in nonattainment areas. Design documentation and cost estimates, both capital cost and operating and maintenance were developed for the FEED study. Except for the gasification process, current commercial versions of each applicable technology were employed. Technology configurations that cannot reasonably be expected to be available with commercial guarantees were not considered.
gasification technologies. This paper summarizes the results of a technoeconomic evaluation to estimate capital and operating costs and the corresponding Levelized Cost of Electricity (LCOE) of small modular coal and coal/biomass fired power generation units – based on a fixed-bed up-draft gasification process coupled with an advanced tar removal system, fueling commercial Jenbacher internal combustion engine-generators – for small scale, combined heat and power (CHP) applications. In particular, the study is specifically referred to the Alaska Syngas project, a Front End Engineering Design (FEED) study on the potential application of the technology for retrofitting an existing coal-fired power plant on the campus of the University of Alaska Fairbanks (UAF). The project, primarily funded by the U.S. Department of Energy’s National Energy Technology Laboratory (NETL), has the aim to eventually demonstrate, on a first of a kind basis, a modular coal gasification system, which can be augmented with up to 20% woody biomass, that generates a clean syngas and pyrolysis liquids for firing in a suitable engine for providing load following services to the local grid and heat for space conditioning. The performance of the entire power generation unit has been assessed through a simulation model (implemented using Aspen Plus® commercial software) [17], set on the basis of the experimental results obtained during previous research projects in the United States and in Italy. Capital costs are based on quotations for specific plant hardware by the technology providers. Operating costs are based on labor, fuel and consumables costs for Fairbanks, Alaska. Two fuel streams are generated by the gasification technology. The cleaned syngas is sent to two Jenbacher spark ignition engines-generators; the cleaned pyrolysis liquids are blended with ultra-low sulfur diesel oil and sent to a diesel engine generator.
2.2. Fuel characterization Two solid fuels have been specified for use on the project. These include local Usibelli coal – selected as the main fuel because of its availability and low cost (it is mined near the site where the plant is going to be installed) – and biomass (wood chips) recovered from the forest floor for fire abatement. In particular, two different options have been considered in this study: the gasification of Usibelli coal and Usibelli coal mixture with up to 20% (in terms of energy input) wood chips. Due to its high reactivity [26,27], Usibelli coal is particularly suitable for fixed-bed up-draft gasification, as demonstrated in previous experimental studies [21,28]. Table 1 summarizes the characterization of both the considered fuels in terms of proximate, ultimate and calorimetric analyses. Both the fuels, sampled by UAF, were analyzed by SGS North America in 2012 and 2014. As discussed elsewhere in this article, the incremental cost of operation for the gasifier/engine system increases with co-firing of wood chips due to the relatively high cost of this material, which is over five times as costly as Usibelli coal delivered to the Atkinson Power building. Utilization of woody biomass from the forest is only for demonstration purposes, in order to assess the plant performance for possible commercial applications of the technology with waste biomass in other sites.
2. Materials and methods The FEED for the Alaska Syngas Project focuses on retrofitting an existing coal-fired power plant with a modular power generation unit based on advanced fixed-bed up-draft gasification technology, and, as mentioned, incorporates experience gained during two different demonstration-scale coal and biomass gasification projects developed in the United States [18–20] and in Italy [21,22]. 2.1. Context and site The proposed plant will be located at the Atkinson Power Plant on the campus of the University of Alaska Fairbanks. This power plant is equipped with coal, natural gas, and oil-fired boilers, steam turbine generators, and a diesel engine generator. It is also the site of a newly constructed Circulating Fluidized Bed (CFB) boiler and steam turbine generator of nominal 17 MWe capacity meeting current air emissions requirements [23]. The U.S. Environmental Protection Agency (EPA) designated the Fairbanks vicinity, the location of the proposed gasifier/engine demonstration, as a “serious nonattainment area for PM2.5” [24,25].
2.3. Experimental background The fixed-bed up-draft gasification technology selected for the Alaska Syngas Project was developed by Hamilton Maurer International, Inc. (HMI) and is based on the historical WellmanGalusha gasifier, which has a commercial history in municipal and industrial applications dating back at least 80 years [29,30]. This technology is basically characterized by an eccentric grate – which supports the fuel bed, allowing the introduction of the gasification agents and the 2
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experimental tests, funded by the Italian Ministry of Economic Development between 2013 and 2018, provided data to re-design several plant components (e.g. the grate driving mechanism) and the operating procedures to improve the gasifier’s operational performance. These advancements, and additional refinements, are incorporated into the gasification design for the Alaska Syngas Project.
Table 1 Characterization of Usibelli coal and wood waste biomass. Usibelli coal
Biomass
As received
Dry
As received
Dry
Proximate analysis (% by weight) Moisture Volatile matter Ash Fixed Carbon (by difference)
26.93 35.43 7.83 29.82
0.00 48.47 10.72 40.81
7.15 77.90 1.40 13.55
0.00 83.90 1.51 14.59
Ultimate analysis (% by weight) Total carbon Hydrogen Nitrogen Sulfur Oxygen (by difference) Moisture Ash
45.35 3.60 0.53 0.24 15.52 26.93 7.83
62.06 4.93 0.72 0.33 21.24 0.00 10.72
47.16 5.67 0.25 0.03 38.34 7.15 1.40
50.79 6.11 0.27 0.03 41.29 0.00 1.51
Calorimetric analysis (MJ/kg) Higher heating value Lower heating value
18.20 16.86
24.91 23.08
18.37 17.07
19.78 18.38
2.4. Approach and method A heat and material balance was generated for the whole plant (to the level of detail necessary to support the cost estimate) using Aspen Plus® commercial software package [17]. In general, the thermodynamic equilibrium models of fixed-bed gasification processes, if not supported and validated with reliable experimental data, are incapable of accurately predicting performance and syngas composition [28], which are influenced by reaction kinetics and fluid-dynamic effects. Therefore, in order to have a reliable performance prediction, the model of the HMI gasifier was adjusted by reference to extensive data from the MIFGa project and from the Sotacarbo experimental experience. The MIFGa program field performance database was used to develop relatively precise empirical correlations between a wide range of conventional proximate/ultimate/calorific value fuel analyses and flow/composition of five gasifier output streams [19]: dry gas, water vapor and aqueous condensate, organic condensate (tar), unconverted coal dust, and bottom ash. The projected gasification performance (stream output and composition) of Usibelli coal (based on its proximate/ultimate/calorific value analyses) predicted by the MIFGa correlations was used to fine-tune the Aspen Plus® model results. A detailed economic analysis has been performed on the basis of the plant performance, in order to evaluate the levelized cost of electricity (LCOE) for the gasifier/engine system, with a sensitivity analysis to assess the effect of plant life and annual availability on LCOE. Moreover, due to the uncertainties of a few parameters, a combined sensitivity based on Monte-Carlo probabilistic approach has been assessed.
discharge of bottom ash – and by an intercooled stirrer which allows to optimize fuel distribution into the bed. The gasification technology was tested for 10,000 h (between 1981 and 1985) in a 1.98 m (6.5 ft) internal diameter reactor within the Mining and Industrial Fuel Gas (MIFGa) Project, sponsored by both the U.S. Bureau of Mines and the U.S. Department of Energy (U.S. Bureau of Mines Contract H0222001) [20]. That project gasified 18 different U.S. coals representing different coal types, using the same gasifier and process conditions, generating a consistent and complete database for the gasification technology operating on a wide range of coals and biomass. The same technology has been successfully tested by Ansaldo Energia (former Ansaldo Ricerche) in Genova, Italy, in a 1.3 m diameter gasifier, in operation between 1999 and 2001, designed by HMI specifically for biomass. The technology has been further developed by Sotacarbo in a demoscale (1.3 m diameter) gasification unit, originally designed on the basis of the Ansaldo Energia’s experience [21,26]. More than 2,000 h of
3. Plant configuration The plant configuration, schematically represented in Fig. 1, has
Fig. 1. Plant configuration simplified scheme. 3
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Model J620 spark ignition engine generators, equipped with catalytic reactors for carbon monoxide conversion and a Selective Catalytic Reduction (SCR) system for NOx removal. Exhaust streams from the diesel engine and from the spark ignition engine flow through Heat Recovery Steam Generators (HRSGs) to produce steam at about 2 bar for co-generation purposes. In the UAF application, the gasifier will operate at about 66% capacity. The gasifier was sized to provide syngas for 3 Jenbacher engines. Only 2 engines were selected for the UAF project at this time to avoid the added costs associated with transforming additional space for a third Jenbacher engine. Future expansion of the system is possible to incorporate a third Jenbacher engine and increase system output accordingly.
Table 2 Summary of the gasification performance. Primary fuel
100% Coal
80% Coal/20% Biomass
Usibelli coal to gasifier (kg/h) Usibelli coal to gasifier (kWth) Biomass to gasifier (kg/h) Biomass to gasifier (kWth) Pyrolysis liquids production (m3/day) Pyrolysis liquids production (kWth)(1) Syngas flow (m3/h) Syngas energy (kWth)(2) Gasifier losses (kWth) Gasifier Efficiency (%)(3)
3,185 14,910 0 0 4.13 2,107 6,344 10,421 2,382 84
2,673 12,513 662 3,135 4.93 2,506 6,288 10,420 2,722 83
Notes: (1) Referred to a lower heating value of 35.03–35.10 MJ/kg. (2) Referred to a lower heating value of 5.92–5.96 MJ/kg. (3) Calculated as the ratio between the thermal power output of syngas, pyrolysis liquids and the thermal power input of coal and biomass.
4. Plant performance As mentioned, plant performance is assessed for two cases: (1) the gasification of 100% Usibelli coal, and (2) the case of 80% Usibelli coal and 20% wood chips (by energy input). Modeled gasifier performance – in terms of material and energy balances – is presented in Table 2. An additional small amount of energy recovery is possible from the gasifier if the syngas cooler is used to generate low pressure steam; however, UAF’s design is configured to generate relatively low temperature “hot” water. Gasifier efficiency for UAF’s application is thus calculated at around 85%, based on energy inputs and outputs measured in terms of lower heating values (LHV). Tables 3 and 4 summarize the performance of the gas engine generator and the existing diesel engine generator, respectively. The gasifier and the gas engines are closely coupled operationally in that they must function as a unit. If less fuel is called for by the spark ignition engines, then the output of syngas will be reduced by moderating the air and steam flow into the reactor while maintaining the reactor set pressure. The diesel engine is decoupled from both the gasifier and the gas engine generators as it will rely mostly on ultra-low sulfur diesel for operation, supplemented by pyrolysis liquids from the gasifier, which will be stored in tanks until needed. It can be seen that the gas engine operates at a power generation efficiency of 34% and a co-generation efficiency up to 70%. The diesel engine fed with ULSD enriched with pyrolysis liquids separated from syngas can allow an annual average power generation efficiency of 39% and a co-generation efficiency of 63%.
been designed to generate electricity and low pressure steam by utilizing syngas and pyrolysis liquids (oils and tars) as fuels in engine generators. The core of the plant is the air-blown fixed-bed gasification reactor. Primary fuel (mainly coal) – characterized by a particle size between 6 and 8 mm and 35–37 mm – is loaded into the top of the 3.05 m (10 ft) diameter gasification reactor, operating at an internal pressure of about 1.7 bar. As the fuel descends, it is progressively dried, devolatilized, pyrolyzed, while being pre-heated to gasification temperatures by the ascending gas flow. It is then gasified with residual carbon being burned with air in a relatively thin combustion zone immediately above the ash zone. Residual ash is collected on a grate, insulating the grate from the combustion zone [31,32]. The gasification agents (blast air and steam) are introduced into the reactor through the ash-pit, below the gasifier grate, and thus are pre-heated as they pass through and cooling bottom ashes. The ash is removed through the eccentric grate. Oxygen in the blast disappears quickly by combustion with residual char leaving the gasification zone. The endothermic gasification reactions are powered by the high-temperature combustion products ascending from the combustion zone. The ascending gas leaving the gasification zone loses temperature as it progressively pyrolyzes, devolatilizes and dries the descending coal. The gas leaving the gasifier is a mixture of dry gas, water vapor, condensable organics (pyrolysis liquids, i.e. oils and tar) and unconverted dust. In order to distribute the fuel as uniformly as possible, the reactor is equipped with a stirrer (internally cooled to keep a low metal temperature), which is characterized by two degrees of freedom: an axial rotation and a vertical translation [33,34]. Furthermore, the gasifier is equipped with a cooling water jacket, in order to operate an accurate temperature control. Raw syngas is preliminarily treated by passing through a high efficiency hot cyclone (operating at about 200 °C and more) and cooled to less than 50 °C using high efficiency surface contact condensers. The particulate cleaned syngas then enters a wet electrostatic precipitator (WESP), which removes pyrolysis liquids from the tar fog. The WESP is designed to condense and separate 99.9% of the pyrolysis liquids from the syngas. The wet caustic scrubber downstream of the WESP operates in a reducing environment to remove H2S prior to delivering the syngas to the spark ignition engines. Pyrolysis liquids removed by the WESP are temporarily stored and delivered to the Colt Pielstick Model 18PC2.6 V diesel engine, currently installed at the University of Alaska Fairbanks. The engine is capable of utilizing the pyrolysis liquids blended with ultra-low sulfur diesel (ULSD) at a 15:85 ratio of pyrolysis liquids and ULSD, which reflects the ratio of liquid fuels expected with the gasifier operating at full capacity and the diesel generator operating at its rated capacity. In parallel, clean syngas is sent to two 1,965 kWe Innio Jenbacher
5. Cost assessment Capital and operating costs were estimated for the whole plant Table 3 Summary of the gas engine generator performance. Primary fuel (1)
Syngas power (kWth) Syngas energy (kWh)(1) Gas engine gross power (kWe) Auxiliary electric loads (kWe) Net electric power (kWe) Steam generation (kg/h)(2) Steam generation (kWth)(2) Building heat during winter (kWth) Building heat during summer (kWth) Net electric efficiency (%) Cogener. efficiency during winter (%) Cogener. efficiency during summer (%)
100% Coal
80% Coal/20% Biomass
10,421 10,551 3,930 360 3,570 2,591 1,961 1,679 422 34 69 53
10,420 10,551 3,930 360 3,570 2,636 1,995 1,679 422 34 70 53
Notes: Referred to a lower heating value of 5.92–5.96 MJ/kg. (1) Referred to a lower heating value of 5.92–5.96 MJ/kg. (2) Saturated steam at 10 bar produced by the HRSG minus steam used for gasifier and dewpoint heater. 4
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Table 4 Summary of the diesel engine generator performance. Load
Maximum power
Annual average power (50%)
Primary fuel
100% Coal
80% Coal/20% Biomass
100% Coal
80% Coal/20% Biomass
Diesel engine gross power (kWe) Auxiliary electric loads (kWe) Net electric power (kWe) Steam generation (kg/h)(1) Steam generation (kWth)(1) Pyrolysis liquids as fuel (m3/day) Pyrolysis liquids as fuel (kWth)(2) Ultra-low sulfur diesel fuel (l/min) Ultra-low sulfur diesel fuel (kWth)(3) Net electric efficiency (%)(4) Cogeneration efficiency (%)(5)
9,600 210 9,390 7,810 5,910 4.13 2,107 409 21,205 40 66
9,600 210 9,390 7,831 5,926 4.93 2,506 401 20,805 40 66
4,800 168 4,632 3,905 2,955 4.13 2,107 193 9,899 39 63
4,800 168 4,632 3,915 2,963 4.93 2,506 185 9,499 39 63
(1)
Saturated steam at 10 bar produced by the HRSG. Referred to a lower heating value of 35.03–35.10 MJ/kg. (3) Referred to a lower heating value of 43.88 MJ/kg. (4) Calculated as the ratio between the electric power and the thermal power of both the considered fuels (pyrolysis liquids and ULSD). (5) Calculated as the ratio between the whole (electric and thermal) power output and the thermal power input of both the considered fuels (pyrolysis liquids and ULSD). (2)
would be a first of a kind plant: even with the accomplishment of a prior FEED study in hand, there are still technical issues to be resolved and new designs to be executed; (2) this is a very small plant, and engineering and design costs do not scale very well with the size of the unit; (3) the engineering and design activities and costs are relatively insensitive to plant size, varying to a small degree. Capital costs analysis includes two kinds of contingencies, related to process and project. Process contingency reflects anticipated risk in the validity of the cost account due to the immaturity of specific line items in the estimate; it varies from 5–10% depending on the amount of risk assessed for each item. Project contingency is assigned at a constant percentage at 15% across the entire project and is assessed on the sum of BEC, ECM, and also on the process contingency. Finally, it is assumed that the method of contracting will be Engineer-Procure-Construction (EPC) management. For this type of contracting, the owner takes the risk of project over-runs. The EPC management contractor or contractors act in a professional capacity, providing design, engineering, and project construction management services. For EPC type contracting, the contractor adds a premium based on their expectations of risk in the project. This risk premium can be expected to be in the range of 30% or higher for this type of project. Table 5 reports, section by section, a summary of the plant total plant cost of the whole plant. The project is estimated to have a bare erected cost of 33.4 M$ and a total plant cost of 45.7 M$, where the cost of gasification impacts just
based on the plant process data and equipment requirements developed during the conceptual design, and both the Cost of Electricity (COE) and the Levelized Cost of Electricity (LCOE) were estimated. The procedure for the evaluation of capital costs and Operation and Maintenance (O&M) costs is similar to that used by the U.S. Department of Energy – National Energy Technology Laboratory (NETL) to assess capital and operating costs of power generation plants fed with fossil fuels [35,36]. The cost of the only non-conventional section (i.e. the gasification reactor) was determined on the basis of specific offers by the potential providers (based on the preliminary design of the component). The other components are commercial and their market costs were considered. 5.1. Capital costs Capital costs were determined for a series of accounts, each covering a major system or structure comprising the total plant. Within each account, costs are presented in a cumulative manner, starting with basic equipment costs, and adding cost of materials and labor to install or erect to arrive at a Bare Erected Cost (BEC). Engineering, Construction Management (ECM), and related fees are then added. This category of costs for commercial plants is typically assessed to be in the range of 7–12% of the BEC. The value used for this function herein is assessed at 17.5% based on several factors: (1) this Table 5 Summary of the plant’s capital costs (k$). Equip-ment
Equipment demolition & removal Structural additions & modifications Fuel handling Gasification Syngas conditioning Gas engine power generation train Ash handling Balance of plant mechanical system Oils and tar Diesel engine (integration) Dry ESP Electrical Instrumentation Total cost
0 0 472 2,200 3,025 5,970 528 288 145 115 1,700 205 890 15,565
Mate-rial
25 474 54 126 110 322 53 383 12 5 120 99 83 1,866
Labor
Sales tax
6,567 864 371 775 634 1,074 315 2,355 200 70 1,649 900 204 15,978
0 0 0 0 0 0 0 0 0 0 0 0 0 0
5
BEC
6,592 1,338 897 3,101 3,796 7,366 896 3,026 375 190 3,469 1,204 1,177 33,409
ECM
1,154 234 157 543 664 1,289 157 530 62 33 607 211 206 5,847
Contingencies
TPC
proc.
proj.
0 0 0 196 261 0 0 0 10 0 0 0 20 486
1,162 236 158 576 708 1,298 158 533 64 33 611 212 210 5,961
8,907 1,808 1,212 4,416 5,429 9,953 1,211 4,089 439 257 4,687 1,627 1,613 45,703
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for about 10% and the most relevant costs are related to the purchase of the gas engine (22%) and to the demolition and removal of the existing equipment (19%).
Table 7 Specific costs for consumables and waste disposal. Consumables
Waste disposal (1)
Ammonia ($/l) Caustic ($/l)(2) Hypochlorite ($/l)(3) SCR catalyst ($/m3) CO catalyst ($/m3) Water ($/m3)
5.2. Operating and maintenance costs Operating and Maintenance (O&M) costs include fixed costs for labor and variable costs for fuels and consumables. Fixed (labor) costs are calculated on the basis of the conventional rates in Alaska. In particular, a base rate of 50 $/h was assumed, with a burden of 30% and an extra overhead charge rate of 25%. Plant management requires that an average of two skilled operators per shift be added to the current operating staff at the Atkinson Power plant (no additional operators are required for the use of the diesel engine). It corresponds to the annual labor cost summarized in Table 6. The analysis was carried out for the two scenarios related to fuel composition (i.e. 100% Usielli coal or 80% Usibelli coal and 20% biomass). In all the cases, an annual availability of 85% (7,450 h per year) was assumed. As for primary fuels, a price of 82.97 $/t was assumed for the purchase of Usibelli coal (it is the current price per metric ton for coal supply in the Atkinson Power plant), whereas biomass is purchased at a market price assumed 366.85 $/t. The gas engines only fire the clean syngas produced by the gasifier, whereas the diesel engine fires a blend of ULSD (currently supplied at a price of 0.62 $/l) and pyrolysis liquids produced by the gasifier. For operation of the 3.05 m diameter HMI gasifier proposed for UAF to support full load operation of the 2 Jenbacher engines, the gasifier will produce sufficient pyrolysis liquids to represent 9.0% of the capacity of the existing 9.6 MWe diesel engine with the diesel operating at full load. The balance of the fuel required by the diesel must be provided by ULSD. The monetary value of the pyrolysis liquids provided to the diesel engine by the gasification unit (0.62 $/l) is accounted for in the O &M cost analysis by debiting the diesel for this value and crediting the gasifier/gas engine system a like amount. In addition to fuel, other costs for operation of the gasifier/gas engine system have to be considered for maintenance materials, consumables (i.e. ammonia, caustic and hypochlorite for gas treatment and catalysts for SCR and CO conversion) and waste disposal (exhausted catalysts, waste water, ash and other solid waste). The specific costs of these materials are reported in Table 7. The system is also credited with the value of pyrolysis liquids for additional power generation in the diesel engine and of low pressure steam supplied to the low pressure steam header of the University campus (which value is calculated in 34.10 $/t). Taken together, the credit for pyrolysis liquids production and cogenerating steam production comprise about three fourths of the cost of the primary fuel (Usibelli coal). No credits are considered for gas engine waste heat used to heat the Atkinson Power building. Moreover, there is no accounting for emissions penalties or credits, as none were identified thus far in this study. Calculation of O&M costs for the diesel engine is much simplified compared to the gasifier/engine case, since the diesel engine is already installed and staffing already embedded in current operation at the Atkinson Power plant. The only variable costs involve fuel, ammonia for NOx reduction in the SCR installed in the duct between the engine
0.74 1.58 0.79 2,720.00 3,635.00 2.63
Waste water ($/m3) Ash ($/t) Other solid waste SCR catalyst ($/m3) CO catalyst ($/m3)(4)
3.18 87.50 0.00 111.00 0.00
Notes: (1) Aqueous NH3 solution at 19% by weight for SCR. (2) Aqueous NaOH solution at 40% for gas desulfurization. (3) Aqueous NaOCl solution at 15% for gas desulfurization. (4) Catalyst is assumed to be recycled. Table 8 Summary of the annual operating (variable) costs (k$/year). Gasification + gas engine
Diesel engine
Coal/biomass ratio
100/0%
80/20%
100/0%
80/20%
Fuels Usibelli coal Biomass Ultra-low sulfur diesel Oils and tars Maintenance materials Water Chemicals (solvents and catalysts) Waste disposal By-products Pyrolysis liquids Steam Total fixed costs
2,170 2,170 0 0 0 553 45 739
3,812 1,820 1,992 0 0 553 45 739
6,441 0 0 5,641 800 114 0 1,417
6,441 0 0 5,489 952 114 0 1,417
385 −1,687 −800 −887 2,204
340 −1,839 −952 −887 3,650
593 −994 0 −994 7,571
593 −994 0 −994 7,571
and the HRSG, and an allowance for periodic catalyst replacement. Ammonia consumption is increased significantly relative to the gas engines because the diesel engine produces more power, but mostly because specific NOx production is higher. The annual variable O&M costs of the project are reported in Table 8, with reference to the same scenarios considered for fixed costs calculation. The most relevant variable cost of the gasification/gas engine system is due to fuel supply, which impacts for 39% if only Usibelli coal is gasified and for 53% when 20% biomass is used in the fuel mix (see Fig. 2). 5.3. Modularity and scalability The gasifier/engine concept is inherently modular and scalable. The applicable size range for this HMI gasifier/Jenbacher engine concept for solid fueled power generation with cogenerated steam (CHP) for typical Alaskan deployment is considered to be economically viable in a size range from about 2 MWe up to 40 MWe or larger. The gasifier/engine system described herein provides a high degree
Table 6 Summary of the annual labor (fixed) costs (k$/year). Gasification + gas engine
Diesel engine (additional)
Coal/biomass ratio
100/0%
80/20%
100/0%
80/20%
Annual operating labor cost Maintenance labor cost Administrative and support labor Property taxes and insurance Total fixed costs
1,139 226 341 excluded 1,706
1,139 226 341 excluded 1,706
0 76 19 excluded 95
0 76 19 excluded 95
6
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(a) Gasification of 100% Usibelli coal
(b) Gasification of 80% coal and 20% biomass
Fig. 2. Distribution of operating (variable) costs.
utilized to handle peak loads, leaving the gasifier/engine combination to be base loaded. A 7 MWe conceptual plant is based on the 3 m (10 ft) gasifier and gas clean-up train evaluated for the Alaska Syngas project, and 3 Jenbacher engines rated at 5.9 MWe in total. For this plant, a Wartsila model 6L20 diesel engine rated at 1.1 MWe running at 900 rpm fires the pyrolysis liquids. Finally, a 21 MWe conceptual plant is comprised of two 3.7 m (12 ft and 3′) gasifier and gas clean-up trains and 9 Jenbacher engines rated at 17.7 MWe in total. For this plant, a Wartsila model 6L32 diesel engine or a similar engine rated at an estimated 3.3 MWe at 720 rpm is selected to fire the pyrolysis liquids. This engine can fire a range of heavy oils encompassing the properties of the pyrolysis liquids produced by the gasifier. The general arrangement is very similar to that of the 7 MWe configuration. The two gasifier trains are arranged in parallel, as are the gas engines. If either configuration (7 MWe or 21 MWe) is operated at part load, the engines can be operated down to about 40% load, or individual engines can be shut down. For grid stability duty following wind, part load operation is most likely preferred. The efficiency and capital costs as function of plant size of the gasifier/gas engine system are reported in Table 9. For any size modular plant, the efficiency of the gasifier/engine system remains essentially constant. This is not the case for a conventional boiler/steam turbine based solid fuel burning plant, which experiences a significant reduction in thermal efficiency in very small sizes. In addition, the capital costs do not scale linearly with plant size. The electric and cogenerating efficiencies are assumed constant, as the Jenbacher engine(s) is (are) the principal power and steam generators. The larger plant might exhibit slightly greater efficiencies if the larger diesel engines provided for these cases show improved efficiency over the smallest unit. Efficiency values shown are for coal to bus-bar, or coal to bus-bar plus steam. For comparison, Figs. 3 and 4 present similar information for a fossil
of modularity and scalability. These attributes arise from the nature of the individual components selected to make up the complete system. By increasing or decreasing the number of gasifiers and engines, any specified amount of power may be produced. At present Jenbacher is only offering the J620 engine for firing syngas, rated at 1.965 MWe per engine. Other engines may be available or Jenbacher could extend their line of syngas capable engines. The J620 engine has 20 cylinders; in principal, similar engines can be built with any number of cylinders from 4 to 24. This provides the potential for a very wide range of power outputs divided into as many engines as desired. For the present, the J620 with 20 cylinders is considered the essential modular building block, along with the gasifier for the power generation system. The gasifier can be scaled up or down in diameter, providing some scalability for the system in addition to the modularity provided by varying the number of gasifiers. These modularity and scalability aspects of the system provide the ability to design a system with reliable performance and costs over a wide range of system electric generation capacities. The cyclone, gas cooler, WESP, and caustic scrubber are all scalable along with the gasifier, up or down. The scaling follows a simple relationship, where input and output are proportional to the square of the gasifier diameter. Thus, a 2.4 m (8 ft) internal diameter gasifier can be expected to have the capacity to provide gas to 2 Jenbacher J620 engines, generating about 3.9 MWe. Two 3.7 m internal diameter gasifiers can be expected produce syngas for 9 Jenbacher engines to produce about 18 MWe. This is probably the largest size that can be contemplated for interior Alaska, since the outside diameter of such a unit will be around 4 m, which is near the limit to allow normal shipping and transport methods. The HMI gasifier also has a wide range of partial power operation; it can be turned down to 30% load or less without compromising gasifier performance. As mentioned, the system also produces pyrolysis liquids that can be fired in a diesel engine or sold for blending with other liquid hydrocarbons. There is a wide range of diesel engines in various sizes available for firing the pyrolysis liquids. In the UAF demonstration plant case, the heavy-duty Colt Pielstick engine in place at UAF will be used. Some examples of system configurations based on the essential components are provided below. The capital cost estimates for each case includes added funds for coal storage and other items necessary in a greenfield application. A 2 MWe plant is the smallest configuration evaluated at present. This unit is assumed to be comprised of one 1.8 m (6 ft) gasifier with cleanup train, one J620 Jenbacher engine, and one Wartsila model 4L20 diesel engine operating at 900 rpm producing about 0.74 MWe. The Wartsila engine only operates at about 50% load, or 100% load for 50% of the time, unless the pyrolysis liquid yield from the gasifier is supplemented with ULSD. For this application, the diesel engine can be
Table 9 Efficiency and capital costs as function of plant size.
7
Plant Size (MWe)
2
7
21
No. of gasifier / internal diameter (m) No. Jenbacher Engines Electric efficiency, LHV base (%) Cogen steam (kg/h at 2 bar) Cogeneration steam (kWth) Cogeneration efficiency, LHV base (%) Total plant cost (M$) Total plant specific cost ($/kWe)
1/1.8 1 29.6 1,297 980 45.8 33 14,300
1/3.0 3 29.6 3,887 2,940 45.8 64 9,100
2/3.7 9 29.6 11,662 8,825 45.8 154 7,300
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Fig. 3. Electric efficiency at different values of plant size.
6. Economic performance and sensitivity
boiler and steam turbine at the same rating points presented in Table 9. The boiler is assumed to be a circulating fluidized bed (CFB) combustor generating steam at the conditions noted in the table. The 21 MWe plant is calibrated to the performance and costs of the 17 MWe CFB plant just completed at UAF (described in Section 2.1). The smaller plants are based on similar configurations to the UAF CFB, with adjustments to the steam cycle to reflect the limits of practice for small steam plants (throttle pressure, throttle temperature, number of feed-water heaters, etc.). The data also shows that for plant sizes below about 30–35 MWe, the HMI gasifier/Jenbacher engine plant can be built in Fairbanks Alaska for a lower capital cost than a boiler/steam turbine plant of comparable size.
The economic analysis here reported is referred to the gasifier/engine system, since the diesel engine is already existing. In addition, as mentioned, a sensitivity analysis has been assessed to consider the effect of the key economic parameters. 6.1. Economic performance The economic assessment here reported is based on the estimation of both the Cost of Electricity (COE) and the Levelized Cost of Electricity (LCOE), both expressed in $/MWh. COE is defined as the ratio between the overall plant costs (both capital and operating), evaluated during all the project life, and the total amount of electrical energy produced in the same period. The same ratio, referred to the
Fig. 4. Total plant specific cost at different values of plant size. 8
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7. Conclusions
present values of each cost and profit, is the LCOE, defined as: n
LCOE =
∑i = 1 (Ci + Oi )
This paper summarizes the results of the feasibility study of the Alaska Syngas project, which aims to install a small modular coal and coal/biomass fired power generation units based on a fixed-bed updraft gasification process coupled with a combined heat and power generator for retrofitting an existing coal-fired power plant on the campus of the University of Alaska Fairbanks. The unit also aims to demonstrate the potential for small-scale, modular, coal gasification technology to provide low-cost fuel for firing reciprocating engine generators with syngas and pyrolysis liquids (oils and tar). By coupling the gasifier with a reciprocating engine, the gasifier/engine combination can be used in baseload and non-baseload applications, and in distributed generation applications. Plant configuration consists of a 3 m diameter fixed-bed up-draft gasifier and gas clean-up equipment suppling the clean syngas to two Jenbacher J620 spark ignition engines for electric power generation. Pyrolysis liquids will be collected and routed to an existing diesel generator. The proposed solution, being modular and scalable, is feasible for commercial-scale applications in the range between 2 and 30 MWe. The gasification of Usibelli coal (100% or 80% with the addition of woody biomass), for a thermal input of about 15 MW, allows to produce about 3.6 MW of electrical energy and about 2.0 MW of steam, with a power generation efficiency of about 25% and a co-generation efficiency of about 37%, considering the whole gasification/gas engine system. In addition, pyrolysis liquids produced by the gasification process (4–5 m3/day, corresponding to 2.1–2.5 MWth) can be used as fuel additive in a diesel engine fed with ultra-low sulfur diesel, allowing a further energy recovery. The project is estimated to have a bare erected cost of 33.4 M$ and a total plant cost of 45.7 M$, where the cost of gasification impacts just for about 10% and the most relevant costs are related to the purchase of the gas engine (22%). Considering the gasifier/engine system fed with 100% Usibelli coal, the unit allows a levelized cost of electricity of 208.06 $/MWh, referred to a plant operating life of 20 years. A sensitivity analysis shows the significant impact of plant’s annual availability on LCOE, whereas relatively low variations of LCOE ( ± 5%) are due to the uncertainties on capital cost estimation or to the variability of the local market.
n
∑i = 1 Ei
where i is the progressive year of the project (i = 1 is the construction phase whereas i = n is the last year of operation), Ci and Oi are the present values of capital and O&M costs (in M$) in year i, respectively, and Ei is the overall amount of electrical energy (in GWh) produced in year i [9,37]. The analysis was carried out calculating, year by year, the annual cash flow related to the gasifier/engine system, based on the assumptions summarized in Table 10. The values are referred to the feeding with 100% Usibelli coal. With specific reference to the Alaska Syngas project, it has been assumed that the whole investment is directly paid without the opening of a senior debt with the banks. Therefore, no interests have been considered in the economic analysis. The analysis, in its base case, shows a COE of 300.21 $/MWh and a LCOE of 208.06 $/MWh. This value is strongly influenced by the plant operating life, assumed 20 years. Fig. 5 shows the linear variation of LCOE for shorter values of the operating life. It is important to underline that LCOE, as defined above, does not consider the revenues for selling the by-products (pyrolysis liquids and steam), but it is only referred to the costs for electricity production.
6.2. Sensitivity analyses The economic analysis here reported is subjected to a series of uncertainties due to the variability of several economic parameters, such as capital and operating costs. Therefore, a combined sensitivity analysis can be a very useful approach to evaluate if and how these parameters affect the LCOE. The sensitivity analysis here reported is based on the Monte Carlo probabilistic method, which is an algorithm that relies on repeated random sampling to obtain numerical results [38–40]. Ten groups of 100,000 iterations have been performed for each case. As stated above, the analysis has been performed with the @ RISK commercial software [41], largely utilized for similar analyses on several fields, when it is impossible to predict the exact impact of several variables on the profitability of the investment. A first simulation was carried out to assess how LCOE is affected by the plant annual availability. It has a significant impact on the variable component of the operating costs and it determines the whole production of electrical energy. The sensitivity analysis here reported (Fig. 6a) assumes a probability of 90% that the annual availability ranges between 6,000 and 8,000 h per year, with a maximum value corresponding to 7,450 h per year, which is the base case assumption. The analysis shows that LCOE ranges between 194 and 260 $/MWh with a probability of 90% (Fig. 6b). A combined sensitivity analysis was carried out to assess the combined effect of the possible variation of several costs on the LCOE. In particular, as for capital costs, the only non-commercial section is represented by the gasification reactor, which cost was assessed during the FEED study on the basis of specific offers. For this section, a 90% probability of a capital costs uncertainties of ± 10% (with respect to the base case) was assumed. For the other sections, only commercial components were considered, so their capital costs are very reliable. The other uncertainties are related to the variable operating costs, influenced by the local or the international market. For all these costs, a Gaussian distribution was considered to estimate their possible variation, within the ranges summarized in Table 11. The result of the combined sensitivity is represented in Fig. 7, which shows that the plant has 90% of probability to allow a LCOE between 198.6 and 217.5 $/MWh.
CRediT authorship contribution statement Charles Ward: Software, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Harvey Goldstein: Software, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Rolf Maurer: Software, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. David Thimsen: Software, Table 10 Economic analysis: main assumptions. Starting of construction phase (year)
2020
Plant construction period (years) Operating life (years)(1) Depreciation period (years) Plant availability (hours/year) Capital costs ($) Operating costs ($/year)(2) Produced electrical energy (kWh/year) Produced thermal energy (kWh/year) Annual discount rate (%) Annual inflation rate (%)
1 20 10 7500 45,703,000 5,595,499 26,250,000 7,878,125 8.0 2.0
Notes: (1) Operating life between 2021 and 2040. (2) Referred to the first year of operation. 9
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Table 11 Uncertainties related to the cost assessment. Cost
Base case
Variation(1)
Gasifier capital cost ($) Usibelli coal ($/year)(2) Maintenance materials ($/year) Chemicals: solvents and catalysts ($/year) Waste disposal ($/year)
4,416,000 2,170,000 553,000 739,000 385,000
± 10% ± 5% ± 10% ± 5% ± 15%
Note: (1)
90% of probability that costs uncertainties ranges within the reported values with a Gaussian distribution. (2) The market price of Usibelli coal is historically very stable.
Writing - review & editing, Visualization. Diane Revay Madden: Project administration, Writing - review & editing. Andrea Porcu: Formal analysis, Investigation, writing - original draft. Alberto Pettinau: Writing - original draft, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization.
Fig. 5. Variation of LCOE with the plant operating life.
Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Brent J. Sheets: Supervision, Writing - review & editing, Visualization. Randy Hobbs: Writing - review & editing, Visualization. Frances Isgrigg: Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Russel Steiger: Validation, Formal analysis, Investigation, Resources,
(a) Assumed probability density function for plant availability.
(b) Resulted probability density function for LCOE. Fig. 6. Impact of plant availability on LCOE. 10
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Fig. 7. Combined sensitivity analysis on LCOE.
Declaration of Competing Interest
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The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgements This work is funded by the U.S. Department of Energy, National Energy Technology Laboratory (DOE Award Number: DE-FE0031446), with cost share by UAF, HMI, Sotacarbo, Golden Valley Electric Association, Aurora Energy LLC, and Hobbs Industries, Inc. References [1] U.S. Department of Energy, National Energy Technology Laboratory. The Role of Coal in a Smart Grid Environment. DOE/NETL – 2011/1474 Final Report 2011 [2] Segurado R, Pereira S, Correia D, Costa M. Techno-economic analysis of a trigeneration system based on biomass gasification. Renew Sustain Energy Rev 2019;103:501–14. [3] Thengane SK, Gupta A, Mahajani SM. Co-gasification of high ash biomass and high ash coal in downdraft gasifier. Bioresour Technol 2019;273:159–68. [4] Upadhyay DS, Sakhiya AK, Panchal K, Patel AH, Patel RN. Effect of equivalence ratio on the performance of the downdraft gasifier – An experimental and modelling approach. Energy 2019;168:833–46. [5] Commeh MH, Kemausuor F, Badger EN, Osei N. Experimental study of ferrocement downdraft gasifier engine system using different biomass feedstocks in Ghana. Sustainable Energy Technol Assess 2019;31:124–31. [6] Allesina G, Pedrazzi S, Allegretti F, Morselli N, Puglia M, Santunione G, et al. Gasification of cotton crop residues for combined power and biochar production in Mozambique. Appl Therm Eng 2018;139:387–94. [7] Madav V, Das D, Kumar M, Surwade M, Parikh PP, Sethi V. Studies for removal of tar from producer gas in small scale biomass gasifiers using biodiesel. Biomass Bioenergy 2019;123:123–33. [8] You S, Tong H, Armin-Hoiland J, Tong YW, Wang CH. Techno-economic and greenhouse gas savings assessment of decentralized biomass gasification for electrifying the rural areas of Indonesia. Appl Energy 2017;208:495–510. [9] Porcu A, Sollai S, Marotto D, Mureddu M, Ferrara F, Pettinau A. Techno-economic analysis of a small-scale biomass-to-energy BFB gasification-based system. Energies 2019;12:494–511. [10] Huang Y, Zhao Y, Hao Y, Wei G, Feng J, Li W, et al. A feasibility analysis of distributed power plants from agricultural residues resources gasification in rural China. Biomass Bioenergy 2019;121:1–12. [11] Liakakou ET, Vreugdenhil BJ, Cerone N, Zimbardi F, Pinto F, André R, et al. Gasification of lignin-rich residues for the production of biofuels via syngas fermentation: comparison of gasification technologies. Fuel 2019;251:580–92. [12] Ding L, Yoshikawa K, Fukuhara M, Xin D, Muhan L. Development of an ultra-small biomass gasification and power generation system: Part 1. A novel carbonization process and optimization of pelletization of carbonized wood char. Fuel 2017;210:674–83. [13] Ding L, Yoshikawa K, Fukuhara M, Kowata Y, Nakamura S, Xin D, Muhan L. Development of an ultra-small biomass gasification and power generation system: Part 2. Gasification characteristics of carbonized pellets/briquettes in a pilot-scale updraft fixed bed gasifier. Fuel 2018;220:210–9.
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uncertain-ties to the combined environmental and economic assessment of algal biorefineries: a Monte Carlo approach. Sci Total Environ 2018;626:762–75. [40] Liu J, Jin F, Xie Q, Skitmore M. Improving risk assessment in financial feasibility of international engineering projects: A risk driver perspective. Int J Proj Manag 2017;35:204–11. [41] Palisade Corporation @RISK, user’s guide – Risk analysis and simulation add-in for Microsoft®Excel; Palisade Corporation 2015 Ithaca, NY, USA
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Contents lists available at ScienceDirect
Fuel journal homepage: www.elsevier.com/locate/fuel
Making coal relevant for small scale applications: Modular gasification for syngas/engine CHP applications in challenging environments
T
Charles Warda, Harvey Goldsteinb, Rolf Maurerc, David Thimsenc, Brent J. Sheetsa, Randy Hobbsd, Frances Isgrigga, Russel Steigera, Diane Revay Maddene, Andrea Porcuf, ⁎ Alberto Pettinauf, a
University of Alaska Fairbanks, Fairbanks, AK, USA Worley ltd., Reading, PA, USA c Hamilton Maurer International, Inc., Hudson, IL, USA d Hobbs Industries, Palmar, AK, USA e U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA, USA f Sotacarbo S.p.A., Carbonia, Italy b
A R T I C LE I N FO
A B S T R A C T
Keywords: Biomass Coal Combined heat and power Fixed-bed gasification Syngas engine
Small-scale coal gasification technology, coupled to a reciprocating engine generator, has the potential for making coal a cost competitive resource for meeting the flexible energy needs and resiliency requirements of utilities across the United States. To maintain grid stability and reliability, electrical generation must be regulated to match the load at the proper voltage and frequency. With the expansion of intermittent sources into the grid, such as wind and solar, frequency and voltage regulation become increasingly important and challenging. This work presents the results of a Front End Engineering Design (FEED) effort to detail the engineering and preliminary economics of a small-scale, air blown, fixed-bed gasification process, operating at near-atmospheric pressure, with gas cleanup to provide syngas and pyrolysis liquid fuels for use in reciprocating engine generators for combined heat and power at the University of Alaska Fairbanks. A very detailed assessment of capital and operating costs allows the evaluation of a levelized cost of electricity of 208.06 $/MWh, which can be reduced through the selling of by-products (steam for heating purposes and pyrolysis liquids to be used for power generation in an existing diesel engine). A combined sensitivity analysis, based on the Monte Carlo approach, has been carried out to evaluate the effects of the uncertainties (capital and operating costs and plant annual availability) on the LCOE.
1. Introduction To maintain grid stability and reliability, electrical generation must be regulated to match the load at the proper voltage and frequency. The diffusion of intermittent renewable sources (mainly wind and solar) makes grid regulation increasingly challenging because utilities must balance ever changing electrical loads with ever changing, non-programmable generation [1]. Small-scale gasification technology, coupled to a reciprocating engine generator (gaseous or liquid fueled), has the potential for making coal and biomass a cost competitive resource for meeting the flexible energy needs and resiliency requirements of utilities [2–4]. Several recent studies on potential applications of gasification technologies in rural and remote areas [3,5–8] consider fixed-bed
⁎
down-draft technologies for small-scale (up to 700 kWth) power generation from waste biomass (and sometimes from local coal), but few studies also consider bubbling [9] or circulating fluidized-bed [10] gasification processes for small- and medium-scale applications. With respect to these technologies, up-draft gasification allows a better conversion efficiency [11] but typically involves higher co-production of pyrolysis liquids (oils and tar). This issue limits the application of this technology to power generation units that include a diesel engine generator since the co-produced liquid fuels cannot burned as is in conventional gas engines. Alternatively, the pyrolysis liquids can be sold locally to nearby oil firing consumers. Several authors presenting the results of experimental studies on biomass and waste gasification technologies for small-scale power generation [12–16], but only a few studies [1] consider the possible application of fixed-bed up-draft
Corresponding author. E-mail address: [email protected] (A. Pettinau).
https://doi.org/10.1016/j.fuel.2020.117303 Received 31 May 2019; Received in revised form 28 December 2019; Accepted 1 February 2020 0016-2361/ © 2020 Elsevier Ltd. All rights reserved.
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Nomenclature BEC CFB CHP COE ECM EPA EPC FEED HRSG LAER
LCOE LHV MIFGa NETL
bare erected cost circulating fluidized bed combined heat and power cost of electricity engineering, construction management U.S. Environmental Protection Agency engineer-procure-construction front end engineering design heat recovery steam generator lowest achievable emission rate
NSPS O&M SCR TPC UAF ULSD WESP
levelized cost of electricity lower heating value Mining and Industrial Fuel Gas project U.S. Department of Energy’s National Energy Technology Laboratory new source performance standard operation and maintenance selective catalytic reduction total plant cost University of Alaska Fairbanks ultra-low sulfur diesel wet electrostatic precipitator.
Consequently, PM2.5 and precursors of PM2.5 (NOx, SO2, volatile organic compounds, and ammonia) will be regulated under the nonattainment New Source Performance Standard (NSPS) [24,25]. Thus, the design for the pilot plant includes technologies for lowering SOx and NOx emissions to allow for operating the reciprocating engine generators on syngas and pyrolysis liquids. NSPS may not be necessary for other jurisdictions, but if the pilot plant is built in Fairbanks, then it will provide valuable cost and performance information for designing a system that meets Lowest Achievable Emission Rate (LAER) criteria. LAER is required on major new or modified sources in nonattainment areas. Design documentation and cost estimates, both capital cost and operating and maintenance were developed for the FEED study. Except for the gasification process, current commercial versions of each applicable technology were employed. Technology configurations that cannot reasonably be expected to be available with commercial guarantees were not considered.
gasification technologies. This paper summarizes the results of a technoeconomic evaluation to estimate capital and operating costs and the corresponding Levelized Cost of Electricity (LCOE) of small modular coal and coal/biomass fired power generation units – based on a fixed-bed up-draft gasification process coupled with an advanced tar removal system, fueling commercial Jenbacher internal combustion engine-generators – for small scale, combined heat and power (CHP) applications. In particular, the study is specifically referred to the Alaska Syngas project, a Front End Engineering Design (FEED) study on the potential application of the technology for retrofitting an existing coal-fired power plant on the campus of the University of Alaska Fairbanks (UAF). The project, primarily funded by the U.S. Department of Energy’s National Energy Technology Laboratory (NETL), has the aim to eventually demonstrate, on a first of a kind basis, a modular coal gasification system, which can be augmented with up to 20% woody biomass, that generates a clean syngas and pyrolysis liquids for firing in a suitable engine for providing load following services to the local grid and heat for space conditioning. The performance of the entire power generation unit has been assessed through a simulation model (implemented using Aspen Plus® commercial software) [17], set on the basis of the experimental results obtained during previous research projects in the United States and in Italy. Capital costs are based on quotations for specific plant hardware by the technology providers. Operating costs are based on labor, fuel and consumables costs for Fairbanks, Alaska. Two fuel streams are generated by the gasification technology. The cleaned syngas is sent to two Jenbacher spark ignition engines-generators; the cleaned pyrolysis liquids are blended with ultra-low sulfur diesel oil and sent to a diesel engine generator.
2.2. Fuel characterization Two solid fuels have been specified for use on the project. These include local Usibelli coal – selected as the main fuel because of its availability and low cost (it is mined near the site where the plant is going to be installed) – and biomass (wood chips) recovered from the forest floor for fire abatement. In particular, two different options have been considered in this study: the gasification of Usibelli coal and Usibelli coal mixture with up to 20% (in terms of energy input) wood chips. Due to its high reactivity [26,27], Usibelli coal is particularly suitable for fixed-bed up-draft gasification, as demonstrated in previous experimental studies [21,28]. Table 1 summarizes the characterization of both the considered fuels in terms of proximate, ultimate and calorimetric analyses. Both the fuels, sampled by UAF, were analyzed by SGS North America in 2012 and 2014. As discussed elsewhere in this article, the incremental cost of operation for the gasifier/engine system increases with co-firing of wood chips due to the relatively high cost of this material, which is over five times as costly as Usibelli coal delivered to the Atkinson Power building. Utilization of woody biomass from the forest is only for demonstration purposes, in order to assess the plant performance for possible commercial applications of the technology with waste biomass in other sites.
2. Materials and methods The FEED for the Alaska Syngas Project focuses on retrofitting an existing coal-fired power plant with a modular power generation unit based on advanced fixed-bed up-draft gasification technology, and, as mentioned, incorporates experience gained during two different demonstration-scale coal and biomass gasification projects developed in the United States [18–20] and in Italy [21,22]. 2.1. Context and site The proposed plant will be located at the Atkinson Power Plant on the campus of the University of Alaska Fairbanks. This power plant is equipped with coal, natural gas, and oil-fired boilers, steam turbine generators, and a diesel engine generator. It is also the site of a newly constructed Circulating Fluidized Bed (CFB) boiler and steam turbine generator of nominal 17 MWe capacity meeting current air emissions requirements [23]. The U.S. Environmental Protection Agency (EPA) designated the Fairbanks vicinity, the location of the proposed gasifier/engine demonstration, as a “serious nonattainment area for PM2.5” [24,25].
2.3. Experimental background The fixed-bed up-draft gasification technology selected for the Alaska Syngas Project was developed by Hamilton Maurer International, Inc. (HMI) and is based on the historical WellmanGalusha gasifier, which has a commercial history in municipal and industrial applications dating back at least 80 years [29,30]. This technology is basically characterized by an eccentric grate – which supports the fuel bed, allowing the introduction of the gasification agents and the 2
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experimental tests, funded by the Italian Ministry of Economic Development between 2013 and 2018, provided data to re-design several plant components (e.g. the grate driving mechanism) and the operating procedures to improve the gasifier’s operational performance. These advancements, and additional refinements, are incorporated into the gasification design for the Alaska Syngas Project.
Table 1 Characterization of Usibelli coal and wood waste biomass. Usibelli coal
Biomass
As received
Dry
As received
Dry
Proximate analysis (% by weight) Moisture Volatile matter Ash Fixed Carbon (by difference)
26.93 35.43 7.83 29.82
0.00 48.47 10.72 40.81
7.15 77.90 1.40 13.55
0.00 83.90 1.51 14.59
Ultimate analysis (% by weight) Total carbon Hydrogen Nitrogen Sulfur Oxygen (by difference) Moisture Ash
45.35 3.60 0.53 0.24 15.52 26.93 7.83
62.06 4.93 0.72 0.33 21.24 0.00 10.72
47.16 5.67 0.25 0.03 38.34 7.15 1.40
50.79 6.11 0.27 0.03 41.29 0.00 1.51
Calorimetric analysis (MJ/kg) Higher heating value Lower heating value
18.20 16.86
24.91 23.08
18.37 17.07
19.78 18.38
2.4. Approach and method A heat and material balance was generated for the whole plant (to the level of detail necessary to support the cost estimate) using Aspen Plus® commercial software package [17]. In general, the thermodynamic equilibrium models of fixed-bed gasification processes, if not supported and validated with reliable experimental data, are incapable of accurately predicting performance and syngas composition [28], which are influenced by reaction kinetics and fluid-dynamic effects. Therefore, in order to have a reliable performance prediction, the model of the HMI gasifier was adjusted by reference to extensive data from the MIFGa project and from the Sotacarbo experimental experience. The MIFGa program field performance database was used to develop relatively precise empirical correlations between a wide range of conventional proximate/ultimate/calorific value fuel analyses and flow/composition of five gasifier output streams [19]: dry gas, water vapor and aqueous condensate, organic condensate (tar), unconverted coal dust, and bottom ash. The projected gasification performance (stream output and composition) of Usibelli coal (based on its proximate/ultimate/calorific value analyses) predicted by the MIFGa correlations was used to fine-tune the Aspen Plus® model results. A detailed economic analysis has been performed on the basis of the plant performance, in order to evaluate the levelized cost of electricity (LCOE) for the gasifier/engine system, with a sensitivity analysis to assess the effect of plant life and annual availability on LCOE. Moreover, due to the uncertainties of a few parameters, a combined sensitivity based on Monte-Carlo probabilistic approach has been assessed.
discharge of bottom ash – and by an intercooled stirrer which allows to optimize fuel distribution into the bed. The gasification technology was tested for 10,000 h (between 1981 and 1985) in a 1.98 m (6.5 ft) internal diameter reactor within the Mining and Industrial Fuel Gas (MIFGa) Project, sponsored by both the U.S. Bureau of Mines and the U.S. Department of Energy (U.S. Bureau of Mines Contract H0222001) [20]. That project gasified 18 different U.S. coals representing different coal types, using the same gasifier and process conditions, generating a consistent and complete database for the gasification technology operating on a wide range of coals and biomass. The same technology has been successfully tested by Ansaldo Energia (former Ansaldo Ricerche) in Genova, Italy, in a 1.3 m diameter gasifier, in operation between 1999 and 2001, designed by HMI specifically for biomass. The technology has been further developed by Sotacarbo in a demoscale (1.3 m diameter) gasification unit, originally designed on the basis of the Ansaldo Energia’s experience [21,26]. More than 2,000 h of
3. Plant configuration The plant configuration, schematically represented in Fig. 1, has
Fig. 1. Plant configuration simplified scheme. 3
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Model J620 spark ignition engine generators, equipped with catalytic reactors for carbon monoxide conversion and a Selective Catalytic Reduction (SCR) system for NOx removal. Exhaust streams from the diesel engine and from the spark ignition engine flow through Heat Recovery Steam Generators (HRSGs) to produce steam at about 2 bar for co-generation purposes. In the UAF application, the gasifier will operate at about 66% capacity. The gasifier was sized to provide syngas for 3 Jenbacher engines. Only 2 engines were selected for the UAF project at this time to avoid the added costs associated with transforming additional space for a third Jenbacher engine. Future expansion of the system is possible to incorporate a third Jenbacher engine and increase system output accordingly.
Table 2 Summary of the gasification performance. Primary fuel
100% Coal
80% Coal/20% Biomass
Usibelli coal to gasifier (kg/h) Usibelli coal to gasifier (kWth) Biomass to gasifier (kg/h) Biomass to gasifier (kWth) Pyrolysis liquids production (m3/day) Pyrolysis liquids production (kWth)(1) Syngas flow (m3/h) Syngas energy (kWth)(2) Gasifier losses (kWth) Gasifier Efficiency (%)(3)
3,185 14,910 0 0 4.13 2,107 6,344 10,421 2,382 84
2,673 12,513 662 3,135 4.93 2,506 6,288 10,420 2,722 83
Notes: (1) Referred to a lower heating value of 35.03–35.10 MJ/kg. (2) Referred to a lower heating value of 5.92–5.96 MJ/kg. (3) Calculated as the ratio between the thermal power output of syngas, pyrolysis liquids and the thermal power input of coal and biomass.
4. Plant performance As mentioned, plant performance is assessed for two cases: (1) the gasification of 100% Usibelli coal, and (2) the case of 80% Usibelli coal and 20% wood chips (by energy input). Modeled gasifier performance – in terms of material and energy balances – is presented in Table 2. An additional small amount of energy recovery is possible from the gasifier if the syngas cooler is used to generate low pressure steam; however, UAF’s design is configured to generate relatively low temperature “hot” water. Gasifier efficiency for UAF’s application is thus calculated at around 85%, based on energy inputs and outputs measured in terms of lower heating values (LHV). Tables 3 and 4 summarize the performance of the gas engine generator and the existing diesel engine generator, respectively. The gasifier and the gas engines are closely coupled operationally in that they must function as a unit. If less fuel is called for by the spark ignition engines, then the output of syngas will be reduced by moderating the air and steam flow into the reactor while maintaining the reactor set pressure. The diesel engine is decoupled from both the gasifier and the gas engine generators as it will rely mostly on ultra-low sulfur diesel for operation, supplemented by pyrolysis liquids from the gasifier, which will be stored in tanks until needed. It can be seen that the gas engine operates at a power generation efficiency of 34% and a co-generation efficiency up to 70%. The diesel engine fed with ULSD enriched with pyrolysis liquids separated from syngas can allow an annual average power generation efficiency of 39% and a co-generation efficiency of 63%.
been designed to generate electricity and low pressure steam by utilizing syngas and pyrolysis liquids (oils and tars) as fuels in engine generators. The core of the plant is the air-blown fixed-bed gasification reactor. Primary fuel (mainly coal) – characterized by a particle size between 6 and 8 mm and 35–37 mm – is loaded into the top of the 3.05 m (10 ft) diameter gasification reactor, operating at an internal pressure of about 1.7 bar. As the fuel descends, it is progressively dried, devolatilized, pyrolyzed, while being pre-heated to gasification temperatures by the ascending gas flow. It is then gasified with residual carbon being burned with air in a relatively thin combustion zone immediately above the ash zone. Residual ash is collected on a grate, insulating the grate from the combustion zone [31,32]. The gasification agents (blast air and steam) are introduced into the reactor through the ash-pit, below the gasifier grate, and thus are pre-heated as they pass through and cooling bottom ashes. The ash is removed through the eccentric grate. Oxygen in the blast disappears quickly by combustion with residual char leaving the gasification zone. The endothermic gasification reactions are powered by the high-temperature combustion products ascending from the combustion zone. The ascending gas leaving the gasification zone loses temperature as it progressively pyrolyzes, devolatilizes and dries the descending coal. The gas leaving the gasifier is a mixture of dry gas, water vapor, condensable organics (pyrolysis liquids, i.e. oils and tar) and unconverted dust. In order to distribute the fuel as uniformly as possible, the reactor is equipped with a stirrer (internally cooled to keep a low metal temperature), which is characterized by two degrees of freedom: an axial rotation and a vertical translation [33,34]. Furthermore, the gasifier is equipped with a cooling water jacket, in order to operate an accurate temperature control. Raw syngas is preliminarily treated by passing through a high efficiency hot cyclone (operating at about 200 °C and more) and cooled to less than 50 °C using high efficiency surface contact condensers. The particulate cleaned syngas then enters a wet electrostatic precipitator (WESP), which removes pyrolysis liquids from the tar fog. The WESP is designed to condense and separate 99.9% of the pyrolysis liquids from the syngas. The wet caustic scrubber downstream of the WESP operates in a reducing environment to remove H2S prior to delivering the syngas to the spark ignition engines. Pyrolysis liquids removed by the WESP are temporarily stored and delivered to the Colt Pielstick Model 18PC2.6 V diesel engine, currently installed at the University of Alaska Fairbanks. The engine is capable of utilizing the pyrolysis liquids blended with ultra-low sulfur diesel (ULSD) at a 15:85 ratio of pyrolysis liquids and ULSD, which reflects the ratio of liquid fuels expected with the gasifier operating at full capacity and the diesel generator operating at its rated capacity. In parallel, clean syngas is sent to two 1,965 kWe Innio Jenbacher
5. Cost assessment Capital and operating costs were estimated for the whole plant Table 3 Summary of the gas engine generator performance. Primary fuel (1)
Syngas power (kWth) Syngas energy (kWh)(1) Gas engine gross power (kWe) Auxiliary electric loads (kWe) Net electric power (kWe) Steam generation (kg/h)(2) Steam generation (kWth)(2) Building heat during winter (kWth) Building heat during summer (kWth) Net electric efficiency (%) Cogener. efficiency during winter (%) Cogener. efficiency during summer (%)
100% Coal
80% Coal/20% Biomass
10,421 10,551 3,930 360 3,570 2,591 1,961 1,679 422 34 69 53
10,420 10,551 3,930 360 3,570 2,636 1,995 1,679 422 34 70 53
Notes: Referred to a lower heating value of 5.92–5.96 MJ/kg. (1) Referred to a lower heating value of 5.92–5.96 MJ/kg. (2) Saturated steam at 10 bar produced by the HRSG minus steam used for gasifier and dewpoint heater. 4
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Table 4 Summary of the diesel engine generator performance. Load
Maximum power
Annual average power (50%)
Primary fuel
100% Coal
80% Coal/20% Biomass
100% Coal
80% Coal/20% Biomass
Diesel engine gross power (kWe) Auxiliary electric loads (kWe) Net electric power (kWe) Steam generation (kg/h)(1) Steam generation (kWth)(1) Pyrolysis liquids as fuel (m3/day) Pyrolysis liquids as fuel (kWth)(2) Ultra-low sulfur diesel fuel (l/min) Ultra-low sulfur diesel fuel (kWth)(3) Net electric efficiency (%)(4) Cogeneration efficiency (%)(5)
9,600 210 9,390 7,810 5,910 4.13 2,107 409 21,205 40 66
9,600 210 9,390 7,831 5,926 4.93 2,506 401 20,805 40 66
4,800 168 4,632 3,905 2,955 4.13 2,107 193 9,899 39 63
4,800 168 4,632 3,915 2,963 4.93 2,506 185 9,499 39 63
(1)
Saturated steam at 10 bar produced by the HRSG. Referred to a lower heating value of 35.03–35.10 MJ/kg. (3) Referred to a lower heating value of 43.88 MJ/kg. (4) Calculated as the ratio between the electric power and the thermal power of both the considered fuels (pyrolysis liquids and ULSD). (5) Calculated as the ratio between the whole (electric and thermal) power output and the thermal power input of both the considered fuels (pyrolysis liquids and ULSD). (2)
would be a first of a kind plant: even with the accomplishment of a prior FEED study in hand, there are still technical issues to be resolved and new designs to be executed; (2) this is a very small plant, and engineering and design costs do not scale very well with the size of the unit; (3) the engineering and design activities and costs are relatively insensitive to plant size, varying to a small degree. Capital costs analysis includes two kinds of contingencies, related to process and project. Process contingency reflects anticipated risk in the validity of the cost account due to the immaturity of specific line items in the estimate; it varies from 5–10% depending on the amount of risk assessed for each item. Project contingency is assigned at a constant percentage at 15% across the entire project and is assessed on the sum of BEC, ECM, and also on the process contingency. Finally, it is assumed that the method of contracting will be Engineer-Procure-Construction (EPC) management. For this type of contracting, the owner takes the risk of project over-runs. The EPC management contractor or contractors act in a professional capacity, providing design, engineering, and project construction management services. For EPC type contracting, the contractor adds a premium based on their expectations of risk in the project. This risk premium can be expected to be in the range of 30% or higher for this type of project. Table 5 reports, section by section, a summary of the plant total plant cost of the whole plant. The project is estimated to have a bare erected cost of 33.4 M$ and a total plant cost of 45.7 M$, where the cost of gasification impacts just
based on the plant process data and equipment requirements developed during the conceptual design, and both the Cost of Electricity (COE) and the Levelized Cost of Electricity (LCOE) were estimated. The procedure for the evaluation of capital costs and Operation and Maintenance (O&M) costs is similar to that used by the U.S. Department of Energy – National Energy Technology Laboratory (NETL) to assess capital and operating costs of power generation plants fed with fossil fuels [35,36]. The cost of the only non-conventional section (i.e. the gasification reactor) was determined on the basis of specific offers by the potential providers (based on the preliminary design of the component). The other components are commercial and their market costs were considered. 5.1. Capital costs Capital costs were determined for a series of accounts, each covering a major system or structure comprising the total plant. Within each account, costs are presented in a cumulative manner, starting with basic equipment costs, and adding cost of materials and labor to install or erect to arrive at a Bare Erected Cost (BEC). Engineering, Construction Management (ECM), and related fees are then added. This category of costs for commercial plants is typically assessed to be in the range of 7–12% of the BEC. The value used for this function herein is assessed at 17.5% based on several factors: (1) this Table 5 Summary of the plant’s capital costs (k$). Equip-ment
Equipment demolition & removal Structural additions & modifications Fuel handling Gasification Syngas conditioning Gas engine power generation train Ash handling Balance of plant mechanical system Oils and tar Diesel engine (integration) Dry ESP Electrical Instrumentation Total cost
0 0 472 2,200 3,025 5,970 528 288 145 115 1,700 205 890 15,565
Mate-rial
25 474 54 126 110 322 53 383 12 5 120 99 83 1,866
Labor
Sales tax
6,567 864 371 775 634 1,074 315 2,355 200 70 1,649 900 204 15,978
0 0 0 0 0 0 0 0 0 0 0 0 0 0
5
BEC
6,592 1,338 897 3,101 3,796 7,366 896 3,026 375 190 3,469 1,204 1,177 33,409
ECM
1,154 234 157 543 664 1,289 157 530 62 33 607 211 206 5,847
Contingencies
TPC
proc.
proj.
0 0 0 196 261 0 0 0 10 0 0 0 20 486
1,162 236 158 576 708 1,298 158 533 64 33 611 212 210 5,961
8,907 1,808 1,212 4,416 5,429 9,953 1,211 4,089 439 257 4,687 1,627 1,613 45,703
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for about 10% and the most relevant costs are related to the purchase of the gas engine (22%) and to the demolition and removal of the existing equipment (19%).
Table 7 Specific costs for consumables and waste disposal. Consumables
Waste disposal (1)
Ammonia ($/l) Caustic ($/l)(2) Hypochlorite ($/l)(3) SCR catalyst ($/m3) CO catalyst ($/m3) Water ($/m3)
5.2. Operating and maintenance costs Operating and Maintenance (O&M) costs include fixed costs for labor and variable costs for fuels and consumables. Fixed (labor) costs are calculated on the basis of the conventional rates in Alaska. In particular, a base rate of 50 $/h was assumed, with a burden of 30% and an extra overhead charge rate of 25%. Plant management requires that an average of two skilled operators per shift be added to the current operating staff at the Atkinson Power plant (no additional operators are required for the use of the diesel engine). It corresponds to the annual labor cost summarized in Table 6. The analysis was carried out for the two scenarios related to fuel composition (i.e. 100% Usielli coal or 80% Usibelli coal and 20% biomass). In all the cases, an annual availability of 85% (7,450 h per year) was assumed. As for primary fuels, a price of 82.97 $/t was assumed for the purchase of Usibelli coal (it is the current price per metric ton for coal supply in the Atkinson Power plant), whereas biomass is purchased at a market price assumed 366.85 $/t. The gas engines only fire the clean syngas produced by the gasifier, whereas the diesel engine fires a blend of ULSD (currently supplied at a price of 0.62 $/l) and pyrolysis liquids produced by the gasifier. For operation of the 3.05 m diameter HMI gasifier proposed for UAF to support full load operation of the 2 Jenbacher engines, the gasifier will produce sufficient pyrolysis liquids to represent 9.0% of the capacity of the existing 9.6 MWe diesel engine with the diesel operating at full load. The balance of the fuel required by the diesel must be provided by ULSD. The monetary value of the pyrolysis liquids provided to the diesel engine by the gasification unit (0.62 $/l) is accounted for in the O &M cost analysis by debiting the diesel for this value and crediting the gasifier/gas engine system a like amount. In addition to fuel, other costs for operation of the gasifier/gas engine system have to be considered for maintenance materials, consumables (i.e. ammonia, caustic and hypochlorite for gas treatment and catalysts for SCR and CO conversion) and waste disposal (exhausted catalysts, waste water, ash and other solid waste). The specific costs of these materials are reported in Table 7. The system is also credited with the value of pyrolysis liquids for additional power generation in the diesel engine and of low pressure steam supplied to the low pressure steam header of the University campus (which value is calculated in 34.10 $/t). Taken together, the credit for pyrolysis liquids production and cogenerating steam production comprise about three fourths of the cost of the primary fuel (Usibelli coal). No credits are considered for gas engine waste heat used to heat the Atkinson Power building. Moreover, there is no accounting for emissions penalties or credits, as none were identified thus far in this study. Calculation of O&M costs for the diesel engine is much simplified compared to the gasifier/engine case, since the diesel engine is already installed and staffing already embedded in current operation at the Atkinson Power plant. The only variable costs involve fuel, ammonia for NOx reduction in the SCR installed in the duct between the engine
0.74 1.58 0.79 2,720.00 3,635.00 2.63
Waste water ($/m3) Ash ($/t) Other solid waste SCR catalyst ($/m3) CO catalyst ($/m3)(4)
3.18 87.50 0.00 111.00 0.00
Notes: (1) Aqueous NH3 solution at 19% by weight for SCR. (2) Aqueous NaOH solution at 40% for gas desulfurization. (3) Aqueous NaOCl solution at 15% for gas desulfurization. (4) Catalyst is assumed to be recycled. Table 8 Summary of the annual operating (variable) costs (k$/year). Gasification + gas engine
Diesel engine
Coal/biomass ratio
100/0%
80/20%
100/0%
80/20%
Fuels Usibelli coal Biomass Ultra-low sulfur diesel Oils and tars Maintenance materials Water Chemicals (solvents and catalysts) Waste disposal By-products Pyrolysis liquids Steam Total fixed costs
2,170 2,170 0 0 0 553 45 739
3,812 1,820 1,992 0 0 553 45 739
6,441 0 0 5,641 800 114 0 1,417
6,441 0 0 5,489 952 114 0 1,417
385 −1,687 −800 −887 2,204
340 −1,839 −952 −887 3,650
593 −994 0 −994 7,571
593 −994 0 −994 7,571
and the HRSG, and an allowance for periodic catalyst replacement. Ammonia consumption is increased significantly relative to the gas engines because the diesel engine produces more power, but mostly because specific NOx production is higher. The annual variable O&M costs of the project are reported in Table 8, with reference to the same scenarios considered for fixed costs calculation. The most relevant variable cost of the gasification/gas engine system is due to fuel supply, which impacts for 39% if only Usibelli coal is gasified and for 53% when 20% biomass is used in the fuel mix (see Fig. 2). 5.3. Modularity and scalability The gasifier/engine concept is inherently modular and scalable. The applicable size range for this HMI gasifier/Jenbacher engine concept for solid fueled power generation with cogenerated steam (CHP) for typical Alaskan deployment is considered to be economically viable in a size range from about 2 MWe up to 40 MWe or larger. The gasifier/engine system described herein provides a high degree
Table 6 Summary of the annual labor (fixed) costs (k$/year). Gasification + gas engine
Diesel engine (additional)
Coal/biomass ratio
100/0%
80/20%
100/0%
80/20%
Annual operating labor cost Maintenance labor cost Administrative and support labor Property taxes and insurance Total fixed costs
1,139 226 341 excluded 1,706
1,139 226 341 excluded 1,706
0 76 19 excluded 95
0 76 19 excluded 95
6
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(a) Gasification of 100% Usibelli coal
(b) Gasification of 80% coal and 20% biomass
Fig. 2. Distribution of operating (variable) costs.
utilized to handle peak loads, leaving the gasifier/engine combination to be base loaded. A 7 MWe conceptual plant is based on the 3 m (10 ft) gasifier and gas clean-up train evaluated for the Alaska Syngas project, and 3 Jenbacher engines rated at 5.9 MWe in total. For this plant, a Wartsila model 6L20 diesel engine rated at 1.1 MWe running at 900 rpm fires the pyrolysis liquids. Finally, a 21 MWe conceptual plant is comprised of two 3.7 m (12 ft and 3′) gasifier and gas clean-up trains and 9 Jenbacher engines rated at 17.7 MWe in total. For this plant, a Wartsila model 6L32 diesel engine or a similar engine rated at an estimated 3.3 MWe at 720 rpm is selected to fire the pyrolysis liquids. This engine can fire a range of heavy oils encompassing the properties of the pyrolysis liquids produced by the gasifier. The general arrangement is very similar to that of the 7 MWe configuration. The two gasifier trains are arranged in parallel, as are the gas engines. If either configuration (7 MWe or 21 MWe) is operated at part load, the engines can be operated down to about 40% load, or individual engines can be shut down. For grid stability duty following wind, part load operation is most likely preferred. The efficiency and capital costs as function of plant size of the gasifier/gas engine system are reported in Table 9. For any size modular plant, the efficiency of the gasifier/engine system remains essentially constant. This is not the case for a conventional boiler/steam turbine based solid fuel burning plant, which experiences a significant reduction in thermal efficiency in very small sizes. In addition, the capital costs do not scale linearly with plant size. The electric and cogenerating efficiencies are assumed constant, as the Jenbacher engine(s) is (are) the principal power and steam generators. The larger plant might exhibit slightly greater efficiencies if the larger diesel engines provided for these cases show improved efficiency over the smallest unit. Efficiency values shown are for coal to bus-bar, or coal to bus-bar plus steam. For comparison, Figs. 3 and 4 present similar information for a fossil
of modularity and scalability. These attributes arise from the nature of the individual components selected to make up the complete system. By increasing or decreasing the number of gasifiers and engines, any specified amount of power may be produced. At present Jenbacher is only offering the J620 engine for firing syngas, rated at 1.965 MWe per engine. Other engines may be available or Jenbacher could extend their line of syngas capable engines. The J620 engine has 20 cylinders; in principal, similar engines can be built with any number of cylinders from 4 to 24. This provides the potential for a very wide range of power outputs divided into as many engines as desired. For the present, the J620 with 20 cylinders is considered the essential modular building block, along with the gasifier for the power generation system. The gasifier can be scaled up or down in diameter, providing some scalability for the system in addition to the modularity provided by varying the number of gasifiers. These modularity and scalability aspects of the system provide the ability to design a system with reliable performance and costs over a wide range of system electric generation capacities. The cyclone, gas cooler, WESP, and caustic scrubber are all scalable along with the gasifier, up or down. The scaling follows a simple relationship, where input and output are proportional to the square of the gasifier diameter. Thus, a 2.4 m (8 ft) internal diameter gasifier can be expected to have the capacity to provide gas to 2 Jenbacher J620 engines, generating about 3.9 MWe. Two 3.7 m internal diameter gasifiers can be expected produce syngas for 9 Jenbacher engines to produce about 18 MWe. This is probably the largest size that can be contemplated for interior Alaska, since the outside diameter of such a unit will be around 4 m, which is near the limit to allow normal shipping and transport methods. The HMI gasifier also has a wide range of partial power operation; it can be turned down to 30% load or less without compromising gasifier performance. As mentioned, the system also produces pyrolysis liquids that can be fired in a diesel engine or sold for blending with other liquid hydrocarbons. There is a wide range of diesel engines in various sizes available for firing the pyrolysis liquids. In the UAF demonstration plant case, the heavy-duty Colt Pielstick engine in place at UAF will be used. Some examples of system configurations based on the essential components are provided below. The capital cost estimates for each case includes added funds for coal storage and other items necessary in a greenfield application. A 2 MWe plant is the smallest configuration evaluated at present. This unit is assumed to be comprised of one 1.8 m (6 ft) gasifier with cleanup train, one J620 Jenbacher engine, and one Wartsila model 4L20 diesel engine operating at 900 rpm producing about 0.74 MWe. The Wartsila engine only operates at about 50% load, or 100% load for 50% of the time, unless the pyrolysis liquid yield from the gasifier is supplemented with ULSD. For this application, the diesel engine can be
Table 9 Efficiency and capital costs as function of plant size.
7
Plant Size (MWe)
2
7
21
No. of gasifier / internal diameter (m) No. Jenbacher Engines Electric efficiency, LHV base (%) Cogen steam (kg/h at 2 bar) Cogeneration steam (kWth) Cogeneration efficiency, LHV base (%) Total plant cost (M$) Total plant specific cost ($/kWe)
1/1.8 1 29.6 1,297 980 45.8 33 14,300
1/3.0 3 29.6 3,887 2,940 45.8 64 9,100
2/3.7 9 29.6 11,662 8,825 45.8 154 7,300
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Fig. 3. Electric efficiency at different values of plant size.
6. Economic performance and sensitivity
boiler and steam turbine at the same rating points presented in Table 9. The boiler is assumed to be a circulating fluidized bed (CFB) combustor generating steam at the conditions noted in the table. The 21 MWe plant is calibrated to the performance and costs of the 17 MWe CFB plant just completed at UAF (described in Section 2.1). The smaller plants are based on similar configurations to the UAF CFB, with adjustments to the steam cycle to reflect the limits of practice for small steam plants (throttle pressure, throttle temperature, number of feed-water heaters, etc.). The data also shows that for plant sizes below about 30–35 MWe, the HMI gasifier/Jenbacher engine plant can be built in Fairbanks Alaska for a lower capital cost than a boiler/steam turbine plant of comparable size.
The economic analysis here reported is referred to the gasifier/engine system, since the diesel engine is already existing. In addition, as mentioned, a sensitivity analysis has been assessed to consider the effect of the key economic parameters. 6.1. Economic performance The economic assessment here reported is based on the estimation of both the Cost of Electricity (COE) and the Levelized Cost of Electricity (LCOE), both expressed in $/MWh. COE is defined as the ratio between the overall plant costs (both capital and operating), evaluated during all the project life, and the total amount of electrical energy produced in the same period. The same ratio, referred to the
Fig. 4. Total plant specific cost at different values of plant size. 8
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7. Conclusions
present values of each cost and profit, is the LCOE, defined as: n
LCOE =
∑i = 1 (Ci + Oi )
This paper summarizes the results of the feasibility study of the Alaska Syngas project, which aims to install a small modular coal and coal/biomass fired power generation units based on a fixed-bed updraft gasification process coupled with a combined heat and power generator for retrofitting an existing coal-fired power plant on the campus of the University of Alaska Fairbanks. The unit also aims to demonstrate the potential for small-scale, modular, coal gasification technology to provide low-cost fuel for firing reciprocating engine generators with syngas and pyrolysis liquids (oils and tar). By coupling the gasifier with a reciprocating engine, the gasifier/engine combination can be used in baseload and non-baseload applications, and in distributed generation applications. Plant configuration consists of a 3 m diameter fixed-bed up-draft gasifier and gas clean-up equipment suppling the clean syngas to two Jenbacher J620 spark ignition engines for electric power generation. Pyrolysis liquids will be collected and routed to an existing diesel generator. The proposed solution, being modular and scalable, is feasible for commercial-scale applications in the range between 2 and 30 MWe. The gasification of Usibelli coal (100% or 80% with the addition of woody biomass), for a thermal input of about 15 MW, allows to produce about 3.6 MW of electrical energy and about 2.0 MW of steam, with a power generation efficiency of about 25% and a co-generation efficiency of about 37%, considering the whole gasification/gas engine system. In addition, pyrolysis liquids produced by the gasification process (4–5 m3/day, corresponding to 2.1–2.5 MWth) can be used as fuel additive in a diesel engine fed with ultra-low sulfur diesel, allowing a further energy recovery. The project is estimated to have a bare erected cost of 33.4 M$ and a total plant cost of 45.7 M$, where the cost of gasification impacts just for about 10% and the most relevant costs are related to the purchase of the gas engine (22%). Considering the gasifier/engine system fed with 100% Usibelli coal, the unit allows a levelized cost of electricity of 208.06 $/MWh, referred to a plant operating life of 20 years. A sensitivity analysis shows the significant impact of plant’s annual availability on LCOE, whereas relatively low variations of LCOE ( ± 5%) are due to the uncertainties on capital cost estimation or to the variability of the local market.
n
∑i = 1 Ei
where i is the progressive year of the project (i = 1 is the construction phase whereas i = n is the last year of operation), Ci and Oi are the present values of capital and O&M costs (in M$) in year i, respectively, and Ei is the overall amount of electrical energy (in GWh) produced in year i [9,37]. The analysis was carried out calculating, year by year, the annual cash flow related to the gasifier/engine system, based on the assumptions summarized in Table 10. The values are referred to the feeding with 100% Usibelli coal. With specific reference to the Alaska Syngas project, it has been assumed that the whole investment is directly paid without the opening of a senior debt with the banks. Therefore, no interests have been considered in the economic analysis. The analysis, in its base case, shows a COE of 300.21 $/MWh and a LCOE of 208.06 $/MWh. This value is strongly influenced by the plant operating life, assumed 20 years. Fig. 5 shows the linear variation of LCOE for shorter values of the operating life. It is important to underline that LCOE, as defined above, does not consider the revenues for selling the by-products (pyrolysis liquids and steam), but it is only referred to the costs for electricity production.
6.2. Sensitivity analyses The economic analysis here reported is subjected to a series of uncertainties due to the variability of several economic parameters, such as capital and operating costs. Therefore, a combined sensitivity analysis can be a very useful approach to evaluate if and how these parameters affect the LCOE. The sensitivity analysis here reported is based on the Monte Carlo probabilistic method, which is an algorithm that relies on repeated random sampling to obtain numerical results [38–40]. Ten groups of 100,000 iterations have been performed for each case. As stated above, the analysis has been performed with the @ RISK commercial software [41], largely utilized for similar analyses on several fields, when it is impossible to predict the exact impact of several variables on the profitability of the investment. A first simulation was carried out to assess how LCOE is affected by the plant annual availability. It has a significant impact on the variable component of the operating costs and it determines the whole production of electrical energy. The sensitivity analysis here reported (Fig. 6a) assumes a probability of 90% that the annual availability ranges between 6,000 and 8,000 h per year, with a maximum value corresponding to 7,450 h per year, which is the base case assumption. The analysis shows that LCOE ranges between 194 and 260 $/MWh with a probability of 90% (Fig. 6b). A combined sensitivity analysis was carried out to assess the combined effect of the possible variation of several costs on the LCOE. In particular, as for capital costs, the only non-commercial section is represented by the gasification reactor, which cost was assessed during the FEED study on the basis of specific offers. For this section, a 90% probability of a capital costs uncertainties of ± 10% (with respect to the base case) was assumed. For the other sections, only commercial components were considered, so their capital costs are very reliable. The other uncertainties are related to the variable operating costs, influenced by the local or the international market. For all these costs, a Gaussian distribution was considered to estimate their possible variation, within the ranges summarized in Table 11. The result of the combined sensitivity is represented in Fig. 7, which shows that the plant has 90% of probability to allow a LCOE between 198.6 and 217.5 $/MWh.
CRediT authorship contribution statement Charles Ward: Software, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Harvey Goldstein: Software, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Rolf Maurer: Software, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. David Thimsen: Software, Table 10 Economic analysis: main assumptions. Starting of construction phase (year)
2020
Plant construction period (years) Operating life (years)(1) Depreciation period (years) Plant availability (hours/year) Capital costs ($) Operating costs ($/year)(2) Produced electrical energy (kWh/year) Produced thermal energy (kWh/year) Annual discount rate (%) Annual inflation rate (%)
1 20 10 7500 45,703,000 5,595,499 26,250,000 7,878,125 8.0 2.0
Notes: (1) Operating life between 2021 and 2040. (2) Referred to the first year of operation. 9
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Table 11 Uncertainties related to the cost assessment. Cost
Base case
Variation(1)
Gasifier capital cost ($) Usibelli coal ($/year)(2) Maintenance materials ($/year) Chemicals: solvents and catalysts ($/year) Waste disposal ($/year)
4,416,000 2,170,000 553,000 739,000 385,000
± 10% ± 5% ± 10% ± 5% ± 15%
Note: (1)
90% of probability that costs uncertainties ranges within the reported values with a Gaussian distribution. (2) The market price of Usibelli coal is historically very stable.
Writing - review & editing, Visualization. Diane Revay Madden: Project administration, Writing - review & editing. Andrea Porcu: Formal analysis, Investigation, writing - original draft. Alberto Pettinau: Writing - original draft, Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization.
Fig. 5. Variation of LCOE with the plant operating life.
Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Brent J. Sheets: Supervision, Writing - review & editing, Visualization. Randy Hobbs: Writing - review & editing, Visualization. Frances Isgrigg: Validation, Formal analysis, Investigation, Resources, Writing - review & editing, Visualization. Russel Steiger: Validation, Formal analysis, Investigation, Resources,
(a) Assumed probability density function for plant availability.
(b) Resulted probability density function for LCOE. Fig. 6. Impact of plant availability on LCOE. 10
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Fig. 7. Combined sensitivity analysis on LCOE.
Declaration of Competing Interest
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