EPA
TVA
U S Environmental
Protection Agency
Office of i
and Development
Tennessee
Auth-
Impact of Ammonia
Utilization by NOX Flue
Gas Treatment Processes
Interagency
Energy/Environment
R&D Program Report
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EPA-600/7-79-011
January 1979
Impact of Ammonia
Utilization by NOX Flue
Gas Treatment Processes
by
T.A. Burnett and H.L Faucett
Tennessee Valley Authority
National Fertilizer Development Center
Muscle Shoals, Alabama 35660
EPA Interagency Agreement D8-E721-FU
Program Element No. 1NE624
EPA Project Officer: J. David Mobley
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park. NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington. DC 20460
-------
DISCLAIMER
This report was prepared by the Tennessee Valley Authority and has been
reviewed by the Office of Energy, Minerals, and Industry, U.S. Environmental
Protection Agency, and approved for publication. Approval does not signify
that the contents necessarily reflect the views and policies of the Tennessee
Valley Authority or the U.S. Environmental Protection Agency, nor does mention
of trade names or commercial products constitute endorsement or recommendation
for use.
ii
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ABSTRACT
At the present time, the most technologically advanced type of flue gas
treatment (FGT) system for the removal of nitrogen oxides (NOx) from power
plant stack gas is selective catalytic reduction (SCR) using ammonia (NH3).
One of the major economic considerations in the widespread application of these
FGT systems is the impact of this demand on the domestic NH-j market. Annual
NH3 FGT requirements for typical fossil fuel-fired boilers were calculated and
the annual NH3 requirement for NOx FGT was predicted for the period 1978-2000.
The total NH3 supply and demand were also projected for the period 1978-2000
and compared with the projected annual NH3 demand for NOx FGT« Based on the
premises of this study this NH3 demand for NOX FGT systems would begin gradually
and rise at relatively slow rates, thus giving the domestic NH3 market adequate
time to adjust to this increased demand. Under other assumptions, such as
requiring NOx FGT systems on all large boilers, significant impacts and market
disruptions can be foreseen. The current and projected NH3 production techniques
were outlined and the 1978 unit production cost for NH3 was estimated for four
potential feedstocks. Since the hydrogen (H2) feedstock cost represents a
significant portion of the cost of generating NH3 and the cost of these feed-
stocks during the period 1978-2000 is uncertain, the unit production costs for
NH3 during the period 1980-2000 were not estimated.
iii
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CONTENTS
Abstract ...............................
Figures ............................... vii
Tables ................................ ix
Abbreviations and Conversion Factors ................. xil
Executive Summary
Introduction ............................. 1
Formation of NOx In Large Boilers ................. 3
Potential NOx Control Methods for Large Boilers .......... 3
NHj Requirements for NOx Control ................... 7
NH3 Requirements for Typical Power Plant Applications ....... 7
Projection of Coal-Fired Generating Units ...... . ...... 12
NH3 Requirements for Both Utility and Industrial Boilers ..... 19
Current NH3 Supply and Demand ................... 22
Comparison of Projected NH3 Demand for NOx FGT with Potential
NH3 Supply ............................ 23
Current NHs Generating Techniques .................. 33
Steam Reforming of Natural Gas ................... 33
Processing Scheme ........................ 34
CO Conversion .......................... 34
Final Purification ........................ 38
NH3 Synthesis ........................... 39
Raw Material, Utility, Labor, and Energy Requirements ...... 41
Process Economics ........................ 41
Other Current NH3 Generating Techniques .............. 43
Refinery Gas ........................... 47
Electrolytic Cells ........................ 48
Coke-Oven Gas .......................... 48
Raw Material, Utility, Labor, and Energy Requirements ...... 51
Potential Future NH3 Generating Techniques .............. 52
Steam Reforming of Naphtha ..................... 52
Process Description ....................... 52
Raw Material, Utility, Labor, and Energy Requirements ...... 54
Process Economics ............. . .......... 54
Partial Oxidation of Hydrocarbons ................. 55
Process Description ....................... 60
Raw Material, Utility, Labor, and Energy Requirements ...... 64
Process Economics ........................ 64
v
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NH3 from Coal 65
Process Description 65
Raw Material, Utility, Labor, and Energy Requirements 74
Process Economics 74
NH3 Imports 76
Projected Mexican NH3 Capacity and Production 76
Economic Comparison of NH3 Production Cost for Various H2 Feedstocks. 81
Current and Projected Natural Gas Supply and Demand 83
Conventional Natural Gas Supplies 86
Supplemental Natural Gas Supplies 87
SNG from Oil and Coal 87
Importation of Natural Gas from Canada 89
Importation of Natural Gas from Mexico 91
Alaskan Natural Gas 93
Importation of Liquefied Natural Gas 93
New Technologies 98
Other Sources of Natural Gas 99
Conclusions 101
Onsite Generation Versus Onsite Storage of NH3 for NO* FGT Systems. 101
Impact of NH3 Demand for NOx FGT on the Domestic NH3 Market .... 101
Current NH3 Production Economics 103
References 104
vi
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FIGURES
Number Page
S-l Projected change in emissions for the five major air
pollutants during the period 1975-1990 xvi
S-2 Comparison of the projected NH3 demand for NOx FGT with
conventional NH3 demand for selected years during the period
1980-2000 (case 1 only) xxii
1 Breakdown of the total U.S. NOx emissions by original
source 2
2 NOX removal efficiency as a function of NH3:NOX mol ratio. . 9
3 Annual NH3 consumption for selected 500-MW boilers for
NOx FGT as a function of NH3:NOx mol ratio 10
4 U.S. electrical generating capacity by fuel type for the
years 1975-1985 14
5 Projected U.S. electrical generating capacity for the
period 1985-2000 at three different annual growth rates . . 15
6 Projected U.S. NH3 demand during the period 1975-2000 at
three annual growth rates 24
7 Annual operating rate of U.S. NH3 plants from 1965-1981 . . 26
8 Projected U.S. NH3 capacity during the period 1975-2000
at three annual growth rates 27
9 Comparison of the projected NH3 demand for NOX FGT with
conventional NH3 demand for selected years during the
period 1980-2000 (case 1 only) 29
10 Block flow diagram of a typical NH3 plant based on natural
gas as the H£ feedstock 35
11 Diagram of typical primary reformer 36
12 Diagram of quench-type converter 40
13 Block flow diagram of a typical NH3 plant based on coke-
oven gas as the H2 feedstock 50
14 Block flow diagram of a typical NH3 plant based on naphtha
as the H£ feedstock 53
15 Block flow diagram of a typical NH3 plant based on heavier
hydrocarbons as the H2 feedstock 59
16 Block flow diagram of a typical NH3 plant based on coal
as the H2 feedstock 69
17 Net U.S. imports and exports of NH3 during the period
1965-1981 79
18 Geographic location of U.S. NH3 plants operating before
1975 84
19 Geographic location of new U.S. NH3 plants operating after
1975 85
vii
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FIGURES (continued)
Number Page
20 Proven U.S. natural gas reserves during the period
1968-1980 88
21 Natural gas imports from Canada during the period
1955-1976 90
22 Natural gas imports from Mexico during the period
1955-1976 92
viii
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TABLES
Number Page
S-l NHg Consumption for Typical 500-MW Coal- and Oil-
Fired Boilers xvii
S-2 Projected U.S. Electrical Generation Capacity by
Fuel for Selected Years During the Period 1975-2000 xviii
S-3 Projected Coal-Fired Power Plant Additions and the
Resulting NHo Demand for NOX FGT During the Period
1984-2000 xix
S-4 Comparison of Annual NH3 Demand for NOx FGT for Three
Options During the Period 1985-2000 xxi
S-5 Comparison of Unit Labor and Energy Requirements per
Ton of NH3 Produced from Various Potential H£
Feedstocks in 1978 xxiii
S-6 Alternative Feedstock Costs and the Resulting Unit
Production Costs of NH3 in 1978 xxiv
1 NO Emissions by Source in 1975 3
2 Effects of Boiler Modifications to Reduce NOx Emissions
by Fossil Fuel Type 5
3 Flue Gas Compositions from 500-MW Coal- and Oil-Fired
Boilers 8
4 Premises for the Calculation of Annual NH3 Consumption
for 500-MW Fossil-Fired Boilers 11
5 NH3 Consumption for Typical 500-MW Coal- and Oil-Fired
Boilers 11
6 Projected U.S. Electrical Generating Capacity by Fuel
Type for the Years 1975-1985 12
7 Estimated U.S. Generating Capacity Additions by Fuel
Type for the Period 1976-1985 13
8 Projected Electrical Generating Capacity by Fuel Type
in the Year 2000 16
9 Projected Coal-Fired Power Plant Additions and the
Total Coal-Fired Generating Capacity by Year for the
Period 1984-2000 17
10 Comparison of Projected Annual U.S. NH3 Consumption by
Alternative NO^ FGT Systems at all New Coal-Fired
Power Plants 18
11 Estimated NOX Emissions from Various Sized Boilers in
1975 and 1985 20
12 Comparison of the Projected Annual NH3 Demand for NOx
FGT During the Period 1985-2000 for Two Cases: Required
on Only New Utility Boilers or for All New Large
Boilers 21
±x
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TABLES (continued)
Number Page
13 U.S. NH3 Demand 1965-76 22
14 U.S. NH3 Plant Capacity Additions and Total U.S. NH3
Plant Capacity During the Period 1967-1980 25
15 Comparison of the Estimated Annual NH3 Demand for
NOX FGT with the Projected Conventional U.S. NH3
Demand During the Period 1985-2000 28
16 Projected U.S. NH3 Demand for NO* FGT for the
Period 1985-2000 if all Coal-Fired Power Plants
Required Treatment 31
17 Typical Natural Gas Composition 33
18 Typical Gas Composition Entering and Leaving Secondary
Reformer 37
19 Typical Synthesis Gas Composition Before and After
Methanation 39
20 Unit Raw Material, Utility, Labor, and Energy Requirements
for the Production of NH^ from Natural Gas 41
21 Annual Capital Charges for Chemical Industry Financing ... 42
22 Assumptions Used to calculate the NH3 Production Costs ... 43
23 Total Annual Operating Costs and Unit Operating Costs for a
1000 Ton/Day NH3 Plant Using Natural Gas as the H£
Feedstock (Low Feedstock Cost Case) 44
24 Total Annual Operating Costs and Unit Operating Costs for a
1000 Ton/Day Nl?3 Plant Using Natural Gas as the H£
Feedstock (Medium Feedstock Cost Case) 45
25 Total Annual Operating Costs and Unit Operating Costs for a
1000 Ton/Day NH3 Plant Using Natural Gas as the H2
Feedstock (High Feedstock Cost Case) 46
26 Typical Compositions of Refinery Off-Gases 47
27 Typical Composition of Coke-Oven Gas 49
28 Unit Raw Material, Utility, Labor and Energy Requirements
for the Production of NH3 from Coke-Oven Gas 51
29 Unit Raw Material, Utility, Labor, and Energy Requirements
for the Production of NH3 from Naphtha by Steam
Reforming 54
30 Total Annual Operating Costs and Unit Operating Costs for
a 1000 Ton/Day NH3 Plant Using Naphtha (Steam Reforming)
as the H2 Feedstock (Low Feedstock Cost Case) 56
31 Total Annual Operating Costs and Unit Operating Costs for
a 1000 Ton/Day NR3 Plant Using Naphtha (Steam Reforming)
as the H2 Feedstock (Medium Feedstock Cost Case) 57
32 Total Annual Operating Costs and Unit Operating Costs for
a 1000 Ton/Day NH3 Plant Using Naphtha (Steam Reforming)
as the H2 Feedstock (High Feedstock Cost Case) 58
33 Typical Operating Parameters for Production of NH3
Synthesis Gas from Various Hydrogen Feedstocks Using
the Shell Gasification (Partial Oxidation) Process 61
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TABLES (continued)
Number Page
34 Typical Feedstocks Used in the Shell Gasification
Process (Partial Oxidation) 62
35 Typical Compositions of Gases to and from a Cryogenic
Purification Unit 63
36 Unit Raw Material, Utility, Labor, and Energy
Requirements for the Production of NHg from Heavy
Fuel Oil 64
37 Total Annual Operating Costs and Unit Operating
Costs for a 1000 Ton/Day NH3 Plant Using Heavy
Fuel Oil as the H2 Feedstock (Low Feedstock Cost
Case) 66
38 Total Annual Operating Costs and Unit Operating
Costs for a 1000 Ton/Day NH3 Plant Using Heavy
Fuel Oil as the H2 Feedstock (Medium Feedstock Cost
Case) 67
39 Total Annual Operating Costs and Unit Operating Costs
for a 1000 Ton/Day NH3 Plant Using Heavy Fuel Oil
as the H2 Feedstock (High Feedstock Cost Case) 68
40 Typical Exit Gas Compositions for Low and High
Temperature Gasifiers 71
41 Typical Synthesis Gas Composition Before and After
Co Shift 72
42 Typical Synthesis Gas Compositions After C02 Wash
and After Liquid N2 Wash 73
43 Comparison of Typical Raw Gas Composition from the
Texaco With That for a High Temperature Gasifier 73
44 Unit Raw Material, Utility, Labor, and Energy
Requirements for the Production of NH3 from Coal 74
45 Total Annual Operating Costs and Unit Operating Costs
for a 1000 Ton/Day NH3 Plant Using Coal as the H2
Feedstock (Low Feedstock Cost Case) 75
46 Total Annual Operating Costs and Unit Operating Costs
for a 1000 Ton/Day NH3 Plant Using Coal as the H2
Feedstock (Medium Feedstock Cost Case) 77
47 Total Annual Operating Costs and Unit Operating Costs
for a 1000 Ton/Day NH3 Plant Using Coal as the H2
Feedstock (High Feedstock Cost Case) 78
48 Projected Mexican NH3 Plants 80
49 Alternative Feedstock Costs and the Resulting Unit
Production Cost of NH3 in 1978 82
50 Estimates of U.S. Natural Gas Reserves 87
51 Natural Gas Reserves of Various Countries 94
52 LNG Exporting Countries in 1985 95
53 Current and Proposed LNG Base-Load Plants 96
54 Current and Projected LNG Imports and LNG Exports
by Country 97
xi
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ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
o
aftj actual cubic feet Ib
Btu British thermal unit LNG
°C degrees Centigrade M
ESP electrostatic precipitator Mft3/day
°F degrees Fahrenheit mol
FGD flue gas desulfurization MW
FGT flue gas treatment (NOx) MWe
ft feet NGL
ft3 cubic feet Nm3
gal gallon NOx
G billion (giga = 109) ppm
Gft3 billion cubic feet psig
GW gigawatt sft-*
hr hour SCR
1C internal combustion sec
k thousand SNG
kW kilowatt T
kWh kilowatthour Tft3
pound
liquefied natural gas
million (mega = 106)
million cubic feet per day
mole
megawatt
megawatt electric
natural gas liquids
normal cubic meter
nitrogen oxides
parts per million
pounds per square inch gauge
standard cubic feet
selective catalytic reduction
second
synthetic natural gas
trillion (tera = 1012)
trillion cubic feet
year
xii
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CONVERSION FACTORS
To convert from
To
Multiply by
British thermal unit
degrees Fahrenheit-32
feet
cubic feet
feet per minute
cubic feet per minute
gallons
gallons per minute
grains per cubic foot
megawatt (electric)
pounds
tons (short)
tons per hour
gram-calories 252
degrees Centigrade 0.5555
centimeters 30.48
cubic meters 0.02832
centimeters per second 0.508
cubic meters per second 0.000472
liters 3.785
liters per second 0.06308
grams per cubic meters 2.228
standard cubic feet per minute 0.000535
kilograms 0.4536
metric tons 0.90718
kilograms per second 0.252
xiii
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IMPACT OF AMMONIA UTILIZATION BY NOX FLUE GAS TREATMENT PROCESSES
EXECUTIVE SUMMARY
Although nitrogen oxide (NOX) concentration in each individual emission
source is relatively low, the number of these potential sources is increasing
and thus the total amount of NOX emitted in the United States is projected to
increase more than 50% during the period 1975-1990 under the current NOX con-
trol regulations. Even with the widespread application of the best control
technology on all new sources, the total U.S. NOX emissions are expected to
increase by about 25% during this same time period. Since NOX is the only one
of the five major air pollutants to show this dramatic increase (see Figure S-l),
the NOX emission regulations for stationary sources may become more stringent
in the future. The potential for additional regulatory control of NOX emis-
sions from stationary sources is further increased by the recent postponement
of NOX emission regulations on mobile sources.
In terms of total NOX emissions, large fossil-fueled boilers represent
the largest class of stationary sources, releasing over 4.7 Mtons of NOX in
1975. At the present time, two differing types of NOX control methods for
these large boilers are undergoing development in the United States and Japan.
Combustion modifications, which seek to reduce NOX emissions by controlling
boiler operating conditions, and hence preventing the formation of NOX, are
receiving considerable attention in the United States. Although these com-
bustion modifications are relatively inexpensive when compared with other
alternatives, they are apparently limited to reducing NOX emissions by about
50%. Flue gas treatment (FGT) systems which are capable of removing up to
90-95% of the NOX emitted are receiving the major emphasis in Japan, primarily
because the current NOX emission regulations are much more stringent in Japan.
As their name implies these systems involve treating and removing the NOX from
the flue gas after it has been formed. Thus if 90% NOX control from all large
boilers is required in the future, two alternative cases are possible: (1) 90%
NO removal by FGT or (2) combination of 50% NOX reduction by combustion modi-
fication and 80% removal of the remaining NOX by FGT. Although case 2 (50%
reduction by combustion modification and 80% removal by FGT) would appear to
be more attractive if 90% NOX control is required, no comparative economics
have yet been completed and thus both cases will be considered.
From the standpoint of development status, the most advanced FGT systems
now are the selective catalytic reduction (SCR) processes. These processes are
based on ammonia (NH3) selectively reducing NOX in the presence of a base-metal
catalyst. A major concern associated with these processes, if widely applied
in the United States, is the direct impact of this additional NH3 demand on
the NH3 market and the subsequent indirect impact on natural gas availability
for producing the NH^.
xv
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60
50
40
30
co
§
M
CO
CO
z
IH
W
20
10
-10
-20
1975
NOx
CO
1980
1985
1990
YEAR
Figure S-l. Projected change In emissions for the five major
air pollutants during the period 1975-1990.
xv L
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NH3 DEMAND FOR NOx FGT
The annual NH3 requirements for 500-MW coal- and oil-fired boilers were
calculated for both cases, i.e., SCR alone and combustion modification in
combination with SCR. Since the NOX removal efficiency for an SCR system
can best be altered by changing the NH3:NOx mol ratio, a generic curve was
drawn showing the relationship between the NH3:NOX mol ratio and the NOx
removal efficiency. For 90% NOX removal and 80% NOx removal (case 1 and case
2), the NH3:NOx mol ratios were 1.05:1 and 0.91:1 respectively. As shown in
Table S-l, the resulting NH3 consumption rates for a 500-MW coal-fired power
plant range from nearly 6300 tons/yr for the 90% efficient SCR system to about
2700 tons/yr for the combined combustion modification-SCR treatment scheme.
For a 500-MW oil-fired power plant the annual NH3 requirements would range
from nearly 1800 tons for the 90% efficient SCR system to about 800 tons for
the combined treatment scheme. Thus even a 2,500-MW coal-fired power plant
requiring about 31,000 tons/yr could not justify a captive NH3 plant since
the minimum plant capacity for economic production of NH3 is 1,000 tons/day
(330,000 tons/yr). The NH3 for NOx control system would therefore probably
be purchased from an existing NH3 plant and shipped to storage tanks at the
power plant.
TABLE S-l. NH3 CONSUMPTION FOR TYPICAL
500-MW COAL- AND OIL-FIRED BOILERS
NOx
treatment
Fuel scheme
Coal SCRa
Coal CM & SCRb
Oil SCR
Oil CM & SCR
NOx
concentration
in flue gas, ppm
600
300c
200
10QC
Mo Is NH3
per mol
NOx
1.05
0.91
1.05
0.91
NH3 consumption,
tons/yr
6,266
2,715
1,781
772
a. Selective catalytic reduction.
b. Combustion modification followed
by selective
catalytic
reduction.
Combustion modification was assumed to be 50% efficient
in controlling NOX emissions.
The projected U.S. electrical capacity and the fuel mix in these power
plants for the period 1975-2000 was estimated as shown in Table S-2. (Although
the specific generating capacity of both oil- and gas-fired boilers in the
year 2000 has not been given, no new gas-fired boilers are expected to be
built after 1980 and a phaseout of oil-fired boilers is also expected during
the period 1985-2000.) By assuming a retirement factor of 0.5% of the total
xvii
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U.S. installed generating capacity each year, the additional new coal-fired
capacity needed each year was calculated. This post-1985 coal-fired capacity
then is the electrical capacity potentially required to achieve a 90% NOx
removal. Since the annual NH3 requirement for a typical 500-MW coal-fired
boiler had been previously calculated, the estimated additional NH3 demand for
NOX FGT could be projected for both cases, i.e., 90% removal by SCR and 80%
removal by SCR, as shown in Table S-3. Although the widespread application of
NOx FGT would require substantial amounts of NH3, the initial increases in
demand would be small enough to minimize any adverse impacts on the NH3 industry,
i.e., requiring only one new NH3 plant to supply the needs of all the NOx FGT
systems that might come online in 1985 and 1986.
TABLE S-2. PROJECTED U.S. ELECTRICAL
GENERATION CAPACITY BY FUEL FOR SELECTED YEARS
DURING THE PERIOD 1975-2000
Electrical generating capacity, GW
Fuel 1975 1980 1985 2000
Coal 183 247 321 829
Oil 127 155 163 -a
Gas 63 59 49 -a
Nuclear 33 78 174 536
Hydrob 69 80 92 -a
Total 474 619 798 1,658
Total of 256 GW but not broken down into
oil, gas, and hydro although most are
expected to be hydro or new technology
such as geothermal, solar, etc.
Includes hydro, pump storage, and other
miscellaneous.
An alternative case would be the setting of standards which require 90%
removal from all new large boilers (i.e., greater than 250 MBtu/hr) rather
than only new utility boilers. Detailed data on the projected capacity of
new large industrial boilers were not available. Recent historical data,
indicating large industrial boilers emit about 25% of all the NOx emitted
from all large boilers, were used to project the additional NH3 demand for
the widespread application of NH3~based NOx FGT system for all new large boilers.
The NH3 demand for NOx FGT under this alternative case then was estimated as
xviii
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TABLE S-3. PROJECTED COAL-FIRED POWER PLANT
ADDITIONS AND THE RESULTING NH3 DEMAND
FOR NOx FGT DURING THE PERIOD 1984-2000
New coal-fired Annual NH3 consumption,3 ktons,
Year capacity, GW
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
19
15
23
24
26
27
29
31
33
35
37
40
42
45
48
51
55
Case 1&
0
94
332
626
939
1,271
1,622
1,998
2,399
2,825
3,276
3,759
4,273
4,818
5,401
6,022
6,687
Case 2c
0
41
144
271
407
551
703
866
1,039
1,224
1,419
1,629
1,851
2,088
2,340
2,609
2,897
Basis
NOx FGT required only for new, coal-fired power
units coming online after January 1, 1985.
Ninety percent removal by selective catalytic
reduction.
Ninety percent removal by combined combustion
modification and selective catalytic reduction.
xix
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25% higher than that for new utility boilers only. Although the actual numbers
change, the result remains the same, i.e., the initial increases in NH3 demand
are sufficiently small so that no abrupt adverse impacts on the NH3 industry
are anticipated.
The available NH3 supply to meet both the conventional NH3 demands and
annual growth of this additional demand for NOx FGT was projected using an
assumed annual growth rate of 3.0%. Since most of the current NH3 demand is
for agricultural uses and no substantial increase in the application rate is
anticipated, the expected growth rate of the domestic NH3 demand was projected
at slightly below the recent historical rate. Under this scenario present NH3
production of 16.4 Mtons (1976) would increase to about 33.1 Mtons in the year
2000. A comparison of this projected NH3 supply with the increased potential
demand for NH3 for NOX FGT is shown in Table S-4 and Figure S-2 for three
alternative scenarios: (1) new large utility boilers only, (2) all new
large boilers, and (3) all large boilers, new and old. For each of these
scenarios, the NH3 consumption rate was calculated assuming that a 90% efficient
SCR system was used for NOx FGT. When using combustion modifications in com-
bination with 80% efficient SCR system, the annual NH3 consumption would be
about 57% less. For the first two scenarios, only new large utility boilers
and all new large boilers, the additional NH3 demand for NOx FGT as a percent
of the total NH3 supply ranges from less than 0.6% in 1985 to about 20-25%
in the year 2000. Thus, although requiring substantial amounts of NH3 during
the later years, the initial need for NH3 for NOX FGT would not have an immediate
substantial impact on the NH3 market.
The third scenario was included to demonstrate the importance of the
premises selected for this study. In an extreme condition such that all
large boilers, both new and old, will require 90% NOx control, the impact
of this additional demand in 1985 would create distortions in the NH3 market
with the resulting adverse impact on the fertilizer industry.
CURRENT AND POTENTIAL NH3 GENERATING TECHNIQUES
Most of the NH3 produced at the present time is based on steam reforming
of natural gas. Although any hydrocarbon could be used, natural gas has the
advantages of a high hydrogen to carbon ratio and a high purity as received
at the plant. The NH3 which is produced from H£ generated by other methods,
such as electrolytic chlorine (Cl2) cells, refinery off-gases, and coke-oven
gas, represents <5% of the total U.S. NH3 supply. Since this H2 is typically
a byproduct stream, it is a relatively cheap source of feedstock but its potential
as a future alternative source of NH3 is severely limited by the demand for the
primary products, i.e., Cl£ and coke.
Other potential feedstocks include petroleum fractions, such as naphtha
and fuel oil, as well as coal. The two major problems with these alternate
feedstocks are a lower hydrogen to carbon ratio and also higher levels of
various impurities. These disadvantages increase the amount of feedstock (on
a Btu basis) needed to generate the same amount of H2 and also increase the
capital investment by requiring both pretreatment of the feedstock and the
xx
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TABLE S-4. COMPARISON OF ANNUAL NH3 DEMAND FOR NO*
FGT FOR THREE OPTIONS DURING THE PERIOD 1985-2000
ProJ acted
Annual NOx FGT NH^ demand,3 Mtons
annual NH3 New large utility
Year supply, Mtons boilers only
1985
1986
1987
1988
1989
1990
1991
1992
1993
x 1994
p. 1995
1996
1997
1998
1999
2000
21.4
22.1
22.7
23.4
24.1
24.8
25.6
26.4
26.9
27.7
28.5
29.4
30.3
31.2
32.1
33.1
0.09
0.33
0.63
0.94
1.27
1.62
2.00
2.40
2.83
3.28
3.76
4.27
4.82
5.40
6.02
6.69
% of
total supply
0.4
1.5
2.8
4.1
5.3
6.5
7.8
9.1
10.5
11.8
13.2
14.5
15.9
17.3
18.8
20.2
All new
large boilers
0.12
0.42
0.78
1.17
1.59
2.03
2.50
3.00
3.53
4.10
4.70
5.34
6.02
6.75
7.53
8.36
% of
total supply
0.6
1.9
3.4
5.2
6.6
8.2
9.8
11.4
13.1
14.8
16.5
18.2
19.9
21.6
23.5
25.3
All large
boilers
5.03
5.36
5.70
6.08
6.48
6.89
7.35
7.84
8.34
8.89
9.46
10.09
10.75
11.44
12.19
12.99
% of
total supply
23.5
24.3
25.1
26.8
26.9
27.8
28.7
29.7
31.0
32.1
33.2
34.3
35.5
36.7
38.0
39.2
a. Basis
FGT system, 90% NOX removal by SCR.
-------
50
40
§
a 30
W
Q
20
Z
10
Legend
L | Conventional NH3 demand
New utility boilers
New large industrial boilers
26.8
21.5
18.5
18.5
0.2
0.9
21.4
0.4
1.6
24.8
33.2
0.9
41.5
1
28.5
1.7
6.7
33.1 -
1980
1985
1990
YEAR
1995
2000
Figure S-2. Comparison of the projected NH3 demand for NOX FGT with
conventional NH3 demand for selected years during the period 1980-2000 (case 1 only)
-------
removal of the additional amounts of impurities. Table S-5 provides a com-
parison of various important operating parameters for generating 1 ton of
NH3 from each of the potential H2 feedstocks. These unit quantities are based
on a 1000 ton/day NH3 plant and include: feedstock, fuel, other energy, total
energy, and labor requirements. As would be expected the labor and the total
energy required per ton of NH3 increases as the feedstock changes from lower
molecular weight, less complex hydrocarbon (natural gas) to the higher molecular
weight, higher impurity feedstock (coal). In fact the labor requirements to
produce 1 ton of NH3 increases by a factor of 2.5 in going from natural gas
to coal as the feedstock while the total energy per ton increases from 31.7
MBtu for natural gas to 41.6 MBtu for coal.
TABLE S-5. COMPARISON OF UNIT LABOR AND ENERGY
REQUIREMENTS PER TON OF NH3 PRODUCED FROM VARIOUS
POTENTIAL H2 FEEDSTOCKS IN 1978a
Natural gas Naphtha Fuel oil Coal
Labor, man-
hr 0.18 0.20 0.23 0.45
Energy, MBtu
Feedstock 19.0 19.4 20.3 27.4
Fuel 12.6 14.1 14.6 13.7
Other 0.1 0.2 0.5 0.5
Total
energy
31.7
33.7
35.4
41.6
a. Basis
Plant capacity, 1000 tons/day.
On-stream time, 330 days/yr.
Current NH3 Production Costs for Various H2 Feedstocks
The feedstock which will be used for NH3 production in the future will
be determined by process economics and the future prices of these various
H2 feedstocks are uncertain at the present time. Current unit production
costs of NH3 for each of the four potential H2 feedstocks were estimated
using three alternative prices as shown in Table S-6. With the current
purchase price of natural gas varying sharply and dependent on numerous
factors, an average price for natural gas would be difficult to identify.
Therefore the range of prices for natural gas shown in Table S-6 was assumed.
Of the three prices assumed for the other three alternate feedstocks (naphtha,
xxiH
-------
fuel oil, and coal), the lower price was typically the current feedstock cost,
the medium price was included to reasonably cover the potential range of the
current feedstock cost, while the higher cost was included to identify an
extreme condition.
TABLE S-6. ALTERNATIVE FEEDSTOCK COSTS AND THE RESULTING
UNIT PRODUCTION COSTS OF NH3 IN 1978
Assumed cost Unit production cost of
Feedstock
Natural gas
Naphtha
Fuel oil
Coal
$/unit
1.00/MBtu
3.00/MBtu
5.00/MBtu
0.40/gal
0.60/gal
0.80/gal
0.35/gal
0.53/gal
0.70/gal
20.00/ton
30. 00 /ton
40.00/ton
$/MBtu
1.00
3.00
5.00
3.00
4.50
6.00
2.43
3.65
4.86
0.95
1.43
1.90
NH3,a $/ton
111
174
237
193
244
294
217
260
302
186
206
225
a. Basis
Plant capacity, 1000 tons/day.
On-stream time, 330 days/yr.
Even with natural gas cost currently ranging up to $2.50/MBtu, it is
apparent that alternate feedstocks cannot economically compete with natural
gas at the present time. Coal at $20.00/ton ($0.95/MBtu) becomes competitive
only after the cost of natural gas exceeds about $3.40/MBtu. It should also
be noted that the unit production costs of NH3 from these feedstocks are based
on current levels of technology and the economics of NH3 production from the
various feedstocks in the future will depend not only on the availability and
cost of feedstocks, but also on innovations resulting from advanced process
development.
POTENTIAL FUTURE SOURCES OF NATURAL GAS
Future supplies of natural gas will be available from either conventional
sources (domestic drilling both onshore and offshore) or supplemental sources
[imported gas, synthetic natural gas (SNG), or Alaskan gas]. Conventional
gas production from known fields is expected to gradually decline in the future
xxiv
-------
as an increasing amount of the gas in these fields is removed. Additional
fields will no doubt be discovered but these will typically be in areas which
have not been explored and thus where production is expected to be more
expensive.
In addition to domestic drilling for gas, numerous other potential sources
of natural gas may be used to supplement this conventional natural gas. These
sources range from importing gas [Canada, Mexico, and liquefied natural gas
(LNG)] to new technologies, such as methane from geopressurized brine, "tight"
shales, and coal mines.
Some of these supplemental sources of natural gas are much more likely
to be used in the near future than others since the technology is currently
available. For example, SNG and imports of natural gas from Canada and Algeria
are already being used to provide additional supplies of natural gas (approximately
1.2 Tft3 in 1978). Other supplemental sources, such as imports from Alaska,
Mexico, and Indonesia, may supply additional natural gas in the near future
since various contracts are being negotiated at the present time. SNG from
coal and other new technologies, although not expected to provide additional
gas in the near future, could be contributing significant amounts of gas by
the 1990' s.
Although technically not a source of natural gas, another mitigating factor
in the potential availability of natural gas is the decision of phaseout the
use of natural gas in large boilers. About 3 Tft3 of natural gas (15% of the
current supply) is now consumed annually by utility boilers to generate electricity.
Although no similar figures are available for consumption by industrial boilers,
it is probably at least the same order of magnitude and thus the recent ban on
the future use of natural gas as a boiler fuel may free substantial quantities of
gas for other uses. In fact, the savings from banning natural gas in utility
boilers alone could free twice as much gas as is required to generate all the
NH3 needed domestically in the year 2000.
CONCLUSIONS
A major concern associated with the widespread application of the dry
SCR-type NC^ FGT systems in the future is the availability of NH3- There is
both increased emphasis on using coal as boiler fuel and uncertainty surrounding
the availability of natural gas, the primary raw material for NH3 production.
As a result, serious questions have been asked about the availability of
sufficient quantities of NH3 for NOx control without adversely affecting NH3
prices and thus indirectly impacting the associated agricultural economy.
After reviewing the NH3 requirements for NOx control at a typical
power plant, the projected U.S. electrical generating capacity, current Nfl3
generating techniques, and natural gas availability, the following conclusions
have been drawn:
1. NH3 for NOx FGT will be purchased on the NH3 market and not generated
at the power plant.
XXV
-------
2. Based on the premises of this study, (particularly the assumption that
only new large boilers will require NOx control technology) the wide-
spread application of NOx FGT systems using dry SCR processes will not
have an abrupt adverse impact on the domestic NH3 market, but rather
a gradual increase in demand for NH3 which can be accommodated by the
normal growth of the NH3 market.
3. If, beginning in 1985, the widespread application of NOx FGT systems
are required on all new large boilers, the annual NH3 production capacity
must be increased from the expected annual growth rate of 3% to 4.5%
in order to avoid an increasing (approaching significant) impact on
the NH3 market beyond 1990.
4. At the present time, alternative feedstocks are generally not economically
competitive with natural gas as an H£ source for the production of NH3-
5. Currently the production of NH3 consumes only minor amounts of the total
U.S. natural gas supply. However, the increased demand for NH3 due to
application of NOx FGT systems would be contrary to a national energy
concern of continuing dependence on natural gas if this NH3 is based
on using natural gas as the feedstock.
xxvi
-------
INTRODUCTION
Of the five most common air pollutants released in the United States,
nitrogen oxides (NOx) are the only ones projected to increase significantly in
the future. The total emission of the other four pollutants [particulate
matter, sulfur oxides (SOx), hydrocarbons, and carbon monoxide (CO)] has
decreased during the past 6 yr and is expected to decline further in the future
as more point sources are equipped with more efficient control systems. With
most public attention focused on these other pollutants which are typically
emitted at higher rates than NOx. the development of equipment and techniques
for controlling NOX has lagged behind. However, recently more attention has
been given to the possible health effects of NOx emissions. Although the NOx
emission from each source appears to be small, the cumulative total is measured
in millions of tons annually and is increasing substantially from year to year
due to the increasing number of sources.
NOx emissions are divided into two classes, mobile or stationary, depending
on the source. The mobile class, as its name implies, includes sources such
as automobiles, trucks, buses, trains, and planes. Attempts at controlling
the NOx emissions from these sources have been delayed due to both technical
and economic considerations. Stationary sources, which release about 56% of
the total amount of NOx emitted in the United States (an estimated 11.15 Mtons
in 1975), are split into three groups: combustion sources, industrial processes,
and other miscellaneous sources. In 1975 combustion sources contributed approxi-
mately 93% of all stationary source emission (an estimated 10.4 Mtons) of which
nearly two-thirds came from fossil fuel-fired boilers (approximately 7.0 Mtons).
If these boilers are further divided according to size (heat rate of the boiler),
large boilers [i.e., greater than 250 MBtu/hr (25 MW equiv)] release 45% of al
NOX emitted from stationary combustion sources. Figure 1 and Table 1 show the
relative contributions from mobile sources and each type of stationary source
to the total NOX emissions in the United States during 1975. Since the mobile
source standards are not expected to become more stringent in the near future,
restricting the amount of NOx emissions from stationary sources, particularly
large fossil fuel-fired boilers, may become necessary since these boilers are
the second largest source of NOx emissions in the U.S. The reason for the
possibility of stricter NOX emission control on large boilers are threefold.
The emissions from these boilers are projected to increase at about 4.9% annually
over the next decade (doubling every 15 yr) assuming present control levels.
Secondly, assuming the application of combustion modification which is now
considered the best available control technology (about 30% decrease in the
NOx formation), the amount of NOX emitted by large boilers will increase from
4.7 Mtons in 1975 to 6.6 Mtons in 1985 (50). And thirdly, although the total
amount of NOx emitted by these boilers is only approximately one-half that of
mobile sources, there are orders-of-magnitude fewer boilers and hence each
boiler source emits significantly more NOx than each individual mobile source.
-------
Industrial processes (2.3%)
Gas turbines (2.8%)
Other (1.5%)
Other
boilers
(11.2%)
Mobile
sources
(44.3%)
Large
boilers
(23.6%)
Figure 1. Breakdown of the total U.S. NOX emissions by original source (45).
-------
Therefore, It is expected that based on each ton of NOx removed it will be
more cost-effective to reduce NOx emissions from large boilers than from
individual mobile sources.
TABLE 1. NOx EMISSIONS BY SOURCE IN 1975 (45)
Annual amount,
ktons
Mobile sources 8,850
Stationary sources
Large boilers 4,728
Other boilers 2,238
1C engines 2,849
Gas turbines 566
Incinerators 39
Industrial processes 454
Field burning 290
Total 20,000
FORMATION OF NOX IN LARGE BOILERS
NOx is formed during high-temperature combustion operation and can be
produced by either of two mechanisms. The first method of formation is thermal
fixation or "thermal NOx" an^ involves the reaction of molecular nitrogen (N2)
and oxygen (02) at high temperatures. The second method is the oxidation of
chemically bound nitrogen within the fuel and is called "fuel NOx-" In oil-
or coal-fired boilers, NOX is formed by both mechanisms, but in natural gas-
fired boilers the NOx is formed only by thermal fixation since natural gas
contains no fuel-bound nitrogen.
POTENTIAL NOx CONTROL METHODS FOR LARGE BOILERS
Two potential methods of reducing NOx emissions from fossil fuel-fired
boilers are undergoing extensive research and development. In the United
States, combustion modification techniques to reduce the amount of NOx formed
during combustion are being emphasized; while in Japan, mainly because of
more stringent NC^ emission regulations, the emphasis is on flue gas treatment
(FGT).
-------
Combustion modification techniques attempt to prevent the formation
of NOx by altering the reaction conditions inside the boiler. Since thermal
fixation is primarily a function of the temperature (i.e., the rate of formation
increases with temperature) and the concentration of 02 in the boiler, reducing
either of these parameters will decrease the amount of thermal NOx formed. These
same boiler modifications which reduce the 02 concentration in the boiler can
also reduce the amount of fuel NOx formed since the conversion of fuel-bound
nitrogen is a strong function of the 02 concentration. Various combustion
modification techniques, which are currently undergoing development work in the
United States, are compared in Table 2 for the three types of fossil fuel-
fired boilers. Combustion modifications are shown to be the most effective on
gas- and oil-fired boilers where a major portion of the NOX is formed by the
thermal mechanism. For coal-fired boilers where much of the NOx comes from
fuel-bound nitrogen, the available combustion modification techniques are
limited to about 40% reduction in NOX.
Although the resulting reduction in the total NOx emissions from large
boilers would appear to be significant, a recent study (45) has determined
that, even with combustion modifications on all new large fossil- fueled boilers.
the expected growth rate for new large boilers will result in a significant
increase in the total NOx emissions from these boilers, rising from 4.73 Mtons
in 1975 to 6.56 Mtons in 1985. Unfortunately, combustion modifications also
have undesirable side effects of reducing boiler efficiency, increasing the
potential for flame instability, and increasing the soot, CO, and particulate
loadings in the flue gas. For these reasons, an alternative method of NOx
control technology, FGT, has recently begun to receive more attention. Although
probably more expensive than combustion modification, FGT allows normal operation
of the boiler and can remove at least 90-95% of the NOx from the flue gas. Many
different types of FGT systems are currently undergoing development work in
Japan and the United States, but the most technically advanced type for removing
NOx from power plant stack gas is now selective catalytic reduction (SCR) (30).
In this type, ammonia (NH3> is injected into the flue gas ducts and the mixture
of NH3 and flue gas passes through a catalytic reactor containing a basp-metal
catalyst. The NOx is selectively reduced to molecular N2 by the following
reactions:
4NH3(g) + 4NO(g) + O2(g) - 4N2(g) + 6H20 (1)
4NH3(g) + 2N02(g) + 02 - 3N2(g) + 6H20 (2)
Although these SCR processes are still in early stages of development
(most have not been tested either on coal-fired flue gas or on a large scale
unit), they are receiving considerable attention because of both the potentially
low capital investment and the fact that they generate molecular No directly
without further chemical processing.
-------
TABLE 2. EFFECTS OF BOILER MODIFICATIONS TO REDUCE NOX
EMISSIONS BY FOSSIL FUEL TYPE (30)
Boiler modification
Percent decrease of NOx formation
in boilers by fuel type
Gas
Oil
Coal
Prevention of thermal NOx by:
Flue gas recirculation
Reduced air preheat
Steam or water injection
Prevention of both thermal and fuel
NOx by:
Staged combustion
Low excess air
Reduced heat release rate
Combination of stage combustion, low
excess air, and reduced heat release
rate
Prevention of fuel NOx by:
Change to fuel with lower percent
nitrogen
60
50
60
55
20
20
50
20 Not effective
40 Not competitive
40 Not competitive
40 40
20 20
20 20
35 40
Not applicable 40 20
-------
A primary consideration in the widespread application of these SCR
processes in the United States is the potential availability and the cost of
NH3 in the future. Since nearly all of the NH3 produced in the United States
is made from natural gas, there are serious concerns over the potential impact
of widespread use of NH3 in FGT applications. The availability and cost of
both natural gas and NH3 may be affected. Would this additional demand for
NH3 create shortages in NH3~based fertilizers and thus increase food costs?
Will there be sufficient natural gas available for meeting this demand for
NH3? If not, what other methods and feedstocks are available for generating
NH3? This report will attempt to provide insights into these questions.
-------
NH3 REQUIREMENTS FOR NOx CONTROL
NH3 REQUIREMENTS FOR TYPICAL POWER PLANT APPLICATIONS
Any evaluation of the impacts of the additional NH3 demand for power
plant FGT systems must begin with a determination of the magnitude of the
additional demand. In order to calculate the NH3 requirements for typical
fossil fuel-fired boilers, it is necessary to presuppose future NOX standards
for large stationary source boilers.
Although the future NOX emission limits have not been published, for the
purposes of this study the following scenario has been hypothesized. Since
the SCR and other FGT processes are still in the early stages of development
in the United States, strict Federal NOx emission regulations of 90% removal
from large stationary sources will probably not be enforced until 1985. Since
Federal new-source performance standards (NSPS) apply only to new sources,
existing sources will not be required to meet these standards but existing
sources converted from gas or oil to oil or coal after 1985 will be. Between
the present and 1985, the NOX emission limits may be reduced but only to the
extent that combustion modifications can be used to meet the newer regulations.
Two possible methods would be available for meeting these emission regula-
tions of 90% NOX removal, (1) the installation of an SCR system designed for
90% NOx removal or (2) the use of combustion modifications to cut NOx emissions
from the boiler by 50% with the additional installation of an SCR system designed
for 80% NOX removal to give an overall NOx removal efficiency of 90%. The
Impacts of each of these methods are considered in later sections.
The typical fossil fuel-fired boilers included in this study were 500-MW
coal- and oil-fired boilers with the flue gas compositions shown in Table 3.
Gas-fired boilers were not considered since they are not expected to be built
after 1985. For the two alternative cases, the uncontrolled conventional 500-MW
coal-fired boiler would release about 600 ppm NOX in the flue gas (3009 Ib/hr),
would require an SCR system capable of a 90% NOx removal efficiency, and would
release only approximately 60 ppm NOx (300 Ib/hr) of NOX after FGT control.
Through the use of combustion modification techniques in the second coal-fired
case, the boiler would emit 300 ppm NOX (1504 Ib/hr) and the additional SCR
system would remove 80% of the remaining NOx to obtain a total of 90% NOX
removal. In a similar manner, the uncontrolled 500-MW oil-fired boiler releasing
200 ppm NOX in the flue gas (856 Ib/hr) would be required to have 90% NOx removal,
i.e., down to 20 ppm (86 Ib/hr) NOx- Again this could be obtained either by an
SCR system designed for 90% removal or through combustion modification to lower
boiler emissions to 100 ppm NOx and tnen an 80^ efficient SCR system.
-------
TABLE 3. FLUE GAS COMPOSITIONS FROM 500-MW
COAL- AND OIL-FIRED BOILERS
Flue gas composition from
Oil-fired boiler Coal-fired boiler
Constituent Vol. % Lb/hr Vol. % Lb/hr
N2 73.60 2,929,000 73.76 3,450,000
02 2.54 115,400 4.83 258,200
C02 11.96 747,900 12.31 904,200
S02 0.13 12,060 0.24 25,130
803 0.0013 151 0.0024 317
NOx 0.02 856 0.06 3,009
HC1 - - 0.01 661
H20 11.75 300.800 8.79 264.500
100.00 4,106,000 100.00 4,906,000
Fly ash, gr/sft3 (wet) 0.032 6.06
The catalytic reduction reactor used in the SCR processes is typically
either a fixed-bed reactor incorporating a catalyst or reactor design to pre-
vent plugging by entrained particulates or a moving-bed reactor. The normal
operating conditions inside this reactor are a temperature of about 350-400°C
(662-752QF) and a space velocity ranging from 5,000-10,000 hr"1. Within these
specified conditions the NOx removal efficiency can be altered by changing the
NH3:NOX mol ratio as shown in Figure 2. Between 0-90% NOx removal, the NOx
removal efficiency is nearly a linear function of the NH3:NOx mol ratio entering
the reduction reactor. Above about 93% NOx removal the curve becomes asymptotic
and greater NOX removal requires large excesses of NH3. Thus, for 90% NOX
removal, an NH3:NOX mol ratio of about 0.95:1 would be required while for 80%
NOX removal an NHsrNOjc mol ratio of approximately 0.83:1 would be needed. These
mol ratios are based on either laboratory or pilot-plant work of various
process developers and most of them recommended operating at a mol ratio in
the range of 1.0-1.1:1 for 90% NOX removal in a commercial system (30).
For this reason the assumed NH3:NOX mol ratios for the 90% and the 80%
NOX removal systems were assumed to be 10% higher than that used in the pilot-
plant work, i.e., 1.05:1 and 0.91:1 respectively. Once this mol ratio has been
estimated, the annual NH3 consumption for the particular power plant can be
obtained from Figure 3. This figure shows the annual NH3 consumption as a
function of the NH3:NOX mol ratio for the four hypothesized cases based on the
premises given in Table 4: (1) 500-MW coal-fired boiler without combustion
modification, (2) 500-MW coal-fired boiler with combustion modification, (3) 500-MW
oil-fired boiler without combustion modification, and (4) 500-MW oil-fired boiler
with combustion modification. The estimated annual NH3 consumption for each of the
-------
100
vo
e
z
w
u
U.
W
1
OS
X
o
ss
80
60
40
20
0.2
0.4
0.6 0.8
MOL NH3/MOL NOX
1.0
Figure 2. NOX removal ef f iriem-y as a funrtion of
1.2
mol ratio.
1.4
-------
10
z
o
H
Z
O
OT c
z 5
o
o
g 4
ZS o
5 3
2
1
I I
Legend
500-MW conventional coal
500-MW coal with CM
500-MW conventional oil.,
500-MW oil with CM
X
X
X
X
0.5
1.0 1.5
MOL NH3/MOL
2.0
2.5
3.0
Figure 3. Annual NH3 consumption for selected 500-MW
boilers for UOX FCT as a function of NH3:NOX mol ratio.
10
-------
four cases is listed in Table 5. The values range from a high of 6266 tons
of NH3/yr for the 500-MW conventional coal-fired boiler without combustion
modifications to a low of 772 tons of NH3 annually for the 500-MW oil-fired
boiler with combustion modifications.
TABLE 4. PREMISES FOR THE CALCULATION
OF ANNUAL NH3 CONSUMPTION FOR 500-MW
FOSSIL-FIRED BOILERS
Parameter Value
Heat rate, Btu/kWh 9,000
Heating value
Coal, Btu/lb 10,500
Oil, Btu/gal 144,000
Availability, hr/hr 7,000
TABLE 5. NH3 CONSUMPTION FOR TYPICAL
500-MW COAL- AND OIL-FIRED BOILERS
NOx
treatment
Fuel scheme
Coal SCRa
Coal CM & SCRb
Oil SCR
Oil CM & SCR
NOX
concentration
in flue gas, ppm
600
300c
200
100C
Mols NH3
per mol
NOx
1.05
0.91
1.05
0.91
NH3 consumption,
tons/yr
6,266
2,715
1,781
772
a. Selective catalytic reduction.
b. Combustion modification followed
by selective
catalytic
reduction.
Combustion modification was assumed to be 50% efficient
in controlling NO* emissions.
The economics of present-day NH3 generating plants dictate a minimum capacity
of 1,000 tons of NH3/day (330,000 tons/yr) and thus local, small NH3 plants at
each boiler would be highly unlikely. Even with large 2,500-MW coal-fired power
plants, the annual NH3 requirement of 31,000 tons would not justify a captive
NH3 plant. Thus it is assumed that for all NOx FGT applications the NH3 would
be purchased from existing fertilizer plants already producing NH3 and shipped
to the power plant and stored in large tanks onsite.
11
-------
PROJECTION OF COAL-FIRED GENERATING UNITS
Any attempt at determining the impact of the widespread application of
FGT systems using NH3 to fossil fuel-fired boilers during the period 1985-2000
requires a reliable projection of new coal- and oil-fired boilers during this
period. Various seemingly extraneous factors have a direct bearing on what the
total electrical demand will be as well as what proportion of this new electrical
capacity will come from which fuel.
In 1977 the U.S. electrical generating industry used the types of fuel
shown in Table 6. Numerous projections of changes in this fuel mix have been
given by various sources for the period 1975-1985. Although the actual
numerical values vary depending on the literature source, several trends are
common to all including a drastic increase in nuclear capacity, a moderate
increase in coal-fired units, a small increase in oil-fired units, and a
reduction in gas-fired units (due to retirements and no new additions after
about 1980). These estimates of total installed generating capacity in 1985
range from Energy Research and Development Administration (ERDA) projection
of 740 gigawatts (GW) with nuclear power representing 145 GW (1) to the Federal
Energy Administration (FEA) 905 GW (the most optimistic of four alternative
scenarios provided by FEA) with nuclear supply 150 GW (31). In between these
extremes both the Federal Power Commission (FPC) (32) and the National
Electric Reliability Council (1) are projecting a 1985 capacity of approximately
798 GW.
TABLE 6. PROJECTED U.S. ELECTRICAL GENERATING CAPACITY
BY FUEL TYPE FOR THE YEARS 1975-1985 (1)
Generating capacity, GW
Year Coal Oil Gas Nuclear Hydro3 Totalb
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
183
193
204
218
232
247
260
278
291
308
321
127
134
140
143
147
155
158
159
160
161
163
63
64
65
65
64
59
58
57
56
54
49
33
43
51
59
69
78
93
113
133
153
174
69
70
71
77
78
80
83
85
88
91
91
474
503
531
561
590
619
651
693
728
766
798
a. Includes hydro, pump storage, and other
miscellaneous.
b. Columns may not total exactly because of rounding.
12
-------
These projections of the total generating capacity by fuel type which were
made by the National Electric Reliability Council are also shown in Figure 4
for the period 1975-1985. Based on the projections, the net annual capacity
additions for each fuel are shown in Table 7. This total U.S. electrical
generating capacity of 798 GW and the fuel mix shown in Figure 4 thus provide
the basis for projecting the generating capacity during the period 1985-2000.
TABLE 7. ESTIMATED U.S. GENERATING CAPACITY
ADDITIONS BY FUEL TYPE FOR THE PERIOD 1976-1985
Electrical generating capacity, GW
Year
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
Coal
10
9
14
14
15
13
18
13
17
13
Oil
7
6
3
4
8
3
1
1
1
2
Gas
1
1
0
(Db
(5)
(1)
(1)
(1)
(2)
(5)
Nuclear
10
8
8
10
9
15
20
20
20
21
Itydrba
1
1
6
1
2
3
2
3
3
0
Total
503
531
561
590
619
651
693
728
766
798
a. Includes hydro, pump storage, and other
miscellaneous.
b. Number in parentheses indicates decrease.
Estimates for the period 1986-2000 are more uncertain since both the
total generating capacity and the fuel mix are susceptible to economic
upheavals or changing trends. The only common trend in the various projections
is that the rate of capacity addition is expected to be lower than its historical
average of about 6%. Figure 5 projects the U.S. electrical capacity as a
function of three growth rates: 4, 5, and 6% with the curve representing 5%
probably being the most likely. The portion of this total capacity based
on coal as the fuel is expected to increase from the projected 40% in 1985
to about 50% in the year 2000 primarily due to both the long lead times in
building nuclear power plants and the elimination of gas and curtailment of
oil as boiler fuels. Therefore, for the purposes of this study, the following
assumptions have been made:
1. Electrical generating capacity will double during the period 1985-2000.
(Average annual growth rate: 4.8%.)
2. Coal-fired power plants will make up 50% of the total generating
capacity in the year 2000.
13
-------
1000
750
o
z
I
u
en
500
250
Coal
I
1975
Figure 4.
1980
YEAR
1985
U.S. electrical generating capacity by fuel type
for the years 1975-1985 (1).
-------
2000,
o
i
Ed
§
a
as
i
Ed
I500l_
loop
4%
5001
1985
1990
1995
2000
YEAR
Figure 5. Projected U.S. electrical generating rapacity
for the period 1985-2000 at three different annual growth rates,
-------
Both of these assumptions are compatible with a report (42) recently released
which projects both the total U.S. electrical capacity and also the total
coal-fired capacity from 1985 to 2025. Thus for the purposes of this report,
the total U.S. generating capacity and the total coal-fired capacity in 2000
were assumed to be 1658 GW and 829 GW as shown in Table 8.
TABLE 8. PROJECTED ELECTRICAL GENERATING
CAPACITY BY FUEL TYPE IN THE YEAR 2000 (42)
Electrical generating
Fuel capacity
Coal
Nuclear
Other
Total 1,658
The installed coal-fired capacity during the period 1985-2000 is projected
to increase from 321 GW to approximately 829 GW. In addition to this net
increase of 508 GW, enough additional new coal-fired capacity will need to be
brought online to replace units lost due to retirement. If an annual retirement
factor of 0.5% (33) of the installed coal-fired capacity is assumed (i.e., 2-3
GW/yr), the projected coal-fired capacity additions each year for the period
1985-2000 are shown in Table 9 as well as the resulting total installed coal-
fired capacity.
These coal-fired units installed and operating after January 1, 1985, will
be the plants required to install "best available technology," i.e., 90% NO*
removal. The previously calculated NH3 requirement for a 500-MW (0.5 GW) coal-
fired unit (both case 1 and case 2) was assumed to represent the average NH^
consumption for new plants and thus multiplying this consumption by the projected
new coal-fired capacity requirements given in Table 9, the estimated yearly
demand for NH3 in new coal-fired units was calculated for both cases. These
NH3 requirements for NOx FGT during the period 1985-2000 are shown in Table 10.
For case 1 with all the new coal-fired additions assumed to require 90% SCR,
the NH3 consumption increases gradually at first with the output equivalent to
one new 1000 ton/day NH3 plant being able to supply enough NH3 to meet all the
NOX FGT applications for the coal-fired units coming online in the United States
for the years 1985 and 1986. The number of these NH3 plants required to produce
NH3 solely for NOX FGT application would gradually increase from the one plant
required in 1985 and 1986 to an estimated 20 plants in the year 2000. For case
2 (all the new coal-fired additions assumed to require only 80% SCR through the
use of combustion modifications) the annual NH3 consumption and hence the
number of new NH3 plants would be about 43% of that required for case 1.
16
-------
TABLE 9. PROJECTED COAL-FIRED POWER PLANT ADDITIONS AND THE TOTAL
COAL-FIRED GENERATING CAPACITY BY YEAR FOR THE PERIOD 198A-2000
Coal-fired capacity Total coal-fired
Year additions.a GW generating capacity, GW
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
19
15
23
24
26
27
29
31
33
35
37
40
42
45
48
51
55
308
321
342
364
388
413
440
469
500
532
567
604
644
686
730
778
829
a. This average annual increase in coal-fired capacity includes
sufficient additional capacity to compensate for an annual
retirement rate of 0.5% the total coal-fired generating
capacity.
17
-------
TABLE 10. COMPARISON OF PROJECTED ANNUAL U.S. NH3 CONSUMPTION
BY ALTERNATIVE NOx FGT SYSTEMS AT ALL NEW COAL-FIRED POWER PLANTS
(Thousands of tons)
Case 1-Without combustion modifications Case 2-With combustion modifications
(600 ppm NO^-90% removal) (300 ppm NOy-80% removal)
Increase in NH3 Total NH3 Increase in NH3 Total NH3
Year consumption8 consumption for FGT consumptions consumption for FGT
00
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
0
94
144
150
163
169
182
194
207
219
232
251
263
282
301
320
345
0
94
332
626
939
1,271
1,622
1,998
2,399
2,825
3,276
3,759
4,273
4,818
5,401
6,022
6,687
0
41
62
65
71
73
79
84
90
95
101
109
114
122
130
139
149
0
41
144
271
407
551
703
866
1,039
1,224
1,419
1,629
1,851
2,088
2,340
2,609
2,897
a. Assuming all new capacity comes online June 1, i.e., only 6 mo of NH3 required
in the first year.
-------
With the recent concern about burning oil and natural gas as boiler
fuels, it has been assumed that no new gas-fired utility boilers will be
built. Oil-fired boilers, on the other hand, have been used and are expected
to continue to be used in areas with significant air quality problems where
coal-fired boilers would lead to a marked deterioration of air quality. For
this reason new oil-fired generating capacity will be added during the period
1985-2000, but only to a very limited extent. In addition to this small number
of new oil-fired sources, new oil-fired boilers would require only about one-
third as much NH3 for NOx FGT as an equivalent-sized coal-fired unit. Thus
when compared with the NH3 required for NOx FGT on new coal-fired boilers,
the additional NH3 demand for NOx FGT on new oil-fired boilers will be negligible
and only the NH3 consumption for coal-fired boilers will be included in this
study.
NH3 Requirements for Both Utility and Industrial Boilers
In formulating the NSPS for NOx requiring best available technology to be
installed on all new large boilers after 1985, i.e., 90% NOx removal either
wholly or partially by NH3~based SCR treatment, these standards may also be
imposed on large industrial boilers (>250 MBtu/hr) as well as utility boilers.
In the previous section on NH3 consumption, only new coal-fired utility boilers
were considered primarily because very little information is available on the
growth of industrial boilers, particularly when this is further restricted to
include only large industrial boilers.
Since so little information is available about these particular boilers,
the following general assumption is used in this study: the total NH3 require-
ment for NOx FGT for all large boilers (>250 MBtu/hr) will be 1.25 times the
projected NH3 requirements for NOx FGT systems on utility boilers. The reasons
for selecting the 25% increase are as follows: (1) the total amount of NOX
emitted from all industrial boilers was estimated as 21.6% of that emitted by
utility boilers in 1975 and projected to be 22.9% in 1980 (see Table 11), (2)
although most of the industrial boilers would have a heat load of less than
250 MBtu/hr, the total amount of NOX emitted from these smaller boilers would
also be proportionately less such that a major portion of the NOx from industrial
boilers would come from the larger boilers, and (3) the impact of these smaller
boilers would probably be less since many small boilers would be fired with oil
rather than coal.
Table 11 lists the estimated NOX emissions for 1975 and 1985 from various
sizes of boilers (including both utility and industrial boilers) according to
the boiler heat load. The large boilers [>250 MBtu/hr (25 MW equiv)] represent
more than two-thirds of the total NOx emissions from stationary source boilers
while the midsized boilers (10-250 MBtu/hr) and the small boilers (<10 MBtu/hr),
each release about one-sixth of the total NOx emissions from boilers. Since
electrical generating utility boilers were estimated to make up about 80% of
these large stationary boilers, multiplying the NH3 consumption by utility boilers
by a factor of 1.25 would provide a reasonable estimate of the total NH^ demand
if 90% NOX removal by NH3-based SCR is required for all new large boilers beginning
in 1985. With utility boilers making up such a large proportion of these large
boilers the growth rate of all large boilers would probably parallel the growth
19
-------
TABLE 11. ESTIMATED NOx EMISSIONS FROM VARIOUS
SIZED BOILERS IN 1975 AND 1985 (45)
Large boilers
(>250 MBtu/hr)
Moderate boilers
(10-250 MBtu/hr)
Small boilers
(0.3-10 MBtu/hr)
Boilers
(<0.3 MBtu/hr)
Total
1975 emissions,
Mtons
4.728
1.297
0.642
0.299
6.966
% of total
67.9
18.6
9.2
4.3
1985 emissions,
Mtons
7.605
1.483
0.978
0.397
10.463
% of total
72.7
14.2
9.3
3.8
Annual growth
rate, %
4.87
1.35
4.30
2.88
N>
O
-------
TABLE 12. COMPARISON OF THE PROJECTED ANNUAL NH3 DEMAND FOR
FGT DURING THE PERIOD 1985-2000 FOR TWO CASES: REQUIRED
ON ONLY NEW UTILITY BOILERS OR FOR ALL NEW LARGE BOILERS
Annual NH^ demand, ktons
New utility
Year Case la
1984 0
1985 94
1986 332
1987 626
1988 939
1989 1,271
1990 1,622
1991 1,998
1992 2,399
1993 2,825
1994 3,276
1995 3,759
1996 4,273
1997 4,818
1998 5,401
1999 6,022
2000 6,687
boilers only
Case 2°
0
41
144
271
407
551
703
866
1,039
1,224
1,419
1,629
1,851
2,088
2,340
2,609
2,897
All new large
boilers
Case la Case 2b
0
118
415
783
1,174
1,589
2,028
2,498
2,999
3,531
4,095
4,699
5,341
6,023
6,751
7,528
8,359
51
180
339
509
688
879
1,082
1,299
1,530
1,774
2,036
2,314
2,610
2,925
3,262
3,622
a. Ninety percent NOX
b. Ninety percent NO^
removal by SCR
only.
removal by combined combustion
modification and SCR.
21
-------
rate for large electric utility boilers projected previously and hence overall
NH3 consumption for all large stationary boilers for each year would be 1.25
times that required for only large utility boilers. This total demand for
NH3 for NQx FGT on all large boilers is shown in Table 12.
CURRENT NH3 SUPPLY AND DEMAND
The earliest and still the most important use of NH3 is for the production
of fertilizers. Approximately 75% of the current U.S. production of 16.4 Mtons
of NH3 is used either directly or indirectly as a fertilizer with the remaining
25% apportioned as follows: 10% for fiber and plastic intermediates, 10% for
commercial explosives, and the remaining 5% for exports (9).
Over the past 10 yr the NH3 demand in the United States, as shown in Table
13, has steadily increased at an annual rate of about 4.5% from 10.6 Mtons in
1966 to 16.4 Mtons in 1976. However, the combination of a very low annual
growth rate in the agricultural use of NH3 (2-3%), a low demand for fiber and
plastic intermediates, and the projected absence of export demands have led
others to project an annual growth rate of only 3% for NH3 during the period
1976-2000 (29). The use of NH3 for commercial explosives has the potential
for large increases in the future due to the expected increase in coal mining
but since this represents such a small portion of the NH3 market its overall
impact on NH3 consumption is expected to be negligible.
TABLE 13. U.S. NH3 DEMAND 1965-76 (4, 39)
NH3 demand, ktons
Year
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
Fertilizer3
5,633
6,468
7,319
8,242
8,449
9,057
9,877
9,741
10,070
11,120
10,450
12,560
Total0
8,869
10,605
12,194
12,120
12,769
13,824
14,538
15,169
15,208
15,733
16,393
16,423
a.
b.
Crop year
Calendar
•
year.
22
-------
For comparison purposes, Figure 6 shows the NH3 demand for the period
1976-2000 under three alternative annual growth rates: 3, 4, and 5%. The
projected demand (excluding the NH3 demand for NO* FGT) in the year 2000 ranges
from 34.3 to 55.5 Mtons depending on the growth rate assumed. Although the
historical trend has averaged about 4.5%, the projected NH3 demand is expected
to increase at a lower growth rate of 3.0%. Under this assumption the NH3
demand in 1985 and 2000 would be 21.4 and 33.1 Mtons respectively.
The U.S. NH3 production capacity on the other hand has grown primarily
by boom-bust cycles in recent years. For example, up until the mid-1960*s
NH3 plants were typically small plants (<300 tons/day) located near the ultimate
consumers. However, with the advent of large capacity centrifugal compressors,
most new NH3 plants jumped in size to the 1000 ton/day plant which is common
today. These plants offered distinct economic advantages over the small plants
and rapidly drove most of these smaller plants out of business when the resulting
surplus capacity came online. This overcapacity and subsequent depressed
market price for NH3 also resulted in very little incentive to add further
capacity during the early 1970's. However, the constantly increasing demand
for NH3 coupled with the beginning of natural gas curtailment during the winter
months rapidly absorbed the overcapacity until in 1974 and 1975 the United
States became a net importer of NH3 and the wholesale price of NH3 doubled and
even tripled within 1 yr (54). With these economic incentives numerous NH3
producers announced plant expansions and additions which have come online during
1977 and 1978. This large increase in capacity had led to another oversupply
situation in the domestic NH3 market. Table 14 lists the NH3 capacity additions
and the U.S. NH3 plant capacity by year during the period 1967-1980. The
operating rate of the U.S. NH3 plants during this same period is shown in
Figure 7. As would be expected during periods when new NH3 capacity is coming
online, the operating rate of the NH3 industry declines until the demand soaks
up excess capacity.
In view of the past history of fluctuating capacity growth, projecting NH3
plant capacities expected for the year 1980-2000 are rather difficult. Various
factors which affect decisions to increase capacity include (1) government
policy and (2) current market conditions, which can change rapidly. Due to the
sensitivity of the NH3 market to supply and demand, the NH3 plant capacity is
expected to grow intermittently whenever demand, and hence prices, rise and
provide economic incentives for expansion. A reasonable assumption in the
projection of growth is that the total U.S. capacity will keep pace with the
projected increase in demand, i.e., approximately 3%/yr. Figure 8 shows the
capacities for the period 1980-2000 based on a growth rate of 3.0% as well as
4% and 5% growth for comparison purposes. The projected NH3 capacity in 1985
and 2000 based on a 3% annual growth rate would be 27.9 and 43.5 Mtons respectively.
COMPARISON OF PROJECTED NH3 DEMAND FOR NOX FGT WITH POTENTIAL NH3 SUPPLY
The previously calculated NH3 demand for NOx FGT (90% NOX removal) required
beginning in 1985 for all new large boilers (industrial as well as utility
boilers) is compared with the projected NH3 demand for the period 1985-2000 in
Table 15 and the relative NH3 demands for NOx FGT and conventional uses as
shown in Figure 9.
23
-------
bO
to
SB
Z
40
30
20
3%
10
1975
1980
1985
1990
1995
2000
YEAR
Figure 6. Projected U.S. NH3 demand during the period 1975-2000
at three annual growth rates.
-------
TABLE 14. U.S. NH3 PLANT CAPACITY ADDITIONS AND TOTAL U.S.
NH3 PLANT CAPACITY DURING THE PERIOD 1967-1980 (26)
Additional capacity, Total capacity
Year ktons3 ktons
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
_
1,921
103
484
(30)
45
645
(38)
1,203
455
2,701
1,337
951
0
12,991
14,806
14,848
16,332
16,302
16,347
16,992
16,954
18,157
18,703
21,404
23,156
24,107
24,107
a. Parentheses indicate decrease.
25
-------
JOO
90
s/i
•
!=>
80
ho
Cd
H
70
u
60
H
tn
w
50
I I I I
1965
1970
1975
1980
YEAR
Figure 7. Annual operating rate of U.S. NH3 plants from 1965-1981 (43).
-------
70
to
60
z
o
50
40
30
3%
20
1
I
1980
1985
1990
YEAR
1995
2000
Figure 8. Projec-ted U.S. NH3 capacity during the period
1975-2000 at three annual growth rates.
-------
TABLE 15. COMPARISON OF THE ESTIMATED ANNUAL NH3 DEMAND FOR NOx FGT
WITH THE PROJECTED CONVENTIONAL U.S. NH3 DEMAND DURING THE PERIOD 1985-2000
Estimated
NH3 demand for
FGT.a ktons
Total projected
U.S. NHo demand,
FGT demand as
percent of projected
U.S. demand
Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Case 1'
118
415
783
1,174
1,589
2,028
2,498
2,999
3,531
4,095
4,600
5,341
6,023
6,751
7,528
8,359
3 Case 2C
51
180
339
509
683
879
1,082
1,299
1,530
1,774
2,036
2,314
2,610
2,925
3,262
3,622
ktons
21,400
22,100
22,700
23,400
24,100
24,800
25,600
26,400
27,100
28,000
28,800
29,700
30,600
31,500
32,400
33,400
Case 1°
0,
1,
3.
5.
6.
8.
9.
11.
13.
14.
16.
18.
19.
21.
23.
25.
.6
,9
,4
,0
,6
,2
,8
,4
,1
.8
.5
,2
.9
.6
,2
.3
Case 2C
0.
0.
1.
2.
2.
3.
4.
4.
5.
6.
7.
7.
8.
9.
10.
10.
2
8
5
2
9
5
2
9
6
3
1
8
5
3
1
8
a.
b.
c.
Coverage: all
Ninety
Ninety
percent
percent
new large boilers (>250
removal by
removal by
SCR only.
MBtu/hr) .
combined combustion modification and SCR.
28
-------
to
vO
50
40
z
o
30
c*i
g 20
1
10
Legend
{| Conventional NH3 demand
New large utility boiler
Other new large boilers
26.8
21.5
18.5
18.5
0.2
0.9
21.4
0.4
1.6
24.8
33.2
i
0.9
3.8
28.5
33.1 -
1980
1985
1990
YEAR
1995
2000
Figure 9. Comparison of the projected NH3 demand for NOX FCT
with conventional NH3 demand for selected years during the period 1980-2000 (case 1 only)
-------
The additional NH3 demand for NOx FGT for case 1 (90% NOX removal by SCR
only) initially would require only 0.6% of the projected NH3 supply in 1985 but
would steadily increase until it requires slightly more than 25% of the total
supply in 2000. For case 2 (90% NOx removal by combined combustion modification
and SCR) these percentages range from 0.2% in 1985 to nearly 11% in the year
2000. In either case these increases are slow enough that with enough foresight,
represented by the 1.5-2.0 yr lead time required to build these plants, the NH3
plant capacity could keep pace with the increasing NH3 consumption.
Thus under the assumptions used in this study, particularly the assumption
that only new sources operating after 1985 are required to obtain 90% NOX removal
through the use of FGT, the application of the best available technology rule for
controlling NOx emissions from large boilers will not result in an abrupt dis-
ruption of the NH3 market in which the demand for NH3 suddenly increases above
the available supply and thus has an adverse impact on the availability and
price of NH3. In fact, with the proper amount of initial planning the potentially
disruptive effects of the application of NOX FGT on the NH3 industry can be
minimized. Under these assumptions the primary impact on the domestic NH3
market would be to cause the U.S. NH3 demand to increase at 4.5%/yr during the
period 1985-2000 rather than the previously assumed 3.0%.
However, various alternative assumptions could result in substantially
different scenarios. For example, continuing delays in nuclear plant construction
could result in an increased emphasis on coal-fired power plants during the
period rather than the 50-30 mix of coal and nuclear. For example, a 5% reduction
in total nuclear capacity (about 27 MW) would probably result in 3.3% (or 27 MW)
increase in both the total coal capacity and the annual NH3 consumption. Another
critical assumption is a doubling of the total U.S. generating capacity between
1985-2000, i.e., an annual increase in capacity of about 4.7% rather than a
higher historic level of 6%. A significant portion of the additional electrical
capacity under a 6% growth rate would be based on coal and thus there would be
a higher than projected NH3 demand.
A more significant assumption is that only new coal-fired power plants coming
online after 1985 are required to use NH3~based NOX FGT systems. If, as shown
in Table 16, all coal-fired power plants were required to install a 90% efficient
NH3~based NOX FGT system, NH3 consumption would increase by about 4 Mtons in 1985
(from approximately 1 new 1000 ton/day plant to 11 plants) and 10.4 Mtons in
2000 (from about 20 new plants to 32 plants). This immediate and large increase
in NH3 demand, equivalent to approximately 19% of the projected NH3 demand in
1985, could create significant economic problems in the agriculture industry.
The availability of NH3 for the widespread application of NOX FGT systems to
new power plants after 1985 does not seem to be a potentially serious problem
since this additional demand is, at least in the early stages, relatively small
compared with conventional NH3 demands for fertilizer applications. The primary
requirement in minimizing the impact on the NH3 market will be to gradually
increase domestic NH3 supplies at a rate of 4.5%/yr rather than the currently
projected 3%. Since most of the current domestic supply of NH3 is generated
from natural gas, the answer to the question of the future availability and cost
of natural gas will have a major impact on the availability and cost of NH3-
30
-------
TABLE 16. PROJECTED U.S. NH3 DEMAND FOR NC^ FGT FOR
THE PERIOD 1985-2000 IF ALL COAL-FIRED POWER PLANTS REQUIRED TREATMENT
Percent of
Total coal-fired NH3 consumption projected total U.S
Year generating capacity, GW for NOx FGTta Mtons NH3 production
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
321
342
364
388
413
440
469
500
532
567
604
644
686
730
778
829
4.02
4.29
4.56
4.85
5.18
5.51
5.88
6.27
6.67
7.11
7.57
8.07
8.60
9.15
9.75
10.39
18.8
19.4
20.1
20.8
21.5
22.2
23.0
23.7
24.8
25.7
26.6
27.4
28.4
29.3
30.4
31.4
Basis
FGT system, 90% NOx removal by SCR.
31
-------
Although the total amount of natural gas consumed in producing NH3 does
not represent a significant portion of the current or projected natural gas
supply, under the present conditions with gas curtailments during the winter
months and the situation projected to deteriorate in the future, it is uncertain
whether additional amounts of natural gas will be available for generating NH3
in the future. For example, in 1978 total domestic NH3 production is estimated
at 17.4 Mtons which will consume approximately 0.54 trillion cubic feet (Tft-*)
of natural gas, about 2.7% of the total U.S. gas production of 20 Tft3.
In the year 2000 the production of NH3, even without the additional demand
for NOX FGT systems, will more than double and hence could require significant
portions of the total U.S. natural gas supply. Serious questions have been
raised as to whether this amount of natural gas will be available for NH3 pro-
duction. Thus the major impact of the widespread application of NOX FGT systems
may not be the direct impacts on the NH3 market but rather the indirect impacts
on the availability and price of natural gas. The following sections will
discuss the current hydrogen (H2) feedstocks for NH3 and projections of the
future availability of these current sources and other potential H£ feedstocks.
32
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CURRENT NHs GENERATING TECHNIQUES
STEAM REFORMING OF NATURAL GAS (27. 53)
Although NH3 has been made by other methods in the past, the simplest
procedure is to chemically combine molecular N2 and molecular H?. This
N2 can be obtained by simply filtering and injecting air into the system.
Process alternatives to NH3 production actually revolve around the method
in which H2 is produced. The HZ must either be purchased directly, such as from
a chlorine (C12) manufacturer, or more commonly, generated by chemical reaction.
This latter method is causing the most interest since the most common chemical
method is the steam reforming of natural gas. In fact about 95% of the NH3
currently being produced in the United States is based on this method (47).
Since steam reforming of natural gas represents such an overwhelming majority
of the NH3 plant capacity, a state-of-the-art review of current NH3 generating
techniques will be primarily concerned with this method.
Natural gas became the primary feedstock during the 1950's with the rapid
development of large commercial gas fields in Texas, Louisiana, and Oklahoma
and the completion of the transcontinental pipelines. Natural gas, primarily
containing methane as shown in Table 17, is an excellent source of H2 since it
is a relatively clean hydrocarbon feedstock and also has a high ratio of
hydrogen to carbon. These two factors combined meant that a high-quality
feedstock was readily available through the United States and other N«3 feed-
stocks such as coal were rapidly replaced by natural gas.
TABLE 17. TYPICAL NATURAL GAS COMPOSITION (53)
% by vol
Constituent At wellhead As delivered
CHA
N2
Ar
CO 2
H2S
74.9
™
7.3
8.9
92.3
2.0
0.4
0.01
<5 ppm
Hydrocarbons
C2 3.2 3.2
C3 1.] 0.9
C4 0.8 0.2
Cs 0.5 0.01
Ce or
higher 2.3
33
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Processing Scheme
A general outline of the processing scheme in a typical natural gas-based
NH3 plant is shown in Figure 10. Although the natural gas from the pipeline
is usually of high purity, the gas may initially be passed through a gas
purification system where any remaining sulfur compounds, primarily hydrogen
sulfide (H2S) are removed by adsorption. Activated carbon is typically used
because activated carbon operates at ambient temperatures and can be regenerated.
When the sulfur content is unusually high, another method such as hot zinc oxide
(ZnO) must be used. Even though the sulfur content is already low when pipe-
line gas is used, this purification step is included to prevent the poisoning
of the nickel (Ni) catalyst used in the steam reforming of the natural gas.
The purified natural gas is injected with steam and passed through a
two-stage reformer system, a primary reformer (a sketch of which is shown in
Figure 11), and a secondary reformer with both containing a bed of Ni catalyst.
Most of the methane is converted to H2 and carbon dioxide (C02) by the following
reactions in the primary reformer.
CH4(g) + 2H2°(g) ^ 4H2(g) + C°2(g)
CH
4(g) + H2°(g) * 3H2(g) + C°(g)
C°(g) + H2°(g) 5 C°2(g) + H2(g) (3)
The operating conditions are about 25-35 atmospheres pressure, temperatures
of 780-850°C (1436-1562°F), and a steam to carbon mol ratio of 3.5-4.0:1. These
high temperatures in the reformer are maintained by indirect heating using both
the purge gas from the synthesis loop and supplemented natural gas as fuel.
The catalyst in these tubes is Ni on a fused alumina (Al203> base with the
Ni content ranging from 12 to 22%. Because of the extreme operating conditions
in the primary reformer, unusual materials of construction for the catalyst
tube are required such as specialty stainless steel.
The gas from the primary reformer, containing some residual methane,
is injected with air and sent to a secondary reformer. The amount of air
introduced into the system is controlled such that the final H2:N2 mol ratio
will be 3:1 when the makeup gas enters the NH3 synthesis loop. The Ni catalyst
[typically 14% Ni, 15% calcium oxide (CaO) , and 67% A1203] in the secondary
reformer operates in the temperature range of 1150-1204°C (2100-2200°F) . A
typical gas composition entering and leaving the secondary reformer is given
in Table 18.
CO Conversion
CO present in the reformed gas is a potential source of H2 and a poison
to the NH3 synthesis catalyst currently in use and necessitates the inclusion
of a conversion unit. The conversion section is a two-stage unit consisting
34
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STEAM •
NATURAL-
GAS
PRIMARY
REFORMER
1
AIR
1 >
1 1 1
SECONDARY TWO STAGE C02
NhrOKMtH * CO SHIM * REMOVAL *" METHANATOR *
CONVERTER
1
coe
1
. -^ . ._>._ ^-^-%1-^_ MmWIwNI M
' REACTOR , f
PURGE GAS ^_
TO REFORMER FURNACE
CONDENSER
Figure 10. Block flow diagram of a typlral NH^ plant
based on natural gas as the \\2 feedstock.
-------
Stoam and
natural gas
Reformer tube
containing
catalyst
Natural gas
fuel
To secondary
reformer
Figure 11. Diagram of typical primary reformer (53),
36
-------
of a high temperature and low temperature converter with an interstage heat
exchanger. Although a single-stage unit could be used to convert the CO back
to methane, this would lead to a high consumption of H2 since 3 mols of H2
are required to convert 1 mol of CO to methane.
C°(g) + 3H2(g) * CT4(g) + H2°(g)
The reduction of CO to methane also negates the potential water gas shift
reaction of CO to produce additional H2, as shown in reaction (3). For these
reasons, the first-shift stage is a high-temperature reactor usin^ an iron-
chromium oxide (Fe203~CrO) catalyst (55% Fe and 6/' Cr) at A15°C (750°F) to
promote the water gas shift (reaction 3) and thereby consuming as much CO as
possible and at the same time maximizing the production of t^.
TABLE 18. TYPICAL GAS COMPOSITION ENTERING
AND LEAVING SECONDARY REFORMER (53)
% by vol, dry basis
Constituent
H2
CO
C02
CH4
N2
Ar
02
Entering
71.4
5.5
14.4
8.7
-
0.03
—
Leaving
58. I
8.5
11.5
0-2
21.3
0.3
0.1
After cooling to 250°C (482°F) in a heat exchanger the gas is then passed
through the low-temperature catalytic reactor containing zinc (Zn), copper
(Cu), and sometimes A1203 to further reduce the CO exit concentration by
reaction (3) to approximately 0.3%. In addition to the interstage heat
exchange an absorbent cartridge of ZnO is usually used before the second-
shift stage to remove the last traces of any sulfur- or chlorine (CD-
containing compounds since the low-temperature catalyst is extremely susceptible
to sulfur and Cl poisoning.
Once most of the CO has been shifted to C02, the C02 is removed from the
systems, usually by solvent extraction. Although monoethanolamine (MEA) was
used in earlier low-pressure NH3 plants, a "promoted" hot potassium carbonate
(K2C03) method such as the Vetrocoke, Benfield, or Catacarb processes have
come into increasing use with the development of modern higher pressure NH3
plants. These newer carbonate processes are labeled as "promoted" since an
additive has been added to the carbonate solution which increases the rate
of CO2 absorption.
37
-------
The synthesis gas entering the C02 removal system is relatively hot
(90-100°C) and passes countercurrently to a hot K2C03 solution in a two-
stage absorber. The C02 is absorbed and reacts with the K2C03, i.e.,
K2C03(aq)+ C02(g) + H2°(g) * 2KHC°3(aq)
The exiting gas from the second stage of the C(>2 absorber typically contains
0.02-0.07% C02-
The C02~rich carbonate solution from the absorber is partially regenerated
by releasing the pressure in a power recovery turbine. The solution is then
pumped to a two-stage regeneration vessel. The upper section of the vessel
is simply a flashing tank where most of the C02 separates from the solution
and passes overhead. A portion of the resulting lean solution recycles to the
first stage of the absorber while the remainder drops to a second stage of the
regenerator. The second stage uses indirect steam heating to further strip
the carbonate solution of C02 prior to recycle to the second stage of the
absorber.
Final Purification
Due to the sensitivity of the NH3 synthesis catalyst to oxides of carbon,
the remaining CO, C02, and 02 concentrations must be further reduced to low
levels (typically <10 ppm). This final gas purification step Is usually an
exothermic catalytic methanation reaction for CO and C0£ and a hydrogenation
reaction for oygen, i.e.,
C°(g) + 3H2(g) - ^(g) + H2°(g)
C°2(g) + 4H2(g) - CH4(g) + 2H2°(g)
2H2(g) + °2(8) - 2H2°(g)
These reactions occur at about 230-315°C (446-600°F) over a nickel oxide (NiO)
catalyst; hence heat exchange between the inlet and outlet gases is needed to
preheat the inlet gas up to the reaction temperature. The typical inlet and
outlet gas compositions around the methanator are shown in Table 19.
The resulting purified synthesis gas is sent to centrifugal compressors
which boost the gas to the NH3 loop pressure of 2000-4000 psig (137-273 atm) .
This increase in pressure is usually carried out in three stages with inter-
stage cooling.
38
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TABLE 19. TYPICAL SYNTHESIS GAS COMPOSITION
BEFORE AND AFTER METHANATION (53)
Composition,
vol, %
Constituent
H2
N2
CO
C02
CH4
Ar
02
Before
74.5
24.3
0.4
0.05
0.45
0.3
—
After
74.1
24.7
<5 ppm
< 5 ppm
0.9
0.3
—
NH3 Synthesis
The compressed synthesis gas is now suitable for use in the production of
NH3 and enters the UH3 generating section of the plant. Since, even with high
operating pressures and a favorable mol ratio of N2:H2, the equilibrium con-
centration of NH3 is relatively low (13-17%), the system must be designed to
allow the gases to make several passes through the catalytic reactor. As the
gases leave the NH3 synthesis reactor they are cooled in a heat exchanger
and, in most cases, are passed through a refrigeration unit to condense most
of the NH3 produced. The resulting gas-liquid mixture is separated and the
liquid NH3 at -33°C (-28°F) is pumped to the storage tanks while most of the
remaining synthesis gas is recycled to the NH3 reactor. A small amount of
this recycle gas is purged to prevent the buildup of inert gases in the loop
and makeup synthesis gas is then added to the recycle mixture and passed through
the catalytic reactor. Since the amount of NH3 formed and hence removed during
each pass is so low, the actual gas stream circulating around the loop is very
large in comparison with inlet and exit gas streams.
The catalytic reactor used to synthesize NH3 typically operates at about
500-510°C (932-950°F) and has an intricate internal design. This type of
reactor is required since the NH3 reaction is highly exothermic but the
catalyst activity and kinetics limit the acceptable temperatures in the reactor
to a narrow range. That is, if the reactor temperatures increase, the catalyst
activity significantly decreases but if the temperatures decrease, the rate
of formation of NH3 significantly decreases. Conversion per pass decreases
in either case.
To overcome these difficult process control problems, the so-called quench
converter design, as shown in Figure 12, was developed. The catalyst particles
typically contain 93% iron oxide (Fe203), 3.3% A1203, 0.67% magnesia (MgO),
0.55% silicone dioxide (Si02), 3.0% CaO, and 0.65% K203. This catalyst is
separated into about three different beds with relatively "cold" synthesis gas
added between each bed. This arrangement results in the partially converted
39
-------
Gas to
condenser
Catalyst
beds
Heat
exchange
Figure 12. Diagram of quench-type converter (53)
40
-------
gas being quenched as it leaves each catalyst bed. The remaining cool synthesis
gas passes around the outside of the reactor and enters an internal heat exchanger
to extract reaction heat from the converter product gas. Thus the incoming
synthesis gas is preheated to the reaction temperature. The preheated gas then
enters the catalyst beds and is partially converted to NH3 before exiting the
reactor through the internal heat exchanger.
Raw Material, Utility, Labor, and Energy Requirements
The raw material, utility, labor, and energy requirements to produce 1 ton
of NH3 in a 1000 ton/day NH3 plant based on using natural gas as the H2 feed-
stock are shown in Table 20. The major item under both raw materials and
utilities is natural gas. In terms of the overall energy required to produce
NH3, natural gas contributes essentially all of the input energy.
TABLE 20. UNIT RAW MATERIAL, UTILITY, LABOR, AND ENERGY
REQUIREMENTS FOR THE PRODUCTION OF NH3 FROM NATURAL GASa (47)
Quantity required, Energy equivalent,
Item unit/ton NH3 MBtu/ton NH3
Raw material
Natural gas, kft3 19.0 19.0
Utility
Natural gas, kft3 12.6 12.6
Electricity, kWh 30.0 0.1
Cooling water, kgal 50.0
Boiler feedwater, kgal 0.5
Labor, man-hr 0.18 -
Total 31.7
a. Basis
Plant capacity, 1000 ton/day.
On-stream time, 330 days/yr.
Process Economics
The total capital investment and the various raw material, utility, and
labor requirements for a natural gas-based plant producing 1000 tons/day of
NH3 have been previously estimated by others (46) and were used as the basis
for this study. However, the unit costs for each of the utilities except
natural gas was modified to reflect updated projections for 1978 costs. Pro-
jecting the major raw material cost, i.e., the price of natural gas, is
41
-------
relatively uncertain at the present time and for this reason several alternate
natural gas prices were chosen. Since the current price of natural gas ranges
up to $2.50/MBtu and is dependent on many factors, $1.00/MBtu was chosen as
the low price alternative and $3.00/MBtu was chosen as the middle range gas
price. The higher natural gas price, $5/MBtu, was included primarily to serve
as an upper limit on the raw material cost. The only other direct costs,
maintenance, and analyses requirements were taken from data given by others
(46). The major indirect cost, capital charges, was calculated at 22.1% of
the total capital investment based on joint EPA-TVA premises. (A breakdown
of this total capital charge is shown in Table 21.) The other indirect costs,
the various overhead charges, were taken from a standard text on chemical
engineering economics (48). The factors used for each of these indirect costs
are shown in Table 22.
TABLE 21. ANNUAL CAPITAL CHARGES
FOR CHEMICAL INDUSTRY FINANCING
Item Percent
Depreciation (straight line - 11 yr) 9.1
Insurance 0.5
Property taxes 1.5
Total rate applied to original investment 11.1
Cost of capital (capital structure assumed
to be 40% debt and 60% equity)
Bonds at 10% interest
Equity at 15% return to stockholder
Income taxes (Federal and State)*
Total rate applied to depreciation base 22.Ob
a. Since income taxes are approximately 50% of gross
return, the amount of taxes is the same as the return
on equity.
b. Applied on an average basis, the total annual
percentage of original fixed investment for new
plants would be:
11.1% + 1/2 (22.0) = 22.1%
42
-------
TABLE 22. ASSUMPTIONS USED TO CALCULATE THE NH3 PRODUCTION COSTS (43)
Item Assumption
Direct Cost
Maintenance 5% of capital investment
Indirect Cost
Overhead
Plant 50% of conversion costs less utilities
Administrative 15% of operating labor and maintenance
Selling costs 2% of direct and indirect costs
Research and development 2% of direct and indirect costs
The total capital investment for a 1000 ton/day NH3 plant based on natural
gas feedstock was estimated at $71.1 M in 1978 and the resulting unit NH3
production cost ranges from about $lll/ton for natural gas priced at $l/MBtu
to $237/ton for natural gas at $5/MBtu. The detailed calculations for the
$l/MBtu, $3/MBtu, and $5/MBtu cases are shown in Tables 23, 24, and 25
respectively.
The major cost associated with producing NH3 from natural gas (for the
$l/MBtu case) is the capital charges, representing approximately 43.0% of
the total annual cost. The second largest annual expense is the cost of natural
gas, about 28.5% of the total when the price of natural gas is $l/MBtu. This
expense for natural gas can be further split into feedstock natural gas, making
up 17.1% of the total annual operating cost, and natural gas used as fuel,
which makes up the remaining 11.4% of the total annual operating cost. The
other annual operating costs were each less than 10% of the total annual
operating cost.
OTHER CURRENT NH3 GENERATING TECHNIQUES
Since the major raw material for NH3 production, other than N2 which is
readily and freely available from air, is H2, any hydrocarbon or hydrocarbon
mixture is a potential source of H2- Although any hydrocarbon would be
technically feasible, economics play a major role in specifying which, if
any, H2 source will replace natural gas.
Any other hydrocarbon source must generate sufficient economic savings,
such as low purchase cost or uninterruptable supply, to overcome the two
major advantages of natural gas, i.e., its high purity as received and its
high H2 to inert composition. Since natural gas from a pipeline already has
most of the sulfur and other potential catalyst poisons removed, a large-scale
gas purification system is not required. Any poisons which are present can
43
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TABLE 23. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING NATURAL GAS AS THE H2 FEEDSTOCK3
(LOW FEEDSTOCK COST CASE)
Item
Annual
quantity (47)
Unit
cost . $
Total annual Percent of
operating cost, S total cost
Direct Costs
Raw materials
Natural gas
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Natural gas
Electricity
Cooling water
Boiler feedw.iter
Maintenance, SZ of plant Investment
Analyses
Total conversion costs
Total direct costs
6,270.000 HBtu
55,700 man-hr
4,170,000 HBtu
9,900,000 kWh
16,500,000 kgal
180.000 kgal
2,080 man-hr
1.00/HBtu
10.00/man-hr
1.00/MBtu
0.027/kVh
0.11/kgal
0.92/kgal
15.00/nan-hr
6,270,000
225.000
6,495,000
557,000
4.170,000
267.000
1.815,000
166,000
3,325,000
31.000
10,331,000
16.826,000
17.1
ITT
1.5
0.7
5.0
0.5
9.1
_O.J.
28. i
4b.O
Indirect Costs
Capital charges. 22.17 of capital
investment
Overhead
Plant, 502 of conversion costs less
utilities
Administrative, 15Z of operating
labor and maintenance
Marketing. 21 of direct and indirect costs
Research and development, 21 of direct and
Indirect costs
Total indirect costs
Total annual operating costs
Equivalent unit operating costs
is. 7 n, non
1.957,000
587,000
7 U ,0(1(1
731 .flOU
ift.S4S.OWI
41.0
1.6
2.0
J..O
S4.0
KKI.O
S/ton of HH.
110.74 J
Basis (47)
Total capital Investment. S71.iOO.000.
Total plant investment. $66.500.000.
On-Btrean time. 330 days/yr.
44
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TABLE 24. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A LDOO TON/DAY NH3 PLANT USING NATURAL GAS AS THE H2 FEEDSTOCK3
(MEDIUM FEEDSTOCK COST CASE)
Item
Annual
quantity (471
Unit
cost, $
Total annual
operating cost. $
Percent of
total cost
Direct Costs
Raw materials
Natural gas
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Natural gas
Electricity
Cooling water
Boiler Ceedwater
Maintenance, SZ of plant investment
Analyses
Total conversion costs
Total direct costs
6,270,000 HBtu
55,700 oan-hr
4,170,000 HBtu
9,900,000 kWh
16,500,000 kgal
180,000 kgal
2,080 man-hr
3.00/HBtu
10.00/man-hr
3.00/MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15.00/man-hr
18,810,000
225.000
19,035,000
557,000
12,510,000
267,000
1,815,000
166.000
3,325,000
31.000
18,671,000
37,706,000
32.7
O.A
33.1
1.0
21.7
0.5
J.2
0.3
5.7
0.1
32.5
Indirect Costs
Capital charges, 22.IX of capital
investment
Overhead
Plant, 502 of conversion costs less
utilities
Administrative, 15Z of operating
Basis (47)
Total capital investment., $71.100,000.
Total plant investment, $66,500,000.
On-atream time, 330 days/yr.
15,713,000
1,957,000
27.4
3.4
labor and maintenance
Marketing
Research and development
Total indirect costs
Total annual operating costs
Equivalent unit operating costs
587,000
731.000
731 .000
19.719.OdO
57,425,000
S/ton of NH,
174.02
1.0
1.3
34.4
100.0
45
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TABLE 25. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING NATURAL GAS AS THE H£ FEEDSTOCK8
(HIGH FEEDSTOCK COST CASE)
I ten
Annual
quantity (47)
Unit
cost , $
Total annual Percent of
operating cost. $ total cost
Direct Costs
Raw materials
Natural gas
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Natural gas
Electricity
Cooling water
Boiler fpndwutpr
Maintenance, S{ of plant investment:
Analyses
Total conversion costs
Total direct costs
6.270.000 HBtu
55,700 man-hr
4.170,000 HBtu
9.900.000 kWh
16.500,000 kgal
180.000 kgal
2,080 man-hr
5.00/HBtu
10.00/man-hr
5.00/MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15.00/man-hr
31.350,000
225.000
31.575.000
557,000
20.850,000
267.000
1.815,000
166,000
3,325,000
31.000
27.011.000
58.586.000
40.0
0.3
40.3
0.7
26.6
0.3
2.3
0.2
A.2
_b
3471
74.8
Indirect Costs
Capital charges. 22. 17 of capital
Investment
Overhead
Plant, 50Z of conversion costs less
utilities
Administrative. 152 of operating
labor and maintenance
Marketing
Research and development
Total Indirect costs
Total annual operating costs
Equivalent unit operating costs
15,713,000
1.957.000
587.000
731.000
731.000
19~, 719. 0110
78.305,000
S/ton of NH-.
237.29
20.1
2.5
0.8
0.9
0.9
25.2
100.0
a. Basis («?>
Total capital Investment. $71,100.000.
Total plant Investment. $66.500.000.
On-stream time, 330 days/yr.
b. L»» than O.I?,
46
-------
be removed with the installation of guard boxes before the catalytic reactors.
Natural gas also primarily contains methane which contains a higher hydrogen
to carbon ratio than any other hydrocarbon.
For these reasons, it is not surprising that about 95% of the current
NH3 production in the United States is generated from natural gas. The
remaining 5% of the NlTj production is, in most instances, special cases where
site-specific circumstances provide favorable economics. These miscellaneous
sources include refinery gas, the off-gas from electrolytic cells, and coke-
oven gas.
Refinery Gas
Refinery gas streams would seem to be a logical raw material for NH3
since refinery operations involve the treatment of various hydrocarbon streams.
Of the many potential off-gas streams in a refinery, the two streams with the
most potential as a feedstock are the gases from the catalytic cracking units
and the catalytic reformer. Typical compositions of these two refinery streams
are shown in Table 26. Of these two streams, the off-gas from the catalytic
reformer shows the most potential since it has a higher H2 concentration
and no 02~containing compounds. For use in an NH3 plant the only pretreatment
step required would be stepwise refrigeration to remove the various hydrocarbon
gases, leaving a high purity H2 stream. The off-gas from the catalytic
cracking units, on the other hand, contains all of the impurities present in
the reformer off-gas and in addition contains 02, CO, and (X>2 which must be
removed.
TABLE 26. TYPICAL COMPOSITIONS OF REFINERY OFF-GASES (53)
Component
H2
C02
CO
02
N2
GI
C2
C3
C4
C5
Sulfur
Gas from a catalytic
cracker, vol %
34.2
1.3
1.2
0.1
5.5
19.2
23.5
12.7
2.6
0.7
l,200a
Gas from a
reformer,
62.0
-
—
-
-
17.2
9.7
4.5
0.4
0.2
—
catalytic
vol %
a. Gr/100 ft3.
-------
The primary advantages of using refinery gas streams are the relatively
low cost and availability of these H2~rich streams. In fact several oil
companies entered the NH3 market in the late 1960's by adding NH3 synthesis
loops at their refineries. However, recently the requirements for H2 within
the refinery for both hydrocracking and hydrotreating, particularly hydro-
desulfurization, have increased such that some refineries have begun to build
gas reformers to generate additional H2- Thus the future potential for
generating NH3 from refinery gas streams appears to be very limited.
Electrolytic Cells
Another source of H£ for NH3 production is the off-gas from electrolytic
cells. Cl2 gas is typically generated by passing an electric current through
a nearly saturated solution of sodium chloride (NaCl) at 60-70°C (140-158°F).
The Cl2 is removed as a gas at the anode and byproduct H2 gas is removed at
the cathode. This H2 can then be simply mixed with N2, compressed, and sent
to the NH3 synthesis loop. This type of process has the economic advantages
of (1) converting a waste gas stream to a marketable byproduct and (2) at the
same time eliminating some of the processing steps usually required in the
production of NH3 from natural gas (reforming and synthesis gas purification).
The major problems associated with using H£ from electrolytic Cl£ cells to
produce NH3 are the small-scale demand for Cl2 compared with the yearly demand
for NH3 and also, in a related matter, the small number of large-scale Cl2
generating plants with the capacity to supply H2 to economically justify the
construction of a large NH3 plant. For example, a 500 ton/day Cl2 plant
produces enough H2 for about 60 tons/day NH3- Thus the potential for producing
NH3 from electrolytic cell off-gas in the future is severely limited.
At the present time, only six NH3 plants in the United States are currently
using H£ from electrolytic Cl2 cells and these plants have a total capacity of
about 315,000 tons/yr (with a range of 8,000 to 115,000 tons/yr). When compared
with the standard natural gas-based NH3 plants with an annual capacity of
400,000 tons/yr for a single plant, they are relatively small and represent only a
minor portion of the total U.S. NH3 capacity.
Coke-Oven Gas
The only other current alternative source of NH3 in the United States is
coke-oven gas. Before the advent of low cost, readily available natural gas,
coke-oven gas was a major source of NH3- However, only two major plants are
now operating and their total output (470,000 tons/yr) represents only about
1.5% of the current U.S. NH3 production. These plants are located at U.S.
Steel's Geneva, Utah, and Clairton, Pennsylvania, coke ovens. The Clairton
plant is the larger one producing approximately 1200 tons/day of NH3-
A quick analysis of the method of producing coke demonstrates why coke-
oven gas was a major source of NH3 in the past. The initial charge of crushed
coal is fed to a coproduct coke oven, a refractory-lined, gas-tight bin with
typical dimensions of 40 x 1.5 x 13 ft. These individual ovens are arranged in
batteries of 10-100 ovens. As heat and air are added to the oven, the volatile
matter in the coal, i.e., the lower molecular weight hydrocarbons, the pyrolyzed
hydrocarbons, and some of the impurities in the coal are driven off as gases.
48
-------
As shown in the block flow diagram in Figure 13, the gas leaving the ovens
at about 1250-1300°C (2282-2372°F) is initially contacted with a weak aqueous
NH3 spray which removes most of NH3 and the tars from the gas. In the process
the gas temperature is reduced to about 100°C (212°F). The liquid mixture
is separated by density into an NH3 solution and byproduct tars. The remaining
tar is removed from the gas by an electrostatic precipitator (ESP) before the
gas is scrubbed with sulfuric acid (112804) to remove any remaining NH3- After
a final scrubbing stage of oil is used to remove the light aromatics such as
benzene, the "partially cleaned" coke-oven gas leaves this cleanup section
of the coke-oven battery with the typical composition shown in Table 27. The
major constituents of the gas, H2 and methane, are usually the two prime H£
feedstocks for NH3 production. However, in most instances during the further
purification of the gas for the production of NH3, all the remaining constituents
except H2 are removed by cryogenic separation. These higher boiling point
impurities, primarily hydrocarbon gases, are used as boiler fuel and the remaining
N2-H2 stream is then compressed and sent to the NH3 synthesis loop.
TABLE 27. TYPICAL COMPOSITION OF COKE-OVEN GAS (2, 53)
Constituent Vol. %
H2
N2
CO
02
CH4
C2H4
C2H6 + C3H8
C3H6 + C4H8
C6H6 + C2H2
0>2
H2S
NO
HCN
4.7
6.6
7.5
0.6
25.1
1.8
0.4
0.4
0.2
2.1
1 gr/Nm3
Trace
5.2 gr/Nm3
The major disadvantage in using coke-oven gas for the production of NH3
is the need for an extensive purification system. This is, however, partially
balanced by the fact that some of the impurities must be removed to meet air
pollution regulations and most of the remaining impurities which are removed
can be either sold as a byproduct [e.g., tars, aromatics, ammonium sulfate
[(NH4)2S04] or used within the plant as boiler fuel. Another disadvantage is
that a large number of individual ovens must be located in a single battery
to generate sufficient gas to justify building both a purification system and
an NH3 plant, particularly since the coke-oven gas can be used as a boiler fuel
without expending the additional capital for processing the gas to Ntt^. This
49
-------
VJl
O
PREPARATION
CRYOGENIC
AIR »j AIR N)
1 1
i
ACID GAS
' — » REMOVAL —i
ctt
rntfcnv/F* AQUEOUS "COLD" SULFURIC LIGHT
BATTtKY WASH WASH WASH
COKE AMMONIA TARS (NH4)2S04
AND TARS
* UAYotN 1U olCCL MILL
TROGEN
1 '
FINAL AMMONIA1
| REACTOR! 4
CONDENSER
\
SEPARATION +• FUEL GAS TO U— REFRIGERATION.*— I
BOILER
1 , ANHYDROUS
* *" AMMONIA
STORAGE
Figure 13. Block flow diagram of a typical NH3 plant based
on coke-oven gas as the H£ feedstock.
-------
last disadvantage implies that this type of NH3 plant will be located only
where extensive steel-making plants are being built and hence has limited
potential for large-scale production of NH3 in the future.
The primary advantage of using coke-oven gas as a raw material for NH3
is that coke-oven gas is a byproduct of steel making and the only cost
associated with its purchase is the expense of replacing its heating value
as a boiler fuel. Another advantage is the extreme high purity of the H2
stream after treatment, the level of inerts in the NH3 synthesis loop is low
enough that the usual purge stream is not required.
Raw Material, Utility. Labor, and Energy Requirements
The raw material, utility, labor, and energy requirements for the pro-
duction of 1 ton of NH3 from coke-oven gas are given in Table 28.
TABLE 28. UNIT RAW MATERIAL, UTILITY, LABOR, AND
ENERGY REQUIREMENTS FOR THE PRODUCTION OF NH3 FROM COKE-OVEN GAS (53)
Quantity required, Energy equivalent,
Item unit/ton NH3 MBtu/ton NH3
Raw material
Coke-oven gas, kft3 147.6 60.0
N2, kft3 29.8
Utility
Fuel, kft3 (61.0)a (38.7)a
Electricity, kWh 730 6.5
Cooling water, kgal 24
Steam, MBtu 0.95 1.0
Labor, man-hr - -
Total 28.8
Surplus fuel gas.
51
-------
POTENTIAL FUTURE NH3 GENERATING TECHNIQUES
STEAM REFORMING OF NAPHTHA (27. 53)
Although not used in the United States at the present time, another
potentially significant raw material, which is widely used in areas of the
world (Great Britain, India, and Japan) where natural gas is not readily
available, is naphtha. Naphtha is a light petroleum distillate (maximum
boiling point, 215°C) which is commercially available and can be reformed in
a similar manner as natural gas. The main problems are to prevent carbon
deposition (coking) on the catalyst and to control excessive steam consumption
during reforming. The primary disadvantage when using naphtha as a raw material
feedstock is its desirability as a feedstock for other petrochemical operations
and gasoline blending. This latter use, at least for the U.S. market in the
near future, eliminates its potential for NH3 production since its value in
gasoline is significantly greater than its value as a feedstock for NH3 pro-
duction. In addition to its higher cost, naphtha also has a much higher sulfur
content than natural gas and hence requires a purification system to remove
these sulfur compounds.
Process Description
The first step in processing naphtha to NHo, as shown in Figure 14, is a
two-stage hydrodesulfurization system in which most of the sulfur in the naphtha
is converted to H2S which is then adsorbed by hot Fe2(>3. This purification
step usually involves a two-stage catalytic hydrogenation in which the naphtha
is vaporized and mixed with an H2~rich gas. As this mixture passes over the
catalyst, the sulfur present in the naphtha is converted to H2S. During the
regeneration of the iron sulfide (FeS) the sulfur is reconverted to sulfur
dioxide (S02) and sent as a concentrated stream to a Claus unit.
The partially cleaned naphtha is mixed with steam and sent to a primary
reformer similar to that used in a conventional natural gas-based NH3 plant.
The operating temperature in the primary reformer is about 750-850°C (1382-
1562°F) at a pressure of 20-30 atmosphere and a steam:carbon mol ratio ranging
from 2.0 to 3.0:1. The catalyst used in the primary reformer is Ni-based;
however, it also contains small amounts of potassium oxide (K20). The catalyst
support material is typically kalsilite (K20-Al203'2Si02) and the catalyst
particles are usually ring shaped.
The remaining sections of the naphtha-based NH3 plants are identical
with those previously shown for an NH3 plant using natural gas as the H2
feedstock. The partially reformed gas is mixed with air and passed through
a secondary reformer to complete the conversion of naphtha to CO and H2- The
52
-------
NAPHTHA
NAPHTHA
DESULFURIZATION
I I
P
PRIMARY
REFORMER
(SECONDARY
REFORMER
TWO STAGE
CONVERTER
C02
REMOVAL
1
SULFUR STEAM
AIR
METHANATION
•COMPRESSIONI
OJ
AMMONIA
SYNTHESIS
REACTOR!
C02
CONDENSER
Figure 1A. Bloc-k flow diagram of a typical NH3 plant based
on naphtha as the H2 feedstock.
-------
CO is converted to C0£ in a two-stage water gas shift reaction system to
maximize the H2 production and the resulting C02 (as well as the C02 formed
during the reforming operation) is removed by a "promoted" K2C03 system. As
before, the remaining small quantities of CO are destroyed in a methanation
reactor and the resulting clean synthesis gas is compressed and sent to the
NH3 synthesis loop.
Raw Material, Utility, Labor, and Energy Requirements
The raw material, utility, labor, and energy requirements for producing
1 ton of NH3 by steam reforming naphtha in a 1000 ton/day plant are shown in
Table 29. The major item under both raw material and utility requirements
is naphtha. In terms of the overall energy required to generate NHj, naphtha
contributes essentially all (99.5%) of the input energy.
TABLE 29. UNIT RAW MATERIAL, UTILITY, LABOR, AND ENERGY
REQUIREMENTS FOR THE PRODUCTION OF NH3
FROM NAPHTHA BY STEAM REFORMING3 (47)
Quantity required, Energy equivalent,
Item unit/ton NH3 MBtu/ton NH3
Raw material
Naphtha, MBtu 19.4 19.4
Utility
Naphtha, MBtu 14.1 14.1
Electricity, kWh 45.5 0.2
Cooling water, kgal 65.5
Boiler feedwater, kgal 0.5
Labor, man-hr 0.20 -
Total 33.7
a. Basis
Plant capacity, 1000 tons/day.
On-stream time, 330 days/yr.
Process Economics
The total capital investment and the various raw material, utility, and
labor requirements for a naphtha-based NH3 plant producing 1000 tons/day of
NH3 have been previously estimated by others (4Z). In a similar manner as
was used in pricing natural gas, the utility and labor costs were based on
updated 1978 costs. Since naphtha is an oil-based petrochemical and hence
54
-------
may be subjected to higher than average escalation rates in the future, three
alternate costs were assumed for the naphtha. The lowest price assumed for
naphtha in 1978 was $0.40/gal, its current price. The middle price and the
high price alternatives were chosen as $0.60 and $0.80/gal, respectively,
reflecting higher feedstock prices. The other direct and the various indirect
costs were calculated in the same manner as was previously discussed for the
natural gas-based NH3 plant.
The total capital investment for a 1000 ton/day NH3 plant based on steam
reforming naphtha was estimated as $82.4 M and the resulting unit production
cost for NH3 ranged about $193/ton for naphtha at $0.40/gal to about $294/ton
for naphtha at $0.80/gal. The detailed calculation for the $0.40/gal naphtha
case is shown in Table 30 and the detailed calculations for the other two cases
are given in Table 31 and 32.
The major cost associated with producing NH3 from naphtha (for the $0.40/
gal case) is the naphtha cost, which accounts for about 51.9% of the annual
production cost. The feedstock naphtha accounts for 30.0% of the annual
operating cost with the naphtha used as fuel contributing the remaining 21.9%.
The capital charges, which are the most important annual cost in the natural
gas-based plant, represent about 28.6% of the total annual operating cost
with the other various direct and indirect expenses each contributing less
than 6% of the total annual cost.
PARTIAL OXIDATION OF HYDROCARBONS (53)
As the heavier hydrocarbons above methane are used as feedstocks for NH3
production, the conversion of these hydrocarbons to H2 by steam reforming
becomes more difficult and more unattractive economically. Not only are the
sulfur content and the content of other impurities higher, thus requiring larger
purification systems (and thus substantially larger amounts of H2) but also
the hydrogen to carbon ratio decreases in the heavier petroleum fractions. A
declining hydrogen to carbon ratio requires an increasing steam to hydrocarbon
ratio to achieve steam reforming without the deposition of carbon on the reforming
catalyst. Usually naphtha is the heaviest petroleum fraction reformed with
steam because of the large quantities of steam required and the operating
problems associated with reforming higher hydrocarbon streams.
Further complicating this hydrocarbon feedstock problem, the lower
molecular weight petroleum fractions are more desirable and hence more expensive
than the heavy hydrocarbons, such as heavy fuel oil or residual oils. Technically
any petroleum fraction can be used in this system; fuel oil and naphtha are
the two fractions most commonly mentioned. Since naphtha has already been
discussed under steam reforming, only heavy fuel oil will be considered here.
Although not economically attractive where natural gas is readily available,
considerable work has recently been done on a method of converting these heavier
petroleum fractions into H2 and CO by partial oxidation. Because of environmental
regulations, they can no longer be burned without hydrotreating the fuel or
the installation of FGD systems. A typical overall processing scheme for partial
oxidation based on a heavy oil feedstock is shown in Figure 15.
55
-------
TABLE 30. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING NAPHTHA (STEAM REFORMING) AS THE H2 FEEDSTOCK3
(LOW FEEDSTOCK COST CASE)
Iter
Direct Costs
Raw naterials
Naphtha
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
1 L llities
Naphtha
EU-ctriclty
Cooling water
Boiler t.edur.iter
Maintenance, 52 of plant Investment
Analvses
Total conversion costs
Annual
quantity (47)
6,395,000 MBtu
62,300 man-hr
4.6iO,000 MBtu
15.000,000 kWh
21.600,000 kgal
150,000 kgal
2,080 man-hr
Unit
cost , $
3. 00 /MBtu
10.00/man-hr
3. 00 /MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15.00/raan-hr
Total annual
operating cost, $
19,185,000
300,000
19,485,000
623,000
13.920,000
405,000
2,376,000
138,000
3,755,000
11,000
21,248,000
Percent of
total cost
30.0
0.5
30.5
1.0
21.9
0.6
3.7
0..!
5.v
33.3
Total direct costs
Indirect Costa
Capital charts, -'.1: of capital
invcstnenl
Overhead
Plant, 50Z 01 conversion costs less
utilities
Administrative, 152 of operating
labor and maintenance
Marketing
Research and development. 22 of direct
and indirect costs
TVtal indirect costs
it-tjl annual operating costs
Equivalent unit operating costs
S/ton of NH,
193.38 J
a. Basis u, )
Total capital invest rent, $82,400.000.
Total plant investment, $75.100,000.
On-streara tine, J30 days/yr.
b. Less than 0.1X.
40,733.000
18.210.000
2,205,000
661,000
731,000
1 ,276, lino
?3,083,000
63,816,000
63.8
28.6
3.5
1.0
1.1
2.0
36.2
100.0
56
-------
TABLE 31. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING NAPHTHA (STEAM REFORMING) AS THE H2 FEEDSTOCK*
(MEDIUM FEEDSTOCK COST CASE)
Item
Annual
quantity (47)
Unic
cost. S
local annual Percenc ^i
operating cost. S total erst
Direct Costs
Raw materials
Naphtha
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Naphtha
Electricity
Cooling water
Boiler ic.-Jw.itrr
Maintenance, SZ of plant Investment
Analyses
Total conversion costs
Total direct costs
6,395,000 MBtu
62,300 man-hr
4.50/MBtu
10.00/man-hr
28,778,000
100,000
29,078,000
623.000
4,640,000 MBtu
15,000,000 kWh
21.600,000 kgal
150,000 kgal
2,080 man-hr
i.50/MBtu
0.027/kWh
0.11/kgal
0.9J/K.«.,1
15. 00 /man-hr
20, SHU. 000
405,000
2,376.000
138,000
3,755.000
31,000
28,208.000
57.286.000
35. S
O.H
lh.0
il. 5
n.2
71.3
Indirect Costs
Capital charges, 22. H of capital
investment
Overhead
Plant, 501 of conversion coses less
utilities
Administrative, 15Z of operating
labor and maintenance
Marketing
Research and development
Total indirect costs
Total annual operating costs
Equivalent unit operating costs
S/con of NH,
... Basis (47)
Total capital investment, 5«J,400,000.
Total plant investment, $75,100,000.
On-stream time, 330 days/yr.
b. Less than 0.1
18.210.COO
2.JOS.000
661,000
7il.i
1 . J7h."ll(l
2 ],l'8l."lHi
Hi i. Jh1*. 000
0.8
0.9
1.6
Z8.7
100.0
57
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TABLE 32. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH-j PLANT USING NAPHTHA (STEAM REFORMING) AS THE H2 FEEDSTOCK5
(HIGH FEEDSTOCK COST CASE)
Dtrc-rt Costs
R.IV n.itori.tls
Naphtha
Catalvst and hcntcals
Total raw materials costs
Conversion
Operating labor and supervision
It 11 it ies
N.ipru ha
Electricity
Cooling - ,t.-T
BolU-r fei-dwaror
Maintenance, 5Z of plant Investment
Analyses
Total conversion .-.ists
Tot.il direct costs
Annual
quantity (-'<'•;
Unit
cost, $
6.395,000 HBtu
62,300 man-hr
6.00/MBtu
10.00/man-hr
Total annual Percent of
operating cost. S total cost
38.370,000
300.000
38.670,000
623,000
4, 640, 000 HBtu
15,000,000 kWh
21,600.000 kgal
ISO. 000 kgal
2,080 man-hr
6.00/MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15. 00 /man-hr
27.840,000
405,000
2,376,000
138,000
3,755,000
31,000
35,168,000
73.838,000
39.6
0.3
39.9
0.7
28.7
0.1
3.9
-o
36.3
7b.2
Indirect Costs
Caplt.il charKes. 22.1' o f capital
Invest nent
»v, rhc.id
Plant, 50Z of conversion osts less
utilities
Admlnistr.it Ivc, 15Z of operating
labor and maintenance
M.nrkot ing
Research and development
Total indirect costs
Ti.itat annual - pi-r.itlng cost^
Equivalent unit operating costs
... Batl-i (W)
r»t.il capital Investment, S82.-00,000.
I t.il plant investment, $75,100.000.
Hi-.-stream time, 330 days/yr.
h. Le^ than n.K.
$/ton of NH
293.70s
18.2KI.OUO
2.205,000
661,000
731.HOO
1.276.0011
18.8
1. 3
0.7
0.7
1.3
23.8
100.0
58
-------
STEAM
HYDROCARBON•
FRACTION
AIR H AIR | NITROGEN
SEPARATION'
i I
r
SULFUR
REMOVAL
I
SUL
I
FUR
)
I
mVO STAGE
Jrf> 9HIFT
CONVERTEf
*
C02
REMOVAL *
C02
1
p
s
FINAL
JRIFICATIC
i
EPAR
•
f
ATIO
-
1
COMPRESSION
)N
N ^.FUEL GAS
1
TO BOILER
1
IAMMONIA
REACTOR
REFRIGERAT
1 '
CONDENSER
I I
Figure 15. Block flow diagram of a typical NH3 plant bnse<
on heavier hydrocarbons as the H2 feedstock.
-------
Process Description
Partial oxidation involves injecting the heavy petroleum fraction and 02,
although less 02 than the stoichiometric amount required for complete combustion,
into a reaction chamber to generate 112 and CO. In some cases, described later,
steam is also injected. The resulting hot, gas-containing impurities are
quenched with H20, which also removes most of the soot and particulates. The
gas is further purified in a scrubber by passing it countercurrent to an H20
wash stream. The wastewater from the scrubber becomes the quench water and
is eventually sent to a carbon recovery system as a carbon-t^O slurry. The
carbon is recovered by mixing naphtha with slurry which preferentially separates
the carbon from the H20. The naphtha-carbon layer is then removed from the
top of a decanter. The naphtha-carbon stream is usually mixed with part of
the hydrocarbon feedstock and sent to a distillation unit. The naphtha is
removed overhead and recycled to treat the carbon-H20 slurry while the carbon-
feedstock mixture can be used for either preheat fuel or recycled feedstock
for partial oxidation.
When the feedstock is made up of saturated hydrocarbons, such as natural
gas or other light hydrocarbon gases, steam injection into the reaction chamber
is not required. However, when heavier petroleum feedstocks, containing olefins,
such as heavy fuel are used, steam must be added to prevent excessive formation
of carbon and hold carbon formation to 1-4% of the incoming carbon in the
feedstock.
The product gas composition is dependent on many factors ranging from the
pressure and temperature in the generator to the composition of the feedstock.
Table 33 lists typical operating conditions and product gas compositions of
three types of feedstocks based on the Shell Gasification Process. Table 34
gives the characteristics and compositions of the heavy fuel oil, light naphtha,
and natural gas used in this gasification process. Since natural gas can be
relatively easily reformed, it was included in this discussion for comparison
purposes only; the remaining sections refer primarily to the partial oxidation
of heavy fuel oil.
The first step after gas production is a sulfur removal stage. Although
most of the sulfur is present in the raw gas as K2S about 5% exists as carbonyl
sulfide (COS). This further complicates the sulfur removal system since both
H£S and COS must be effectively removed. Various acid gas removal systems
have been used including Alkazid, Sulfinol, or hot "promoted" K2C03. Regardless
of which of these methods is used, the gas passes countercurrently to the
absorbing solution which removes H2S and C02> The crude gas containing COS
then typically passes through a catalytic reactor to hydrolyze the COS to H2S
and C02 and then passes through a second absorption tower. The sour off-gas
from the absorption system containing about 15% H2& is sent to a Claus unit to
produce byproduct elemental sulfur.
The partially cleaned synthesis gas Is then preheated, Injected with steam,
and passed through a conventional hot Fe203 catalyst where the water gas shift
reaction occurs. The major difference between the shift reactors used in a
conventional NI?3 plant (see Water Gas Shift section in Natural Gas section)
60
-------
TABLE 33. TYPICAL OPERATING PARAMETERS FOR PRODUCTION OF
NH3 SYNTHESIS GAS FROM VARIOUS HYDROGEN FEEDSTOCKS USING
THE SHELL GASIFICATION (PARTIAL OXIDATION) PROCESS (53)
Parameter
Operating conditions
Pressure, psig
Preheat temperatures, °F
Feedstock
02
Steam
Temperature of crude gas, °F
Raw material consumption and
utilities used per pound of
feedstock
02, sft3
Steam, pound
Cooling water, gal
Boiler feedwater, gal
Electricity, kWh
Product gas per pound of
feedstock
Product gas, sft-*
(CO + H2) produced, sft3
Composition, vol %
H2
CO
C02
CH4
N2
H2S
Natural
gas
450
457
457
475
285
16.6
0.05
0.14
0.39
7.6
63.2
60.1
60.9
34.5
2.8
0.4
1.4
Feedstock3
Naphtha
450
77
457
475
95
14.9
0.35
3.85
0.30
11.4
54.3
50.8
51.6
41.8
4.8
0.4
1.4
0.007
Heavy
fuel oil
450
457
457
475
95
12.7
0.40
4.03
0.28
11.4
49.9
46.6
46.1
46.9
4.3
0.4
1.4
0.9
a. Typical compositions are shown in Table 34.
61
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TABLE 34. TYPICAL FEEDSTOCKS USED IN THE SHELL
GASIFICATION PROCESS (PARTIAL OXIDATION)(53)
Natural Gas
Characteristic
Heating value, Btu/sft3 937
Composition, vol %
CH4 97.31
2.30
0.20
C4H10 0.15
N2 0.04
Light Naphtha
Characteristics
Specific gravity, 60/60 0.669
ASTM distillation, IB2, °F 99
ASTM distillation, FBP, °F 246
Heating value, Btu/lb 18,630
Composition, wt %
Carbon 84.00
Hydrogen 15-97
Sulfur 0.03
Paraffins 86
Aromatics 5
Naphthenes 9
Heavy Fuel Oil
Characteristics
Specific gravity, 60/60 0.97
Viscosity, seconds Saybolt
Universal at lOOop 3,500
Conradson carbon, wt% 10.2
ASTM pour point, °F 59
Heating value, Btu/lb 17,710
Composition, wt %
Carbon 84.60
Hydrogen 11.30
Sulfur 3.50
Nitrogen 0.40
Ar 0.13
Ash 0.07
62
-------
and those used in a partial oxidation system is that only a high-temperature
catalyst is normally used and extra steam injectors are available if the inlet
gas temperature is too low. The CO and H20 react as follows:
C°(g) + H2°(g) - C°2(g) + H2(g) <
The C02 is then removed using conventional technology, such as MEA, TEA-MEA,
or hot carbonate which were previously discussed.
Before introducing the synthesis gas to a liquid N2 wash, the gas usually
passes through a cold methanol wash (Rectisol) ro remove C02 and H20 which
would tend to form solids in the precooler at these cryogenic temperatures.
Failure to remove these impurities would lead to frequent shutdowns of the
cryogenic unit for defrosting.
The final purification step is usually a cold N2 wash since cryogenic
liquid N2 is available as a byproduct from the air separation plant. The
inlet synthesis gas is precooled by passing it countercurrently to the purified
synthesis gas from the liquid N£ scrubber. The cooled synthesis gas is then
passed countercurrently to the liquid N2- At these cryogenic temperatures
the remaining impurities condense in the liquid N2 and separate from the
synthesis gas. In addition to the purifying the synthesis gas, the evaporation
of liquid N2 in the washing scrubber provides the N2 to yield the H2:N2 mol
ratio required for NH3 production. The waste liquid N£ from the washing
scrubber is vaporized by passing it through an expansion valve and is used
to liquefy the incoming N2 gas from the air separation plant. The resulting
waste gas as shown in Table 35 is used as boiler fuel.
TABLE 35. TYPICAL COMPOSITIONS OF GASES
TO AND FROM A CRYOGENIC PURIFICATION UNIT (53")
Composition, vol %
Purified
Constituent Feed gas synthesis gas Waste gas
H2 94.0 75.0 16.0
N2 0.1 25.0 44.0
CO 4.8 <5 ppm 33.0
CH4 0.5 <1 ppm 3.5
Ar 0.1 <60 ppm 3.3
C02 0.001
H20 0.0003
02 0.0005 <10 ppm
63
-------
The cleaned synthesis gas then passes through the precooler to cool the
incoming synthesis gas before entering the synthesis loop. The impurities
are reduced to such a low level, as shown in Table 35. that the purge stream
from the synthesis loop is not needed; the few impurities that remain are
dissolved in and removed with liquid NH3 product.
Raw Material, Utility, Labor, and Energy Requirements
The raw material, utility, labor, and energy requirements for the pro-
duction of 1 ton of NH3 from heavy fuel oil in a 1000 ton/day NH3 plant are
given in Table 36. As in all the other NH3 generating systems, the major
item is the H2 feedstock material since it is used both as a raw material
and as a fuel in the system. The energy input in the fuel oil represents
about 99.5% of the total energy consumed in the process.
TABLE 36. UNIT RAW MATERIAL, UTILITY, LABOR, AND ENERGY
REQUIREMENTS FOR THE PRODUCTION OF NH3 FROM HEAVY FUEL OILa (47)
Energy
Quantity required, equivalent,
_ Item _ unit /ton NH3 _ MBtu/ton
Raw material
Heavy fuel oil, MBtu 20.3 20.3
Utility
Heavy fuel oil, MBtu 14.6 14.6
Electricity, kWh 136.0 0.5
Cooling water, kgal 80.0
Boiler feedwater, kgal 0.4
Labor, man-hr 0.23 -
Total 35.4
a. Basis
Plant capacity, 1000 tons /day.
On-stream time, 330 days/yr.
Process Economics
The total capital investment and the various raw material, utility, and
labor requirements for a 1000 ton/day NH3 plant based on the partial oxidation
of heavy fuel oil have been previously estimated by others (47). The various
factors used to calculate the indirect costs and the unit costs for the various
utilities are identical to those used previously for the other potential feed-
stocks. Also, in a similar manner to that used for the other feedstocks, three
64
-------
prices for the heavy oil were assumed. The lowest cost, $0.35/gal, is the
current market price while the medium cost ($0.53/gal) and the high cost
($0.70/gal) options were included to cover higher price scenarios. The
resulting unit production cost for NH3 ranged from about $217/ton for the
low cost case ($0.35/gal) to about $302/ton for the high cost fuel-oil case
($0.70/gal). The detailed breakdown of the annual operating costs for the
low cost heavy fuel-oil case is shown in Table 37. The breakdowns for the
other two feedstock costs are shown in Tables 38 and 39.
For the $0.35/gal case, the major annual operating cost (39.2%) was
for heavy fuel oil. Capital charges required 36.8% of the total annual
amount. The other annual charges each represent less than 8% of the total
operating costs.
NH3 FROM COAL (47. 52, 53)
With the recent concern about the availability and cost of natural gas
in the United States, increasing attention has been focused on the potential
use of coal as an H2 feedstock for the production of NH3. Before the discovery
of large natural gas deposits in the early 1950's, the primary feedstock for
NH3 was coal.
The major difference between using coal and the current use of natural
gas would be the replacement of the primary and secondary reformers with
coal gasifiers, coal preparation equipment, and crude gas cleanup system, as
shown in Figure 16. The major advantage of using coal gasification would be
an ample and long-term domestic supply of feedstock. The major disadvantage
would be the increased capital investment for the gasifiers, the coal pre-
paration equipment, and the gas purification system.
Although the following sections will discuss the commercially proven
NH3~from-coal processes, several demonstration projects involving new coal
gasification technology are in various stages of development. The demonstration
at TVA's National Fertilizer Development Center of retrofitting a coal gasification
system onto the front end of an existing natural gas-based NH3 plant will be
the first of these modern NH3-from-coal facilities to be operating in the
United States. Initial operation of this plant, which will convert 168 tons/
day of coal to NH3, is scheduled for early 1980. Another project is a grass
roots 1200 ton/day NH3 plant consuming 1700 tons/day of coal. The contract
for this plant between the U.S. Department of Energy (DOE) and W. R. Grace and
Company, in conjunction with Ebasco Services, Inc., involves a feasibility study
for the coal gasification and gas purification sections of the NH3 plant. If
the results of the feasibility study are favorable and this project is selected
for further funding, operation of the plant could begin as early as 1982.
Process Description
Coal gasification is essentially a partial-oxidation operation similar
to that used in the treatment of heavy fuel oil feedstock. Pulverized coal,
steam, and 02 from an air separation unit are fed to a gasifier, which can
be a fixed-bed, an entrained-bed, or a fluidized-bed reactor. Although many
65
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TABLE 37. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING HEAVY FUEL OIL AS THE H2 FEEDSTOCK'
(LOW FEEDSTOCK COST CASE)
Annual Unit
Item quantity (47) cost. S
1)1 TV. -i Costs
Raw mten.ils
Heavy fuel oil 6,715,000 HBtu 2.43/HBtu
Catnlyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision 74,800 man-hr 10.00/man-hr
Utilities
Heavy fuel oil 4,820,000 HBtu 2.43/HBtu
Electricity 45.000.000 kWh 0.027/kUh
Cooling water 26.400.000 kgal 0.11/kgal
Boiler fi-.-dw.itcr 120,000 kgal 0.92/kgal
Maintenance. SZ of plant investment
Analyses 2,060 nan-hr 15. 00 /man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges, ?2.1' of capital
Investment
Overhead
Plant. 50Z of conversion costs less
utilities
Administrative, 15* of operating
labor and maintenance
Marketing
Research and development, 21 of direct
and indirect costs
Total Indirect costs
Total annual operating costs
S/ton of NH..
Equivalent unit operating costs 21A.9S
Total annual
operating cost. $
16,317,000
150,000
16,467.000
748.000
11,713.000
1.215,000
2,904,000
110,000
5,680,000
31,000
22,401,000
38,868,000
26, 365, 000
3,230,000
969,000
731.000
1.437.UCin
32,727,000
71,595,000
Percent of
total cost
22.8
0.2
23.0
1.0
16.4
1.7
4.1
0.2
7.9
_h
31.3
54.3
36.8
4.5
1.4
1.0
2.0
45.7
100.0
b.
Basis < 47)
Total capital Investment, $119,300,000.
Total plant investment, $113.600,000.
On-strean time, 330 days/yr.
I.e-.s than 0.1" .
66
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TABLE 38. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH-j PLANT USING HEAVY FUEL OIL AS THE H2 FEEDSTOCK3
(MEDIUM FEEDSTOCK COST CASE)
Item
Direct Costs
Raw materials
Heavy fuel oil
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Heavy fuel oil
Electricity '
Cooling water
Boiler ffedwat.-r
Maintenance, 5Z of plant Investment
Analyses
Total conversion costs
Total direct costs
Annual
quantity H7)
Unit
cost . S
6,715,000 HBtu
74,800 man-hr
4,820.000 MBtu
43,000,000 kUh
26.400.000 kgal
120,000 kgal
2,080 man-hr
3.65/MBtu
10.00/man-hr
3.65/MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15.00/man-hr
Total annual Fervent ot
operating '-_;'stj_ 5 total cost
2i,510,000
_ 150,000
24."660,000
7iH.C)00
17,593,000
1,215,000
2,904,000
110,000
5,680,000
31.000
28,281,000
52,941,000
J.2
0.'.
Jll. h
1.-4
I.-
ll.l
lh
TT.o
hi . i
Indirect Costs
Capital charges, -2.17- of capital
investment
Overhead
Plant, 50Z of conversion costs less
utilities
Administrative, 1SZ of operating
labor and maintenance
Marketing
Research and development
Total indirect costs
Total annual operating costs
Equivalent unit operating costs
a. Basis 1.7)
Total capital investment. $119,100,000.
Total plant Investment, $111,600,000.
On-stream time, 310 Java/vr.
b. Less than 0.1...
S/ton of NH
259.60 '
Jfc, (hi,lino
3,230,000
969.000
1. .u!.Mii
85,668,000
1.8
1.1
0."
100. 0
67
-------
TABLE 39. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH-j PLANT USING HEAVY FUEL OIL AS THE H2 FEEDSTOCK3
(HIGH FEEDSTOCK COST CASE)
Item
Annual
quantity (4?)
Unit
cost, $
Total annual
operating cost, $
Percent of
total coat
Direct Costs
Raw materials
Heavy fuel all
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Heavy fuel oil
Electricity
Cooling water
Boiler fcvduatfr
Maintenance, 5! of plane investment
Analyses
Total conversion costs
Total direct costs
6.715,000 MBtu
74,800 man-hr
4,820,000 MBtu
45,000,000 kWh
26,400.000 kgal
120,000 kgal
2,080 man-hr
4.86/MBtu
10.00/man-hr
4.86/MBtu
0.027/kUh
0.11/kgal
0.92/kgal
15.00/man-hr
32,635,000
150.000
32,785,000
748,000
23,425,000
1.215,000
2,904,000
110,000
5,680.000
31.000
34,113,000
66,898,000
32.7
0.2
32.9
0.8
23.5
1.2
2.9
0.1
5.7
_b
3472
67.1
Indirect Costs
Capital charges, 22.lZ0f capital
Investment
Overhead
Plant, 50Z of conversion costs less
utilities
Administrative, 15Z of operating
labor and maintenance
Marketing
Research and development
Total Indirect costs
Total annual operating costs
26,365.000
3,230,000
969.000
731.0DO
1.432.000
32,727.000
99,625,000
26.5
3. J
1.0
0.7
.
32.9
100.0
tqulvalent unit operating costs
S/ton of NH.
301.89 •*
a. Basis (47)
Total capital Investment, $119,300,000.
Total plant Investment, $113,600,000.
On-stream time. 330 days/yr.
b. Less than 0.1Z.
68
-------
COAL
COAL
PREPARATION
GASIFICATION-
I
STEAM
AIR.
AIR
QUENCH,
ESP, AND
GAS
HOLDER
'COMPRESSION
SULFUR
REMOVAL
TWO STAGE
CO SHIFT j.
CONVERTER
1
ASH
SULFUR
NITROGEN
SEPARATION
\o
1
FINAL |_
PURIFICATION
I I
• COMPRESSION-
SEPARATION-
FUEL GAS TO
BOILER
I AMMONIA
SYNTHESIS
REACTOR
•REFRIGERATION
L,
I
ANHYDROUS
AMMONIA I
STORAGE
Figure 16. Block flow diagram of a typical NH3 plant based
on coal as the H2 feedstock.
-------
chemical reactions involving coal, steam, and 02 occur in the gasifier, the
primary equilibrium reactions are:
C(s) + H2°(g) I C° + H2(g>
CU> + 1/2°2(g> * C°(g)
C(s) + °2(g) * C°2(g)
C(s) + C02(g) S 2CO(g)
C°(g) + H2°(g) * °°2(g) + H2(g)
The desired reaction, reaction (10), is an endothermic reaction which requires
extensive amounts of energy. The primary reason for injecting 02 is to generate
sufficient heat from reactions (11) and (12) to allow reaction (10) to proceed.
The final gaseous mixture, or crude gas, is a complex equilibrium system that
is dependent on the degree of oxidation, the temperature and pressure, and
hence the particular gasification system selected as well as the feed ratios
of the various streams.
The gasification scheme selected has a significant impact on the various
downstream operations prior to entering the NH3 synthesis loop and therefore
two gasification variations will be briefly mentioned. The first is a fixed-
bed reactor, such as the Lurgi gasifier. These gasifiers can operate at low
or high pressure but are typically low-temperature units (800-1100°C). The
second variation is an entrained flow reactor such as the Koppers-Totzek
gasifier. These gasifiers operate at low pressure at a high temperature
(1600-2000°C). Other gasification systems and additional data on the above-
mentioned gasifiers are available from other sources (11, 35, 37).
Although generating NH3 synthesis gas using low-temperature gasifiers is
technically feasible and has been used in the past, these type systems may
not be attractive for producing NH3 since these processes generate more of
the higher hydrocarbons such as methane and tars and hence less H2 and CO. The
higher operating temperatures of the entrained-flow reactors, on the other
hand, convert the coal to primarily H2 and CO with very few higher hydrocarbons.
Typical exit gas compositions after initial cleanup for the low- and high-
temperature gasifiers are shown in Table 40. These differences would be
substantially larger, of course, in the raw gas since the low-temperature gasifier
product gas also contains tars, phenols, and NH3 which are removed in the
initial gas cleanup section. For these reasons only the high-temperature
gasification system (Koppers-Totzek) will be discussed further.
In the Koppers-Totzek gasification scheme shown in Figure 16, the pulverized
coal, oxygen, and stream are fed into the gasifier and the previously mentioned
reactions occur at 1600-2000°C (2912-3632°F) and atmospheric pressure. Signi-
ficant amounts of ash are entrained in the product gas and must be removed.
This product is initially cooled to about 870-1100°C (1598-2012QF) by a water
70
-------
quench and then passed through a waste heat boiler to further cool the gas
to 300°C (572°F). Final cooling to about 40°C (104°F) is achieved in a
cooler washer and the resulting gas is sent to the ESP for additional particulate
removal. This partially cleaned gas passes through a gas holder and is then
compressed to about 30 atmospheres prior to chemical purification.
TABLE 40. TYPICAL EXIT GAS COMPOSITIONS FOR
LOW AND HIGH TEMPERATURE GASIFIERS (36, 53)
Composition, vol %a
Constituent Low temperature High temperature
C02 30.3 13.4
CO 17.5 54.4
H2 42.1 30.0
CH4 9.6 0.1
H2S + COS -b 0.6
N2 + Ar 0.5 1.5
a. Dry basis.
b. Not listed.
Since coal contains significant amounts of sulfur which will be present in
the synthesis gas primarily as H2S, but with lesser amounts of COS, CS2, and
other miscellaneous carbon-sulfur compounds, these compounds are removed prior
to shift conversion. Although many H2S removal systems are commercially
available (including the hot K2C03 process described earlier), the Rectisol
processes will be described here. In the Rectisol process, the H2S-containing
stream is passed countercurrently to a cold (-30 to-50°C) methanol solution
which preferentially and almost completely removes H2S. The resulting H2S-
containing methanol stream also contains some C02 and can be regenerated in
a separate vessel by reducing the pressure. This concentrated H2S stream can
then be further processed to form byproduct elemental sulfur in a Claus unit
while the methanol is recycled to the absorber. The "partially" cleaned
synthesis gas, with the typical composition shown in Table 41, is then pre-
heated, injected with steam, and sent to a conventional two-stage CO shift
converter.
The first-stage converter uses an iron-chromium (Fe-Cr) catalyst at
415° (750°) to promote the water gas shift reaction, i.e.,
C°(g) + H2°(g) * C°2(g) + H2(g)
and thereby producing as much H2 as possible while at the same time consuming
CO. After cooling to about 25QOC (482°F) in an interstage heat exchanger,
the crude gas is passed through a low-temperature catalytic reactor containing
71
-------
a zinc-copper oxide (ZnO-CuO) catalyst to further reduce the final CO con-
centration. In addition to the interstage cooling, the crude gas is usually
passed through a guard cell containing ZnO for f^O^ to remove the last traces
of sulfur compounds before entering the low-temperature shift converter. The
typical composition of this shifted gas is given in Table 41.
TABLE 41. TYPICAL SYNTHESIS GAS COMPOSITION
BEFORE AND AFTER CO SHIFT (53)
Composition, vol %
Before shift After shift:
Constituent conversion conversion
C02
CO
H2
N2
Ar
CH^
11.3
56.0
31.0
1.0
0.6
0.1
41.3
3.0
54.6
0.6
0.4
0.1
a. Dry basis.
The synthesis gas is then passed through a final purification stage
consisting of C02 removal system and a cryogenic N£ wash. This C02 removal
system is another low-temperature (-54°C) methanol wash nearly identical with
that used for ^S removal. The cold methanol containing C02 is pumped to a
second vessel where, at a reduced pressure, the C0£ is flashed off as a
byproduct stream. The regenerated methanol is then recycled to the absorber.
The synthesis gas leaving the C02 wash, which has a typical composition,
shown in Table 42, passes through carbon beds to remove any remaining C02
and methanol which would freeze out at cryogenic temperatures.
As a final purification stage and also to provide the N2 for the 3:1
stoichiometric ratio of N2:H2 for NH3 production, the gas is sent to a liquid
N2 washing. This final purification stage is identical with that previously
discussed in the section on partial oxidation. The resulting synthesis gas
with the composition shown in Table 42 is further compressed before entering
the conventional NH3 synthesis loop. A portion (13-17%)of the synthesis
mixture is converted per pass through the reactor with the remainder recycled
for the addition of more synthesis gas mixture and another pass through the
reactor. The NH3 is separated by condensation and stored as a liquid in
refrigerated storage tanks.
72
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TABLE 42. TYPICAL SYNTHESIS GAS COMPOSITIONS
AFTER C02 WASH AND AFTER LIQUID N2 WASH (59)
Composition, vol
After C02 After liquid
Constituent wash N2 wash
C02
CO
H2
N2
Ar
CH4
5.0
93.1
1.1
0.6
0.1
-
75
25
-
-
a. Dry basis.
Recently Texaco Development Company has begun to market a coal gasifier
which is gaining acceptance as an additional alternative to the Koppers-
Totzek gasification system. The Texaco process, although a lower temperature
process [gasifier temperature, 1100-1350°C (2012-2462<>F)], uses a high
pressure (500 psig) gasifier and thus eliminates some of the downstream com-
pression stages. The raw gas from the gasifier has a composition similar
to that generated in the high-temperature systems as shown in Table 43. The
remaining processing steps are similar to those discussed for the high-
temperature gasification process, i.e., desulfurization, CO shift, C02 removal,
final purification, compression, and NH3 synthesis.
TABLE 43. COMPARISON OF TYPICAL RAW GAS COMPOSITION
FROM THE TEXACO WITH THAT FOR A HIGH TEMPERATURE GASIFIER3 (53)
Gas compositions, vol %
Constituent
CH4
CO
C02
H2
N2 H
H2S
h Ar
+ COS
Texaco
0.2
45.0
17.2
35.8
0.6
1.2
High temperature
0.1
54.4
13.4
30.0
1.5
0.6
a. Dry basis.
73
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Raw Material, Utility, Labor, and Energy Requirements
The raw material, utility, labor, and energy requirements for producing
1 ton of NH3 in a 1000 ton/day Nl^-from-coal plant are given in Table 44.
As is typical for NH3~from-coal plants, the primary raw material and utility
requirement is coal with this coal also accounting for essentially all
(98.9%) of the input energy.
TABLE 44. UNIT RAW MATERIAL, UTILITY, LABOR, AND ENERGY
REQUIREMENTS FOR THE PRODUCTION OF NH3 FROM COAL* (47)
Quantity required, Energy equivalent,
Item unit/ton NH3 MBtu/ton NH3
Raw material
Coal, MBtu 27.4 27.4
Utility
Coal, MBtu 13.7 13.7
Electricity, kWh 136.0 0.5b
Cooling water, kgal 70.0
Boiler feedwater, kgal 0.45
Labor, man-hr 0.45 -
Total 41.6
a. Basis
Plant capacity, 1000 tons/day.
On-stream time, 330 days/yr.
b. Assuming 3,412 Btu/kWh.
Process Economics
The total capital investment for a 1000 ton/day NH3~from-coal plant was
estimated at $132.8 M based on information given by others (47). As in all
the previous economic summaries, the annual operating costs were calculated
on the basis of joint EPA-TVA premises and 1978 raw material and utility
costs. If a coal cost of $20.00/ton is assumed, the resulting annual
operating costs are approximately $61.4 M and the equivalent unit operating
cost is about $186/ton of NH3 as shown in Table 45. Capital charges represented
about 47.8% of the annual operating cost while coal cost contributed about 21%.
The remaining annual costs each represented 11% or less of the total annual
cost.
74
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TABLE 45. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING COAL AS THE H2 FEEDSTOCK3
(LOW FEEDSTOCK COST CASE)
Item
Annual
quantity (47)
Unit
cost, $
Total annual
operating cost, $
Percent of
total cost
Direct Costs
Raw materials
Coal
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Coal
Electricity
Cooling water
Boiler feedwater
Maintenance, 51 of plant investment
Analyses
Total conversion costs
Total direct costs
9,029,000 HBtu
150,000 man-hr
4,514,000 HBtu
45.000,000 ktfh
23,100,000 kgal
150,000 kgal
2,080 man-hr
0.95/MBtu
10.00/raan-hr
0.95/MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15.00/roan-hr
8,578,000
150,000
8,728,000
1,500,000
4,288,000
1,215,000
2,541,000
138,000
6,430.000
31,000
16,143,000
24,871,000
7.n
J.n
li.Z
0.2
10.5
_b
2O
Indirect Costs
Capital charges, 22.II of capital
investment
Overhead
Plant, SOX of conversion costs less
utilities
Administrative, 15Z of operating
labor and maintenance
Marketing
Research and development, 2Z of direct
and indirect costs
Total Indirect costs
Total annual operating costs
Equivalent unit operating costs
S/ton of NH-
185.92J
3,981,000
' 1,194,000
7II .OH'
1.227.000
J6.482.000
M. 153,000
2.0
100.0
a. Basis (47)
Total capital Investment, $132,800,000.
Total plant Investment, $128,600,000.
On-stream time, 330 days/yr.
b. Less than 0.1Z.
75
-------
Alternative coal cost of $30/ton and $40/ton were chosen to reflect
potentially higher fuel costs and the resulting annual operating cost for
each case is shown in Table 46 and 47 respectively.
NH3 IMPORTS (7, 13, 14)
In addition to domestic NH3 production, net imports or exports have an
additional impact on the U.S. NH3 supply and demand situation. Until 1973,
the United States was a perennial net exporter of NHo as shown in Figure 17.
The high levels of U.S. exports during the period 1967-1971 correspond to the
time when many of the new large capacity (1000 ton/day) NH3 plants were
coming onstream and there was a large surplus of domestic capacity. With
this surplus of NH3 capacity no new plants were initiated; as demand increased
to absorb this excess capacity, the United States became a net importer of
NH3 from 1975-1977. The recent large increase in domestic NH3 is expected to
sharply curtail NF.3 imports during 1978 and 1979, and since no new plants are
currently under construction, imports of NH3 are projected to rise sharply
again in the 1980's.
Most of these NH3 imports are expected to come from three countries:
Russia, Canada, and Mexico. Of a projected total 3.5 Mtons of NH3 imports
(gross) in 1980, an estimated 1.5 Mtons will come from Russia, 0.5 Mtons
from Canada, and 1.5 Mtons from Mexico and other Latin American companies.
The Russian imports are the result of long-term contract for a phosphate-N2
trade negotiated between Occidental Petroleum and Russia. The Canadiam imports
of 0.5 Mtons in 1980 is about double the current rate and is primarily due to
the large increases in installed NH3 capacity expected to come online during
the next 2 yr. However, most of these Canadian imports are consumed across
the border in the upper Midwest and will not contribute significantly to the
potential NH3 oversupply on the gulf coast. The Mexican imports, however,
are perhaps the most unsettling from the standpoint of the U.S. NH3 producers.
With its recently discovered large oil and gas reserves (total reserves of
20 Tft^ in the Reforma field alone) and the projected large NH3 plant capacity
additions, not only will Mexico have the capacity to export large quantities
of NH3 to the U.S. Gulf and East Coasts (as well as the U.S. West Coast through
a trans-Mexican NH3 pipeline) but many of the export orders by the other Latin
American countries will be filled with Mexican NH3-
Projected Mexican NH3 Capacity and Production
With their large and increasing natural gas production and reserves,
Mexico has the potential to become an important exporter of NH3 as well as
natural gas. The proximity of their gas-producing areas to the Gulf of Mexico,
and hence the ease of shipment to the U.S. Gulf Coast and to other Latin
American countries by barge would seem to offer attractive economic incentive
to PEMEX (Petroleos Mexicano's), particularly since they have recently begun
an unprecedented growth in NH3 capacity. Six new plants, listed in Table 48,
are in various stages of construction and will raise the total annual NH3
production in Mexico to nearly 4.0 Mtons.
76
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TABLE 46. TOTAL ANNUAL OPERATING COSTS AND UNIT
FOR A 1000 TON/DAY NH-j PLANT USING COAL AS THE
(MEDIUM FEEDSTOCK COST CASE)
OPERATING COSTS
H2 FEEDSTOCK3
Item
Annual
quantity (47)
Unit
cost, S
Total annual Percent of
operating cost. S total cost
Direct Costs
Raw materials
Coal
Catalyst and chemicals
Total raw materials costs
Conversion
Operating labor and supervision
Utilities
Coal
Electricity
Cooling water
Boiler feedwater
Maintenance, 5Z of plant investment
Analyses
Total conversion costs
Total direct costs
9,029,000 MBtu
150,000 man-hr
4,514,000 MBtu
45,000,000 kUh
23,100,000 kgal
150,000 kgal
2,080 man-hr
1.43/MBtu
10.00/nan-hr
1.43/MBtu
0.027/kUh
0.11/kgal
0.92/kgal
15.00/man-hr
12,911.000
150.000
13.061,000
1,500,000
6,455,000
1,215,000
2,541,000
138,000
6,430,000
31,000
18,310,000
31,371.000
1<».0
_0._2
11.2"
2.2
1.8
3.8
0.2
9. S
'.h
JTYS
Indirect Costs
Capital charges, 22.1Zof capital
investment
Overhead
Plant, SOZ of conversion costs less
utilities
Administrative, 1SZ of operating
labor and maintenance
Marketing
Research and development
Total indirect costs
Total annual operating costs
29, 14", 0(11)
3,981,000
1,194.000
731.'iOO
1 .??7.(j(Hi
5."
1.8
1.1
J_.fl
53.K
100.0
Equivalent unit operating costs
S/ton of NH1
205.62
a. Basis (67)
Total capital investment, $132,800,000.
Total plant Investment, $128,600,000.
On-stream time, 330 days/yr.
b. Less than 0.12.
77
-------
TABLE 47. TOTAL ANNUAL OPERATING COSTS AND UNIT OPERATING COSTS
FOR A 1000 TON/DAY NH3 PLANT USING COAL AS THE
(HIGH FEEDSTOCK COST CASE)
H2 FEEDSTOCK6
I ten
Direct Costs
Raw materials
Coal
Catalyst and chemicals
Total raw materials costs
Annual
quantity (47)
9,029,000 MBtu
Unit Total annual
cost, $ operating cost, 5
1.90/MBtu 17,155,000
ISOjOOO
17,305,000
Percent of
total cost
23.1
0.2
23.3
Conversion
Operating labor and supervision
Unities
Coal
Electricity
Cooling water
Boiler f.'ii,iu.ir..r
Maintenance, 5Z of plant Investment
Analyses
Total conversion costs
Total direct costs
150.000 man-hr
4,514.000 MBtu
45,000.000 kWh
23,100.000 kgal
150.000 kgal
2,080 man-hr
10.00/man-hr
1.90/MBtu
0.027/kWh
0.11/kgal
0.92/kgal
15.00/man-hr
1,500.000
8,577.000
1,215.000
2,541.000
138,000
6,430.000
31.000
20,432,000
37,737,000
2.H
11.6
1.6
3.4
0.2
8.7
_h
JfTs"
so. 8
Indirect Costs
Capital charges, 22.11 of capital
investment
Overhead
Plant, 50Z of conversion costs less
utilities
Administrative, 15Z of operating
labor and maintenance
Marketing
Research and development
Total indirect costs
Total annual operating costs
Equivalent unit operating costs
S/ton of HH
224.91
29.349.0fif
3,981.000
1.194,000
711.000
t.227.(MIO
36.482.00n
39.5
5.4
l.h
1.0
±•2
49.2
100.0
... Basis (47)
Total capital investment. $132.800,000.
Tocal plant investment, $128,600.000.
On-stream tine, 330 days/yr.
b. Lens than 0.1 .
78
-------
800
600
400
200
C/J
ee.
O
CO
i -200
rJ
I -400
5
-600
-800
-1000
52
1965
1 I I I I I I I I I |
600
I I I
670 -
165
JOS
383
964
32
295
20
1
35
147
243
Legend
| | Actual
Projt-ctfd
I I
I I
I J_ I I I I
1969
1973
1977
1981
YEAR
Figure 17. Net U.S. imports and exports of NH3 during the period 1965-1981 (43).
-------
TABLE 48. PROJECTED MEXICAN NH3 PLANTS (8, 19)
Startup Capacity,
Plant date tons/yr
Cosoleacaque No. 1
Cosoleacaque No. 2
Salamanca
Allende No. 1
Allende No. 2
Salima Cruz No. 1
Saltma Cruz No. 2
1977
1977
1978
19803
1980a
1980s
1980*
450,000
450,000
300,000
445,000
445,000
455,000
445,000
a. Projected.
Even though only a portion (40%) of this new NH3 production coming online
in 1977 will be comsumed to produce urea, Mexico is expected to also become a
net exporter of this valuable fertilizer. A total of 460,000 tons/yr of this
NH3 will be used in two urea plants, one using 275,000 tons/yr of NH3 from
the Cosoleacaque complex and the other urea plant consuming NH3 from the new
Salamanca plant. In contrast to 1975-76 when Mexico imported 46,000 tons
of nitrogen fertilizers (mostly from the United States), in the near future,
Mexico is expected to export upwards of 200,000 tons of N£ in the form of
urea. Thus, in addition to possible losing the Mexican fertilizer market (50,000
tons of nitrogen fertilizers in 1976) American producers can expect a potential
double loss since Mexico will be exporting fertilizers to previously American
markets in other Latin American countries.
NH3 exports from Mexico are expected to reach 500,000 tons by 1978. For
the years beyond 1978 numerous factors will determine the potential Mexican
exports of NH3 including population and agricultural trends but NH3 exports
could reach 1.5 Mtons/yr in the early 1980's. Therefore, in addition to
displacing NH3 (and NH3-based fertilizers) exported by the United States to
South America and thereby indirectly increasing the U.S. supply of NH3, the
export of some of this excess NH- to the United States has the potential of
directly affecting the U.S. NH3 supply.
80
-------
ECONOMIC COMPARISON OF NH3 PRODUCTION COST
FOR VARIOUS H2 FEEDSTOCKS
From a comparison of the estimated 1978 NH3 production costs for the various
hydrocarbon feedstocks calculated in the previous sections and summarized in
Table 49, it is apparent that these alternate feedstocks cannot economically
compete with natural gas at the present time based on the premises of this
study. With coal priced at $20.00/ton (0.95/MBtu) and naphtha costing $0.40/gal
($3.00/MBtu), the price of natural gas must exceed about $3.40/MBtu in order
for coal and $3.60 for naphtha to become economically attractive.
Although the price of natural gas is expected to increase in the future,
the actual selling price of natural gas is uncertain and hence the relative
price difference between natural gas and the other alternate feedstocks are
difficult to project into the future. Even the future availability of natural
gas for NH3 production is questionable. The economics of NH3 production from
the various feedstocks in the future will depend not only on the availability
and cost of feedstocks, but also on innovations resulting from advanced process
development.
81
-------
TABLE 49. ALTERNATIVE FEEDSTOCK COSTS AND THE RESULTING
UNIT PRODUCTION COST OF NH3 IN 1978
Assumed cost
Unit production cost
Feedstock
Natural gas
Naphtha
Fuel oil
Coal
$/unit
1.00/MBtu
3.00/MBtu
5.00/MBtu
0.40/gal
0.60/gal
0.80/gal
0.35/gal
0.53/gal
0.70/gal
20.00/ ton
30.00/ton
40.00/ton
$/MBtu
1.00
3.00
5.00
3.00
4.50
6.00
2.43
3.65
4.86
0.95
1.43
1.90
of NH-*,a $/ton
111
174
237
193
244
294
217
260
302
186
206
225
a. Basis
Plant capacity, 1000 tons/day.
On-stream time, 330 days/yr.
Premises are described in text under "Current
Generating Techniques," "Steam Reforming of
Natural Gas."
82
-------
CURRENT AND PROJECTED NATURAL GAS SUPPLY AND DEMAND
At one time in the United States (and even at the present time in some
countries) natural gas was vented or flared because there were no local markets
for the gas but the associated oil was highly desired. With the increase in
drilling for oil in the 1950's in the United States and the associated increase
in natural gas supplies, transcontinental pipelines were constructed so that
the resulting gas byproduct could be transported to areas of the country without
substantial natural gas reserves. Since natural gas was orginally considered
as a waste stream from oil wells, this gas was sold to the pipeline companies
at low prices simply for disposal. The demand for natural gas continued to grow
as more and more consumers switched from coal and coal-gas to the cheaper and
cleaner natural gas. This change over was significantly increased during the
rise of the environmental movement of the early 1970's.
With the major multinational oil companies concentrating on drilling and
production the total number of wells being drilled in the United States gradually
dropped during the 1960's and early 1970's. The proven natural gas reserves began
to decline as more gas was consumed than was being replaced by the discovery of
new natural gas reservoirs. Retail gas companies continued to sign up both
residential and industrial customers during this time until natural gas demand
began to exceed pipeline supplies during the winter months and industrial customers
faced substantial curtailments.
This trend has led to the current situation—industrial customers consuming
natural gas from interstate pipelines face substantial natural gas cutbacks
during the winter months when residential demands require most of the available
gas. This winter curtailment is a substantial operating problem for natural gas-
based NH3 plants since the peak demand and sales period for fertilizers is
during spring planting and it would be desirable for the Nl^ plants to be operating
at peak capacity during these winter months.
One alternative solution to this natural gas shortage problem which has
already been taken by many of the NH3 producers is the substitution of intra-
state for interstate natural gas. NH3 plants operating prior to 1976, i.e.,
NH3 plants planned and designed before the Arab oil embargo and the era of natural
gas curtailments, were scattered around the country but were concentrated primarily
in the Gulf States (gas-producing states) or states consuming large amounts of
NH3, i.e., the Corn Belt States such as Nebraska and Iowa, as shown in Figure 18.
Figure 19 pinpoints the location of NH3 plants coming online during the period
1976-1980, i.e., plants planned after the oil embargo and the beginning of the
winter gas curtailments. At the time these NH3 plants were being planned
interstate gas, although slightly cheaper, was subject to these winter curtail-
ments. The pipeline gas companies selling interstate gas were banned from
accepting new customers and the new post-1975 NH3 plants were built primarily
in gas-producing states such as Oklahoma, Louisiana, and Texas. However,
83
-------
00
Legend
• <250 MST
O 250-500 MST
>500 MST
Figure 18. Geographic location of U.S. NH3 plants operating before 1975 (39).
-------
00
Legend
<250 MST
O 250-500 MST
>500 MST
Figure 19. Geographic location of new U.S. NH3 plants operating after 1975 (39)
-------
with the recent substantial increases in intrastate gas prices (more than
$2.00/MBtu in 1977 vs about $0.55/MBtu in 1973) NH3 producers planning new plants
may return to the interstate gas market if the ban on new customers is removed.
The other options which NH3 producers are considering at the present time to
guarantee a supply of natural gas include: (1) diversifying into natural gas
production (or form a partnership with a gas producer) and build the NH3 plant
or (2) locating the NH3 plant where long-term gas supply contracts are available.
Any assessment of the availability of natural gas in the United States
during the period 1980-2000 in essence will be affected by legislative decisions
concerning future energy supplies and environmental factors and not necessarily
on technical or economic considerations. The potential sources of natural gas
are divided into two categories: (1) conventional sources and (2) supplemental
sources. Conventional sources of natural gas refer to domestic production in
the contiguous 48 states from both onshore and offshore drilling. The supplemental
sources include all other potential sources of natural gas including gas from
Alaska.
CONVENTIONAL NATURAL GAS SUPPLIES
The assessment of future availability of conventional natural gas depends,
of course, on the actual reservoirs of gas available to be tapped. Since the
total domestic reserves are unknown, various methods have been developed to
estimate these total gas reserves.
Hydrocarbon reserves, whether natural gas or crude oil, are usually split
into several categories depending on the information available on the potential
production field. "Proven" reserves are those in which enough wells and/or
exploration has been carried out that producing this much gas is only a matter
of pumping the gas to the surface. "Probable" reserves, on the other hand,
incorporate reserves of gas which appear likely by drilling in the fringe
areas of existing fields although enough drilling has not been completed to
include these under the proven category. "Possible" reserves are based on
information about potentially lucrative geological formations which have been
identified and which in the past have provided substantial amounts of natural
gas. "Speculative" reserves are more or less simple guesses based on essentially
no information. Thus from a planning standpoint, proven reserves are the most
important with progressively less confidence in the reserves classed as probable,
possible, and speculative.
The total amount of natural gas in each of these categories has been estimated
by various authors as shown in Table 50. As would be expected, the range of
estimated natural gas reserves varies only slightly for proven reserves but quite
substantially for possible and speculative reserves. These estimated proven
reserves of about 216 Tft^ are also a reason for concern since current annual
production if running at 19-20 Tft^ and at this rate these proven reserves
would only last about 11 yr at current rates of consumption. Of course, this
projection fails to take into consideration the other types of reserves which
will undoubtedly provide additional proven reserves and provide additional
years of natural gas but the exact amounts are now largely unknown.
86
-------
TABLE 50. ESTIMATES OF U.S. NATURAL GAS RESERVES (5, 20. 31, 37, 40)
Natural gas reserves, Tft^, as estimated by;
Potential gas
Type of reserve FEA Exxon USGS CIA committee
Proven 237 237 - 218 216
Probable 202 111 - - 215
Possible 522 287 484 - 363
Speculative - 295 - - 345-395
Total 961 930 - - 1,139-1,189
Further aggravating this concern about natural gas is the steady decline
in proven reserves as shown in Figure 20 for the period 1968-1980. The amount
of natural gas being produced and sold annually from these proven reserves
is more than that being confirmed and added. Currently additional drilling
is being done primarily in relatively safe areas, such as already existing fields
where the success rate is high, and very little drilling is being done in
previously unexplored areas (containing the possible or speculative reserves,
most of the potential reserves listed in Table 50) where the risks for finding
and proving large new gas fields are greater. Thus, under the present conditions
the probability of substantially increasing proven reserves and thus allaying
fears of a looming natural gas crisis are highly unlikely.
SUPPLEMENTAL NATURAL GAS SUPPLIES
In addition to these conventional natural gas deposits, other potential
deposits of gas are domestically available but at substantially higher prices.
These sources would include: (1) synthetic natural gas (SNG) from coal or
oil, (2) imported natural gas from Alaska, Canada, and Mexico by pipeline or
liquefied natural gas (LNG) from Algeria and Indonesia, and (3) new technologies
such as gas from geopressurized brine solutions, natural gas from "tight" forma-
tions such as shales, and methane from coal mines. The major drawback associated
with these alternative sources are the costs involved. The price of the resulting
natural gas from these sources is expected to be greater than about $3.00/kft3
(vs recently increased rate for new interstate gas of $1.44).
SNG From Oil and Coal
SNG from either oil or coal faces one other common problem in addition to
the cost of the resulting gas. From the standpoint of making NH3, it makes
little sense to partially oxidize either feedstock to H2 and CO, shift the gas
mixture to methane, transport the gas through a pipeline system, and then steam
reform the methane back into H2 and CO. If either oil or coal is to be used to
manufacture NH3, from an overall economic and also technical point of view the
87
-------
300
co
275
Legend
Actual
Projected
8
w
C/l
U
06
250
CO
co
w
1
225-
200
1968
1970
1972
197A
1976
1978
1980
YEAR
Figure 20. Proven U.S. natural gas reserves during the period 1968-1980 (51),
-------
hydrocarbon feedstock should be gasified as the initial stage of the NH3 unit
and all of the resulting gas used directly (see earlier sections on partial
oxidation of oil and coal) to make NH3.
Another major problem associated with the use of petroleum fractions for
making SNG is its desirability as a feedstock for other petrochemicals. The
typical petroleum fraction used in generating SNG, natural gas liquids and
naphtha, have many other more profitable uses. Natural gas liquids are a
major feedstock for various plastic materials, as well as gasoline, while naphtha
is used both in the blending gasoline and as a feedstock for various reforming
operations. With the particular cut of naphtha used to make SNG already in
short supply, the diversion of large amounts of this naphtha to produce SNG
will only result in increasing both the importation and the cost of refined
petroleum products, such as naphtha. It has been suggested that only those
oil-based SNG plants already proposed would require additional oil imports
of 646,000 barrels (bbl) per day (22). Although the actual cost for SNG
from naphtha has not been published, the resulting gas would be expected to
cost in the range of $2.50-4.00/kft3.
The capital investment (1976 dollars) for a nominal 250 Mft3/day SNG-
from-coal plant ranges from $870 M to $1.5 G (depending on the process involved).
When compared with the current total U.S. consumption of 20 Tft3. the output
of one of these coal-to-gas plants represents only about 0.4% of this total
annual demand for natural gas. In addition, none of these gasification systems
have been constructed or tested on a commercial scale in the United States as
yet. Large-scale production of pipeline quality gas from coal will not become
an important energy source until the 1990's, although one or two plants are
expected onstream by the late 1980's.
The projected gas prices from commercial coal-to-gas plants depend on
the process selected, the coal to be gasified, the accounting procedures
used, and the source being cited. These prices for SNG from coal have recently
been estimated (29) to range from $2.70 to $6.72/kft3. Again it should be
pointed out that these costs are based on small pilot-plant operations (<2.4
Mft3/day) and are subject to considerable revision as more development work
is completed.
Importation of Natural Gas From Canada
After an initial period of net U.S. exports to Canada in the early 1950's,
the United States increased its imports of natural gas from 1958 until reaching
a peak of 1.0 Tft3 in 1973 and then slowly declined to 0.95 Tft3 in 1976 (see
Figure 21). These imports were brought about by the discovery of large natural
gas reserves in Western Canada and the lack of pipelines to transport this
gas to consumers in Eastern Canada. As a result, excess Western Canadian gas
was sent across the border to consumers in the upper Midwest while American
gas from Texas and Louisiana was pumped to Eastern Canada through transcontinental
pipelines. However, after the oil crisis of 1973, the amount of gas exported
to the United States was decreased. The price for Canadian gas delivered to
the border has increased during the past 4 yr, from $0.40/kft3 in 1973 to
about $1.20/kft3 in 1977 and these increases are expected to continue until
89
-------
VO
o
1.2
1.0
CO
4J
H 0.75
*
CO
i
s
3 0.5
0.25
L955
1960
1965
YEAR
1970
1975
Figure 21. Natural gas Imports from Canada during the period 1955-1976 (34)
-------
the cost of exported gas is equivalent to that of imported oil. The price
of this gas has recently been projected to rise to about $2.70/kft3 by 1980
(46).
Importation of Natural Gas From Mexico (6, 15, 16, 18)
Although imports by pipeline from Canada are expected to decline in the
near future due to increased demand within Canada and the possible construction
of a trans-Canadian pipeline to transport the gas to eastern provinces,
the prospects of importing natural gas from Mexico have brightened considerably
since the early 1970's. During the late 1950's and continuing through the
1960's Mexico exported relatively small amounts (0.05 Tft3) of natural gas
to the United States (see Figure 22), but in the 1970's this gas was needed
within Northern Mexico and the exports were stopped. However, many of the
wells in the recently discovered Reforma field in Southern Mexico are producing
six or seven times as much gas as orginally expected and the Mexican oil
company, PEMEX, is faced with a substantial surplus of natural gas which must
be either consumed or flared. PEMEX had orginally planned to construct seven
large NH3 plants with a total capacity of 3 Mtons/yr; even so, considerable
natural gas, which otherwise would be flared, will be available for export.
Due to other economic considerations which eliminate the potential use of this
gas within Mexico, exploratory talks have recently begun on the construction
of a 750-mi gas pipeline from the Reforma area of Mexico to the Texas border
at Reynosa and the export of 1-2 Gft3/day of gas to the United States beginning
in 1979 (35).
Even though this 2 Gft3/day appears to be a significant amount of gas,
it represents only about 3.5% of the current U.S. natural gas supply. On
the other hand, this 2 Gft3 of natural gas per day, if applied solely for NH3
production would generate about 63,500 tons/day or 20,950,000 tons/yr, i.e.,
more than the total U.S. NH3 consumption at the present time. The selling
price of this gas, although not published at the present time, is expected
to be equivalent to the projected price of heating oil in New York harbor
or about $2.50/kft3 delivered at the U.S.-Mexican border (6, 18).
Although this project is only tentative at the present time, the com-
bination of a huge surplus of natural gas in the Reforma area of Mexico
(estimated 1980 production, 10 Gft3/day), the need by PEMEX to generate
revenues to finance other petrochemical plants (projected natural gas treat-
ment capacity in 1980, 2.34 Gft3/day), and the shortage of natural gas in
the United States all seem to indicate that this pipeline will be completed
and in operation supplying an initial 1.0 Gft3/day of badly needed gas to the
United States. This could be possible by as early as 1979 or 1980 and reaching
full capacity of 2.0 Gft3/day by 1981.
Even with this much gas being withdrawn and pumped to the United States,
sufficient gas would still be available for constructing conventional NH3
plants within Mexico. PEMEX has already contracted for four of these large
NH3 plants consuming about 0.189 Gft3/day and producing 6000 tons/day (about
2 Mtons/yr) of NH3 and plans are underway for at least three more large NH3
plants. These four contracted plants will almost double the current Mexican
NH3 capacity to 13,000 tons/day. Additional NH3 plants, financed by American
companies, could be built and the resulting NH3 shipped to Gulf ports by
barging across the Gulf of Mexico.
91
-------
\o
0.10
0.075
en
*j
IM
H
en
I
0.050
0.025
1955
1960
J_
1965
YEAR
J_
1970
1975
Figure 22. Natural gas Imports from Mexico during the period 1955-1976 (34)
-------
Alaskan Natural Gas (3, 17, 21)
With the discovery of large oil and associated natural gas deposits on
the Alaskan North Slope and the recent completion of the trans-Alaskan oil
pipeline, various proposals have been advanced to bring this gas to the
contiguous 48 states rather than either reinjecting or flaring the gas.
Although this is not the first major natural gas discovery in Alaska (reserves
of about 5 Tft3 were discovered earlier at Kenai), it is by far the largest
with probably reserves of about 26 Tft3.
At the present time, the favored proposal for bringing this North Slope
gas south is the so-called Alcan route, a 2754-mi pipeline from Prudhoe Bay
south along the trans-Alaskan oil pipeline to near Fairbanks and then south-
east along the Alaskan highway to the U.S.-Canadian border. Portions of this
system would consist partly of existing pipelines with about 1800 mi of new
pipe needed. The initial capacity of the pipeline would be 2.6 Gft3/day (about
1.0 Tft3 annually) and cost between $6.7-10.0 G (3, 25). Assuming a well-head
price of $1.00/kft3, the estimated cost of the gas at the U.S.-Canadian border
would range, depending on the source, from $1.79-3.50/kft3 (3, 17, 21). With
construction scheduled to begin in 1979, the first gas probably would not be
available before 1982 and potential delays in initiating construction of up
to 2 yr are already being mentioned.
Importation of Liquefied Natural Gas (10)
Although proposals for transocean shipping of natural gas have been
discussed for the past decade, the importation of LNG is only slightly closer
to commercial realization in the United States today than it was 10 yr ago.
In gas-starved nations such as Japan, the large-scale importation of LNG is
a commercial reality but in the United States, which has substantial natural
gas reserves, the economics did not and still do not justify the large-scale
use of LNG. Its primary use in the United States at the present time is
limited to a role as a peak-shaving energy source during periods of high
demand. However, by 1985 LNG imports are expected to contribute substantial
amounts of natural gas to supplement declining domestic gas production.
There are only a few countries in the world (shown in Table 51) with large
natural gas reserves and low domestic consumption to guarantee a good, long-
term (20-25 yr) supply of natural gas. Since the most commonly discussed
standard LNG plant has a 1 Gft3/day capacity, minimum proven reserves of about
10 Tft3 are needed to support the construction of a natural gas liquefication
plant. Of the countries listed in Table 51 as potential exporters of LNG, only
Malaysia and Australia with relatively small domestic reserves actually have
a large potential as a noncontracted source of LNG for the United States
during the 1980's, as shown in Table 52. Russia with perhaps the largest
reserves has contracted to sell some of its excess gas to Eastern and Western
Europe (5.1 Gft3/day) and will probably sell additional gas to Japan in the
near future. Russian exports of LNG to the United States, although greatly
discussed do not appear promising at the present time. Iran with the second
largest reserves has decided that internally consuming the available gas is
in its national interest and hence little additional gas will be available for
93
-------
export until the mid-1980's. Algeria has already contracted its available
natural gas for LNG export and Saudi Arabia has only recently begun construction
of a gas-gathering system. Thus most of the potential gas available for LNG
already has been or will be contracted for in the near future. Additional
supplies of LNG may not be available
TABLE 51. NATURAL GAS RESERVES OF VARIOUS COUNTRIES (49)
Natural gas reserves,
Country
USSR
Iran
Algeria
Saudi Arabia
Nigeria
Abu Dhabib
Indonesia6
Australia
Iraq
Libya
Malaysia
Qatar
Proven
850
330
125
107
45
33
31
30
27
26
10
8
Potential
2,000
750
150
_a
90
-
-
-
-
-
-
a. Unknown.
b. Includes Bahrein, Dubai, Oman, and UAE.
c. Includes Arum, Kalimantan, Brunei, and Papua.
Eight base-load LNG plants (i.e., gathering, treating, liquefying, and
exporting) are now operating worldwide and eight more are in various stages
of construction. These plants and various applicable information about each
plant are listed in Table 53. Using the announced and probable contracts for
these plants, the expected world trade in LNG for various years is shown in
Table 54. From this table it is apparent that the United States and Japan are
the two largest potential buyers, importing 49% and 28% of the world supply
of LNG in 1985, respectively, while Algeria and Indonesia are expected to
export nearly two-thirds of the available LNG.
It must also be kept in mind that a typical LNG tanker carries the equiva-
lent of 2700 Mft3 of gas. If one round trip requires about 24 days, a single
ship could supply only about 0.041 Tft3 annually or about 0.2% of the current
annual U.S. natural gas demand. With the cost of a single LNG tanker currently
estimated at $120-140 M, another limiting factor in the worldwide LNG trade
could be the availability of LNG tankers. Thus, although LNG imports are
expected to provide a substantial amount of supplemental natural gas in the
future, LNG alone will not solve the present natural gas shortage.
94
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TABLE 52. LNG EXPORTING COUNTRIES IN 1985 (49)
Natural gas
production,
Country Tft^/yr
USSR
Iran
Algeria
Saudi Arabia
Nigeria
Abu Dhabi
Iraq
Qatar
Malaysia
Indonesia
Australia
19.0
5.6
2.5
1.6
0.3
1.0
0.4
0.5
0.4
0.7
1.3
Potential
gas surplus,
Tft3/yr
3.4*
1.1
2.1
0.0
0.29
0.5
0.07
0.3
0.36
0.65
0.36
Contracted gas
exports (country) ,
Tft3/yr
1.9 (Europe)
0.4 (Europe)
0.35 (USSR)
0.35 (USA and
Japan)
0 . 6 (Europe
1.5 (USA)
-
0.29 (USA)
0.5 (Japan)
-
-
-
0.5 (Japan)
0.15 (USA)
-
Noncontracted
gas available
for LNG, Tft3/yr
1.5
0.0
0.0
0.0
0.0
0.0
0,07
0.3
0.36
0.0
0.36
a. Includes imports of 0.4 TftVyr.
95
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TABLE 53. CURRENT AND PROPOSED LNG BASE-LOAD PLANTS (50)
Site
Current
Algeria
Arzew
Skikda
Indonesia
Brunei
Libya
Marsa El Berga
U.S.
Kenai, Alaska
Committed
Algeria
Arzew
Skikda
Indonesia
Kalimantan
Abu Dhabi
Das Island
Probable
Algeria
Arzew
Chile
Cabo Negro
Indonesia
Arun
Malaysia
Sarawak
Nigeria
Conney
U.S.
Cook Inlet
Yr of LNG plant Importing country
operation capacity, Mft-Vday (amount, Mft^/day)
1964
1972
1974
1970
1969
1977a
1975
19763
1977a
1976
1979»
1979b
19773
-c
_c
1978t>
200
450
750
385
173
1,100
170
350
1,200
350
1,000
290
1,220
-
800
400
France (50)
Spain (40)
Great Britain (100)
France (350)
U.S. (44)
Japan (741)
Italy (235)
Spain (110)
Japan (160)
U.S. (1,000)
U.S. (61.4)
U.S. (600)
Spain (436)
Japan (1,050)
Japan (450)
Belgium (340)
U.S. (1,345)
Brazil (220)
Japan (550)
Japan (750)
U.S. (800)
U.S. (400)
a. Under construction.
b. Planned.
c. Unknown.
96
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TABLE 54. CURRENT AND PROJECTED LNG IMPORTS
AND LNG EXPORTS BY COUNTRY (55)
LNG trade, Mft3/day
1977 1980 1983 1985
Importing country
U.S. 42 1,816 4,570 6,200
W. Europe 986 1,625 2,950 2,950
Japan 1.180 1,605 3,480 3.480
Total 2,208 5,046 11,000 12,630
Exporting country
Algeria 693 2,976 5,845 6,675
Libya 335 335 335 335
Nigeria - - 800
Iran - - 800 800
Alaska 135 265 535 535
Indonesia 750 1,175 2,340 2,340
Abu Dhabi 295 295 295 295
Malaysia - - 850 850
Total 2,208 5.046 11,000 12,630
97
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The expected price of this imported LNG has also increased substantially
in the past decade. Although originally sold at near production cost, with
the Arab oil embargo and the quadrupling of oil prices, the selling price of
LNG in the exporting countries has also substantially increased to reflect
the higher demand for premium fuel. The projected selling price of imported
LNG in the United States is currently estimated to range from $3.00-3.50/kft3,
which is essentially double the current price of conventional domestic natural
gas. Future prices for delivered LNG are expected to be equivalent (on a
$/MBtu basis) to that of imported crude oil, which has been estimated at about
$3.67 in 1980 and $4.67/MBtu in 1985 (10). In fact a recent cost for Algerian
gas to be delivered to the United States in 1984 was estimated to be about
$4.57/kft3 (10).
New Technologies (12, 41)
Other potential future sources of natural gas include various new tech-
nologies such as methane from coal mines, gas from tight shales and methane
from geopressurized brine solutions. Of these new technologies that is closest
to commercial realization is the recovery of methane associated with coal seams.
One of the major problems associated with mining coal is the potentially
explosive nature of methane in coal mines. The flammability limits of methane
range from approximately 5 to 15% by volume in air and in the past numerous
mine accidents were caused by methane explosions. By operating the mine with
enough ventilation such that the methane concentration in the mine remains
below the 5% explosive limit, coal mining has become a much safer occupation.
This resulting methane-in-air mixture is swept from the mine and exhausted to
the atmosphere.
This large-scale waste of a valuable energy source, although necessary in
the past with the low cost and ready availability of natural gas, is now
undergoing increased attention. For example, the FFC has recently proposed
exempting this methane from Federal regulation and thus give mines an economic
incentive to sell this gas at whatever price the consumers are willing to pay.
Although minor amounts are already being sold to interstate pipelines, it has
been estimated that about 250 Mft-Vday of methane is either being vented or
flared from currently operating U.S. coal mines.
This methane was apparently formed as the organic material, orginally
laid down within the seam, gradually decomposed under heat and pressure to
form coal. The amount of methane remaining in the seam depends on the per-
meability of the underlying and overlying rock strata and also the amount of
fracturing in the coal. Some particular seams contain large amounts of methane
while others contain very little.
ERDA has estimated that up to 749 Tft3 of methane may be trapped in various
coal seams and about 30% of this gas could be recovered. Although no method
for removing this methane has been tested on a commercial scale as yet, it has
been suggested that by drilling through a coal seam and then fracturing the coal
by explosives could release the methane and allow its removal from the mine.
No costs have been estimated for this gas and additional development work is
needed before the large-scale application of this technology will be available.
98
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Estimates of the natural gas reserves held in eastern tight shales
range up to 1200 Tft3, a potential 60-yr supply at current rates of con-
sumption. Although this natural gas deposit stretching from New York and
Michigan south to Alabama has been extensively tapped during the past 50 yr,
numerous problems have prevented its widespread use as a source of natural
gas. The largest drawback associated with these deposits is that the shale
in which the gas is trapped is relatively impermeable. Unless the well happens
to hit a natural fracture, gas production is very slow and may not economically
justify a gas-collection system.
Potential recovery techniques must include some method of causing large
fractures in the tight shale formations and at the present time this is the
limiting technical factor in removing the gas. Various options such as the
injection of water under pressure, conventional explosives, and even nuclear
explosions have been used in the past with limited success. However, as long
as the price of natural gas remains low, natural gas production from these
shale formations will not provide significant amounts of gas.
The other potential source of gas listed under new technologies is the
recovery of natural gas from geopressurized brine solutions. These hot brine
solutions containing up to 60 ft-* of dissolved methane per barrel of brine
are located at depths of 10,000 to 20,000 ft over an area estimated at 80,000
to 160,000 sq mi along the Texas and Louisiana coast. A recent estimate by
the USGS has put the total recoverable reserves of methane at 490
Numerous methods of recovering both the methane and the inherent energy
of the hot, pressurized brine solutions have been suggested but the most
promising appears to be a stepwise reduction of the pressure, releasing the
methane and turning a power recovery turbine. A plant based on this method
and treating 50,000 bbl/day of brine would produce about 8 MW of electricity
in addition to 3 Mft^ of methane per day (assuming 60 ft^/bbl). However,
substantial development work remains to be done both in confirming various
optimistic assumptions and obtaining more data on these geopressurized zones.
Some of these major problem areas include: (1) permeability of the zones and
hence productivity of the region, (2) physical properties of the brines
(primarily methane content), and (3) feasibility of spent brine reinjection.
Other Sources of Natural Gas
Although technically not an additional source of natural gas, several
recent developments have suggested ways by which additional supplies of natural
gas may be freed for other uses in the future. The first involves two potential
innovations in the NH3 plant which would reduce the amount of natural gas
consumed per ton of product while the second pertains to the redirection of
scarce natural gas away from simple burning of gas as a boiler fuel.
Of the two process modifications to the conventional NH3 plant currently
undergoing research and development, the first and potentially most important
modification is the recent work done on replacing natural gas as the fuel used
to indirectly heat the primary reformer, with vaporized fuel oil. About one-
third of the natural gas consumed in producing NH3 (12,600 ft3/ton) is effectively
99
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wasted in heating the primary reformer. By substituting another fuel, such
as vaporized fuel oil, in all natural gas-based NH3 plants in the future,
the natural gas required for producing NH3 could be reduced by about 40%. The
second modification (24) involves adding a cryogenic separation step to the
purge gas stream from the synthesis loop. Since nearly 65% of this purge gas
is H2, using a cryogenic separator to recover 90% of this I?2 and recycling it
to the synthesis loop has been estimated to yield an additional 5% NH3 for the
same input of natural gas (savings—approximately 1500 ft-Vton of NHj).
In addition to these potential natural gas savings within the NH3 industry,
the realization of the value of natural gas has led others to project that
natural gas will be redirected toward those uses where natural gas must be used
exclusively. For example, FEA has recently begun to prohibit the use of natural
gas as a primary energy source for both utility and industrial users. Since
the consumption of natural gas in utility boilers alone is currently estimated
(44) at about 3.5 Tft3 annually (about 17.5% of the current supply), most of
this gas will gradually become available for other uses as more of the older
plants are retired and no new gas-fired power plants are built. In fact, it
was recently estimated (25, 50) that natural gas consumption in utility boilers
would decline to 1.5 Tft3 by 1985 and to less than 1.0 Tft3 in 2000. Although
no estimate of gas savings from the phaseout of gas use in industrial boilers
is available, from the utility boiler savings alone it is apparent that significant
amounts of gas can be freed for other uses, especially the production of NH3.
This is not meant to imply that this additional gas will be used exclusively
or even partially to produce NH3, only that the available gas may be directed
to higher priority uses.
100
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CONCLUSIONS
Various processes for removing NOx from boiler flue gas are now under-
going development and one of the more promising and the furthest developed
method is the SCR- type system. SCR processes involve the injection of NH3
into the flue gas ducts and passing the resulting gas mixture over a base-
metal catalyst. The NOx and the NH3 react to form N2 and H20 which are then
exhausted. The entire system is relatively simple with only one major piece
of equipment, the catalytic reduction reactor, and no major byproduct streams
requiring further treatment.
The most critical question associated with wide-scale commercial application
of this NOx control technology has been, "What will the impact on NH3 production
and marketing be?" The NH3 is only injected at a rate such that the mol ratio
of NH3:NOx is about 1:1 and the NOx concentration is very low (i.e., about 600
ppm for coal-fired flue gas). However, the increasing emphasis both on using
coal as a boiler fuel and on using increased amounts of electrical energy has
led others to project the possibility of severe economic disruptions in the NH3
market in the future if NOx FGT is required for all large boilers.
ONSITE GENERATION VERSUS ONSITE STORAGE OF NH3 FOR NO^ FGT SYSTEMS
The annual NH3 consumption for an NOx FGT system for typical 500-MW coal-
and oil-fired boilers range from 6266 tons/yr for the 500-MW coal-fired boiler
without combustion modifications to 772 tons/yr for a 500-MW oil-fired boiler
with combustion modifications. For a plant to produce NH3 at a competitive
price it must have a minimum capacity of approximately 1000 tons/day (330,000
tons/yr) and clearly even a 2000-MW coal-fired power plant, which is a large
unit by present standards, could not economically justify a captive NH3 plant.
Instead the NH3 would be purchased from an independent producer, shipped to the
power plant, and stored onsite until needed.
IMPACT OF NH3 DEMAND FOR NOx FGT ON THE DOMESTIC NH3 MARKET
As a basic premise for calculating the annual NH3 consumption for NOx FGT,
it was assumed that only new fossil fuel-fired boilers coming online after
January 1, 1985, would be required to install 90% efficient NOx contr°l systems.
The capacity of new utility boilers coming online each year and the fuel mix
in these new boilers during the period 1985-2000 was then estimated by using
the recent projection of the National Electric Reliability Council as the base
case for both the fuel mix and the total domestic generating capacity in 1985.
It was further assumed that the total U.S. generating capacity would double
during the period 1985-2000 from 798 GW to about 1660 GW. Assuming that no
new gas-fired and very few oil-fired utility boilers will be brought online
101
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after 1985 and that the current problems with bringing nuclear units online
will continue, coal would be the fuel for 50% (829 GW) of all the utility
boilers generating electricity in 2000.
The annual coal-fired electrical capacity additions needed to meet this
projected coal-fired generating capacity in 2000 steadily increased from the 15
GW added in 1985 to 55 GW in 2000. The resulting annual NH3 requirement for
NOx FGT, assuming the average 500-MW coal-fired boiler emits 600 ppm NOx (3000
Ib of NOx/hr) in the flue gas, ranges from 0.09 Mtons in 1985 to 6.7 Mtons in
the year 2000 for a 90% efficient SCR system and from 0.04 Mtons in 1985 to
2.9 Mtons in the year 2000 for the case of combustion modification followed
by an 80% efficient SCR system. For case 1 (90% efficient SCR system) this
annual NH3 requirement NOx FGT ranges from 0.44% of the total projected domestic
NH3 demand in 1985 to 20.1% in the year 2000. For case 2 (combustion modification
followed by an 80% efficient SCR system) these percentages are 0.19% and 8.7%
respectively. The requirement for 90% NOx removal from utility boiler stack
gas using only SCR will require the addition of about one new 1000 ton/day NHo
plant each year while using combustion modifications with an 80% efficient
SCR system will dictate about one new 1000 ton/day NH3 plant every 2 yr. Thus
the requirement for 90% NOx removal as outlined in the premises of this study
will probably not have a severe impact on the NH3 market. Instead of the projected
3% annual increase in NH3 demand during the period 1978-2000, the additional
consumption of NH3 for NOx FGT will result in an annual 4.5% increase in NH3
demand during the years 1985-2000.
In addition to large utility boilers, large industrial boilers contribute
a significant fraction of the total amount of NOx released in the United States
and hence may become subject to the same requirement for 90% NOx removal from
all new sources previously postulated for large utility boilers. Although the
total capacity of all large U.S. industrial boilers has not been published,
this industrial boiler capacity was estimated as about 25% of the utility boiler
capacity. Using the same emission assumptions as was used for the utility
boilers, the annual NH3 consumption for NOx FGT controls on all new large boilers
(both utility and industrial) would range from 0.12 Mtons in 1985 to 8.4 Mtons
in the year 2000. Although these NH3 usage rates are higher than those for
new large utility boilers only, the increase is not significant enough to cause
any further dramatic increase in demand for NH3.
If, on the other hand, the premises had stated that all large boilers,
i.e., old and new, would require 90% efficient NOx control the result would
have been substantially different. Under this assumption, the estimated NH3
demand for NOx control would range from 4.0 Mtons in 1985 (19% of projected
NH3 demand) to 10.4 Mtons in 2000 (31.4% of projected NH3 demand). Such an
increase in demand in 1985 would most likely result in a large increase in
the price of NH3.
The major impact of the increased NH3 consumption due to the adoption
of more stringent NOX controls may not necessarily be on the domestic NH3
market but rather the indirect effect on the availability and price of natural
gas. With the current national energy policy geared toward reducing our depen-
dence on natural gas and the current uncertainty concerning the future availability
of natural gas, even these small amounts (relative to current gas production)
may in the future be considered a significant impact.
102
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CURRENT NH3 PRODUCTION ECONOMICS
Although numerous potential H£ feedstocks are available for the production
of NH3, approximately 95% of the NH3 produced domestically is made from natural
gas. The remaining 5% of current production comes from various miscellaneous
sources such as off-gases from electrolytic cells and coke-oven gas. However,
these other sources are usually unique systems in which various factors have
come together to provide an economic incentive for NH3 generation. The potential
of these sources for producing a larger share of the domestic NH3 supply is not
promising.
At the present time, the widespread curtailment of natural gas during the
peak heating season and the steady decline in both proven reserves and production
of conventional natural gas have led to concerns that enough natural gas will
not be available to meet this additional demand. Conventional natural gas
supplies and reserves are declining at the present time but supplemental supplies
of natural gas, such as LNG, SNG (from oil and coal), Alaskan gas, and imports
from Canada and Mexico, are increasing. The cost of this natural gas, however,
is expected to be sharply higher than current prices ($1.45-2.00/MBtu) which
are themselves significantly higher than prices of only 2-3 yr ago.
These higher natural gas prices and questions about the future availability
of natural gas have revived interest in the use of alternative feedstocks for
the production of NH3. Any hydrocarbon is a potential H2 feedstock and since
oil and coal are widely availabe these are the two most commonly mentioned
alternative feedstocks. Various processes for converting either oil or coal
into H2 to be used for NH3 synthesis are technically feasible and are commer-
cially available on the world market. The major stumbling block for domestic
acceptability is the process economics.
Each of these alternative feedstocks requires a higher initial capital
investment and thus at the same fuel cost, the unit cost of producing NH3
would be higher for both naphtha and coal than for natural gas. Thus for
either naphtha or coal to compete economically with natural gas, this dis-
advantage must be offset by a significant feedstock cost differential.
At the present time and under the premises of this study, the feedstock
cost differential is not large enough for alternate feedstocks to economically
compete with natural gas since, even at a natural gas price of $2.00/MBtu,
NH3 can be produced for about $143/Mton while current naphtha and coal costs
yield NH3 production costs of $193 and $186/Mton respectively. However,
with the cost of natural gas expected to increase in the near future, this
feedstock cost differential between natural gas and alternate feedstocks may
increase sufficiently to justify the production of NH3 from these other feed-
stocks.
103
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TECHNICAL REPORT DATA
(Pleat read Instructions on the reverse before completing)
1. REPORT NO. 2.
EPA-600/7-79-011
4. TITLE AND SUBTITLE
Impact of Ammonia Utilization by NOx Flue Gas
Treatment Processes
7. AUTHOR (S)
T.A. Burnett and H. L. Faucett
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Tennessee Valley Authority
National Fertilizer Development Center
Muscle Shoals , Alabama 35660
12. SPONSORING A6ENCV NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
3. PERFORMING ORGANIZATION REPORT NO.
Y-134
10. PROGRAM ELEMENT NO.
1NE624
11. CONTRACT/GRANT NO.
JAG-D8-E721-FU
13. TYPE OF REPORT AND PERIOD COVERED '
Final: 8/77 - 11/78
14. SPONSORING AGENCY CODE
EPA/600/13
16. SUPPLEMENTARY NOTES jERL-RTP project officer is J. David Mobley, Mail Drop 61.
541-2915.
919/
s. ABSTRACT
report gives results of a study of the impact of ammonia (NH3) utiliza-
tion by NOx flue gas treatment (FGT) processes. The most technologically advanced
FGT system for the highly efficient (about 90%) removal of NOx from power plant
stack gas is selective catalytic reduction (SCR) using NH3. A major economic consi-
deration in the widespread application of SCR is the impact of this demand on the
domestic NH3 market. Annual NH3 requirements for NOx FGT control of new,
fossil-fuel-fired boilers were calculated and predicted for the period 1978-2000. The
total NH3 supply was also projected for the same period and compared with the pro-
jected annual demand for NOx FGT. The study concludes that NH3 demand for NOx
FGT systems will begin gradually and rise at relatively slow rates, giving the do-
mestic NH3 market adequate time to adjust to the increased demand. Under other
than study assumptions (e.g., requiring retrofit of NOx FGT systems on all large
boilers), significant impacts and market disruptions are foreseen. The current and
projected NH3 production techniques were outlined and the 1978 unit production cost
For NH3 was estimated for four potential feedstocks.
17. KEY WORDS AND DOCUMENT ANALYSIS
». DESCRIPTORS
Pollution Fossil Fuels
Flue Gases Combustion
Gas Purification
Ammonia
Nitrogen Oxides
Catalysis
18. DISTRIBUTION STATEMENT
Unlimited
b.lDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Flue Gas Treatment
Selective Catalytic Re-
duction
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (Thltptge)
Unclassified
c. COSATI Field/Group
13B 21D
21B
13H,07A
07B
07D
21. NO. OF PAGES
132
22. PRICE
CPA Form 2220-1 (9-72)
108
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