United States EPA-600 /R- 93" 170
Environmental Protection
A9ency September 1993
v?EPA Research and
Development
BIOMASS
GASIFICATION
PILOT PLANT STUDY
Prepared for
Office of Policy, Planning and Evaluation
Prepared by
Air and Energy Engineering Research
Laboratory
Research Triangle Park NC 27711
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/R-93-170
September 1993
BIOMASS GASIFICATION PILOT PLANT STUDY
FINAL REPORT
Prepared by:
A.H. Furman
S.G. Kimura
R.E. Ayala
J. F. Joyce
GE Research and Development Center
P.O. Box 8
Schenectady, New York 12301
Vermont DPS Contract No. 0938222
U.S. EPA Cooperative Agreement CR 817675
Vermont DPS Project Officer: Richard Sedano
State of Vermont Department of Public Service
State Office Building
Montpelier, Vermont 05602
U.S. EPA Project Officer: Carol R. Purvis
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
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ABSTRACT
A gasification pilot program was carried out at the GE Research and Development Center
using two biomass feedstocks: bagasse pellets and wood chips. The object of the testing was
to determine the properties of biomass product gas and its suitability as a fuel for gas-turbine-
based power generation cycles. Gasification of the feedstocks was performed at a feed rate of
approximately one ton per hour, using the GE pressurized, fixed-bed gasifier and a single
stage of cyclone particulate removal, operating at 1000 °F. The biomass product gas was
analyzed for chemical composition, particulate loading, fuel-bound nitrogen (FBN) levels, and
sulfur and alkali metal content.
Both feedstocks gasified easily. The composition and heating value of the biomass product
gas were compatible with gas turbine combustion requirements. However, the particulate
removal performance of the pilot facility single-stage cyclone did not meet turbine
specifications. In addition, alkali meta! compounds in the particulate matter (at 1000 °F) carried
over from the gasifier exceeded turbine limits. Improved particulate removal technology,
designed specifically for biomass feedstock characteristics, could meet turbine requirements
for both particulate and alkali loading. FBN compounds were also measured since they can be
converted to NOx during combustion in a gas turbine. Since this conversion is highly
dependent on gas turbine combustor design, no firm conclusions regarding NOx production
can be reached without actual combustion testing.
This report was submitted in fulfillment of Vermont Department of Public Service
Contract 0938222 covering work performed by General Electric Corporate Research and
Development under the partial sponsorship of the U.S. Environmental Protection Agency under
cooperative agreement CR 817675. This report covers a period from April 1991 until March
1993, and the work was completed as of July 1992.
FOREWORD
This report was prepared by General Electric Company Corporate Research and
Development under contract with the State of Vermont Department of Public Services. The
report summarizes the technical results achieved on the "Biomass Gasification Pilot Plant
Study" program. Additional agencies involved in the program, either through supply of funding
or supply of feedstock, were the U.S. Environmental Protection Agency Air and Energy
Engineering Research Laboratory (AEERL), the U.S. Department of Energy Office of
Conservation and Renewable Energy, the U.S. Agency for International Development Office of
Energy and Infrastructure, and the Winrock International Institute for Agricultural Development.
The authors would also like to acknowledge the support of the Department of Energy
Morgantown Energy Technology Center in permitting use of portions of the pilot gasification
facility installed with METC funds and the contributions of all the individuals involved in
production of the test fuels and operation of the pilot facility.
ii
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CONTENTS
Figures v
Tables vi
Metric Conversion Factors vii
1 PROJECT SUMMARY 1-1
2 INTRODUCTION 2-1
3 EXPERIMENTAL FACILITY 3-1
3.1 OVERALL SYSTEM DESCRIPTION 3-1
3.2 SYSTEM FLOW 3-1
3.3 GASIFIER 3-2
3.4 FUEL HANDLING SYSTEM 3-5
3.5 SAMPLING AND ANALYSIS 3-6
3.6 DATA ACQUISITION, ANALYSIS, AND CONTROL 3-9
4 BIOMASS GASIFICATION TEST RESULTS 4-1
4.1 PROGRAM OBJECTIVES 4-1
4.2 BIOMASS FEEDING TESTS 4-1
4.3 GASIFIER OPERATION 4-5
4.4 GASIFICATION OF BAGASSE 4-6
4.4.1 Bagasse Properties 4-6
4.4.2 Gasification Run Summary — Bagasse Pellets 4-8
4.4.3 Mass and Energy Balance Discussion — Bagasse Gasification 4-13
4.5 GASIFICATION OF WOOD CHIPS... 4-16
4.5.1 Wood Chip Properties 4-16
4.5.2 Gasification Run Summary — Wood Chips 4-19
4.5.3 Mass and Energy Balance Discussion — Wood Chip Gasification .... 4-26
4.5.4 Wood Chip Steam-to-Air RatioVariations 4-29
4.6 FUEL COMPARISONS 4-30
4.6.1 Gasifier Operating Parameters 4-30
4.6.2 Gas Composition Variations 4-32
5 GAS STREAM CONTAMINANTS 5-1
5.1 GENERAL DISCUSSION 5-1
5.2 BAGASSE FUEL GAS CONTAMINANTS 5-1
5.2.1 Particulates 5-1
5.2.2 Alkali Metals 5-4
5.2.3 Fuel-Bound Nitrogen 5-5
5.2.4 Sulfur 5-7
5.3 WOOD CHIP GAS STREAM CONTAMINANTS 5-8
5.3.1 Particulates 5-8
5.3.2 Alkali Metals 5-11
5.3.3 Fuel-Bound Nitrogen 5-12
5.3.4 Sulfur 5-13
6 CONCLUSION 6-1
Appendix A: GASIFIER/CYCLONE A-1
A.1 GASIFIER REACTOR A-1
A.2 CYCLONE A-3
A.3 FUEL HANDLING A-5
iii
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CONTENTS (cont'd)
Appendix B: SAMPLING PROCEDURES B-1
B. 1 PARTICULATE SAMPLING B-1
B.1.1 Overview B-1
B.1.2 Description of Setup B-1
B.1.3 Primary Cyclone Particulate Sampling B-2
B. 1.3.1 Primary Cyclone Particulate Filter Installation B-2
B. 1.3.2 Primary Cyclone Particulate Sample Extraction B-3
B. 1.3.2.1 Initial status B-3
B.1.3.2.2 Sample extraction B-3
B. 1.3.2.3 Primary cyclone particulate filter removal B-4
B.2 PROCEDURE FOR AMMONIA AND HYDROGEN CYANIDE
GAS ANALYSIS B-5
B.2.1 Overview B-5
B.2.2 Gas Sampling B-7
B.2.3 Gas Analysis B-7
B.2.4 Gas Bubbling and Solution Labeling B-8
B.2.5 Sample Analysis B-9
B.3 PROCEDURE FOR ANALYSIS OF TAR AND WATER PHASES
IN THE FUEL GAS LIQUID CONDENSATE B-10
B.3.1 Overview B-10
B.3.2 Equipment B-11
B.3.3 Chemicals B-11
B.3.4 Procedure for Liquid Phase Separation and Extraction B-11
B.3.5 Chemical Analysis B-12
B.4 CALIBRATION OF ANALYTICAL INSTRUMENTATION B-12
B.4.1 Overview B-12
B.4.2 Setup and Operating Parameters for Gas Analysis Instrumentation ..B-13
B.4.2.1 Mass Spectrometer. B-13
B.4.2.1.1 Mass Spectrometer initial startup B-13
B.4.2.1.2 Mass Spectrometer calibration B-13
B.4.2.1.3 Mass Spectrometer operation B-13
B.4.2.1.4 Mass Spectrometer shutdown B-14
B.4.2.2 Gas Chromatograph #1 B-14
B.4.2.3 Gas Chromatograph #3 B-14
Appendix C: DATA ACQUISITION AND CONTROL SYSTEM C-1
C.1 OVERVIEW C-1
C.2 DATA ACQUISITION C-2
C.3 CONTROL SYSTEM C-2
Appendix D: MASS AND ENERGY BALANCES D-1
D.1 OVERVIEW D-1
D.2 DETAILED MASS AND ENERGY BALANCES D-1
Appendix E: QA PROJECT PLAN FOR THE VERMONT BIOMASS
GASIFICATION PILOT PLANT STUDY E-1
E.1 SCOPE E-1
E.2 PROJECT DESCRIPTION E-1
E.3 DATA QUALITY INDICATORS: GOALS FOR CRITICAL MEASUREMENTS..E-2
iv
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FIGURES
NUMBER PAGE
3-1. Pilot gasification facility 3-1
3-2. Gasifier/ hot gas cleanup facility process flow diagram 3-2
3-3. Gasifier vessel assembly 3-3
3-4. Reaction zones and associated temperature profiles 3-4
3-5. Gasifier fuel handling system 3-6
3-6. Schematic of sampling points in the pilot gasification facility 3-7
3-7. Conditioning system: Gasifier sample trains 3-8
3-8. Primary cyclone particulate sampling 3-9
4-1. Flow rate of Wood Chip Sample #8 during various stages of drying 4-4
4-2. Valve positions during gasifier test trials 4-6
4-3. Gasifier operating data — Bagasse 4-9
4-4. Gas temperature profile — Bagasse 4-10
4-5. Gasifier system flows — Bagasse 4-11
4-6. Gas composition data — Bagasse 4-11
4-7. Gasifier operating data — Wood Chips (290 psig) 4-19
4-8. Gas temperature profile — Wood Chips (290 psig) 4-21
4-9. Gasifier system flows — Wood Chips (290 psig) 4-22
4-10. Gas composition data — Wood Chips (290 psig) 4-22
4-11. Gasifier system flows — Wood Chips (200 psig) 4-24
4-12. Gas temperature profile—Wood Chips (200 psig) 4-24
4-13. Gas composition data — Wood Chips (200 psig) 4-25
5-1. Particle size analysis of particulate and dust for Bagasse gasification 5-3
5-2. Particulate size analysis — Wood Chips 5-9
5-3. Particulate size analysis — Bagasse vs. Wood Chips 5-9
A-1. Gasifier vessel assembly A-1
A-2. Gasifier blast system A-3
A-3. Cyclone and pressure vessel A-4
A-4. Gasifier process flow diagram A-6
B-1. Primary cyclone particulate sampling B-2
B-2. Ammonia/hydrogen cyanide sampling apparatus B-6
C-1. Gasifier data acquisition and control system C-1
E-1. Schematic of sampling points in the pilot gasification facility E-3
E-2. Conditioning system: Gasifier sample trains E-4
E-3. Primary cyclone particulate sampling E-5
v
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TABLES
NUMBER PAGE
4.1 Comparison of Feedstock Density 4-1
4.2 Wood Chip Test Sample Data 4-2
4.3 Characteristics of Bagasse Pellets 4-6
4.4 Composition of Bagasse Pellets 4-7
4.5 Ash Mineral Analyses - Raw Bagasse 4-8
4.6 Bagasse Gasification Flows 4-14
4.7 Fuel Gas Composition - Bagasse 4-14
4.8 Gasifier Ash Composition - Bagasse 4-15
4.9 Ash Mineral Analyses After Gasification - Bagasse 4-15
4.10 Characteristics of Wood Chips 4-17
4.11 Composition of Wood Chips 4-17
4.12 Ash Mineral Analyses - Raw Wood Chips 4-18
4.13 Gasifier Mass Flow - Wood Chips (290 psig) 4-26
4.14 Fuel Gas Composition - Wood Chips (290 psig) 4-27
4.15 Gasifier Ash Composition - Wood Chips (290 psig) 4-27
4.16 Ash Mineral Analyses After Gasification - Wood Chips (290 psig) 4-28
4.17 Gasifier Mass Flow - Wood Chips (200 psig) 4-29
4.18 Fuel Gas Composition - Wood Chips (200 psig) 4-29
4.19 Gas Composition Variations - Wood Chips (mole % wet) 4-30
4.20 Comparison of Gasifier Operating Parameters 4-31
4.21 Gas Composition Comparison (mole % wet) - Cyclone Exit 4-32
5.1 Cyclone Dust Composition - Bagasse.. 5-2
5.2 Gas Particulate Composition - Bagasse 5-3
5.3 Alkali Distribution - Bagasse 5-5
5.4 Fuel-Bound Nitrogen - Bagasse and Coal 5-5
5.5 Sulfur Distribution - Average Values for Bagasse 5-7
5.6 Solid Matter Bulk Density 5-8
5.7 Cyclone Dust Composition - Wood Chips (290 psig) 5-10
5.8 Gas Particulate Composition - Wood Chips (290 psig) 5-10
5.9 Alkali Distribution - Wood Chips (290 psig) 5-11
5.10 Alkali Distribution - Wood Chips (200 psig) 5-12
5.11 Fuel-Bound Nitrogen - Wood Chips 5-12
5.12 Sulfur Distribution - Average Values for Wood Chips (290 psig) 5-13
A.1 Cyclone Design Specifications A-3
C.1 Proloop Controllers C-3
D.1 Gasifier Mass Balance - Bagasse 10/9/91 0100-0600 D-2
D.2 Gasifier Energy Balance - Bagasse 10/9/91 0100-0600 D-3
D.3 Gasifier Mass Balance - Wood chips (290 psig)
10/30/91 1645 to 10/-31/91 1900 D-4
D.4 Gasifier Energy Balance - Wood chips (290 psig)
10/30/91 1645 to 10/-31/91 1900 D-5
D.5 Abbreviations Used in Tables D.1 Through D.4 D-6
vi
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METRIC CONVERSION FACTORS
Many nonmetric units are used in this report for the reader's convenience. Readers more
familiar with metric units may use the following factors to convert to that system.
Nonmetric Times Yields Metric
atm*
101.325
kPa
Btu
1.055
kJ
Curie
3.7 x 1010
Bq
6F
5/9(°F-32)
°C
ft
0.3048
m
ft2
0.093
m2
ft3
28316
cm3
gal.
3785.4
cm3
grain
0.064799
g
hp
746
W
in.
2.54
cm
lb
0.4536
kg
micron
1.0
Hm
oz
0.0283
kg
psi
6.8948
kPa
ton(short 2000 Ibm)
907.185
kg
•Standard atmosphere (760 torr)
vii
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Section 1
PROJECT SUMMARY
The gasification performance of two biomass feedstocks — wood chips and bagasse —
was evaluated in the pilot Integrated Gasification Combined Cycle (IGCC) facility located at the
GE Research and Development Center in Schenectady, New York. The overall objective of
this program was to evaluate biomass as a feedstock for a biomass gasification/gas turbine
system, which is a potentially cost-effective and highly efficient approach for using forest and
agricultural wastes for power generation. Specific objectives were to measure gas composition
and to determine whether the gas would meet gas turbine requirements.
The pilot IGCC facility consists of a pressurized, fixed-bed gasifier with a nominal operating
pressure of 20 atmospheres and a hot gas cleanup system, comprising a high-temperature
cyclone, a solid-sorbent desulfurization system, and a polishing cyclone. The gasifier has a
nominal capacity for coal gasification of one ton per hour. Since desulfurization is not an issue
for the biomass feedstocks evaluated, only the gasifier and high-temperature cyclone were
used. The product gas was flared.
Because the pilot gasifier and its associated fuel feeding system were designed for
operation on coal, the issue of feeding of biomass, with its lower density and different flow
properties, was addressed before gasification testing. Bagasse, which was supplied as small
cylindrical pellets, was found to feed easily with some modifications to the fuel feeding
equipment. However, it was necessary to evaluate several wood chip samples before one was
found that could be fed at the required feed rate.
A total of 42.5 tons of bagasse was gasified during a 32-hour test, and 83.8 tons of wood
chips were gasified in an 81-hour test. These quantities of fuel represented the total fuel
available to the program. Wood chips were provided by the Vermont Department of Public
Service. The bagasse pellets were obtained from the Winrock International Institute for
Agricultural Development.
Both biomass fuels gasified readily. Their reactivity was higher than that for coal.
Gasification capacities of both fuels were limited by feed rate or system capacity, and not by
gasification kinetics. Product gas compositions for both biomass feedstocks indicated that they
would have combustion characteristics compatible with gas turbine combustor requirements.
However, particulate removal performance of the single cyclone was inadequate to meet fuel
contaminant specifications. In particular, alkali metals, which are present in the fine particulate
material carried over from the gasifier and which cause hot corrosion on gas turbine hot gas
path components, were present at levels well in excess of turbine specification limits. The low
density of particulates and their poor flow properties, which made removal from the cyclone
difficult, caused the cyclone to perform poorly. This result was not unexpected since the
cyclone had been designed for removing contaminants from coal gas. In order to achieve
contaminant levels consistent with gas turbine requirements, it will be necessary to improve
particulate removal. This improvement is well within the state-of-the-art of particulate cleanup
technology.
A second class of contaminant measured was fuel-bound nitrogen (FBN) compounds.
Typical of these are ammonia, cyanides, and nitrogen-containing organic compounds. A large
1-1
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fraction of FBN will be converted to NOx during combustion in conventional gas turbine
combustors. Thus when stringent NOx emissions requirements (less than 10 ppm) are in
effect, it may be necessary to consider alternative approaches to reducing the level of this
pollutant. One potential approach is to utilize advanced combustion techniques such as "rich-
quench-lean" to reduce the conversion of fuel bound nitrogen. This technology is still in its
early stage of development and will require significant effort to bring it to a suitable stage of
commercial readiness. A second approach is to cool the fuel gas and "scrub" the gas with
water to remove the FBN compounds. This approach lowers the overall plant efficiency,
reduces the heating value of the fuel, and creates an environmental disposal problem
associated with the disposal of the "scrub" water.
Other approaches include the use of commercially available selective catalytic reduction
(SCR) technology to reduce the NOx level in the exhaust gas. It should be noted that FBN
production is a strong function of both the feedstock and gasifier, with higher temperature
gasifiers such as fluidized and entrained gasifiers producing less FBN than fixed-bed gasifiers.
A system tradeoff study should help to determine the best system level approach to NOx
reduction by identifying the capital equipment cost differences and the associated plant
efficiency impact on the overall system design.
The testing at the GE-CRD pilot plant has demonstrated the successful gasification of biomass
and the general suitability of biomass fuel gas for use in a gas turbine. Areas of possible
further development include improved particulate removal, improved low NOx combustion, and
pre- and post-gas cleanup. These accomplishments represent a key step in the overall
development of a Biomass-IGCC power generation system.
1-2
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Section 2
INTRODUCTION
The integrated gasification combined cycle (IGCC) has been shown to be an attractive
approach to power generation using coal. Recent analyses have also shown that gasification
of biomass coupled with a gas turbine represents an attractive power generation alternative
because it couples excellent environmental performance with high efficiency. Conceptually the
biomass gasification/gas turbine system is relatively simple. An air-blown, pressurized gasifier
produces a low-Btu gas whose combustible components consist primarily of hydrogen, carbon
monoxide, and methane. The diluents that reduce the heating value of the gas are primarily
carbon dioxide, nitrogen, and water vapor. Additional combustibles are in the form of vaporized
higher-order hydrocarbons. The biogas exiting from the gasifier passes through a high-
temperature particulate-removal system, then flows to the gas turbine combustor through a
fuel control valve.
One of the most attractive features of this power generation concept is its environmental
performance. Because of the high efficiencies of gas turbine combustors, there are virtually no
hydrocarbon emissions, thus eliminating the possibility of producing hazardous organics. The
low-Btu content of the gas results in very little formation of thermal NOx, but the NOx formed
from the fuel-bound nitrogen species in the fuel gas, such as ammonia, will have to be
controlled if tight NOx limits are required. The primary waste product for disposal is ash, which
is removed from the bottom of the gasifier and from the cyclone.
Biomass supplies may be available from sources ranging from agricultural and forest wastes to
planned energy farms. A typical plant may range in size between 5 and 50 megawatts. A
30-megawatt plant would require approximately 150,000 dry tons of biomass a year.
In order to demonstrate the technical feasibility of a biomass gasification/gas turbine power
generation system, several issues associated with the gasification process must be addressed.
Although highly reactive and easily gasified, the fuel gas composition must be determined in
order to "tune" the gas turbine combustor to minimize emissions. In addition to combustibility, it
must also be determined that the residual ash and vaporized components that may cause
deposition, corrosion, or erosion in the turbine are at acceptable levels. The capability to meet
environmental requirements must also be demonstrated.
In a joint program with the Vermont Department of Public Service, the U.S. Department of
Energy Office of Conservation and Renewable Energy, the U.S. Environmental Protection
Agency Air and Energy Engineering Research Laboratory, the U.S. Agency for International
Development Office of Energy and Infrastructure, and the Winrock International Institute for
Agricultural Development, the coal gasification/gas cleanup pilot facility located at the GE
Research and Development Center in Schenectady, New York, was used to evaluate the
technical issues associated with the biomass gasification process. The pilot facility consists of
a pressurized fixed-bed gasifier capable of gasifying one ton per hour of feedstock, associated
air and steam supply systems, and a hot gas cleanup system. The gasifier was commissioned
in 1976 and has been used to gasify a range of coals, municipal solid wastes, and wood
pellets. Extensive gas sampling and on-line analyses are performed during operation. A gas
turbine simulator will be added to the facility for use in combustion and turbine compatibility
studies.
2-1
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Section 3
EXPERIMENTAL FACILITY
3.1 OVERALL SYSTEM DESCRIPTION
The pilot gasification facility is located at the GE Research and Development Center
(GE-CRD) in Schenectady, New York. This test facility (shown in Figure 3-1) consists of an
advanced fixed-bed gasifier, a full-flow, high-temperature gas cleanup system, and an
advanced, computerized data acquisition, analysis, and control system. Auxiliary systems
include a high-flow, high-pressure process air supply, indirect air preheaters, a high-pressure
steam boiler to supply process steam, and an extensive gas and particulate sampling system.
Figure 3-1. Pilot gasification facility
3.2 SYSTEM FLOW
Figure 3-2 presents a schematic diagram for the gasifier/hot gas cleanup facility. The
gasifier vessel is mounted in a 6-story building. Feedstock is fed from the main storage bin or
portable feeder via elevator into the weigh bin, and then into one of two lockhoppers that feeds
the gasifier via a pressurized auger. Blast steam and air enter at the base of the gasifier, under
3-1
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the rotating grate, arid ash is removed from the gasifier through the ash lockhopper. The hot
raw gas exits from the top of the gasifier. The gas can be sent directly to a roof-mounted flare,
or it can be processed through a particulate-removing cyclone. Once through the cyclone the
raw gas can be directed to the flare or to the hot gas sulfur-removal facility located adjacent to
the gasifier tower. For the purpose of the biomass evaluation, the raw gas flowed directly
through the primary cyclone and then was burned in the flare. Gas turbine combustion
evaluations were not performed.
Flare
Turbine
Simulator
J Air
Fuel
Secondary
Cyclone
Absorber
Primary
Cyclone
Air
| Dust
Gasifier
Exhaust
| Dust
/fffBIa
¦ " " lair
Regenerator
(air + steam)
e
Sorbent
I Ash
Fines
Figure 3-2. Gasifier/hot gas cleanup facility process flow diagram
3.3 GASIFIER
The gasifier vessel is shown in a cutaway side-section view in Figure 3-3. The mechanical
systems associated with the gasifier are a feed auger, a bed stirrer, and a grate. The auger's
speed is adjustable to control the feed rate of fuel into the gasifier to provide steady and
controlled gasifier operation. The stirrer consists of a rotating shaft with water-cooled rabble
arms that can be lowered axially to break up coal agglomerates in the top portion of the bed as
well as weakly fused clinkers in the lower oxidation zone. Stirring the bed promotes an even
temperature distribution radially through the gasifier bed and distributes the feed entering the
gasifier from the feed auger evenly at the top of the bed. The grate consists of a rotating cone,
which supports the bed, and a radially adjustable plow. An alloy steel bosh ring is located in
the gasifier vessel just above the grate pan to provide a hard surface for protection against
abrasive wear.
As the grate rotates, the stationary plow sweeps ash from the bed into the ash lockhopper.
The plow can be adjusted radially to control the amount of ash removed with each rotation of
the grate. The rotational speed of the grate can be adjusted to control the rate of ash
discharge. These adjustments make it possible to maintain the appropriate ash removal rates
3-2
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regardless of gasifier load or fuel type. Reaction air and steam enter below the grate to cool
the grate, bosh, and ash during operation. Further details of the gasifier system are included in
Appendix A.
Fuel Feed
Lockhopper B
Lock hopper A
Auger Feeder
Grate
A»h Lockhopper
Stirrer Drive
Assembly
Raw Gas
Stirrer Arms
(Raised)
Disassembly
T rolleys
¦ Steam & Air (Blast)
Ash Pit
Sweepout Arm
Grate Drive
Assembly
Ash Residue
Figure 3-3. Gasifier vessel assembly
3-3
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Figure 3-4 shows the reaction zones and associated temperature profile for fixed bed
gasification. Process gases, steam, and air pass counter-current to the solid flow through the
gasifier. As the fuel enters the gasifier from the feed auger, the heat of the gasification process
removes the surface moisture. The water exits as vapor from the gasifier immediately and
does not contribute to the gasification reactions. The fuel undergoes devolatilization producing
char and devolatilized hydrocarbons.
AIR
DRYING
GASIFICATION
OXIDATION
STEAM
OAS
CO + H20 -~C02 ~ H2
C + C02 -*¦ 2CO
C + H20-»¦ CO + H2
C + H2 -~ CH4
C + 02 -* C02
Temperature Profile
500
1500
TEMPERATURE W
3000
Figure 3-4. Reaction zones and associated temperature profiles
In the gasification region, gases react with the char residue in the following reactions:
(1) C + C02 -> 2CO
(2) C + H20 -*CO + H2
(3) C + 2H2->CH4
Heat for reactions (1), (2), and (3) is provided by the oxidation reaction (reaction 4) that
occurs between the oxygen and remaining char in the oxidation zone. Reactions (1) and (2)
are endothermic and are thermodynamically favored at temperatures over 1300 °F; however,
they are slow and rarely reach equilibrium below 2000 °F. Reaction (3) is slightly exothermic
and is favored at temperatures below 1100 °F.
The remaining carbon is consumed in the oxidation zone according to the following
reaction:
(4) C + 02->C02
3-4
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Reaction (4) is highly exothermic and rapid and, if allowed, can reach temperatures in
excess of 2400 °F. The reaction continues in the lower region of the bed until all of the carbon
in the fuel and oxygen from the incoming blast stream have been consumed.
There is also a water gas shift reaction:
(5) CO + H20 -» C02 + H2
Equilibrium for this reaction is controlled by fuel composition, fuel reactivity, steam
decomposition, blast flow, and temperature. This reaction affects the overall gas composition
of the process.
Ash, which remains after gasification, is cooled by the incoming air and steam blast, which
is distributed evenly at the bottom of the bed by the grate. Steam is used in the blast to
maintain the ash below its fusion temperature. Solid residence time in the gasifier is on the
order of several hours; whereas, gas residence time is on the order of seconds.
3.4 FUEL HANDLING SYSTEM
The fuel handling system is shown schematically in Figure 3-5. The main storage bin is
filled with the feedstock from the portable auger truck conveyor, via the feedstock elevator.
Either the portable auger or the main storage bin feeder operates simultaneously with the
feedstock elevator to fill the weigh bin to a preset amount. The gasifier is charged through one
of two lockhoppers that use a diverter gate assembly to provide a smooth and consistent flow
of feedstock to the auger. As one lockhopper is being filled with feedstock from the weigh bin,
the other is discharging into the auger and vice versa. The second lockhopper also provides
additional system reliability in the event of a feed problem in one of the lockhoppers. Delivery
rate of the auger can be adjusted to maintain near-constant feedstock bed inventory
regardless of gasifier throughput.
All operations are performed remotely from a centralized control room. A more detailed
description of the fuel handling system is included in Appendix A.
3-5
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Diverters
Bin
Lockhoppers
Main
Storage
Bin
ias Offtake
Gasifier
Auger
Auger
Figure 3-5. Gasifier fuel handling system
3.5 SAMPLING AND ANALYSIS
Samples of gas, solid, and condensible vapor streams are obtained throughout the gasifier
facility in order to quantify the composition of all input and output flow streams. The streams
are analyzed for chemical composition, and particulate loading is measured.
Figure 3-6 indicates the sampling locations used for the biomass feedstock trials as well as
the analytical capabilities of the gas sampling system. Sample Points CD and <2) were used to
obtain process gas samples for determination of gas composition, and tar, oil, and water vapor
concentrations. Hot particulate sampling was performed at the outlet of the primary cyclone to
determine particulate and alkali loading in the cleaned gas. Solids samples of the incoming
fuel, gasifier ash, and cyclone dust were taken at intervals throughout the test for composition
analysis. Detailed sampling procedures are included in Appendix B.
3-6
-------
Flare
Particulate
Fuel
Sample Point (2)
Primary
Cyclone
Fuel
Gas
Dust
Sample Point (?)
Ash
GAS
Gas Chromatograph #1
Varlan 3700
Thermal Conductivity
Column:Carbosleve S-ll
H2
N2/02/Ar
CO
CH4
C02
(% Concentrations)
Gas Chromatograph #3
Varian 3400
Flame Photometric
Column: Chromosil 310
H2S
COS
CS2
(Low Concentration)
(ppm Concentrations)
Mass Spectrometer
Perkin-Elmer
MGA 1200
Ranges
N2: 0-100%
NH3: 0-2%
CO: 0-20%
C02:0-20,100%
H2: 0-20,100%
02: 0-2%
CH4:0-10%
H2S: 0-1%
SOLIDS - Fuel, Ash, Dust, Particulate
LIQUIDS - Condensate, Tars, Oils
Figure 3-6. Schematic of sampling points in the pilot gasification facility
Fuel gas from Sample Points ® and (?) passes through a conditioning system, shown in
Figure 3-7, which cools the gas and condenses water, tars, and oils prior to analysis. Fuel gas
conditioning is required to avoid fouling of the gas chromatograph columns and the mass
spectrometer. Water, tars, and oils are collected and measured in the condensate traps to
determine their concentration in the raw gas. Proximate and ultimate analyses are performed
on the condensate, tars, and oils to determine chemical composition. The gas streams are
analyzed using one of two gas chromatographs or a mass spectrometer. In addition, gas grab
samples from either Sample Point (1) or Sample Point @ can be obtained by means of a
portable sample bomb and analyzed off-line for ammonia and hydrogen cyanide
concentrations.
3-7
-------
High-Pressure Steom
High-Pressure Nitrogen
(probe purge)
P-300 psio
flowrote=40 cc/sec
O 40 psig (to onolyzers)
;n
3/8" heated hose from Casifier Offtake
P=300 psio
flowrate«40 cc/sec
• 40 psig (to anolyzers)
¦+0-
_
3/8" heoted hose from Primary Cyclone
"~ft—(Gloss WooQ Eft
~ft—(Gloss Wool}- -~fi-
ll!
purge
Constant Temp. Both
-Maintained ot ~20T
for Controlled Condensation
' ¦' Air_ J
Air-Actuated Forward
8ellows Pressure
Volve Regulator
to
onolyzer
# 1
~0
Figure 3-7. Conditioning system: Gasifier sample trains
Hot, isokinetic, particulate sampling is performed at the outlet of the primary cyclone to
collect samples of particulate matter and determine the loading and size distribution of the
particles present in the fuel gas. Particulate samples are obtained by flowing the raw gas
through a high-temperature filter. The primary cyclone sampling system is shown in Figure 3-8.
Proximate and ultimate analyses are performed on the collected sample to determine chemical
composition, and laser particle size analysis is performed to determine particle size distribution.
Fuel, gasifier ash, and cyclone dust samples are collected at prescribed intervals during
the test. Proximate and ultimate analyses are performed to determine chemical compositions.
Mineral analysis is performed on the fuel and gasifier ash samples.
3-8
-------
HP NITROGEN SUPPLY
N2 PRESSURE
REGULATOR
0-600
PSO
IV-2
—II—
BV-t
tar a*
SAMPlKiQ Pftoec
TO T
VENT LINE
IV-9
FILTER HOUSING
S HEATER
0250-ORIFICE
PLATE
IV-3
CV-1
IV*4
BV.1.IV-2: IT VALVTTtCH e«-l WAtVtS
GM.-N*. I/TBOUTIONVALVES
EV-1.EV« PM«UR£ EQWU.IZATION V«.VtS
SM*l£ FLOW conmot VVU.VI
OP
TRANS
CV-1:
TRANS
OAPSUHELtC
Figure 3-8. Primary cyclone particulate sampling
3.6 DATA ACQUISITION, ANALYSIS, AND CONTROL
The coal gasification/cleanup facility uses a computer and a programmable logic controller
for data acquisition and control. These two systems work together, sharing data bidirectionally,
to monitor and control the test in progress. A Hewlett Packard A-900 minicomputer handles
data acquisition and is responsible for the communication link between the computers. A
General Electric Series Six programmable controller is used to control the operation of the test
facility. It is responsible for all safety interlocks, control functions, and most of the user
interactions with the test facility. A detailed description of this system is included in
Appendix C.
3-9
-------
Section 4
BIOMASS GASIFICATION TEST RESULTS
4.1 PROGRAM OBJECTIVES
GE Research and Development Center performed a pilot-scale biomass gasification study
for the purpose of evaluating the compatibility of gasified biomass feedstocks with gas turbine
power generation systems. The three fuels to be tested were bagasse, wood chips, and
switchgrass. Although GE-CRD was closely involved in developing fuel specifications,
procurement of the fuels was outside its responsibility. The study had four technical objectives:
1. To determine the composition of the product gas and gasification rate.
2. To determine the nature of the contaminants in the gas that might have a detrimental
effect on the gas turbine.
3. To measure the contaminants in the gas that might have a negative environmental
effect.
4. To determine the effectiveness of cyclones for particulate removal.
4.2 BIOMASS FEEDING TESTS
Prior to the gasification trials, cold flow testing was performed to determine the properties
of bagasse and wood chips to enable them to be fed into the gasifier through the existing coal
feed system. Switchgrass was not available and therefore was not tested. A target flowrate of
4000 Ib/hr was chosen in the off-line trials to attain a minimum operational fuel flow of
approximately 2000 Ib/hr, when the time allowed for lockhopper transient times during system
feed operation is taken into account.
Cold flow testing of bagasse and wood chips was necessary for two major reasons.
(1) Since the existing feed system, shown in Figure 3-5, was designed for relatively free-
flowing coal, some of the flow angles and equipment sizes might not be compatible with fuels
having generally poor flow characteristics such as wood chips. (2) Bagasse and wood chips
have a much lower density than coal, as shown in Table 4.1, and therefore require larger
volumetric flowrates to process a given weight.
Table 4.1 Comparison of Feedstock Density
Fuel
Density, lb/ft3
Coal
55-60
Bagasse
34
Wood chips
15
Initially, the ability of each feedstock to be fed into the weigh bin was evaluated.
Feedstocks that could be fed successfully were then flow-tested through the lockhoppers and
the auger, which was operated at maximum speed, into the gasifier. A discharge rate from the
main storage bin was also obtained, since that bin would be used as a surge hopper during
fired testing. Based on the results of these tests, minor modifications were made to the
lockhoppers, auger, and main bin feeder to "optimize" the existing hardware for use on wood
4-1
-------
chips and bagasse pellets. Replacement of the fuel system with hardware specifically
designed for biomass fuels was beyond the scope of the program. Instead, a tight fuel
specification on moisture content, size, and shape was developed to provide a fuel that had a
reasonable chance of feeding through the existing hardware.
In total, one bagasse sample and eight wood chip samples were tested to determine their
flow characteristics. All of the wood samples were supplied through the Vermont Department
of Public Service; the bagasse was supplied through Winrock International.
Table 4.2 presents a summary of the properties and flow test results for the eight wood
chip samples.
Table 4.2 Wood Chip Test Sample Data
Feed-
stock
Moisture
(%)
as rec'd
Moisture
(%)
during test
Average
Size, in.
(x 0.25 in.)
Uniformity
Auger
Gear
Ratio
Auger
Speed
rpm
Feed
Rate
(lb\hr)
Wood #1
35%
12%
1.5x1.0
Poor
5.1:1
1.4
1218
Wood #2
20%
12%
1.5x1.0
Fair
1.2:1
6.0
3870
Wood #3
46%
46%
2.5x2.5
Good
1.2:1
6.0
no flow
Wood #4
30%
30%
2.0x1.0
Fair
1.2:1
6.0
no flow
Wood #5
20%
19%
1.5x1.5
Fair
1.2:1
6.0
no flow
Wood #6
15%
<15%
1.0x1.0
Poor
1.2:1
6.0
3252
Wood #7
30%
17%
1.5x1.0
Good
1.2:1
5.8
3990
Wood #8
20%
12%
2.0x1.0
Good
1.2:1
6.0
4124
Table 4.2A Wood Chip Test Sample Data (Cont'd)
Feedstock
Source
Comments
Wood #1
NY, chip vendor
Fines and large pieces
Wood #2
Wood #1, hand sorted at GE-CRD
Still some fines
Wood #3
Vt, green wood, commercial chipper
Very clean, avg. chip size large
Wood #4
Vt, seasoned, rough-cut lumber
Many large knotted chips
Wood #5
Vt, green wood, high-speed chipper
Still not small enough
Wood #6
Wood #5, re-chipped at GE-CRD
Too many fines, no large chips
Wood #7
Vt, small PTO-driven chipper
Size good, moisture high
Wood #8
Vt, LaBranche Lumber Co., Inc, dried
Moisture low, size good
The first wood sample was supplied by a wood chip vendor in northern New York State,
who also sent a small sample of shredded bark (not included in Table 4.2, 4.2A) that did not
flow and was therefore rejected. The wood chip sample, designated Wood #1, was not uniform
in size and contained large strands of bark and sticks. Approximately 100 lbs of Wood #1 was
4-2
-------
loaded into the weigh bin for the first feed trial. The outlet valve was opened, and the sample
flowed from the bin without interruption.
The weigh bin outlet was reconnected to the lockhoppers, and a more complete flow test
was conducted through the lockhoppers and auger using 100 lbs of Wood #1. The sample
flowed from the weigh bin, through lockhopper B, and into the gasifier via the auger, operating
at maximum speed (-1.4 rpm). The flow test was successful in that no bridging occurred
although the feed was somewhat intermittent. The flow rate of Wood #1 was only 1125 Ib/hr,
which was considerably below the 4000 Ib/hr target rate.
Since the poor flow characteristics of Wood #1 were attributed in part to the presence of
large pieces of wood, a batch was hand sorted to remove the large pieces. This became Wood
#2. Removal of the large pieces only increased the flow rate to 1276 Ib/hr.
At this point it was felt that the flow rate through the auger may be the limiting factor on
overall feed rate. The auger drive gear was replaced to reduce the drive ratio from 5.1:1 to
1.2:1, thereby raising the maximum auger speed from 1.4 rpm to 6 rpm. When retested at the
higher speed, the Wood #2 feed rate increased to 3870 Ib/hr. Even though this rate
approached the 4000 Ib/hr target rate, it was decided that a drier and more consistent
feedstock was needed from a supplier to avoid on-site hand sorting.
Wood #3 sample was supplied by a commercial pulp and paper chipping operation in
Vermont. Its moisture content was higher than the previous samples, and the chip size larger
although very uniform in size. The chips were also very clean. Unfortunately, the sample did
not flow from the weigh bin, indicating that green, 3-inch top size chips were too big. Wood #4
was made from rough-cut lumber using a small chipper but contained many oversized knotted
chips throughout. The sample was not screened to remove the knotted pieces and did not feed
though the system.
Wood #5 was produced by the same method as was used for Wood #3 except that the
chipper was operated at higher speed in order to reduce wood chip size. However, the wood
chips were still too large. Wood #6 was prepared by re-chipping Wood #5 using a portable
chipper. A large quantity of fines was formed. However, with the reduced wood chip size,
improved flow properties were obtained.
A small quantity of Wood #7 was supplied by the State of Vermont. The sample was
unscreened and some hand sorting was performed before the flow test. Although the sample
did feed, production of 100 tons of woods chips by this method was deemed impractical.
Wood #8 was received from LaBranche Lumber Co., Inc, in Newport, Vermont. The chips
were produced from air-dried mixed hardwood, then over- and under-screened to a
0.25"x1.25" size. The sample chips were very uniform and clean and contained no foreign
material. The moisture content exceeded 20%. Wood #8 was found to flow well through
lockhopper B, but would not flow through lockhopper A. However, as the wood chips dried,
dramatic improvement in flow properties was noted (Figure 4-1). On the basis of these results,
Wood #8, dried to 10% or less moisture, was selected for gasification testing.
4-3
-------
5000
4500
4000
.c 3500
3000
_ 2500
jg 2000
1500
1000
WOOD #8. 10CKH0PPER B
500
11 12 13 14_ 15 16 17 18 19 20 21
Moisture, %
Figure 4-1. Flow rate of Wood Chip Sample #8 during various stages of drying
The final test on the wood samples involved a flow test through the main storage bin. This
bin is located inside the gasifier structure and has a storage capacity of slightly under 1000 ft3.
Discharge of material is controlled by a vibrating feeder operating at a fixed rate. A sample of
Wood #8 was tested and produced a feed rate of slightly over 3600 Ib/hr. When the slope of
the feeder was increased by 6 degrees, the maximum allowed by the mounting arrangement,
the feed rate increased to 4750 Ib/hr. This throughput was considered acceptable and no
further bin modifications or off-line feed tests were performed.
It should be noted that although it was necessary to select the gasification feedstock
carefully, the wood chips that were finally selected were prepared by conventional means. No
extraordinary chipping requirements were needed to achieve an acceptable feedstock.
The pelleted bagasse sample was supplied by Winrock International. The pellets were
cylindrical, 0.25 inch in diameter and approximately 1 inch long. They were compact and very
uniform and passed the flow tests through the weigh bin, lockhoppers, and auger easily. A
feed rate of 2928 Ib/hr was obtained at the original auger gearing set for coal (max 1.4 rpm).
Because bagasse fed at a higher rate for a given rpm than wood, an intermediate drive ratio of
2.3:1 was installed, which increased the maximum auger speed to 3 rpm. At this setting a
throughput of 6100 Ib/hr was obtained, exceeding the target rate of 4000 Ib/hr by a
comfortable margin.
The bagasse was then tested through the main bin after modifications to the outlet feeder
had been completed , A feed rate of 9600 Ib/hr was obtained for the bagasse tests, compared
to 4750 Ib/hr for Wood #8 at the same setting. It should be noted that the ratio of the two feed
4-4
-------
rates is approximately equal to the density ratio of bagasse to wood, or slightly over 2:1. This
test completed the off-line feed evaluations on bagasse.
In addition to changing the storage bin feeder angle and gasifier feed auger speed, the
system was modified by the installation of air-operated vibrators on both lockhoppers. If
bridging did occur, the vibrators could be operated to help break up the blockage and allow
continued operation. Additional nuclear detectors were installed just above the lower valves in
the lockhopper cone area to enable confirmation that the lockhoppers were completely empty.
If the fuel bridged in the lockhopper, the nuclear detector would continue to indicate "full" and
prevent overfilling on the next cycle. On coal, one detector located below the valve is sufficient.
4.3 GASIFIER OPERATION
Bagasse pellets and wood chips were gasified in the GE-CRD fixed bed gasifier during two
separate run weeks. In both cases, the gasifier was started from a cold condition on charcoal,
allowed to stabilize for 12 hours, and then brought up to test conditions on the biomass
feedstock. The fuel gas bypassed the cyclone and went directly to the flare during startup.
Once exit gas temperatures had reached approximately 900 °F, the gas was routed to the
cyclone. The bagasse pellets were tested first; followed by wood chips. In total, 42.5 tons of
bagasse were consumed in a test lasting 32 hours, and 83.8 tons of wood chips in a test
lasting 81 hours. These quantities represent the total amount of fuel delivered. A nominal
steam-to-air ratio of 0.4 lb/lb was used in the blast for both fuels. This value was based on the
ash fusion properties of the fuel and results of previous testing on coal and wood pellets. In
addition, the effect of operating at higher and lower steam-to-air ratios was investigated during
the wood test. The stirrer was run continuously and the grate speed adjusted to discharge ash
at a rate proportional to the gasification rate. Operating pressure was nominally 300 psig for
both runs, with a short period of operation at 200 psig during the wood chip run to explore
throughput and composition at reduced pressure.
Performance parameters characterizing the gasifier operation were calculated for a
representative steady state period during each run along with detailed mass and energy
balances. The distribution of sulfur, fuel-bound nitrogen, particulate, and alkali in the fuel gas is
discussed in detail.
The gasifier was operated during the test trials in one of four modes: startup, normal,
shutdown, and bank operation. The system configurations for these operational modes are
summarized in Figure 4-2.
4-5
-------
Flare
A. Sulfur
^ > Removal
System
Gasifier
Cyclone
Operational
Valve 1
Valve 2
Valve 3
Valve 4
Valve 5
Mode
Position
Position
Position
Position
Position
Startup
open
closed
closed
closed
pressure control
Normal
closed
open
open
closed
pressure control
Shutdown
open
closed
closed
closed
pressure control
Bank
open
closed
closed
closed
pressure control
Figure 4-2. Valve positions during gasifier test trials
4.4 GASIFICATION OF BAGASSE
4.4.1 Bagasse Properties
Table 4.3 summarizes the physical characteristics of the bagasse fuel as supplied to
GE-CRD.
Table 4.3 Characteristics of Bagasse Pellets
Source
Winrock International; Pelletized by Fiber
Resources, Inc., Pine Bluff, Arkansas
Process
dewatered; dried; roll pelletized
Storage
cardboard boxes
Size
1.0" x 0.25" dia
Avg. Moisture
8.5%
Density
34.3 lb/ft3
Uniformity
good
Comments
dusty; some broken pellets; some "fluff
4-6
-------
The bagasse pellets were supplied by Winrock International, and manufactured by Fiber
Resources, Inc., Pine Bluff, Arkansas. They were produced using a standard wood pelletizing
system and delivered in 4 ft x 4 ft cardboard boxes. Off-site warehouse storage was rented to
provide dry storage until the time of the tests since the pellets would swell up and break apart
if allowed to become wet. Incomplete pellets and fibrous material were found in several of the
boxes received.
Composition of the pelletized bagasse is listed in Table 4.4. The high volatile and oxygen
content, coupled with a low fixed carbon are typical of biomass fuels and contribute to the
fuel's high reactivity. The low percentage of sulfur results in low sulfur emissions. The fusion
temperature of the ash is relatively high and the spread between softening and fluid quite
broad. A high fusion temperature is desirable in fixed bed gasification because it reduces the
quantity of steam required in the blast for temperature control, resulting in improved
thermodynamic performance. As indicated in Table 4.5, the main constituent of the ash is
silica, which contributes to the relatively high fusion temperature.
Table 4.4 Composition of Bagasse Pellets
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
6960
6761—7159
% H20
8.47
8.40—8.54
% Moisture
8.47
8.40—8.54
%c
42.13
41.12—43.14
% Ash
7.78
5.90—9.65
% H
5.66
5.27—6.05
% Volatile
69.89
69.39—70.38
% N
0.87
0.76—0.97
% Fixed Carbon
13.87
12.56—15.18
%S
0.06
0.05—0.08
% Sulfur
0.06
0.05—0.08
% Ash
7.78
5.90—9.65
% O (diff)
35.04
34.54—35.53
Fusion Temperature of Ash, °F
Percentage of Selected Elements
in Dry Fuel
Ash Phase
reducing
oxidizing
Selected Elements
percentage
Initial Deformation
2225
2250
Na
0.09
Softening
2375
2500
K
0.52
Hemispherical
2520
2630
Fluid
2700+
2700+
4-7
-------
Table 4.5 Ash Mineral Analyses - Raw Bagasse
Ash from Dry Fuel,
weight %
Silicon dioxide
72.62
Aluminum oxide
6.23
Titanium oxide
0.47
Iron oxide
2.85
Calcium oxide
7.15
Magnesium oxide
1.42
Potassium oxide
5.91
Sodium oxide
1.20
Sulfur trioxide
0.41
Phosphorous
pentoxide
1.53
Strontium oxide
0.07
Barium oxide
0.00
Manganese oxide
0.15
Undetermined
0.00
4.4.2 Gasification Run Summary - Bagasse Pellets
Bagasse pellets were gasified at a pressure of 290 psig for a period of approximately
32 hours, consuming 42.5 tons of fuel, which was the total supplied by Winrock International
for the test. Figure 4-3 shows the gasifier pressure and air and steam flows during the test trial.
The bagasse was delivered to the site in boxes holding approximately 1000 lbs each. Prior to
the start of the test, slightly over 20 tons were loaded into the main storage bin; the remainder
was stored on and off site in the original containers. No problems were encountered during
any of the transfer operations in spite of the fact that some of the boxes contained
unconsolidated and broken material.
4-8
-------
400
- Air
Steam
Gosifler Pressure
Pressure
300
i?
M
a.
v.
3
| 200
a.
u
Air
m
D
O
100
Steam
Q V-' '»
Midnight 6 AM
6 PM Midnight
Noon
Noon
8-9 October 1991
Figure 4-3. Gasifier operating data — Bagasse
The bagasse test was initiated on October 8, following a 12-hour stabilization period in
which the gasifier was brought up to 50% load and 290 psig on charcoal at a steam-to-air ratio
of 0.4. Prior to the transfer to pellets, the stirrer was set for continuous operation at a rotational
rate of 1.0 rpm and vertical travel of 1.0 fpm lower, 0.5 fpm raise. Grate speed was adjusted to
maintain a stable temperature profile in the oxidation zone. The gas flow would normally be
directed through the cyclone prior to the transfer to the test feedstock but in this case it was
not because of the unknown behavior of the bagasse in the reactor. The cyclone was
ultimately brought on line when system operation was stabilized and gasifier offtake
temperatures reached approximately 900 °F one hour into the test.
The transfer from charcoal to bagasse was made with an initial load of 380 lbs of pellets
through lockhopper B, followed immediately by a second load through lockhopper A to provide
a uniform feed to the auger. At the time of the switchover, auger speed was set at 1.2 rpm, or
40% of maximum. By alternating lockhoppers so that one lockhopper is delivering fuel to the
auger, and adjusting the feedrate by changing auger speed to match gasifier load, a near-
continuous flow of fuel to the reactor is obtained. The procedure is used successfully on coal
and results in a uniform temperature and gas composition at the outlet.
While no problems are encountered on coal operation with this procedure, problems were
immediately experienced with discharge of bagasse. Based on the lockhopper level indicators,
which continued to indicate "full", and the increasing gasifier outlet temperature, it was
apparent that no bagasse was being delivered to the gasifier from the lockhopper. Under
normal conditions, at 30 % auger speed, residence time in the lockhopper and feed chute is on
the order of a few minutes, sufficient for the bagasse to reach 300 to 400 °F. Apparently, when
4-9
-------
exposed to these elevated temperatures, the bagasse pellets become sticky and do riot flow,
resulting in blockages at both lockhopper outlets. Since no fuel could be fed, the gasifier air
and steam rates were lowered to bank conditions while the feed system was cleared. This
change in operation is reflected by the drop in flows at 0915, as shown in Figure 4-3.
To prevent a recurrence of the problem, a batch feed mode was adopted in which each
lockhopper load was fed immediately into the gasifier via the auger operating at 100% speed,
rather than metered at a lower auger speed to provide continuous feed. The batch feeding
proved successful, but large swings in gasifier outlet temperature and gas flow resulted as
shown in Figures 4-4 and 4-5. Since the auger delivery rate at 100% speed exceeded the
capacity of the lockhoppers, the outlet temperature would drop significantly as new fuel was
fed in, then slowly rise as the gasification rate caught up with the feed rate. Figure 4-4 also
shows that the temperature swings were dampened as the gas flowed through the system. As
shown in Figure 4-6, the gas composition remained relatively constant in spite of the batch
feeding. As the run progressed, the auger speed was eventually dropped to 85%, which
allowed approximately 2-minute residence times in the lockhoppers. Lower rates were not
attempted.
1500
Cm«t Ornate
VjfvWi* IMl
- Go* to Flora
1000
hi
3
Q.
E
500
¦ i i i i i i
Offtake
Flare
Air + Steam
0
1 AM
_j . I i_
I I I L.
_i I I I ' ' '
2 AM
3 AM 4 AM
9 October 1991
5 AM
6 AM
Figure 4-4. Gas temperature profile — Bagasse
4-10
-------
• Co* to Flora
- Mr
Gos to Flore
«
a
a
n
*
o
E
*
m
>.
C/)
-J 1 L.
X
/"
I
Air
Steam
-j t_
vH-'
_l I L.
1 AM
2 AM
3 AM 4 AM
9 October 1991
5 AM
6 AM
Figure 4-5. Gasifier system flows — Bagasse
* ' *
1 AM
-i 1 >_
X
_i i i_
2 AM
3 AM 4 AM
9 October 1991
5 AM
6 AM
Figure 4-6 Gas composition data — Bagasse
4-11
-------
The blast flow was gradually increased to 1.0 lb/sec air, 0.4 lb/sec steam. At these
conditions, gasifier and feed operations appeared stable and a mass balance period was
initiated. Problems with failure of a lockhopper rupture disc and plugging of the common vent
line on both lockhoppers led to a reduction in air and steam flow approximately 4.5 hours into
the steady-state mass and energy balance period. The suspected cause of the disc failure was
fatigue, aggravated by the high cycle times and reverse pressurization that occurred
occasionally when both lockhoppers were vented simultaneously. The system remained at
bank conditions for approximately 7 hours while portions of the vent line were replaced. During
this period, a small flow of air was used to maintain the gasifier in a hot standby condition.
Pressure was held at 290 psig.
Steady-state operations were resumed at an air flow of 1.0 lb/sec and 0.4 steam-to-air
ratio, and a gasifier pressure of 290 psig. As indicated by the steep slope in air flow at 2300
(shown in Figure 4-3), the system can be brought up in load rapidly from pressurized hot bank.
Eight hours of steady-state operation followed. During this period, the stirrer was operated
continuously and the grate run at a slow but continuous speed to match the quantity of ash
being produced. The auger was operated at 85% speed for an average feed rate of 3735 Ib/hr.
Gasifier operation was generally smooth throughout this period in spite of the high fuel
throughputs achieved. No additional problems were encountered with plugging of the
lockhoppers or vent lines.
Gasifier operation was halted for approximately 8 hours later because of an interruption in
fuel delivery to the site, a problem unrelated to gasifier operation, and system flow was
reduced to a hot pressurized bank condition. After the fuel was delivered, the gasification test
was resumed and the air flow stabilized at 1.0 lb/sec. Air flow was then increased in an effort
to determine the maximum throughput obtainable on bagasse. Air was ramped up slowly to
1.2 lb/sec at a steam-to-air ratio of 0.4, at which point the system back-pressure control valve
could no longer maintain pressure below the 290 psig set point. Because of the high gas flows,
system pressure fluctuated up to 300 psig even with the valve fully open. These conditions
were maintained for approximately 4 hours, until the fuel supply was exhausted and the
gasifier was shut down voluntarily. Air and steam flows to the reactor were shut off and system
pressure reduced to atmospheric. Gasification appeared to be stable even at the high
throughputs tested, with the ultimate rate likely to be even higher. Other variations in gasifier
operating conditions such as alternate steam-to-air ratios in the blast were not investigated
because of the short duration of the test and lack of additional fuel.
No problems were encountered with discharge of ash from the system throughout the run.
The grate was generally run continuously with speed adjusted to maintain a stationary
temperature profile in the reactor. The ash was granular in consistency, with some clinker up to
3 to 4 inches in diameter occasionally mixed in. Torque requirements on both the grate and
stirrer were well within design limits throughout the run, indicating no unusual formations in the
bed.
Sampling of gas and solids was performed throughout the run. No unusual problems were
encountered with sampling of the hot fuel gas in spite of the increased hydrocarbon content.
Hot particulate sampling was performed at the outlet of the primary cyclone. Because of the
relatively short duration of the test, only a limited number of samples were obtained.
4-12
-------
Mechanical performance of the cyclone and associated equipment was satisfactory
throughout the test. The dust lockhopper was discharged at 1-hour intervals, generally yielding
from 25 to 35 lbs of a dry, fluid-like dust. An air-driven vibrator was cycled automatically during
the blowdown cycle to ensure complete discharge of the lockhopper. No problems were
experienced with deposition in the dust lockhopper or blowdown piping, in spite of the relatively
cool temperatures in these areas (-400 °F) and the low density of the dust. Post test
inspection of the cyclone discharge showed no signs of erosion and only minor buildup of
particulates on the walls. Cyclone performance is discussed further in Section 5.
4.4.3 Mass And Energy Balance Discussion - Bagasse Gasification
Detailed mass and energy balances were calculated around the gasifier for steady-state
operating periods during the bagasse gasification trials. These balances were conducted to
determine those flowrates that were not directly measured but are required for the calculation
of gasifier performance parameters. In addition, the balances provide confirmation of
measurement of mass and energy flows into and out of the gasifier, thus allowing a greater
degree of confidence in calculated performance.
The overall mass balance was made by forcing the nitrogen flow into and out of the gasifier
to balance. A dry gas flow is calculated such that the calculated nitrogen flowrate from the
normalized gas composition data is equal to the nitrogen rate, including purges, minus the
nitrogen lost through lockhopper pressurization, the tars and oils, and the dust. In these
calculations, it was assumed that one-half of the fuel-bound nitrogen in the incoming fuel
converts to NH3 and HCN; this nitrogen was not included in the mass balance. The dust, ash,
fuel, and air and steam flowrates are measured values averaged over the given time periods.
Quantities of tar and oil and water vapor in the raw gas are obtained from cumulative
measurements obtained from cooled samples of the raw gas. The energy balance uses 70 °F
as a reference temperature and higher heating values of the constituents. Both sensible and
chemical heats are calculated for each of the reactants and products of gasification.
Detailed mass and energy balances for the bagasse gasification test are presented in
Tables D.1 and D.2 in Appendix D. Table 4.6 summarizes the mass flows including outlet
temperature for the selected mass balance period 0100 through 0500 on October 9.
Corresponding gas compositions are presented in Table 4.7. Air and steam flows were held at
1.05 lb/sec and 0.41 lb/sec respectively throughout this period, and grate operation was
continuous except for the short periods when the grate was shut off during discharge of ash
from the lockhopper. The stirrer was operated continuously from the top of the fuel bed to
within 3 ft of the grate surface at a rotational rate of 1 rpm.
4-13
-------
Table 4.6 Bagasse Gasification Flows
Dry Fuel
3735 Ib/hr
Fuel Gas (wet)
8771 Ib/hr
Steam Flow
1476 Ib/hr
Gas Temperature
Air Flow
3780 Ib/hr
Gasifier Outlet
1000 °F
Gasifier Ash Discharge
278.5 Ib/hr
Cyclone Exit
950 °F
Cyclone Dust Discharge
30.1 Ib/hr
Specific Throughput
Particulate (cyclone exit)
0.35 Ib/hr
Gasifier Grate
535 lb fuel/ft2-hr
Table 4.7 Fuel Gas Composition - Bagasse
FUEL GAS COMPOSITION (wet)
Fuel Gas
Constituents
mole %
Fuel Gas
Constituents
mole %
n2
27.7
h2s
130 ppmv
co2
11.4
nh3
850 ppmv
CO
15.2
h2o
29.4
H2
12.2
Tars/Oils (TAO)
0.28
ch4
3.5
Heating Value 172 Btu/scf dry
133 Btu/scf wet
Flowrate of the bagasse averaged 3735 Ib/hr of dry fuel (4081 Ib/hr as received) during the
time period, for a corresponding specific dry fuel feed throughput of 535 Ib/hr of fuel per
square foot of grate area. This is significantly higher than normal operation on coal and reflects
the high reactivity of the bagasse. Ash discharge amounted to 278 Ib/hr, or approximately
7.5% of the dry fuel. This quantity is actually slightly less than the average ash content
measured in the raw bagasse (Table 4.5) but does fall within the variances found in ash
content between various samples of bagasse. It also indicates complete gasification of the
fuel, a result which is substantiated by the extremely low carbon content measured in the
gasifier ash as indicated in Table 4.8. A mineral analysis of the ash resulting from gasification
is included in Table 4.9 Very little change in mineral composition is noted compared to the ash
contained in the raw fuel (Table 4.5). The high moisture content of the gasifier ash is likely due
to condensation of a small portion of the blast steam in the ash sump. Average raw gas fuel
flow was 8771 Ib/hr, which includes approximately 1960 Ib/hr of water vapor and 78 Ib/hr
condensible tars and light oils along with the main constituents. Higher heating value of the
fuel gas on a dry basis was 172 Btu/scf which is higher than that typically obtained on coal.
The heating value drops to approximately 133 Btu/scf when the fuel moisture and higher order
hydrocarbons are included. The cyclone dust discharge remained relatively constant at
30 Ib/hr. This rate represents less than 1 % carryover, which is very low considering the high
4-14
-------
throughputs tested. It also suggests that the pelletizirig process used for the bagasse provided
a durable feedstock which did not break up on exposure to the gasification conditions.
Table 4.8 Gasifier Ash Composition - Bagasse
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
<100
<100
% H20
20.5
18.3-21.8
% Moisture
20.5
18.3-21.8
%c
0.18
0.11-0.22
% Ash
78.4
77.2-80.7
% H
0.11
0.04-0.28
% Volatile
1.11
0.91-1.46
% N
0.57
0.46-0.71
% Fixed Carbon
0.05
0.03-0.08
%S
0.01
% Sulfur
0.01
0.01
% Ash
78.4
77.2-80.7
% O (diff)
0.30
0.03-0.71
Table 4.9 Ash Mineral Analyses After Gasification - Bagasse
Ash from Gasification,
weight %
Silicon dioxide
71.64
Aluminum oxide
6.55
Titanium oxide
0.69
Iron oxide
3.01
Calcium oxide
6.38
Magnesium oxide
1.47
Potassium oxide
5.95
Sodium oxide
1.12
Sulfur trioxide
0.03
Phosphorous
pentoxide
1.11
Strontium oxide
0.07
Barium oxide
0.00
Manganese oxide
0.12
Undetermined
1.86
4-15
-------
Since carbon provides the major contribution to the chemical fuel value in the gas, its
satisfactory accounting is important. For this period of operation on bagasse, 1764 Ib/hr of
carbon entered the gasifier as opposed to 1503 Ib/hr leaving the system, leaving
approximately 17% unaccounted for at the outlet. A portion of the difference can be attributed
to measurement error; however, it is suspected that the major difference is due to the
presence of higher order aromatic hydrocarbons (ethane, ethylene, benzene) present in the
fuel gas stream that were not measured by the gas sampling equipment. Historic testing on
coal and biomass has shown the presence of these trace species in the gas at the 1 to 3%
level, which, if included in the bagasse balance, improve the carbon closure to within a few
percent. The trace species were not directly measured in the current test because the
available gas sampling equipment was in full use for primary and backup operation on
measurement of major constituents. The very low carbon content measured in the ash («1%)
coupled with the carbon already accounted for in the dust carryover further supports the
presence of unmeasured higher order hydrocarbons as the basis for the discrepancy. The
overall mass balance including all the element streams closes to within 1%.
Total heat entering the gasifier was approximately 31,352,000 Btu/hr compared with
26,085,000 Btu/hr leaving, which means that approximately 17% of the energy is unaccounted
for. This is considered to be an acceptable, but marginal, agreement since small errors in
measurement of major flow streams can contribute to large errors in the energy balance, and
the outlet flow from the gasifier oscillated significantly with each load of bagasse fed into the
gasifier. The suspected presence of a small percentage of higher order aromatic hydrocarbons
would improve the energy balance further by effectively raising the heating value and therefore
the energy content of the outlet gas. Overall gasification efficiency, taking credit for the
chemical and sensible energy in the gas tars and oils, is approximately 90%. This compares
favorably with operation on coal and would be expected to improve in larger systems where
wall effects and heat loss become less significant. The losses in energy conversion are
associated with the ash rejection, both thermal and chemical, with lockhopper vent losses, and
with heat loss due to hardware cooling and conduction/radiation losses from the vessel
exterior.
4.5 GASIFICATION OF WOOD CHIPS
4.5.1 Wood Chip Properties
Table 4.10 summarizes the physical properties of the wood chips used for gasification.
Table 4.11 summarizes the composition
4-16
-------
Table 4.10 Characteristics of Wood Chips
Source
State of Vermont; Chipped by
LaBranche Lumber Co., Inc; Dried
by Bob Foster, Vermont
Process
chipped/wood hog
screened
rotary-drum-dried
Storage
covered pile
Size
2.0" x 0.5" x 0.25"
Avg. Moisture
5.6%
Density
15.0 lb/ft3
Uniformity
excellent
Comments
very low fines
very clean
Table 4.11 Composition of Wood Chips
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
7983
7800 -8232
% H20
5.6
4.9—7.3
% Moisture
5.6
4.9—7.3
%c
49.1
44.0—50.6
% Ash
0.9
0.52—1.24
% H
5.7
5.6—6.0
% Volatile
79.6
78.4—80.8
% N
0.45
0.43—0.45
% Fixed Carbon
13.9
13.1—14.9
%S
0.04
0.01—0.09
% Sulfur
0.04
0.01—0.09
% Ash
0.91
0.52—1.24
% O (diff)
38.23
37.23—<39.43
Fusion Temperature of Ash, °F
Percentage of Selected Elements
in Dry Fuel
Ash Phase
reducing
oxidizing
Selected Elements
percentage
Initial Deformation
2200
2200
Na
0.02
Softening
2230
2220
K
0.05
Hemispherical
2240
2240
Fluid
2260
2330
4-17
-------
The wood chips were supplied by LaBranch Lumber Co. from mixed hardwood, rough cut
lumber, then dried to under 10% moisture in a portable rotary dryer at another site before
being delivered to GE-CRD in self-unloading chip vans. The bark content of the wood prior to
chipping was minima!
As with bagasse, the wood chips have a high volatile content indicating high reactivity. The
ash level of less than 1 % is extremely low compared with bagasse and coal. The ash fusion
temperature spread between the initial softening point and fluid point is extremely narrow, i.e.,
60 °F. This suggests that temperature control in the oxidation zone of the gasifier is extremely
critical in order to prevent ash fusion and resultant clinker formation. A mineral analysis of the
ash contained in the wood chips is given in Table 4.12. Compared to bagasse, the percentage
of silica is considerably lower and calcium higher.
Table 4.12 Ash Mineral Analyses - Raw Wood Chips
Mineral Analysis
Ash from Dry Fuel,
weight %
Silicon dioxide
33.04
Aluminum oxide
10.15
Titanium oxide
1.68
Iron oxide
6.18
Calcium oxide
27.60
Magnesium oxide
6.24
Potassium oxide
4.92
Sodium oxide
1.80
Sulfur trioxide
3.40
Phosphorous
pentoxide
1.68
Strontium oxide
0.01
Barium oxide
0.06
Manganese oxide
1.52
Undetermined
1.72
4-18
-------
4.5.2 Gasification Run Summary - Wood Chips
Approximately 84 tons of wood chips were gasified for a period of 80.5 hours at pressures
of 200 and 290 psig. Figure 4-7 shows the gasifier pressure and air and steam flows during the
test trial. Prior to the start of the test, a portion of the fuel was loaded into the main storage bin;
the remainder was stored outdoors for direct feed into the weigh bin via the portable feed
auger. The storage bin typically holds 28 tons of coal but due to the lower density of wood
chips only 15 tons could be accommodated. The chips were consumed first from the storage
pile then from the main bin. No problems were encountered in any of the chip transfer
operations although time required to load the storage bin and lockhopper feed system was
generally longer than that for bagasse pellets or coal.
«
o
9
400
300
m
Q.
I
3
200
100
0
I I I I I I I I I
I I I I I V
I I I I I
i t y I r
Ak
SWom
Gasifier P.
V
t
Air flow
jLt
111 iki
Steam flow
Noon
Oct 29
Noon Noon
Oct 30 Oct 31
29 Oct - 2 Nov 1991
Noon
Nov 1
0
a.
a.
m
*
o
E
VI
>»
(/>
Figure 4-7. Gasifier operating data — Wood Chips (290 psig)
The gasifier was prepared for operation using the same startup procedure as for bagasse.
Approximately 12 hours were allowed to bring the system to a hot, pressurized standby mode
on charcoal. While the ash fusion temperature of the wood was lower than for the bagasse,
and the spread between initial softening and fluid very narrow, it was decided to start the test
initially at the 0.4 steam-to-air ratio used for bagasse. If excessive clinker formation had
become a problem, the steam requirements to the blast could be increased as the test
progressed. The stirrer was set for continuous operation at a rotational rate of 1 rpm and
vertical travel of 1.0 fpm lower, 0.5 fpm raise. This rate was later changed to lower the vertical
travel to approximately 0.8 fpm in the downward direction. Based on the results of the feeding
tests, the auger final drive ratio was modified to increase the maximum rpm from 3 to 6. The
auger was set at 65% speed (~4 rpm) prior to the addition of the first load of wood chips. Air
4-19
-------
and steam flows were set to 50% of design. The weigh bin set point was also lowered from
350 lbs for bagasse to 150 lbs to accommodate the lower density of the chips.
The first load of wood chips was added through lockhopper B and fed without incident.
Problems were encountered with failure of the rupture disc and blockage in the lockhopper
discharge cone when attempts were made to feed through lockhopper A , the smaller of the
two feed systems. Since a sufficient fuel feed rate could not be maintained through a single
lockhopper, the gasifier was dropped in load while the problems with the A feed train were
resolved. This change is reflected in the drop in air flow, shown in Figure 4-7, shortly after
startup.
Problems with premature failure of the lockhopper rupture discs was experienced on the
bagasse and continued to be an issue with the wood chips. The problem is partially related to
biomass in that the lower density and heating values require significantly more lockhopper
cycles to feed a given energy content to the gasifier than would be required on coal. This
frequent cycling can lead to fatigue and premature failure of the discs. The problem is
compounded in the GE pilot system because the vent lines are interconnected and reverse
pressurization of the discs can occur if the lockhoppers are vented simultaneously. This
reverse pressurization severely weakens the discs, leading to rapid failure. Repiping the
lockhopper vents so that each line is independent and changing the style of the disc would
solve this problem. For the purposes of the wood test, the vent rates of the lockhoppers were
slowed and the operating procedure modified to minimize cross venting.
Once the feed system was cleared, gasifier operation was stabilized at an air flow of
0.7 lb/sec and steam-to-air ratio of 0.4. Operation at air flows up to 0.8 lb/sec were attempted,
but difficulty was experienced in keeping up with the feed requirements through the
lockhoppers. While at the higher air flow, test operation was interrupted for a period of
approximately 1 hour due to failure of the main air compressor. A standby unit was brought on
line and operation resumed at 0.7 lb/sec air flow. The ease with which the gasifier was brought
up and down in load as set points were changed or problems encountered is due in part to the
large inventory of carbon in the bed which provides a positive damping effect during transients.
Approximately 4 hours into the first mass balance period, an unusual problem occurred
with the feed system auger. The torque requirements to drive the auger, which are typically
very low, began to climb significantly until the auger stalled. As no fuel could be fed, the air
and steam flows were lowered to hot standby conditions. The auger was eventually freed by
continuously stirring in the area and increasing the torque limit on the drive. It is not clear what
caused the auger to stall although it is suspected that the fuel bed actually bridged temporarily,
causing the gasifier to become overfull and requiring the auger to force the fuel in against the
bed rather than on top of it. Once cleared, the auger continued to operate freely throughout
the remainder of the test.
Steady-state operation was resumed at 0.7 lb sec flow, 0.4 steam-to-air ratio, and gasifier
pressure of 290 psig. Approximately 40 hours of uninterrupted operation followed. During this
period the stirrer was operated continuously. The grate was operated intermittently because
very little ash was being produced. The grate plow was retracted from the bed to reduce the
amount of ash discharged per revolution in an effort to allow continuous grate rotation. The
current gearing on the grate is designed for a fuel containing 8-15% ash, typical of coal. Since
ash content of the wood chips was less than 1%, even at the lowest grate speed setting too
4-20
-------
much ash was discharged per revolution to permit continuous rotation. Modifications to the
gearing could be easily made to correct this. The ash was granular in consistency, somewhat
finer than bagasse ash, with surprisingly little clinker formation given the lower ash fusion
temperatures.
The feed auger was operated at 65% speed for an average throughput of 2130 Ib/hr.
Approximately 13 lockhopper cycles per hour were required to maintain this rate, compared to
4 or 5 for coal; the difference was due to the lower density and fuel value of the wood. No
problems were encountered throughout this period with flow of material through the
lockhoppers. The gasifier is capable of handling higher throughputs but would require larger
lockhoppers to attain the necessary feed rates.
The smaller loads and larger number of lockhopper cycles resulted in a quasi-continuos
feed to the gasifier. This more consistent feed reduced fluctuations in the offgas temperature,
Figure 4-8, and flowrate, Figure 4-9, as compared to that observed on bagasse. The
temperature swings were also significantly damped as the gas progressed through the system
to the flare. Operation of the stirrer through the complete reaction zone, as was practiced on
both bagasse and wood, also affects outlet gas temperature because varying amounts of heat
are removed from the bed, depending on stirrer position. The gas compositions, shown in
Figure 4-10, remained relatively constant, except for short periods of operation when the feed
rate temporarily fell behind and the outlet temperature approached 1200 °F, as indicated by
the spikes in N2 content and drop in combustible constituents at around 0400 and 0500.
1500
GoaMw Orttate
Cycfeiw Wat
to to Flani
Gasifier Offtake
1000
u.
Cyclone Inlet
Flare
500
Air + Steam
1 AM
3 AM
4 AM
5 AM
6 AM
Midnight
2 AM
31 October 1991
Figure 4-8. Gas temperature profile - Wood Chips (290 psig)
4-21
-------
Mr (too
Gos to Flare
Steam
Midnight 1 AM 2 AM 3 AM 4 AM
31 October 1991
5 AM
6 AM
Figure 4-9. Gasifier system flows - Wood Chips (290 psig)
CO
C02
CH4
60
50
N2
CO
30
C02
H2
20
CH4
5 AM
6 AM
Midnight
3 AM
4 AM
1 AM
2 AM
31 October 1991
Figure 4-10. Gas composition data - Wood Chips (290 psig)
4-22
-------
While gasifier operation was generally smooth throughout the 40-hour period, problems
were experienced with discharge of dust from the cyclone lockhopper system. Hourly
blowdown of the dust lockhopper yielded only a minimal discharge of very light carbonaceous
material, considerably less than would be expected based on fuel and gas flowrates. As with
the bagasse, an air-driven vibrator was cycled automatically during the letdown cycle but
apparently was ineffective in promoting solids discharge. To determine whether dust was being
removed from the gas but hanging up in the lockhopper system, a modified blowdown
procedure was adopted in which the lockhopper was discharged at pressures slightly above
atmospheric. This pressurized blowdown resulted in a significant discharge of dust, indicating
that the cyclone was removing at least some particulate from the gas stream but the dust was
either too light or too sticky to be discharged simply by gravity through the lockhopper. Unless
the dust is periodically removed from the lockhopper, it will eventually become re-entrained in
the gas stream, thereby lowering overall cyclone efficiency significantly. This problem
continued throughout the test run. The pressurized blowdown procedure required manual
intervention of the control system and was only used occasionally throughout the remainder of
the run. Cyclone performance is discussed further in Section 5.
The gasifier was dropped to a hot pressurized bank at the end of the 40-hour mass and
energy balance period for a period of 2 hours while additional fuel was delivered to the site. At
the resumption of testing, the gasifier pressure was lowered from 290 to 200 psig in an attempt
to increase the wood chip throughput by reducing the vent/pressurize cycle times of the
lockhoppers at lower pressure. Air flow was raised slowly from 0.7 lb/sec to a maximum of
0.82 lb/sec at a steam-to-air ratio of 0.35. This operating period is shown in Figure 4-7 and, in
more detail, in Figure 4-11. Air flows above 0.82 lb/sec were not attempted as difficulty was
experienced in keeping pace with the required feed rate, resulting in gasifier offtake
temperatures occasionally exceeding 1200 °F as the fuel feed rate fell behind the gasification
rate. These temperature excursions, shown in Figure 4-12, corresponded with a reduction in
the quality of gas (Figure 4-13) produced due to the increase in nitrogen concentrations
coupled with a decrease in combustible gases as a result of the fuel supply lagging the
gasification process. Larger lockhoppers would be required for higher feed rates.
4-23
-------
G«t tO RdTB
SUow flow
Gas to Flore
E 1.5
Steam ?
3 PM 4 PM 5 PM 6 PM 7 PM
I November 1991
8 PM
9 PM
Figure 4-11. Gasifier system flows - Wood Chips (200 psig)
1500
Gasifier Offtake
Cyclone Inlet
1000
u.
3
S
Flare
9
a.
E
I—
500
Air + Steam
4 PM
5 PM
6 PM
7 PM
8 PM
9 PM
3 PM
1 November 1981
Figure 4-12. Gas temperature profile - Wood Chips (200 psig)
4-24
-------
CO
H2
C02
CH4
70
60
f N2
50
40
CO
30
C02
20
~\f
0
H2
CH4
0 >—
3 PM
4 PM
5 PM
6 PM
1 Nov«mb«r 1991
7 PM
8 PM
9 PM
Figure 4-13. Gas composition data - Wood Chips (200 psig)
It should be rioted that the amount of ash removed during this period was lower than for
periods of operation at 290 psig, in spite of the higher fuel flow. It is suspected that the gas
velocities in the bed were sufficient at the lower pressure to entrain the smaller particles of ash
and carry them out the top. This theory is substantiated by the enriched ash and alkali content
of the particulate collected for this period (Section 5.3.2) and effectively limits the throughput of
the gasifier, in spite of the fact that higher gasification rates are theoretically possible.
The gasifier was shut down voluntarily at the conclusion of the low-pressure trials because
the fuel supply was exhausted. Air and steam flow were shut off to the gasifier and the system
slowly reduced to atmospheric pressure. After an overnight cool-down, the remainder of the
fuel bed was grated out.
Inspections of the gasifier after the run showed the system to be in good condition.
Inspection of the gasifier offtake piping upstream of the cyclone indicated some deposit
particularly at 90-degree bends. The material was light and easily removed but could be a
concern if buildup continued with operational time. A time-dependent rate of deposition could
not be determined from this test alone since the piping can only be inspected before and after
the run. Inspection of the cyclone gas outlet pipe revealed similar deposits. Buildup was also
found in the cyclone dust blowdown system, which is not surprising given the problems
encountered during the run with discharge of dust. This dust was removed quite easily by
lowering a cleaning chain down through the chamber, indicating that only minor modifications
might be required to provide satisfactory discharge of dust during operation. None of the
deposits appeared to be due to tar deposition, indicating that the offgas temperatures
maintained during the run were sufficient to maintain the tar in the vapor phase and minimize
4-25
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condensation. Offgas temperature cannot be controlled independently but can be biased
toward higher values by maintaining lower fuel levels in the gasifier and utilizing dry fuel.
4.5.3 Mass and Energy Balance Discussion - Wood Chip Gasification
The steady-state operating period selected for detailed mass and energy balances was
1645 on October 30 through 1900 October 31. This time period falls inside the uninterrupted
40-hour steady-state operating period during which gasifier operation was relatively constant.
Air and steam flows were held at 0.7 lb/sec and 0.28 lb/sec respectively throughout this period
and the stirrer operated continuously. Grate operation was intermittent due to the small
quantity of ash being produced. The effect of non-continuous grate operation on overall
gasification performance is negligible however.
System flows are summarized in Table 4.13 and gas compositions in Table 4.14. Details of
the heat and mass balances are included in Tables D.3 and D.4 in Appendix D. Wood chip
flowrate averaged approximately 2127 Ib/hr dry basis (2240 Ib/hr as received) throughout this
time period, which is equivalent to a specific throughput of 305 lb dry fuel /hr per square foot of
grate area. Ash discharge amounted to 24.1 Ib/hr, or slightly over 1% of the raw feedstock.
The low ash discharge rate is consistent with the average measured ash content of 0.9% in
the raw feedstock and indicates complete gasification of the fuel, a result confirmed by the
extremely low carbon content remaining in the ash after gasification, as indicated in
Table 4.15. A mineral analysis of the ash produced from gasification is included in Table 4.16.
The mineral composition is similar to that of the ash contained in the wood prior to gasification
(Table 4.12). The relatively high moisture content of the ash is due to condensation of steam
from the blast. On the average, 5680 Ib/hr of wet fuel gas was produced. The amount of dust
removed by the cyclone is small, amounting to less than 0.6% of the incoming fuel. The mass
balance data indicates that closure of carbon entering and leaving the system is within 7%,
with 1092 Ib/hr of carbon entering the system compared with 1020 Ib/hr measured leaving.
While this carbon closure shows better agreement than for bagasse, the presence of higher
order aromatics (ethane, ethylene, benzene) at the 1 to 3% range is suspected here as well,
which, if included, would drive the balance toward tighter closure. Overall closure, considering
all the input and output streams, was within 3%.
Table 4.13 Gasifier Mass Flow - Wood Chips (290 psig)
Dry Fuel
2127 Ib/hr
Fuel Gas (wet)
5680 Ib/hr
Steam Flow
1008 Ib/hr
Gas Temperature
Air Flow
2520 Ib/hr
Gasifier Outlet
1115 °F
Gasifier Ash Discharge
24.1 Ib/hr
Cyclone Exit
1050°F
Cyclone Dust Discharge
12.2 Ib/hr
Specific Throughput
Particulate (cyclone exit)
1.65 Ib/hr
Gasifier Grate
305 lb fuel/ft2-hr
4-26
-------
Table 4.14 Fuel Gas Composition - Wood Chips (290 psig)
Fuel Gas
Constituents
mole %,
wet
Fuel Gas
Constituents
mole %
n2
28.9
h2s
28 ppmv
(N
o
o
12.8
nh3
710 ppmv
CO
14.8
h2o
27.0
h2
10.9
Tars/Oils
0.23
T
X
o
4.93
Heating Value 179 Btu/scf dry
143 Btu/scf wet
Table 4.15 Gasifier Ash Composition - Wood Chips (290 psig)
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
<100
<100
% H20
33.8
22.0—41.2
% Moisture
33.8
22.0—41.2
%c
1.2
0.6—2.0
% Ash
58.7
51.3—70.9
% H
0.2
0.03—0.13
% Volatile
7.1
6.6—7.8
% N
0.1
0.08—0.12
% Fixed Carbon
0.4
0.03—0.96
%S
0.02
% Sulfur
0.02
% Ash
58.7
51.3—70.9
% O (diff)
6.1
5.3—7.0
4-27
-------
Table 4.16 Ash Mineral Analyses After Gasification - Wood Chips (290 psig)
Mineral Analysis
Ash from Gasification,
weight %
Silicon dioxide
36.48
Aluminum oxide
6.74
Titanium oxide
0.32
Iron oxide
2.72
Calcium oxide
31.86
Magnesium oxide
12.37
Potassium oxide
5.58
Sodium oxide
0.71
Sulfur trioxide
0.03
Phosphorous
pentoxide
1.28
Strontium oxide
0.10
Barium oxide
0.12
Manganese oxide
0.92
Undetermined
0.77
Total heat entering the gasifier was approximately 19,572,000 Btu/hr compared with
approximately 17,858,000 Btu/hr at the outlet, leaving 9% of the total energy not accounted
for. This is considered to be acceptable agreement given that small errors in measurement of
major flow streams can contribute to large errors in the energy balance, and that the presence
of unmeasured trace gases would effectively raise the Btu content of the outlet gas, further
reducing the gap. Based on these numbers, an overall hot gasification efficiency of
approximately 91% was obtained for the wood chips.
Gasifier flows obtained for operation at 200 psig are summarized in Table 4.17, and gas
compositions in Table 4.18. At the higher air flow of 0.82 lb sec (2952 Ib/hr), an average fuel
input of 2338 Ib/hr dry basis (2800 Ib/hr as-received) was achieved, yielding a specific
throughput of 335 lb dry fuel/hr per square foot of grate area. Corresponding gas flow
increased to 6372 Ib/hr. The ash flow actually decreased slightly in spite of the higher
throughputs due to entrainment of finer ash particles from the bed at the higher gas velocities.
The small variations in gas composition and heating value observed between the 200 and 290
psig operating points are probably due mostly to experimental variances as the expected
pressure effects in this range are small. Methane formation is favored at higher pressures for
example and does show a slight increase at 290 psig. The lower tar/oil content of the fuel gas
measured at 200 psig would not be predicted for lower pressure, however, and is felt to be due
4-28
-------
to inaccuracies resulting from the short sampling time available at the high-flow, low-pressure
set point.
Table 4.17 Gasifier Mass Flow - Wood Chips (200 psig)
Dry Fuel
2338 Ib/hr
Fuel Gas (wet)
6372 Ib/hr
Steam Flow
1008 Ib/hr
Gas Temperature
Air Flow
2952 Ib/hr
Gasifier Outlet
1180°F
Gasifier Ash Discharge
17.1 Ib/hr
Cyclone Exit
1075 °F
Cyclone Dust Discharge
12.2 Ib/hr
Specific Throughput
Particulate (cyclone exit)
1.77 Ib/hr
Gasifier Grate
335 lb fuel/ft2-hr
Table 4.18 Fuel Gas Composition - Wood Chips (200 psig)
Fuel Gas
Constituents
mole %
Fuel Gas
Constituents
mole %
n2
30.4
h2s
27 ppmv
C02
12.0
nh3
485 ppmv
CO
14.5
h2o
29.0
h2
9.2
Tars/Oils
0.09
X
o
4.5
Heating Value 169 Btu/scf dry
125 Btu/scf wet
4.5.4 Wood Chip Steam-to-Air Ratio Variations
Since gasifier performance, operability, and gas compositions are affected by the steam-to-
air ratio selected for the blast, operation at two alternate blast ratios was performed during the
wood chip gasification test. The resulting gas compositions are summarized in Table 4.19.
4-29
-------
Table 4.19 Gas Composition Variations - Wood Chips (mole % wet)
Case 1
Case 2
Case 3
Case 4
Steam/Air, lb/lb
0.40
0.50
0.35
0.35
Pressure, psig
290
290
290
200
n2
28.9
25.7
28.4
30.4
C02
12.8
12.4
12.4
12.0
CO
14.8
12.2
14.3
14.5
h2
10.9
9.4
9.7
9.2
•
-------
higher moisture content in the fuel gas of the biomass, the wet higher heating values of the
three fuels are approximately the same, 130-140 Btu/scf. The fuel gas moisture is the sum of
unreacted steam from the blast, surface moisture on the incoming fuel, and chemically bound
water released during devolatization and gasification. Biomass fuels tends to release larger
quantities of pyrolysis water than coal; hence the reason for higher overall fuel gas moisture
levels at approximately the same steam-to-air ratio and incoming fuel moisture.
Table 4.20 Comparison of Gasifier Operating Parameters
Bagasse
Wood Chips
Coal
Raw Fuel, Ib/hr
4000
2240
1860
Air Flow, Ib/hr
3780
2520
4320
Steam Flow, Ib/hr
1480
1008
1728
Steam/Air Ratio, lb/lb
0.4
0.4
0.4
Specific Throughput,
lb dry fuel/ft2-hr
535
305
240
Fuel Moisture, %
8.5
5.5
9.0
Raw Gas, Ib/hr
8770
5680
6300
Gasifier Outlet Temperature, °F
1000
1115
1084
Cyclone Exit Temperature, °F
950
1050
1025
Air/Dry Fuel, lb/lb
1.0
1.2
2.6
Raw Gas/Dry Fuel, lb/lb
2.4
2.7
3.7
TAO, wt% dry fuel
4.1
3.7
3.0
Gas HHV, Btu/scf (dry)
172
179
160
Gas Water Content, vol %
29.4
27.0
18.5
Particulate (Cyclone Exit),
ppmw
30—100
150—300
*
* Cyclone not run at 0.4 S/A ratio; Particulate 30—100 ppm typical
The specific throughput of bagasse was twice that of coal and 1.75 times that of the wood
chips, producing a higher output of fuel gas. When corrected for the lower fuel heating values
of biomass, the Btu input for the bagasse test was approximately 20% higher than on coal and
22% lower for wood gasification compared with coal. This underscores the issue of handling
large volumes of low-density fuel, and puts a premium on densification and fuel drying,
particularly in pressurized systems. The wood chips are approximately one quarter the density
of coal and, therefore, required more frequent lockhopper cycles to obtain the same specific
throughput.
4-31
-------
There is approximately 35% more tar in the biomass fuel gas than in coal. This difference
does not directly affect gasification operations as long as the system is kept hot and the tar
remains in vapor phase. On a hot basis, gasification efficiency is not adversely affected either
as credit is taken for the heating value contained in the higher order hydrocarbons.
4.6.2 Gas Composition Variations
Table 4.21 compares the gas compositions of bagasse at 290 psig and wood chips at
290 psig and 200 psig. The gas concentrations are similar for bagasse and wood chips at
290 psig, with wood chips yielding a slightly higher wet higher heating value as a result of the
lower moisture content in the fuel gas. The wood chips also produced 22% less H2S at both
pressures, due to a lower percentage of sulfur in the incoming fuel. The wood chips
gasification at 200 psig produced a gas with a lower heating value than the fuel gas produced
at 290 psig, due in part to the higher outlet gas temperature and higher water content at the
lower pressure. The concentration of NH3 is lower at reduced pressure, leading to lower NOx
emissions at the turbine
Table 4.21 Gas Composition Comparison (mole % wet) - Cyclone Exit
Bagasse
(290 psig)
Wood Chips
(290 psig)
Wood Chips
(200 psig)
N2
27.7
28.9
30.4
CM
o
o
11.4
12.8
12.0
CO
15.2
14.8
14.8
h2
12.2
10.9
9.2
ch4
3.5
4.93
4.5
H2S, ppmv
130
28
27
NH3, ppmv
850
710
485
H20
29.4
27.0
29.0
TAO
0.28
0.23
0.09
Alkali, ppmw
0.285
0.516
1.035
Temperature, °F
950
1050
1075
HHV, Btu/scf (wet)
133
143
125
4-32
-------
Section 5
GAS STREAM CONTAMINANTS
5.1 GENERAL DISCUSSION
Contaminants remaining in the gas stream after cyclone cleanup which are of concern to
the gas turbine include particulate matter and alkali metals. Contaminants which must be
controlled to meet environmental restrictions include fuel-bound nitrogen and sulfur.
Particulates carried out of the gasifier with the fuel gas must be removed prior to
combustion in order to minimize particulate emissions in the turbine exhaust and to protect the
gas turbine from erosion, corrosion, and deposition associated with particulate matter.
The biomass gasification pilot plant study utilized a single stage of cyclone operating at the
gasifier temperature and pressure for particulate removal. This approach provides minimal
particulate removal efficiency, but is also the simplest and least costly approach if successful.
Cyclone efficiency was determined by measuring the quantity of dust captured and removed
by the cyclone and the quantity remaining in the fuel gas stream using the hot particulate
sampling system. For both feedstocks, cyclone dust and fuel gas particulates were analyzed
for comparison with the feedstock and to assess potential detrimental effects on the
downstream equipment and on the gas turbines. Particulate size distributions were also
determined.
The level of alkali in the fuel gas is important because corrosive alkali species (i.e., sodium
and potassium) are transported through the system to the turbine, where, following
combustion, they cause corrosion of the hot gas path components. Gas turbine specifications
require that alkali levels be controlled to low limits to minimize this attack.
Fuel-bound nitrogen (FBN) is an important component of the fuel gas because it is
potentially converted to NOx during combustion. FBN components in the fuel gas are related to
the FBN content of the gasification feedstock and gasification conditions. FBN in gasified coal
is predominantly in the form of ammonia, with lesser amounts in other forms, such as HCN,
phenols, and condensible hydrocarbons. For gasification systems incorporating high-
temperature cleanup, these species will remain in the fuel gas; for low-temperature water-
scrubbed systems, FBN will be removed.
Sulfur in the fuel gas stream contributes to emissions of SOx during combustion. Sulfur
levels tend to be significantly lower in biomass fuels than in coal and therefore may not require
further controls.
5.2 BAGASSE FUEL GAS CONTAMINANTS
5.2.1 Particulates
Based on measurements of cyclone dust catch and hot isokinetic gas samples, the
average particulate loading of the fuel gas entering the cyclone was 3400 parts per million by
weight (ppmw), and that of the clean fuel gas was 40 ppmw. This yields an overall particulate
removal efficiency for the cyclone of nearly 99% in the selected steady-state mass and energy
balance period on bagasse.
5-1
-------
Analyses of the particulates yields some interesting data. Tables 5.1 and 5.2 show
analyses for the particulates captured and removed by the cyclone (cyclone dust) and those
remaining in the fuel gas (gas particulate). Compared with the bagasse feedstock, the cyclone
dust has a substantially lower volatile content and higher ash content as would be expected for
this highly volatile feedstock. The cyclone dust ash content is also substantially higher than
that for the gas particulates, indicating that the mineral matter is concentrated in the larger,
denser particles which are more readily captured by the cyclone. It is also suspected that some
oxidation of the cyclone dust took place in the collection barrel after blowdown, as evidenced
by the high temperature of the barrel during the test. The problem was minimized in the wood
test by installation of a nitrogen purge.
Table 5.1 Cyclone Dust Composition - Bagasse
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
8803
6718-10133
% H20
2.37
0.97-4.02
% Moisture
2.37
0.97-4.02
%C
57.3
45.2-66.2
% Ash
32.6
24.0-48.6
% H
1.8
1.5-1.9
% Volatile
13.0
8.9-16.4
% N
1.63
1.40-1.87
% Fixed Carbon
52.0
41.6-58.5
%S
0.11
0.06-0.16
% Sulfur
0.11
0.06-0.16
% Ash
32.6
24.0-48.6
% 0 (diff)
4.31
2.29-6.67
% Na
0.23
% K
1.15
5-2
-------
Table 5.2 Gas Particulate Composition - Bagasse
Proximate Analysis
Ultimate Analysis
Btu/lb
12486
% H20
1.42
% Moisture
1.42
%c
*
% Ash
13.46
% H
*
% Volatile
28.7
% N
% Fixed Carbon
56.5
%S
0.11
% Sulfur
0.11
% Ash
13.46
% O (diff)
*
*Sample quantity too small
% Na
0.12
to complete analysis
% K
0.57
Particle size analysis was performed on the primary cyclone particulate and dust using a
laser particle size analyzer. As seen in Figure 5-1, for the bagasse run, the cyclone dust
particles are larger than the particulate remaining in the gas stream. Since the pilot cyclone is
rated to have a high removal efficiency for particles larger than 10 fim, it is not surprising to
find that the median size of particles remaining in the gas stream is under 10 urn.
10.000 T
/A
9.000 -- Median * 9 microns
8.000 --
Median ¦ 17 microns
7.000 -
IE
IU
m
2
=>
Z
>
a
*
5.000 -
Particulate
4.000
Cyclone Dust
3.000 -
1.000 *
0.000 ¦+
1
1000
100
10
PARTICLE SIZE, microns
Figure 5-1. Particle size analysis of particulate and dust for Bagasse gasification
5-3
-------
Based on the particulate loading and particle size measurements, as well as the particulate
analyses, it is possible to estimate the characteristics of particulates entering the turbine. If it is
assumed that the particles entering the combustor are completely burned so that only ash exits
from the combustor, and if it is also assumed that the ash particles do not agglomerate, then
the particle loading entering the turbine is approximately 1 ppmw and the average size is less
than 2 microns. At these sizes, particulate erosion should not be of concern.
Thus, from a purely physical standpoint, a single cyclone is an effective cleanup device for
gasified bagasse. It should be noted, however, that for other types of gasifiers and for other
forms of bagasse feedstock, particulate capture requirements may be different.
5.2.2 Alkali Metals
As can be seen from the composition data in Table 4.9, potassium comprises 5.9%, and
sodium 1.1% (as oxides) of the mineral matter in bagasse. If all of the potassium and sodium
in the bagasse fuel were to pass into the turbine, severe hot corrosion would be expected.
During gasification, the bulk of the alkali metals are removed with the gasifier bottom ash.
However, some alkali metal is carried out of the gasifier with the particulates. Because of the
low outlet temperature of the fixed bed gasifier, no vapor phase alkali metal species will be
present in the fuel gas. Thus the effectiveness of the particulate removal device dictates the
effectiveness of alkali metal control.
Sodium and potassium analyses were performed on particulates captured from the fuel
gas stream exiting the cyclone. These results, summarized in Table 5.3, indicate that the alkali
metal loading in the fuel gas is approximately 285 parts per billion (ppb) by weight. The major
contribution comes from alkali contained in the particulate. At this level, about 50 ppb of alkali
would exit the combustor and enter the turbine. Current gas turbine specifications require that
the products of combustion contain less than 20 ppb of alkali. This specification was based on
sodium-containing liquid fuels. Since potassium, in combination with sodium, is likely to form a
more corrosive deposit than sodium alone, alkali metal specifications for potassium-containing
fuels may be more stringent.
Improved particulate removal or, possibly, water scrubbing will be required to achieve the
required alkali metal levels in the fuel gas. An alternative approach to achieving adequate
corrosion life is to apply corrosion-resistant coatings to turbine components.
5-4
-------
Table 5.3 Alkali Distribution - Bagasse
Dry Fuel
Na
K
3735 Ib/hr
3.502 Ib/hr
19.360 Ib/hr
Fuel Gas (wet)
Na
K
8771 Ib/hr
0.0004 Ib/hr
0.0020 Ib/hr
Steam Flow
1476 Ib/hr
Condensate/TAO
Concentration*
Ash*
Na*
K*
Total Alkali*
2112 Ib/hr
24.1 wt%
0.06 wt %
3.2 ppbw
1.5 ppbw
4.7 ppbw
Air Flow
3780 Ib/hr
Gasifier Ash Discharge
Na
K
278.5 Ib/hr
2.91 Ib/hr
17.30 Ib/hr
Particulate
Concentration*
Ash*
Na*
K*
Total Alkali*
0.35 Ib/hr
39.9 ppmw
5.4 ppmw
0.05 ppmw
0.23 ppmw
0.28 ppmw
Cyclone Dust Discharge
Na
K
30.1 Ib/hr
0.068 Ib/hr
0.347 Ib/hr
Total Alkali
(condensate and particulate): 0.285 ppmw
*AII concentrations are of wet Fuel Gas.
5.2.3 Fuel-Bound Nitrogen
Table 5.4 shows the FBN content of gasified bagasse and the FBN content of gasified
Illinois #6 coal for comparison. Also shown are estimates for total NOx emissions resulting from
the conversion of FBN to NOx and thermal NOx production in conventional gas turbine
combustors.
Table 5.4 Fuel-Bound Nitrogen - Bagasse and Coal
Bagasse
Illinois #6
Coal
Fuel-Bound Nitrogen, wt % as N
0.9
1.5
Fuel Gas - ppmv as N
NH,
non NH3
850
2100
6000
437
Estimated NOx, ppmv at 15% 02
175-280
5-5
-------
Unlike the FBN in gasified coal, the FBN contained in gasified bagasse is largely non-
ammonia. Based on the chemical composition of the bagasse fuel gas, it is likely that the non-
ammonia FBN compounds are in the form of hydrogen cyanide (HCN), amines, such as methyl
amine (CH3NH2), and pyridines, such as C5H5N.
There is extensive technical literature exploring the conversion of these non-ammonia FBN
species to NOx in both premixed and non-premixed (diffusion flame) flames. (See A.F.
Sarofim, G.C. Williams, M. Modell, and S.M. Slater, "Conversion of fuel nitrogen to nitric oxide
in premixed and diffusion flames," AiChE Symposium Series, vol. 7, no. 148, 1975, pp. 51-61.)
The literature concludes that the conversion of these FBN compounds to NOx is insensitive to
the form of the nitrogen compound. Therefore estimates regarding the production of NOx from
bagasse product gas containing non-ammonia FBN will be based on GE experimental data for
the conversion of ammonia to NOx in experimental low-Btu lean diffusion flame combustors.
The conversion data indicate that FBN conversion is expected to be in the range of 30% to
50%. In addition to NOx produced by conversion of FBN, it is estimated that the thermal NOx
production at these temperatures and fuel composition will be approximately 10 ppm (at 15%
oxygen). It should be noted that the overall NOx emission estimates, shown in Table 5.4, are
speculative and highly dependent on specific combustor design. Combustion testing will be
required to establish actual emission levels. The requirement for NOx emissions from gas
turbines will be dependent on the location of the plant site, with emissions as low as 9 ppm
required for some areas such as Southern California, and higher limits (up to 75 ppm) in other
areas, again dependent on state and local regulations. Thus, it appears that improvement in
technologies to reduce the NOx from biomass IGCC will be required for plants located in the
United States.
Currently GE and other organizations are developing low NOx combustors for fuels
containing FBN. One approach to this development is the use of rich-quench-lean (RQL)
technology This is a staged combustion approach with a rich first stage and a rapid quench
using secondary air followed by a lean burnout stage. Theoretical predictions indicate that RQL
combustion can achieve FBN conversion rates as low as 10%. It should be recognized that this
technology is in its early stage of development and will require substantial additional
development before it can be offered as a commercial product.
A more speculative approach to reducing the FBN in the fuel gas is the use of catalytic
materials to promote the reduction of FBN species to their equilibrium levels. These species
are generally produced by gasifiers at levels that are much higher than their equilibrium value.
Thus, by bringing the composition of the fuel gas to chemical equilibrium, the concentration of
FBN can be reduced. This approach will require development of advanced catalytic materials
that are insensitive to the "poisons," such as H2S and chlorides, contained in fuel gas at low
levels . This technology is not available commercially.
Alternately post combustion NOx cleanup technologies, such as selective catalytic
reduction (SCR), are commercially available. SCR can reduce NOx levels in the exhaust gas
products by 90%. However this approach is expensive, has a moderate performance penalty
associated with the addition of backpressure to the gas turbine, and requires the use of
ammonia, which is released to the environment in small quantities.
5-6
-------
A more conventional approach to reducing FBN in the bagasse fuel gas is cooling the
product gas and water scrubbing to remove particulate materials as well as the FBN
compounds. This approach removes all of the particulate material and the associated alkali
metal contaminants as well. However this approach would create several other problems
including a reduction in plant efficiency resulting from the loss of the sensible energy of the
fuel gas (estimated at approximately 5% reduction in plant efficiency). Scrubbing the fuel gas
also removes the tars and oils and their associated heating value from the fuel gas (which
could amount to 10% of the heating value of the fuel). Safe disposal of the contaminated
scrubber water represents a significant environmental problem, requiring additional plant
equipment. Although the process of cooling and water scrubbing the fuel gas will remove some
contaminants from the fuel gas, the resulting impact on plant efficiency and plant capital cost
will be detrimental.
In summary, many solutions exist to reduce NOx emissions from biomass IGCC plants;
however, a detailed systems tradeoff study could identify the best solution for a specific plant
site. It should be noted that the results of similar tradeoff studies for coal gasification plants
indicate that the cost and efficiency benefits of hot gas cleanup outweigh the capital cost and
efficiency penalties of competing approaches.
5.2.4 Sulfur
Bagasse contains 0.06% sulfur on the average, which results in fuel gas containing only
130 ppm of H2S (Table 4.7). This low value can be compared with a typical medium-sulfur coal
content of 1.6% S, which results in 3000 ppm of H2S in the fuel gas. Because of the low sulfur
content, the SOx emissions from bagasse-based gas turbine power generation will be less
than those of a typical coal-burning steam plant with a high-efficiency flue gas scrubber.
Details of the distribution of sulfur in the solids, tars, oils, and condensate can be found in
Table 5.5. Closure of the sulfur balance around the system is within the variances found in the
individual process streams.
Table 5.5 Sulfur Distribution - Average Values for Bagasse
Dry Fuel
Sulfur in Fuel: Average
Range
3735. Ib/hr
2.45 Ib/hr
(2.04-3.26 Ib/hr)
Fuel Gas (wet)
H2S-S
8771 Ib/hr
1.51 Ib/hr
±.02
Steam Flow
1476 Ib/hr
Condensate/TAO
S*
2112 Ib/hr
0.40 Ib/hr
±.10
Air Flow
3780 Ib/hr
Gasifier Ash Discharge
S
278.5 Ib/hr
0.04 Ib/hr
Particulate
S*
0.35 Ib/hr
0.001 Ib/hr
Cyclone Dust Discharge
S
30.1 Ib/hr
0.05 Ib/hr
Total Sulfur (condensate + particulate):
1.91 Ib/hr ±.10 217ppmw
*AII concentrations are of wet Fuel Gas.
5-7
-------
5.3 WOOD CHIP GAS STREAM CONTAMINANTS
5.3.1 Particulates
Substantially larger quantities of particulates were contained in the gasified wood chip fuel
gas than for bagasse or coal. Particulate levels in the product fuel gas were 290 ppmw for
290 psig operation and 280 ppmw at 200 psig. Since the estimated particulate loading for the
fuel gas was approximately 2000 ppm, cyclone efficiencies were only of the order of 85%. One
reason for poor cyclone efficiencies is the low density of the particulates carried over from the
gasifier.
The bulk density of the cyclone dust was measured to determine the cyclone's
effectiveness in removing solids from the hot fuel gas. The measurement was made by placing
a known weight of the sample in a graduated cylinder and lightly tapping the cylinder at least
30 times or until the sample did not significantly change volume when visually inspected. Since
the measurements were made after the samples had been in containers for a few days, the
measured density may not be an accurate indication of the density of the particles in the hot
gas stream but are useful for purposes of comparison. Results are presented in Table 5.6,
along with a comparison value for coal. Bagasse particulate samples were not analyzed for
bulk density because insufficient amounts of sample were available after the chemical
analyses were performed.
Table 5.6 Solid Matter Bulk Density
Gas Stream
Particulates, g/cc
Cyclone
Dust, g/cc
Coal
0.101
0.495
Wood Chip
0.046
0.071
Bagasse
not measured
0.209
As can be seen from Table 5.6, the density of the particulates associated with wood chips
was extremely low compared with bagasse and coal. Since cyclones are inertia! separation
devices, it is not surprising that particulate removal efficiencies were lower for the wood chip
gasification run.
Another cause of poor cyclone performance was the difficulty of removing captured
particulates from the cyclone due to their low density and poor flow properties. Since captured
particulates were not being discharged from the cyclone properly, it is possible that some
particulates were being re-entrained into the fuel gas stream, thereby lowering overall removal
efficiency.
A size analysis of two samples of particulate matter collected after the cyclone during the
wood chip run are shown in Figure 5-2. The closeness of the distribution curves for Samples 5
and 6, taken under steady-state operation of the system, indicates that there is little variation in
particulate size during base operation of the gasifier. The median particle size of 10 microns is
slightly larger than that measured for bagasse. This would be expected given the lower density
of the wood particulate.
5-8
-------
10.000
Median Size = 10 microns
9.000 -
7.000 +
£ 6.000 T
z 5.000 --
4.000 --
3.000 -
ZQOO
0.000
1 10 100 1000
PARTICLE SIZE, microns
Figure 5-2. Particulate size analysis — Wood Chips
A comparison of the size distributions for particulate matter from the bagasse and wood
tests is presented in Figure 5-3. The shapes of the distribution curves are similar.
10.000 T
9.000 --
Median Size = 9-10 microns
8.000 --
7.000
E
Ui
m
Z
3
Z
6 000 -
5.000 --
>
a
*
4.000 --
WOOD CHIPS
BAGASSE
3.000 --
2.000 --
1.000
0.000
1 10 100 1000
PARTICLE SIZE, microns
Figure 5-3. Particulate size analysis — Bagasse vs. Wood Chips
5-9
-------
Tables 5.7 and 5.8 show the compositions of the captured dust and particulate remaining
in the fuel gas. The fuel gas particulates have lower ash content than the cyclone dust, but
higher ash than the wood chip feedstock due to devolatilization in the gasifier. Clearly, more
effective means for particulate removal will be required for a wood-chip gasification system.
Options include more effective cyclones, filters, or water scrubbing.
Table 5.7 Cyclone Dust Composition - Wood Chips (290 psig)
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
13644
13447-14175
% H20
1.13
0.47-2.04
% Moisture
1.13
0.47-2.04
%c
87.8
87.4-88.2
% Ash
7.0
5.2-7.6
% H
1.5
1.3-1.9
% Volatile
21.3
14.7-31.0
% N
0.87
0.72-1.25
% Fixed Carbon
70.6
63.4-76.8
%S
0.06
0.03-0.07
% Sulfur
0.06
0.03-0.07
% Ash
6.96
5.20-7.63
% 0 (diff)
1.6
0.03-3.7
% Na
0.115
% K
0.556
Table 5.8 Gas Particulate Composition - Wood Chips (290 psig)
Proximate Analysis
Ultimate Analysis
average
range
average
range
Btu/lb
14424
13874-15028
% H20
1.75
0.47-2.40
% Moisture
1.75
0.47-2.40
%c
92.3
90.7-95.2
% Ash
2.3
0.9-3.6
% H
1.8
1.4-2.1
% Volatile
21.0
20.0-22.5
% N
1.28
1.17-1.37
% Fixed Carbon
75.0
73.2-76.1
%S
0.11
0.03-0.21
% Sulfur
0.11
0.03-0.21
% Ash
2.3
0.9-3.6
% O (diff)
0.5
0.0-1.75
% Na
0.03
% K
0.15
5-10
-------
5.3.2 Alkali Metals
The alkali metal content of the wood particulates remaining in the gas stream is
approximately one-fourth that for bagasse. However, because of the high particulate loading of
the fuel gas, its total alkali metal level is twice that for bagasse, as indicated in Table 5.9. Like
bagasse, the ratio of potassium to sodium is high. Improved particulate control, which will be
required to reduce particulate loadings at the turbine inlet, will also reduce alkali metal
concentrations. At the level of 0.516 ppmw total alkali measured for the wood gas at 290 psig,
about 90 ppb of alkali would exit the gas turbine combustor and enter the turbine, as compared
to the current gas turbine limit of 20 ppb alkali.
Table 5.9 Alkali Distribution - Wood Chips (290 psig)
Dry Fuel
Na
K
2127 Ib/hr
0.338 Ib/hr
1.029 Ib/hr
Fuel Gas (wet)
Na
K
5680 Ib/hr
0.0005 Ib/hr
0.0024 Ib/hr
Steam Flow
1008 Ib/hr
Condensate/TAO
Concentration*
Ash*
Na*
K*
Total Alkali*
1220 Ib/hr
21.5 wt%
0.05 wt %
8.1 ppbw
0.1 ppbw
8.2 ppbw
Air Flow
2520 Ib/hr
Gasifier Ash Discharge
Na
K
24.1 Ib/hr
0.111 Ib/hr
0.974 Ib/hr
Particulate
Concentration*
Ash*
Na*
K*
Total Alkali*
1.65 Ib/hr
290 ppmw
5.0 ppmw
0.086 ppmw
0.422 ppmw
0.508 ppmw
Cyclone Dust Discharge
Na
K
12.2 Ib/hr
0.014 Ib/hr
0.069 Ib/hr
Total Alkali
(condensate + particulate): 0.516 ppmw
*AII concentrations are of wet Fuel Gas.
Table 5.10 shows the alkali distribution at 200 psig gasifier operation. The overall wood
chip throughput was increased; however, the gasifier ash discharge decreased, indicating that
ash was being entrained in the fuel gas stream. As a result, only 45% of the alkali was
removed in the gasifier ash discharge, the remainder exiting with the fuel gas due to the higher
bed velocity. The ash content in the particulate at 200 psig operation was double the ash
content at 290 psig operation. The alkali content in the fuel gas, therefore, also doubled.
Table 5.10 summarizes the alkali loading in the gasifier system at 200 psig. This would indicate
that the upper limit on gasification throughput is dictated by entrapment of ash from the fuel
bed rather than by the gasification reactions themselves. Running at lower steam-to-air ratios
to produce a coarser, denser ash would help minimize carryover, although the operability
window provided by the ash fusion properties is rather narrow.
5-11
-------
Table 5.10 Alkali Distribution - Wood Chips (200 psig)
Dry Fuel
Na
K
2338 ib/hr
0.418 Ib/hr
1.273 Ib/hr
Fuel Gas (wet)
Na
K
6372 Ib/hr
0.0011 Ib/hr
0.0055 Ib/hr
Steam Flow
1008 Ib/hr
Condensate/TAO
Concentration*
Ash*
Na*
K*
Total Alkali*
1406 Ib/hr
22.1 wt%
0.04 wt %
4.5 ppbw
0.1 ppbw
4.6 ppbw
Air Flow
2952 Ib/hr
Gasifier Ash Discharge
Na
K
17.1 Ib/hr
0.079 Ib/hr
0.691 Ib/hr
Particulate
Concentration*
Ash*
Na*
K*
Total Alkali*
1.77 Ib/hr
278 ppmw
10.1 ppmw
0.174 ppmw
0.856 ppmw
1.030 ppmw
Cyclone Dust Discharge
Na
K
12.2 Ib/hr
0.014 Ib/hr
0.069 Ib/hr
Total Alkali
(condensate + particulate): 1.035 ppmw
*AII concentrations are of wet Fuel Gas.
5.3.3 Fuel-Bound Nitrogen
Table 5.11 shows the FBN content of the gasified wood chips. Also shown are estimates
for NOx emissions resulting from the conversion of FBN to NOx in conventional gas turbine
combustors.
Table 5.11 Fuel-Bound Nitrogen - Wood Chips
Fuel-Bound Nitrogen, wt % as N
0.5
Fuel Gas — ppmv as N
nh3
non NH3
710
1015
Estimated NOx, ppmv at 15% 02
100-160
Because of the lower level of nitrogen in the wood chips, FBN levels in the fuel gas are
substantially lower than for bagasse. Consequently, NOx emissions are expected to be lower.
However, as in the case of bagasse, the conversion of FBN to NOx during combustion is not
well known and any emission estimates are highly speculative.
5-12
-------
5.3.4 Sulfur
The wood chips contained 0.04% sulfur on the average. The variation between samples
was relatively high, ranging from 0.01 to 0.09% (Table 4.11). The average H2S content of the
fuel gas at 290 psig was 28 ppmv (Table 4.14), significantly lower than the 130 ppmv obtained
for bagasse, and orders of magnitude lower than the 3000 ppmv for gasified medium sulfur
coal. Details of the specific distribution of sulfur in the solids and product gas are shown in
Table 5.12. It should be noted that a larger contribution to total sulfur comes from the tars and
oils and condensate than from H2S. Also, the ratio of total sulfur in the fuel gas, including
contributions from H2S, particulate, higher order hydrocarbons and condensate, to that
obtained from bagasse is approximately 0.6, or very nearly the ratio of sulfur contained in the
parent fuels. The discrepancy in closure of the balance between sulfur entering in the fuel and
that exiting in the gas is within the variation in sulfur content of the wood chips. Considering
the total sulfur in the fuel gas, sulfur emissions in the form of S02 from the gas turbine exhaust
would be expected to be in the range of 45 ppmv (corrected to 15% 02, dry).
Table 5.12 Sulfur Distribution - Average Values for Wood Chips (290 psig)
Dry Fuel
Sulfur in Fuel: Average
Range
2127 Ib/hr
1.06 Ib/hr
(0.22-2.01 Ib/hr)
Fuel Gas (wet)
H2S-S
5680 Ib/hr
0.21 Ib/hr
±.02
Steam Flow
1008 Ib/hr
Condensate/TAO
S*
1220 Ib/hr
0.49 Ib/hr
±.36
Air Flow
2520 Ib/hr
Gasifier Ash Discharge
S
24.1 Ib/hr
0.009 Ib/hr
Particulate
S*
1.65 Ib/hr
0.004 Ib/hr
Cyclone Dust Discharge
S
12.2 Ib/hr
0.003 Ib/hr
Total Sulfur (condensate + particulate):
0.71 Ib/hr±.36 125 ppmw
*AII concentrations are of wet Fuel Gas.
5-13
-------
Section 6
CONCLUSION
Gasification tests were conducted on bagasse and wood chips in the fixed-bed coal gasifi-
cation pilot plant located at the GE Research and Development Center in Schenectady, New
York. Gasification runs in which 42.5 tons of bagasse pellets and 83.8 tons of dried wood chips
were consumed were performed over periods of 32 hours and 81 hours, respectively. Gasifi-
cation was performed at 20 atmospheres, and the fuel gas cleanup system consisted of a single
cyclone. The following technical conclusions are based on results from feeding trials and
gasification runs.
Feeding of biomass into a pressurized gasifier can be accomplished as long as either the
biomass feedstock or the pressurization system is specified appropriately. The feedstock used
in these gasification runs required careful selection and, in the case of bagasse, pelletization
was needed because of the design of the lockhopper system, which was designed for feeding
coal. Although many wood chip samples were evaluated before an appropriate feedstock could
be found, the final material was processed using conventional means.
Both biomass materials were highly reactive and easily gasified at substantially higher rates
than can be achieved with coal. The biogas was slightly higher in heating value than coal gas,
and its composition indicates that its combustion properties are compatible with gas turbine
combustors. However, because of the low density — especially for wood chips — of the fine
particles entrained in the product gas, the cyclone was unable to reduce particulate loadings to
levels required by gas turbines. The alkali metals contained in these fine particles were at a level
substantially in excess of the gas turbine fuel gas specification. Thus, improved particulate
removal through cyclone modification, the addition of a filtration system, or wet scrubbing may
probably be required. More efficient particulate removal technologies are well within the state-of-
the-art.
An extremely attractive feature of biomass is its potential for low emissions. Sulfur loadings
are substantially lower than for medium- and low-sulfur coals. Indeed, the sulfur levels are lower
than the levels for medium-sulfur coal burning facilities with high-efficiency flue gas
desulfurization systems. Fuel bound nitrogen (FBN) levels, which are of concern because of the
conversion of FBN to NOx during combustion, are lower than for coal. However, the FBN
distribution between ammonia, cyanides, and nitrogen-containing organics is quite different than
for coal. In order to meet stringent NOx emission requirements (less than 10 ppm), it may be
necessary to implement one or more of the following advanced technologies: (1) removal of
FBN compounds by scrubbing, (2) catalytic decomposition, (3) advanced low NOx combustion
technology, and (4) post-combustion cleanup. Each of these approaches has a cost and
efficiency impact, but the best approach can be identified by system tradeoff studies of the
specific equipment that will be utilized.
One of the key reasons for interest in biomass as a power generation feedstock is that the
emissions of CO2, a greenhouse gas, are compensated for by the absorption of atmospheric
CO2 by the biomass during its growth cycle.
It can be concluded that biomass is a viable feedstock for the gasification/gas turbine power
generation system. Implementation does not require development of breakthroughs in gasification or
turbine technology. However, there is also ample opportunity for efficiency improvement, cost
reduction, and further reduced environmental impact through advances in technology.
6-1
-------
Appendix A
GASIFIER/CYCLONE
A.1 GASIFIER REACTOR
The gasifier vessel is shown in a cutaway side-section view in Figure A-1. The vessel
consists of a shell 5 feet (OD) x 24 feet with 1-inch thick walls and hemispherical end caps of
285 Grade C steel.
Fuel Feed
Stirrer Drive
" Assembly
LockhoppcrB
Lockhopper A
Raw Gas
Stirrer Arms
* (Raised)
Auger Feeder
CD
Disassembly
Trolleys
Grate
¦ Steam 8. Air (Blast)
AshPit
Swcepout Arm
Grate Drive
Assembly
Ash Lockhopper
Ash Residue
Figure A-1. Gasifier vessel assembly
A-1
-------
The shell was constructed in four sections that are joined together with 5-foot flanges,
which allow easy disassembly for repair or inspection. The shell is protected from the high
temperatures of the gasification process by two layers of castable refractory material: a
hardcast, high-alumina inner layer, 3.75 inches thick, and an insulating outer layer, 8.75 inches
thick, of Litecast 50 refractory. The effective inner diameter of the vessel with these layers is
35 inches.
The gasifier midsection is enclosed in a water-cooled jacket for overtemperature protection.
The jacket is constructed of 0.75-inch steel in a four-quadrant design and covers the entire
outside of the midsection.
A cooling water supply system pumps water from the cooling tower loop to the jacket. Four
orifices in the lines leading to each quadrant of the jacket measure the coolant flow rate. In
addition, thermocouples in the water lines allowed for measurement of the temperature of the
water entering and leaving the jacket so that the heat loss from the gasifier into the jacket
(needed for the gasifier energy balance calculations) could be calculated.
A 2000-millicurie nuclear bed level monitor is installed on the gasifier vessel to provide a
measure of the bed height in the gasifier. The unit is designed to provide a continuous readout
of bed level over a 2-foot span at a location 10 to 12 feet above the grate pan; 11 feet is the
nominal design point. The radiation source in the unit is Cobalt 60.
The gasifier top stirrer can penetrate the feedstock bed to within -2.5 feet of the grate pan.
The stirrer assembly includes three rabble arms, each of which is series water-cooled. In
normal operation, on a typical caking coal, the stirrer agitates the top 8 feet of the 11-foot bed.
Vertical stirrer travel is adjustable from 0 to 2 feet/min. It is usually set at 0.5 foot/min in the
downward direction and 1.0 foot/min in the upward direction. The rotation rate of the stirrer is
also adjustable, but is usually set at about 70 revolutions per hour during baseline gasifier
operation.
The grate is a rotating cone, which supports the bed and uniformly distributes the air and
steam blast. As the grate rotates, a movable plow sweeps the ash from the bed into the ash
lockhopper. The axial position of the plow is adjustable to control the amount of ash removed
with each rotation of the grate. The rotation rate of the grate is adjustable to control the rate of
ash discharge. Grate rotation rates are maintained in the range of 6 to 40 revolutions per hour,
which allows an ash bed to be maintained above the grate to protect the lower gasifier
internals from the high temperatures in the oxidation zone of the gasifier. During operation air
and steam entering through the blast cools the grate, bosh, and ash bed of the gasifier.
The blast preparation system, shown in Figure A-2, enables steam and air to be mixed at
the proper mass ratio in the gasifier blast line with sufficient enthalpy input to maintain the blast
above its dew point. High-pressure air is supplied by one of two 800-hp, 3-stage inter-cooled
and after-cooled Worthington compressors. The compressors are capable of delivering 8
Ibm/sec of air at 300 psig. Air preheat is obtained primarily by an indirect gas-fired preheater
that can increase the air temperature to 800 °F, if required. Steam is provided at 400 psig at
saturated conditions (450 °F) by a natural-gas-fired steam generator capable of delivering up
to 1.4 Ibm/sec of flow. The lines are well trapped to remove condensate. The steam generator
is generally operated at near full-load conditions, and the excess steam is vented to obtain a
near steady delivery pressure to the gasifier.
A-2
-------
Air Compressor Air Heater (Gas)
Air
Air Control Valve
Feedwater
Steam Heater
& »
Blast Control Valve
City Water
Steam
Control Valve
Water
Treatment
Gas
Boiler
Figure A-2. Gasifier blast system
A.2 CYCLONE
A 304H stainless steel hot gas cyclone separator of standard geometry design removes
particulates from the raw gas exiting from the gasifier. The design specifications for the
cyclone are given in Table A.1.
Table A.1 Cyclone Design Specifications
Gas flow rate (nominal)
2.4 lb/sec
Gas inlet velocity (nominal)
65 ft/sec
Gas pressure (nominal)
300 psig
Gas pressure (maximum)
315 psig
Gas temperature (nominal)
1000 °F
Gas temperature (maximum)
1200 °F
Gas molecular weight
23
Inlet particulate loading
40 grains/acfm
The cyclone is housed in a 304H stainless steel pressure vessel that is heat traced and
insulated to maintain metal temperatures above 800 °F during startup and operation. Design
features of the cyclone and pressure vessel are shown in Figure A-3.
A-3
-------
d*«- too *
H.P.3.0 PLAU66
;-PRfi55URE VfeSStt
„ 24* /—
/
!*~ scM.ao pips
W/l*»-&DO*
K.F.5.O. FLAU66
3CH.B0 P|P6
!»*~ 5CU. IZO
PIPE CAP —-
ft"# 3CM. SO PiPfc
id' ~ - a oo •
R FIO . FLAU&SS
Im'*-UX>»
RKSQ RAWGt
1
l&"+ scu 120
PIPS
Z'+ SCM.BO PIP£
W/Z'*-600«
R.F.S.O. FIAUCC
(TVP. 4 PLACC3)
1 A
IB*• SCU. 120 PIPt CAP
4.* ~ SCH. 60 Pipe-
4B»-600 •
R.F.S.D. FIAJJ6S
¦I"* SCH. BO PIP6
W/ l"« -liOO-
R.F.5.0 FLAU&£
du5t ourur
Figure A-3. Cyclone and pressure vessel
The single-stage cyclone is equipped with a dust-removal lockhopper system. High-
temperature block valves installed on the inlet and outlet of the cyclone permit isolation during
startup. The entire lockhopper system is heat traced to the same specifications as the cyclone.
Bypass piping from the cyclone to the flare allows cyclone checkout and stabilization during
startup.
Instrumentation is provided to measure the pressure drop, temperature, and flow in the
cyclone assembly. A control system, to permit safe operation of the isolation valving around
the cyclone, and a lock hopper dust removal system are integrated into the programmable-
controller-based control system.
A-4
-------
A.3 FUEL HANDLING
The feedstock handling system is shown schematically in Figure A-4. The main storage
bin, which has an internal capacity of approximately 1000 ft3, is filled with the feedstock from
the portable auger truck conveyor, via the feedstock elevator. Either the truck conveyer or the
main storage bin feeder operates simultaneously with the feedstock elevator to fill the weigh
bin to a preset amount.
A diverter gate assembly enables the two lockhoppers to provide a smooth and consistent
flow of feedstock to the auger. As one lockhopper is being filled from the weigh bin, the other
is discharging into the auger and vice versa. All operations are controlled remotely from a
centralized control room.
Feed flow into and out of both lockhoppers is controlled by Everlasting knife gate valves.
The two-lockhopper system allows a smoother flow of feed into the gasifier, improves
reliability, and provides the greater feed capacity needed during high-throughput testing.
Lockhopper A has an internal capacity of 13 ft3. Lockhopper B has an internal capacity of
~15 ft3 and incorporates a 60° stainless steel liner cone that directs the feed from the vessel to
the lower valve. This cone allows the feedstock to flow more freely from the vessel and
reduces the possibility of feed hanging up in the lockhopper. The lockhoppers discharge to the
same feed auger, with Lockhopper A slightly further away from the gasifier vessel. Delivery
rate of the auger can be adjusted to maintain near-constant feedstock inventory to the bed
regardless of gasifier throughput.
A weigh bin load cell and readout system provides accurate weight readings of the feed
charges added to the lockhopper. This signal provides automatic shutoff to the elevator feed
system and is recorded by the data acquisition system for calculation of fuel throughput.
The charging procedure is initiated with a manual signal from the main operating panel.
The main bin feeder and elevator operate simultaneously until the preset weight limit on the
weight indicator is exceeded by the load cell output, thereby signaling a full charge of
feedstock. With the lockhopper (A, for illustrative purposes) at atmospheric pressure and the
top lockhopper valve XV-703 open, the weigh bin empties through its outlet valve, XV-702.
The top lockhopper valve XV-703 and the vent line XV-706 are closed, and nitrogen charged
to raise the lockhopper pressure to gasifier pressure by opening XV-705. The bottom
lockhopper valve XV-704 is then opened, permitting feedstock to fall into a chute leading into
the auger section. The feedstock is metered into the bed by the continuously rotating auger at
a rate proportional to gasifier load.
A-5
-------
, IOCXHOPPS*
PV842
B)OM
XV507 SULFUR
NfiWCWAl
SYSTEM
STORAGE
XV7G2
MAIN
STORAGE
BIN
XV509
XV501
XV76v
STEAM
STEAM
Xv7u3 XV707
XV500
XV706
XV70S
XV710
XV709
XV736
xV70d XV706
STEAM
SIEAm
XV? 70
XV768
~ SmRB?
XV74i
COAL GAS
XV743
BOVTP
XV744
XV7i6
XV745
XV? 50
XV75?
VA3Q3
XV755
XV774
VA304
XV753
ASH
CANNON
XV773
VS307
vwr
WCCMNGTON HP
AJR COMPRESSOR
TOOOAIC HEATER
Cannon
CHARGE/PURGE
STEAM
CtAYTON STEAM
GENERATOR
Figure A-4. Gasifier process flow diagram
A-6
-------
Appendix B
SAMPLING PROCEDURES
B.1 PARTICULATE SAMPLING
B.1.1 Overview
The particulate sampling system is used to collect samples of particulate matter for
determination of the loading and size distribution of the particles present in the fuel gas. Two
locations in the process gas stream are generally used for sampling: (1) the sampling port
downstream of the primary cyclone and (2) the port downstream of the secondary cyclone. For
the runs performed under the biomass program, only primary cyclone particulate samples were
taken since the secondary cyclone and the high-temperature sulfur-removal system were not
operated.
The procedure followed during particulate sampling is of utmost importance in obtaining
meaningful data for the characterization of the particulates. If the particles do not follow the
gas velocity streamlines through the piping system, deposition at pipe elbows and size
segregation in the gas phase can take place. Under these conditions, the collected samples
are not representative of the actual amounts and size distribution in the gas phase. For this
reason, isokinetic sampling, i.e., sampling at conditions where the solid particles have the
same velocity (magnitude and direction) as the gas stream, is necessary. Isokinetic sampling
presents a number of challenges, most important of which are: (1) matching the sample probe
velocity to the mainstream gas velocity at the temperature and pressure of the system, and
(2) assuring that the solid collected onto the filter medium is in fact the total solid matter
present in the volume of gas flowing through the sampling probe (i.e., assessment of the
leakage and efficiency of filter).
B.1.2 Description of Setup
The sampling setup is shown in Figure B-1. In this setup, all gas lines leaving the process
stream are heated and maintained at 900 °F by temperature controllers and heating tapes.
The sampling probe is located inside the straight pipe coming out of the primary cyclone exit.
The sample gas within the probe line flows isokinetically with respect to the gas flow in the
process line. The sample gas flows outward through the filter leaving the particulates collected
on and within the filter media. The filters used for particulate sampling are Balston type BH
filters rated at 0.1 micron opening size. Filter samples are purged with nitrogen for at least one
hour during cooling to prevent auto-ignition of particulate matter from exposure to oxygen in
the air during housing disassembly. Flow and nitrogen pressure changes are made gradually
to prevent damage to filter elements from sudden surges of gas. At least one particulate
sample is extracted per station per shift.
A step-by-step procedure including filter installation, sample extraction, and filter removal
follows.
B-1
-------
HP NITROGEN SUPPIY
IV-1
N2 PRESSURE
REGULATOR
0-600
PSK3
IV-2
TO 2-
VENT LINE
BV-1
777777777T7r
FILTER HOUSING
« HEATER
OJSCT ORIFICE
PLATE
CV-1
IV-7
IV*4
IV-5
EV-2
CV-l:
0-15 PSK3
TRANS
CAPSUH61IC
Figure B-1. Primary cyclone particulate sampling
B.1.3 Primary Cyclone Particulate Sampling
B. 1.3.1 Primary Cyclone Particulate Filter Installation
1. Obtain the appropriate data sheet from the sampling engineer.
2. Remove a filter element from the bake-out oven and place it in a desiccator to prevent
moisture pickup as it cools. Put a replacement element in the oven.
3. Let element in desiccator cool a few minutes. Weigh and record the filter element, with and
without endcap installed.
4. Place filter and cap in desiccator for transport to the sampling area.
5. Clean and oil the large ring and ring joint faces (RJF). Install the filter/cap assembly in the
particulate filter housing using the hitch pins, spring and pressure plate provided. Lower the
top half of the housing into the bottom half, taking care to avoid touching the housing
against the lower half.
6. Apply anti-seize compound to the eight 3/4" studs and install. Torque to 50 ft-lbs in a criss-
cross sequence. Install blind flange on filter housing exit. Using nitrogen purge flange,
gradually (to avoid damage to filter element) pressurize housing to 320 psig. "Snoop" large
ring joint. Tighten 3/4" studs as necessary. Slowly relieve nitrogen pressure from housing.
Remove nitrogen purge assembly and 1/2" blank flange.
7. Remove the housing from the auxiliary furnace and insert carefully into the main furnace.
8. Clean the 1/2" RJFs. Apply anti-seize compound to the 1/2" RJF studs. Tighten the flanges
evenly.
B-2
-------
9. Leak check the ring joints under nitrogen pressure as follows:
a. Ascertain that nitrogen pressure is at 0 psig (regulator backed off completely).
b. Close valves EV-1, EV-2, IV-2, IV-4, IV-5, IV-6, IV-7, IV-8, CV-1, BV-2.
c. Open valves IV-1, IV-3, IV-9.
d. Gradually (to avoid damage to filter element) increase nitrogen pressure, using the
pressure regulator, to 320 psig. Observe pressure on 0-600 psig pressure gauge. The
housing is now under 320 psig pressure.
e. Apply a water/soap leak check mixture to the 1/2" ring joints. Tighten joints to eliminate
all leaks. Also, apply a water/soap leak check mixture to all sample system fittings
under pressure. Repair all leaks.
10. When system is leak-tight, bleed down nitrogen pressure to 200 psig as follows.
a. Close valve IV-1, and back off nitrogen pressure regulator completely.
b. Open BV-2; then, iust crack open CV-1 to release pressure gradually (to avoid damage
to filter element). When pressure falls to 200 psig, close CV-1; then, BV-2.
11. Re-insulate the filter housing, taking care to avoid damaging the Samox heating tape.
12. Plug housing heat tape into heat zone #1 power cord. Turn on filter furnace #6 and heat
zone #1 temperature controllers.
13. Allow at least 2 hours for housing temperature equilibration before extracting particulate
sample.
14. Enter date and time of filter installation, plus sample #, in the particulate sample log sheet.
15. System is now ready for sample extraction.
B.1.3.2 PRIMARY CYCLONE PARTICULATE SAMPLE EXTRACTION
B.1 .3-2,1 Initial status
System status at start of procedure:
Hot gas cleanup system
Primary particulate sampling system
B.1.3.2.2 Sample extraction
1. The sampling engineer shall record initial gasifier conditions and gas composition on the
data sheet for the filter installed per Section 6.2.4.1.1.
2. Open, or check open, valves EV-1, EV-2, IV-3, IV-4, IV-5, IV-6, IV-7, IV-8, IV-9.
3. Close, or check closed, valves BV-1, BV-2, CV-1, IV-1, IV-2.
4. Check primary particulate sampling system pressure as indicated on the 0-600 psig
pressure gauge. It should read between approximately 200 psig and gasifier system
Operating at normal temperature and pressure;
coal gas flowing from gasifier through primary
cyclone to absorber via pipe 4"CG-501.
Ready for sample extraction, per
Section 6.2.4.1.1.
Valves IV-3, IV-9 open. All other valves closed.
B-3
-------
pressure (normally 280 psig). If necessary, increase the sampling system pressure to within
10 psig of gasifier system pressure as follows.
a. Set nitrogen regulator delivery pressure to within 10 psig of PARTICULATE SAMPLING
system pressure.
b. Open valve IV-1.
c. Gradually (to avoid damage to filter element), using the pressure regulator, increase
nitrogen pressure to within 10 psig of GASIFIER system pressure.
d. Close valve IV-1. Back off nitrogen pressure regulator completely.
5. Bring up display #47 on the computer terminal.
6. Verify that all heat zones are to prescribed temperature, 900 °F ±50 °F. If not, inform the
sampling engineer.
7. Install actuator handle on BV-1 and slowly open the valve. Process gas is now connected
to the sampling system. Close equalization valves EV-1, EV-2.
8. Open BV-2 (vent line valve) fully.
9. While watching display #47, SLOWLY (in order to avoid damage to filter element from
sudden flow surge) open CV-1 in small increments to achieve sample gas flow to within
±10% of the desired rate. Record time when desired flow rate is first achieved. Hereafter,
adjust valve CV-1, which is a trimming valve, to maintain the sample gas flow within the
±10% allowed. Record the flow information on 2-minute intervals, noting any peculiarities or
extreme changes in "desired" or "actual" isokinetic flow. Initial data sheet.
10. Continue sample extraction for 120 minutes (after isokinetic flow is achieved), unless
indicated otherwise by the sampling engineer.
11. SLOWLY close CV-1. Record time flow stopped.
12. Close BV-1 and immediately remove the actuator handle.
13. Just crack open CV-1 to release pressure gradually (to avoid damage to filter element).
Observe the pressure fall to 0 psig on the 0-600 psig pressure gauge. If the pressure does
not fall to 0 psig, summon the sampling engineer before attempting system disassembly.
14. Open equalization valves EV-1, EV-2.
15. Sampling engineer shall enter final gasifier operating conditions and gas compositions on
data sheet.
B.1.3.2.3 Primary cyclone particulate filter removal
1. Turn off heat tracing to filter furnace controller #6 and heat zone controller #1. Disconnect
power cord to Samox heat tape, from heat zone #1.
2. Remove thermal insulation to gain access to the two 1/2" RJFs securing the filter housing
to the sample system.
3. Close CV-1 fully; close BV-2. Close all other valves except IV-3 and IV-9, which keep the 0-
600 psig gauge actively connected to the sampling system.
4. Remove the 4 studs securing each of the two RJFs. Apply anti-seize compound.
B-4
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5. Carefully slide the complete filter housing from the main filter furnace and place in the
auxiliary furnace. Avoid any jarring actions which will remove particulate material from the
filter element.
6. Connect the nitrogen purge flange to the housing inlet flange (straight section). Purge the
filter housing with nitrogen flow (regulator setting of 5-10 psig) for 1 hour prior to housing
disassembly.
7. With nitrogen purge still flowing, loosen and remove the eight 3/4" studs from the filter
housing flange. Lift off the upper portion of the housing, taking care to avoid touching the
filter element against the housing walls. Place upper portion of the housing assembly in the
unistrut filter rack. Turn nitrogen purge flow off, but leave purge assembly connected.
8. Remove the filter retaining assembly, taking care that filter end cap remains on the filter.
Carefully remove the filter from the housing. Avoid loss of particulates from jarring actions
or spillage.
9. Place an end cap on the open filter end and secure both caps with a rubber band. Place
the filter in a desiccator and keep there to avoid moisture pickup as it cools.
10. The filter/end cap assembly must now be weighed. After removing the rubber band and the
end cap installed in Step 9, weigh the assembly on the same analytical balance used for
initial weighing and record final weight on the data sheet. Re-cap and band the filter
element and place it back into desiccator until it is to be emptied.
11. Being very careful not to lose any material, empty particulates completely out of filter into a
wide mouth 4-ounce sample jar. Close lid tightly. Label with pre-printed label, entering all
data called for. Bring to sampling engineer for storage, analysis, etc.
B.2 PROCEDURE FOR AMMONIA AND HYDROGEN CYANIDE GAS ANALYSIS
B.2.1 Overview
Because of the limitations of the existing analytical instruments, it is not possible at present
to perform an accurate analysis of a gas stream for ammonia and hydrogen cyanide content at
gasifier process conditions of high temperature (near 1000 °F) and high pressure (near
280 psig). Mass spectrometers require that the gas be cooled below 400 °F or, preferably, to
room temperature, and dried of condensing moisture to around 1% water. In the process of
cooling, water-soluble species such as ammonia and hydrogen cyanide may be removed from
the gas stream so that the measurements of gas composition are erroneous.
Further error is introduced by the depressurization of a gas/liquid condensate sample,
which changes the partition coefficient of ammonia between the liquid and gas phases. An
alternate approach is to capture the desired species in a liquid solution. ASTM-approved
methods for wet-chemistry analysis of liquid samples (e.g., ASTM Method 1426-79 for
ammonia) have interferences for ammonia analysis by other ions present in solution such as
amines, and some metal ions; dissolved H2S also interferes with hydrogen cyanide
measurements.
In order to overcome the experimental difficulties and the limitations of the analytical
instruments, several sampling procedures coupled to approved analysis methods were
developed. In the procedure that was followed, a known quantity of a hot process sample gas
B-5
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was captured in a pressure vessel (i.e., a grab sample) and passed first through dilute
solutions of acids to capture NH3 and then through dilute solutions of base to capture HCN.
The use of ion-selective electrodes — Orion 95-12 for ammonia and Orion 94-06 for
cyanide — made it possible to determine the molar concentration of each aqueous solution
while minimizing interferences. The gaseous concentration levels (ppmv) of NH3 and HCN
were calculated from the measured concentrations of the solutions.
A schematic diagram of the ammonia/hydrogen cyanide sampling apparatus is presented
in Figure B-2. During gas sampling, the stainless steel pressure vessel is connected directly to
the hot gas sampling point, and the gas at the local operating pressure and temperature is
allowed to pressurize the vessel.
Vent
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S.S. Pressure Vessel
Glass Bubbler
Glass Bubbler
Glass Bubbler
Figure B-2. Ammonia/hydrogen cyanide sampling apparatus
As soon as the gas cools and the steam condenses in contact with the sulfuric acid
solution, the ammonia dissolves in the liquid instantaneously because of its low pH (~0.5). The
pressure vessel is then depressurized by bubbling the gas through three glass bubblers: one
containing additional sulfuric acid solution (to ascertain that all ammonia has been trapped)
and two others containing sodium hydroxide solution (pH -12.5) to capture hydrogen cyanide.
The analyses of all four solutions collected during sampling is performed using ion-selective
electrodes for ammonia and hydrogen cyanide. A small concentration of lead acetate was
added to the last two bubblers to eliminate interference of dissolved sulfide ion with the
cyanide determination.
Even though many precautions have been taken to eliminate interferences of foreign
species/ions when measuring ammonia concentrations, the results reported as ammonia
concentrations may inevitably also include contributions of small concentrations of other
nitrogen-containing species in the gas (e.g., amines and carbamides). These interferences are
generally unavoidable whether wet chemistry or ion-selective analyses are used for the
determination of ammonia. Nonetheless, these other species may be equally important for the
calculation of NOx levels produced from fuel-bound nitrogen.
B-6
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B.2.2 Gas Sampling
1. Perform the disassembly, cleaning, reassembly of the pressure vessel and the preparation
of the grab sample in a well-vented hood approved for chemical use:
a. Pressure vessel disassembly and cleaning. Disassemble and clean the 1-liter
stainless steel sample gas pressure vessel before each gasifier trial. Rinse the vessel
thoroughly with a minimal amount of technical-grade acetone until all tar residues are
dissolved and removed. Inspect and clean the tubing, valves, and pressure gauge.
Collect and store all acetone-based waste separately. Use acid-resistant gloves, safety
glasses, and protective clothing.
b. Pressure vessel reassembly. Reassemble the pressure vessel. Then pressure check
it with either nitrogen or air to 300 psig. Repair or replace any defective part of the
apparatus in order to seal the vessel properly. Use high-pressure-tubing (e.g., copper
or stainless steel) when pressure checking.
c. Preparation of sample gas. Perform this preparation step before each grab sample.
Remove one of the inlet tubes to the pressure vessel and add approximately 25 ml of a
O.I-/WH2SO4, solution. Shake moderately, and drain into a waste container labeled
"NH3/acid". Repeat procedure once more. While the inlet tube is disconnected,
measure out 100 ml O.I-/WH2SO4 in a graduated cylinder and add to the pressure
vessel. Reseal the vessel and record the volume of acid added on the data sheet as
"volume added."
2. Prepare the grab sample using the following procedure:
a. Sample Point Connection. Take the pressure vessel to the sampling floor of the
gasifier and connect it to the sampling point desired (gasifier or primary or secondary
cyclone), attach the thermocouple readout, and allow the gas sampling line to purge by
opening the gas line valve for 1 to 2 minutes. Open the inlet valve of the pressure
vessel to allow the sample gas to flow in. As soon as the vessel valve is open, begin
monitoring the pressure gauge. As soon as the pressure in the vessel maximizes, shut
off both the gas inlet valve and the pressure vessel inlet valve.
b. Records. Record the following data: date and time, gauge pressure at maximum,
thermocouple readout at maximum pressure, sample source, and vessel number.
Disconnect the vessel from the gas source. Obtain additional samples or transport the
vessels to the vented hood where gas analysis will take place.
B.2.3 Gas Analysis
1. Prepare the following solutions before beginning gas analysis:
CAUTION; The following reaction is extremely exothermic, take appropriate safety measures.
a. 0.1-M sulfuric acid (H2SO4). In a 1-liter volumetric flask add 31 ml of Acculute™
1.0-N H2SO4 and then fill to the mark with deionized water.
CAUTION: The following reaction is extremely exothermic, take appropriate safety measures.
b. 0.1-M sodium hydroxide (NaOH). In a 1-liter volumetric flask add 15 ml of Acculute
1.0-N NaOH and then fill to the mark with deionized water.
c. 1.17 x 10_3-M lead acetate (PbAce) in 0.1 -M NaOH. Weigh out 3.035 g PbAce.3H20
and place in a 1-liter volumetric flask. Add enough 0.1-M NaOH to dissolve the solid
B-7
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with shaking, and then fill to the mark. In a clean 5-gallon plastic pail add the dissolved
PbAce/NaOH solution and then add an additional 7 liters of 0.1 -M NaOH.
d. 1.17 x 10"1-M PbAce. Weigh out 4.000 g PbAce.3H20 and place in a clean 100-ml
volumetric flask. Add sufficient deionized water to dissolve the PbAce with shaking,
and then fill to the mark.
CAUTION: The following reaction is extremely exothermic, take appropriate safety measures.
e. 10-M NaOH. Weigh out 40 g NaOH and place in a 100-ml volumetric flask. Add
approximately 50 ml deionized water while swirling the flask (create a vortex). This
enables the NaOH pellets to dissolve without sticking to one another. Dilute the
contents to the mark with deionized water.
2. To three 500 ml. glass sample bottles add the following solutions and label accordingly:
b 200 ml 0.1 M H2S04
c 200 ml 1.17 x 10"3 PbAce/0.1 -M NaOH
d 200 ml 1.17 x 10"3 PbAce/0.1-M NaOH
3. Chill solutions well in advance so they are at ice temperature when the bubbler is started.
Attach the bubbling apparatus to the three glass bottles (b, c, and d). These bottles may
be prepared in advance, capped, labeled, and placed in the bath.
B.2.4 Gas Bubbling and Solution Labeling
1. Gas bubbling. The gas bubbling should be done in a hood. Secure the pressure vessel
to the back of the fume hood by means of the gas bottle strap and attach the NH^tar
pressure regulator. Once the regulator outlet is connected to the inlet of sample bottle b,
begin gas bubbling. To depressurize the vessel, adjust the regulator to deliver about 1 to 3
psig so that the bubbling time is at least 10 to 15 minutes.
2. Solution labeling. Once the vessel is depressurized, remove the sample bottles from the
bubbling apparatus, cap, label, and set them aside. At this point, used solution should be
labeled with a new ID, with the gas sample number added to the letter identifier (e.g., lb,
1c, Id). The glass fritted bubbler and the pipettes should be rinsed with deionized water in
their respective sample bottles. Replace the sample bottles with containers of fresh
solutions (b, c, and d); the train is now ready for bubbling another gas sample. The
pressure vessel is now emptied of solution by removing one of the inlet tubes from the top
and tipping the vessel over several times while holding a 4 oz. plastic bottle to the hole.
This bottle is labeled a with the appropriate gas sample identification (ID) number. The
vessel is rinsed twice with a minimal amount of O.I-MH2SO4; the waste is collected and
placed in a container labeled NH;}/acid. Follow Procedure A.3 to prepare the empty vessel
for another sample.
3. Sample storage. Ammonia samples (a and b) are placed in a chemical refrigerator.
Cyanide samples (c and d) should be analyzed as soon as possible; refrigeration is helpful
but not necessary if they are to be analyzed immediately. Consult sampling engineer for
guidance.
B-8
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B.2.5 Sample Analysis
An Orion 720A ISE meter and appropriate electrodes are required; ammonium chloride
(NH4CI) and potassium cyanide (KCN) standards are used to calibrate the instrument daily
before sample analysis.
1. Standard Preparation and Disposal
a. NH4CI. The use of a standard commercially available O.I-/WNH4CI solution (Fisher
Brand 13-620-800) is recommended. A ten-fold dilution of this standard and
subsequent dilutions are performed in order to create a range of 1 x 10"1-/W through
1 x 10~b-M standard NH4CI solutions. (E.g., a volume of 50 ml of each solution is
pipetted and diluted to 500 ml with deionized water in a volumetric flask.)
Waste Disposal All spent solutions and calibration residues containing NH4CI should be
placed in a container labeled NH3/acid.
b. KCN. A 0.01 -M KCN standard solution is made by adding 0.65 g KCN to 10 ml 10-M
NaOH and 500 ml deionized water in a 1-liter volumetric flask. After the solid has
dissolved, the flask is filled to the mark with deionized water. A ten-fold dilution of this
standard and subsequent dilutions are performed so as to create a range of 1 x 10~2-M
through 1 x 10~e-M standard KCN solution. (E.g., a volume of 50-ml of each solution is
pipetted and diluted to 500-ml in a volumetric flask.
Waste Disposal All spent solutions and calibration residues containing KCN should be
placed in a container labeled CN/base.
2. Instrument Calibration. Procedures follow those described in the Orion Instrument
Manual for the ammonia electrode (95-12) and the cyanide electrode (94-06).
a. Ammonia. This ammonia-ion-selective electrode is calibrated for the range
1 x 10"1-M through 1 x 10~4-M NH3. Pipette 50 ml of standard solution into each of
four 300-ml glass beakers; place a clean Teflon stirbar in each beaker; cover the
beaker with parafilm to prevent contamination. Place the instrument in calibration
mode for 4 standards. After rinsing the ammonia electrode with deionized water and
blotting it dry with a fresh Kimwipe®, place the electrode in the lowest standard
concentration. While stirring slowly, add 1 ml of 10-M NaOH to liberate the NH3 gas;
set the electrode at a 20-degree angle to prevent gas bubbles from collecting.
Dislodge any bubbles that do stick with a slight tap to the electrode top. When the
"RDY ENTER VALUE" message appears, enter the calibration level. For 1 x 10"4-/W
NH3, enter a value of 1.70 (ng/g). Remove the electrode from the solution, rinse with
deionized water, dry, and place in the next higher concentration; repeat the procedure
and enter values of 17.0, 170, and 1700 according to the solution used. When
calibration is complete, the instrument will calculate a slope for the 4 concentration
points; this value should be in the range of -54 to -60 mV. Record this value. If it is
out of the range, recalibrate the electrode.
b. Cyanide. The cyanide-ion-selective electrode is calibrated for range 1 x 10"3-M
through 1 x 10~5-M KCN. Pipette 50 ml aliquots of standard solution into each of three
300-ml plastic beakers; place a clean Teflon stirbar in each beaker; cover the beaker
with parafilm to prevent contamination. Place the instrument in calibration mode for
B-9
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3 standards. After rinsing both the cyanide and reference electrodes with deionized
water and blotting dry with a clean Kimwipe, place the electrodes in the lowest standard
concentration. While slowly stirring, add 1 ml of 10-M NaOH to complete the formation
of CN ion. When the "RDY ENTER VALUE" message appears, enter the calibration
level. For 1 x 10~5-M KCN, enter a value of 0.26 (ng/g). Remove the electrodes from
the solution, rinse with deionized water, dry, and place them in the next highest
concentration. Repeat the procedure so that values of 2.6, and 26.0 are entered.
When calibration is complete, the instrument will calculate a slope for the
3 concentration points; this value should be in the range of -54 to -60 mV. Record this
value. If it is out of the range, recalibrate the electrode.
3. Solution analysis. Bring solutions to room temperature before beginning analysis; a warm
water bath may be used. Place a 50-ml aliquot of sample in a 300-mI plastic beaker along
with a clean, dry stirbar. Place the appropriate electrode (rinsed and blotted dry) in the
covered sample beaker and put the instrument in measure mode. Add 1 ml 10-M NaOH
while slowly stirring. The Orion 720A will emit a "beep" tone when the mV output is stable;
record this value as ppmw NH3 or CN. The total volume of the original solution must be
obtained. To do so, pour the remaining solution into a 250-ml graduated cylinder and add
50 ml (the aliquot volume) to obtain a total volume.
4. Report of data. Each individual sample (ID number and a, b, c, or d) will generate a "total
solution volume" ml, "ppmw NH3 or CN" ^g/g, and "[NH3] or [CN]M moles/liter.
Concentration in mols/liter is obtained by dividing the ppmw value by the standard level
according to the calibration procedure. (E.g., 10.0 ppmw NH3 = 10.0/1.7 = 5.88 x 10-A-M
NH3.)
5. Sample disposal
a. Analyzed solutions. The solution aliquots should be placed in the appropriate waste
container - NH3/acid (samples a and b) or CN/base (samples c and d).
b. Unanalyzed solutions. After complete data workup and analysis the remaining liquids
can be disposed of in similar fashion as "analyzed solutions."
c. Sample bottles. All plastic bottles are contaminated with tar and are to be rinsed with
deionized water and then disposed of in a separate plastic bag labeled accordingly. All
glass bottles can be reused after proper cleaning.
B.3 PROCEDURE FOR ANALYSIS OF TAR AND WATER
PHASES IN THE FUEL GAS LIQUID CONDENSATE
B.3.1 Overview
Prior to chemical analysis of gases by mass spectrometry and/or gas chromatography, the
gas samples must be conditioned so as to preserve the proper operation of the instrument and
avoid instrument damage. Conditioning requires cooling of the gases to room temperature and
filtration to remove particulate matter carried over with the gases. As a result of conditioning, a
liquid condensate is collected between the gas sampling point and the instrument location.
B-10
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The liquid condensate contains various amounts of sulfur, nitrogen, alkali metals,
halogens, and other chemical species. The condensate from the gas streams (e.g., gasifier,
primary and secondary cyclone, if applicable) is collected regularly (minimally at 4-hour-
intervals) and stored in sealed glass containers for chemical analysis.
The results of the chemical analysis for some or all species are used to perform an overall
material balance of selected chemical species present at various points in the gasification
process. The procedure described here summarizes the procedures for collecting, extracting,
and quantifying the tar and oil (TAO) and water phases and their composition in the
condensate.
B.3.2 Equipment
1. Graduated separatory/addition funnel (1000 ml)
2. Funnels
3. Glass sample vials (8 dram)
4. Pipettes (10 ml)
5. Graduated cylinder (10 ml)
6. Graduated cylinder (100 ml)
B.3.3 Chemicals
1. Acetone (reagent grade)
2. Hexane (reagent grade)
B.3.4 Procedure for Liquid Phase Separation and Extraction
Step 1. Water phase prior to extraction
The liquid condensate originally collected in the condensate traps during the normal
gasifier operation is transferred to glass jars and left undisturbed to allow solid particulate
matter to settle. A 30-ml sample from the water layer of the condensate is withdrawn with a
pipette and labeled "Water Layer Prior to Extraction." The date, time, and source of the
condensate trap are included in the label on this and all succeeding extractions.
Step 2. Extraction of the tar and oil (TAO) layer
A 10-ml volume of hexane is added to the condensate in the jar and the contents shaken
well to maximize contact among the different phases. The object of this procedure is to extract
the TAO layer using the least amount of hexane possible to make a clean separation between
the organic (e.g., tar and oil) and water layers. If the interface between layers is emulsified
rather than sharp, an insufficient amount of hexane for the extraction has been added. In that
event, an additional 10 ml of hexane in 10 ml increments (but not to exceed 30 ml total
hexane) are added until a sharp boundary between phases is obtained. The entire contents
are then transferred to a graduated 1000-ml separation/addition funnel.
B-11
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A 10-ml volume of hexane is added to the empty condensate jar to collect any residual
organic liquid phase. The rinse is added to the contents in the separatory funnel, and the
rinsing step repeated once more if necessary. A solid residue may still adhere to the walls of
the jar. This residue contains particulate matter and dust from the gas and will be removed
later on using an acetone wash (Step 5).
Step 3. Determination of the water layer volume
The separatory funnel is shaken thoroughly and its contents are then allowed to settle for a
few hours. The volume of the water layer in the funnel is measured and the total volume of the
water in the condensate obtained by adding the amount of water phase removed (e.g., 30 ml)
in Step 1. The total water volume is recorded in the notebook for future mass balance
calculations. The water layer is removed from the funnel and a 30-ml sample is saved and
labeled "Water Layer After Extraction."
Step 4. Determination of the TAO layer volume
The volume of the organic layer remaining in the funnel is measured to the nearest ml in a
100"ml graduated cylinder and the measurement recorded. The total TAO volume in the initial
condensate is obtained by subtracting the amount of hexane added in Step 2 (e.g., 30 ml
hexane) from the volume of the organic layer and recorded. The organic layer is saved and
labeled "Tar Extract in Hexane."
Step 5 Collection of residual solid matter
The empty condensate jar is finally rinsed with two 10-ml additions of acetone to wash the
residual solid matter from the container walls. The wash is added to a separatory funnel. The
funnel is shaken thoroughly, the final volume of the liquid wash is measured to the nearest ml
in a 100-ml graduated cylinder and recorded in the laboratory notebook. The acetone wash is
saved and labeled "Acetone Wash."
B.3.5 Chemical Analysis
The samples collected following the above procedures are sent to the appropriate
analytical labs per direction of the sampling engineer. Typically, the following analyses are
performed on the TAO, water, and acetone wash layers on a regular basis:
• Proximate and ultimate analyses, including sulfur
• Alkali metals (Na, K)
• Chlorine
Other chemical analyses performed by inductively-coupled plasma (ICP) spectroscopy may
include trace elements such as mercury or lead.
B.4 CALIBRATION OF ANALYTICAL INSTRUMENTATION
B.4.1 Overview
The calibration of the analytical instrumentation, mass spectrometer, oxygen analyzers,
and gas chromatographs is performed using certified standards (± 1.0 mole percent) supplied
by Scott Specialty Gases. These binary gases (pure gas in nitrogen) and simulated gas stream
blends are replaced once a year or earlier as dictated by usage or supplier; those calibration
B-12
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gases containing low (ppm) levels of H2S, COS, C2S, and oxygen are replaced every six
months.
Instruments are calibrated at the beginning and end of each run. This method consists of
flowing the calibration gas through the instrument and adjusting the integration factor in the
gas chromatographs, the Faraday cup alignment in the mass spectrometer, or the photocell
current feedback in the oxygen analyzer so that the output is equal to the calibration gas
concentration. A further calibration check is performed by using another binary gas and/or a
gas stream blend. During the run, periodic checking of the instrument takes place at least
every 24 hours. If significant drift has occurred (± 3.0%), a recalibration is performed.
The startup, calibration, operation, and shutdown procedures for the mass spectrometer
are given here as examples. Similar written procedures are available for the gas
chromatographs and will not be included here.
B.4.2 Setup and Operating Parameters
for Gas Analysis Instrumentation
B.4.2.1 Mass Spectrometer
B.4.2.1.1 Mass Spectrometer initial startup
Turn on the main circuit breaker at the rear of the instrument. The current display reading
on the front panel should read 70 or less and the standby light should be on before the
instrument is run. (It takes approximately one hour for the instrument to attain run status.)
B.4.2.1.2 Mass Spectrometer calibration
The calibration procedure is outlined in Chapter 4 of the Operations Manual. The
procedure for operation and shutdown is included here as Sections B.4.2.1.3 and B.4.2.1.4.
Calibration gas can be sent to the instrument by using the following procedure:
1. Turn the Mass Spectrometer Selection Switch on the Gas Distribution Panel to the desired
calibration gas. (If the selected calibration gas is listed on the Hazardous Gas Shutdown
Panel, open the shutdown valve for that gas.)
2. Turn the Selector Switch on the Gas Selector Panel to position 2 and open the calibrate
valve.
3. When the required adjustments have been made as per the calibration procedure in the
Operations Manual, turn the calibration gas off.
a. Turn the Selector Switch on the Gas Selector Panel to position 1 and close the
calibrate valve.
b. Turn the Mass Spectrometer selection switch on the Gas Distribution Panel to the N2
position.
c. Turn off the shutdown valve on the Hazardous Gas Shutdown Panel (if required).
B.4.2.1.3 Mass Spectrometer operation
1. Set the selector switch on the Gas Selector Panel on the desired gas stream.
2. Open the flow valve of the selected gas stream.
B-13
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3. Set the flow rate of the gas stream at approximately 2.0 scf/h.
4. Switch the instrument from the STANDBY mode to the ON mode.
5. Turn the inlet selection knob to position 1.
6. Gas Stream component percentages may be monitored on the instrument display by
turning the composition knob to the desired gas component.
7. All gas stream component percentages are displayed simultaneously on screen #40 on the
HP display terminal.
B.4.2.1.4 Mass Spectrometer shutdown
1. Turn the inlet selector switch off.
2. Return the instrument to the STANDBY mode by pressing the STANDBY switch.
3. Turn the selector switch on the Gas Selector Panel to position 2 and open the calibrate
valve.
4. Turn the Mass Spectrometer Selection Switch on the Gas Distribution Panel to the N2
position.
5. Adjust the flow rate on the Gas Selector Panel flowmeter so it is between 1.0 and 2.0 scf/h.
NOTE: Condensate must not be ingested into the instrument. Damage to or failure of
the Mass Spectrometer may occur.
B.4.2.2 Gas Chromatograph #1
The sampling duty cycle for gas chromatograph #1 is 1 hr per stream, approximately
2 samples per hour. The analysis is for H2, N2/02/Ar, CO, CH4, C02.
B.4.2.3 Gas Chromatograph #3
There is 1 sample point for gas chromatograph #3, approximately 15 samples per hour.
The analysis is for H2S, COS, and CS2 in low concentration.
B-14
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Appendix C
DATA ACQUISITION AND CONTROL SYSTEM
C.1 OVERVIEW
The coal gasification/cleanup facility uses a data acquisition and control system comprising
two computers (Figure C-1) that work together, sharing data bidirectionally, to monitor and
control the test in progress.
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C-1
-------
A Hewlett Packard A-900 minicomputer handles the data acquisition task and is
responsible for the communication link between the computers. A General Electric Series Six
programmable controller controls the operation of the test facility and is responsible for all
safety interlocks and control functions and most of the user interactions with the test facility.
C.2 DATA ACQUISITION
The data acquisition system is responsible for acquiring data, performing engineering
calculations, and storing data and calculated results on magnetic tape for post-processing. The
system is also in charge of the bidirectional data link with the Series Six controller. The core of
the data acquisition system is TMGR, a software system developed at GE-CRD. TMGR
coordinates the scheduling of many of the data acquisition processes and acts as an informal
database, that is, a centralized storage area in which the processes deposit data. The data
acquisition system receives data from three analog instruments :
1. Hewlett Packard 3852. This scanning voltmeter acquires temperature data from
thermocouples, pressure data from pressure transducers, and gas composition data
from a mass spectrometer and several other constant update gas analyzers. Of the 400
possible analog channels found in the HP3852, over 350 are currently in use.
2. Hewlett Packard 3396: These gas chromatograph integrators report gas composition
data via RS-232 interface lines. They monitor the output from the gas chromatographs,
convert that output to gas composition information, and send an ASCII report to the
HP A-900 computer. Software has been written on the A-900 to monitor the RS-232
lines, catch the reports as they are generated, parse the reports in order to understand
their contents, and merge the data with the rest of the data in the system.
3. General Electric Series Six: The Series Six acquires critical data (temperatures,
pressures, and gas compositions) directly for control purposes. This data is passed to
the HP A-900 for on-line engineering calculations, and for long-term storage.
Once data is acquired, it is used in real time to calculate test parameters. Typical
calculations include gas flows, gas velocities, and cleanup system efficiencies. Calculation
results are then displayed on-line and saved for post-processing on disk and magnetic tape.
Operators interact with the data acquisition system by using RS-232 terminals and user-
interface programs running on the HP A-900. The user interface simplifies access to the TMGR
data acquisition software. Control room personnel use two of these terminals to monitor the
test as it progresses. Tables showing current data can be viewed at either of the two terminals,
and the color graphics terminal can be used to plot critical data and calculations for the current
day.
C.3 CONTROL SYSTEM
Process control is handled with a GE Series Six programmable controller. All control
functions are performed ether directly through the Series Six or through proloop process
controllers associated with the Series Six. The Series Six is used primarily to allow remote
activation of mechanical apparatus (e.g., to open and close valves, move stirrers, and turn
augers) as well as provide overall process control logic. The proloop controllers are used to
control gas flow rates, maintain desired temperatures, and stabilize gas compositions. These
C-2
-------
proloops share status information including the process variable (i.e., the item being
controlled), the set-point, and the output of the proloop with the Series Six and then ultimately
with the HP A-900 data acquisition system. The control system is also responsible for safety
interlocks that enforce safe operating procedures.
Analog data required to control the test is entered into the Series-Six controller via three
paths:
1. Analog input cards: The Series Six has approximately 80 analog input channels that
allow temperature, pressure, and gas concentration information to be read directly into
the controller. This data is used to control the test and is also shared with the data
acquisition system.
2. Proloop Process Controllers: These stand-alone controllers, listed in Table C-1, control
critical flows and temperatures. They then share important internal status information
with the Series Six and ultimately with the data-acquisition system.
Table C.1 Proloop Controllers
Loop
Function
Single Loop #1
Main air flow to gasifier, in. water
Single Loop #2
Steam flow to gasifier, in. water
Single Loop #3
Gasifier vessel pressure, psig
Multiloop #1
Loop #1
Flare aux. air flow
Loop #2
Main gasifier steam pressure
Loop #3
Self-controlled
Loop #4
Self-controlled
Loop #5
Bank air, manual mode only
Multiloop #2
Hot gas cleanup regeneration, not
used for this test
Multiloop #3
3. Data Acquisition System: In several non-critical areas, analog information first goes to
the HP A-900 and is then shared with the Series Six for control purposes. For
example, analog information goes to the HP first when large numbers of thermocouples
are averaged to calculate a process variable.
In order to operate the test, control room personnel use 6 IDT (Industrial Data Terminals)
terminals that interact with the Series Six. The terminals are designed specifically for industrial
control of process facilities.
C-3
-------
Appendix D
MASS AND ENERGY BALANCES
D.1 OVERVIEW
Detailed mass and energy balances are included for steady-state operating periods during
the bagasse and wood chip gasification trials. Discussions regarding these balances can be
found in Sections 4.4.3 (Bagasse) and 4.5.3 (Wood Chips).
D.2 DETAILED MASS AND ENERGY BALANCES
Tables D.1 and D.2 show the gasifier mass and energy balances for the bagasse trial run
on October 9, 1991. Tables D.3 and D.4 show the gasifier mass and energy balances for the
wood chip trial held on October 30-31, 1991. Abbreviations used in these mass and energy
balances are listed in Table D.5.
D-1
-------
Table D.1 Gasifier Mass Balance - Bagasse
10/9/91
0100-06001
GASIFIER INPUTS
(LBM/HR)
C
H
0
N
AR S
ASH
TOTAL
D.WOOD
1763.8
247.5
1449.0
31.0
2.4
241.2
3735.0
W.MOIS
38.7
307.0
345.6
AIR
.5
0.0
876.1
2854.8
48.6
3780.0
STEAM
165.2
1310.8
1476.0
PRG.N2
50.0
50.0
TOTAL
1764.3
451.4
3942.9
2935.9
48.6 2.4
241.2
9386.6
GASIFIER
OUTPUTS
(LBM/HR)
C
H
0
N
AR S
ASH
TOTAL
N2
2868.8
2868.8
02
1.7
1.7
C02
506.3
1348.8
1855.1
AR
46.5
46.5
CO
674.0
897.8
1571.9
H2
90.7
90.7
CH4
155.3
52.1
207.4
H2S
.1
1.5
1.6
DRY GAS
1335.6
142.9
2248.3
2868.8
46.5 1.5
6643.7
R.G H20
219.2
1739.8
1959.0
CLH.LOS
18.2
4.9
54.4
39.1
.6 .0
117.3
TAO
128.4
8.8
12.0
.2
.4
3.1
152.8
D.FINES
20.0
.6
.7
.5
.1
8.2
30.0
D. SOLID
.8
.3
2.5
1.7
.0
273.1
278.5
S.MOIS
8.8
69.8
7B.5
ALH.LOS
.0
.6
7.7
10.1
.2
18.5
CONDEN.
9.0
71.1
80.0
ADJ.HIT
15.5
15.5
TOTAL
1503.1
395.0
4206.2
2935.9
47.3 2.0
284.4
9373.9
IN/OUT
1.1738
1.1426
.9374
1.0000
1.0278 1.2029
.8482
1.0014
MOLE* N2 02
C02
AR
CO
H2
CH4
H2S
H20
DRYG 39.408 .020
16.221
.448
21.595
17.316
4.976
.018
WETG 27.782 .014
11.436
.316
15.224
12.207
3.508
.013
29.500
BLST 47.972 12.870
.018
.573
38.567
DRY COMP C H
0
N
S
ASH
WOOD 47.22 6.63
38.79
.83
.06
6.46
FINES 66.66 1.98
2.22
1.66
.17
27.31
TAO 84.05 5.73
7.84
.12
.26
2.00
SOLIDS .30 .11
.90
.60
.01
98.08
MOLES DiG=259.87 DGMW-25.57 TAO= .02300 //#DG W.WOOD-4080.6 #/HR
MOLES W.G-368.61 WGMW-23.34 PRE=290.00 FSIG MOIS.%- 8.47
V0L.M=76.95%DC
PYR.F=23.00%VM
C.E%=75.72 BOT.SOLID= 357.0 //HR AMW-28.96 S/A= .390 #/#
S.U%=35.48 MOIS.(%) =22.00 BMW=24.74
tAbbreviations listed in Table D.5
D-2
-------
Table D.2 Gasifier Energy Balance - Bagasse
10/9/91 0100-0600t
GASIFIER HEAT BALANCE INPUTS
TOTAL
TOTAL
SENSIBLE
CHEMICAL
TOTAL
MASS
TEMP
PRES.
HEAT
HHV
HEAT
HEAT
(LB/HR)
(F)
(PSIG)
(UNITS)
(BTU/LB)
(UNITS)
(UNITS)
D.WOOD
3735.0
70.0
0.00000
7828.
29.23737
29.23737
C.MOIS
345.6
70.0
0.00000
AIR
3780.0
495.0
293.0
.38942
STEAM
1476.0
425.0
293.0
1.72533
PRG.N2
50.0
70.0
0.00000
TOTAL
9386.6
31.35211
GASIFIER
HEAT BALANCE OUTPUTS
TOTAL
TOTAL
SENSIBLE
CHEMICAL
TOTAL
MASS
TEMP
PRES.
HEAT
HHV
HEAT
HEAT
(LB/HR)
(F)
(PSIG)
(UNITS)
(BTU/LB)
(UNITS)
(UNITS)
N2
2868.8
954.2
.64858
.64858
02
1.7
954.2
.00034
.00034
C02
1855.1
954.2
.40176
.40176
AR
46.5
954.2
.00511
.00511
CO
1571.9
954.2
.35839
4346.
6.83160
7.18998
H2
90.7
954.2
.27808
61030.
5.53579
5.81388
CH4
207.4
954.2
.13579
23886.
4.95480
5.09059
H2S
1.6
954.2
.00038
7105.
.01127
.01165
DRY GAS
6643.7
954.2
1.82843
2609.
17.33346
19.16190
R.G H20
1959.0
954.2
290.0
2.86754
CLH.LOS
117.3
120.0
290.0
.01624
2015.
.23636
.25260
TAO
152.8
954.2
.05404
*15181.
2.31974
2.37378
D.FINES
30.0
954.2
.01416
10414.
.31242
.32658
D.SOLID
278.5
340.0
.01684
* -8 5.
-.02375
-.00690
S.MOIS
78.5
340.0
290.0
.08631
ALH.LOS
18.5
250.0
290.0
.00569
CONDEN.
80.0
250.0
.01441
ADJ.NIT
15.5
954.2
.00351
COOL.W
.50000
SHELL L
.50000
TOTAL
9373.9
26.08540
IN/OUT
1.0014
1.2019
(UNITS)=MILLION BTUS PER HOUR BASE TEMP (F)- 70.0
COLD GAS EFF (%)- 59.29 ENTAL CONV EFF (%)= 55.29
DRY GAS HEAT VAL (BTU/SCF): HHV-172.45 LHV=159.04 AT BASE T & STP
(STP)=1 ATM & 70 F
CP (BTU/LB/F)
WOOD - .622
FINES - .534
TAO - .400
SOLIDS= .224
AVE WOOD ADDED AT ONE TIME = 300. LBS
AVE SOLIDS REMOVED AT ONE TIME= 100. LBS
V-CLH= 13.00 FT3
V-ALH= 7.27 FT3
AVE COAL BULK DENS. = 37.0 LB/FT3
AVE SOLIDS BULK DENS= 60.0 LB/FT3
PRES.N2 TEMP- 60.0 F
'Calculated; tAbbreviations listed in Table D.5
D-3
-------
Table D.3 Gasifier Mass Balance - Wood Chips (290 psig)
10/30/91 1645 to 10/31/91 1900t
GASIFIER INPUTS
(LBM/HR)
C
H
O
N
AR
S
ASH
TOTAL
D.WOOD
1092.0
134.2
865.1
9.6
.9
25.3
2127.0
W.MOIS
12.3
98.0
110.3
AIR
.3
0.0
584.1
1903.2
32.4
2520.0
STEAM
112.8
895.2
1008.0
PRG.N2
50.0
50.0
TOTAL
1092.3
259.3
2442.3
1962.8
32.4
.9
25.3
5815.3
GASIFIER
OUTPUTS
(LBM/HR)
C
H
0
N
AR
S
ASH
TOTAL
N2
1899.5
1899.5
02
1.1
1.1
C02
359.2
957.1
1316.3
AR
30.5
30.5
CO
416.4
554.7
971.0
H2
51.7
51.7
CH4
138.8
46.6
185.4
H2S
.0
.2
.2
DRY GAS
914.4
98.3
1512.8
1899.5
30.5
.2
4455.8
R.G K20
127.7
1013.5
1141.2
CLH.LOS
27.6
6.8
76.2
57.3
.9
.0
168.9
TAO
65.9
4.5
5.8
.1
.5
1.6
78.4
D. FINES
10.8
.2
.2
.1
.0
.9
12.1
D.SOLID
.9
.1
2.5
.0
.0
24.1
27.7
S.MOIS
2.2
17.1
19.2
ALH.LOS
.0
.1
.8
1.0
.0
1.8
CONDEN.
5.4
42.9
48.4
ADJ.NIT
4.8
4.8
TOTAL
1019.6
245.2
2671.9
1962.8
31.5
.7
26.6
5958.3
IN/OUT
1.0713
1.0577
.9141
1.0000
1.0292
1.1530
.9527
.9760
MOLEt N2 02
C02
AR
CO
H2
CH4
H2S
H20
DRYG 39.791 .020
17.552
.449
20.344
15.059
6.781
.004
WETG 29.008 .015
12.795
.327
14.831
10.978
4.944
.003
27.100
BLST 47.525 12.750
.018
.567
39.140
DRY COMP C H
0
N
S
ASH
WOOD 51.34 6.31
40.67
.45
.04
1.19
FINES 88.93 1.55
1.52
.88
.07
7.05
TAO 84.08 5.73
7.44
.12
.63
2.00
SOLIDS 3.33 .22
9.08
.14
.04
87.19
MOLES D.G=170.40 DGMW*=26.15 TAO= .01760 f/tDG W.WOOD=2237.3 #/HR
MOLES W.G=233.75 WGMW-23.94 PRE-290.00 PSIG MOIS.%= 4.93
VOL.M=84.53%DC
P¥R.F=23.00%VM
C.E%»83.74 BOT.SOLID= 46.9 #/HR AMW=28.96 S/A- .400 #/#
S.U*=38.75 MOTS.(%) =41.00 BMW=24.68
tAbbreviations listed in Table D.5
D-4
-------
Table D.4 Gasifier Energy Balance - Wood Chips (290 pslg)
10/30/91 1645 to 10/31/91 1900t
GASIFIER HEAT BALANCE INPUTS
TOTAL TOTAL
SENSIBLE CHEMICAL TOTAL
MASS TEMP PRES. HEAT HHV HEAT HEAT
(LB/HR) (F) (PSIG) (UNITS) (BTU/LB) (UNITS) (UNITS)
D.WOOD
2127.0
70.0
0.00000
8492.
18.06249
18.06249
C.MOIS
110.3
70.0
0.00000
AIR
2520.0
608.0
293.0
.33104
STEAM
1008.0
426.0
293.0
1.17900
PRG.N2
50.0
70.0
0.00000
TOTAL
5815.3
19.57254
GASIFIER HEAT BALANCE OUTPUTS
TOTAL
TOTAL
SENSIBLE
CHEMICAL
TOTAL
MASS
TEMP
PRES.
HEAT
HHV
HEAT
HEAT
(LB/HR)
(F)
(PSIG)
(UNITS)
(BTU/LB)
(UNITS)
(UNITS)
N2
1899.5
1115.3
.51189
.51189
02
1.1
1115.3
.00027
.00027
C02
1316.3
1115.3
.34487
.34487
AR
30.5
1115.3
.00397
.00397
OO
971.0
1115.3
.26417
4346.
4.22030
4.48447
H2
51.7
1115.3
.18794
61030.
3.15688
3.34482
CH4
185.4
1115.3
.14943
23886.
4.42809
4.57751
H2S
.2
1115.3
.00007
7105.
.00165
.00171
DRY GAS
4455.8
1115.3
1.46261
2650.
11.80691
13.26952
R.G H20
1141.2
1115.3
290.0
1.76821
CLH.LOS
168.9
120.0
290.0
.02025
2110.
.35628
.37653
TAO
78.4
1115.3
.03279
*15232.
1.19449
1.22728
D.FINES
12.1
1115.3
.00784
13821.
.16723
.17507
D.SOLID
27.7
340.0
.00167
* 316.
.00874
.01042
S.MOIS
19.2
340.0
290.0
.02115
ALH.LOS
1.8
250.0
290.0
.00057
CONDEN.
48.4
250.0
.00870
ADJ.NIT
4.8
1115.3
.00129
COOL.W
.50000
SHELL L
.50000
TOTAL
5958.3
17.85873
IN/OUT
.9760
1.0960
(UNITS)=MILLION BTUS PER HOUR BASE TEMP (F)= 70.0
COLD GAS EFF (%)- 65.37 ENTAL CONV EFF (%)= 60.32
DRY GAS .HEAT VAL (BTU/SCF): HHV=179.14 LHV=165.07 AT BASE T fi STP
(STP)=1
ATM i
70 F
CP (BTU/LB/F)
AVE
WOOD ADDED AT ONE
TIME = 150. LBS
V-CLH=
13.00 FT3
WOOD =
.596
AVE
SOLIDS REMOVED AT
ONE TIME= 100. LBS
V-ALH=
7.27 FT3
FINES =
.620
TAO . =
.400
AVE
WOOD BULK DENS. =
15.0 LB/FT3 PRES.N2
TEMP=
60.0 F
SOLIDS=
.224
AVE
SOLIDS BULK DENS=
60.0 LB/FT3
'Calculated; 1"Abbreviations listed in Table D.5
D-5
-------
Table D.5 Abbreviations Used in Tables D.1 Through D.4
#/#DG
Pounds/Pounds Dry Gas
LHV
ADJ.NIT
N2 adjustment to balance N2 flows
MOIS.
ALH.LOS
Ash Lockhopper Loss (vent gas)
MOIS.%
AMW
Air Molecular Weight
MOLE%
AR
Argon
MOLES D.G.
BLST
Blast (air + steam)
MOLES W.G
BMW
Blast Molecular Weight
N
BOT.SOLID
Bottom Solids
0
G
Carbon
PRE
C.E.%
Carbon Efficiency Percentage
PRES.N2
CH4
Methane
TEMP
CLH.LOS
Coal Lockhopper Loss
PRG.N2
CO
Carbon Monoxide
PYR.F
C02
Carbon Dioxide
R.G.H20
CONDEN
Condensate
S
COOL.W
Cooling Water
S.MOIS
CP
Specific Heat at Constant Pressure
S.U.%
D,FINES
Dry Fines
S/A
D.SOLID
Dry Solids
SHELLL
D.WOOD
Dry Biomass Feed, weight
TAO
DC
Dry Composition
V-ALH
DGMW
Dry Gas Molecular Weight
V-CLH
DRYCOMP
Dry Composition
VOL.M
DRYG
Dry Gas
VM
ENTAL CONV
W.MOIS
EFF
Enthalpy Conversion Efficiency
W.WOOD
H
Hydrogen
WETG
H2S
Hydrogen Sulfide
WGMW
HHV
Higher Heating Value
Lower Healing Value
Moisture
Moisture Percent
Mole Percent
Moles Dry Gas
Moles Wet Gas
Nitrogen
Oxygen
Pressure
Pressurized Nitrogen Temperature
Nitrogen Purge, weight
Pyrolysis
Raw Gas Water
Sufur
Solids Moisture
Steam Utilization Efficiency
Steam/Air Ratio
Shell Loss
Tars and Oils
Volume Ash Lockhopper
Volume Coal Lockhopper
Volatile Matter
Volatile Matter
Biomass Moisture, weight
Weight of Wood
Wet Gas
Wet Gas Molecular Weight
D-6
-------
Appendix E
QA PROJECT PLAN FOR THE VERMONT
BIOMASS GASIFICATION PROJECT
E.1 SCOPE
In accordance with the quality requirements of the Air and Energy Engineering Research
Laboratory (AEERL) of the Environmental Protection Agency (EPA), the following QA Project
Plan (QAPjP) has been developed to address the biomass gasification testing to be performed
by the GE Research and Development Center (GE-CRD). This project is jointly funded by the
State of Vermont, the EPA, the Department of Energy, and the U.S. Agency for International
Development. In accordance with the guidelines of the AEERL Quality Assurance Procedures
Manual for Contractors and Financial Assistance Recipients (November 1991 Draft), this
project is considered a Category IV effort, assessing the feasibility of utilizing gasified biomass
as a fuel for high-efficiency gas-turbine-based power generation cycles. The QA Project Plan
will include the elements discussed in Appendix E of the AEERL QA Manual and will reference
procedures and data to be included in the GE-CRD Final Report on the Biomass Gasification
Pilot Plant Study.
E.2 PROJECT DESCRIPTION
The objective of this program is to utilize the GE Pilot Gasification facility, located in
Schenectady New York, to gasify a variety of biomass feedstocks and perform chemical
analysis of the low-Btu fuel gas derived from these fuels to determine whether they are
suitable for use as a fuel in a gas-turbine-based power system.
The pilot gasification facility consists of an advanced fixed-bed gasifier, a full-flow, high-
temperature gas cleanup system, and a computerized data acquisition, analysis, and control
system. The gasification system was originally designed to gasify approximately one ton of
coal per hour, operating at a pressure of 300 psi, and producing gas at approximately 1000 °F.
The raw, low-Btu gas produced by the gasifier is then subject to gas cleanup consisting of a
single stage of cyclone cleaning to remove fine particulate matter from the gas stream. The
cleaned gas is then sent to a flare for combustion prior to being released.
Samples of gas, solid, and condensible vapor streams are obtained at predefined sample
points throughout the gasifier/cleanup system. These samples are then analyzed to quantify
the composition of all input and output flow streams. Mass balances are then constructed to
determine the fate of all species and components of interest. Primary consideration is given to
the chemical composition and particulate loading of the fuel gas stream leaving the system.
The gas, solids, and condensate measurement system has been developed by GE-CRD
over a 15-year period in conjunction with a DOE-sponsored program to develop an advanced
cleanup system for coal gasification products. All measurements will be performed by GE-CRD
personnel assigned to the pilot gasification facility. The measurement system uses on-line gas
chromatographs and mass spectrometers, in conjunction with grab samples, isokinetic
particulate sampling, and standard chemical analysis of solids and liquid streams. Detailed
procedures for the sampling system will be included in the final report.
The results of this test program will be used to assess the quality of minimally processed
biomass-derived fuel gas with respect to its use as a potential fuel for gas turbines and to
E-1
-------
make recommendations regarding improvements that may be necessary to meet the gas
turbine fuel requirements. To make this assessment, three basic questions must be
addressed. (1) Are the heating value and chemical composition of the fuel gas of a sufficient
level and composition to result in stable combustion? (2) Is the level of particulate loading/size
distribution in the fuel gas stream acceptable for normal turbine blade life? (3) Are the levels of
alkali metals in the fuel/particulate stream low enough to meet the turbine specifications to
prevent "hot corrosion" of the blade materials. The results of this program will be used to guide
future areas of development concerning improvements in fuel quality.
E.3 DATA QUALITY INDICATORS: GOALS FOR CRITICAL MEASUREMENTS
Types of Data to be Collected
As previously noted, the primary types of data to be collected are the chemical composition
of the fuel gas and the loading and chemical composition of the particulate material entrained
with the fuel gas. This data is gathered at several points throughout the system, using gas
conditioning and particulate sampling setups as shown in Figures E-1 through E-3.
Figure E-1 shows the sampling locations to be used for the biomass feedstock trials as well
as the analytical capabilities of the gas sampling system. Sample Points © and ® will be used
to obtain process gas samples for determination of gas composition, and tar, oil, and water
vapor concentrations. Hot particulate sampling will be performed at the outlet of the primary
cyclone to determine particulate and alkali loading in the cleaned gas. Solids samples of the
incoming fuel, gasifier ash, and cyclone dust will be taken at intervals throughout the test for
composition analysis.
Required Data Quality
The data gathered must have sufficient accuracy to answer three basic questions: (1) Are
the heating value and composition of the fuel gas adequate for combustion in a gas turbine?
(2) Is the particulate loading low enough to prevent erosion of the turbine? (3) Does the fuel
gas/particulate mixture contain significant amounts of alkali metals?
To determine the heating value of the fuel gas, the major flammable/nonflammable
chemical constituents (H2, CH4, CO, C02, N2, H20) must be known with reasonable accuracy,
within 2% of the total amount of the species under measurement. As noted the chemical
composition of the fuel gas is measured using laboratory gas chromatographs and a mass
spectrometer. The required accuracy is easily achieved with this type of analysis equipment.
The particulate sampling system is based on measuring a specific gas flow through a
heated filter for a fixed period of time and weighing the filter element to determine the increase
in the filter weight. The accuracy of the particulate measurement should be on the order of
10% of the total to determine whether the particulate loading in the gas stream is acceptable. It
should be recognized that the particulate sampling is performed over a period of approximately
120 minutes and thus represents an average over this time period, and allows more accurate
measurement of the gas flow and solids. The isokinetic flow through the filter system is set to
within 10% of the desired flowrate, and the flow is measured using an orifice-differential
pressure arrangement. The flow measurement is monitored by the data acquisition system and
the flow values are integrated over the measurement period to correct for any minor changes
in flow through the filter. The filter is weighed before and after the test period. A micro balance
E-2
-------
Flare
Particulate
Fuel
Sample Point (2)
Primary
Cyclone
Fuel
Gas
Dust
Sample Point (T)
Ash
GAS
Gas Chromatograph #1
Varian 37QD
Thermal Conductivity
Column:Carbosleve S-ll
H2
N2/02/Ar
CO
CH4
C02
(% Concentrations)
Gas Chromatograph #3
Varian 3400
Flame Photometric
Column: Chromosil 310
H2S
COS
CS2
(Low Concentration)
Ippm Concentrations)
Mass Spectrometer
Perkin-Eimer
MGA 1200
Ranges
N2: 0-100%
NH3: 0-2%
CO: 0-20%
C02:0-20,100%
H2: 0-20, 100%
02:0-2%
CH4:0-10%
H2S: 0-1%
SOLIDS - Fuel, Ash, Dust, Particulate
LIQUIDS - Condensate, Tars, Oils
Figure E-1. Schematic of sampling points in the pilot gasification facility
with an accuracy of milligrams is used, and the weight gain is on the order of several grams.
Based on this procedure, results are expected to be accurate to within 10%.
The measurement of the alkali metals in the gas/particulate stream is determined by
analyzing the ultimate chemical composition of the particulate matter captured in the
particulate measurement system. This approach is based on the understanding that at 1000 °F
all alkali metal compounds are in a solid form as particulate; thus by measuring the alkali
content of the particulate, and knowing the total particulate loading in the fuel gas, the overall
alkali content of the gas can be determined. This measurement shall be accurate to
approximately 10% to verify the adequacy of the fuel for use in gas turbines.
E-3
-------
Level of QA/QC Planned
GE Research and Development Center's Advanced Project Laboratory maintains a high-
level of quality with respect to data measurement. Instruments are regularly calibrated before
and during test runs to known calibration standards. Gasifier test data is reviewed for
consistency with respect to previous runs of similar nature, and due to the length of the test
runs (40-80 hours) multiple data measurements are made and reviewed for repeatability.
Prior to each run the entire gas measurement system is calibrated using standard
calibration gases. The calibration gases are certified to within 1% of the gas species content.
Flow measurement transducers are calibrated prior to every run, and standard ASME orifice
plates and mountings are used. The measurements are accurate to within 5%. Chemical
analyses of samples are performed by commercial testing labs to ASTM standards. Ultimate
chemical analyses, such as those performed on particulate, are accurate to within 0.1%.
Fuel gas from Sample Points © and (2) passes through a conditioning system, shown in
Figure E-2, which cools the gas and condenses water, tars, and oils prior to analysis. Fuel gas
conditioning is required to avoid fouling of the gas chromatograph columns and the mass
spectrometer. Water, tars, and oils are collected and measured in the condensate traps to
determine their concentration in the raw gas. Proximate and ultimate analyses are performed
on the condensate, tars, and oils to determine chemical composition. The gas streams are
analyzed using one of two gas chromatographs or a mass spectrometer. In addition, gas grab
samples from either Sample Point CD or Sample Point (?) can be obtained by means of a
portable sample bomb and analyzed off-line for ammonia and hydrogen cyanide
concentrations.
High—Pressure Steam
High-Pressure Nitroqen^|j
(probe purge)
P«300 pswj
flowrote=40 cc/sec
O 40 psig (to analyzers)
3/8 heated hose from Gasifier Offtake
P=300 psio
flowrate-40 cc/sec
O 40 psig (to analyzers)
H
3/8* heated hose from Primary Cyclone
©
-*fi—(5 ass Wool) ~&-
H! ~
1
r©
III
• purge
®
Constant Temp. Bath
-Maintained ot ~20T
for Controlled Condensation
/ Bolston \
V Filter J~7,
4a
Air-Actuated Forward
8et1ows Pressure
Valve Regulator
to
analyzer
t 1
Figure E-2. Conditioning system: Gasifier sample trains
E-4
-------
Hot, isokinetic, particulate sampling is performed at the outlet of the primary cyclone to
collect samples of particulate matter and determine the loading and size distribution of the
particles present in the fuel gas. Particulate samples are obtained by flowing the raw gas
through a high-temperature filter. The primary cyclone sampling system is shown in Figure E-3.
Proximate and ultimate analyses are performed on the collected sample to determine chemical
composition, and laser particle size analysis is performed to determine particle size distribution.
Fuel, gasifier ash, and cyclone dust samples are collected at prescribed intervals during
the test. Proximate and ultimate analyses are performed to determine chemical compositions.
Mineral analysis is performed on the fuel and gasifier ash samples.
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Figure E-3. Primary cyclone particulate sampling
E-5
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1. RfcPOH r NC. 7.
EPA-600/R-93-170
3.
4. T 1 f Lb AND SUBTI T l.F
Biomass Gasification Pilot Plant Study
5. REPORT UATfc
September 1993
6. PfcHFORMING ORGANIZATION CODE
7. AUTHOR(S)
A. II. Furman, S. G. Kimura, R. E. Ayala, and
J. F. Joyce
8. PERFORMING ORGANIZATION REPORT NO.
9. PERKOHMING OPOANIZA HON NAMfc AND ADDRESS
GE Research and Development Center
P. C. Box 8
Schenectady, New York 12301
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
0938222 (Vermont DPS)
CR817675 (EPA)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE Or RfcPORT AND PERIOD COVERED
Final; 7/90 - 3/93
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary notes ^EERL project officer is Carol R. Purvis, Mail Drop 63, 919/541-
7519. Vermont DPS project officer is Richard Sedano (State of Vermont Dept. of
Public Service, State Office Bldg. , Montpelier, VT 05602).
TECHNICAL REPORT DATA
/Please read IwUntctiviis on the reverse before eomplet
feedstocks: bagasse pellets and wood chips. The object of the program was to deter-
mine the properties of biomass product gas and its suitability as a fuel for gas-
turbine-based power generation cycles. The feedstocks were gasified at a feed rate
of approximately 1 ton/hr (907 kg/hr), using a GF1 pressurized, fixed-bedgasifier
and a single stage of cyclone particulate removal, operating at 538 C. The biomass
product gas was analyzed for chemical composition, loading, fuel-bound
nitrogen (FBN) levels, and sulfur and alkali content. Both feedstocks gasified easily.
The composition and heating value of the biomass product gas were compatible with
gas turbine combustion requirements. However, the particulate removal perfor-
mance of the pilot facility single-stage cyclone did not meet turbine specifications.
In addition, alkali metal compounds in the particulate matter (at 538 C) carried over
from the gasifier exceeded turbine limits. Improved particulate removal technology,
designed specifically for biomass feedstock characteristics, could meet turbine re-
quirements for both particulate and alkali loading. FBN compounds were also mea-
sured since they can be converted to nitrogen oxides (NOx) during combustion in a
gas turbine.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Biomass
Gasification
Bagasse
Wood
Gas Turbines
Particles
b.IDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Particulate
Wood Chips
c. COSATI Field/Group
13 B 14 G
08A.06C
13H,07A
HE
IIL
13 G
3. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
100
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
E-6
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