September 9, 2008
TECHNICAL SUPPORT DOCUMENT FOR THE
PETROCHEMICAL PRODUCTION SECTOR:
PROPOSED RULE FOR MANDATORY
REPORTING OF GREENHOUSE GASES
Office of Air and Radiation
U.S. Environmental Protection Agency
September 9, 2008
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CONTENTS
1.0 INTRODUCTION 1
2.0 SOURCE DESCRIPTION 1
2.1 Acrylonitrile 1
2.2 Carbon Black 2
2.2.1 Furnace Black Process 3
2.2.2 Thermal Black Process 4
2.2.3 Acetylene Black Process 4
2.2.4 Lamp Black Process 5
2.3 Ethylene 5
2.4 Ethylene Dichloride 7
2.5 Ethylene Oxide 8
2.6 Methanol 9
2.6.1 Conventional Reforming Process 9
2.6.2 Coal Gasification 10
2.6.3 Partial Oxidation 11
3.0 TOTAL EMISSIONS 12
4.0 OPTIONS FOR REPORTING THRESHOLD 13
5.0 OPTIONS FOR MONITORING METHODS 14
5.1 Review of existing programs and methodologies 15
5.2 Discussion of options for monitoring methods 15
5.2.1 Option 1 15
5.2.2 Option 2 15
5.2.3 Options 17
6.0 Missing Data 18
6.1 Option 2 19
6.2 Options 19
7.0 Quality Assurance and Quality Control Requirements 19
7.1 Monitoring of Flow and Composition 20
7.2 CEMS 20
8.0 REFERENCES 20
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1.0 INTRODUCTION
The petrochemical industry consists of numerous processes that use fossil fuel or
petroleum refinery products as feedstocks. However, for this Greenhouse Gas (GHG) reporting
rule, the petrochemical production source category only considers the production of acrylonitrile,
carbon black, ethylene, ethylene dichloride, ethylene oxide, and methanol. The petrochemical
source category includes all forms of carbon black (e.g., furnace black, thermal black, acetylene
black, and lamp black) because their production is based on petrochemical feedstocks. The rule
focuses on these six processes because production of GHGs from these processes has been
recognized by the Intergovernmental Panel on Climate Change (IPCC) to be significant
compared to other petrochemical processes.1 For the purposes of this report, bone black is not
considered to be a form of carbon black because it does not use petrochemical feedstocks.
As discussed in section 2 of this report, there are 88 facilities operating petrochemical
processes in the United States, and 9 of these facilities are operating either two or three types of
petrochemical processes (e.g., ethylene and ethylene oxide).
2.0 SOURCE DESCRIPTION
This section summarizes the processes and major emission points of GHGs for each of
the six types of petrochemical processes identified in section 1.0. The facilities making each
type of petrochemical are also listed. More complete descriptions of the processes are available
in referenced documents.
2.1 Acrylonitrile
It
The primary use of acrylonitrile is in the production of acrylic and modacrylic fibers
is also used in the production of various resins and in the production of adiponitrile and
acrylamide. The five facilities that make acrylonitrile in the United States are listed in Table 1.
All of these facilities manufacture acrylonitrile by direct ammoxidation of propylene with
ammonia (NH3) and oxygen over a catalyst.2 This process is referred to as the SOHIO process,
after the Standard Oil Company of Ohio (SOHIO). Although not commercialized in the United
States, other methods to produce acrylonitrile include the ammoxidation of propane and the
direct reaction of propane with hydrogen peroxide.3
Table 1. Acrylonitrile Production Facilities in the United States
4-7
Facility
Cytec
Lucite (formerly DuPont)
Ineos Nitriles
Ineos Nitriles
Solutia
City
Waggaman (Avondale)
Beaumont
Green Lake
Lima
Alvin
State
LA
TX
TX
OH
TX
Capacity
(mm lbs/yr)a
475
308
1,014
410
1,100
Capacities are presented in million pounds per year (mm Ibs/yr).
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The SOHIO process involves a gas-phase, fluidized bed reaction of chemical-grade
propylene, ammonia, and oxygen (from air) over a catalyst.1'2 The catalyst is a mixture of heavy
metal oxides (including bismuth and molybdenum). The ammoxidation of propylene converts
only about 70 percent of the propylene feedstock to acrylonitrile, and about 15 percent is
converted to acetonitrile and hydrogen cyanide (HCN). The remaining propylene feedstock is
either converted to CO2 by direct oxidation of the feedstock or converted to other hydrocarbons
through side reactions. The exact yield of acrylonitrile at each facility depends in part on the
type of catalyst used and the process configuration. The reaction governing the production of
acrylonitrile is shown below.
CH2=CHCH3 + 1.5O2 + NH3 -> CH2=CHCN + 3H2O
The direct oxidation of propylene to generate CO2 follows the reaction shown below.
C3H6 + 4.5O2 -> 3CO2 + 3H2O
After a series of heat recovery and neutralization steps, the product gas stream from the
reactor passes through an absorber which uses water as the scrubbing fluid. Most of the
acrylonitrile, HCN, acetonitrile, and other organic compounds are transferred to the water. Inert
compounds, such as CO2 and nitrogen, and small amounts of organic compounds remain in the
gas stream that is vented from the absorber. This vent stream is routed to a thermal incinerator to
control hydrocarbon emissions. The liquid stream from the absorber undergoes a series of
distillations to obtain acrylonitrile and one or more byproducts of the desired purity. All 5
facilities in the United States recover HCN as a byproduct. All of the facilities also separate
acetonitrile from water that is recycled to the absorber, but only the Lucite and Ineos Nitriles
facilities recover the acetonitrile as a byproduct; the other two facilities burn the acetonitrile
stream.2'5
The gaseous stream from the absorber contains much of the CO2 generated in the reactor.
Small amounts of CO2 may be lost through equipment leaks between the reactor and the
absorber, and small amounts may be carried along with the primary process fluid and released
from other process vents. Emission streams from these other process vents and storage tanks are
routed to flares to control emissions of hydrocarbons. Supplemental fuel (natural gas) is used in
the incinerators and flares as necessary to maintain operating temperatures.2 Combustion of
organic pollutants and supplemental fuel in the thermal incinerators and flares is another source
of CO2 emissions. Small amounts of unburned methane may be emitted from the combustion
units, and small amounts of nitrous oxide (N2O) may also be generated in and emitted from the
combustion units. No supplemental fuel-fired boilers or process heaters are needed because
excess heat from the exothermic ammoxidation reaction and incinerator exhaust is recovered to
supply other energy needs in the process.
2.2 Carbon Black
Carbon black is a black powder or granular substance formed through a high temperature
(1,320 °C to 1,540 °C) reaction of hydrocarbon fuel with a limited supply of combustion air. It
is used primarily as a reinforcing agent in tires and other rubber compounds, and also has
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applications as a pigment.1 As shown in Table 2, 21 facilities produce carbon black in the
United States. Most of these facilities use the furnace black process (also called the oil furnace
process in some reference documents). Other production processes include the thermal black
process, the acetylene black process, and the lamp black process. All of these processes are
described in the sections below. Another process, the channel black process, has not been used
in the United States since 1976 and is not discussed further in this report.8
Table 2. Carbon Black Production Facilities in the United States5'9
Facility
Cabot Corp.
Cabot Corp.
Cabot Corp.
Cabot Corp.
Chevron Phillips
Columbian Chemicals Co.
Columbian Chemicals Co.
Columbian Chemicals Co.
Columbian Chemicals Co.
Continental Carbon Co.
Continental Carbon Co.
Continental Carbon Co.
Degussa Engineered Carbons
Degussa Engineered Carbons
Degussa Engineered Carbons
Degussa Engineered Carbons
Degussa Engineered Carbons
General Carbon Co.
Sid Richardson Carbon Co.
Sid Richardson Carbon Co.
Sid Richardson Carbon Co.
City
Franklin
Pampa
Ville Platte
Waverly
Cedar Bayou
El Dorado
North Bend
Proctor
Ulysses
Phenix City
Ponca City
Sunray
Aransas Pass
Belpre
Borger
New Iberia
Orange
Los Angeles
Addis
Big Spring
Borger
State
LA
TX
LA
WV
TX
AR
LA
WV
KS
AL
OK
TX
TX
OH
TX
LA
TX
CA
LA
TX
TX
Capacity
(mm Ibs/yr)
355
65
355
220
20
130
350
200
115
200
285
190
125
185
290
250
155
1
310
235
315
Process
Furnace
Furnace
Furnace
Furnace
Acetylene
Furnace
Furnace
Furnace
Furnace
Furnace
Furnace
Furnace
Furnace
Furnace
Furnace, Thermal
Furnace
Furnace
Lamp black
Furnace
Furnace
Furnace
2.2.1 Furnace Black Process1'8'10'11
In the furnace black process a heavy aromatic liquid, also known as carbon black oil, is
injected continuously into the combustion zone of a natural gas-fired furnace. Both the natural
gas and a portion of the carbon black feedstock are oxidized to provide heat in the furnace, and
the remainder of the carbon black feedstock is pyrolyzed to carbon black in an oxygen-depleted
environment. In addition to the desired carbon black product, the vent gas from the furnace
contains numerous compounds including CO2, unburned CH4, carbon monoxide, hydrogen, and
various organic compounds. A water quench is used to cool the gas stream and stop the
reactions. Both the combustion air and the carbon black oil are preheated before entering the
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furnace. Some of the energy to preheat these streams may come from the furnace exhaust gas;
the remainder is provided by combustion of off-gasses from downstream in the process or from
supplemental fuels.
Carbon black is separated from the gas stream in a fabric filter. Typically, a portion of
the exhaust, or tail gas, from the fabric filter is burned to provide heat for the product dryers, and
the rest is burned in a thermal incinerator for pollution control. Hot exhaust from the thermal
incinerator may be used to generate steam, and at least one facility uses the steam to run a steam
turbine that generates electricity. Carbon black manufacturing facilities generally have several,
perhaps many, furnaces. Furnaces that are used to make the same grade of product may all
discharge to a single product processing train with one dryer. Although data for most facilities
are not available, it is likely that each facility has only one thermal incinerator for burning all
excess tail gas that is not needed to provide heat for dryers (there may be a backup device such
as a flare for periods when the incinerator is out of service). The number of process heaters per
facility is also unknown, but it is possible that steam generated by recovering heat from the tail
gas incinerator is used without the need for additional combustion units.
Most of the CC>2 that is generated in the furnaces is released to the atmosphere in the
exhaust from the thermal incinerator and the combustion units for each dryer. Small amounts
also may be released through equipment leaks in the process. The thermal incinerator,
combustion units for dryers, and any additional combustion units needed to supply heat for
preheaters emit additional CO2 that is generated by burning the tail gas (i.e., carbon monoxide
and various hydrocarbons) and if necessary, supplemental fuel. Unburned CFLt from the
furnaces and supplemental fuel in other combustion units is also released to the atmosphere from
the same emission points. Small amounts of N2O also likely are generated in and released from
each of the combustion units.
2.2.2 Thermal Black Process1'8
In the thermal black process gaseous hydrocarbons or atomized petroleum oils are
decomposed in a pair of furnaces in the absence of air. One furnace receives and cracks the
carbon black feedstock while the other is being preheated by combustion of off-gas from the
fabric filter used to recover the carbon black. Natural gas or another fuel may also be used to
supplement the off-gas, if necessary. The off-gas is primarily hydrogen but also contains 6
percent CFLi and 4 percent higher hydrocarbons. Once the first furnace becomes too cool to
crack the feed, the flows to the reactors are switched. The GHGs emitted from this process are
CO2, CH4, and N2O, and all of the main emission points are combustion units, the same as for the
furnace black process. As shown in Table 2, only one facility in the United States is making
carbon black using the thermal black process, and this process accounts for only a portion of the
carbon black produced at the facility. Information about the number of combustion sources at
this facility in addition to the combustion needed to preheat the furnaces is not available.
2.2.3 Acetylene Black Process1'8
In the acetylene black process, acetylene or acetylene-containing light hydrocarbons are
fed into a preheated reactor where the acetylene is decomposed into carbon black. This is an
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exothermic process and has a very high yield (95-99 percent). As shown in Table 2, acetylene
black is produced by only one facility in the United States, and the amount produced accounts
for less than one-half of one percent of the total carbon black capacity in the United States.
2.2.4 Lamp Black Process
1,8
For the lamp black process, carbon black feedstock is open-burned in shallow pans. Little
data are available to indicate the efficiency of this process or the emissions generated by it. As
shown in Table 2, lamp black accounts for less than one-tenth of one percent of the total carbon
black capacity in the United States.
2.3 Ethylene
In the United States, all ethylene is produced by way of steam cracking. Ethylene
(CH2=CH2) may be produced from steam cracking of a petrochemical feedstock in a
petrochemical plant, or from cracking and other processes operated at petroleum refineries. A
list of currently operating facilities that manufacture ethylene is displayed in Table 3.)
Table 3. Ethylene Production Facilities in the United States5'12'13
Facility
BASF Fina
Chevron Phillips
Chevron Phillips
Chevron Phillips
Chevron Phillips
Chevron Phillips
Dow
Dow
Dow
Dow
Dow
Dow
DuPont
Eastman
Equistar
Equistar
Equistar
Equistar
City
Port Arthur
Cedar Bayou (Baytown)
Port Arthur
Sweeny
Sweeny
Sweeny
Freeport
Freeport
Plaquemine
Plaquemine
Taft
Taft
Orange
Longview
Channelview
Chocolate Bayou (Alvin)
Clinton
Corpus Christi
State
TX
TX
TX
TX
TX
TX
TX
TX
LA
LA
LA
LA
TX
TX
TX
TX
IA
TX
Capacity
(mm Ibs/yr)
1,830
1,750
1,750
2,034
1,480
600
1,390
2,226
1,146
1,630
1,300
904
1,500
1,847
3,858
1,200
1,049
1,700
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Table 3. Ethylene Production Facilities in the United States5'12'13
Facility
Equistar
Equistar
ExxonMobil
ExxonMobil
ExxonMobil
ExxonMobil
Formosa Plastics
Huntsman
Huntsman
Huntsman
Ineos Olefms and Polymers
Javelina
Sasol North America
Shell
Shell
Shell
Sunoco
Westlake Petrochemicals
Westlake Petrochemicals
Westlake Petrochemicals
Williams Olefms
City
LaPorte
Morris
Baton Rouge
Baytown
Beaumont
Houston
Point Comfort
Odessa
Port Arthur
Port Neches
Chocolate Bayou (Alvin)
Corpus Christi
Lake Charles (Westlake)
Deer Park
Norco
Norco
Marcus Hook
Calvert City
Sulphur
Sulphur
Geismar
State
TX
IL
LA
TX
TX
TX
TX
TX
TX
TX
TX
TX
LA
TX
LA
LA
PA
KY
LA
LA
LA
Capacity
(mm Ibs/yr)
1,740
1,212
2,200
4,840
1,800
225
3,375
800
1,400
450
3,860
333
1,000
3,100
1,984
1,446
496
450
1,250
1,150
1,350
In the United States, most ethylene is produced from steam cracking of ethane, propane,
or naphtha. Some facilities also use butane, gas oil, or other feedstocks. Most facilities use more
than one type of feedstock.13
Steam cracking petrochemical feedstocks to produce ethylene also produces other high
value (saleable) petrochemical products, including propylene, butadiene, and aromatic
compounds. The separation and purification of all of the products derived from the steam
cracking operation are considered to be part of the ethylene process. The steam cracking process
also generates CH4, which is generally burned for energy recovery within the process along with
hydrogen and other light ends that are not recovered as products.1
All of the GHG emissions associated with the ethylene process are from combustion
units. Carbon dioxide is the primary GHG, but small amounts of unburned CH4 are also emitted,
and small amounts of N2O are likely generated in and emitted from the combustion units.
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Except for processes using ethane or gas oil feedstocks, combustion of the off-gas from the
process is sufficient to provide the steam for the cracking operation and any other energy needs
in the process.1 Small amounts of supplemental fuel are needed (and presumably mixed with the
off-gas) when ethane or gas oil are used as the feedstock. The number of combustion units at
each facility for energy purposes is not known because information about the number of steam
cracking units at each facility is not available, and it is not known whether facilities have a
centralized combustion unit to supply energy for all purposes or multiple units. Each facility,
however, likely has a single fuel gas system (with or without supplemental natural gas) that
supplies fuel to all combustion units.
In addition to combustion units for energy purposes, each ethylene production facility has
a flare to control emissions from excess fuel gas production. For this analysis, it is assumed that
each facility also has one thermal incinerator to control hydrocarbon emissions from process
vents, storage tanks, and other emission points associated with production of ethylene and
byproducts. As for combustion units used to supply energy, the primary GHG emitted from
these combustion units is CC>2. Small amounts of CH4 and N2O are also emitted.
2.4 Ethylene Bichloride
Ethylene dichloride (1,2-dichloroethane) is produced from ethylene by direct
chlorination, oxychlorination, or by a combination of the two processes (referred to as the
"balanced process"). As shown in Table 4, most facilities in the United States use the balanced
process.
Table 4. Ethylene Dichloride Production Facilities in the United States5'14
Facility
Dow
Dow
Dow
Formosa Plastics
Formosa Plastics
Geismar Vinyls
Georgia Gulf
Georgia Gulf
Occidental
Occidental
Occidental
(formerly Vulcan)
OxyMar
Oxy Vinyls
Oxy Vinyls
PPG Industries
Westlake
City
Freeport
Oyster Creek
Plaquemine
Baton Rouge
Point Comfort
Geismar
Lake Charles
Plaquemine
Convent
Ingleside (Corpus Christi)
Geismar
Ingleside (Corpus Christi)
Deer Park
La Porte
Lake Charles
Calvert City
State
TX
TX
LA
LA
TX
LA
LA
LA
LA
TX
LA
TX
TX
TX
LA
KY
Capacity
(mm Ibs/yr)
1,650
3,000
2,800
1,225
2,900
1,180
1,700
2,530
1,500
1,500
600
3,900
2,100
3,900
2,700
1,950
Process
Direct chlorination
Balanced
Balanced
Balanced
Balanced
Balanced
Balanced
Balanced
Direct chlorination
Direct chlorination
Direct chlorination
Balanced
Balanced
Balanced
Balanced
Balanced
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The direct chlorination process involves gas-phase reaction of ethylene with chlorine to
produce ethylene dichloride. The oxychlorination process involves gas-phase reaction of
ethylene with hydrochloric acid (HC1) and oxygen to produce ethylene dichloride and water.
Most facilities that produce ethylene dichloride use it as a feedstock in the production of vinyl
chloride monomer. Cracking ethylene dichloride to produce vinyl chloride also produces HC1.
This HC1 can be used as a raw material in the oxychlorination process. Therefore, most ethylene
dichloride/vinyl chloride monomer production facilities operate a 'balanced process' in which
ethylene dichloride is produced using both the direct chlorination process and the
oxychlorination process.1'15
The oxychlorination process produces a small amount of CC>2 from the direct oxidation of
the ethylene feedstock; most of this CC>2 is released to the atmosphere from a knockout drum that
follows the oxychlorination reactor and quench.15 Most of the CC>2 emissions from the
oxychlorination process and essentially all of the CC>2 emissions from the direct chlorination
process are from combustion units.1 Some of the energy needs are supplied by recovering heat
from the incinerator that is used to control hydrocarbon emissions from process vents and storage
tanks, and the rest is provided by burning supplemental fuels. The number of combustion units
per facility is unknown, but it is likely that supplemental fuel from the same source is used in all
of them. Organic liquid wastes are also disposed of by incineration.15 The CH4 content of
process vent emissions is considered to be negligible, but some unburned CH4 is emitted from
the combustion units that burn supplemental fuel.1 Small amounts of N2O are also likely emitted
from the combustion units.
Because it includes the oxychlorination process, the 'balanced process' also emits CC>2
from the direct oxidation of the ethylene feedstock. Emissions from combustion units are
comparable to those from the individual processes.
2.5 Ethylene Oxide
Ethylene oxide (C2H4O) is used as a feedstock in the manufacture of glycols, glycol
ethers, alcohols, and amines. It is manufactured by reacting ethylene and oxygen over a catalyst.
The oxygen may be supplied to the process through either an air or a pure oxygen stream. As
shown in Table 5, almost all ethylene oxide manufacturers in the United States use the oxygen
process.
The by-product CC>2, from the direct oxidation of the ethylene feedstock, is removed
from the process vent stream using a recycled carbonate solution. The recovered CC>2 may be
vented to the atmosphere or recovered for further utilization (e.g., food production).19
The ratio of metric tons of ethylene consumed per metric ton of ethylene oxide produced
defines the selectivity of the ethylene oxide process. The combined ethylene oxide reaction and
by-product CC>2 reaction is exothermic and generates heat, which is recovered to produce steam
for the process. The ethylene oxide process also produces other liquid and off-gas by-products
(e.g., ethane) that may be burned for energy recovery within the process. The amount of CC>2,
other by-products, and steam produced from the process is dependent upon the selectivity of the
process.1
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Table 5. Ethylene Oxide Production Facilities in the United States5'16"18
Facility
BASF
Dow
Dow
Dow
Eastman
Equistar
Formosa
Huntsman
Old World Industries
PD Glycol
Shell
Sunoco
City
Geismar
Seadrift
Taft
Plaquemine
Longview
Bayport
Point Comfort
Port Neches
Clear Lake
Beaumont
Geismar
Claymont
State
LA
TX
LA
LA
TX
TX
TX
TX
TX
TX
LA
DE
Capacity
(mm Ibs/yr)
485
950
1,700
620
230
800
550
1,015
780
700
920
120
Process
Oxygen
Air
Air/Oxygen
Oxygen
Oxygen
Oxygen
Oxygen
Oxygen
Oxygen
Oxygen
Oxygen
Oxygen
2.6 Methanol
Methanol is most commonly synthesized in the gas phase over a heterogeneous catalyst
from a synthesis gas (syngas), which is a mixture containing hydrogen, carbon monoxide, and
carbon dioxide. One company also operates a liquid-phase conversion process. Several process
techniques to produce syngas have been developed such as steam reforming of natural gas, coal
gasification, partial oxidation of various hydrocarbon feedstocks, and combinations of these
technologies. Although steam reforming of natural gas is the most common method of
producing syngas worldwide, only two facilities in the United States use this method. Other
facilities in the United States produce syngas using coal gasification or partial oxidation of
natural gas. All of the facilities use only a portion of the syngas to produce methanol. The rest is
used to produce other chemicals, some of which are in other GHG reporting source categories
such as hydrogen and ammonia production. Table 6 lists currently operating methanol
manufacturing facilities in the United States.
2.6.1 Conventional Reforming Process1'28'30
The conventional reforming process for methanol production involves steam reforming to
produce syngas (which may include either a single reformer unit or both a primary reformer unit
and a secondary reformer unit) followed by conversion of the syngas to methanol. A typical
steam reforming process begins with a preheated natural gas feedstock, which is then
desulfurized, mixed with steam, and reformed and cooled before finally being compressed as
feed to a methanol conversion unit.
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Table 6. Methanol Production Facilities in the United States5'20'27
Facility
Dakota
Gasification
Company
Eastman
Millenium
Terra Industries
Praxair
City
Beulah
Kingsport
La Porte
(Deer Park)
Woodward
Geismar
State
ND
TN
TX
OK
LA
Capacity
(mm gpy)
2
102a
210
40
30
Process to produce
syngas
Coal gasification
Coal gasification
Partial oxidation of
natural gas
Steam reforming of
natural gas
Steam reforming of
natural gas
Other GHG
source categories
at facility
Ammonia,
Carbon dioxide
Ammonia
Hydrogen
aTotal capacity includes 70 million gal/yr unit based on conventional gas-phase methanol
conversion and 32 million gal/yr unit based on a new liquid-phase conversion unit. Both units
convert syngas produced in the coal gasification unit.
Off-gas from the methanol conversion unit includes methane feedstock that did not break
down in the reformer and some syngas that was not converted to methanol in the methanol
conversion unit. A portion of this gas is compressed and recycled to the methanol conversion
unit. The remainder is purged to prevent buildup of noncondensable gases. The purged gas is
used as fuel in the reformer. The methanol from the methanol conversion unit is purified in a
series of distillation units. Light ends from the distillation unit are used as fuel in the reformer.
Heavy liquid organic compounds from the final methanol distillation column are a hazardous
waste, which may be burned if a permit is obtained, or this stream may be further processed.
Water from the distillation column, which contains methanol and other organic compounds, is
sent to biological treatment. A flare is used to control startup, shutdown, and malfunction
emissions. Although no facilities in the United States are known to operate the conventional
reforming process in this way, one option is to utilize CO2 captured from other industrial
processes as a supplemental feedstock to the methanol production process.
2.6.2 Coal Gasification26'28'31'32
Coal gasification is accomplished by a combination of partial oxidation and
hydrogasification of coal feedstock. The coal reacts with oxygen to produce carbon monoxide
and with water to produce carbon monoxide and hydrogen. Carbon monoxide and water can
then react to yield carbon dioxide and hydrogen, and the carbon dioxide can be reacted with coal
to produce carbon monoxide.
The Dakota Gasification facility primarily produces synthetic natural gas, but they also
produce a variety of other chemicals as byproducts. The facility uses 14 Lurgi moving bed
gasifiers to convert lignite to a raw synthesis gas. Coal is fed to the top of each gasifier, and
steam and oxygen are fed to the bottom of the gasifiers. As the steam and oxygen rise through
the coal bed they react with the coal to form the raw syngas. After exiting the top of the
10
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gasifiers, the raw gas is cooled in waste heat recovery boilers. A portion of the raw gas is sent to
a shift conversion unit where some of the carbon monoxide in the gas reacts with water vapor to
form hydrogen and carbon dioxide. The shifted gas is then recombined with the remainder of the
raw gas. The mixed gas is sent to an acid gas unit where carbon dioxide, sulfur compounds, and
naphtha are removed by a cold methanol wash. Most of the synthesis gas from the acid gas unit
is sent to a methanation unit to produce synthetic natural gas. On average, about 10 percent of
the syngas is diverted to an ammonia production unit. Purge gas from the ammonia process is
used as fuel in boilers at the facility. A small amount of syngas is used to produce methanol.
Methanol is not identified as a saleable product from the facility, so enough may be produced
only to use as the absorbing fluid in the acid gas unit. The carbon dioxide from the acid gas unit
is compressed and sold for use in enhanced oil recovery operations. Naphtha is also recovered
from the acid gas unit and either sold as a product or used as fuel in boilers and superheaters at
the facility. The gasification process also produces a significant amount of water vapor that is
condensed in the waste heat recovery boilers and other cooling operations. This condensed
water contains coal fines, tars, oils, phenolic compounds, and ammonia. The coal fines, tar, and
tar oil are removed by gravity separation. Coal fines and tar are recycled to the gasifiers, and the
coal tar is used as fuel in boilers and superheaters. The water stream is further processed to
remove crude phenolic compounds and ammonia. The crude phenol stream is further processed
to produce phenol and cresylic acid as saleable products. The ammonia is fed to a flue gas
desulfurization scrubber that is used to remove sulfur dioxide from the boiler exhaust gas. The
water stream from these units is used as make-up water in the plant's cooling tower. The facility
has a total of three boilers and two superheaters.
The syngas that the Eastman facility produces from coal gasification is used to make
methanol and other products derived from methanol. The Eastman facility uses two Texaco
pressurized entrained-flow gasifiers (one on-line and the second on stand-by). A coal slurry and
oxygen are fed to the gasifier. A portion of the raw gas from the gasifier is sent to a water shift
reactor to produce hydrogen. The shifted gas and the unshifted raw gas are sent to separate acid
gas units where most of the carbon dioxide and hydrogen sulfide are removed. The carbon
dioxide is vented to the atmosphere. A portion of the syngas from one of the acid gas units is
sent to a cryogenic unit to separate hydrogen from carbon monoxide. The hydrogen is combined
with the rest of the syngas and sent to the methanol conversion units. The facility has both a
conventional gas-phase conversion unit and a new liquid-phase unit. A portion of the gas that is
not converted in the methanol conversion units is recycled to the units, and the rest is purged to
be used as fuel. Overhead light ends from the methanol purification steps (distillation) are also
collected and used as fuel. Bottoms from the distillation unit contain water, methanol, and a
variety of other organic compounds. This stream is further processed to recover additional
methanol. The methanol product is reacted with acetic acid to produce methyl acetate, and the
methyl acetate is reacted with carbon monoxide from the cryogenic unit to produce acetic
anhydride.
2.6.3 Partial Oxidation22'28
Partial oxidation consists of the incomplete combustion of hydrocarbon to produce
syngas. Steam is used to control the reaction temperature, which leads to additional hydrogen.
Reaction conditions are typically around 1500°C and 150 atmospheres. This process is attractive
11
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because it allows utilization of hydrocarbon feeds that could not be handled in the more
conventional vapor-phase processes, such as steam reforming. Thus, partial oxidation typically
is used to produce syngas from heavy hydrocarbon liquids, but other feedstocks can also be used.
Disadvantages include the cost and soot formation due to thermal cracking of feedstock or the
reversible reaction of carbon monoxide decomposition to carbon and carbon dioxide.
Additionally, sulfur compounds have to be removed downstream before the syngas is converted
to methanol.
The Millenium facility operates a partial oxidation unit that uses natural gas and oxygen
as the feedstocks. A portion of the resulting syngas is separated into a carbon monoxide stream
and a hydrogen-rich stream. The hydrogen-rich stream and the remaining syngas are fed to the
methanol conversion unit. The carbon monoxide and methanol are used to make acetic acid.
3.0 TOTAL EMISSIONS
Petrochemical production accounts for an estimated 55 million metric tons (mmt) of CC>2
equivalent (CC^e) emissions per year, representing less than 1 percent of the total U.S. GHG
emissions of 7,054 million metric tons in 2006.33 The emissions from petrochemical production
operations were estimated by applying the IPCC's default Tier I emission factors for CO2 and
CH4 to each petrochemical production facility in the United States.1 The primary activity data
needed to use these emission factors is the production capacity at the facility. Other important
considerations are the type of feedstock or operating characteristics at each facility. For
example, the CO2 emissions per million pounds of ethylene oxide produced differ depending on
whether the facility feeds oxygen or air to the reactor. Information about operating facilities,
their production capacities, and types of processes was obtained from several resources as noted
in section 2.0. Using this approach, about 95 percent of the CO26 emissions are from CO2, and 5
percent are from CH4.
This approach potentially overstates the total CO26 emissions because the actual
production rate at a facility may be less than its design capacity. At the same time, the approach
may underestimate the total CO26 emissions because N2O emissions from combustion are not
estimated. In their discussion of combustion units, the IPCC estimates the mass of CH4
emissions from burning natural gas or refinery gas to be nearly 10 times higher than the N2O
emissions. However, because the global warming potential (GWP) of N2O is nearly 15 times
greater than the GWP of CH4, the total CO26 emissions from N2O may be as much as 1.5 times
greater than the CO26 emissions from CH4. The default emission factors also do not account for
emissions from flares, but these emissions are expected to be small relative to process emissions
and emissions from combustion units used to supply energy. Another potential limitation is that
the emission factors do not account for CH4 emissions from onsite anaerobic wastewater
treatment systems, but such emissions are expected to be minimal because petrochemical
facilities are not known to use anaerobic wastewater treatment systems. It is not clear if the
emission factors include CO2 emissions from the conversion of organic compounds in aerobic
wastewater treatment systems, but these emissions also are expected to be small. Finally, as
discussed further in section 5 of this report, the uncertainty of the estimates obtained using this
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approach for any individual facility is expected to be higher than for more site-specific
approaches.
The total emissions include both process-based emissions and emissions from
combustion of supplemental fuel. For the purposes of this analysis, process-based emissions
take many forms. For example, CC>2 formed by direct oxidation of ethylene in an ethylene oxide
reactor or the direct oxidation of propylene in an acrylonitrile reactor are process-based
emissions. Methane in the off-gas from an ethylene process is a process-based emission if it is
released unburned from process vents or a combustion unit. Similarly, CC>2 created by burning
the off-gas from any petrochemical process is a process-based emission. Carbon dioxide
emissions from an aerobic wastewater treatment system and the direct release of CO2 and CH4 in
equipment leaks are other forms of process-based emissions. The only emissions that are not
process-based are emissions (CO2, CH/t, and N2O) derived from the combustion of supplemental
fuel. Based on available data it is difficult to estimate the percentage of emissions from specific
process vents, supplemental fuel-fired combustion units, equipment leaks, and wastewater
treatment systems for each process. However, it is clear that process-based emissions dominate
for acrylonitrile, ethylene, and ethylene oxide processes. Both process-based and combustion-
based emissions appear to be significant for carbon black and methanol processes. As noted in
section 2 of this report, essentially all GHG emissions from ethylene dichloride processes are
from combustion of supplemental fuel. Equipment leak and wastewater emissions (although
considered to be a form of process-based emissions) are both estimated to be less than 1 percent
of the total CC^e emissions from petrochemical production.
4.0 OPTIONS FOR REPORTING THRESHOLD
The following four options were evaluated as potential reporting thresholds for
petrochemical facilities:
Option 1. All petrochemical facilities with facility-wide GHG emissions exceeding 1,000
mtCO2e report
Option 2. All petrochemical facilities with facility-wide GHG emissions exceeding 10,000
mtCO2e report.
Option 3. All petrochemical facilities with facility-wide GHG emissions exceeding 25,000
mtCO2e report
Option 4. All petrochemical facilities with facility-wide GHG emissions exceeding 100,000
mtCO2e report
Table 7 illustrates the process and combustion-based GHG emissions from petrochemical
operations at facilities that would be covered under the four options. Based on our analysis, 84
of the 88 petrochemical facilities have estimated GHG emissions greater than 100,000 metric
tons of CO2 equivalent (mtCO2e)/yr, 87 of the 88 facilities have estimated GHG emissions
greater than 25,000 mtCO2e/yr, and all 88 facilities have estimated GHG emissions greater than
1,000 mtCO2e/yr. This information shows the various thresholds do not have a significant effect
on the amount of emissions or the number of facilities that would be covered. Given the
uncertainty in the emissions estimation procedure, we are not certain that even the smallest
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facilities have emissions as low as estimated. Furthermore, the emissions presented in Table 7
are not the total emissions from petrochemical facilities because many of the 88 facilities also
have operations that are part of other source categories. For example, some petrochemical
operations occur at petroleum refineries; the emissions from the refining operations at these
facilities are not included in Table 7. In addition, numerous petrochemical manufacturing
facilities produce other chemicals that are not subject to reporting. These facilities may have
combustion sources for the non-petrochemical production processes that are not included in
Table 7. Similarly, some petrochemical facilities may also make ammonia, hydrogen, or other
products, but emissions from these non-petrochemical processes are not shown in Table 7.
Table 7. Thresholds for GHG evaluation.
Source
Category
Petrochemical
production
Threshold Level,
mtCO2e/yr
>1,000
>1 0,000
>25,000
>1 00,000
Total
National
Emissions
(mmt CO2e)
54.83
54.83
54.83
54.83
Number of
Facilities
88.0
88.0
88.0
88.0
Emissions Covered
mmt
CO2e/year
54.83
54.82
54.82
54.82
Percent
100.0
99.98
99.98
99.7
Facilities Covered
Number
88
87
87
84
Percent
100.0
98.9
98.9
95.5
5.0 OPTIONS FOR MONITORING METHODS
Three options were considered for estimating process-based emissions and emissions
from combustion sources that supply energy to petrochemical processes. The options reflect a
range of monitoring methodologies, and progressing from one option to the next decreases the
amount of uncertainty in the emission estimates. Although other source categories may apply at
certain petrochemical production facilities, such as petroleum refinery units or onsite wastewater
treatment units, options for estimating emissions from these source categories are described in
the technical support documents for the applicable source categories. Procedures for estimating
combustion source emissions, however, are estimated as part of these options because process
and combustion operations are closely related in this source category.
Option 1: Apply a default emission factor based on the type of process and an annual
activity rate (measured or estimated production rate).
Option 2: Perform a carbon balance using all feedstocks and products/byproducts to
estimate emissions containing CO2 derived from the feedstocks, and measure flow and
carbon content of supplemental fuel used in combustion devices that supply energy to a
petrochemical process.
Option 3: Perform direct and continuous measurement of CO2 emissions from each stack
(process vent or combustion source, except flares) using a continuous emission
monitoring system (CEMS) for CO2 concentration and stack gas volumetric flow rate
based on the requirements in 40 CFR part 75, and estimate emissions from flares using
the same procedures as described for petroleum refineries (Subpart Y).
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5.1 Review of existing programs and methodologies
Methodologies were reviewed for measuring or estimating GHG emissions for the
petrochemical production source category developed by different international groups, U.S.
agencies, and others. The 2006 IPCC Guidelines for National Greenhouse Gas Inventories
(Chapter 3.9 Petrochemical and Carbon Black Production) provided methodologies for these
processes.1 Further, the instructions for Form EIA-1605 from the Department of Energy's
Voluntary Reporting of Greenhouse Gases Program recommend using either direct measurement
or IPCC default factors to estimate methane emissions from petrochemical production and CO2
emissions from methanol production. No regulations apply to reporting greenhouse gas
emissions from petrochemical processes.
5.2 Discussion of options for monitoring methods
5.2.1 Option 1
Option 1 is the same as the IPCC Tier 1 approach. Emissions would be calculated using
default CC>2 and CFLi emission factors published by IPCC. These emission factors express the
emissions per metric ton of product produced. Thus, the option is easy to implement because the
only activity data needed in the calculation are plant-specific production rates. In addition, the
cost to implement the option should be low because the monitoring equipment needed to
measure the volume or mass of product is likely already being used. A disadvantage of using
default values instead of direct measurements is that the level of uncertainty is high; default
factors cannot reflect site-specific differences in characteristics such as the type of feedstock,
operating conditions, catalyst selectivity, and thermal/energy efficiencies. Furthermore, these
default factors exclude emissions from process flares and in the case of acrylonitrile, exclude
combustion of auxiliary fuel for process waste gas energy recovery as well. Thus, the use of
default values is more appropriate for sector wide or national total estimates from aggregated
activity data than for determining emissions from a specific facility.
5.2.2 Option 2
Option 2 is derived from IPCC Tier 2, though unlike the IPCC approach, Option 2 does
not consider supplemental fuel as a feedstock in the carbon balance. The supplemental fuel is
not included as a feedstock because these fuels generally do not mix with process fluids, which
means emissions from combusting them can readily be estimated using procedures for
combustion sources.
Inputs for the carbon balance are the flow and carbon content of each feedstock and
product. The difference in carbon content between inputs and outputs is calculated as CO2
emissions, which means that any carbon that is converted to carbon monoxide or CFLi is assumed
to be CO2. Any hydrocarbons that are lost through equipment leaks or discharged to wastewater
are also assumed to be converted to CO2 emissions. Products include the intended petrochemical
as well as byproducts and organic wastes. Feedstocks are generally only a single chemical at any
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given time, but the feedstock may vary over time (particularly for ethylene production). Several
potential issues with this option are described below.
Assuming carbon in VOC equipment leaks is lost as CC>2 means the carbon balance
approach potentially overstates CO2 emissions. To evaluate the significance of the error
introduced by this assumption, we estimated VOC emissions from a model ethylene facility. We
assumed this average facility has approximately 90,000 pumps, valves, and connectors. Total
VOC emissions from this model facility were estimated to be about 140 Mg/yr based on
operation for 8,400 hours/yr and using emission factors that were used to estimate VOC
emissions from these types of equipment in analyses for the equipment leak NSPS in 40 CFR
part 60, subpart VVa. For this analysis, we assumed that the average carbon fraction in the
numerous products from an ethylene process can be characterized by the carbon fraction in
propylene. As a result, if the carbon in the hydrocarbon equipment leaks is assumed to be lost as
CO2, then the CO2 emissions from the model process are overstated by about 440 Mg/yr.
Extrapolating to the 39 ethylene facilities nationwide results in estimated nationwide emissions
of about 17,000 Mg/yr of CO2. This represents only about 0.04 percent of the total estimated
CO26 emissions from ethylene production. Thus, VOC emissions in equipment leaks can be
safely ignored when using a carbon balance to estimate CO2 emissions, even if facilities are not
controlling VOC emissions from equipment leaks to the level required by New Source
Performance Standards in 40 CFR part 60, subpart VVa (or National Emission Standards for
Hazardous Air Pollutants in several subparts in 40 CFR part 63). VOC emissions for other
petrochemical processes are expected to be similar or of even lower magnitude because other
petrochemical processes are expected to have fewer pieces of equipment.
Under this option, emissions from combustion of process off-gas to supply energy to the
process are calculated as process emissions because the process off-gas is not a product (the
option does not include these emissions in estimates of emissions from combustion sources
because there is no easy way to exclude them from the carbon balance). A potential issue with
this approach, however, is that the carbon balance calculates only CO2 emissions, but not CH4
and N2O emissions, from the combustion of process off-gas. As a result, total CO26 emissions
are potentially understated, particularly since the GWPs of CH4 and N2O are much higher than
for CO2. Adding to the potential underestimation is the fact that any CFLt emissions from
unreacted CFLt feedstock or unrecovered CFLt byproduct are assumed to be CO2. However, the
underestimation in the overall CO26 emissions estimate is expected to be small because the
default emission factors for CH4 and N2O from the combustion of refinery gas (comparable to
off-gas from petrochemical processes) are approximately 5 orders of magnitude lower than the
default emissions factor for CO2. Furthermore, although section 3.0 of this report indicates that
about 5 percent of total CO26 emissions are estimated to be from CH4, an unknown portion of
these emissions is from combustion of supplemental fuels in combustion units. Combustion of
supplemental fuels does not contribute to the potential underestimation in total CO26 because
CFLt and N2O emissions from the combustion of supplemental fuels are estimated under this
option in accordance with the procedures for combustion sources.
The uncertainty of emissions estimated using this option will depend on the accuracy of
flow and carbon content measurements and the fraction of input carbon that ends up in products.
A very small uncertainty in any of these measurements could produce large uncertainty in the
16
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emissions estimate. If a large fraction of carbon from the feedstock ends up in the product(s),
this could even result in negative emissions estimates. For most petrochemical processes, the
amount of feedstock carbon that is emitted is estimated to be fairly high—between 15 and more
than 30 percent. For the direct chlorination process to produce ethylene dichloride, however,
only 2.5 percent of the input carbon may not end up in products. Carbon dioxide emitted from
other processes may contain about 5 percent to 6 percent of the carbon in the feedstock.
Typically, it is anticipated that compositional analyses and carbon content methods will be
accurate to plus or minus 1 percent and flow measurements will be accurate to plus or minus 5
percent. Given that sales are based on the amount of material sold, the accuracy of product flow
and compositional analyses may be better than these rates. Table 8 shows the estimated
uncertainties associated with the mass balance approach for each of the petrochemical processes,
assuming 2 percent uncertainty in the input and output flow measurements, 1 percent uncertainty
in the inlet carbon content measurement, and 0.1 percent uncertainty in the product carbon
content measurement. For processes that have high product carbon yields, such as ethylene
dichloride, the mass balance approach has significant uncertainties.
5.2.3 Option 3
Option 3 would require all process vent emissions to be routed to one or more stacks for
direct and continuous measurement of CC>2 emissions from each process vent stack (except
flares) and each combustion source stack (i.e., combustion for energy purposes). Process vent
stacks include uncontrolled stacks as well as stacks following emission control devices such as
thermal incinerators (even if heat is recovered from the exhaust gas) and flares. For flares, this
option requires emissions from combustion of the routine flare gas to be based on annual fuel
consumption (based on company records), a default higher heating value (HHV) for the fuel, and
a fuel-specific emission factor. This calculation method cannot be used to provide accurate
estimates of the GHG emissions released during periods of start-up, shutdown, or malfunction
(SSM) because the flow rate and composition of the gases released to the flare during SSM
events can vary so widely. As such, this option requires a separate engineering calculation of the
GHG emissions from flares that occur during SSM events. In addition to using CEMS to
estimate CO2 emissions from combustion sources, CH4 and N2O emissions from combustion
sources would be estimated using applicable procedures for combustion sources, as described in
the Technical Support Document for Combustion Sources (EPA-HQ-OAR-2008-004). Unlike
Option 2, emissions from the combustion of both process off-gas and supplemental fuels would
be estimated using the procedures for combustion sources. The uncertainty of this option is
estimated to be about 8 percent, assuming uncertainty in measurements for stack velocity, stack
cross-sectional area, CO2 concentration, temperature, pressure, and moisture content of 5
percent, 2 percent, 5 percent, 0.5 percent, 1 percent, and 3 percent, respectively. This option is
similar to the IPCC Tier 3 approach, except that the IPCC guidelines indicate that process vent
emissions may be either estimated or measured, and the IPCC methods for estimating CFLi
emissions from flares are more rigorous.
17
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Table 8. Uncertainty Calculations for Option 2 for Petrochemical Processes.
Petrochemical
Acrylonitrile
Ethylene
Ethylene
dichloride
Ethylene oxide
Methanol
Carbon black
Percentage
of carbon in
feedstock
that ends up
in product(s)
76
76 to 94
(used 85%)
93.5 to 97.5+
(used 95%)
71 to 85
(used 78%)
67
58
Data used to estimate percentage of input
carbon that ends up in products1
0.83 ton CO2 per ton acrylonitrile when HCN is
also recovered
Fraction in products depends on feedstock:
0.267 ton methane produced (and burned) per
ton of propane feedstock. 0.061 ton methane
produced (burned) per ton of ethane feedstock
Fraction in products depends on process: for
direct chlorination, 0.29 ton ethylene yields 1
ton EDC (and some of what is lost may really
be hydrocarbons not CO2) for oxychlorination,
0.302 ton ethylene yields 1 ton EDC
Fraction depends on process and catalyst
selectivity: for lowest selectivity, 0.9 ton
ethylene yields 1 ton EO; for highest
selectivity, 0.75 ton ethylene yields 1 ton EO
According to IPCC, 36.5 GJ from natural gas
needed to produce 1 metric ton of methanol,
1 5.3 kg C per GJ of natural gas, and 0.67
metric ton of CO2 produced per metric ton of
methanol. This includes natural gas that is
burned as well as natural gas converted in
reformer. (Note that when synthesis gas is
produced by partial oxidation of coal or natural
gas, the fraction of carbon in the feedstock
that ends up in the methanol may be
different.)
As for methanol, only factors are for CO2 per
ton of product: 2.62 ton CO2 per ton of carbon
black produced. So if carbon black is all
carbon and the carbon in CO2 and carbon
black accounts for all carbon output, then 58
percent of the carbon input ends up in the
carbon black.
Estimated uncertainty
of emissions
estimated using mass
balance
12%
19%
58%
12%
8%
6%
6.0 MISSING DATA
A complete record of all measured parameters used in GHG emissions calculations is
required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a
substitute data value for the missing parameter must be used in the calculations. The procedures
for estimating missing data vary based on the required monitoring method. In all cases at least
75 percent of all data must be captured on an annual basis (i.e., substitute values may be
estimated for no more than 25 percent of required measurement values).
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6.1 Option 2
The recommended procedures for estimating substitute values to use in place of any
missing feedstock and product flow and carbon content data are the same as for missing fuel
flow and carbon content data, which are provided in the TSD for stationary fuel combustion
sources. In addition, the same procedures are recommended to estimate missing supplemental
fuel flow and carbon content data. For missing carbon content data, the substitute data value
would be the arithmetic average of the quality-assured values of that parameter immediately
preceding and immediately following the missing data incident. If, for a particular parameter, no
quality-assured data are available prior to the missing data incident, the substitute data value
would be the first quality-assured value obtained after the missing data period. For missing
flows, the substitute value would be the best available estimate of the flow rate based on all
available process data. The owner or operator would be required to keep records of the
procedures used for all such estimates.
6.2 Option 3
Required measurement data under Option 3 are the CO2 emissions concentration and the
gas stream flow rate for each CEMS. Total fuel flow and possibly the higher heating value of
the fuel are also required for each combustion unit. Recommended procedures for estimating
missing values for these parameters are the same as for units using Tier 4 in the general
stationary fuel combustion source category. For missing concentration data or fuel heating
value, the substitute data value would be the arithmetic average of the quality-assured values of
that parameter immediately preceding and immediately following the missing data incident. If,
for a particular parameter, no quality-assured data are available prior to the missing data incident,
the substitute data value would be the first quality-assured value obtained after the missing data
period. For missing stack and fuel flow rates, the substitute value would be the best available
estimate of the flow rate based on all available process data. The owner or operator would be
required to keep records of the procedures used for all such estimates. An alternative to the
recommended approach would be to implement the procedures described in Part 75.35(a), (b),
and (d).
7.0 QUALITY ASSURANCE AND QUALITY CONTROL REQUIREMENTS
Facilities must conduct quality assurance and quality control (QA/QC) of the data used in
calculating GHG emission estimates. All facilities are encouraged to prepare an in-depth quality
assurance and quality control plan that contains checks on all information used to determine the
GHG emissions, such as data accuracy (e.g. equipment calibration and data repeatability) and the
calculations performed to estimate the GHG emissions (e.g. to ensure that there are no
computational errors). Thorough QA/QC records should be kept, and these should be made
available for inspection upon request. Examples of QA/QC procedures specific to the
petrochemical source category are listed below. Other applicable procedures may be found in the
TSD for stationary fuel combustion sources.
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7.1 Monitoring of Flow and Composition
For facilities using the mass balance method, Option 2, the owner or operator must
document the procedures used to ensure the accuracy of all measurements made in monitoring
flow and composition of the feed and product streams, such as:
. Measurement of the mass rate of each solid feedstock and product, and volume of
each gas and liquid feedstock and product,
. Calibration of all weighing equipment and measurement devices, both upon initial
compliance and at regular increments thereafter,
. Weekly determination of the carbon content of the feedstock and product or of the
composition by gas chromatograph,
. Documentation of accuracy of weighing equipment and measurement devices, and
. Documentation of equipment maintenance activities.
7.2 CEMS
Applicable QA/QC procedures for CEMS would be the same as for units complying with
the Tier 4 requirements for stationary fuel combustion sources. These procedures include those
that are related to: initial certification of the CC>2 and stack gas flow monitors, periodic
calibrations and audits to ensure the continued accuracy of CC>2 monitors and flow meters,
acquiring and recording data, computing emissions and other pertinent procedures. In addition,
QA/QC procedures for the fuel flow rate and heating value measurements would be the same as
for any other stationary combustion sources, as described in the TSD for stationary fuel
combustion sources.
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6. "Chemical Industry News from the US.: October 2005".
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Attachment A
Estimated Equipment Leak Emissions for Ethylene Production
Ethylene process unit (assume subject to 40 CFR part 63, subpart UU)
Types of equipment Equipment
counts
gas valves
light liquid valves
pumps
flanges
19680
12800
224
60000
Emission
factor,
kg/hr/unit
0.000203
0.000232
0.000695
0.000162
Assumed operating time, hr/yr 8,400
Annual emissions, Mg/yr 141.5
Assume the emissions can be represented as propylene
MW 42
Carbon mass fraction 0.857
Annual CO2 emissions if leaks
were to be captured and burned,
Mg/yr 444.6
Nationwide number of units 39
Nationwide potential CO2 emissions,
Mg/yr 17,339
23
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