Technical Support Document for the Ammonia
Production Sector: Proposed Rule for Mandatory
Reporting of Greenhouse Gases
Office of Air and Radiation
U.S. Environmental Protection Agency
January 22, 2009
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
CONTENTS
1. Industry Description 1
2. Total Emissions 2
2.1 Process Emissions 3
2.2 Stationary Combustion 3
3. Review of Existing Programs and Methodologies 4
3.1 2006 IPCC Guidelines 4
3.2 2008 U. S. Inventory of Greenhouse Gas Emissions and Sinks 5
3.3 WRI/WBCSD Protocol.
3.4 The Climate Registry 6
3.5 Technical Guidelines Voluntary Reporting of Greenhouse Gases (1605(b))
Program 7
4. Options for Reporting Threshold 8
4.1 Options Considered 8
4.1.1 Emissions Thresholds 8
4.1.2 Capacity Thresholds 12
4.1.3 No Emissions Threshold 12
4.2 Analysis of Emissions and Facilities Covered Per Option 13
4.2.1 Emissions Thresholds 13
4.2.2 Capacity Threshold 13
4.2.3 No Emissions Threshold 13
5. Options for Monitoring Methods 13
5.1 Option 1: Simplified Emissions Calculation 13
5.2 Option 2: Mass Balance 13
5.3 Option 3: Facility Specific Calculation 13
5.4 Option 4: Direct Measurement 15
6. Procedures for Estimating Missing Data 16
6.1 Procedures for Option 1: Simplified Emission Calculation 16
6.2 Procedures for Option 2: Mass Balance 16
6.3 Procedures for Option 3: Facility Specific Calculation 16
6.4 Procedures for Option 4: Direct Measurement 16
6.4.1 Continuous Emission Monitoring Data (CEMS) 16
6.4.2 Stack Testing Data 17
7. QA/QC Requirements 17
7.1 Stationary Emissions 17
7.2 Process Emissions 17
7.2.1 Continuous Emission Monitoring System (CEMS) 17
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
7.2.2 Stack Test Data 17
7.2.3 Equipment Maintenance 18
7.3 Data Management 19
8. Types of Emission Information to be Reported 19
8.1 Other Information to be Reported 19
8.1.1 Option 1: Simplified Emissions Calculation 20
8.1.2 Option 2: Mass Balance 20
8.1.3 Option 3: Facility Specific Calculation 20
8.1.4 Option 4: Direct Measurement 20
8.2 Additional Data to be Retained Onsite 21
9. References 21
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
1. Industry Description
Ammonia is a major industrial chemical that is mainly used as fertilizer, directly applied as
anhydrous ammonia, or further processed into urea, ammonium nitrates, ammonium phosphates,
and other nitrogen compounds. Ammonia also is used to produce plastics, synthetic fibers and
resins, and explosives. There has been a decrease in ammonia manufacture in recent years due to
several factors, including market fluctuations and increasing natural gas prices. Ammonia
manufacture relies on natural gas as both a feedstock and a fuel, and as such, domestic
manufacturers are competing with imports from countries with lower natural gas prices. If
natural gas prices remain high, domestically manufactured ammonia will likely continue to
decrease with increasing ammonia imports (EEA 2004).
Total estimated U.S. production of ammonia was approximately 8 million metric tons in 2006,
ranging from around 22,000 metric tons to nearly 1.5 million metric tons across 24 operational
facilities (USGS Mineral Yearbook 2006). Facility-level ammonia and urea production capacity
data are presented in Table 1.
Emissions of CC>2 occur during the production of synthetic ammonia, primarily through the use
of natural gas as a feedstock. One nitrogen production plant located in Kansas produces
ammonia from petroleum coke feedstock, but the other ammonia manufacturing plants produce
ammonia from natural gas. In a few plants a portion of the CC>2 produced is captured and used to
produce urea or methanol. The brine electrolysis process for production of ammonia does not
lead to process-based CC>2 emissions.
Table 1. U.S. Producers of Ammonia and Urea (metric tons per year)
Company
Agrium Inc.
Agrium Inc.
Agrium Inc.
CF Industries Inc.
Coffeyville Resources LLC
Dyno Nobel ASA
Dyno Nobel ASA
El Dorado Chemical Co.
Green Valley Chemical Corp.
Honeywell International Inc.
Koch Nitrogen Co.
Koch Nitrogen Co.
Koch Nitrogen Co.
Koch Nitrogen Co.
Koch Nitrogen Co.
Plant Location
Borger, TX
Finley, WAC
Kenai, AK
Donaldsonville, LA
Coffeyville, KS
Cheyenne, WY
St. Helens, OR
Cherokee, AL
Creston, IA
Hopewell, VA
Beatrice, NE
Dodge City, KS
Enid, OK
Fort Dodge, IA
Sterlington, LA
Year End Ammonia
Capacity (metric
tons) a'b
490,000
180,000
280,000
2,040,000
375,000
174,000
101,000
175,000
32,000
530,000
265,000
280,000
930,000
350,000
1,110,000
Year End
Urea Capacity (metric tons)
89,727
0
215,444
2,020,095
172,306
92,079
103,182
197,418
0
0
61,748
73,984
346,527
160,402
0
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
Company
Mosaic Co., The
Nitromite Fertilizer (Valero
Energy Corp.)
PCS Nitrogen Inc.
PCS Nitrogen Inc.
PCS Nitrogen Inc.
Rentech Energy Midwest Corp.8
Shoreline Chemical
Terra Industries Inc.
Terra Industries Inc.
Terra Industries Inc.
Terra Industries Inc.
Terra Industries Inc.
Total
Plant Location
Faustina (Donaldsonville),
LA
Dumas, TXd
Augusta, GA
Geismar, LAC
Lima, OH
East Dubuque, IL
Gordon, GA
Beaumont, TXC
Port Neal, IA
Verdigris, OK
Woodward, OK
Yazoo City, MS
Year End Ammonia
Capacity (metric
tons) a'b
508,000
128,000
688,000
483,000
542,000
278,000
31,000
231,000
336,000
953,000
399,000
454,000
12,700,000
Year End
Urea Capacity (metric tons)
0
0
454,521
337,688
370,826
120,329
0
0
226,942
495,614
94,008
158,284
5,791,125
Note: Estimated operating capacity based on 7-day-per-week full production.
a Data are rounded to no more than three significant digits; may not add to totals shown.
b Engineering design capacity adjusted for 340 days per year of effective production capability.
c These facilities no longer manufacture ammonia but rather use imported ammonia to produce upgrade products
such as nitric acid and urea ammonium nitrate (UAN).
d Closed in 2006.
8 Purchased from Royster-Clark Inc. in 2006.
f It was assumed that those facilities that had urea capacity in 2004 continued to have urea capacity in 2006 and that
those facilities that did not have urea capacity in 2004 continued not to have urea capacity in 2006.
Source: Ammonia capacity: USGS Minerals Yearbook 2006
(http://minerals.usgs.gov/minerals/pubs/commoditv/nitrogen/mvb1-2006-nitro.xls). Urea capacity: IFDC 2005.
North America Fertilizer Capacity. Market Information Unit. Market Development Division. September 2005.
2006 urea capacity values were estimated by adjusting data from IFDC 2005 using the relative relationship of 2004
urea to ammonia capacities.
2.
Total Emissions
According to the U.S. Greenhouse Gas Inventory, total CC>2 process emissions from ammonia
production were 11.8 million metric tons of CC>2 equivalents (mtCC^e) (U.S. EPA 2008) in 2006.
These estimates were based on national-level production data. Emissions have decreased 28
percent since 1990, and 2006 emissions were 4 percent lower than the previous year (U.S. EPA
2008). Emissions of CC>2 from on-site combustion are not currently accounted for separately in
the U.S. Inventory. However, the processing of ammonia requires boilers and other equipment
that use natural gas and other fuels, and hence, results in emissions from combustion as well as
the ammonia manufacturing process.
According to facility specific production estimates, national emissions from ammonia
manufacturing were estimated to be 14.6 mtCC^e. These emissions include both process related
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
CC>2 emissions and on-site stationary combustion emissions (CO2, CH/t, and N2O) from 24
manufacturing facilities across the United States. Process-related emissions account for 7.6
million mtCO2e, or 52 percent of the total, while on-site stationary combustion emissions
account for the remaining 7.0 million mtCO2e emissions.
2.1 Process Emissions
Ammonia is produced using either natural gas or petroleum coke, although the industry
predominantly uses natural gas. There are five principal process steps in synthetic ammonia
production from natural gas feedstock. The primary reforming step converts CH4 to CC>2, carbon
monoxide (CO), and H2 in the presence of a catalyst. Only 30 to 40 percent of the CH4 feedstock
to the primary reformer is converted to CO and CO2. The secondary reforming step converts the
remaining CH4 feedstock to CO and CO2. The CO in the process gas from the secondary
reforming step (representing approximately 15 percent of the process gas) is converted to CO2 in
the presence of a catalyst, water, and air in the shift conversion step. CO2 is removed from the
process gas by the shift conversion process, and the hydrogen is combined with the nitrogen (TS^)
in the process gas stream during the ammonia synthesis step. The CO2 is included in a waste gas
stream with other process impurities and is absorbed by a scrubber solution. In regenerating the
scrubber solution, CO2 is released.
The conversion process for conventional steam reforming of CH/t, including primary and
secondary reforming and the shift conversion process is approximately as follows:
(catalyst)
0.88 CH4 + 1.26 Air + 1.24 H2O > 0.88 CO2 + N2 + 3 H2
N2 + 3 H2 -» 2 NH3
To produce synthetic ammonia from petroleum coke, the petroleum coke is gasified and
converted to CO2 and H2. These gases are separated, and the H2 is used as a feedstock to the
ammonia production process, where it is reacted with N2 to form ammonia.
Not all of the CO2 generated in the production of ammonia is emitted directly to the atmosphere.
At some production plants, both ammonia and CO2 are used as raw materials in the production of
urea [CO(NH2)2], which is another type of nitrogenous fertilizer that contains carbon as well as
nitrogen. The carbon in the consumed urea is assumed to be released into the environment as
CO2 during use. Therefore, the CO2 generated by ammonia production that is subsequently
captured and used to produce other materials is not included in this source category.
2.2 Stationary Combustion
Combustion emissions from ammonia manufacturing plants result from the combustion of
natural gas and fuel oil. Combustion sources include primary reformers and boilers. The
feedstock (raw material) used in ammonia production is not necessarily the same as the fuel used
for energy (combustion) in ammonia production. For example, although one facility produces
ammonia from petroleum coke, this same facility combusts natural gas for its stationary sources.
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
In addition, although other fuels may be combusted for energy, MECS data for NAICS code
325311, "Nitrogenous Fertilizers" which includes ammonia manufacturing, indicates 98 percent
of the total fuel energy consumption (i.e., excluding purchased electricity) is natural gas.
3. Review of Existing Programs and Methodologies
Existing reporting programs and methodologies for ammonia manufacture include IPCC,
WRI/WBCSD Protocol, DOE 1605(b), and Climate Registry. They are described below.
3.1 2006 IPCC Guidelines
The 2006 IPCC Guidelines consider three different methods for calculating total emissions from
ammonia production, including process emissions from feedstock and stationary combustion
emissions from fuel combustion (IPCC 2006, Table 3.1). Note that the 2006 IPCC Guidelines
for ammonia production use the term "fuel" in referring to the combined "fuel" (i.e., energy)
natural gas and "feedstock" (i.e., raw material) natural gas, and provides a single Tier 1 emission
factor to estimate the total CO2 emissions from natural gas consumption in ammonia production.
In Table 2, "fuel" (stationary combustion) and "feedstock" (process) CO2 emissions from
ammonia production are estimated separately. The Tier 1 method uses a default emission factor
per unit of output multiplied by production activity data. The equation is as follows:
EC02 = AP x FR x CCF x COF x 44/12 - Rc02
Where:
Eco2 = emissions of CC>2 (kg)
AP = production of ammonia (metric tons)
FR = fuel requirement per unit of output (GJ/metric tons ammonia produced)
CCF = carbon content of the fuel (kg C/GJ)
COF = carbon oxidation factor of the fuel (fraction)
Rco2 = CO2 recovered for downstream use (kg)
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
The Tier 2 method estimates total fuel requirement for each fuel type by using the equation
below:
TFR; = £ (APij x FRij)
Where:
TFR; = total fuel requirement for fuel type i (GJ)
= ammonia production using fuel type i in process type j (metric tons)
= fuel requirement per unit of output for fuel type i in process type j
(GJ/metric tons ammonia produced)
Ammonia production, fuel type, and process type is obtained from producers and default factors
are used for fuel requirement per unit of output. Default carbon content of fuel and carbon
oxidation factor are used for Tier 2. Emissions are estimated using the equation below:
EC02 = 2 (TFR; x CCF x COF x 44/12) - Rco2
Where:
Eco2 = emissions of CO2 (kg)
TFR; = total fuel requirement for fuel type i (GJ)
CCF = carbon content of the fuel (kg C/GJ)
COF = carbon oxidation factor of the fuel (fraction)
Rco2 = CC>2 recovered for downstream use (kg)
For Tier 3 estimates, total fuel requirement must be obtained from producers.
3.2 2008 U.S. Inventory of Greenhouse Gas Emissions and Sinks
The U.S. Inventory estimates emissions for ammonia production according to the following
equation:
CO2 Emissions = APPC * CCPC + APNG * CC
NG
Where:
APpc =Ammonia production from petroleum coke (tons ammonia)
CCpc =Carbon content of petroleum coke (3.57 ton CCVton ammonia produced)
APNo =Ammonia production from natural gas (tons ammonia)
= Carbon content of natural gas (1.2 ton CCVton ammonia produced)
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
The U.S. Inventory also estimates emissions from urea consumed for industrial processes (does
not include urea applied to agricultural lands) and reports this estimate along with the ammonia
production estimate.
3.3 WRI/WBCSD Protocol
The World Resource Institute and World Business Council for Sustainable Development's
Greenhouse Gas Protocol follows IPCC's Tier 2 approach and IPCC's Tier 3 if sufficient data
are available.
3.4 The Climate Registry
This protocol has two different methodologies. The Tier Al method uses direct measurement,
either through CEMS or periodic direct measurements. The Tier A2 is a mass balance approach
using the same equation as used for Tier 1 of the 2006 IPCC Guidelines:
Emissions = [E (TFR x CCF x COF x 44/12) for each fuel type] - RECC02
Where:
TFR = total feedstock requirement for each fuel type, GJ (see calculation below)
CCF = carbon content factor for each fuel type, kg C/GJ
COF = carbon oxidation factor for each fuel type, fraction
RECco2 = CC>2 recovered for downstream use (e.g., urea production), kg
Note: CC>2 recovery includes CC>2 for urea production and carbon capture and storage
(CCS) only.
TFR = E (PRODamm x FR) for each fuel type and process type
Where:
PRODamm = ammonia production for each fuel type and process type, tons
FR = fuel requirement for each fuel type and process type, GJ/ton ammonia
production
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
3.5 Technical Guidelines Voluntary Reporting of Greenhouse Gases (1605(b)) Program
This protocol has three different methodologies. The "A" rated method is direct measurement of
emissions, either by using a continuous emission monitoring system (CEMS) or by periodic
direct measurements. The "B" rated method is based on calculation, using measurement of
feedstock and its carbon content. The mass balance approach is based on the carbon content and
consumption data for feedstock. Reporters can use default carbon content values from EIA 2003
if plant-specific data is not available. The "C" rated method is based on calculation, using
quantity of ammonia produced. If no plant-specific information is available, reporters can use a
default emission factor of 1.26 metric ton CCVmetric ton ammonia produced.
Table 2. CO2 Emissions Coefficients for U.S. Natural Gas as provided by DOE's Voluntary
Reporting of Greenhouse Gases Technical Guidelines for Ammonia
HHV Btu content per Standard Cubic
Foot
975-1,000
1,000-1,025
1,025-1,050
1,050-1,075
1,075-1,100
Emissions Coefficient
(metric tons carbon per billion Btu)
CO2
54.01
52,91
53.06
53.46
53.72
Carbon
14.73
14.43
14.47
14.58
14.65
Source: U.S. DOE 2007.
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
4. Options for Reporting Threshold
Several alternative emission and capacity threshold options for reporting facility-level GHG
emissions from the ammonia manufacturing sector were analyzed. This section describes the
reporting options considered and associated emissions and the coverage of ammonia
manufacturing facilities under each option.
4.1 Options Considered
4.1.1 Emissions Thresholds
For the reporting of process CC>2 emissions from ammonia production, threshold options
considered included emissions-based thresholds of 100,000 metric tons of CC^e (mtCC^e),
25,000 mtCO2e, 10,000 mtCC^e, and 1,000 mtCC^e for both combustion and process emissions.
The results of the threshold analysis incorporating these four threshold options are summarized
in Table 3.
Table 3. Threshold Analysis for Ammonia
Threshold
Level
(metric
tons
C02e)
100,000
25,000
10,000
1,000
Process
Emissions
(metric
tons
C02e/yr)
7,499,174
7,553,606
7,553,606
7,553,606
Combustion
Emissions
(metric tons
C02e /yr)
6,950,345
6,989,401
6,989,401
6,989,401
Total
National
Emissions
(metric
tons CO2e
)
14,543,007
14,543,007
14,543,007
14,543,007
Number
of
Facilities
24
24
24
24
Emissions Covered
metric
tons
CO2e/yr
14,449,519
14,543,007
14,543,007
14,543,007
Percent
99%
100%
100%
100%
Facilities Covered
Number
22
24
24
24
Percent
92%
100%
100%
100%
The IPCC Tier 1 method was used to determine process CC>2 emissions from the facilities
presented in Table 1, because production capacity was the only facility-level data available. A
default process emission factor of 1.2 metric tons CCVmetric tons ammonia produced was
obtained from the Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006 (U.S. EPA
2008) for those facilities that use natural gas as feedstock for the steam reforming process. An
emission factor of 3.57 was used for the one facility that manufactures ammonia from petroleum
coke. This emission factor was determined by dividing the total CC>2 produced by this plant
from petroleum coke consumption (assuming 90 percent of the petroleum coke consumed is
carbon) by the total ammonia produced at the plant for the years 2000, 2001, and 2002. It should
be noted that the CC>2 emission factor for ammonia production in the 2006 IPCC Guidelines
includes CC>2 emissions from both fuel natural gas and feedstock natural gas, while the CC>2
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
emission factor in the previous IPCC Guidelines, and the CC>2 emission factor used in the 1990-
2006 U.S. Inventory, account for only feedstock natural gas but not fuel natural gas.
Facility-level production was calculated by using facility-level capacity data as shown in Table 1
and multiplying by a capacity factor of 72 percent, which is the capacity utilization reported for
U.S. ammonia producers in 2006 (USGS 2007). Estimated facility-level production was then
multiplied by the default emission factor in order to determine estimated facility process
emissions. The facilities are presented in Table 3.
Table 3. Ammonia Facilities With Capacity and Production Data
Plant
Agrium Inc.
Agrium Inc.
Agrium Inc.
CF Industries Inc.
Coffeyville Resources LLC
Dyno Nobel ASA
Dyno Nobel ASA
El Dorado Chemical Co.
Green Valley Chemical Corp.
Honeywell International Inc.
Koch Nitrogen Co.
Koch Nitrogen Co.
Koch Nitrogen Co.
Koch Nitrogen Co.
Koch Nitrogen Co.
Mosaic Co., The
Nitromite Fertilizer (Valero Energy
Corp.)
PCS Nitrogen Inc.
Plant location
Borger, TX
Finley, WAb
Kenai, AK
Donaldsonville, LA
Coffeyville, KS
Cheyenne, WY
St. Helens, OR
Cherokee, AL
Creston, IA
Hopewell, VA
Beatrice, NE
Dodge City, KS
Enid, OK
Fort Dodge, IA
Sterlington, LA
Faustina (Donaldsonville), LA
Dumas, TXC
Augusta, GA
Capacity
(Metric tons)
490,000
180,000
280,000
2,040,000
375,000
174,000
101,000
175,000
32,000
530,000
265,000
280,000
930,000
350,000
1,110,000
508,000
128,000
688,000
Production
(Metric tons)
352,800
0
201,600
1,468,800
279,000
125,280
72,720
126,000
23,040
381,600
190,800
201,600
669,600
252,000
799,200
365,760
53,760
495,360
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
Plant
PCS Nitrogen Inc.
PCS Nitrogen Inc.
Rentech Energy Midwest Corp.d
Shoreline Chemical
Terra Industries
Terra Industries Inc.
Terra Industries Inc.
Terra Industries Inc.
Terra Industries Inc.
Total
Plant location
Geismar, LAb
Lima, OH
East Dubuque, IL
Gordon, GA
Beaumont, TX
Port Neal, IA
Verdigris, OK
Woodward, OK
Yazoo City, MS
Capacity
(Metric tons)
483,000
542,000
278,000
31,000
231,000
336,000
953,000
399,000
454,000
12,700,000
Production
(Metric tons)
0
390,240
200,160
22,320
0
241,920
686,160
287,280
326,880
8,213,880
a Emission estimates presented here differ from those published in the U.S. Greenhouse Gas Emissions and Sinks
1990-2006 (U.S. EPA 2008). Emission estimates presented here were calculated using a bottom up approach based
on facility level data whereas emission estimates found in the U.S. Greenhouse Gas Emissions and Sinks 1990-2006
are calculated using a top down approach based on national production data.
b These facilities no longer manufacture ammonia but rather use imported ammonia to produce upgrade products
such as nitric acid and UAN.
c Closed in 2006.
d Purchased from Royster-Clark Inc. in 2006.
Source: Ammonia capacity: USGS Minerals Yearbook 2006
(http://minerals.usgs.gov/minerals/pubs/commodity/nitrogen/mybl-2006-nitro.xlsX Production was estimated using
a factor of 72% from USGS 2007. The USGS Mineral Yearbook for 2006 states that ammonia producers in the US
operated at about 72% of design capacity in 2006. This value includes capacities at plants that operated during any
part of the year and does not include plants that were idle for all of 2006. Process emission estimates were
calculated using estimated production values and an emission factor for natural gas from U.S. EPA 2008. An
emission factor for petroleum coke was used for Coffeyville Resources LLC as their primary feedstock is petroleum
coke.
In order to determine CC>2 emissions from combustion related to the ammonia production
process, region-specific energy intensities for fossil fuel combustion were used. It was assumed
that each facility used natural gas as its combustible fuel based on MECS data for NAICS code
325311.
Total ammonia plant energy intensity by region was obtained from Phylipsen et al, 2002.
National average energy intensity values for feedstock energy and electricity were obtained from
Lawrence Berkeley National Laboratories (LBNL) 2000 and were 19.4 million Btu per ton
(MMBtu/ton) and 0.43 MMBtu/ton respectively. In order to obtain energy intensity by region
for combustion alone, national average feedstock and electricity energy intensities for ammonia
production were subtracted from regional total ammonia plant energy intensity from Phylipsen et
al., 2002. These values can be seen in Table 4. For those facilities that were not captured among
the regions available in Phylipsen et al., 2002, a national value of 15.9 MMBtu/metric tons
obtained from Lawrence Berkeley National Laboratory 2002 was used.
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
Table 4. Energy Intensity Values for Ammonia Production
Southeast U.S. (Mississippi)
South Central U.S.
(Texas/Louisiana)
North Central U.S. (Oklahoma
and the mid-west)
National U.S.
Data obtained from
Phylipsen et al.
(MMBtu/ton)
33.7
34.2
35.5
Adjusted to represent
for only Combustion
(MMBtu/ton)
13.9
14.4
15.7
Energy Intensity for
fuel combustion
(MMBtu/Mt)
15.3
15.8
17.3
15.9
Source: Phylipsen, D. etal, 2002. National U.S.: LBNL 2000.
Methane and N2O emission factors for stationary combustion, shown in Table 5, were derived
from Table 2.3 of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC
2006) for Manufacturing Industries and Construction. Industrial source emission factors, shown
in Table 6, were derived from Table 2.7 of 2006 IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC 2006).
Table 5. Default Emission Factors for Stationary Combustion in Manufacturing Industries and
Construction
Fuel
Natural Gas
CH4 Default
Emission Factor
(kg/TJ)
1
N2O Default
Emission Factor
(kg/TJ)
0.1
Source: From Table 2.3 of 2006 IPCC Guidelines for National Greenhouse Gas Inventories.
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Technical Support Document for Ammonia: Proposed Rule for Mandatory Reporting of Greenhouse Gases
Table 6. Industrial Source Emission Factors
Basic Technology
Liquid Fuels
Residual Fuel Oil Boilers
Gas/Diesel Oil Boilers
Large Stationary Diesel Oil
Engines>600 hp (447 kW)
Liquefied Petroleum Gases
Boilers
Solid Fuels
Other Bituminous/Sub-big.
Overfeed Stoker Boilers
Other Bituminous/Sub-Bit.
Underfeed Stoker Boilers
Other Bituminous/Sub-
bituminous Pulverized
Other Bituminous Spreader
Stokers
Other Bituminous/Sub-bit.
Fluidized Bed Combustor
Natural Gas
Boilers
Gas-Fired Gas Turbines
>3MW
Natural Gas-fired
Reciprocating Engines
Biomass
Wood/Wood Waste Boilers
Configuration
Dry Bottom, wall fired
Dry Bottom, tangentially fired
Wet Bottom
2-Stroke Lean Burn
4-Stroke Lean Burn
4-Stroke Rich Burn
Emission factors (kg/TJ energy
input)
CH4
3
0.2
4
0.9
1
14
0.7
0.7
0.9
1
1
1
4
693
597
110
11
N2O
0.3
0.4
NA
4
0.7
0.7
0.5
1.4
1.4
0.7
61
1
1
NA
NA
NA
7
Source: From Table 2.7 of 2006 IPCC Guidelines for National Greenhouse Gas Inventories.
4.1.2 Capacity Thresholds
Capacity based thresholds are not presented here because all but one plant exceeds the highest
emissions-based thresholds. Capacity based thresholds will capture a similar number of facilities
and amount of emissions.
4.1.3 No Emissions Threshold
The no emissions threshold includes all ammonia production facilities included in this Technical
Support Document regardless of their emissions or capacity.
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4.2 Analysis of Emissions and Facilities Covered Per Option
4.2.1 Emissions Thresholds
At the threshold levels of 1,000 metric tons, 10,000 metric tons, and 25,000 metric tons, all
facilities exceed the threshold, therefore covering 100% of total emissions. However, at the
100,000 metric tons level, two facilities do not exceed the threshold - the Gordon, GA facility of
Shoreline Chemical Millennium Inorganic Chemicals Inc., which produces an estimated 45,000
metric tons CC>2 emissions per year, and the Creston, IA facility of Green Valley Chemical Corp,
which produces an estimated 49,000 metric tons CC>2 emissions per year. At the 100,000 metric
tons threshold level, 99 percent of emissions would be covered.
4.2.2 Capacity Threshold
Capacity based thresholds were not analyzed.
4.2.3 No Emissions Threshold
The no emissions threshold includes all ammonia production facilities included in this Technical
Support Document regardless of their emissions or capacity.
5. Options for Monitoring Methods
Four separate monitoring methods were considered for this technical support document: a
simplified emission calculation (Option 1), a mass balance (Option 2), a facility specific
calculation (Option 3), and direct measurement (Option 4). All of these options require annual
reporting.
5.1 Option 1: Simplified Emissions Calculation
A simplified emissions calculation approach would use IPCC's Tier 1 methodology for
estimating emissions, using facility-specific production data and a default emission factor. The
equation used for this method can be found in Section 3.1 "Existing Relevant Reporting
Programs/Methodologies."
5.2 Option 2: Mass Balance
A mass balance approach uses default carbon content values for pipeline quality natural gas
(from the U.S. DOE). Using default carbon content for fuel would not provide the same level of
accuracy as using facility-specific carbon contents. This approach is consistent with IPCC Tier
2, DOE 1605 (b) and The Climate Registry "B" rated estimation methods.
5.3 Option 3: Facility Specific Calculation
If the facility does not use CEMS, an alternative hybrid method is proposed based on the IPCC
Tier 2 method guidance for determining CO2 emissions from ammonia production. This method
calculates process emissions through facility-level data collection on the consumption of the
generally natural gas feedstock, the carbon content of the feedstock, and the quantity of CO2 sent
for downstream use, i.e., urea production. Separate equations are proposed for gaseous, liquid,
or solid feedstocks.
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For gaseous feedstocks, the following equation would be used to calculate CC>2 emissions:
Where:
CC>2 = Annual CC>2 mass emissions arising from feedstock consumption (metric
tons)
(Fdstk)n = Volume of the gaseous feedstock used in month n (scf of feedstock)
(CC)n = Average carbon content of the gaseous feedstock, from the analysis results
for month n (kg C per kg of feedstock)
MW = Molecular weight of the gaseous feedstock (kg/kg-mole)
MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions)
n = Months per year
44/12 = Ratio of molecular weights, CC>2 to carbon
0.001 = Conversion factor from kg to metric tons
(Rco2)n = CC>2 recovered for downstream use for month n (urea or methanol
production, CC>2 capture), kg CC>2
For calculating CC>2 emissions from liquid feedstocks, the following equation would be used:
— * (Fdstk)„ * (CC) „ - (Rcm) „) * 0.001
-i ^ \ ' n \ //7 vCL/Z/M/
Where:
CC>2 = Annual CC>2 mass emissions arising from feedstock consumption (metric
tons)
(Fdstk)n = Volume of the liquid feedstock used in month "n" (gallons of feedstock)
(CC)n = Average carbon content of the gaseous feedstock, from the analysis results
for month "n" (kg C per gallon of feedstock)
n = Months per year
44/12 = Ratio of molecular weights, CC>2 to carbon
0.001 = Conversion factor from kg to metric tons
(Rco2)n = CC>2 recovered for downstream use for month "n" (urea or methanol
production, CC>2 capture), kg CC>2.
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For solid feedstocks, emissions of CC>2 would be calculated using the following equation:
co2=(Y44
Where:
* (Fdstk)„ * (CC) _ - (Rcm) „) * 0.001
-i /^ V ' n V / M vCL/Z/M/
CC>2 = Annual CO2 mass emissions arising from feedstock consumption (metric
tons)
(Fdstk)n = Mass of the solid feedstock used in month "n" (kg of feedstock)
(CC)n = Average carbon content of the solid feedstock, from the analysis results for
month "n" (kg C per kg of feedstock)
n = Months per year
44/12 = Ratio of molecular weights, CC>2 to carbon
0.001 = Conversion factor from kg to metric tons
(Rco2)n = CC>2 recovered for downstream use for month "n" (urea or methanol
production, CC>2 capture), kg CC>2.
5.4 Option 4: Direct Measurement
Direct measurement constitutes either measurements of the GHG concentration in the stack gas
and the flow rate of the stack gas using a Continuous Emissions Monitoring System (CEMS), or
periodic measurement of the GHG concentration in the stack gas and the flow rate of the stack
gas using periodic stack testing. Under either a CEMS approach or a stack testing approach, the
emissions measurement data would be reported annually.
Elements of a CEMS include a platform and sample probe within the stack to withdraw a sample
of the stack gas, an analyzer to measure the concentration of the GHG (e.g., CO2) in the stack
gas, and a flow meter within the stack to measure the flow rate of the stack gas. The emissions
are calculated from the concentration of GHGs in the stack gas and the flow rate of the stack gas.
The CEMS continuously withdraws and analyzes a sample of the stack gas and continuously
measures the GHG concentration and flow rate of the stack gas.
For direct measurement using stack testing, sampling equipment would be periodically brought
to the site and installed temporarily in the stack to withdraw a sample of the stack gas and
measure the flow rate of the stack gas. Similar to CEMS, for stack testing the emissions are
calculated from the concentration of GHGs in the stack gas and the flow rate of the stack gas.
The difference between stack testing and continuous monitoring is that the CEMS data provide a
continuous measurement of the emissions while a stack test provides a periodic measurement of
the emissions. A method using periodic, short-term stack testing would be appropriate for those
facilities where both inputs (such as feedstock and fuel) and process operating parameters remain
relatively consistent over time. In cases where there is the potential for significant variations in
the process input characteristics or operating conditions, continuous measurements would be
needed to accurately record changes in the actual GHG emissions from the sources resulting
from any process variations.
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6. Procedures for Estimating Missing Data
Options and considerations for missing data vary depending on the proposed monitoring method.
Each option would require a complete record of all measured parameters as well as parameters
determined from company records that are used in the GHG emissions calculations (e.g., carbon
contents, monthly fuel consumption, etc.).
6.1 Procedures for Option 1: Simplified Emission Calculation
If facility-specific production data is missing for one year, an average value using the production
data from the year prior and the year after the missing year may be calculated. Default emission
factors are readily available through IPCC guidelines (IPCC 2006).
6.2 Procedures for Option 2: Mass Balance
Default emission factors are readily available through the Department of Energy (IPCC 2006).
6.3 Procedures for Option 3: Facility Specific Calculation
For process sources that use the hybrid approach, the following data would be needed: fuel type,
fuel consumption, fuel molecular weight (for gaseous fuels), fuel carbon content, and amount of
CC>2 recovered for downstream use. In general, the substitute data value could be the arithmetic
average of the quality-assured values of that same parameter immediately preceding and
immediately following the missing data incident. If no quality-assured data are available prior to
the missing data incident, the substitute data value could be the first quality-assured value
obtained after the missing data period could be used. For missing oil or gas flow rates, standard
missing data procedures in section 2.4.2 of appendix D to part 75 apply. For missing records of
solid fuel usage, the substitute data would be the best available estimate of fuel consumption,
based on all available process data.
6.4 Procedures for Option 4: Direct Measurement
6.4.1 Continuous Emission Monitoring Data (CEMS)
For options involving direct measurement of CC>2 emissions using CEMS, Part 75 establishes
procedures for the management of missing data. Specifically, the procedures for managing
missing CC>2 concentration data are specified in §75.35. In general, missing data from the
operation of the CEMS may be replaced with substitute data to determine the CC>2 emissions
during the period for which CEMS data are missing. Section 75.35(a) requires the owner or
operator of a unit with a CC>2 CEMS to substitute for missing CC>2 pollutant concentration data
using the procedures specified in paragraphs (b) and (d) of §75.35; paragraph (b) covers
operation of the system during the first 720 quality-assured operation hours for the CEMS, and
paragraph (d) covers operation of the system after the first 720 quality-assured operating hours
are completed.
During the first 720 quality-assured monitor operating hours following initial certification at a
particular unit or stack location, the owner or operator would be required to substitute CC>2
pollutant concentration data according to the procedures in §75.3 l(b). That is, if prior quality-
assured data exist, the owner or operator would be required to substitute for each hour of missing
data, the average of the data recorded by a certified monitor for the operating hour immediately
preceding and immediately following the hour for which data are missing. If there are no prior
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quality-assured data, the owner or operator would have to substitute the maximum potential CC>2
concentration for the missing data.
Following the first 720 quality-assured monitor operating hours, the owner or operator would
have to follow the same missing data procedures for SC>2 specified in §75.33(b). The specific
methods used to estimate missing data would depend on the monitor data availability and the
duration of the missing data period.
6.4.2 Stack Testing Data
For options involving direct measurement of CC>2 flow rates or direct measurement of CC>2
emissions using stack testing, "missing data" is not generally anticipated. Stack testing
conducted for the purposes of compliance determination is subject to quality assurance
guidelines and data quality objectives established by the U.S. EPA, including the Clean Air Act
National Stack Testing Guidance published in 2005 (EPA 2005). The 2005 EPA Guidance
Document indicates that stack tests should be conducted in accordance with a pre-approved site-
specific test plan to ensure that a complete and representative test is conducted. Results of stack
tests that do not meet pre-established quality assurance guidelines and data quality objectives
would generally not be acceptable for use in emissions reporting.
7. QA/QC Requirements
Facilities might be required to conduct quality assurance and quality control of the production
and consumption data, supplier information (e.g., carbon contents), and emission estimates
reported. Facilities could be encouraged to prepare an in-depth quality assurance and quality
control plan which would include checks on production data, the carbon content information
received from the supplier and from the lab analysis, and calculations performed to estimate
GHG emissions. Several examples of QA/QC procedures are listed below.
7.1 Stationary Emissions
Facilities could follow the guidelines given by the Stationary Combustion Source TSD.
7.2 Process Emissions
Options and considerations for QA/QC will vary depending on the proposed monitoring method.
Each option would require unique QA/QC measures appropriate to the particular methodology
employed to ensure proper emission monitoring and reporting.
7.2.1 Continuous Emission Monitoring System (CEMS)
For units using CEMS to measure CC>2 emissions, the equipment could be tested for accuracy
and calibrated as necessary by a certified third party vendor. These procedures should be
consistent in stringency and data reporting and documentation adequacy with the QA/QC
procedures for CEMS described in Part 75 of the Acid Rain Program.
7.2.2 Stack Test Data
EPA could apply current EPA regulations for performance testing under 40 CFR § 63.7(c)(2)(i)
that state that before conducting a required performance test, the owner/operator is required to
develop a site-specific test plan and, if required, submit the test plan for approval. The test plan
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is required to include "a test program summary, the test schedule, data quality objectives, and
both an internal and external quality assurance (QA) program" to be applied to the stack test.
Data quality objectives are defined under 40 CFR § 63.7(c)(2)(i) as "the pre-test expectations of
precision, accuracy, and completeness of data." Under 40 CFR § 63.7(c)(2)(ii), the internal QA
program is required to include, "at a minimum, the activities planned by routine operators and
analysts to provide an assessment of test data precision; an example of internal QA is the
sampling and analysis of replicate samples." Under 40 CFR § 63.7(c)(2)(iii) the external QA
program is required to include, "at a minimum, application of plans for a test method
performance audit (PA) during the performance test." In addition, according to the 2005
Guidance Document, a site-specific test plan should generally include chain of custody
documentation from sample collection through laboratory analysis including transport, and
should recognize special sample transport, handling, and analysis instructions necessary for each
set of field samples (US EPA 2005).
7.2.3 Equipment Maintenance
For units using flow meters to directly measure the flow rate of fuels, raw materials, products, or
process byproducts, flow meters could be required to be calibrated on a scheduled basis in
accordance with equipment manufacturer specifications and standards. Flow meter calibration is
generally conducted at least annually. A written record of procedures needed to maintain the
flow meters in proper operating condition and a schedule for those procedures should be part of
the QA/QC plan for the capture or production unit.
An equipment maintenance plan should be developed as part of the QA/QC plan. Elements of a
maintenance plan for equipment include the following:
• Conduct regular maintenance of equipment, e.g. flow meters.
o Keep a written record of procedures needed to maintain the monitoring system in
proper operating condition and a schedule for those procedures;
o Keep a record of all testing, maintenance, or repair activities performed on any
monitoring system or component in a location and format suitable for inspection. A
maintenance log may be used for this purpose. The following records could be
maintained: date, time, and description of any testing, adjustment, repair,
replacement, or preventive maintenance action performed on any monitoring
system and records of any corrective actions associated with a monitor's outage
period. Additionally, any adjustment that recharacterizes a system's ability to
record and report emissions data must be recorded (e.g., changing of flow monitor
or moisture monitoring system polynomial coefficients, K factors or mathematical
algorithms, changing of temperature and pressure coefficients and dilution ratio
settings), and a written explanation of the procedures used to make the
adjustment(s) shall be kept (EPA 2003).
For units using CEMS to measure CC>2 flow rates or CC>2 emissions, the equipment might be
required to be tested for accuracy and calibrated as necessary by a certified third party vendor.
These procedures should be consistent in stringency and data reporting and documentation
adequacy with the QA/QC procedures for CEMS described in Part 75 of the Acid Rain Program
(EPA 2008a).
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7.3 Data Management
Data management procedures could be included in the QA/QC Plan. Elements of the data
management procedures plan might include:
• Check for temporal consistency in production data, carbonate content data, and
emission estimates. A monitoring error is probable if differences between annual data
cannot be explained by:
Changes in activity levels,
- Changes concerning fuels or input material,
Changes concerning the emitting process (e.g. energy efficiency improvements)
(European Commission 2007).
• Determine the "reasonableness" of the emission estimate by comparing it to previous
year's estimates and relative to national emission estimate for the industry:
Comparison of data on fuel or input material consumed by specific sources with
fuel or input material purchasing data and data on stock changes,
- Comparison of fuel or input material consumption data with fuel or input material
purchasing data and data on stock changes,
Comparison of emission factors that have been calculated or obtained from the
fuel or input material supplier, to national or international reference emission
factors of comparable fuels or input materials
Comparison of emission factors based on fuel analyses to national or international
reference emission factors of comparable fuels, or input materials,
- Comparison of measured and calculated emissions (European Commission 2007).
• Maintain data documentation, including comprehensive documentation of data
received through personal communication:
- Check that changes in data or methodology are documented
8. Types of Emission Information to be Reported
Information reported may vary depending on the monitoring method selected. However, all
facility owners and operators would submit their process CC>2 emissions data and combustion
related CC>2, CH4, and N2O data. For reporting options for emissions (CC>2, CH4, and N2O)
from stationary combustion, refer to EPA-HQ-OAR-2008-0508-004. However, some
monitoring options discussed later in section 6 will capture total greenhouse emissions at
ammonia production facilities (process and combustion) and we have noted where the
monitoring option will sufficiently meet or be consistent with reporting options discussed in the
stationary fuel combustion technical support document.
8.1 Other Information to be Reported
In addition, facility owners and operator could submit the following additional data on an annual
basis. These data are the basis for calculations and would be needed to understand the emissions
data and verify the reasonableness of the reported emissions. The data could include: the total
quantity of feedstock consumed for ammonia manufacturing, the quantity of CC>2 captured for
use and the end use, if known, the total amount of fuel used to determine CC>2, CH4, and N2O
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from stationary fuel combustion units at ammonia manufacturing facilities, the monthly analyses
of carbon content for each feedstock used in ammonia manufacturing, and monthly urea,
methanol, and hydrogen production.
The following sections describe data that could be required for specific monitoring options.
8.1.1 Option 1: Simplified Emissions Calculation
For the simplified emissions calculation, the facility should report its ammonia production in
addition to GHG emissions.
8.1.2 Option 2: Mass Balance
For the mass balance approach, the facility should report its ammonia production in addition to
GHG emissions.
8.1.3 Option 3: Facility Specific Calculation
For the facility-specific calculation method, the facility would report its production data, fuel
type, fuel consumption, carbon content of fuel, and quantity of carbon recovered for downstream
use.
8.1.4 Option 4: Direct Measurement
For options based on direct measurement, either using a CEMS or through stack testing, the
GHG emissions are directly measured at the point of emission.
8.1.4.1 CEMS
For direct measurement using CEMS, the facility would report the GHG emissions measured by
the CEMS for each monitored emission point and would also report the monitored GHG
concentrations in the stack gas and the monitored stack gas flow rate for each monitored
emission point. These data would illustrate how the monitoring data were used to estimate the
GHG emissions.
The following data could be reported to support direct measurement of emissions using CEMS:
• The unit ID number (if applicable);
• A code representing the type of unit;
• Maximum product production rate and maximum raw material input rate (in units of
metric tons per hour);
• Each type of raw material used and each type of product produced in the unit during
the report year;
• The calculated CC>2, CH4, and N2O emissions for each type of raw material used and
product produced, expressed in metric tons of each gas and in metric tons of CC^e;
• A code representing the method used to calculate the CC>2 emissions for each type of
raw material used (e.g., part 75, Tier 1, Tier 2, etc.);
• If applicable, a code indicating which one of the monitoring and reporting
methodologies in part 75 of this chapter was used to quantify the CC>2 emissions;
• The calculated CC>2 emissions from sorbent (if any), expressed in metric tons; and
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• The total GHG emissions from the unit for the reporting year, i.e., the sum of the CC>2,
CH4, and N2O emissions across all raw material and product types, expressed in metric
tons of CO26.
8.1.4.2 Stack Testing
For direct measurement using stack testing, the facility would report the GHG emissions
measured during the stack test, the measured GHG concentrations in the stack gas, the monitored
stack gas flow rate for each monitored emission point, and the time period during which the
stack test was conducted. The facility should also report the process operating conditions (e.g.,
raw material feed rates) during the time period during which the test was conducted.
8.2 Additional Data to be Retained Onsite
Facilities could be required to retain data concerning monitoring of GHG emissions onsite for a
period of 5 years from the reporting year. For CEMS, these data could include CEMS
monitoring system data including continuous-monitored GHG concentrations and stack gas flow
rates, and calibration and quality assurance records. For stack testing these data could include
stack test reports and associated sampling and chemical analytical data for the stack test. Process
data, including process raw material and product feed rates and carbon contents, could also be
retained on site. The EPA could use such data to conduct trend analyses and potentially to
develop process or activity-specific emission factors for the process.
9. References
IFDC (2005). International Fertilizer Development Center. North America Fertilizer Capacity.
Market Information Unit. Market Development Division. September 2005.
IPCC (2006). 2006IPCC Guidelines for National Greenhouse Gas Inventories. The National
Greenhouse Gas Inventories Programme, The Intergovernmental Panel on Climate Change, H.S.
Eggleston, L. Buenida, K. Miwa, T Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
LBNL (2000). Worrell, E., D. Phylipsen, D. Einstein, and N. Martin, April 2000. Lawrence
Berkeley National Laboratory (LBNL), Environmental Energy Technologies Division. Energy
Use and Energy Intensity in the U.S. Chemical Industry.
http://www.energystar.gov/ia/business/industry/industrial_LBNL-44314.pdf
Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July
2007, "Establishing guidelines for the monitoring and reporting of greenhouse gas emissions
pursuant to Directive 2003/87/EC of the European Parliament and of the Council. Available at
http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF.
Part 75, Appendix Bl, Available at http://www.epa.gov/airmarkt/spm/rule/001OOOOOOB.htm.
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Phylipsen, D., K. Blok, E. Worrell, and J. de Beer, 2002. Benchmarking the energy efficiency of
the Dutch industry: an assessment of the expected effect on energy consumption and CC>2
emissions. Energy Policy 30 (2002) 663-679.
U.S. DOE (2007). Technical Guidelines Voluntary Reporting of Greenhouse Gases (1605(b))
Program. Available at
http://www.pi.energy.gov/enhancingGHGregistry/documents/January2007_1605bTechnicalGuid
elines.pdf
U.S. EPA (2005). Clean Air Act National Stack Testing Guidance, U.S. Environmental
Protection Agency Office of Enforcement and Compliance Assurance, September 30, 2005, Page
11. www.epa.gov/compliance/resources/policies/monitoring/caa/stacktesting.pdf
U.S. EPA (2007). Climate Leaders, Inventory Guidance, Design Principles Guidance, Chapter 7
"Managing Inventory Quality". Available at:
http://www.epa.gov/climateleaders/documents/resources/design_princ_ch7.pdf
U.S. EPA (2008). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. U.S.
Environmental Protection Agency, Washington D.C. USEPA #430-R-08-005.
USGS (2007). 2006Minerals Yearbook: Nitrogen. U.S. Geological Survey, Reston, VA.
Available at http://minerals.usgs.gov/minerals/pubs/commoditv/nitrogen/mvbl-2006-nitro.pdf
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