Parametric Model of Greenhouse Gas Emissions
for Fischer-Tropsch Fuels
University of Dayton Research Institute
Subrecipient Agreement No. FA8650-10-2-2934
Prime Cooperative Agreement No. FA8650-10-2-2934
Final Report
Submitted to
Dr. Philip Taylor
University of Dayton Research Institute
300 College Park
Dayton, Ohio 45469
Submitted by
David T. Allen and Kirsten S. Rosselot
Center for Energy and Environmental Resources
The University of Texas at Austin
10100 Burnet Road, Bldg 133 (R7100)
Austin, TX 78758
Jeremiah Miller, John R. Ingham and William Corbett
URS Corporation
4141 Col. Glenn Highway
Beavercreek, OH 45431
October 5, 2011
1
Executive Summary
The US Air Force is currently assessing the use of Fischer-Tropsch (FT) fuels, blended with
conventional jet fuel, as aircraft fuel. However, a potential barrier to the use of FT fuels is the
greenhouse gas emissions associated with their manufacture. Emerging guidelines for
procurement of fuels place limits on the life cycle greenhouse gas emissions for fuels purchased
by the US federal government. Using methodologies recommended by an Aviation Fuel Life
Cycle Assessment Working Group, assembled by the US Air Force, this report describes
estimates of life cycle greenhouse gas emissions for FT aviation fuels.
FT aviation fuels can be made using a variety of feedstocks (e.g., coal, natural gas, biomass) and
using a wide variety of processing configurations. The overall goals of the analyses described in
this work were to assess (i) which FT processing parameters, feedstock choices, and greenhouse
gas emission estimation assumptions would have the greatest impact on overall cradle-to-gate
(total pre-combustion) greenhouse gas emissions, and (ii) whether the variability introduced by
processing choices would be significant.
To address these two issues, a model capable of estimating cradle-to-gate greenhouse gas
emissions for FT fuels under a variety of user defined operating conditions was created. The
model was run hundreds of times to generate an ensemble of FT processing scenarios that are
described in this report. The model is available to other users for estimating greenhouse gas
emissions for additional scenarios not considered in this work, and a user’s guide to the operation
of the model is included in this report.
Overall, the greatest variability in greenhouse gas footprints for the ensemble of FT processing
scenarios was found for the following process conditions:
 sequestration vs. emission of carbon dioxide emissions from syngas production and from
the FT reactor  the choice of catalyst in the FT reactor  the use of biomass as a feedstock rather than coal  the carbon number distribution of liquid hydrocarbons from the FT reactor Life cycle assessment methodological choices (i.e., allocation methods) also had a significant
impact on the estimated greenhouse gas footprint. These parameters were often coupled, with
the sensitivity of process conditions depending on the allocation choices. For example, in
addition to the above list, the cradle-to-gate greenhouse gas footprint was sensitive to the fraction
of unreacted syngas that is recycled to the FT reactor for some allocation choices.
Collectively, these results suggest that potential fuel suppliers will need to document both the
details of process configurations and their emission estimation methodologies to obtain precise
greenhouse gas emission estimates. The results also suggest that improvements in processing
technology (e.g., FT catalysts) could lead to significant reductions in greenhouse gas emissions
associated with FT aviation fuel production.
2
Contents
Executive Summary ........................................................................................................................ 2 Chapter 1: Introduction .................................................................................................................. 5 Chapter 2: Syngas Manufacture ..................................................................................................... 8 2.1 Raw Material Acquisition ..................................................................................................... 8 2.2 Gasification ........................................................................................................................... 9 2.3 Water-Gas Shift .................................................................................................................. 10 2.4 Syngas Cleanup................................................................................................................... 11 2.5 Syngas Generation in the Model ........................................................................................ 12 Chapter 3: Fischer-Tropsch Processing ....................................................................................... 13 3.1 Process Description............................................................................................................. 13 3.2 Reactor Feed Description.................................................................................................... 15 3.3 Reactor Description ............................................................................................................ 15 3.4 Product Separation .............................................................................................................. 17 3.5 Autothermal Reformer ........................................................................................................ 17 3.6 Gas Cooling ........................................................................................................................ 19 3.7 Carbon Dioxide Removal ................................................................................................... 19 3.8 Recycle Stream ................................................................................................................... 19 3.9 Hydrogen Recycle............................................................................................................... 19 3.10 Fuel Gas ............................................................................................................................ 19 3.11 The Structure of the FT Reactor Model ........................................................................... 19 Chapter 4: Wax Upgrading .......................................................................................................... 25 4.1 Hydrocracker Model ........................................................................................................... 25 4.2 Liquid fuel products ........................................................................................................... 30 4.3 Estimating greenhouse gas emissions ................................................................................ 34 Chapter 5: Model Operation ....................................................................................................... 39 5.1 FT Reactor Model Operation ............................................................................................. 39 5.2 Hydrocracker Model Operation ......................................................................................... 49 Chapter 6: Ensemble Modeling of Variability ............................................................................. 58 6.1 Results ................................................................................................................................ 60 6.2 Process Selections That Influence the Estimated Cradle-to-Gate Greenhouse Gas
Footprint of SPK ....................................................................................................................... 71 6.3 Life Cycle Assessment Selections That Influence the Estimated Cradle-to-Gate
Greenhouse Gas Footprint of SPK............................................................................................ 75 Appendix A. The base case for electricity generation ................................................................. 82 3
List of Acronyms and Abbreviations
ASU
Air separation unit
ATR
Autothermal reformer
bbl
barrel
bpd
barrels per day
CFR
combined feed ratio
CO2E
carbon dioxide equivalent
DoD
U.S. Department of Defense
FT
Fischer-Tropsch
GWP
Global warming potential
HHV
Higher heating value
IAWG
Interagency Working Group
LHV
Lower heating value
MDEA
methyl diethanol amine
MMBtu
million Btus
SCF
standard cubic feet
SPK
Synthesized paraffinic kerosene
UT
University of Texas
VLE
Vapor-liquid equilibrium
WGS
Water-gas shift
4
Chapter 1: Introduction
Figure 1-1 shows a simplified flowsheet of a process that produces liquid fuels from coal and
biomass using gasification and Fischer-Tropsh (FT) synthesis. Coal and biomass are gasified to
produce syngas (mainly carbon monoxide and hydrogen), which is then cleaned and modified
through a water gas shift to achieve a desired CO/hydrogen ratio. The modified syngas is sent
through a FT reactor, where hydrocarbon chains are formed. The output of the FT-reactor is sent
to a hydrocracker to shorten the hydrocarbon chains that are longer than desired. Fuel gas is
produced in the hydrocracker and in the FT reactor. Carbon dioxide is generated during the
water-gas shift reaction and removed during gas cleanup, and more carbon dioxide is generated
in the FT reactor.
H2O
particulates
coal/biomass
fuel gas
gasification
O2
H2
liquid
fuels
hydrocracker
fuel gas
wax
CO2
H2O
FT reactor
raw syngas
water‐gas shift
adjusted syngas
clean syngas
Cl
CO2
H2S
gas cleanup
Figure 1-1. Simplified flowsheet of liquid fuel production from coal and biomass
The US Air Force is assessing the use of Fischer-Tropsch (FT) fuels, such as the hydrocarbons
formed in the process shown in Figure 1-1, in a variety of aircraft. However, a potential barrier
to the use of FT fuels is the greenhouse gas emissions associated with their manufacture. The
Energy Independence and Security Act of 2007 prohibits the federal government from
purchasing alternative fuels for transportation that have greater greenhouse gas footprints than
fuels produced from conventional petroleum sources. Specifically, Section 526 of the Energy
Independence and Security Act of 2007 provides that:
No Federal agency shall enter into a contract for procurement of an alternative or synthetic fuel, including a
fuel produced from nonconventional petroleum sources, for any mobility-related use, other than for research
or testing, unless the contract specifies that the lifecycle greenhouse gas emissions associated with the
production and combustion of the fuel supplied under the contract must, on an ongoing basis, be less than or
equal to such emissions from the equivalent conventional fuel produced from conventional petroleum
sources.
5
Previous work done for the University of Dayton Research Institute by the University of Texas
and URS (Allen et al, 2010), assessed the life cycle greenhouse gas emissions of FT fuels, made
from three types of processes:
1) Steam methane reforming followed by FT wax production (cobalt catalyst) and
upgrading (US average natural gas as a feed)
2) Coal (Kittanning #6 coal) gasification followed by FT wax production (cobalt
catalyst) and upgrading
3) Coal/biomass (mixtures of switchgrass and Kittanning #6 coal) gasification followed
by FT wax production (cobalt catalyst) and upgrading
These greenhouse gas emission estimates were compared to a petroleum baseline fuel. The
results, for greenhouse gas emissions that can be attributed directly to the fuel life cycle, are
summarized in Table 1-1. The results are reported as the carbon dioxide equivalents per megajoule of the lower heating value (MJ LHV) of aviation fuel. Greenhouse gas emissions included
releases of carbon dioxide, methane and nitrous oxide, but not particulate matter. Impacts of
indirect land use were not included; details are available in the final report (Allen et al., 2010).
Table 1-1. Global warming potentials (GWPs), expressed as equivalent carbon dioxide
emissions per megajoule of lower heating value (g CO2E/MJ LHV), for Fischer-Tropsch
fuels
Petroleum baseline
Natural Gas feedstock
Coal feedstock
93% coal
7% switchgrass
85% coal
15% switchgrass
75% coal
25% switchgrass
Pre-combustion
14.3±4
12±10
117±10
107±15
Life cycle stage
Combustion
73.2±1
70±1
70±1
67±1
Total
87.5
82
187
174
101±15
64±1
165
85±20
59±1
144
The results indicated that the greenhouse gas footprints of natural gas-derived FT fuels are less
than the petroleum baseline, while coal-derived FT fuels have greenhouse gas footprints that are
110% larger than the petroleum baseline. Mixing biomass with coal had a moderate impact on
the greenhouse gas footprint directly attributed to fuel production, decreasing the footprint by
about 1% for each 1% of biomass added to the feed.
The greenhouse gas emission estimates developed in previous work were based on a small
number of processing conditions, however, a wide variety of process configurations are possible
for FT fuel synthesis, and these different processing configurations could lead to significantly
different greenhouse gas emission estimates. For example, whether or not the carbon dioxide
generated during the water-gas shift reactions and in the FT reactor is sequestered has a
significant effect on the net greenhouse gas emissions of FT fuels during the cradle-to-gate part
of their life-cycle. Other processing parameters, such as choices of FT catalysts and internal
recycle ratios, may also be important.
6
The goal of the work described in this report is to expand the modeling performed by Allen et al.
(2010) by developing parametric models of greenhouse gas emissions of FT fuel processing.
The parameters to be considered include a variety of process variables (e.g., fraction of the
unreacted syngas recycled to the FT reactor; molecular weight distribution of the waxes
produced in the FT reactor; fraction of heavy fuels recycled to the hydrocracker) that would be
expected to vary among facilities producing FT fuels. In developing the parametric models, the
FT fuel synthesis was divided into three main processing steps: syngas manufacture, FT
synthesis, and FT wax upgrading. Chapter 2 of the report describes syngas manufacture and the
associated greenhouse gas emissions for coal and biomass feedstocks. Chapter 3 describes the
FT process to produce wax and describes the FT reactor model used in this work, and Chapter 4
describes the wax upgrading process for producing aviation fuel (synthesized paraffinic
kerosene, or SPK), and describes the upgrading section model. Chapter 5 provides a tutorial on
the use of the combined models, and Chapter 6 describes a series of parametric analyses
performed with the model.
References
Allen, D. T.; Murphy, C.; Rosselot, K.S.; Watson, S.; Miller, J.; Ingham, J. and Corbett, W.
“Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer-Tropsch
Processing” Final Report to University of Dayton Research Institute from the University of
Texas, Agreement No. RSC09006; Account No. 2919890002; Prime Agreement No. F3361503-2-2347; February, 2010.
7
Chapter 2: Syngas Manufacture
This chapter describes the acquisition of raw materials and the processes for producing syngas
used to generate Fischer-Tropsch (FT) fuels. The processes for producing syngas described here
are largely drawn from the work previously reported by Allen et al. (2010), while the raw
material acquisition values are based on the results of an Interagency Working Group (IAWG)
study that studied the greenhouse gas emissions from production of FT aviation fuels (Allen et
al, 2011).
2.1 Raw Material Acquisition
Raw material acquisition includes all activities required to produce, process and transport raw
materials to the FT production facility. The raw materials modeled in this work are coal and
switchgrass.
2.1a Coal Acquisition
In previous work by the UT and URS team, analyses were performed using Kittanning #6 coal.
Previous work by the Interagency Working Group (IAWG) was based on Illinois #6 coal (Allen
et al., 2011). The compositions of Kittanning #6 coal and Illinois #6 coal are similar, as shown
in Table 2-1. This work assumes the use of Illinois #6 coal as a raw material so that the most
recent work of the IAWG can be used in the analyses, and so that the analyses generated in this
work are compatible with IAWG data synthesis activities.
Table 2-1. Coal composition (weight %)
Composition (weight %)
Component Illinois #6 Kittanning #6
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
Total
11.12%
63.75%
4.50%
1.25%
0.29%
2.51%
9.70%
6.88%
100.00%
2.40%
71.00%
5.20%
1.30%
0.40%
3.00%
9.40%
7.30%
100.00%
The IAWG analysis reported a total greenhouse gas footprint for coal delivered to the FT
production facility of 91 g CO2E/kg coal, 78 g CO2E/kg coal from mining and 14 g CO2E/kg
coal from transportation.
2.1b Switchgrass Acquisition
In previous work by the UT and URS team, analyses were performed using a switchgrass
described by Tarka (2009), which is the same as the composition of the switchgrass used by
Allen et al (2011). The composition of the switchgrass is shown Table 2-2.
8
Table 2-2. Switchgrass composition (weight %)
Component Composition (weight %)
Moisture
11.12%
Carbon
63.75%
Hydrogen
4.50%
Nitrogen
1.25%
Chlorine
0.29%
Sulfur
2.51%
Ash
9.70%
Oxygen
6.88%
Total
100.00%
The life-cycle values include cultivation (including the use of fertilizers), harvesting, and
transportation of switchgrass to the FT production facility. Consequential and land use impacts
are also included, along with the establishment of the switchgrass plots from pasture or crop
lands, the construction of the farming and transportation equipment, and storage of the
switchgrass until it is shipped to the FT production facility. The total IAWG greenhouse gas
footprint for switchgrass delivered to the FT production facility is -1,500,000 g CO2E/ton
switchgrass, with 93,000 g CO2E/ton switchgrass from switchgrass production, -1,700,000 g
CO2E/ton switchgrass from carbon dioxide uptake during growth, 110,000 g CO2E/ton
switchgrass from indirect and direct land use, and 38,000 g CO2E/ton switchgrass from
transportation.
2.2 Gasification
The gasifier data used in this work is drawn from Allen et al. (2010) and, to a lesser extent, from
the IAWG report (Allen et al, 2011). The flow diagram for the gasification section of the FT
facility is shown in Figure 2-1. The coal delivered to the facility is ground to a size less than 200
mesh, then fed into the gasifier. The switchgrass is processed through a debaler that removes the
twine from the bales and begins to break down the bales. The switchgrass is then fed into an
initial knife mill to reduce the particle size, followed by a second collision mill to further reduce
the particle size to less than 1 mm. The switchgrass must be reduced to this size to ensure
reliable feeding to the gasifier. The switchgrass and coal are fed through separate handling
systems so that should the switchgrass handling system become plugged the gasifier can
continue operation on coal only. The feedstocks are reacted with oxygen from a cryogenic air
separation unit (described in Section 2.2a) in a Shell gasifier. The Shell gasifier was selected
because it has proven ability to gasify a feedstock containing up to 30% biomass. It is a high
temperature (~2500o F), high pressure (450 psia) entrained flow gasifier. Under these
conditions, a high quality syngas is produced that is low in tars, methane and other hydrocarbons.
The composition of the syngas produced by the gasifier is affected by the composition of the
feedstocks. As discussed before, the composition of coal and switchgrass from the IAWG report
are used for gasification analysis. The composition of the syngas at varying concentrations of
coal and biomass is shown in Table 2-3.
9
Figure 2-1. Gasification flow diagram
Table 2-3. Syngas composition based on feed composition
Compound
H2O
CO2
O2
N2
CH4
CO
COS
H2
H2S
HCl
Total
100% Coal
0.031
0.020
0.000
0.020
0.000
0.617
0.001
0.301
0.008
0.001
1
Mole fraction in syngas
84% Coal
0.045
0.031
0.000
0.019
0.000
0.588
0.001
0.307
0.007
0.001
1
69% Coal
0.056
0.042
0.000
0.018
0.000
0.559
0.001
0.317
0.006
0.001
1
2.2a Air Separation Unit
Oxygen supplied to the gasifier and autothermal reformer (discussed in Section 3.5) is produced
in a standard cryogenic air separation unit (ASU). The oxygen stream is 95% oxygen by volume
with the remainder being mostly nitrogen. The ASU also produces a nitrogen stream that is
98.7% pure and can be used in other areas of the facility. More detailed information concerning
the ASU is available in Allen et al. (2010).
2.3 Water-Gas Shift
Iron catalyst FT reactors typically require a syngas feed with a molar H2:CO ratio of 1.1:1, while
those with a cobalt catalyst typically require a syngas feed with a molar H2:CO ratio of 2.1:1.
10
The syngas exiting the gasifier has a molar H2:CO ratio between 0.49 for the 100% coal case and
0.57 for the 69% coal case. This ratio is adjusted by performing a water-gas shift (WGS)
reaction on a portion of the syngas from the gasifier, taking into account that in addition to the
syngas from the gasifier, an unreacted syngas stream is recycled to the FT reactor, an
autothermal reformer syngas stream enters the reactor, and a hydrogen recycle stream is returned
to the reactor. The overall molar H2:CO ratio entering the FT reactor is maintained at its desired
level by varying the amount of syngas fed into the WGS reactor.
The WGS reaction is described by:
CO + H2O  CO2 + H2
Any COS present in the syngas stream that undergoes the WGS reaction is hydrolyzed into H2S
that can be removed during syngas cleanup. The hydrolysis reaction is described by:
COS + H2O  CO2 + H2S
Any syngas that does not undergo the WGS reaction is sent to a COS reactor to hydrolyze the
COS so that it can be removed during syngas cleanup. The flow diagram for the WGS section is
shown in Figure 2-2.
COS Reactor
21
19
18
20 WGS Reactor
Syngas from Reactor
22
23 Impurity Removal
25
Heat Removal
26
24
Steam In
Stream #
18
19
20
21
22
23
24
25
Stream Name
Gasifier Syngas
COS Syngas
WGS Syngas
COS Cleaned Syngas
WGS Adjusted Syngase
Ratio Adjusted Syngas
Acid Gas Removal
Ratio Adjusted Syngas
Figure 2-2. WGS section flow diagram
2.4 Syngas Cleanup
FT catalysts are susceptible to catalyst poisoning, and sulfur and chlorine must be removed from
the syngas before it is sent to the FT reactor. The COS found in the gasifier syngas has already
been converted to H2S that is easier to remove from the syngas. Ammonia, sulfur, and chlorine
are removed from the syngas using the Rectisol® process. This process also removes carbon
dioxide from the syngas; for this analysis it is assumed that 96% of the carbon dioxide is
removed. The carbon dioxide that is removed was produced in the gasifier, the WGS reactor and
the COS reactor. The carbon dioxide stream from the Rectisol® process can be sequestered or
used for enhanced oil recovery. The sulfur level in syngas exiting the Rectisol® process remains
high enough to potentially poison the FT catalyst, and the sulfur levels are further reduced using
zinc oxide polishing.
11
2.5 Syngas Generation in the Model
Syngas calculations in the greenhouse gas emission model and their locations within the model’s
workbook are described in the final section of Chapter 3.
References
Allen, D. T.; Murphy, C.; Rosselot, K.S.; Watson, S.; Miller, J.; Ingham, J. and Corbett, W.
“Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer-Tropsch
Processing” Final Report to University of Dayton Research Institute from the University of
Texas, Agreement No. RSC09006; Account No. 2919890002; Prime Agreement No. F3361503-2-2347; February, 2010.
Allen, D.T., Allport, C., Atkins, K., Choi, D.G., Cooper, J.S., Dilmore, R.M., Draucker, L.C.,
Eickmann, K.E., Gillen, J.C., Gillette, W., Griffin, W.M., Harrison, W.E.,III, Hileman, J.I.,
Ingham, J.R., Kimler, F.A.,III, Levy, A., Miller, J., Murphy, C.F., O’Donnell, M.J., Pamplin, D.,
Rosselot, K., Schivley, G., Skone, T.J., Strank, S.M., Stratton, R.W., Taylor, P.H., Thomas,
V.M., Wang, M.Q., Zidow T. Life Cycle Greenhouse Gas Analysis of Advanced Jet Propulsion
Fuels: Fischer-Tropsch Based SPK-1 Case Study. Final Report from the Aviation Fuel Life
Cycle Assessment Working Group to the U.S. Air Force, AFRL-RZ-WP-TR-2010-XXXX, Draft
February 4, 2011.
Tarka, Thomas J. “Affordable, Low-Carbon Diesel Fuel from Domestic Coal and Biomass”,
prepared for the Department of Energy, National Energy Technology Laboratory, 2009 available
at: http://www.netl.doe.gov/energy-analyses/pubs/CBTL%20Final%20Report.pdf
12
Chapter 3: Fischer-Tropsch Processing
3.1 Process Description
The Fischer-Tropsch (FT) process converts syngas (carbon monoxide and hydrogen) into a wide
range of hydrocarbons that are subsequently separated into a liquid products stream (FT wax)
and a variety of lighter hydrocarbon byproducts and combustible gases. A process flow diagram
of a typical FT processing section is shown in Figure 3-1.
The FT reactor, described in Section 3.3, is usually a slurry bed reactor. Syngas (stream 1)
produced in the syngas manufacture and cleanup section is combined with recycle streams
internal to the FT processing section and fed to the FT reactor. The FT products exiting the
reactor (stream 5) are separated into products and recycle streams as described in Section 3.4.
FT wax (stream 9) is sent to the wax upgrading section and processed into liquid fuels as
discussed in Chapter 4. Light hydrocarbons are partially combusted in an autothermal reformer,
as described in Section 3.5, to supplement the syngas from the gasifier. Unreacted syngas is
processed to remove water, carbon dioxide and hydrogen. A portion of the unreacted syngas
(stream 2) is recycled to the reactor and the remainder of the syngas is assumed to be used as fuel
gas to produce energy and/or heat for the FT production facility, or to produce electricity that is
exported off-site.
13
17
H2 Removal
16
2
15
14
CO2 Removal
7 and 8
3
13
6
ATR
12
Heat Removal
Gas Cooling
11
Heat Removal
1
4
Catalyst
Separation
FT Reactors
5
FT Products
Separator
10
Heat Removal
9
Catalyst Make-up
Catalyst Blow-down
Figure 3-1: Fischer-Tropsch processing section flow diagram
14
Stream #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Stream Name
Ratio Adjusted Syngas
Unreacted Syngas Recycle
ATR Syngas
Combined Syngas
FT Reactor Output
Light HC's
ATR Steam
ATR Oxygen
FT Wax
Unreacted Syngas
Condensed Water
Unreacted Syngas
Recovered CO2
Unreacted Syngas
Unreacted Syngas
H2 Recycle
Fuel Gas
3.2 Reactor Feed Description
There are four reactor feed streams. The main feed to the reactor is the clean syngas, produced
as described in Chapter 2. There are also three recycle streams internal to the FT processing
section. The light hydrocarbons are removed from the FT products during the separation step
and sent to an autothermal reformer where they are partially combusted to produce an additional
syngas stream (Section 3.5). A portion of the unreacted syngas that exits the reactor is recycled
back to the reactor as described in Section 3.8. The final reactor input stream is a hydrogen
recycle stream that is described in Section 3.9.
3.3 Reactor Description
The FT reaction is typically described as:
(2n+1) H2 + n CO  CnH(2n+2) + n H2O
Additional reactions produce carbon dioxide, oxygenated hydrocarbons, and unsaturated
products. The production of these byproducts is highly dependent on catalyst selection and
operating conditions.
The FT reaction is exothermic and requires the removal of heat to maintain the desired reaction
temperature. With a slurry-bed FT reactor, heat is removed from the reactor by heat-exchanger
tubes immersed in the slurry reactor. The slurry reactor has a high catalyst surface area and a
reasonably uniform temperature throughout. A single pass conversion of carbon monoxide to
useful hydrocarbon products of 87% and higher have been reported in literature.
The FT reactor model developed in previous work (Allen et al., 2010) held the FT wax profile
constant. To increase the utility of the model, the ability to vary the composition of the FT wax
has been included in the version of the model developed in this work. The distribution of FT
products by carbon number is typically described by:
Wn = n(1-)2n-1 (Equation 3-1)
where n is the carbon number, Wn is the weight fraction of the products that have a carbon
number of n, and  is the chain growth probability. The carbon number distribution of the
product is controlled by the  value, which is highly dependent on the process conditions.
Typical  values for an iron catalyst are approximately 0.70 to 0.75. An value of 0.70 would
result in the product distribution shown in Figure 3-2.
15
0.14
Mass fraction
0.12
0.1
0.08
0.06
0.04
0.02
0
0
5
10
15
20
25
30
35
40
45
Carbon number
Figure 3-2: Carbon number distribution for  value of 0.70
FT reactors with iron-based catalysts produce a mixture of heavy waxes and diesel to naphtha
range products. Typical  values for a cobalt catalyst are approximately in the 0.80 to 0.90
range. An value of 0.85 would result in the product distribution shown in Figure 3-3.
0.14
0.12
Mass fraction
0.1
0.08
0.06
0.04
0.02
0
0
5
10
15
20
25
30
35
40
45
Carbon number
Figure 3.3: Carbon number distribution for  value of 0.85
The model uses the weight fraction of waxes described by Equation 3-1 to generate the FT
product suite. The user can also input a wax distribution and have the model calculate an 
value that best represents the input distribution.
16
3.4 Product Separation
The FT products exiting the reactor must be separated and sent to the appropriate areas of the FT
production facility. The model handles the separation process by assigning specific molecules or
fractions of specific molecules to specific product streams. This does not change based on FT
products stream composition or flow rates. The FT products are split into three product streams.
Unreacted syngas containing water, carbon dioxide, nitrogen, carbon monoxide, hydrogen, and
C1 and C2 hydrocarbons, is separated and send for further processing (Sections 3.6 – 3.10). The
light hydrocarbons, containing C3 through C5 hydrocarbons and small amounts of C6 through
C8 hydrocarbons, are separated from the FT wax and sent to the autothermal reformer for
production of additional syngas. The FT wax, containing the C6+ hydrocarbons, is sent to the
upgrading section for further processing, as described in Chapter 4.
3.5 Autothermal Reformer
Light hydrocarbons (C3 to C5 with small amounts of C6 to C8) are fed to an autothermal
reformer (ATR). The ATR combines the light hydrocarbons from the FT reactor with an excess
of steam and oxygen from an air separation unit to produce additional syngas. The oxygen used
in the ATR is provided by the ASU described in Section 2.2a. Autothermal reforming is
preferable to steam reforming in this case because the process can be adjusted to give the desired
molar H2:CO ratio by varying the input of steam and oxygen. The autothermal reforming
reaction takes place in a pressure vessel where the oxygen, steam and hydrocarbons are partially
combusted (autothermal referring to the partial combustion of the hydrocarbons that provides the
required energy for reforming) then fed through a catalyst bed.
The ATR modeled for this report is based on the analysis performed by Piña et al (2006). Piña et
al studied the autothermal reforming of methane. Methane has a higher H2:C ratio (2.0:1) than
the C3 to C6 hydrocarbons (1.24:1). The composition of the syngas used in this report has been
adjusted to reflect the lower molar H2:C ratio. Figure 3-4 shows a simplified schematic of a
typical ATR.
Figure 3-4: Autothermal reformer (Piña et al, 2006)
17
The ATR can be operated at a variety of steam to carbon (S:C or S/C) input ratios. When the
steam to carbon ratio is increased, the molar H2:CO ratio also increases and the CO:CO2 ratio
decreases. Figures 3-5 and 3-6 show the relationship between the steam to carbon ratio and the
molar H2:CO and CO:CO2 ratios used in this work.
4
3.5
CO:CO2 Ratio
3
2.5
2
1.5
1
0.5
0
0.5
1
1.5
2
2.5
S/C Ratio
Figure 3-5: CO:CO2 ratio as a function of steam to carbon ratio
3
H2:CO Ratio
2.5
2
1.5
1
0.5
0
0.5
1
1.5
2
2.5
S:C Ratio
Figure 3-6: Molar H2:CO ratio as a function of steam to carbon ratio
For FT reactors using a cobalt catalyst, a molar H2:CO ratio of 2.1:1 in the combined feed
streams to the FT reactor is required. For this report, the conditions in the ATR have been set to
produce a syngas that has a 2.1:1 molar H2:CO ratio. The amount of gasifier syngas that is fed to
18
the WGS reactor is varied to make the overall molar H2:CO ratio fed to the FT reactor (including
the unreacted syngas, the ATR feed, and the hydrogen recycle) meet reactor requirements.
3.6 Gas Cooling
The unreacted syngas is separated from the FT products during products separation. The
unreacted syngas contains water, carbon dioxide, nitrogen, carbon monoxide, hydrogen, and C1
and C2 hydrocarbons. The gas cooling results in a syngas that has a temperature less than the
boiling point of water. This removes a majority of the water, which originated in the water-gas
shift reactor, the FT reactor, or the ATR, from the unreacted syngas before it proceeds to further
processing.
3.7 Carbon Dioxide Removal
Following gas cooling, carbon dioxide is removed from the unreacted syngas. Carbon dioxide is
removed using an methyldiethanol amine (MDEA) unit. For the purposes of this report it was
assumed that the MDEA unit was run to capture 96% of the carbon dioxide in the unreacted
syngas stream. More detailed information on the MDEA unit is provided in Allen et al. (2010).
3.8 Recycle Stream
After the carbon dioxide is removed from the unreacted syngas stream, the main components of
the stream are hydrogen and carbon monoxide. A portion of this stream can be recycled to the
reactor to augment the syngas produced by gasification. The model allows recycle rates ranging
from 0% to 75%. The previous work (Allen et al., 2010) held the unreacted syngas recycle rate
constant at 50%.
3.9 Hydrogen Recycle
The remaining unreacted syngas undergoes membrane separation to remove the hydrogen before
the remainder of the unreacted syngas is combusted for power generation. The membrane
separation removes 95% of the hydrogen from the unreacted syngas.
3.10 Fuel Gas
The portion of the unreacted syngas that is not recycled is combusted in process heaters or to
generate electricity. This stream is composed of nitrogen, carbon monoxide, and C1 and C2
hydrocarbon molecules, with small amounts of water, carbon dioxide, and hydrogen remaining.
The carbon dioxide emissions from the combustion of the fuel gas contributes to the overall
greenhouse gas footprint of the FT processing section.
3.11 The Structure of the FT Reactor Model
This section describes the function of the worksheets in the FT reactor model and the flow of
data between the sheets. The FT reactor model is a workbook titled “FT Section Model v3.xlsx.”
Each worksheet in this workbook that models a piece of process equipment includes both a mass
19
and atomic balance. The model also contains an overall mass and atomic balance which can be
found on the “Overall Outputs” worksheet. The overall mass and atomic balances account for
the FT reactor as well as the WGS reactor and syngas cleanup.
The “Specifications” worksheet is where the user provides variables that the model uses to
calculate the results. The main user-defined variables are the H2:CO ratio, mass fraction of coal
gasified, percent of oxygenated hydrocarbons in the products, percent of olefinic hydrocarbons in
the products, reactor single pass carbon monoxide conversion, percent of converted carbon
monoxide converted to carbon dioxide and percent unreacted syngas recycled. The user also
chooses the composition profile of the wax by inputting either an FT reactor α value in cell B14
or a wax composition in cells F19:F268 of the “Specifications” worksheet (if wax composition
values are provided, the model relies on them, and anything entered in cell B14 is ignored by the
model).
When the model runs, it first determines if the user has defined a wax. If the user has defined a
wax, that wax composition is used as described later in this section; however, if the user has not
defined a wax the model uses the α value in cell B14 to generate the wax composition.
The user may select the mass fraction of coal gasified from a dropdown list. If the user selects
one of the mass fractions populated in the list, the model also populates the syngas composition.
If the user selects a user defined mass fraction of coal gasified, then the user must also define the
composition of the syngas. If “user defined” is selected for the mass fraction of coal gasified
instead of one of the values in the drop-down, the model will not calculate the greenhouse gas
footprint for the acquisition and processing of raw materials. This is because the model in its
present form is not capable of performing these calculations.
The percent hydrogen removal, percent carbon dioxide removal and required wax production can
also be selected by the user in the “Specifications” worksheet.
The allowable wax delta and the allowable H2:CO ratio delta are model control inputs and help
the model define when convergence has been reached. These two variables should not be
changed unless the model will not converge. If any cells on the “Specifications” worksheet are
highlighted in red after the model runs, the model did not converge and (as described in Chapter
5.1) the calculate button must be pressed. If the calculate button has been clicked several times
and the model still will not converge, then the allowable wax delta or the allowable H2:CO ratio
delta may need to be increased.
The “Results” worksheet compiles all the results from all the worksheets into one location. The
results are organized in a manner which allows them to be easily accessed and included in
reports generated using this model. If any cells on this page other than the cell at the top left are
highlighted in red, the model has not converged.
The “Flow Diagram” worksheet contains the flow diagrams used for this model.
The “Gasification” worksheet pulls the mass fraction of coal gasified from the specifications
sheet. This is then compared to the three base case scenarios (1.0, 0.84 and 0.69). If the mass
20
fraction of coal gasified matches one of the base case scenarios then the sheet calculates the flow
rates for coal, biomass and oxygen from the ASU based on the required flow rate of carbon
monoxide which is defined on the “Overall Inputs” worksheet. The “Gasification” worksheet
also includes syngas compositions for the three base cases.
The “GHG Footprint Data” worksheet contains the greenhouse gas footprint data for the
production and transportation of the raw materials, land use for switchgrass production, onsite
processing of the raw materials, onsite electric and steam footprints, and the fuel gas combustion.
The onsite processing of raw materials and the onsite electric and steam footprints are not
included in the overall greenhouse gas footprint numbers since it is assumed in this model that
the a baseline amount of power production from fuel gas combustion meets the onsite power
demands for a particular base case, described in Appendix A. If additional fuel gas is generated,
it results in excess electricity generated for export offsite. Likewise, if less fuel gas is generated
than in the base case, electricity is purchased from offsite. These columns are highlighted in
yellow to alert the user that they are not included in the overall greenhouse gas footprint, but are
cataloged for completeness. All greenhouse gas footprint data is then normalized per kg of FT
wax produced. The greenhouse gas emissions for methane and nitrous oxide are converted to
carbon dioxide equivalents using the IPCC 2007 conversion factors.
The “Overall Inputs” worksheet contains all the inputs for the FT reactor section of the model.
There are three worksheets that provide values for the “Overall Inputs” worksheet: “WGS
Steam,” “ATR Steam,” and “ATR Oxygen.” In the “Overall Inputs” worksheet, the composition
of the syngas stream leaving the gasifier is taken from cells A17:B29 on the “Specifications”
worksheet. Flow rates are calculated iteratively. Required wax production is also taken from the
“Specifications” worksheet. The user-input value is compared to the calculated wax production
from the “FT Products Separation” worksheet, and if it is too low, the flow rate of the gasifier
syngas is increased. If the wax production is too high, the flow rate of the syngas is decreased.
Once this is done, Excel® recalculates the entire workbook. The resulting wax flow rate is again
compared to the specified wax flow rate. Excel® performs iterative calculations until the
calculated wax flow rate is equal to the user specified flow rate (within the limits set by the
allowable wax delta on the “Specifications” worksheet).
The “Overall Outputs” worksheet combines information about all the output flow streams of the
model in one place. These streams include the FT wax, streams from the acid gas removal
process (this is two separate streams which can be found at the bottom of the “WGS”
worksheet), water removal, carbon dioxide removal and fuel gas. The “Overall Outputs”
worksheet also contains overall mass and atomic balances for the FT reactor model. For the
mass balance calculations, the inputs are drawn from the “Overall Inputs” worksheet. The
atomic balances may be off by numbers far less than 1. This is not an error with the model, but
an artifact of the manner in which Excel® performs iterative calculations and determines when
convergence has been reached.
The “WGS” worksheet takes the gasifier syngas stream from the “Overall Inputs” worksheet and
divides it into two streams. One stream is sent to the WGS reactor to produce hydrogen as
described in Section 2.3. The remainder of the syngas is sent to the carbonyl sulfide reactor.
The percentage of gasifier syngas sent to the WGS reactor is controlled by the calculated overall
21
H2:CO ratio and the required H2:CO ratio. The H2:CO ratio is calculated on the “Combined
Syngas” worksheet after all reactor feed streams have been combined. If the user-input ratio is
higher than actual ratio, the percentage of gasifier syngas sent to the WGS is increased. If the
user-input ratio is lower than the calculated ratio, the percentage of gasifier syngas sent to the
WGS is decreased. Excel® performs iterative calculations until the calculated H2:CO ratio is
equal to the user input H2:CO ratio (within the limits set by the allowable H2:CO ratio delta).
The WGS reaction is then modeled. The model only simulates the forward WGS reaction and
not the reverse reaction. All syngas entering the WGS reactor is assumed to undergo the WGS
reaction. The remainder of the syngas is sent to the carbonyl sulfide reactor where the carbonyl
sulfide is hydrolyzed. The streams are then combined and impurities (carbon dioxide, hydrogen
chloride, and hydrogen sulfide) are removed from the syngas stream.
The “Combined Syngas Input” worksheet combines all streams entering the FT reactor. The
cleaned syngas from the “WGS” worksheet, the ATR syngas from the “ATR” worksheet, the
unreacted syngas recycle from the “Syngas Recycle Split” worksheet and the hydrogen recycle
from the “H2 Removal” worksheet together comprise the feed for the FT reactor.
The “Input Wax” worksheet is only used if the user has defined a user defined wax composition
on the “Specifications” worksheet. This worksheet takes the user defined wax from the
“Specifications” worksheet and determines the maximum mass fraction value. The wax is then
truncated so that only carbon numbers equal to or higher than the maximum mass fraction value
are used to determine the α value of the user defined wax. The wax is truncated because the
lighter ends of the wax where the mass fractions are increasing may have had portions removed
by the separation processes and therefore would not be representative of the actual FT products
produced by the reactor. The truncated wax then has the mass fractions normalized so the total
mass fraction for that portion of the wax is one.
The “Alpha Calculation” worksheet is also only used if the user has defined a user defined wax
composition on the “Specifications” worksheet. This worksheet contains the wax composition
for every α value from 0.01 to 1 (increasing by intervals of 0.01). The mass fractions for the
waxes from each α value are truncated and normalized to match the truncated and normalized
user-defined wax developed on the “Input Wax” worksheet. The absolute value of the difference
between the truncated user defined wax and the truncated alpha value wax is determined for
every carbon number for each α value. The difference for each carbon number is then totaled
and becomes the delta between that α value and the user-defined wax.
The “Alpha Value” worksheet is another worksheet that is only used if a user defined wax
composition was selected on the “Specifications” worksheet. The” Alpha Value” worksheet
draws the delta values for each α value from the “Alpha Calculation” worksheet and determines
which α value has the minimum associated delta, or the best fit α value. The best fit α value is
then used to generate the FT products that are used for the rest of the model.
In the “Reactor Calculations” worksheet, if the user has defined a user defined wax, then the α
value from the “Alpha Value” worksheet is used to generate the FT products. The calculated α
value is used because most wax compositions do not contain any information on the light ends of
the product which have a large impact on the overall greenhouse gas footprint. If the user has
22
chosen to enter an α value instead of a user-defined wax, then the chosen α value is used to
generate the FT products. The mass fractions of the FT products are then normalized so the total
mass fraction is one. The average molecular weights from the “Molecular Weights” worksheet
are used to determine the mole fraction of the FT products. The number of moles of carbon
monoxide entering the FT reactor is taken from the “FT Reactor” worksheet and the number of
moles of carbon monoxide converted to FT products is determined. The molar flow of each
carbon number in the FT products is calculated based on the mole fractions of the FT products
and the moles of carbon monoxide converted in the FT reactor. The number of moles of
hydrogen, oxygen and carbon in the FT products are then determined so that overall mass and
atomic balances can be performed on the “FT Reactor” worksheet. The percentages of
oxygenates and olefins are included in these calculations. The numbers for the molar
percentages of oxygenates and olefins for each carbon number are drawn from the “Molecular
Weights” worksheet.
The “FT Reactor” worksheet calculates the composition and flow rate of the entire product suite
from the FT reactor. The syngas input stream is drawn from the “Combined Syngas Input”
worksheet. The FT products and their molar flow rates are drawn from the “Reactor
Calculations” worksheet. The molar flow of carbon monoxide is determined by multiplying the
input molar flow of carbon monoxide by one less the FT reactor single pass carbon monoxide
conversion given in the “Specifications” worksheet. The molar flow of carbon dioxide is
determined by multiplying the input molar flow of carbon monoxide by the FT reactor single
pass carbon monoxide conversion and the percentage of converted carbon monoxide that is
converted to carbon dioxide. Nitrogen, methane, and ethane pass through the reactor unchanged.
The molar flow of water is controlled to balance the oxygen mole balance for the reactor. The
flow rate of hydrogen is controlled so that an atomic balance for hydrogen is obtained. The
lower heating value (LHV) for the FT products (C1+) is calculated based on the molar flow and
the LHV calculations on the “Heating Values” worksheet.
The “FT Products Separation” worksheet separates the products into three streams. The
unreacted syngas stream contains all non-hydrocarbons and the C1 and C2 hydrocarbons. This
stream is sent to the “H2O Removal” worksheet for further processing. The light hydrocarbon
stream contains all C3 to C5 hydrocarbons and a portion of the C6 to C8 hydrocarbons. This
stream is sent to the “ATR” worksheet for syngas production. The FT wax stream contains any
C6 to C8 hydrocarbons that are not contained in the light hydrocarbon stream and all C9+
molecules. This stream is sent to the upgrading section, which is described in Chapter 4.
The “ATR” worksheet converts the light hydrocarbon stream into a syngas stream that can be
recycled to the “Combined Syngas Input” worksheet. The light hydrocarbon stream is drawn
from the “FT Products Separation” worksheet. This model locks the output H2:CO ratio from the
ATR at 2.1. Based on this number, the steam to carbon ratio (S/C) in the ATR is 1.17, the
oxygen to carbon ratio (O2/C) is 0.599 and the carbon monoxide to carbon dioxide ratio
(CO/CO2) is 1.86. There is excess steam in the ATR, and the excess steam passes through the
ATR without reacting. This process completely converts all hydrocarbons that enter the ATR.
In the “H2O Removal” worksheet, the unreacted syngas stream from the “FT Products
Separation” worksheet is cooled to below the boiling point of water. The unreacted syngas
23
leaving the “H2O Removal” worksheet is saturated with water vapor, but a majority of the water
has been removed from the unreacted syngas stream. The unreacted syngas is then sent to the
“CO2 Removal” worksheet. The amount of carbon dioxide removed is based on the user-input
value in the “Specifications” worksheet. The remaining unreacted syngas is sent to the “Syngas
Recycle Split” worksheet.
The” Syngas Recycle Split” worksheet draws the unreacted syngas from the “CO2 Removal”
worksheet. The unreacted syngas stream is split into two streams: a recycle stream that is sent
back to the “Combined Syngas Input” worksheet and an unreacted syngas stream that is sent to
the “H2 Removal” worksheet for further processing. The percentage of the incoming syngas that
is recycled to the reactor is selected by the user on the Specifications worksheet.
The “H2 Removal” worksheet removes the hydrogen from the unreacted syngas stream. The
percent of hydrogen removal is selected by the user on the “Specifications” worksheet. The
hydrogen that is removed is recycled to the “Combined Syngas Input” worksheet.
The “Molecular Weights” worksheet converts the mass percentages of paraffinic, olefinic and
oxygenated products into mole fractions for C3+ hydrocarbons based on the user defined inputs
from the “Specifications” worksheet. The “Heating Values” worksheet calculates the HHV and
LHV using the group contribution method and also calculates the LHV using the Hileman
method (Hileman et al, 2010). The Hileman method values are the values used for LHV in this
model.
References
Allen, D. T.; Murphy, C.; Rosselot, K.S.; Watson, S.; Miller, J.; Ingham, J. and Corbett, W.
“Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer-Tropsch
Processing” Final Report to University of Dayton Research Institute from the University of
Texas, Agreement No. RSC09006; Account No. 2919890002; Prime Agreement No. F3361503-2-2347; February, 2010.
Hileman, J, R Stratton, P Donohoo. Energy content and alternative jet fuel viability. Journal of
Propulsion and Power. 2010. 0748-4658 vol.26 no.6 (1184-1196) doi: 10.2514/1.46232.
Piña, Juliana; Bucalá, Verónica; and Borio, Daniel Oscar (2006) "Optimization of Steam
Reformers: Heat Flux Distribution and Carbon Formation," International Journal of Chemical
Reactor Engineering: Vol. 1: A25.
24
Chapter 4: Wax Upgrading
The liquid hydrocarbon output (wax) generated during Fischer-Tropsch (FT) processing
generally contains hydrocarbons that are too large to be used as jet fuel and that are made up
almost exclusively of saturated, straight chain compounds. The wax must be upgraded to yield
synthesized paraffinic kerosene (SPK) that can be blended with jet fuel from conventional
refineries and used in aircraft. The basic process configuration for the upgrading section, shown
conceptually in Figure 4-1, mixes the wax with an excess of hydrogen and feeds it to a
hydrocracker. During hydrocracking, the feed is contacted with a catalyst at elevated
temperature (typically >300°C) and pressure (typically >50 atm), creating lower molecular
weight and more extensively branched compounds. Some of the hydrogen fed to the
hydrocracker is consumed; the excess is recycled to the hydrocracker. The products of
hydrocracking, which include fuel gas, naphtha, SPK and diesel, are separated using distillation.
Some of the liquid output from the FT reactor may already be in the SPK distillation range and
may be routed around the hydrocracker and sent straight to separation. This stream is labeled
“preseparated wax” in Figure 4-1. The wax that goes directly to liquid fuel products without
going through the hydrocracker is also called straight-run product.
Hydrocrackers are generally operated in recycle mode so that material that is too heavy to be
included in the hydrocracker product cuts (labeled “heavy ends” in Figure 4-1) is recycled back
to the hydrocracker for further processing. If production of diesel is not desired, the diesel
distillation cut is included in the heavy ends to be recycled. In a no-recycle configuration, a
residual stream is generated that includes hydrocracker output too heavy to be included in the
liquid product streams.
fuel gas
C1-C4
makeup
hydrogen
water
Compressor
naphtha
wax from FT column
High
Pressure
Separation
Wax
Hydrocracking
Separation
diesel
SPK (to blending)
recycle hydrogen
heavy ends
light ends from wax
Figure 4-1. Wax upgrading unit
4.1 Hydrocracker Model
25
The model developed for this work predicts the output generated by hydrocracking a specified
wax (see Chapter 3). The user may either provide a carbon number distribution for the wax
being fed to the hydrocracker, as well as the amount of oxygenates and olefinic compounds
present in the wax, if any, or accept the wax output of the FT model described in Chapter 3 as
wax input to the hydrocracker model. (Note that cradle-to-gate greenhouse gas emissions of the
SPK produced in the upgrading section are not estimated by the model unless the wax output of
the FT model is used as the wax input to the hydrocracker model.) The user must also specify
the fraction of bonds broken during hydrocracking, whether or not recycle of heavy ends is
desired, and what degree and type of isomerization is expected in the reactor. Detailed
information about running the model is contained in Chapter 5.
The hydrocracker for upgrading FT wax to SPK and other liquid fuels can play a significant role
in determining the overall greenhouse gas emissions of the process for making liquid fuels from
natural gas, coal, and biomass because of its role in determining product slate and, to a lesser
extent, because of the hydrogen consumption in the reactor. The model estimates the effect of
wax feed characteristics on hydrocracker output and the impact of hydrocracker operation
choices on both product slate and hydrogen consumption.
During hydrocracking, bonds are saturated and compounds are hydrogenated so that nearly all
the products of the hydrocracker are saturated alkanes (in some hydrocrackers, naphthenic
compounds -- ringed alkanes -- are also produced). Also, molecules are broken (cracked) into
smaller molecules, and straight-chain molecules can be isomerized to form branched molecules.
The model developed in this work relies on well-known rules for the likelihood of a bond
breaking during hydrocracking (Shah et al., 1988). In a hydrocracker, the two outermost carbonto-carbon bonds at both ends of a molecule are unlikely to break. If the next innermost bond is
broken, propane is created. This bond has half the likelihood of all the other bonds in the
molecule of breaking, and the likelihood of the other bonds breaking is all the same. For
example, consider a molecule of n-nonane, which has nine carbons and eight carbon-to-carbon
bonds:
C - C - C – C – C – C – C – C – C
1
2
3
4
5
6
7
8
As modeled, bonds 1, 2, 7, and 8 are unable to break. Bonds 3 and 6 have half the likelihood of
breaking as bonds 4 and 5, and bonds 4 and 5 have an equal likelihood of breaking.
The hydrocracker model developed in previous work (Agreement Number RSC09006; Account
No. 2919890002, Prime Agreement No. F33615-03-2-2347) assumed that hydrocracking occurs
in a two-phase (catalyst and a liquid reactant/product mixture) reactor. Most industrial, and even
laboratory scale, reactors exhibit three-phase behavior (catalyst, low molecular weight material
in a vapor phase, and a liquid phase containing higher molecular weight material). The
distinctive feature of a three-phase reactor is that the material in the vapor phase no longer has
access to the catalyst, which is assumed to be coated by liquid. This reduces the creation of very
light ends in the hydrocracker, since low carbon number material enters the vapor phase and
escapes the reactor without further reaction.
26
The modified hydrocracking model described here accounts for an unreactive vapor phase. It
does this by connecting a series of small reactors in series. Vapor phase compounds from each
subreactor are prevented from reacting in subsequent reactors. The subreactors are pictured
conceptually in Figure 4-2.
wax
feed
1
2
........
20
21
hydrocracker output
products
a) The no-recycle case. The hydrocracker is treated as a series of modeled sub-reactors with some fraction of bonds
broken in each reactor. As the feed moves down the chain, more and more small molecules are created that enter the
vapor phase and are no longer available for cracking in subsequent sub-reactors. The sub-reactor that the product
output exits from is determined by the user input fraction of total bonds broken and must generally be interpolated
between the output of two of the reactors in the chain.
wax
feed
1
2
........
20
21
hydrocracker output
products
recycle
b) The recycle case. As with the no-recycle case, the hydrocracker is treated as a series of sub-reactors with the
same fraction of bonds broken in each reactor. As the feed moves down the chain, more and more small molecules
are created that enter the vapor phase and are no longer available for cracking in subsequent sub-reactors. The subreactor that the product output exits from is determined by the user input fraction of total bonds broken and must
generally be interpolated between the output of two of the reactors in the chain. The recycle stream is routed back
and fed to the first reactor. The calculations must be iterated until the composition of the feed to the first reactor
(recycle stream and wax stream combined) converges.
Figure 4-2. Modeled hydrocracker subreactors
The vapor phase is represented by species with user-selected carbon numbers less than a
threshold value. In an actual hydrocracker, this threshold carbon number depends on the
temperature and pressure in the hydrocracker, but predicting the behavior of the lighter
compounds in the mixture is complex due to the isomers present in the mix. A single threshold
carbon number based on reactor temperature and pressure is unlikely to be realistic. Because of
isomerization, there is a distribution of threshold carbon numbers, each with different
isomerization patterns, that would be found in the vapor phase in the reactor. A distribution
27
around the threshold carbon number, rather than a sharp carbon number cutpoint, is employed by
the model.
In each sub-reactor, a small fraction of the total bonds that are available for breaking is broken.
Based on the probability rules as applied to the model, this excludes all of the two outermost
bonds in each molecule and half of the third innermost bond in each molecule. The number of
bonds broken by carbon number depends on both the number of available bonds at that carbon
number and the amount of material at that carbon number that is present. Because of the
probability rules described earlier, the largest molecules are consumed as the reactions proceed.
4.1a Probability calculations in the model
The bond breaks for each subreactor are calculated in the “calculate the breaks” worksheet of the
model. This worksheet is a matrix with the number of moles entering the subreactor for each
carbon number contained in cells B10 to B257 and in cells E5 to IR5. The number of moles is
based on 100 moles being fed to subreactor 1 and grows with each subreactor. The theoretical
number of breakable bonds per molecule (row 2) and the vapor-liquid equilibrium effect on bond
breakage (row 3) combine to give a value for the breakable bonds at each carbon number (row
4). Cell B5 calculates the fraction of total bonds that are broken in this subreactor, and cell B3
calculates the fraction of breakable bonds broken in the subreactor. The average number of
breakable bonds per molecule, based on values calculated in row 1, is calculated in cell B2, and
cell B1 has the terminal carbon number found in the wax (this terminal carbon number is the
largest carbon number with at least 0.0001 mol % of the wax). Cells C8 to H8 have the carbon
number range across which the vapor-liquid equilibrium takes effect (advanced users may wish
to alter this range). The main purpose of this worksheet is to calculate the values in cells E10 to
IR257. For each carbon number input, the same fraction of breakable bonds are broken and new
smaller species are created, following the probability rules for bond breakage described earlier.
Because the fraction of bonds broken in each subreactor is deliberately small, there is generally
some unbroken material at each carbon number, except at the high end of the carbon numbers.
The amount of unbroken material in each subreactor is assumed not to isomerize and must be
tracked. This is done in rows 261 to 511 of the “calculate the breaks” worskheet.
Column IS contains the sum of all the products of breaking at each carbon number – this
becomes the input for the next subreactor in the series. The model includes macros that copy this
column into column B and into a column on the “find break-fraction combo” worksheet. When
the macro is run, the output for subreactor 1 from column IS in the “calculate the breaks”
worksheet is copied into column C of the “find break-fraction combo” worksheet, then the output
of subreactor 2 is copied into column D, and so on. The input to subreactor 1 is copied into
column B of the “find break-fraction combo” worksheet.
The user-selected fraction of bonds broken occurs somewhere in between two of the subreactors,
and once the macro has finished running and the results of all 29 subreactors are copied into the
“find break-fraction combo” worksheet, the final results are interpolated between the two
subreactors where the user-selected value of fraction of bonds broken lies. This occurs in cells
A512 to AG763 of the “find break-fraction combo” worksheet. The totals for this section, less
28
unbroken material, are found in column AB. These results are used in the next part of the model,
which assigns the hydrocracker output to product cuts.
Cells A262 to AC511 of the “find break-fraction combo” worksheet continue to track the
unbroken material, which does not isomerize. The totals for this section, found in column AC,
are also used in the next part of the model, which assigns hydrocracker output to product cuts.
In order to relate fraction of bonds actually broken to total bonds broken, the moles of bonds in
each subreactor for each carbon number are calculated in cells AL11 to BO259 of the “find
break-fraction combo” worksheet.
4.1b Modeled carbon number characterization compared to experimental results
The carbon number distribution of the output predicted by the model has been compared to
experimental results from a number of researchers. In order to generate these comparisons, the
modeled fraction of bonds broken and the threshold carbon number was selected to best fit the
experimental data. Figure 4-3 shows a comparison between modeled results and experimental
results for hydrocracking a stream containing 88% C16 and 12% C17 (Sie et al, 1991). Figure 44 gives a comparison between modeled results and experimental results for hydrocracking a
SMDS FT wax under high and medium severity conditions (Sie et al, 1991). Figure 4-5 gives a
comparison between modeled and experimental results for hydrocracking the wax produced in an
iron slurry FT reactor (Leckel et al, 2005).
14
12
mole percent
10
modeled results (VLE C#
15, 0.0725 of bonds
broken)
8
experimental data (Sie et
al, 1991 Figure 10)
6
4
2
0
0
5
10
15
carbon number
Figure 4-3: Modeled and experimental carbon number distributions from hydrocracking a
stream that is 88% C16 and 12% C17
29
wax feed
10
mass percent
8
6
4
2
0
0
10
20
carbon number
30
40
modeled values medium
severity case (no recycle; 0.013
of bonds broken, VLE C#=18)
modeled values high severity
case (no recycle, 0.0265 of
bonds broken, VLE C#=18)
experimental medium severity
products (SMDS medium) (Sie
et al, 1991, Figure 12)
experimental high severity
products (SMDS heavy) (Sie et
al, 1991, Figure 12)
Figure 4-4. Modeled and experimental carbon number distributions from hydrocracking
an SMDS Fischer-Tropsch wax
5
wax feed (Leckel, 2005, Figure
3)
4.5
4
modeled values, 7 MPa case
(no recycle, VLE C# 29, 0.026
of bonds broken)
experimental values, 7 MPa
case (Leckel, 2005, Figure 3)
3.5
mass percent
3
2.5
2
1.5
1
0.5
0
0
10
20
30
40
50
60
70
80
90
carbon number
Figure 4-5. Modeled and experimental carbon number distributions from hydrocracking
an iron slurry Fischer-Tropsch wax
4.2 Liquid fuel products
Cracking is not the only reaction that takes place in a hydrocracker. Isomerization also occurs.
Isomerization does not consume hydrogen, but it does have an effect on product slate, as boiling
point decreases with increased branching. Isomerization also influences other important fuel
30
characteristics, such as density, heat of combustion, and combustion indices such as octane
number.
4.2a Estimating volumes of liquid fuels produced
Distillation cut points and other product properties are generally dependent on isomers present,
not just on the carbon number of the product. The model relies on formulas that are dependent
on carbon number for developing a set of representative isomers at each carbon number. Users
must specify the extent to which isomerization is occurring (the fraction of carbons that are
branched in the most commonly branched isomers that are produced) and whether creation of
naphthenes is allowed. Shah et al (1988, Appendix C) data for low carbon number hydrocracker
output were used to get an understanding of the upper bound of potential branching and creation
of naphthenic compounds. (The extent and types of isomerization that occur in a reactor depend
not just on reactor conditions but also on the type of catalyst used in the reactor.)
As with the two-phase model created for the earlier work, compounds that aren’t cracked in the
reactor are now isolated before the isomerization step because it is assumed that if they do not
contact the catalyst, they do not isomerize.
Boiling points, which determine distillation cuts, are based on an adaptation of the Stein and
Brown (1994) estimation method. The equations are (Tb in K):
Tb (degrees K) = 198.2 + Σ( ni × gi )
Tb (corr) = Tb - 94.84 + 0.5577 Tb - 0.0007705 (Tb)2 [Tb <= 700 K]
Tb (corr) = Tb + 282.7 - 0.5209 Tb [Tb > 700 K]
boiling point coefficients:
-CH3
21.98
-CH2- straight 24.22
>CH- straight 11.86
26.44
-CH2- ring
>CH- ring 21.66
4.2b Liquid fuel calculations in the model
The worksheet “assign to product cuts” is where the modeled result is isomerized, boiling point
values are assigned, and material is placed into product cuts based on boiling point. There are
five regimes in this sheet, each with carbon numbers 3 to 33: the regime at which the most
common degree of branching is observed (columns D to AH), a regime where half as much
branching as the most common degree of branching is observed (columns AI to BM), a regime
where 1.5X as much branching as the most common degree of branching is observed (columns
BN to CR), a regime for ringed compounds (columns CS to DW) and a regime for material that
is not branched because it has not contacted the catalyst in the hydrocracker (columns DX to
FB). All isomers of C34+ are combined in column FC. The group contribution value for boiling
point is given in row 7, and the product cut that the material falls into are coded in row 8. Row 9
helps calculate the product cut values of row 8. The codes for the distillation cuts are given in
Table 4-1. The SPK distillation cut is broken into seven sub-cuts that correspond to the 2008
military specifications for SPK. These specifications have changed, but the framework has been
left in place in case future specifications resemble the 2008 specifications again. Advanced users
31
can alter the military specification temperatures by changing cells A6 to A11 in the “model
control” worksheet. Group contribution equations and values for calculating the boiling point
can be found in column B of the “group cont values & equns” worksheet.
Table 4-1. Codes for product distillation cuts in the hydrocracker model
Code
Cut
z
fuel gas (C3 to C4)
a
naphtha (C5 to user-selected temperature #1)
b, c, d, e
SPK (>user-selected temperature #1 to 205°C)
f, g, h
SPK (>205°C to user-selected temperature #2)
i
diesel (>user-selected temperature #2 to user-selected temperature #3
j
residual/recycle (>user-selected temperature #3)
Cells D10 to FC257 of the “assign to product cuts” worksheet contain the number of moles of
material at each boiling point and product cut by carbon number. Columns FD to FO sum the
moles of product cuts for all isomers by carbon number, and columns FP to GA convert the
moles to mass. The weight percent of the products is given in columns GB to GM. Total feed
for subreactor 1 is calculated in column GT.
When the model is operated in recycle mode, the amount of material to be recycled is not known
until all the bonds have been broken. This amount is mixed with input wax and fed to subreactor
1, which changes the amount of material to be recycled. After calculating the recycle stream
repeatedly, the profile of the material to be recycled stops changing with each modeled run. The
model treats recycled material as if it were uncracked. However, this should not alter the overall
results because that material isomerizes before it exits the hydrocracker as product.
4.2c Military specifications for SPK distillation cuts
The temperature cutoffs for SPK-fraction distillation cuts are specified by the user, and can be
adjusted so that the maximum amount of SPK product that meets military specifications is
produced. The military specification (DoD, 2010) for the final boiling point of SPK is a
maximum of 300°C, and there is no initial boiling point. Instead, military specifications require
that at least 10% of SPK be recovered at 205°C and that the temperature at which 90% of the
SPK product boils is at least 22°C higher than the temperature at which 10% of the SPK product
boils.
There are military specifications for SPK other than distillation cut fractions. These include
maximum allowed aromatics, sulfur, freezing point, viscosity, naphthalenes, thermal stability,
particulate matter, and filtration time. There are also allowed ranges for flash point temperature
range, API, and electrical conductivity, and minimum required values for heat of combustion and
water separation. Other than distillation cuts, the only properties that were estimated in this
study were density and heat of combustion, as described below.
32
4.2d Estimating density of liquid fuel products
The model results can be used to estimate the density of the modeled liquid fuel hydrocracker
products. Density of the product streams is calculated using a relationship based on their
hydrogen mass fraction (Hileman et al, 2010). This relationship, contained in column G of the
“group cont values & equns” worksheet, is
density (g/mL)   0.039  hydrogen mass fraction  100  1.34
Hydrogen mass fraction for each product stream was calculated using the average molecular
weight generated by the model.
Military specifications require the density of SPK to be between 0.751 and 0.770 kg/L at 15°C
(DoD, 2010). Modeled densities for SPK are in this range only in the 250°C to 300°C range,
which, at least when the group contribution methods described here are used to predict density
and boiling points, means that both the density specification and the distillation temperature
specifications simultaneously is precluded.
4.2e Estimating heat of combustion of liquid fuel products
The model results can be used to estimate the heat of combustion of the modeled hydrocracker
product streams. The net heat of combustion of the product streams is calculated using a
relationship based on their hydrogen mass fraction (Hileman et al, 2010). This relationship,
found in column H of the “group cont values & equns” worksheet, is
LHV (M J/kg)   0.572  hydrogen mass fraction  100  35.3
As with density, hydrogen mass fraction for each product stream was calculated using the
average molecular weight generated by the model. In cases where the gross heat of combustion
was desired, it was calculated from the net heat of combustion using the relationship
LHV  HHV  21.96  hydrogen mass fraction
This relationship is given in column I of the “group cont values & equns” worksheet. Military
specifications require the net heat of combustion of SPK to be 42.8 MJ/kg or greater (DoD,
2010).
4.2f Product property calculations in the model
The worksheet “assign to product cuts” is also where the estimated product properties are
calculated. The formulas and values used to create the estimates are in the “group cont values
and equns” worksheet. By carbon number, the number of atoms of each species of hydrocracker
output are given starting in column A of the “assign to product cuts” worksheet in row 268, the
molecular weight in row 269, the mass fraction of hydrogen in row 270, and the mass of carbon
and hydrogen in products resulting from 100 moles of feed to the hydrocracker in rows 271 and
272. Boiling point formulas are in rows 274 to 281. Rows 274 to 321 contain acentric factor,
critical pressure, and critical temperature estimates that ultimately were not used in the modeling
because they were not providing reasonable results for the modeled conditions. Mass percent by
carbon number is calculated in rows 323 to 324, density in row 326, and lower heating value in
33
row 328. Beginning in column FD, estimated property values by product cut rather than carbon
number are given. Row 269 gives molecular weight, row 272 gives hydrogen mass fraction, row
273 gives density, row 274 gives lower heating value, and row 275 gives higher heating value.
Rows 332 to 968 calculate the temperatures at which 10% by mass and 90% by mass of the SPK
is recovered (this is to test that the military specifications for distillation gradient is met).
Estimated wax properties (column BX to CD) and the properties of the straight run cut (the
preseparated wax) (columns AE to BV) are given in the “wax input” worksheet.
4.3 Estimating greenhouse gas emissions
Greenhouse gas emissions assigned to the SPK stream from the upgrading process depend on
utility demands for heat and energy for separators and compressors, as well as the amount of
hydrogen consumed in the hydrocracker and the relative volumes of co-products produced. In
this analysis, it was assumed that the greenhouse gas footprint of constructing the upgrading
section were insignificant.
4.3a Stoichiometric hydrogen demand during hydrocracking
A simple means of estimating hydrogen consumption in the hydrocracker is to calculate the
stoichiometric hydrogen demand – the hydrogen required to saturate and hydrogenate all the
molecules and to take the place of carbon bonds when molecules are broken. Stoichiometric
hydrogen demand can be estimated if the average molecular weight of the wax feed and the
average molecular weight of the hydrocracker output are known, along with the concentration of
olefinic bonds and oxygenated compounds. For a given feed, the smaller the molecular weight
of the output, the higher the stoichiometric hydrogen demand. The fraction of oxygenated
molecules and olefinic bonds in the wax are important to hydrogen consumption if they are
present in significant quantities.
Modeled values were used to calculate the stoichiometric hydrogen demand in the hydrocracker
and from that, an estimate of the greenhouse gas emissions from hydrogen consumed during
hydrocracking. This stoichiometric hydrogen consumption is equal to the hydrogen required to
crack the molecules entering the hydrocracker, the hydrogen required to consume the oxygen in
the oxygenated compounds entering the hydrocracker, and the hydrogen required to saturate the
olefinic bonds entering the hydrocracker.
The model is configured such that the user selects the amount of SPK produced. This determines
the amount of wax required. In order to calculate the hydrogen demand, the volume of feed to
the hydrocracker had to be calculated. For the recycle case, this is the wax feed plus the recycle
stream. The wax feed rate was calculated by performing a carbon balance around the
hydrocracker. The equation for the carbon balance is
34
carbon in wax input  carbon in fuel gas  carbon in naphtha  carbon in SPK  carbon in residual
 m
 W
 MWW

 NW

 m
 m 
  F  NF   N
 MWF 
 MWN

 mS 
 mD
 NN  
 NS  
 MWD

 MWS 

 mR
 ND  

 MWR

 NR

In this equation, N is the average number of carbon atoms per molecule, m is the mass flow rate,
and MW is molecular weight. The subscripts W, F, N, S, D, and R stand for wax input, fuel gas,
naphtha, SPK, diesel, and recycle, respectively. For a saturated alkane, N is equal to
N 
(MW - 2)
14
The oxygen and olefin concentrations in the input to the hydrocracker are not large enough to
change the molecular weight of the feed, so a value for the molecular weight that assumes
saturated alkanes gives reasonable results. Substituting and rearranging gives
 m   MWW  2 
Carbon input   W  

14

 MWW  
 m   MWF  2   mN   MWN  2 
  F 



14
  MWN  

 MWF   14
 m   MWS  2   mD   MWD  2 
 S 



14

  MWD  
 MWS   14
 m
 R
 MWR
  mF   MWF  2   mN


   MW
MWF   14
 
N


mW 



  MWR  2 


14


  MWN  2   mS   MWS  2   mD

   MW   14    MW
14
 
 
S 
D

 MWW  2 


14


  MWD  2   mR

   MW
 
R
  14
  MWR  2  



  14
 MWW



Per mol of hydrocracker feed (recycle plus wax), the moles of hydrogen molecules required for
cracking is equal to
 NI

1 

NO
mol H 2 for cracking
number of broken bonds

 1 mol H 2 
 1 mol H 2 
mol input
mol input
 mol input 




In this equation, N (the average number of carbons per molecule) is derived from the molecular
weights of the hydrocracker input and output that were calculated by the model. The subscript O
designates output (including the portion of the output that is recycled) and the subscript I
designates input to the hydrocracker.
Per mole of wax feed, the moles of hydrogen molecules required to consume the oxygen in
oxygenated compounds and to saturate the bonds in the olefinic compounds is given by
35
mol H 2 to oxygenate 2 mol H 2  f oxygenated

mol wax
mol wax
and
mol H 2 to saturate 1 mol H 2  f olefinic

mol wax
mol wax
In these equations, f is the fraction of molecules in the wax feed that are olefinic or oxygenated.
The recycle stream is assumed to be 100% saturated alkanes, so only the wax portion of the total
feed to the hydrocracker has oxygenated compounds, not the recycle portion. That portion is
mol fraction of input that is wax 
mols of wax
mols of wax  mols of recycle
Molar consumption can be converted to mass consumption by applying the molecular weights.
Greenhouse gas emission factors of 0.0000298 kg methane/SCF H2, 0.000000103 kg nitrous
oxide/SCF H2, and 0.0204 kg carbon dioxide/SCF H2 (0.0212 kg CO2E/SCF H2) were applied in
order to estimate the greenhouse gas emissions for the modeled stoichiometric hydrogen
demand. These values were taken from Table 4-28 of Skone and Gerdes (2008), and are
intended to reflect average cradle-to-gate emissions from hydrogen production at refineries
nationwide, assuming hydrogen is produced at a modern steam methane reforming plant using
natural gas as the feed, with subsequent hydrogen purification by pressure swing adsorption.
4.3b Combustion of fuel gas for heat and electricity generation
Fuel gas is produced in both the FT reactor and in the hydrocracker, with the fuel gas produced
in the FT reactor of lesser quality. In every modeled scenario, it is assumed that all of the fuel
gas produced is burned either in process heaters or to generate electricity. Carbon dioxide
emissions from burning the fuel gas are estimated based on the carbon species present in the fuel
gas and on the volume of fuel gas produced, with complete combustion assumed.
A base case for all processes within the facility fenceline, including switchgrass and coal
processing, gasification, fuel gas purification and water gas shift reactions, the FT process, and
the upgrading section was developed that produced just enough fuel gas in the hydrocracker and
the FT reactor to meet the energy needs of the entire process. In this base case, described in
more detail in Appendix A, 69% of the feed to the gasifier is coal and the hydrocracker is
operated in recycle mode with only naphtha and diesel produced. The FT reactor has an iron
catalyst. The ratio of the combined higher heat content of the fuel gas produced in the FT reactor
and in the upgrading section to the heat content of the wax in this base case is 0.0690.
If run conditions result in a ratio higher than this, then a credit can be taken for excess electricity
generation, and if run conditions result in a ratio lower than this, electricity must be purchased.
In other words, if process configurations result in less total energy from combustion of fuel gas
produced than is produced in the base case on a per unit of energy wax produced and upgraded,
it is assumed that no other significant overall process demands for process heat or electricity will
occur and additional electricity demands will be met by purchasing electricity. National average
values of greenhouse gas emissions for electricity are applied: 0.000858 kg methane/kWh,
0.00000959 kg nitrous oxide/kWh, and 0.739 kg carbon dioxide/kWh (Skone and Gerdes, 2008).
Because of the sensible heat made available during the processes, steam can be generated
36
without burning fuel gas and the fuel gas is used only to superheat the steam before generating
electricity. Thus, the efficiency of electrical generation is high, at 83%.
If process configurations result in more fuel gas being produced than is produced in the base
case, it is assumed that the excess fuel gas will be burned to produce excess electricity and a
displacement credit based on the national greenhouse gas emission estimate for that excess
electricity is applied. As with the case for less fuel gas being produced than the base case, the
excess fuel gas is needed only to superheat steam for electricity generation and the efficiency is
high.
4.3c Displacement credits for naphtha produced
The ASTM boiling range of light straight-run gasoline is 90-220°F (Skone and Gerdes, 2008,
Table 4-1). The naphtha produced in the hydrocracker is similar to straight run gasoline because
it is paraffinic and because of its distillation temperature range. This type of naphtha is usually
used as feedstock for production of olefins. A credit can be taken for the cradle-to-gate
greenhouse gas emissions that would have been released due to production of this naphtha
stream at a conventional refinery.
In an analysis of the greenhouse gas emissions from conventional refineries (Skone and Gerdes,
2008), special naphthas and petrochemical feedstocks are grouped with the "light ends" streams
at a refinery, along with still gas and LPG. The cradle-to-gate greenhouse gas emissions of all
light ends are estimated as being equal on a per barrel basis, at 0.515 kg methane per barrel,
0.00130 kg nitrous oxide per barrel, and 60.9 kg carbon dioxide per barrel (74 kg CO2E/bbl).
For naphtha less than 401°F and special naphthas, the HHV is 5.248 MMBtu/bbl (Skone and
Gerdes, 2008, Table 4-18). The HHV of the modeled naphtha stream (which varies depending
on the modeled scenario) determines the credit assigned to naphtha production.

kg CO 2 eq 
 74
  HHV of modeled naphtha 
bbl
naphtha 
naphtha credit  

MMBtu HHV  
MJ 
 5.248
  1055.06

bbl
naphtha
MMBtu



4.3d Displacement credit for diesel produced
A nationally representative estimate of the cradle-to-gate greenhouse gas emissions from diesel
production at conventional refineries was used to calculate the displacement credit for diesel
produced in the hydrocracker. This value is 0.540 kg methane per barrel, 0.00134 kg nitrous
oxide per barrel, and 82.5 kg carbon dioxide per barrel (96.5 kg CO2E/bbl) (Table L-1 of Skone
and Gerdes, 2008).
4.3e Greenhouse gas footprint calculations in the model
The greenhouse gas footprint calculations are found in the “results” worksheet of the
hydrocracker model. Rows 15 to 59 of this worksheet contain flow rates for wax, preseparated
wax, fuel gas, naphtha, SPK, diesel, residual, hydrogen, recycle, coal, and switchgrass. Rows 63
to 92 of this worksheet have estimated properties of the streams, including density, molecular
weight, average carbon number, heating values, and the ratio of wax needed to produce the fuels
in the hydrocracker to the wax produced by the FT model. Rows 95 to 113 contain literature and
assumed values for atomic mass, oxygenated and olefinic compounds found in wax, stream
37
temperatures, heating values for certain species, carbon dioxide equivalency factors, the base
case electricity demand, and the efficiency of onsite electricity generation. Rows 116 to 120
have the excess/deficit fuel gas calculations, rows 123 to 152 have the greenhouse gas emission
factors, and rows 156 to 183 have the greenhouse gas estimates. Rows 186 to 188 contain the
carbon sequestration estimates and rows 191 to 203 give unit conversion values that were used in
the calculations.
References
U.S. Department of Defense (DoD). Detail specification: turbine fuel, aviation, kerosene type,
JP-8 (NATO F-34), NATO F-35, and JP-8+100 (NATO F-37). MIL-DTL-83133G. 30 April
2010.
Hileman, J, R Stratton, P Donohoo. Energy content and alternative jet fuel viability. Journal of
Propulsion and Power. 2010. 0748-4658 vol.26 no.6 (1184-1196) doi: 10.2514/1.46232.
Leckel, D. Hydrocracking of iron-catalyzed Fischer-Tropsch waxes. Energy and Fuels, 2005,
19, 1795-1803.
Shah, PP, GC Sturtevant, JH Gregor, MJ Humbach, FG Padrta, KZ Steigleder. Fischer-Tropsch
wax characterization and upgrading, final report. US Department of Energy. Available through
NTIS DE88014638. June 6, 1988.
Sie, ST, MMG Senden, HMH van Wechem. Conversion of natural gas to transportation fuels via
the Shell Middle Distillate Synthesis process (SMDS). Catalysis Today, 8 (3), 371-394 (1991).
Skone, TJ, K Gerdes. Development of baseline data and analysis of life cycle greenhouse gas
emissions of petroleum-based fuels. US Department of Energy, National Energy Technology
Laboratory, Office of Systems, Analysis and Planning. November 26, 2008
38
Chapter 5: Model Operation
This chapter presents detailed instructions for using the greenhouse gas emission estimation
model. The two sections of the chapter correspond to the model sections: Section 5.1 contains a
tutorial for the Fischer-Tropsch (FT) reactor model and Section 5.2 contains a tutorial for the
hydrocracker model. The hydrocracker model can be operated so that it is automatically linked
to the FT reactor model so that cradle-to-gate greenhouse gas emissions for production of SPK
can be estimated.
Figures in this chapter reflect screen shots made in Excel® 2007; other versions of Excel® may
have a different appearance.
5.1 FT Reactor Model Operation
The FT reactor model is an Excel® workbook called “FT Section Model v3.xls.” This
workbook can be used to model the input and output streams of an FT reactor. The model takes
a set of user defined variables and generates an FT wax component distribution, estimates the
syngas requirements, and determines the associated greenhouse gas emissions from the point of
raw material acquisition to the FT reactor for a given quantity of FT wax produced.
The model varies the syngas input to the reactor and the amount of syngas sent to the water-gas
shift (WGS) reactor in order to meet the constraints imposed by the user. The model achieves
this by taking advantage of intentional circular references and iterative calculations in Excel®.
When the model is launched, a warning message about circular references in the workbook may
be displayed. Since the circular reference is intentional, respond by clicking on the “OK” button
if this message appears.
Next, click on the “ribbon” (in Excel® 2007) or the File tab (in Excel® 2010) in the upper left
hand side of the window (indicated by the red arrow in Figure 5-1), then click on the Options
button at the lower right of the drop down menu (indicated by the green arrow in Figure 5-1).
39
Figure 5-1. First step for enabling iterative calculations
Choose the “Formulas” tab on the left side of the pop-up box (indicated by the blue arrow in
Figure 5-2). Ensure that the box for “enable iterative calculations” is checked, that “maximum
iterations” is set to 32767, and that the “maximum change” is set to 0.001 (indicated by the black
arrow in Figure 5-2).
Model settings that can be altered by the user are contained in the worksheet titled
“Specifications,” which is shown in Figure 5-3. Since this is an iterative model, Excel®
undergoes a series of iterations until it converges on the desired results when changes are made
to the model’s settings. The process of iterating may take a few minutes, depending on the speed
of the computer being used. While iterations are in progress, the values of various cells change
rapidly and Excel® may temporarily appear to “freeze up” until convergence is reached. Excel®
“unfreezes” when calculations are complete.
40
Figure 5-2. Second step for enabling iterative calculations
The “calculate” button (indicated by the yellow arrow in Figure 5-3) must be clicked after each
round of iterations is complete in order to verify that further iterations are not necessary; if the
model has converged, clicking on the “calculate” button will not launch another round of
iterations. The wax output level and molar H2:CO ratio calculated by the model are displayed at
the top of the “Specifications” worksheet (in cells B1 and D1). If these cells are highlighted in
red, it is a warning that convergence has not been reached.
This model is capable of simulating the performance of a FT reactor using either a cobalt- or
iron-based catalyst. The user-defined variables associated with each type of catalyst are noted
below.
41
Figure 5-3. FT reactor model specifications worksheet
The user-selected elements of the “Specifications” worksheet are:
1. The molar ratio of H2:CO in the overall combined feed to the FT reactor (cell B2). As
discussed in Chapters 2 and 3, the model meets the user-selected ratio by adjusting the
amount of syngas from the gasifier that is sent to the WGS reactor. Cobalt catalyst FT
reactors require a higher molar H2:CO ratio than iron catalyst reactors because the WGS
reaction is not promoted in cobalt catalyst FT reactors. The typical ratio for an FT reactor
with a cobalt-based catalyst is 2.1:1; a reactor with an iron-based catalyst reactor is typically
fed a stream with a molar ratio of 1.1:1.
42
2. The percentage by mass of gasifier feed that is coal (cell B3). Users may choose 100% coal
by mass, 84% coal by mass, or 69% coal by mass from a drop-down box. The remainder of
the feed is assumed to be switchgrass. If one of these three coal feed ratios is chosen, the
associated values from the gasifier model populate the user defined syngas composition (in
cells B19:B29 of the “Specifications” worksheet). It is possible to enter a different value for
the fraction of gasifier feed that is coal, but in that case the user must also define the
composition of the syngas produced by the gasifier.
3. The mass percent of oxygenated (cell B4) and olefinic (cell B5) hydrocarbons that are found
in the FT wax. Cobalt catalyst FT reactors typically produce smaller amounts of oxygenates
and olefins than iron catalyst FT reactors. Shah et al (1988) found that the wax from an iron
catalyst FT reactor was 2.9% oxygenates and 7.4% olefins by mass.
4. The FT reactor single pass carbon monoxide conversion (cell B6). This is the total
percentage of carbon monoxide entering the reactor that does not exit the reactor as carbon
monoxide (regardless of what the carbon monoxide is converted to). A cobalt catalyst
reactor may have a single pass conversion in the 70% range while the single pass conversion
for an iron-catalyzed reactor system may be as high as 90%.
5. The percent of converted carbon monoxide that is converted to carbon dioxide (cell B7). This
can be less than 2% for a cobalt catalyst reactor, while for an iron catalyst reactor it may be
as high as 35% to 40%.
6. The percent hydrogen removal (cell B8) and percent carbon dioxide removal (cell B9).
These values reflect the fact that at an actual plant, separation processes are not perfect. The
hydrogen recovered in the reactor’s gas purification section is recycled to the FT reactor,
which in turn impacts the amount of syngas from the gasifier that is fed to the WGS reactor.
For this reason, decreasing the amount of hydrogen removed in this step can increase the
overall carbon dioxide production during water-gas shift.
7. Required wax production (cell B10). Six million kg/day of FT wax generally produces about
50,000 BPD of liquid fuel products from the upgrading section. Exactly how much liquid
fuels are produced in the upgrading section depends on wax composition and on process
choices in the upgrading section. The hydrocracker model calculates how much wax is
needed to make a desired quantity of liquid fuels given the particular wax and upgrading
section process selections, and when the hydrocracker and FT models are linked, the
hydrocracker model adjusts values from the FT model so that they correspond to the wax
production calculated by the hydrocracker model.
8. Percent of unreacted syngas that is recycled (cell B11). This value can range from 0% to
75%; the user selects values from a drop-down box that has 5% increments. Increasing the
recycle ratio returns more carbon monoxide to the system and decreases the demand on raw
material needed for gasification, which can lower the overall facility greenhouse gas
footprint. Recycle ratios in excess of 75% are not realistic and create issues that do not allow
the model to converge.
9. The allowable wax delta (cell B12) and allowable molar H2:CO ratio delta (cell B13.) These
are both model variables that help the model define when it has converged. It is not
recommended that model users change these values.
10. The FT reactor α (cell B14) and user defined wax composition (cells E19:E268). Only one
of these sets of values should be filled out. If the user has defined the wax in cells E19:E268,
the model will generate a comparable wax. If the user has not defined a wax composition
43
(i.e., cells E19:E268 have been left blank) the model generates a wax using the α value from
cell B14.
5.1a FT Reactor Model Demonstration Case Study
In this model demonstration, you will operate the FT reactor model to produce a wax similar to
the wax reported by Sie et al (1991), using a cobalt catalyst and assuming that the feed to the
gasifier is 16% switchgrass. You are also asked to assume that 50% of the unreacted syngas
stream is recycled to the FT reactor and that the wax produced contains 2.9% oxygenates and
7.4% olefins by mass. Run the model to produce 5,995,488 kg/h of wax, with 95% hydrogen
removal and 96% carbon dioxide removal. Do not change the default values for the wax and
H2:CO molar ratio deltas.
To run the model, make sure that Excel® is configured to perform iterative calculations, as
described earlier in this chapter, and open the “Specifications” worksheet. First, we are going to
tell the FT reactor model to produce a wax similar to the wax reported in Sie et al (1991). This
wax is one of the example waxes whose composition is provided in the “wax input” worksheet of
the hydrocracker model. Open the hydrocracker model, which is in a workbook titled “VLE
hydrocracker model.xls,” go to the “wax input” worksheet, and copy cells T10:T257 from that
worksheet to cell E21 in the FT reactor model’s specifications worksheet. The FT reactor model
will freeze momentarily as it performs calculations.
Since this is a cobalt catalyst, set the molar H2:CO ratio to 2.1, the carbon monoxide single pass
conversion to 70%, and the percent of carbon monoxide converted to carbon dioxide to 2%.
Select 0.84 for the mass fraction of coal gasified because you have been given that the feed is
16% biomass, and select 50% for the percent of unreacted syngas that is recycled. Enter the
appropriate values for oxygenates, olefins, production of wax, and the removal rates of carbon
dioxide and hydrogen from the first paragraph of this section. Make sure cell B14 is blank; the
model must either be given an α value or a wax composition, but not both. Figure 5-4 is a
screenshot that shows what the “Specifications” worksheet looks like when all of the information
has been entered.
44
Figure 5-4. FT reactor model demonstration case study inputs
You may have noticed that every time you change a value, the model goes through another round
of iterations (advanced users may want to turn the iterating feature off before entering all the
values in the specifications worksheet and then turning it back on so that the model runs). The
45
model has finished calculating if you click on the “calculate” button at the bottom left of the
workbook window and nothing happens. Neither cell B1 nor D1 is highlighted in red when
iterations are complete.
Based on the wax composition that was entered by the user, the model has calculated an  value
of 0.89 (found in cell F3 of the “Alpha Value” worksheet). Table 5-1 shows some of the
contents of the results tab.
Table 5-1. FT reactor demonstration case study results
Run Conditions
User Specified
Required H2:CO Ratio to Reactor
Allowable H2:CO Delta
FT Wax Production
Allowable Wax Production Delta
Reactor Temperature
Reactor Alpha
FT Single Pass Conversion
% of CO converted to CO2
% of Oxygenated HC's in Products by Weight
% of Olefinic HC's in Products by Weight
% H2 Removal
% CO2 Removal
% Syngas Recycle
2.1
Mass Flow Rates
Inputs (FT Production Section)
Gasifier Syngas
WGS Steam
Model Actual
2.11281561
0.02
5995488
200
Unit
moles/mole
moles/mole
5995419.64
kg/day
kg/day
o
494
K
0.89
70.0%
2.0%
2.9%
7.4%
95.0%
96.0%
50.0%
Value
Unit
Source
34,533,308
7,225,315
kg/day
kg/day
ATR Steam
1,124,154
kg/day
ATR Oxygen
ATR Oxygen (O2 only)
1,072,401
1,024,970
kg/day
kg/day
calculated to meet daily demand for FT Wax
calculated to meet daily demand by WGS reactor based on Syngas Flow
calculated from report by Pina et al and adjusted to account for higher carbon # hydrocarbons
calculated based on needs of the ATR
Outputs (FT Value
Unit
Source
46
Production Section)
FT Wax
Acid Gas Removal
5,995,420
1,399,221
kg/day
kg/day
Acid Gas Removal (CO2 only)
Condensed Water
Recovered CO2
Fuel Gas
859,965
kg/day
10,389,897
21,455,053
4,715,589
kg/day
kg/day
kg/day
Fuel Gas
44,806,898,035
kJ/day
Fuel Gas
46,453,054,635
kJ/day
Gasification Section
Coal Feedrate
Value
Unit
17,855
Tonnes/day
Biomass Feedrate
3,401
Tonnes/day
Gasification Oxygen
15,222,089
kg/day
Gasification Oxygen 14,556,846
(O2 only)
kg/day
Gasifier Syngas H2:CO Ratio 0.522 moles/mol demand from hydroprocessing section
removal of all HCl, H2S and % of CO2 defined in Run Conditions above
water removed from unreacted syngas stream
CO2 removed from unreacted syngas stream
remainder of unreacted syngas after removal of water, CO2, recycle stream and H2
calculated using LHV values listed on Molecular Energies worksheet
calculated using HHV values listed on Molecular Energies worksheet
Source
Calculated based on report " Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer‐
Tropsch Processing" Allen et al, 2010.
Calculated based on report " Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer‐
Tropsch Processing" Allen et al, 2010.
Calculated based on report " Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer‐
Tropsch Processing" Allen et al, 2010.
Calculated based on report " Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer‐
Tropsch Processing" Allen et al, 2010.
Calculated from gasifier data Table 5-2 shows the carbon number distribution of the FT Liquids sent to the hydrocracking
section through carbon number 40, while Figure 5-5 shows a comparison of the user-defined wax
to the wax generated by the FT reactor model.
47
0.06
Input Wax
0.05
Mass Fraction
Calculated Wax
0.04
0.03
0.02
0.01
0
0
20
40
60
80
100
Carbon Number
Figure 5-5.
Comparison of user-defined wax to model-generated wax for the
demonstration case study
48
Table 5-2. FT wax composition for demonstration case study
Carbon Number Mass Percent
6
4.0
7
4.6
8
4.9
9
5.0
10
5.0
11
4.9
12
4.7
13
4.5
14
4.4
15
4.2
16
3.9
17
3.7
18
3.5
19
3.3
20
3.1
21
2.9
22
2.7
23
2.5
24
2.3
25
2.2
26
2.0
27
1.8
28
1.7
29
1.6
30
1.4
31
1.3
32
1.2
33
1.1
34
1.0
35
0.9
36
0.9
37
0.8
38
0.7
39
0.7
40
0.6
5.2 Hydrocracker Model Operation
The workbook “VLE hydrocracker model.xls” can be used to model hydrocracker output for a
given wax or for a wax generated by the FT model. It provides estimates of physical properties
of hydrocracker products, hydrogen consumption, and flow rates of all hydrocracker streams for
a given flow rate of SPK as well as greenhouse gas emission estimates. If a wax generated by
the FT model is used as a feedstock to the hydrocracker, the hydrocracker model provides cradle49
to-gate greenhouse gas emission estimates for SPK produced in an FT production facility, from
coal mining and switchgrass cultivation to liquid fuels ready for transport.
In this model, the hydrocracker is treated as a series of about 20 subreactors. This is done in
order to protect light compounds that would be found in the vapor phase from further cracking.
For example, in the first subreactor, there may be constituents that would be in the vapor phase
under the given reactor conditions. Within that subreactor, some new vapor phase products are
created. These newly created vapor phase products are not allowed to react in the next
subreactor or in any subsequent subreactors.
The modeling portion of this workbook has the following sections, each with its own worksheet:
1 “calculate the breaks” calculates the carbon number of products created in each subreactor for
each carbon number input
2 “find break-fraction combo” determines where in the sequence of subreactors the user-selected
fraction of bonds broken is located and calculates the hydrocracker product stream by carbon
number
3 “assign to product cuts” assigns isomerization to the hydrocracker products, assigns them to
distillation cuts, and calculates physical properties
In addition to choosing the wax to be upgraded, the user selects many values. The upper and
lower boiling point of the SPK stream can be altered by the user so that estimated properties of
the SPK stream meet military specifications as closely as possible. The extent of cracking is
controlled by the user so that particular product yields can be optimized. The user decides
whether heavy fractions are recycled to the hydrocracker and whether those heavy fractions are
in the heavier-than-SPK or heavier-than-diesel range. Isomerization in the model is based on
user-input values for extent of isomerization and extent of naphthenes created. The user also
chooses the carbon number of compounds that are found mostly in the vapor phase in the
hydrocracker; this value is related to the temperature and pressure in the hydrocracker.
In particular, in the “wax input” worksheet, the user chooses:
 whether to use the wax created in the associated FT model or provide the weight percent by
carbon number for another wax
 the weight percent of olefinic and oxygenated compounds in the wax
In the “model control” worksheet, the user chooses values that determine the product yields from
the given wax:
 initial and final boiling points of the SPK fraction
 the fraction of bonds broken
 whether recycle of heavy ends is desired and what temperature fraction is recycled, e.g.,
heavier than SPK or heavier than diesel
 the temperature cutoff for preseparated wax, if any (some waxes contain material that is
already in the desired distillation fraction range)
 a vapor-liquid equilibrium (VLE) carbon number that represents the carbon number that is
mostly contained in the vapor phase (the advanced user may also wish to alter the spread
over which carbon numbers around that carbon number are affected by VLE in the “calculate
the breaks” worksheet)
50




the desired flow rate of SPK in barrels per day (bpd) (all flow rates are based on this userchosen value)
the fraction of branched carbon atoms found in the most commonly observed isomer class
the level of ringiness in the liquid fuel products (high, medium, or none), which determines
the percentage of compounds that are ringed (0.055, 0.0275, or none, respectively)
the distillation cut temperatures contained in cells A6-A11 of the “model control” worksheet
(this is an option for advanced users and would be unusual)
The model calculates the combined feed ratio (CFR) to characterize how much material is being
recycled to the hydrocracker. CFR is equal to the total feed divided by the unrecycled feed.
Thus, if 33% of the feed to the hydrocracker is recycled material, the CFR is 1.5. CFR is found
in cell M11 of the “model control” worksheet. In recycle mode, the amount of material that is
recycled to the hydrocracker depends on whether diesel or SPK is the heaviest product desired,
but it also depends on the fraction of bonds broken. If more bonds are broken, less material is
recycled. Thus, the user controls CFR by controlling the fraction of bonds broken (cell A25 in
the “model control” worksheet).
In no recycle mode, residual can be generated. This is material that is heavier than the heaviest
desired product. When the model is operated in no-recycle mode, CFR is 1 and the fraction of
bonds broken is adjusted by the user to control the amount of residual produced.
The model’s calculations rely on instructions contained in macros, so the “macro” feature of
Excel® must be enabled in order for the model to operate. In older versions of Excel®, an
“enable macros” dialogue box opens when a workbook that uses macros is launched. In later
versions, a warning bar appears under the toolbar above the worksheet cells and the user can
click on the bar to enable macros. Once the model is run, run conditions and model warnings, if
any, can be viewed in the upper right corner of the "results" worksheet, which also provides all
the flow rates and greenhouse gas emission estimates.
The flow rate calculations will not work if no SPK is produced in the hydrocracker, and there is a
limit to how high the fraction of bonds broken can be set. Compounds that don't break in the
hydrocracker are assumed to not be isomerized as well. Generally, the smaller a compound is
when it enters the hydrocracker, the less likely it is to be broken or cracked (in some cases, it is
100% unlikely). Distillation cuts and other properties were estimated based on group
contribution methods and other formulas whose results depend on isomerization. When the
recycle stream is combined with the wax stream, it is reborn as straight chain alkanes in the
model. While this is not strictly correct, it is unlikely to have much impact on the results because
these recycled compounds will be “isomerized” as they are cracked into product streams.
To run the model, the user must enter the desired conditions in the yellow highlighted cells in the
"model control" and "wax input" worksheets. Then, the user pushes the appropriate button on
the model control page (recycle or no recycle) to run the model. After the model runs, the user
may wish to adjust the final boiling point of the naphtha and SPK streams so that distillation
specs are met with the highest possible volume of SPK created for a given volume of wax input.
In recycle mode with SPK as the heaviest desired product, the model must be run again if the
51
final boiling point of the SPK fraction is changed. If the carbons and mass are not balancing (at
top right of "results" worksheet), push the button to run the model again.
The best way to illustrate use of the model and demonstrate use of the model’s features is to use
an example.
5.2a Modeling demonstration case study
We wish to upgrade the output wax of the FT reactor model described in the first section of this
chapter, which was operated to produce a wax similar to that described by Sie et al, 1991. The
upgrading section will be operated under recycle conditions producing diesel with a final boiling
point of 370°C as the heaviest product with a combined feed ratio (CFR) of 1.5. The wax will
not be pre-separated; in other words, there is no straight-run product. Our goal is to produce
50,000 bpd of liquid product (diesel, SPK, and naphtha). We think that the most commonly
branched group of isomers will have 0.11 of their carbon atoms branched and that no ringed
compounds will form in the hydrocracker. Furthermore, we believe that at least half of the C10
compounds will be found in the vapor phase in the hydrocracker.
Characterization of the Sie et al wax is given as an example wax in column T of the “wax input”
worksheet. This characterization was entered into the FT model as described in the previous
section. In the “wax input” worksheet of the hydrocracker model, we set the value of cell R1 to
“m” so the modeled parallel to the Sie wax is entered as the wax input in cells N10 to N257, as
shown in Figure 5-6.
Figure 5-6. Wax inputs for demonstration case study
52
Next, we go to the “model control” worksheet. We enter “d” in cell A18 because the heaviest
desired product is diesel. In cell A19, we put 370 because we want the final boiling point of the
diesel to be 370°C. In cells A20 and A21 we enter reasonable values for the final boiling point
of the SPK and naphtha cuts (265°C and 136°C); these values will have to be reassessed after the
model runs. We input a reasonable value for the barrels per day of SPK produced (20,000) in
cell A22; again, we will adjust this number after the model runs until the total liquid product is
50,000 bpd. We enter “y” in cell A24 because we want recycle operation, and 0.02 in the
fraction of bonds broken cell (A25) because that is a good starting point when recycle is desired.
We select 0.11, none, and 0 in cells A26 to A28 because that describes the isomerization we
expect. We enter 10 in cell A29 because at least half the C10s are expected to be found in the
vapor phase where they are protected from further cracking, and we don’t want preseparation so
we enter a 0 in cell A30. These values are shown in Figure 5-7.
Figure 5-7. Model inputs for demonstration case study
Then we push the recycle mode button and wait for the model to finish running. In recycle
mode, the model has to calculate the output of all 20 reactors, find the recycle stream, add it to
the wax stream, and recalculate all 20 reactors again. The model does this seven times when the
recycle button is clicked, which is usually enough times to converge on the wax+recycle input to
the reactor. If the sum of the values for the six mass and atomic balances in the “results”
worksheet is more than 0.05%, a message saying to run the model again will be displayed.
When the model finishes running, it stops on the “results” worksheet. In the top left corner of
this worksheet (cells B2:B9), the run conditions are summarized. The top right corner (cells
E2:E11) shows whether run integrity was compromised. If a message to run the model again is
53
displayed, go back to the “model control” worksheet and click to run the model in recycle mode
again.
CFR is calculated in cell M11 of the “model control” worksheet. As described at the beginning
of this section, we want a CFR of 1.5, and our run returned a value of 1.3, so we need to go back
to the “model control” worksheet and adjust the fraction of bonds broken downwards to meet
that condition. We try a few rounds of adjustments, ending up with a value for fraction of bonds
broken of 0.0137. Now the CFR is 1.5.
To finish, we need to adjust the final boiling point of the naphtha and SPK streams so that the
milspecs for distillation temperatures and net heating value are met. There is no range at which
both the estimated distillation temperatures and estimated density values simultaneously meet
military specifications: the estimated densities do not meet the density requirement unless the
initial boiling point of the of the SPK stream is above 205°C, and in order to meet the distillation
military specification, at least 10% of the stream must be recovered at 205°C. In order to most
closely meet the density requirement, the highest initial boiling point for SPK that satisfies the
military specifications is selected. For this run, that means setting the final boiling point of the
naphtha stream at 194°C (cell A21 on the “model results” worksheet). The largest volume of
SPK is created when the final boiling point of the SPK stream is set at 300°C (cell A20 on the
“model results” worksheet, and this value also results in the highest possible density estimate.
Total liquid output from the hydrocracker is calculated in cell M2 of the “model control”
worksheet. We adjust the flow rate of SPK (cell A22 in the “model control” worksheet) from the
hydrocracker to obtain the desired 50,000 bpd of total liquids. The flow rate of SPK from the
hydrocracker must be set to 18,103 bpd in order to get a total liquids flow rate of 50,000 bpd.
Figure 5-8 shows the final values in the “model control” worksheet for the demonstration case
study.
54
Figure 5-8. Final model input screen for demonstration case study
Let’s take a detailed look at the flow rate results and some of the physical property estimates,
which are summarized in the table below.
55
Table 5-3. Results of hydrocracker model
parameter
MASS FLOW RATES
wax from FT column
hydrogen consumption
fuel gas output (from
hydrocracker)
value
unit
50,199 bpd
9,515,641 scfd
1,452,079 scfd
output of naphtha
output of SPK
21,498 bpd
18,103 bpd
output of diesel
10,399 bpd
water flow rate
15,344 kg/d
CALCULATED/INPUT PROPERTIES
density of SPK from
hydrocracker (20
degrees C)
LHV of SPK
source
calculated from carbon balance to hydrocracker
and adjusted for fraction that goes straight to SPK
and straight to naphtha
based on stoichiometric hydrogen consumption
and feed rate to hydrocracker
calculated based on fraction of hydrocracker
outputs to fuel gas by mass
calculated based on fraction of hydrocracker
outputs to naphtha by mass (depends on userselected final boiling point of naphtha)
user input
calculated based on fraction of hydrocracker
outputs to diesel by mass (depends on userselected final boiling point of SPK and diesel)
calculated based on fraction of oxygenated
compounds in wax, MW of wax, MW of water,
flow rate of wax
from model using weighted average of densities
of individual compounds; densities estimated
using Hileman et al's hydrogen mass fraction
0.747 g/mL formula
from weighted average of group cont method
44.0 MJ/kg LHV for species in modeled SPK
For this wax under these conditions, a little more than 50,000 bpd of wax and nearly 10 million
scfd of hydrogen are required to make 50,000 bpd of liquid products.
5.2b Greenhouse gas footprint from cradle-to-gate for modeling demonstration case study
Table 5-4 shows the estimated cradle-to-gate greenhouse gas footprint for the FT production
facility for this modeled scenario. The cradle-to-gate greenhouse gas emission estimate for this
FT processing section/upgrading section scenario is –45.7 g CO2E/MJ LHV SPK.
56
Table 5-4. Cradle-to-gate greenhouse gas footprint for the demonstration case study
Life-Cycle Stage
coal mining
coal transportation
switchgrass production
credit for biogenic CO2 during switchgrass production
switchgrass direct and indirect land use
switchgrass biogenic direct and indirect land use
switchgrass transportation
hydrogen production
credit for naphtha
credit for diesel
burning hydrocracker fuel gas to generate power or heat
burning FT reactor fuel gas to generate power or heat, adjusted for wax
production
credit for excess power generation
net CO2E emissions
CO2E,
g/MJ LHV
SPK
14.6
2.5
2.8
-51.6
2.6
1.5
1.2
2.1
-16.7
-10.6
3.1
61.4
-58.6
-45.7
The model also calculates the amount of carbon dioxide that is sequestered. The net sequestered
carbon dioxide for the demonstration case study is 234 g CO2E/MJ LHV SPK, nearly all of
which is from the unreacted syngas stream exiting the FT reactor.
References
Allen, D. T.; Murphy, C.; Rosselot, K.S.; Watson, S.; Miller, J.; Ingham, J. and Corbett, W.
“Characterizing the Greenhouse Gas Footprints of Aviation Fuels from Fischer-Tropsch
Processing” Final Report to University of Dayton Research Institute from the University of
Texas, Agreement No. RSC09006; Account No. 2919890002; Prime Agreement No. F3361503-2-2347; February, 2010.
Shah, PP, GC Sturtevant, JH Gregor, MJ Humbach, FG Padrta, KZ Steigleder. Fischer-Tropsch
wax characterization and upgrading, final report. US Department of Energy. Available through
NTIS DE88014638. June 6, 1988.
Sie, ST, MMG Senden, HMH van Wechem. Conversion of natural gas to transportation fuels via
the Shell Middle Distillate Synthesis process (SMDS). Catalysis Today, 8 (3), 371-394 (1991).
57
Chapter 6: Ensemble Modeling of Variability
There are a number of variables that influence the greenhouse gas footprint of SPK production.
These variables include raw material feed as well as process conditions in the upgrading section
and the FT reactor. In this chapter the process and feedstock influences on the greenhouse gas
footprint are systematically considered. This information aids in the understanding of which
process conditions are important determiners of the cradle-to-gate greenhouse gas footprint of
SPK. It also sheds light on the directions of the trends in greenhouse gas emissions as process
conditions change.
Nine scenarios for producing FT wax were considered. The cases included in this study are
described in Table 6-1. For the cobalt catalyst cases, the molar H2:CO ratio fed to the FT reactor
was set at 2.1, the single pass conversion of carbon monoxide in the FT reactor was set at 70%,
and the carbon monoxide converted to carbon dioxide was set at 2%. For the iron catalyst case,
the molar H2:CO molar ratio of feed to the FT reactor was set at 1.105:1, the single pass
conversion of carbon monoxide in the FT reactor was set at 87%, and the carbon monoxide
converted to carbon dioxide was set at 36%. In all cases, the hydrogen removal was set at 95%,
the carbon dioxide removal was set at 96%, the mass fraction of compounds in the FT wax that
contain an olefinic bond was 7.4%, and the mass fraction of compounds in the FT wax that
contain an oxygen atom was 2.9%.
Table 6-1. Process selection scenarios for creating FT wax
Wax Case
Number
1
2
3
4
5
6
7
8
9
FT Reactor
Catalyst
cobalt
cobalt
cobalt
cobalt
cobalt
cobalt
cobalt
iron
iron
Feed to
Gasifier
31% biomass
16% biomass
16% biomass
16% biomass
16% biomass
16% biomass
0% biomass
16% biomass
16% biomass
FT Reactor Syngas
Recycled
50%
25%
50%
50%
50%
75%
50%
50%
50%
FT Reactor
α
0.85
0.85
0.8
0.85
0.9
0.85
0.85
0.725
0.85
Three of the FT wax cases (2, 4, and 6) show the effect of changes in the amount of unreacted
syngas that is recycled to the FT reactor. Except for the percentage of unreacted syngas recycled
to the FT reactor, the process selections for these three cases are identical (the settings reflect a
cobalt catalyst FT reactor with α set at 0.85 and 16% biomass fed to the gasifier). Similarly,
Cases 1, 4, and 7 examine the effect of changes in the amount of biomass fed to the gasifier, and
Cases 3, 4, and 5 show the effect of changes in the value for α, which determines chain growth in
the FT reactor. Cases 8 and 9 show the effect of using an iron-based catalyst instead of a cobaltbased catalyst in the FT reactor for two different FT reactor chain growth probabilities.
For each of the wax cases, three upgrading scenarios (A, B, and C in Table 6-2) were applied to
the wax to complete the cradle-to-gate production of SPK. In upgrading scenario A, diesel is the
58
heaviest liquid fuel produced and hydrocracker output heavier than diesel is recycled to the
hydrocracker. In upgrading scenario B, SPK is the heaviest liquid fuel produced and output
heavier than SPK is recycled to the hydrocracker. In upgrading scenario C, SPK is the heaviest
liquid fuel produced and the hydrocracker is operated so that there is no recycling of heavy ends.
For cases A, B, and C, these are the only process selections that change: the combined feed ratio
for cases A and B is 1.5, the vapor-liquid equilibrium carbon number is 11, the preseparation
temperature is 200°C, the fraction of branched carbons in the most commonly branched
compounds is 0.11, and none of the products contain rings.
For one of the nine wax cases, Case 4, additional upgrading scenarios (A1-A9 in Table 6-2) were
considered, for a total of 36 cases. These additional upgrading scenarios allow for a comparison
of results when the level of ringed compounds in the liquid fuel output is varied (scenarios A and
A5), when the combined feed ratio is varied (scenarios A, A1, and A2), when the extent of
isomerization in the hydrocracker is varied (scenarios A, A3, and A4), when the pressure and
temperature of the hydrocracker change so that the vapor-liquid equilibrium carbon number
changes (scenarios A, A6, and A7), and when the temperature at which the wax is preseparated
is varied (scenarios A, A8, and A9).
In each of the upgrading scenarios, the final boiling point of the SPK was set at 300°C and the
final boiling point of the naphtha stream was set at 186°C to meet military specifications for
distillation temperatures and gradients while producing an SPK product that has a greater
potential for meeting the military specification for density. Also, for each of the upgrading
scenarios where diesel was the heaviest product, the final boiling point of the diesel was set at
370°C. The fraction of bonds broken was adjusted to achieve the desired recycle rate, or
combined feed ratio. For upgrading case C, the fraction of bonds broken was adjusted until the
residual stream was less than 1.5 mass % of the SPK stream (this is the maximum amount of
residual allowed in the military specifications).
59
Table 6-2. Process selection scenarios for upgrading FT wax to liquid fuel products
Fraction of
Branched
Carbons in
Vapor% of
Liquid
Most
Upgrading
Products
Commonly
Section
Combined Equilibrium
That Are
Branched
Carbon
Preseparation
Case
Heaviest
Feed
Compounds
Ringed
Number
Temperature
Number
Product
Ratio
A
diesel
1.5
11
200°C
0.11
none
A1
diesel
2
11
200°C
0.11
none
A2
diesel
1.25
11
200°C
0.11
none
A3
diesel
1.5
11
200°C
0.22
none
A4
diesel
1.5
11
200°C
0
none
A5
diesel
1.5
11
200°C
0.11
medium*
A6
diesel
1.5
15
200°C
0.11
none
A7
diesel
1.5
8
200°C
0.11
none
A8
diesel
1.5
11
300°C
0.11
none
A9
diesel
1.5
11
none
0.11
none
B
SPK
1.5
11
200°C
0.11
none
C
SPK
1
11
200°C
0.11
none
*0.0275 of compounds are ringed (mass fraction) at this level of ringiness
6.1 Results
The carbon number compositions of the FT reactor material sent to upgrading in Cases 1 through
9 are shown in Figure 6-1. As α decreases, the FT product stream becomes comprised of smaller
molecules. Case 5, with an α of 0.9, has the heaviest wax, while the low chain growth
probability iron catalyst case, with an α of 0.725, has an FT product with little material that is
heavier than diesel.
60
18
16
mass percent
14
Cases 1, 2, 4, 6, 7, and
9
12
10
Case 3
8
6
Case 5
4
2
0
Case 8
0
20
40
60
80
carbon number
Figure 6-1. Carbon number composition of the study waxes
Figure 6-2 gives the greenhouse gas footprint for wax Cases 1 through 9, upgrading scenarios A,
B, and C. Figure 6-3 gives the greenhouse gas footprint for wax Case 4, upgrading scenarios AA9. In all cases, when the carbon dioxide streams from the WGS and FT reactors are
sequestered, the net cradle-to-gate CO2E emissions are negative. This is because the credit for
uptake of carbon dioxide during switchgrass growth (where applicable), the credit for electricity
generation, and to a lesser extent, the displacement credits for production of naphtha and diesel
(where applicable) are of greater magnitude than the greenhouse gas emissions associated with
burning the fuel gas, making the hydrogen, and acquiring and transporting the raw materials. In
other words, under these conditions there is a credit for production of SPK. The largest
variations are seen between upgrading scenarios A and B and upgrading scenario C, and between
the cobalt catalyst FT reactor and the high chain growth probability iron catalyst FT reactor
(Cases 1-7 and 9) and the low chain growth probability iron catalyst FT reactor (Case 8).
There were no cases where the estimated cradle-to-gate greenhouse gas footprint for jet fuel
produced using conventional petroleum refining (13 g CO2E/MJ LHV jet fuel, from Skone and
Gerdes, 2008) was exceeded (with sequestration of CO2 generated during syngas production and
in the FT reactor).
61
0
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
net CO2E emissions, g/MJ LHV SPK
100
‐100
‐200
‐300
‐400
‐500
‐600
case number
Figure 6-2. Net cradle-to-gate greenhouse gas footprint for Cases 1A-9C
Sequesterable carbon dioxide estimates are given in Figures 6-4 and 6-5. As with the net
greenhouse gas credit, the most variability is seen between upgrading scenarios A and B and
upgrading scenario C, and between the cobalt catalyst FT reactor and the high chain growth
probability iron catalyst FT reactor (Cases 1-7 and 9) and the low chain growth probability iron
catalyst FT reactor (Case 8).
net CO2E emissions, g/MJ LHV SPK
0
‐10
4A
4A1
4A2
4A3
4A4
4A5
4A6
4A7
4A8
4A9
‐20
‐30
‐40
‐50
‐60
‐70
case number
Figure 6-3. Net cradle-to-gate greenhouse gas footprint for Cases 4A to 4A9
62
1200
1000
CO2
sequestered
from water‐gas
shift reaction
g/MJ LHV SPK
800
600
400
CO2
sequestered
from unreacted
syngas in FT
reactor
200
0
1A 1B 1C 2A 2B 2C 3A 3B 3C 4A 4B 4C 5A 5B 5C 6A 6B 6C 7A 7B 7C 8A 8B 8C 9A 9B 9C
case number
Figure 6-4. Cradle-to-gate sequesterable carbon dioxide for Cases 1A-9C
300
g/MJ LHV SPK
250
200
CO2 sequestered from water‐gas shift reaction
150
100
CO2 sequestered from unreacted syngas in FT reactor
50
0
4A 4A1 4A2 4A3 4A4 4A5 4A6 4A7 4A8 4A9
case number
Figure 6-5. Cradle-to-gate sequesterable carbon dioxide for Cases 4A to 4A9
With sequestration, the net cradle-to-gate greenhouse gas credits for these 36 scenarios varied
from 10 g CO2E/MJ LHV SPK for cases 7A and 7B (cobalt catalyst FT reactor, 0% biomass,
50% syngas recycle in FT reactor, 0.85 FT reactor α; upgrading section run to produce diesel or
63
SPK as the heaviest product with a combined feed ratio of 1.5, a vapor-liquid equilibrium carbon
number of 11, a preseparation temperature of 200°C, 0.11 of carbons branched in the most
common branching scenario, and no rings produced during hydrocracking) to 550 g CO2E/MJ
LHV SPK for case 8C (iron catalyst FT reactor; upgrading section run to produce SPK as the
heaviest product with no recycle, a vapor-liquid equilibrium carbon number of 11, a
preseparation temperature of 200°C, 0.11 of carbons branched in the most common branching
scenario, and no rings produced during hydrocracking).
On a per unit of LHV per SPK basis, upgrading scenario B has nearly the same net cradle-to-gate
greenhouse gas credit of scenario A for each of the wax cases, and upgrading scenario C has 2 to
12 times the greenhouse gas credit of scenario A for each of the wax cases.
Figure 6-6 shows the greenhouse gas credit for each stage of the cradle-to-gate life stages for the
1A-9C scenarios and Figure 6-7 shows the greenhouse gas credit for each stage of the cradle-togate life stages for the 4A-4A9 scenarios. In all cases, more fuel gas (on an HHV basis) was
generated than in the base case. Some life cycle stages were relatively unimportant in all the
biomass cases: switchgrass transportation and production and direct and indirect land use (both
biogenic and otherwise). The most important single contributor of net greenhouse gas emissions
in all cases was either the biogenic carbon dioxide credit during production of switchgrass, the
credit for excess power generation, or combustion of fuel gas.
64
600
other (switchgrass land use,
hydrogen production)
400
CO2E credit for excess power
generation
200
CO2 emissions from burning fuel
gas to generate power or heat
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
g/MJ LHV SPK
0
CO2E credits for diesel
‐200
CO2E credits for naphtha
‐400
‐600
CO2E emissions from coal and
switchgrass transportation
‐800
CO2E emissions from switchgrass
production
CO2E credit for biogenic CO2
during switchgrass production
‐1000
‐1200
CO2E emissions from coal mining
case number Figure 6-6. Contribution of life cycle stages to greenhouse gas footprint for Cases 1A-9C
65
150
other CO2E credit for excess power generation
50
CO2 emissions from burning fuel gas to generate power or heat
g/MJ LHV SPK
100
CO2E credits for diesel
0
4A
4A1
4A2
4A3
4A4
4A5
4A6
4A7
‐50
4A8
4A9
CO2E credits for naphtha
CO2E emissions from coal and switchgrass transportation
‐100
CO2E emissions from switchgrass production
‐150
CO2E credit for biogenic CO2 during switchgrass production
CO2E emissions from coal mining
‐200
case number
Figure 6-7. Contribution of life cycle stages to greenhouse gas footprint for Cases 4A-4A9
66
Table 6-3 summarizes several of the estimated properties that are associated with military
specifications for each SPK case: the temperatures at which 10% and 90% of the SPK stream is
distilled, the density of the SPK, and the lower heating values of the SPK. It also gives the coal,
biomass, wax, and hydrogen required to make 50,000 bpd of liquid fuel products. Density,
which was estimated using a formula that depends on hydrogen mass fraction, varies from 0.740
to 0.747 g/mL for the 36 cases but never meets the military specification that requires that
density be greater than or equal to 0.750. Increasing FT reactor α, which creates a heavier wax
that has more opportunities for branching during hydrocracking, eliminating preseparation in
cases where branching occurs in the hydrocracker (which has the effect of generating a heavier
SPK stream because of increased branching and the effect it has on distillation boiling points)
and producing naphthenes in the hydrocracker increased the density of the SPK stream.
Operating without any preseparation at all also produced a denser SPK stream, which seems
anomalous. However, operating with no preseparation had the effect of increased branching,
forcing compounds that were in the SPK cut with preseparation into the naphtha cut with the
ultimate effect of creating a heavier SPK stream. Operating the upgrading section with no
recycle resulted in a less dense SPK product because it results in more production of lighter
weight compounds. It may be that for some conditions, if the initial boiling point of the SPK
stream had been set high enough, the estimated density would meet military specifications.
In all cases, the 10% recovery fraction temperature and the temperature gradient military
specifications were met, as was the military specification for net heating value.
67
Table 6-3. Summary of properties and raw material requirements for each case
10% 90% coal recovered recovered SPK SPK (degrees (degrees LHV density, required, Case Celsius) tonne/d Celsius) (MJ/kg) g/ml 1A 187 286 44.0 0.745
16,446
1B 187 286 44.0 0.745
16,533
1C 187 241 44.1 0.740
17,213
2A 187 286 44.0 0.745
19,737
2B 187 286 44.0 0.745
19,842
2C 187 241 44.1 0.740
20,657
3A 187 285 44.0 0.744
21,438
3B 187 285 44.0 0.744
21,515
3C 187 236 44.1 0.740
22,148
4A 187 286 44.0 0.745
18,979
4A1 187 286 44.0 0.745
18,955
4A2 187 285 44.0 0.745
19,017
4A3 187 288 44.0 0.746
18,964
4A4 187 294 44.0 0.744
18,992
4A5 187 286 44.0 0.747
19,008
4A6 187 286 44.0 0.745
18,954
4A7 187 286 44.0 0.745
18,985
4A8 187 294 44.0 0.746
18,949
4A9 195 294 44.0 0.747
18,979
4B 187 286 44.0 0.745
19,080
4C 187 241 44.1 0.740
19,863
5A 187 294 44.0 0.746
17,464
5B 189 286 44.0 0.746
17,586
5C 187 241 44.1 0.740
18,594
6A 187 286 44.0 0.745
18,213
6B 187 286 44.0 0.745
18,310
6C 187 241 44.1 0.740
19,062
7A 187 286 44.0 0.745
21,374
7B 187 286 44.0 0.745
21,488
7C 187 241 44.1 0.740
22,371
8A 187 272 44.0 0.743
26,832
8B 187 279 44.0 0.743
26,872
8C 187 236 44.1 0.740
27,302
9A 187 286 44.0 0.745
18,254
9B 187 286 44.0 0.745
18,352
9C 187 241 44.1 0.740
19,105
to make 50,000 bpd of liquid fuel products:
coal and switchgrass switchgrass required, wax hydrogen required, tonne required, consumed, tonne/d carbon/d bpd scfd 7,389
13,432 50,121
4,737,524
7,428
13,504 50,387
9,107,122
7,733
14,059 52,457 20,203,386
3,759
14,082 50,121
4,737,524
3,779
14,157 50,387
9,107,122
3,935
14,739 52,457 20,203,386
4,083
15,296 50,101
2,289,446
4,098
15,351 50,281
5,080,820
4,219
15,803 51,761 13,202,598
3,615
13,541 50,121
4,737,270
3,611
13,525 50,059
3,893,755
3,622
13,569 50,223
5,994,419
3,612
13,531 50,083
3,699,969
3,618
13,551 50,157
5,500,887
3,621
13,562 50,199
4,748,696
3,610
13,524 50,055
4,319,239
3,616
13,546 50,137
4,773,438
3,609
13,520 50,042
3,605,803
3,615
13,542 50,122
6,410,297
3,634
13,613 50,387
9,105,045
3,783
14,172 52,457 20,203,387
3,326
12,460 50,093
9,653,572
3,350
12,548 50,444 15,513,459
3,542
13,267 53,335 30,420,364
3,469
12,995 50,121
4,737,524
3,488
13,064 50,387
9,107,122
3,631
13,600 52,457 20,203,386
0
13,626 50,121
4,737,524
0
13,699 50,387
9,107,122
0
14,261 52,457 20,203,386
5,111
19,145 50,094
919,620
5,118
19,173 50,168
1,954,733
5,200
19,480 50,971
6,347,419
3,477
13,024 50,119
4,721,379
3,496
13,094 50,388
9,116,224
3,639
13,632 52,457 20,203,369
The most SPK per raw material carbon input was created during Case 5B (cobalt catalyst FT
reactor, 16% biomass, 50% syngas recycle in FT reactor, 0.9 FT reactor α; upgrading section run
to produce SPK as the heaviest product with a CFR of 1.5, a vapor-liquid equilibrium carbon
number of 11, a preseparation temperature of 200°C, 0.11 of carbons branched in the most
common branching scenario, and no rings produced during hydrocracking). The least SPK per
68
raw material carbon input was created during Case 8C (iron catalyst FT reactor; upgrading
section run to produce SPK as the heaviest product with no recycle, a vapor-liquid equilibrium
carbon number of 11, a preseparation temperature of 200°C, 0.11 of carbons branched in the
most common branching scenario, and no rings produced during hydrocracking).
Table 6-4 summarizes the fuel gas and liquid product flow rates for each case, and Table 6-5
shows estimates of the raw material feedstock costs and electricity and liquid product prices for
each of the 36 runs. To generate the values in Table 6-5, the wholesale price of electricity,
naphtha, jet fuel, and diesel were estimated to be $50/MWh, $3.25/gallon, $3/gallon, and
$3.50/gallon, respectively. The delivered cost of coal was assumed to be $40/short ton and the
delivered cost of switchgrass was assumed to be $95/short ton (dry basis). The values for
product prices less feedstock costs vary from $2.1 billion/yr (for Cases 1A-B, 5A-B, and 9A-B)
to $2.5 billion/yr (Case 8C).
69
Table 6-4. Flow rates of fuel gas, naphtha, SPK, and diesel for all cases
case 1A 1B 1C 2A 2B 2C 3A 3B 3C 4A 4A1 4A2 4A3 4A4 4A5 4A6 4A7 4A8 4A9 4B 4C 5A 5B 5C 6A 6B 6C 7A 7B 7C 8A 8B 8C 9A 9B 9C million scfd
bpd fuel gas from FT reactor fuel gas from hydrocracker naphtha
SPK diesel
159 0.7
22,014 20,729 7,257
160 2.0
28,111 21,889 0
166 7.1
43,210 6,790 0
217 0.7
22,014 20,729 7,257
218 2.0
28,111 21,889 0
227 7.1
43,210 6,790 0
202 0.3
26,611 18,940 4,448
202 1.1
30,668 19,332 0
208 4.8
42,779 7,221 0
160 0.7
22,013 20,730 7,257
160 0.5
20,740 21,117 8,143
160 1.1
23,925 19,996 6,078
160 0.5
23,079 19,393 7,528
160 0.9
22,287 19,560 8,152
160 0.7
22,037 20,667 7,297
160 0.5
21,284 21,465 7,250
160 0.8
22,030 20,694 7,277
160 0.6
21,233 22,683 6,084
160 0.6
24,135 17,878 7,987
161 2.0
28,106 21,894 0
168 7.1
43,210 6,790 0
134 1.6
18,932 21,029 10,038
135 3.2
26,764 23,236 0
143 10.5
44,595 5,405 0
102 0.7
22,014 20,729 7,257
103 2.0
28,111 21,889 0
107 7.1
43,210 6,790 0
161 0.7
22,014 20,729 7,257
162 2.0
28,111 21,889 0
168 7.1
43,210 6,790 0
233 0.0
34,117 14,286 1,597
234 0.4
35,696 14,304 0
238 2.3
42,994 7,006 0
110 0.7
21,989 20,739 7,272
110 2.0
28,126 21,874 0
115 7.1
43,209 6,790 0
70
Table 6-5. Delivered cost of raw materials and wholesale value of products, million $/yr
case 1A 1B 1C 2A 2B 2C 3A 3B 3C 4A 4A1 4A2 4A3 4A4 4A5 4A6 4A7 4A8 4A9 4B 4C 5A 5B 5C 6A 6B 6C 7A 7B 7C 8A 8B 8C 9A 9B 9C Estimated cost of deliverd coal and switchgrass 513 516 537 444 446 465 482 484 498 427 427 428 427 427 428 427 427 426 427 429 447 393 396 418 410 412 429 344 346 360 604 605 614 411 413 430 approximate value of electricity and liquid fuels produced
2,629
2,615
2,753
2,707
2,694
2,835
2,754
2,747
2,855
2,629
2,628
2,634
2,632
2,640
2,630
2,624
2,630
2,615 2,642
2,615
2,754
2,571
2,547
2,723
2,551
2,537
2,671
2,629
2,615
2,753
3,018
3,017
3,082 2,555
2,541
2,676
71
difference
2,116
2,099
2,216
2,263
2,247
2,370
2,271
2,263
2,357
2,202
2,201
2,206
2,205
2,213
2,202
2,198
2,203
2,188 2,215
2,186
2,307
2,178
2,152
2,304
2,141
2,125
2,242
2,285
2,269
2,393
2,415
2,413
2,467 2,144
2,128
2,246
6.2 Process Selections That Influence the Estimated Cradle-to-Gate Greenhouse Gas
Footprint of SPK
Outside of Case 4A and upgrading scenarios B and C, the remaining 17 wax and upgrading
scenario combinations can be viewed as a perturbation of Case 4A (all selections match Case 4A
except one wax production process selection or one upgrading process selection). For the range
of process selection choices considered in this study, the difference between the greenhouse gas
credits of Case 4A and the 16 cases gives some insight into the potential impact of altering that
process condition. Table 6-6 shows the difference between the net cradle-to-gate greenhouse gas
credit on a per unit LHV of SPK basis for these cases and Case 4A as a factor. The process
options that influenced greenhouse gas credits the most in this study were the catalyst chosen for
the FT reactor (the iron catalyst had a larger credit than cobalt) and the amount of biomass fed to
the gasifier (more biomass led to a larger credit). Also important were the FT reactor  (with a
decrease in  leading to a larger credit) and the preseparation temperature in the upgrading
section (with more preseparation resulting in a smaller credit).
Table 6-6. Variability in net greenhouse gas credits due to process selections
case comparison to case 4A (factor)
8A ‐‐ use iron catalyst FT reactor, decrease α in FT reactor
4.7 1A ‐‐ increase biomass
1.9 3A ‐‐ decrease α in FT reactor
1.8 4A9 ‐‐ decrease the preseparation temperature
1.2 2A ‐‐ decrease syngas recycle to FT reactor
1.1 4A4 ‐‐ decrease branching in hydrocracker
1.1 4A3 ‐‐ increase branching in hydrocracker
1.1 4A2 ‐‐ decrease recycle to hydrocracker
1.1 4A7 ‐‐ decrease the vapor‐liquid equilibrium carbon number
1.0 4A5 ‐‐ increase ringiness in hydrocracking
1.0 4A ‐‐ comparison case
1.0 4A1 ‐ increase recycle to hydrocracker
1.0 4A6 ‐‐ increase the vapor‐liquid equilibrium carbon number
0.9 6A ‐‐ increase syngas recycle to FT reactor
0.9 4A8 ‐‐ increase the preseparation temperature
0.9 9A ‐‐ use iron catalyst, α in FT reactor same as comparison case
0.9 0.7 5A ‐‐ increase FT reactor 
7A ‐‐ decrease biomass
0.2 Variations in preseparation temperature had the largest effect of alterations amongst the 4A
cases, with no preseparation having a larger greenhouse gas credit. Changing the combined feed
ratio to the hydrocracker from 1.5 to 1.25, increasing the vapor-liquid equilibrium carbon
number in the hydrocracker from 11 to 15, and doubling and eliminating branchiness in the
hydrocracker output had a moderate impact on net cradle-to-gate greenhouse gas credit. Little to
no difference was observed in the overall cradle-to-gate greenhouse gas credits when the vaporliquid equilibrium carbon number was lowered from 11 to 8, when hydrocracker output
72
contained naphthenes, or when the combined feed ratio was changed from 1.5 to 2 in the
upgrading section.
6.2a Sequestration vs. Emission of Carbon Dioxide Streams
Treating the carbon dioxide streams from the WGS reaction and the FT reactor as sequestered
(without a greenhouse gas penalty) rather than emitted to the atmosphere is a process selection
that has a profound impact on the results of this analysis, both in terms of the greenhouse gas
footprint and in terms of the most advantageous process selections from a greenhouse gas
footprint perspective. The cases with the largest cradle-to-gate greenhouse gas credits also have
the largest sequestered carbon dioxide streams. From a greenhouse gas perspective, when
sequestration is applied, the cases where recycle of heavy ends in the upgrading section is not
employed (the C cases of Figure 6-2) are the most attractive. Figure 6-8 shows that when the
carbon dioxide streams from the WGS section and the FT reactor are treated as if they are
emitted instead of sequestered, the C cases are instead the least attractive from a greenhouse gas
perspective. Of the cases where recycling of heavy ends occurs in the upgrading section (the A
and B cases), the low chain growth probability iron catalyst FT reactor case (8A and 8B)
becomes the least attractive case, and the 31% biomass case (Case 1B) becomes the most
attractive.
Figure 6-9 shows the net cradle-to-gate greenhouse gas emission values for Cases 4A to 4A9.
Again, less variation is seen amongst these process selections than between the process
selections of Cases 1A to 9C. The most advantageous case from a greenhouse gas footprint
perspective when carbon dioxide was sequestered was Case 4A9 (no preseparation of light wax
before sending wax through the hydrocracker); when carbon dioxide is emitted instead, it
becomes the least advantageous case. The least advantageous case from a greenhouse gas
perspective when carbon dioxide streams were sequestered was Case 4A8 (setting the
preseparation temperature for the wax stream higher so that more material bypasses the
hydrocracker). This case becomes the most advantageous case from a greenhouse gas
perspective when carbon dioxide streams are emitted instead of sequestered.
None of the cases have an estimated cradle-to-gate greenhouse gas footprint for SPK that is
lower than the footprint for producing jet fuel using conventional refining techniques when the
carbon dioxide streams from WGS and the FT reactor are emitted instead of sequestered.
73
(WGS and FT reactor carbon dioxide streams emitted instead of sequestered)
600
500
400
300
200
100
0
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
net CO2E emissions, g/MJ LHV SPK
700
case number
Figure 6-8. Net cradle-to-gate greenhouse gas emissions for cases 1A to 9C when carbon
dioxide generated during water-gas shift and in the Fischer-Tropsch reactor are emitted
instead of sequestered
net CO2E emissions, g/MJ LHV SPK
250
(WGS and FT reactor carbon dioxide streams emitted instead of sequestered)
200
150
100
50
0
4A
4A1
4A2
4A3
4A4
4A5
4A6
4A7
4A8
4A9
case number
Figure 6-9. Net cradle-to-gate greenhouse gas emissions for cases 4A to 4A9 when carbon
dioxide generated during water-gas shift and in the Fischer-Tropsch reactor are emitted
instead of sequestered
74
6.3 Life Cycle Assessment Selections That Influence the Estimated Cradle-to-Gate
Greenhouse Gas Footprint of SPK
6.3a Allocation Alternatives
In the case of SPK, the allocation of greenhouse gas emissions to co-product streams (diesel,
naphtha, and fuel gas/electricity) play an important role in the estimated cradle-to-gate
greenhouse gas footprint. Because the credit for electricity generated using excess fuel gas has
such a large influence on results, three alternatives for addressing the allocation of impacts to this
stream were explored. These alternatives along with the original allocation of Figures 6-2, 6-3,
6-6, and 6-7 are described in Table 6-7.
Figure 6-10 shows the net estimated CO2E emissions for Cases 1A-9C for the four allocation
alternatives, and Figure 6-11 shows how the contributions from the various life-cycle stages
compare for the four allocation alternatives for Cases 1A-9C. The largest difference is seen
between the original allocation alternative and applying a displacement credit for production of
fuel gas. The only scenario (assuming sequestration of CO2 from syngas production and from
the FT reactor) for which the cradle-to-gate greenhouse gas footprint for jet fuel produced using
conventional petroleum refining (13 g CO2E/MJ LHV jet fuel, from Skone and Gerdes, 2008)
was exceeded is for Cases 7A and 7B for the allocation alternatives that apply Tarka’s reported
flow rates instead of modeled flow rates and that use an electricity generation efficiency of 40%
instead of 83%, and for Case 7C for the allocation alternative that uses an electricity generation
efficiency of 40% instead of 83%.
It is of interest to note how these allocation alternatives influence the impact of process selection
on the cradle-to-gate greenhouse gas footprint of SPK. For the allocation scenario that applies a
40% electricity generation efficiency instead of 83%, upgrading scenario B has 0.4 to 1 times the
net greenhouse gas credit of upgrading scenario A for all of the cases, and upgrading scenario C
has 2 to 10 times the net greenhouse gas credit of upgrading scenario A for all of the cases. For
the allocation scenario that applies Tarka’s flow rates instead of modeled flow rates, upgrading
scenario B has 0.9 to 1.8 times the net greenhouse gas credit of upgrading scenario A for all of
the cases, and upgrading scenario C varies from 160 times the greenhouse gas credit of
upgrading scenario A to a case where there are greenhouse gas emissions instead of a credit. For
the allocation scenario that relies on displacement for fuel gas instead of displacement for
electricity generated from fuel gas, upgrading scenario B has 0.8 to 1.1 times the net greenhouse
gas credit (or, for Case 7, emissions) of upgrading scenario A for all the cases, and upgrading
scenario C has 0.6 to 6 times the greenhouse gas credit of scenario A for each of the wax cases.
This compares to the original allocation scheme, where upgrading scenario B has nearly the
same cradle-to-gate greenhouse gas credit of scenario A for each of the wax cases, and upgrading
scenario C has 2 to 12 times the greenhouse gas credit of scenario A for each of the wax cases.
75
Table 6-7. Alternatives for allocating greenhouse gas footprint emissions to fuel gas
Alternative Name
Original
Based on 40% instead
of 83% electrical
generation efficiency
Based on energy
content of Tarka’s
reported flow rates
Applying a credit for
production of fuel gas
instead of production of
electricity
Description
A credit of 0.763 kg CO2E/kWh was applied to electricity generated from
burning excess fuel gas. The amount of energy in the excess fuel gas available
for power generation was estimated by comparing to the energy of the fuel gas
streams from a scenario that modeled Tarka’s Case 7 as closely as possible,
using the assumption that the modeled fuel gas generated in Tarka’s Case 7
was just enough to provide for the facility’s heat and electricity needs and that
varying process conditions would not change these energy requirements on a
per unit of energy in wax basis. The efficiency of electricity generation was
assumed to be 0.83 and the higher heating value of the fuel gases were used in
the calculations.
In the original case, it was assumed that any incremental excess fuel gas would
be used to superheat steam, and that the efficiency of converting this fuel gas to
electricity was high, at 83%. This allocation applies an electrical generation
efficiency of 40% to the excess fuel gas instead. Compared to the original
allocation alternative, the credit for electricity generation is roughly halved in
this allocation alternative.
In order to calculate the amount of excess fuel gas in the original scheme,
Tarka’s process was modeled as closely as possible and the modeled energy
content of the fuel gas that was generated was compared to the modeled energy
content for the 33 process selection cases. In this alternative, Tarka’s data for
stream flow rates for Case 7 are used directly to compare to the modeled
energy content of the fuel gas for the 33 process selection cases (the efficiency
of electricity generation was assumed to be 0.83 and the higher heating value
of the fuel gases were used in the calculations for this allocation alternative).
While the total material flow rates of the fuel gas streams for the modeled base
case and the Tarka-reported values are very similar, the component breakdown
of the streams is quite different, and the total energy content of the Tarkareported fuel gas is 25×106 MJ/d, compared to a total energy content of the
modeled fuel gas of 12×106 MJ/d. The energy content of Tarka’s reported wax
and the modeled wax are similar. This results in doubling the amount of fuel
gas energy content needed to provide the system’s process heat and electricity
needs. Nevertheless,, in every case, the process selections for the 33 cases
resulted in more fuel gas energy content than Tarka’s Case 7 (on a per unit of
wax energy content basis). Compared to the original allocation alternative, the
credit for electricity generation is reduced from 14% (for Case 8C) to 80% (for
Case 6A), but the greenhouse gas emissions from fuel gas combustion remain
the same.
In this alternative, a credit is given for production of excess fuel gas that is
based on production of fuel gas at refineries nationwide (using energy content
as a basis and averaging the greenhouse gas footprint of cradle-to-gate
production of LPG and still gas in Skone and Gerdes, 2008). Thus, the fuel gas
impacts are allocated much the same way as the naphtha and diesel co-product
streams. There is no electricity generated from the excess fuel gas and not all
of the fuel gas is combusted. In this allocation alternative, the fuel gas
displacement credit is smaller than in the original allocation alternative, but the
greenhouse gas emissions from fuel gas combustion are also reduced.
76
Table 6-8 repeats the comparisons of Table 6-6, but with each of the allocation alternatives so
that the effect of allocation on the relative greenhouse gas footprint for the process selections can
be seen. The order of the variations from Case 4A is the same or nearly the same for all of the
allocation alternatives, but the degree of variation differs. Allocating by Tarka’s flow rate values
instead of modeled values had the most variation amongst the cases. With this allocation
alternative, Case 8A had 11 times the credit as Case 4A, and Case 7A has estimated net
emissions instead of the net credit that Case 4A predicted. In the allocation alternative using
displacement allocations for fuel gas instead of displacement allocations for electricity generated
from fuel gas, there is the least variation between Case 4A and the other cases. Increasing the
unreacted syngas recycled to the FT reactor and using an iron catalyst reactor with the same FT
reactor α as the comparison case resulted in a higher greenhouse gas credit than decreasing it did
for the allocation alternative that assigned a 40% electricity generation efficiency, in contrast to
the other three allocation alternatives.
References
Skone, TJ, K Gerdes. Development of baseline data and analysis of life cycle greenhouse gas
emissions of petroleum-based fuels. US Department of Energy, National Energy Technology
Laboratory, Office of Systems, Analysis and Planning. November 26, 2008.
77
100
‐100
‐200
‐300
‐400
‐500
‐200
‐300
‐400
‐500
‐600
case number (original fuel gas allocations)
100
case number (allocation based on Tarka's HHV)
net CO2E emissions, g/MJ LHV SPK
100
0
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
net CO2E emissions, g/MJ LHV SPK
‐100
‐100
‐200
‐300
‐400
‐500
‐600
0
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
‐600
0
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
net CO2E emissions, g/MJ LHV SPK
0
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
net CO2E emissions, g/MJ LHV SPK
100
‐100
‐200
‐300
‐400
‐500
‐600
case number (allocation based on 40% efficiency)
case number (allocation based on displacement)
Figure 6-10. Net cradle-to-gate greenhouse gas emissions for four fuel gas allocation alternatives for Cases 1A to 9C. Clockwise from top
left: the original allocation alternative repeated from Figure 6-2, an alternative based on energy content of Tarka’s reported flow rates,
an alternative based on applying a credit for production of fuel gas instead of production of electricity, and an alternative based on 40%
instead of 83% electrical generation efficiency
78
200
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
‐200
CO2E credits for naphtha
‐400
CO2E emissions from coal and
switchgrass transportation
CO2E emissions from switchgrass
production
CO2E credit for biogenic CO2 during
switchgrass production
CO2E emissions from coal mining
‐600
‐800
‐1000
‐1200
0
‐800
‐1000
CO2E credits for naphtha
‐400
CO2E emissions from coal and
switchgrass transportation
CO2E emissions from switchgrass
production
CO2E credit for biogenic CO2
during switchgrass production
CO2E emissions from coal mining
‐800
‐1000
‐1200
other (switchgrass land use,
hydrogen production)
CO2E credit for excess fuel gas,
g/MJ LHV
CO2 emissions from burning fuel
gas to generate power or heat
CO2E credits for diesel
400
200
0
g/MJ LHV SPK
‐200
case number (allocation based on Tarka's HHV)
600
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
0
CO2E emissions from coal and
switchgrass transportation
CO2E emissions from switchgrass
production
CO2E credit for biogenic CO2
during switchgrass production
CO2E emissions from coal mining
‐600
other (switchgrass land use,
hydrogen production)
CO2E credit for excess power
generation
CO2 emissions from burning fuel
gas to generate power or heat
CO2E credits for diesel
200
CO2E credits for naphtha
‐400
‐1200
400
‐600
‐200
case number (original fuel gas allocation)
600
g/MJ LHV SPK
200
‐200
CO2E credits for naphtha
‐400
CO2E emissions from coal and
switchgrass transportation
CO2E emissions from switchgrass
production
CO2E credit for biogenic CO2
during switchgrass production
CO2E emissions from coal mining
‐600
‐800
‐1000
‐1200
case number (allocation based on 40% efficiency)
other (switchgrass land use,
hydrogen production)
CO2E credit for excess power
generation
CO2 emissions from burning fuel
gas to generate power or heat
CO2E credits for diesel
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
g/MJ LHV SPK
0
400
1A
1B
1C
2A
2B
2C
3A
3B
3C
4A
4B
4C
5A
5B
5C
6A
6B
6C
7A
7B
7C
8A
8B
8C
9A
9B
9C
400
600
other (switchgrass land use,
hydrogen production)
CO2E credit for excess power
generation
CO2 emissions from burning fuel gas
to generate power or heat
CO2E credits for diesel
g/MJ LHV SPK
600
case number (allocation using fuel gas instead of electricity displacement)
Figure 6-11. Contribution of life cycle stages to greenhouse gas footprint for four fuel gas allocation alternatives for Cases 1A-9C.
Clockwise from top left: the original allocation alternative repeated from Figure 6-2, an alternative based on energy content of
Tarka’s reported flow rates based on fuel gas LHV instead of HHV, an alternative based on applying a credit for production of fuel
gas instead of production of electricity, and an alternative based on 40% instead of 83% electrical generation efficiency
79
Table 6-8. Factors by which net cradle-to-gate greenhouse gas emissions for SPK
production for Cases 4A1-4A9 and 1A-9A differed from case 4A for four fuel gas
allocation alternatives
case
8A ‐‐ use iron catalyst FT reactor, decrease α in FT reactor
1A ‐‐ increase biomass
3A ‐‐ decrease alpha in FT reactor
4A9 ‐‐ decrease the preseparation temperature
2A ‐‐ decrease syngas recycle to FT reactor
4A4 ‐‐ decrease branching in hydrocracker
4A3 ‐‐ increase branching in hydrocracker
4A2 ‐‐ decrease recycle to hydrocracker
4A7 ‐‐ decrease the vapor‐
liquid equilibrium carbon number
4A5 ‐‐ increase ringiness in hydrocracking
4A ‐‐ comparison case
4A1 ‐ increase recycle to hydrocracker
4A6 ‐‐ increase the vapor‐
liquid equilibrium carbon number
6A ‐‐ increase syngas recycle to FT reactor
4A8 ‐‐ increase the preseparation temperature
9A ‐‐ use iron catalyst, α in FT reactor same as comparison case 5A ‐‐ increase FT reactor alpha
7A ‐‐ decrease biomass
original
allocation alternative
40% instead of 83% Tarka's flow rates electricity generation instead of modeled efficiency
flow rates displacement allocation for fuel gas
4.7
1.9
5.6
4.1
10.9
3.4
3.0
2.4
1.8
1.6
3.1
1.5
1.2
1.3
1.2
1.2
1.1
0.3
1.3
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
0.9
1.0
0.9
0.9
0.9
0.9
0.9
1.7
0.7
1.0
0.9
0.8
0.8
0.9
0.9 1.5 0.6 0.9 0.7
0.2
0.7
*
0.0
*
0.8
*
*These values were negative (a greenhouse gas credit) for case 4A and positive
(greenhouse gas emissions) for case 7A.
80
81
Appendix A. The base case for electricity generation
A life-cycle assessment of the GWP of diesel produced from CBTL using an iron-catalyst
FT column is provided in “Affordable, Low-Carbon Diesel Fuel from Domestic Coal and
Biomass” (Tarka, 2009). The values from this report provide two things of value to this
study: a base case estimate of fuel gas required to produce the required electricity and
meet process heat demands, and an opportunity to compare greenhouse gas footprint
estimates with those of another researcher. The process simulations for this study were
performed in commercial software (Aspen).
The relevant conditions for Case 7 from Tarka (2009) are:
 30% switchgrass after initial drying of switchgrass at the facility, corresponding
to 31% switchgrass as-received
 no autothermal reforming of the fuel gas stream from the upgrading section
 production of 20,575 bpd of diesel and 9,425 bpd of naphtha
 84% (by mass) of fuel gas stream produced in FT reactor recycled to the FT
reactor
The energy content of the fuel gas generated during hydrocracking and in the FT reactor
in the base case of the effort this report describes is presumed to satisfy the facility’s
electrical power and process heat needs. As gasifier feed, FT reactor, and hydrocracker
conditions are varied, it is assumed that the overall facility electrical power and process
heat needs are not significantly altered, and any fuel gas generated in excess of the base
case amount will result in a greenhouse gas displacement credit for the excess electricity
generated by the additional fuel gas. Conversely, if process conditions are changed so
that less fuel gas is generated than in the base case, greenhouse gas emissions associated
with purchasing the electricity that must be exported are included in the overall facility
footprint.
In order to develop the base case, the FT reactor model of this study was operated as
similarly as possible as the reactor of Tarka’s Case 7, with alpha adjusted so that it
produced a wax as similar as possible to the wax produced in Tarka Case 7 (2009). That
wax was used as input to the hydrocracker model of this study, which was operated to
produce a product slate as similar as possible to the liquid fuel product slate of Tarka case
7 (2009).
Tarka (2009) does not include the stream flow rates; these were obtained in a personal
communication from Tarka (2010).
Tarka’s modeled FT reactor had four output streams: a fuel gas stream, an oxygenates
stream, a straight-run cut, and a wax cut. For Tarka’s case 7, the oxygenates stream is
179,500 lb/hr of water and 2,471 lb/hr alcohols. The straight run FT output, which is
called straight run because it is already in the liquid fuel product range and does not pass
through the hydrocracker, is 37,170 lb/hr. The wax cut is 291,000 lb/hr.
82
Tarka did not provide detailed composition information about the straight run cut or the
wax cut. The flow rates of these streams are summarized in Table A-1.
Table A-1. Flow rates of FT reactor liquid output for Tarka Case 7 (Tarka, 2010)
Description
total flow
1-PEN-01
N-PEN-01
1-HEX-01
N-HEX-01
C7-C11
C12-C18
C19-C24
C25+
AVE MW OF
STREAM
AVE CARBON # OF
STREAM
wax sent to
hydrocracker
lb/hr
lbmol/hr
291028.6
613.634
0
0
0
0
0
0
0
0
0
0
0
0
9189.865
40.603
281838.7
573.031
straight run product from FT reactor
lb/hr
lbmol/hr Naphtha Diesel
37172.1
287.45
2922.159
41.665
X
324.684
4.5
X
3010.013
35.765
X
334.446
3.881
X
15691.76 135.855
X
14889.04
65.784
X
0
0
0
0
474
129
33.7
9.1
Table A-1 also shows which of the straight run streams were included in the naphtha and
diesel liquid fuel output.
Note that 90% of the pentane and hexane flows are olefinic. This is outside the range of
what the authors have encountered in literature for iron-catalyst FT reactors (for example,
Shah et al, 1988). A value of 7.4% was used in the FT model of this study.
Also, the average molecular weight of the C19-C24 stream is 226 g/mol, which
corresponds to an average carbon number of 16, a physical impossibility. In finding the
best fit to the liquid output from these values, the molar flow rates were used. The C12C18 stream was binned with the C19-C24 stream, an adjustment that was made so that an
average molecular weight of 226 g/mol for the C19-C24 stream is possible. These rules
were used for finding the best fit to Tarka’s molar flow rates because his flow rates were
created during an Aspen simulation that obeyed conservation of mass and atomic
balances.
The FT model of this study can recycle up to 75% of the unreacted syngas to the FT
reactor. In Tarka’s Case 7, 84% of the unreacted syngas was recycled to the FT reactor.
This value was set at 75% for the model of this study to match Tarka’s conditions as
closely as possible.
The FT model of this study employs an autothermal reactor to partially combust the light
ends (mostly C3-C5, with small amounts of C6-C8) output of the reactor, creating syngas
that is recycled to the FT column. Tarka’s modeled FT reactor did not employ this
83
technology. Instead, C3 and C4 is included in Tarka’s fuel gas stream and C5 is included
in the straight-run products. The FT model was modified so that instead of going to the
autothermal reactor, C3 and C4 was included in the unreacted syngas fuel gas stream.
The best fit of Tarka’s FT reactor liquid output to the liquid output of this study by mol
fraction was achieved at the highest possible value for α, an α value of 0.965. At α values
higher than this, the wax stream contains a significant amount of material in the C250+
range, and this is outside the range of the wax for both the FT model and the
hydrocracker model of this study. Run conditions were an H2:CO ratio of 1.105:1, % of
oxygenated compounds by mass 0.75%, FT reactor single pass CO conversion 87%, and
% of converted CO converted to CO2 36%. The liquid outputs from Tarka’s FT reactor
and the FT model of this study are shown in Figure A-1.
0.8
0.7
Mol Fraction
0.6
0.5
0.4
Tarka Case 7
0.3
FT reactor model of this study
0.2
0.1
0
C25+
C12‐C24
C6‐C11
Stream
Figure A-1. Base case wax output from this study’s FT model compared to wax
from Tarka’s Case 7 (2010)
The output of the FT model in this study does not separate straight run FT products from
the wax FT products. Instead, the wax and liquid product streams from the FT reactor are
combined and the hydrocracker model of this study has a preseparation feature where FT
output that is in the liquid fuel range can be routed around the hydrocracker and straight
to separations.
The liquid output carbon number distribution from the FT model described in this study
was fed into the hydrocracker model of this study and conditions were adjusted such that
the outputs matched the molar flow rates of Tarka’s modeled hydrocracker outputs
combined with his straight run product outputs as closely as possible. Tarka’s straight
run flow rates are given in Table A-1; his hydrocracker outputs for Case 7 are given in
Table A-2.
84
Table A-2. Flow rates of hydrocracker liquid output for Tarka Case 7 (Tarka,
2010)
Hydrocracker Output
Description
lb/hr
lbmol/hr Naphtha Diesel Fuel Gas
Total flow
295,035
2,010
CO2
2.98E-01
0.007
X
N2
0.245
0.009
X
CH4
1982.553 123.579
X
C2H6
2753.545
91.572
X
C3H8
4038.533
91.584
X
ISOBU-01
2661.76
45.795
X
N-BUT-01
2661.76
45.795
X
N-PEN-01
6642.751
92.068
X
N-HEX-01
7934.396
92.071
X
C7-C11
59046.672 511.211
X
C12-C18
156670.133 692.208
X
C19-C24
50642.738 223.752
X
AVE MW OF STREAM
147
AVE CARBON # OF STREAM
10.3
Table A-2 also shows which streams were included in the fuel gas stream and in the
naphtha liquid fuel output and the diesel liquid fuel output from the hydrocracker. Note
that branched butane is created but no branched pentanes or hexanes. Based on these
flow rates, the average molecular weight of the C12-C18 and C19-C24 streams are
identical (226 g/mol), which corresponds to an average carbon number of 16, a physical
impossibility in the case of C19-C24. The C12-C18 and C19-C24 flow rates were
combined when finding the best fit to the hydrocracker model of the current study, and
the best fit to the molar flow rates was found.
Hydrocracker model conditions were chosen to mirror Tarka Case 7 as closely as
possible. The process Tarka modeled produced diesel and naphtha as the only liquid
fuels produced, and the greenhouse gas footprint is reported in terms of LHV diesel. The
model of this study requires production of SPK and produces greenhouse gas estimates in
terms of LHV SPK. In order to produce the desired results, the model of this study was
run with an SPK output tailored to match Tarka’s diesel output. SPK was selected as the
heaviest desired product, and the naphtha stream was tailored to match the naphtha
stream reported by Tarka. To accomplish this, the final boiling point of the SPK stream
was set at 383°C (to include n-C24 based on group contribution boiling point values) and
the final boiling point of the naphtha stream was set at 188°C (to include n-C11 based on
group contribution boiling point values). Tarka (2009) does not specify whether the
hydrocracker of his study was operated in recycle mode, but recycle of heavy ends is
standard practice and the hydrocracker model of this study was operated in recycle mode.
Conditions that produced no branched or ringed compounds were chosen in order to
facilitate reporting of results by carbon number, the way Tarka reports them. Because
Tarka’s straight run product from the FT reactor included material up to C18, the cutoff
85
temperature for pre-separated wax in the hydrocracker model was set at 310°C because
this ensures that C18 and lower compounds are routed around the hydrocracker to
separation.
Once all these values were set, the fraction of bonds broken and the largest carbon
number found in the vapor phase were varied until the best fit to Tarka’s Case 7 molar
flow rates was found. This occurred at a vapor phase carbon number of 8 and a fraction
of bonds broken equal to 0.039. This resulted in a combined-feed ratio of 1.7, where 42
mass % of the hydrocracker output was recycled to the hydrocracker. The liquid fuel
products from Tarka’s Case 7 and the hydrocracker model of this study are compared in
Figure A-2.
0.5
0.45
0.4
Mol fraction
0.35
0.3
Tarka Case 7
0.25
0.2
hydrocracker model of this study
0.15
0.1
0.05
0
1
2
3
4
5
6
7‐11 12‐24
Stream (by carbon number)
Figure A-2. Base case output from this study’s hydrocracker model compared to
output from hydrocracker of Tarka’s Case 7 (2010)
Results from Tarka and the models of this study are given side-by-side in Table A-3.
Tarka’s streams C12-C18 and C19-C24 are combined because of the dissonance between
stream labels and average stream carbon number.
86
Table A-3. Tarka (2010) stream flow rates and flow rates of this study (kg/d to produce 30,000 bpd of liquid fuel)
Stream
carbon
dioxide
methane
carbon
monoxide
carbonyl
sulfide
hydrogen
ethene
ethane
propene
propane
isobutane
n-butane
1-butene
1-pentene
n-pentane
1-hexene
n-hexane
C7-C11
C12-C18
Oxygenates
Total Flow,
kg/hr
Oxygenates from
FT Reactor
Tarka
This
Case 7
Study
CO2 to Sequestration from FT
Reactor and Gas Cleanup
Tarka Case 7
Fuel Gas from FT Reactor
to Heat and Power
Tarka Case
7
This Study
This Study
Fuel Gas from
Hydrocracker to Heat and
Power
Tarka Case
7
This Study
Naphtha from Straight Run and
Hydrocracker Output
Diesel from Straight Run and
Hydrocracker Output
Tarka Case 7
Tarka Case 7
This Study
This Study
0
0
0
0
14,488,810
91
12,181,020
0
91,259
59,759
124,476
4,528
3
21,583
0
0
0
0
0
0
0
0
0
0
0
0
301
0
265,358
428,168
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
26,900
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
105,088
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
88
46,694
18,373
6,124
23,656
7,885
0
9,025
27,075
0
0
0
0
0
0
0
0
3,455
0
8,739
0
3,162
0
4,069
0
0
0
0
0
0
0
0
0
0
0
29,976
0
43,964
28,977
28,977
0
0
0
0
0
0
0
0
0
0
0
0
0
32,978
0
84,884
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
31,811
75,849
32,768
90,017
813,620
0
0
0
0
0
0
0
0
0
0
0
0
119,632
1,430
139,807
866,591
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2,418,941
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2,406,901
0
26,900
105,088
14,489,202
12,181,020
555,295
576,597
153,479
117,862
1,044,064
1,127,460
2,418,941
2,406,901
87
In both the Tarka Case 7 study (2009) and this study, 30,000 bpd of liquid fuel products were
produced. Tarka reported consumption of 8,974,904 kg/d of #6 Illinois coal (63.75 mass %
carbon) and 3,846,387 kg/d of switchgrass with 10% water content (42.26% carbon) to make that
much liquid fuel, while this study consumed 8,144,131 kg/d of Illinois #6 coal (63.75% carbon)
and 3,658,957 kg/d of switchgrass with 15% water content (39.92% carbon). On a carbon basis,
the raw material flow rate in Tarka Case 7 is 9% larger than in this study. Tarka reported 8,813
kg/hr of hydrogen consumed in the hydrocracker for his Case 7, this study estimates that value to
be 1,293 kg/hr. The difference in hydrogen consumption may be due in part to Tarka’s
production of 90% olefins.
The heat content of the fuel gas from the FT reactor and the upgrading section for the base case
is assumed to provide exactly for the facility’s process heat and electricity needs. The weighted
average higher heating value for the fuel gas from the FT reactor is estimated to be 5.61 MJ/kg
with a flow rate of 1,048,730 kg/d and 49.7 MJ/kg for the fuel gas from the hydrocracker with a
flow rate of 117,862 kg/d. It is assumed that under different process conditions, there is no
significant change in process heat and electricity demand at the facility for a given heat content
of wax produced, and the creation of more or less fuel gas than the base case determines how
much electricity must be purchased or exported. This normalizes the heat content of the fuel gas
against a sensible process variable, a process variable that is present in every run condition and
representative of the overall process heat and power demands no matter what user-selected
values are chosen. The higher heating value of the wax in the base case is 47.0 MJ/kg with a
flow rate of 3,623,716 kg/d. Thus, 0.0690 HHV fuel gas/HHV wax is required to supply the
process heat and electricity needs of the facility.
Table A-4 contains the greenhouse gas footprint estimates produced in the base case for this
study. Complete combustion of the fuel gas streams is assumed and a displacement credit is
taken for naphtha produced. The displacement credit for naphtha is based on the Skone and
Gerdes (2008) cradle-to-gate emissions from light ends production adjusted for the difference in
the energetic content of naphtha less than 401°F and special naphthas and the modeled naphtha
of the base case.
88
Table A-4. Base case greenhouse gas footprint estimates for cradle-to-gate production of
liquid fuels
CO2E, kg/d
Life Cycle
coal mining
coal transportation
coal mining and transportation
switchgrass production
biogenic CO2 during switchgrass production
photosynthesis
this study
632,141
109,946
742,087
289,315
-5,287,193
Tarka
(2009)
Case 7
770,263
5,976,720
switchgrass direct and indirect land use
switchgrass biogenic direct and indirect land use
switchgrass transportation
switchgrass cultivation and transportation
total switchgrass
261,689
157,335
119,446
hydrogen production
displacement credit for production of naphtha
burning hydrocracker fuel gas to generate power or heat
burning FT reactor fuel gas to generate power or heat, adjusted for wax production
net CO2E emissions (cradle-to-gate)
-4,459,408
257,938
-722,954
355,830
856,643
-2,969,864
558,730
5,417,990
-714,015
4,372,188
Tarka (2009) reports an LCA effective carbon of 35.1 kg CO2E/MMBtu LHV for Case 7. This
includes emissions of 0.9 kg CO2E/MMBtu LHV during fuel distribution and 76.7 kg
CO2E/MMBtu LHV during combustion of fuel during vehicle operation. This corresponds to a
cradle-to-gate greenhouse gas footprint for production of liquid fuels for Tarka’s Case 7 of –43
kg CO2E/MMBtu LHV, or -41 g CO2E/MJ LHV. In terms of LHV diesel, this study estimated
cradle-to-gate greenhouse gas emissions to be –28 g CO2E/MJ LHV. Both studies applied an
LHV of diesel of 5 MMBtu/bbl.
Tarka (2009) provides more detailed information in Figure 3-6 for the greenhouse gas emissions
per life cycle stage for his Case 5, which is 15% biomass (partially dried after receiving basis).
Some of the values for Case 7 can be derived from this figure based on the amount of coal or
biomass consumed or the quantity of naphtha produced. Where possible, these derived values
are included in Table A-4. Where comparable, the table shows that many of the values are
similar.
Tarka (2009) reports 15,983 tons/d (short tons) of carbon sequestered on a CO2E basis for Case
7, or 14,530,000 kg/d. The models of this study provide an estimate of 12,181,555 kg/d of
carbon dioxide sequestered, so this study and Tarka’s Case 7 are in reasonably good agreement
for this value as well.
89
References
Shah, PP, GC Sturtevant, JH Gregor, MJ Humbach, FG Padrta, KZ Steigleder. Fisher-Tropsch
wax characterization and upgrading, final report. US Department of Energy. Available through
NTIS DE88014638. June 6, 1988.
Skone, Timothy J., and Kristin Gerdes. "Development of Baseline Data and Analysis of Life
Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels." US Department of Energy,
National Energy Technology Laboratory, Office of Systems, Analysis and Planning. November
26, 2008.
Tarka, T., “Affordable, Low-Carbon Diesel Fuel from Domestic Coal and Biomass,”
DOE/NETL-2009/1349, National Energy Technology Laboratory, 14 January 2009.
Tarka, T., National Energy Technology Laboratory, May 2010 personal communication data file
StreamTableCaseJ3aValue.xls.
90