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Dry petroleum coke gasification in a pilot-scale entrainedflow gasifier and inorganic element partitioning model Marc A. Duchesne, Scott Champagne, and Robin William Hughes Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 16 Jun 2017 Downloaded from http://pubs.acs.org on June 16, 2017
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Energy & Fuels
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Dry petroleum coke gasification in a pilot-scale entrained-flow
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gasifier and inorganic element partitioning model
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Marc A. Duchesne*, Scott Champagne, Robin W. Hughes
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Natural Resources Canada, CanmetENERGY, 1 Haanel Drive, Ottawa, ON, Canada, K1A 1M1
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∗
Corresponding author: e-mail:
[email protected], Telephone: 1-613-947-0287
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Abstract
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Entrained-flow gasification has several advantages over competing technologies for converting
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petroleum coke, a by-product of oil refining. However, due to the high capital costs and limits of
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current commercial technology, the economics look favorable only with high natural gas and oil
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prices, and high CO2 emission penalties. The objective of the current study is to accelerate the
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development of petroleum coke gasification technologies via dry-feed pressurized entrained-flow
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gasifier pilot-scale tests with petroleum coke. The results indicate carbon conversion generally
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increased with higher O:C ratios. Thermodynamic model predictions generally vary by less than
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25% from the experimental outlet gas flowrates of the main species, CO and H2. The predicted
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flowrates for other gases vary much more from experimental values, while the predicted carbon
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conversion values are similar (± 16 percentage points), and the predicted temperatures are mostly
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lower than experimental values. Mass balances and enrichment factors were calculated for
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inorganic elements due to their potential environmental and technological impact. In general, 1 ACS Paragon Plus Environment
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results from this study indicate similar or lower volatility for elements when compared to
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combustion systems. An inorganic element partitioning model is presented and compared to
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experimental values. Considerations for other types of petroleum coke are also provided.
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Key words: Gasification, Petroleum Coke, Pilot-plant, Entrained-flow, Partitioning model
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1. Introduction
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In 2014, Higman estimated the global capacity for petroleum coke gasification to be ~3,000
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MWth, with a further ~17,000 MWth capacity in construction or planned.1 The National Energy
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Technology Laboratory Gasification Plant Databases of proposed projects and projects
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undergoing construction and initial operation lists 11 petroleum coke gasification projects (out of
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151 total gasification projects) that use petroleum coke.2 Eight projects in the United States have
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been delayed or cancelled, while one project in Panama and two in India are considered active.
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Canada produces approximately four million tonnes of petroleum coke, a by-product of oil
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refining, each year and has a stockpile approaching 100 million tonnes.3,4 Alberta Innovates, a
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provincially-funded corporation in Alberta, Canada, commissioned Jacobs Consultancy to study
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the economics of a 4-18 million tonnes/year (~4,000-18,000 MWth) petroleum coke gasification
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complex with the capability of producing a variety of products including electric power,
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hydrogen, petrochemical products and transportation fuels.5 This study concluded that due to the
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high capital costs and limits of current commercial technology, the gasification complex
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economics look favorable only with high natural gas and oil prices, and high CO2 emission
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penalties (Table 1). For context, the 2015 average Alberta natural gas and West Texas
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Intermediate oil prices were 2.08 USD/GJ and 48.79 USD/bbl, respectively,6 and the 2 ACS Paragon Plus Environment
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Government of Canada has committed to a CO2 penalty of approximately 37 USD/tonne by
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2022.7 The Alberta Innovates study further stated that the development of technologies can
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transform the economics. Some of the technologies highlighted in the study, as well as EPRI and
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NETL gasification technology reports, include warm gas clean-up, solid feeding systems,
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advanced gas turbines and fuel cells.8,9 Combining these technologies can reduce the cost of
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electricity from a gasification plant by up to 50%.10
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Table 1. Comparison of production cost by petroleum coke gasification and conventional processes5 Natural gas price (USD/GJ)
Oil price (USD/bbl)
4.28 4.28 4.28 8.89 8.89 8.89
60 60 60 85 85 85
CO2 penalty (USD/tonne)
Petroleum coke gasification cost (USD per million tonnes of hydrogen / methanol)
Conventional process cost (USD per million tonnes of hydrogen / methanol)
0 50 120 0 50 120
2050 / 400 2100 / 400 2250 / 425 2050 / 400 2100 / 400 2200 / 425
1300 / 350 1850 / 400 3050 / 475 2200 / 425 2800 / 475 4050 / 550
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Despite the high heating value and low ash content of petroleum coke, its high carbon, sulfur,
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vanadium and nickel content, and low reactivity make it a challenging feedstock.11,12
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Gasification has several advantages over competing technologies for converting petroleum
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coke.13–15 Namely, CO2 and sulphur capture is more efficient and less costly with gasification
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than with conventional combustion processes.11,16–18 More specifically, entrained-flow gasifiers
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operate at higher temperatures than fixed-bed or fluidised-bed gasifiers, making them suitable for
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low-reactivity feedstocks such as petroleum coke. They also produce an inert slag containing
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metals that could otherwise be released in a hazardous form. Pilot-scale studies can be used to
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enhance the entrained-flow petroleum-coke gasification process by implementing methods and
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technologies that are not ready for the commercial scale. Few studies of this nature are
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available.19–22 The current study aims to fill knowledge gaps regarding petroleum coke
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gasification technologies by converting petroleum coke in a pilot-scale dry-feed pressurized
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entrained-flow gasifier under a wide range of operating conditions. Tests were purposely
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designed to provide pressure, temperature and gas/liquid/solid sample compositions required for
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model validation and process optimization. Complementary studies based on these tests include
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the development of instrumentation, validation of reduced order and computational fluid
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dynamics (CFD) models, and demonstration of a pressurized dry fuel conveying system (Table
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2).
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Table 2. Objectives of the current study and related studies Subject
Objective Develop instruments for reliable and fast online temperature measurements.
Gasifier performance monitoring23,24
Link with current study A flame emission spectrometer was used during tests to monitor flame temperature. Fiber Bragg grating arrays monitored gasifier skin temperatures during tests.
Fuel conveying
Develop a reliable dense-phase pressurized fuel conveying system.
The fuel conveying system was used for the tests in the current study.
Reduced order modeling26,27
Develop a semi-comprehensive gasifier model for rapid simulations.
Data from the current study was used to validate steady-state and dynamic reduced order models.
Computational fluid dynamics modeling28
Develop a comprehensive gasifier model.
Data from the current study was used to validate a computational fluid dynamics model.
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Energy & Fuels
Current study
Determine general performance trends and develop a model to track inorganic elements.
General performance trends were obtained, and an inorganic element partitioning model was created and validated.
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In addition to the potential negative environmental impact of elements such as As, B, Cd, Hg, Pb
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and Se,29–31 many of the emerging technologies to enhance the performance and economics of
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gasification plants are sensitive to inorganic elements (i.e., elements other than C, H, O, N and S)
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found in the fuel. For example, alkali metals are problematic for gas turbines.32 As, Cl, P and Sb
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can degrade the nickel yttria-stabilized zirconia (Ni-YSZ) anodes in solid oxide fuel cells
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considered for integration with gasification.33,34 More conventional IGCC configurations with
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CO2 capture include one or more unit operations with an aqueous or solvent based wash such as
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full quench, Selexol, Rectisol, amine unit, or desaturator. These units are effective for the
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removal of the portion of inorganic elements that are not captured in the slag or fly ash; however,
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there is evidence that inorganic elements originating from the fuel may increase oxidative
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degradation of solvents leading to hazardous aerosol emissions.35–37 In the current study,
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experimental results are presented for inorganic element partitioning based on the
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characterization of solid and liquid samples from the petroleum coke gasification tests. The
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partitioning is compared to other entrained-flow gasifier and combustor data. Although models
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for inorganic element partitioning during gasification are available in literature, many only
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present expected phases, with limited interactions, as a function of temperature.38–42 Some
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models present staged cooling and phase separation, but the cooling stages are not representative
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of phenomena in a gasification facility.43–45 In this study, an inorganic element partitioning
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model, based on estimated stream splits and staged thermodynamic equilibrium calculations for
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different reactor zones, is presented and compared to experimental values.
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2. Materials and Methods
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2.1 Gasification plant
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The CanmetENERGY pressurized entrained-flow slagging gasifier (Figure 1) has been
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previously described by Sahraei et al.26 The feeding system used nitrogen for conveying and is
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described by Kus et al.25 A flame emission spectroscopy (FES) probe was used during the tests
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to estimate the flame’s temperature, and required injection of ~ 4 kg/h of nitrogen purge gas into
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the system. Its implementation and results from testing are described by Parameswaran et al.24
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The locations of SynTemp type B thermocouples are indicated on Figure 1 as TC1 through TC4.
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They protruded past the hot face and into the reaction chamber by ~5 mm. The thermocouples
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are calibrated to have ±0.25% accuracy, although the accuracy may decrease with usage and be
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affected by fouling. Oxygen flow was adjusted to maintain a constant temperature at
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thermocouple TC4. A gas sampling probe, at the same elevation as TC4, provided the syngas
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composition inside the reactor. Dried gas analysis was performed via two parallel gas
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chromatographs capable of measuring CO, CO2, CH4, H2, O2, COS, H2S and N2 once every two
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minutes (i.e., once every four minutes per chromatograph). The relative error on values obtained
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by chromatography is believed to be less than 5%. After each test day, samples were collected
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from bag filters A/B (0.5 micron), the scrubber filter (0.5 micron) and the fine particulate filter
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(10 microns), partially dried, and then placed in sealed containers. A water sample was taken
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from the housing of bag filters A/B and preserved for analysis.
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Energy & Fuels
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Figure 1. Schematic diagram of CanmetENERGY’s pressurized entrained-flow gasification system.
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2.2 Sample characterization methods
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Sample characterization methods are summarized in Table 3.
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Table 3. Characterization methods
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Property
Method
Proximate analysis moisture, secondary moisture, ash and fixed carbon
ASTM D7582
Proximate analysis volatile matter
ISO 562
Ultimate analysis carbon, hydrogen and nitrogen
ASTM D5373
Ultimate analysis sulfur
ASTM D4239
Ultimate analysis oxygen
by difference
Gross calorific value
ISO 1928
Ash fusion temperatures
ASTM D1857
Major and minor ash oxide concentrations
ASTM D4326
Elemental concentrations in liquid and solid samples
U.S. EPA Method 6010C (SW-846)
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2.3 Petroleum coke
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The petroleum coke used in this study is an Alberta, Canada oil sands delayed coke. Prior to
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characterization and use, it was crushed, dried and pulverized (90%+ below 200 mesh).
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Properties of the petroleum coke are presented in Table 4. These properties are averages with
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standard deviations for three samples taken from different barrels.
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Table 4. Properties of the petroleum coke Property
Unit
Average Standard value deviation
Proximate analysis Moisture Secondary moisture Ash Volatile Fixed carbon
wt% wt% wt% wt% wt%
0.70 0.50 3.68 12.25 83.36
0.17 0.43 0.80 0.39 1.00
Ultimate analysis Carbon Hydrogen Nitrogen Total sulfur Oxygen by difference
wt% wt% wt% wt% wt%
83.10 3.63 1.59 6.39 0.89
0.95 0.29 0.07 0.54 0.53
Gross calorific value
MJ/kg
33.35
0.21
Oxidizing ash fusion temperatures Initial °C 1295 °C Spherical 1374 °C Hemispherical 1401 °C Fluid 1450
52 50 26 3
Reducing ash fusion temperatures °C Initial 1333 °C Spherical 1400 °C Hemispherical 1418 °C Fluid 1446
75 39 31 19
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2.4 Modeling methods
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FactSage software predicts equilibrium solid-liquid-gas phases and compositions based on Gibbs
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free energy minimization.47 In this study, FactSage 7.0 was used for two types of calculations.
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The first calculation type, henceforth referred to as a bulk thermodynamic prediction, was
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completed with the FactPS database with all gas, liquid and solid compounds considered. The
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petroleum coke fuel was modeled by creating a customized fuel compound based on its carbon,
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hydrogen and sulphur content, as well as its gross calorific value (Table 4). Details of this
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procedure can be found in the FactSage Compound module slideshow. The fuel, oxygen, steam
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and nitrogen feed rates were then entered in the Equilib module where 1 g in the calculation
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represented 1 kg/h in the modeled test. All feeds were set to an initial pressure of 1600 kPa and
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temperature of 25 °C, except for steam that had an initial temperature of 220 °C. Although the
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heat loss during the tests is not measured and variable, previous experimental and modeling
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experience suggest that it is less than 10% of the fuel’s thermal input rate, and therefore all
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calculations were assumed adiabatic. The second calculation type, henceforth referred to as a
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detailed thermodynamic prediction, was completed in a similar fashion to a bulk thermodynamic
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calculation; however, ash components in elemental form were included, temperature and
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pressure for equilibrium were specified, and the FToxid and FactPS database were considered.
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Within these databases, default pure compound phases were selected and most default solution
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phases were selected. To avoid exceeding the solution phase limit in FactSage, immiscibility was
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not considered for any given solution type, and some solution phases mainly composed of minor
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elements were not considered. A list of all solution phases considered is provided in the
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supplementary information Table S1.
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Energy & Fuels
3. Results and discussion
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3.1 Operating conditions and performance
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The gasification test campaign included five days of testing. V1, V2, V3, S1 and S2 tests were
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completed during the first, second, third, fourth and fifth day, respectively. Multiple target
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conditions, where injected gas flowrates, syngas composition and TC1-TC4 temperatures were
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stable for 25 minutes, were attained with each of the first three days of testing. A single target
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condition was maintained for an extended period of time (i.e., 190-300 minutes) during each of
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the last two days of testing. Test conditions, including average injected gas flowrates, dry syngas
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composition and flowrate, carbon conversion, and cold gas efficiency for each test are
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summarized in Table 5. The reported dry syngas composition is for gas collected from the
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sampling probe (indicated in Figure 1) that was cooled and dried for analysis by gas
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chromatography. According to bulk thermodynamic predictions, the moisture content of the
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syngas prior to drying is less than 7 mol%. Generally, two thirds of the nitrogen in the syngas is
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from fuel conveying and one third is from the FES probe purge (see Section 2.1), while the
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amount of nitrogen in the fuel is negligible (Table 4). Average injected fuel flowrates varied
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from 34.9 to 66.1 kg/h, average injected steam flowrates varied from 0.0 to 21.8 kg/h, and
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average injected oxygen flowrates vary between 28.4 and 43.6 kg/h. The operating pressure was
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either 800 or 1600 kPa. Note that the oxygen flowrate was controlled to maintain a TC4
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temperature of ~1225 °C for tests V1a, V1b and V1c, and a TC4 temperature of ~1300 °C for all
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other tests. Plots showing injected gas flow rates, dry syngas compositions and TC1-TC4
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temperatures for the entire duration of each test day are available in the supplementary
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information. The dry syngas flowrate (Table 5) exiting the reactor was estimated by performing a
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nitrogen mass balance based on known nitrogen injection flowrates (i.e., fuel conveying gas, fuel
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nitrogen and flame emission spectroscopy probe purge gas) and the dry syngas composition.
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Carbon conversion (Table 5) was estimated by performing a carbon mass balance with the
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injected fuel and dry syngas. The estimation of an impossibly high conversion for test V1d
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(109%) is possibly due to some accumulation of solid carbon in the system during tests V1a-V1c
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which were all completed with a lower TC4 temperature of ~1225 °C. As an alternative to
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performing a mass balance with the exiting gas phase, a mass balance with the carbon in the
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solid outputs (slag pot, quench water filters, scrubber filter and gas filter) and liquid output
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(effluent water) has been completed to determine the carbon conversion. By this method, the
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calculated carbon conversion for tests S1 and S2 are 87.1% and 84.4%, respectively. These
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values are within 0.8 percentage points of the conversion obtained by mass balance with the dry
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syngas composition. 5-8% of the injected carbon was recovered in the slag pot solids, 5-11% in
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the quench water solids, ~0.1% in the remaining solids and liquid. Carbon conversion based on a
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mass balance with the solid and liquid outputs could not be completed for the V1, V2 and V3 test
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series as the operating conditions varied within a given day and solid sampling was only
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completed at the end of each test day. The achieved carbon conversions are generally lower than
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what is expected for commercial entrained-flow gasifier operation, i.e., 98-99.5%,48 due to
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system constraints at the pilot scale (e.g., high surface-to-volume ratio, pressure
