t FA/600/A-93/109
THE COPROCESSING OF FOSSIL FUELS AND BIOMASS FOR C02
EMISSION REDUCTION IN THE TRANSPORTATION SECTOR
Meyer Steinberg0', Yuanji Dong®, Robert H. Borgwardtp)
(1) Brookhaven National Laboratory, Upton, NY 11973
(2) Hydrocarb Corporation, New York, NY 10018
(3) U.S. Environmental Protection Agency, Research Triangle Park, NC 27711
ABSTRACT
Conversion of biomass to alcohol for displacement of petroleum fuels can
emissions. Coprocessing biomass with natural gas to produce methanol can
petroleum displaced and minimize mitigation cost. This paper discusses
reaction rate studies of a biomass gasification process aimed at these goals.
KEYWORDS
Hydrocarb; biomass; methanol; transportation; alternative fuel.
INTRODUCTION
Research is underway to evaluate the Hydrocarb process for conversion of carbonaceous raw material
to clean carbon and methanol products. These products are valuable in the market either as fuel or as
chemical commodities. As fuel, methanol and carbon can be used economically, either independently
or in slurry form, in efficient heat engines (turbines and internal combustion engines) for both mobile
and stationary single and combined cycle power plants. When considering C02 emission control in the
utilization of fossil fuels, the coprocessing of those fossil fuels with biomass (which may include wood,
municipal solid waste, and sewage sludge) is a viable mitigation approach. By coprocessing both types
of feedstock to produce methanol and carbon-and sequestering all or part of the carbon--a significant
net C02 reduction is achieved if the methanol is substituted for petroleum fuels. Biomass removes C02
from the atmosphere by photosynthesis and is thus a prime feedstock for mitigation of C02 emission
from mobile sources. Since the availability of biomass will, in most cases, determine the amount of
petroleum that can be displaced, it is essential to obtain maximum yield of fuel from the biomass
conversion process.
Basic Hydrocarb Process
The Hydrocarb process would use carbonaceous feedstock or combination of feedstocks to produce, in
addition to pure carbon, the coproducts, hydrogen, methane, or methanol (Fig. 1). A simplified block
flow diagram is shown in Fig. 2 for converting biomass and natural gas to carbon and methanol. It
combines three basic steps: (1) a hydropyrolyzer (HPR) in which the carbonaceous material is
hydrogasified with a recycled hydrogen-rich gas to form a methane-rich gas, (2) a methane pyrolyzer
(MPR) in which methane is decomposed to carbon and hydrogen, and (3) a methanol synthesis reactor
(MSR) in which the CO is catalytically combined with hydrogen to form methanol (MeOH or CH3OH)
and the remaining hydrogen-rich gas is recycled to the first step (HPR). The principal distinguishing
features of the process are that the hydropyrolysis is an exothermic reaction which does not require
effectively mitigate C02
maximize the amount of
process simulations and

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internal heating, the methane pyrolysis is an cndolhermic process which does require heating, and the
recycled hydrogen-rich gas conserves the energy balance in the process.
All ( n.il r;'1ilc}
( ' (impute) ~ 11, 		O l4
F* * til I ict tti it. Meiliane
()plionnl n t If I i i i on ^
(*a( O, I .imc^fonc
M,n wpict
(Cnrhon dioxide
C * 1Methane
Alternative feed^'ocks
Wood
I'apr r
Municipal solid waste
I Vai
UuhKr
|	Cnrlxni black
-~ ll: + C (pure)
I •'ncloificimic
Copmduets
ll2 - Hydm^en
Cllj - Methane, SNG
01,011 • Methanol
Waste sticanis
	~- lljO - Water
		* COj - Carlx>n dioxide
	* CaS04 - Gypsum
	~ Nj - Nitio^cn
	»• Ash
Fig. 1. Production of a clean carbon fuel and coproducts.
BIOMASS
HEAT INPUT
(H2. CH 4, CH3OH)
CARBON
RECYCLE GAS (H2 . CH4 )
METHANOL
METHANOL
SYNTHESIS
(MSR)
HYDROPYROLYZER
(HPR)
Fig. 2. Hydrocarb process block diagram.
PROCESS CHEMISTRY
The first two steps of the Hydrocarb process have been successfully tested, albeit at different conditions
than those to be discussed here, at pilot plants operated by Rheinbraun in Germany (hydropyrolysis of
coal) and UOP in the U.S. (continuous methane pyrolysis); the third step, methanol synthesis, is
practiced on a commercial scale with natural gas as feedstock. Process design calculations using
thermochemical equilibrium data indicate that the Hydrocarb reactors should operate in the range of 50
aim (5 MPa) pressure with temperatures in the range, 800°-900°C for the HPR, 1000°-1100°C in the
MPR, and the MSR at 260°C. In addition to literature data, kinetic data were needed for designing the
hydropyrolyzer with biomass feedstock and for the thermal decomposition of methane at the design
conditions. The following experimental study was therefore undertaken.
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Hydropyrolysis of Biomass
The pyrolysis and hydropyrolysis of biomass in the form of poplar wood sawdust having particle size
less than 150 pm in diameter were investigated in a 25 mm ID and 2.5 m long tubular reactor facility
at Brookhaven National Laboratory (Steinberg et al., 1993). The tests were conducted at temperatures
up to 800°C and pressures between 30 and 50 atm. The experiments were performed in two different
modes, depending on the heat-up rate. In the low heat-up rate mode, the biomass was first loaded in
the reactor at room temperature. Hydrogen was then introduced into the system to a desired initial
pressure level. The reactor was slowly heated up at a rate of less than 10°C/min. The change in the
pressure in the reactor and the composition of the effluent gas were monitored with time. In the higher
heat-up rate mode, the reactor was heated and pressurized with hydrogen up to the desired reaction
conditions before introducing the biomass. The variations of pressure and gas composition versus time
were then recorded and analyzed. From these data, rates of reaction and degree of conversion were
determined.
At the low heat-up rate, the reaction proceeds in two steps. The first step, biomass pyrolysis, takes
place at temperatures of 300 to 400°C and then hydropyrolysis takes place at 700°C and above. This
was confirmed by experiments using pressurized thermogravimetric analysis (PTGA). Under conditions
of rapid heat-up at higher temperature and higher hydrogen pressure, gasification and hydrogasification
of biomass are especially effective in producing C02 and methane. An overall conversion of 88 to 90
wt% of biomass was obtained. This agrees with previous work on flash pyrolysis and hydropyrolysis
of biomass under rapid heat-up and short residence time conditions (Steinberg and Fallon, 1981). Initial
rates of biomass conversion increase significantly with increases in hydrogen pressure. At 800°C and
51.3 atm the initial rate of biomass conversion to gaseous components was 92% per min.
Thermal Decomposition of Methane
The reaction rate of methane decomposition was investigated in the temperature range 700 to 900°C
at pressures ranging from 28 to 56 atm using the same reactor facility at Brookhaven (Steinberg et al.,
1993). In these experiments, methane was fed into the reactor continuously. Gas from upstream and
downstream of the reactor was analyzed on-line to calculate the reaction rate. The variations in methane
concentration vs. residence time under different operating conditions are shown in Figure 3.
100
90
80
Equilibrium Data
70
at 700"C and 56.1 atrr
Equilibrium Data
at-flOO'C aftd- 5671" atm
ID
Z
<
X
J—
60
50
Equilibrium Data
40
at 900-C and 66.1 atm
30
20
0
20
40
60
80
100
120
RESIDENCE TIME (sec.)
900*C 66.1 aim	800*C 66.1 atm -e- 700*C 66.1 atm
900"C 28.1 atm	900*C 41.8 atm
Fig. 3. Methane concentration vs. residence time.
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A gas residence time of about 2 min. is required for the reaction to reach near equilibrium composition
at 50 atm and 900°C. From a first order Arrhenius rate model, the activation energy for methane
decomposition is determined to be 31.3 kcal/mol CH„ (131 kJ/mol). This low value suggests that the
high-surface-area submicron carbon particles formed in the reactor catalyze the methane decomposition
reaction. At 900°C, the rate constant was approximately independent of pressure in the range
investigated, 28 to 56 atm. The rate of methane decomposition increases with methane partial pressure
to the first order. It is concluded that the rate of methane decomposition is favored by higher
temperatures and pressures, while the thermochemical equilibrium of methane decomposition is favored
by lower pressures. By extrapolating to higher temperatures using the derived rate equation, the
residence time to reach near equilibrium at 50 atm would be 41 sec. at 1000°C and 12 sec. at 1100°C.
PROCESS SIMULATION COMPUTER MODEL
A process simulation computer model was developed based on well-known thermodynamic data taking
into account equilibrium among the gaseous species CH4, CO, C02, H2, and H20 and carbon in the solid
phase. This detailed model allows the complete determination of the mass and energy balances around
each reactor and around the entire process for various feedstock types and for various pressure and
temperature conditions in each reactor. From numerous simulations, we cite here only two which are
most relevant to C02 emissions reduction (Dong, et al., 1992). In one configuration we obtain a net
zero C02 emission, and in the other configuration we maximize the production and utilization of
methanol as transportation fuel and substantially reduce C02 emission, although not to zero.
Figure 4 shows a process flow diagram for zero C02 configuration: poplar wood and natural gas are
feedstocks and the product carbon is sequestered while the methanol is utilized. All stream
compositions are indicated in the diagram.
Wood
DRYER
CH4 -
28 kg
Wood 100 kg
(H20 11.8
H20 0 kg
HPR
800°C
Char
6.41
& Ash--J
kg
746°C
20.3 kmol
CO 4.49
CO2 1.44
CH4 39.48
H20 12.16
H2 41.28
N2 1.11
H2S 0.02
Purge gas
1.26 kmol
	L
MeOH
79.4 kg
_1_
H20
6.6 kg
HE
17.6 kmol
CO 2.4 4
C02 1.24
CH4 18.3
H20 0.05
H2 75.82
N2 1.19
MeOH 1.0
19 . 64
MPR
1100°C
Alumina
9.42
COM
1400°C
Flue
27.0
kmol
27.0 kmol
CO 12.25
CO2 0.17
CH4 12.76
H20 2.08
H2 71.91
N2 0.83
CH4 4.22
CON
50°C
48.72 kmol
CO 2.3
CO2 1.17
CH4 17.2
H20 0.8
H2 71.4
N2 1.12
MeOH 6.0
260°C
Purge gas —
Fig. 4. Hydrocarb process simulation for zero C02 emission.
Carbon efficiency = 42.57%, Thermal efficiency = 50.33%.
Sequester 19.64 kg carbon per 100 kg dry biomass feed.
The thermal efficiency of the process was determined to be 50.3% which includes the energy necessary
to heat the MPR supplied by burning methane in the MPR heater. The net C02 emission for this
system is zero as calculated as by:
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Net carbon Carbon emitted from the combustion of methanol as fuel minus carbon removed
emission = from the atmosphere by photosynthesis of biomass minus carbon sequestered
(as COj)	plus carbon emitted as C02 from the MPR combustor (fueled by natural gas,
purge gas, and carbon)
Figure 5 shows a configuration in which the methane feedstock is increased and more methanol is
produced while all the carbon produced in the MPR is used, in addition to methane and purge gas, to
supply heat to the MPR. The thermal efficiency for this system is 72.5% and the net C02 emission is
94 lb/COj/lO'Btu (40.6 kg CCVGJ) which is 55% less than the displaced gasoline emission. The
configuration shown in Figure 5 maximizes the methanol production and minimizes the methanol
production cost.
Wood
DRYER
Wood 100 kg
(H20 11.8 *)
Steam 50 kg
(268°C )
958 C
40 kg
Purge gas
0.19 knol
j 50* C
MeOH H20
165.8 kg 9.0 kg
Char & Ash
6.3 kg
800* C
20.95 knol
CO 6.78
CO2 3.28
CH4 30.92
H20 16.24
K2 36.54
N2 6.1
H25 0.02
HE/1
21.8 kmol
CO 5.46
C02 3.3
CH4 17.45
—,H20 0.03
H2 64.72
N2 8.02
MeOH 1.0
66.09 knol
CO 4.99
C02 3.03
260" C CH4 15.95
H20 0.78
H2 59.17
N2 7.34
MeOH 8.74
38.44
kmol
260 C
1100
260 C
1100
knol
38.44
CO 18
CO 2 0
CH4 9
H20 2
H2 63
Alumina
COM
1400*
Flue
4 . 59
Purge gas
CH4
H20
20° C
• Steam 50.9 kg
268* C
Fig. 5. Hydrocarb process simulation for maximum methanol yield and minimum production cost.
Carbon efficiency = 67.8%, Thermal efficiency = 72.5%, C02 emission = 94 lb/106Btu.
No carbon sequestered.
To show the efficiency of the Hydrocarb technology for methanol production and C02 reduction, a
comparison is made with separate conventional biomass gasification and natural gas reforming plants.
Table 1 summarizes this comparison based on fixed unit amounts of biomass and natural gas fed to each
plant and compares the methanol yield with a Hydrocarb plant configured according toFigure5.The
biomass gasification plant is based on a range of values from four gasification processes evaluated by
Larson and Katofsky (1992). It is seen that a Hydrocarb plant can produce from 11 to 25% more
methanol than two individual plants utilizing the same feedstocks. Furthermore the C02 emission per
unit methanol energy Ob C02 emitted/lO'Btu) is 20 to 35% less than the two combined plants.
It also can be seen from Table 1 that the biomass leverages natural gas in the Hydrocarb plant so that
the yield of methanol per unit of natural gas is as high as 79% greater than the yield from a natural gas
reforming plant alone. Conversely, natural gas leverages biomass in the Hydrocarb plant to produce
up to 4.2 times the yield of methanol per unit of biomass from a biomass gasification plant alone.
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Table 1. Comparison of methanol production and C02 reduction obtainable from Hydrocarb
and from separate conversion of biomass and natural gas
Factor
Hydrocarb
process
Biomass
gasification*
Natural gas
reformingb
Feedstock
Dry biomass (wood), kg
Natural gas (CHJ, kg
Thermal efficiency, %
Carbon efficiency, %
Methanol yield,
kg MeOH/kg feedstock
Total production, kg MeOH
Net C02 emission, kg
lb CO2/10*Btu MeOH (LHV)d
kgC02/GJ MeOH (LHV)
Gasoline displaced, gal.c
Net C02 reduction from displaced
gasoline, kg
88.2
61.2
73
68
1.88/biomass
2.61/CH,
1.11/total
166
144
94
40.6
35.8
178
88.2
0
64 - 50
41 - 32
0.57 - 0.45
50.3 - 39.7C
0
0
0
10.9 - 8.6
98 - 77
0
61.2
64 - 60
78 - 73
1.56 - 1.46
99.4 - 93.0*
168
180 - 193
77.8 - 83.8
21.5 - 20
0
' The range of values represents the four gasification processes evaluated by Larson and Katofsky
(1992).
b Ranges shown represent performance of different reforming technologies (Wyman et al., 1992).
c The sum of the lowest and highest methanol production for the biomass and natural gas individual
plants = 132.7 to 119.7 kg MeOH. Thus the Hydrocarb plant with a production of 166 kg yields
11 to 25% more MeOH than the sum of the two individual plants for the same amount of biomass
and natural gas feedstock.
d Lower heating value
e 1 gal. = 3.785 liter
HYDROCARB METHANOL AS AN ALTERNATIVE TRANSPORTATION FUEL
An analysis can also be made with respect to C02 emissions when considering methanol's displacing
gasoline as a transportation fuel. About 30% of the U.S. anthropogenic C02 emission comes from the
transportation sector which is about equal to emissions from stationary sources. EPA has estimated that
1.54 gal. of methanol can displace 1 gal. of gasoline in automobiles on a mileage per unit energy basis
(Office of Mobile Sources, 1989). Gasoline emits 9 kg C02 per gal. For maximum Hydrocarb
methanol production configuration (Fig. 5), the C02 emitted is 4 kg C02 per gal. of gasoline displaced.
There is thus a 55% reduction in C02 emission by the use of Hydrocarb methanol in displacing
gasoline. The next to the last line in Table 1 then indicates the amount of gasoline displaced with the
use of Hydrocarb methanol compared to the two individual conventional biomass gasification and
natural gas reforming plants. Finally, the last line indicates the net reduction in C02 from the displaced
gasoline which shows that Hydrocarb methanol can yield from 80% to 130% greater reduction in C02
emission than the other conventional biomass gasification plant.
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Cost Estimates
The following is a summary of the conclusions of a preliminary economic study of alternate fuel
options. The capital cost estimate is based on a comparative analysis with a Texaco Coal gasification
process (Fluor Engineers and Constructors, 1981) assuming that equal gas throughput will have the
same capital cost when escalated to 1992 dollars. Credit was taken for elimination of the air separation
plant and half credit for acid gas removal which are not needed in the Hydrocarb plant. A plant
capacity of 5000 dry metric tons of biomass per day (DMT/day) was selected after consideration of the
supply area and delivered cost of biomass produced as short-rotation woody crops from energy farms
surrounding the plant site. Table 2 gives the economic parameters assumed for methanol production
based on the maximum-yield option (Fig. 5) which results in a methanol production cost of $0.405/gal.
Table 2. Hydrocarb methanol production economics based on maximum yield option
Biomass Feedstock
Natural Gas Feedstock
Methanol Production
Capital Investment
Delivered Cost of Biomass
Maximum Distance of Plantation
Natural Gas Cost
Carbon Sequester
O&M
Return on Equity
Debt/Equity
Total Capital Charge Rate
Ind. Inv. on Equity & Taxes
Annual Operating Factor
Production Cost of Methanol
5000 DMT Biom ass/Day
4.68 x 106 m3/Day (165 x 106 SCF/Day)
2.85 x 106 GPD
$838 x 106
$51.00/DMT
84 km
$2.50/106Btu
$23/ton
$5.00/DMT Biomass
25%
80%/20%
20.9%
90%
$0.405/gal.
An equivalent gasoline price and incremental cost of gasoline displaced is calculated in Table 3. The
U.S. national-average gasoline price for the year 1989 was $1.12 per gal. Taking into account methanol
displacement, production cost, taxes, markups and distribution cost, the incremental cost of gasoline
displaced is equal to $1,01/gal. or llC/gal. less than the national average.
Table 3. Incremental cost of gasoline displacement by Hydrocarb methanol
National average gasoline price = $1.12/gal.
Equivalent gasoline price = 1.54($0.405 + $0.12 + $0.07 + $0.06) = $1.01/gal.
where: 1.54 = volumetric ratio, methanol to gasoline
$0,405 = methanol production cost
$0.12 = taxes
$0.07 = markup
$0.06 = distribution cost
Incremental cost of gasoline displacement = $1.01 - $1.12 = -$0.11/gal.
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Impact on Pctiolcum Displacement
Tlie Energy Policy Act of 1992 (P L. 102-486) promotes replacement of petroleum molor fuels willi
alternative fuels to the maximum extent practicable. The intent of the Act is to ensure availability of
alternative fuel that will have the greatest impact on (1) reducing oil imports, (2) improving the national
economy, and (3) reducing greenhouse gas emissions. The Act sets a 10% replacement goal of
petroleum motor fuel with alternative fuels by the year 2000 and 30% by 2010. This means that there
would have to be made available a supply of 7.5 quads (1 quad = 1.055 x 10'8 J/yr) of alternative fuel
by 2010. If biomass supply is limited to 6-12 quads (mainly due to suitable biomass farm areas), then
ethanol cannot meet the 30% petroleum displacement goal. On the other hand, Hydrocarb could meet
the 30% goal with as little as 2.5 quads of biomass. If we include the addition of MSW (municipal
solid waste) as feedstock which is essentially processed biomass, Hydrocarb could further increase the
leverage of biomass supply for methanol production.
The number of Hydrocarb plants needed to supply 30% of U.S. highway fuel consumption by 2010
(7.56 quads) amounts to 80 each having a 5000 DMT/day biomass capacity or 40 for 10,000 DMT/day
biomass feed capacity. Hydrocarb methanol plants consume 30% less natural gas for the 30%
petroleum displacement than when replacing petroleum with compressed natural gas as an alternative
fuel. Even if all the petroleum fuel were replaced with Hydrocarb methanol, which would require 8.4
quads of biomass, the natural gas requirement would be 16.5 quads. The U.S. reserve of conventional
natural gas is estimated at present to be at least 1000 quads.
CONCLUSION
Our comparisons suggest that the Hydrocarb process has the potential to significanlly displace petroleum
fuels at a compctetive price while reducing C02 emissions from the iransportalion sector. The reaction
rate studies and process simulations reported here are the first step in establishing feasibility. The next
step, currently underway, is to resolve technical uncertainties of the process with a bcnch-scale (15-cm
I.D. reactors) test facility. This research will be focused on such issues as the control of volatile alkalis
during gasification, high-temperature particulate removal, high pressure combustion and indirect heat
transfer to the methane pyrolyzer by circulation of inert solids, and high-temperature heat exchanger
design.
REFERENCES
Dong, Y., Steinberg, M. and Borgwardt, R. (1992). Analysis of the Hydrocarb Process for Methanol
Production from Biomass, Presented at the 1992 Greenhouse Gas Emission and Mitigation Research
Symposium, Sponsored by U.S. Environmental Protection Agency, Air and Energy Engineering
Research Laboratory, Washington, D.C.
Fluor Engineers and Constructors, inc. (1981). Methanol Production by Coal Gasification. Research
report EPRI-AP-1962, prepared for Electric Power Research Institute, Palo Alto, CA.
Larson, E.D. and Katofsky, R.E. (1992). Production of Hydrogen and Methanol via Biomass
Gasification. In Advances in Thermochemical Conversion. Elsevier Applied Science, London.
Office of Mobile Sources (1989). An Analysis of the Economic and Environmental Effects of
Methanol as an Automotive Fuel. EPA Report No. 0730 (NTIS PB90-225806), Molor Vehicle
Emissions Laboratory, Ann Arbor, MI.
Steinberg, M. and Fallon, P.T. (1981). Flash Pyrolysis and Hydropyrolysis of Biomass, Research
report BNL 30263. Brookhaven National Laboratory, Upton, NY.
Steinberg, M., Kobayashi, A. and Dong, Y. (1993). Rates of Reaction and Process Design Data for
the Hydrocarb Process. Research report EPA-600/R-93-020, U.S. EPA, Air and Energy
Engineering Research Laboratory, Research Triangle Park, NC.
Wyman, C.E., Bain, R.L., Hinman, N.D. and Stevens, D.V. (1992). Ethanol and Methanol from
Ccllulosic Materials. In Renewable Energy. Sources of Fuels and Electricity (R.H. Williams, Ed.),
Island Press, Washington, D.C.
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¦•nppT --D-irMl TECHNICAL REPORT DATA
x 1U*±1 (Please read laiinictiotis on the reverse before complet
1 REPORT \0. 2.
EPA/600/A-93/109
3.
4. ~ITi_E ANDSUBT.TLE
The Coprocessing of Fossil Fuels and Biomass for
CO2 Emission Reduction in the Transportation Sector
'i. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7-AUTHOR
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