United States
Environmental Protection
Agency
Enforcement and
Compliance
Assurance (2222A)
November 2000
Case Conclusion
Data Sheet
Training Booklet
[I.
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TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1-1
1.1 Background 1-1
1.2 How CCDS Data are Used by EPA/OECA 1-2
1.3 How This Document Is Organized 1-2
2.0 QUALITY ASSURANCE/QUALITY CONTROL FOR THE CCDS PROCESS 2-1
2.1 Completing the Form 2-1
2.2 Review of the CCDS Form 2-2
2.3 Reconciliation of Inconsistent and Incomplete Forms 2-5
2.4 CCDS Data Entry into DOCKET 2-5
3.0 CCDS FORM AND INSTRUCTIONS 3-1
3.1 The Revised CCDS Form 3-1
3.2 Form Instructions 3-7
>..
4.0 GUIDE FOR POLLUTANT REDUCTION/ELIMINATION CALCULATIONS 4-1
4.1 When Do You Need to Calculate Pollutant Reductions/Eliminations? 4-1
4.2 How Do You Calculate Pollutant Reductions/Eliminations? 4-2
4.2.1 Basic Methodology 4-2
4.2.2 Calculation Basis for Time 4-3
5.0 WATER EXAMPLES 5-1
5.1 Clean Water Act/NPDES 5-1
5.1.1 Background 5-1
5.1.2 Input Needed to Calculate Pollutant Reductions 5-1
5.1.3 Step-by-step Instructions for Calculating Pollutant Reductions 5-2
5.2 Stormwater Violation for CAFO 5-5
5.2.1 Background 5-5
5.2.2 Input Needed to Calculate Pollutant Reductions 5-5
5.2.3 Step-by-Step Instructions for Calculating Pollutant Reductions 5.7
5.2.4 Example Calculation 5-7
5.3 Combined Sewer Overflow (CSO) 5-8
5.3.1 Background 5-8
5.3.2 Input Needed to Calculate Pollutant Reductions 5-9
5.3.3 Step-by-Step Instructions for Calculating Pollutant Reductions 5-10
5.3.4 Example Calculation 5-11
5.4 Safe Drinking Water Act Pollutant Reduction 5-12
5.4.1 Background 5-12
5.4.2 Input Needed to Calculate Pollutant Reductions 5-12
5.4.3 Step-by-step Instructions for Calculating Pollutant Reductions 5-13
5.4.4 Example Calculation ...., 5-14
5.5 SDWA Microbial Violation 5-15
5.5.1 Background 5-15
OECA/OC/IUTB
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TABLE OF CONTENTS (Continued)
Page
5.6 References 5-16
6.0 AIR EXAMPLES 6-1
6.1 NOx Reductions at a Petroleum Refinery under PSD/NSR 6-1
6.1.1 Background 6-1
6.1.2 Input Needed to Calculate Pollutant Reductions 6-3
6.1.3 Step-by-Step Instructions for Calculating Pollutant Reductions 6-4
6.1.4 Example Calculations 6-6
6.2 S02 and HAP Reductions at a Kraft Pulp and Paper Mill Under MACT 6-10
6.2.1 Background 6-10
6.2.2 Input Needed to Calculate Pollutant Reductions 6-13
6.2.3 Step-by-Step Instructions for Calculating Pollutant Reductions 6-14
6.2.4 Example Calculations 6-15
6.3 Leak Detection and Repair 6-20
6.3.1 Background 6-20
6.3.2 Input Needed to Calculate Pollutant Reductions 6-20
6.3.3 Step-by-Step Instructions for Calculating Pollutant Reductions 6-23
6.3.4 Example Calculations 6-24
6.4 Asbestos NESHAP 6-26
6.4.1 Background 6-26
6.4.2 Input Needed to Calculate Pollutant Reductions 6-27
6.4.3 Step-by-Step Instructions for Calculating Pollutant Reductions 6-29
6.4.4 Example Calculation 6-29
6.5 References 6-30
7.0 SOLID WASTE EXAMPLES 7-1
7.1 Corrective Action 7-1
7.1.1 Background 7-1
7.1.2 Input Needed to Calculate Pollutant Reductions 7-2
7.1.3 Step-by-Step Instructions for Calculating Pollutant Reductions 7-2
7.1.4 Example Calculation 7-3
7.2 RCRA UST 7-5
7.2.1 Background on UST Regulations 7-5
7.3 Used Oil Management 7-7
7.3.1 Background on Used Oil Regulations 7-7
7.3.2 Input Needed to Calculate Pollutant Reductions 7-8
7.3.3 How to Calculate Pollutant Quantities 7-8
7.3.4 Example Calculation 7-9
8.0 UNITS AND UNIT CONVERSIONS 8-1
9.0 LOOK-UP TABLES 9-1
OECA/OC/IUTB 11
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LIST OF TABLES
Page
3-1 Question 17 Actions 3-5
3-2 Key SEP Actions to Track 3-6
3-3 CCDS Form Instructions 3-7
3-4 Statutory Section Numbers for Laws Violated, Question 5 3-9
3-5 Definitions for Question 17 3-13
3-6 Preferred Nomenclature for Common Pollutants - Questions 19 and 24 3-15
3-7 Question 19 and 24 Entries for "Media" 3-16
3-8 Question 19 and 24 Entries for "Units" 3-16
3-9 Definitions for Question 20 3-17
5-1 Pollutants in Pounds per Animal per year for Dairy Facilities 5-6
5-2 Pollutants in Pounds per Animal per year for Beef Facilities 5-6
5-3 Typical Pollutant Concentrations (in mg/L) by Source 5-9
6-1 Worksheet to Calculate NOx Emission Reductions from Process Heaters and
Boilers 6-9
6-2 SOCMI Leak Rate/Screening Value Correlations 6-21
6-3 Petroleum Industry Leak Rate/Screening Value Correlations 6-21
6-4 SOCMI Default Zero Leak Rates and Pegged Leak Rates 6-21
6-5 Petroleum Industry Default Zero Leak Rates and Pegged Leak Rates 6-22
6-6 Asbestos Content for Various Materials 6-27
6-7 Bulk Densities for Binder/Sizing Materials 6-28
8-1 Common Conversion Factors 8-2
8-2 Examples of Common Pollutant Loading Conversions for Different Media 8-2
OECA/OC/IUTB iii
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LIST OF TABLES (Continued)
Page
9-1 National Primary Drinking Water Regulations 9-1
9-2 National Secondary Drinking Water Regulations 9-5
9-3 NOx and SO2 Emission Factors for Boiler Fuel Oil Combustion 9-6
9-4 NOx Emission Factors for Boiler Natural Gas Combustion 9-7
9-5 SO2 Emission Factors for Boiler Natural Gas Combustion 9-8
9-6 NOx Emission Factors for Process Heater Natural Gas Combustion 9-8
9-7 NOx Emission Factors for Process Heater Oil Combustion 9-9
9-8 Estimated Control Efficiencies (%) for NOx 9-10
LIST OF FIGURES
Page
2-1 CCDS Completion Checklist 2-3
2-2 CCDS Calculation Checklist 2-4
3-1 Case Conclusion Data Sheet 3-2
OECA/OC/IUTB IV
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i.o INTRODUCTION
1.1 Background
EPA implemented the Case Conclusion Data Sheet (CCDS) in FY 1996 to capture relevant
information on results and environmental benefits of concluded enforcement cases including
pollutant reduction benefits. CCDS information must be provided whenever any formal
enforcement case is "concluded." For civil judicial cases, the information is reported when a
consent decree, court order, or judgment is entered (not lodged). For administrative cases,
information is reported when an administrative order or final agreement is signed (usually by the
Regional Administrator) and issued. EPA has evaluated the CCDS data and identified areas in
which improvements are needed. Examples of the types of problems encountered with the
CCDS data are:
A lack of consistency in the timeframe used for reporting pollutant
reductions from a case. For example, in a large diesel engine case, six
manufacturers were found to have violated requirements for the control of NOX in
their engines. The estimate of NOX reductions for the case were annualized from
reductions that were expected to occur over a 25 year period and one year of
emissions was reported. Other cases have reported average total reductions for a
multi-year period.
Missing pollutant reduction data is prevalent. For example, many of the
submitted CWA cases that require a facility to come into compliance with specific
pollutant limitations do not have a pollutant load calculated when one should be.
Other cases are reported with a pollutant identified but no amount reported and/or
no units of measurement reported.
Pollutant reduction data is misreported. For example, some EPCRA cases
erroneously showed large quantities of pollutant reduction for pollutant reporting
actions that should have been reported under TRI which would not have resulted
in a pollutant reduction. (An exception to this is EPCRA Supplemental
Environmental Projects (SEPs) which may result in pollutant reduction through
the application of a control technology or process change.)
In addition, EPA's analysis of the CCDS process, including discussion with regional and
headquarter managers and staff, identified two main obstacles to completing the CCDS properly.
The first is a lack of guidance on how to complete the form particularly in calculating pollutant
reductions or chemicals/waste brought under proper management control. This document and
the accompanying Quick Guide are geared toward addressing this obstacle.
The second obstacle affecting the quality and completeness of CCDS data is that insufficient
time is spent in completing the form. Input from the regions shows that most offices are
spending no more than 5-15 minutes to complete each form. OECA expects that each CCDS
would require approximately 10-30 minutes to complete and will require more time when
pollutant reduction/elimination calculations are required. Additionally, while some regional
offices employ some level of completeness check of the form prior to entry into the Docket
OECA/OC/IUTB 1-1
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system, most offices do not employ a technical review of the form. An independent technical
review of each completed form would resolve many of the problems described above.
1.2 How CCDS Data are Used by EPA/OECA
The data from completed CCDS forms are entered into OECA's Enforcement Docket System by
each of the EPA regional offices. The data are used for the following annual reports:
Fiscal Year RECAP Measures of Success Management Report;
Fiscal Year Press Advisory; and
Fiscal Year Enforcement and Compliance Assurance Annual Report.
These reports have the following purpose and uses:
Provide data to evaluate compliance with the Government Performance and
Results Act (GPRA) whereby government agencies are required to assess program
performance. In the National Performance Measures Strategy for EPA's
Enforcement and Compliance Assurance Program, implementation of Goal 9
(credible deterrent to pollution and greater compliance with the law) includes
developing measurements of actual outcomes (e.g., the environmental impact of
an enforcement action).
Provide input for resource and funding decisions which are made to optimize
environmental benefits.
Allow program managers to justify compliance and enforcement activities by
documenting environmental improvements.
OECA's emphasis on the environmental benefits of its compliance and enforcement activities is
growing and OECA needs to be able to assess the impact and benefit to the environment from
these actions. The data collected on the CCDS is key to achieving this goal and therefore
improving the quality of the CCDS data is imperative.
1.3 How This Document Is Organized
This training booklet is organized to present the overall CCDS process, including Quality
Assurance/Quality Control (QA/QC; Section 2.0), guidance on completing the form (Section
3.0), and general guidance on estimating pollutant reductions resulting from enforcement actions
(Section 4.0). Sections 5.0 through 7.0 provide media-specific guidance and examples for
estimating pollutant reductions. Section 8.0 presents a summary of unit conversions for use in
estimating pollutant reductions and Section 9.0 presents look up tables for use in some of the
water and air examples.
OECA/OC/IUTB 1-2
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2.0 QUALITY ASSURANCE/QUALITY CONTROL FOR THE CCDS PROCESS
This section provides a process for assessing the quality of estimated pollutant reductions;
reconciling inaccurate, incomplete, and inconsistent data entries; and facilitating Regional review
of completed CCDS forms. The CCDS review methodology includes an independent review of
the CCDS form and the use of two checklists to provide a consistent and documentable QA/QC
program. Regions need to ensure that a data quality review process is implemented and while it
may differ in specific detail, it needs to address similar principles of data review and correction.
The CCDS completion process involves the attorney and/or program staff who provide the case
information, the reviewers of the form, and the Docket data entry staff. Once a case file is
received, the CCDS must be completed and transferred to Docket staff in a timely manner. The
basic steps in the CCDS QA/QC process are:
1. Complete the CCDS form;
2. Review key data on the form;
3. Reconcile inconsistencies and incomplete entries as needed; and
4. Enter CCDS data into the Docket.
2.1 Completing the Form
The CCDS contains information about the case including facility information, reasons for the
enforcement action/order, costs/penalties associated with the action/order, and the resulting
environmental benefits. Sections 3.0 through 9.0 of this training booklet provide guidance on
completing this form. A smaller condensed version of this document, entitled Case Conclusion
Data Sheet Quick Guide can be obtained from:
Ms. Donna Inman
U.S. EPA Headquarters (Mailcode 2222A)
OECA/OC/IUTB
1200 Pennsylvania Ave., N.W.
Washington, D.C. 20004
(202)564-2511
Fax (202) 564-0028
Inman.donna@epa.gov
OECA/OC/IUTB
2-1
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2.2 Review of the CCDS Form
It is important that the completed CCDS be reviewed by another program staff member. Key
information may be mis-reported, or not reported at all. An independent reviewer can often spot
problems or omissions by reviewing the form. EPA has prepared two checklists to facilitate this
review. One is for a completeness check and the second is for a check on pollutant reduction
calculations. These checklists are discussed below.
Figure 2-1 presents a checklist to use for a completeness review. The reviewer indicates that the
proper information has been provided on the CCDS by completing the last column in Figure 2-1.
This checklist also has a sign-off table at the top for tracking the status of the CCDS form and its
review. Each person signs and dates this box when they have completed their tasks or when the
form is transferred to the next person. A reviewer should not sign off on the form until all issues
have been resolved to his/her satisfaction. The end of the checklist includes a yes/no question to
identify if the CCDS needs to be returned to the person who completed it because key fields are
blank, with no explanation as to why. It is important to note in Figure 2-1 that several of the
questions that are considered "key" for the purpose of the CCDS program are not required
fields for Docket data entry, thus if these questions are left blank, incomplete CCDS
information would be recorded for the case.
Generally, reporting errors and/or inconsistencies are most common when pollutant reductions
are being reported. If pollutant reductions/eliminations are reported in CCDS Question 19 and/or
24, the reviewer should use Figure 2-2 to verify that these are correctly reported. The reviewer
should evaluate the case file, case summary, or referral transmission memo that should
accompany the CCDS, including the calculation sheets used to quantify environmental benefits.
If sufficient information is not provided, the reviewer should return the CCDS to the person who
completed it.
EPA recommends that all case conclusion data sheets be reviewed for completeness using the
Figure 2-1 checklist, or an equivalent written process, and that all forms that require a pollutant
reduction calculation be reviewed using the Figure 2-2 checklist. EPA estimates that about 30 to
40 percent of concluded enforcement actions require a pollutant reduction calculation.
OECA/OC/IUTB 2-2
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Figure 2-1. CCDS Completion Checklist
Docket Number
CCDS Sign Off
CCDS Completed By:
CCDS Review Completed By:
CCDS Returned for Problem Resolution To:
Yes N/A
CCDS Docket Entry Completed By:
Name of Person
Date
CCDS Field
Are all questions required for Docket entry complete?
Includes questions 1, 3, 4a (if civil judicial case), 4b, 5, 8, 9, 10, 11, 12,
13, 14, and 16
If not, which questions are not complete?
Are all questions key for the CCDS program complete?
Includes questions 7, 17, 19 (if action from column 1 of Q. 17 is
checked), 20, and 24 (if Q.20(b) or 20(c) is checked)?
If not, which questions are not complete?
Completed
(Y,N)
Form Complete
Revision(s) Required / /
Indicate Problem (s) / missing item(s):
OECA/OC/IUTB
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Figure 2-2. CCDS Calculation Checklist
Docket Number
CCDS Question ft/Description
Completed
(Y, N, N/A)*
Reviewer Comments
General
Do statutes violated (Q. 5) correspond with the multi-media
check (Q. 8)?
Q. 17 Injunctive Relief and Other Compliance Activities
(Non-SEP Related)
Are any Q. 17, Column 1 actions (Actions That Result in
Pollutant Reduction/Elimination) checked?
If yes, is corresponding information presented in Question
19?
Are valid pollutant names provided?
Are reduction/elimination amounts provided in acceptable
units for the media affected?
Is the affected media indicated?
Does the affected media correspond to the statutes violated
and the physical actions checked?
Are calculation sheets included in the review package?
Can you verify that the estimation methods are valid?
Can you replicate the calculations?
Q. 20 Supplemental Environmental Projects (SEPs)
Are any of the following categories checked?
- Pollution prevention
- Pollution reduction
Tyes, is corresponding information presented in Question
24?
Are valid pollutant names provided?
Are reduction/elimination amounts provided in acceptable
units for the media affected?
s the affected media indicated?
)oes the affected media correspond to the statutes violated
and the physical actions checked?
Are calculation sheets included in the review package?
Can you verify that the estimation methods are valid?
Can you replicate the calculations?
* N/A = Not Applicable
OECA/OC/1UTB
2-4
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2.3 Reconciliation of Inconsistent and Incomplete Forms
As noted above, the reviewer is responsible for verifying that the CCDS is complete and contains
accurate pollutant reduction data. If key fields are blank, calculations are in error, or calculations
cannot be verified, then the form should be returned to the originator for corrections. Many of the
key fields included in the checklists for this manual are not required Docket fields; therefore, if
the information is not included on the CCDS, then the Docket system will not prompt the data
entry staff for its inclusion. An incomplete or inaccurate form should not be entered into the
Docket system so it is imperative that gaps are filled and problems are corrected prior to
transferring the form to the Docket data entry staff.
2.4 CCDS Data Entry into DOCKET
Each EPA regional office has staff responsible for entry of the CCDS data into the EPA
DOCKET system. The Docket database has been designed with various data entry edit checks to
help insure proper data entry. In addition, EPA has developed an Enforcement DOCKET system
user's manual to support these staff in proper data entry. The user's manual, entitled
Enforcement DOCKET User's Manual can be obtained from:
Mr. Merle Miller
U.S. EPA Headquarters (Mailcode 2222A)
OECA/OC/DSIMB
1200 Pennsylvania Ave., N.W.
Washington, D.C. 20004
(202)564-4114
miller.merle@epa.gov
OECA/OC/IUTB 2-5
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3.0 CCDS FORM AND INSTRUCTIONS
This section provides a general discussion of the CCDS form (Section 3.1) and question-specific
instructions (Section 3.2).
3.1 The Revised CCDS Form
Figure 3-1 presents the revised CCDS form (Sept. 2000 version). The CCDS form has been
revised to reorganize questions 1-16 into categories that are more consistent with the Docket
system data entry screens and to clarify questions 17 and 20 regarding when pollutant
reduction/elimination estimates are required. The CCDS form is organized into the following
categories:
Case Information (Questions 1-10);
Facility Information (Questions 11-14);
Case Conclusion Information (Questions 15-16);
Case Conclusion - Compliance Action (Questions 17 -19);
Case Conclusion - Supplemental Environmental Project (SEP) Information
(Questions 20 - 24);
Case Conclusion - Penalty Information (Questions 25 - 26); and
Case Conclusion - Cost Recovery (Question 27).
OECA/OC/IUTB 3-1
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Figure 3-1
September 2000 Case Conclusion Data Sheet Name .
Phone
A. OASF. INFORMATION: Date
1. Case name:
2. Enforcement DOCKET System #:
3. Court Docket/Regional Hearing Clerk Administrative Docket #:
4(a) EPA Lead Attorney:
4(b) EPA Program Contact:
5. Statute(s) and Section(s) violated (Not authorizing section or CFR):_
6. Authorizing section for administrative actions: /_
7. Administrative action date: Issued/Filed Final Order
-OR- Civil Judicial action date: Settlement Lodged _Settlement Entered_
8. Was this a multi-media action? Yes _ No
Check all that apply/make this action multi-media: inspection complaint settlement SEP
9. Was the Agency activity taken in response to Environmental Justice concerns? Yes No
Check all that apply: Low Income Minority Population Low Income&Mlnority Population Other
10. If this action was taken as part of an FY2000/2001 MOA Priority Activity, the SIC code should be entered on the Docket
Facility Record Screen and, where necessary, on the Docket Violation Information Screen using the appropriate code noted in
brackets. (See Section One of RECAP for full list of MOA Measures and the DOCKET Data Element Dictionary for additional
violation type Definitions). Please circle the appropriate SIC Code and/or check the appropriate MOA priority activity.
Wet Weather: CSO (CSO) ; CAFO (AFLOT) ; Stormwater (STORM) ; Sanitary Sewer Overflow (SSO)
Petroleum Refining: - Refinery Fuel Gas (REFFG) ; LDAR (LDAR) ; Benzene Waste (BENZW)
Iran and Steel (SIC Code 3312,3315,3316,3317): Unregulated wastes (UNREG) ;
KO61 Noncompliance (RKOGI)
Primary NonFerrous Metals (SIC Code: 3331,3334,3339); Bevil enforcement actions (BEVIL) ;
Chemical Sector (SIC 2869, 2899):
SDWA Mierohial: TCR violations (PWTCR) ; SWTR violations (SWTR)
Metal Services (SIC Code: 3471,3479)
RCRA: Permit Evaders (RCRPE) ; Misidentified wastes (RMISWT)
CAA Air Toxics and NSR/PSD: (NSR) ; (PSD) Coal-Fired Power Plant (SIC 4911)
B. FACILITY INFORMATION: (IF MORE FACILITIES, ATTACH ADDITIONAL PAGES)
11. Facility Name
12. Facility Address: Street: City: St: Zip:.
13(a) Primary 4-digit SIC-code , b) Other 4-digit SIC-codes , , , _
14. Facility Identification (enter information on Docket Screen 13)
(a) EPA Program ID # for the facility
(b) EPA-FLA # (if Program ID not available or applicable)
C. CASF. CONCLUSION INFORMATION;
15. Was Alternative Dispute Resolution used in this action? Yes No
16. Action Type
(a) Consent decree or court order resolving a civil judicial action
_ (b) Administrative Penalty Order (with/without injunctive relief)
(c) Superfund administrative cost recovery agreement
(d) Federal facility compliance agreement (not incl. RCRA matters)
(e) Field citation
(0 Administrative Compliance Orders
(g) Notice of Determination
OECA/OC/IUTB 3-2
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D. CASE CONCLUSION-COMPLIANCE ACTION:
Injunctive Relief and Other Compliance Activities(Non-SEP Related) (APO's without injunctive relief [16(b)] and Superfund
Administrative Cost Recovery Agreements (16(c)] SHOULD SKIP THIS SECTION)
17. What action did violator accomplish prior to receipt of settlement/order or will take to return to compliance or meet additional
requirements? This may be due to settlement/order requirements or otherwise required by statute or regulation. Include actions
completed prior to the final settlement/order and actions to be taken by violator to return to compliance or meet additional
requirements. Where separate penalty and/or compliance orders are issued in connection w/same violations(s), report the
following information for only one of those orders. Select response(s) from the following:
Actions That Result in
Pollutant Reduction/Elimination
(COMPLETE 0.191
Actions That Result in
Pollutant Identification
(IDENTIFY POLL. IN O.19)
_Use Reduction Storage Change
..Industrial Process Change Labeling/Manifesting
_Emissions/Discharge Change Permit Application
(install/modify controls)
_Disposal Change
.Remediation
Removal
~RD/RA
Actions That Do Not Result in
Pollutant Reduction/Elimination
(SKIP 0.19)
Testing
Auditing
Monitoring/Sampling
Recordkeeping
Reporting
Information Letter Response
Training
Provide Site Access
Site Assessment
Restoration
RI/FS
Environmental Management Reviews
Other (please describe).
18. Cost of actions described in item #17. (Actual cost data supplied by violator is preferred figure.)
Column 1 actions: $ Column 2 and 3 actions: S
19. Quantitative environmental impact of actions described in item #17:
REDUCTIONS/ELIMINATIONS:
Pollutant
Avg. Annual
Amount
Units
Destination Media
(e.g., air, water, land)
E. CASE CONCLUSION - SUPPLEMENTAL ENVIRONMENTAL PROJECT (SEP) INFORMATION:
20. Categories of SEP(s) (Check all appropriate categories; if none proceed to #25)
_(a) Public Health
(b) Pollution Prevention (Complete Q. 24)
(1) equipment/technology modifications
(2) process/procedure modification
(3) product reformulation/redesign
(4) raw materials substitution
(5) improved housekeeping/O&M/training/inventory-control
(6) in-process recycling
(7) energy efficiency/conservation
(c) Pollution Reduction (Complete Q. 24)
(d) Environmental Restoration and Protection
(e) Assessments and Audits
(f) Environmental Compliance Promotion
(g) Emergency Planning and Preparedness
(h) Other SEP category (specify)
OECA/OC/IUTB
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21. SEP description
22. Cost of SEP (Cost calculated by the Project Model is preferred): $
23. Is Environmental Justice addressed by SEP? Yes No
24. Quantitative environmental impact of SEP: pollutants and/or chemicals and/or waste-streams,
and amount of reductions/eliminations (e.g., emissions/discharges)
Pollutant Avg. Annual Units Destination Media
Amount (e.g., air, water, land)
F. CASE CONCLUSION - PENALTY (IF THERE IS NO PENALTY, ENTER 0 AND PROCEED TO #27)
2S.(a) Assessed Penalty $
2S.(b) (if shared) Federal share $
2S.(c) (if shared) State or Local share $
26. For multi-media actions, Federal Penalty Assessed by statute:
Statute Amount
$
$
$
G. CASE CONCLUSION - COST RECOVERY
27. Amount cost recovery awarded:
EPA: $
State/Local Government $
Other: S
PLEASE ATTACH ADDITIONAL CONCLUSION SHEETS OR SHEETS OF PAPER TO PROVIDE INFORMATION WHIC1
DOES NOT FIT ON INITIAL CASE CONCLUSION DATA SHEET.
OECA/OC/IUTB 3-4
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One important aspect of the CCDS is the quantification of pollutant reductions that occur as a
result of enforcement activities. These reductions are quantified using the following questions on
the form:
Injunctive Relief and Other Compliance Activities (Non-SEP Related) (Q. 17);
The Quantitative Environmental Impacts of these activities (Q. 19);
Categories of Supplemental Environmental Projects (SEP(s)) (Q. 20); and
Quantitative Environmental Impacts of these SEP activities (Q. 24).
Environmental improvements are not only associated with cases and compliance actions, but
SEPs as well. Not all improvement actions have quantifiable benefits. The actions listed on
Question 17 are divided into three groups as shown in Table 3-1 below. Actions checked in the
first column should have pollutant reductions quantified in Question 19. Actions checked in the
second column should have resulted in identification of a pollutant(s) at the facility as part of the
action or order that should then be identified in Question 19. Actions checked in the third
column do not usually result hi quantifiable pollutant reductions and for these activities Question
19 should be skipped.
Table 3-1. Question 17 Actions
Actions That Result in Pollutant
Reduction/Elimination
Actions That Ensure Proper
Management of Pollutants
Actions That Do Not Result in
Pollutant Reduction/Elimination
Use Reduction
Storage Change
Testing
Industrial Process Change
Labeling/Manifesting
Auditing
Emissions/Discharge Change
(install or modify controls)
Permit Application
Monitoring/Sampling
Disposal Change
Remediation
Removal
Remedial Design/Remedial
Assessment (RD/RA)
Recordkeeping
Reporting
Information Letter Response
Training
Provide Site Access
Site Assessment
Remedial Investigation/Feasibility
Study (RI/FS)
Environmental Management
Reviews
Restoration
OECA/OC/IUTB
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Actions where quantitative benefits can be tracked are changes in emissions, discharges, and
disposal practices. These actions include pollution prevention activities that reduce the use,
production, or generation of toxic or hazardous materials and other wastes. This includes any
practice that reduces the amount of a hazardous substance, pollutant, or contaminant entering any
waste stream or otherwise being released into the environment prior to recycling, treatment, or
disposal.
Environmental restoration and protection activities are also tracked. In most cases,
environmental restoration actions will not result in pollutant reduction. However, it is important
to estimate pollutant reductions if these types of projects go beyond simply repairing the damage
caused by a violation to enhance the condition of the environment adversely affected.
OECA also tracks the environmental benefits that result from SEPs. Table 3-2 lists the key SEP
actions (from CCDS Question 20) and identifies those actions that result in quantifiable
environmental benefits.
Table 3-2. Key SEP Actions to Track
Public Health
Pollution Prevention*
Pollution Reduction4
Environmental Restoration and Protection
Assessments and Audits
Environmental Compliance Promotion
Emergency Planning and Preparedness
* Items where benefits can (and should) be quantified.
Once you have determined that an enforcement action has resulted in a quantifiable pollutant
reduction, you need to complete Question 19 and/or Question 24 of the CCDS. You must
correctly identify the pollutant(s) affected, quantify the amount of contamination that has been
reduced or eliminated, and identify the affected media.
OECA/OC/IUTB 3-6
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3.2 Form Instructions
Table 3-3 provides instructions for completing the CCDS form. This table is followed by Tables
3-4 through 3-9 which provide information on specific valid inputs for the form.
Table 3-3. CCDS Form Instructions
Question #
Name
Phone
Date
1
2
3
4(a)
4(b)
5
6
7
8
9
10
11
Instructions
Name of the person responsible for filling out the CCDS. List the last name followed by the first initial.
Telephone number of the person filling out the CCDS.
Date the person filled out the CCDS. Please list as mm/dd/yy
Enter the case name exactly as it appears in the caption of the enforcement instrument.
This is the Enforcement Docket System case number which is assigned by an EPA Docket analyst as the
case is opened in Docket, leave this blank.
If this is a judicial case, enter the official Court Docket Number assigned by the U.S. District court for
civil cases; if this is an administrative case, enter the Regional Administrative Docket number assigned
by the Regional Hearing Clerk. These numbers are not the same as the EPA Enforcement Docket
System case number in Question 2. The correct numbers to be entered in Question 3 will usually be
found to the right of the caption, on the first page of the enforcement instrument.
For Regional cases, this is the lead attorney; for HQ cases, this person is assigned by the Office of
Regulatory Enforcement. List the last name followed by the first initial. If this is an administrative
action that does not have an assigned attorney, leave blank.
This is the EPA Program office technical contact assigned to the case. List the last name followed by the
first initial.
Enter the acronym for the law violated (CWA, CAA, RCRA, etc) before the slash, followed by the
statutory section number for the section that was violated. Pick the appropriate section from Table 3-4
below, (e.g., CAA/1 1 1 ; RCRA/3004)
Do not enter the section number of the statutory section that authorizes EPA to bring the case (e.g.,
CAA/3 13; RCRA 3008a). Do not use US Code or CFR citations in this field.
Enter the section number of the statutory section that authorizes EPA to bring the enforcement action.
For example, nearly all Clean Air Act cases involving SOP, NSPS, or NESHAPs violations are brought
pursuant to Section 1 13 of the CAA; all administrative penalty cases for RCRA Subtitle C violations are
brought pursuant to Section 3008a of RCRA; etc.
The Issued/Filed date is the date the Complaint or Administrative Order was signed by the appropriate
EPA official and issued to the respondent. The Final Order date is the date the compliance order
becomes effective without further administrative appeal. For unappealed or unilateral administrative
compliance orders, the final date is the signature date of the EPA issuing official. For two-step orders,
both issue date and final date should be provided on the form, even if the issue and final date are the
same. Enter as mm/dd/yy.
This asks what action or actions have triggered the responsible office to consider the case as multi-
media. For example, a settlement addressing a violation in one program includes issues covered under
other programs.
This indicates whether the responsible office developed the case as an environmental justice action.
This question is to identify if the action was taken as part of a MOA priority sector or media activity.
This is the full name of the facility.
OECA/OC/1UTB
3-7
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Table 3-3. CCDS Form Instructions (Continued)
Question #
13(a)
13(b)
14(a)
14(b)
15
16
17
18
19
. 20
21,22,23
24
25(a)
26,27
Instructions
The Standard Industrial Classification Code (SIC) reflects the economic activities at the facility where
the violation occurred. The primary SIC describes the predominant economic activity at the facility.
This line may be left blank if the SIC code is unknown or is not applicable (e.g., an abandoned
hazardous waste site). The SIC codes may be obtained from the Docket Facility System if a code was
entered when the Docket record in the facility system was created.
The other secondary codes reflect SIC classifications for additional economic activities at the facility.
Enter the EPA Program ID number for the facility involved. E.g., the CERCLIS number for Superfund
facilities; the RCRIS number for RCRA facilities; the PCS number for NPDES facilities. For assistance
in finding a Program ID # go to www.epa.gov/enviro and access the Query - Facility Information
button. Query the system on facility name and address to pull a report with all air, water, and RCRA
numbers.
This number can be found on the Envirofacts web site at www.epa.gov/enviro.
Alternative Dispute Resolution (ADR) is a procedure, such as mediation or arbitration, used by EPA in
resolving differences with companies, groups, and/or individuals over enforcement-related issues.
Check the appropriate action type from the list on the CCDS form.
Check only the actions that apply to the settlement or order. Table 3-5 below provides definitions for
the different violator actions. If an action is checked from the first column then Question 19 should be
completed including pollutants, amount, units, and media. If an action is checked from the second
column then enter the pollutants identified by the case in Question 19. If only actions from the third
column are checked, then it is unlikely that pollutant reductions/eliminations apply and you can SKIP
Question 19.
Column 1 Actions include anything from the first column of Question 17. Columns 2 and 3 Actions
include anything from the second or third columns of Question 17. Actual cost data supplied by the
violator are preferred. For Superfund actions, this should be the estimated value of Responsible Party
work to be performed as included in the ROD or other documents.
Complete this question if you have checked any actions from the first and/or second column of Question
17. If you checked items from the first column calculate pollutant reduction/eliminations as appropriate
(See Section 4.0).
Table 3-6 lists common pollutants with the preferred nomenclature for the Docket system.
The destination media is the media where the pollutant(s) or waste were emitted/discharged.
Table 3-7 lists the valid entries possible for this column.
Do include units with any pollutant amount provided. Docket system preferred units are "pounds".
Table 3-8 lists the valid entries possible for mis column.
Check only the actions that apply to the SEP. Table 3-9 provides definitions for the different SEP
actions. If 20(b) or 20(c) is checked, Question 24 should be completed including pollutants, amount,
units, and media. If only actions that do not result in a pollutant reduction/elimination are checked, then
SKIP Question 24.
Self Explanatory
Complete this question if you have checked 20(b) or 20(c). See instructions under Question 19.
Do not include the dollar value of any SEP. Include only the case amount to be paid by a certain date.
Self Explanatory '"
OECA/OC/IUTB
3-8
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Table 3-4. Statutory Section Numbers for Laws Violated, Question 5
Law
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
Section
Other
110
111
112
112R
112R9
113A
114
118D
165
173
Other
103A
103D2
104E2
104E3
104E4
104E5
106A
107 A
107C3
Description
Other violations not covered
elsewhere
SIP Standards
New Source Performance
Standards (NSPS)
NESHAPS, except 112(r)
Gnrl. Duty & Ace. Release
Prevention
violation of 1 12(r)(9) Order
Violation of Existing
Administrative Order
Recordkeeping, Insp., Info.
Request
Fed Facility Motor Vehicles
Prevention of Significant
Deterioration (PSD)
New Source Review Permit
Requirements
Other Violations Not Covered
Elsewhere
Notification of Haz. RQ
Release
Destruction of Records
Info Access
Entry Access
Inspection and Samples
Violation of 104(e)
Compliance Order
Imm. & Sub. Endngrmnt.
Order
Cost Recovery
Treble Damages
Law
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CAA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
CERCLA
Section
203
211
213
219
303
412
502
608
609
610
611
107L
107M
108
109A5
120E
122D3
122E3B
122G
122H
Description
Prohibited Acts: Mobile Sources
Fuel Regulation
Non-road Engines & Vehicles
Urban Bus Standards
Emergency Powers
Acid Rain Requirements
Operating Permits (Title V)
CFC Recycling/Emissions
Reduction
MVACs (CFCs)
Non-essential CFC Products
CFC Labeling
Lien
Maritime Lien
Violation of Financial Resp.
Violation of 109(a)(5) Subpoena
Fed. Fac. Interagency
Agreement
Violation of Existing AO or CD
Violation of 122(e)(3)(B)
Subpoena
Admin. De Minimis Settlement
Admin. Cost Recovery Settmnt.
OECA/OC/IUTB
3-9
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Table 3-4. Statutory Section Numbers for Laws Violated, Question 5 (Continued)
Law
CWA
CWA
CWA
CWA
CWA
CWA
|| CWA
EPCRA
EPCRA
EPCRA
EPCRA
EPCRA
II FIFRA
1 FIFRA
|| FIFRA
1 FIFRA
| FIFRA
FIFRA
FIFRA
FIFRA
| FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
MPRSA
Section
Other
301
307
308
309A3
311B
311E
Other
302
303
304
311
Other
12A1A
12A1B
12A1C
12A1D
12A1E
12A1F
12A2A
12A2B
12A2C
12A2D
12A2E
12A2F
12A2G
101
Description
Other Violations Not Covered
Elsewhere
NPDES Discharge w/o
Permit/Permit Violations
Tox & Pret. Eff. Stds.
Records, Entry, Info. Req.
Violation of Existing AO
Oil & Haz Substances Dis
Oil Imm & Sub Endngrmnt
Other Violations Not Covered
Elsewhere
List Presence of
Substances/Notify
Emergency Response Plans
Emergency Release Notificat.
Material Safety Data Sheets
Other Violations Not Covered
Elsewhere
Unregistered Pesticide
Claim Difference
Composition Difference
Colored/Discolored
Adulterated/Misbranded
Device Misbranded
Label Alter/Detach
Refuse Records, Repts, Entry
False guaranty
Conf. Inf. Reveal
Advertise w/o Classification
Restricted Usage
Misuse
Law
CWA
CWA
CWA
CWA
CWA
CWA
EPCRA
EPCRA
EPCRA
EPCRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
FIFRA
Prohibited Acts |
Section
311F
311J
318
404
405
504
312
313
322
323
12A2H
12A2I
12A2J
12A2K
12A2L
12A2M
12A2N
12A2O
12A2P
12A2Q
12A2R
12A2S
9
Description
Oil Removal Cost Recovery
SPCC/FRP Violations
Aquaculrure
Dredge/Fill Permits
Sewage Sludge Disposal
Emergency Powers
Inventory of Chemicals
Toxic Chemical Release
Reporting (TRI)
Trade Secrets
Provide Info to Health Prof.
Contrary Use - Experimental
Violate SSUR Order
Violate Suspension Order
Violate Cancellation Order
Establishment Registration
Falsify applic., inf., etc
Failure to File Reports
Add/Remove Substance
Test pesticide on humans
Falsify testing info.
Falsify registration data
Violate Regs Under 3(a) or 19
Establishment Inspection
OECA/OC/IUTB
3-10
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Table 3-4. Statutory Section Numbers for Laws Violated, Question 5 (Continued)
Law
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
SDWA
SDWA
SDWA
SDWA
SDWA
SDWA
SDWA
Section
Other
3002
3003
3004
3005
3007
3008A
3008H
3010
3013
Other
1412
1414C
1414G
1415
1416
1417
Description
Other Violations Not Covered
Elsewhere
Haz Waste Generator Regs
Haz Waste Transporter Regs
TSD Standards
TSD Permit Requirements
Recordkeeping, Inspection,
Information Request
Violation of Existing
Compliance Order
Int. Status Corr. Act. Order
Notification of HW Activity
Monitoring, Analysis, Testing
Order
Other Violations Not Covered
Elsewhere
Natl Drinking Water Regs
PWS - Notice to Persons
Served
PWS-Viol. of!414(g)AO
Variances
Exemptions
Lead Pipe, Solder & Flux
Law
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
RCRA
SDWA
SDWA
SDWA
SDWA
SDWA
SDWA
SDWA
Section
3014
3017
3020
3023
7003
9002
9003
9005
9006A
1421
1423C
1431
1432
1441
1445
1463
Description
Recycled Oil
Export of Haz Waste
Undergmd Inj. of Haz Waste
HW Discharge to Fed-Owned
TW
Imminent Hazard Order
UST Notification Requirements
UST Release Detect, Prev, Con-
Inspection, Monitoring, Testing,
Corrections
UST Compliance Order
UIC Regulations
UlC-Viol. of!423(c)AO
Emergency Powers
Tampering with a PWS
Adequate Supplies of Chems
Recordkeeping & Access
Lead in Water Coolers
OECA/OC/IUTB
3-11
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Table 3-4. Statutory Section Numbers for Laws Violated, Question 5 (Continued)
Law
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
MRBMA
MRJBMA
MRBMA
MRBMA
MRBMA
Section
Other
4
5B
5F
6A
6E
7
8
11
12
13
15-2
Other
5A
5F
6
103
Description | Law
Other Violations Not Covered
Elsewhere
Testing Requirements
Pre-manufacture Notice
Violation of Unreasonable
Risk AO
Haz Chems (not otherwise
specified)
PCBs
Imminent Hazard
Reporting & Records Relent.
Inspections & Subpoenas
Exports
Imports
Knowing Commercial Use
Other Violations Not Covered
Elsewhere
Violation of MRBMA 5(a)
AO
Violation of 5(0 Subpoena
Reports, Records, Access
Rechargeable Batteries &
Labeling
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
TSCA
MRBMA
MRBMA
MRBMA
MRBMA
MRBMA
Section
16A4
203
205
206
207A2
207A5
208
215
402
406A
406B
104
203
204
205
206
Description
Failure to Pay Civil Penalty
School Asbestos Regs
Plan Submission -LEA
Asbestos - Contractor/Lab Cert.
False Info on Asbestos
Inspection
False Asb. Info under 205(d)
Asbestos Emergency Auth.
Asbestos Worker Protection
Pb Paint Training & Cert.
HUD 1018 Disclosure Rule
Renovation/Lead Haz Pamphlet
Battery Handling (enforced
under RCRA)
Alkaline-Manganese Batteries
Zinc-Carbon Batteries
Button Cell Mercuric Oxide
Batteries
Non-button Cell Mercuric Oxide
Batteries
OECA/OC/IUTB
3-12
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Table 3-5. Definitions for Question 17
Compliance Action
Definition
Actions that Reduce/Eliminate Pollutants
Use Reduction
Industrial Process Change
Emissions/Discharge Change
Disposal Change
Remediation
Removal
RD/RA
This category covers reduced use of a substance within a process and
reduced distribution of substances in commerce. E.g., ceasing sales to the
general public of a restricted use pesticide.
This category includes process-based facility-specific activities relating
to changes in industrial processes and procedures other than pollution
control equipment. E.g., upgrading of equipment or processes to reduce
the emission of a pollutant at the point of its generation.
This category includes activities involving emissions and discharges of
pollutants. E.g., elimination of the discharge of a pollutant to surface
water.
This category includes activities involving disposal of waste and spent
products. E.g., disposal of hazardous waste in an approved landfill.
This category covers Remediation activities of environmental
contamination. E.g., cleanup of an oil spill.
This category covers expedited cleanup of wastes or contaminated
material to address acute threats to humans, environment, or property.
E.g., cleanup of heavily contaminated soil and abandoned waste drums
adjacent to a school.
This category covers designing and implementing a protracted cleanup of
a contaminated site or sites under Superfund.
Actions that Ensure Proper Management of Pollutants
Storage Change
Labeling/Manifesting
Permit Application
This category includes activities involving storage of waste and spent
products. E.g., modifications of the storage for used oil at a facility.
This category includes types of labeling and manifesting. E.g., labeling
pesticide containers with instructions for safe use and handling or
manifesting hazardous RCRA wastes.
This category includes participation in required permit process by an
unpermitted facility. E.g., an inspected facility storing wastes onsite
without notification or permit.
Actions that Do Not Reduce/Eliminate Pollutants
Testing
Auditing
This category includes generating data (as opposed to reporting existing
data) from actions, including laboratory testing of compounds. E.g.,
toxicity testing of commercial chemicals.
This category involves cases where environmental auditing is included
with the settlement/order as a means for identifying problems and
reducing the likelihood of similar problems recurring.
OECA/OC/IUTB
3-13
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Table 3-5. Definitions for Question 17 (Continued)
Compliance Action
Monitoring/Sampling
Recordkeeping
Reporting
Information Letter Response
Training
Provide Site Access
Site Assessment
Restoration
RI/FS
Environmental Management
leviews
Definition
This category includes monitoring and sampling activities performed to
assess pollutant levels in different media. E.g., effluent monitoring to
ensure hazardous substances are not discharged at unacceptable levels.
This category includes types of recordkeeping ranging from records of
sampling and analysis of hazardous waste to records of inspections and
maintenance, e.g., underground storage tank monitoring records.
This category includes reporting required by regulations or permits, e.g.,
DMR reports required under the NPDES regulations.
This category includes compelling response by a recipient to a formal
request for information relating to an uncontrolled hazardous waste site.
This category includes worker training programs. E.g., pesticide or
asbestos removal workers being trained in proper handling techniques.
This category includes compelling facility/site owners to admit EPA
officials entry to inspect or assess hazards. E.g., gaining entrance to a
fenced, locked storage area containing potential leaking drums where
admittance has been denied.
This category includes collecting site samples and data to assess the
severity of contamination hazard. E.g., a site/facility where indications
suggest an extensive cleanup may be required.
This category involves returning a developed or degraded location to its
previous undeveloped state or which mimics natural characteristics.
E.g., creation of wetland area in compensation for an area displaced or
developed.
This category covers investigation and study of requirements for
extensive cleanup of a hazardous waste site. E.g., evaluating where
buried waste may have migrated into adjoining watercourses.
This category covers developing a management system which includes
organizational structure, planning activities, responsibilities, practices,
procedures, processes and resources for developing, implementing,
achieving, reviewing, and maintaining the environmental policy.
OECA/OC/IUTB
3-14
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Table 3-6. Preferred Nomenclature for Common Pollutants - Questions 19 and 24
Preferred Nomenclature
Ammonia
BODS
COD
DO
Hexavalent Chromium
MEK
MIBK
NOx
Oil and Grease
PAH
PCB
PM
S02
TCDD
TCDF
THF
TPH
TSS
Total Coliform
VOC
Other names for the Same Pollutant1
Ammonia Nitrogen, NH3-N, Ammonia as N
Biochemical Oxygen Demand, BOD
Chemical Oxygen Demand
Dissolved Oxygen
Chromium - VI, Chromium/Hexavalent Chromium
Methyl Ethyl Ketone
Methyl Isobutyl Ketone
Nitrogen Oxides
Oil, Grease
Polycyclic Aromatic Hydrocarbons
PCB's
Paniculate Matter
Sulfur Dioxide
2,3,7,8 - TCDD, Dioxins
2,3,7,9 - TCDF, Furans
Tetrahydrofuran
Total Petroleum Hydrocarbon
Total Suspended Solids, SS, Settleable Solids
Coliform, Coliform Bacteria, Fecal Coliform
Volatile Organic Chemical
1 For information on other names for the same pollutant and CAS Numbers for specific pollutants see
http://oaspub.epa.gov/crs/chemqry$startup
OECA/OC/IUTB
3-15
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Table 3V7. Question 19 and 24 Entries for "Media"
Air
Drinking Water
Groundwater
Land
Landfill
Liquid
Sediment
Sludge Lagoon
Soil
Surface Water
Water
Wetlands
Table 3-8. Question 19 and 24 Entries for "Units"
Units
CBI
CUFT
CUM
CUYD
DRUMS
GAL
G
KG
L
Definition
Confidential Business Information
Cubic Feet
Cubic Meters
Cubic Yard
Drums (55 gallons)
Gallons
Grams
Kilograms
Liters
Units
LB
MTON
MG
ML
OZ
PPB
PPM
PPT
TONS
Definition
Pounds
Metric Tons
Milligrams
Milliliters
Ounces
Parts Per Billion
Parts Per Million
Parts Per Trillion
Tons
OECA/OC/IUTB
3-16
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Table 3-9. Definitions for Question 20
SEP Category
Public Health
Pollution Prevention
Pollution Reduction
Environmental Restoration
and Protection
Assessments and Audits
Environmental Compliance
Promotion
Emergency Planning and
Preparedness
Definition
A project which provides diagnostic, preventative, and/or remedial components
of human health care related to the health damage caused by the violation.
A project which reduces the generation of pollution through source reduction. If
the pollutant or waste stream has been generated, pollution prevention is no
longer possible and the waste must be handled by appropriate recycling,
treatment or disposal methods.
A project which results in a decrease in the amount or toxicity of any hazardous
substance, pollutant or contaminant entering a waste stream or otherwise being
released into the environment (e.g, recycling, treatment).
A project which goes beyond repairing the damage caused by the violation to
enhance the condition of the environment adversely affected.
Pollution prevention assessments are systematic, internal reviews of specific
processes and operations designed to identify and provide information about
opportunities to reduce the use, production, and generation of toxic and
hazardous materials and other wastes. Site assessments are investigations of the
condition of the environment at a site, or of the environment impacted by a site,
and/or investigations of threats to human health or the environment relating to a
site. Environmental compliance audits are an independent evaluation of a
defendant/respondent's compliance status with environmental requirements.
A project which involves disseminating information or providing training or
technical support to a regulated party or to some or all members of the
defendant/respondent's economic sector.
A project where a defendant/respondent provides assistance, such as computers
and software, telephone/radio communication systems, chemical emission
detection and inactivation equipment, HAZMAT equipment, or training for first
responders to chemical emergencies, to a responsible state or local planning
entity.
OECA/OC/IUTB
3-17
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4.0 GUIDE FOR POLLUTANT REDUCTION/ELIMINATION CALCULATIONS
This section presents a general overview of when and how to estimate pollutant
reductions/eliminations associated with enforcement actions. Sections 5.0, 6.0 and 7.0 present
the following media-specific examples for water, air, and solid/hazardous wastes, respectively:
Media
Water
Air
Solid/Hazardous
Waste
Example Description
CWA/NPDES
Stormwater Violation for CAFO
Stormwater CSO
SDWA Pollutant Reduction
SOWA Microbial Violation
NOx Reduction at a Petroleum
Refinery under PSD/NSR
SO, and HAP Reduction at a Pulp
and Paper Mill under MACT
Leak Detection And Repair
Asbestos NESHAP
Corrective Action
RCRA UST
Used Oil Management
Section Number
5.1
5.2
5.3
5.4
5.5
6.1
6.2
6.3
6.4
7.1
7.2
7.3
4.1 When Do You Need to Calculate Pollutant Reductions/Eliminations?
When the civil judicial or administrative order requires the respondent to take actions that reduce
or eliminate pollutant releases, then the program office technical lead or lead attorney should
report and estimate of the environmental benefit of those actions in the CCDS Question 19. The
first column of the CCDS Question 17 identifies actions requiring pollutant reduction or
elimination estimates. In addition, if a case includes a SEP incorporating pollution prevention or
pollution reduction, then the environmental benefit of the project should be estimated and
reported in the CCDS Form Question 24.
OECA/OC/IUTB
4-1
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4.2 How Do You Calculate Pollutant Reductions/Eliminations?
The following sections present the basic methodology to use in estimating pollutant reductions or
eliminations and a discussion of the time basis to use in these calculations.
4.2.1 Basic Methodology
To calculate pollutant reductions or eliminations for air, water, or solid waste cases, you need to
use the difference between the current "out of compliance" concentration and the post-action "in
compliance" concentration for each pollutant of concern. This difference is then converted to
mass per time using flow or quantity information from the case. The following steps outline the
general method to follow to estimate a pollutant reduction/elimination.
Step A Determine the average "out of compliance" concentration of each pollutant
(concentrations are usually reported in mg/1, ug/1, or pg/1).
Step B Determine the post-action concentration for each pollutant (this may be a permit
limit, a prescribed action level, or the assumption of complete elimination of the
pollutant if proper disposal/removal actions are required).
Step C Determine average flow or quantity of media impacted.
Step D Determine the incremental concentration by which the pollutant is out of
compliance by subtracting the post-action concentration from the "out of
compliance" concentration.
Incremental Concentration = Out of compliance cone. - Post-action cone.
Step E Determine the incremental loading using flow or quantity information, for example:
Loading (Ibs/day) = Incremental Concentration (mg/L) x Flow (MOD) x 8.34
8.34 (Conversion Factor) = (g/1000mg) x (lb/454g) x (3.78L/gal) x (1E6gal/Mgal)
Step F Report on the CCDS form the total pollutant reduction that will occur during the first
year of post-action compliance.
Pollutant Reduction (Ibs) = Loading (Ibs/day) x Discharge Time (days/year) x 1 year
OECA/OC/IUTB 4-2
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4.2.2 Calculation Basis for Time
In determining pollutant reductions reported on the CCDS, a period of time over which the reduction
credit is taken must be established. EPA anticipates two general scenarios for pollutant reduction
calculations. The first is when a facility implements a one-time action to come into compliance. An
example of this is when a facility installs a source-specific pollutant control device to achieve
compliance. In this case, the pollutant reduction is realized after implementation of the device. The
second scenario is when a facility implements a series of actions to achieve compliance. An example
of this is the recent case against diesel engine manufacturers, where changes will be made over time
as the truck fleet is turned over. Another example would be a staged installation of low-NOx burners
for all combustion sources through a petroleum refinery (such an effort would likely occur over
several years). In this scenario, the pollutant reduction is realized over time as the pollution control
devices are installed.
For the first scenario, the first year of pollutant reductions should be used as the basis for CCDS
pollutant reduction calculations. In this case, EPA would estimate the pollutant reduction as pounds
per unit time (usually hours or days) and then use the facility's discharge or operating schedule to
estimate a total mass of pollutant reduction for one year. This approach provides a consistent
reporting basis.
For the second scenario, estimate the total pollutant reduction over the lifespan of the implementation
project and report an estimated annual "average" reduction once the equipment/change is fully
implemented.
OECA/OC/IUTB 4-3
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5.0 WATER EXAMPLES
The sections below present various pollutant reduction examples for water media. Each section
includes information on the following:
Background;
Input needed to calculate pollutant reductions;
Step-by-step instructions for calculating pollutant reductions; and
Example calculations using specific scenarios.
Section 5.6 presents references and web sites used in developing these examples.
5.1 Clean Water Act/NPDES
5.1.1 Background
The CWA requires point sources discharging to waters of the United States to obtain a National
Pollutant Discharge Elimination System (NPDES) Permit. The NPDES program is implemented
through site-specific permits that may be as stringent as or more stringent than national regulations.
The NPDES program is enforced by comparing actual discharges to the permitted level of pollutant
discharges.
The NPDES program regulates industrial process discharges from direct and indirect dischargers,
municipal sewage treatment plant effluent, and storm water runoff. Direct dischargers discharge
water directly to surface waters while indirect discharges discharge to a publicly owned treatment
works (POTW). Limitations may be set for indirect dischargers to prevent interference with POTW
treatment processes or pass-through of the pollutants to surface waters. EPA's Office of Water,
Office of Science and Technology has set effluent limits for various industries. Information can be
found on their website at www.epa.gov/waterscience/guide. The regulations are listed in 40 CFR
Part 401 through Part 471.
5.1.2 Input Needed to Calculate Pollutant Reductions
The following information is needed to calculate pollutant reductions:
Current or past "out of compliance" discharge concentration (generally in mg/L) or
load (generally in pounds/day)
[This concentration or load may come from the plant's discharge monitoring reports
(DMRs) or from sampling conducted during case development]
Enforceable limits required to bring the facility into compliance
[This concentration or load comes from the facility permit]
Wastewater discharge flow rate
[This information comes from facility monitoring data]
OECA/OC/IUTB 5-1
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5.1.3 Step-by-step Instructions for Calculating Pollutant Reductions
To calculate pollutant reductions for water, use the difference between sampled concentrations and
the permit limit expressed as a concentration. The following steps outline the general method that
should be followed to calculate the pollutant reduction. This method can be used for all pollutants for
which pre-compliance and permit concentrations are known.
Step A Determine the average actual concentration of each pollutant in mg/L.
Step B Determine the enforceable limits for each pollutant in mg/L.
[In cases where both a maximum daily concentration and a monthly average
concentration are given, the pollutant reduction should be calculated using the
monthly average.]
Step C Determine average flow in million gallons per day (MOD).
Step D Determine the concentration by which the pollutant is out of compliance by
subtracting the permit limit from the actual concentration.
Exceeded Concentration (mg/L) = Actual concentration - Permit Limit
Step E Determine the exceeded loading in pounds by using the following formula:
Loading (Ibs/day) =Exceeded Concentration (mg/L) x Flow (MOD) x 8.34
8.34 (Conversion Factor) = (g/lOOOmg) x (lb/454 g) x (3.78L/gal) x (1E6gal/Mgal)
Step F Determine the total pollutant reduction to be reported on the CCDS form.
[Assume pollutant reductions occur over a one-year time period. The number of days
per year that the plant discharges \vastewater should be used. If the discharge time is
not known, the operating time (days/year) for the specific plant should be used. If an
operating time is not known or is not applicable, 365 days/year should be used.]
Pollutant Reduction (Ibs) = Loading (Ibs/day) x Time (days/year) x l year
OECA/OC/IUTB 5-2
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5.1.4 Example Calculations
Example 1: NPDES Permit Violation for Direct Industrial Discharger
The method used to calculate pollutant reductions for a permit violation by an industrial discharger is
similar for all industries. The permit limits (converted to a required concentration using the facility
flow) are compared with pollutant concentrations obtained from sampling. This example calculates a
pollutant reduction from a chemical manufacturing plant but could be used for any industry.
NPDES sampling by the Sunburst Chemical Company indicates that the plant has elevated
concentrations of Biochemical Oxygen Demand (BOD) and Total Suspended Solids (TSS). Under an
enforcement order, the facility is installing additional pollution prevention technologies to bring the
plant into compliance. The average effluent concentrations of BOD and TSS are 100 mg/L and 120
mg/L respectively and the mill's treatment system processes on average 6 Million Gallons per Day
(MOD). The plant's permit specifies a BOD limit of 1,000 pounds/day and a TSS limit of 1,500
pounds/day. The plant discharges 365 days per year.
Step A Actual concentrations:
BOD = 100 mg/L
TSS = 120 mg/L
Step B Enforceable limits converted to concentrations:
BOD = 1,000 Ibs/day x 1/6 MOD x 1/8.34 = 20 mg/L
TSS = 1,500 Ibs/day x 1/6 MOD x 1/8.34 - 30 mg/L
Step C Flow = 6 MOD
Step D BOD Exceeded Concentration = 100 - 20 = 80 mg/L
TSS Exceeded Concentration = 120 - 30 = 90 mg/L
Step E Loading (Ibs/day) = Exceeded Concentration (mg/L) x Flow (MOD) x 8.34
BOD Loading = 80 (mg/L) x 6 (MOD) x 8.34 = 4,000 Ibs/day
TSS Loading = 90 (mg/L) x 6 (MOD) x 8.34 = 4,500 Ibs/day
Step F Pollutant Reduction (Ibs) = Loading (Ibs/day) x Time (days/year) x l year
BOD Reduction = 4,000 Ibs/day x 365 days/yr. x l yr. = 1,460,000 Ibs.
TSS Reduction = 4,500 Ibs/day x 365 days/yr x 1 yr.= 1,640,000 Ibs.
OECA/OOIUTB 5-3
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Example 2: NPDES Permit Violation for an Indirect Discharger (Pretreatment Violation)
Sampling at ThinkFast Printed Wiring Board Manufacturing Corporation indicates elevated
concentrations of cadmium. The average effluent concentrations of cadmium over six months of
sampling was 0.19 mg/L. ThinkFast discharges wastewater to the local POTW. Their permit limits
cadmium at a maximum daily effluent concentration of 0.14 mg/L and a maximum monthly average
of 0.09 mg/L. Under an enforcement order, the facility is installing additional pollution prevention
technologies to bring the plant into compliance. The average annual discharge of the plant is 25
million gallons. The plant operates and discharges wastewater 5 days a week, 24 hours a day.
Step A Actual average concentration:
Cadmium = 0.19 mg/L
Step B Enforceable limit:
Cadmium = 0.09 maximum monthly average
Step C Flow = 25 MGY
Compute flow in million gallons per day. The site operates 5 days a week.
Flow (MOD) = 25 MGY x lyear/260 days = 0.0962 MOD
Step D Cadmium Exceeded Concentration = 0.19- 0.09 = 0.10 mg/L
Step E Loading (Ibs/day) = Incremental Concentration (mg/L) x Flow (MOD) x 8.34
Cadmium Loading = 0.10 (mg/L) x 0.0962 (MOD) x 8.34 = 0.0802 Ibs/day
Step F Pofiutant Reduction (Ibs) = Loading (Ibs/day) x Time (days/year) x 1 year
Cadmium Reduction = 0.0802 Ibs/day x 260 days/yr x 1 yr = 21 Ibs
OECA/OC/IUTB 5-4
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5.2 Stormwater Violation for CAFO
5.2.1 Background
Stormwater permits usually require management practices as opposed to specific discharge limits.
Therefore, the methodology for estimating reductions will be more case-specific. This section
describes calculations for reduction of Stormwater at concentrated animal feeding operations
(CAFOs). This section focuses on installing berms at beef and dairy facilities to control
contaminated runoff. Pork and poultry are raised in covered houses; therefore, contaminated runoff
should not be an issue at these facilities.
5.2.2 Input Needed to Calculate Pollutant Reductions
Number of animals at the facility
Pollutant concentration in pounds of pollutant per animal
(See Table 5-1 for dairy feedlots and Table 5-2 for beef cattle feedlots)
These tables were calculated using information from EPA's Draft Cost Methodology Report for Beef
and Dairy Animal Feeding Operations using the following assumptions:
Berms contain 100% of the feedlot runoff;
Approximately 1.5% of the annual runoff is feedlot solids (i.e., manure); and
The composition of solids in the runoff is the same as the composition of manure.
OECA/OC/IUTB 5-5
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Table 5-1. Pollutants in Pounds per Animal per year for Dairy Facilities
Total Solids
Volatile Solids
BODS
COD
TKN
Ammonia-N
Total Phosphorus
Orthophosphorus
Potassium
Calcium
Magnesium
Sulfur
Sodium
Iron
Manganese
Boron
Molybdenum
Zinc
Copper
Central
4.601739
3.897943
0.866210
4.222772
0.184070
0.046559
0.049807
0.016241
0.113690
0.075793
0.026528
0.024362
0.016241
0.004223
0.000650
0.000476
0.000023
0.000596
0.000168
Mid Atlantic
3.874310
3.281768
0.729282
3.555249
0.154972
0.039199
0.041934
0.013674
0.095718
0.063812
0.022334
6.02051 1
0.013674
0.003555
0.000547
0.000401
0.000019
0.000501
0.000141
Region
MidWest
2.244051
1.900843
0.422410
2.059246
0.089762
0.022705
0.024289
0.007920
0.055441
0.036961
0.012936
0.011880
0.007920
0.002059
0.000317
0.000232
0.000011
0.000290
0.000082
South
2.259882
1.914253
0.425390
2.073774
0.090395
0.022865
0.024460
0.007976
0.055832
0.037222
0.013028
0.011964
0.007976
0.002074
0.000319
0.000234
0.000011
0.000292
0.000082
Pacific
1.554912
1.317102
0.292689
1.426860
0.062196
0.015732
0.016830
0.005488
0.038415
0.025610
0.008964
0.008232
0.005488
0.001427
0.000220
0.000161
0.000008
0.000201
0.000057
Table 5-2. Pollutants in Pounds per Animal per year for Beef Facilities
Total Solids
Volatile Solids
BODS
COD
TKN
Ammonia-N
Total Phosphorus
Orthophosphorus
Potassium
Calcium
Magnesium
Sulfur
Sodium
Iron
Manganese
Joron
Molybdenum
Zinc
Copper
Central
4.381409
3.651174
0.584188
4.016292
0.164303
0.028844
0.034321
0.022272
0.105884
0.058419
0.025923
0.018621
0.018986
0.004381
0.000694
0.000259
0.000027
0.000657
0.000164
MidAtlantic
3.688809
3.074008
0.491841
3.381408
0.138330
0.024285
0.028896
0.018751
0.089146
0.049184
0.021825
0.015677
0.015985
0.003689
0.000584
0.000218
0.000023
0.000553
0.000138
Region
MidWest
2.136606
1.780505
0.284881
1.958556
0.080123
0.014066
0.016737
0.010861
0.051635
0.028488
6.01*2642
0.009081
0.009259
0.002137
0.000338
0.000126
0.000013
0.000320
0.000080
South
2.151680
1.793067
0.286891
1 .972373
0.080688
0.014165
0.016855
0.010938
0.051999
0.028689
0.012731
0.009145
0.009324
0.002152
0.000341
0.000127
0.000013
0.000323
0.000081
Pacific
1 .480463
1.233720
0.197395
1.357091
0.055517
0.009746
0.011597
0.007526
0.035778
0.019740
0.008759
0.006292
0.006415
0.001480
0.000234
0.000088
0.000009
0.000222
0.000056
OECA/OC/IUTB
5-6
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5.2.3 Step-by-Step Instructions for Calculating Pollutant Reductions
The following steps outline the general method that should be followed to calculate the pollutant
reduction from installing berms at beef and dairy facilities.
Step A Determine the number of animals at the facility
Step B Determine amount of pollutant in runoff (Ibs/animal/year) from Table 5-1 or 5-2.
Step C Multiply the number of animals by the amount of pollutant to obtain the pollutant
reduction in pounds per year.
5.2.4 Example Calculation
An investigation into a fish kill at a local creek found that runoff from an adjacent dairy feedlot
facility was being discharged into the creek. The dairy feedlot houses 2,500 cows and is located in
the Mid West. The creek contains elevated levels of phosphorus, which is a common pollutant found
in feedlot operation runoff. In addition, an inspection of the feedlot operation found that the feedlot
did not have berms installed around the perimeter of the confined animal area to collect runoff. As
part of the enforcement action, the feedlot will be required to install berms which direct all
contaminated runoff to a wastewater storage pond.
Step A The number of animals at the facility = 2,500 animals
Step B Using Table 5-1, the amount of pollutant runoff = 0.024 Ibs total
phosphorus/animal/year
Step C Pollutant reduction = 2500 * 0.024 = 60 Ibs/year
OECA/OC/IUTB
5-7
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5.3 Combined Sewer Overflow (CSO)
5.3.1 Background
Combined sewers collect both storm water and sanitary sewage in the same piping system. During
rainfall, the sewer capacity can be exceeded and the sewer may overflow, which is known as a
combined sewer overflow or CSO. Combined sewer overflows may contain contaminated
stormwater along with human and industrial waste. CSOs are primarily a problem in cities with old
infrastructure and are most common in the Northeast and Great Lakes Region.
The EPA has adopted a CSO Control Policy which was published on April 19,1994. The policy
requires communities to implement nine minimum CSO controls and develop a long-term CSO
control plan. The nine minimum controls are:
Proper operation and maintenance of the combined sewer system;
Maximum use of the collection system for storage;
Review and modification of pretreatment requirements;
Maximization of flow to the publicly owned treatment works (POTW) for treatment;
Prohibition of CSOs during dry weather;
Control of solid and floatable materials in CSOs;
Pollution prevention;
Public notification of CSO occurrences and impacts; and,
Monitoring of CSO impacts and the effectiveness of CSO controls.
Long-term plans must evaluate control strategies and identify control measures and should include
monitoring and modeling. According to the Combined Sewer Overflow Control policy
(www.epa.gov/owm/csopol.htm), a program that meets any of the following criteria would provide an
adequate level of control:
No more than 4 overflow events per year occur;
At least 85% of the overflow is eliminated or captured for treatment; or,
The mass of pollutants that cause water quality impairments are eliminated or
removed.
Combined sewer flows should receive primary treatment, solids and floatables removal, and
disinfection.
OECA/OC/IUTB 5-8
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5.3.2 Input Needed to Calculate Pollutant Reductions
Most CSO control actions reduce the amount of flow that bypasses treatment. Therefore, more of the
CSO flow is treated. Input data needed to develop a pollutant reduction calculation include:
Amount of flow that bypasses treatment before control action.
Amount of flow that bypasses treatment after control action.
Typical concentrations of overflow. If the concentrations are not known, average
values can be obtained from Table 5-3.
Concentrations of treated effluent from the municipal wastewater treatment plant. If
the concentrations are not know, average values can be obtained from Table 5-3.
Table 5-3. Typical Pollutant Concentrations (in mg/L) by Source
Source
Urban stormwater
Combined sewers
Municipal sewage,
untreated
Municipal sewage,
treated
Suspended
Solids
10-10,000
100-2,000
100-330
10-30
BOD,
10-250
20-600
100-300
15-30
COD
20-600
20-1000
250-750
25-80
Total Nitrogen
3-10
9-10
40
30
Total
Phosphorus
0.6
1.9
10
5
Source: Standard Handbook of Environmental Engineering, 2nd edition.
OECA/OC/IUTB
5-9
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5.3.3 Step-by-Step Instructions for Calculating Pollutant Reductions
Step A Determine the average concentration of each pollutant in the combined sewer overflow
in mg/L.
Step B Determine the average concentration of each pollutant in the treated effluent in mg/L.
Step C Determine the concentration by which the pollutant is reduced by subtracting the
concentration in the treated effluent from the concentration in the combined sewer
overflow.
Concentration Reduced (mg/L) = CSO concentration - Effluent Concentration
Step D Determine yearly combined sewer overflow volume (MGY).
[This information should be in the case files]
Step E Determine the flow reduction from the control action (MGY). This is the amount of
flow that will be sent to treatment rather than bypassing the system.
Step F Determine the exceeded loading in pounds by using the following formula:
Loading (Ibs) = Reduced concentration (mg/L) x Flow (MGY) x 8.34 x 1 year
8.34 (Conversion Factor) = (g/1000mg) x (lb/454g) x (3.78L/gal) x (lE6gal/Mgal)
OECA/OC/IUTB 5-10
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5.3.4 Example Calculation
A municipality currently has 40 CSO events per year which results in 30 billion gallons a year
bypassing treatment and discharging directly to surface waters. The discharge of BOD into the
surface water has led to deteriorating water conditions. Additional storage capacity was added to
store 85% of the CSO volume until it can be bled into the treatment system.
Step A From Table 5-3 the average BODS concentration in a CSO is 310 mg/L.
Step B From Table 5-3 the average BOD5 concentration in treated effluent is 22.5 mg/L.
Step C Concentration Reduced (mg/L) = 310- 22.5 = 287.5 mg/L
Step D Based on information from the municipality, the yearly combined sewer overflow
volume is 30 billion gallons per year = 30,000 MGY
Step E The municipality is adding storage capacity for 85% of the CSO volume.
Reduction in flow = 0.85 x 30,000 MGY
= 25,500 MGY
Step F BOD5 Reduction (Ib) = Reduced concentration (mg/L) x Flow (MGY) x 8.34 x 1 year
BODj Reduction (Ib) = 287.5 x 25,000 x 8.34 x 1 = 6.11 x 107 Ibs BOD5
OECA/OC/IUTB 5-11
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5.4 Safe Drinking Water Act Pollutant Reduction
5.4.1 Background
EPA's Office of Ground Water and Drinking Water regulates contaminants that present health risks
and can potentially occur in public drinking water supplies. EPA set National Primary Drinking
Water Regulations (NPDWRs) which are legally enforceable standards that apply to public water
systems. The standards limit the levels of specific contaminants. The NPDWRs set a Maximum
Contaminant Level Goal (MCLG) and a Maximum Contaminant Level (MCL) for specific
contaminants. MCLGs are defined as the maximum level of a contaminant in drinking water at
which no known or anticipated adverse effect on health would occur. MCLGs are not enforceable.
MCLs are the maximum allowable concentration of the contaminant for each pollutant. The MCL is
an enforceable standard. The NPDWRs contain limits for inorganic chemicals, organic chemicals,
radionuclides, and microorganisms.
EPA has also established National Secondary Drinking Water Regulations (NSDWRs) which are
non-enforceable guidelines that States may choose to adopt as enforceable standards. Contaminants
listed in the NSDWRs are contaminants which primarily cause cosmetic or aesthetic effects. A copy
of the NPDWRs and NSDWRs can be found at www.epa.gov/OGWDW/mcl.htm. The regulations
are also listed in 40 CFR Part 141. Section 9.0 of this training booklet presents Tables 9-1 and 9-2
which list these primary and secondary regulatory standards.
5.4.2 Input Needed to Calculate Pollutant Reductions
The following information is needed to calculate pollutant reductions:
Current "out of compliance" discharge concentration (generally in mg/L)
[This concentration may come from the water treatment plant's monitoring reports or
from sampling conducted during case development]
Enforceable limit required to bring the plant into compliance
[This will be the SDWA MCL set for various pollutants]
Water flow rate
[This information comes from plant monitoring data]
OECA/OC/IUTB 5-12
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5.4.3 Step-by-step Instructions for Calculating Pollutant Reductions
To calculate pollutant reductions for water, use the difference between sampled concentrations and
the permit limit. The following steps outline the general method that should be followed to calculate
the pollutant reduction.
Step A Determine the average "out of compliance" concentration of each pollutant in mg/L.
Step B Determine the enforceable limits (NPDES permit, NPDWR) for each pollutant in
mg/L.
Step C Determine average flow in million gallons per day (MOD).
Step D Determine the exceeded concentration by which the pollutant is out of compliance by
subtracting the permit limit from the "out of compliance" condition.
Exceeded Concentration (mg/L) = "Out of compliance" concentration (mg/L) - Permit
limit (mg/L)
Step E Determine the exceeded loading in pounds by using the following formula:
Loading (Ibs/day) = Exceeded Concentration (mg/L) x Flow (MOD) x 8.34
8.34 (Conversion Factor) = (g/lOOOmg) x (lb/454g) x (3.78L/gal) x (JE6gal/Mgal)
Step F Determine the total pollutant reduction to be reported on the CCDS form.
Pollutant Reduction (Ibs) = Loading (Ibs/day) x Time (days/year) x l year
OECA/OC/IUTB 5-13
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5.4.4 Example Calculation
This method applies to all pollutants with a concentration limit. Thus, the example below calculates a
pollutant reduction for chromium but can be used for other pollutants.
An Agency inspection of a public drinking water system discovered elevated levels of chromium,
where the average concentration of chromium in the drinking water was 0.2 mg/L. The Primary
Drinking Water Regulations specify a maximum contaminant level (MCL) of 0.1 mg/L for
chromium. The contamination is believed to be due to discharges from industries into the water
supply and an enforcement order requires additional treatment of the drinking water to the MCL
level. The system supplies 40 MOD of drinking water.
Step A Out of compliance concentration:
Chromium = 0.2 mg/L
Step B Enforceable limit:
Chromium = 0.1 mg/L
Step C Flow = 40 MOD
Step D Chromium Exceeded Concentration = 0.2 - 0.1 = 0.1 mg/L
Step E Loading (Ibs/day) = Exceeded Concentration (mg/L) x Flow (MOD) x 8.34
Chromium Loading = 0.1 (mg/L) x 40 (MOD) x 8.34 = 33.4 Ibs/day
Step F Pollutant Reduction (Ibs) = Loading (Ibs/day) x Time (days/year) x l year
Chromium Reduction = 33.4 Ibs/day x 365 days/year x l year = 12,200 Ibs.
OECA/OOIUTB 5-14
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5.5 SDWA Microbial Violation
5.5.1 Background
As mentioned in Section 5.4.1, the NPDWRs set MCLs for microoganisms. Contaminants listed
under the microorganism section of the NPDWR include Giardia lamblia, heterotrophic plate count,
Legionella, total coliforms, turbidity, and viruses. These contaminants cannot be expressed in the
typical concentration units of mass per unit volume. Giardia lamblia, Legionella, and viruses are all
microorganisms which are regulated by treatment technique which is an enforceable level of
technical performance which public water systems must follow to ensure control of the
contaminant. Treatment techniques are set for contaminants that can not be measured. Although
heterotrophic plate count and turbidity are not specific microorganisms, these are also regulated by
treatment technique. Heterotrophic plate count indicates how effective treatment is at controlling
microorganisms while turbidity can indicate the presence of microbes since particulate matter can
provide a medium for microbial growth. The MCL for total coliform states that no more than 5.0%
of samples can be total coliform-positive in a month. For water systems that collect less than 40
samples per month, no more than one sample can be total-coliform positive. Because microbial
contaminants are not measured in concentration terms, it is not possible to obtain microbial
pollutant reductions in terms of pounds of pollutant removed. Therefore, no pollutant reduction
should be calculated for microbial contaminants. The microorganism parameter should be noted
on the CCDS, but no pollutant reduction is required. Additional information on microbial
pollutants and disinfection byproducts in drinking water can be found at
www.epa.gov/OGWDW/mdbp/mdbp.litmltfregsch.
OECA/OC/1UTB 5-15
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5.6 References
U.S. EPA, February 2000. Drinking Water: Past. Present, and Future, EPA 816-F-
00-002.
U.S. EPA, Office of Water, Office of Ground Water and Drinking Water, Current
Drinking Water Standards, www.epa.gov/OGWDW/mcI.html
U.S. EPA, Office of Water, Office of Science and Technology, Effluent Guidelines
www.epa.gov/waterscience/guide
Letterman, Raymond D., ed., Water Quality and Treatment: A Handbook of
Community Water Supplies, American Water Works Association, McGraw-Hill, Inc.,
Washington, D.C., 1999.
OECA/OC/IUTB 5-16
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6.0 AIR EXAMPLES
The sections below present various pollutant reduction examples for air media. Each section
includes information on the following:
Background;
Input needed to calculate pollutant reductions;
Step-by-step instructions for calculating pollutant reductions; and
Example calculations using specific scenarios.
Section 6.5 presents references and web sites used in developing these examples.
6.1 NOx Reductions at a Petroleum Refinery under PSD/NSR
6.1.1 Background
Emissions of NOx at petroleum refineries are associated with refinery combustion units. Refinery
boilers and process heaters are usually targeted for NOx reductions under compliance actions.
Fluidized catalytic cracking unit (FCCU) regenerators are also sources of NOx emissions at
petroleum refineries (NOx is generated when coke is burned off of the catalyst); however, these
units are typically not controlled for NOx reductions and therefore will not be discussed further
under this guidance. There are two primary types of fuel burned in the boilers and process heaters:
fuel oil and gas. The gas can be either refinery fuel gas that is produced at the facility or natural gas.
There are different options that facilities may use to reduce NOx emissions depending on the unit
and fuel type.
The primary reduction techniques for boilers and process heaters can be classified into one of three
fundamentally different methods combustion controls, post-combustion controls, and fuel
switching. Combustion controls reduce NOx by suppressing NOx formation during the combustion
process while post-combustion controls reduce NOx emissions after their formation. Combustion
controls are the most widely used method of controlling NOx formation in all types of boilers and
process heaters and include:
Low excess air;
- Burners out of service;
Biased-burner firing;
Flue gas recirculation;
Overfire air; and
Low-NOx burners.
Post-combustion control methods include selective noncatalytic reduction (SNCR) and selective
catalytic reduction (SCR). These controls can be used separately, or combined to achieve greater
NOx reduction. Fuel switching replaces one type of fuel with another and can also be combined
with other controls to achieved greater NOx reduction.
OECA/OC/IUTB 6-1
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Combustion Techniques (FOR and Low NQx Burners)
Currently, the two most prevalent combustion control techniques used to reduce NOx emissions are
flue gas recirculation (FOR) and low NOx burners. In an FOR system, a portion of the flue gas is
recycled from the stack to the burner windbox. Upon entering the windbox, the recirculated gas is
mixed with combustion air prior to being fed to the burner. The recycled flue gas consists of
combustion products which act as inerts during combustion of the fuel/air mixture. The FOR system
reduces NOx emissions by two mechanisms. Primarily, the recirculated gas acts as a diluent to
reduce combustion temperatures, thus suppressing the thermal NOx mechanism. To a lesser extent,
FOR also reduces NOx formation by lowering the oxygen concentration in the primary flame zone.
Low NOx burners reduce NOx by accomplishing the combustion process in stages. Staging
partially delays the combustion process, resulting in a cooler flame which suppresses thermal NOx
formation. The two most common types of low NOx burners being applied are staged air burners
and staged fuel burners. NOx emission reductions of 40 to 85 percent (relative to uncontrolled
emission levels) have been observed with low NOx burners. When low NOx burners and FOR are
used in combination, these techniques are capable of reducing NOx emissions by 60 to 90 percent.
Post-Combustion Technologies
Two post-combustion technologies that may be applied to natural gas-fired boilers to reduce NOx
emissions are selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR). The
SNCR system injects ammonia or urea into combustion flue gases (in a specific temperature zone)
to reduce NOx emission. In many situations, a boiler or process heater may have an SNCR system
installed to trim NOx emissions to meet permitted levels. In these cases, the SNCR system may not
be operated to achieve maximum NOx reduction. The SCR system involves injecting NH into the
flue gas in the presence of a catalyst to reduce NOx emissions.
Fuel Switching
Fuel switching may be used to reduce NOx emissions. For certain boiler and process heater units, it
may be possible for the facility to switch from fuel oil combustion to natural gas combustion. This
switch in fuels can result in reduced NOx emissions.
OECA/OC/IUTB 6-2
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6.1.2 Input Needed to Calculate Pollutant Reductions
To calculate NOx emission reductions from boilers or process heaters, it will be necessary to have
the following information available for each unit where emission reductions are being calculated:
The control technology in place prior to efforts utilized by the facility to achieve
compliance (e.g., is the boiler unit uncontrolled before compliance measures are
adopted?)
The reduction strategy to be used to achieve compliance
(e.g., low-NOx burner retrofit to an uncontrolled boiler)
The annual heat input or the annual quantity of fuel burned in the unit
(facilities will maintain this information onsite)
Note: Section 9.0 of this guidance provides selected tables from the references mentioned in this
section.
OECA/OC/IUTB 6-3
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6.1.3 Step-by-Step Instructions for Calculating Pollutant Reductions
There are essentially two methods to calculate NOx reductions from process heaters and boilers:
1. Calculate emissions for the unit using emission factors representing the pre-
compliance and post-compliance conditions (e.g., uncontrolled and controlled
scenario; or, emissions from fuel oil burning versus emission from refinery fuel gas
switching). Subtract the post-compliance estimate from the pre-compliance estimate
to determine the reductions.
2. Calculate emissions for the pre-compliance condition (e.g., uncontrolled) using
emission factors. Multiply a NOx control efficiency to the pre-compliance emission
estimate that represents the control strategy that is or will be used by the facility to
come into compliance (e.g., the control efficiency for a low-NOx burner). The
estimated reduction is equal to the amount of NOx emissions controlled.
Published emission factors and control efficiencies are available for process heaters and boilers by
fuel type and size or rated heat input of the unit. It is important to note that there are no published
emission factors or control efficiencies specific to the use of 'refinery fuel gas'. Factors are
available for the combustion of natural gas. In situations where refinery gas is being used as a fuel,
the emissions reductions should be calculated using the emission factors or control efficiencies that
are published for natural gas combustion in boilers and process heaters. The exception to this case
would be if the facility provides emission factors specific to the refinery fuel gas being used at that
facility.
The following steps should be followed to calculate NOx emission reductions for boilers and
process heaters at petroleum refineries. Note: The steps should be followed to calculate emission
reductions for each unit that is affected by the compliance measures and total reductions
should be summed for all affected units to estimate a total reduction quantity for the
compliance action. The worksheet provided in Table 6-1 can be used to compile the following
information in order to calculate emission reductions (the field names in Table 6-1 are coded to the
items listed below):
Step A Enter the operating conditions of the unit under non-compliance conditions.
Step B Enter the reduction strategy for the affected unit.
Step C If the affected unit is a boiler, locate the emission factor in Table 1.3-1 or Table 1.4-1
of AP-42 (EPA, 1995) that best matches the pre-compliance condition (e.g.,
uncontrolled). If the affected unit is a process heater, locate the emission factor from
Tables 5-11 to 5-15 of the Alternative Control Techniques Document - NOx
Emissions from Process Heaters (EPA, 1993) that best matches the pre-compliance
condition. Enter the value for emission factor in the worksheet in Table 6-1. Note:
Section 9.0 of this guidance provides selected tables from these references.
OECA/OC/IUTB 6-4
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Step D If the affected unit is a boiler, locate the emission factor in Table 1.3-1 or Table 1.4-1
of AP-42 that best matches the post-compliance condition (e.g., unit controlled with
low NOx burners). If the affected unit is a process heater, locate the emission factor
from Tables 5-11 to 5-15 of the Alternative Control Techniques Document - NOx
Emissions from Process Heaters that best matches the post-compliance (i.e.,
controlled) condition. Enter the value for emission factor in the worksheet in Table
6-1. NOTE: if an emission factor that represents the reduction strategy cannot be
located in the referenced tables, then skip to step "E" below.
Step E If emission factors representing emission reduction strategies are not available, it is
also possible to calculate emission reductions based on estimated control efficiencies.
In these cases, refer to Table 12.3-1 of Volume II, Chapter 12 of the EIIP document
series, entitled How to Incorporate the Effects of Air Pollution Control Device
Efficiencies and Malfunctions into Emission Inventory Estimates (EIEP, 2000).
Locate the control efficiency that best matches the reduction strategy used for
compliance and enter the value in Table 6-1, Column E.
Step F If the unit is a process heater, enter the annual heat input for the affected unit for
which emission reductions are being estimated.
[Conversion factors to go from a volume basis to an energy basis are provided in
Table 6-1.}
Step G If the unit is a boiler, enter the annual quantity of fuel burned.
[If the fuel burned is fuel oil use units of I * JO3 gallons; if the fuel burned is natural
gas use units ofl x Iff scf. Conversion factors to go from a volume basis to an
energy basis are provided in Table 6-1.}
Step H Multiply the emission factor (from Column C) for the pre-compliance scenario by
either the heat input value (from Column F for process heaters) or the fuel burned
(from Column G for boilers) and enter the emission estimate in Column H. Note: To
convert from pounds to tons, divide by 2,000.
Step I Multiply the emission factor for the post-compliance scenario (Column D) by either
the heat input value (Column F for process heaters) or the fuel burned (Column G for
boilers) and enter the emission estimate in Column I. If an emission factor was not
available for the control device adopted by the facility to come into compliance, then
skip to step K below. See example calculation below.
Step J Subtract Column I from Column H and enter the quantity of NOx emissions reduced
for the unit. Note: To convert from pounds to tons, divide by 2,000.
Step K Multiply the pre-compliance estimate in Column H by the control efficiency in
Column E and enter the quantity of NOx emissions reduced for the unit.
OECA/OC/IUTB 6-5
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6.1.4 Example Calculations
The following examples demonstrate how emission reductions can be calculated for a petroleum
refining facility. The input data to perform the reduction calculation have been entered onto the
worksheet in Table 6-1 to illustrate how the worksheet can be used.
Example 1:
ABC Oil Company has a facility that added a new gas-fired boiler and 2 gas-fired process heaters
(both are natural draft [ND] heaters) in order to increase its production. The boiler and process
heaters were installed with no controls. In operating the new units, the facility increased its NOx
emissions by more than 40 tons per year, and thus triggered PSD/NSR, falling out of compliance
with Prevention of Significant Deterioration (PSD) requirements for their NOx emissions cap.
Following an administrative order, the facility agrees to add control devices to the new boiler and
process heater units in order to reduce NOx emissions. The facility agrees to use a low-NOx burner
(LNB) and flue-gas recirculation (FOR) on the boiler unit and to retrofit the two new process
heaters with ultra low-NOx burners (ULNB). The annual quantity of fuel burned in the boiler is
687 x 106 scf. The annual quantity of heat input into the process heaters is 1.0 x 106 MMBtu each.
The worksheet in Table 6-1 is used to calculate emissions for the boiler (Bl) and the process heaters
(PHI and PH2) based on uncontrolled conditions (pre-compliance) and also with controls installed
(post-compliance). The calculations of reductions follow the steps outlined in Section 6.1.3.
For Boiler 1:
Pre-compliance NOx emissions (Column H) =
Post compliance NOx emissions (Column I) =
Annual NOx reduction (Column J)
annual quantity of fuel burned (Column G) x
pre-compliance emission factor (Column C)
687 x 106 scf/yr x 100 lb/106 scf
68,700 Ib/yr
34 ton/yr
Annual quantity of fuel burned (Column G) x
post-compliance emission factor (Column D)
687 x 106 scf/yr x 32 lb/106 scf
21,9841b/yr
11 ton/yr
Pre-compliance emissions - post-compliance
emissions
34 ton/yr -11 ton/yr
23 ton/yr
OECA/OC/IUTB
6-6
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For Process Heaters 1 and 2:
Pre-compliance NOx emissions (Column H)=
Post-compliance NOx emissions (Column I)=
Annual NOx reduction (Column J)
Annual heat input (Column F) x pre-
compliance emission factor (Column C)
1.0 x 106 MMBtu/yr x 0.098 Ib/MMBtu
98,000 Ib/yr
49 ton/yr
Annual heat input (Column F) x post-
compliance emission factor (Column D)
1.0 x 106 MMBtu/yr x 0.025 lb/ MMBtu
25,000 Ib/yr
12.5 ton/yr
Pre-compliance emissions - post-compliance
emissions
49 ton/yr-12.5 ton/yr
36 ton/yr
The total reductions for the facility based on its compliance actions equals the sum of
the reductions for all three units on which controls were installed. The total reductions for NOx are
equal to 95 tons per year.
Total NOx Reduction
Bl reduction + PH 1 reduction + PH 2
reduction
23 ton/yr + 36 ton/yr + 36 ton/yr
95 ton/yr
OECA/OC/1UTB
6-7
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Example 2:
XYZ Refining Company has decided that to come into compliance with its PSD requirements it will
switch from using No. 6 fuel oil in its utility boiler to using No. 2 fuel oil, and in addition, will
install low-NOx burners with flue gas recirculation. The utility boiler is rated at 250 MMbtu/hr heat
input and has a normal firing configuration prior to compliance action. The annual quantity of fuel
burned in the utility boiler is 11,680 * 103 gallons. The worksheet in Table 6-1 is used to calculate
emissions for the utility boiler (UB1) based on uncontrolled conditions (pre-compliance) and after
the fuel switch and control device additions are made (post-compliance). The NOx reductions
achieved represent the difference between the pre-compliance and post-compliance estimates, which
in this case is estimated to be 216 tons.
Pre-compliance NOx emissions (Column H)
Po^t-compliance NOx emissions (Column I)
Total annual NOx reduction
Annual fuel burned (Column G) x pre-
compliance emission factor (Column C)
11,680 x 103 gal/yr x 47 lb/103 gal
548,960 Ib/yr
274 ton/yr
Annual fuel burned (Column G) x post-
compliance emission factor (Column D)
11,680 x 103 gal/yr x 10 lb/103 gal
116,800 Ib/yr
58 ton/yr
Pre-compliance emissions - post-
compliance emissions
274 ton/yr - 58 ton/yr
216 ton/yr
OECA/OC/IUTB
6-8
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Table 6-1. Worksheet to Calculate NOx Emission Reductions from Process Heaters and Boilers
Unit
ID
Bl
PHI
PH2
UBI
Pre-
compliance
condition
(A)*
no control
no control
no control
no control
Reduction
Strategy
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6.2 SO2 and HAP Reductions at a Kraft Pulp and Paper Mill Under MACT
6.2.1 Background
In the kraft pulping process, wood is digested under elevated temperature and pressure using a
cooking liquor of sodium hydroxide and sodium sulfide. The digester contents are separated by the
pulp washing system into a pulp slurry and spent cooking liquor. The pulp slurry is sent to
subsequent processing and conditioning equipment (e.g., screening, oxygen delignification,
bleaching) and the spent cooking liquor is concentrated in the evaporator system and then fired in
the chemical recovery boiler. The inorganic cooking chemicals, recovered as smelt from the boiler
furnace floor, are sent to the recausticizing area to be used in preparing fresh cooking liquor. The
kraft pulping process also produces several byproducts (tall oil, turpentine) that are usually
recovered onsite.
Air toxics (hazardous air pollutants or HAPs) and total reduced sulfur (TRS) compounds are formed
in the wood digestion process and pulp treatment processes (e.g., oxygen delignification, chemical
bleaching) and are emitted from discrete process vents and open equipment throughout the process.
The emission points at a typical kraft pulp and paper mill include vents from the following systems:
digester, evaporator, turpentine recovery, pulp washing, screening, knotter, decker, oxygen
delignification, and chemical bleaching. Most mills tend to reuse or recycle process condensates in
an effort to reduce fresh water consumption. Process equipment that uses recycled condensates
typically has higher emissions than the same piece of equipment using fresh water due to the
volatilization of pollutants in the process condensates.
Sulfur dioxide (S02) emissions at kraft pulp and paper mills are generated by the combustion of
sulfur-containing fuels (black liquor and fossil fuels) and by the combustion of pulping vent gases
that contain TRS compounds. Lime kilns, which convert calcium carbonate to quick lime for use in
liquor preparation, are generally not considered significant sources of SO2 emission at kraft mills
since the exhaust gases are usually passed through a wet scrubber to remove particulate matter,
which in turn also reduces SO2 emissions.
The recovery boiler is the heart of the kraft chemical pulping process. During normal operation,
spent cooking liquor (black liquor) from the evaporator system is burned in the chemical recovery
boiler (fuel oil or natural gas may be burned during periods of start-up and shutdown). The organic
content of the black liquor is oxidized to generate process steam and the inorganic cooking
chemicals are recovered as smelt from the furnace bed. Some of the sulfur contained in the black
liquor is reduced in the furnace bed and exits the boiler with the smelt. The remaining sulfur is
oxidized in the upper furnace. The S02 emissions from the recovery boiler are determined by the
relative amounts of sodium and sulfur volatilized during black liquor combustion.
The generation of black liquor is directly related to pulp production, therefore, any increases in pulp
production necessitates an increase in black liquor firing rate with an associated increase in S02
emissions. In some cases, the recovery boiler has sufficient excess capacity to handle pulp
production increases. However, if the pulp production capacity is greater than the available
recovery capacity, then the boiler must be modified to handle the increase in black liquor
throughput.
OECA/OC/IUTB 6-10
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Although the chemical recovery boiler is the primary source of process steam in the mill, fossil fuels
and wood waste are fired in power boilers at pulp and paper mills to generate additional process
steam and electricity. Sulfur dioxide emissions generated by burning a given fuel are proportional
to the heat input rate of the boiler. An increase in heat input rate, either due to modification of an
existing boiler or addition of a new boiler, translates to an increase in SO2 emissions.
Control Techniques
Air Toxic Emissions
Air toxic emissions from regulated pulping process vents are almost exclusively controlled using
mill combustion sources (e.g., power boilers, lime kilns) or using dedicated thermal oxidizers.
Reductions in HAP emissions can also be achieved by replacing higher-emitting process equipment
with lower-emitting ones. For example, HAP emissions from the pulp washing system could be
reduced by replacing the rotary vacuum drum washers with diffusion washers.
Sulfur Dioxide Emissions
The strategy for reducing S02 emissions is dependent on the source of sulfur (i.e., fuel or pulping
process vent gases). For sources of emissions associated with fuel combustion, emission reductions
can be achieved through physical process modifications and fuel switching. However, for chemical
recovery boilers, fuel switching is only an option during periods of start-up and shutdown. For
sources of S02 emissions associated with pulping process vent gas combustion, emission reductions
can be achieved by treating the inlet gas to remove TRS compounds prior to combustion or by
treating the outlet gas to remove S02 directly. This type of gas treatment is typically accomplished
using a gas scrubber with caustic scrubbing media (sodium hydroxide or fresh (white) cooking
liquor).
Process Modifications
Process modifications are the most prevalent control techniques used to reduce SO2 emissions from -
chemical recovery boilers. Sulfur dioxide emissions are influenced by the temperature in the lower
furnace area and can be nearly zero for boilers that have been modified to operate with a hotter
lower furnace. Sulfur dioxide emissions can also be reduced by using sulfur-free chemicals, such as
caustic soda (NaOH) and soda ash (Na^Oj), instead of saltcake (NajSOJ to makeup sodium lost in
the chemical recovery process.
Fuel Switching
Fuel switching can reduce SO2 emissions from power (and recovery boilers during start
up/shutdown), if a fuel with a lower sulfur content can be used. For example, a boiler burning coal
or distillate oil, natural gas would be a candidate for fuel switching. However, fuel switching would
not be feasible for a boiler firing natural gas since a fuel with a lower sulfur content is not available.
OECA/OC/IUTB 6-11
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Gas Treatment
At some mills, the pulping process vent gases are routed through a scrubber (typically using white
cooking liquor or caustic solution as the scrubbing media) to absorb sulfur compounds prior to
combustion. This type of pretreatment is usually limited to dedicated thermal oxidizers. Due to the
large volume of gas associated with recovery and power boilers, treatment of inlet and outlet gases
to remove TRS (or SO2 after combustion) is usually cost prohibitive.
OECA/OC/IUTB 6-12
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6.2.2 Input Needed to Calculate Pollutant Reductions
The preferred method for calculating emission reductions associated with an add-on control
technology or with process modifications is to use approved test data for the period before and after
the emission reduction was achieved. For some process modifications, such as modifications to the
heat recovery sections of recovery boilers, test data may be the only method for calculating emission
reductions since reliable emission factors are not generally available. However, if approved test
data are not available, as in most cases, then emission factors and control technology/treatment
device efficiencies must be used to estimate emission reductions.
As discussed in Section 6.2.1, emissions from noncombustion and combustion sources at kraft pulp
mills are either directly or indirectly a function of the pulp production rate. Consequently, site-
specific process data (e.g., pulp production rate, fuel firing rate, operating schedule) are necessary to
estimate reductions using emission factors.
Input Needed for Noncombustion Sources
Emission reductions for noncombustion sources are typically achieved through the use of an add-on
control technology or the use of lower-emitting process equipment. In calculating emission
reductions from noncombustion sources at kraft pulp and paper mills, the following information is
typically required:
Type of process equipment;
Appropriate emission factors;
Pulp production rate;
Operating schedule;
Concentration of pollutant in process water (if any); and
Efficiency of add-on treatment or control device (if applicable).
Input Needed for Combustion Sources
For combustion sources at kraft mills, emission reductions can be achieved using process
modifications or add-on control technologies. However, due to the large volume of exhaust gas
associated with combustion sources, add-on control technologies can be cost prohibitive. Depending
on the units of the emission factors chosen, the following process data may be needed to estimate
emissions:
Operating schedule;
Types of fuels fired;
Heat content of fuels;
Maximum heat input rate; and
Efficiency of add-on treatment or control device (if applicable).
Combustion sources at kraft mills are often used to control emissions from the pulping process. If a
combustion source, such as a power boiler, is used as a control device, the contribution to S02
emissions associated with oxidizing the TRS compounds from pulping process vents should be
included in the total S02 emissions from the combustion source.
OECA/OC/IUTB 6-13
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Emission factors for characterizing HAP and TRS emissions are typically in units of mass of
pollutant per mass of pulp production and are available from EPA documents (AP-42, Pulp and
Paper NESHAP emission factor document). Emission factors are also available from industry
reports and publications. Sulfur dioxide emission factors for fuel combustion are typically given in
mass of pollutant per unit of fuel usage. AP-42 contains emission factors for various boiler
configurations and fuels firing combinations. Process data (e.g., pulp production rate, operating
schedule) should be obtained from mill documents or mill personnel. The efficiencies of control
technologies or devices can be found in the EPA's Emission Inventory Improvement Program,
Volume II, Chapter 12, How To Incorporate the Effects of Air Pollution Control Device Efficiencies
and Malfunctions into Emission Inventory Estimates. Note: Section 9.0 of this guidance provides
selected tables from the references mentioned in this section.
6.2.3 Step-by-Step Instructions for Calculating Pollutant Reductions
Approved test data is the best method to use for demonstrating emission reductions. If test data are
available, the emission reduction is determined by comparing the emissions before and after the
control device or modification was implemented (i.e., subtract the post-compliance emissions from
the pre-compliance emissions). However, if test data are not available, emission factors, process
data, and control technology/treatment device efficiencies (if applicable) must be used to estimate
emission reductions.
To estimate the reduction in S02 emissions achieved by fuel switching, the following calculation
steps should be used:
Step A Gather process parameters for power boiler no. 1.
Step B Find appropriate SO2 emission factors for no. 6 fuel oil and natural gas for power
boiler no. 1.
Step C Determine the maximum amount of no. 6 fuel oil burned per year in the boiler.
Step D Determine the equivalent amount of natural gas burned per year in the boiler.
Step E Calculate the SO2 emissions from firing no. 6 fuel oil for the boiler.
Step F Calculate the S02 emissions from firing natural gas for the boiler.
Step G Subtract the SO2 emissions from natural gas firing from the SO2 emissions from no.
6 fuel oil firing to estimate emission reductions.
To estimate the reduction in HAP emissions achieved by an add-on control device, the following
calculation steps should be used:
Step A Gather process parameters for the pulp washing system.
Step B Find an appropriate HAP emission factor for the pulp washing system.
OECA/OC/IUTB 6-14
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Step C ' Determine the uncontrolled HAP emissions from the pulp washing system.
Step D Determine the control efficiency of the add-on control device.
Step E Calculate the HAP emission reduction by multiplying the control efficiency of the
add-on device by the uncontrolled emissions from the pulp washing system.
6.2.4 Example Calculations
The following examples demonstrate how HAP and S02 emission reductions can be calculated from
emission sources at a kraft pulp and paper mill. In these examples, the data (emission factors,
process parameter, and control device efficiencies) are arranged such that the specific units
(MMBtu/hr, Ib/ton, Ib removed/100 pounds at inlet) in the numerator and denominator of the data
can be canceled out. This approach is used to help ensure that conversion errors are not introduced
into the emission reduction calculations.
Example 1: Sulfur Dioxide Emission Reductions Using Fuel Switching
Under a Prevention of Significant Deterioration (PSD) violation, ABC Paper Company was found
to have significantly increased pulp production. The increase in pulp production resulted in an
increase in S02 emissions from the recovery furnace due to increased firing of black liquor. Since
the cost of an add-on control device for reducing SO2 emissions was determined to be cost-
prohibitive, the mill is planning to offset the SO2 emissions increase from the recovery boiler by
reducing SO2 emissions from the mill's power boiler.
To achieve the required S02 emission reduction, the mill plans to switch from burning no. 6 oil to
natural gas in the power boiler. The mill currently has one no. 6 fuel oil-fired power boiler with
maximum heat input rate of 250 million British thermal units per hour (MMBtu/hr). The boiler uses
low-NOx burners and has a maximum operating schedule of 8,760 hours per year.
Step A In calculating emissions from the power boiler, the following process parameters are
needed:
Maximum heat input rate (MMBtu/hr);
Fuels fired;
Type of burners used; and
Boiler operating hours.
From the information provided in Example 1, the following information is obtained:
Maximum heat input rate of power boiler no. 1 = 250 MMBtu/hr;
No. 6 fuel oil is fired;
The boiler uses low-NOx burners; and
The boiler operates a maximum of 8,760 hours per year.
Step B Once the boiler process parameters have been identified, appropriate SO2 emissions
factors for no. 6 fuel oil and natural gas firing can be found in Sections 1.3 and 1.4,
OECA/OC/IUTB 6-15
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respectively, of EPA's AP-42. For the boiler and fuel type, the following emission
factors were selected from Tables 1.3-1 and 1.4-1:
no. 6 fuel oil firing = 157(S) lb/1,000 gallons
where S = the percent sulfur in no. 6 fuel oil; and
natural gas firing = 0.6 Ib/scf of natural gas
For the fuel oil emission factor, the percent sulfur content of the fuel oil is needed
before the emission factor can be used. Appendix A of AP-42 (Miscellaneous Data
and Conversion Factors) contains average fuel characteristics that can be used in lieu
of more specific information (e.g., vendor specifications for percent sulfur). For this
calculation, the percent sulfur in fuel oil was selected as 0.5 percent. Therefore, the
SO2 emission factor for fuel oil is calculated as follows:
157(0.5) = 78.5 lb/1,000 gallon fuel oil
Step C The maximum amount of no. 6 fuel oil burned in the boiler is determined using the
maximum heat input rate, the heat content of no. 6 fuel oil, and the operating
schedule. Since the heat content of no. 6 fuel oil was not provided by the mill, an
average value of 140,000 Btu/gallon (for distillate oil) was selected from Appendix
A of AP-42.
To determine the maximum amount of no. 6 fuel oil burned in the boiler, the'
following unit conversion is used:
MMBtu 1,000,000 Btu x hrs x gallon no.6 oil
hr MMBtu yr 140,000 Btu
For power boiler no. 1, the above unit conversion is calculated as follows:
250 MMBtu x 106 Btu x 8760 hr x 1 gal = 1.56 x 1Q7 gal
hr MMBtu yr 140,000 Btu yr
Step D Once the maximum amount of no. 6 fuel oil burned for the boiler is determined, an
amount of natural gas that is equivalent to the quantity of no. 6 fuel oil is needed. To
determine the equivalent amount of natural gas burned per year in the boiler, a unit
conversion similar to that used in Step 3 is followed:
MMBtu x 1,000,000 Btu hr x scf natural gal
hr MMBtu yr 1,050 Btu
For power boiler no. 1, the above unit conversion is calculated as follows:
250 MMBtu x 106 Btu x 8.760 hr x 1 scf _ 2.09 x 1Q9 scf
hr MMBtu yr 1,050 Btu yr
OECA/OC/IUTB 6-16
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Step E The SO2 emissions from firing no. 6 fuel oil in power boiler no. 1 are calculated
using the appropriate emission factor determined in Step 2 and the maximum amount
of fuel oil burned, determined in Step 3, as follows: .
78'5 '" Sฐ' x "ซ * '' *' JJ2!L- = 6ป,8 to,, SO^r
1,000 gal fuel oil yr 2,000 Ib
Step F Similarly to the procedures in Step E, the SO2 emissions from natural gas firing in
power boiler no. 1 are calculated as follows:
0.6 Ib 2.09 x io9 scf 1 ton A , __ .
x x = 0.63 tons SO,/yr
*% /\/\/\ 1L
IO6 scf yr 2,000 Ib
Step G The emission reduction achieved by switching from no. 6 fuel oil to natural gas for
the power boiler is determined by subtracting the S02 emissions determined in Step 6
from the SO2 emissions determined in Step 5.
Power boiler no. 1 emission reduction = 613.98 - 0.63 = 613.35 tons SO2/yr
Example 2: Air Toxic Emission Reduction Using an Add-on Control Device
As a result of an enforcement action, a kraft mill subject to the pulp and paper NESHAP must
control their emissions from their brown stock washing system (all other subject vents at the mill
are currently controlled). Because the distance between the pulp washing system and the existing
power boilers is too great, the mill decides to control the pulp washing system emissions using a
dedicated thermal oxidizer meeting the design parameters specified in the NESHAP.
The pulp production rate of the mill is 1,200 air-dried tons of pulp per day (ADTPD). The pulp
washing system is a diffusion washer (i.e., low-air flow design) that uses fresh water as wash water.
Step A In calculating uncontrolled HAP emissions from a pulp washing system, the
following process parameters are needed:
Type of pulp washing system (e.g., rotary vacuum drum);
HAP concentration of washed water used; and
Pulp production rate.
From the information provided in Example 2, the following information is obtained:
Type of pulp washing system = diffusion washer (low-air flow design);
HAP concentration of washed water = negligible; and
Pulp production rate = 1,200 ADTPD.
Step B The Chemical Pulping Emission Factor Development Document (Revised Draft)
prepared by the EPA for the pulp and paper NESHAP (40 CFR part 63 subpart S)
OECA/OC/IUTB 6-17
-------
contains HAP emission factors for kraft pulp mills. In Table 1-1 of the emission
factor document, HAP emissions are presented for an example (1,000 tons oven-
dried pulp per day, ODTPD). For low air flow washers, the HAP emissions for the
example mill in the emission factor document are given as 20 megagrams per year
(Mg/yr). Dividing the HAP emissions by the example mill production yields (1,000
tons air-dried pulp per day) and an assumed operating schedule of 365 days per year,
a HAP emission factor of 5.48E-05 Mg/ODT is obtained.
Step C Once an appropriate HAP emission factor for the pulp washing system has been
obtained, uncontrolled emissions can be estimated by multiplying the mill pulp
production rate by the HAP emission factor. However, in this example, the pulp
production rate is given in terms of air-dried tons and the emission factor is in terms
of oven-dried tons. To properly use the HAP emission factor, the pulp production
rate must be converted to oven-dried tons using the following relationship:
1 air-dried ton of pulp = 0.9 oven-dried ton of pulp
This relationship is developed based on the industry standard that an air-dried ton of
pulp contains 10 percent moisture. Using the above conversion, the ADTPD pulp
production rate in this example is converted to ODTPD using the following
calculation:
1,200 air-dried tons x 0.9 oven-dried ton _ j ogQ ODTPD
day 1 air-dried ton
The uncontrolled HAP emissions from the pulp washing system can now be
estimated by multiplying the mill pulp production rate by the HAP emission factor as
follows:
5.48 x l(T5 Mg HAP 1,080 ODTP 365 days _ 21.60 Mg HAP
^.^__^__ J^ ^iซซ.^^_nVMซ^ X *B_^^^^^^_K_^^B _ ซซ^^^Bซ^_^ปB^_ซ^_^BW^_^ซB_
ODTP day yr yr
Step D The pulp and paper NESHAP provides several control options for reducing HAP
emissions from pulping process vents. The control options, of which the design
thermal oxidizer is an alternative, are intended to achieve at least 98 percent
destruction of HAP emissions. Therefore, it is appropriate to assume that the control
efficiency of the thermal oxidizer in this example is 98 percent.
Step E Once an appropriate efficiency for the add-on control device is obtained, the HAP
emission reduction for the pulp washing system is calculated by multiplying the
control device efficiency by the uncontrolled HAP emissions as follows:
21.6 Mg HAP at thermal oxidizer inlet 98 Mg Reduced _ 21.17 Mg HAP reduced
X
yr 100 Mg at thermal oxidizer inlet yr
OECA/OC/IUTB 6-18
-------
This metric value can be converted to English units using the following conversion:
21.17 Mg HAP Reduced x 1000 kg x 1 Ib x 1 ton _ 23.31 tons HAP Reduced
yr Mg 0.4S4 kg 2000 Ib yr
OECA/OC/IUTB 6-19
-------
6.3 Leak Detection and Repair
6.3.1 Background
Under the Clean Air Act, fugitive emissions from a variety of equipment, including pumps, valves,
flanges, connectors, and compressors, are to be controlled through the implementation of a Leak
Detection and Repair program (LDAR). Through this program, equipment must be routinely
monitored for leaks and if a leak is found, it must be repaired. If equipment leaks go undetected,
fugitive emissions of volatile organic compounds (VOCs) and other hazardous chemicals will be
emitted continually into the atmosphere. These emissions have a number of adverse effects such as
contributing to smog and human health problems.
Once a LDAR program has been implemented and a leak has been identified, emissions from a
particular piece of equipment can be estimated using the EPA correlation equation approach. This
method involves obtaining screening values (from a portable organic vapor analyzer) before and
after the leak was repaired. Using these values, a calculation can be performed to determine the
resulting reduction in emissions. If screening data is available, but as "greater than or equal to
10,000 ppmv" or "less than or equal to 10,000 ppmv," screening ranges should be used.
6.3.2 Input Needed to Calculate Pollutant Reductions
To estimate LDAR pollutant reductions according to the EPA correlation equation method, the
following information is needed:
The equipment screening value (ppmv) before the repair
The equipment screening value (ppmv) after the repair
The hours of operation (hr/yr)
The pollutant concentration (weight percent) within the equipment
The Total Organic Carbon (TOC) concentration (weight percent) within the
equipment
The EPA correlation equation approach involves the use of a unit and site-specific correlation
equation. These correlation equations have been developed for organic chemical manufacturing
(SOCMI) process units and for the petroleum industry and can be found in the document entitled,
Protocol for Equipment Leak Emission Estimates (EPA, Nov. 95). Table 6-2 and 6-3 contain a few
of these equations.
OECA/OC/IUTB 6-20
-------
Table 6-2. SOCMI Leak Rate/Screening Value Correlations
Equipment Type
Gas valves
Light liquid valves
Light liquid pumps
Connectors
Correlation
leak rate (kg/hr) = 1.87 E-06 x (SV)0873
leak rate (kg/hr) = 6.41 E-06 x (SV)0797
leak rate (kg/hr) = 1 .90 E-05 x (SV)ฐ U4
leak rate (kg/hr) = 3.05 E-06 x (SV)0"5
Source: Protocol for Equipment Leak Emission Estimates (EPA, Nov. 1995).
SV = screening value in ppmv
Table 6-3. Petroleum Industry Leak Rate/Screening Value Correlations
Equipment Type
Valves (all)
Pump seals (all)
Open-ended lines (all)
Connectors (all)
Flanges (all)
Others*
Correlation
leak rate (kg/hr) = 2.29 E-06 x (SV)0744
leak rate (kg/hr) = 5.03 E-05 x (SV)0610
leak rate (kg/hr) = 2.20 E-06 x (SV)ฐ "
leak rate (kg/hr) = 1.53 E-06 x (SV)073i
leak rate (kg/hr) = 4.61 E-06 x (SV)0703
leak rate (kg/hr) = 1.36 E-05 x (SV)03W
Source: Protocol for Equipment Leak Emission Estimates (EPA, Nov. 1995)
SV = screening value in ppmv
* others shall be applied to any equipment type other than connectors, flanges, open-ended lines, pumps, or valves.
If the available screening value is a "zero" screening value (the screening value that represents the
minimum detection limit of the monitoring device) or a "pegged" screening value (the screening
value that represents the upper detection limit of the monitoring device), the correlations in the
above two tables cannot be used. Instead, the values displayed in Tables 6-4 and 6-5 should be used
rather than a correlation.
Table 6-4. SOCMI Default Zero Leak Rates and Pegged Leak Rates
Equipment Type
Gas Valves
Light liquid valves
Light liquid pumps
Connectors
Default Zero Emission
Rate (kg/hr)
6.6E-07
4.9E-07
7.5E-06
6.1E-07
Pegged Emission Rate
(10,000 ppmv) (kg//hr)
0.024
0.036
0.14
0.044
Pegged Emission Rate
(100,00 ppmv) (kg/hr)
0.11
0.15
0.62
0.22
Source: Protocol for Equipment Leak Emission Estimates (EPA, Nov. 1995)
OECA/OC/IUTB
6-21
-------
Table 6-5. Petroleum Industry Default Zero Leak Rates and Pegged Leak Rates
Equipment Type
Connector (all)
Flange (all)
Open-ended line (all)
Pump (all)
Valve (all)
Other
Default Zero Emission
Rate (kg/hr)
7.5E-06
3.1E-07
2.0E-06
2.4E-05
7.8E-06
4.0E-06
Pegged Emission Rate
(10,000 ppmv) (kg/hr)
0.028
0.085
0.030
0.074
0.064
0.073
Pegged Emission Rate
(100,000 ppmv) (kg/hr)
0.030
0.084
0.079
0.160
0.140
0.110
Source: Protocol for Equipment Leak Emission Estimates (EPA, Nov. 1995)
OECA/OC/IUTB
6-22
-------
6.3.3 Step-by-Step Instructions for Calculating Pollutant Reductions
Step A For each leaking equipment type, choose the appropriate equation from Table 6-2 or
6-3. If the available screening value is a "zero" or "pegged" value, choose the
appropriate value from Table 6-4 or 6-5. If a "zero" or "pegged" screening value
exists before repair, skip Step B. If a "zero" or "pegged" screening value exists after
repair, skip StepD.
Step B Enter the equipment screening value (ppmv) before the repair into the equation
chosen in Step A in order to calculate the leak rate (kg/hr) before repair
Step C Calculate the pollutant emissions (kg/yr) before repair of the leak using the following
equation:
Pollutant emissions before repair (kg/yr) = [Leak rate (kg/hr) calculated in Step B or
picked in Step A * pollutant concentration (weight percent) within the equipment *
hours of operation (hr/yr)] / TOC concentration (weight percent) within the
equipment
Step D Now, enter the screening value (ppmv) after the repair into the equation chosen in
Step A in order to calculated the leak rate after repair
Step E Calculate the pollutant emissions (kg/yr) after repair of the leak using the following
equation:
Pollutant emissions after repair (kg/yr) = [Leak rate (kg/hr) calculated in Step D or
picked in Step A * pollutant concentration (weight percent) within the equipment *
hours of operation (hr/yr)] / TOC concentration (weight percent) within the
equipment
Step F The emission reduction achieved by the repair is determined by subtracting the
emissions after repair from the emissions before the repair and converting to a total
load reduction for one year.
OECA/OC/IUTB 6-23
-------
6.3.4 Example Calculations
Example 1: SOCMI with Non-Zero, Non-Pegged Screening Values
An EPA inspection of a chemical manufacturing facility identified a leak at a pump
that pumps light liquid. The monitoring device signaled that the VOC concentration was 5,000
ppmv. Upon repair of the leak, the inspector went back to the equipment location with his
monitoring device. This time the device registered a VOC concentration of 50 ppmv. Records
show that the pump is run for approximately 8760 hr/yr and that the light liquid that is pumped
contains 20% wt. VOC and 40% wt. TOC.
Step A The following equation is chosen from the SOCMI table (Table 6-2) and corresponds
to the light liquid pump: leak rate (kg/hr) = 1.90 E-05 x (SV)0824
where SV = screening value in ppmv
Step B Leak rate (kg/hr) before repair = 1.90E-05 x (5000)0'824 = 0.0212 kg/hr
Step C VOC emission (kg/yr) = 0.0212 (kg/hr) x 20 (wt. %) x 8760 (hr/yr) / 40 (wt. %)
VOC emission (kg/yr) before repair = 92.8 kg/yr
Step D Leak rate (kg/hr) after repair = 1.90E-05 x (50)ฐ824 = 0.000477 (kg/hr)
Step E VOC emission (kg/yr) = 0.000477 (kg/hr) x 20 (wt. %) x 8760 (hr/yr) / 40 (wt. %)
VOC emission (kg/yr) after repair = 2.09 kg/yr
!
Step F VOC emission reduction = (92.8 (kg/yr) - 2.09 (kg/yr)) x l lb/454 kg x lOOOg/kg x
1 year = 200 IDS of VOC
OECA/OC/IUTB 6-24
-------
Example 2: Petroleum Industry with Zero and Pegged Screening Values
A LDAR inspection of a petroleum refining facility resulted in the discovery of leaks at 4
connectors. During the inspection, the monitoring device signaled that the VOC concentrations
were greater than 10,000 ppmv, the upper detection limit of the monitoring device. An
administrative order requires repair of the connectors to a monitoring concentration of less than
1,000 ppmv, the lower detection limit of the monitoring device. Facility records show that the
facility operates continuously (approximately 8760 hr/yr) and that the light liquid that is pumped
through the connectors contains 20% wt. VOC and 40% wt. TOC.
Step A Since the screening values before the repair are "pegged" and after the repair will be
"zero," respectively, the values are chosen off of Table 6-5.
Leak rate before repair = 0.028 kg/hr.
Leak rate after repair = 7.5E-06 kg/hr
Skip B Skipped
Step C VOC emission (kg/yr) = 0.028 (kg/hr) x 20 (wt. %) x 8760 (hr/yr) / 40 (wt. %)
VOC emission (kg/yr) before repair = 122.6 kg/yr per connector
Step D Skipped
Step E VOC emission (kg/yr) = 7.5E-06 (kg/hr) x 20 (wt. %) x 8760 (hr/yr) / 40 (wt. %)
VOC emission (kg/yr) after repair = 0.03 kg/yr per connector
Step F VOC emission reductions = (122.6 (kg/yr) - 0.03 (kg/yr)) x 4 connectors x
1 lb/454g x lOOOg/kg x 1 year = 1,080 Ibs VOC
OECA/OC/IUTB 6-25
-------
6.4 Asbestos NESHAP
6.4.1 Background
The EPA is one of six agencies with the authority to regulate asbestos. The EPA's authority to do
so is provided under both the Toxic Substances Control Act (TSCA) and the Clean Air Act (CAA).
Under TSCA, EPA is authorized to enforce the requirements of the Asbestos Ban and Phase Out
Rule (ABPO) and the Asbestos Hazard Emergency Response Act. The Asbestos Ban and Phase
Out Rule phases out and bans production of five specific types of a asbestos-containing products
including corrugated paper, rollboard, and flooring paper, as well as new uses of asbestos. The
Asbestos Hazard Emergency Response Act prescribes asbestos management practices and
abatement standards for public schools and private, not-for-profit schools. Finally, the EPA is
authorized under the CAA at 40 CFR Part 61 Subpart M to enforce the requirements of the National
Emissions Standards for Hazardous Air Pollutants regulations dealing with asbestos (Asbestos
NESHAP). Note: asbestos was delisted under 40 CFR Part 63 as a source category but is still
regulated by 40 CFR Part 61 Subpart M.
The Asbestos NESHAP provides regulatory standards that are applicable to asbestos disposal and
asbestos removal from buildings as part of renovation and demolition projects. With the goal of
minimizing asbestos emissions during the processing, transport, or disposal of asbestos containing
material, the Asbestos NESHAP requires that building owners and/or renovation/demolition
contractors follow specific work practices to minimize asbestos releases. Furthermore, the
regulation requires that the proper regulatory authorities be notified prior to all demolitions and any
renovation involving certain threshold levels of asbestos containing material (expressed as linear or
square feet).
Unlike other NESHAP regulations, the Asbestos NESHAP does not specify a numeric emission
limitation for the release of asbestos fiber during renovation/demolition, nor does it require any air
monitoring or sampling during renovation or removal activities. Instead of a numeric emissions
limitation, the Asbestos NESHAP specifies that zero visible emissions from the outside air are
allowed during the removal, transport, or disposal of asbestos containing waste. Towards this end,
the asbestos NESHAP requires specific work practices be followed including a requirement that any
asbestos containing materials be sufficiently wetted to a level which would prevent release of
particulates prior to, during, and after renovation/demolition activities until the point of disposal. In
addition, the regulation requires that asbestos containing material be transported in leak-tight
containers or wrapped and disposed of at an acceptable disposal site.
OECA/OC/IUTB 6-26
-------
6.4.2 Input Needed to Calculate Pollutant Reductions
There is no straightforward way to calculate emissions reductions associated with asbestos
regulatory enforcement since there is no specific emission limitation for asbestos fiber releases
during renovation/demolition activities nor is any air monitoring required during such activities.
Furthermore, asbestos emissions resulting from renovation/demolition activities are fugitive in
nature (i.e., they do not pass through a stack or vent). Straightforward emission factors such as
those normally used to estimate emissions from smokestack sources (e.g., tons of NOx emissions
per unit fuel usage at a petroleum refinery combustion unit) are not available for asbestos removal
operations. Consequently, calculation of either asbestos emissions during renovation/demolition
activities or emission reductions due to actions resulting from regulatory enforcement would require
emissions modeling that accounts for numerous variables, including climatic conditions.
Although an estimate of asbestos fiber emission reductions may be difficult to obtain, estimates of
total asbestos fiber properly disposed of may be calculated. Table 6-5 presents the percentages of
asbestos contained within various asbestos containing materials. Table 6-6 presents information on
the bulk densities for various building materials based on the typical binder/sizing material.
Table 6-6. Asbestos Content for Various Materials
Type of Building
Material
Cementitious extrusion
panels: concrete-like
products (Category II)
Roofing felts
(Category I)
Description
corrugated
flat
flexible
flexible perforated
laminated (outer surface)
roof tiles
clapboard
siding shingles
roofing shingles
pipe
smooth surface
mineral surface
shingles
pipeline
% Asbestos
20-45
40-50
30-50
30-50
35-50
20-30
12-15
12-14
20-32
20-15
10-15
10-15
1
10
Binder/Sizing
Portland cement
Portland cement
Portland cement
Portland cement
Portland cement
Portland cement
Portland cement
Portland cement
Portland cement
Portland cement
asphalt
asphalt
asphalt
asphalt
OECA/OC/IUTB
6-27
-------
Table 6-6. Asbestos Content for Various Materials (Continued)
Type of Building
Material
Asbestos-containing
compounds
(Category I and II)
Asbestos ebony products
Tile and sheet goods
Description
caulking putties
adhesive (cold-applied)
roofing asphalt
mastics
asphalt tile cement
roof putty
plaster/stucco
sealants fire/water
cement, insulation
cement, finishing
cement, magnesia
Floor tile and
vinyl/asbestos tile
Sheet goods
asphalt/asbestos tile
Sheet goods/resilient
% Asbestos
30
5-25
5
5-25
13-25
10-25
2-10
50-55
20-100
55
15
50
21
26-33
30
Binder/Sizing
linseed oil
asphalt
asphalt
asphalt
asphalt
asphalt
Portland cement
castor oil or polyisobuxylene
clay
clay
magnesium carbonate
Portland cement
poly(vinyl)chloride
asphalt
dry oils
Source: "Guidance for Controlling Asbestos-containing Materials in Buildings" (Purple Book), Appendix A, Page A-
1; EPA 560/5-85-024.
Table 6-7. Bulk Densities for Binder/Sizing Materials
Material
Portland Cement
Asphalt
Asbestos
Bulk Density
(Ib/ft3)
94
45
22
Source
www.genlime.com/masonry/limemortar/mixdesign/mixdesign.html
www.mid.uk.com/documents/library.htm
www.mid.uk.com/documents/library.htm
To estimate the elimination of asbestos through proper demolition practices and disposal, the
following information is needed:
A description of the type of asbestos containing material involved in the case;
The quantity of material handled and disposed (typically in linear foot, sq. feet, or
cubic feet); and
An estimate of the bulk density of the material.
OECA/OC/IUTB
6-28
-------
6.4.3 Step-by-Step Instructions for Calculating Pollutant Reductions
Step A Determine the type of asbestos containing material involved in the case and use
Table 6-5 to determine the percentage content of asbestos.
Step B Identify the quantity of material to be handled and disposed of by the order/action.
Step C Estimate the bulk density of the asbestos containing material using Table 6-6.
Step D Convert the quantity of material to a weight basis using the bulk density and multiply
this by the percent asbestos in the material to determine the reduction of asbestos that
will be achieved by proper disposal.
6.4.4 Example Calculation
An inspection of a local elementary school identified loose and decaying asbestos roof tiles. A
corresponding enforcement action will result in the removal and disposal of these tiles. The case
file indicates that approximately 2000 sq. feet of material will need to be removed and disposed of
in an approved landfill.
ป
Step A Using Table 6-5, asbestos containing roof tiles contain 20 - 30 percent asbestos and
use portland cement as the binding material.
(For this case we will assume an average asbestos content of 25%)
Step B The quantity of material to be disposed of is approximately 2,000 square feet.
Step C Assuming this material is 25% asbestos and 75% portland cement, an estimate of the
bulk density for this type of material is calculated as follows:
[94 Ib/ft3 x 0.75] + [22 Ib/ft3 x 0.25] = 76 Ib/ft3
Step D Asbestos elimination = 2,000 sq. ft. x 0.25 inch (estimated roof tile thickness) x
1 foot/12 inches x 76 Ib/ft3 x 0.25 = 792 Ibs asbestos
OECA/OC/IUTB 6-29
-------
6.5 References
U.S. EPA, 1995. Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and
Area Sources, Fifth Edition, AP-42. Supplements A, B, C, D, and E. Sections 1.3, Natural Gas
Combustion and Section 1.4, Fuel Oil Combustion. U.S. Environmental Protection Agency. Office
of Air Quality Planning and Standards, Research Triangle Park, NC.
www.epa.gov/ttn/chief7ap-42etc.html
U.S. EPA, 1993. Alternative Control Techniques Document- NOx Emissions from Process Heaters
(Revised). EPA-453/R-93-034. U.S. Environmental Protection Agency. Office of Air Quality
Planning and Standards., Research Triangle Park, NC. www.epa.gov/ttn/catc/dirl/procheat.pdf
EIIP, 2000. How to Incorporate the Effects of Air Pollution Control Device Efficiencies and
Malfunctions into Emission Inventory Estimates. Volume II, Chapter 12 of the Emission Inventory
Improvement Program (EIIP) document series, www.epa.gov/ttn/chief/eiip
Adams, Terry N., editor, et. al. 1997. Kraft Recovery Boilers. Chapter 8, Recovery Boiler Air
Emissions. American Forest and Paper Association. New York, NY.
Smook, G.A. 1997. Handbook for Pulp & Paper Technologists, 2nd Edition. Angus Wilde
Publications. Bellingham, WA.
USEPA. 1995. Compilation of Air Pollutant Emission Factors. AP-42, 5th Edition, including
Supplements A through F. Sections 1.3,1.4, and 10.2. U. S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC.
www.epa.gov/ttn/chief7ap-42.html.
Chemical Pulping Emission Factor Development Document. Revised Draft. Prepared by Eastern
Research Group for U.S. EPA. July 8,1997. Air docket A-92-40, item IV-A-8.
USEPA. July 2000. Emission Inventory Improvement Program. Volume II, Chapter 12: How To
Incorporate the Effects of Air Pollution Control Device Efficiencies and Malfunctions into Emission
Inventory Estimates, www.epa.gov/ttn/chief7eiip/iil2.pdf
U.S. EPA, November 1995. Office of Air Quality Planning and Standards, Protocol for Equipment
Leak Emission Estimates. See http://www.epa.gov/ttn/chief/efdocs/lks95_ch.pdf
U.S. EPA, July 1997. Emission Inventory and Improvement Plan. Vol. 2, Ch 4 and 5. See
http://www.epa.gov/ttn/cWef7eiip/techrep.htmtfpointsrc
http://www.epa.gov/reg5foia/asbestos/ban.html (information on the ABPO rule)
http://www.epa.gov/reg5foia/asbestos/legislat.html (information on various Asbestos-related
legislation)
"Common Questions on the Asbestos NESHAP", EPA 340/1-90-021, December 1990 available at:
http://yosemite.epa.gov/r5/r5ard.nsf72f86cbca09880b61862565fe005881927OpenView
OECA/OC/IUTB 6-30
-------
"Enforcement and Compliance Assurance Accomplishments Report", FY 1997,
OECA, EPA-300-R-98-003, July 1998.
OECA/OC/IUTB 6-31
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7.0 SOLID WASTE EXAMPLES
The sections below present various pollutant reduction examples for solid waste media. Each
section includes information on the following:
Background;
Input needed to calculate pollutant reductions;
Step-by-step instructions for calculating pollutant reductions; and
Example calculations using specific scenarios.
Section 7.4 presents references and web sites used in developing these examples.
7.1 Corrective Action
7.1.1 Background
Past and present activities at RCRA facilities may result in releases of hazardous waste and
hazardous constituents to soil, groundwater, surface water, and air. The RCRA Statute generally
mandates that EPA require the investigation and cleanup, or remediation, of these hazardous
releases at RCRA facilities. This program is known as the corrective action program. EPA enforces
the corrective action program primarily through the statutory authorities established by the
Hazardous and Solid Waste Amendments (HSWA) of 1984.
The corrective action program is structured around elements common to most cleanups under other
EPA programs: an initial site assessment, an extensive characterization of the contamination, and
the evaluation and implementation of cleanup alternatives, both immediate and long-term. To
facilitate investigations, EPA uses the concept of action levels in some cases. Action levels are risk-
based concentrations of hazardous constituents in ground water, soil, or sediment, and the presence
of hazardous constituents above these action levels suggests that there has been a release requiring
corrective measures. Under this approach, contamination below appropriate action levels would not
generally be subject to cleanup or further study.
EPA or the state agency expects facility owners and operators to recommend a preferred remedy or
preferred performance standards, including proposed media cleanup levels and compliance time
frames. Although this recommendation is the responsibility of the owner and operator, EPA or the
state agency can reject any alternative and require further analysis or prescribe a different remedy.
For more information on corrective action to clean up hazardous waste contamination see:
http://www.epa.gov/epaoswer/general/orientat/
OECA/OC/IUTB 7-1
-------
7.1.2 Input Needed to Calculate Pollutant Reductions
To calculate pollutant reductions from a corrective action, it will be necessary to have the following
information available:
The pollutants identified as present above action levels which require control.
The pre-corrective action concentration of these pollutants in each media (soil,
groundwater, surface water, air).
The corrective action used as the remedy in the action (e.g., pump and treat for
ground water contamination, contaminated soil removal).
Treatment levels required by the corrective action remedy.
The quantity of media to be treated or removed.
7.1.3 Step-by-Step Instructions for Calculating Pollutant Reductions
Step A For each pollutant in each media identify the pre-treatment concentration.
Step B For each pollutant in each media, identify the remedy and determine if the remedy
will result in either treatment of the pollutant to a specified level or removal of the
pollutant.
[The corrective action remedy should specify the required treatment level; for
hazardous wastes treated to meet Land Disposal Restrictions see
http://www.epa.gov/reg5oli2o/uic/lbhwa.htm]
Step C For each media, determine the quantity of material treated or removed.
[For soil this will likely be expressed as cubic yards of soil removed or treated. For
groundwater or surface water this will be expressed as a flow or total volume of
liquid. For air emissions, the treatment remedy will likely involve removal and/or
treatment of the contaminated media that results in the air emission.]
Step D Determine the reduction of pollutant through treatment or removal as the pre-
treatment concentration minus the required post-treatment concentration. For
contaminated soil removal assume that no additional pollutant release will occur after
proper treatment and disposal of the soil, thus the post-treatment concentration would
be 0 mg/kg.
Step E Multiply the reduction of pollutant concentration by the quantity of media treated or
removed and convert to the units of pounds of pollutant.
[Note: to convert a pollutant concentration in soil in mg/kg to a pollutant mass by
volume, you will need to assume a bulk density for soil. Soil bulk densities will
generally range from 1.0 Mg/m3for clays, silty clays, or clay loams to 1.8 Mg/m3
for sandy soils
(see http://soil-physics.nmsu.edu/sp/classes/s252 l/lab_manual/Chapt5.htm)]
OECA/OC/IUTB 7-2
-------
7.1.4 Example Calculation
XYZ Industrial Company is a hazardous waste storage facility with a RCRA permit. During a
routine EPA inspection, the Agency discovered contamination in XYZ Industrial's tank storage
area. Soils under the area were contaminated by wastes spilled during pumping and by leaking
tanks. The soil exhibited high levels of trichloroethylene (100 mg/kg), a volatile organic compound
that migrates easily through the soil into the groundwater and is believed to cause cancer.
Additionally, the investigation of the site discovered that a municipal drinking water well located
within a mile of the facility was also contaminated with trichloroethylene at a concentration of 5
mg/1. None of this contamination was detected in the initial permitting process.
EPA conducted a RCRA facility assessment (RFA) to compile information on the types of
hazardous wastes managed at the facility in the past, areas where these wastes were managed, and
possible exposure pathways.
The owner and operator of XYZ Industrial then conducted a RCRA facility investigation (RFI),
with EPA oversight, to estimate the health and environmental problems that could result if the
contamination was not cleaned up, and to determine the extent of the contamination. To protect
human health and the environment while the assessment and investigation were taking place, the
owner and operator established an alternative drinking water source for the households served by
the municipal well as interim measures.
A corrective measures study (CMS) determined that the company should clean up the groundwater
contamination via a pump and treat process, excavate the soil and treat it thermally prior to disposal
off-site at a permitted landfill. In a statement of basis, EPA proposed the above technologies as the
recommended remedial alternative. The statement of basis included all documentation in support of
the recommended remedy, as well as the cleanup levels that had to be achieved during the remedial
action. This included treatment of the groundwater to 0.05 mg/1 trichloroethylene through the pump
and treat system, which would be designed to treat at a flowrate of 1,000 gallons per day. The
recommendations of the CMS were incorporated into an administrative order imposed on the
facility by the Agency in its enforcement action.
The total reductions of trichloroethylene for the facility based on the adopted corrective action
equals the sum of the reductions from the groundwater pump and treat system and the reduction
from the contaminated soil removal.
The calculation of these reductions is shown below.
For Groundwater:
Step A Pre-compliance concentration:
Trichloroethylene at 5 mg/1
Step B Post-compliance concentration:
Trichloroethylene at 0.05 mg/1
Step C Pump and treat flowrate = 1,000 gallons/day
OECA/OC/IUTB 7-3
-------
Assume that the system will treat throughout the reporting year at 365 days/year
Step D Incremental concentration = 5 mg/1 - 0.05 mg/1 = 4.95 mg/1 trichloroethylene
Step E Annual removal = 4.95 mg/1 x 1,000 gal/day x [3.785 1/gal x 365 days/yr x 0.00220
Ibs/gm x 0.001 gm/mg]
= 15 Ibs. of trichloroethylene removed per year of treatment
For Soil:
Step A Pre-compliance concentration:
Trichloroethylene at 100 mg/kg
Step B Post-compliance concentration:
Trichloroethylene at 0 mg/kg
Assumes that no pollutant will be, released following removal, treatment, and proper
disposal of the soil.
Step C Volume of material removed = 500 cubic yards
Step D Incremental concentration = 100 mg/kg - 0 mg/kg = 100 mg/kg trichloroethylene
Step E Annual removal = 100 mg/kg x 500 cubic yards x [1.4 Mg/m3 x 0.764 m3/cubic
yard x 1000 kg/Mg x 0.001 gm/mg x 0.00220 Ibs/gm]
= 118 Ibs. of trichloroethylene removed with the soil
In this example, assumed a soil bulk density of 1.4 Mg/m3.
Total Trichloroethylene removal from the soil and groundvvater will be:
15 Ibs. + 118 Ibs. = 133 Ibs.
OECA/OC/IUTB 7-4
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7.2 RCRA UST
7.2.1 Background on UST Regulations
In 1976 Congress wrote The Resource Conservation and Recovery Act (RCRA) as an amendment
to the Solid Waste Disposal Act which was created in 1965. RCRA created the framework for EPA
to regulate solid waste, hazardous waste, medical waste, and underground storage tanks (USTs).
Three goals were in mind when this act was written: 1) protect the environment, as well as human
health; 2) conserve energy and natural resources; and 3) reduce or eliminate the generation of
hazardous waste. To achieve these goals, RCRA was composed of 10 subtitles that granted the
EPA with the authority to develop regulatory programs. Subtitle I provides EPA with this
regulatory authority for USTs and is an important component of the act because it allows EPA to
regulate products as well as wastes.
An underground storage tank is defined as a tank with at least 10 percent of its volume
underground, including piping, ancillary equipment, and containment systems. In order to be
regulated by Subtitle I, the tank must store petroleum or a hazardous substance. Certain tanks are
excluded from this definition including:
Farm and residential tanks holding motor fuel for noncommercial purposes with a
capacity less than or equal to 1,100 gallons;
Tanks storing heating oil to be used on the premises where it is stored;
Septic tanks collecting waste and storm water;
Tanks on the floor of underground areas;
Emergency spill and overfill tanks;
Tanks with a capacity of 110 gallons or less; and
Wastewater treatment tanks.
This list contains only some of the excluded tanks. For a complete list of exempt USTs, please see
40 CFR, Part 280 (http://www.epa.gov/docs/epacfr40/chapt-I.info/subch-I/40P0280.pdf).
For those USTs regulated by RCRA, performance standards for design, construction, and,
installation, as well as compatibility standards for new tanks have been created. Additionally,
requirements concerning leak detection, record keeping, reporting, corrective action, and closure
have also been developed. In some cases, these requirements have been developed by individual
state governments rather than the EPA. In those cases, the state governments have obtained
authorization from the Administrator to operate an UST program in lieu of the federal program.
The regulation of USTs is very important because leaks from an UST can cause fires and
explosions, as well as contamination of the ground water that many Americans rely on for drinking.
In order to ensure the protection of both people and the environment, many important regulations
have been developed for the safe operation of USTs. Included in these regulations is the
requirement that all owners and operators of an UST take corrective action in response to a leak.
Specific closure requirements must also be followed for the temporary or permanent closure of any
UST. Additionally, owners must demonstrate financial responsibility for the cost of cleaning up
any leak and for the cost of compensating others for bodily injury or property damage due to an
UST.
OECA/OC/IUTB 7-5
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Over the course of the UST regulations, two major deadlines have passed. The first of these
deadlines was December, 1993. By this time, all new or existing USTs had to be equipped with a
leak detection system. Examples of a leak detection system are listed below:
Interstitial Monitoring - Leaks are detected in the space between the UST and a
second barrier
Automatic Tank Gauging System - An automated system that monitors product level
and inventory control
Monitoring of Vapors in Soil - Monitors for gases in the soil surrounding the UST
Monitoring for Liquids on the Groundwater - Monitors the groundvvater surround the
UST for product releases
Statistical Inventory Reconciliation - A computer software program conducts
statistical analysis of inventory and delivery data
Systems not included in the above list, but shown to work as effectively, could have been approved
by the regulatory authority.
The second of the two deadlines was December 22, 1998. By this time, all new or existing USTs
had to be equipped with spill, overfill, and corrosion protection. To ensure spill protection, USTs
were required to be equipped with catchment basins to contain spills. For overfill protection, USTs
were required to be equipped with automatic shut off devices, overfill alarms, or ball float valves.
Lastly, for corrosion protection, the tank and piping had to be made completely of non-corrodible
material, or of steel having a corrosion-resistant coating and having cathodic protection, or of steel
clad with a thick layer of non-corrodible material.
In order to comply with these regulations, owners and operators of existing USTs that did not meet
the requirements had three options: 1) close the existing UST; 2) upgrade the substandard UST
through adding the necessary equipment; or 3) replace the substandard UST. If one of these three
options was not taken and the UST did not meet the deadline requirements, operation of the UST
was and still is illegal. On the same note, new USTs must be constructed to meet these
requirements or be considered illegal.
To deal with non-compliance or illegal UST operation, EPA or the state regulatory agency may
impose enforcement actions to ensure that the substandard UST is temporarily closed until it may be
permanently closed, replaced, or upgraded. These pollution prevention actions may include
monetary penalties and administrative and judicial enforcement actions. These actions will not
result in a pollution reduction scenario, thus a pollutant reduction will not need to be
calculated. However, if an UST pollutant release is detected, the result is a corrective action
scenario and pollutant reductions can be calculated (See Section 7.1 example).
OECA/OC/IUTB
7-6
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7.3 Used Oil Management
7.3.1 Background on Used Oil Regulations
In an effort to encourage the recycling of used oil, and in recognition of the unique properties and
potential hazards posed by used oil, Congress passed the Used Oil Recycling Act in 1980. This Act
amended RCRA by requiring EPA to study used oil and to develop used oil management standards.
In November 1985, EPA promulgated restrictions on the burning of used oil for energy recovery
and in September 1992, EPA developed a comprehensive used oil recycling program which is
codified in 40 CFR Part 279. Part 279 includes an assumption that all used oil will be recycled.
This assumption simplifies the used oil management system by enabling handlers to only comply
with the used oil regulations, instead of the hazardous waste regulations. Only when the used oil is
actually disposed of or sent for disposal must a handler determine whether or not the used oil
exhibits a characteristic of hazardous waste and manage it in accordance with hazardous waste
regulations.
Used oil mixed with hazardous waste is subject to all applicable hazardous waste standards. Since
the Agency cannot always determine if a used oil has been mixed with a listed hazardous waste, the
used oil can be tested for total halogens. Used oil that contains more than 1,000 parts per million
(ppm) of total halogens is presumed to have been mixed with a listed hazardous waste. A used oil
generator can rebut this presumption by demonstrating, through analysis or other documentation,
that the used oil has not been mixed with listed hazardous waste. In addition, used oil contaminated
with poly-chlorinated biphenols (PCBs) at 50 ppm or greater is subject to Toxic Substances Control
Act requirements instead of the used oil requirements.
The used oil recycling program includes management standards for all facilities that handle used oil.
These entities are either generators, collection centers and aggregation points, transporters, transfer
facilities, processors and refiners, or marketers. Used oil generators are persons whose act or
process produces used oil, or first causes used oil to be subject to regulation. Examples of common
generators include car repair shops, service stations, and metalworking industries. Individuals who
generate used oil through the maintenance of their own vehicles and equipment are not considered
used oil generators. The regulations for used oil include storage requirements; burning restrictions;
and record keeping and reporting for oil transporters, transfer facilities, processors and refiners,
burners, and marketers. For used oil generators only the storage requirements apply and include the
following:
Store used oil in tanks and containers. Storage of used oil in lagoons, pits, or surface
impoundments is prohibited, unless these units are subject to hazardous waste TSDF
standards;
Clearly mark containers and tanks with the words "Used Oil";
Keep containers and tanks in good condition and free of leaks; and
Respond to releases of used oil from their storage units.
These standards are designed to establish minimum regulations for all facilities; additional
requirements may be imposed by state or local authority.
OECA/OC/IUTB 7-7
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7.3.2 Input Needed to Calculate Pollutant Reductions
In general, enforcement cases related to used oil management do not result in pollutant reductions,
but instead result in proper management of the used oil. Therefore, pollutant reduction calculations
are not required. Instead, the amount of used oil coming under proper management can be
estimated using information from the case file on pollutant volume and/or generation.
7.3.3 How to Calculate Pollutant Quantities
The determination of quantity of material or pollutant brought into proper management will be case-
specific. In the example below, the volume of used oil brought under proper management is
estimated using the dimensions of a storage pit and an estimate of used oil generation per time based
on facility personnel knowledge.
OECA/OC/IUTB 7-8
-------
7.3.4 Example Calculation
Metal Works Company is a metal machining shop which uses lubricating oil in their process. After
use, the oil is stored on site. During an on-site inspection the used oil from the shop was found to
be stored in a concrete pit (which is 4 ft. by 6 ft. and contains oil at a 12 inch depth) along the back
of the shop. The Agency inspector issued an administrative order requiring the facility to install a
used oil tank for storage, relocate the used oil in the pit at the back of the facility to the new storage
tank, properly label the tank as "Used Oil", and arrange for periodic pick up by a used oil
transporter. The quantity of used oil generated at the facility is approximately 10 gallons per month.
An estimate of the amount of used oil coming under management is calculated as:
Used oil in the outdoor pit + used oil generated during the reporting year.
Volume of Used oil in the outdoor pit is calculated as:
4 ft. x 6 ft. x l ft. = 24 cubic feet x 7.48 gallons/cubic foot = 180 gallons
Used oil generated per year is calculated as:
10 gallons/mo, x 12 mo./year = 120 gallons
Total Used Oil Brought into Proper Management is:
180 gallons + 120 gallons = 300 gallons
7.4 References
U.S. EPA, 2000. Office of Solid Waste, RCRA Orientation Manual. Section III, Chapter 9. See
http://www.epa.gov/epaoswer/general/orientat
40 CFR Part 268, Subpart D - Land Disposal Restrictions Treatment Standards
U.S. EPA, 2000. Office of Solid Waste. RCRA Orientation Manual. Section III, Chapter 2. See
http://www.epa.gov/epaoswer/general/orientat/
U.S. EPA. RCRA Statutory Overview.
See http://www.epa.gov/epaoswer/hotline/training/statov.txt
U.S. EPA. July 1995. Office of Solid Waste and Emergency Response. Musts for USTs: A
Summary of Federal Regulations for Underground Storage Tank Systems. See
http://www.epa.gov/swerustl/pubs/musts.pdf
U.S. EPA. Office of Underground Storage Tanks. 1998 Deadline for Upgrading, Replacing, or
Closing Substandard USTSystems. See http://www.epa.gov/swerustl/1998/index.hrrn
OECA/OC/IUTB 7-9
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8.0 UMTS AND UNIT CONVERSIONS
Unit conversion is a simple tool which allows one to describe a quantity in other terms that are of
interest. In its most basic form, unit conversion may contain only one step involving multiplication
of a given quantity by a known conversion factor. More complex conversions may involve
handling multiple sets of given information and conversion factors all within the same calculation.
However, the steps for both simple and more complex unit conversions are the same as illustrated
by the following examples.
Example 1: Simple Unit Conversion
To convert a pollutant loading discharged to a stream from 1.5 kilograms (kg) per day to pounds
(Ibs) per day requires the following information: 1.5 kg per day, represents the given information
and 2.2 Ibs per 1 kg, represents the required conversion factor.
A unit conversion will return an answer in the units of interest. This is accomplished by canceling
out identical units that are opposite to each other in separate entries (i.e., one must be in the
denominator and one must be in the numerator of the respective entries). In this example, the units
for kilograms have been canceled out to return an answer in Ibs per day:
1.5 kg 2.2 Ibs _ 3.3 Ibs
X
day 1 kg day
Example 2: Complex Unit Conversion
An example of a complex unit conversion would be calculating the tons of particulate matter (PM)
emitted per year when given an actual pollutant concentration of 0.15 grains (gr) of PM per dry
standard cubic feet (dscf) of exhaust and an exhaust flow rate of 75,000 dscf per minute. For this
calculation, the following conversion factors are used.
7,000 grains per pound 2000 pounds per ton
60 minutes per hour 8,760 hours per year
As with the previous example, all units except tons and year will cancel each other
out thus returning an answer in the units of interest, tons per year:
0.15 grains 75,000 dscf 1 pound 60 minutes 8,760 hours 1 ton 422 tons
5 X X X X X ^_ = _
1 dscf 1 minute 7,000 grains 1 hour year 2,000 pounds year
Table 8-1 below contains common conversion factors encountered in calculations to determine
pollutant loading. Table 8-2 contains various examples of unit conversions commonly used to
calculate pollutant loadings in air, solid waste, and water media, respectively.
OECA/OC/IUTB 8-1
-------
Table 8-1. Common Conversion Factors
Mass
1 microgram (ug) =
1 milligram (mg) =
1 gram (g) =
1 kilogram (kg) =
1 megagram (Mg) =
1 pound (Ib) =
1 pound (Ib) =
1 ton (short) =
1 ton (short) =
1000picograms(pg)
1000 micrograms (ug)
1000 milligrams (mg)
1000 grams (g)
1,000 kilograms (kg)
7,000 grains (gr)
454 grams (g) .
0.907 metric tons
2,000 pounds (Ibs)
Volume
1 cubic foot (ft3) =
1 cubic yard (yd3) =
1 gallon (gal) =
7.481 gallons (gal)
0.764 cubic meters (m3)
3.785 liters (1)
Time
1 day =
1 hour =
1 year =
1 year =
24 hours
60 minutes
365 days
8,760 hours
Table 8-2. Examples of Common Pollutant Loading Conversions for Different Media
Air
0.15 gr PM _ 75,000 dscf _ 1 pound _ 60 minutes _ 8,760 hours
1 dscf I minute 7,000 gr I hour 1 year
0.07 Ibs NO,
I million Btu
0.13 pounds VOC
thousand Ibs steam
100 million Btu 8,760 hours 1 ton
1 hour 1 vear 2.000 Ibs
110 thousand Ibs steam 8,760 hours 1
1 hour 1 year 2,000
1 ton 422 tons PM
2,000 Ibs year
31 tons NOt
vear
ton 63 tons VOC
pounds year
Solid Waste
100 mg benzene 500 yd* soil _ 1.4 Mg soil _ 0.764 m' _ 1,000 kg _
1 kg soil 1
1 mj soil 1 vd3 1 Mg
I Ib I g _118 Ib
454 g * 1,000 mg betuen
Water
4.95 mg benzene removed
1 ( treated
80 mg BOD
1 ซ
1,000 gal 3.785 ( 365 days 1 g
1 day 1 gal 1 year 1,000 mg
9,000,000 gal 3.785 C g 1 Ib
1 day 1 gal 1,000 mg 454 g
1 Ib 15 Ibs benzene
454 g year
. 6,002 Ibs BOD
day
OECA/OC/IUTB
8-2
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9.0 LOOK-UP TABLES
Table 9-1. National Primary Drinking Water Regulations
Contaminants
Inorganic Chemicals
Antimony
Arsenic
Asbestos (fiber > 10 micrometers)
Barium
Beryllium
Cadmium
Chromium
Copper
Cyanide (as free cyanide)
Fluoride
Lead
Inorganic Mercury
Nitrate (measured as nitrogen)
Nitrite (measured as nitrogen)
Selenium
Thallium
MCLG1 (mg/L)4
0.006
none5
7 million fibers per liter
2
0.004
0.005
0.1
1.3
0.2
4.0
zero
0.002
10
1
0.05
0.0005
MCLJ or XT3 (mg/L)4
0.006
0.05
7MFL
2
0.004
0.005
0.1
Action Level
= 1.3:11*
0.2
4.0
Action Level
= 0.015; TT6
0.002
10
1
0.05
0.002
Organic Chemicals
Acrylamide
Alachlor
Atrazine
Benzene
Benzo(a)pyrene
Carbofuran
Carbon tetrachloride
MCLG1 (mg/L)4
zero
zero
0.003
zero
zero
0.04
zero
MCL2 or XT3 (mg/L)4
TT7
0.002
0.003
0.005
0.0002
0.04
0.005
OECA/OC/IUTB
9-1
-------
Table 9-1. National Primary Drinking Water Regulations (Continued)
Organic Chemicals (cont.) ||
Chlordane
Chlorobenzene
2,4-D
Dalapon
1 ,2-Dibromo-3-chloropropane (DBCP)
o-Dichlorobenzene
p-Dichlorobenzene
1 ,2-Dichloroethane
1 , 1 -Dichloroethylene
cis- 1 ,2-Dichloroethylene
trans- 1 ,2-Dichloroethylene
Dichloromethane
1 ,2-Dichloropropane
Di(2-ethylhexyl)adipate
Di(2-ethylhexyl)phthalate
Dinoseb
Dioxin (2,3,7,8-TCDD)
Diquat
Endothall
Endrin
Epichlorohydrin
Ethylbenzene
Ethelyne dibromide
Glyphosate
Heptachlor
Heptachlor epoxide
Hexachlorobenzene
Hexachlorocyclopentadiene
Lindane
MCLG1 (mg/L)4
zero
0.1
0.07
0.2
zero
0.6
0.075
zero
0.007
0.07
0.1
zero
zero
0.4
zero
0.007
zero
0.02
0.1
0.002
zero
0.7
zero
0.7
zero
zero
zero
0.05
0.0002
MCL2 or XT3 (mg/L)4
0.002
0.1
0.07
0.2
0.0002
0.075
0.005
0.007
0.07
0.1
0.005
0.005
0.4
0.006
0.007
0.00000003
0.02
0.1
0.002
TT7
0.7
0.7
0.0004
0.0002
0.001
0.05
0.0002
OECA/OC/1UTB
9-2
-------
Table 9-1. National Primary Drinking Water Regulations (Continued)
Organic Chemicals (cont.)
Methoxychlor
Oxamyl (Vydate)
Polychlorinated biphenyls (PCBs)
Pentachlorophenol
Pichloram
Simazine
Styrene
Tetrachloroethylene
Toluene
Total Trihalomethanes (TTHMs)
Toxaphene
2,4,5-TP (Silvex)
1 ,2,4-Trichlorobenzene
1,1,1-Trichloroethane
1 , 1 ,2-Trichloroethane
Trichloroethylene
Vinyl chloride
Xylenes (total)
MCLG1 (mg/L)4
0.04
0.2
zero
zero
0.5
0.004
0.1
zero
1
none3
zero
0.05
0.07
0.20
0.003
zero
zero
10
MCL1 or TT3 (mg/L)4
0.04
0.2
0.0005
0.001
0.5
0.004
0.1
0.005
1
0.10
0.003
0.05
0.07
0.2
0.005
0.005
0.002
10
Radionuclides
Beta particles and photon emitters
Gross alpha particle activity
Radium 226 and Radium 228 (combined)
MCLG1 (mg/L)4
none5
none5
none5
MCL2 or TT3 (mg/L)4
4 millirems per year
15 picocuries per liter
(pCi/L)
5pCi/L
Microorganisms
Giardia lamblia
rieterotrophic plate count
'.egionella
MCLG1 (mg/L)4
zero
N/A
zero
MCL2 or TT3 (mg/L)4
TT8
TT8
TT8
OECA/OC/1UTB
9-3
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Table 9-1. National Primary Drinking Water Regulations (Continued)
Microorganisms
Total coliforms (including fecal coliform and E.colf)
Turbidity
Viruses^enteriq)
MCLG1 (mg/L)4
zero
N/A
zero
MCL1 or XT0 (mg/L)4
5.0%'
TT8
TT8
'Maximum Contaminant Level Goal
2Maximum Contaminant Level
'Treatment Technique
'Units are in milligrams per Liter (mg/L) unless otherwise noted.
'MCLGs were not established before the 1986 Amendments to the Safe Drinking Water Act. Therefore, there is no
MCLG for this contaminant.
'Lead and copper are regulated in a treatment technique which requires systems to take tap water samples at sites with
lead pipes or copper pipes that have lead solder and/or are served by lead service lines. The action level, which triggers
water systems into taking treatment steps if exceeded in more than 10% of tap water samples, for copper is 1.3 mg/L,
and for lead is 0.015 mg/L.
'Each water system must certify, in writing, to the state that when acrylamide and epichlorohydrin are used in drinking
water systems, the combination (or product) of dose and monomer level does not exceed the levels specified, as
follows:
Acrylamide = 0.05% dosed at 1 mg/L (or equivalent)
Epichlorohydrin = 0.01% dosed at 20 mg/L (or equivalent)
"The Surface Water Treatment Rule requires systems using surface water or ground water under the direct influence of
surface water to (1) disinfect their water, and (2) filter their water or meet criteria for avoiding filtration so that the
following contaminants are controlled at the following levels:
Giardia lamblia: 99.9% killed/inactivated
Viruses: 99.99% killed/inactivated
Legionella: No limit, but EPA believes that if Giardia and viruses are inactivated, Legionella will also be
controlled.
Turbidity: At no time can turbidity go above 5 NTU; systems that filter must ensure that the turbidity go no
higher than 1 NTU in at least 95% of the daily samples in any month.
HPC: No more than 500 bacterial colonies per milliliter.
*No more than 5.0% samples total coliform-positive in a month. For water systems that collect fewer than 40 routine
samples per month, no more than one sample can be total coliform-positive.
'"Fecal coliform and E.coli are bacteria whose presence indicates that the water may be contaminated with human or
animal wastes.
OECA/OC/1UTB
9-4
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Table 9-2. National Secondary Drinking Water Regulations
Contaminant
Aluminum
Chloride
Color
Copper
Corrosivity
Fluoride
Foaming Agents
Iron
Manganese
Odor
PH
Silver
Sulfate
Total Dissolved Solids
Zinc
Secondary Standard
0.05 to 0.2 mg/L
250mg/L
IS (color units)
1.0 mg/L
noncorrosive
2.0 mg/L
0.5 mg/L
0.3 mg/L
0.05 mg/L
3 threshold odor number
6.5-8.5
0.10 mg/L
250 mg/L
500 mg/L
5mg/L
OECA/OOIUTB
9-5
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Table 9-3. NOx and SO2 Emission Factors for Boiler Fuel Oil Combustion
Firing Configuration (SCC)'
NOx Emission Factor
(lb/103 gal)b
SO2 Emission Factor
(lb/lb/103 gal)c
Boilers > 100 Million Btu/hr
No. 6 oil fired, normal firing (1-01-004-01), (1-02-
004-01), (1-03-004-01)
No. 6 oil fired, normal firing, low NOx burner, (1-01-
004-01), (1-02-004-01)
No. 6 oil fired, tangential firing, (1-01-004-04)
No. 6 oil fired, tangential firing, low NOx burner, (1-
01-004-04)
No. 5 oil fired, normal firing (1-01-004-05), (1-02-
004-04)
No. 5 oil fired, tangential firing, (1-01-004-06)
No. 4 oil fired, normal firing (1-01-005-04), (1-02-
005-04)
No. 4 oil fired, tangential firing, (1-01-005-05)
No. 2 oil fired (1-01-005-01), (1-02-005-01), (1-03-
005-01)
No. 2 oil fired, LNB/FGR, (1-01-005-01), (1-02-005-
01), (1-03-005-01)
47
40
s
32
26
47
32
47
32
24
10
157S
157S
157S
157S
157S
157S
150S
150S
157S
157S
Boilers < 100 Million Btu/hr
No. 6 oil fired, (1-02-004-02/03), (1-03-004-02/03)
No. 5 oil fired, (1-03-004-04)
No. 4 oil fired, ( 1 -03-005-04)
Distillate oil fired (1-02-005-02/03), (1-03-005-
02/03)
Residential furnace (A2104004/A2 10401 1)
55
55
20
20
18
157S
157S
150S
142S
142S
a SCC = Source Classification Code
b Expressed as NO2. Test results indicate that at least 95% by weight of NOx is NO for all boiler types except
residential furnaces, where about 75% is NO. For utility vertical fired boilers use 105 lb/103 gal at full load and normal
(>15%) excess air. Nitrogen oxides emissions from residual oil combustion in industrial and commercial boilers are
related to fuel nitrogen content, estimated by the following empirical relationship: Ib NO2/103gal = 20.54 + 104.39(N),
where N is the wight % of nitrogen in the oil. For example, if the fuel is 1% nitrogen, then N = 1.
c S indicates that the weight % of sulfur in the oil should be multiplied by the value given. For example, if the fuel is
1 % sulfur, then S = l.
Source: Table 1.3-1 of AP-42 (EPA, 1995)
OECA/OC/IUTB
9-6
-------
Table 9-4. NOx Emission Factors for Boiler Natural Gas Combustion
Combustor Type (MMBtu/hr Heat Input [SCC]
NOx Emission Factor (lb/106 scf)*
Large Wall-Fired Boilers (> 100) [1-01-006-01, 1-02-066-01, 1-03-006-01]
Uncontrolled (Pre-NSPS)b
Uncontrolled (Post-NSPS)b
Controlled - Low NOx burners
Controlled - Flue gas recirculation
280
190
140
100
Small Boilers (<100) [1-01-006-02, 1-02-006-02, 1-03-006-02, 1-03-006-03]
Uncontrolled
Controlled - Low NOx burners
Controlled - Low NOx burners/Flue gas recirculation
100
50
32
Tangential-Fired Boilers (All Sizes) [1-01-006-04]
Uncontrolled
. Controlled - Flue gas recirculation
170
76
Residential Furnaces (<0.3) [No SCC]
Uncontrolled
94
a Expressed as N02. For large and small wall fired boilers with SNCR control, apply a 24 percent reduction to the
appropriate NOx emission factor. For tangential-fired boilers with SNCR control, apply a 13 percent reduction to the
appropriate NOx emission factor.
b NSPS = New Source Performance Standard s defined in 40 CFR Subparts D and Dp. Post-NSPS units are boilers
with greater than 250MMBtu/hr of heat input that commenced construction, modification, or reconstruction after
August 17, 1971, and units with heat input capacities between 100 and 250 MMBtu/hr that commenced construction,
modification, or reconstruction after June 19, 1984.
Source: Table 1.4-1 of AP-42 (EPA, 1995)
OECA/OC/IUTB
9-7
-------
Table 9-5. SO2 Emission Factors for Boiler Natural Gas Combustion
Pollutant
SO,1
Emission Factor (lb/10( scf) |
0.6 1
a Based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content is natural gas of 2,000 grains/106 scf. The
SO2 emission factor in this table can be converted to other natural gas sulfur contents by multiplying the SO2 emission
factor by the ratio of the site-specific sulfur content (grains/106 scf) to 2,000 grains/106 scf.
Source: Table 1.4-2 of AP-42 (EPA, 1995)
Note: This emission factor is to be used for all natural gas fired boilers
Table 9-6. NOx Emission Factors for Process Heater Natural Gas Combustion
Type of Process
Heater
ND
MD
Uncontrolled NOx
Emission Factor
(Ib/MMBtu)'
0.098
0.197
NOx Control Technique
(ND)LNB
(ND)ULNB
(ND) SNCR
(ND) LNB + (ND) SNCR
(MD) LNB
(MD) ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FOR
(MD) LNB + SNCR
(MD) LNB + SCR
Controlled NOx
Emission Factor
(Ib/MMBtu)
0.049
0.025
0.039
0.020
0.099
0.049
0.079
0.049
0.089
0.039
0.025
a Uncontrolled emissions for natural gas-fired heaters are from thermal NOx formation
ND = natural draft
MD = mechanical draft
Source: Table 5-11 and 5-12 of Alternative Control Techniques Document - NOx Emissions from Process Heaters
(EPA, 1993)
OECA/OC/IUTB
9-8
-------
Table 9-7. NOx Emission Factors for Process Heater Oil Combustion
Model Heater
Capacity
(MMBtu/hr)
69
69
135
135
Type of
Process
Heater
ND
ND
MD
MD
Fuel
Distillate
Oil
Residual Oil
Distillate
Oil
Residual Oil
Uncontrolled Emission
Factor (Ib/MMBtu)
Thermal
NOx1
0.14
0.14
0.26
0.26
Fuel
NOz"
0.06
0.28
0.06
0.28
NOz Control
Technique
(ND)LNB
(ND)ULNB
(ND) SNCR
(ND)LNB +
(ND) SNCR
(ND)LNB
(ND)ULNB
(ND) SNCR
(ND)LNB +
(ND) SNCR
LNB
ULNB
SNCR
SCR
LNB + FOR
LNB + SNCR
LNB + SCR
LNB
ULNB
SNCR
SCR
LNB + FOR
LNB + SNCR
LNB + SCR
Controlled
NOz Emission
Factor
(Ib/MMBtu)
0.121
0.048
0.080
0.048
0.308
0.097
0.168
0.123
0.175
0.082
0.128
0.080
0.168
0.070
0.026
0.340
0.143
0.216
0.135
0.355
0.136
0.051
a Uncontrolled emission factor for thermal NOx represents the NOx from thermal NOx formation
b Uncontrolled emission factor for fuel NOx represents the NOx from fuel NOx formation
ND = natural draft
MD - mechanical draft
Source: Table 5-13 and 5-14 of Alternative Control Techniques Document - NOx Emissions from Process Heaters
(EPA, 1993)
OECA/OC/IUTB
9-9
-------
Table 9-8. Estimated Control Efficiencies (%) for NOx
II
Process
Chemical Manufacturing
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion -
Distillate Oil
Fuel Combustion -
Distillate Oil
Fuel Combustion -
Distillate Oil
Fuel Combustion -
Distillate Oil
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion -
Municipal Waste
Fuel Combustion -
Municipal Waste
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Operation
Acrylonitrile -
Incinerator Stacks
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Incinerator
Boiler
Joiler
Control Device Type
Selective Non-catalytic
Reduction
Flue Gas Recirculation
Low Excess Air
Low NOx Burners
Natural Gas Bumers/Rebum
Overfire Air
Selective Catalytic Reduction
Selective Non-catalytic
Reduction
Flue Gas Recirculation
Low Excess Air
Overfire Air
Selective Catalytic Reduction
Low-NOx Burner with Selective
Non-catalytic Reduction
Low-NOx Burner with Overfire
Air and Selective Catalytic
Reduction
Low-NOx Burner with Overfire
Air
Selective Catalytic Reduction
Selective Non-catalytic
Reduction
rlue Gas Recirculation
-ow Excess Air
Average
Control
Efficiency
(%)
80
90
69
1
Control
Efficiency
Range (%)
5-45
5-30
35-55
50-70
5-30
63-94
45-55*
2-19
20-45
90 (max)
50-80
85-95
40-60
80 (max)
30-65
49-68
0-31
OECA/OC/1UTB
9-10
-------
Table 9-1. National Primary Drinking Water Regulations (Continued)
Organic Chemicals (cont.)
Methoxychlor
Oxamyl (Vydate)
Polychlorinated biphenyls (PCBs)
Pentachlorophenol
Pichloram
Simazine
Styrene
Tetrachlorbethylene
Toluene
Total Trihalomethanes (TTHMs)
Toxaphene
2,4,5-TP (Silvex)
1 ,2,4-Trichlorobenzene
1,1,1 -Trichloroethane
1,1,2-Trichloroethane
Trichloroethylene
Vinyl chloride
Xylenes (total)
MCLG1 (mg/L)4
0.04
0.2
zero
zero
0.5
0.004
0.1
zero
1
none5
zero
0.05
0.07
0.20
0.003
zero
zero
10
MCL1 or TT3 (mg/L)4
0.04
0.2
0.0005
0.001
0.5
0.004
0.1
0.005
1
0.10
0.003
0.05
0.07
0.2
0.005
0.005
0.002
10
Radionuclides
Beta particles and photon emitters
Gross alpha particle activity
Radium 226 and Radium 228 (combined)
MCLG1 (mg/L)4
none5
none5
none5
MCL1 or XT' (mg/L)4
4 millirems per year
15 picocuries per liter
(pCi/L)
5pCi/L
Microorganisms
Giardia lamblia
ieterotrophic plate count
^egionella
MCLG1 (mg/L)4
zero
N/A
zero
MCL1 or TT3 (mg/L)4
TT8
TT8
TT8
OECA/OC/1UTB
9-3
-------
Table 9-1. National Primary Drinking Water Regulations (Continued)
Microorganisms
Total coliforms (including fecal coliform and E.coli)
Turbidity
Viruses (enteric)
MCLG1 (mg/L)4
zero
N/A
zero
MCL1 or XT3 (mg/L)4
5.0%'
TT8
TT8
'Maximum Contaminant Level Goal
2Maximum Contaminant Level
'Treatment Technique
'Units are in milligrams per Liter (mg/L) unless otherwise noted.
'MCLGs were not established before the 1986 Amendments to the Safe Drinking Water Act. Therefore, there is no
MCLG for this contaminant.
6Lead and copper are regulated in a treatment technique which requires systems to take tap water samples at sites with
lead pipes or copper pipes that have lead solder and/or are served by lead service lines. The action level, which triggers
water systems into taking treatment steps if exceeded in more than 10% of tap water samples, for copper is 1.3 mg/L,
and for lead is 0.015 mg/L.
'Each water system must certify, in writing, to the state that when acrylamide and epichlorohydrin are used in drinking
water systems, the combination (or product) of dose and monomer level does not exceed the levels specified, as
follows:
Acrylamide = 0.05% dosed at 1 mg/L (or equivalent)
Epichlorohydrin = 0.01% dosed at 20 mg/L (or equivalent)
"The Surface Water Treatment Rule requires systems using surface water or ground water under the direct influence of
surface water to (1) disinfect their water, and (2) filter their water or meet criteria for avoiding filtration so that the
following contaminants are controlled at the following levels:
Giardia lamblia: 99.9% killed/inactivated
Viruses: 99.99% killed/inactivated
Legionella: No limit, but EPA believes that if Giardia and viruses are inactivated, Legionella will also be
controlled.
Turbidity: At no time can turbidity go above 5 NTU; systems that filter must ensure that the turbidity go no
higher than 1 NTU in at least 95% of the daily samples in any month.
HPC: No more than 500 bacterial colonies per milliliter.
*No more than 5.0% samples total coliform-positive in a month. For water systems that collect fewer than 40 routine
samples per month, no more than one sample can be total coliform-positive.
>0Fecal coliform and E.coli are bacteria whose presence indicates that the water may be contaminated with human or
animal wastes.
OECA/OC/IUTB 9-4
-------
Table 9-2. National Secondary Drinking Water Regulations
Contaminant
Aluminum
Chloride
Color
Copper
Corrosivity
Fluoride
Foaming Agents
Iron
Manganese
Odor
PH
Silver
Sulfate
Total Dissolved Solids
Zinc
Secondary Standard
0.05 to 0.2 mg/L
250mg/L
IS (color units)
1.0 mg/L
noncorrosive v
2.0 mg/L
0.5 mg/L
0.3 mg/L
0.05 mg/L
3 threshold odor number
6.5-8.5
0.10 mg/L
250 mg/L
500 mg/L
5 mg/L
OECA/OC/IUTB
9-5
-------
Table 9-3. NOx and SO2 Emission Factors for Boiler Fuel Oil Combustion
Firing Configuration (SCO)'
NOx Emission Factor
(lb/103 gal)"
SO, Emission Factor
(lb/lb/10Jgal)c
Boilers > 100 Million Btu/hr
No. 6 oil fired, normal firing (1-01-004-01), (1-02-
004-01), (1-03-004-01)
No. 6 oil fired, normal firing, low NOx burner, (1-01-
004-01), (1-02-004-01)
No. 6 oil fired, tangential firing, (1-01-004-04)
No. 6 oil fired, tangential firing, low NOx burner, (1-
01-004-04)
No. 5 oil fired, normal firing (1-01-004-05), (1-02-
004-04)
No. 5 oil fired, tangential firing, (1-01-004-06)
No. 4 oil fired, normal firing (1-01-005-04), (1-02-
005-04)
No. 4 oil fired, tangential firing, (1-01-005-05)
No. 2 oil fired (1-01-005-01), (1-02-005-01), (1-03-
005-01)
No. 2 oil fired, LNB/FGR, (1-01-005-01), (1-02-005-
01), (1-03-005-01)
47
40
V,
32
26
47
32
47
32
24
10
157S
157S
157S
157S
157S
157S
150S
150S
157S
157S
Boilers < 100 Million Btu/hr
No. 6 oil fired, (1-02-004-02/03), (1-03-004-02/03)
No. 5 oil fired, (1-03-004-04)
No. 4 oil fired, (1-03-005-04)
Distillate oil fired (1-02-005-02/03), (1-03-005-
02/03)
Residential furnace (A2104004/A2 10401 1)
55
55
20
20
18
157S
157S
150S
142S
142S
a SCC = Source Classification Code
b Expressed as NO2. Test results indicate that at least 95% by weight of NOx is NO for all boiler types except
residential furnaces, where about 75% is NO. For utility vertical fired boilers use 105 lb/103 gal at full load and normal
(>15%) excess air. Nitrogen oxides emissions from residual oil combustion in industrial and commercial boilers are
related to fuel nitrogen content, estimated by the following empirical relationship: Ib NO2/103gal = 20.54 + 104.39(N),
where N is the wight % of nitrogen in the oil. For example, if the fuel is 1% nitrogen, then N = 1.
c S indicates that the weight % of sulfur in the oil should be multiplied by the value given. For example, if the fuel is
1 % sulfur, then S = l.
Source: Table 1.3-1 of AP-42 (EPA, 1995)
OECA/OC/IUTB
9-6
-------
Table 9-4. NOx Emission Factors for Boiler Natural Gas Combustion
Combustor Type (MMBtu/hr Heat Input (SCC)
NOx Emission Factor (lb/10* scf)1
Large Wall-Fired Boilers (>100) [1-01-006-01, 1-02-066-01, 1-03-006-01]
Uncontrolled (Pre-NSPS)k
Uncontrolled (Post-NSPS)b
Controlled - Low NOx burners
Controlled - Flue gas recirculation
280
190
140
100
Small Boilers (<100) [1-01-006-02, 1-02-006-02, 1-03-006-02, 1-03-006-03]
Uncontrolled
Controlled - Low NOx burners
Controlled - Low NOx burners/Flue gas recirculation
100
50
32
Tangential-Fired Boilers (All Sizes) [1-01-006-04]
Uncontrolled
Controlled - Flue gas recirculation
170
76
Residential Furnaces (<0.3) [No SCC]
Uncontrolled
94
a Expressed as NO2. For large and small wall fired boilers with SNCR control, apply a 24 percent reduction to the
appropriate NOx emission factor. For tangential-fired boilers with SNCR control, apply a 13 percent reduction to the
appropriate NOx emission factor.
b NSPS = New Source Performance Standard s defined in 40 CFR Subparts D and Dp. Post-NSPS units are boilers
with greater than 250MMBtu/hr of heat input that commenced construction, modification, or reconstruction after
August 17, 1971, and units with heat input capacities between 100 and 250 MMBtu/hr that commenced construction,
modification, or reconstruction after June 19, 1984.
Source: Table 1.4-1 of AP-42 (EPA, 1995)
OECA/OC/IUTB
9-7
-------
Table 9-5. SO2 Emission Factors for Boiler Natural Gas Combustion
Pollutant
SO,1
Emission Factor (lb/106 set) ||
0.6 I
a Based on 100% conversion of fuel sulfur to S02. Assumes sulfur content is natural gas of 2,000 grains/106 scf. The
SO2 emission factor in this table can be converted to other natural gas sulfur contents by multiplying the SO2 emission
factor by the ratio of the site-specific sulfur content (grains/106 scf) to 2,000 grains/10s scf.
Source: Table 1.4-2 of AP-42 (EPA, 1995)
Note: This emission factor is to be used for all natural gas fired boilers
Table 9-6. NOx Emission Factors for Process Heater Natural Gas Combustion
Type of Process
Heater
ND
MD
Uncontrolled NOx
Emission Factor
(Ib/MMBtu)1
0.098
0.197
NOx Control Technique
(ND)LNB
(ND)ULNB
(ND) SNCR
(ND) LNB + (ND) SNCR
(MD) LNB
(MD)ULNB
(MD) SNCR
(MD) SCR
(MD) LNB + FOR
(MD) LNB + SNCR
(MD) LNB + SCR
Controlled NOx
Emission Factor
(Ib/MMBtu)
0.049
0.025
0.039
0.020
0.099
0.049
0.079
0.049
0.089
0.039
0.025
a Uncontrolled emissions for natural gas-fired heaters are from thermal NOx formation
ND = natural draft
MD = mechanical draft
Source: Table 5-11 and 5-12 of Alternative Control Techniques Document - NOx Emissions from Process Heaters
(EPA, 1993)
OECA/OC/IUTB
9-8
-------
Table 9-7. NOx Emission Factors for Process Heater Oil Combustion
Model Heater
Capacity
(MMBtu/hr)
69
69
135
135
Type of
Process
Heater
ND
ND
MD
MD
Fuel
Distillate
Oil
Residual Oil
Distillate
Oil
Residual Oil
Uncontrolled Emission
Factor (Ib/MMBtu)
Thermal
NOx1
0.14
0.14
0.26
0.26
Fuel
NOx"
0.06
0.28
0.06
0.28
NOx Control
Technique
(ND)LNB
(ND)ULNB
(ND) SNCR
(ND)LNB +
(ND) SNCR
(ND)LNB
(ND) ULNB
(ND) SNCR
(ND)LNB +
(ND) SNCR
LNB
ULNB
SNCR
SCR
LNB + FOR
LNB + SNCR
LNB + SCR
LNB
ULNB
SNCR
SCR
LNB + FOR
LNB + SNCR
LNB + SCR
Controlled
NOx Emission
Factor
(Ib/MMBtu)
0.121
0.048
0.080
0.048
0.308
0.097
0.168
0.123
0.175
0.082
0.128
0.080
0.168
0.070
0.026
0.340
0.143
0.216
0.135
0.355
0.136
0.051
a Uncontrolled emission factor for thermal NOx represents the NOx from thermal NOx formation
b Uncontrolled emission factor for fuel NOx represents the NOx from fuel NOx formation
ND = natural draft
MD = mechanical draft
Source: Table 5-13 and 5-14 of Alternative Control Techniques Document - NOx Emissions from Process Heaters
(EPA, 1993)
OECA/OC/IUTB
9-9
-------
Table 9-8. Estimated Control Efficiencies (%) for NOx
Process
Chemical Manufacturing
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion -
Distillate Oil
Fuel Combustion -
Distillate Oil
Fuel Combustion -
Distillate Oil
Fuel Combustion -
Distillate Oil
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion - Coal
Fuel Combustion -
Municipal Waste
Fuel Combustion -
Municipal Waste
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Operation
Acrylonitrile -
Incinerator Stacks
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Incinerator
Boiler
Boiler
Control Device Type
Selective Non-catalytic
Reduction
Flue Gas Recirculation
Low Excess Air
Low NOx Burners
Natural Gas Burners/Rebum
Overfire Air
Selective Catalytic Reduction
Selective Non-catalytic
Reduction
Flue Gas Recirculation
Low Excess Air
Overfire Air
Selective Catalytic Reduction
Low-NOx Burner with Selective
Non-catalytic Reduction
Low-NOx Burner with Overfire
Air and Selective Catalytic
Reduction
Low-NOx Burner with Overfire
Air
Selective Catalytic Reduction
Selective Non-catalytic
deduction
Flue Gas Recirculation
Low Excess Air
Average
Control
Efficiency
(%)
80
90
69
Control
Efficiency
Range (%
5-45
5-30
35-55
50-70
5-30
63-94
45-55*
2-19
20-45
90 (max)
50-80
85-95
40-60
80 (max)
30-65
49-68
0-31
OECA/OC/IUTB
9-10
-------
Table 9-8. Estimated Control Efficiencies (%) for NOx (Continued)
" ' ' " * ' - *',..'
. * -, . * ' " i * -. '" *
'""' \. Process .;.'. ,
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Gas
Fuel Combustion -
Natural Boiler Gas
Fuel Combustion -
Residual Oil
Fuel Combustion -
Residual Oil
Fuel Combustion -
Residual Oil
Fuel Combustion -
Residual Oil
Tuel Combustion -
Residual Oil
;uel Combustion - Utility
Oil or Natural Gas
uel Combustion - Wood
Mineral Products
ndustry
'etroleum Industry
Operation ,,
Boiler
Boiler
Boiler
Boiler
Gas Turbines
Gas Turbines
Reciprocating
Engines
Gas Turbines
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Boiler
Glass Flue
Process Heater
. . . .- . ; Control Device Type
Low NOx Burners
Overfire Air
Selective Catalytic Reduction
Selective Non-Catalytic
Reduction
Selective Catalytic Reduction
Water or Steam Injection
Selective Non-catalytic
Reduction
Staged Combustion
Low-NOx Burner with Overfire
Air
Flue Gas Recirculation
Low Excess Air
Overfire Air
Selective Catalytic Reduction
Selective Non-catalytic
Reduction
Flue Gas Recirculation
Selective Non-catalytic
Reduction
Selective Non-catalytic
Reduction
Selective Catalytic Reduction
Average
Control
Efficiency
(%)
'60
21
90
Control
Efficiency
Range (%)
40-85
" ' 13-73
80-90
35-80
60-96
60-94
80-90
50-80
40-50
2-31
5-31
24-47
70-80
35-70
40-65
50-70
50-75
OECA/OC/IUTB
-------
Table 9-8. Estimated Control Efficiencies (%) for NOx (Continued)
Process
Petroleum Industry
Operation
Process Heater
Control Device Type
Selective Non-catalytic
Reduction
Average
Control
Efficiency
(%)
Control
Efficiency
Range (%)
35-70
* Average of widely varying values
Source: Table 12.3-1 of EIIP, Vol II, Chapter 12
OECA/OC/IUTB
9-12
------- |