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

SO2 EMISSION

MONITORING

PROTOCOLS

REVISED DRAFT REPORT

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

and

Perrin Quarles Associates, Inc.

675 Peter Jefferson Parkway

Charlottesville, VA 22911

May 2003

Pechan Rpt. No. 03.01.001/9431.000 (Rev.)

iii

CONTENTS

Page

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

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

FOREWORD ............................................................. ix

PREFACE .............................................................. xiii

A. REGULATORY FRAMEWORK FOR TRIBAL VISIBILITY

IMPLEMENTATION PLANS ........................................ xiii

B. TRIBAL PARTICIPATION IN THE WRAP ............................. xiv

CHAPTER I

SUMMARY OF FINDINGS AND RECOMMENDATIONS .......................... 1

A. IDENTIFICATION OF EXISTING BEST MONITORING PRACTICES ........ 1

B. DISCUSSION AND RECOMMENDATIONS/ISSUES FOR INDUSTRIAL

SECTOR MONITORING PROTOCOLS .................................. 1

C. COST ISSUES ..................................................... 16

CHAPTER II

COPPER SMELTERS ...................................................... 21

CHAPTER III

SULFUR PLANTS ......................................................... 39

CHAPTER IV

FUEL COMBUSTION UNITS ............................................... 49

CHAPTER V

CATALYTIC CRACKING UNITS ............................................. 65

CHAPTER VI

FLARES ................................................................. 73

CHAPTER VII

LIME KILNS ............................................................. 79

CHAPTER VIII

CEMENT KILNS .......................................................... 83

CHAPTER IX

ALUMINUM SMELTERS - POTLINES ........................................ 87
iv

CONTENTS (continued)

Page

CHAPTER X

GLASS MANUFACTURING ................................................ 93

CHAPTER XI

METALLURGIC COKE PRODUCTION ....................................... 99

CHAPTER XII

SULFURIC ACID PRODUCTION ........................................... 101

REFERENCES .......................................................... 103
v

TABLES

Page

1 Association Among Primary Source Categories, Associated Source Types, and

Report Chapters ................................................... xi

I-1 State Monitoring Methods Summary .................................... 2

I-2 NSPS/Other Federal Monitoring Methods Summary ....................... 6

I-3 Current Best Monitoring Practices Summary ............................. 8

I-4 State/Sector Summary of SO2 Floor Allocations (tons per year) .............. 19

II-1 Monitoring Requirements for Main Stack and Other SO2 Sources 

at Kennecott Copper in Utah ......................................... 23

II-2 Monitoring Requirements for Acid Plant at Kennecott Copper in Utah ........ 26

II-3 Monitoring Requirements for Stack, Hoods, and Fugitive Emissions at

Copper Smelters in Arizona .......................................... 28

II-4 Monitoring Requirements for Acid Plant Tail Gas at Copper Smelters

in Arizona ........................................................ 30

III-1 NSPS Monitoring Requirements for Sulfur Recovery Plants at Refineries ..... 40

III-2 NSPS Monitoring Requirements for Sulfur Plants at Natural Gas Processing

Plants ............................................................ 42

III-3 Monitoring Requirements for Sulfur Plants at Natural Gas Processing Plants

in the State of New Mexico ........................................... 44

III-4 Monitoring Requirements for Sulfur Recovery Plants at Refineries

in the State of New Mexico ........................................... 47

IV-1 Summary of Part 75, OTC and NSPS Monitoring Methods ................. 50

IV-2 Part 75 CEMS Methodology .......................................... 51

IV-3 Part 75 Appendix D Fuel Sampling/Flow Method for Oil and Gas Fired Units . . 53

IV-4 Part 75 Low Mass Emissions Unit Methodology for Oil and Gas Fired Units ... 56

IV-5 NSPS Monitoring Methodology for Coal and Oil Fired Industrial Boilers ...... 58

IV-6 NSPS Monitoring Methodology for Refinery Boilers/Process Heaters ......... 60

IV-7 State of Oregon Coal-fired Boiler CEMS/Flow Estimation Example .......... 61

IV-8 State of Oregon Industrial Boiler Fuel-based Estimation Method ............ 62

IV-9 State of Oregon Recovery Furnace CEMS/Flow Estimation Example ......... 63

V-1 NSPS Monitoring Requirements for Fluidized Catalytic Cracking Units ...... 66

V-2 FCCU Monitoring Requirements for SCAQMD Rule 1105 and Rule 2011 ...... 69

V-3 Monitoring Requirements for Fluidized Catalytic Cracking Units in the

State of New Mexico ................................................ 72

VI-1 Monitoring Requirements for Flares at Refineries from Consent Decrees ...... 74

VI-2 Monitoring Requirements for Flares at Refineries in the State of New Mexico . . 76

VI-3 Monitoring Requirements for Flares at Natural Gas Processing Plants in

the State of New Mexico ............................................. 77

VII-1 NSPS Monitoring Requirements for Lime Kilns at Kraft Pulp and Paper Mills . 80

VII-2 Monitoring Requirements for Lime Kilns in the State of Nevada ............. 81

VII-3 Monitoring Requirements for Pulp & Paper Lime Kilns in the State of

Oregon (excluding Lane County) ...................................... 82
vi

TABLES (continued)

Page

VIII-1 Monitoring Requirements for Cement Kilns in the State of Nevada .......... 84

VIII-2 Monitoring Requirements for Cement Kilns in the State of Colorado ......... 85

VIII-3 Monitoring Requirements for Cement Kilns in the State of Oregon

(excluding Lane County) ............................................. 86

IX-1 Aluminum Smelter Monitoring Requirements in the State of Oregon

(excluding Lane County) ............................................. 89

IX-2 Aluminum Smelter Monitoring Requirements in the State of Washington ..... 90

IX-3 Costs for Monitoring Pressure Drop Across Wet Scrubber .................. 91

X-1 Monitoring Requirements for Glass Manufacturing in the State of Colorado ... 94

X-2 Monitoring Requirements for Glass Manufacturing in the State of Oregon ..... 95

X-3 Monitoring Requirements for Glass Manufacturing in the SCAQMD, California 96

XI-1 Monitoring Requirements for Coke Production in the State of Wyoming ...... 100
vii

ACRONYMS AND ABBREVIATIONS

ADTP air dried tons pulp

AMA American Mining Association

AMS Alternative Monitoring System

ASTM American Society for Testing and Materials

CAM Compliance Assurance Monitoring

CD calibration drift

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations

CGA Cylinder Gas Audit

CO carbon monoxide

DAHS Data Acquisition and Handling System

DAS data acquisition system

EPA U.S. Environmental Protection Agency

FCCU fluid catalytic cracking units

GCV gross calorific value

GCVTC Grand Canyon Visibility Transport Commission

lbs/hr pounds per hour

LME Low Mass Emissions

LPG liquified petroleum gas

MMBtu/hr million British thermal units per hour

MTF Market Trading Forum

MW molecular weight

NOx oxides of nitrogen

NSPS New Source Performance Standard

O2 oxygen

OSI Overall System Integrity

OTC Ozone Transport Commission

Pechan E.H. Pechan & Associates, Inc.

ppm parts per million

PQA Perrin Quarles Associates, Inc.

PSEL plant site emission limit

QA quality assurance

QC quality control

RAA Relative Accuracy Audit

RATA Relative Accuracy Test Audit

RECLAIM SCAQMD's Regional Clean Air Incentives Market

RM Reference Methods

RTU remote terminal unit

SCAQMD South Coast Air Quality Management District

SIP State Implementation Plan

SO2 sulfur dioxide

SOP standard operating procedure
viii

ACRONYMS AND ABBREVIATIONS (continued)

SOx sulfur oxides

SRE Sulfur Recovery Efficiency

SRU Sulfur Recovery Unit

TBD to be determined

TCI Total Capital Investment

TIP tribal implementation plan

TRS total reduced sulfur

WRAP Western Regional Air Partnership
ix

FOREWORD

The Western Regional Air Partnership (WRAP) is a collaborative effort of tribal

governments, State governments, and various Federal agencies to implement the

recommendations of the Grand Canyon Visibility Transport Commission (GCVTC) and to

develop the technical and policy tools needed by western States and tribes to comply with

the U.S. Environmental Protection Agency (EPA) regional haze rule. The activities of the

WRAP are conducted by a network of committees and forums composed of WRAP members

and stakeholders who represent a wide range of viewpoints.

The WRAP established the Market Trading Forum (MTF), in large part, to develop and

recommend emission control strategies for stationary sources of air pollution. A major

focus of the MTF has been the establishment of regional emission milestones for sulfur

dioxide (SO2) and a regional backstop cap-and-trade program to be triggered if the

milestones are not met through voluntary means. 

Accurate emissions measurement is critical to the success of any cap-and-trade

program. For many sources that would be subject to the cap-and-trade program (electric

utility boilers are one example), SO2 emissions are already well quantified and

documented. Other sources may be using methods that are less accurate and/or less

consistent across sources. The MTF established a emissions monitoring workgroup to

address this issue.

This draft report is one of the products of the contractors [E.H. Pechan & Associates,

Inc. and Perrin Quarles Associates, Inc. (Pechan and PQA)] that were hired to evaluate

monitoring methods currently being used in the western States. This contractual effort is

designed to develop emission monitoring protocols for non-electricity generating unit

facilities, an estimate of their implementation cost, and regulatory text to facilitate their

consistent codification among the WRAP members. The protocols would be implemented

after the backstop trading program is triggered.

Note that the evaluations made in this report are performed without regard to the

geographic locations of sources within the study area. Thus, sources located on tribal land

are not handled any differently than those not on tribal lands. The evaluations consider

the accuracy and cost of monitoring methods for similar sources. Similar sources are not

just those within the same source type, but also can be classified based on fuel type or size

as well.

The primary source categories identified by the workgroup for analysis include: copper

smelters, refineries, natural gas processing plants, oil and gas production, lime plants,

cement plants, industrial boilers (including cogenerators), aluminum smelters, and pulp

and paper. An earlier MTF-sponsored floor allocation report identified the primary SO2

emitting source types within these source categories. These are listed in Table 1. Because

some of the SO2 source types occur in more than one source category, the chapters in this
x

report are organized by source type, rather than by source category, under the supposition

that source types would have common monitoring methods. Where the analysis shows this

not to be the case, emission monitoring protocols are identified separately based on the

source category/source type combination. Table 1 provides a guide to which report

chapters address each source category/source type combination.
xi

Table 1

Association Among Primary Source Categories, Associated Source Types, and

Report Chapters

Primary Source Category Source Types Report Chapter

1. Copper Smelters II

2. Refineries

Sulfur Plants III

Fuel Combustion Unit

- Boilers

- Process Heaters

IV

Catalytic Cracking Units V

Flares VI

3. Natural Gas Processing Plants

Sulfur Plants III

Flares VI

4. Oil and Gas Production

Sulfur Plants III

Flares VI

5. Lime Plants

Kilns VII

6. Cement Plants

Kilns VIII

7. Industrial Boilers (including cogenerators)

Boilers - fossil-fuel fired IV

8. Aluminum Smelters

Potlines IX

9. Pulp and Paper

Boilers - fossil-fuel fired IV

Recovery Boilers IV

Lime Kilns VII

10. Glass Manufacturing

Glass Melting Furnaces X

Boilers - fossil-fuel fired X

11. Metallurgic Coke Production

Coke Calciners XI

12. Sulfuric Acid Plants

Sulfuric Acid Production Plant XII
xii
1Tribes also possess a more fundamental source of authority to regulate their environments,

based on their inherent authority as sovereign nations, which predates the formation of the United

States. However, in the context of air pollution regulation and visibility planning in particular,

tribal authority will more likely be based on delegation of Federal authority.

xiii

PREFACE

A. REGULATORY FRAMEWORK FOR TRIBAL VISIBILITY IMPLEMENTATION

PLANS

The regional haze rule explicitly recognizes the authority of tribes to implement the

provisions of the rule, in accordance with principles of Federal Indian law, and as provided

by the Clean Air Act §301(d) and the tribal authority rule [40 Code of Federal Regulations

(CFR) §§49.1– .11]. Those provisions create the following framework:

1. Absent special circumstances, reservation lands are not subject to State

jurisdiction.

2. Federally recognized tribes may apply for and receive delegation1 of Federal

authority to implement Clean Air Act programs, including visibility regulation, or

"reasonably severable" elements of such programs (40 CFR §§49.3, 49.7). The

mechanism for this delegation is a tribal implementation plan (TIP). A reasonably

severable element is one that is not integrally related to program elements that

are not included in the plan submittal, and is consistent with applicable statutory

and regulatory requirements.

3. The regional haze rule expressly provides that tribal visibility programs are “not

dependent on the strategies selected by the State or States in which the tribe is

located” (64. Fed. Reg. 35756), and that the authority to implement §309 TIPs

extends to all tribes within the GCVTC region (40 CFR §51.309(d)(12)).

4. EPA has indicated that under the tribal authority rule, tribes are not required to

submit §309 TIPs by the end of 2003. Rather, they may choose to opt-in to §309

programs at a later date (67 Fed. Reg. 30439).

5. Where a tribe does not seek delegation through a TIP, EPA, as necessary and

appropriate, will promulgate a Federal implementation plan within reasonable

timeframes to protect air quality in Indian country (40 CFR §49.11). EPA is

committed to consulting with tribes on a government-to-government basis in

developing tribe-specific or generally applicable TIPs where necessary (See, e.g.,

63 Fed. Reg. 7263-64).

The amount of modification, if any, needed for this report to fulfill tribal needs may

vary considerably from tribe to tribe. The authors have striven to ensure that all

references to tribes in the document are consistent with principles of tribal sovereignty and

autonomy as reflected in the above framework. Any inconsistency with this framework is

strictly inadvertent and not an attempt to impose requirements on tribes which are not

present under existing law.
xiv

B. TRIBAL PARTICIPATION IN THE WRAP

Tribes, along with States and Federal agencies, are full partners in the WRAP, having

equal representation on the WRAP Board as States. Whether Board members or not, it

must be remembered that all tribes are governments, as distinguished from the

“stakeholders” (private interest) which participate on Forums and Committees but are not

eligible for the Board.

Despite this equality of representation on the Board, tribes are very differently

situated than States. There are over four hundred Federally-recognized tribes in the

WRAP region, including Alaska. The sheer number of tribes makes full participation

impossible. Morever, many tribes are faced with pressing environmental, economic, and

social issues, and do not have the resources to participate in an effort such as the WRAP,

however important its goals may be. These factors necessarily limit the level of tribal

input into and endorsement of WRAP products.

The tribal participants in the WRAP, including Board members Forum and Committee

members and co-chairs, make their best effort to ensure that WRAP products are in the

best interest of the tribes, the environment, and the public. One interest is to ensure that

WRAP policies, as implemented by States and tribes, will not constrain the future options

of tribes who are not involved in the WRAP. With these considerations and limitations in

mind, the tribal participants have joined the State, Federal, and private stakeholder

interests in approving this report as a consensus document.
1

CHAPTER I

SUMMARY OF FINDINGS AND RECOMMENDATIONS

A. IDENTIFICATION OF EXISTING BEST MONITORING PRACTICES

The initial phase of this project involved collecting information from State and Federal

resources on monitoring practices at the primary industrial facilities that would be affected

under a WRAP backstop trading program. We compiled information on Federal

requirements in New Source Performance Standard (NSPS) subparts for the applicable

source types, from recent Federal consent decrees that affect refineries, and from 40 CFR

Part 75 requirements that affect industrial boilers that may opt in to the Acid Rain

Program (or that are affected under the Oxides of Nitrogen (NOx) State Implementation

Plan (SIP) Call trading program). In addition, a number of State and local agencies were

contacted based on a contact list provided by WRAP staff. Contacts were made with

Arizona, Colorado, Idaho, Nevada, New Mexico, Oregon, Utah, and Wyoming, as well as

the South Coast Air Quality Management District (SCAQMD) in California.

Based on this research, we compiled examples of monitoring approaches for each of the

major industrial sector source types identified as possible trading sources. Table I-1

provides an overview of the State monitoring practices we identified for each source

category. Table I-2 then provides the same information based on our review of applicable

Federal NSPS requirements. Sections II through IX of this report provide more detailed

information by source type.

B. DISCUSSION AND RECOMMENDATIONS/ISSUES FOR INDUSTRIAL SECTOR

MONITORING PROTOCOLS

After compiling the various monitoring options, we evaluated the approaches and

identified the best monitoring practices for each source category. These are summarized in

Table I-3. The final column in the table indicates whether the monitoring is suitable for

use as part of a trading program, whether a monitoring approach applied to a comparable

source category should be considered for the trading program, or whether there are

technical/cost issues that raise the possibility that other monitoring or applicability

procedures should be considered to address the applicable source category/unit type.

In Table I-3, the Part 75 monitoring requirements are used as a primary benchmark in

reviewing the best monitoring practices identified for each source category. EPA has

developed Part 75 for the Acid Rain trading program, and has extended the use of Part 75

to other trading programs as well (such as the NOx SIP Call). The Ozone Transport

Commission used a monitoring program comparable to Part 75 for its regional NOx trading
2

Table I-1

State Monitoring Methods Summary

Primary Source Category Source Types Arizona

SCAQMD

Calif Colorado Idaho Nevada New Mexico Oregon Utah Wyoming

1. Copper Smelters SO2

Continuous

Emissions

Monitoring

System

(CEMS) for

stacks with

specific limits.

Also, facilitywide monthly

material

balance.

SO2 CEMS

and sulfur

balance.

SO2 CEMS

2. Refineries Sulfur Plants (SRU) SO2 monitor at

the outlet of the

tail gas unit

plus

incinerator. 

Flow CEMS.

CEMS for flow

and SO2. Also

requires daily

measurement 

of incinerator

temperature,

incinerator

excess oxygen

(O2), acid gas

flow rate, H2S

conc. and

accumulated

elemental

sulfur

recovered.

SO2 CEMS (no

flow

requirements)

SO2 CEMS

operated

according to 40

CFR 60,

Appendix F.

Fuel Gas Combustion Unit

 - Boilers

 - Process Heaters

Fuel gas

continuous

monitoring( or

use SO2 CEMS

on a

representative

stack and back

calculate sulfur

content in the

mix drum). 

Also, fuel flow

monitoring to

calculate mass

emissions.

Fuel gas H2S

monitoring and

fuel usage is

required for

sources

subject to

Subpart J.

CEMS may be

required for

NOx and

carbon

monoxide (CO)

based on size

of unit. 

No SO2 CEMS

required for

firing nat. gas. 

Monitor fuel oil

and fuel gas

usage. 

Sample fuel oil

for sulfur

content.

Monitor fuel

gas H2S

content.
Table I-1 (continued)

Primary Source Category Source Types Arizona

SCAQMD

Calif Colorado Idaho Nevada New Mexico Oregon Utah Wyoming

3

Catalytic Cracking Units SO2 and Flow

CEMS

CEMS is

proposed in a

consent decree

[requirements

are to be

determined

(TBD)]

SO2 CEMS (no

flow

requirements)

SO2 CEMS

Flares Not considered

by SCAQMD's

Regional Clean

Air Incentives

Market

(RECLAIM).

Rule 1118

addresses.

They do

episodic

sampling.

Measure acid

gas flow and

concentration

and fuel gas

flow for

supplemental

heat. Calculate

acid gas flared.

No monitoring

required.

3. Natural Gas Processing Plants Sulfur Plants Same as

refinery sulfur

plant

SO2 CEMS (no

flow

requirements)

Flares Analyzer to

measure and

record flow and

H2S of both

inlet gas to

plant and acid

gas to flare.

4. Oil and Gas Production Sulfur Plants

Flares

5. Lime Plants Kilns No

requirements

to monitor or

regulate SO2.

See below

under 9. Pulp

and Paper --

Lime Kilns.

Daily coal

sulfur

analyses, daily

production

records, stack

emission

testing once

every five

years.

CEMS for TRS Stack test

every 5 years.
Table I-1 (continued)

Primary Source Category Source Types Arizona

SCAQMD

Calif Colorado Idaho Nevada New Mexico Oregon Utah Wyoming

4

6. Cement Plants Kilns Annual

performance

test

SO2 and Flow

CEMS (kiln

with standard

baghouse and

stack). SO2

and parametric

flow correlation

(kiln with

positive

pressure

baghouse

without a stack

where no

suitable

location for

flow CEMS).

SO2 and Flow

CEMS at

HolcimFlorence Plant

Kiln 1 total

annual

throughput and

fuel use.

Kiln 2 monthly

coal sulfur

analyses,

annual

production

records, stack

test once per

year

Kiln source test

once per

permit term. 

Monitor sulfur

content of each

fuel shipment.

Stack test

every 2 years

plus fuel sulfur

content

7. Industrial Boilers (including cogenerators) Boilers - fossil-fuel fired

 - coal, solid fuel

 - natural gas

 - process gas

 - fuel oil

[Not investigated with States in detail because of existing monitoring practices applicable to this source type under Part 75 and NSPS]

8. Aluminum Smelters Potlines Source test

semi-annually

for SO2

9. Pulp and Paper Recovery Boilers SO2 CEMS

with stack flow 

based on BLS

monitoring and

BLS/stack flow

correlation

Lime Kilns SO2 CEMS

with stack flow

based on

parameter

monitoring

correlation.

TRS CEMS

10. Glass Manufacturing Glass Melting Furnaces SO2 CEMS

and in-stack

flow meters

SO2 CEMS

and monitoring

of fuel

consumption

Fuel sulfur

content

measurements

and production

records used to

estimate SO2

emissions
Table I-1 (continued)

Primary Source Category Source Types Arizona

SCAQMD

Calif Colorado Idaho Nevada New Mexico Oregon Utah Wyoming

5

11. Metallurgic Coke Production Coke Calciner SO2 and flow

CEMS

Stack test to

establish SO2

emission

factor. 

Measure

annual

production.
6

Table I-2

NSPS/Other Federal Monitoring Methods Summary

Primary Source Category Source Types Applicable NSPS SO2/Flow Monitoring Requirements

1. Copper Smelters Roasters, Smelting furnace,

Copper converters

Subpart P SO2 CEMS (no flow measurements)

2. Refineries Sulfur Plants (SRU) Subpart J SO2 CEMS (no flow measurements). If no incineration

after recovery, can measure as TRS rather than as SO2

Fuel Gas Combustion Unit

-Boilers

-Process Heaters

H2S continuous monitoring (can be at common drum

serving multiple units) or SO2 CEMS (no flow

measurements under either option)

Catalytic Cracking Units SO2 CEMS (no flow measurements). CEMS not

required for units without add-on control device to meet

NSPS limits.

Flares Consent Decrees Flowmeters, H2S concentration (from sulfur recovery

analyzer, knowledge of sulfur content, or direct

(periodic) measurement), and use of applicable formula

to convert to SO2 tons.

3. Natural Gas Processing Plants Sulfur Plants Subpart LLL Daily measurements of sulfur product accumulation,

H2S concentration in acid gas, and average flow rate

(based on continuous measurements). Also, SO2

CEMS and temperature monitoring for incinerator

controlled units, expressed as mass per unit of time. If

no incinerator (or in place of temperature monitor),

TRS CEMS, but expressed as SO2 mass per unit of

time. 

Flares None

4. Oil and Gas Production Sulfur Plants No NSPS Not applicable

Flares Not applicable

5. Lime Plants Kilns Subpart HH None

6. Cement Plants Kilns Subpart F None
Table I-2 (continued)

Primary Source Category Source Types Applicable NSPS SO2/Flow Monitoring Requirements

7

7. Industrial Boilers (including

cogenerators)

Boilers - fossil-fuel fired

- coal, solid fuel

- natural gas

- process gas

- fuel oil

(a) Part 75

(b) Subparts D, Db, Dc

(a) For boilers >250 million British thermal units per

hour (MMBtu/hr), Part 75 requirements (SO2/Flow

CEMS if solid fuel, fuel flow and fuel sampling option if

oil or gas-fired)

(b) For boilers 30-250 MMBtu/hr, SO2 CEMS (no flow

measurements). Also, daily fuel sampling or daily

reference method testing options in certain

circumstances. Fuel supplier certification also an

option for low sulfur oil.

8. Aluminum Smelters Potlines Subpart S None

9. Pulp and Paper Boilers - fossil-fuel fired Subparts D, Db, Dc See Item 7., above

Recovery Boilers TRS CEMS (no flow measurements)

Lime Kilns TRS CEMS (no flow measurements)

10. Glass Manufacturing Plants Glass Melting Furnace Subpart CC No SO2 limits or monitoring requirements

11. Metallurgic Coke Production Coke Calciner No NSPS Not applicable

12. Sulfuric Acid Plants Sulfuric Acid Production Unit Subpart H SO2 CEMS (no flow measurements)
8

Table I-3

Current Best Monitoring Practices Summary

Source Type Monitoring Method Where Required

Trading

Recommendations/Issues

1. Copper Smelters (a) Material Balance [American Mining

Association (AMA) Proposal]

(b) SO2/Flow CEMS [Kennecott, main stack]

(a) AMA proposal based

on AZ and NM

requirements

(b) Utah

(a) AMA proposal is to be

discussed by States, EPA, and

industry

(b) Utah protocol is Part 75

comparable; require Part 75

compliance

2. Sulfur Plants SO2/Flow CEMS Utah and South Coast,

CA 

Part 75 comparable; require Part

75 compliance

3. Refinery Fuel

Combustion Units

(a) Fuel gas continuous monitoring for fuel

sulfur content and flow based on fuel flow

meters. 

(b) Alternate Option: Also may use SO2 CEMS

on a representative stack to back calculate

sulfur content in fuel in lieu of fuel gas

continuous monitoring.

South Coast, CA (a) Part 75 comparable; require

Part 75 compliance

(b) Consider adding this

approach as optional protocol

4. Catalytic Cracking Units SO2/Flow CEMS South Coast, CA (SO2

CEMS also in NSPS,

Utah and consent decree

proposal for New Mexico

refinery)

Part 75 comparable; require Part

75 compliance

5. Flares Flowmeters, H2S concentration (from sulfur

recovery analyzer, knowledge of sulfur content,

or direct (periodic) measurement), and use of

applicable formula to convert to SO2 tons

Refinery consent decrees Limited usefulness for trading

program -- see discussion.

6. Lime Kilns SO2 CEMS with stack flow based on parameter

monitoring correlation. 

Idaho (lime kiln at a pulp

and paper facility)

(a) Consider use of flow CEMS

as applied currently for cement

kilns

(b) Positive pressure baghouse

exception may be necessary

(see cement kilns)
Table I-3 (continued)

Source Type Monitoring Method Where Required

Trading

Recommendations/Issues

9

7. Cement Kilns (a) SO2/Flow CEMS 

(b) Exception: Use correlation approach for

flow if positive pressure baghouse prevents use

of a flow CEMS

Colorado and South

Coast, CA 

(a) Part 75 comparable; require

Part 75 compliance

(b) Exception technically

necessary -- add as optional

protocol for positive pressure

baghouse application

8. Aluminum Smelters Source test semi-annually for SO2, together

with sulfur sampling of anode materials to show

compliance with plant mass emission limit 

Oregon Existing best monitoring

practices inadequate for trading. 

Presence of both significant

fugitives and controls for

captured emissions would

require materials balance

approach plus inlet/outlet SO2

control device CEMS and flow

CEMS to account for controlled

emissions. Consider addressing

aluminum smelters outside of

trading program.

9. Gas or Oil-Fired Boilers 1) SO2/Flow CEMS, or 

2) Fuel sampling and fuel flowmeters, or

3) If emit <25 tons/year SO2, use default SO2

value plus default heat input (or long term fuel

flow method for heat input)

Part 75; South Coast, CA Part 75 applies; require Part 75

compliance

10. Solid- Fuel Fired

Industrial Boilers >250

MMBtu/hr

SO2/Flow CEMS Part 75 (opt-in units) Part 75 applies; require Part 75

compliance
Table I-3 (continued)

Source Type Monitoring Method Where Required

Trading

Recommendations/Issues

10

11. Solid- Fuel Fired

Industrial Boilers <250

MMBtu/hr

SO2 CEMS, or daily stack test, or coal sampling

and analysis. No flow monitoring required

under NSPS

NSPS Based on NSPS, SO2 CEMS

appear applicable from technical

and economic standpoint. At

some point, size may be an

issue from economic standpoint;

could consider applicability

cutoff, although WRAP floor

allocation inventory suggests

cutoff for small, solid-fuel-fired

boilers may be unnecessary.

Given SO2 CEMS requirements,

lack of flow monitoring appears

to be based on lack of regulatory

need as opposed to

technical/cost considerations.

12. Recovery Furnaces SO2 CEMS and fuel monitoring correlation

method for flow

Current Practice - Oregon Consider adding flow CEMS

given application to comparable

industrial boiler and kiln

applications.

13. Glass Melting Furnaces SO2 CEMS and in-stack flow meter, or an

alternate method for low flow rates

South Coast, CA Part 75 comparable; require Part

75 compliance

14. Coke Calciners SO2 and flow CEMS South Coast, CA Part 75 comparable; require Part

75 compliance

15. Sulfuric Acid Plants SO2/flow CEMS Utah and Arizona Part 75 comparable; require Part

75 compliance
11

program as well. The SCAQMD likewise adopted generally similar approaches for all

major sources (generally those with over 10 tons of SO2 emissions per year for the relevant

source types) as part of its SO2 RECLAIM program.

 For solid fuel units, Part 75 requires an SO2 and flow CEMS to determine SO2 mass

emissions. However, it is important to note that Part 75 (and the Ozone Transport

Commission (OTC) and RECLAIM programs) do include some non-CEMS options for other

units. For gas and oil fired units, Part 75 allows the use of fuel flow monitoring and fuel

sampling (with sampling frequencies based on sulfur content and variability). For gas and

oil units that have low mass emissions (#25 tons per year), Part 75 allows the use of

default values to account for mass emissions. The RECLAIM program has similar fuelbased options.

Part 75 has not been applied to all forms of industrial facilities, and our use of Part 75

as a benchmark does not exclude consideration of options, which may not meet the same

criteria as Part 75. Rather, for those source categories where the best monitoring practices

are comparable to the Part 75 benchmark, we note that further, detailed technical

justification and consideration of monitoring alternatives for that source category is

generally unnecessary, except for considering alternative technical exceptions. For

instance, the best monitoring practices for industrial boilers and cogenerators are generally

comparable to Part 75 requirements. Also, in a number of non-boiler/process heater source

categories, State or local requirements were found which are comparable to Part 75 SO2

and Flow CEMS. These include refinery sulfur plants and catalytic cracking units, and

Portland cement kilns required to use SO2 and flow CEMS.

For categories where the current best monitoring practices do not compare favorably

with the Part 75 benchmark, further analysis is required to identify the technical,

economic, or regulatory reasons for the current level of monitoring, and, based on those

factors, establish recommendations for appropriate monitoring protocols. The following

discussion amplifies the findings listed in Table I-3 for each of the primary source types.

(1) Industrial Boilers and Cogenerators

Part 75 monitoring requirements are directly applicable to the fossil fuel fired

industrial boiler and cogenerator category. Therefore Part 75 monitoring methods are

identified generally as the best monitoring practice for these units.

However, consideration must be given to the appropriateness of Part 75 as a best

monitoring practice for smaller units. Part 75 requirements currently apply to units

serving generators with a nameplate capacity greater than 25 MW. This is comparable to

a unit with 250 million Btu/hr rated heat input capacity (10,000 Btu/kilowatt hour heat

rate). A number of the coal-fired industrial boiler units in the floor allocation inventory are

smaller than this threshold, so we do not identify Part 75 as the current best monitoring

practice for these units. Instead, the Part 60 NSPS practices are identified as best

monitoring practice for units >30 MMBtu/hr capacity but <250 MMBtu/hr capacity. These

requirements typically require an SO2 CEMS, although the NSPS allow for daily stack

testing or coal sampling and analysis as an option. The NSPS does not impose any flow

monitoring because flow data are unnecessary to establish compliance with the NSPS

limits. However, at least one State has applied parametric correlation methods for flow to
12

the industrial boiler category, so we list that technique as the best flow monitoring practice

for this group of units.

Recommendation: Require compliance with Part 75.

(2) Recovery Furnaces

The current best monitoring practices (State and Federal) identified for paper mill

recovery furnaces are not comparable to Part 75. The NSPS do not require SO2 or flow

monitoring. While we identified State requirements to use a CEMS for SO2, we did not

identify any stack flow CEMS requirements. We did identify a State requirement to

determine stack flow based on a correlation with black liquor flow monitoring. The

technical monitoring application of a flow CEMS, however, should be the same for a

recovery furnace as a fossil fuel-fired boiler. Thus, the lack of a State requirement for a

flow CEMS appears to be based on the lack of a regulatory driver for such a requirement,

as opposed to technical aspects of flow monitoring. Given the size of a typical recovery

furnace and total plant investment for pulp mills (and existing SO2 CEMS), the cost

implications of adding a flow CEMS do not appear unreasonable compared to flow CEMS

applied to other industrial sectors. Thus, there does not appear to be a strong rationale for

using a non-CEMS approach to flow monitoring for this source category that differs from

the recommendation for the industrial boiler category.

Recommendation: Require compliance with Part 75. 

(3) Refinery Combustion Sources

The NSPS, SCAQMD RECLAIM, and Part 75 all establish the option for monitoring

sulfur content of the fuel as a method for determining SO2 emissions. The RECLAIM and

Part 75 rules also apply fuel flow metering to determine SO2 mass emissions. Thus, the

existing best monitoring practices for these units are appropriate for use in a trading

program.

Recommendation: Require compliance with Part 75; consider RECLAIM monitoring

as an option. 

(4) Cement and Lime Kilns

Existing State monitoring practices already include an SO2 and Flow CEMS

requirement for a cement kiln. The best monitoring practice identified for a lime kiln was

a State requirement for an SO2 CEMS, with flow determined using parameter monitoring

correlations. Given the application of a flow CEMS to the generally comparable cement

kiln application, this difference in best monitoring practices appears to be driven by

general regulatory considerations and not significant technical issues. Given the similarity

between the two types of kilns, and the existing application of one type of CEMS to a lime

kiln, the general recommended approach for the kiln applications is an SO2/Flow CEMS

approach. 

However, a flow CEMS may not be appropriate for cement or lime kilns served by

positive pressure baghouses. The lack of a location for a flow CEMS downstream of the
13

control device (to avoid interference from the harsh, upstream environment), is a technical

obstacle to use of a flow CEMS in these situations. In those cases the best monitoring

practice for flow is a parameter monitoring correlation (identified for a cement kiln in the

South Coast RECLAIM program).

Recommendation: Require compliance with Part 75; use RECLAIM approach for

flow monitoring at units with positive pressure baghouses. See also consideration of “opt

out” provisions for units in this source category as part of considering monitoring costs.

(5) Sulfur Plants and Fluid Catalytic Cracking Units (FCCUs)

For sulfur plants, the proposed monitoring protocol requires SO2 and flow rate CEMS. 

Such requirements are already in place in Utah and the South Coast of California. While

the floor allocation method sets the floor for each unit using a lower emission factor for the

larger sulfur plants than it does for smaller units (using the same criteria as the NSPS),

there appear to be no barriers to applying the same monitoring requirements to all sulfur

plants regardless of size. All sulfur plants at refineries are included in the trading

program, for example.

As with sulfur plants, the proposed monitoring protocol for FCCUs at refineries

requires SO2 and flow CEMS. Because there may be flow monitoring concerns for

refineries that do not have CO boilers, we are investigating whether there are any western

State refineries with FCCUs that do not also have CO boilers. If all FCCUs have CO

boilers, a single protocol should be sufficient for this source type. The evaluation

performed so far has used the 1996 WRAP point source file and the 1999 National

Emission Inventory to check whether there are CO boilers at western State refineries. 

Very few CO boilers show up in these data sets. Therefore, we will probably have to rely

on industry contacts for this information.

The SCAQMD does have specialized procedures for conducting quality assurance (QA)

on CEMS for units with low SO2 concentrations. Part 75 also has special procedures for

quality assurance tests for units with low concentrations. A further detailed analysis of

the differences in these procedures will be conducted to evaluate whether one, or both, of

the approaches should be used for purposes of this trading program.

Recommendation: Require compliance with Part 75 for both sulfur plants and

FCCUs. For an FCCU without a CO boiler, consider flow monitoring alternatives if

necessary based on stack configuration issues. Also, compare SCAQMD spiking protocol

for quality assurance purposes compared with Part 75 approaches (for units with low SO2

concentrations).

(6) Glass Melting Furnaces

SO2 monitoring requirements were evaluated for glass manufacturing plants in

Colorado, Oregon, and the SCAQMD. The plants in Colorado and Oregon emitted all SO2

via a stack. Colorado requires continuous monitoring systems for SO2 and monitoring of

fuel consumption, while Oregon estimates SO2 emissions from monthly production records

for tons of glass melted, and natural gas and fuel oil fuel usage estimates from meter/gauge

readings. SO2 emissions are then calculated using emission factors.
14

The SCAQMD requires the use of CEMS at the glass plant(s). There are some flow

monitoring issues at these plants because oxy-fuel systems are being adopted (using

oxygen rather than air). Oxygen use reduces the overall flow as there is reduced oxidizer

volume. In these cases, they cannot use an alternate method such as measurement of the

fuel burned and use of an f-factor to determine stack flow. In-stack flow meters must be

used or an alternative method for low flow rates such as the use a tracer gas (e.g., helium).

Recommendation: Require compliance with Part 75. For low flow situations, we do

not recommend a separate protocol at this time. Given the small number of affected

plants, a petition for an alternative for any such situation that may arise appears to be an

acceptable approach to address site-specific issues.

(7) Metallurgic Coke Production

There are limited coke production operations in the WRAP Region. Protocols for this

industry are based on the rotary calciner used for coke production at P4 Production in Rock

Springs, Wyoming and facilities operating in the South Coast of California. No SO2

emission monitoring is required for the Wyoming facility. Annual SO2 emissions are

computed using a stack test-based SO2 emission factor and operating hours/production rate

estimates.

There is at least one coke calciner included in the South Coast RECLAIM program,

and the CEMS and flow monitoring requirements are no different from those applied under

SCAQMD Rule 2011 for other source types, so the SO2 emission monitoring protocol for

metallurgic coke production is based on these South Coast requirements.

Recommendation: Require compliance with Part 75.

(8) Sulfuric Acid Production Plants

Emission monitoring protocols for sulfuric acid plants are based on the requirements

for acid plants at copper smelters in the region. Because SO2 CEMS and flow monitoring

are required for the Kennecott unit, these are considered the best monitoring practices for

H2SO4 production.

Recommendation: Require compliance with Part 75.

(9) Sources with Fugitive Emissions

There are a number of categories with significant fugitive SO2 emissions for which Part

75 methods are not appropriate. These include the two primary smelter categories

(aluminum and copper), and refinery flares. For the smelters, some combination of mass

balance including SO2 and flow CEMS, may be required based on the specific smelter. 

Flares have intermittent emissions, with a large range in concentrations.

(a) Copper Smelters

For copper smelters in the transport region, there need to be two monitoring protocols. 

The first is based on the current requirements for Kennecott-Salt Lake, which underwent a
15

modernization effort during the mid-1990s, and emits all of its SO2 via stack releases. The

emission monitoring requirements for Kennecott are to install and monitor SO2 and flow

via a CEM at the acid plant and the main smelter stack. A separate protocol is needed for

smelter configurations that currently exist in Arizona and New Mexico, where a large

fraction of the SO2 emissions are vented to the atmosphere as fugitives. This protocol is

based on the Arizona Mining Association proposal, which in turn is based on current SIPapproved monthly material balance requirements.

Recommendation: For any plant such as the Kennecott plant, require compliance

with Part 75. For smelters with fugitive emission sources, no protocol can be recommended

at this time given the significant emissions from this sector, and the differences in data

precision, accuracy, frequency, and overall quality between the mass balance option for

these smelters and the monitoring available for other sources. EPA, the States, and the

industry are expected to continue discussions on the appropriate protocol for these sources. 

As an interim measure, consider one of the non-monitoring options in subsection (d) below.

(b) Aluminum Smelters

Recent information provided by the Oregon Department of Environmental Quality

indicates that Reynolds Metals has closed permanently and the primary smelter at the

Northwest Aluminum plant is temporarily shut down. Current monitoring requirements

for aluminum smelters in Oregon are limited to a semi-annual source test for SO2 together

with sulfur sampling of anode materials to show compliance with a plant mass emission

limit. Average annual SO2 emissions at this plant are about 400 tons. If the best current

practice is used to define the emission monitoring protocol for aluminum smelters, then the

requirements for this category would be well below those for those for the other categories

being studied. While not specifically demonstrated for this source type, the stack SO2

emissions from an aluminum smelter should be amenable to SO2 CEM and flow

measurement. However, it has not been determined what fraction of the SO2 emissions are

stack versus fugitive emissions. The 1996 WRAP point source data base shows that 55

percent of the facility-level SO2 comes from the vertical stud soderberg cell. This may

indicate that the remaining 45 percent of the SO2 is released from vents, etc.

Therefore, if this plant was to be included in the trading program, the protocol would

have to address both stack and fugitive emissions from this facility. One approach would

be to account for all sulfur inputs (similar to the copper smelter protocol), use inlet/outlet

SO2 CEMS plus flow monitoring to account for the sulfur controlled at the stack, and then

assume the remaining sulfur is emitted as SO2. Given the potential complexity of this

option, and recent information that the only remaining smelter may be curtailing

operations, the WRAP may want to consider excluding this source category from the

program, or establishing a generic petition process within the rule to add a source-specific

protocol if needed for this type of facility. See subsection (d), below, for further discussion. 

Recommendation: Consider one of the non-monitoring options in subsection (d),

below.
16

(c) Flares

The best monitoring practice was from a recent consent decree that required gas flow

monitoring combined with periodic sampling/analysis for sulfur content. Potential bypass

of flares is an issue for monitoring under a trading program, however. Note that the

SCAQMD excluded flares from their RECLAIM program. Because of the nature of this

emission source, exclusion from the trading program or providing flares with non-tradeable

allowances may be an option (see below).

Recommendation: Consider one of the non-monitoring options in subsection (d),

below.

(d) Other Non-monitoring Options for Fugitive Sources

Because of the inherent difficulty of monitoring sources with significant fugitive

emissions, especially in a manner comparable to the other participants in the trading

program, the WRAP may want to consider the option of excluding these units from the

trading program. The volume of the emissions from the copper smelter sector (and also

from flares) may make this option unacceptable. The volume from aluminum smelters

should not affect the overall viability of the trading program.

A second alternative is to include these categories in the trading budget and allocate

allowances, but not allow these source types to sell allowances. The sources would use the

best available monitoring to account for their emissions and balance the total emissions

against their allowances. If emissions are less than allowances, then the sources would

require no further action. If emissions exceeded allowances, then the sources would have

to buy sufficient allowances to cover their emissions. Because this issue is a fundamental

trading program design issue and not an emissions monitoring issue, we have not

evaluated this option fully as part of this report.

A third option would be to establish a generic petition process in the current trading

rule that would enable a separate approval process for these types of complex monitoring

situations, which often may have source-specific issues that limit the usefulness of a

generic protocol. The petition could require the source to develop a proposed protocol

(which may be based on a protocol already approved under the SIP for other non-trading

program purposes), then approval by the applicable State, and subsequent approval into

the SIP by EPA before the source may participate in the trading program. This approach

would enable the States to proceed with current SIP rulemakings on the essential elements

of their section 309 plans. The States then could work with the relatively few sources

involved and with EPA on the technical monitoring details for these sources. This

approach seems necessary if these sources are to be included given that the current

monitoring approaches do not readily translate into emissions accounting with the same

degree of accuracy as methods that would be employed by other sources participating in

the trading program.

C. COST ISSUES

In evaluating the costs of monitoring options, we identified the following primary

sources of information:
17

(1) Part 75 Cost Study and ICR. EPA's Clean Air Markets Division had collected

information from vendors and other sources on CEMS, fuel flowmeter, and testing

costs as part of evaluating the costs of its monitoring requirements under the Acid

Rain Program and NOx SIP Call. Based on that information, we have included

information that indicates that the annualized cost of an SO2/Flow CEMS to meet

Part 75 requirements will be approximately $75,000 (1998 dollars). For a fuel

flowmeter, the total capital costs were estimated at $3,000-8,000 approximately

for gas or oil meters (excludes installation costs), with quality assurance cost of up

to $2,000 per year. Fuel sampling costs would be an additional expense, but those

values were not part of this study (the ICR for Part 75 does assume approximately

$300/oil sample for oil-fired units, while gas-fired units rely on fuel supplier

information or default values). 

(2) OAQPS CEM Cost Model. EPA's Office of Air Quality Planning and Standards

developed a CEM Cost Model for meeting Part 60 (NSPS) requirements. Based on

that model (in 1998 dollars) the annualized cost of an SO2/Flow CEMS would be

approximately $58,000.

Additional cost information was not identified in an initial search. For purposes of this

initial report, we did not attempt to gather further details or contact vendors directly to

assemble additional data. To the extent the WRAP participants identify particular

monitoring applications where additional cost data would enhance the final decision

making process on acceptable monitoring protocols, we will contact appropriate vendors

and affected facilities to evaluate costs in detail for that application. 

Two other factors should be considered in evaluating the cost implications of

monitoring options for the WRAP trading program:

! The program applies to all SO2 emitting units at a facility, regardless of size or the

amount of emissions, and

! The program does not establish emission reduction targets for a number of the

source categories that will participate in the program.

The first consideration – presence of small units – suggests that the rule may require

some form of reduced monitoring or opt out process for these small units. As an example, a

smelt dissolving tank at a kraft pulp mill may have a small amount of SO2 emissions that

would be prohibitively expensive to monitor with the same reliability, accuracy and

precision as the recovery boiler at the same facility. An emergency diesel generator at a

facility would be another possible example. The best monitoring practices identified in this

report focused on the primary emissions units at facilities such as a pulp mill, and do not

take into account these minor points of SO2 emissions.

The second consideration – facilities with no reduction targets – also suggests the

possibility of an opt out process. These facilities, if they do not intend to control emissions

and create tradeable allowances, would be required to employ significant, and costly,

monitoring only for tracking emissions at historical levels if required to participate fully in

the trading program.
18

An alternative would be to account for the emissions from these units as part of the

overall trading budget, but then allocate the allowances as non-tradeable allowances. If

the source continues to operate at or below historical operating levels, the source can

continue to use the same emission estimation procedures used to allocate emissions, and

thereby have sufficient allocated allowances to cover all of the emissions. If operations

increase, the facility would have to purchase additional allowances to cover its estimated

increased emissions, based on the same emission estimation techniques used to establish

the allowance allocation for the source. If the source intended to expand operations

significantly, or adopt control measures to have allowances for trade, the source could

choose not to opt out but instead comply fully with the monitoring requirements for trading

sources and receive tradeable allowances.

This type of approach would limit the cost of the trading program for those facilities

that are not expected or required to be active participants in reducing or trading emissions. 

However, the impact of this opt out option in the context of the overall allowance

allocations under the trading program could affect a significant portion of the overall nonutility sector emissions. Table I-4 reproduces Table XIV-1 from the "Market Trading

Forum Non-utility Sector Allocation: Final Report from the Allocations Working Group,"

which lists the total floor allocations for the various industrial categories (WGA, 2002). 

The categories that could be eligible for this opt out provision include cement and lime

manufacturing, pulp and paper process units (including recovery boilers and lime kilns,

but not other boilers), elemental phosphorous production, glass manufacturing, and

metallurgical coke production. In evaluating the total potential impact of this type of opt

out provision, the relative contribution of the industrial sector versus the utility sector to

total regionwide emissions needs to be considered. The electric generating sector

comprises over 50 percent of the total 2018 milestone emissions from sources that would be

included in the trading program, and this opt out provision would not apply to any of those

electric generating units.
19

Table I-4

State/Sector Summary of SO2 Floor Allocations

(tons per year)

Sectors

States Refineries

Lime

Manufacturing*

Industrial

Boilers

Pulp and

Paper

Cement

Manufacturing

Natural Gas

Processing

Elemental

Phosphorus**

Glass

Manufacturing***

Copper

Smelters

Aluminum

Plants

Sulfuric

Acid Plants

Coke

Production Total

Arizona 1,365 978 320 43,000 45,663

California**** 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

Wyoming 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.

****Sector-level emissions are not reported for California – just the State total.
20
21

CHAPTER II

COPPER SMELTERS

Primary copper smelters process copper sulfide ore concentrate to produce anode

copper. Most of the smelters use a batch copper converting process (either Pierce-Smith or

Hoboken converter designs) to produce blister copper. The Kennecott Utah Copper

Corporation (Kennecott) smelter, however, uses a flash copper converting technology,

which produces blister copper in a continuous process. All primary copper smelters in the

WRAP region control SO2 emissions by routing the process off-gases from the smelting and

converting processes to double contact sulfuric acid plants. Fugitive SO2 emissions result

from equipment leaks and from slag tapping, matte tapping, and slag return. Fugitive

emissions are sometimes captured with a hood and routed to air pollution control

equipment. 

There are six primary copper smelters in the WRAP region. Currently, only three of

these smelters are producing copper; the ASARCO smelter in Hayden, Arizona, the Phelps

Dodge smelter in Miami, Arizona, and Kennecott near Garfield, Utah. The other three

smelters have suspended operations and are not producing copper at this time. Pechan

reviewed permit information for three copper smelters; BHP in San Manuel, Arizona, 

ASARCO, and Kennecott. Note that the monitoring requirements for fuel combustion

units at smelters were not reviewed since these requirements are discussed in a separate

chapter in this report. 

As stated above, Kennecott utilizes a different copper smelting process than the

smelters in Arizona and New Mexico. The majority of the SO2 emissions generated from

this process are released at the main stack. Therefore, Utah requires the main stack at

Kennecott to have a CEMS for SO2 and NOx, flow monitoring, and stack testing every 3

years. Kennecott is required to have an SO2 CEMS for the sulfuric acid plant (40 CFR 60

Subpart H, NSPS for Sulfuric Acid Production). It is also required to monitor other

emissions units at the plant as well. The wet scrubbers are required to be monitored for

pressure drop and liquid flow to the scrubbers. Periodic stack testing for SO2 and sulfuric

acid is required at the following emissions units: liberator, cathode washing, anode scrap

washing, precious metals recovery, silver production. The monitoring requirements for

Kennecott are summarized in Tables II-1 and II-2.

The process used by smelters in New Mexico and Arizona results in significant SO2

being emitted as fugitive emissions. A different monitoring scheme is required for these

smelters. The AMA submitted recommendations for SO2 emissions monitoring at copper

smelters in New Mexico and Arizona. The recommendation is presented in Attachment A

at the end of this chapter. The AMA proposed a sulfur balance method for the facility

which requires sampling of all sulfur containing materials and calculating the sulfur

removed by processes and air pollution control equipment. There are no requirements for

SO2 CEMS. The proposal does not throughly address missing data. In addition, for quality

assurance requirements, the ASARCO permit contains a quality assurance/quality control 
22

(QA/QC) plan for sulfur analysis at its laboratory that could supplement the AMA proposal

(see Attachment B).

Arizona requires measurement systems for continuously monitoring SO2

concentrations and stack gas volumetric flow rates of the following emissions sources: 

(1) outlet of each piece of SO2 control equipment, (2) captured fugitive emissions (hoods),

and (3) converter roof fugitive emissions. Arizona also requires SO2 CEMS and flow

monitoring for the acid plant tail gas. Lastly, Arizona requires that any bypass to the acid

plant be equipped to monitor and record all periods that the bypass is in operation. The

monitoring requirements for Arizona are summarized in Tables II-3 and II-4. These

monitoring requirements assess compliance with specific emission limits, and would not

provide a full accounting of all emissions at a typical smelter.

Ambient SO2 monitoring in the vicinity of the smelter site is required for ASARCO and

Kennecott. The Kennecott permit does not require continuous recording of the monitor if it

is equipped with an alarm. Ambient air monitoring requirements are not summarized in

this chapter.
23

Table II-1

Monitoring Requirements for Main Stack and Other SO2 Sources 

at Kennecott Copper in Utah

Primary Source Category: Copper Smelters (Kennecott Copper, Utah)

Source Type: Main stack, air pollution control equipment, and other emission sources

Emission Measurement/Quantification System:

1) For main stack requires SO2 and NOx CEMS and stack volumetric flow rates (stack gas temperature

and velocity measurement instrumentation).

2) Requires at least one pressure drop and one liquid flow observation per day for each operating

scrubber.

3) Requires SO2 and sulfuric acid stack testing for the following emissions units: Liberator, Cathode

Washing, Anode Scrap Washing, Precious Metals Recovery, Silver Production. Stack tests are

conducted every 3 years in accordance with 40 CFR 60, Appendix A (Method 1, Method 8, and Method

2).

Averaging Times:

3 hour average, 24 hour calendar day average and annual average

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: None Specified

For stack testing, the pollutant concentration is multiplied by the volumetric flow rate and specified

conversion factors.

Procedures for Addressing Missing and Invalid Data: 

Must measure at least 95% of the hours during which emissions occurred in any month. Failure to

measure any 18 consecutive hours of emissions data shall constitute a violation. Any hours for which

the emissions data are greater than 20% in error will be considered to have not been measured.

During periods of malfunction or maintenance, stack gas flow rate may be estimated. These estimates

will be considered as measurements. No more than 10% of the flow rates in any one month shall be

estimated.

If the pressure drop or liquid flow rate deviates from acceptable ranges, the cause must be determined

corrective action must be taken immediately. If they remain out of range for greater than 48 hours, it

shall be considered a deviation from the permit.

Alternative sampling methods approved in writing may be used to supplement monitor availability.
24

Recordkeeping and Reporting Requirements:

Requires semi-annual reports for SO2 emissions including deviations from permit requirements.

Requires stack testing report be submitted within 60 days of test including results as compared to limits

and compliance status. Report must include all raw data.

Requires electronic quarterly CEMS audit report. Report shall include:

1) Source information, 

2) CEMS information (channel, manufacturer, model/serial number, span, installation dates and

locations),

3) periods of span exceedances, system outages, malfunctions, or modifications, 

4) system performance specification audits, 

5) summary of excess emissions including magnitude and duration,

6) description explaining each event of monitor unavailability or excess emissions.

Requires monthly report for

1) date, place, time, and operating conditions for sampling, measurement and analysis,

2) results of each measurement or monitoring system and performance of such systems,

3) calculations used to derive the estimated flow rates and periods where flow rate was estimated,

4) deviation of scrubber performance.

For CEMS, must maintain a file of all:

1) parameters for each continuous monitoring system and monitoring device,

2) performance test measurements,

3) continuous monitoring system performance evaluations,

4) continuous monitoring system or monitoring device calibration checks, and

5) adjustments and maintenance conducted on these systems or devices.

The file shall be retained for at least two years.

Additionally, the following data shall also be recorded: 

1) The total number of hourly periods during the month in which measurements were not taken,

2) The reason for measurement loss in each period greater than three continuous hours of loss,

3) The dates and number of exceedances on which the 3 and 24 hour emissions averages exceeded

the applicable emission level,

4) All conversion values used to derive the 3 and 24 hour average emissions for SO2, including

temperature and differential pressure of stack gases,

5) Support information including all calibration and maintenance records, all original strip-charts or

appropriate recordings for continuous monitoring instrumentation.

The records of all required monitoring data, support information, and copies of all reports must be

retained for least 5 years

Initial Performance Testing: 

SO2 CEMS shall meet 40 CFR Part 60, Appendix B, "Performance Specification 2 - Specifications and

Test Procedures for SO2 and NOx Continuous Emission Monitoring Systems in Stationary Sources."

Flow monitor shall meet 40 CFR Part 52 Appendix E.

Pressure drop and liquid flow rate for each scrubber shall be observed and recorded at the time of any

compliance stack testing.
25

Periodic Calibration: CEMS shall meet 40 CFR 60 Appendix F. Calibration shall be performed once

per day and the hours during which calibration is performed shall be considered as measured if at least

40 minutes of data are measured for each of those hours.

Pressure drop and liquid flow rate shall be calibrated in accordance with manufacturer's instructions.

Audits: 

Conduct Relative Accuracy Test Audits (RATA) and quarterly Relative Accuracy Audits (RAA) or

Cylinder Gas Audits (CGA) following Title 40 CFR 60 Appendix F.

Conduct Performance Specification in Appendix E of 40 CFR 52 procedures on the stack gas flow rate

measurement system in the event that the results of the quarterly and annual tests demonstrate that

the SO2 monitoring system is not performing properly.

Other Appropriate Quality Control and Quality Assurance Measures: None specified 

Cost Analysis: Not Available
26

Table II-2

Monitoring Requirements for Acid Plant at Kennecott Copper in Utah

Primary Source Category: Copper Smelters (Kennecott Copper, Utah.)

Source Type: Sulfuric Acid Plant

Emission Measurement/Quantification System:

SO2 CEMS and flow monitor

Stack testing of SO2 concentration and flow rate every three years using in accordance with 40 CFR 60,

Appendix A, (Method 1, Method 8, and Method 2).

Averaging Times:

1-hour averages computed from four or more data points equally spaced over each 1-hour period.

6-hour average calculated as arithmetic mean of 6 contiguous one-hour average SO2 CEMS

concentrations.

24-hour average calculated as averages of 4 consecutive 6-hour periods of each operating day.

Annual average

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions:

For stack testing, the pollutant concentration is multiplied by the volumetric flow rate and specified

conversion factors.

Procedures for Addressing Missing and Invalid Data: 

Alternative sampling methods approved in writing may be used to supplement monitor availability.

Recordkeeping and Reporting Requirements:

Requires semi-annual reports for SO2 emissions including deviations from permit requirements.

Requires stack testing report be submitted within 60 days of test including results as compared to limits

and compliance status. Report must include all raw data.

Requires electronic quarterly CEMS audit report. Report shall include:

1) Source information, 

2) CEMS information (channel, manufacturer, model/serial number, span, installation dates/locations),

3) periods of span exceedances, system outages, malfunctions, or modifications, 

4) system performance specification audits, 

5) summary of excess emissions including magnitude and duration,

6) description explaining each event of monitor unavailability or excess emissions.

For CEMS, must maintain a file of all:

1) parameters for each continuous monitoring system and monitoring device,

2) performance test measurements,

3) continuous monitoring system performance evaluations,

4) continuous monitoring system or monitoring device calibration checks, and

5) adjustments and maintenance conducted on these systems or devices.

The file shall be retained for at least two years.
27

Initial Performance Testing: 

SO2 CEMS shall meet 40 CFR Part 60, Appendix B, "Performance Specification 2 - Specifications and

Test Procedures for SO2 and NOx Continuous Emission Monitoring Systems in Stationary Sources"

Periodic Calibration:

SO2 CEMS shall meet 40 CFR Part 60, Appendix F. A monitor which fails the daily calibration drift test

shall be declared out-of-control, and the out-of-control period shall be documented in the State

electronic data report. Corrective action shall be taken promptly.

Automatically check and record the zero and span calibration drifts (CD) at least once daily in

accordance with the manufacturer’s procedure. Adjust zero and span drift, at a minimum, whenever

the 24-hr zero drift or 24-hr span drift exceeds 100 parts per million (ppm).

Audits: 

Conduct quarterly audits for the SO2 CEMS including relative accuracy test audit (RATA). An alternate 

test (cylinder gas audit or relative accuracy audit) may be conducted in three of the four calendar

quarters in place of conducting RATA.

Performance specification tests and audits shall be conducted so that the entire continuous monitoring

system is concurrently tested.

Other Appropriate Quality Control and Quality Assurance Measures:

Preventive maintenance of CEMS (including spare parts inventory)

Program of corrective action for malfunctioning CEMS

Cost Analysis: Not Available
28

Table II-3

Monitoring Requirements for Stack, Hoods, and Fugitive Emissions at Copper

Smelters in Arizona

Primary Source Category: Copper Smelters, Arizona

Source Type: Air Pollution Control Equipment, Hoods, and Fugitive Emissions

Emission Measurement/Quantification System:

1) Requires a material balance for sulfur (See Attachments A and B).

2) Requires a measurement system for continuously monitoring SO2 concentrations and stack gas

volumetric flow rates of the following:

a. outlet of each piece of sulfur dioxide control equipment 

b. captured fugitive emissions (hoods)

c. converter roof fugitive emissions.

3) At each point in the facility where a means exists to bypass the sulfur removal equipment, the

bypass shall be instrumented and monitored to detect and record all periods that the bypass is in

operation.

Averaging Times: hourly, 3-hour and annual averages

Hourly averages based on one measurement of SO2 concentration and stack gas flow rate reading in

each 15-minute period. Requires 45 minutes of monitoring in each hour.

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: 

Annual average SO2 emissions = average SO2 emissions for all hours measured during the compliance

period ending on that day.

3-hour SO2 emissions averages = at the end of each clock hour, average hourly SO2 emissions for the

preceding three consecutive hours.

Actual cumulative occurrence and emission level = sum total of SO2 emissions from the smelter

processing units and SO2 control and removal equipment.

The captured fugitive emissions shall be included as part of the total plant emissions, but not the

uncaptured fugitive emissions and those emissions due to the use of fuel for space heating or

steam generation. Periods of malfunction, startup, shutdown or other upset conditions shall be

included in the determination.

Procedures for Addressing Missing and Invalid Data:

Failure to measure at least 95% of the hours during which emissions occurred in any month, using the

CEMS shall constitute a violation.

Failure to measure any 12 consecutive hours of emissions in accordance with the requirements in this

subsection shall constitute a violation.

Maintain sufficient spare parts or duplicate systems for the continuous monitoring equipment to allow

for the replacement within six hours of any monitoring equipment part which fails or malfunctions.
29

Recordkeeping and Reporting Requirements:

Maintain a record of all average hourly emissions measurements for 5 years

Monthly reporting requirements

(1) the annual average emissions (expressed in lb/hr) as calculated at the end of each day of the

month;

(2) The total number of hourly periods during the month in which measurements were not taken and

the reason for loss of measurement for each period;

(3) The number of three-hour emissions averages which exceeded each of the applicable emissions

levels for the compliance periods ending on each day of the month being reported;

(4) The date on which a cumulative occurrence limit was exceeded during the month being reported.

(5) All times bypass was in operation and the reason for the bypass.

Initial Performance Testing: Meet 40 CFR Part 60, Appendix B:

“Performance Specification 6 - Specifications and Test Procedures for Continuous Emission Rate

Monitoring Systems in Stationary Sources” including: (1) Performance and Equipment Specifications

(2) CD Test Procedure, and (3) RA Test Procedure, and 

"Performance Specification 2 - Specifications and Test Procedures for SO2 and NOx Continuous

Emission Monitoring Systems in Stationary Sources" including: (1) Installation and Measurement

Location Specifications, (2) Performance and Equipment Specifications, (3) Performance Specification

Test Procedure, (4) The CEMS Calibration Drift Test Procedure, (5) Relative Accuracy Test Procedure

Periodic Calibration: Meet 40 CFR Part 60, Appendix F

Automatically check, quantify, and record the zero and span calibration drifts at least once daily. If

greater than 2Xs the specified limit, the zero and span must be adjusted.

Also subject to the manufacturer’s recommended zero adjustment and calibration procedures at least

once per 24-hour operating period unless manufacturer specifies calibration at shorter intervals.

Audits: Conduct CEMS audits once per quarter including

 Relative Accuracy Test Audit (RATA) must be conducted at least once every four calendar quarters. 

 Cylinder Gas Audit (CGA), if applicable, may be conducted in three of four calendar quarters

 Relative Accuracy Audit (RAA) may be conducted three of four calendar quarters

Other Appropriate Quality Control and Quality Assurance Measures:

Preventive maintenance of CEMS

Program of corrective action for malfunctioning CEMS

Cost Analysis: Not Available
30

Table II-4

Monitoring Requirements for Acid Plant Tail Gas at Copper Smelters in Arizona

Primary Source Category: Copper Smelters (Ray Complex Hayden Smelter, Arizona.)

Source Type: Sulfuric Acid Plant Tail Gas 

Emission Measurement/Quantification System:

SO2 CEMS installed at the acid plant tail gas monitoring station to monitor emissions from the Inco

oxygen flash furnace.

Averaging Times:

1-hour averages computed from four or more data points equally spaced over each 1-hour period.

6-hour average calculated as arithmetic mean of 6 contiguous one-hour average SO2 CEMS

concentrations. 

24-hour average calculated as averages of 4 consecutive 6-hour periods of each operating day.

Annual average

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: None Specified

Procedures for Addressing Missing and Invalid Data: 

If the SO2 CEMS has an excessive audit inaccuracy, corrective action shall be taken followed by a

RATA and test audit. If inaccuracies occur for 2 consecutive quarters, the QA procedures shall be

rewritten or CEMS replaced. 

Recordkeeping and Reporting Requirements:

Required to submit semi-annual compliance certification, quarterly excess emissions report, and

quarterly monitoring report.

Monitoring report includes CEMS data accuracy audits (RATA), results from EPA performance audit

samples, applicable reference methods, summary of all corrective actions.

Required to keep records of monitoring information including, but not limited to, the following:

1. The date, place as defined in the permit, and time of sampling or measurements;

2. The date(s) analyses were performed;

3. The name of the company or entity that performed the analyses;

4. A description of the analytical techniques or methods used;

5. The results of such analyses;

6. The operating conditions as existing at the time of sampling or measurement;

7. Occurrence and duration of any startup, shutdown, or malfunction in operations, any malfunction of

the air pollution control equipment, or any periods during which a continuous monitoring system or

monitoring device is inoperative;

8. Calibration and maintenance records, strip-chart recordings or other data recordings for continuous

monitoring instrumentation, and copies of all reports; and

9. Continuous monitoring system performance evaluations and performance testing measurements.

Must retain records of all required monitoring data and support information for a period of at least 5

years.

Initial Performance Testing:

SO2 CEMS shall meet 40 CFR Part 60, Appendix B, "Performance Specification 2 - Specifications and

Test Procedures for SO2 and NOx Continuous Emission Monitoring Systems in Stationary Sources"
31

Periodic Calibration:

SO2 CEMS shall meet 40 CFR Part 60, Appendix F

Automatically check and record the zero and span calibration drifts (CD) at least once daily in

accordance with the manufacturer’s procedure. Adjust zero and span drift, at a minimum, whenever the

24-hr zero drift or 24-hr span drift exceeds 100 ppm.

Audits: 

Conduct quarterly audits for the SO2 CEMS including relative accuracy test audit (RATA), and cylinder

gas audit (CGA) or relative accuracy audit (RAA).

Other Appropriate Quality Control and Quality Assurance Measures:

Preventive maintenance of CEMS (including spare parts inventory)

Program of corrective action for malfunctioning CEMS

Cost Analysis: Not Available
32

Attachment A

AMA Proposed Protocol For Determining Copper Smelter SO2 Emissions

Sulfur Balance Method

I. DETERMINATION OF SULFUR EMISSIONS FOR THE SMELTER AS A WHOLE

SHALL BE SUBJECT TO THE FOLLOWING CONDITIONS:

A. The emission sum shall apply to all process sulfur emitted into the ambient air

from smelter processing units and sulfur control and removal equipment

associated with the smelting process. The total monthly amount of sulfur

emissions is equal to the weight of the total sulfur introduced into the smelting

process in any calendar month minus the weight of all sulfur removed from the

smelting process streams in that month in any physical form, plus or minus the

weight of the sulfur contained in any month-month decrease or increase necessary

to indicate materials in process. Removed sulfur shall include but not be limited

to sulfur contained in slag, blister copper, copper anodes, reverts, sulfuric acid,

liquified sulfur dioxide, elemental sulfur, flue dust, precipitator dust, acid plant

sludge, scrubber effluent and absorption plant purge. All sulfur not listed above

as removed, including fugitive sulfur emissions, shall be considered as emissions

to the ambient air.

B. Material balances for sulfur described in A.1. above shall be obtained in

accordance with the procedures listed in below.

C. Average daily emissions are to be determined by dividing the total monthly

emissions by the number of operating days in the particular month. An operating

day is defined as any day in which sulfur containing feed is introduced into the

smelting process.

II. CALCULATING INPUT SULFUR

Total sulfur input is the sum of the product of the weight of each sulfur bearing

material introduced into the smelting process as calculated in A.1 below multiplied by the

fraction of sulfur contained in that material as calculated in A.2 below plus the amount of

sulfur contained in fuel utilized in the smelting process as calculated in A.3 below.

A. Material Weight

All sulfur bearing materials, other than fuels, introduced into the smelting process

shall be weighed. Such weighing shall be subject to the following conditions:

1. Weight shall be determined on a belt scale, rail or truck scales, or other

weighing device.

2. Weight shall be determined within an accuracy of ±5 percent.

3. All devices or scales used for weighing are to be calibrated to manufacturer's

specifications. Scales will be calibrated at least quarterly.
33

4. Sulfur bearing materials subject to being weighed shall include but not be

limited to concentrate, cement copper, reverts which are discarded and not

part of the internal circulating load, precipitates, and miscellaneous outside

products. Materials such as limestone and silica flux which are mixed with a

charge of sulfur bearing materials shall be weighed and reported.

B. Sulfur Content

The sulfur content of all sulfur bearing materials introduced into the smelting process

shall be calculated using the following steps:

1. Sampling - The procedure to be followed in sampling is dependent upon the

input vehicles for the sulfur bearing material.

a. Railcar - The smelter operator shall collect a sample using an auger, pipe

sampling, or other representative method. A minimum of two points per

car will be taken and combined. One to twenty cars from the same source

will be combined into one lot.

b. Truck - The smelter operator shall collect a sample using an auger, pipe

sampling, or other representative method. Shipments from offsite may

be sampled at the mine site provided each truckload is sampled. Samples

are combined into lots from trucks delivering material from the same

source. For fluxes from smelter controlled mines, one truckload per day

are sampled.

2. Sample Preparation - Each total sample shall be prepared for analysis in the

following manner:

a. If necessary, the sample shall be crushed to minus quarter inch particles.

b. Each sample is to be thoroughly blended in a roto-cone blender or similar

device.

c. A blended composite sample is to be prepared based on individual sample

weight and moisture. Material to be used in the composite sample is to

be cut with a sample scoop or knife and used to make an 1800-2400 gram

composite sample for each lot.

d. Each composite sample is to be dried and then pulverized to minus 80

mesh using a roto-disc pulverizer or similar equipment and then blended

in a roto-cone blender or similar equipment.

e. A 200 gram portion is to be cut from the composite sample for analysis.
34

3. Sample Analysis.

a. The sample shall be analyzed to determine sulfur content using X-ray

Fluorescence Spectroscopy, Inductively Coupled Plasma Spectroscopy, or

a LECO Sulfur Analyzer.

4. Sulfur Determination - The sulfur content of all feed material treated per

month will be determined by month end physical inventories in conjunction

with certified scales for bed contents. Physical inventory determines

beginning and ending bed for each month and all beds processed during the

month, together with inventory changes for secondaries. Based upon

individual lot numbers for each material processed (i.e., concentrates, reverts,

purchased secondaries, recyclable material, and fluxes) the composite

analysis will be used to determine sulfur input.

C. Fuel Sulfur Content

Sulfur in fuels shall be calculated by multiplying the amount of fuel delivered to the

process by the fraction of sulfur in the fuel as reported to the smelter operator by the fuel's

supplier. The sulfur content determination shall be accurate to within ±5 percent.

III CALCULATING REMOVED SULFUR

Total removed sulfur is the sum of the sulfur removed in each of the following products

as determined by each process set forth below.

A. Furnace Slags

1. The weight of the slag shall be determined using a count of furnace slag

ladles. The weight used for slag in slag ladles will be determined periodically.

2. A sample will be collected from each slag ladle during skimming operations

and may be combined into a daily composite sample.

3. The sample shall be prepared and analyzed for sulfur. The sample will be

dried and pulverized using a roto-disc pulverizer. A 200 gram sample will

then be split out using a Jones splitter, or equivalent.

4. The sample will be analyzed as in B.3 above.

B. Scrubber Sludge

1. For sludge that is collected (as a slurry), clarified, and filtered before drying, a

weight will be determined. If the material is trucked to a drying facility, the

sludge will be sampled each time a truck is filled. A weight will be

determined for a truckload. The sample will be prepared and analyzed for

sulfur using the procedures in II.B.3 above.
35

2. If scrubber sludge is managed in a manner other than as set forth in III.B.1

above, it shall be quantified, sampled, and analyzed pursuant to generally

acceptable methods.

C. Strong Acids

1. The daily production of acid shall be determined by using either a flowmeter

which measures all acid added to the storage tanks from which trucks or rail

cars are loaded, or a daily inventory increased by the amounts of acid shipped

or otherwise transferred during that day.

2. The meter reading or daily inventory will be accurate to within ±5 percent.

3. Strong acid samples will be analyzed for sulfuric acid concentration using

specific gravity, sonic (sound velocity) or other acceptable analytical methods. 

4. The acid stream will be analyzed twice per shift to check sensor accuracy.

5. A product sample will be sent to the laboratory for analysis daily.

6. All flow meters, density gauges, sonic sensors, pressure sensors, etc., used in

determining the sulfur balance will be calibrated according to manufacturer's

specifications.

D. Weak Acids

1. The amount of weak acid discharged from the acid plant and scrubber

systems is to be determined through flow meters.

2. Flow meters will be calibrated as in C.6 above.

3. A 100 ml sample of weak acid shall be collected daily and combined in a

sample container to form a monthly composite sample which is analyzed for

sulfur content using the Barium Sulfate Gravimetric Method or its

equivalent.

E. Sulfur in Copper Production

1. The weight of copper produced is to be determined by weight of copper cast to

an accuracy of within ±5 percent.

2. The weight and number of castings shall be recorded.

3. For blister or anode castings containing more than 100 ppm sulfur the

following procedure will be followed. Three sample bars per charge are to be

obtained at the beginning, middle, and end of each pour. A portion

(approximately 1 gram) from each sample is to be analyzed for sulfur content

using a LECO Sulfur Analyzer with an induction furnace to volatilize the

sulfur and measure the resultant compound using Infrared Spectroscopy to
36

an accuracy of within 50 percent. As an alternative, a slab cut from the bar

will be analyzed using an Optical Emission Spectrometer (using time resolved

spectroscopy). Other analytical techniques may be used if approved.

4. If the average concentration in anode castings has been less than 100 ppm

during the preceding 12-month period, sampling and analysis may be reduced

to a monthly composite or a 50 ppm value may be assumed without sampling.

F. Materials in Process

1. Total tonnage of materials in process shall be determined by physical

inventory on the first day of each month.

2. A monthly change of in-process inventory shall be calculated for each material

in process by taking the difference between the inventory from each material

in process on the first day of the preceding month and multiplying that

difference by the monthly composite sulfur assay for that material.

3. The change of monthly in-process inventory must be accurate to within ±50

percent.
37

Attachment B

QA/QC Plan for Sulfur Analyses at ASARCO Hayden Laboratory

Sulfuric Acid - Shipments and Production

1. Operation: The Sulfuric Acid Analyzer will be operated as per manufacturer’s

instructions.

2. Blank Analyses: A blank analysis consisting of deionized water will be analyzed daily.

This will be compared to the velocity of sound in water and must fall within ± 5% of the

published value.

3. Calibration Verification Sample: A standard sample will be analyzed with each set of

samples. The Calibration Verification Sample must fall within ± 2% of its control

value. The results of the analysis will be plotted on a control chart to indicate the

control value is within three (3) standard deviations.

4. Duplicates: Every twentieth (20) sample, or one sample from each analytical set, will

be analyzed in duplicate. The relative standard deviation will be calculated and must

fall within ± 20%.

5. Quality Control Sample: A quality control sample will be analyzed quarterly. The

analysis will compare within ± 10%. (blind note: JTBaker Sulfuric acid 9681-02)

6. Quality Assurance: When control limits are exceeded, the analysis will be repeated. If

necessary, a supervisory chemist will be notified and the necessary steps will be taken

to bring the analysis within control. No analyses will be reported or used as valid data,

until the method is found to be under control.

LECO Sulfuric Analyzer - Concentrates and By-Products

1. Operation: The LECO Sulfur Analyzer will be operated as per manufacturers

instructions.

2. Blank Analyses: A blank analysis consisting of the crucible accelerator and cover will

be analyzed with each set of samples. The blank value will be calculated assuming a

0.500 gm weight. Blanks that are above 0.10% must be replaced and the analysis

repeated.

3. Calibration Verification Sample: A standard sample will be analyzed with each set of

samples. The Calibration Verification Sample must fall within ± 10% of its control

value. The results of the analysis will be plotted on a control chart to indicate the

control value is within three (3) standard deviations.

4. Duplicates: All samples will be analyzed in duplicate. The relative standard deviation

will be calculated and must fall within ± 20%.
38

5. Quality Control Sample: A quality control sample will be analyzed quarterly. The

analysis will compare within ± 10%.

6. Quality Assurance: When control limits are exceeded, the analysis will be repeated. If

necessary, a supervisory chemist will be notified and the necessary steps will be taken

to bring the analysis within control. No analyses will be reported or used as valid data,

until the method is found to be under control.

Weak Acid Solutions - Process Solutions

1. Operation: The Sulfuric Acid Analyzer will be operated as per manufacturer’s

instructions.

2. Blank Analyses: A blank analysis consisting of deionized water will be analyzed daily.

This will be compared to the velocity of sound in water and must fall within ± 5% of the

published value.

3. Calibration Verification Sample: A standard sample will be analyzed with each set of

samples. The Calibration Verification Sample must fall within ± 2% of its control

value. The results of the analysis will be plotted on a control chart to indicate the

control value is within three (3) standard deviations.

4. Duplicates: Every twentieth (20) sample, or one sample from each analytical set, will

be analyzed in duplicate. The relative standard deviation will be calculated and must

fall within ± 20%.

5. Quality Control Sample: A quality control sample will be analyzed quarterly. The

analysis will compare within ± 10%. (blind note: JTBaker Sulfuric acid 9681-02)

6. Quality Assurance: When control limits are exceeded, the analysis will be repeated. If

necessary, a supervisory chemist will be notified and the necessary steps will be taken

to bring the analysis within control. No analyses will be reported or used as valid data,

until the method is found to be under control.
39

CHAPTER III

SULFUR PLANTS

Sulfur plants are located at refineries, natural gas processing plants and oil and gas

production facilities. The sulfur in the fuel is first removed by scrubbing with an amine

solution. Then H2S is removed from the waste gas stream by the sulfur recovery plant. 

Most plants use the Claus sulfur recovery method which oxidizes H2S into elemental

sulfur, SO2 and water. The elemental sulfur recovered is often sold as a by-product. The

tail gas from the sulfur recovery plant contains sulfur dioxide and other reduced sulfur

compounds. After the Claus plant, the residual H2S in the waste gas may be further

treated in a "tail gas" treatment plant like the SCOT or Stretford-Beavon process. H2S

conversion efficiencies of up to 99.9 percent of sulfur are possible. Residual H2S may also

be flared.

The NSPS for petroleum refineries (40 CFR 60 Subpart J) includes SO2 standards for

Claus sulfur recovery plants. Monitoring requirements in the NSPS rule for refineries are

summarized in Table III-1. The NSPS requires gaseous CEMS for sulfur recovery plants. 

The constituents monitored vary according to the control equipment installed on the plant,

but include SO2, reduced sulfur compounds, and O2. The NSPS does not require flow

monitoring because the flow levels are unnecessary for evaluating compliance.

The NSPS for natural gas processing plants (40 CFR 60 Subpart LLL) includes

standards for sulfur recovery plants. Monitoring requirements in the NSPS rule for

natural gas processing plants are summarized in Table III-2. The monitoring

requirements specify measuring the sulfur production rate and H2S concentration daily

and using a continuous monitoring device to measure average acid gas flow rate from the

sweetening unit hourly. For units with oxidation or reduction control system, the

requirements are similar to those for refineries: CEMS for SO2 and O2, or CEMS for TRS,

except that the values are reported as mass per unit of time, and thus are more amenable

to use in an emissions trading program.

Refineries are located in California, Colorado, New Mexico, Utah and Wyoming.

Natural gas processing plants are located in New Mexico, Utah and Wyoming. Oil and gas

production facilities are located in California, Colorado, New Mexico, Utah and Wyoming. 

In California’s SCAQMD, sulfur plants are subject to the RECLAIM SO2 program. 

Generally, sources use SO2 and flow CEMS under this program for these units.

In addition, New Mexico submitted monitoring requirements for sulfur plants at

natural gas processing plants and refineries which are provided in Table III-3 and Table

III-4. Sulfur plants at both refineries and natural gas processing plants may be required to

use CEMS, either as part of NSPS compliance, or if subject to new source review

permitting. Other sources typically use portable analyzer checks or other approaches.
40

Table III-1

NSPS Monitoring Requirements for Sulfur Recovery Plants at Refineries

Primary Source Category: Refineries 40 CFR 60 Subpart J New Source Performance Standard

Source Type: Claus sulfur recovery plants

Emission Measurement/Quantification System:

1) with oxidation or reduction control system followed by incineration:

CEMS for SO2 (dry basis, 0% excess air) and O2 (for correcting the data for excess air)

Span values: 500 ppm SO2 and 25% O2.

 

2) with reduction control systems not followed by incineration:

CEMS for reduced sulfur (dry basis, 0% excess air) and O2 emissions. 

Span values: 450 ppm reduced sulfur and 25% O2. 

(If performance specification test yields O2 concentrations below 0.25%, O2 not required)

 or

CEMS using an air or O2 dilution and oxidation system to convert the reduced sulfur to SO2 (dry basis,

zero percent excess air) and O2 CEMS for correcting the data for excess oxygen. 

Span values: 375 ppm SO2 and 25% O2.

Averaging Times: 

Calculate 1-hr average of SO2 concentration from 4 or more samples collected periodically during hour. 

Compliance determined by average of 12-hour period 

Calculate 7-day rolling average basis 

Requires a minimum of 22 valid days of data shall be obtained every 30 rolling successive calendar

days

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: None

Procedures for Addressing Missing and Invalid Data:

Requires sources to account for emissions during periods when there are no valid data (missing data

periods) due to the monitor not operating or operating out of control.

Recordkeeping and Reporting Requirements:

Required to submit a written report of the results of the performance evaluation within 60 days of

completion. 

Required to submit semi-annual report specifying periods where monitoring values exceed limits for a

specified monitoring period and periods of missing data
41

Initial Performance Testing:

For SO2 and TRS CEMS: Performance Specification 2

Reference Methods (RM) 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy

evaluations. Conduct a minimum of nine sets of all necessary RM test runs. Correlate the CEMS and

the RM test data. Calculate the mean difference between the RM and CEMS values.

Calibration Drift (CD) - while unit is operating at more than 50 percent of normal load, determine the

magnitude of the CD once each day (at 24-hour intervals) for 7 consecutive days. CD must not drift or

deviate from the reference value of the calibration gas by more than 5 percent of the established span

value for 6 out of 7 test days.

Periodic Calibration:

Calibration of CEMS as specified by manufacturer

Automatically check, quantify, and record the zero and span calibration drifts at least once daily. If

greater than 2Xs the specified limit, the zero and span must be adjusted.

Audits:

Conduct a performance evaluation of the CEMS during or within 30 days any performance test required

under §60.8

Conduct CEMS audits once per quarter

Relative Accuracy Test Audit (RATA) must be conducted at least once every four calendar quarters. 

Cylinder Gas Audit (CGA), if applicable, may be conducted in three of four calendar quarters

Relative Accuracy Audit (RAA) may be conducted three of four calendar quarters

Take corrective action, as required, to correct any problems with CEMS

Other Appropriate Quality Control and Quality Assurance Measures:

Preventive maintenance of CEMS (including spare parts inventory). 

QC for data recording, calculations, and reporting. 

Program of corrective action for malfunctioning CEMS. 

Cost Analysis:

a. Installed Capital Cost

b. Direct Operating Cost

c. Total Annualized Cost

d. Equipment Life

e. Year Dollars

f. Discount Rate
42

Table III-2

NSPS Monitoring Requirements 

for Sulfur Plants at Natural Gas Processing Plants

Primary Source Category: Natural Gas Processing 40 CFR 60 Subpart LLL

Source Type: Sulfur Plants

Emission Measurement/Quantification System:

Requires measuring the following on a daily basis:

1) accumulation of sulfur product over each 24-hour period using an instrument to measure sulfur

production rate or manual measurement of sulfur liquid levels in storage tanks.

2) H2S concentration in the acid gas from the sweetening unit for each 24 hour period by collecting and

analyzing at least one sample using specified method.

3) average acid gas flow rate from the sweetening unit using a continuous monitoring device that

records hourly flow rate.

Optional H2S measurement technique is Tutwiler procedure 

For unit with oxidation or reduction control system followed by incinerator, requires the following:

1) CEMS for SO2(expressed as equivalent sulfur mass flow rate) 

Span value of 30% to 70% of unit emission limit

2) monitoring device to measure temperature of gas leaving combustion zone of incinerator

or

CEMS for TRS (upon promulgation of performance spec. for CEMS of TRS at sulfur recovery plants)

For unit with oxidation or reduction control system not followed by incinerator;

1) CEMS for reduced sulfur compounds as SO2 (expressed as equivalent sulfur mass flow rate) (upon

promulgation of performance spec. for CEMS of TRS at sulfur recovery plants)

Averaging Times:

Daily measurement of sulfur production rate

Daily sampling of H2S

Hourly measurement of acid gas flow rate averaged over 24-hour period

For CEMS, hourly average based on 15-minute sampling intervals

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions:

Daily average sulfur feed rate = average daily flow rate x average daily H2S concentration x CF

Daily average SO2 reduction efficiency = sulfur production rate ÷ average daily sulfur feed rate x CF,

where CF=conversion factor

For unit with oxidation or reduction control system followed by incinerator:

Total sulfur emission rate = SO2 + TRS (both as equivalent sulfur mass flow rate)

Procedures for Addressing Missing and Invalid Data:

At least 2 data points required to calculate hourly average for CEMS

At least 18 1-hour averages to calculate 24-hour averages

No procedures specified
43

Recordkeeping and Reporting Requirements:

Records of measurements and calculations must be retained for 2 years

Submit written report for excess emissions, when emission reduction efficiency is less than minimum,

or for temperature of combustion zone is out of range

Initial Performance Testing:

Temperature monitor must be manufacturer certified as ± 1% accurate for operating temperature range

Performance Specification 2 for SO2 CEMS

Reference Methods (RM) 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy

evaluations. Conduct a minimum of nine sets of all necessary RM test runs. Correlate the CEMS and

the RM test data. Calculate the mean difference between the RM and CEMS values.

Calibration Drift (CD) - while unit is operating at more than 50 percent of normal load, determine the

magnitude of the CD once each day (at 24-hour intervals) for 7 consecutive days. D must not drift or

deviate from the reference value of the calibration gas by more than 5 percent of the established span

value for 6 out of 7 test days.

Periodic Calibration:

Monitoring devices must be calibrated at least annually according to manufacturers specifications.

Automatically check, quantify, and record the zero and span calibration drifts at least once daily. If

greater than 2Xs the specified limit, the zero and span must be adjusted.

Audits:

Conduct a performance evaluation of the CEMS during or within 30 days any performance test required

under §60.8

Conduct CEMS audits once per quarter

Relative Accuracy Test Audit (RATA) must be conducted at least once every four calendar quarters. 

Cylinder Gas Audit (CGA), if applicable, may be conducted in three of four calendar quarters

Relative Accuracy Audit (RAA) may be conducted three of four calendar quarters

Sampling and analysis methods accuracy audit

Other Appropriate Quality Control and Quality Assurance Measures:

Preventive maintenance of CEMS (including spare parts inventory). 

QC for data recording, calculations, and reporting. 

Program of corrective action for malfunctioning CEMS.

Cost Analysis:

a. Installed Capital Cost

b. Direct Operating Cost

c. Total Annualized Cost

d. Equipment Life

e. Year Dollars

f. Discount Rate
44

Table III-3

Monitoring Requirements for Sulfur Plants at Natural Gas Processing Plants

in the State of New Mexico

Primary Source Category: Natural Gas Processing Plants/New Mexico

Source Type: Sulfur Plants

Emission Measurement/Quantification System: CEMS, Overall System Integrity (OSI) & Sulfur

Recovery Efficiency (SRE)

Averaging Times: The monitor shall complete a minimum of one cycle of operation (sampling,

analyzing and data recording) for each successive 15-minute period or less. One-hour averages shall

be computed from four or more data points equally spaced over each one-hour period. The data from

the SO2 stack gas monitor and flow meter shall be analyzed on an hourly basis for SO2 concentration

and volume flow rate. The minimum data capture for the CEMS shall be 95%.

OSI monthly equipment inspections for Non-NSPS Subpart LLL sources and daily for sources subject

to LLL. State regulation(s) require the measurement (frequency varies from daily to quarterly) of the

following Sulfur Recovery Unit (SRU) parameters: incinerator temperature, excess O2 level in the

incinerator, acid gas flow rate and H2S concentration and a running tally of the accumulated elemental

sulfur recovered.

Consideration of Batch, Seasonal, and Cyclical Operations: None.

Calculations Used to Determine Quarterly and Annual Mass Emissions: SO2 emissions = Daily H2S

volume * H2S concentration (PPMV) * H2S (MW) * 64/32 / E6 * 385 (F factor) * 24 hrs/day.

Procedures for Addressing Missing and Invalid Data: Periods when the SRU and/or CEMS are not

operational are excluded from the data capture calculation and records shall be kept for these

occurrences in accordance with 40 CFR 60.7

Recordkeeping and Reporting Requirements: The permittee shall maintain records of all SRU

inspections and tests required and records of any adjustments, repairs, or replacements needed to

bring the SRU into compliance with the permit conditions. All records shall show the date of inspection

and the name of the person(s) who carried out the inspection. If the permittee keeps records more

frequently than the minimum frequency required, the permittee shall also keep these records for

Department inspection.

The permittee shall maintain records of the SRU operating parameters and equipment and operational

inspections and results of the periodic mass emission tests on the incinerator. The permittee shall

maintain records showing calibration results on any instrument or apparatus used to determine

pollutant concentration species, process stream flows, or temperatures.

For sources subject to Subpart LLL: The permittee shall maintain records of all calibrations carried out

on the SO2 CEMS. The record shall show the date of calibration, and calibration gas data

(concentration, gas supplier name and address, mixture serial number and expiration date). 

Compliance with 40 CFR 60.7 is required.

The permittee shall maintain records of all service and maintenance performed on the CEMS, including

a description of the problem requiring the maintenance or repair.

Reports of equipment and/or operational inspections shall briefly summarize in chronological order the

results of all SRU inspections noting any adjustments needed to bring the SRU into compliance with

permit conditions. 
45

Reports of periodic emissions tests shall summarize in tabular form, for each test, the SO2

concentrations expressed in ppm. The table shall include the incinerator combustion zone

temperature, the level of excess air, and the SRU bed temperatures.

The report of the initial or subsequent emissions tests shall conform to the standard format specified by

the Department, Standard Operating Procedure: Contents of Stack Test Reports. The SO2

 CEM shall

comply with the reporting requirements of 40 CFR 60.7 regarding submission of excess emissions

reports. Reports of all required monitoring activities for this facility, except those reports required by an

NSPS, shall be submitted to the Department according to the schedule indicated below. Reports

required by NSPS Subpart LLL shall be submitted at the frequency required by the appropriate NSPS

subpart.

Protocols for emissions tests shall be submitted to the Department at least four (4) weeks prior to the

scheduled test date with content according to the Department’s Standard Operating Procedure for

Contents of Stack Test Protocols. If information remains the same as in previously submitted

protocols, test protocols shall reflect that fact and show only new information.

Initial Performance Testing: A mass emissions test for SO2, shall be conducted on the SRU in

accordance with EPA Methods 1 through 4, Method 6 (SO2) contained in 40 CFR Part 60, Appendix A,

and with the requirements of Subpart A, General Provisions, Sect. 60.8(f). 

The SRUs sulfur recovery efficiency and the incinerator's sulfur combustion efficiency shall be

determined in accordance with the appropriate subsections of NSPS Subpart LLL, 40 CFR 60.644.

Non-NSPS units shall determine the SRUs sulfur recovery efficiency, and the incinerator's sulfur

combustion efficiency shall be determined in accordance with the attached Standard Operating

Procedure: Sulfur Recovery Unit Performance Testing.

The permittee shall notify the Department at least thirty (30) days prior to the test date and allow a

representative of the Department to be present at the test. The permittee shall arrange a pre-test

meeting with the Department at least thirty (30) days prior to the test date and shall observe the

following pre-testing and testing procedures:

The test protocol and test report shall conform to the standard format specified by the Department as

described in Standard Operating Procedure: Contents of Stack Test Protocols. The most current

version of the format may be obtained from the Enforcement Section of the Air Quality Bureau.

The permittee shall provide (a) sampling ports adequate for the test methods applicable to the facility,

(b) safe sampling platforms, (c) safe access to sampling platforms and (d) utilities for sampling and

testing equipment. The stack shall be of sufficient height and diameter so that a representative test of

the emissions can be performed in accordance with EPA Method 1.

During compliance tests, the following variables shall be measured and recorded and included with the

test report:

The SRUs bed temperatures (top, middle, and bottom), condenser temperatures, incinerator

combustion zone temperature, flow and concentration of acid gas feedstock to SRU, and amount of

elemental sulfur recovered.

Where necessary to prevent cyclonic flow in the stack, flow straighteners shall be installed.

The tests shall be carried out at 90% or greater of the SRUs full operating capacity and at other

operating loads as may be specified by the Department at the time of the test or pre-test meeting.

Periodic Calibration: CEMS shall be calibrated daily in accordance with NSPS Subpart A, 40 CFR

60.13(d)(1).
46

Audits: An SRU with an SO2 CEMS requires no periodic emissions testing unless the SRU is by itself

major for NOx or CO. If the SRU is by itself major for either NOx

 or CO, then NOx and CO concentration

measurements are required even when the incinerator has an SO2 CEM. 

The SO2 {and NOx and CO} concentration of the incinerator flue gas shall be measured. The

measurement may be carried out using a portable flue gas analyzer using the procedures in the most

current version of the Bureau's Standard Operating Procedure: Use of Portable Analyzers in

Performance Tests. The permittee need only observe those sections relative to sample conditioning,

analyzer range and sensitivity, response time, and calibration. The test may also be carried out using

any effective procedure approved in advance by the Department. Emissions shall be expressed in

ppm.

Each test shall be carried out while the SRU is operating at a load representative of the load during the

relevant time period. Periodic emissions tests shall be conducted at the intervals in the following

schedule:

First test: Six (6) months from permit issuance;

Second test: Twelve (12) months from permit issuance;

Third test: Twenty four (24) months from permit issuance;

Fourth test: Forty eight (48) months from permit issuance;

All subsequent testing shall follow at twenty-four (24) month intervals. However, the test schedule is

contingent on maintaining test data that indicates compliance. If any test indicates non-compliance, the

periodic emissions test sequence shall revert to the beginning of the above schedule, starting with the

date of the most recent test.

Other Appropriate Quality Control and Quality Assurance Measures: Initial emission testing is required

for SRU’s that have not been stack tested in the ten years previous to permit issuance. SRU’s

equipped with CEMS shall be recertified every year in accordance with NSPS Appendix B, 40 CFR 60.

Cost Analysis: Unknown.
47

Table III-4

Monitoring Requirements for Sulfur Recovery Plants at Refineries

in the State of New Mexico

Primary Source Category: Refinery/New Mexico

Source Type: Sulfur Plant

Emission Measurement/Quantification System: Continuous Emissions Monitoring System (CEMS),

Overall System Integrity (OSI) & Sulfur Recovery Efficiency (SRE)

Averaging Times: The monitor shall complete a minimum of one cycle of operation (sampling,

analyzing and data recording) for each successive 15-minute period or less. One-hour averages shall

be computed from four or more data points equally spaced over each one-hour period. The data from

the SO2 stack gas monitor and flow meter shall be analyzed on an hourly basis for SO2 concentration

and volume flow rate. The minimum data capture for the CEMS shall be 95%.

OSI monthly equipment inspections for Non-NSPS Subpart J sources and daily for sources subject to

J. State regulation(s) require the measurement (frequency varies from weekly to monthly) of the

following Sulfur Recovery Unit (SRU) parameters: feedstock sulfur content entering the sulfur recovery

plant, the weight of the recovered sulfur and the concentration of sulfur dioxide and hydrogen sulfide in

the exit gas stream or streams. 

Consideration of Batch, Seasonal, and Cyclical Operations: None.

Calculations Used to Determine Quarterly and Annual Mass Emissions: SO2 emissions = Daily H2S

volume * H2S concentration (PPMV) * H2S (MW) * 64/32 / E6 * 385 (F factor) * 24 hrs/day. Also the

methods outlined in Subpart J 60.106. 

Procedures for Addressing Missing and Invalid Data: Periods when the SRU and/or CEMS are not

operational are excluded from the data capture calculation and records shall be kept for these

occurrences in accordance with 40 CFR 60.7.

Recordkeeping and Reporting Requirements: The permittee shall maintain records of all SRU

inspections and tests required and records of any adjustments, repairs, or replacements needed to

bring the SRU into compliance with the permit conditions. All records shall show the date of inspection

and the name of the person(s) who carried out the inspection. If the permittee keeps records more

frequently than the minimum frequency required, the permittee shall also keep these records for

Department inspection. Records of all calibration and maintenance performed for the instruments that

measure sulfur flow and concentration into and out of the SRU

The permittee shall maintain records of the SRU operating parameters and equipment and operational

inspections and results of the periodic mass emission tests on the incinerator. The permittee shall

maintain records showing calibration results on any instrument or apparatus used to determine

pollutant concentration species, process stream flows, or temperatures.

For sources subject to Subpart J: The permittee shall maintain records of all calibrations carried out on

the SO2 CEMS. The record shall show the date of calibration, and calibration gas data (concentration,

gas supplier name and address, mixture serial number and expiration date). Compliance with 40 CFR

60.7 is required.

The permittee shall maintain records of all service and maintenance performed on the CEMS, including

a description of the problem requiring the maintenance or repair.

Reports of equipment and/or operational inspections shall briefly summarize, in chronological order, the

results of all SRU inspections noting any adjustments needed to bring the SRU into compliance with

permit conditions. 

Reports of periodic emissions tests shall summarize in tabular form for each test the SO2

concentrations expressed in ppm. The table shall include the incinerator combustion zone

temperature, the level of excess air, and the SRU bed temperatures. 
48

The report of the initial or subsequent emissions tests shall conform to the standard format specified by

the Department, Standard Operating Procedure: Contents of Stack Test Reports. The SO2 CEM shall

comply with the reporting requirements of 40 CFR 60.7 regarding submission of excess emissions

reports. Reports of all required monitoring activities for this facility, except those reports required by an

NSPS, shall be submitted to the Department according to the schedule indicated below. Reports

required by NSPS Subpart J shall be submitted at the frequency required by the appropriate NSPS

subpart.

Initial Performance Testing: A mass emissions test for SO2, shall be conducted on the SRU in

accordance with EPA Methods 1 through 4, Method 6 (SO2) contained in 40 CFR Part 60, Appendix A,

and with the requirements of Subpart A, General Provisions, Sect. 60.8(f). 

Compliance with the SO2, H2S and reduced sulfur standards in 60.104(a)(2) in accordance with the

appropriate subsections of NSPS Subpart J, 40 CFR 60.106.

Non-NSPS shall determine the SRUs sulfur recovery efficiency, and the incinerator's sulfur combustion

efficiency shall be determined in accordance with the attached Standard Operating Procedure: Sulfur

Recovery Unit Performance Testing.

During compliance tests, the following variables shall be measured and recorded and included with the

test report:

The SRUs bed temperatures (top, middle, and bottom), condenser temperatures, incinerator

combustion zone temperature, flow and concentration of acid gas feedstock to SRU, and amount of

elemental sulfur recovered.

Periodic Calibration: CEMS shall be calibrated daily in accordance with NSPS Subpart A, 40 CFR

60.13(d)(1).

Audits: An SRU with an SO2

 CEMS requires no periodic emissions testing unless the SRU is by itself

major for NOx or CO. If the SRU is by itself major for either NOx or CO, then NOx and CO concentration

measurements are required even when the incinerator has an SO2 CEM. 

The SO2 {and NOx and CO} concentration of the incinerator flue gas shall be measured. The

measurement may be carried out using a portable flue gas analyzer using the procedures in the most

current version of the Bureau's Standard Operating Procedure: Use of Portable Analyzers in

Performance Tests. The permittee need only observe those sections relative to sample conditioning,

analyzer range and sensitivity, response time, and calibration. The test may also be carried out using

any effective procedure approved in advance by the Department. Emissions shall be expressed in

ppm.

Each test shall be carried out while the SRU is operating at a load representative of the load during the

relevant time period. Periodic emissions tests shall be conducted at the intervals in the following

schedule:

First test: Six (6) months from permit issuance;

Second test: Twelve (12) months from permit issuance;

Third test: Twenty four (24) months from permit issuance;

Fourth test: Forty eight (48) months from permit issuance;

All subsequent testing shall follow at twenty-four (24) month intervals. However, the test schedule is

contingent on maintaining test data that indicates compliance. If any test indicates non-compliance, the

periodic emissions test sequence shall revert to the beginning of the above schedule starting with the

date of the most recent test.

Other Appropriate Quality Control and Quality Assurance Measures: Initial emissions testing is

required for SRU’s that have not been stack tested in the ten years previous to permit issuance. SRU’s

equipped with CEMS shall be recertified every year in accordance with NSPS Appendix B, 40 CFR 60.

Cost Analysis: Unknown
49

CHAPTER IV

FUEL COMBUSTION UNITS

This chapter addresses existing monitoring requirements for the broad category of

industrial boilers, turbines, and other fuel combustion units that may be subject to the

backstop trading program. This category affects many different industrial facilities, and

includes many different types of units, especially with respect to fuel type and unit size. 

The fuel type has a significant impact on monitoring. For example, EPA has generally

been receptive to fuel sampling options in trading programs, but only for non-solid fuel

combustion units. In addition, the possibility that small units may be subject to the

trading program is an issue for selecting appropriate monitoring. 

The methodology for reviewing this category began with an acknowledgment that the

monitoring provisions in 40 CFR Part 75 already apply to many of the unit types in this

category, and that those provisions include non-CEMS options for units that do no burn

solid fuel. In addition, the OTC has applied similar monitoring to numerous industrial fuel

combustion units (but for NOx mass in place of SO2 mass emissions). These existing

monitoring programs are used as the basic benchmark in this chapter because they are

designed for emissions trading programs. However, these existing monitoring programs

have not applied to smaller industrial combustion units nor to pulp mill recovery furnaces. 

To address these units, we examined NSPS provisions and followed up with State contacts

to identify any additional State-based monitoring requirements. 

The results of this review are summarized in the following tables. Table IV-1 provides

a brief snapshot of the primary federal and OTC monitoring requirements that apply, and

Tables IV-2 through IV-6 provide a more detailed overview of the requirements in Table

IV-1 that potentially could be used as part of an SO2 trading program. Tables IV-7 through

IV-9 provide examples of SO2 mass monitoring systems from Oregon that appear to be

potential candidates as well. Note that the SCAQMD also has SO2 mass monitoring under

its RECLAIM program. Because of the closeness between the basic elements of those

provisions and EPA's Part 75 program, we have not summarized the South Coast

provisions separately. 

We have included some approximate cost information for many of the basic monitoring

approaches. Preliminary cost estimates are provided for Part 75 CEMS and fuel

sampling/fuel flow monitoring methodologies based on previous Part 75 monitoring cost

analysis. We also used the EPA, CEMS Cost Model Version 3.0 and User Manual, 1998.
50

Table IV-1

Summary of Part 75, OTC and NSPS Monitoring Methods

Primary Source Category Source Types

Applicable Federal/Trading Program Monitoring Options

PART 75 Regulations OTC NOx Budget Program NSPS

Refineries Fuel Gas Combustion Unit

 - Boilers

 - Process Heaters

! SO2 and Flow CEMS (all

fuel types).

[See Table IV-2]

! Fuel sampling and

analysis for sulfur and

gross calorific value

(GCV), and fuel flow

monitoring. Sampling and

analysis schedule based

on maximum sulfur

content and sulfur/GCV

variability (oil and gas

units only). Use assumed

sulfur default value for

pipeline natural gas.

[See Table IV-3]

! Units with low mass

emissions (25 tons/year

SO2) can use default SO2

emission factors combined

with unit’s max. rated heat

input or long term fuel flow

monitoring (gas and oil

fired units only) . [See

Table IV-4] 

Generally the same as Part 75,

except used for NOx mass

monitoring. See approved fuel

sampling approaches for GCV of

process gas. Units that had

been subject to the OTC

program monitoring

requirements now must meet

Part 75, Subpart H requirements

as part of the NOx SIP Call. 

Note that this requirement

extends to cement kilns. 

SO2 and O2 CEMS 

(ppm); or

Fuel gas H2S monitoring (ppm or

gr/dscf).

[Part 60, Subpart J] [See Table

IV-6]

Industrial Boilers (including cogenerators) Boilers - fossil-fuel fired

 - coal, solid fuel

 - natural gas

 - process gas

 - fuel oil

SO2 and O2 or CO2 CEMS

(lb/MMBtu); 

Daily coal or oil sampling and

analysis for sulfur and heat

content; or

Daily stack testing (lb/MMBtu). 

Note: May use as received tank

sampling in place of daily

sampling for oil. 

For small units or units burning

low sulfur oil, can use fuel

supplier certification. 

(lb/MMBtu).

[Part 60 Subparts D, Da, Db, Dc] 

[See Table IV-5]

Pulp and Paper Boilers - fossil-fuel fired

Recovery Boilers Not directly applicable. Not directly applicable. TRS CEMS

(ppm)

[Part 60 Subpart BB]
51

Table IV-2

Part 75 CEMS Methodology

Primary Source Category: Refineries, Industrial Boilers, Pulp and Paper

Source Type: Boilers/Process Heaters/Recovery Furnaces

Emission Measurement/Quantification System: Requirements are in 40 CFR 75.10 and 75.11.

! SO2 and Flow CEMS (may also use a diluent CEMS if heat input is also required)

! The CEMS includes a Data Acquisition and Handling System (DAHS) for electronic

processing of measurement data. 

! Equipment and performance specifications are in Part 75, Appendix A.

Averaging Times: Hourly (measurement recorded at least every 15 minutes) - Sec. 75.10(d). 

Consideration of Batch, Seasonal, and Cyclical Operations: The frequency of quality assurance testing

(RATAs, linearity, flow to load, differential pressure flow monitor leak checks) is based on the number

of operating hours in a quarter (Part 75, Appendix B).

Calculations Used to Determine Quarterly and Annual Mass Emissions: Calculations are specified in

Part 75, Appendix F, Sec. 2:

! Annual Mass Emissions = Sum of Quarterly Mass Emissions

! Quarterly Mass Emissions = Sum of Hourly Emissions

! Hourly Emissions = (hourly SO2 concentration) x (hourly flow) x (unit conversion factor)

Procedures for Addressing Missing and Invalid Data: Part 75, Subpart D requires sources to account

for emissions during periods when there are no valid data (missing data periods) due to the monitor not

operating or operating out of control. The missing data algorithms in Table 1, Sec. 75.33, become

increasingly conservative as monitor downtime increases, and are based on previous monitoring data. 

There are also optional missing data procedures for units using control equipment which rely on control

equipment parameter monitoring (Sec. 75.34).

Recordkeeping and Reporting Requirements:

Recordkeeping:

! Monitoring plan which includes basic unit identification information and monitoring

methodology (Sec. 75.53).

! Quality Assurance/Quality Control Plan and Maintenance Log (Sec. 75.21 and Appendix B)

! Certification (including recertification) and quality assurance test results (Sec. 75.59)

! Hourly CEMS data including unit operating time, SO2 concentration, flow, SO2 mass rate,

percent monitor data availability, and SO2 method of determination (Sec. 75.57).

Reporting:

! Initial certification application (includes monitoring plan and initial certification test results)

(Secs. 75.62 and 63).

! Quarterly reporting of hourly CEMS data, quality assurance test results, recertification tests,

and summary of quarterly and year to date emissions (Sec. 75.64). 
52

Initial Performance Testing: Part 75 initial certification testing is outlined in Sec. 75.20 and Appendix A,

Sec. 6:

! 7-day calibration error test for each monitor

! Linearity check for each pollutant concentration monitor

! Relative Accuracy Test Audit (RATA) for each monitor

! Bias test for each SO2 pollutant concentration monitor and flow monitor

! Cycle time test for each SO2 pollutant concentration monitor

! Daily interference test for flow monitors

! DAHS testing

Periodic Calibration: Part 75, Appendix B:

! Daily calibration error tests are required for the gas CEMS.

! Daily interference test for flow CEMS.

Audits: Part 75, Appendix B:

! Quarterly linearity tests for SO2 CEMS

! Quarterly flow-to-load evaluations for flow monitor values.

! Semi-annual or annual RATAs for SO2 and flow CEMS.

! Annual leak check for differential pressure flow CEMS.

Other Appropriate Quality Control and Quality Assurance Measures: Recertification (includes quality

assurance testing) is required for a replacement, modification, or change that may significantly affect

the CEM's ability to accurately measure monitored parameters (Sec. 75.20(b)).

Cost Analysis:

a. Installed Capital Cost: $124,000 to $192,000 with median of $138,000 (Part 75 CEM Cost Study

(1999)). This is for a Part 75 NOx\Diluent\Flow CEMS, but SO2 analyzer cost

should be comparable (OAQPS CEM Cost Model Manual - $12,500 for SO2

analyzer versus $10,440 for NOx analyzer), or

$165,000 for SO2/Flow CEMS (OAQPS CEM Cost Model).

b. Direct Operating Cost: $55,500 for a complete Part 75 CEMS setup, which includes both SO2, NOx,

Diluent, and Flow CEMS (U.S. EPA Title IV ICR, 2002, labor costs adjusted

to 1998 dollars), or 

$34,800 for SO2/Flow CEMS (OAQPS CEM Cost Model).

c. Total Annualized Cost:$75,100 (Part 75 CEM Cost Study (1999) and Part 75 ICR),or 

$58,400 (OAQPS CEM Cost Model).

d. Equipment Life: 5 - 20 years, median - 10 years (Part 75 CEM Cost Study (1999))

e. Year Dollars: 1998

f. Discount Rate: 7%
53

Table IV-3

Part 75 Appendix D Fuel Sampling/Flow Method for Oil and Gas Fired Units

Primary Source Category: Refineries, Industrial Boilers, Pulp and Paper

Source Type: Gas and Oil Fired Boilers/Process Heaters.

Emission Measurement/Quantification System: 40 CFR Part 75, Appendix D. 

! Fuel flow monitoring with certified flow meter, and

! Fuel sampling and analysis to determine SO2 emission factor, and fuel heat input.

! Oil sampling and analysis for sulfur content, density, and gross caloric value (GCV) using

American Society for Testing and Materials (ASTM) standard methods. Sampling

alternatives (Appendix D, Sec 2.2, Table D-4) include: after each delivery, from the fuel

storage tank, daily flow proportional sampling, and daily as fired sampling.

! Gaseous sampling and analysis for sulfur content and GCV using ASTM standard methods

varies by fuel sulfur content and sulfur/GCV variability. Sulfur content analysis is not required

for pipeline natural gas if supplier contract or tariff verifies a total sulfur content not greater

than 0.5 gr/100 scf, or not greater than 20.0 gr/100cf for natural gas. Required sulfur analysis

sampling frequency can be hourly, daily, annually, or by shipment. Required GCV analysis

sampling frequency can be hourly, daily, monthly or by shipment. (Appendix D, Sec 2.3 Table

D-5)

! Must use a Data Acquisition and Handling System (DAHS) for electronic processing of

measurement data. 

! Equipment and performance specifications for fuel flow monitors are in Part 75, Appendix D. 

The DAHS specifications are in Part 75, Appendix A, Sec. 4.

Averaging Times: Hourly 

Consideration of Batch, Seasonal, and Cyclical Operations: The frequency of quality assurance testing

is based on quarterly operating hours (Part 75, Appendix D, Sec. 2.1.6.)

Calculations Used to Determine Quarterly and Annual Mass Emissions: Calculations are specified in

Part 75, Appendix D, Sec. 2.3:

! Annual Mass Emissions = Sum of Quarterly Mass Emissions

! Quarterly Mass Emissions = Sum of Hourly Emissions

! Hourly Emissions = SO2 emission factor (lb/MMBtu) x hourly heat input (MMBtu), or

( ) x fuel flow rate (scf/hr) x sulfur content (gr/scf) 2.0

7000

! The SO2 emission factor may be a default factor of 0.0006 lb/MMBtu, if using pipeline natural

gas. If using natural gas, can use contract/tariff value as default. If using other gas, can

calculate a default value if low sulfur variability, or use as sampled value based on hourly,

daily, or as shipped basis. 

Procedures for Addressing Missing and Invalid Data: Part 75, Subpart D requires sources to account

for emissions during periods when there are no valid data (missing data periods) due to the monitor not

operating or operating out of control: 

! Missing fuel analysis data - use default values in Appendix D, Sec. 2.4.1 Table D-6.

! Missing fuel flow rate (single fuel) - load based using data from previous 720 monitored

hours, or if load data is not appropriate for the unit, use the average flow rate over the

previous 720 hours for the same fuel. (Appendix D, Sec. 2.4.2).

! Missing fuel flow rate (multiple fuels) - Similar to the single fuel requirements, except that the

previous 720 hours when burning multiple fuels are used. (Appendix D, Sec. 2.4.2).
54

Recordkeeping and Reporting Requirements:

Recordkeeping:

! Monitoring plan which includes basic unit identification information and monitoring

methodology (Sec. 75.53).

! Quality Assurance/Quality Control Plan and Maintenance Log (Sec. 75.21 and Appendix B).

! Certification (including recertification) and quality assurance test results (Sec. 75.59).

! Hourly data including unit operating time, load, type of fuel, fuel flow, fuel GCV, oil density if

required, heat input rate, fuel sulfur content, SO2 mass rate, percent monitor data availability,

and SO2 method of determination (Sec. 75.57).

Reporting:

! Initial certification application (includes monitoring plan and initial certification test results)

(Secs. 75.62 and 63).

! Quarterly reporting of hourly data, quality assurance test results, recertification tests, and

summary of quarterly and year to date emissions (Sec. 75.64). 

Initial Performance Testing:

! Fuel flow meter accuracy testing (Appendix D, Sec. 2.1.5). Meters used for commercial

billing are exempt (Part 75, Appendix D, Sec. 2.1.4.2).

! DAHS testing (Sec. 75.20 and Appendix A, Sec. 6).

Periodic Calibration: See Audits.

Audits: Quality assurance requirements do not apply to fuel flow meters used for billing purposes (Part

75, Appendix D, Sec. 2.1.4.2).

Part 75, Appendix D, Sec. 2.1.6:

! Fuel flowmeter accuracy test performed every 4 operating quarter which may be extended up

to 20 operating quarters. 

! Primary element visual inspection performed every 12 calendar quarters. 

Part 75, Appendix D, Sec. 2.1.7: Optional fuel flow to load test may be performed in lieu of fuel

flowmeter accuracy test.

Other Appropriate Quality Control and Quality Assurance Measures: Recertification (includes quality

assurance testing) is required for a replacement, modification, or change that may significantly affect

the monitoring system ability to accurately measure monitored parameters (Sec. 75.20(b)).
55

Cost Analysis:

a. Capital Cost: $3,200 - $10,000, median $7,800 for oil flow meter

$1,500 - $6,400, median $2,900 for gas flow meter

Installation costs are not included (Part 75 CEM Cost Study (1999)). 

b. Direct Operating Cost: $750 for inspection, $200- $2,000 for in-line calibration (Part 75 CEM Cost

Study (1999)).

c. Total Annualized Cost:$250 - $350 per manual oil sample (utility group (Class of '85) comments on

Part 75). Number of events/year dependent on unit characteristics. No

information on costs for continuous sampling approaches for high sulfur

variability gaseous fuel (such as using a gas chromatograph). 

d. Equipment Life: Not available

e. Year Dollars: 1998

f. Discount Rate: 7%
56

Table IV-4

Part 75 Low Mass Emissions Unit Methodology for Oil and Gas Fired Units

Primary Source Category: Refineries, Industrial Boilers, Pulp and Paper

Source Type: Gas and oil fired boilers/process heaters, with annual SO2 emissions less than or equal 

to 25 tons. To qualify, units burning a gaseous fuel other than natural gas also must meet the default

emission rate qualifications in Part 75, Appendix D, Sec. 2.3.6(b). This qualification procedure requires

a 720 hour sampling test to show low fuel sulfur variability (maximum standard deviation of 5.0 gr/100

scf) or low sulfur content (maximum of 20 gr/100 scf).

Emission Measurement/Quantification System: Low Mass Emission (LME) Provisions in 40 CFR

75.19(c).

! For each hour, record unit operating time, type of fuel burned, and if using the long term fuel

flow method - load or steam production. Units using the long term fuel flow method also

measure the amount of fuel burned each quarter (measured using billing records, tank level

measurement, or Appendix D fuel flow monitors).

! Hourly SO2 emission rate based on default values for natural gas and fuel oil in Table LM-1,

or calculated default values (Equation D-1) for gaseous fuels other than natural gas.

! Hourly heat input may be based on the unit’s maximum rated heat input times operating time,

or long term fuel monitoring, combined with sampled or default fuel gross caloric value (GCV)

and fuel density values). Hourly apportionment of the long term fuel use is apportioned

based on hourly load as a fraction of the total quarterly load.

Averaging Times: Hourly, Quarterly

Consideration of Batch, Seasonal, and Cyclical Operations: Not Applicable

Calculations Used to Determine Quarterly and Annual Mass Emissions:

Sec. 75.19(c)(3) and (4):

! Annual Mass Emissions = Sum of Quarterly Mass Emissions.

! Quarterly Mass Emissions = Sum of Hourly Emissions.

! Hourly Emissions = SO2 Default Emission Factor x Hourly Heat Input.

! Hourly Heat Input = Maximum rated heat input capacity times operating time or apportioned

based on long term heat input measurement and hourly load.

! Natural gas and fuel oil default values are provided for emission factors (lbs SO2/MMBtu),

GCV, and oil density. Other gaseous fuels have prescribed approach to determine fuelspecific defaults.

Procedures for Addressing Missing and Invalid Data: Not applicable.
57

Recordkeeping and Reporting Requirements: 

Recordkeeping:

! Monitoring plan which includes basic unit identification information and monitoring

methodology (Sec. 75.53).

! Hourly records of unit operating time, fuel burned, and unit load if using long term fuel flow

monitoring (Sec. 75.19(c)(2)). 

! Quarterly long term fuel monitoring results for units using that heat input option (Sec.

75.19(e)).

! Sampling and analysis results for fuel sulfur content, GCV, and density if required (Sec.

75.19(e)).

Reporting: 

! Initial certification application (includes monitoring plan and LME applicability demonstration)

(Secs. 75.62 and 63, Sec. 75.19a). 

! Quarterly reporting of hourly operating records, and summary of quarterly and year to date

emissions (also heat input and load if using long term fuel monitoring) (Sec. 75.64)

Initial Performance Testing: Initial LME Applicability Demonstration, Sec. 75.19(a):

! Three years of emission data are required to demonstrate that annual SO2 emissions are not

greater than 25 tons, or

! If three years of data does not exist (or if there is a change in operations through permit

limits), the demonstration may be based on projected annual emissions.

! Units burning gaseous fuels other than natural gas must demonstrate sulfur content and

variability meets the default equation qualifications in Part 75, Appendix D, Sec. 2.3.6(b).

! Also, units using Part 75, Appendix D fuel flow monitors for long term fuel flow monitoring

must meet Part 75, Appendix D, Sec. 2.1.5 certification requirements (initial fuel flow meter

accuracy test). Billing meters are exempt from certification requirements.

Periodic Calibration: Units using fuel flow monitors for long term fuel flow monitoring must perform

periodic calibration tests and inspections every twelve operating quarters (frequency may be extended

to every twenty operating quarters). These requirements are in Part 75, Appendix D, Sec. 2.1.6.

Audits: Annual LME applicability demonstration in Sec 75.19(b).

Other Appropriate Quality Control and Quality Assurance Measures: Not applicable.

Cost Analysis:

a. Installed Capital Cost: N/A

b. Direct Operating Cost: Labor burdens for recordkeeping/reporting will apply. EPA estimates 16

hours per year ($899) above and beyond customary business practices

(2002 Acid Rain Program ICR). 

c. Total Annualized Cost: Labor burdens for recordkeeping/reporting will apply. EPA estimates 16

hours per year ($899) above and beyond customary business practices

(2002 Acid Rain Program ICR). 

d. Equipment Life: N/A

e. Year Dollars: 2001 (for labor rates)

f. Discount Rate: N/A
58

Table IV-5

NSPS Monitoring Methodology for Coal and Oil Fired Industrial Boilers

Primary Source Category: Industrial Boilers

Source Type: Coal or Oil Fired Industrial Boilers (10 MMBtu/hr to 250 MMBtu/hr)

40 CFR 60 Subparts Db and Dc - New Source Performance Standards.

Emission Measurement/Quantification System: Monitoring requirements vary based on fuel type and

boiler size. Alternatives described below may be used for all units except where specified

1) SO2 and diluent CEMS; or

 

2) Daily Method 6 stack test; or

 

3) Fuel sampling/analysis (as fired sampling unless unit burns oil and has a maximum rated heat input

# 100 MMBtu/hr; in that case sampling may be performed each time the fuel tank is filled); or 

4) Supplier fuel receipts (oil fired boilers burning oil with S content # 0.5%, or oil fired boiler with

maximum rated heat input # 100 MMBtu/hr; Coal fired boilers with maximum rated heat input # 30

MMBtu/hr).

Averaging Times:

! 30 day rolling averages,

! Daily averages,

! CEMS hourly average based on 15-minute sampling intervals.

Consideration of Batch, Seasonal, and Cyclical Operations: Units with infrequent operation (capacity

factor of 10% or less on subject fuel) may be eligible for alternative monitoring methods.

Calculations Used to Determine Quarterly and Annual Mass Emissions: None

Procedures for Addressing Missing and Invalid Data: Emission data must be obtained for at least 75%

of operating hours in at least 22 out of 30 successive days by the monitoring methods described above.

Recordkeeping and Reporting Requirements: Sec. 60.49b and Sec. 60.48c.

! Records of measurements and calculations must be retained 2 years. 

! Submit initial performance test results and summary or excess emission reports semiannually.

Initial Performance Testing: Performance Specification 2 for SO2 CEMS (7 day calibration drift and

RATA)

Periodic Calibration: Daily calibration drift test (40 CFR Part 60, Appendix F). The monitoring devices

must also be calibrated at least annually according to manufacturers specifications.
59

Audits:

! Conduct a performance evaluation of the CEMS during or within 30 days any performance

test required under §60.8. 

! Conduct CEMS audits once per quarter (40 CFR Part 60, Appendix F)

- Relative Accuracy Test Audit (RATA) must be conducted at least once every four

calendar quarters. 

- Cylinder Gas Audit (CGA), if applicable, may be conducted in three of four

calendar quarters

- Relative Accuracy Audit (RAA) may be conducted three of four calendar quarters

Other Appropriate Quality Control and Quality Assurance Measures:

! Preventive maintenance of CEMS (including spare parts inventory). 

! QC for data recording, calculations, and reporting. 

! Program of corrective action for malfunctioning CEMS. 

Cost Analysis: See OAQPS CEM Cost Model figures in Table IV-2 for SO2/flow. Note that NSPS does

not address flow monitoring. 
60

Table IV-6

NSPS Monitoring Methodology for Refinery Boilers/Process Heaters

Primary Source Category: Refineries

Source Type: Fuel Gas Combustion Devices (Boilers/Process Heaters) 40 CFR 60 Subpart J - New

Source Performance Standard

Emission Measurement/Quantification System: To demonstrate compliance with fuel gas H2S

concentration limit in Sec 60.104(a)(1): 

 1) SO2 and O2 CEMS (ppm), or

 2) Continuous monitoring of H2S concentration in the fuel gas (gr/dscf or mg/dscm).

Averaging Times:

! Rolling 3-hour averages

! Hourly average based on 15-minute sampling intervals

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: None

Procedures for Addressing Missing and Invalid Data:

No procedures specified.

Recordkeeping and Reporting Requirements (Sec. 60.7):

! Records of measurements and calculations must be retained 2 years.

! Submit summary or excess emission reports semi-annually.

Initial Performance Testing:

! Performance Specification 2 for SO2 CEMS (7 day calibration drift and RATA)

! Performance Specification 7 for the H2S CEMS (7 day calibration drift and RATA)

Periodic Calibration: Daily calibration drift test. The monitoring devices must also be calibrated at least

annually according to manufacturers specifications.

Audits:

! Conduct a performance evaluation of the CEMS during or within 30 days any performance

test required under §60.8

! Conduct CEMS audits once per quarter

- Relative Accuracy Test Audit (RATA) must be conducted at least once every four

calendar quarters. 

- Cylinder Gas Audit (CGA), if applicable, may be conducted in three of four

calendar quarters

- Relative Accuracy Audit (RAA) may be conducted three of four calendar quarters

Other Appropriate Quality Control and Quality Assurance Measures:

! Preventive maintenance of CEMS (including spare parts inventory). 

! QC for data recording, calculations, and reporting. 

! Program of corrective action for malfunctioning CEMS. 

Cost Analysis: See Table IV-2 for OAQPS CEM Cost Model figures for SO2/flow CEMS. Note that

NSPS Subpart 3 does not address flow monitoring. 
61

Table IV-7

State of Oregon Coal-fired Boiler CEMS/Flow Estimation Example

Primary Source Category: Beet Sugar Manufacturing

Source Type: Coal Fired Boiler

Emission Measurement/Quantification System: Continuous Emission Monitoring System (based on

NSPS requirement) and steam data/emission factor for conversion to mass emissions.

Averaging Times: Hourly averages and monthly average of the hourly averages

Consideration of Batch, Seasonal, and Cyclical Operations: Yes, this is a seasonal operation and the

CEMS reporting and QA/QC requirements are based on actual operating hours. 

Calculations Used to Determine Quarterly and Annual Mass Emissions:

Mass emissions determinations to determine compliance with the plant site emission limit (PSEL) is

performed as follows:

Peu x EFeu/2000

Peu = 1000 lbs steam per year

EFeu = 0.100 lb SO2 /1000 lbs steam

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements:

! The permittee shall maintain a minimum valid data availability of 90% of boiler operating

hours, on a seasonal basis.

! Monitoring system performance reports shall be submitted to the Department semi-annually.

! The permittee shall maintain a CMS log as required by the Department continuous

monitoring manual.

! Semi-annual compliance certifications

Initial Performance Testing: No performance testing requirements of emission unit within current

permit that exceed the CEMS auditing procedures (RATA)

Periodic Calibration: Daily calibration

Audits: Quarterly audits, either CGA or RAA. Once every four quarters of operation a RATA is

required.

Other Appropriate Quality Control and Quality Assurance Measures: Mandatory submittal and periodic

review of CEM quality assurance plan and standard operating procedures manual.

Cost Analysis: Unknown
62

Table IV-8

State of Oregon Industrial Boiler Fuel-based Estimation Method

Primary Source Category: Kraft Pulp Mill

Source Type: Power Boiler (oil/ natural gas fired)

Emission Measurement/Quantification System: Material Balance Approach

Averaging Times: Not Applicable

Consideration of Batch, Seasonal, and Cyclical Operations: No consideration for batch, seasonal &

cyclical operations. There are considerations for switching between types of fuels and for testing oil

guns.

Calculations Used to Determine Quarterly and Annual Mass Emissions: Material Balance Calculation:

E = 2 x F x S

E=emissions of SO2

S=sulfur content, % wt.

F=Fuel use (lbs/month or tons/yr)

Procedures for Addressing Missing and Invalid Data: Not Applicable

Recordkeeping and Reporting Requirements:

! The permittee shall monitor and record the type and amount of fuels used each day.

! The permittee shall monitor and record the number of hours per year that oil is used as fuel.

! The permittee shall monitor and record the sulfur content of each batch of fuel oil received.

! Semi-annual monitoring report requirement.

Initial Performance Testing: No performance testing requirements of emission unit within current

permit.

Periodic Calibration: Not Applicable

Audits: Audit records during source inspection

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: Unknown
63

Table IV-9

State of Oregon Recovery Furnace CEMS/Flow Estimation Example

Primary Source Category: Unbleached Kraft Pulp Linerboard and Corrugating Medium Mill

Source Type: Recovery Furnaces

Emission Measurement/Quantification System: CEMS for TRS (as H2S) and for SO2

Averaging Times:

TRS: Daily arithmetic averages calculated from 1-hour arithmetic averages.

SO2: Three hour block average concentration calculated from one hour arithmetic averages

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions:

! TRS: Calculate emissions of total reduced sulfur [TRS/ton equivalent air dried tons pulp

(ADTP)] by:

- Daily average concentration

- Flow rate estimated from source tests & firing rate correlation

- Equivalent ADTP production

! SO2: Calculate emissions of SO2 by utilizing concentration from CEM and exhaust flow rate

calculated from the flow rate/BLS firing rate correlation.

Procedures for Addressing Missing and Invalid Data: None, 75% data recovery on a 1-hour period and

90% data recovery for a 1-hour period required for a CMS data average to be accepted (ODEQ

Continuous Monitoring Manual).

Recordkeeping and Reporting Requirements:

! The permittee shall report the following information within 30 days of the end of each

calendar month:

- Daily average concentration of TRS gases

- Daily average emissions of TRS gases as lbs/equivalent tons of pulp processed

- Three-hour average emissions of SO2 based on all samples collected in one

sampling period, expressed as ppmdv, and the exhaust flow rate during the last

source test.

Initial Performance Testing: No performance testing requirements of emission unit within current

permit that exceeds the CEMS auditing procedures (RATA)

Periodic Calibration: Daily Calibrations

Audits: Quarterly audits, either CGA or RAA. Once every four quarters a RATA is required.

Other Appropriate Quality Control and Quality Assurance Measures: Mandatory submittal and periodic

review of CEM quality assurance plan and standard operating procedures manual.

Cost Analysis: Unknown
64
65

CHAPTER V

CATALYTIC CRACKING UNITS

Catalytic cracking units convert gas oil feed streams into fuel gas, liquified petroleum

gas (LPG), high-octane gasoline, and distillate fuel through the use of a catalyst, generally

in the form of fluidized particulates (fluidized catalytic cracking). The feed stream is

heated in process heater and then the catalyst is added to separate the hydrocarbons. The

spent catalyst is regenerated by steam stripping and burning off petroleum coke deposits. 

SO2 is emitted from the process heater and during regeneration of the catalysts.

The NSPS for petroleum refineries (40 CFR 60 Subpart J) includes SO2 standards for

FCCUs. Monitoring requirements in the NSPS rule are summarized in Table V-1. There

are different requirements based on the following situations; 1) source has an SO2 control

device and meets 90% reduction standard, 2) source has an SO2 control device and meets <

50 ppm standard, 3) source has no control device, or source uses a waste-incinerator boiler. 

Sources with a control device must monitor SO2 emission rates using a CEMS for SO2 and

O2. Sources with no control device must record the sulfur content of the fresh feed, the

average coke burn-off rate, and hours of operation on a daily basis. Sources with an

incinerator-waste heat boiler must record fuel usage and operating hours.

There are refineries located in California, Colorado, New Mexico, Utah and Wyoming. 

It is unknown whether these facilities have SO2 control devices installed on the FCCUs. 

Information from California’s SCAQMD indicates that SO2 and flow CEMS are required

under RECLAIM for this source type. The SCAQMD uses alternative quality assurance

procedures for FCCUs with low SO2 concentrations (<5 ppm) – see SCAQMD Rule 2011,

Appendix A, Attachment F. Table V-2 summarizes SCAQMD SO2 monitoring

requirements for FCCUs.

Pechan obtained information from the State of New Mexico regarding a consent decree

for a refinery. In the consent decree, a CEMS for the FCCU is proposed. There are no

details on specific monitoring requirements. The information obtained from New Mexico is

presented in Table V-3.
66

Table V-1

NSPS Monitoring Requirements for Fluidized Catalytic Cracking Units

Primary Source Category: Refineries 40 CFR 60 Subpart J

Source Type: Fluid Catalytic Cracking Unit (FCCU)

Emission Measurement/Quantification System:

With an add-on control device of 90% reduction: 

CEMS for SO2 (dry, 0% O2 ppmv) and O2 at both the inlet and outlet of the SO2 control device 

Span value: inlet is125% and outlet is 50% of the maximum estimated hourly potential SO2 emission

concentration entering the control device. Span value for O2 monitor is 10%

With an add-on control device and emission of >= 50 ppm: 

CEMS for SO2 (dry, 0% O2 ppmv) and O2 at the discharge

Span value: SO2 is 50 percent of the maximum hourly potential of the control device, O2 is 10%

Without the use of an add-on control device:

Record the average coke burn-off rate (Mg (tons) per hour) and hours of operation on a daily basis.

Monitor sulfur content of fresh feed. 

FCCU catalyst regenerator using incinerator-waste heat boiler:

Record fuel usage rate and hours of operation

Averaging Times:

For CEMS:

1-hour averages of SO2 and O2 shall be computed from four or more data points equally spaced over

each 1-hour period. Samples collected at inlet and/or outlet of control system or at discharge point

Calculate 7-day average concentration (arithmetic mean of 1-hour averages during 7 successive days)

Calculate 7-day average percent reduction for control device using 7-day averages

Compliance determined on 7-day rolling average basis 

Provide minimum of 22 valid days of data for every 30 rolling successive calendar days 

CEMS downtime: provide data for a minimum of 18 hours per day in at least 22 out of 30 rolling

successive calendar days. 

For average coke burn-off rate:

One 3-hour test daily using:

 Method 8 modified for Moisture content and sulfur oxides (SOx) as SO2

 Method 2 for velocity and flow

 Method 3 integrated sampling for gas analysis

Calculate coke burn off in Mg/hr (Ton/hour) as specified in 40 CFR 60.106 (b)(3)

Calculate sulfur oxides as SO2 per Mg (ton) of coke burn off

7-day average of sulfur oxides as SO2 per Mg (ton) of coke burn off

For feed sampling:

1 fresh feed sample per 8 hours analyzed using specified ASTM method

Calculate 7-day average sulfur content of fresh feed

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: None
67

Procedures for Addressing Missing and Invalid Data:

Requires sources to account for emissions during periods when there are no valid data (missing data

periods) due to the monitor not operating or operating out of control. 

Specifies supplemental sampling procedures for CEMS down times

Recordkeeping and Reporting Requirements:

Required to submit a written report of the results of the performance evaluation within 60 days of

completion. 

Required to submit semi-annual report: 

Report all data and calibrations from CEMS including daily drift and quarterly accuracy assessments

under Appendix F, supplemental sampling data, quality control procedures. Report 7-day rolling

averages.

Report daily Method 8 test results for moisture content and sulfur dioxide as SO2 (or alternate method), 

Report daily fresh feed sulfur content tests

Also report date and explanation for exceedances of 7-day average, corrective action taken, any

periods where 30-day data or daily monitoring requirements were not met and explanation, times hourly

averages are based on manual sampling instead of CEMS, times when concentration exceeded span

of CEMS, any modifications to CEMS, any changes to emissions control system while data not

available.

Initial Performance Testing:

Performance Specification 2 for SO2 CEMS

Reference Methods (RM) 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy

evaluations. Conduct a minimum of nine sets of all necessary RM test runs. Correlate the CEMS and

the RM test data. Calculate the mean difference between the RM and CEMS values.

Calibration Drift (CD) - while unit is operating at more than 50 percent of normal load, determine the

magnitude of the CD once each day (at 24-hour intervals) for 7 consecutive days. CD must not drift or

deviate from the reference value of the calibration gas by more than 5 percent of the established span

value for 6 out of 7 test days.

Periodic Calibration:

Calibration of CEMS as specified by manufacturer

Automatically check, quantify, and record the zero and span calibration drifts at least once daily. If

greater than 2Xs the specified limit, the zero and span must be adjusted.
68

Audits: 

Conduct a performance evaluation of the CEMS during or within 30 days any performance test required

under §60.8. 

Conduct CEMS audits once per quarter

 Relative Accuracy Test Audit (RATA) must be conducted at least once every four calendar quarters. 

 Cylinder Gas Audit (CGA), if applicable, may be conducted in three of four calendar quarters

 Relative Accuracy Audit (RAA) may be conducted three of four calendar quarters

Sampling and analysis methods accuracy audit

Other Appropriate Quality Control and Quality Assurance Measures:

Preventive maintenance of CEMS (including spare parts inventory). 

QC for data recording, calculations, and reporting. 

Program of corrective action for malfunctioning CEMS.

Cost Analysis:

EPA estimated that cost for CEMs for the extractive analyzer system would be $69,300 (1984 dollars)

including installation and data acquisition system (DAS), $46,200 without it.

The agency obtained cost data by contacting vendors and operators and found that “the worst-case”

cost for an SO2/diluent extractive system varied from 43,000 to $100,000 (1984 dollars). This cost

included additional cost for longer sample lines, corrosion-resistant probes, probe backflush systems,

and computer data acquisition systems capable of generating emission reports.

Worst-case installation costs ranged from $2,000 to $80,000. Total worst-case costs for an extractive

analyzer would be from $45,000 to $180,000 (including DAS and installation).

Best case costs for an extractive analyzer system including installation, ranged from $15,400 to

$86,000.

The across the stack CEMS for an SO2/diluent CEMS including a DAS to range from $44,000 to

$96,000 in a worst case scenario with installation cost varying from $2,000 to $80,000. Assuming a

DAS cost of $23,100, the total worst case cost without a DAS would be from $22,900 to $153,000.

Best case scenario costs ranged from $34,000 to $60,000 per analyzer.

The annual maintenance costs estimated were $11,000 for either an extractive or across the stack

CEMS.
69

EQUIPMENT MEASURED VARIABLES

1. Stack SOx concentration and exhaust flow rate;

2. CEMS Status code;

3. Feed rate.

FCCUs with feed hydrodesulfurization All variables identified for FCCUs.

All variables identified for FCCUs; and

4. Type and amount of catalyst used.

All variables identified for FCCUs; and

4. Scrubber solution injection rate.

All variables identified for FCCUs; and

4. Scrubber solution injection rate

FCCUs

FCCUs with SOx reducing catalyst

FCCUs with wet flue gas 

desulfurization (e.g., slurry of 

Ca(OH)2/CaCO3 or NaOH/Na2CO3)

FCCUs with dry flue gas 

desulfurization (e.g., dried slurry of 

Ca(OH)2/CaCO3 or NaOH/Na2CO3)

Table V-2

FCCU Monitoring Requirements for SCAQMD Rule 1105 and Rule 2011

Primary Source Category: Refineries

Source Type: Fluidized Catalytic Cracking Units (FCCUs)

Emission Measurement/Quantification System:

Must install, calibrate, maintain, and operate an approved CEMS or Alternative Monitoring System

(AMS) 

CEMS/AMS must measure:

a. Sulfur oxide concentrations discharged from equipment,

b. Oxygen concentrations, at sulfur oxide monitoring location (if required for stack gas flow rate)

c. Stack gas volumetric flow rate using an in-stack flow meter or an approved alternate method.

d. Fuel gas flow rate and sulfur content, if the CEMS uses these to determine SOx emissions.

e. Variables in table 

Must measure and record at least once per shift other data necessary for calculating emissions.

Averaging Times: 

1-hour average equally computed based on four valid 15-minute average emission data points equally

spaced over each 1-hour period. (Only 2 required during CEMS maintenance activities)

Consideration of Batch, Seasonal, and Cyclical Operations: None
70

∑ ∑

= =

= +

p

m

m

n

k

G Ek E

1 1

7

1.662 10−ei = ai × ci × ×

Calculations Used to Determine Quarterly and Annual Mass Emissions: 

Sulfur oxide mass emissions in units of lb/hour: 

where: ei = Mass emissions of sulfur oxides (lb/hr),

ai = Stack gas concentration of sulfur oxide (ppmv), and

ci = Stack gas volumetric flow rate (scfh).

The daily emissions of sulfur oxides for each affected SOx source: 

where:

G = Daily emissions of sulfur oxide (lb/day),

Ek = Hourly average emission rate using CEMS (lb/hr)

Em = Hourly average emission rate of sulfur oxides using substitute data (lb/hr),

n = Number of hours of valid data from CEMS coinciding with the operating hours

p = Number of hours using substitute data when the source is operating; and

m = Number of operating hours of the source during the day.

All measurements for concentrations and stack gas flow rates, and selection of F factor shall be made

on a consistent wet or dry basis.

Must obtain approval for all formulas necessary to calculate the mass emission rates of SOxfrom the

regenerator per thousand barrels of feed. 

Procedures for Addressing Missing and Invalid Data:

Emission rate data may be obtained using District Methods 6.1 or 100.1 (for SOx) in conjunction with

District Methods 1.1, 2.1, 3.1, and 4.1 or by using District Methods 6.1 or 100.1 in conjunction with

District Method 3.1 and EPA Method 19. 

Emission rate data may also be obtained using District Methods 307-91 or ASTM Method D1072-90,

Standard Test for Total Sulfur in Fuel Gases (for sulfur content in the fuel gas) in conjunction with the fuel

gas flow rate.

May use the procedure in 40 CFR Part 75 Subpart D if the relative accuracy of the pollutant analyzer and

flow measurement system during the last CEMS certification test and/or RATA are both less than 10%.

Calculate on a daily basis the percent data availability of analyzer then substitute data calculated as:

 a. if availability is >= 95% and missing data is:

 < 24 hours: 1N Procedure in Attachment A or E(1)(b)(ii), or

 > 24 hours: max hourly concentration recorded for previous 30 days.

 b. if availability is >= 90% and missing data is:

 < 3 hours: average of concentration for the hour before and after missing data period,

 > 3 hours: max hourly concentration recorded for previous 30 days, or

 > 24 hours: max concentration recorded for previous 365 days

 c. if availability is > 90%: highest hourly concentration recorded during the service of the CEMS
71

Recordkeeping and Reporting Requirements:

1. Total daily SOx mass emissions from each source, 

2. Daily status codes, 

3. Daily electronic transmittal of remote terminal unit (RTU) data, 

4. Monthly submittal of daily records of SOx emission rates per thousand barrels of feed, 

5. Monthly aggregated SOx emissions, 

6. Semi-annual and CEMS certification tests

7. Must submit a CEMS plan for approval

CEMS data shall be recorded by: 1) RTU and 2) strip chart or alternative electronic recorder. The strip

chart recorder or alternative shall receive data independent of the RTU and serve as an independent

tool for verifying data. 

Must measure and record 1) variables necessary for the alternate gas volumetric flow rate method, 2)

measurements in Table 2-A and 3) other measured data to support calculations.

Recorded data shall be readily accessible upon request.

Must maintain records of measurements, tests, calibrations audits and QA data for 3 years. Keep a

written record of QA and audit procedures.

Initial Performance Testing: Same requirements as audits

Periodic Calibration:

CEMS design shall allow determination of calibration drift. Requires zero and span calibration checks, and

zero and span adjustments. Perform any calibration error test procedures specific to the CEMS. 

Attachment C Quality Assurance And Quality Control Procedures:

1. Test, record, and compute the calibration error of each monitor at least once per operating day. Perform

the daily calibration error test according to the procedure in Chapter 2, Subdivision B, Paragraph 1,

Subparagraph a, Clause ii of this Attachment. 

2. Test, compute, and record the calibration error of each stack flow monitor at least once per 14 calendar

days. Perform daily flow monitor interference checks. All transducers and transmitters installed on stack

flow monitors must be calibrated every two operating calendar quarters.

Audits: Requires semi-annual CEMS certification test

Meet specifications in 40 CFR Part 60, Appendix B, Performance Specification 2, Section 8 and

Appendix A Attachment B Bias Test of this rule. Minimum of nine sets of tests conducted. Specifies

alternate procedures. 

1. Monitors and Analyzers: relative accuracy of >= 20% of the mean value of the reference method

test data.

2. Volumetric flow measurement system: relative accuracy of >= 15% of the mean value of the

reference method test data. Must perform study to determine the acceptability of the potential flow

monitor location and to determine the number and location of flow sampling points. 

3. Must demonstrate the absence of stratification (difference between highest and lowest

concentration divided by average concentration is >10%.

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: Not Available
72

Table V-3

Monitoring Requirements for Fluidized Catalytic Cracking Units in the State of

New Mexico

Primary Source Category: Refinery/New Mexico

Source Type: Catalytic Cracking Units

Emission Measurement/Quantification System: A CEMS is proposed in a consent decree for an FCCU

at a refinery in New Mexico.

Averaging Times: TBD. 

Consideration of Batch, Seasonal, and Cyclical Operations: None.

Calculations Used to Determine Quarterly and Annual Mass Emissions: TBD.

Procedures for Addressing Missing and Invalid Data: TBD.

Recordkeeping and Reporting Requirements: Records in accordance with 40 CFR Subpart J 60.107.

Initial Performance Testing: Required for new units.

Periodic Calibration: TBD. In accordance with 40 CFR Subpart J 60.105 Monitoring of emissions and

operations.

Audits: TBD. In accordance with 40 CFR Subpart J 60.105 Monitoring of emissions and operations.

Other Appropriate Quality Control and Quality Assurance Measures: TBD.

Cost Analysis: Unknown
73

CHAPTER VI

FLARES

Flaring is an air pollution control technology employed at refineries, natural gas

processing plants, and oil and gas production facilities to dispose of waste gas during

process upsets and emergencies. SO2 emissions from flaring result from burning waste gas

which contains sulfur. The amount of SO2 emitted during flaring is a function of the waste

gas flow rate and sulfur content. The sulfur content of the flaring gas can vary widely

depending on the type of process which generates the waste gas. 

There are no Federal regulations that apply to SO2 monitoring of flares. However,

recent consent decrees affecting some western refineries require SO2 emissions monitoring

for certain types of flaring activity. For acid gas flaring, hydrocarbon flaring or tail gas

incidents, flow meters and periodic measurement of H2S concentration is required. If

operating the flare as a fuel gas combustion device, the source must monitor H2S in

accordance with fuel gas combustion devices subject to 40 CFR § 60.104, which requires a

CEMS for SO2 and O2, or a CEMS for H2S. Table VI-1 summarizes the monitoring

requirements for flaring activities from these consent decrees. 

Summaries of New Mexico monitoring requirements for flares at refineries and natural

gas processing plants are provided in Table VI-2 and Table VI-3, respectively. New Mexico

requires monitoring for acid gas, inlet plant gas, and fuel gas flow and the concentration of

H2S in the acid gas and inlet plant gas. SO2 emissions are then calculated from specified

formulas. 

SCAQMD does not require SO2 monitoring of flares, since they are not covered by

RECLAIM. There is a district rule (Rule 1118) for flare emissions. Currently SCAQMD is

gathering information on flare emissions during episodes by sampling the gas using SILCO

coated canisters. SILCO is a Restek trade name. Gas flow to the flares are measured

using ultrasonic flow monitors, apparently to deal with the high turndown ratios.
74

Table VI-1

Monitoring Requirements for Flares at Refineries from Consent Decrees

Primary Source Category: Refineries Consent Decrees

Source Type: Flares

Emission Measurement/Quantification System:

For acid gas flaring, hydrocarbon flaring or tail gas incidents:

Flow meters installed on all acid gas or hydrocarbon lines to the refinery flares, or other reliable flow

parameters should be measured;

H2S concentration (“ConcH2S”) shall be determined from the sulfur recovery plant feed gas analyzer,

from knowledge of the sulfur content of the process gas being flared or by direct measurement

(Tutwiler, draeger tube) 

If operating the flare as a fuel gas combustion device:

Monitoring H2S in accordance with fuel gas combustion devices subject to 40 CFR § 60.104(a)(1)

CEMS for SO2 (dry basis, zero percent excess air) emissions into the atmosphere and O2 for correcting

the data for excess air. Span value: 50 ppm SO2 and 25 percent O2

or

CEMS for H2S (dry basis) in fuel gases before being burned in any fuel gas combustion device. 

Span value: 425 mg/dscm H2S. 

or

May use an approved alternative monitoring method

(See summary for fuel gas combustion units at Refineries for additional information)

Averaging Times: None specified in consent decrees for flow meters or H2S measurement

Consideration of Batch, Seasonal, and Cyclical Operations: 

SO2 emissions resulting from a flaring incident that is comprised of intermittent flaring;

the quantity of SO2 emitted shall be equal to the sum of the quantities of SO2 flared during each such

period of intermittent flaring.

Calculations Used to Determine Quarterly and Annual Mass Emissions:

SO2 emissions resulting from Flaring shall be calculated by the following formula:

Tons of SO2 = [FR][TD][ConcH2S][8.44 x 10-5].

ER = Emission Rate in pounds of SO2 per hour

FR = Average Flow Rate to Flaring Device(s) during Flaring, in standard

cubic feet per hour

TD = Total Duration of Flaring in hours

ConcH2S = Average Concentration of Hydrogen Sulfide in gas during Flaring

(or immediately prior to Flaring if all gas is being flared) expressed

as a volume fraction (scf H2S/scf gas)

8.44 x 10-5 = [lb mole H2S/379 scf H2S][64 lbs SO2/lb mole H2S][Ton/2000 lbs]

If the Tail Gas Incident is a event exceeding the 250 ppmvd (NSPS J limit), from

a monitored Sulfur Recovery Plant incinerator, then specified formula applies.
75

Procedures for Addressing Missing and Invalid Data: 

Missing data point(s) shall be estimated according to best engineering judgment or other monitoring

data and a report submitted, which includes data used in the calculation and an explanation of the basis

for any estimates of missing data.

Recordkeeping and Reporting Requirements: None specified

Initial Performance Testing: None specified

Periodic Calibration: None specified

Audits: None specified

Other Appropriate Quality Control and Quality Assurance Measures: None specified

Cost Analysis: Unknown
76

Table VI-2

Monitoring Requirements for Flares at Refineries in the State of New Mexico

Primary Source Category: Refinery/New Mexico

Source Type: Flare

Emission Measurement/Quantification System: Emissions derived by calculation from data generated

by recordkeeping and reporting requirements.

Averaging Times: Not Applicable

Consideration of Batch, Seasonal, and Cyclical Operations: Supplemental heat to be provided in

proportion to the quantity of acid gas being flared.

Calculations Used to Determine Quarterly and Annual Mass Emissions: Acid gas flow and

concentration.

Procedures for Addressing Missing and Invalid Data: Not Applicable

Recordkeeping and Reporting Requirements: Records of: All periods of operation during which the

flare pilot flame is absent in flare and the steps taken to re-ignite the pilot; Repairs, maintenance, and

calibration of the acid gas flowmeter for flare; Repairs, maintenance.

Initial Performance Testing: Flares used to comply with the NSPS Subpart GGG requirements for VOC

shall be tested in accordance with the requirements contained in 40 CFR 60, Subpart A, General

Provisions, paragraph 60.8 (performance tests) and 60.18 (general control device requirements). No

independent tests for SO2 emissions.

Periodic Calibration: The H2S monitor shall be operated, maintained, and certified in accordance with

60.105; The H2S monitors shall be re-certified no later than every 3 years from the date of the original

and subsequent certifications.

Audits: The H2S monitor shall be operated, maintained, and certified in accordance with 60.105; The

H2S monitors shall be re-certified no later than 3 years, from the date of the original and subsequent

certifications.

Other Appropriate Quality Control and Quality Assurance Measures: Flare shall be equipped with a

flare tip or burners to supply supplemental fuel gas to provide enough supplemental heat. An alarm

system in good working order shall be connected to a flare that will signal non-combustion of the gas. 

In accordance with 60.104, the fuel gas to be combusted in affected heaters and affected flare pilots

shall be sweetened refinery fuel gas with a maximum H2S concentration of 0.1 grain/dscf. In

accordance with 60.105, the H2S concentration of the refinery fuel gas supplied to the affected heaters

or flare pilots shall be monitored by a continuously recording H2S monitor. An alarm in good working

order to signal non-combustion of the gas shall be installed.

Cost Analysis: Unknown.
77

Table VI-3

Monitoring Requirements for Flares at Natural Gas Processing Plants in the State

of New Mexico

Primary Source Category: Natural Gas Processing Plants/New Mexico

Source Type: Flare

Emission Measurement/Quantification System: An analyzer system shall be installed to automatically

measure and record on an ongoing basis: (1) the flow rate of the inlet gas to the plant, (2) the H2S

concentration of the inlet gas to the plant, (3) the flow rate of the acid gas to the flare, and (4) the H2S

concentration of the acid gas to the flare.

Averaging Times: The H2S concentration of the inlet gas shall be measured and recorded at least once

every three hours. The flow rates shall be measured and recorded at least once per hour. The H2S

concentration of the acid gas shall be measured and recorded at least twice per day.

Consideration of Batch, Seasonal, and Cyclical Operations: None.

Calculations Used to Determine Quarterly and Annual Mass Emissions: Daily H2S volume * H2S

concentration (PPMV) * H2S (MW) * 64/32 / E6 * 385 (F factor) * 24 hrs/day.

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements: Daily records of the following are required:

(1) the flow of gas entering the plant (MMSCF),

(2) the average daily H2S concentration of the inlet gas (ppmv),

(3) the amount of sulfur (short tons) inlet to the plant using the results of 1 and 2, above,

(4) the flow of acid gas sent to the flare (MMSCF), 

(5) the H2S concentration of the acid gas sent to flare (ppmv), 

(6) the amount of sulfur (short tons) sent to the flare using the results of 4 and 5, above, 

(7) the percent of the inlet sulfur that was flared using the results of (3) and (6), above.

Initial Performance Testing: For sources subject to NSPS, testing shall be required in accordance with

the requirements contained in 40 CFR 60, Subpart A, General Provisions, paragraph 60.8

(performance tests) and 60.18 (General Control Device Requirements).

Periodic Calibration: A standard operating procedure (SOP) for the flow and concentration calibration

procedure for the H2S concentration instruments shall be developed and approved. Proper operation

of the alarm system or the spark igniter is to be checked once in January and once in July of each year. 

Audits: The H2S concentration certification tests shall be conducted in accordance with EPA

Performance Specification 7 (PS-7) in 40 CFR Appendix B. However, PS-7 will need to be modified to

accommodate the high H2S concentrations that will be encountered in the acid gas. The proposed

modifications to PS-7 shall be explained in the test protocol.

Other Appropriate Quality Control and Quality Assurance Measures: The acid gas flare shall be

equipped with either (1) a well maintained alarm system that signals non-combustion of the gas, or (2)

an automatic spark igniter that sends an ignition spark to the flare pilot.

Cost Analysis: Unknown
78
79

CHAPTER VII

LIME KILNS

In the western States, there are lime kilns at lime manufacturing plants and at pulp

and paper mills. There are two primary types of lime kilns, rotary kiln and vertical kilns. 

Other types include rotary hearth and fluidized bed kilns. Rotary kilns, account for about

90 percent of all U.S. lime production and can burn coal, oil, and natural gas. The other

types of kilns cannot burn coal as readily, therefore, these kilns are less common. The

WRAP inventory information indicates that no vertical kilns are included in units

addressed in the floor allocations for the trading program (based on a review of source

classification codes).

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

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

produced, and the type of kiln. The primary source of SO2 emissions is from the

combustion of fossil fuel to heat the kiln. The vast majority of the fuel sulfur is not emitted

because of reactions with calcium oxides in the kiln. SO2 emissions may be also be reduced

if the pollution equipment uses a wet control process for particulates or if it brings calcium

oxides and SO2 into intimate contact. Since SO2 control is inherent to the process,

additional controls are not typically applied to lime plants. 

NSPS for Kraft Pulp Mills are specified in 40 CFR 60 Subpart BB. This standard

requires CEMS for total reduced sulfur (TRS) emissions (on a dry basis) and O2 (% by

volume on a dry basis) for affected lime kilns at kraft pulp mills. If the source uses a SO2

scrubber control device, the source can monitor for continuous measurement of the

pressure loss across the control device and scrubbing liquid supply pressure rather than

employ a CEMS. The same record keeping requirements apply. Monitoring requirements

are summarized in Table VII-1.

Lime kilns are located in the States of Arizona, California, Nevada, and Utah. There

are seven pulp and paper lime kilns located in the State of Oregon. Summaries of SO2

monitoring requirements were obtained from Nevada and Oregon and are given in Table

VII-2 and Table VII-3, respectively. Nevada requires analysis of the fuel sulfur content. 

In addition it requires monitoring daily production. SO2 emissions are calculated using a

permit-specific emissions factor. Stack emission testing is required once every 5 years. 

Best SO2 monitoring practices for pulp and paper lime kilns in the State of Oregon require

a CEMS for TRS measured as H2S. A stack test is required once every 4 years. The

SCAQMD has one lime kiln. Lime kilns must follow the general district SO2 monitoring

rules, which require either SO2 CEMS and flow monitoring, or fuel gas continuous

monitoring (sulfur content and fuel flow). It is not known what type of monitoring is being

performed at the lime kiln in SCAQMD.
80

Table VII-1

NSPS Monitoring Requirements for Lime Kilns at Kraft Pulp and Paper Mills

Primary Source Category: Pulp and Paper 

Source Type: Lime Kiln

Emission Measurement/Quantification System:

CEMS for TRS emissions (dry basis) and O2 (% by volume on a dry basis). CEMS located downstream

of the control device(s). Span value: 30ppm TRS and 25% O2.

For any lime kiln or smelt dissolving tank using a scrubber emission control device: 

 1) monitor for continuous measurement of the pressure loss across the control device

 2) monitor for continuous measurement of the scrubbing liquid supply pressure to control device 

Averaging Times:

For CEMS:

1-hour averages of CEMS TRS (corrected to 10% O2) and O2 computed from four or more data points

equally spaced over each 1-hour period.

12-hour average TRS and O2 based on arithmetic mean of 12 contiguous 1-hour averages from CEMS

For pressure monitors: Record pressure measurements once per shift

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: None specified

Procedures for Addressing Missing and Invalid Data: None specified

Recordkeeping and Reporting Requirements: Requires semiannual report including periods of excess

emissions. The procedures under §60.13 shall be followed for evaluation and operation of the CEMS.

Initial Performance Testing: The pressure drop monitor is to be certified by the manufacturer to be

accurate to within a gage pressure of ±500 pascals (ca. ±2 inches water gage pressure). The supply

liquid pressure monitor is to be certified by the manufacturer to be accurate within ±15 percent of

design scrubbing liquid supply pressure.

The procedures under §60.13 shall be followed for installation.

Periodic Calibration: The procedures under §60.13 shall be followed for evaluation and operation of

the CEMS. 

Performance Specifications 1, 3, and 5 of Appendix B using Method 16 for TRS Method 3B for O2.

Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with

Procedure 1 of Appendix F. 

Audits: For CEMS: in accordance with Appendix F

Other Appropriate Quality Control and Quality Assurance Measures: For CEMS: in accordance with

Appendix F

Cost Analysis: Unknown
81

Table VII-2

Monitoring Requirements for Lime Kilns in the State of Nevada

Name: Graymont Western (formerly Continental Lime)

Primary Source Category: Lime Plants

Source Type: Lime Kiln (specifically, 3 lime kilns and associated equipment)

Emission Measurement/Quantification System: Current permit limits coal sulfur content and

throughput. Monitoring requires daily coal sulfur analyses (from a composite of samples taken once

per shift), daily production records, annual emission reporting, and stack emission testing once every 5

years.

Averaging Times: All emission limits are based on hourly averages as well as annual averages.

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: Annual production * Emission

Factor. The emission factor is generally provided by the Agency and is obtained from the permit limits

(emissions limit ÷ permitted production rate).

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements: See above

Initial Performance Testing: Currently, a performance test is required within 180 days of permit

issuance and once every five years thereafter.

Periodic Calibration: None, beyond those typically performed during the performance testing.

Audits: Typically, once per year by Agency compliance staff, or more frequently, if necessary.

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: None Provided
82

Table VII-3

Monitoring Requirements for Pulp & Paper Lime Kilns in the State of Oregon

(excluding Lane County)

Primary Source Category: Unbleached Kraft Pulp Linerboard and Corrugating Medium Mill

Source Type: Lime Kilns

Emission Measurement/Quantification System: CEMS for TRS (as H2S)

Averaging Times: TRS: Daily arithmetic averages calculated from 1-hour arithmetic averages

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions:

TRS: Calculate emissions of total reduced sulfur (TRS/ton equivalent air dried pulp) by:

-daily average concentration

-flow rate estimated from source tests & firing rate correlation

-equivalent ADTP production

Procedures for Addressing Missing and Invalid Data: None, 75% data recovery on a 1-hour period and

90% data recovery for a 1-hour period required for a CMS data average to be accepted (ODEQ

Continuous Monitoring Manual).

Recordkeeping and Reporting Requirements:

The permittee shall report the following information within 30 days of the end of each calendar month:

-Daily average concentration of TRS gases

-Daily average emissions of TRS gases as lbs/equivalent tons of pulp processed

Initial Performance Testing: No performance testing requirements of emission unit within current

permit that exceeds the CEMS auditing procedures (RATA)

Periodic Calibration: Daily Calibrations

Audits: Quarterly audits, either CGA or RAA. Once every four quarters a RATA is required

Other Appropriate Quality Control and Quality Assurance Measures: Mandatory submittal and periodic

review of CEM quality assurance plan and standard operating procedures manual.

Cost Analysis: Unknown
83

CHAPTER VIII

CEMENT KILNS

Cement kilns generate SO2 emissions from two processes; 1) the combustion of fuel

which contains sulfur, and 2) heating of the feedstock, generally pyrite, which also contains

sulfur. SO2 emissions vary by kiln type, generally based on how effectively the kiln type

mixes the SO2 containing gases with the alkaline calcium compounds. Emissions from

kilns also vary according to the sulfur content of the feedstock. Changes in feedstock can

cause a change in emissions up to a factor of 100. According to EPA AP-42 emission

factors, emissions from cement kilns can vary by as much as a factor of 20. 

There are cement kilns in Arizona, Colorado, Idaho, Nevada, New Mexico, Utah and

Wyoming. Monitoring requirements for SO2 emissions from cement kilns vary among

States and may be kiln-specific. Information about existing SO2 monitoring requirements

was obtained from Nevada, Colorado and Oregon. These requirements are summarized in

Table VIII-1, Table VIII-2, and Table VIII-3, respectively.

Nevada and Oregon require analysis of the sulfur content of the fuel and feedstock and

monitoring of total annual throughput and annual fuel usage. SO2 emissions are then

estimated from published emission factors. Nevada and Oregon also require periodic stack

testing to ensure compliance. Colorado requires a CEMS for SO2 monitoring of cement

kilns. No information on stack testing requirements in Colorado was available. One kiln

in Nevada has a positive pressure baghouse (open baghouse), therefore, monitoring of stack

emissions is not required at this source.

The SCAQMD reported via a teleconference that it has two cement kilns operating in

the district. One cement kiln uses a SO2 CEMS with a stack flow monitor. The other

cement kiln, which uses a positive pressure baghouse for particulate control, measures SO2

(and NOx) with CEMS upstream of the baghouse. Plant SO2 emission concentrations are

low, so measuring before the baghouse does not have a significant impact on emission

accounting. The heavy particulate loading upstream of the baghouse precludes the use of

a standard flow monitoring technique. Therefore, stack flow is measured using a

correlation with fan amperage measurements. This correlation method is subject to

relative accuracy testing using Reference Method 2.
84

Table VIII-1

Monitoring Requirements for Cement Kilns in the State of Nevada

Name: Nevada Cement Company

Primary Source Category: Cement Plants

Source Type: Cement Kilns (specifically, 2 cement kilns and associated equipment). One kiln is

controlled by a positive pressure baghouse (non-testable), the other kiln is testable.

Emission Measurement/Quantification System: Current permit limits coal sulfur content and

throughput. Monitoring for total annual throughput and annual fuel is required for Kiln #1. Monitoring

for Kiln #2 requires monthly coal sulfur analyses (from a composite of samples representing each

delivery received in the month), and annual production records. Annual emission reporting is required

for both units, and stack emission testing once per year for Kiln #2 only.

Averaging Times: All emission limits are based on hourly averages as well as annual averages except

for NOx, which has only an annual average.

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: Annual production * Emission

Factor. The emission factor is generally provided by the Agency and is obtained from the permit limits

(emissions limit ÷ permitted production rate). A source test result can also be used to replace the

provided emission factor.

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements: See above

Initial Performance Testing: Currently, a performance test is required within once per year.

Periodic Calibration: None, beyond those typically performed during the performance testing.

Audits: Typically, once per year by Agency compliance staff, or more frequently if necessary.

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: None Provided
85

Table VIII-2

Monitoring Requirements for Cement Kilns in the State of Colorado

Facility Name: Holcim, Inc. Florence Plant (Colorado)

Primary Source Category: Portland Cement Manufacturing

Source Type: Kiln/Precaliner

Emission Measurement/Quantification System: Continuous Emission Monitoring System for SO2

and Flow

Averaging Times: Annual

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: Pounds per hour (lbs/hr)

values are totaled to arrive at the annual mass emissions.

Procedure for Addressing Missing and Invalid Data: Not sure

Recordkeeping and Reporting Requirements: Keep emission data onsite for review.

Initial Performance Test: Not sure

Periodic Calibration: Daily calibrations

Audits: Cylinder gas audits quarterly

Other QA/QC Activities: Annual RATAs
86

Table VIII-3

Monitoring Requirements for Cement Kilns in the State of Oregon

(excluding Lane County)

Primary Source Category: Portland Cement Manufacturing

Source Type: Kiln/Roller Mill System

Emission Measurement/Quantification System: Monitoring the sulfur content of each shipment of fuel

received

Averaging Times: Not Applicable

Consideration of Batch, Seasonal, and Cyclical Operations: No

Calculations Used to Determine Quarterly and Annual Mass Emissions:

Mass emissions determinations on a 12 consecutive calendar month basis to determine compliance

with the plant site emission limit (PSEL) is performed as follows:

E

Peu x EFeu

K

E E E E etc

i

m i ii iii

=

= + + +

∑

( )

( .)

1

12

E12m= (Ei + Eii + Eiii + etc.)

Peu = tons of clinker per month

EFeu = 0.100 lb SO2/ton clinker

K1 = 2000 lbs/ton

Procedures for Addressing Missing and Invalid Data: Not Applicable

Recordkeeping and Reporting Requirements:

The permittee must maintain records of the sulfur content of each shipment of fuel received.

The permittee shall maintain records of daily clinker production and kiln feed rates. 

Semi-annual reporting of compliance certification.

Initial Performance Testing:

The permittee must determine compliance with the sulfur dioxide standards by conducting a source test

once each permit term. 

Periodic Calibration: Not Applicable

Audits: Audit records during inspection and review source test report.

Other Appropriate Quality Control and Quality Assurance Measures: Not Applicable

Cost Analysis: Costs for source testing and recordkeeping labor-hours unknown
87

CHAPTER IX

ALUMINUM SMELTERS - POTLINES

The primary source of SO2 emissions in aluminum production is the sulfur in the

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 also be a significant SO2 emission

source. As the coke is processed or consumed in the reduction cell, SO2 is released. The

majority of SO2 emissions are collected by the pot hood exhaust system. SO2 emissions are

generally controlled by limiting the sulfur content in the coke and pitch used in the anodes. 

SO2 can also be controlled by a wet scrubber.

The NSPS for primary aluminum plants limits fluoride emissions, but does not address

SO2 emissions. Washington is the only State that has established an SO2 emission limit

specifically for primary aluminum plants. Washington, however, is outside the trading

region. Washington’s 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. In

addition, it limits SO2 stack emissions to 1,000 ppm. 

There are 2 primary aluminum plants located in Oregon, Reynolds Metal and

Northwest Aluminum. Note that the Reynolds Metal facility is permanently shut down

and the primary smelting operations at the Northwest Aluminum facility are currently

shut down. Monitoring requirements for aluminum smelters in the State of Oregon are

listed in Table IX-1. Since there are a limited number of sources in the trading region,

Pechan obtained monitoring requirements for the State of Washington as well. 

Washington State has seven aluminum smelters. Pechan reviewed two air permits for

primary aluminum plants located in the State of Washington: Vanalco, Inc. and Kaiser

Aluminum & Chemical Corp. The monitoring requirements for these facilities are

summarized in Table IX-2.

The State of Oregon requires periodic stack testing of SO2 in order to monitor

emissions from aluminum smelters. In the State of Washington, SO2 emissions are

required to be monitored using either a mass balance approach, which requires sampling of

the sulfur content of the petroleum coke and pitch, or periodic stack testing. Note that the

State of Washington calculated SO2 emissions for the Kaiser and Vanalco plants under

normal operating conditions (normal air flow rate and highest aluminum production rate). 

These estimates were well below the State’s 1,000 ppm limit, with the possible exception of

an upset condition. Therefore, the plants are exempt from monitoring for the 1,000 ppm

standard. 

A wet scrubber is the floor SO2 control technology assumed for aluminum smelters

based on Northwest Aluminum having this SO2 control in-place at its Oregon plant. A

possible monitoring requirement for aluminum smelters, which have or install a wet

scrubber, is to monitor the pressure drop across the scrubber and the scrubbing liquid

pressure. This approach is an option under the NSPS for lime kilns at kraft pulp and
88

paper mills and under the Compliance Assurance Monitoring (CAM) Rule for Title V

sources. The pressure drop and scrubbing liquid pressure monitors the performance of the

scrubber and not SO2 emissions. Therefore, this approach does not necessarily indicate

compliance with regulations. Table IX-3 presents costs for monitoring the pressure drop

across a wet scrubber (assumed cost year is 1999).
89

Table IX-1

Aluminum Smelter Monitoring Requirements in the State of Oregon

(excluding Lane County)

Primary Source Category: Primary Aluminum Production

Source Type: Potlines

Emission Measurement/Quantification System: Three test runs per semi-annual period by EPA

Methods 6, 6A, or 6B.

Averaging Times: Not Applicable

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: The permittee shall perform

source testing to monitor compliance with the potlines contribution to SO2 short term and annual plant

site emission limits.

Procedures for Addressing Missing and Invalid Data: Enforcement actions may be taken if testing is

not performed as required.

Recordkeeping and Reporting Requirements: The permittee shall report the SO2 emissions expressed

in ppm and lbs/TAP within 30 days of the end of each calendar quarter.

Initial Performance Testing: Performance testing required semi-annually

Periodic Calibration: Not Applicable

Audits: Audit records during inspection and review of source test report.

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: Unknown
90

Table IX-2

Aluminum Smelter Monitoring Requirements in the State of Washington

Primary Source Category: Primary Aluminum Production

Source Type: Potlines

Emission Measurement/Quantification System:

Requires the following; 1) analyze sulfur content of each load or batch of petroleum coke and pitch

using ASTM D4239, and 2) measure aluminum production daily, or source testing. 

Note that sources are exempt from monitoring for 1,000 ppm SO2 standard since they can

demonstrate, using a worse-than-worst-case analysis, that the source is incapable of violating the

standard, with the possible exception of an extreme upset condition.

Averaging Times: Monthly 

Consideration of Batch, Seasonal, and Cyclical Operations: Sample each batch of coke and pitch. 

Calculations Used to Determine Quarterly and Annual Mass Emissions:

Calculate SO2 emissions from mass balance assuming all sulfur converts to SO2.

SO2/ton Al = [ 3(C x SC)+(3(P x SP)+3(O x SO) ] x 40 / Al 

where C, P, and O are the coke, pitch, and fuel oil usage during the month from each shipment, in tons;

SC, SP, and SO are the % sulfur concentration of each shipment of coke, pitch or fuel oil, respectively; and

Al is the aluminum production for the month. 

The factor of 40 derives from converting tons of raw materials to pounds (2,000 lbs/ton), converting the

percentage of sulfur in raw materials to a decimal fraction (100), and converting the weight of sulfur to the

weight of SO2 (1 lb sulfur equals 2 lbs SO2).

Procedures for Addressing Missing and Invalid Data: None Specified

Recordkeeping and Reporting Requirements: 

Submit monthly report of SO2 emissions (lbs SO2/ton Al) including records of raw materials usage,

representative raw materials sample analysis and aluminum production rate.

Initial Performance Testing: 

Upon request, source must conduct SO2 emissions testing using EPA Test Method 6, 6A, 6B, 6C or 8 

from 40 CFR Part 60 Appendix A.

Periodic Calibration: None 

Audits: None Specified

Other Appropriate Quality Control and Quality Assurance Measures: None Specified

Cost Analysis: Unknown
91

Table IX-3

Costs for Monitoring Pressure Drop Across Wet Scrubber

Item Total Cost, $

Capital and other initial costs

Planninga 4,890

Equipment selectionb 0

Support facilitiesc 2,000

Purchased equipment cost d 3,260

Install and check DASe 5,680

Data collection textf16,140

Total Capital Investment (TCI) 31,970

Annual Costs, $/yr

Operation and maintenanceg 900

Annual RATAh10,930

Recordkeeping and reportingi 2,020

Property taxes, insurance, and administrativeg 1,280

Capital recoveryh 3,020

Total Annual Cost, $/yr 26,650

aBased on $4,250 labor to review regulations, define monitoring requirements and develop CAM plan plus

$640 in supplies.

bCost of selecting PC-based data acquisitions system included in planning costs.

cCost of installing sampling ports in stack.

dCost based on Pentium class PC, monitor, printer, and operating software.

ePC installation and interconnection for sensor signals, equipment calibrations and start-up services.

fCost for data collection testing is based on the cost for initial RATA testing on a CEM.

gBased on 10% of purchased equipment cost + 10% of installation labor cost.

hCost for data collection testing is based on the cost for annual RATA testing on a CEM.

i

5 min. per shift 3 shifts per day x (365 days/yr) @ $17.50/hr for operators.

jAdd 2.5% of operator time for engineerís review @ $30/hr, 2.5% of operator time for managerís review @

$50/hr, 10% of operator time for clerical support @ $10/hr and $100 for supplies.

kQA planning, training, and equipment inventory estimated to be 50% of CEM cost.

lBased on 4% of TCI, 20 year life and 7% interest.

SOURCE: EPA, 2002.
92
93

CHAPTER X

GLASS MANUFACTURING

The major source of SO2 emissions in the glass industry is the glass melting furnace. 

Furnace emissions appear to be attributable to both the manufacturing process and the

fuel burned. Fuel-derived SO2 emissions are lower from natural gas-fired furnaces than

from oil-fired furnaces, unless the oil has been desulfurized.

SO2 monitoring requirements were evaluated for glass manufacturing plants in

Colorado, Oregon, and the SCAQMD. The plants in Colorado and Oregon emitted all SO2

via a stack. The summaries of these monitoring requirements are provided in Table X-1,

Table X-2, and Table X-3 respectively. Colorado requires continuous monitoring systems

for SO2 and monitoring of fuel consumption, while Oregon estimates SO2 emissions from

monthly production records for tons of glass melted, and natural gas and fuel oil fuel usage

estimates from meter/gauge readings. SO2 emissions are then calculated using emission

factors.

The SCAQMD requires the use of CEMS at the glass plant(s). There are some flow

monitoring issues at these plants because oxy-fuel systems are being adopted (using

oxygen rather than air). Oxygen use reduces the overall flow as there is reduced oxidizer

volume. In these cases, they cannot use an alternate method such as measurement of the

fuel burned and use of an f-factor to determine stack flow. In-stack flow meters must be

used or an alternative method for low flow rates such as the use a tracer gas (e.g., helium).
94

Table X-1

Monitoring Requirements for Glass Manufacturing in the State of Colorado

Name: Rocky Mountain Bottle Company

Primary Source Category: Glass Manufacturing

Source Type: Glass Melting Furnaces and Bottle Making Machines

Emission Measurement/Quantification System: 

Glass Melting Furnaces: 

Current permit limits SO2 emissions to 82.65 lb/hr and 362 tpy. CEMS must be installed, calibrated,

maintained and operated for the measurement of SO2 emissions discharged from the combined stack.

The hourly emission limits are based on an average of emissions for the hours of operation during each

28 day period of operation. 

Bottle Making Machines: 

Current permit limits SO2 emissions and oil consumption.

SO2 emissions are calculated by the end of each subsequent 28 day period. The bottle making

machines are a minor SO2 source (limited to 6.8 tpy).

Averaging Times: Emission limits are based on hourly averages as well as annual averages.

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: 

Bottle Making Machines:

Oil consumption/period * Emission Factor

Emission Factor = 0.105 ton of SO2 /ton of oil consumed

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements: Submission of compliance certifications including

emission limitations are required not less than annually. Monitoring deviation reports are due at least

every six months. 

A 13-period rolling total of emissions must be maintained for demonstration of compliance with annual

emissions.

Reports must be retained for at least 5 years.

Initial Performance Testing: None

Periodic Calibration: None.

Audits: Once per year by Agency compliance staff, or more frequently, if necessary

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: None Provided
95

Table X-2

Monitoring Requirements for Glass Manufacturing in the State of Oregon

Name: Owens-Brockway Glass Container, Inc.

Primary Source Category: Glass Manufacturing

Source Types: Glass Melting Furnaces and Boilers emit SO2

Emission Measurement/Quantification System: 

Current permit limits SO2 emissions to 313 tpy.

Glass melting furnaces: 

Record the tons of glass melted per month using production records.

Measure natural gas and fuel oil volume burned per month by using fuel usage meter/gauge readings.

Current permit limits sulfur content of distillate oil.

Sulfur content is monitored by obtaining an analysis certificate from the vendor of each batch or by

analyzing representative samples from each batch of fuel received. Sulfur content is analyzed by using

Methods ASTM D129-64, D1552-83, or D4057-81 or an equivalent method.

Boilers:

Measure natural gas and fuel oil volume burned per month by using fuel usage meter/gauge readings.

Current permit limits distillate oil sulfur content.

Sulfur content is monitored by obtaining an analysis certificate from the vendor of each batch or by

analyzing representative samples from each batch of fuel received. Sulfur content is analyzed by using

Methods ASTM D129-64, D1552-83, or D4057-81 or an equivalent method.

Averaging Times: 12-month rolling average.

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Monthly and Annual Emissions: 

Monthly Emissions:

EMO,iPiEFi,j= K

Yearly Emissions:

EAnnual EMO,i Past 12- month= ∑

Where :

EMO,i = monthly pollutant emissions from individual device

Pi = operating parameter

EFi,j= emission factor based on AP-42 and testing, depends on emission unit, given in lbs/lb of SO2 used,

lbs/1000 gal, or lbs/ 106 ft3.

K= conversion factor (1 ton/2,000 lbs or 2,000)

The emission factors for the furnaces and boilers are:

EU4 - Distillate Oil 142 (%S) AP-42

GM1 - Glass Melted 1.5 lbs/ton glass Testing

GM4 - Glass Melted 0.70 lbs/ton glass Testing

EU7 - Natural Gas 2.6 lbs/ 106 ft3 AP-42

EU7 - Distillate Oil 142 (%S) AP-42

The emission factor for the glass melting furnaces must be verified once every five years by using EPA

Method 6, 6c.

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements: Monthly and annual records of fuel oil and natural gas

consumption must be maintained.

Semi-annual and annual monitoring reports are required.

Monitoring data and support information must be kept for at least 5 years.

Initial Performance Testing: None

Periodic Calibration: None

Audits: Typically, once per year by Agency compliance staff, or more frequently if necessary.

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: None Provided
96

∑ ∑ = =

= +

p

m

m

n

k

G E k E

1 1

7

1.662 10 −ei = ai × ci × ×

Table X-3

Monitoring Requirements for Glass Manufacturing in the SCAQMD, California

Primary Source Category: Glass Manufacturing Plants

Source Type: Boilers/ Furnaces

Emission Measurement/Quantification System: 

Must install, calibrate, maintain, and operate an approved CEMS or Alternative Monitoring System

(AMS). 

CEMS/AMS must measure:

a. Sulfur oxide concentrations discharged from stack,

b. Fuel gas flow rate and sulfur content, if the CEMS uses these to determine SOx emissions. 

c. Stack gas volumetric flow rate using one of the following methods;

1. An in-stack flow meter,

2. An approved alternate method such as measurement of the fuel burned and use of an f-factor

to determine stack flow. The fuel measurements must meet the same relative accuracy as the

flow monitor, and are tested against reference method 2.

3. Glass furnaces using oxygen-fuel systems operate at low flow rates due to the use of oxygen

rather than air as the oxidizer. These systems require in-stack flow meters or use of a tracer gas

to determine a dilution ratio and stack flow.

4. Oxygen concentrations, at sulfur oxide monitoring location if required for stack gas flow rate.

Averaging Times: 1-hour average equally computed based on four valid 15-minute average emission

data points equally spaced over each 1-hour period. (Only 2 required during CEMS maintenance

activities) 

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Monthly and Annual Emissions: 

Sulfur oxide mass emissions in units of lb/hour:

where: ei = Mass emissions of sulfur oxides (lb/hr),

ai = Stack gas concentration of sulfur oxide (ppmv), and

ci = Stack gas volumetric flow rate (scfh). 

The daily emissions of sulfur oxides for each affected SOx source: 

where:

G = Daily emissions of sulfur oxide (lb/day),

Ek = Hourly average emission rate using CEMS (lb/hr)

Em = Hourly average emission rate of sulfur oxides using substitute data (lb/hr),

n = Number of hours of valid data from CEMS coinciding with the operating hours

p = Number of hours using substitute data when the source is operating; and

m = Number of operating hours of the source during the day.
97

Procedures for Addressing Missing and Invalid Data:

Emission rate data may be obtained using District Methods 6.1 or 100.1 (for SOx) in conjunction with

District Methods 1.1, 2.1, 3.1, and 4.1 or by using District Methods 6.1 or 100.1 in conjunction with

District Method 3.1 and EPA Method 19. 

Emission rate data may also be obtained using District Methods 307-91 or ASTM Method D1072-90,

Standard Test for Total Sulfur in Fuel Gases (for sulfur content in the fuel gas) in conjunction with the fuel

gas flow rate.

May use the procedure in 40 CFR Part 75 Subpart D if the relative accuracy of the pollutant analyzer and

flow measurement system during the last CEMS certification test and/or RATA are both less than 10%.

Calculate on a daily basis the percent data availability of analyzer then substitute data calculated as:

 a. if availability is >= 95% and missing data is:

 < 24 hours: 1N Procedure in Attachment A or E(1)(b)(ii), or

 > 24 hours: max hourly concentration recorded for previous 30 days.

 b. if availability is >= 90% and missing data is:

 < 3 hours: average of concentration for the hour before and after missing data period,

 > 3 hours: max hourly concentration recorded for previous 30 days, or

 > 24 hours: max concentration recorded for previous 365 days

 c. if availability is > 90%: highest hourly concentration recorded during the service of the CEMS.

Recordkeeping and Reporting Requirements: 

1. Total daily SOx mass emissions from each source, 

2. Daily status codes, 

3. Daily electronic transmittal of RTU data, 

4. Monthly submittal of daily records of SOx emission rates per thousand barrels of feed, 

5. Monthly aggregated SOx emissions, 

6. Semi-annual and CEMS certification tests

7. Must submit a CEMS plan for approval

CEMS data shall be recorded by: 1) RTU and 2) strip chart or alternative electronic recorder. The strip

chart recorder or alternative shall receive data independent of the RTU and serve as an independent

tool for verifying data. 

Must measure and record 1) variables necessary for the alternate gas volumetric flow rate method, 2)

measurements in Table 2-A and 3) other measured data to support calculations.

Recorded data shall be readily accessible upon request.

Must maintain records of measurements, tests, calibration audits and QA data for 3 years. Keep a

written record of QA and audit procedures.

Initial Performance Testing: Same requirements as audits

Periodic Calibration: 

CEMS design shall allow determination of calibration drift. Requires zero and span calibration checks,

and zero and span adjustments. Perform any calibration error test procedures specific to the CEMS. 

Attachment C Quality Assurance And Quality Control Procedures:

1. Test, record, and compute the calibration error of each monitor at least once per operating day. 

Perform the daily calibration error test according to the procedure in Chapter 2, Subdivision B,

Paragraph 1, Subparagraph a, Clause ii of this Attachment. 

2. Test, compute, and record the calibration error of each stack flow monitor at least once per 14

calendar days. Perform daily flow monitor interference checks. All transducers and transmitters

installed on stack flow monitors must be calibrated every two operating calendar quarters.
98

Audits: Requires semi-annual CEMS certification test

Meet specifications in 40 CFR Part 60, Appendix B, Performance Specification 2, Section 8 and

Appendix A Attachment B Bias Test of this rule. Minimum of nine sets of tests conducted. Specifies

alternate procedures. 

1. Monitors and Analyzers: relative accuracy of >= 20% of the mean value of the reference method

test data.

2. Volumetric flow measurement system: relative accuracy of >= 15% of the mean value of the

reference method test data. Must perform study to determine the acceptability of the potential flow

monitor location and to determine the number and location of flow sampling points. 

3. Must demonstrate the absence of stratification (difference between highest and lowest concentration

divided by average concentration is >10%.

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: None Provided
99

CHAPTER XI

METALLURGIC COKE PRODUCTION

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 an enclosed chamber to approximately

1050oC, which removes all volatile elements 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.

There are limited coke production operations in the WRAP Region. Protocols for this

industry are based on the rotary calciner used for coke production at P4 Production in Rock

Springs, Wyoming and facilities operating in the South Coast of California. Table XI-1

summarizes the existing SO2 emission monitoring requirements for P4 Production. In

short, no SO2 emission monitoring is required for this facility. Annual SO2 emissions are

computed using the stack test-based SO2 emission factor and operating hours/production

rate estimates.

There is at least one coke calciner included in the South Coast RECLAIM program,

and the CEMS and flow monitoring requirements are no different from those applied under

SCAQMD Rule 2011 for other source types, so the SO2 emission monitoring protocol is not

repeated in this chapter.
100

Table XI-1

Monitoring Requirements for Coke Production in the State of Wyoming

Name: P4 Production - Rock Springs Coking Plant

Primary Source Category: Coke Manufacturing

Source Type: Rotary Coker. This plant uses petroleum coke blended with coal as a feedstock. SO2

emissions result from the sulfur in these fuels.

Emission Measurement/Quantification System: 

No SO2 emissions monitoring is required for this facility. SO2 emission factors are based on stack

tests. The last stack test on the main coker stack was performed just prior to issuance of the Title V

permit (prior to 1999). All SO2 emissions are via the stack.

Averaging Times: Emission limits are annual totals.

Consideration of Batch, Seasonal, and Cyclical Operations: None

Calculations Used to Determine Quarterly and Annual Mass Emissions: 

Annual emissions are estimated using the stack test-based SO2 emission factor and operating hours. 

The annual throughput is estimated using the average feed rate for the year (in tons per hour). The

tested feed rate is pro rated for the year's production.

Procedures for Addressing Missing and Invalid Data: None

Recordkeeping and Reporting Requirements: Emission fees are based on annual emission estimates

submitted to the State of Wyoming.

Initial Performance Testing: None

Periodic Calibration: None.

Audits: 

Other Appropriate Quality Control and Quality Assurance Measures: None

Cost Analysis: None Provided
101

CHAPTER XII

SULFURIC ACID PRODUCTION

Emission monitoring protocols for sulfuric acid plants are addressed in Chapter II -

Copper Smelters. See Table II-2 for a summary of the SO2 monitoring requirements for the

acid plant at Kennecott Copper in Utah and Table II-4 for the monitoring requirements for

acid plant tail gas at copper smelters in Arizona. Because SO2 CEMS and flow monitoring

are required for the Kennecott unit, these are considered the best monitoring practices for

H2SO4 production.
102
103

REFERENCES

40 CFR Part 60 – New Source Performance Standards.

40 CFR Part 75 – Continuous Emission Monitoring.

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

Catalytic Cracking Unit Regenerators – Background Information for Proposed

Standards,” Final EIS, EPA-450/3-82-013b, April 1989.

EPA, 1998: U.S. Environmental Protection Agency, “CEMS Cost Model Version 3.0 and

User Manual,” 1998.

EPA, 2002a: U.S. Environmental Protection Agency, “Information Collection Request

Renewal for the Acid Rain Program Under the Clean Air Act Amendments Title IV,”

May 16, 2002.

EPA, 2002b: U.S. Environmental Protection Agency, “EPA Air Pollution Control Cost

Manual, Section 2, Chapter 4 Monitors,” EPA/452/B-02-001, January 2002.

OTC, 1997: Ozone Transport Commission, “Guidance for Implementation of Emission

Monitoring Requirements for the NOx Budget Program,” January 28, 1997.

PQA, 1999: Perrin Quarles Associates, “Compilation of Monitoring Cost Information for

Part 75 and Model NOx Trading Rule Implementation,” [cited as Part 75 CEM Cost

Study], January 1999.

WGA, 2002: Western Governors’ Association, “Market Trading Forum Non-Utility Sector

Allocation – Final Report From The Allocations Working Group,” Denver CO, prepared

by E.H. Pechan and Associates, Inc., November 2002.
104