PECHAN

5528-B Hempstead Way

Springfield, VA 22151

703-813-6700 telephone

703-813-6729 facsimile

3622 Lyckan Parkway

Suite 2002

Durham, NC 27707

919-493-3144 telephone

919-493-3182 facsimile

P.O. Box 1575

Shingle Springs, CA 95682

530-672-0441 telephone

530-672-0504 facsimile

MARKET TRADING FORUM

NON-UTILITY SECTOR

ALLOCATION

FINAL REPORT FROM THE

ALLOCATIONS WORKING

GROUP

Prepared for:

Western Governors’ Association

1515 Cleveland Place

Denver, CO 80202

Prepared by:

E.H. Pechan & Associates, Inc.

5528-B Hempstead Way

Springfield, VA 22151

November 2002

WGA Contract No. 30204-48

Pechan Rpt. No. 02.11.001/9422.000

iii

CONTENTS

Page

TABLES ......................................................... ........... v

ACRONYMS AND ABBREVIATIONS .......................................... vii

EXECUTIVE SUMMARY ..................................................... ix

CHAPTER I

INTRODUCTION ......................................................... . . I-1

A. ANALYSIS METHODS ............................................... I-1

CHAPTER II

PETROLEUM REFINING ................................................... II-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. II-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... II-1

1. Sulfur Recovery Units ........................................... II-1

2. Fuel Gas Combustion Units ...................................... II-2

3. Catalytic Crackers .............................................. II-3

4. Flares ........................................................ II-3

C. FLOOR ALLOCATION RESULTS .................................... II-3

D. COMPARISON WITH HISTORICAL EMISSIONS ...................... II-10

E. EXAMPLE CALCULATION ......................................... II-10

1. Sulfur Recovery Unit ........................................... II-10

2. Fuel Gas Combustion .......................................... II-10

3. Catalytic Crackers ............................................. II-12

4. Flares ....................................................... II-12

CHAPTER III

LIME MANUFACTURING .................................................. III-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. III-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... III-1

CHAPTER IV

INDUSTRIAL BOILERS AND COGENERATORS ............................... IV-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. IV-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... IV-1

1. Coal Fired Units ................................................ IV-2

2. Oil Fired Units ................................................. IV-2

C. FLOOR ALLOCATION RESULTS .................................... IV-3

D. COMPARISON WITH HISTORICAL EMISSIONS ....................... IV-3

E. EXAMPLE USE OF CAPACITY UTILIZATION DATA FOR FLOOR

ALLOCATION ESTIMATES ......................................... IV-3

CHAPTER V

PULP AND PAPER INDUSTRY ............................................... V-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES .............. V-1

1. Recovery Furnaces ............................................... V-1

2. Lime Kilns ..................................................... V-1

B. FLOOR ALLOCATION ESTIMATION METHODS ........................ V-2

1. Recovery Furnaces ............................................... V-2

2. Lime Kilns ..................................................... V-2

C. FLOOR ALLOCATION RESULTS ..................................... V-2

D. COMPARISON WITH HISTORICAL EMISSIONS ........................ V-4
iv

CONTENTS (continued)

Page

CHAPTER VI

CEMENT MANUFACTURING ............................................... VI-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. VI-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... VI-1

C. FLOOR ALLOCATION RESULTS .................................... VI-1

D. COMPARISON WITH HISTORICAL EMISSIONS ....................... VI-4

CHAPTER VII

NATURAL GAS PROCESSING PLANTS ..................................... VII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............ VII-1

B. FLOOR ALLOCATION ESTIMATION METHODS ...................... VII-1

C. FLOOR ALLOCATION RESULTS ................................... VII-2

1. General Plants ................................................ VII-2

2. Specific Example .............................................. VII-3

D. COMPARISON WITH HISTORICAL EMISSIONS ...................... VII-3

CHAPTER VIII

ELEMENTAL PHOSPHORUS PRODUCTION ............................... VIII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ........... VIII-1

B. FLOOR ALLOCATION ESTIMATION PROCEDURES ................. VIII-1

CHAPTER IX

GLASS MANUFACTURING ................................................. IX-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. IX-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... IX-2

CHAPTER X

COPPER SMELTERS ....................................................... X-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES .............. X-1

B. FLOOR ALLOCATION ESTIMATION METHODS ........................ X-1

C. COMPARISON WITH HISTORICAL EMISSIONS ........................ X-2

CHAPTER XI

ALUMINUM PRODUCTION ................................................ XI-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............. XI-1

B. FLOOR ALLOCATION ESTIMATION METHODS ....................... XI-2

CHAPTER XII

SULFURIC ACID PLANTS ................................................. XII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ............ XII-1

B. FLOOR ALLOCATION ESTIMATION METHODS ...................... XII-2

CHAPTER XIII

METALLURGIC COKE PRODUCTION ..................................... XIII-1

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES ........... XIII-1

1. By Product Coke Ovens ........................................ XIII-1

2. Rotary Calciners .............................................. XIII-1

B. FLOOR ALLOCATION ESTIMATION METHODS ..................... XIII-2

C. COMPARISON WITH HISTORICAL EMISSIONS ..................... XIII-3

CHAPTER XIV

FLOOR ALLOCATION SUMMARY .......................................... XIV-1
v

TABLES

Page

I-1 Methodology for the Calculation of the Floor Allocations for Non-Utility Sources I-3

II-1 Sulfur Plants - Required Minimum SO2

 Emission Reduction Efficiency ...... II-2

II-2 Petroleum Refining Floor Allocation Calculation ......................... II-4

II-3 Petroleum Refineries – Historical Emissions – 1990 to 2000 .............. II-11

III-1 Emission Factors for Lime Manufacturing .............................. III-3

III-2 Lime Manufacturing - Historical Emissions - 1990 to 2000 ................. III-4

IV-1 Assumed Level of Control for SO2 Floor Allocation ....................... IV-2

IV-2 Facility SO2

 Floor Allocation Estimation for ICI Boilers ................... IV-5

IV-3 Comparison of SO2 Floor Allocation with Historical Emissions for ICI Boilers . IV-7

IV-4 Example Use of Capacity Utilization Data for Floor Allocation Estimates .... IV-9

V-1 Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Unit Capacity Values ........................................ V-3

V-2 Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Fuel Throughput ............................................ V-3

V-3 Pulp and Paper - Historical Emissions - 1990 to 2000 ...................... V-5

VI-1 Floor Allocations ................................................... VI-2

VI-2 Cement Manufacturing - Historical Emissions - 1990 to 2000 .............. VI-3

VI-3 Example Calculation ................................................ VI-4

VII-1 Sulfur Plants - Required Minimum SO2

 Emission Reduction Efficiency ..... VII-2

VII-2 Possible Floor - Natural Gas Processing Units .......................... VII-4

VII-3 Oil and Gas Production - Historical Emissions - 1990 to 2000 ............. VII-6

VIII-1 Elemental Phosphorus Production - Historical Emissions - 1990 to 2000 ... VIII-2

IX-1 Glass Manufacturing - Historical Emissions - 1990 to 2000 ................ IX-3

X-1 Copper Smelter SO2 Emission Projections (tpy) ........................... X-2

X-2 Recent Historical Copper Smelter SO2 Emissions ......................... X-3

XI-1 Aluminum Plant Data Used to Estimate Floor Allocations ................. XI-4

XI-2 Aluminum Smelting - Historical Emissions - 1990 to 2000 ................. XI-5

XII-1 Sulfuric Acid Plants ................................................ XII-3

XIII-1 Historical SO2 Emissions at P4 Production, Rock Springs, WY ............ XIII-2

XIII-2 Coking Plant - Historical Emissions - 1990 to 2000 ..................... XIII-3

XIV-1 State/Sector Summary of SO2 Floor Allocations (tons per year) ............ XIV-2

XIV-2 Facility-Level SO2 Floor Allocations - Comparison with Year 2000

SO2 Emissions (tons per year) ........................................ XIV-3
vi
vii

ACRONYMS AND ABBREVIATIONS

BACT Best Available Control Technology

BART Best Available Retrofit Technology

BLS Black liquor solids

CAA Clean Air Act

CWPB center-worked prebake cells

DCE Direct contact evaporator

dscf dry standard cubic foot

ESPs electrostatic precipitators

FCCU fluid catalytic cracking unit

GCVTC Grand Canyon Visibility Transport Commission

H2S hydrogen sulfide

HSS horizontal stud Soderberg

ICI industrial, commercial, and institutional

kg kilogram

LAER Lowest Achievable Emission Reduction

lbs/MMBtu pounds per million British thermal units

Mg megagram

MTF Market Trading Forum

NOxoxides of nitrogen

NSPS New Source Performance Standards

ppm parts per million

ppmv parts per million volume

PTE potential to emit

RECLAIM Regional Clean Air Incentives Market

SCC Source Classification Code

SIC Standard Industrial Classification

SIP State Implementation Plan

SO2sulfur dioxide

SRU Sulfur Recovery Unit

SWPB side-worked prebake cells

tpy tons per year

VSS vertical stud Soderberg

WGA Western Governors’ Association

WRAP Western Regional Air Partnership
viii
ix

EXECUTIVE SUMMARY

This study was performed for a Working Group of the Western Regional Air

Partnerships’ (WRAP) Market Trading Forum. It provides a current, best estimate of the

floor allocation for non-utility sources in the region that would be established if western

States and tribes adopt a regional, backstop trading program for sulfur dioxide (SO2

) to

meet the requirements of Section 309 of the regional haze rule. The major SO2 emitting

non-utility source categories evaluated in this study include the following: petroleum

refineries, lime manufacturing, industrial boilers and co-generators, pulp and paper

manufacturing, cement manufacturing, natural gas processing and oil and gas production,

elemental phosphorus production, glass manufacturing, aluminum smelters, sulfuric acid

plants, and coke production. Of these industry sectors, phosphorus, aluminum smelters,

sulfuric acid plants, and coke production plants were not considered in the original source

categories for the Market Trading Forum. The floor control technology (or emission rate or

SO2 control effectiveness) was determined by evaluating the emissions performance of other

sources in that source category in the western States. The floor is defined to be best

available control technology (BACT), best available retrofit technology (BART), or lowest

achievable emission rate (LAER) for existing sources. For some sources, EPA has not

determined what these levels of emissions are. SO2

 floor allocations were computed for

each of about 200 major non-utility sources in the western States, where major is defined as

those sources emitting greater than 100 tons per year (tpy).

While this analysis uses plant and process-level information to estimate floor

allocations, if the backstop trading program is triggered, SO2

 allowances under the trading

program will be allocated by the participating transport region States and Tribes at that

time. This study is only an approximation of how the allocations might be made based

upon the limited information that we have today. It is expected that the States and Tribes

would be able to obtain more detailed information about current emissions and controls for

these non-utility sources than has been available for the current project.

The floor allocation analysis has been performed separately for each of the 12 major

non-utility source categories in the west. The text below summarizes the key findings for

each source category.

To simplify the analysis, it was determined that California SO2

 sources are already

highly controlled. The California floor allocation of 27,335 tpy is based on the opt-in/out

2018 SO2 allocation that has been estimated previously by the WRAP Market Trading

Forum.

Petroleum Refining: There are ten petroleum refineries outside California in the

WRAP transport region. Data were received from all of these refineries for the allocation

process. These floor allocations were computed for each of the four major SO2 emitting

processes at refineries: sulfur plants, fluidized catalytic cracking units (FCCUs), fuel

combustion units, and flares. The SO2 floor allocation for these ten refineries is 11,418 tpy,

or about 5,400 tpy less than historic emissions during 1996 to 2000. This is one of the best

characterized source categories.

Cement Manufacturing: The control technology analyses for cement kilns showed that

there was no demonstrated SO2 control technique at western State sources that could be

applied to reduce SO2 across the source population. There are widely varying SO2

emissions rates from these kilns, and the process itself removes sulfur from the off gas. As

a result, this sector’s floor allocation of 7,761 tpy was based on recent historic emissions. 

The analysis for lime manufacturing reached the same conclusion as that for cement. The

lime manufacturing floor allocation is 2,103 tpy.
x

Boilers and Co-generators: The floor for boilers and co-generators at industrial

facilities was estimated by applying the equivalent of 85 percent SO2

 control to coal and oilfired sources not already at, or near, this control level. Average capacity factors were used

to estimate boiler utilization for estimating the floor with a 5 percent growth margin. This

assumption is consistent with that used in the utility boiler floor allocations. Some nonutility boilers are operating at low utilization rates. The industrial boiler and cogenerator

floor allocation is 7,910 tpy.

Pulp and Paper Industry: Recovery furnaces and lime kilns are the SO2 sources at the

Kraft pulp mills in the west. Most of these mills are in Oregon. Floor allocations for

recovery furnaces and lime kilns are based on standard U.S. Environmental Protection

Agency (EPA) emission factors and 100 percent capacity utilization (or recent annual

throughput, if capacity estimates were not available). The pulp and paper floor allocation is

7,184 tpy.

Natural Gas Processing Plants and Oil and Gas Production: SO2 emissions from

natural gas processing plants result from combustion of sour gases. It was decided that the

current New Source Performance Standard (NSPS) would serve as the floor. The NSPS

requires a variable sulfur removal efficiency based on the hydrogen sulfide (H2S) content of

the acid gas and the amount of sulfur in the gas. If a facility had current control levels

higher than the assumed floor, the actual average emissions over the past three years were

used to estimate the floor. Since emissions from flaring operations both in the plant and

the well field are not amenable to control, floor emissions are assumed to be the average of

the emissions in three recent years. Data availability was a significant issue in

determining the floor allocations for some gas plants. The floor allocation for this source

category is 28,884 tpy.

Elemental Phosphorus Production: One of the two U.S. elemental phosphorus

production facilities is in Idaho. Because of the uniqueness of this facility, no floor control

technology was identified. The floor allocation is set at year 2000 SO2 emissions, which

were 15,861 tpy. It is expected that the State of Idaho will perform a more detailed

evaluation of this facility during preparation of its regional haze State Implementation

Plan (SIP).

Glass Manufacturing: The major source of SO2 emissions in the glass industry is the

glass melting operation. There are only two active glass manufacturing facilities in the 8

non-California WRAP States. With a lack of information about SO2 control techniques in

practice, the floor allocation for glass manufacturing plants was set according to historical

SO2 emissions. The glass manufacturing floor allocation is 368 tpy.

Copper Smelters: Because of the uniqueness of the existing copper smelters, retrofit

technology analysis must be performed on a smelter-by-smelter basis. A double contact

acid plant is considered the appropriate retrofit control equipment. All copper smelters in

the western States are currently equipped with double contact acid plants. The current

year SO2 allocation for the six copper smelters in the 9-State region is 86,000 tons. This

allocation is reduced to 78,000 tons by 2013 and is the same in 2018.

Aluminum Production: There are only 2 primary aluminum plants in the study region

and both are located in Oregon. The primary SO2 source in aluminum production is the

sulfur in the coke, and the coal tar pitch binder used to produce the anodes. The floor

control technology for aluminum smelters was determined by evaluating the emissions

performance at the two Oregon facilities. One facility uses a wet scrubber to achieve a 70

percent SO2 emission reduction. Therefore, a wet scrubber with a 70 percent SO2 reduction

was selected as the floor technology for aluminum smelters. The aluminum smelter floor

allocation is 2,076 tpy.

Sulfuric Acid Plants: The only significant source of air emissions from a contact

sulfuric acid plant is the tail gas leaving the final absorbing tower. This gas contains small

amounts of SO2 and even smaller amounts of sulfur trioxide, sulfuric vapor, and sulfuric
xi

acid mist. Based on the information available for the 4 sulfuric acid plants in the west, it

was decided that the floor allocation should be estimated by applying the NSPS

requirements to each sulfuric acid plant. Achieving this standard requires a conversion

efficiency of 99.7 percent in an uncontrolled plant, or the equivalent SO2 collection

mechanism in a controlled facility. However, recent historical SO2 emissions for these

facilities were lower than the NSPS emission rate times capacity estimated values, so the

sulfuric acid plant floor was estimated using these historical SO2 emission values. The

resulting floor allocation for these sulfuric acid plants is 5,386 tpy.

Metallurgic Coke Production: SO2 emissions from coke oven operations primarily result

from combustion of the byproduct coal gas in the oven. There were three coke production

facilities operating in the west during the 1990s. Coke production has recently ceased at

two of these facilities. The only facility that continues to operate is a rotary calciner in

Wyoming. Because of the uniqueness of this operation, the floor allocation is based on

recent historic SO2

 emissions, and is 631 tpy.

There are two benchmarks that can be used to put the floor allocations in perspective. 

One is year 2000 historic emissions and the other is the non-utility SO2

 emissions forecast

for 2018. The floor allocation estimate in this report is about 2,500 tons higher than year

2000 historical emissions. However, this comparison of the respective emission totals is

skewed by the fact that year 2000 copper smelter emission were about one-half of the 78

thousand ton allocation for this sector. When copper smelters are removed from the totals,

the floor allocation is about 45 thousand tons lower than year 2000 emissions. A

comparison of the floor allocation with the SO2 emissions in the 2018 opt-in/out emission

allocations shows that the floor allocation is approximately the same.
xii
I-1

CHAPTER I

INTRODUCTION

This report describes an analysis that was prepared for a Working Group of the

Western Regional Air Partnership’s (WRAP) Market Trading Forum (MTF). It provides the

current best estimate of the floor allocation for non-utility sources in the region that would

be established if western States and tribes adopt a regional, backstop trading program for

sulfur dioxide (SO2

) to meet the requirements of Section 309 of the regional haze rule. Note

that this does not establish final allocations for sources in the region. Each State and tribe

will determine the appropriate floor level for sources within their jurisdiction, and will

include this information in their State or tribal implementation plan. The program is

voluntary for western States and tribes. Information is provided to assist eligible States

and tribes evaluate the impacts of the program, but decisions to participate in the program

will be made by each separate jurisdiction.

The distribution of regional SO2 allowances to existing sources in the nine Commission

Transport States is composed of two portions: floor and reducible allocation. There are two

components of the floor allocation - an allocation for the California Regional Clean Air

Incentives Market (RECLAIM) program, and source-specific floor allocations for nonRECLAIM sources. The floor allocation is a minimum allocation for all existing sources,

which will be calculated to ensure that well-controlled sources will receive a full allocation.

California RECLAIM Program: 3,462 SO2

 allowances will be included in the California

budget for RECLAIM sources. These credits will be a subset of the existing source pool for

the State of California and, hence, will not consume any extra credits from the total credit

pool.

Source-specific Floor Allocation: A floor allocation will be calculated for all existing

sources in the region based on some specified level of control (e.g., Best Available Control

Technology [BACT], Best Available Retrofit Technology [BART], Lowest Achievable

Emission Reduction [LAER]) for non-utility sources.

The sources affected by the backstop trading programs are all those stationary sources

in participating States and tribes that emit SO2

 in an amount greater than or equal to 100

tons per year (tpy). The 100 ton cut off will be assessed at the plant level to correspond

with the methodology used in the 1990 emissions inventory. Among the source types

covered by this definition are utility and industrial boilers, refineries, smelters, pulp and

paper mills, cement and lime kilns, and all of the other source categories listed in section

169(g)(7) of the Clean Air Act (CAA).

In this report, the geographic area of analysis is defined to be the nine Commission

Transport Region States, which are Arizona, California, Colorado, Idaho, Nevada, New

Mexico, Oregon, Utah, and Wyoming. Facilities included in the analysis are those that

emitted 100 tpy or more of SO2 sometime during the period 1990 to 2000. Plants that are

electric utilities are excluded from this analysis.

A. ANALYSIS METHODS

The floor allocation analysis for the non-utility sector was performed using the

following steps:

1. It was assumed that the SO2 sources in the State of California are already at the

floor. This is expected because of the stringency of the air emission regulations in

that State.
I-2

2. Because copper smelter allocations for 2018 have already been determined, no

additional analyses were performed for copper smelters. Smelter allocations are

presented in Chapter X.

3. The focus of the analysis was on non-California, non-smelter facilities that had at

least 100 tpy of SO2

 emissions during at least one year in the period 1990 to 2000. 

States included in this analysis were Arizona, Colorado, Idaho, Nevada, New

Mexico, Oregon, Utah, and Wyoming.

4. The major SO2 emitting non-utility source categories evaluated in this study

included the following: petroleum refineries, lime manufacturing, industrial

boilers and co-generators, pulp and paper manufacturing, cement manufacturing,

natural gas processing and oil and gas production, elemental phosphorus

production, glass manufacturing, aluminum smelting, sulfuric acid production, and

metallurgical coke production.

5. The floor control technology or emission rate or SO2 control effectiveness was

determined by evaluating the emissions performance of other sources in that

source category in the western States. The floor is defined to be BACT, BART, or

LAER for existing sources. The floor for each of the major source categories is

summarized in Table I-1.

6. The primary source of emissions information for the western States is the 1996

WRAP point source inventory. The 1996 emission estimates were prepared under

contract to the Western Governors’ Association (WGA) by Pacific Environmental;

Services and Eastern Research Group, Inc. under contract to the WGA (PES,

2001). However, this data set was not sufficient for providing all of the

information needed to compute the floor allocation for each source. The State air

pollution control agencies in each of the 8 States were contacted to obtain

supplementary data. For most source categories, this additional information

included estimates of unit capacities. This could be either the design capacity for

boilers, or the production capacity for industrial processes.

7. Once data was received from the State agencies, it was used to estimate the floor

allocation by source and facility based on the control technologies listed in Table

I-1 and the unit or plant-specific information about existing capacities and SO2

control techniques.

The chapters that follow explain the floor allocation analyses for each of the key

industrial sector source categories in the western United States.
I-3

Table I-1

Methodology for the Calculation of the Floor Allocations for Non-Utility Sources

Source Category Technologies or Standard for Floor

Copper Smelters Due to the uniqueness of the existing smelters, retrofit technology

analysis must be perform ed on a smelter-by-smelter basis. 

Currently, the Hidalgo smelter is the only BART-eligible source on

the list in this category. A double-contact acid plant will be

considered the appropriate retrofit control equipment (all sm elters in

the region are currently equipped with double-contact acid plants). 

On August 21, 2000, New Mexico completed an engineering

analysis that verified earlier determinations by the MTF that the

fugitive SO2 capture system at Hidalgo satisfies BART at 96%

overall capture.

Refineries There are four sources of SO2 emissions at the refinery level. Floor

based upon New Source Perform ance Standards (NSPS) where

applicable.

Description Assumed Average Control Level

Sulfur Recovery Unit (SRU) Meet NSPS Subpart J or the

equivalent of 3-stage Claus units with

a tail gas unit (NSPS and the tail gas

unit does not apply to Claus units

smaller than 20 long tons/day or less).

Fuel gas com bustion units Fix at the NSPS emission limit rate of

0.027 pounds per million British

thermal units (lbs/MMBtu) assuming

fuel gas input and not fuel oil.

Catalytic crackers NSPS (J) selected 9.8 lbs of SO2 per

1,000 lbs of coke burned.

Flares Based upon average of the last 5

years' emission, AP42 factors for

calculated. No additional controls.

Natural Gas Processing Description Assumed Average Level of Control

Process Emissions Reduction to satisfy NSPS. Variable

reduction depending on hydrogen

sulfide (H2S) content and plant size. 

Flaring Based upon average of the last 5

years' emission.

Oil & Gas Production Description Assumed Average Level of Control

Flaring Based upon average of the last 5

years' emission.

Lime Plants No additional reduction. Approximately 50% control inherent in the

process. Additional SO2

 controls are not in place at lime plants in

the western States.
Table I-1 (continued)

Source Category Technologies or Standard for Floor

I-4

Industrial Boilers (Cogens) Technology determination dependent upon current level of control.

Description Assumed Average Level of Control

Uncontrolled Units 85%

Units controlled at less than

70%

Treat as uncontrolled (see above).

Units controlled between

70-80%

Increase reductions by 5% (i.e., if a

unit is at 72%, would be assumed to

control to 77%).

Units controlled greater

than 80%

No additional reductions.

Pulp and Paper Sulfur sources are recovery furnaces and boilers. Boiler discussions

covered with industrial boilers.

Recovery Furnaces: No additional reduction. Low emissions

coupled with lack of more than one example of scrubbing.

Cement Plants No additional reduction. Approximately 70-90 percent control

inherent in the process. Additional SO2 controls are not typically

applied to these levels of processes.

Aluminum Smelters A wet scrubber with a 70 percent SO2

 emission reduction selected

as the floor based on achieved control levels at NW Aluminum in

Oregon.

Sulfuric Acid Plants No additional reduction. Existing units are already controlled to

NSPS levels (4 lbs per ton of 100% acid produced).

Coke Production Only one facility is still operating. Because of the uniqueness of this

rotary calciner, the floor allocation is established at historic SO2

emission levels.
II-1

CHAPTER II

PETROLEUM REFINING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The petroleum refining industry involves numerous processes that convert crude oil

into more than 2,500 products, including gasoline, liquefied petroleum gas, kerosene, jet

fuel, diesel fuel, other fuel oils, lubricating oils, and feed stock for the petrochemical

industry. Petroleum refinery activities include the storage of crude oil at the refinery,

petroleum handling and refining operations, and storage of the refined products prior to

shipment. As of January 1990, there were 189 operating refineries in the United States

with a total crude capacity of 15.4 million barrels per calendar day.

Removal of sulfur from refinery streams is a part of refining. It would be desirable to

remove all sulfur compounds before any crude processing begins, but because this is

impractical, sulfur is removed throughout the refining process. There are several reasons,

besides air pollution control, for removing sulfur from intermediate fractions and products

of crude oil. Sulfur removal reduces corrosion, odor, breakdown frequency, catalyst

poisoning, and gum formation and improves octane rating, color, and lube oil life.

B. FLOOR ALLOCATION ESTIMATION METHODS

There are four possible unit types (SO2 emission points) within a refinery, as noted in

the methodology for the calculation of the floor allocations for non-utility sources. These

four SO2

 sources are: (1) the SRU; (2) fuel gas combustion units; (3) catalytic crackers; and

(4) flares. The approach for estimating SO2 floor allocations is unique for each of these four

SO2 source types within the refinery. Floor calculation methods are presented below for

each of these four source types.

1. Sulfur Recovery Units

Sulfur recovery refers to conversion of H2S to elemental sulfur. H2S is a by product of

processing natural gas and refining high sulfur crude oils. The most common conversion

method used is the Claus process. Approximately 90 to 95 percent of recovered sulfur is

produced by the Claus process. The Claus process typically recovers 95 to 97 percent of the

H2S feed stream.

The average production rate of a sulfur recovery plant in the United States varies from

51 to 203 megagrams (Mg) (56 to 224 tons) per day. Some of the small to mid-sized

refineries in the western States have sulfur plant capacities that are lower than these

average values.

The SO2

 floor allocation for SRUs depends on the size of the sulfur plant. For sulfur

plants of 20 long tons per day or larger, the NSPS require a 3-stage Claus unit with a tail

gas unit. Existing NSPS limit sulfur emissions from Claus sulfur recovery plants of greater

than 20.32 Mg (22.40 tons) per day capacity to 0.025 percent by volume (250 parts per

million volume [ppmv]). The NSPS and tail gas unit do not apply to Claus units smaller

than 20 long tons per day or less. For these smaller sulfur plants, the SO2

 floor allocations

are estimated as 95 percent SO2 control.

Table 8.13-1 in AP-42 provides the following SO2

 emission factors for modified Claus

Recovery Plants:
II-2

Emission Factors for Modified Claus Sulfur Recovery Plants

SO2

 Emissions

Number of 

Catalytic Stages

Average %

Sulfur Recovery

Kilograms (kg)/Mg of

Sulfur Produced

lbs/ton of

Sulfur Produced

1, Uncontrolled 93.5 139 278

3, Uncontrolled 95.5 94 188

4, Uncontrolled 96.5 73 145

2, Controlled 98.6 29 57

3, Controlled 96.8 65 129

The SO2

 emission factor for 99.8 percent sulfur recovery is 8 lbs/ton and for 96.8

percent sulfur recovery is 132 lbs/ton of sulfur produced. This emission factor value is

multiplied by the sulfur plant capacity in tons per day, 365 days per year, and 1 ton per

2,000 lbs to arrive at an annual SO2 emissions floor estimate. Equation (1) below shows the

above description as a formula:

For refineries with sulfur plants smaller than 20 long tons per day, and lower H2S

contents in their acid gas, an SO2

 control level of 96.8 percent may not be achievable. In

that situation, an alternative way to calculate the floor is to use the sulfur feed rate and the

H2S content of the acid gas of the affected facility to compute the appropriate minimum SO2

reduction efficiency using the relationships shown in Table II-1. This table is from the

NSPS for onshore natural gas production.

Table II-1

Sulfur Plants - Required Minimum SO2 Emission Reduction Efficiency

H2S Content of

Acid Gas (Y), %

Sulfur Feed Rate (x), Long Tons per Day

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 74.0

. . . . . . . 85.35X0.0144Y0.0128 . . . . . . .

or 99.8, whichever is smaller

20<Y<50 74.0

. . . . 85.35X0.0144Y0.0128 . . . .

or 97.5, whichever is smaller 97.5

10<Y<20 74.0

85.35X0.0144Y0.0128

or 90.8, whichever is smaller 90.8 90.8

Y<10 74.0 74.0 74.0 74.0

2. Fuel Gas Combustion Units

Fuel gas combustion units in refineries were defined to include all process heaters and

boilers, and their combined oil and gas combustion capacity. SO2

 floor allocations are

estimated as the combined oil and gas combustion capacity multiplied by 0.027 lbs/MMBtu. 

This emission rate is an approximation of the SO2 emission factor for a fuel gas combustion

unit meeting the NSPS of 0.10 grains H2S per dry standard cubic foot (dscf) as required by

40 CFR 60 Subpart J.

This H2S value is converted to an SO2

 emission rate in lbs/MMBtu using the equation

below:
II-3

In the floor allocation estimates for fuel gas combustion units, the fuel gas combustion

capacity is based on reported values for the refineries in Colorado, New Mexico, and Utah

as well as for Wyoming Refining and Frontier Refining in Wyoming. Where this value has

not been reported, it is estimated to be 5 percent of the crude oil processing capacity at that

refinery. The industry norm is reported to be in the range of 5 to 10 percent. The 5 percent

value was used because it is the average value for the western State refineries for which

data on fuel gas combustion capacity were provided.

3. Catalytic Crackers

The SO2

 floor allocation for catalytic crackers at petroleum refineries is computed using

the NSPS for fluid catalytic cracking units (FCCUs). The NSPS for FCCUs without add-on

controls is 9.8 kg SOx per 1,000 kg coke burn-off. For FCCUs without add-on control

devices, EPA decided that the regulated pollutant should be SOx

, because SO3

 could

constitute a significant portion of the total SO2 emissions from FCCUs using SOx reduction

catalysts. The standard for FCCUs without add-on controls requires the use of Method 8 to

determine the total SOx

 emissions from affected facilities.

One of the issues in applying the NSPS emission rate to estimate the SO2

 floor

allocation is the availability of information about the amount of coke burn-off for each

FCCU. The Source Classification Code (SCC) units used in emission inventories, and AP42 SO2

 emission factors, are expressed as lbs/1,000 barrels of fresh feed. Therefore, it is

necessary to develop a conversion factor to go from an emission limit expressed as an SOx

emission rate per 1,000 kg coke burn-off to an emission limit expressed in AP-42 or SCC

units if the coke burn rate is not available for a refinery.

In order to apply the NSPS SO2 emission rate to estimate the floor allocation for

FCCUs, information about the coke burn rate was needed for each refinery. For 10 of the

Western State refineries listed in Table II-1, estimates of the coke burn rate in pounds per

hour were available from a data set that the American Petroleum Institute provided to EPA

as part of the MACT standard setting process. These coke burn rates are based on 1997

operations. For the refineries with FCCUs and no coke burn rate available, the coke burn

rates were estimated using the relationship between the FCCU feed capacity in barrels per

calendar day and the coke burn rate (pounds per hour) for the 10 western refineries with

reported values. The relationship used was 16 pounds coke per barrel of oil. Refineries

where this default value was applied included the two Colorado refineries and Flying J, Inc.

in Utah. Wyoming Refining provided a design coke burn rate for its FCCU.

4. Flares

Flares are commonly used for the disposal of waste gases during process upsets and

emergencies. They are basically safety devices that are also used to destroy organic

constituents in waste emission streams. The AP-42 SO2 emission factor for a vapor

recovery system and flaring is 26.9 lbs per 1,000 barrels refinery feed. This emission factor

is applied to estimate the SO2

 emissions floor for flares at each refinery.

C. FLOOR ALLOCATION RESULTS

Table II-2 includes the floor allocation calculation for the refineries in the 8 nonCalifornia Western Regional Air Partnership (WRAP) States. The Oil & Gas Journal

Worldwide Refining Survey for 2000 provided the values for sulfur plant capacity, catalytic

cracking unit capacity, and crude capacity listed in Table II-2 where they were not

otherwise provided by State air agencies or refinery companies. Fuel gas combustion

capacities in MMBtu/hour (hr) are estimated using information provided by State air

pollution control agencies. Sinclair Corporation provided data for its two Wyoming

refineries (Greene, 2002).
II-4

Table II-2

Petroleum Refining Floor Allocation Calculation

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

Cono co Inc. Co mmerce C ity CO Sulfur R eco very U nit 70 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2 per ton

sulfur produced

102.2

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

112.9

 Oil MMBtu/hr

 Total 955 MMBtu/hr

FCCU 12,666 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

554.8

Flares 57,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

282.3

All Sources Combined 1,052.2

Colorado Refining Denver CO Sulfur R eco very U nit 4 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

96.4

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2

 per

million Btu

60.2

 Oil MMBtu/hr

 Total 509 MMBtu/hr

FCCU 5,333 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per coke

burn off

233.6

Flares 35,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

171.8

All Sources Combined 562.0

Giant Refining Co. Bloom field NM Sulfur R eco very U nit 2 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

48.2

Fuel Gas Combustion

 Gas 328 MMBtu/hr 0.027 lbs of SO2 per

million Btu

38.8

 Oil MMBtu/hr
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-5

 Total 328 MMBtu/hr

FCCU 5,400 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

236.5

Flares 18,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

90.8

All Sources Combined 414.3

Giant Refining Co. Gallup NM Sulfur R eco very U nit 2 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

48.2

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

37.3

 Oil MMBtu/hr

 Total 315 MMBtu/hr

FCCU 8,200 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

359.2

Flares 32,200 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

158.1

All Sources Combined 602.7

Navajo Refining Co. Artesia NM Sulfur R eco very U nit 140 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2 per ton

sulfur produced

204.4

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

109.3

 Oil MMBtu/hr

 Total 924 MMBtu/hr

FCCU 13,000 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

569.4

Flares 70,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

343.6
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-6

All Sources Combined 1,226.7

BP/now Tesoro Petroleum Sa lt Lake City UT Sulfur R eco very U nit 17.4 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

419.2

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

100.0

 Oil MMBtu/hr

 Total 846 MMBtu/hr

FCCU 14,000 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

613.2

Flares 52,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

255.3

All Sources Combined 1,387.7

Chevron Products Co. Sa lt Lake City UT Sulfur R eco very U nit 22.4 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

539.6

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

145.9

 Oil MMBtu/hr

 Total 1,234 MMBtu/hr

FCCU 6,500 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

284.7

Flares 55,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

270.0

All Sources Combined 1,240.3

Silver Eagle Refining Inc. W ood s Cro ss UT Sulfur R eco very U nit 0 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

0.0

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

15.6
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-7

 Oil MMBtu/hr

 Total 132 MMBtu/hr

FCCU 0 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

0.0

Flares 12,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

61.4

All Sources Combined 77.0

Flying J Inc. Sa lt Lake City UT Sulfur R eco very U nit 7 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

168.6

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

57.8

 Oil MMBtu/hr

 Total 489 MMBtu/hr

FCCU 7,533 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn

329.9

Flares 24,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

117.8

All Sources Combined 674.2

Phillips Petroleum Co. W ood s Cro ss UT Sulfur R eco very U nit 14 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2

 per ton

sulfur produced

337.3

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

83.4

 Oil MMBtu/hr

 Total 705 MMBtu/hr

FCCU 5,000 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

219.0

Flares 25,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

122.7
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-8

All Sources Combined 762.4

Frontier Refining Inc. Cheyenne W Y Sulfur R eco very U nit 110 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2 per ton

sulfur produced

160.6

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

155.5

 Oil MMBtu/hr

 Total 1,315 MMBtu/hr

FCCU 7,330 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

321.1

Flares 46,000 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

225.8

All Sources Combined 863.0

Sinclair Oil Corp. Casper W Y Sulfur R eco very U nit 21.7 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

522.8

Fuel Gas Combustion

 Gas MMBtu/hr 0.027 lbs of SO2

 per

million Btu

77.1

 Oil MMBtu/hr

 Total 652 MMBtu/hr

FCCU 7,590 Coke Burn R ate (lbs/hr) 20 lbs of SO2

 per ton

coke burn off

332.4

Flares 22,000 Based on 2001

operations (bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

108.0

All Sources Combined 1,040.3

Sinclair Oil Corp. Sinclair W Y Sulfur R eco very U nit 52.6 Su lfur plant capacity

tons sulfur per day

8 lbs of SO2

 per ton

sulfur produced

76.8

Fuel Gas Combustion
Table II-2 (continued)

Plant Name City State Source Type Plant/Unit Capa city Capacity Notes

Floor Allocation

Em ission Rate

Emission

Rate Units

Floor allocation

tons/year

II-9

 Gas MMBtu/hr 0.027 lbs of SO2 per

million Btu

119.9

 Oil MMBtu/hr

 Total 1,014 MMBtu/hr

FCCU 13,120 Coke Burn R ate (lbs/hr) 20 lbs of SO2 per ton

coke burn off

574.7

Flares 60,000 Based on 2001

operations (bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

294.6

All Sources Combined 1,066.0

W yoming Refining Co. Ne wca stle W Y Sulfur R eco very U nit 3 Su lfur plant capacity

tons sulfur per day

132 lbs of SO2 per ton

sulfur produced

72.3

Fuel Gas Combustion

 Gas 0 MMBtu/hr 0.027 lbs of SO2

 per

million Btu

51.6

 Oil 0 MMBtu/hr

 Total 436.6 MMBtu/hr

FCCU 6,028.5 Data provided by

W yoming Refining

(lbs/hr) design coke burn

rate

20 lbs of SO2 per ton

coke burned

264.0

Flares 12,500 From the December 2000

Oil and Gas Journal

(bbls/cd)

26.9 lbs/1,000 bbl

refinery feed

61.4

All Sources Combined 449.3

Total Floor Allocation (CO, NM, UT, WY) 11,418
II-10

D. COMPARISON WITH HISTORICAL EMISSIONS

Table II-3 summarizes historical SO2

 emissions from petroleum refineries located in the

9 WRAP States. California refineries are included in this table. This table provides a point

of comparison with the floor allocations shown in Table II-2.

E. EXAMPLE CALCULATION

This section provides an example calculation of the refinery floor allocation using the

data provided for this project by Wyoming Refining. This refinery is located in Newcastle,

Wyoming. This same information can be found in Table II-2 in condensed form.

1. Sulfur Recovery Unit

The SO2 floor allocation for the SRU is based on the capacity of the unit. Because the

capacity of the Wyoming Refining sulfur plant is less than 20 long tons per day, a sulfur

recovery efficiency of 96.8 percent is applied in the floor calculation. (If the sulfur plant

was larger than 20 long tons per day, a 99.8 percent sulfur recovery value would be

applied.)

The SO2 emission factor for 96.8 percent sulfur recovery is 132 lbs SO2 per ton of sulfur

produced as shown below:

Then, the SO2 floor allocation is the sulfur plant capacity (3 short tons per day) multiplied

by the SO2

 emission factor and 365 days per year, as follows:

2. Fuel Gas Combustion

The SO2 floor allocation for fuel gas combustion is based on the combined boiler and

process heater combustion capacity with each refinery. Wyoming Refining estimates that

its total boiler plus process heater fired duty capacity at the refinery is 436.6 MMBtu per

hour. The SO2 floor allocation is estimated to be the combined oil and gas combustion

capacity multiplied by 0.027

lbs/MMBtu.
II-11

Table II-3

Petroleum Refineries – Historical Emissions – 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

AZ 4 005 0001 42 2911 6 Oil/Gas Intermountain Refining 803 0 0 0

CA 6 037 800012 14 2911 6 Oil/Gas AR CO (NS R U SE ON LY) ARCO PRODUCTS CO 1,919 2,359 1,706 2,315

CA 6 037 800030 14 2911 6 Oil/Gas CHEVRON U.S.A. INC (EIS USE) - EL SEGUNDO CHEVRON PRODUCTS CO. 833 1,795 938 1,208

CA 6 013 10 11 2911 6 Oil/Gas CHEVRON USA INC - RICHMOND CHEVRON PRODUCTS COMPANY 1,291 1,018 1,413 1,244

CA 6 095 15 11 2911 6 Oil/Gas EX XO N C OR PO RA TION - BEN ICIA 4,922 6,042 5,779 5,779

CA 6 029 37 13 2911 6 Oil/Gas KE RN OIL & R EFININ G C O. 319 425 443 364

CA 6 037 800089 14 2911 6 Oil/Gas MOBIL OIL CORP (EIS USE) - TORRANCE MOBIL OIL CORP (EIS USE) 256 807 725 1,018

CA 6 013 32 11 2911 6 Oil/Gas PACIFIC REFINING COMPANY NOW PLANT ID 11587 278 290 0 0

CA 6 029 25 13 2911 6 Oil/Gas SAN JOAQUIN REFINERY SAN JOAQUIN REFINING COMPANY 337 313 138 0

CA 6 013 11 11 2911 6 Oil/Gas SHELL O IL COMPAN Y - MARTINEZ MARTINEZ REFINING COMPANY 2,790 2,518 2,374 1,159

CA 6 037 800223 14 2911 6 Oil/Gas TEXACO REFINING & MARKETING IN - WILMINGTON 546 727 590 953

CA 6 029 33 13 2911 6 Oil/Gas TEXAC O REFINING AN D MAR KETING - BAKE RSFIELD EQUILON ENTER PRISES LLC 471 190 94 72

CA 6 013 12758 11 2911 6 Oil/Gas TOSCO CORP AVON REFINERY 7,661 4,459 5,422 5,422

CA 6 037 800026 14 2911 6 Oil/Gas ULTR AM AR INC (NS R U SE ON LY) 341 959 669 620

CA 6 037 800144 14 2911 6 Oil/Gas UNION OIL CO OF CAL (NSR USE O TOSCO REFINING COMPANY 724 1,005 806 806

CA 6 079 4 13 2911 6 Oil/Gas UNOCAL CARBON TOSCO SANTA MARIA REFINERY 0 0 0 0

CA 6 079 4 13 2911 6 Oil/Gas UNOCAL CHEM DIV-UNOCAL CORP - ARROYO GR TOSCO 3,034 3,950 0 0

CA 6 013 16 11 2911 6 Oil/Gas UNOCAL CORPORATION - RODEO TOSCO RODEO REFINERY 584 728 675 615

CA 6 037 14 2911 6 Oil/Gas UNOCAL REFINING & MARKETING CO TO SC O R EFININ G (L .A.) 0 343 508 587

CA 6 079 13 13 2911 6 Oil/Gas UNOCAL- SANTA MARIA REFINERY TOSCO SANTA MARIA REFINERY 647 225 3,501 3,727

CA 6 037 800047 14 2911 6 Oil/Gas FLETCHER OIL & REF CO (EIS USE 107 0 0 0

CA 6 037 800184 14 2911 6 Oil/Gas GO LD EN WES T R EF CO (EIS US E) 232 0 0 0

CA 6 037 800103 14 2911 6 Oil/Gas PO WER INE OIL CO (EIS US E) 196 0 1 1

CA 6 037 800115 14 2911 6 Oil/Gas SHELL OIL CO (EIS USE) - CARSON SHELL O IL PRODUC TS 778 0 0 0

CO 8 001 0004 53 2911 6 Oil/Gas COLO REFINING 632 664 526 545

CO 8 001 0003 53 2911 6 Oil/Gas CONOCO DENVER 2,336 2,610 2,496 1,972

CO 8 077 0001 55 2911 6 Oil/Gas LANDMARK PETROLEUM 157 0 0 0

NM 35 045 0023 60 2911 6 Oil/Gas GIANT INDUSTRIES/BLOOMFIELD REF 676 772 920 920

NM 35 031 0008 61 2911 6 Oil/Gas GIANT REFINING/CINIZA REFINERY 1,346 1,115 1,779 1,779

NM 35 015 0010 65 2911 6 Oil/Gas NAVAJO REFINING/ARTESIA REFINERY 1,549 1,552 969 980

UT 49 035 0004 32 2911 6 Oil/Gas Am oco Pe troleum Produc ts TESORO PETROLEUM 6,701 983 1,116 1,368

UT 49 011 0003 31 2911 6 Oil/Gas Chevron Products Company 2,424 1,116 845 1,242

UT 49 011 0008 31 2911 6 Oil/Gas Flying J Incorporated 312 574 225 300

UT 49 011 0013 31 2911 6 Oil/Gas Phillips 66 Company 5,672 864 862 601

W Y 56 021 0001 9 2911 6 Oil/Gas FRONTIER OIL & REFINING - CHEYENNE 1,521 1,769 1,422 1,396

W Y 56 025 0001 9 2911 6 Oil/Gas LITTLE AMERICA REFINING COMPANY SINCLAIR - CASPER 1,899 1,629 1,305 1,458

W Y 56 007 0011 9 2911 6 Oil/Gas SIN CLAIR @ SIN CLAIR 5,917 3,990 3,524 3,407

W Y 56 045 0001 9 2911 6 Oil/Gas WYOMING REFINING CO WY OMING R EFINING - NEWC ASTLE 630 930 804 876

W Y 56 025 0002 9 2911 6 Oil/Gas AMOCO REFINERY 1,153 0 0 0

Tota ls 61,994 46,721 42,575 42,734
II-12

3. Catalytic Crackers

The SO2

 floor allocation for catalytic crackers is based on the coke burn rate at the

FCCU and the NSPS SO2

 emission rate. The FCCU for Wyoming Refining has a design

feed rate of 5,300 barrels per day, or 6,029 lbs per hour. The NSPS SO2

 emission rate is 20

lbs SO2 per ton coke burn-off.

4. Flares

The SO2 floor allocation for the flares at Wyoming Refining is estimated according to

the total crude processing capacity of the facility. The estimated crude processing capacity

for Wyoming Refining is 12,500 barrels per calendar day. This capacity value is multiplied

by the AP-42 SO2

 emission factor for a vapor recovery system and flaring of 26.9 lbs per

1,000 barrels refinery feed.

REFERENCES

40 CFR Part 60, 2001a: Code of Federal Regulations, “Subpart J - Standards of

Performance for Petroleum Refineries,” (60.100-60.109), 2001.

40 CFR Part 60, 2001b: Code of Federal Regulations, “Subpart LLL - Standards of

Performance for Onshore Natural Gas Processing: SO2

 Emissions,” 2001.

EPA, 1989: U.S. Environmental Protection Agency, “Sulfur Oxides Emissions from Fluid

Catalytic Cracking Unit Regenerators – Background Information for Promulgated

Standards – Final EIS,” EPA-450/3-82-013b, Office of Air Quality Planning and

Standards, Research Triangle Park, NC, April 1989.

EPA, 1993: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors (AP-42), Section 8.13 Sulfur Recovery,” Office of Air Quality Planning and

Standards, Research Triangle Park, NC, 1993.

EPA, 1995: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors (AP-42), Section 5.1 Petroleum Refining,” Office of Air Quality Planning and

Standards, Research Triangle Park, NC, 1995.

Greene, 2002: Letter from Samuel B. Greene, P.E., Sinclair Oil Corporation, Salt Lake City,

UT, to Jim Wilson, E.H. Pechan & Associates, Inc., Springfield, VA, Re: Sinclair Oil

Corporation Western Regional Air Partnership - Market Trading Forum, Non-Utility

SO2

 Floor Allocation Study, Transmittal of Requested Information, September 30, 2002.

Oil & Gas Journal, 2000: Oil & Gas Journal, “2000 Worldwide Refining Survey,” December

18, 2000, Volume 98.51, 2000.
III-1

CHAPTER III

LIME MANUFACTURING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Lime is the high temperature product of the calcination of limestone. Although

limestone deposits are found in every State, only a small portion is pure enough for

industrial lime manufacturing. The Standard Industrial Classification (SIC) code for lime

manufacturing is 3274. The six-digit SCC for lime manufacturing is 3-05-016.

The heart of a lime plant is the kiln. The prevalent type of kiln is the rotary kiln,

accounting for about 90 percent of all U.S. lime production. This kiln is a long, cylindrical,

slightly inclined, refractory-lined furnace, through which the limestone and hot combustion

gases pass concurrently. Coal, oil, and natural gas may all be fired in rotary kilns. Product

coolers and kiln feed preheaters of various types are commonly used to recover heat from

the hot lime product and hot exhaust gases, respectively.

The next most common type of kiln in the United States is the vertical, or shaft, kiln. 

This kiln can be described as an upright heavy steel cylinder lined with refractory material. 

The limestone is charged at the top and is calcined as it descends slowly to discharge at the

bottom of the kiln. A primary advantage of vertical kilns over rotary kilns is higher

average fuel efficiency. The primary disadvantages of vertical kilns are their relatively low

production rates and the fact that coal cannot be used without degrading the quality of the

lime produced. There have been few recent vertical kiln installations in the United States

because of high product quality requirements.

Other, must less common, kiln types include rotary hearth and fluidized bed kilns. 

Both kiln types can achieve high production rates, but neither can operate with coal. The

“calcimatic” kiln, or rotary hearth kiln, is a circular kiln with a slowly revolving doughnutshaped hearth. In fluidized bed kilns, finely divided limestone is brought into contact with

hot combustion air in a turbulent zone, usually above a perforated grate. Because of the

amount of lime carryover into the exhaust gases, dust collection equipment must be

installed on fluidized bed kilns for process economy.

SO2 emissions are influenced by several factors, including the fuel sulfur content, the

sulfur content and numeralogical form (pyrite or gypsum) of the stone feed, the quality of

lime being produced, and the type of kiln. The dominant source of SO2 emissions is the

kiln’s fuel, and the vast majority of the fuel sulfur is not emitted because of reactions with

calcium oxides in the kiln. SO2 emissions may be further reduced if the pollution

equipment uses a wet process or if it brings calcium oxides and SO2 into intimate contact.

Table III-1 provides SO2 emission factors for lime manufacturing. This table shows

that there is a wide range of SO2 emissions performance depending on the kiln type,

pollution control equipment, feedstock, and fuel.

Because of differences in the sulfur content of the raw material and fuel and in process

operations, a mass balance on sulfur may yield a more representative emission factor for a

specific facility than AP-42 emission factors.

B. FLOOR ALLOCATION ESTIMATION METHODS

With the wide range of SO2 emission factors for lime manufacturing, the SO2 control

that is inherent in the lime manufacturing process, and additional controls are not typically

applied to lime plants, the SO2 floor allocation for lime plants will be based on historical
III-2

emissions. The historical emissions for the 1990 to 2000 period are listed in Table III-2. 

The calendar year 2000 SO2

 emission total for lime manufacturing is 2,316 tons.

REFERENCES

AWMA, 2000: Air & Waste Management Association, “Air Pollution Engineering Manual,”

2

nd edition, edited by Wayne T. Davis, 2000.

EPA, 1998: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors, AP-42, Section 11:17: Lime Manufacturing,” Office of Air Quality Planning

and Standards, Research Triangle Park, NC, 1998.
III-3

Table III-1

Emission Factors for Lime Manufacturinga

Source SO2

b Emission Factor Rating

Coal-fired rotary kiln (SCC 3-05-016-18) 5.4 D

Coal-fired rotary kiln with fabric filter (SCC 3-05-016-18) 1.7 D

Coal-fired rotary kiln with wet scrubber (SCC 3-05-016-18) 0.30 D

Gas-fired rotary kiln (SCC 3-05-016-19) ND

Coal- and gas-fired rotary kiln with venturi scrubber

(SCC 3-05-016-20)

ND

Coal- and coke-fired rotary kiln with venturi scrubber

(SCC 3-05-016-21)

ND

Coal-fired rotary preheater kiln with dry PM controls

(SCC 3-05-016-22)

2.3 E

Coal-fired rotary preheater kiln with m ulticlone, water spray,

and fabric filter (SCC 3-05-016-22)

6.4 E

Gas-fired calcimatic kiln (SCC 3-05-016-05) ND

Gas-fired parallel flow regenerative kiln with fabric filter

(SCC 3-05-016-23)

0.0012 D

Product cooler (SCC 3-05-016-11) ND

NOTES: aFactors represent uncontrolled emissions unless otherwise noted. Factors are lbs/ton of lime produced unless

noted. ND = no data. Classification Code.

bMass balance on sulfur may yield a more representative emission factor for a specific facility.
III-4

Table III-2

Lime Manufacturing - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

Floor

Allocation*

AZ 4 025 0011 41 3274 10 Me tals/Min ing/Min erals CHEMICAL LIME (CHEMSTAR) CHEMICAL LIME CO - NELSON

PLANT

141 122 562 702 632

AZ 4 003 0003 47 3274 10 Me tals/Min ing/Min erals CHEMICAL LIME (DOUGLAS) CHEMICAL LIME CO - DOUGLAS

PLANT

212 634 724 742 733

CA 6 053 12 12 3274 10 Me tals/Min ing/Min erals NATIONA L REFRA CTOR IES&MINERALS CHEMICAL LIME CO - NATIVIDAD

PLANT

243 <100 69 82 76

NV 32 003 0003 22 3274 10 Me tals/Min ing/Min erals CHEMSTAR APEX CHEMICAL LIME CO - APEX

PLANT

783 175 210 193

NV 32 007 0261 3274 10 Me tals/Min ing/Min erals CONTINENTAL LIME INC., PILOT PEAK

PLANT

GRAYMONT WESTERN US INC,

PILOT PEAK PLANT

<100 136 235 249 242

UT 49 027 35 3274 10 Me tals/Min ing/Min erals CONTINENTAL LIME INC., CRICKET

MOUNTAIN PLANT

GR AY MO NT W ES TE RN US , INC.,

CRICKET MOUNTAIN PLANT

115 297 275 331 303

Tota ls 1,594 1,289 2,040 2,316 2,179

NOTE: *Based on 1998 and 2000 historical SO2

 emission estimates.
IV-1

CHAPTER IV

INDUSTRIAL BOILERS AND COGENERATORS

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Industrial, commercial and institutional (ICI) boilers produce steam or heat water for

use in industrial processes, electrical/mechanical power generation, or space heating. Some

have a dual functionality such as the cogeneration of steam and electricity. Auxiliary

boilers provide backup power and power for startup/shutdown of large units. Large boilers

($150 MMBtu/hr) are generally field-erected units while small boilers are preassembled,

packaged units. The design of an individual ICI boiler is often dependant on the application

of steam and the space limitations in a particular plant.

ICI boilers generate steam at lower temperatures and pressures than utility boilers,

therefore, their heat inputs are smaller. Industrial boilers generally have heat input rates

ranging from 30 to 250 MMBtu/hr, but may be as high as 1,500 MMBtu/hr (EPA, 1994).

Commercial and institutional boilers typically have heat input rates ranging from 0.4 to 12

MMBtu/hr, but may be as high as 100 MMBtu/hr (EPA, 1994). The overall population of ICI

boilers have small heat inputs, with 80 percent of the population operating at less than 5

MMBtu/hr per boiler (STAPPA, 1994). Over 80 percent of the ICI boilers burn oil and gas.

The remaining boilers burn primarily coal, with a small number burning biomass, waste or

other non-fossil fuel. ICI combustion units often burn a mixture of conventional fuels and

biomass or waste. Pulverized coal-fired units account for approximately 1 percent of the

total ICI boiler population. However, they have large heat inputs, greater than 100

MMBtu/hr, therefore, they represent 14 percent of the total ICI boiler capacity. Oil and gas

fired ICI boilers are smaller in size than coal-fired boilers, typically less than 250

MMBtu/hr.

The use of ICI boilers varies with the industrial application. In addition, the

application of steam from an industrial boiler can change with the seasons, and can vary

through the course of a day as well, depending on the processes and activities underway at

a given moment and their demand for steam. Therefore, ICI boilers may have a much lower

annual operating load or capacity factor than a typical utility boiler. 

B. FLOOR ALLOCATION ESTIMATION METHODS

The analysis was limited to facilities which emit greater than 100 tpy of SO2 in total,

and/or individual units which emit greater than 25 tpy of SO2

. In addition, only coal and oil

fired units were analyzed. Auxiliary boilers were included in the floor allocation estimation

if the unit had a potential to emit (PTE) greater than 25 tpy. This includes boilers larger

than 5 MMBtu/hr firing fossil fuel with a sulfur content of 1 percent or more.

The air pollution agencies for each WRAP State provided information for each ICI

boiler being analyzed. This information included the boiler design capacity, annual fuel

consumption for recent calendar years, fuel type (coal or oil), fuel sulfur content, SO2

 control

device information, and the control device SO2

 control efficiency, or permitted SO2

emissions limit for each unit.

The SO2

 floor allocations are calculated for each facility based on the current level of

control. An average level of control is then assumed for each facility, according to Table

IV-1 below:
IV-2

Table IV-1

Assumed Level of Control for SO2

 Floor Allocation

Current Facility Level of Control

Assumed Average Level of Control

for Estimating the Floor

Uncontrolled, 0% 85% Reduction

Units controlled at 0% to <70% 85% Reduction

Units controlled at 70% to 80 % Increase reduction by 5%

Units controlled at 80% or greater No additional reduction

Floor allocations for industrial boilers/cogenerators were also based on the average

capacity utilization during the most recent calendar years. Some States were able to

provide as many as five years worth of boiler utilization data. The recent years of boiler

utilization (fuel consumption) data were used to estimate an average capacity factor for

each unit. This average capacity factor was used, along with a 5 percent margin for growth,

in the SO2

 floor allocation calculation for each boiler/cogenerator.

1. Coal Fired Units

Coal fired units were assumed to fire subbituminous coal with a heating value of 9,000

Btu/lb (18 MMBtu/ton) of coal burned, unless a specific coal type or heating value was

reported (AWMA, 2000). The ICI boilers in the WRAP States were assumed to burn

subbituminous coal since it has a low sulfur content. In addition, a lower grade of

subbituminous coal, class C coal, was assumed to be used for ICI applications. The fuel

sulfur content used to calculate the floor allocation was facility-specific, where available. 

For facilities that did not report sulfur content, an average sulfur content (1 percent) for the

type of coal being fired was used (AWMA, 2000).

The SO2

 emission factor for subbituminous coal fired boilers in pounds of SO2

 emitted

per ton of coal burned is given in AP-42 as:

where S is the percentage sulfur content of the coal burned by each combustion unit (EPA,

1998a).

2. Oil Fired Units

Oil fired units were assumed to have a heating value of 0.15 MMBtu/gal unless a

specific oil type or heating value was reported (AWMA, 2000). The fuel sulfur content used

to calculate the floor allocation was facility-specific. For facilities not reporting sulfur

content, an average sulfur content for the type of oil being fired was used (AWMA, 2000).

The SO2

 emission factor for No. 2 and No. 6 oil fired boilers in pounds of SO2 emitted

per 1,000 gallons of oil burned is given in AP-42 as:

where S is the percentage sulfur content of the oil burned by each combustion unit (EPA

1998b).
IV-3

Units that burn natural gas and oil are assumed to burn natural gas as a primary fuel,

if the emission data indicated SO2

 emission < 5 tpy. If natural gas is the primary fuel, no

allocations are computed.

C. FLOOR ALLOCATION RESULTS

Table IV-2 summarizes the floor allocation calculation for the ICI boilers in the 8 nonCalifornia Western Regional Air Partnership (WRAP) States.

D. COMPARISON WITH HISTORICAL EMISSIONS

Table IV-3 summarizes historical SO2 emissions from industrial boilers located in

Arizona, Colorado, Idaho, Oregon, Utah, and Wyoming. This table provides a point of

comparison with the floor allocations shown in Table IV-2 and historical emissions at each

facility. Note that the historical emissions are the total plant emissions, not just those

resulting from operation of the boiler. In general, boilers which currently have a scrubber

are able to meet their SO2 floor allocations based on historical emissions. 

E. EXAMPLE USE OF CAPACITY UTILIZATION DATA FOR FLOOR ALLOCATION

ESTIMATES

The floor allocation estimation method for boilers and cogenerators takes into account

utilization of these fuel combustion units in the most recent historical years. This section

provides an example of how the capacity factor calculation was performed for one boiler at

Abitibi Consolidated in Arizona.

In order to estimate the average annual capacity factors of each unit, Pechan requested

the actual fuel throughput data for the last 5 years for each boiler. The data was supplied

by the air pollution agencies for each WRAP State. The fuel throughput data supplied by

the Arizona DEQ for Abitibi Consolidated is listed in Table IV-4.

Fuel throughput for all fuel types, coal, oil and natural gas were used to estimate the

annual heat input for each unit using the following equation:

where:

Qannual

= annual heat input for each boiler (MMBtu/yr),

T = throughput for given fuel type, and

HC = heat content for a given fuel type.

Most States did not specify the heat content for each fuel, therefore, the following default

values were used:

Coal Heat content = 18.0 MMBtu/ton

Oil Heat content = 0.15 MMBtu/gal

Natural Gas Heat content = 1,020 MMBtu/MMscf

The boiler design capacity at Abitibi Power boiler #2 is 1,132 MMBtu per hour. In this

exercise, the annual fuel consumption is compared with this boiler design capacity to

estimate the percentage of total capacity that is used in each year. The Arizona DEQ was

able to provide fuel throughput, or fuel consumption, estimates for four calendar years: 

1998 through 2001. This particular unit burns coal and oil, but not natural gas. Fuel

consumption estimates were provided by the State in tons for coal and gallons for oil. The

average heat contents of these two fuels are listed in Table IV-4 and are used to compute an

All Fuels Combined Throughput value in column J. Column K contains the boiler design

capacity value converted to an annual equivalent. The capacity factor for each calendar

year is computed (in column L) as the ratio of column J to column K. For Abitibi Power

boiler #2, these capacity factors range from 60 to 70 percent, with an average capacity
IV-4

factor of 64 percent. The 64 percent average capacity factor value is used in the floor

allocation estimate. (Note that during a leap year (2000), the potential hours of operation

are greater.)

This average capacity factor is used to calculate the SO2 floor allocation. This value is

multiplied by 1.05 to provide some margin for future increases in operations. Only the

primary fuel (coal in this example) is assumed to burned by the boiler in the floor allocation

estimation. The SO2 allocations are calculated using the assumed control efficiency (85

percent) as specified in Table IV-1. The SO2 floor allocation is calculated using the

following equation:

where:

SO2

= SO2 floor allocation (tons/yr),

Qdesign

= annual heat input (MMBtu/yr),

HCprime = heat content of primary fuel (MMBtu/ton, MMBtu/gal), 

EF = SO2 emissions factor (lb/ton, lb/gal),

CF = average capacity factor (%), and

CE = required control efficiency (%).

For Abitibi Power boiler #2, the appropriate values for the above equation are:

Qdesign

= 9,916,320

HCprime = 18

EF = 35

CF = 0.64

CE = 85

As is shown in column P of Table IV-4, the SO2 floor allocation estimate for Abitibi

Power boiler #2 is 978 tpy.

REFERENCES

AWMA, 2000: Air and Waste Management Association, Davis, Wayne T. ed., “Air Pollution

Engineering Manual,” Second Edition, John Wiley and Sons, Inc., New York, 2000.

EPA, 1994: U.S. Environmental Protection Agency, “Alternative Control Techniques

Document – NOx

 Emissions from Industrial/Commercial/Institutional Boilers,” EPA453/R-94-022, Emission Standards Division, Office of Air Quality Planning and

Standards, Research Triangle Park, NC, March 1994.

EPA, 1998a: U.S. Environmental Protection Agency, “Compilation of Air Pollutant

Emission Factors (AP-42), Section 1.1 Bituminous And Subbituminous Coal

Combustion,” Office of Air Quality Planning and Standards, Research Triangle Park,

NC, 1998.

EPA, 1998b: U.S. Environmental Protection Agency, “Compilation of Air Pollutant

Emission Factors (AP-42), Section 1.3 Fuel Oil Combustion,” Office of Air Quality

Planning and Standards, Research Triangle Park, NC, 1998.

STAPPA, 1994: State and Territorial Air Pollution Program Administrators (STAPPA) and

Association of Local Air Pollution Control Officials (ALAPCO), “Controlling Nitrous

Oxides,” July 1994.
IV-5

Table IV-2

Facility SO2 Floor Allocation Estimation for ICI Boilers

Fac ility Un it

Capac ity in

MM Btu/hr Fuel

Sulfur

Content

Current SO2

Co ntrols

Percent

Reduction SO2 Lim it

Average

Capac ity

Factor

(% )

Assumed

 Percent

Reduction

Floor

Allocation

(tpy)

Arizona

Abitibi Consolidated No. 2 Power Boiler 1,132 Coal 1.0 None 0 64 85 978

Colorado

TR IGE N - C olorado E nerg y Corp Boiler #3 225 Coal 0.39 0 43 85

TR IGE N - C olorado E nerg y Corp Boiler #4 360 Coal 0.38 0 62 85

TR IGE N - C olorado E nerg y Corp Boiler #5 650 Coal 0.43 0 59 85 387

Idaho

Amalgamated Sugar, Nampa S-B1 105 Coal 1.0 None 0 34 85

Amalgamated Sugar, Nampa S-B2 105 Coal 1.0 None 0 35 85

Amalgamated Sugar, Nampa S-B3 250 Coal 1.0 None 0 43 85 242

Amalgamated Sugar Company, Paul S-B1 200 Coal 1.0 None 0 35 85

Amalgamated Sugar Company, Paul S-B2 200 Coal 1.0 None 0 23 85 155

Am algam ated Sugar C om pany, T win Falls P-B1 280 Coal 1.0 None 0 30 85

Am algam ated Sugar C om pany, T win Falls P-B2 285 Coal 1.0 None 0 24 85 203

Oregon

Boise Cascade c Power Boiler 6-9 N/A Oil 2.0 No 0 4125 tpy -- 85 411

Amalgamated Sugar B& W Bo ilers 204 Coal 1.5 W et Scrubber 45 200 tpy 12 85

Amalgamated Sugar Foster Riley Boiler 136 Coal 1.5 0 265 tpy 20 85

Amalgamated Sugar Foster W heeler Boiler 300 Coal 1.5 0 775 tpy 21 85 74

Georgia Pacific W est Power Boiler #1 Unknown Oil 2.0 None 0 429.6 tpy -- 85 143

Pope & Talbot Power Boiler #1 Unknown Oil 2.0 None 0 391 tpy -- 85 107

W est Linn Paper Co. Boilers 1 & 2 Oil 2.0 None 0 492.74 tpy 46 85 211

Georgia-Pacific W auna Power Boiler Unknown Oil 2.0 None 0 641.1 tpy -- 85

Georgia-Pacific W auna Package Boiler Unknown Oil 2.0 None 0 0.5 tpy 0 85 277

W eyerh aeu ser Springfield Power Boiler Unknown Oil 2 None 0 590 tpy -- 85

W eyerh aeu ser Springfield Package Boiler Unknown Oil 0.55 None 0 73 tpy -- 85

W eyerh aeu ser Springfield Package Boiler 16 Oil 2 None 0 39 tpy 0 85 362

Utah

Sunnyside Cogeneration Associates FBC Boiler #1 700 Coal 1.0 Scrubber 86 462 lbs/hr 84 86 1,270

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 1 431 Coal 0.68 None a0 1258 tpy 41 85

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 2 431 Coal 0.68 None a

0 1258 tpy 33 85

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 3 431 Coal 0.68 None a0 1258 tpy 28 85

Ke nne cott U tah C opp er Corp N . Conce ntator Un it 4 838 Coal 0.68 None a

0 2445 tpy 39 85 700

Brigh am You ng U niversity Units #2, #3, and #5 128 Coal 0.70 None a0 217 tpy 0 85

Brigh am You ng U niversity Auxiliary #7 5 Oil 1.5 0 6 85 0

Brush Wellman Incorporated S-11 - Main Boiler 81.2 Oil 1.5 None 46 0.85 lb/MB tu 32 85

Brush Wellman Incorporated S-10 Backup Boiler 12.66 Oil 1.5 None 46 0.85 lb/MB tu 19 85 23
Table IV-2 (continued)

Fac ility Un it

Capac ity in

MM Btu/hr Fuel

Sulfur

Content

Current SO2

Co ntrols

Percent

Reduction SO2 Lim it

Average

Capac ity

Factor

(% )

Assumed

 Percent

Reduction

Floor

Allocation

(tpy)

IV-6

Geneva Steel Po wer B oiler 1 411 Coal/Gas 1.0 None 0 4

Geneva Steel Po wer B oiler 2 411 Coal/Gas 1.0 None 0 4

Geneva Steel Po wer B oiler 3 411 Coal/Gas 1.0 None 0 4

Geneva Steel Po wer B oiler 4 205 Coal/Gas 1.0 None 0 0

Geneva Steel Power Boiler 5 205 Coal/Gas 1.0 None 0 520.2 tpy 0 96 17

Wyoming

Solvay Minerals, Inc. Boiler #18 350 Coal 0.7 Scrubber 85 0.2 62 85

Solvay Minerals, Inc. Boiler #19 350 Coal 0.7 Scrubber 85 0.2 61 85 294

General Chemical Bo iler C 534 Coal 0.5 No 0 1.2 74 85

General Chemical Bo iler D 880 Coal 0.5 No 0 1.2 71 85 750

Holly Sugar-Torrington Plant 221 .2 Coal 0.7 No 0 None 17 85 23

FMC Corp - Green River Plant Boiler #6 887 Coal 0.5 Sc rubb er b0 1.2 70 85

FMC Corp - Green River Plant Boiler #7 887 Coal 0.5 Sc rubb er b0 1.2 70 85 956

University of W yoming Central Heating Plant Boiler #2 73.1 Coal 0.5 No 0 1.2 18 85

University of W yoming Central Heating Plant Boiler #3 73.1 Coal 0.5 No 0 1.2 25 85 22

University of W yoming Central Heating Plant Boiler #4 73.1 Coal 20

FMC Granger Boiler #1 358 Coal 1.0 Scrubber 99 0.2 lb/M Mb tu 48 99

FMC Granger Boiler #2 358 Coal 1.0 Scrubber 99 0.2 lb/M Mb tu 48 99 305

Total Floor Allocation 7,910

NOTES: aNatural gas is fired during winter months per SIP requirements.

bSc rubber is for the entire p lant no t just the b oiler.
IV-7

Table IV-3

Comparison of SO2 Floor Allocation with Historical Emissions for ICI Boilers

Historical SO2 Emissions

Fac ility Un it Capacity (MM Btu/hr) SO2 Floor Allocation (tpy) 199 0 (tpy) 199 6 (tpy) 199 8 (tpy) 200 0 (tpy)

Arizona

Abitibi Consolidated Power Boiler #2 1,132 978 2,455 2,448 1,893

Colorado

TRIGEN - Colorado Energy Corp b Boiler #3 225

TRIGEN - Colorado Energy Corp b Boiler #4 360

TRIGEN - Colorado Energy Corp b Boiler #5 650 387 2,675 3,708 2,583

Idaho

Amalgamated Sugar, Nampa S-B1 105

Amalgamated Sugar, Nampa S-B2 105

Amalgamated Sugar, Nampa S-B3 250 242 1,008 1,660 1,787 1,697

Amalgamated Sugar Company, Paul S-B1 200

Amalgamated Sugar Company, Paul S-B2 200 155 608 306 217 1,322

Am algam ated Sugar C om pany, T win Falls P-B1 280

Am algam ated Sugar C om pany, T win Falls P-B2 268 203 599 1,364 1,053 1,053

Oregon

Boise Cascade c Power Boiler 6-9 N/A 411 2,453 685 746 1,834

Amalgamated Sugar c B& W Bo ilers 204

Amalgamated Sugar c Foster Riley Boiler 136

Amalgamated Sugar c Foster W heeler Boiler 300 74 594 625 1,235 987

Ge orgia Pa cific W est c Power Boiler #1 Unknown 143

Pope & Talbot c Power Boiler #1 Unknown 107 39 161

W est Linn Paper Co. a Boilers 1 & 2 365 211

Georgia-Pacific - Wauna c Power Boiler Unknown

Georgia-Pacific - Wauna c Package Boiler 18 277 254 165

W eyerh aeu ser Springfield Power Boiler Unknown 297

W eyerh aeu ser Springfield Package Boiler Unknown 65

W eyerh aeu ser Springfield Package Boiler 16 0

Utah 

Sunnyside Cogeneration Associates bFBC Boiler #1 700 1,270 0 1,006 970 1,054

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 1 431

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 2 431

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 3 431

Ke nne cott U tah C opp er Corp, N . Conce ntator b Un it 4 838 700 2,905 2,141 2,200 2,534

Brigh am You ng U niversity Units 2, 3, and 5 128

Brigh am You ng U niversity Auxiliary #7 5 0 248 90 158 125

Brush Wellman Incorporated S-11 Main Boiler 81.2

Brush Wellman Incorporated S-10 Back-up Boiler 12.66 23 161 175 208 179
Table IV-3 (continued)

Historical SO2

 Emissions

Fac ility Un it Capacity (MM Btu/hr) SO2

 Floor Allocation (tpy) 199 0 (tpy) 199 6 (tpy) 199 8 (tpy) 200 0 (tpy)

IV-8

Geneva Steel Po wer B oiler 1 411

Geneva Steel Po wer B oiler 2 411

Geneva Steel Po wer B oiler 3 411

Geneva Steel Po wer B oiler 4 205

Geneva Steel Po wer B oiler 5 205 17 8,473 2,020 881 979

Wyoming

So lvay M inerals, Inc. b Boiler #18 350

So lvay M inerals, Inc. b Boiler #19 350 294 101 72 52

Ge neral C hem ical b Bo iler C 534

Ge neral C hem ical b Bo iler D 880 750 4,196 5,651 4,538 5,000

Ho lly Sugar-Torrington Plant b221 .2 23 374 266 154 178

FM C C orp - G reen Rive r Plan t b Boiler #6 887

FM C C orp - G reen Rive r Plan t b Boiler #7 887 956 4,795 5,256 4,533 4,901

Un iversity of W yom ing C entra l Hea ting Plant a Boiler #2 73.1

Un iversity of W yom ing C entra l Hea ting Plant a Boiler #3 73.1 22 152 154 223 193

Un iversity of W yom ing C entra l Hea ting Plant a Boiler #4 73.1

FMC Granger Boiler #1 358

FMC Granger Boiler #2 358 305 475 473 149 212

NOTES: aFacility with boilers as only SO2 source.

b

Fac ility has m ultiple so urce s, em ission s are total plan t.

c

Facility ha s m ultiple so urces, em issio ns are boile rs on ly.
IV-9

Table IV-4

Example Use of Capacity Utilization Data for Floor Allocation Estimates

A B C D E F G H I J K L M N O P

Coal Oil Natural Gas

Fac ility Un it Year

Throughput

(ton/yr)

Heat Value

(MMB tu/ton)

Throughput

 (gal/yr)

Heat Value

(M M Btu /gal)

Throughput

(MM cf/yr)

Heat

Value

(M M Btu /ft3)

Throughput

All Fuels

Com bined

(MM Btu/yr)

Design

Capac ity

(MM Btu/yr)

Capac ity

Factor

Primary

Fuel Sulfur

Content

(% )

SO2 EF

(lb/ton)

SO2

Reduction

(% )

SO2

Allocation

(tons)

Arizona

Abitibi Consolidated Power Boiler # 2 1998 387,532 18.0 44,000 0.15 0.0 6,982,176 70%

1,132 MMBtu/hr 1999 353,163 18.0 - 0.15 0.0 6,356,934 64%

2000 350,531 18.0 29 0.15 0.0 6,309,562 64%

2001 327,428 18.0 193,000 0.15 0.0 5,922,654 60%

18.0 9,916,320 64% 1.00 35.0 85.0 978

NO TE : Thro ugh put is the an nua l fuel consu m ption in the ca lend ar year.
IV-10
V-1

CHAPTER V

PULP AND PAPER INDUSTRY

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The processing of wood for a variety of products is one of the ten largest industries in

the United States. To produce paper or paperboard, wood must be pulped first. In general,

the pulp and paper production processes can be divided into three steps: pulp making, pulp

processing, and paper/paperboard processing. The three basic types of pulping processes,

which are the major sources of SO2

, are chemical pulping, mechanical pulping, and semichemical pulping. Chemical wood pulping involves cooking wood chips or sawdust in an

aqueous chemical solution to dissolve the lignin that binds the cellulose fibers together.

There are two major types of chemical pulping used: Kraft/soda pulping and sulfite

pulping. Kraft pulping accounts for over 80 percent of the chemical pulp produced in the

United States.

Sources of SO2

 in a Kraft mill include: (1) boilers generating steam for power and

heat, using coal, oil, natural gas, or bark/wood waste as fuel; (2) recovery furnaces where

SO2

 emissions occur from the oxidation of reduced sulfur compounds; and (3) lime kilns

when fuel oil is being combusted.

Allocations for boilers are discussed in Chapter IV, "Industrial Boilers and

Cogenerators." Floor allocations for recovery furnaces and lime kilns are described in this

chapter. Note that the calculations for these sources are the same as those for like

configurations set forth in other chapters.

1. Recovery Furnaces

After the cooking period, the pulp and the liquor in which it cooked are separated,

the spent liquor (black liquor) is evaporated and concentrated to about 65 percent solids.

Concentrated black liquor is then sprayed into the furnace and the organic compounds are

combusted. The combustion of black liquor in a recovery furnace results in SO2 emissions

that vary with liquor properties (i.e., sulfidity, heat value), combustion air and liquor firing

patterns, furnace design and operational patterns.

SO2

 reduction is achieved by altering the process, rather than applying control

technology. Strategies to lower liquor sulfidity and optimize combustion and firing patterns

in such way that yields maximum and uniform temperatures in the lower furnace are used

to minimize SO2

 emissions. Flue gas desulfurization is energy intensive and its efficiency

uncertain, considering the generally low concentrations and fluctuating levels of SO2 in the

furnace flue gases.

2. Lime Kilns

In a pulp and paper lime kiln, the inorganic molten smelt that forms and collects at

the bottom of the furnace is withdrawn through spouts into a smelt-dissolving tank where

jets of water are used to quench the molten smelt, forming green liquor. The green liquor is

then combined with quicklime (CaO), resulting in a white liquor solution containing NaOH,

Na2S and lime mud precipitate (mainly CaCO3). This lime mud is washed, dried and

calcined in the lime kiln to regenerate quicklime. The regenerated quicklime in the kiln

acts as an in-situ-scrubbing agent and the Venturi scrubber that usually follows the kiln

further reduces SO2

 levels. Emissions from smelt-dissolving tanks and lime kilns are

generally negligible.
V-2

B. FLOOR ALLOCATION ESTIMATION METHODS

The analysis was limited to pulp and paper facilities that emit greater than 100 tpy

of SO2

 from all processes. There are seven pulp and paper facilities evaluated – six located

in the State of Oregon and one in Idaho. The Oregon Department of Environmental

Quality provided data on the unit capacity for each Oregon facility. However, the data given

were the permitted SO2 emission levels and the design capacity of production of each

recovery furnace or kiln.

Abitibi in Navajo County, Arizona no longer operates a recovery furnace. They are

no longer pulping and have converted to recycled paper processing. Therefore, they receive

no floor allocation for recovery furnace operation.

1. Recovery Furnaces

The floor allocation for recovery furnaces is determined assuming that the process

provides sufficient SO2 reductions. No further SO2 reductions will be required when

estimating the floor allocations. Pechan estimated the floor allocation using the emission

factor given in AP-42 in lbs/air-dried ton of pulp (ADT) and the designed pulp production

capacity. The SO2 floor allocations are given by the equation:

where:

AF = SO2 allocation for recovery furnaces in the facility, and

EFSO2 = AP-42 emission factor = 7 lbs/ADT.

For facilities where pulp production capacity was not given, but fuel throughput was

reported in its place, SO2

 allocations are estimated as the fuel throughput multiplied by the

EPA AP-42 SO2

 emission factor.

2. Lime Kilns

The floor allocation for lime kilns is determined in the same manner as recovery

furnaces. The floor allocation for lime kilns assumes no further SO2 reductions will be

required when estimating the floor allocations. Using the emission factor for lime kilns

given in AP-42, the SO2 floor allocation equation for lime kilns is given by:

where:

AK = SO2

 allocation for lime kilns in the facility, and

EFSO2 = AP-42 emission factor = 0.3 lbs/ADT.

For facilities where pulp production capacity was not given, but fuel throughput was

reported in its place, SO2

 allocations are estimated as the fuel throughput multiplied by the

EPA AP-42 SO2 emission factor.

C. FLOOR ALLOCATION RESULTS

Table V-1 presents the floor allocation calculations for pulp and paper plants in

Oregon based on the permitted capacity of the recovery furnaces and kilns. Unit capacity

values were given in air-dried tons of pulp per day. For the floor calculations, it was

assumed that the furnace was operated 365 days per year at 100 percent capacity.
V-3

Table V-2 presents the floor allocation for facilities where the pulp production

capacity was not given, but fuel throughput was reported instead. The Potlatch facility

listed in Table V-2 is located in Idaho. All other pulp and paper mills listed in Tables V-1

and V-2 are in Oregon. Therefore, the computed floor allocations by State are 1,807 tpy for

Idaho, and 5,377 tpy for Oregon. The California allocation for pulp/paper is based on the

1996, 1998, and 2000 historical SO2

 emissions data in Table V-3, and is 324 tpy.

Table V-1

Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Unit Capacity Values

Facility Unit Capacity* (ADTP/day) SO2 Allocations (tpy)

Boise Cascade Corporation Recovery Furnace#2 450 575

Recovery Furnace#3 700 894

Lime Kiln#4 1,150 63

Georgia-Pacific (W auna Mill) Recovery Furnace 1,015 1,297

Lim e Kiln 1,174 64

W eyerhauser Springfield #3 Recovery Boiler 1,150 760

#4 Recovery Boiler 1,150 790

Lime Kilns 2,156 118

NOTE: *Design and a ctual capacity are unknown, the values given are the permitted levels.

Table V-2

Facility SO2 Floor Allocation Estimation for Pulp and Paper Facilities

Based on Fuel Throughput

Facility Unit Fuel Throughput

SO2 Allocations

(tpy)

Georgia-Pacific West, Inc. Recovery Furnace#1 DCE-BLS 242,725 tpy 129

Nat. gas

Recovery Furnace#2 DCE-BLS 242,725 tpy 129

Nat. gas

Lime Kiln#2 Nat. gas 553.7*10E6 ft3/y 0

RFO

#6 oil

Lime Kiln#3 Nat. gas 553.7*10E6 ft3/y 0

RFO

#6 oil

Willamette Industries, Inc. Recovery Furnace#5 BLS 495,000 tpy 235

Nat. gas 350 MMft3 0

No.2 fuel oil 1E06 gal/y 39

Lime Kiln #3 Oil/nat.gas/LPG 1.35E05 ton lime mud/y 36

Pope & Talbot, Inc. Recovery Furnace BLS 461,081 tpy 67

Oil 1.2E06 gal/y 173

Lime Kiln CaO 55,536 tpy 0

Oil 1.8E06 gal/y 1

NCG/CaO 5,662 tpy 7

Potlatch #4 Recovery Boiler BLS 117,113 tpy 410

#5 Recovery Boiler Pulp 393,548 tpy 1,377

#2 Lime Kiln CaO 10,247 tpy 2

#3 Lime Kiln CaO 61,467 tpy 9

#4 Lime Kiln CaO 60,147 tpy 9
V-4

D. COMPARISON WITH HISTORICAL EMISSIONS

Table V-3 summarizes historical SO2

 emissions from pulp and paper facilities. This

table provides a point of comparison with the floor allocations shown in Tables V-1 and V-2

and historical emissions at each facility. Note that the historical emissions are the total

plant emissions, not just those resulting from operation of the recovery furnace and lime

kiln.

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 18 -Wood Processing Industry, 2000.

EPA, 1998: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors, AP-42, Fifth Edition, Volume I: Stationary Point and Area Source, Section

10.2 Chemical Wood Pulping,” Office of Air Quality Planning and Standards,

Research Triangle Park, NC, 1998.
V-5

Table V-3

Pulp and Paper - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

AZ 4 017 0007 43 2611 3 W ood/Paper/Pulp STONE CONTAINER ABITIBI 8,536 2,455 2,448 1,893

CA 6 023 21 10 2611 3 W ood/Paper/Pulp SIMPSON PAPER CO MPANY SIMPSON PAPER CO 1,021 315 315

CA 6 089 23 2611 3 W ood/Paper/Pulp SHASTA PAPER-ANDERSON 216

CA 6 013 3257 11 2611 3 W ood/Paper/Pulp GAYLORD CONTAINER CORPORATION 263 0 0

CA 6 023 37 10 2611 3 W ood/Paper/Pulp LO UISIAN A-P AC IFIC C OR P. 302 <100 42 42

CA 6 077 191 11 2621 3 W ood/Paper/Pulp NEW ARK SIERRA PAPERBOARD CORP. 270 0 0

ID 16 045 2611 3 W ood/Paper/Pulp BOISE CASCADE - EMMETT 252

ID 16 069 0001 3 2621 3 W ood/Paper/Pulp POTLATCH 1,379 700 700 1,694

OR 41 009 1849 6 2621 3 W ood/Paper/Pulp Boise Cascade Company 2,453 685 746 1,834

OR 41 041 0005 5 2631 3 W ood/Paper/Pulp Georgia-Pacific W est, Inc. 56 207 322 452

OR 41 019 0036 5 2631 3 W ood/Paper/Pulp International Paper 874 602 1,006 0

OR 41 007 0004 5 2621 3 W ood/Paper/Pulp James R iver II, Inc. Ge orgia- Pacific (W auna Mill) 331 573 617 643

OR 41 043 3501 5 2621 3 W ood/Paper/Pulp Pope & T albot Pulp, Inc. 485 133 92 293

OR 41 071 6142 5 2621 3 W ood/Paper/Pulp Smurfit Newsprint Corporation 2 592 368 461 519

OR 41 043 0471 5 2631 3 W ood/Paper/Pulp W illamette Industries, Inc. 396 54 485 327

OR 41 039 8850 5 2631 3 W ood/Paper/Pulp Collins Products LLC W eyerhaeuser Co. (Particleboard) 202 0 3 1,721

OR 41 047 5398 5 2621 3 W ood/Paper/Pulp Ogden Martin Systems of Marion, Inc. Covanta Marion, Inc. 127 18 22

17,287 6,210 7,259 9,886
V-6
VI-1

CHAPTER VI

CEMENT MANUFACTURING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The cement industry involves the calcining of limestone in clinker and the

subsequent crushing of the clinker into cement. Cement manufacturing activities include

the process the mining and mixture of raw materials such as limestone and other materials,

the pryoprocessing of the raw materials into a clinker, and the grinding of the clinker and

other materials such as silicates into the final cement. As of December 2000, there were

201 kilns with a total capacity of 84 million tpy. The kiln is a predominate source of SO2

emissions. The SO2 emissions result from the combustion of the sulfur in the fuel and the

sulfur (generally in the form of pyrite) that can occur in the feedstock.

Kilns generally take five forms:

! wet (where the feedstock contains up to 43 percent water);

! dry;

! semi-dry;

! dry with a pre-heater;

! and dry with a pre-calciner.

SO2 emissions vary by kiln type generally based on how effectively the kiln type mixes the

SO2 containing gases with the alkaline calcium compounds. The pre-heater and precalciner kilns can remove 90+ percent of the SO2

 in the gas stream while the dry process

kiln removes about 70 percent. In addition, the type of particulate control devices can

impact the amount of SO2

 removed in the process. Fabric filters, both because they mix the

SO2 containing gases with the particles collected on the filter, and because they operate at a

generally lower temperature then electrostatic participators (ESPs), collect more SO2 than

ESPs.

B. FLOOR ALLOCATION ESTIMATION METHODS

Estimation of the floor allocation procedure for the cement industry poses several

difficulties. First, there is no demonstrated control technology for control of SO2

 emissions

from cement kilns. Second, emissions from kilns vary considerably due to numerous

variables including kiln type and sulfur content of feedstock. According to EPA AP-42

emission factors, emissions can vary by as much as a factor of 20. Emission data from two

similar kilns in Utah shows that changes in feedstock can cause a change in emissions up

to a factor of 100. Because of this variability and lack of predictability of emissions, the

floor allocation was based on the average emissions from each plant over the past several

years.

C. FLOOR ALLOCATION RESULTS

Table VI-1 shows the allocation results of the emissions to each plant. As discussed

above, the data are based on the emissions reported in State inventories unless otherwise

indicated (See Table VI-2). Several of the sources added new kilns in the past several

years. For these sources only emission data after the new kiln were included. Permit
VI-2

Table VI-1

Floor Allocations

State Plant Name SO2 Floor Allocation (tpy) State Totals (tpy)

AZ Phoenix Cement

Portland Cement Plant

3201

320

CO Holcim Portland 3,374

CO Holcim Laporte 1,402

CO Cemex 160

4,936

ID Ash Grove Inkom 522

522

NV Nevada Cement 305

NV Royal Cement 1432

448

NM Rio Grande 1,1033

1,103

UT Holcim 2672

267

W Y Centex 1654

165

TOTAL 7,761 7,761

NOTES: 1Pe rmit limited potential to em it.

2Only two years after new kiln included.

3Only one year of data available.

4New kiln in 1997.
VI-3

Table VI-2

Cement Manufacturing - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

AZ 4 019 3241 4 Ce m ent/C onc rete Arizona Portland Cement 101 13 10 8

AZ 4 025 41 3241 4 Ce m ent/C onc rete Phoenix Cement <100 197 339 539

CA 6 029 9 13 3241 4 Ce m ent/C onc rete CA L POR TLAN D C EM EN T C O. 429 245 245 245

CA 6 029 20 13 3241 4 Ce m ent/C onc rete CALAVERAS CEMENT CO 286 286 286 286

CA 6 085 17 11 3241 4 Ce m ent/C onc rete KAISER CEMENT CORPORATION HANSON PERMANENTE CEMENT 474 464 416 474

CA 6 087 11 11 3241 4 Ce m ent/C onc rete LONE STAR INDUST CEMENT PLANT RMC P ACIFIC MATE RIALS 250 286 393 314

CA 6 071 7000000 15 3241 4 Ce m ent/C onc rete MITSUBISHI CEMENT 28 574 946 298

CA 6 071 1200003 15 3241 4 Ce m ent/C onc rete RIVERSIDE CEMENT COMPANY 0 527 527 164

CA 6 071 100005 15 3241 4 Ce m ent/C onc rete CEMEX-CALIFORNIA CEMENT 0 0 0 427

CA 6 071 15 3241 4 Ce m ent/C onc rete SOUTHW ESTERN PORTLAND CEMENT C SOUTHDOWN-VICTORVILLE PLANT 108 0 0 0

CO 8 069 0002 52 3241 4 Ce m ent/C onc rete HOLNAM LAPORTE HOLC IM 623 623 375 404

CO 8 043 0001 58 3241 4 Ce m ent/C onc rete HOLNAM PORTLAND HOLC IM 4,069 3,615 3,219 3,288

CO 8 013 0003 53 3241 4 Ce m ent/C onc rete SOUTHWEST PORTLAND CEMEX-LYONS PLT. 967 160 160 50

ID 16 005 0004 7 3241 4 Ce m ent/C onc rete ASHGROVE CEMENT 790 200 200 1,327

NV 32 019 0387 20 3241 4 Ce m ent/C onc rete NEVADA CEMENT COMPANY FERNLEY PLANT 360 340 346 172

NM 35 001 3241 4 Ce m ent/C onc rete RIO GRANDE PORTLAND CEMENT 0 0 0 1,103

UT 49 029 0001 31 3241 4 Ce m ent/C onc rete Holnam Incorporated HOLC IM 911 3 247 288

9,496 7,533 7,709 9,387
VI-4

limits were selected, since the kiln is under construction and there was no actual emission

data. Table VI-3 provides an example of this calculation.

Table VI-3

Example Calculation

Facility

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

Floor

Estimate1

Nevada Cement 340 346 172 286

Holcim Laporte 632 375 404 470

1

Floor estimate base d on the average o f these 3 years.

D. COMPARISON WITH HISTORICAL EMISSIONS

Table VI-2 shows a comparison of emissions to the historical emissions based on

State emissions inventories. Since the floor is based on historical emissions, the general

match is very close, but for any individual plant, the floor may be higher or lower than

recent emissions.

REFERENCES

EPA, 1995: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors (AP-42),” Chapter 11.6, Cement Manufacturing, Office of Air Quality

Planning and Standards, Research Triangle Park, NC, 1995.

PCA, 2001: Portland Cement Association, U.S. and Canadian Portland Cement Industry

Plant Information Summary, Data as of December 31, 2000, Portland Cement

Association, Economic Research Department, 2001.
VII-1

CHAPTER VII

NATURAL GAS PROCESSING PLANTS

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

SO2 emissions from natural gas processing plants result from the combustion of sour

gases. Sour gases may contain less than 1 percent H2S to over 20 percent H2S.

H2S is removed from the natural gas by scrubbing with an amine solution. The

amine solution is heated to regenerate the amine solution. Heating the amine also produces

a very concentrated H2S stream. This H2S stream can be treated to produce sulfur. The

most common treatment is by using a Claus plant. The Claus plant can convert about 80-

98.6 percent of the H2S to sulfur depending on the number of stages and the concentration

of H2S. The average recovery percentage for a 3-stage Claus plant would be about 96

percent, on average. The residual H2S after the Claus plant is either flared or converted to

additional sulfur in a "tail gas" treatment plant like the SCOT or Stretford-Beavon process.

H2S conversion efficiencies of up to 99.9 percent are possible. Residual H2S may be flared.

In addition to the plant tail gas flare, SO2

 emissions also result from upset

conditions at the plant, or in the well field, or emissions when new wells are brought in.

Upsets at the plant cause the sulfur recovery plant to be bypassed and the H2S is flared to

produce SO2

. Upsets in the well field may result in sour natural gas being flared as a safety

precaution to reduce exposure to toxic levels of H2S.

B. FLOOR ALLOCATION ESTIMATION METHODS

The requirements for, and the economics of, sour gas control are a function of a

number of variables, including the amount of H2S in the offgas, the size and age of the

facility, and the air pollution control requirements in existence at the time the facility was

built. Existing sour gas processing plants may have been built in situations where no

regulations existed, under the 1987 NSPS, or under a BACT review under prevention of

significant deterioration regulations.

It was decided that the current NSPS would serve as the floor. The NSPS requires a

variable sulfur removal efficiency based on the H2S content of the acid gas and the amount

of sulfur in the gas. The required emission reduction for each facility was based on the

equations in Table VII-1 since these are the long term reductions called for in the NSPS. If

a facility had current control levels higher than the assumed floor, the actual average

emissions over the past three years were assumed to be the floor. Since emissions from

flaring operations, both in the plant and the well field, are not amenable to control, floor

emissions will be assumed to be the average of three years emissions, whenever the data is

available.
VII-2

Table VII-1

Sulfur Plants - Required Minimum SO2

 Emission Reduction Efficiency

H2S Content of

Acid Gas (Y), %

Sulfur Feed Rate (x), Long Tons per Day

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 74.0 . . . . . . . 85.35X0.0144Y0.0128 . . . . . . .

or 99.8, whichever is smaller

20<Y<50 74.0 . . . . 85.35X0.0144Y0.0128 . . . .

or 97.5, whichever is smaller

97.5

10<Y<20 74.0 85.35X0.0144Y0.0128

or 90.8, whichever is smaller

90.8 90.8

Y<10 74.0 74.0 74.0 74.0

Data availability was a significant issue in determining the floor allocation for some

plants. The data from New Mexico was not adequate to distinguish between process plant,

upset flare, and well field emissions.

C. FLOOR ALLOCATION RESULTS

1. General Plants

Table VII-2 shows the floor allocation calculation for the natural gas processing

plants in the 8 non-California Western Regional Air Partnership (WRAP) States.

In Table VII-2, the plant name and SCC code are those provided in the State

inventory. The emission source column (process or flare) notes whether the emissions are

likely to come from the normal processing of natural gas (process) or the result of upset or

well field emissions (flare). The distinction was made on the basis of comments in the

emission inventory and confirmed in conversations with the State. Current emissions are

based on the average of several years data (2000, 1998, 1996) if available, and on one year's

data if that was all that was available. In some cases, new plants were under construction

and permit levels were used in lieu of actuals. Current reductions were based on data in the

State inventories and confirmed via conversations with State agencies.

Floor emissions vary by the H2S content of the gas, the amount of sulfur produced by

the plant, the age of the plant (older plants are not subject to the NSPS), and State

regulations. In Wyoming, although individual plants vary, the average H2S content of

natural gas is higher than in other States and the degree of control required under the

NSPS is greater. In addition, newer plants tend to be larger and have undergone a BACT

review. In New Mexico, the relatively low H2S content means that less control may be

required under the NSPS. This is due both to the H2S content as well as the small amount

of sulfur produced by the processing plants. However, a State rule (20.2.35 NMAC)

requires a minimum of a 90 percent reduction for plants that release more than 5 tons per

day of sulfur from existing plants regardless of the H2S content of the gas.

The level of control assumed to be the floor will be the most stringent of all of the

potential regulatory requirements. However, the application of the potential floor

procedures can result in no SO2 controls having to be applied on some sources. For

example, the Duke Energy Artesia plant in New Mexico processes less than 2 long tons per

day of sulfur (this is equivalent to about 1,600 tpy of SO2

 emissions) and therefore the

NSPS does not apply. State regulations do not apply, since the sulfur throughput is below

the regulatory threshold. The floor for this plant is based on the average emissions over the

past three years.
VII-3

2. Specific Example

The Burlington Northern Lost Cabin facility in Wyoming provided additional

information needed to demonstrate how the floor calculations could be applied to a specific

facility. The Lost Cabin facility consists of two existing gas processing lines with a capacity

of 133 MMCF/day and has one new train with a capacity of 133 MMCF/day. Both lines

process a gas with a methane concentration of 68 percent, a carbon dioxide concentration of

20 percent, and an H2S content of 12 percent.

Each train is controlled by a three stage Claus unit followed by a SCOT tail gas unit.

The unit is required to have a conversion efficiency of 99.8 percent. Plantwide emissions are

limited to 642 lbs/hr and 1,367 tpy.

The plant underwent a BACT review under PSD and exceeds all requirements of the

NSPS. Under the NSPS, a reduction of 97.5 percent would have been required since the

H2S content of the acid gas stream is 37 percent (which is defined as the gas stream leaving

the amine regenerator and can be calculated as the ratio of the acid gases [H2S and CO2

] in

the input gas stream) and the sulfur production exceeds 300 long tons per day (see Table

VII-1). Since the required reduction exceeds the floor level, the permitted levels represent

the floor.

Since much of the plant is new, no data on upset emissions is available. Emissions

from well-field activities are very variable. Wells are very large at this plant and one very

large well can have up to 1,000 tons of emissions. The plant estimates that annual SO2

emissions of about 500 tpy from well field activities can be expected.

D. COMPARISON WITH HISTORICAL EMISSIONS

Table VII-3 summarizes historical SO2

 emissions from natural gas processing plants

located in the 9 WRAP States. California facilities are included in this table. This table

provides a point of comparison with the floor allocations shown in Table VII-2. For

Wyoming, the historic emissions are close to floor for most sources due to the high level of

control. However, a direct comparison is difficult since the historical emissions may include

well field and upset emissions. Two New Mexico sources will require additional control or

additional emission allocations.
VII-4

Table VII-2

Possible Floor - Natural Gas Processing Units

State Plant SCC

Emission Source

(Process vs Flare) Current % Reduction

Pe rm it

Emissions

Floor

Emission

Reduction

Possible

SO2 Floor

(tpy)

NM Conoco-Maljamar 31000028 Plant 0 3,574 87 222

NM W estern Gas Reso urces 31000208 Plant 90 3,127 90 3,127

NM Agave Energy 31000205 Plant 0 2,983 86.3 365

NM Duke Energy

Eunice

31000208 Plant 90 2,756 90 2,250

NM Duke Energy

Artesia

31000208 Plant 0 1,459 0 1,192

NM Dynergy Midstream

Monument

31000208 Plant 90 1,431 90 675

NM Dynergy Midstream

Sau nders

31000208 Plant 90 1,387 90 163

NM Duke Energy

Pla nt 5

31000205 Plant 96.4 1,300 96.4 1,181

NM Sid Richardson 31000201 Plant 91.7 1,206 91.7 1,206

NM JL Davis Gas Processing

Denton Plant

31000205 Plant 0 1,158 0 840

NM Marathon Oil 31000201 Plant 90 1,100 90 665

NM Duke Energy

Lee Gas

31000299 Plant 93 818 93 0

4

NM ARCO Permian

Empire Abo Plant

31000208 Plant 96 565 96 431

NM Duke Energy

Bu rton Flats

31000205 Plant 0 246 0 164

NM Duke Energy

Dagger Draw Plant

31000208 Plant 98 243 98 218

NM Duke Energy

Huber Gas Plant

31000205 Unknown 0 231 0 163

UT Tom Brown- Lisbon Plant Plant 95 1,593295 1,593

W Y Ho well Petroleu m - Elk Basin 31000205 Plant 93.5 1,200 93.5 1,200

W Y Burlington Resources

Lost Cabin

Plant 99.8 1,3672

99.8 1,367

W Y Burlington Resources

Lost Cabin

Flare 0 50010 500

W Y KC S M ountain

Ainsworth Flare

31000205 Flare 0 843 0 843

W Y KC S M ountain

Rushm ore Flare

31000205 Flare 0 11810 118

W Y Ma rathon Pitchfork Battery 31000205 Flare 0 6110 61

W Y Exxon Shute Creek 31000205 Plant 99.7 1,206 99.7 1,206

W Y Exxon Shute Creek 31000205 Flare 0 33010 330

W Y Amoco W hitney Canyon 31000205 Plant 99 5,379 99 5,379

W Y Amoco W hitney Canyon 31000205 Flare 0 22310 223

W Y Texaco Byron 31000205 Plant 0 200 0 200
Table VII-2 (continued)

State Plant SCC

Emission Source

(Process vs Flare) Current % Reduction

Pe rm it

Emissions

Floor

Emission

Reduction

Possible

SO2

 Floor

(tpy)

VII-5

W Y Chevron Carter Creek 31000205 Plant 99+ 0

3

0

W Y Chevron C arter Creek 31000205 Flare 0 200 0 200

W Y Hallwood Petroleum

Federal Packsaddle 1-24

31000205 Flare 0 133 0 133

W Y Hallwood Petroleum

Federal Packsaddle 1

31000205 Flare 0 96010 960

W Y Oregon Basin Gas Plant 31000205 Plant 90 391 90 391

W Y KC S Gold Eagle Flare 31000205 Flare 0 790 0 790

W Y Interenergy

Hiland Gas Plant

31000205 Flare 0 2811

0 281

W Y Marathon Oil

Mill Iron

31000205 Flare 0 247 0 247

Em ission Totals 39,606 28,884

NOTES: 1. Only one year of data available; 2. Floor based on permit levels; 3. Plant does not incinerate tail gas - no SO2 emitted; 4. Plant has no emissions listed

for the past three years.

State SO2 floor allocations based o n the e stimates in this tab le are N M (12,862 tpy), UT (1,593 tpy), and W Y (14,42 9 tpy).
VII-6

Table VII-3

Oil and Gas Production - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

CA 6 029 1141 13 1311 6 Oil/Gas SANTA FE ENE RGY TEXACO CA INC 1,539 855 2,050 2,050

CA 6 029 1129 13 1311 6 Oil/Gas TEXACO EXPLOR & PROD INC 1 89 112 63

CA 6 029 206 13 1311 6 Oil/Gas BERRY PETR OLEUM COMP ANY 237 0 0 0

CA 6 019 71 12 1311 6 Oil/Gas CHEVRON USA INC. - COALINGA 809 0 0

CA 6 029 272 13 1311 6 Oil/Gas M H WHITTIER SENECA RESOURCES 347 0 0

CA 6 053 19 12 1311 6 Oil/Gas MOBIL OIL CORP - SAN ARDO AERA ENERGY 304 0 1 6

CA 6 029 1135 13 1311 6 Oil/Gas SHELL KERNRIDGE AERA ENER GY LLC 294 <100 82 55

CA 6 019 64 12 1311 6 Oil/Gas SHELL WESTERN E&P INC. - COALINGA 144 0 0

CA 6 029 331 13 1311 6 Oil/Gas SW EPI-WEST COAST DIVISION AERA ENER GY LLC 775 <100 10

CA 6 053 30 12 1311 6 Oil/Gas TEXACO INC - SAN ARDO 100 <100 36 32

CA 6 029 299 13 1311 6 Oil/Gas UNOCAL - BAKERSFIELD UNOCAL OIL & GAS DIVISION 159 0 0

CA 6 059 42775 14 1311 6 Oil/Gas W EST NEW PORT OIL CO 297 <100 10 11

CO 8 045 24 51 1311 6 Oil/Gas UNOCAL RETORT-PARACHUTE 679 0 0 0

CO 8 045 0025 51 1311 6 Oil/Gas UNOCAL UPGRADE 177 0 0 0

NM 35 015 0024 65 1311 6 Oil/Gas AGAVE ENERGY/YATES PLANT 962 962 962 2,983

NM 35 015 0002 65 1311 6 Oil/Gas ARCO PERMIAN/EMPIRE ABO GAS PLNT 700 565 565 565

NM 35 015 0006 65 1311 6 Oil/Gas GPM GAS/INDIAN HILLS AMINE PLNT 900 450 450 900

NM 35 025 0046 65 1311 6 Oil/Gas GPM GAS/LEE GAS PLANT 818 0 818 818

NM 35 025 0007 65 1311 6 Oil/Gas J.L. DAVIS GAS PROCESS/DENTON 385 890 891 1,158

NM 35 025 0052 65 1311 6 Oil/Gas TEXACO/EUNICE NORTH GAS PLANT 673 1,076 1,346 673

NM 35 025 0051 65 1311 6 Oil/Gas TEXACO/EUNICE SOUTH GAS PLANT 4,019 4,386 3,355 5,476

NM 35 015 0003 65 1311 6 Oil/Gas TRANSWESTERN PIPE DUKE ENERGY/HUBER GAS 221 231 231 231

NM 35 041 0001 63 1311 6 Oil/Gas W ARREN PETROLEUM/BLUITT GAS PLANT 270 3,348 582 270

NM 35 025 0061 65 1311 6 Oil/Gas W ARREN PETROLEUM/MONUMENT PLANT MONUMENT PLANT 1,460 1,709 1,432 1,432

NM 35 045 0247 60 1311 6 Oil/Gas W ESTERN GAS PROCESSORS/SAN JUAN RVR 5,475 980 980 3,138

NM 35 025 0128 65 1311 6 Oil/Gas CITATION/ANTELOPE RDG GAS PLANT 291 0 NA

NM 35 025 0118 65 1311 6 Oil/Gas CON OCO /BELL LAKE 2 W ELL #6 129 0 NA

NM 35 015 0125 65 1311 6 Oil/Gas FEAGA N ENE RGY/W DAGG ER DR AW GAS P LT 240 0 NA

NM 35 005 0050 65 1311 6 Oil/Gas YATES PETROLEUM/PATHFINDER AMINE 227 57 57
Table VII-3 (continued)

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

VII-7

UT 49 037 35 1311 6 Oil/Gas UNOCAL CORPORATION TOM BROWN - LISBON PLANT 1,575 1,391 1,478 1,252

W Y 56 029 0012 9 1311 6 Oil/Gas AM OCO - ELK BA SIN HOW EL L PET ROLE UM - ELK B AS IN 1,096 1,218 1,422 2,638

W Y 56 041 0012 9 1311 6 Oil/Gas AMOCO - WHITNEY CANYON 6,401 5,835 11,130 6,889

W Y 56 041 0009 9 1311 6 Oil/Gas CHEVRON - CARTER CREEK 1,537 1,165 3,330 2,096

W Y 56 023 0013 8 1311 6 Oil/Gas EXXON - SHUTE CREEK 1,078 1,999 2,015 1,383

W Y 56 1311 6 Oil/Gas EXXON BLAC K CAN YON DE HY & W ELL FIELD 167

W Y 56 017 9 1311 6 Oil/Gas KCS MO UNTA IN RESOU RCES - GOLDEN E AGLE 558 942 17

W Y 56 003 9 1311 6 Oil/Gas KCS MOUNTAIN RESOURCES - AINSW ORTH 807 845 0

W Y 56 029 0007 9 1311 6 Oil/Gas MA RAT HON GAS PLAN T - OREG ON BA SIN 406 456 388 358

W Y 56 017 9 1311 6 Oil/Gas MARATHON OIL - MILL IRON 234 260 0

W Y 56 003 0012 9 1311 6 Oil/Gas TEXAS-BYRON PLANT BIG HORN GAS PROCESSING - BYRON 192 169 605 257

W Y 56 037 0008 9 1311 6 Oil/Gas UNION PAC - BRADY RME PETRO LEUM - BRADY 415 331 576 300

W Y 56 013 008 9 1311 6 Oil/Gas DEVON SFS OPERATING CO. BEAVER CREEK 831

W Y 56 037 0014 9 1311 6 Oil/Gas COLORADO INTERSTATE GAS - TABLE ROCK 522 20 39

W Y 56 003 0013 9 1311 6 Oil/Gas MARATHON OIL COMPANY - GARLAND 257 7 10

W Y 56 013 9 1311 6 Oil/Gas LO UISIA NA LAN D & E XPLO R - LO ST CA BIN BU RLIN GTO N RE SO URCES -LO ST CA BIN 4,547 1,336 1,700

36,111 34,735 38,346 37,749
VII-8
VIII-1

CHAPTER VIII

ELEMENTAL PHOSPHORUS PRODUCTION

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

P4 Production has an elemental phosphorus facility near Soda Springs, Idaho. This

is one of the two elemental phosphorus production facilities in the United States. Year

2000 SO2 emissions from this facility are estimated to be 15,861 tpy. This reflects increased

utilization compared with 1996 and 1998 operations. This facility has no SO2 emissions

limit in its operating permit. The Idaho Department of Environmental Quality is currently

evaluating this facility’s SO2 emissions situation. For the purposes of this report, the floor

allocation for P4 Production is set at its year 2000 SO2 emissions level of 15,861 tons. It is

expected that the State of Idaho will perform a more detailed evaluation of this facility

during preparation of its regional haze State Implementation Plan (SIP).

B. FLOOR ALLOCATION ESTIMATION PROCEDURES

Recent historical emissions for P4 Production are listed below in Table VIII-1.
VIII-2

Table VIII-1

Elemental Phosphorus Production - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

ID 16 029 0001 7 2819 5 Chem icals/Plastics MONSANTO/P4 PRODUCTION P4 PRODUCTION 7,543 7,988 7,601 15,861
IX-1

CHAPTER IX

GLASS MANUFACTURING

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

The air emissions from glass manufacturing are in three zones: (1) raw material

blending and transport, (2) melting, and (3) forming and finishing. The majority of air

emissions are in the melting furnace operation.

Melting for container and flat glass is generally conducted in a continuous

reverbatory furnace fired by natural gas or oil. Electric boost furnaces have been

introduced in some operations to minimize flue gas emissions.

The major source of SO2 emissions in the glass industry is the glass melting

operation. Forming and annealing operations are minor sources. Furnace emissions

appear to be attributable to both the manufacturing process and the fuel burned. Fuelderived SO2

 emissions are lower from natural gas-fired furnaces than from oil-fired

furnaces, unless the oil has been desulfurized. Flue gases from furnaces burning natural

gas have been reported to contain 2 parts per million (ppm) SO2

, or less. About 600 ppm

SO2

 can be expected in flue gas from a furnace burning fuel oil containing one percent

sulfur. Greater use of electric furnaces or electric boosting may decrease SO2

 emissions.

Process modifications that may reduce SO2 emissions include altering the raw

material charge to reduce the sulfur content or to increase the fraction of recycled glass,

changing the furnace controls or equipment, and altering the pull rate. Process

modifications that reduce the salt cake content in the raw batch can significantly reduce

SO2

 emissions. For example, one California flat-glass plant reportedly reduced furnace

emissions of SO2 by 78 percent from 2.1 to 0.5 kilograms per megagram (kg/Mg) (5.0 to 1.1

lbs/ton) by reducing the salt cake in the raw batch 60 percent (from 12 to 5 kg/Mg, 30 to 12

lbs/ton of sand). Similarly, another California flat-glass plant has reportedly reduced its

SO2 emissions 75 percent (from 1.6 to less than 0.4 kg/Mg, 4 to less than 1 lbs/ton of batch

constituents) by reducing the input of salt cake. Glass quality was not compromised in

either case. The salt cake cannot be reduced below certain minimums without effecting

glass quality. The minimum salt cake required varies depending upon furnace type, pull

rate, glass type, and other variables.

Fuel changes have also been shown to reduce SO2 emissions. These include

switching to natural gas or low-sulfur fuel oil, switching to all-electric melting, and using

electric boosting for melting. Electric melters significantly reduce SO2, NOx, and

particulate emissions because they eliminate the combustion of fossil fuels. Electric

melting also is reported to minimize SO2 and other gaseous losses from the vaporization of

raw materials because the surface of the melt is insulated by a semisolid crust. Gases

discharged through the crust of the melt consist mainly of carbon dioxide and water. 

Today, borosilicate, opal, and green glass are produced with electric furnaces. The

capacities of such furnaces are about 100 to 110 Mg/day (110 to 120 tons/day). Electric

melters have not been demonstrated for larger operations, such as large container furnaces,

the nominal capacities of which are about 220 Mg/day (240 tons/day), and flat-glass

furnaces, which range from about 600 to 800 Mg/day (660 to 880 tons/day).

Several emission control systems that are available to the glass industry for

particulate control are also capable of achieving various levels of secondary SO2 control. 

For example, a venturi scrubber system can control SO2 emissions from commercial glass

plants. The system includes a packed tower where part of the sulfate particulates are

removed from the hot furnace flue gases, a dual-throat venture scrubber, where SO2 and
IX-2

additional particulates are removed by alkaline washing, and a cyclone for final particulate

collection. Currently, only the container glass segment of the glass industry is reported to

use scrubber systems for emission control.

Injecting a sorbent such as alumina, limestone, or nepheline syenite into a fabric

filter system can effectively remove SO2

 from furnace flue gases. The spent sorbent may be

landfilled or possibly recycled.

One patented system of dry removal involves the combined use of hydrated lime and

nepheline syenite for acid gas neutralization and fine particle agglomeration. In this

system, hot furnace flue gas is first mixed with quench water, hydrated lime for primary

SO2

 removal, and secondary air to cool the gas stream to a temperature range of 94o to

427oC (200o

 to 800oF). Next, nepheline syenite is added to the gas stream to capture

residual SO2 and submicrometer particulates. The gas stream enters the fabric filter where

the solid product is removed for either recycling to the furnace or landfilling.

Dry sorbent systems at several commercial glass furnaces reduced SO2 by 80 to 95

percent at a container glass furnace, 50 to 90 percent at a fiberglass furnace, and 88 to 98

percent at a flat-glass furnace.

Mist eliminators apparently have no effect on SOx gases. One sampling test

indicated no decrease in SO2 and SO3 concentrations through the control device (EPA,

1981).

B. FLOOR ALLOCATION ESTIMATION METHODS

It is expected that the floor allocation for glass manufacturing plants will be set

according to recent historical SO2 emissions from these facilities. These SO2 emissions are

listed in Table IX-1.

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 15 - Mineral Products Industry, 2000.

EPA, 1981: U.S. Environmental Protection Agency, “Control Techniques for Sulfur Oxide

Emissions from Stationary Sources,” Second Edition, EPA-450/3-81-004, Office of Air

Quality Planning and Standards, Research Triangle Park, NC, April 1981.
IX-3

Table IX-1

Glass Manufacturing - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

Floor

Allocation

CA 6 037 106797 14 3221 8 Glass BALL-FOSTER GLASS CONTAINER CO SAINT-GOBAIN CONTAINER <100 <100 166 174

CA 6 099 1662 11 3221 8 Glass GALLO GLASS CO 61 271 269 440

CA 6 039 801 12 3221 8 Glass MADERA G LASS COMPA NY 108 170 190 104

CA 6 077 593 11 3221 8 Glass OW ENS ILLINOIS OW ENS-BROCKWAY GLASS CONTAINER 319 285 218 248

CA 6 037 7427 14 3221 8 Glass OWENS-BROCKWAY GLASS CONTAINER - VERNON 193 323 280 435

CA 6 001 2086 11 3221 8 Glass ANCHOR GLASS CONTAINER CORPORA 119 0 0

CA 6 001 30 11 3221 8 Glass OW ENS-BROCKWAY GLASS CONTAINER - OAKLAND 122 128 64 57

CO 8 059 0008 53 3221 8 Glass COORS GLASS ROC KY MOU NTAIN BOT TLE 159 221 234 255 237

OR 41 051 1876 5 3221 8 Glass Owens-Brockway Glass Container, Inc. 103 169 116 108 131

1,284 1,667 1,537 1,821
IX-4
X-1

CHAPTER X

COPPER SMELTERS

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Primary copper smelters in the WRAP States process copper sulfide ore concentrate

to produce anode copper. There are six primary copper smelters in the WRAP region. Five

of the primary copper smelters are near the copper mines in the southwest United States. 

These smelters use a batch copper converting process (either Pierce-Smith or Hoboken

converter designs) to produce blister copper. Currently, only two of these smelters are

producing copper (the ASARCO smelter in Hayden, Arizona and the Phelps Dodge smelter

in Miami, Arizona). The other three smelters have suspended operations and are not

producing copper at this time.

The sixth primary copper smelter in the WRAP States is the Kennecott Utah Copper

Corporation near Garfield, Utah. The Kennecott smelter was built during the mid-1990s

(replacing the existing smelter at the site) and uses a flash copper converting technology. 

This technology allows blister copper to be produced in a continuous process.

All primary copper smelters in the region control SO2

 emissions by routing the

process off-gases from the smelting and converting processes to double contact sulfuric acid

plants.

B. FLOOR ALLOCATION ESTIMATION METHODS

Because of the uniqueness of the existing copper smelters, retrofit technology

analysis must be performed on a smelter-by-smelter basis. Currently, the Hidalgo smelter

is the only BART-eligible source in this category. A double contact acid plant is considered

the appropriate retrofit control equipment (all smelters in the western States are currently

equipped with double contact acid plants). On August 21, 2000, New Mexico completed an

engineering analysis that verified earlier determinations by the MTF that the fugitive SO2

capture system at Hidalgo satisfies BART at 96 percent overall SO2 capture.

The Annex to the Grand Canyon Visibility Transport Commission’s (GCVTC)

recommendations defines stepped reduction milestones through 2018 for SO2

 emissions

from large industrial sources in the 9-State Commission Transport Region. The current

year SO2 allocation for the six copper smelters in the 9-State region is 86,000 tons. This

allocation is reduced to 78,000 tons by 2013 and is the same in 2018. For the recent

Emission Forecasts to 2018 analysis, the plant-level difference SO2

 emissions difference

between 86,000 tons and 78,000 tons was simulated by subtracting 2,000 tons each from

the four largest smelters, which are ASARCO-Hayden, BHP-San Manuel, Phelps-Dodge

Chino Mines, and Phelps Dodge-Hidalgo. The resulting allocations of 2018 SO2

 emissions

by facility are shown in Table X-1. Note that the 78,000 tons of SO2

 allocation for copper

smelters is an aggregate value for the region, rather than a requirement for each smelter to

reduce emissions to prescribed levels. Table X-1 illustrates one way that this regional

allocation might be met. Many other examples are provided in the EPA regional haze rule.
X-2

Table X-1

Copper Smelter SO2 Emission Projections (tpy)

State Facility Name 2018

AZ ASARCO Smelter-Hayden 21,000

AZ BHP-San Manuel 14,000

AZ Cyprus Miami Mine 8,000

NM Phelps Dodge-Chino Mines 14,000

NM Phelps Dodge-Hidalgo Smelter 20,000

UT Kennecott Utah Copper Corp. 1,000

Total Copper Smelter 78,000

C. COMPARISON WITH HISTORICAL EMISSIONS

Table X-1 SO2

 emission estimates can be compared with recent historical (1990 to

2000) emissions for those smelters shown in Table X-2.
X-3

Table X-2

Recent Historical Copper Smelter SO2 Emissions

State

State

ID

County

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2 tpy

1990

SO2 tpy

1996

SO2 tpy

1998

SO2 tpy

2000

Smelter Sector

AZ 4 007 0004 45 3331 2 Copper ASARCO SMELTER - HAYDEN 29,814 33,124 22,077 16,753

AZ 4 021 0032 46 3331 2 Copper BHP(Magm a Metals) BHP - San Manuel 15,900 16,678 10,409 0

AZ 4 007 0006 45 3331 2 Copper CYPRUS MIAMI MINE 5,676 5,737 6,097 6,810

AZ 4 019 0040 46 1021 2 Copper Cyp rus Sie rrita 800 548 <100 <100

NM 35 017 0001 64 3331 2 Copper PHELPS DODGE/CHINO MINES 28,058 14,784 15,685 11,420

NM 35 023 0003 64 3331 2 Copper PHELPS DODGE/HIDALGO SMELTER 41,433 32,121 29,188 0

UT 49 035 0030 32 3331 2 Copper Kennecott Utah Copper Corp. 26,829 1,556 762 937

148,510 104,549 84,218 35,920
X-4
XI-1

CHAPTER XI

ALUMINUM PRODUCTION

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Primary aluminum production plants in the United States produce aluminum metal

by electrolytically reducing alumina that have been refined from bauxite ore. There are 23

primary aluminum plants in the United States. There are only 2 plants in the study region

and both are located in Oregon.

Aluminum production is carried out in a semibatch manner in large electrolytic cells

called pots with a direct current input of up to 280,000 amperes at about 5 volts. The pot, a

rectangular steel shell ranging in size from 30-50 feet long, 9-12 feet wide, and 3-4 feet

high, is lined with a refractory insulating shell on which carbon blocks are placed to form

the cathode.

An aluminum pot will typically emit 20-35 kg per metric ton of gaseous and

particulate fluoride and roughly an equal amount of particulate matter. The NSPS limits

emissions to no more than 1 kg fluoride/Mg (2.0 lbs/ton) of aluminum produced for potroom

groups at Soderberg plants, 0.95 kg/Mg (1.9 lbs/ton) of aluminum produced at pre-bake

plants, and 0.05 kg/Mg (0.1 lbs/ton) of aluminum equivalent for anode bake plants.

The reduction cells in use for aluminum production in the United States are of two

basic types – prebake and Soderberg. There are two types of Soderberg cells that are

designated according to the manner of mounting the stud in the carbon anode: vertical stud

Soderberg (VSS) or horizontal stud Soderberg (HSS).

Prebake cells are so named because the anodes are preformed and then baked in a

separate facility often referred to as an anode bake plant. The anodes are then mounted in

the cell and are consumed in the aluminum production. The anode butts, which remain

after the anode is consumed, are recycled for use in the preparation of new anodes.

In the Soderberg process, continuously formed, consumable anodes are used. The

anode paste is baked by the heat generated in the reduction cell.

The primary source of sulfur oxide emissions in aluminum production is the sulfur

in the coke (normally petroleum coke) and the coal tar pitch binder used to produce the

anodes. In the prebake process, the combustion fuel to bake the anodes may be a

significant SO2 emission source. Petroleum coke usually contains 2.5 to 5 percent sulfur,

but may vary from 1.5 to 7 percent sulfur. Pitch normally contains about 0.5 percent

sulfur. The sulfur content of the coke depends on the crude petroleum stock and the

tendency of the sulfur to concentrate in the still bottoms at the refinery and thus in the

coke.

As the coke is processed (during prebake) or consumed in the reduction cell, sulfur

oxides are released. The emissions include those from the anode prebake operation

(prebake), the “primary” emissions (which are captured by the pot hood exhaust system),

and the “secondary” emissions (which escape the primary exhaust system and exit through

the roof monitors). The great majority of SO2 emissions are collected by the pot hood

exhaust system.

One source reports uncontrolled SO2 emissions from anode bake plants range from 5

to 47 ppm, which is 0.7 to 2 kg SO2/Mg aluminum produced (1.4 to 4 lbs SO2/ton aluminum
XI-2

produced). Other data indicate that emissions are in the range of 0.09 to 1.7 kg SO2/Mg

aluminum produced (0.18 to 3.4 lbs SO2

/ton aluminum produced).

The total amount of SO2 generated per unit of aluminum produced is essentially the

same for the prebake, VSS, and HSS cases. The “primary” cell hooding configuration for

collection of process fumes is affected by the characteristics of the different cell types. 

There are two types of prebake cells, center-worked prebake cells (CWPB) and side-worked

prebake cells (SWPB), as well as the two Soderberg processes, VSS and HSS, which are in

use by the domestic aluminum industry. Information from seven primary aluminum plants

indicates the following:

Cell Type

Primary Hood Collection

Efficiency, %

Primary Collector Exhaust Rate

(106

 square cubic feet per ton of aluminum)

CWPB 65 to 98 (4.11 to 5.05)

SWPB 85 (3.44)

VSS 81 (0.67)

HSS 80 to 95 (5.06 to 7.85)

This information indicates that the gas volume associated with the production of a

fixed amount of aluminum is in the range of 5 to 12 times (average 8 times) greater for

CWPB, SWPB, or HSS than for VSS. Consequently, the concentration of SO2

 in a volume of

exhaust gas in the primary collector system can be expected to be about 8 times greater for

a VSS unit than for other units.

Reported data on uncontrolled “primary” exhaust system SO2 emissions are as

follows:

Unit Source SO2

 Concentration, ppm

Total SO2 emissions,

kg SO2

/Mg Aluminum

(lbs SO2

/ton aluminum)

Prebake Cell A 5 Not reported

B Not reported 20.9 to 23.4 (41.7 to 46.8)

[average of 22.4 (44.8)]

C Not reported 30 (60) [3% sulfur in the coke]

VSS Cell A 80 Not reported

B 200 to 300 17.5 to 25 (35 to 50)

C 200 (average) Not reported

The trend in construction of new aluminum plants is toward prebake systems. A

major factor influencing this trend is the lower power requirement of the prebake cell

compared with Soderberg cells. It is reported that 9 of the 11 aluminum plants opened

since 1960 are of the prebake type, and 99 percent of the 324 Gigagrams (357,000 tons)

capacity added since 1973 has been at prebake facilities. Of the 23 primary aluminum

production plants in the United States, 18 use the prebake process and 5 use the Soderberg

process.

B. FLOOR ALLOCATION ESTIMATION METHODS

There are two aluminum smelters located within the study region, and they are both

located in Oregon. The data provided by the Oregon Department of Environmental Quality

on the unit capacities and SO2 emissions potential for these two smelters is provided in

Table XI-1. This table shows that the SO2 emissions potential for Reynolds Metal, if

operated at its design capacity, is 4,700 tpy. This is the same as their permitted SO2

emission limit. For NW Aluminum, the SO2

 emissions potential is 518 tpy.
XI-3

The NSPS for primary aluminum plants limits fluoride emissions, but does not

affect SO2

 emissions. Washington is the only State that has established an SO2

 emission

limit specifically for primary aluminum plants. The rule limits the maximum allowable

total SO2 emissions from all sources within the plant to 60 lbs per ton of aluminum

produced on a monthly basis. Based on the SO2 emission rates by process for Reynolds

Metal, which is 65.3 lbs SO2

 per ton of aluminum produced, applying the State of

Washington rule would only provide an 8 percent reduction in SO2 emissions.

Comparing the capacity-based SO2 emission estimates in Table XI-1 with recent

historical emissions (see Table XI-2) shows that recent historic SO2 emissions from

Reynolds Metals are considerably below their capacity/permitted emission limit, and that

they vary considerably from year-to-year. NW Aluminum SO2

 emissions in the period 1996

to 2000 average about 80 percent of total capacity.

The floor control technology for aluminum smelters was determined by evaluating

the emissions performance of Reynolds Metals and NW Aluminum. NW Aluminum uses a

wet scrubber to achieve a 70 percent SO2 emission reduction. Therefore, a wet scrubber

with a 70 percent SO2

 reduction was selected as the floor technology for aluminum

smelters. The effect of this floor technology application is shown in the rightmost column of

Table XI-1.

REFERENCES

CFR, 2001: Code of Federal Regulations, “Subpart S - Standards of Performance for

Primary Aluminum Plants (60.190-60.195),” July 1, 2001.

EPA, 1981: U.S. Environmental Protection Agency, “Control Techniques for Sulfur Oxide

Emissions from Stationary Sources,” Second Edition, EPA-450/3-81-004, Office of Air

Quality Planning and Standards, Research Triangle Park, NC, April 1981.
XI-4

Table XI-1

Aluminum Plant Data Used to Estimate Floor Allocations

Company Em issions U nit Fuel Type

Actual

Capac ity

Capac ity

Units

Control

Device

SO2

 Emission

Factors

(lbs/ton)

SO2 Control

Efficiency

SO2

 Emissions

Actual Capacity

(tons/yr)

Floor Allocation

at 70% Control

(tons/yr)

Re ynold s M etals Carbon bakes

Potroom fugitives

Potroom emissions

Backup fuel

Plant total

Natural gas

N/A

N/A

#2 fuel oil

N/A

N/A

0.18-.19

2.5

62.5

0.105

N/A

N/A

27 

177 

4,488 

7.5 

4,700 

27 

177 

1,346.4 

7.5 

1,557.9 

NW Aluminum Cell line

Cell line

Casthouse furnace

Plant total

N/A

Propane

Natural gas

97,500

144,000

80,000,000

TAP/yr

gallons/yr

cubic fee t/yr

W et scrubber

No

No

0.7

N/A

N/A

517 

<0.1 

1 

<518 

517 

<0.1 

1 

518 

Total 5,218 2,076 

NOTES: Control Device: While there are no physical control devices, the most effective form of SO2

 control is limiting the amount of sulfur in fuel oil. For example, the sulfur

content in distillate fuel oil sold in NW usually averages much less than 0.1, whereas the rule limit is 0.5. Actual Capacity Emission is limited by the SO2

 PSEL. SO2

emission factors are in lbs per ton of aluminum produced.
XI-5

Table XI-2

Aluminum Smelting - Historical Emissions - 1990 to 2000

Sta te

Sta te

ID

Co unty

ID

Fac ility

ID

IAS

Region SIC

MTF

Sector Sector Description Facility Name (1990)

Current Facility Name

(if different from 1990)

SO2

tpy

1990

SO2

tpy

1996

SO2

tpy

1998

SO2

tpy

2000

100 tpy or More SO2

OR 41 065 0001 5 3334 10 Me tals/Min ing/Min erals Northwest Aluminum Com pany, Inc. 423 448 375 397

OR 41 051 1851 5 3334 10 Me tals/Min ing/Min erals Reynolds Metals Company 3,340 0 503 1,510

3,763 448 878 1,907
XI-6
XII-1

CHAPTER XII

SULFURIC ACID PLANTS

Sulfuric acid is the most widely used industrial chemical. The chief uses of sulfuric

acid are in production of fertilizer, manufacture of chemicals, oil refining, pigment

production, iron and steel processing, synthetic fiber production, and metallurgical

operations. The predominant process used for the production of sulfuric acid is the contact

process. The entire discussion in this chapter focuses on the contact process.

Sulfuric acid is produced by burning sulfur or sulfur-bearing materials to form SO2. 

Sources of SO2

 include: (1) elemental sulfur; (2) spent acid; (3) smelter off-gas; (4) pyrites;

and (5) waste gas from fossil-fuel-fired boilers.

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Contact sulfuric acid plants are classified as hot gas (sulfur burning) or cold gas

(metallurgical and spent acid) systems. Plants operating on elemental sulfur receive hot

SO2

 gas directly from the sulfur burner and waste heat recovery system. When SO2

 gas

from a metallurgical operation or other byproduct source (such as spent acid or iron pyrites)

is used, it is received cold from the wet scrubber-cooler and purification systems.

A basic variation of the contact process is the double absorption technique, also

known as double catalysis. This design is largely based on the need to meet air pollution

control regulations.

The only significant source of air emissions from a contact sulfuric acid plant is the

tail gas leaving the final absorbing tower. This gas contains small amounts of SO2

 and even

smaller amounts of SO3, sulfuric vapor, and sulfuric acid mist.

SO2 emissions are determined primarily by overall plant design (e.g., number of

catalyst passes, amount of catalyst, dual or single absorption, etc.). New plants are usually

designed to meet NSPS emission limits using the dual absorption process. In certain

situations, plants can achieve better than NSPS limits using the dual absorption process. 

For example, in a metallurgical acid plant, lower SO2

 emissions can sometimes be achieved

catalytically if the process gas from a smelter has a sufficiently high oxygen-to-SO2 ratio. 

Proper catalyst volumes and interpass cooling can be incorporated into the initial design,

however. Existing plants that are required to reduce their SO2 emissions usually choose to

convert to dual absorption or install a tail gas scrubber.

Dual absorption has been generally accepted as BACT. Conceptually, dual

absorption is the addition of another converter and absorbing tower on the tail end of a

single absorption plant (with appropriate heating and cooling of the gas stream) so there is

no new technology involved. Only sulfuric acid is produced in the dual absorption

equipment.

Various scrubbing, or tail gas, technologies are available for removing SO2 from gas

streams. Tail gas treatment is rarely used to achieve NSPS limits for new plants. A tail

gas process at the end of a dual absorption plant may be the preferred technology where

local regulations require substantially lower than NSPS emission rates.

Tail gas processes that produce a by-product that can be recycled to the acid plant

(e.g., weak sulfuric acid) are of special interest because they eliminate the need for off-site

by-product disposal. Two such processes are hydrogen peroxide scrubbing and SO2

oxidation with activated carbon.
XII-2

B. FLOOR ALLOCATION ESTIMATION METHODS

Based on the information available for sulfuric acid plants in the west, it was

determined that it is appropriate to estimate the floor allocation by applying the NSPS

requirements to each sulfuric acid plant.

Subpart H - Standards of Performance for Sulfuric Acid Plants

60.82 Standard for Sulfur Dioxide

On or after the date on which the performance test required to be conducted by Sec.

60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause

to be discharged into the atmosphere from any affected facility any gases which contain SO2

in excess of 4 lbs per ton of acid produced. Achieving this standard requires a conversion

efficiency of 99.7 percent in an uncontrolled plant, or the equivalent SO2 collection

mechanism in a controlled facility.

Table XII-1 lists the sulfuric acid plants, their characteristics, and the estimated

annual SO2

 floor allocations. An initial SO2

 floor allocation was estimated by multiplying

the daily throughput limit by the NSPS emission rate (4 lbs SO2 per ton 100 percent acid

produced), times 365 days per year, converted from lbs to tons by dividing by 2000. In

equation form, this is:

This based on throughput initial floor allocation was found to exceed the annual SO2

permit limits for each of these units. Therefore, the estimated floor allocations for these

sulfuric acid plants was established using recent historic SO2

 emissions data. These

historic emission values are all slightly below the annual SO2 permit limits.

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 12 - Chemical Process Industry, 2000.

CFR, 2001: Code of Federal Regulations, Subpart H - Standards of Performance for

Sulfuric Acid Plants (60.82), July 1, 2001.

Idaho DEQ, 2002a: State of Idaho, Department of Environmental Quality, Air Quality Tier

1 Operating Permit, J.R. Simplot Co. - Don Siding Plant, 2002.

Idaho DEQ, 2002b: State of Idaho, Department of Environmental Quality, Air Quality Tier

1 Operating Permit, Nu-West Industries, Inc.; Agrium Conda Phosphate Operations,

2002.
XII-3

Table XII-1

Sulfuric Acid Plants

State Facility Name

Start

Date

Sulfuric Ac id

Plant ID Process

Control

Technique

Annual SO2

Pe rm it Lim it

(tons)

Da ily

Throughput

Limit (tons)

Based on

Throughput

SO2 Floor

Alloc ation (tpy)

Floor Allocation

Us ing His toric

Emissions

Average (tpy)

Idaho Nu-W est Industries East NA NA 945 1,550 1,131 612

Idaho JR Simplot 300 Single contact 2 stage scrubber system 750 1,750 1,277 1,939

400 Doub le contact Doub le contact with mist

eliminator

1,458 NA 1,458

W yom ing SF Pho sphates, Inc. 1995 Source 9b MEC 963.6 1,320 964 1,638

1984 Source 9a Lurgi 1,387 1,900 1,387

W yom ing Koch Sulfur

Pro ducts

EU -1 NA 719 NA 719 1,197

EU -5 NA 721 NA 721

NA = not available.
XII-4
XIII-1

CHAPTER XIII

METALLURGIC COKE PRODUCTION

A. SECTOR DESCRIPTION AND SIGNIFICANT SO2 SOURCES

Metallurgical coke is derived from coal and used in iron and steel industry processes. 

Coke is manufactured by pyrolysis, the heating of coal in the absence of air. In this process,

high grade, bituminous coal is heated in a enclosed chamber to approximately 1050°C

(1925°F), which removes all volatile components of the coal. The resulting product is a solid

material consisting of elemental carbon and any minerals that were not volatilized in the

heating process.

1. By Product Coke Ovens

In a typical coking operation, 35 to 100 coke ovens are located in a row referred to as

the oven battery. Each oven has three main parts: coking chambers, heating chambers,

and regenerative chambers. The coking chamber has ports in the top for charging (loading)

of the coal. A typical U.S. coke oven produces 7.5 tons to 39 tons of coke per cycle. Most

coke plants are co-located with iron and steel production facilities.

All ovens currently operating in the United States are by-product recovery ovens. 

These ovens operate by reusing gases (volatiles) emitted by the hot coal. In by-product

recovery ovens, the volatiles from the coal are collected and sent to a by-product recovery

plant. The off gas is condensed and separated into a liquid fraction (coal tar) and a gaseous

fraction (coal gas). The coal gas contains a number of contaminants including hydrogen

sulfide. Some by-product recovery processes remove the sulfur from the gas prior to

combustion. Approximately 33 percent to 40 percent of the clean coal gas is then returned

to the oven battery to be used as fuel. The remaining coal gas can be used as fuel for other

processes at the plant or sold to other facilities.

Emissions of SO2 from coke ovens operations primarily result from combustion of the

byproduct coal gas in the oven. A small portion of SO2 emissions comes from uncontrolled

“charging”, the process of loading coal into the oven. Control of SO2

 from combustion of coal

gas is primarily accomplished by; (a) removing the sulfur from the gas prior to combustion

or (b) utilizing low sulfur coal in the coking process. There are a number of methods for

removing sulfur from the coal gas, such as wet scrubbing.

2. Rotary Calciners

There is only one known rotary calciner used for coke production in the United

States, P4 Production in Rock Springs, WY. It uses a Salem Brosius, 65 foot diameter,

continuous feed rotary hearth calciner. Basically, the process involves feeding a mixture of

coal and petroleum (pet) coke onto a rotating table located inside a furnace. The coal is

heated to a high temperature as it rotates to produce coke. The coke exits the hearth and

enters a cooling chamber. Like byproduct recovery ovens, the furnace operates by reusing

the volatile gases emitted from the coal. However, in this process, the furnace is initially

started with natural gas. Once started, the coal gas being emitted during the coking

process is utilized as fuel directly. The waste gas is then ducted to an incinerator.

Byproducts of the process include fine coke, ash, CO2, SO2, and rock.

Emissions of SO2

from a rotary hearth calciner are primarily due to the volatiles from

the heated coal. The waste gas is ducted to an incinerator and baghouse prior to being
XIII-2

emitted to the atmosphere. There is no desulfurization of the waste gas. The amount of

SO2

 emitted from the facility is a function of the properties of the feed coal. 

B. FLOOR ALLOCATION ESTIMATION METHODS

The analysis was limited to facilities which emit greater than 100 tpy of SO2 in total. 

There are three facilities which have been identified. Two are coking plants, Astaris

Coking Plant in Wyoming and Geneva Steel in Utah. There is one rotary calciner in

Wyoming, P4 Production, Rock Springs Coal Calcining Plant. The air pollution agencies for

Wyoming and Utah provided information on the coking and calcining facilities for

estimating floor allocations. 

Astaris Coking Plant was shut down in April of 2001. Therefore, this facility does

not receive an SO2

 allocation. 

Geneva Steel has committed to ceasing all SO2 emissions from the coke ovens and

the sinter plant. These emissions have been banked for future use or trading as precursor

pollutants within the current local Utah County PM10 SIP. The Utah Air Quality Board

approved this change on June 5, 2002. Since the SO2

 emissions for coking and sintering at

the plant are now essentially zero, the SO2 floor allocation for coking is also zero. 

The third facility is P4 Production, Rock Springs Coal Calcining Plant. The plant is

designed to process 220,000 tpy of feed materials to produce 110,000 tpy of coke product. 

The plant operates for up to 8,000 hours per year. This works out to a design process rate

of 27.5 tons per hour (tph) or 660 tons per day (tpd) of feed. According to the operating

permit, the total facility potential to emit is 2,841.1 tpy of SO2 based on 8,760 operating

hours. There are no NSPS requirements the facility must comply with for SO2

. This rotary

coker was built in 1972 and thus is "grandfathered" from the Wyoming Air Quality

Division's permit requirements. The historical emissions for this facility are presented in

Table XIII-1.

Table XIII-1

Historical SO2

 Emissions at P4 Production, Rock Springs, WY

Historical Emissions of SO2

 (tpy) Average Annual SO2

Emissions (tpy)

1990 1996 1997 1998 2000 1996 - 2000 

933 663 586 642 633 631

As stated previously, the SO2

 emitted is a function of the feed coal. The plant uses a

blend of coal and petroleum coke (pet coke). The 1994 annual inventory showed that the

pet coke blend was 7.2 percent for the year, with SO2 emissions of 420.0 tpy; up 15 percent

from the 365.6 tpy emitted in 1993, when straight coal was used as 100 percent of the

feedstock. The most recent year's data shows that the pet coke blend was 25 percent for

1998, the maximum allowable amount to maintain compliance with the SO2

 emissions

limit.

The procedure for estimating the floor allocation for P4 Productions is difficult for

several reasons. First, there are no identified control technologies available for the rotary

calciner. Second, there are no NSPS requirements. Third, P4 Production has a potential to

emit 2,841.1 tpy based on 8,760 hours of operation. This is much higher than the annual

emissions reported by the plant. Lastly, the SO2 emissions from the rotary calciner are a

function of the sulfur content of the feed which varies over time. Since the coking process

at P4 Production is unique and cannot be compared with emissions from other facilities, the

SO2

 allocations for P4 Productions will be based on its average annual emissions. This is
XIII-3

consistent with the allocation approach developed for source categories with no technology

available for reducing sulfur and variable sulfur content in the feed such as flaring.

The allocation for P4 Production will be based on emissions of SO2 from years 1996,

1997, 1998 and 2000. Averaging historical emissions results in a floor allocation of 631 tpy

of SO2 for the P4 Production facility. As stated previously, the SO2

 floor allocations for

Astaris and Geneva Steel are zero.

C. COMPARISON WITH HISTORICAL EMISSIONS

Table XIII-2 presents the historical SO2

 emissions and the SO2

 floor allocations for

all three coking facilities. Note that Geneva Steel has an SO2 allocation for its boilers,

which is discussed in Section IV.

Table XIII-2

Coking Plant - Historical Emissions - 1990 to 2000

Sta te Co unty

ID

Fac ility

ID SIC

MTF

Sector

Sector

Description

Facility Name

(1990)

Current Facility Name

(if different from1990)

SO2

 tpy

1990

SO2

 tpy

1996

SO2

 tpy

1998

SO2

 tpy

2000

SO2

 Floor

Allocation

W Y 037 0003 10 Metals/Mining/

Min erals

Sweetwater

Resources

P4 Production - Rock

Springs

933 663 642 633 631

W Y 023 001 10 Metals/Mining/

Min erals FMC Coking Plant Astaris Coking Plant 1,194 1,413 1,454 1,409 0

UT 049 0027 3312 10 Metals/Mining/

Min erals Geneva Steel 8,473 2,020 881 979 0

REFERENCES

AWMA, 2000: Air and Waste Management Association, “Air Pollution Engineering

Manual,” 2nd edition, Chapter 14 - Metallurgical Industry, 2000.

EPA, 1981: U.S. Environmental Protection Agency, “Control Techniques for Sulfur Oxide

Emissions from Stationary Sources,” Second Edition, EPA-450/3-81-004, Office of Air

Quality Planning and Standards, Research Triangle Park, NC, April 1981.

EPA, 1998: U.S. Environmental Protection Agency, “Compilation of Air Pollutant Emission

Factors,” AP-42, Fifth Edition, Volume I: Stationary Point and Area Source, Section

12.2 Coke Production” Office of Air Quality Planning and Standards, Research

Triangle Park, NC, 1998.
XIII-4
XIV-1

CHAPTER XIV

FLOOR ALLOCATION SUMMARY

Table XIV-1 summarizes the SO2 floor allocation estimates from all of the previous

chapters by State and by sector. California estimates listed in Table XIV-1 are based on

average SO2

 emissions in these sectors from 1996, 1998, and 2000. Table XIV-1 shows the

estimated SO2 floor allocation for non-utility sources in the 9-State Commission Transport

Region to be about 195 thousand tons. If copper smelter SO2

 allocations in 2018 are

subtracted from this amount, the floor allocation is 117 thousand tons. The non-smelter,

non-California SO2 emissions total is 89,000 tons.

Table XIV-2 provides a complete list of the facility-level SO2

 floor allocations, and

includes year 2000 SO2 emissions as a point of comparison.
XIV-2

Table XIV-1

State/Sector Summary of SO2 Floor Allocations

(tons per year)

Sectors

States Refineries

L im e

Manufacturing*

Industrial

Boilers

Pulp and

Paper

Cement

Manufacturing

Natural Gas

Processing

Elemental

Phosphorus **

Glass

Manu facturing***

Copper

Sm elters

Aluminum

Plants

Sulfuric

Acid Plan ts

Coke

Production Total

Arizona 1,365 978 320 43,000 45,663

Ca lifornia 27,335

Colorado 1,614 387 4,936 237 7,174

Idaho 601 1,807 522 15,861 2,551 21,342

Nevada 435 448 883

New Mexico 2,244 1,103 12,862 34,000 50,209

Oregon 1,585 5,377 131 2,076 9,169

Utah 4,142 303 2,010 267 1,593 1,000 9,315

W yom ing 3,418 2,350 165 14,429 2,835 631 23,828

Total 11,418 2,103 7,911 7,184 7,761 28,884 15,861 368 78,000 2,076 5,386 631 194,918

NOTES: *Based on 1998 and 2000 historical SO2 emission estimates.

**Based on year 2000 SO2

 emission estimates for P4 Production, which are substantially higher than 1996 or 1998 emissions.

***Based on 1996, 1998, and 2000 historical SO2

 emission estimates.
XIV-3

Table XIV-2

Facility-Level SO2 Floor Allocations

Comparison with Year 2000 SO2

 Emissions (tons per year)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2

 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

AZ Cement/Concrete Arizona Portland Cement X 320 0 0

AZ 0011 Metals/Mining/Minerals CHEMICAL LIME (CHEMSTAR) CHEMICAL LIME - NELSON X 702 632 632

AZ 0003 Metals/Mining/Minerals Chemical Lime (Douglas) X 742 733 733

AZ Cement/Concrete Phoenix Cement X 539 320 320

AZ 0007 Wood/Paper/Pulp STONE CONTAINER ABITIBI X 1,893 0 978 978

AZ 0001 Oil/Gas Intermountain Refining X Closed 0 0 0

AZ 0004 Copper ASARCO SMELTER - HAYDEN X 16,753 21,000 21,000

AZ 0032 Copper BHP(Magma Metals) BHP - San Manuel X 0 14,000 14,000

AZ 0006 Copper CYPRUS MIAMI MINE X 6,810 8,000 8,000

AZ 0040 Copper Cyprus Sierrita X 0 0 0

45,663

CO 0048 Metals/Mining/Minerals CFI 267 0

CO 0004 Oil/Gas COLO REFINING X Refinery 545 562 562

CO 0003 Oil/Gas CONOCO DENVER X Refinery 1,972 1,052 1,052

CO 0008 Glass COORS GLASS ROCKY MOUNTAIN BOTTLE X 255 237 237

CO 0002 Cement/Concrete HOLNAM LAPORTE HOLCIM LAPORTE X 404 1,402 1,402

CO 0001 Cement/Concrete HOLNAM PORTLAND HOLCIM PORTLAND X 3,288 3,374 3,374

CO 0097 Misc. METRO WASTEWATER 56 0

CO 0003 Cement/Concrete SOUTHWEST PORTLAND CEMEX-LYONS PLT. X 50 160 160

CO 9 Misc. GENERAL SERVICES ADMINISTRATION 0 0

CO 0001 Oil/Gas LANDMARK PETROLEUM 0 0

CO CHP TRIGEN-COLORADO ENERGY CORP. X 2,583 0 387 387

CO 24 Oil/Gas UNOCAL RETORT-PARACHUTE X 0 0

CO 0025 Oil/Gas UNOCAL UPGRADE X 0 0

CO 0001 Food WESTERN SUGAR 1 19 0

CO 0002 Food WESTERN SUGAR 2 0 0

7,174

ID Wood/Paper/Pulp/Cogeneration Tamarack Energy 117 0

ID 0004 Cement/Concrete ASHGROVE CEMENT X 1,327 522 522

ID Power Avista 130 0

ID Food Basic American Foods (Shelly) 149 0

ID Wood/Paper/Pulp Boise Cascade - Emmett 252 0

ID 0001 Misc. DOE-INEEL 460 0

ID 0005 Chemicals/Plastics FMC ASTARIS 0 0

ID Food MAGIC VALLEY FOODS 0 0

ID 0001 Chemicals/Plastics MONSANTO/P4 PRODUCTION P4 Production X Elemental Phosphorus 15,861 15,861 15,861

ID 0003 Chemicals/Plastics NU WEST INDUSTRIES Sulfuric acid plants 86 612

ID 0001 Wood/Paper/Pulp POTLATCH X Paper Mill 1,694 1,807 1,807

ID Misc. RICKS COLLEGE 0 0

ID 0006 Chemicals/Plastics SIMPLOT Sulfuric acid plants 543 1,939

ID 0010 Food TASCO (NAMPA) Amalgamated Sugar (Nampa) 1,697 242 242

ID 0001 Food TASCO (PAUL) Amalgamated Sugar (Paul) 1,322 155 155

ID 0001 Food TASCO (TWIN) Amalgamated Sugar (Twin) 1,053 203 203

ID Food Idaho Supreme 0 0

ID 0001 Misc. MTN. HM. AFB 144 0

21,341

NV 0003 Metals/Mining/Minerals CHEMSTAR APEX CHEMICAL LIME CO-APEX PLANT X Lime plant 210 193 193

NV 0387 Cement/Concrete NEVADA CEMENT COMPANY FERNLEY PLANT X 172 305 305

NV Cement/Concrete Royal Cement Not in previous report 143 143
Table XIV-2 (continued)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

XIV-4

NV 0261 Metals/Mining/Minerals GRAYMONT WESTERN US INC PILOT PEAK X Lime plant 249 242 242

NV 0451 Metals/Mining SANTA FE PACIFIC GOLD CORP TWIN CREEKS/NEWMONT MINING CORP 113 0

NV 0433 Metals/Mining/Minerals BASIC INC.(Now PREMIER CHEMICALS LLC) PREMIER SERVICES (Gabbs Facility) 0

NV 0863 Misc. HAWTHORNE ARMY 0

NV Metals/Mining Independence Big Springs ANGLO GOLD 0

NV 0019 Metals/Mining/Minerals TITANIUM METALS 0

883

NM 0024 Oil/Gas AGAVE ENERGY/YATES PLANT Agave Plant X 2,983 365 365

NM 0002 Oil/Gas ARCO PERMIAN/EMPIRE ABO GAS PLNT X 565 431 431

NM 0004 Oil/Gas CONOCO/MALJAMAR GAS PLANT MALJAMAR GAS PLANT X 3,574 222 222

NM 0023 Oil/Gas GIANT INDUSTRIES/BLOOMFIELD REF X Refinery 920 414 414

NM 0008 Oil/Gas Giant Refining/Ciniza Refinery (Gallup) X Refinery 1,779 603 603

NM 0044 Oil/Gas GPM GAS EUNICE GAS PLANT VERSADO GAS PRODUCERS LLC X 2,759 0

NM 0011 Oil/Gas GPM GAS/ARTESIA GAS PLANT DUKE ENERGY/ARTESIA GAS PLANT X 1,459 1,192 1,192

NM 0006 Oil/Gas GPM GAS/INDIAN HILLS AMINE PLNT 900 0

NM 0046 Oil/Gas GPM GAS/LEE GAS PLANT Duke Energy Lee Plant X 818 0 0

NM 0035 Oil/Gas GPM GAS/LINAM RANCH GAS PLANT Duke Energy Plant 5 1,304 1,181 1,181

NM 0007 Oil/Gas J.L. DAVIS GAS PROCESS/DENTON X 1,158 840 840

NM 0008 Oil/Gas MARATHON OIL/INDIAN BSN GAS PLT X 1,100 665 665

NM 0010 Oil/Gas NAVAJO REFINING/ARTESIA REFINERY X Refinery 980 1,227 1,227

NM 138 Oil/Gas PAN ENERGY/BURTON FLATS GAS PLT Duke Energy Burton Plant X 246 164 164

NM 0285 Oil/Gas PAN ENERGY/DAGGER DRAW GAS PLT DUKE ENERGY/DAGGER DRAW X 247 218 218

NM Cement/Concrete RIO GRANDE PORTLAND CEMENT X 1,103 1,103 1,103

NM 0008 Oil/Gas SID RICHARDSON GASOLINE/JAL#3 X 0 1,206 1,206

NM 55 Oil/Gas TEXACO/BUCKEYE GASOLINE PLANT DYNERGY 673 0

NM 0052 Oil/Gas TEXACO/EUNICE NORTH GAS PLANT X 5,476 0

NM 0051 Oil/Gas TEXACO/EUNICE SOUTH GAS PLANT X 231 0

NM 0003 Oil/Gas TRANSWESTERN PIPE DUKE ENERGY/HUBER GAS X 270 163 163

NM 0001 Oil/Gas WARREN PETROLEUM/BLUITT GAS PLANT X 1,226 0

NM 0060 Oil/Gas WARREN PETROLEUM/EUNICE GAS PLANT Duke Energy EUNICE GAS PLANT 2,756 2,250 2,250

NM 0061 Oil/Gas WARREN PETROLEUM/MONUMENT PLANT Dynergy MONUMENT PLANT X 1,387 675 675

NM 0063 Oil/Gas WARREN PETROLEUM/SAUNDERS PLANT Dynergy SAUNDERS PLANT 0 163 163

NM 0064 Oil/Gas WARREN PETROLEUM/VADA GAS PLANT 3,138 0

NM 0247 Oil/Gas WESTERN GAS PROCESSORS/SAN JUAN RVR Western Gas Resources X 3,127 3,127

NM 0128 Oil/Gas CITATION/ANTELOPE RDG GAS PLANT X 0

NM 0118 Oil/Gas CONOCO/BELL LAKE 2 WELL #6 X 0

NM 0125 Oil/Gas FEAGAN ENERGY/W DAGGER DRAW GAS PLT Duke Energy Dagger Draw X 0

NM 0050 Oil/Gas YATES PETROLEUM/PATHFINDER AMINE X 0 0 0

NM 0001 Copper PHELPS DODGE/CHINO MINES X 11,420 14,000 14,000

NM 0003 Copper PHELPS DODGE/HIDALGO SMELTER X 0 20,000 20,000

50,209

OR 0002 Food Amalgamated Sugar Company, The X 987 0 74 74

OR Wood/Paper/Pulp X Not in previous report 0

OR 1849 Wood/Paper/Pulp Boise Cascade Company X 1,834 1,532 411 1,943

OR Oil/Gas X Not in previous report

OR 0005 Wood/Paper/Pulp Georgia-Pacific West, Inc. X 452 258 143 401

OR 0007 Metals/Mining Glenbrook Nickel Company 0 0

OR 2125 Metals/Mining/Minerals Globe Metallurgical Inc. 197 0

OR 0036 Wood/Paper/Pulp X 0 0

OR 0004 Wood/Paper/Pulp James River II, Inc. Georgia- Pacific (Wauna Mill) X 643 1,361 277 1,638

OR 0001 Metals/Mining/Minerals Northwest Aluminum Company, Inc. X 397 518 518

OR 1876 Glass Owens-Brockway Glass Container, Inc. X 108 131 131
Table XIV-2 (continued)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

XIV-5

OR 3501 Wood/Paper/Pulp Pope & Talbot Pulp, Inc. X 293 248 107 355

OR 1851 Metals/Mining/Minerals Reynolds Metals Company X 1,510 1,558 1,558

OR 6142 Wood/Paper/Pulp Smurfit Newsprint Corporation 2 X No longer pulping 519 0 0

OR Wood/Paper/Pulp West Linn Paper Co. X Not in previous report 0 211 211

OR 8866 Wood/Paper/Pulp Weyerhaeuser Company SierraPine, Ltd. X 0 0 0 0

OR 0471 Wood/Paper/Pulp Willamette Industries, Inc. X 327 310 310

OR 8850 Wood/Paper/Pulp Collins Products LLC Weyerhaeuser Co. X Weyerhaeuser Springfield 1,721 1,668 362 2,030

OR 5034 Misc. Cascade Steel Rolling Mills, Inc. 0 0

OR 2028 Oil/Gas Kinder Morgan Energy Partners, L.P X

OR 0041 Chemicals/Plastics Georgia-Pacific Resins, Inc. 0

OR 0013 Wood/Paper/Pulp J. Peterkort & Company Collins Products LLC 0

OR 5398 Wood/Paper/Pulp Ogden Martin Systems of Marion, Inc. Covanta Marion, Inc. X 0

OR 2050 Misc. Oregon Health Sciences University OHSU X 0 0

OR 0015 Wood/Paper/Pulp Weyerhauser - Coos Bay Hog waste-fired boiler 882 0

9,169

UT 10572 Copper Kennecott Utah Copper Corp. X Smelter 2,534 1,000 700 1,700

UT 10096 CHP Sunnyside Cogeneration Associates X 1,054 1,270 1,270

UT 0004 Oil/Gas Amoco Petroleum Products Tesoro X Refining 1,368 1,388 1,388

UT 0004 Misc. Brigham Young University X 125 1 1

UT 0001 Metals/Mining/Minerals Brush Wellman Inc. X 179 23 23

UT 0003 Oil/Gas Chevron Products Company X Refining 1,242 1,240 1,240

UT -9902 Metals/Mining/Minerals Continental Lime Inc. Graymont X Lime 331 303 303

UT 0008 Oil/Gas Flying J Incorporated X Refining 300 674 674

UT 0027 Metals/Mining/Minerals Geneva Steel X Shutdown coke ovens and sinter plant 979 17 17

UT 0001 Cement/Concrete Holnam Incorporated Holcim X Cement 288 267 267

UT 0013 Oil/Gas Phillips 66 Company X Refining 601 762 762

UT Oil/Gas Silver Eagle Refining Inc. X Not in previous report (Refining) 77 77

UT -9901 Oil/Gas Unocal Corporation Tom Brown-Lisbon Plant X Natural gas processing 1,252 1,593 1,593

UT 10676 Utelite Corporation 133 0 0

9,315

WY 0012 Oil/Gas AMOCO - ELK BASIN HOWELL PETROLEUM - ELK BASIN X 2,638 1,200 1,200

WY 0012 Oil/Gas AMOCO - WHITNEY CANYON X 6,889 5,602 5,602

WY 0009 Oil/Gas CHEVRON - CARTER CREEK X 2,096 200 200

WY Cement/Concrete Centex X Not in previous report 165 165

WY 0013 Oil/Gas EXXON - SHUTE CREEK X 1,383 1,536 1,536

WY Oil/Gas EXXON BLACK CANYON DEHY & WELLFIELD 167 0

WY 0010 Metals/Mining/Minerals FMC - GRANGER (TEXAS GULF) X 212 305 305

WY 48 Metals/Mining/Minerals FMC - GREEN RIVER X 4,901 956 956

WY 0001 Metals/Mining/Minerals FMC COKING PLANT ASTARIS COKING PLANT X Shutdown April 2001 1,409 0

WY 0001 Oil/Gas FRONTIER OIL & REFINING - CHEYENNE X Refining 1,396 863 863

WY 0002 Metals/Mining/Minerals GENERAL CHEMICAL X 5,000 750 750

WY 0001 Food HOLLY SUGAR - TORRINGTON X 178 23 23

WY Oil/Gas INTERENERGY - HILAND WILDHORSE ENERGY - HILAND X 269 281 281

WY Oil/Gas

KCS MOUNTAIN RESOURCES - GOLDEN

EAGLE X 17 790 790

WY Oil/Gas KCS MOUNTAIN RESOURCES - AINSWORTH X 0 843 843

WY 1 Oil/Gas KCS Mountain Resources Rushmore X 118 118 118

WY 0005 Chemicals/Plastics KOCH SULFUR PRODUCTS COMPANY PEAK SULFUR X Sulfuric acid plants 1,245 1,197 1,197

WY Oil/Gas LOUISIANA LAND & EXPLOR - LOST CABIN b BURLINGTON RESOURCES - LOST CABIN b X 213 1,867 1,867

WY 0007 Oil/Gas MARATHON GAS PLANT - OREGON BASIN Oregon Basin Gas Plant X 358 391 391

WY Oil/Gas MARATHON OIL - MILL IRON X 0 247 247
Table XIV-2 (continued)

State

Facility

ID Sector Description Facility Name (1990) Current Facility Name

In Current

Report Comments

 SO2

Emissions

Year 2000

SO2 NonBoiler

Allocation

SO2

Boiler

Allocation

Total

SO2

Allocation

State

Totals

XIV-6

WY 1 Oil/Gas Marthon Oil Pitch Fork Battery X 61 61 61

WY 0003 Metals/Mining/Minerals SWEETWATER RESOURCES P4 PRODUCTION - ROCK SPRINGS X Rotary coker 633 631 631

WY 0022 Chemicals/Plastics SF PHOSPHATES, INC X Sulfuric acid plants 1,790 1,638 1,638

WY 0001 Oil/Gas LITTLE AMERICA REFINING COMPANY SINCLAIR - CASPER X Refining 1,458 1,040 1,040

WY 0011 Oil/Gas SINCLAIR @ SINCLAIR X Refining 3,407 1,066 1,066

WY Oil/Gas SNYDER OIL - RIVERTON DOME DEVON SFS - RIVERTON DOME 492 0

WY Metals/Mining/Minerals SOLVAY MINERALS X 52 294 294

WY 0012 Oil/Gas TEXAS-BYRON PLANT BIG HORN GAS PROCESSING - BYRON X Texaco 257 200 200

WY 0008 Oil/Gas UNION PAC - BRADY RME PETROLEUM - BRADY X 300 0

WY 0005 Misc. UW CENTRAL HEAT PLANT X 193 22 22

WY 0001 Oil/Gas WYOMING REFINING CO WYOMING REFINING - NEWCASTLE X Refining 876 449 449

WY 008 Oil/Gas DEVON SFS OPERATING CO. BEAVER CREEK X 831 0

WY 0003 Metals/Mining/Minerals AMERICAN COLLOID - WEST COLONY 0

WY 0002 Oil/Gas AMOCO REFINERY Closed 0 0

WY 0001 Metals/Mining/Minerals BENTONITE CORPORATION LOVELL 0 0

WY 0014 Oil/Gas COLORADO INTERSTATE GAS - TABLE ROCK 0 0

WY 0013 Oil/Gas MARATHON OIL COMPANY - GARLAND 0 0

WY Oil/Gas Hallwood Petroleum-Federal Packsaddle 1-24 X Not in previous report 133 133

WY Oil/Gas Hallwood Petroleum-Federal Packsaddle 1 X Not in previous report 960 960

23,828

TOTALS 170,226 167,583 167,583 

aSO2

 Allocation based on historical emissions.

bPlant has just added capacity and allocation is based on current (July 2002 capacity).