U.S. Department of the Interior

Minerals Management Service 

Gulf of Mexico OCS Region 

OCS Study 

MMS 2002-073 

Emission Inventories of OCS 

Production and Development Activities 

in the Gulf of Mexico 

Final Report 

Authors 

Dana L. Coe 

Courtney A. Gorin 

Lyle R. Chinkin 

Sonoma Technology, Inc 

Petaluma, California 

Mark Yocke 

ENVIRON International, Inc. 

Novato, California 

David Scalfano 

Northlake Engineers and Surveyors, Inc. 

Mandeville, Louisiana 

Prepared under MMS Contract 

1435-01-98-CT-30856 

by 

Sonoma Technology, Inc. 

1360 Redwood Way, Suite C 

Petaluma, California 94954-1169 

Published by 

New Orleans

February 2003 
 iii

DISCLAIMER 

This Final Report was prepared under contract between the Minerals Management Service 

(MMS) and Sonoma Technology, Inc. This Final Report has been technically reviewed by the 

MMS, and it has been approved for publication. Approval does not signify that the contents 

necessarily reflect the views and policies of the MMS, nor does mention of trade names or 

commercial products constitute endorsement or recommendation for use. It is, however, exempt 

from review and compliance with the MMS editorial standards. 

REPORT AVAILABILITY 

Extra copies of this report may be obtained from the Public Information Office (Mail Stop 5034) 

at the following address: 

U.S. Department of the Interior 

Minerals Management Service 

Gulf of Mexico OCS Region 

Public Information Office (MS 5034) 

1201 Elmwood Park Boulevard 

New Orleans, Louisiana 70123-2394 

Telephone: (504) 736-2519 or 

 1-800-200-GULF 

CITATION 

Suggested citation: 

Coe D.L., Gorin, C.A., Chinkin L.R., Yocke M., and Scalfano, D. 2003. Emission inventories of 

OCS production and development activities in the Gulf of Mexico: final report. 

U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, 

New Orleans, LA. OCS Study MMS 2002-073. 200 pp.
v 

ACKNOWLEDGMENTS 

The authors wish to acknowledge the contributions of key MMS staff: Bill Hutzell, 

Alexis Lugo-Fernandez, Terry Schoelten, Richard Karp, and Wallace Adcox. The authors also 

wish to acknowledge Ensco, Inc. of Melbourne, Florida for developing the draft version of the 

database management system and documentation.
vii 

TABLE OF CONTENTS 

Section Page

LIST OF FIGURES........................................................................................................................ ix 

LIST OF TABLES ......................................................................................................................... xi 

LIST OF ABBREVIATIONS ......................................................................................................xiii

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

1.1 Background ..........................................................................................................1-1 

1.2 Project Objectives ................................................................................................1-2 

1.3 Scope of Work......................................................................................................1-2 

1.3.1 Prepare Backcast Inventories for 1977 and 1988.....................................1-2 

1.3.2 Compile a Current-year BAMP Inventory of Platform Sources..............1-3 

1.3.3 Develop a Database Management System (DBMS) ................................1-4 

1.4 Guide to This Report............................................................................................1-4 

2. PREPARE BACKCAST INVENTORIES FOR 1977 AND 1988 ..................................2-1 

2.1 Overview of Historical Emissions........................................................................2-1 

2.2 Stationary Sources................................................................................................2-4 

2.2.1 Summary of Technical Approach ............................................................2-4 

2.2.2 Results ......................................................................................................2-4 

2.3 Mobile Sources...................................................................................................2-10 

3. YEAR-2000 EMISSION INVENTORY FOR OUTER CONTINENTAL SHELF 

PLATFORMS IN THE VICINITY OF BRETON NATIONAL WILDLIFE AREA.....3-1 

3.1 Inventory Development Methods.........................................................................3-1 

3.1.1 Data Collection.........................................................................................3-1 

3.1.2 Input Data Processing, Quality Assurance, and Quality Control.............3-1 

3.1.3 Database Management System Processes................................................3-1 

3.2 Summary of Estimated Emissions........................................................................3-2 

4. REFERENCES.................................................................................................................4-1 

APPENDIX A: PLATFORM ACTIVITY DATA SOURCES AND PROCESSING FOR 

ESTIMATING HISTORICAL EMISSIONS...................................................A-1 

APPENDIX B: GRIDDED EMISSIONS FOR MOBILE SOURCES, 1977 AND 1988......... B-1 

APPENDIX C: EMISSION PLOTS FOR PLATFORMS, 1977 AND 1988 ............................ C-1 

APPENDIX D: DATA STRUCTURES AND FORMATS FOR 1977 AND 

1988 INVENTORIES ......................................................................................D-1 

APPENDIX E: EMISSIONS CALCULATION PROCEDURES AND QUALITY 

CONTROL PROCEDURES FOR THE DATABASE MANAGEMENT 

SYSTEM .......................................................................................................... E-1 

APPENDIX F: DOCUMENTATION AND GUIDE FOR THE DATABASE 

MANAGEMENT SYSTEM .............................................................................F-1 
ix 

LIST OF FIGURES 

Figure Page

1-1. Outer continental shelf (OCS) facilities in the Gulf of Mexico.........................................1-1 

2-1. Example gridded mobile source emissions display...........................................................2-3 

2-2. Example gulf-wide platform emissions display ................................................................2-3 

2-3a. Relative contribution by source type to 1977 emissions ...................................................2-5 

2-3b. Relative contribution by source type to 1988 emissions ...................................................2-5 

2-4a. Estimated gulf-wide emissions for 1977 ...........................................................................2-6 

2-4b. Estimated gulf-wide emissions for 1988 ...........................................................................2-6 

2-5. Natural gas released to vents or flares in the Gulf of Mexico ...........................................2-7 

2-6. The temporal variation of activity by equipment type in 1988 .........................................2-8 

2-7a. Monthly variation of SOx emissions in 1988....................................................................2-9 

2-7b. Monthly variation of CO, NOx, THC, and VOC emissions in 1988.................................2-9 

2-7c. Monthly variation of PM emissions in 1988 .....................................................................2-9 

3-1. Monthly total emissions for OCS facilities included in the year 2000 BNWA 

emission inventory.............................................................................................................3-3 

3-2. Monthly total CO emissions by type of equipment or process for OCS facilities 

included in the year 2000 BNWA emission inventory......................................................3-5 

3-3. Monthly total NOx emissions by type of equipment or process for OCS facilities 

included in the year 2000 BNWA emission inventory......................................................3-5 

3-4. Monthly total PM10 by type of equipment or process for OCS facilities included 

in the year 2000 BNWA emission inventory.....................................................................3-6 

3-5. Monthly total SOx emissions by type of equipment or process for OCS facilities 

included in the year 2000 BNWA emission inventory......................................................3-6 

3-6. Monthly THC emissions by type of equipment or process for OCS facilities 

included in the year 2000 BNWA emission inventory......................................................3-7 

3-7. Monthly total VOC emissions by type of equipment or process for OCS 

facilities included in the year 2000 BNWA emission inventory .......................................3-7 
x 

LIST OF FIGURES (Continued) 

Figure Page

3-8. Distributions of annual total emissions for six pollutants by type of equipment 

or process for OCS facilities included in the year 2000 BNWA emission inventory .......3-8 

3-9. Geographic distribution of total annual CO emissions for OCS facilities included 

in the year 2000 BNWA emission inventory.....................................................................3-9 

3-10. Geographic distribution of total annual NOx emissions for OCS facilities included 

in the year 2000 BNWA emission inventory.....................................................................3-9 

3-11. Geographic distribution of total annual SOx emissions for OCS facilities included 

in the year 2000 BNWA emission inventory...................................................................3-10 

3-12. Geographic distribution of total annual PM10 for OCS facilities included in the 

year 2000 BNWA emission inventory.............................................................................3-10 

3-13. Geographic distribution of total annual VOC emissions for OCS facilities included 

in the year 2000 BNWA emission inventory...................................................................3-11 
xi 

LIST OF TABLES 

Table Page

1-1. OCS emission inventory source categories .......................................................................1-3 

2-1a. Total 1977 emissions related to OCS oil and gas production and development ..............2-1 

2-1b. Total 1988 emissions related to OCS oil and gas production and development ..............2-2 

2-2. Basis and source of emissions or activity data for emission source categories ................2-4 

3-1. Minimum and maximum monthly total emissions for OCS facilities included in 

the year 2000 BNWA emission inventory.........................................................................3-3 

3-2. Minimum, maximum, and average monthly counts of active equipment units 

or processes included in the year 2000 BNWA emission inventory .................................3-4 
xiii 

LIST OF ABBREVIATIONS 

BAMP Breton Aerometric Monitoring Program 

BNWA Breton National Wildlife Area 

BOADS Breton Offshore Activities Data System for Air Quality 

CD compact disc 

CO carbon monoxide 

CON construction 

DBMS Database Management System 

DMA Marine Distillate fuel A 

DMB Marine Distillate fuel B 

DRILL drilling 

EPA U.S. Environmental Protection Agency 

EQ engines, turbines, and boilers 

ESRI Environmental Systems Research Institute, Inc. 

FL flares 

FWS Fish and Wildlife Service 

GIS Geographic Information System 

GLY glycol units 

GMAQS Gulf of Mexico Air Quality Study 

GV gas venting 

H2S hydrogen sulfide 

HC hydrocarbons 

hp horsepower 

LTO landing/takeoff 

MMS Minerals Management Service 

MOAD MMS Offshore Activities Database 

MUD mud degreasing 

NO2 nitrogen dioxide 

NOx oxides of nitrogen 

NTL Notice to Lessees 

OCS Outer Continental Shelf 

ODS Offshore Data Services 

OOC Offshore Operators Committee 
xiv 

LIST OF ABBREVIATIONS (Continued) 

PM particulate matter 

PM10 particulate matter less than 10 microns 

PM2 5 particulate matter less than 2.5 microns 

PSD prevention of significant deterioration 

QA quality assurance 

QC quality control 

SOx oxides of sulfur 

SO2 sulfur dioxide 

STI Sonoma Technology, Inc. 

STO storage tanks 

THC total hydrocarbons 

TSP total suspended particulates 

USCG U.S. Coast Guard 

VOC volatile organic compounds 

1-2

(OCS) leaseholders within 100 km of BNWA to collect and submit meteorological, air quality, 

and emissions data. In response, the Offshore Operators Committee (OOC) initiated the Breton 

Aerometric Monitoring Program (BAMP) to collect air quality, meteorological, and emissions 

information. This report summarizes the results of emissions data collection efforts that took 

place during the year 2000. Approximately 500 offshore structures within 100 km of the BNWA 

are represented. 

1.2 PROJECT OBJECTIVES 

The purpose of this project, “Emission Inventories of OCS Production and Development 

Activities in the Gulf of Mexico” (MMS Contract No. J-30856) is to provide technical support 

for the development of the year-2000 BAMP and past years’ (1977, 1988) gridded emission 

inventories. The gridded OCS emission inventories include primary air pollutants (carbon 

monoxide [CO], oxides of nitrogen [NOx], sulfur oxides [SOx], total suspended particulates 

[TSP], particulate matter less than 10 microns [PM10], particulate matter less than 2.5 microns 

[PM2.5], total hydrocarbons [THC], and volatile organic compounds [VOC]). These inventories 

include area and mobile sources that are spatially resolved to the grid-cell level, and point 

sources that are assigned to specific coordinates. Past-year inventories were developed from a 

1991 base-year inventory. Additionally, software tools to assist the MMS to collect and manage 

the OCS emission inventory in the future were developed. 

1.3 SCOPE OF WORK 

1.3.1 Prepare Backcast Inventories for 1977 and 1988 

Historical inventories for the entire Gulf of Mexico were prepared for 1977 and 1988 

to support PSD baseline analyses. OCS emission source categories included in the historical 

inventories are shown in Table 1-1. The quality of the historical inventories depends heavily 

on the reliability of the source data. For this project, the sources of data were (a) the 

year-2000 emission inventory developed during the BAMP, (b) the 1993 gulf-wide emission 

inventory developed by MMS, and (c) historical records of oil and gas exploration and 

production in the Gulf of Mexico. 
1-3

Table 1-1. OCS emission inventory source categories. 

Source Category Source Description 

Platform Sources Platform Equipment 

 -engines and turbines 

 -storage tanks 

 -flares 

 -glycol regenerators 

 -vents 

 -amine units 

 -fugitive emissions 

 -petroleum loading/unloading 

Platform-Associated Sources Crew/Supply Boats 

Oil Barges 

Shuttle Tankers 

Tugboats 

Research Vessels 

Crew Helicopters 

Construction Barges 

Pipeline Sources Pipeline Construction Equipment 

 -pipeline barges 

 -tugboats 

Exploration & Drilling Drilling Equipment 

 -Engines and Turbines 

 -Mud Degassing 

1.3.2 Compile a Current-year BAMP Inventory of Platform Sources 

An inventory of offshore facilities (including platforms and wellheads) for the BAMP 

study period was constructed. The inventory was based on MMS’ survey of facilities within 100 

km of the BNWA (per NTL 96-04). The inventory covered platform equipment and processes 

for surveyed facilities. Many significant emissions sources within the OCS are non-platform or 

temporary sources that were not surveyed, such as crew and supply boats, crew and supply 

helicopters, pipeline-laying vessels, exploratory and drilling vessels, military and commercial 

ships, barges, commercial fishing boats, recreational boats, geogenic sources, and biogenic 

sources. (However, the historical 1977 and 1988 inventories, discussed above, included nonplatform area sources for the gulf-wide area.) Current year (BAMP-period) estimates of OCS 

platform emission sources were prepared for the following platform source categories: 

• Platform equipment • Engines and turbines 

• Flares • Storage tanks 

• Glycol regenerators • Platform drilling equipment 

• Vents • Boilers 

• Amine units • Fugitive emissions 

• Petroleum loading and 

unloading operations 
1-4

MMS’ survey data included an MMS-approved source identification code, owner, 

location, source type code, and activation/de-activation (or “deployment”) dates for each 

platform. In addition, the data include month- and source-specific activity data, such as times of 

operation, process throughputs, and control efficiencies. The database is organized according to 

individual sources, structure, complexes, and lessees at monthly averaging periods (or more 

highly resolved time periods for selected upset conditions). 

Specialized data collection software was developed (Breton Offshore Activities Data 

System for Air Quality [BOADS]) for use by MMS to collect and perform end-user QA/QC of 

the current-year emissions activity data. The BOADS software incorporated automated QA/QC 

including checks of (1) parameter ranges and magnitudes by source categories and (2) data 

formats and units to ensure data integrity. 

1.3.3 Develop a Database Management System (DBMS) 

The final element of the study was to provide a reliable and efficient means to produce 

and maintain the OCS activity and emissions databases (including the current-year BNWA 

inventory). To accomplish this objective, a relational DBMS built in Oracle was developed and 

delivered to the MMS. The DBMS facilitates data input, rapid data access, automated data 

reports, and efficient data queries. The DBMS also computes and provides error warnings, range 

checks, and outlier flags. 

1.4 GUIDE TO THIS REPORT 

The remainder of this report is divided into sections covering each of the three major 

elements of the study as listed above. Section 2 provides a summary of the methods and results 

of the historical backcasts. Section 3 provides a description of the current year BNWA inventory 

and an overview of the Oracle DBMS built to store the emission inventory. Appendix A details 

emissions backcasting estimation methods and data sources. Appendices B and C contain 

graphical displays. Appendix D presents emission activity data storage formats. Appendix E 

presents current-year emissions estimation methods. Appendix F contains documentation of the 

DBMS. 
2-1 

2. PREPARE BACKCAST INVENTORIES FOR 1977 AND 1988 

2.1 OVERVIEW OF HISTORICAL EMISSIONS 

In this section, we provide an overall summary of the historical emissions for activities 

related to the development and production of oil and gas in the Gulf of Mexico estimated in this 

study and provide brief descriptions of the data sources and methods used to estimate historical 

emissions. More details of the inventory compilation are provided in Appendix A. The 

emissions-related activities covered in this emission inventory compilation are divided into 

stationary (e.g., platform-based equipment) and mobile (e.g., transitory equipment including 

crew and supply boats, drill and pipeline-laying vessels, etc.) sources. 

Tables 2-1a and 2-1b list the emissions for each of the source categories included in this 

study for 1977 and 1988. As shown in the table, no single source category is responsible for 

most of the emissions. Overall, platform emissions are greater than mobile source emissions. 

Among platform sources, platform equipment (e.g., engines, turbines, and boilers) are the 

predominant source of combustion-related emissions, venting is the predominant source of THC 

and VOC, followed closely by glycol units. Among mobile sources, crew and supply boats are 

the single largest source category of all pollutants. It is also interesting to note that different 

pollutants trend differently from 1977 to 1988, with some increasing, some decreasing, and some 

remaining about the same. 

Table 2-1a. Total 1977 emissions related to OCS oil and gas production and development. 

1977 Annual Total Emissions (tons)

 CO NOx TSP PM10 PM2 5 SOx THC VOC 

Mobile Sources 

Helicopters 8 27 4 2 1 4 1 1

Crew & Supply Boats 1,493 13,305 331 331 304 2,408 142 142

Exploration Ships 178 1,367 34 34 31 631 18 18

Drill Ships 320 4,034 100 100 92 1,811 25 25

Pipe Laying Ships 110 848 21 21 19 392 11 11

Total Mobile 2,109 19,581 489 488 448 5,246 198 198

Stationary Sources 

Construction 685 2,580 56 46 39 293 73 66

Drilling 3,521 13,257 289 237 198 1,674 373 328

Platform equipment 76,599 57,946 486 486 486 182 15,791 1,101

Flaring 2,755 506 7 7 7 4,807 0 0

Glycol units 0 0 0 0 0 0 12,530 12,430

Venting 0 0 0 0 0 0 434,895 24,319

Mud Degassing 0 0 0 0 0 0 2,998 0

Storage Tanks 0 0 0 0 0 0 9,843 9,138

Total Stationary 83,561 74,289 838 777 730 6,956 476,502 47,382

TOTAL 85,670 93,869 1,328 1,265 1,179 12,202 476,699 47,580
2-2 

Table 2-1b. Total 1988 emissions related to OCS oil and gas production and development. 

1988 Annual Total Emissions (tons)

 CO NOx TSP PM10 PM2 5 SOx THC VOC 

Mobile Sources 

Helicopters 14 48 7 4 3 7 1 1

Crew & Supply 

Boats 2,668 23,773 591 591 544 4,303 254 254

Exploration 

Ships 178 1,367 34 34 31 631 18 18

Drill Ships 566 7,141 176 176 162 3,206 46 46

Pipe Laying 

Ships 134 1,031 26 26 24 476 14 14

Total Mobile 3,560 33,359 834 831 764 8,623 333 333

Stationary 

Sources 

Construction 880 3,314 104 85 71 377 93 85

Drilling 1,759 6,621 144 119 99 836 186 164

Platform 

equipment 96,888 73,294 584 584 584 182 19,974 1,393

Flaring 1,212 223 3 3 3 2,114 0 0

Glycol units 0 0 0 0 0 0 15,226 15,105

Venting 0 0 0 0 0 0 235,508 13,169

Mud Degassing 0 0 0 0 0 0 2,619 0

Storage Tanks 0 0 0 0 0 0 10,451 9,703

Total 

Stationary 100,739 83,452 835 791 758 3,509 284,057 39,619

TOTAL 104,299 116,811 1,669 1,622 1,521 12,132 284,390 39,951

Mobile source emissions were assigned spatial distributions and platform equipment 

emissions were assigned geographic coordinates as described later in this section (see 

Figures 2-1 and 2-2; see Appendix D for documentation and spatial data). Complete sets of 

figures for 1977 and 1988 are included in Appendix B for all mobile source emissions and in 

Appendix C for platform emissions. 
2-3 

Figure 2-1. Example gridded mobile source emissions display. 

(Projection is defined in Appendix B.) 

Figure 2-2. Example gulf-wide platform emissions display. 

(Projection is defined in Appendix C.) 
2-4 

2.2 STATIONARY SOURCES 

2.2.1 Summary of Technical Approach 

The gulf-wide emissions inventory (MOADS 3), which was developed as part of the Gulf 

of Mexico Air Quality Study (GMAQS) in 1993, served as the basis for many of the backcasts 

performed in this study. Although MOADS 3 was the best available data for gulf-wide 

emissions estimates, it still required considerable augmentation and modification for use in 

backcasting the 1977 and 1988 historical emissions inventories. For example, not all platformrelated sources required for this study were included in the 1993 MOADS 3 (see Table 2-2). 

Specifically, drilling and construction sources were added, and improved emission factors and 

activity data were incorporated. 

The adjusted MOADS 3 inventory was then used as a baseline from which historical 

emissions could be estimated by using economic scaling factors or extrapolated activity data 

(such as commissioning or decommissioning dates, growth or decline in production rates, 

estimated activity variation of platform equipment, the addition of emissions controls, or the 

introduction of new technologies). For some sources, emissions modeling techniques were 

employed to directly estimate emissions from emission factors and average or default values. In 

other cases, a range of possible emissions estimates was generated to examine the relative 

importance of the emissions sources and the effects of selected estimation methodologies. 

Historical emissions were distributed in space and time according to historical activity data or 

more recently developed Gulf-specific information by using spatial analysis techniques. 

Detailed descriptions of data sources, emission factors, and estimation methods are provided in 

Appendix A. 

Table 2-2. Basis and source of emissions or activity data for emission source categories. 

Source Category Source Description 

Source 

Type Emissions Data Source of Emissions Data 

Platform Sources Platform Equipment 

 -engines and turbines 

 -storage tanks 

 -flares 

 -glycol regenerators 

 -vents 

Stationary Physical and 

operational data for 

stationary source 

activity 

Data from MMS BOADS 

survey program and/or 

existing emissions data; 

MOADS 3 emissions 

database 

Platform Associated 

Sources 

Construction Barges Area Construction activity MMS platform construction 

and modification records 

 

Exploration & 

Drilling 

Drilling Equipment 

 -Engines and Turbines 

 -Mud Degassing 

Area Activity data Drill rig permits and 

schedules from MMS 

database 

2.2.2 Results 

Figures 2-3 and 2-4 depict the relative emissions for each platform-related emissions 

source for 1977 and 1988 and the total emissions for all platform equipment combined. Platform 





2-10 

Historical Trends

Oil and gas development and production are subject to economic cycles and 

technological limitations. Examination of the historical activity data compiled in this study 

reveals several observable trends. For example, within 100 km of the BNWA the number of 

platforms approximately doubled, increasing from 300 to 500, from 1990 to 2000. It is also 

interesting to note that the average platform depth was relatively unchanged at approximately 

100 feet during the period from 1977 to 1990, but the average depth more than doubled after 

1998 through the current year. The deeper the water, the more energy is required to construct the 

platform, which is directly proportional to emissions generation. This same trend is inherent in 

drilling activity data as well. Although the actual numbers of wells drilled per year is decreasing 

due to better detection equipment and past exploration, the depth of wells drilled is increasing 

over time. 

Interestingly, from 1977 to 1990, the amount of gas released to vent or flare equipment 

declined; but the amount released after 1990 increased in concert with increasing production 

levels (note that gulf-wide oil production has almost doubled since 1990). Emissions from diesel 

engines also reflect a doubling of diesel engine use from 1990 to 2000. A reduction in flaring 

activity from 1977 to 1990 was also observed. As the amount of flaring decreases, the emissions 

from other platform equipment contribute a greater share of the inventory. 

2.3 MOBILE SOURCES 

This section summarizes the approach and results of the development of gridded 

emissions inventories for mobile sources operating in the OCS areas of the Gulf of Mexico. The 

subjects of this study were only those mobile sources related to oil and gas exploration and 

production activities in the OCS and included 

• crew and supply boats, 

• pipeline-laying ships, 

• research and exploration vessels, 

• crew and supply helicopters, and 

• drilling ships. 

The data sources and methods for estimating emissions from the each source category 

were somewhat different; the methodologies and results are discussed in the following 

subsections. Some issues are also common to more than one category. Gulf-wide emissions 

were spatially allocated to a 45 (west to east) by 26 (south to north) grid, about 20-km by 20-km 

with a grid origin (southwest corner) located at coordinates 26 degrees North latitude and 97.2 

degrees East longitude. All gridding was performed using ESRI’s ARC/INFO, a commonly used 

GIS software package. (Map projection is provided in Appendix B.) 

The 1993 MMS Offshore Activity Data Bases (MOADS) served as the starting point for 

many of the backcasts. MOADS contains data pertaining to the numbers, activities, fuel 

consumption, and engine sizes of crew and supply boats and helicopters. These data provide 

1993 emissions totals, which serve as basis for backcasting and gridding of emissions for some 
2-11 

source categories. In addition, MMS recently published a series of data compact discs (CD) 

entitled “50 Year Anniversary Offshore Oil and Gas CD Collection.” Data from this four-CD set 

and additional data downloaded from the MMS Internet web site were used to estimate the 

numbers of active platforms, production levels, and drilling and pipeline-laying activities and 

locations in 1977 and 1988. Ship vessel registration and characteristics data maintained by the 

U.S. Coast Guard (USCG) were accessed and used to characterize the size and propulsion units 

of research vessels. A private data source (Offshore Data Services [ODS], 1977 and 1988) 

provided historical information about pipeline-laying and drill-ship activities. For each mobile 

source category, specific emission factors were obtained from EPA databases (AP42 and/or 

NONROAD) for THC, CO, NOx, SOx, and TSP. VOC factors were expressed as fractions of 

THC emissions, and PM10 and PM2.5 factors were expressed as fractions of TSP emissions. 

Crew and Supply Helicopters

There are 13 companies operating helicopters in the OCS region, which are represented 

in the 1993 MOADS, from which 1993 helicopter activity levels and areas of operations, as well 

as emissions estimates, were derived. Helicopter emission factors are from AP-42, Table II-1-8. 

We selected emissions factors representative of turbine engines in the helicopter fleet operating 

in the Gulf of Mexico OCS region and assumed a jet fuel density factor of 2.6 kg/gal. Emissions 

were estimated for all phases of helicopter operation since these helicopters most often operate 

within the convective marine mixing layer. Since landings/takeoffs (LTOs) comprise a very 

small portion of the total hours of operation and no LTO data were available, they are ignored in 

this analysis. Furthermore, since helicopters utilize a relatively constant amount of power for all 

phases of operation, a single emission factor was used for all flight modes. Thus, emissions were 

estimated as the product of the emission factor and the total hours of flight. 

Helicopter emissions for 1988 and 1977 were estimated by assuming that OCS-wide 

emissions were proportional to the number of platforms operating in those years compared to 

1993. The total OCS emissions were then spatially allocated by assuming that emissions in each 

cell were proportional to the number of operating platforms in that cell. PM2.5 and PM10 were 

estimated from TSP by applying mass fractions of 0.390 and 0.553 taken from the NONROAD 

SPECIATE database version 1.5 (profile #34001 - Jet Aircraft). VOC was estimated as 90% of 

THC. Based upon the SPECIATE database (Version 3.0, profile 1098 - Aircraft 

Landing/Takeoff [LTO] - Commercial), it was assumed that methane and ethane comprise about 

10% of THC. 

The 1993 MOADS database contained estimates only of crew and supply helicopters’ 

fuel consumption and operating hours by helicopter type. No information was available for 

routes flown or departure/destination pair statistics. Also, spatial allocation factors and 

information were not preserved in the MOADS database. Thus, it was required that we devise a 

new spatial allocation procedure for this historical backcasting effort. 

It was determined in the 1993 GMAQS study that helicopter routing is frequently 

indirect, offshore trips often involve stops at more than one platform and may involve multiple 

refueling stops at certain offshore platforms. We observed that the spatial distribution of the 

final gridded offshore area source emission inventories plotted in the GMAQS report largely 
2-12 

reflected the distribution of platforms. Thus, our spatial allocation procedures simply allocated 

total offshore helicopter emissions in proportion to the number of platforms in each grid cell. 

Total offshore emissions were calculated as the product of the total flight hours for each 

helicopter type and an emissions factor appropriate to the specific engine on each helicopter 

type. The distance traveled by the helicopter is implicitly accounted for in the number of flight 

hours as distance traveled is simply the product of flight hours and average speed. The specific 

routes of flights were not explicitly treated; it was assumed that the level of helicopter activities 

and routing are related to the position and number of offshore platforms. It can be argued that 

this method might, in principle, lead to underestimation of emissions closer to shore since all 

offshore crew and supply helicopters initially embark from land bases. However, allocation of 

emissions to near-shore platforms included emissions due to multiple stops and refueled missions 

that actually occurred further offshore. Thus, the possible short-changing of emissions from 

helicopters transiting the near-shore tracts en route to tracts farther offshore is at least 

qualitatively offset by this allocation to near-shore tracts of emissions from extra offshore legs. 

As a practical matter, an elaborate spatial allocation scheme that explicitly accounts for 

the large number of possible helicopter routes is not warranted given the overall level of 

uncertainty involved in the emissions backcasting process. The spatial distribution produced by 

our methods is reasonably plausible and consistent with the final inventories presented in the 

GMAQS report. 

Crew and Supply Boats

The MOADS data contains 1993 annual usage data in hours and rated horsepower for the 

crew and supply boats by engine type. The crew and supply boat emission factors were derived 

from information given in Table 5-1 of Analysis of Commercial Marine Vessels Emissions and 

Fuel Consumption Data (U.S. Environmental Protection Agency, 2000). This reference presents 

the following equation for calculating PM, NOx, CO, and HC emissions factors: 

Emissions Rate (g/kW-hr) = a (Fractional Load)^(-x) + b (2-1)

The equation for SO2 is 

Emissions Rate (g/kW-hr) = a (Fuel Sulfur Flow in g/kW-hr) + b (2-2)

The equation for fuel consumption is 

Fuel Consumption (g/kW-hr) = 14.12/(Fractional Load) + 205.717 (2-3)

Marine diesel fuel sulfur level was obtained from Table 4 of In-Use Marine Diesel Fuel 

(U.S. Environmental Protection Agency, 1999) as 0.36% by weight for DMA, the predominant 

marine fuel for medium and small engine vessels. Emission factors were estimated at 70% load, 

based on Table 5-2 in the reference above, and expressed as mass per horsepower-hour (hp-hr). 

The 1977 and 1988 total emissions were estimated by scaling the 1993 emissions by the 

ratio of platforms operating in 1977 and 1988 to those operating in 1993, respectively. The total 

emissions were increased by a factor of 1.56 to account for the fact that only 64% of the crew 
2-13 

and supply boat operators responded to the 1993 MOADS activity survey. The spatial allocation 

procedures used were the same as for crew and supply helicopters, with each cell receiving the 

amount of emissions proportional to the number of platforms present. 

PM10 and PM2.5 were estimated from TSP using the fractions 1.0 and 0.92 which were 

obtained from the NONROAD SPECIATE database version 1.5 profile # 32202 - Heavy duty 

diesel. 

For lack of specific data, it was assumed that VOC emissions are approximately equal to 

THC. This seems reasonable in the case of heavy-duty diesel engines since they emit little 

methane or ethane. 

The method used to estimate 1993 crew and supply boat emissions was similar to that 

used in the 1993 MOADS, but we used updated emission factors. 1993 annual boat usage data 

were obtained from the MOADS database. Emission factors were calculated on the basis of a 

recent EPA report (U.S. Environmental Protection Agency, 2000). The EPA emission factor 

equations were derived from a substantially larger database than previous factors, cover a wide 

range of engine sizes (encompassing the boat types of interest here), and are reported to be an 

improvement over previous emission factor estimation methods. 

Table 2-3. Marine engine emission factor and fuel consumption algorithms, 

in g/kW-hr, for all marine engines (U.S. Environmental Protection 

Agency, 2000). 

Pollutant Exponent (x) Intercept (b) Coefficient (a) 

PM 1.5 0.2551 0.0059 

NOx 1.5 10.4496 0.1255 

NO2 1.5 15.5247 0.18865 

SO2 n/a n/x 2.3735 

CO 1 n/s 0.8378 

HC 1.5 n/s 0.0667 

CO2 1 648.6 44.1 

1. All regressions but SO2 are in the form of 

 Emissions Rate (g/kW-hr) = a (Fractional Load) -x + b 

2. Fractional load is equal to actual engine output divided by rated engine output. 

3. The SO2 regression is the form of: 

 Emissions Rate (g/kW-hr) = a (Fuel Sulfur Flow in g/kW-hr) + b 

4. Fuel Consumption (g/kW-hr) = 14.12/(Fractional Load) + 205.717. To convert the calculated fuel 

consumption into units of (gallons pounds per kW-hr), divide by these figures by 3780 g/gallon. 

5. n/a = not applicable; n/s = not statistically significant. 

Due to the use of updated emissions factors in this study, total 1993 emissions estimated 

in this study for crew and supply boats were somewhat different than the totals reported in the 

1993 GMAQS report. The current estimates of crew and supply boats NOx emissions are 

significantly higher, VOC significantly lower, and CO about the same as reported in the 
2-14 

GMAQS report. In this study, we opted to use the most current emissions factors rather than 

replicating the 1993 MOADS results. 

As was the case for crew and supply helicopters, spatial allocation factors and 

information were not preserved in the 1993 MOADS database. Thus, it was required that we 

devise a new spatial allocation procedure for this historical backcasting effort. 

Crew and supply boat emissions were calculated as the product of the total operating 

hours, engine output, and the EPA emission factor discussed above. In this case, operating hours 

are a better measure of emissions than distance traveled since boats often operate at high load 

factors even when they are not underway in the cruise mode. 

Just as for helicopters, it was determined in the 1993 GMAQS study that boat routing is 

frequently indirect, and offshore trips often involve stops at more than one platform. Also, 

significant portions of boat operating hours were spent maneuvering or “station-keeping” at the 

platform sites. Again, we observed that the spatial distribution of the final gridded offshore area 

source emission inventories plotted in the GMAQS report largely reflected the distribution of 

platforms. Thus, our spatial allocation procedures simply allocated total offshore emissions in 

proportion to the number of platforms in each grid cell. It can be argued that this method might, 

in principle, lead to underestimation of crew and supply boat emissions closer to shore because 

these boats initially embark from onshore ports. However, allocations of emissions to near-shore 

platforms included emissions due to multiple stops and onsite maneuvering that actually 

occurred further offshore. Thus, the possible short-changing of emissions from boats transiting 

the near-shore tracts en route to tracts farther offshore is at least qualitatively offset by this 

allocation of emissions to near-shore from extra offshore legs and non-cruise-related operating 

activity. 

At this time, a complicated method to account for the large number of possible routes is 

not justified given the current level of uncertainty with the process of emissions backcasting. 

The spatial distribution produced by our methods is reasonably plausible and is consistent with 

the final inventories presented in the GMAQS report. 

Drill Ships

Borehole data were obtained from the MMS web site (Minerals Management Service, 

2000). These data sources contain detailed information about the locations and time of 

installation of exploratory boreholes for both 1977 and 1988. To determine the duration of the 

drilling for each borehole, the “spud date” was assumed to indicate the start of drilling, and the 

“total depth date”, the final day. Continuous operation was assumed between these two dates. 

The effective drill period was assumed to be the duration between the spud and total depth dates 

or 10 days, whichever was longer. Only drilling that occurred within the calendar year for each 

year was considered (i.e., if drilling lasted from December 1988 to January 1989, only December 

was counted). 

Drill ship emission factors were obtained from Table 5-1 of Analysis of Commercial 

Marine Vessels Emissions and Fuel Consumption Data (U.S. Environmental Protection Agency, 
2-15 

2000). The equation published therein for calculating PM, NOx, CO, and HC emissions factors 

is 

Emissions Rate (g/kW-hr) = a (Fractional Load)^(-x) + b (2-4)

The equation for SO2 is 

Emissions Rate (g/kW-hr) = a (Fuel Sulfur Flow in g/kW-hr) + b (2-5)

The equation given for fuel consumption is 

Fuel Consumption (g/kW-hr) = 14.12/(Fractional Load) + 205.717 (2-6)

However, since we did not have fractional load data, we used an average drill ship fuel usage 

rate of 2256 gallons/day, which was published in an April 1995 letter from the Offshore 

Operators Committee to Chris Oynes of MMS. Marine diesel fuel sulfur levels were obtained 

from Table 4 of In-Use Marine Diesel Fuel (U.S. Environmental Protection Agency, 1999) as 

0.91 % by weight for DMB (the predominant marine fuel for large engine vessels). Emission 

factors measured in terms of the mass of emissions per mass of fuel consumed were converted to 

units of kg emissions/gal fuel by using a fuel density of 3.0 kg/gal. Emission factors were 

estimated at 100% load. 

Emissions were calculated for each drill ship voyage reported in the MMS borehole 

database for 1977 and 1988. Borehole coordinates were used to allocate emissions to the 

appropriate grid cell. Since only a small fraction of the vessel time is spent in transit and most 

borehole locations in these years were near the coastline, we allocated all emissions to the cells 

containing the borehole (i.e., we did not account for emissions associated with travel to and from 

the borehole locations). 

Exploration Vessels

The activities of exploration vessels were estimated using 1988 MMS exploration and 

research permit data. Permit data for 1977 were not available, so we assumed the levels and 

locations of exploration vessel activities in 1977 to be the same as 1988. The MMS data were 

arranged by individual ship voyage with a specified time frame and area of exploration. We 

obtained USCG vessel registration data and vessel specifications for the vessel lists in the MMS 

permit archives. If the rated horsepower of a ship’s engines were not available in this USCG 

database, horsepower was estimated using a correlation between boat length and horsepower 

developed from the available data points. If boat length was also unavailable, an average value 

of 3000hp was assumed. 

The MMS permit data specified the lease block(s) in which a specific research/ 

exploration vessel was to operate. We assigned emissions from each voyage uniformly to all 

grid cells contained within the listed lease block(s). The records that did not have a block 

assigned or that had inconsistent data were examined and treated on a case-by-case basis. For 

example, in the case of voyages that involved a single ship without an assigned block, emissions 
2-16 

were spread over the entire OCS. When a voyage date for a specific ship overlapped 

significantly with that of a second voyage of the same ship, the second record was ignored to 

avoid double-counting. It was also necessary to correct obvious inconsistencies or errors in the 

ship registry numbers. The number of operating days were estimated and allocated based on 

permit dates and blocks. Although in some cases the 1988 permits allowed exploration into 

1989, the numbers of operating days were estimated using December 31, 1988, as a cutoff. It 

was determined through discussions with operators that the permit periods are often much longer 

than the actual voyages. Based on these discussions, the number of operating days per permit 

was assumed to be two weeks or the total permit period, whichever was smaller. 

Exploration vessel emission factors were calculated in the same manner as for crew and 

supply boats. However, the load factor was estimated to be 60% (based on discussions with 

operators), and SO2 emissions were estimated by assuming 0.91% fuel sulfur content, which is 

the average for marine diesel B (DMB), the most common distillate fuel for large-engine oceangoing vessels according to In-Use Marine Diesel Fuel (U.S. Environmental Protection Agency, 

1999). Horsepower ratings were determined by matching either the ship’s name or registry 

number to the available USCG vessel information data. Registry number was used first and if 

that did not produce a match, then the name was used. If these two did not produce a match, the 

average of 3000 hp was used—a situation that occurred for only four voyage permit records. 

PM10 and PM2.5 were estimated from TSP using the fractions 1.0 and 0.92, which were 

obtained from the EPA NONROAD SPECIATE database version 1.5 profile # 32202 – Heavyduty diesel. Due to lack of data, it was assumed that VOC emissions are approximately equal to 

THC. This seems reasonable because heavy-duty diesel engines emit little methane or ethane. 

Estimated exploration vessel emissions for each voyage were uniformly allocated to 

those grid cells within the lease tracts listed in each permit. If there were multiple tracts in any 

single permit record, each tract was assumed to have received an equal portion of the emissions, 

without regard to the size of the tract. Permit records that covered the entire Gulf had their 

associated emissions spread evenly across the entire OCS grid. 

Pipe-Laying Ships

Information about pipelines installed in the Gulf of Mexico in 1977 and 1988 were 

obtained from the ODS. These data included information about the area (tract) into which the 

pipe was installed, pipe diameter, and pipeline length. In 1988, a few of the pipelines started and 

terminated in different tracts. These cases were examined individually. If the dominant length 

of the pipeline extended in one tract, that tract was assigned the whole length of the pipe. If the 

distance in each tract was roughly equal, the pipe length was divided between the tracts. 

The ODS database also included some information on “days-to-complete”, which was 

assumed to be equal to the duration of pipeline-laying activities in each case. However, this 

information was missing from many records. Using data from complete records, two statistical 

regression analyses were performed: one relating pipe length to installation duration, and the 

second relating both pipe length and diameter to installation duration. Although the regression 

using both pipe length and diameter resulted in fewer complete records, it produced a stronger 
2-17 

regression coefficient and was therefore used to estimate the durations of pipe installations with 

missing completion time records. All pipeline installations were assumed to have been 

performed using ships with 3000 hp engines at 60% load. The emission factors for pipelinelaying ships were derived in the same manner as for exploration vessels, using 0.91% sulfur 

content. The emissions for each installation were calculated using a kg/hp-hr emission factor 

and the assumed hp and duration. 

PM10 and PM2.5 were estimated from TSP using the fractions 1.0 and 0.92, which were 

taken from the EPA NONROAD SPECIATE database version 1.5 profile # 32202 - Heavy duty 

diesel. Due to lack of data, it was assumed that VOC emissions are approximately equal to THC. 

This seems reasonable because heavy-duty diesel engines emit little methane or ethane. 

Spatial allocation of estimated emissions from pipeline-laying ships began by totaling the 

emissions in each tract. Then, we assumed that pipelines generally extend from one facility or 

platform to another. Thus, the emissions total for each tract was allocated to each grid cell in 

proportion to the number of active platforms in the cell. 
3-1 

3. YEAR-2000 EMISSION INVENTORY FOR OUTER CONTINENTAL SHELF 

PLATFORMS IN THE VICINITY OF BRETON NATIONAL WILDLIFE AREA 

3.1 INVENTORY DEVELOPMENT METHODS 

3.1.1 Data Collection 

The MMS directed OCS facility operators to report emissions activity data on a monthly 

basis throughout the year 2000 for facilities within 100 km of the BNWA. OCS facility 

operators responded by submitting electronic activity data files for approximately 510 facilities 

each month. The data files were used to calculate air emissions from equipment and processes 

that are common to oil and gas exploration and production facilities, including amine gas 

sweetening units, boilers, internal combustion engines, turbines, drilling operations, fugitives, 

flares, loading operations, glycol gas dehydrators, storage tanks, and vents. 

Operators generated electronic data reports by applying BOADS. BOADS produces data 

files in Microsoft Access format. Each data file contained a single month’s activity data (e.g., 

quantities of fuel consumed, process throughputs, etc.) for multiple facilities and multiple 

equipment or process units. The BOADS system is documented elsewhere (Coe et al., 2000). 

The MMS gathered the data files, resolved initial questions with the operators, and transmitted 

the data files to Sonoma Technology, Inc. (STI). 

3.1.2 Input Data Processing, Quality Assurance, and Quality Control 

For ease of use and convenience, STI processed and merged the entire set of BOADS 

data files into a single file with the same format characteristics as the original BOADS files. STI 

performed a manual QA/QC review of the merged data file and entered justifiable adjustments 

where warranted. As they were entered, QA/QC adjustments to the raw data were recorded and 

documented in a data table. This QA/QC record was included with the final version of the 

merged input database. 

3.1.3 Database Management System Processes 

Input data were loaded into an Oracle-based DBMS that was designed specifically to 

input, store, and process BOADS data files. Upon data load, the DBMS runs automated 

procedures to calculate and store emissions data and to record potential QC issues. The DBMS 

calculation procedures are described in Appendix E. The DBMS replicates BOADS QC checks, 

and also runs additional QC checks, which are also described in Appendix E. As part of its 

automated QC process, the DBMS generates a collection of QC reports in the form of ASCII 

files. The final version of the DBMS, loaded with BOADS input data, emissions results, and QC 

records was provided to the MMS with this report. Documentation for the DBMS is provided in 

Appendix F. 
3-2 

3.2 SUMMARY OF ESTIMATED EMISSIONS 

Total emissions were summarized for all facilities that were reported to be “active” with 

at least one active equipment unit or process. Emissions were calculated for two scenarios: with 

existing control technologies installed and with no control technologies. The two scenarios 

differed very little. Controlled and uncontrolled emissions of NOx, CO, and PM10 differed by 

1% or less. Controlled and uncontrolled emissions of THC and VOC differed by 11% and 14%, 

respectively. With control technologies considered, SOx emissions increased by 9% because 

Claus sulfur recovery units and equipment tail gas flares were considered to be control 

technologies for hydrogen sulfide (H2S), which produce SOx emissions as a by-product of H2S 

combustion or conversion. The remainder of this section describes the controlled emissions 

scenario. 

Figure 3-1 illustrates total monthly estimated emissions for all facilities that were 

represented in the electronic data reports submitted to the MMS. Estimated total emissions 

ranged from the monthly minima and maxima listed in Table 3-1 for each pollutant. Several 

pollutants underwent large monthly variabilities, which were driven by upset events with 

emissions routed to vents and flares. 

Table 3-2 summarizes the total numbers of active equipment or process units that were 

represented in the monthly data files. Figures 3-2 through 3-7 illustrate the monthly 

variabilities in total emissions broken down by each type of equipment or process. Several 

interesting patterns are apparent in Figures 2 through 7. The large variabilities in emissions from 

vents and flares are obvious and are due almost entirely to upset events. Counter-intuitively, it 

also appears that CO, PM10, and SOx emissions from flares are decoupled because they reached 

peak levels at different times of the year. This decoupling is due to the fact that total emissions 

from flares are strongly dependent on the unique characteristics of any flares that experience 

upset conditions. CO emissions from flares are proportional to the total quantity of gas 

combusted in flares. SOx emissions peak when large volumes of acid gas are combusted under 

upset conditions. PM10 emission rates depend not only on the total volume of gas flared, but also 

on the reported smoking conditions of flares operating under upset conditions. 

Gasoline engines, which are associated with relatively high emission rates of CO, were 

used at only one individual platform during the months of January and February, which resulted 

in small peaks in the CO emissions for this type of equipment. Similarly, a small peak in CO 

emissions for drilling operations is observable in February, which was associated with the use of 

gasoline as fuel during a single drilling operation. Thus, in January and February alone, CO 

emissions from gasoline engines and drilling operations exceeded the CO emissions from flares. 

Figure 3-8 illustrates the distribution of total annual emissions by pollutant and 

equipment type. From this figure, it is apparent that natural gas engines are the predominant 

source of NOx emissions and flares are the predominant source of SOx emissions. A variety of 

sources contribute to emissions of PM10, THC, and VOC. 

Figures 3-9 through 3-13 depict geographic distributions of air pollutant emissions for 

OCS facilities included in the year 2000 BNWA inventory.

3-4 

Table 3-2. Minimum, maximum, and average monthly counts of active equipment units 

or processes included in the year 2000 BNWA emission inventory. 

 Minimum Maximum Average 

Equipment or Process Type (count) (count) (count) 

Amine gas sweetening units 3 5 4 

Boilers 110 131 121 

Diesel or gasoline IC engines 616 645 631 

Drilling operations 14 26 20 

Flares 38 51 42 

Platforms with fugitives 252 270 266 

Glycol gas dehydrators 109 121 113 

Loading operations 1 2 2 

Natural gas engines 475 499 490 

Natural gas turbines 133 140 136 

Storage tanks 135 146 142 

Vents 152 171 163 

Total number of active OCS facilities 430 449 439 




3-9 

Figure 3-9. Geographic distribution of total annual CO emissions for OCS facilities included 

in the year 2000 BNWA emission inventory. 

Figure 3-10. Geographic distribution of total annual NOx emissions for OCS facilities included 

in the year 2000 BNWA emission inventory. 
3-10 

Figure 3-11. Geographic distribution of total annual SOx emissions for OCS facilities included 

in the year 2000 BNWA emission inventory. 

Figure 3-12. Geographic distribution of total annual PM10 for OCS facilities included in the 

year 2000 BNWA emission inventory. 
3-11 

Figure 3-13. Geographic distribution of total annual VOC emissions for OCS facilities 

included in the year 2000 BNWA emission inventory. 
4-1 

4. REFERENCES 

Coe, D.L., D.J. Ladner, J.D. Prouty, L.R. Chinkin, M. Yocke, and D. Scalfano. 2000. User’s 

guide for the Breton Offshore Activities Data System (BOADS) for air quality. U.S. 

Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New 

Orleans, LA. OCS Study MMS 2000-081. 

Corbeille, R. 1997. Hydrogen sulfide occurrences in the Gulf of Mexico region. Report prepared 

by U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS 

Regional Office, New Orleans, LA. 

Minerals Management Service. 2000. Gulf of Mexico Region: Products/Free Data. Available on 

the Internet at <http://www.gomr.mms.gov/homepg/pubinfo/repcat/well/5010.html>. 

Offshore Data Services. 1977, 1988. Gulf of Mexico, Monthly Offshore Rig Reports. 

Proprietary data sources and reports prepared by Offshore Data Services, 3200 Wilcrest 

Dr. Suite 170, Houston Texas 77042, USA, Tel: 1 832 463 3000. 

U.S. Environmental Protection Agency. 1977. Atmospheric emissions from offshore oil and gas 

development and production. Prepared by Energy Resources Company, Inc., Cambridge, 

MA. 

U.S. Environmental Protection Agency. 1995. Natural gas processing. In compilation of air 

pollutant emission factors, vol. 1: stationary point and area emission units (AP-42), 5th 

ed. (January 1995), Supplement A (January 1995), Chapter 5.3. Report prepared by 

Office of Air Quality Planning and Standards of the EPA, Research Triangle Park, NC. 

U.S. Environmental Protection Agency. 1999. In-use marine diesel fuel. Prepared for U.S. 

Environmental Protection Agency, Engine Programs and Compliance Division, Office of 

Mobile Sources by ICF Consulting Group, Fairfax, VA, EPA Contract No.68-C-98-170, 

Work Assignment No. 0-4, August. Available on the Internet at 

<http://www.epa.gov/otaq/regs/nonroad/marine/ci/fr/dfuelrpt.pdf> 

U.S. Environmental Protection Agency. 2000. Analysis of commercial marine vessels emissions 

and fuel consumption data. Prepared for U.S. Environmental Protection Agency Office 

of Transportation and Air Quality under contract to Sierra Research by Energy and 

Environmental Analysis, Inc., EPA Contract No. 68-C7-0051, Work Assignment No. 1-

10, EPA420-R-00-002, February, Table 5-1. Available on the Internet at 

<http://www.epa.gov/otaq/models/nonrdmdl/c-marine/r00002.pdf>. 

U.S. Environmental Protection Agency. 2001. Uncontrolled emission factor listing for criteria air 

pollutants. In compilation of air pollutant emission factors, vol. 2: mobile sources (AP42), 5th ed. (November 2000), Chapter 14. Report prepared by Eastern Research Group, 

Inc., Research Triangle Park, NC. 
 A-1

APPENDIX A 

PLATFORM ACTIVITY DATA SOURCES AND PROCESSING FOR 

ESTIMATING HISTORICAL EMISSIONS 
 A-3

The development of a historical emissions inventory for platform operations in the Gulf 

of Mexico required the use of many sources of data. This section describes sources of data and 

steps followed to develop the historical inventories. 

MMS HISTORICAL ACTIVITY DATA 

The Minerals Management Service (MMS) maintains considerable information on 

historical activity on the development and production of oil and gas in the Gulf of Mexico. 

Together with MMS staff, several key measures of historical activity were obtained for use in 

this study as described below. 

Production Data

Production data for leases within the Gulf of Mexico for the years of 1977, 1988, and 

2000 were obtained from MMS. In addition, data for years 1991 and 1992 were obtained to 

compare with production data used in the MOADS inventory, which took place from June 1991 

to May 1992. Regardless of year, the production data records include: MMS lease number, 

number of active months, protraction block, area code, annual total barrels of oil produced by 

lease, and annual amount of natural gas produced by lease in thousand cubic feet. The 

protraction block and area code provide spatial information specific to each lease. It is important 

to note that the production data are provided for leases, which occupy a large area (typically 

5,000 acres), as compared to the emissions inventory data, which are specific to individual 

platforms. 

Platform Records

An electronic list of all platforms constructed in the Gulf of Mexico was supplied to STI. 

The file includes a unique platform id code called MMS ID (derived from concatenation of 

complex id and structure id), the lease number that the platform is in, operator number, area and 

block number (spatial information), installation and removal date, whether the platform is 

considered “major” or staffed 24 hours a day, water depth, and latitude and longitude. This file 

was primarily used to determine the construction-related emissions for the historical emission 

inventory; however, it also proved useful to spatially allocate emissions from leases to point 

specific locations. From the installation date, those platforms constructed during 1977 and 1988 

were easily separated from the entire data set for estimation of emissions from construction 

activities. For those platforms constructed in either 1977 or 1988, we developed a matrix 

relating water depth and number of pilings (either actual or estimated) to equipment type and 

estimated amount of fuel used. 

Borehole Data

Drilling emissions 

The emissions associated with equipment used to drill the oil and gas wells was based on 

the MMS ASCII file “5010”, which was downloaded from the MMS website on September 13, 

2001. The file description was “All Borehole data by field”. This file contains information 
 A-4

about every “borehole” bored into the Gulf of Mexico since record-keeping began. There are two 

primary types of boreholes: experimental and developmental. As the emissions associated with 

exploratory drilling tend to be “mobile” they have been included in the mobile portion of the 

emission inventory and are discussed elsewhere. The borehole data file included: API well 

number, operator number, spud date (i.e. date drilling began), total depth date (date well reached 

total depth), well type code (e.g. exploratory or developmental), drilling depth information, 

Bottom lease number, area and block codes, and the latitude and longitude of the surface and 

bottom of the well. These data serve as the basis for the estimation of emissions resulting from 

drilling rigs during the years of the historical inventory. 

The borehole data provided by MMS was used to develop emissions estimates of drilling 

activities. The “Spud Date” and “Total Depth Date” were used to calculate the length of drilling 

operations: called the “Drill Duration”. These data were quality controlled before being used to 

calculate emissions. About 95% of “Drill Duration,” ranged from 3 days to 185 days. However, 

several hundred drilling operations fell well outside this typical range of drilling duration. 

Therefore, it was decided to account for these activities’ emissions by assuming that they 

occurred with the average drilling duration, which is 43 days. The original start date was not 

modified, but the total depth date was re-calculated as being 43 days from the start date. In 

addition, some records were missing temporal information. Although the records with no 

temporal information represent a very small percent of the entire data set, if they all occurred in 

one year (say 1977 or 1988), it could have a significant impact on that year’s inventory. When 

the records that had missing temporal information were compared with an updated borehole file 

(downloaded June 3, 2002), it was apparent that most of the wells with missing dates in the 

original file were drilled in 2001 or 2002. These wells had not yet begun drilling at the time they 

were entered into the originally downloaded borehole data. As such, those wells with no 

temporal information were assumed to be wells that were not active during the historical 

emissions inventory years. 

Mud Degassing 

The borehole data obtained from MMS are also the basis for the estimation of mud 

degassing emissions. A source of emissions that occurs concurrent with borehole drilling 

activity is the release of gases that have been dissolved in the mud of the ocean floor. This 

process is referred to as “mud degassing”. Unlike emissions associated with drilling equipment, 

the release of gases entrained in the sea mud are likely to occur in the vicinity of the borehole 

and are considered a part of the stationary source inventory. As such, mud-degassing emissions 

were estimated for all boreholes (as opposed to only developmental wells) drilled during the 

years of the inventory. 

OGOR-B

“Oil and Gas Operations Report” List B (OGOR-B) is an annual “inventory” of oil and 

gas extracted from federal lands. The detailed information contained in this report includes 

monthly lease specific data about amount of oil and gas sold, vented or flared, or used on the 

platforms for energy generation, as well as many other classifications. The level of detail found 

in these reports is particularly useful for trend extrapolation and backcasting of historical 

activities where no other data is available. STI obtained OGOR-B reports for years 1985-2000 
 A-5

from MMS. It is important to note that the OGOR-B reports are not available for any year prior 

to 1985. Thus, we derived data for 1977 by extrapolating available data. 

The only processing required for the OGOR-B files was the conversion of “Unit 

Agreement Numbers” into their composite leases using MMS file 4600, “Pbunitas.dat”. The 

information associated with Unit Agreement Numbers was divided into the appropriate leases by 

one of two methods. The Unit Agreement file 4600 intermittently lists the percent of each 

lease’s contribution to Unit Agreement production. In this case the OGOR-B unit agreement data 

was apportioned to each lease based on their indicated percentage. If the unit agreement file had 

no percentages indicated, then the OGOR-B data was apportioned evenly among all applicable 

leases. 

Natural gas used on platforms 

The OGOR-B file has “disposition codes” which indicate the activity type of the 

associated information. The Disposition code 20 is defined as “reported products used on, or for 

the benefit of, Lease/Agreement operations with prior approval from BLM or OMM (e.g. 

Lease/Agreement gas used to operate production facilities)”. The information contained in 

OGOR-B reports for disposition code 20 was used to determine the quantity of natural gas 

reported used on leases over the last 15 years in the Gulf of Mexico. The amount of natural gas 

used on the leases is considered to have been for equipment operation and was used to estimate 

yearly and monthly variations in natural gas use. Table A-1 lists the reported consumption of 

natural gas for lease operations by year as generated from the OGOR-B reports. 

Table A-1. OGOR-B reported natural gas use for platform operations by year. 

Year OGOR-B reported natural gas used (dis. code=20) 

2000 109,222,260 Mcf 

1991-92 90,618,695 Mcf 

1988 84,141,550 Mcf 

1977a 66,521,815 Mcf 

a The following equation was used to estimate the amount of natural gas used in 1977. This equation was 

derived from a trend regression of natural gas used as a function of natural gas produced for data in 1985 

through 2000. 

Percent NG used = (1.83417E-10 × NG produced + 1.075%) ÷ 100% 

NG used77 = (1.83417E-10 × NG produced + 1.075%) ÷ 100% × 3,766,717,354 (Mcf) 

NG used77 = 1.766% × 3,766,717,354 (Mcf) = 66,521,815 Mcf 

Natural gas vented and flared 

Venting and flaring activities are reported in OGOR-B reports under disposition codes 21 

and 22. These codes are defined respectively as “Reported flared or vented casinghead gas” and 

“reported well gas that was flared or vented”. The level of detail in the OGOR-B reports 

regarding venting and flaring activities is the most specific information found, yet it is still too 

general for accurate estimation of emissions as the quantity of gas vented and flared are reported 

in aggregate. 
 A-6

The data in the OGOR-B reports was used in conjunction with production information to 

generate Gulf specific venting and flaring trends. The amount of gas vented and flared from oil 

wells and gas wells was summed together to generate total gas released. Total gas released was 

divided by gas produced to understand how release rates vary as a function of time and 

production. From the results of these analyses an estimate of total natural gas released in 1977 

was developed. Table A-2 summarizes the amount of natural gas reportedly sent to vents and 

flares in the OGOR-B reports and the amount estimated for 1977. 

Table A-2. The sum of OGOR-B reported natural gas vented and flared by year. 

Year 

Natural gas vented and 

flared from OGOR-B 

(MCF) 

Percent of total 

natural gas 

production 

2000 12,834,605 Mcf 0.259 

1991-92 11,924,751 Mcf 0.255 

1988 16,869,964 Mcf 0.369 

1977a 33,814,584 Mcf 0.898 a Note this represents an estimate based on regression analyses. 

GIS map layers

ArcView GIS software was used to develop spatial relationships between the emissions 

inventory and geographical features in the Gulf of Mexico and for QC purposes. The initial GIS 

data layers were obtained from the MMS and included land and water boundaries, gridded ocean 

blocks and corresponding areas, protraction blocks, bathymetry lines, and active leases. The 

spatial analysis software in GIS helped to further identify the region that was 100 km from the 

Breton National Wildlife Refuge. 
 A-7

AVAILABLE EMISSION INVENTORIES 

MOADS 3 

The existing Gulf-wide emissions inventory, MOADS 3, was used as the basis for the 

historical inventories. It was originally developed for the Gulf of Mexico Air Quality Study 

(GMAQ) in 1993. The MOADS 3 emissions inventory was compiled from surveys of platform 

equipment operations in the Gulf of Mexico from June 1991 through May 1992. Note that 

MOADS 3 only includes emissions generated by platform sources. Therefore, alternative data 

sources were used to generate historical emissions for drilling equipment and platform 

construction rigs as will be discussed later. 

During our initial review of MOADS 3, we found that the MOADS 3 inventory was not 

complete for all platform equipment activity. The equipment types included in the MOADS 3 

inventory are listed by SCC code in Table A-3 and include platform engines (both natural gas 

and diesel powered), turbines, and boilers, as well as venting and flaring equipment, and storage 

tanks for diesel and crude oil. Emissions from the operation of gas processing equipment (glycol 

units, amine sweeteners, and appurtenance platforms) were not included in the MOADS 3 

inventory. (Appurtenance platforms are processing-only platforms; they report no production of 

oil or gas, but could contribute emissions from processing equipment.) The significance of the 

emissions from appurtenance platforms has not been documented; however, it is our 

understanding that appurtenance platforms were virtually non-existent in 1977, but have since 

grown in importance as explained by Dr. Richard Karp of MMS. 

Table A-3. Emissions sources included in the MOADS 3. 

SCC Code Description 

Number of 

Occurrences

Activity 

Code 

10200501 Industrial External Combustion Boiler: Distillate Oil 1 BOI 

10200601 Large Industrial External Combustion Boiler: natural Gas 35 BOI 

10200602 Medium Industrial External Combustion Boiler: natural Gas 27 BOI 

10200603 Small Industrial External Combustion Boiler: natural Gas 603 BOI 

20200101 Industrial Diesel Turbine 5 DIE 

20200102 Industrial Internal Combustion Engine: Diesel 2,634 DIE 

20200201 Industrial natural Gas Turbine 345 NGT 

20200202 Industrial Internal Combustion Engine: natural gas 2,263 NGE 

20200401 Large Bore Internal Combustion Engine: Diesel 48 DIE 

31000205 Industrial natural Gas Flare 78 FLA 

40301010 Breathing Loss from Crude Oil Storage Tanks 629 STO 

40301012 Working Loss from Crude Oil Storage Tanks 629 STO 

40301019 Breathing Loss from Diesel Storage Tanks 1097 STO 

40301021 Breathing Loss from Diesel Storage Tanks 1097 STO 

99000030 Vent 675 GV 
 A-8

To assess MOADS 3, we compared a subset of the inventory to the recently completed 

current-year emissions inventory for the BNWA. The BNWA inventory includes the emissions 

from only the area within 100 kilometers of the BNWA. This QC process revealed several 

inconsistencies between the two inventories. The primary differences included (1) emission 

factor differences, (2) natural gas engine type distribution, (3) emissions of SOx and PM from 

flaring activities, and (4) VOC emissions from all sources. We found that several of the 

platforms included in the MOADS inventory were not installed at that time according to the 

MMS records. The MOADS 3 emissions inventory was compiled from surveys performed from 

June 1991 until the end of May 1992. A list of these platforms that have inconsistencies with the 

platform information provided by MMS is provided in Table A-4. We used MOADS platform 

records as is and did not make any changes to MOADS platform records to account for these 

discrepancies. 

Table A-4. Platforms in MOADS 3 with discrepancies with MMS records. 

MMS_ID 

SHORT_ID (in 

historical database) INSTALL_DATE REMOVAL_DATE 

21405 4 1085 1/1/93 Null 

24142_1 2426 6/11/93 Null 

21405 1 1082 12/8/93 Null 

23820_1 2882 12/12/92 9/8/00 

20045 1 413 12/6/94 Null 

24084_1 2911 5/5/94 7/13/99 

22444 1 1750 2/15/98 Null 

21613_1 2761 1/1/61 12/31/75 

 

To accurately gage the difference between the two inventories’ estimated emissions, the 

inventories first had to be normalized to account for variations in activity level (e.g. if there was 

more production in year 2000 than in 1993, there could be more emissions). This inventory 

normalization revealed that the two inventories had been developed with different emission 

factors; the BNWA inventory had been developed with the recently updated EPA emission 

factors for many equipment types used on platforms. 

As shown in Table A-2 above, natural gas engines represent a sizable portion of the 

platform equipment. Within the category of natural gas reciprocal engines there are many types 

and sizes of engines with a large variation of emission factors for NOx, CO, THC, VOC, and PM. 

Thus, the distribution pattern of these natural gas engines types can have a significant impact on 

the emission inventory. The engine type distribution can be especially important because NOx

and CO emissions from natural gas engines represent about 87% and 80% (respectively) by 

weight of the emissions for the total platform source inventory. From the available MOADS 3 

inventory documentation, the assignment of emission factors was based on an assumed 

distribution of natural gas engine types (Systems Applications International, 1995. Appendix N12). The MOADS 3 natural gas engine distribution varied significantly from the BOADS 

inventory, which was based on recent survey data. 
 A-9

Another notable difference between the two inventories is the discrepancy between SOx

emissions resulting from flaring equipment. The MOADS inventory reports that SOx emissions 

are three orders of magnitude lower than that reported by BOADS inventory, on a per volume 

flared basis (this difference was associated with a very low sulfur content assumed in natural gas 

sent to flares in the MOAD 3 inventory). Additionally, we found that particulate emissions 

associated with flares were not included in MOADS 3 (Systems Applications International, 

1995); although relatively low, particulate emissions can be expected to occur with the operation 

of flaring equipment. Finally, after examining MOADS 3’s supporting documentation, we found 

that in the MOADS 3 inventory THC was mislabeled as VOC. 

As a result of the review and QC process several adjustments were made to the original 

MOADS 3 inventory prior to its use in preparing scaled backcast emissions. The MOADS 3 

inventory was modified first by revising the distribution of natural gas engine types and updating 

all platform equipment emission factors. (Before using the new EPA emission factors, we 

confirmed that the EPA’s new emission factors were not the result of changes in technology.) 

SOx emissions from flaring were revised based on the average H2S concentration of non-upset 

flared natural gas as reported in the BOADS inventory (versus an assumed concentration in the 

original MOADS 3). The relative ratio of gases vented to gases flared was adjusted as described 

on pages A-20 through A-22. Finally, PM emissions from flaring were incorporated into the 

MOADS 3 inventory based on BOADS inventory’s frequency of flares operating with smoke 

conditions. Combined these modifications to the original MOADS 3 inventory had a significant 

impact on the total emissions. The most important modification in terms of net emissions change 

was incorporating updated AP-42 emission factors. The original MOADS 3 emissions are 

summarized in Table A-5. These can be compared to Table A-6, which lists the emissions 

inventory resulting from the modifications listed above. 

Table A-5. The original MOADS 3 inventory. 

 

Emissions (tons/year) 

Activity Type NOx THC VOC CO SOx PM 

Engines, Turbines, 

or Boilers 93,131 38,255 N/A 21,318 182 1,725

Gas vented or flared 104 229,336 N/A 567 0.44 0

Storage tanks - 10,579 N/A - - -

Original Total 93,235 278,170 N/A 21,885 182 1,725

N/A Not available 

Table A-6. MOADS 3 inventory after modifications. 

Revised Emissions (tons/year) 

Activity Type NOx THC VOC CO SOx PM 

Engines, Turbines, 

or Boilers 78,936 21,511 1,500 104,346 182 619

Gas vented or flared 153 169,099 9,456 834 1,454 2

Storage tanks - 10,579 9,822 - - -

Revised Total 79,089 201,189 20,778 105,180 1,639 621
 A-10

The change in emissions from engines, turbines and boilers on platforms is due to two 

adjustments: an updated distribution of natural gas reciprocal engine types and updated emission 

factors. Under the SCC category “natural gas reciprocating engines” there are currently six 

different sub-categories, all of which have different emission factors. In the MOADS 3 

inventory, the assumed natural gas engine distribution was 66% 2-stroke engines, 16.7% 4-stroke 

lean burn, and 16.7% 4-stroke rich burn. From the BOADS survey results, the sampled 

platforms reported a very different engine distribution than that assumed in MOADS 3; the 

majority of platforms operate a 4-stroke engine, only 7% of the respondents indicated 2-stroke 

engine operations, 8% of engines were 4-stoke clean burn, 11% were 4-stoke lean burning, and 

the remaining 74% of engines were 4-stroke rich burn. The application of a revised distribution 

resulted in a substantial increase of CO emissions, while NOx, THC, VOC and PM were only 

slightly reduced. Table A-7 shows the 1990 emission factors (SAI, 1995; EPA, 2000a) and year 

2000 emission factors for each natural gas engine type, the different inventory distributions, and 

weighted total emission factors used in the BOADS inventory effort. 
 A-11

Table A-7. Natural Gas Engine Usage and Emission Factors 

Emission Factors by Engine Type 

 Year Units 

Engine 

Type CO NOx SOx

c

 THC VOC d TSP 

Distribution 

Percentage 

1990 lbs/MMcf 

2-stroke 

lean 399 2835 0.3 1575 115.5 66.67

1990 lbs/MMcf 

4-stroke 

lean 441 3360 0.3 1365 189 16.67

1990 lbs/MMcf 

4-stroke 

rich 1680 2415 0.3 283.5 31.5 16.67

 

MOADS 

Emission 

Factors a

 lbs/MMcf 

Weighted 

Total 620 2850 0.3 1300 100 35 100

 

2000b lbs/MMcf 

2-Cycle 

Clean 405 140 N/A 1900 285 29 1

2000b lbs/MMcf 

2-Cycle 

Lean 400 3300 N/A 1700 125 10 3

2000b lbs/MMcf 

2-Cycle 

Rich 1800 4400 N/A 350 29 13 3

2000b lbs/MMcf 

4-Cycle 

Clean 530 130 N/A 2600 92 17 8

2000b lbs/MMcf 

4-Cycle 

Lean 330 4280 N/A 1500 120 10 11

2000b lbs/MMcf 

4-Cycle 

Rich 3900 2300 N/A 375 31 10 74

 

2000 lbs/MMcf 

Weighted 

Total 3035 2415 N/A 731 51 11 100

Ratio of New 

Emission Factors to 

MOADS Old 

Emission Factors 

Ratio Used 

to Adjust 

MOADS 4.89 0.85 N/A 0.56 N/A 0.31 

a Weighted average emission factors used for natural gas engines, Systems Applications International Report (1995). 

b Year 2000 emission factors from EPA AP-42 Compilation of Emission Factors Chapter 3.2 (2000a). 

c SOx emissions are computed by using an assumed average sulfur fuel content of 2,000 grains/scf. 

d VOC emissions estimated by the ratio of VOC to THC emissions from natural gas engines. 
 A-12

BNWA INVENTORY 

As noted above, the MOADS inventory was adjusted to incorporate newly available 

information acquired from a survey of the production platforms within 100 km of the Breton 

National Wildlife Area (BNWA). The BNWA Inventory was compared to a sub-set of the 

MOADS inventory. Below we describe the adjustment to the MOADS based on the BNWA 

emissions inventory. 

Glycol Unit Activity

From the surveys of platform operations, glycol unit activity as a function of natural gas 

production was determined. After the BOADS inventory results were quality controlled, the 

amount of gas processed by Glycol units was essentially 100% of that produced in year 2000. 

We then assumed that this relationship was valid historically, since glycol unit operation is 

necessary to maintain proper pipeline integrity. 

The emission factors used to estimate emissions from glycol activity were from a 

combination of Louisiana State survey results and GRI-GlyCalc software. Emissions of VOCs 

are based upon an emission factor derived from a survey of facilities that was conducted by the 

Louisiana DEQ in 1991 (personal communication with D. Scalfano, Northlake Engineers and 

Surveyors, Inc., Mandeville, LA, 2001). Emissions of THC are extrapolated from molar glycol 

affinities (THC:VOC) that were modeled using GRI-GlyCalc. Emissions are highly dependent 

upon the type of glycol used in the dehydrator unit and Triethylene Glycol was used in almost 

100% of all platforms surveyed. 

Venting and Flaring Inventory

Readily available data such as the OGOR-B reports do not differentiate the proportion of 

gas diverted to venting versus flaring. From an emissions standpoint there is a considerable 

difference between the combustion by-products of natural gas (flares) and the release of natural 

gases to the atmosphere (vents). Therefore we determined the split from the detailed survey 

results from MOADS and BOADS. One draw back of this process is that the information is 

limited to only two time-periods: 1991-92 and 2000-01. Another draw back is that the 

information for BOADS is limited to a small sub-section of the entire Gulf of Mexico and as 

such Gulf-wide variation can only be assumed. However, this uncertainty was reduced by 

selecting those platforms within a 100 km of the Breton area from the MOADS inventory using 

ArcView GIS tools and comparing the two inventories directly. The results of this comparison 

are summarized below in Table A-8. 
 A-13

Table A-8. Natural gas vented and flared in MOADS and BOADS. 

Inventory Activity Data restricted to Breton Area Gulf-wide Data 

BOADS (2000) MOADS (1993) Total MOADS 

inventory (1993) 

Volume Flared (MCF/year) 2,290,986 1,636,660 2,921,825

Volume Vented (MCF/year) 4,469,993 3,894,364 9,751,877

Total Natural Gas Released 

(MCF/year) 

6,760,979 5,531,024 12,673,702

Percent Flared: 33.9 29.6 23.1

Percent Vented: 66.1 70.4 76.9

Ratio of Gas Flared to Gas 

Vented: 

0.51 0.42 0.30

Gas with high H2S content must be flared for safety reasons. Although the H2S content 

was not quantified for the Breton Area, the Breton area could have a disproportionately higher 

amount of flaring activities since the H2S content of gas is documented to be high in nearby 

Mobile, Alabama and other pockets close to the coastline (EPA, 1995; Corbeille, 1997). This 

assumption is supported by comparing the percentage of gas flared in the MOADS inventory, 

restricted to Breton Area, to the MOADS gulf-wide inventory. The MOADS data in the Breton 

area for percentage flared is approximately 30% of the total volume of gas released, where as the 

gulf-wide percentage is 23%. 

The results of the BOADS inventory surveys were used to replace the national default 

values used in MOADS for sulfur content and smokeless flaring conditions. The weighted 

average H2S content in the BOADS inventory was between 3000 and 5250 ppmv for natural gas 

sent to flares. The midpoint of this range (4100 ppmv) was used to estimate the amount of H2S 

typically sent to flares in the adjusted MOADS inventory. Although this value seems high, it is 

still an order of magnitude smaller than the sulfur content the EPA reported for natural gas 

extracted from Mobile, Alabama (EPA, 1995). We recognize that the BOADS inventory average 

H2S content may be higher than that found on average Gulf-wide; however, use of the BOADS 

average H2S content provides a conservatively high SOx emissions estimate for the historical 

inventory. The particulate matter emitted from smoky flares was also indirectly surveyed in the 

BOADS inventory. The survey results combined with EPA emission factors provided an 

average emission factor for all flares operated: 9.4 × 10-4 lb/MMBtu (assuming an average 

natural gas heating value of 1050 Btu/scf). 
 A-14

METHODOLOGY 

WELL DRILLING EMISSIONS 

Drilling Equipment Emissions

The methodology used to estimate emissions for this source relied on borehole data from 

MMS. Daily fuel consumption was based on a survey of actual fuel consumption during drilling 

rig operations. The predominate drilling rig used was a “Jackup” Drill. Fuel consumption was 

based on a weighted average of this drill and two others. The average fuel use plus one standard 

deviation is 2256 gallons of diesel fuel/day of drilling; this value is used to provide a 

conservatively high estimate of the total fuel consumption. The amount of fuel consumed was 

estimated based on calculated daily fuel consumption times the number of drilling days. The 

estimated fuel consumption was combined with appropriate emission factors (EPA AP42) to 

calculate the emissions from drilling. 

The EPA background document for large engines provides the uncontrolled emission 

factors, which are particularly relevant to the estimation of historical emissions (EPA, 2001). 

Table A-9 lists the emission factors used to estimate emissions from total diesel fuel 

consumption during drilling. The amount of diesel fuel consumed was converted to quantity of 

energy used by multiplying the number of gallons by 7.1 lbs/gallon and then multiplying pounds 

by 19,300 Btu/lb and finally, converting this to the appropriate units to use the emission factors 

below. 

Table A-9. Uncontrolled Emission Factors for Drilling Rig Equipment (EPA, 2001). 

Emission Type Emission Factor 

(lbs/MMBtu) 

NOx 3.2 

CO 0.85 

SOx 

a

 0.404 

THC 0.09 

VOC 0.0792 

PM 0.0697 

PM10 0.0573 

PM2.5 0.0479 

a Sulfur content of marine diesel fuel was estimated to be 0.4%. 

For the calculation of the SOx emission factor S = 0.4 * 1.01 

Mud Degassing

Part of the mud degassing emissions estimation process required the calculation of the 

total depth drilled. True Vertical Depth is reported to be “The vertical distance, in feet, from the 

rig kelly bushing to the maximum depth of the well.” To determine the total well depth, the 

distance from the rig kelly bushing to the water and the surface of the water to the ocean floor 

needs to be subtracted from the reported True Vertical Depth. The surface of the water to the 
 A-15

ocean floor is the reported “water depth”, and the distance from the rig kelly bushing to the water 

surface is named the “RKB elevation”. The total depth drilled was calculated by subtracting the 

values for reported water depth and RKB Elevation from True Vertical Depth. The total depth 

was then used to determine the volume of mud displaced by the drilling activities. The volume 

was calculated based on the assumption that a drill bit of 3 inch (or use a quarter of a foot) radius 

was used and the volume displaced was cylindrical in shape. Thus, the total volume displaced 

was equivalent to pi*r^2 multiplied by the drilled depth, in feet. The average amount of gas 

dissolved in the mud is referenced to be as high as 63 cubic feet of gas per cubic foot of mud 

(EPA, 1977). The speciation profile for natural gas released from mud is undocumented; 

however, even if the VOC content of the gas was as high as 10%, it would still be an 

insignificant source of VOC relative to the rest of the inventory. Based on this, the VOC 

emissions from mud degassing are not incorporated into the inventory and it is assumed that the 

gas released is all THC. The molecular weight of THC combined with the referenced amount of 

gas released produces the emission factor of 2.71 lbs THC/cubic foot of mud displaced. 

Spatial and Temporal Allocation

Once the emissions were estimated, they were spatially and temporally allocated based 

on the borehole data supplied by MMS. The borehole data provided spatial information for each 

borehole drilled by indicating surface coordinates in latitude and longitude. The surface latitude 

and longitude of each borehole were used to spatially allocate the emissions associated with 

drilling operations. Since the borehole data was day-specific, the emissions were temporally 

allocated to months of the year based on the number of drilling days in each month. For 

instance, if the “spud date” was August 27 and the “Total Depth Date” was September 10, then 

the number of drilling days in August would be five and September would be ten. The total 

emissions were allocated to each month by dividing the total number of drilling days, in this case 

15, by the number of drilling days in a month. One third of the emissions would be allocated to 

the month of August and two thirds would be allocated to September, with the methodology used 

to temporally allocate drilling emissions. 

PLATFORM CONSTRUCTION EMISSIONS 

The data for the estimation of emissions from platform construction activities is derived 

from the MMS-supplied platform list and actual construction equipment fuel consumption data. 

The information about the number of platforms constructed in a given year is based on the 

“installation date” provided for each platform documented by MMS. For the majority of the 

early platforms, the installation date indicated the platform was installed on the first of the year 

for every platform. This does not provide enough information to determine temporal variation for 

the construction emissions; however, it is sufficient to determine which platforms were 

constructed in the inventory years: 1988, 1977. Relevant information also includes latitude and 

longitude of the platform and water depth. 

The method used to estimate fuel consumption for platform construction equipment is a 

function of water depth and number of platform pilings. Water depth dictates the type of 

equipment used and the average daily fuel consumption. Then the number of pilings is an 

indication of the platform size. The more pilings the more days the construction will take. The 
 A-16

estimated number of days is multiplied by the estimated daily fuel consumption to generate total 

fuel consumption. 

We developed a methodology to determine fuel consumption based on water depth and 

actual or estimated number of pilings. Actual number of pilings was confirmed from digital 

photos from the MMS, when available. For those platforms without available photos, estimated 

number of pilings was determined from team member’s experience and from consultation with 

Mr. Tommy Laurendine of the MMS platform group. In addition, Mr. Mac McDonald with 

McDermott Marine provided fuel consumption numbers for different platform types as shown in 

Table A-10. He assisted us in determining installation duration for different size platforms, 

platform size established by number of pilings (see Table A-11). Then, the average daily fuel 

consumption was multiplied by the installation duration to arrive at total fuel use for each 

platform. Emissions from construction activities are determined by multiplying fuel 

consumption values by the emission factors for Large Stationary Diesel Engines in Chapter 3.4 

of AP-42. An average heating value of diesel fuel is assumed to be 19,300 Btu/lb with a density 

of 7.1 lb/gallon. The emission factors for uncontrolled NOx were used with the understanding 

that most regulation was not implemented in the GOM until after the historical inventory years. 

Table A-10. Estimated daily diesel fuel consumption for platform construction activities. 

Daily Fuel Consumption of Marine Construction Equipment (gal) 

Equipment Type Water Depth (ft) 

 < 300 ft 300 - 600 ft < 600 ft 

Deck Barge (various sizes) 1,514 1,514 7,919 

135" Crewboat 2,907 2,907 2,907 

180" Supplyboat 2,735 2,735 2,735 

Tugboat (various Hp) 1,367 2,790 5,323 

Total Estimated Fuel 

(gal/day) 8,523 9,946 18,884 

Table A-11. Installation duration of platforms as a function of water depth and size. 

Installation Duration per Platform (days) 

Number of 

Platform Pilings Water Depth (ft) 

 < 300 ft 300 - 600 ft < 600 ft 

Caisson 6 

3 Pile 9 

4 Pile 10 19 38 

6 Pile 14 26 52 

8 Pile 18 33 66 

16 Pile 30 
 A-17

Spatial and Temporal Allocation

The spatial and temporal allocations of the emissions from platform construction 

equipment were distributed by the information provided in the platform list from MMS. The 

platform list indicated the latitude and longitude of the platforms, as well as the installation date. 

We treated construction barges as point sources, since they maintain their locations within 100 ft 

of a platform. Thus, the emissions from construction equipment are spatially allocated to the 

coordinates of the platform. The temporal distribution for emissions activities are considered to 

be seasonally dependant and the following monthly allocations were assumed (see Table A-12) 

based on seasonal variability. 

Table A-12. Temporal Allocation for platform construction emissions. 

Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

Percentage of 

Annual 

Activity 

3 3 7 7 7 10 15 15 15 10 5 3 

PLATFORM EQUIPMENT EMISSIONS 

Engines, Turbines, and Boilers

Emissions from platform engines, turbines, and boilers are apportioned to leases based on 

the annual lease production data provided by MMS. Without month specific production data, 

annual emissions were temporally allocated evenly to each month. It is recognized that the 

monthly distribution can have a large variation. However, there is not a significant seasonal 

pattern: platform and lease monthly production variation is fairly random. 

Nitrogen Oxides, Carbon Monoxide, Total Hydrocarbons and Volatile Organic Compounds: 

NOx and CO: As discussed previously NOx and CO emissions from natural gas engines 

represent over 85% of the emissions from non-flare, combustion equipment on platforms (e.g. 

reciprocating engines, turbines, and boilers). As natural gas engines’ emissions represent a large 

fraction of the total platform equipment emissions, all NOx emissions from non-flare, 

combustion equipment are grouped together and scaled from natural gas combustion activity. 

The NOx emissions from these equipment (adjusted MOADS 3 values) are scaled historically 

according to reported quantity of natural gas used. Analysis of natural gas use as a function of 

production revealed that natural gas use is directly proportional to natural gas extraction. Also of 

interest is that in 2000, the price of natural gas was at record highs. Even when the market price 

of gas was high the percent of natural gas used on platforms still increased proportionally with 

natural gas extraction. Thus, the amount of natural gas used as fuel on the platforms is directly 

proportional to extraction and relatively independent of market value: a fact which makes it a 

good activity surrogate for platform equipment emissions. MOADS emissions were scaled as 

shown below to estimate historical inventories. 

Emis(yr) = EmisMOADS × NGused(yr) ÷ NGusedMOADS
 A-18

The ratio of natural gas used in 1988 to natural gas used in 1991-92 was 0.9285, or a 

decrease of 7.25%. This estimated change in natural gas use is multiplied by the adjusted 

MOADS 3 inventory emissions to determine the emissions in 1988 from platform equipment. 

THC & VOC: The methodology used to develop THC and VOC emissions estimates 

from non-flare, combustion equipment for all years is based on the scaling and apportionment 

methodology used for NOx emissions. THC emissions from natural gas engines represent an 

even larger fraction of the emissions from non-flare, combustion equipment on platforms than 

CO or NOx: 97% or THC non-flare, combustion emissions are from natural gas engines. Just 

like NOx emissions, the THC emissions from these equipments are scaled historically according 

to reported quantity of natural gas used. We calculated VOC emissions from THC emissions 

based on the ratio of VOC to THC emission factors. 

Particulate Matter 

The fine PM component from combustion sources are essentially all of the estimated PM. 

As such, PM10 and PM2 5 are considered to be the same as PM emissions, except for construction 

and drilling related emissions where different emission factors were available. In contrast to 

other emission types (NOx, and CO), PM emissions from natural gas engines do not represent a 

majority of the non-flare, combustion sources. To account for other combustion related PM 

emissions, the PM component of the inventory is calculated and apportioned differently than 

NOx, CO, THC, and VOC emissions. PM emissions are calculated separately for natural gas 

engines, natural gas turbines, diesel fuel combustion (engines and turbines), and boilers. The 

MOADS 3 equipment classifications that are grouped into the following categories for PM 

emissions estimation purposes are included in Table A-3. The total estimated PM emissions 

from the following categories are apportioned to leases based on either natural gas production or 

oil production (as the emissions are fuel dependent) and then apportioned to platforms based on 

the number of active platforms in each lease. The yearly emissions are evenly distributed among 

all months. 

PM/PM10/PM2.5: natural gas engines (NGE) The PM emissions from natural gas engine 

combustion are scaled and apportioned based on the ratio of MOADS 3 original PM emission 

factors to revised PM emission factors (as was done for other pollutants). The ratio of emission 

factors used here account for the distribution of engine types observed in the BOADS 2000 

inventory and the newly updated emission factors. The PM emissions from natural gas engine 

are isolated from other equipment PM emissions to generate emissions exclusive to natural gas 

engine activity. The adjusted emissions are then scaled historically based on the variation in 

natural gas use, as reported by OGOR-B. As these engines are fueled by natural gas, the 

emissions are allocated to leases based on lease natural gas production. 

PM_Emis = PM10 _Emis = PM2.5_Emis = Original PM_NGE Emis × 0.3097 (Ratio) 

PM/PM10/PM2.5:natural gas Turbines (NGT) The only modification required to estimate 

PM emissions from natural gas Turbines is an adjustment of MOADS 3 emissions estimates for 

recent AP-42 emission factor update. The new AP-42 emission factor for PM is 7 lbs/MMscf, as 

compared to the emission factor used in MOADS 3, 35 lbs/MMscf. Once the 1990 base year 

emissions were established, then the historical emissions were estimated by scaling the emissions 
 A-19

by the ratio of natural gas used, as reported by OGOR-B. This methodology of scaling the 

emissions based on reported natural gas use is the same as for NOx emissions for non-flare, 

combustion sources, above. As the fuel for this category is natural gas, the emissions are 

allocated among leases based on lease natural gas production. 

Adjusted PM_NGT EmisMOADS=PM_NGT Emis(Original MOADS 3) × 7 ÷ 35 

Emis(yr) = PM_NGT EmisMOADS × NGused(yr) ÷ NGusedMOADS 

PM/PM10/PM2.5:Diesel combustion sources (DIE) The emission factors for diesel 

engine combustion have not been changed since the application of emission factors in MOADS 

3. The MOADS 3 PM emissions estimates for diesel engines were historically scaled according 

to yearly total oil production. We allocated emissions among leases based on reported levels of 

lease oil production. 

PM_DIE Emis(yr) = PM_DIE EmisMOADS × Oil production(yr) ÷ Oil productionMOADS

PM/PM10/PM2.5:Boilers (BOI) − The only modification required to estimate PM 

emissions from Boilers is an adjustment of MOADS 3 emissions estimates for recent AP-42 

emission factor update. The new AP-42 emission factor for PM is 7.6 lbs/MMscf, as compared 

to the fuel weighted emission factor used in MOADS 3, 6.17 lbs/MMscf. The historical 

emissions were estimated by scaling the boiler PM emissions by the ratio of natural gas used, as 

reported by OGOR-B. This methodology of scaling the emissions based on reported natural gas 

use is the same as for NOx emissions for non-flare, combustion sources, above. As the fuel for 

this category is natural gas, the emissions are allocated among leases based on lease natural gas 

production. 

Adjusted PM_BOI EmisMOADS = PM_BOI Emis(Original MOADS 3) × 7.6 ÷ 6.17 

PM_BOI Emis(yr) = PM_BOI EmisMOADS × NGused(yr) ÷ NGusedMOADS

Sulfur Oxides 

Approximately 90% of SOx emissions from engines, turbines and boilers are generated 

from diesel combustion. However, the SOx emissions from all engine types contribute only 2 to 

8% of the total SOx inventory, depending on the year and flaring estimation methodology. Since 

the change in diesel use on platforms over the last 25 years is undocumented, the MOADS 3 SOx

emissions from engine combustion are held constant over all years. The SOx emissions in the 

MOADS 3 inventory did not require adjustment as did NOx, CO, VOC and THC because SOx

emissions are fuel dependant, rather than equipment dependant. As such, SOx emissions are 

independent of NGE distribution and emission factor changes. The ratio of total equipment SOx

emissions to total equipment NOx emissions for a given year is used to allocate yearly emissions 

to leases. The calculated SOx to NOx ratio is multiplied by each leases’ NOx emissions to 

generate lease specific SOx emissions from non-flare, combustion equipment. Different ratios 

are used for each inventory year. 

Ratio 1977 = SOx _EQ emissions (constant) ÷ NOx _EQ emissions (1977) 
 A-20

 = 363,892 ÷ 146,428,852 = 0.00248511 

Ratio 1988 = 0.00121131 

Glycol Dehydrator Units

As glycol unit operation is dependent upon the amount of natural gas processed, the 

emissions estimates from glycol equipment are based on natural gas production. Natural gas 

production information is used to determine both total yearly emissions from glycol units and to 

distribute emissions among leases. BOADS inventory data for natural gas processing rates were 

analyzed for statistically significant monthly variation in glycol operation; however, no 

significant variation was observed. As such, yearly emissions from glycol activities were 

distributed evenly among all months of the year. 

Total Hydrocarbons and Volatile Organic Compounds 

The emissions from Glycol Units were not incorporated into the original MOADS 3 

inventory, so an entirely separate methodology was used to determine THC and VOC emissions 

from glycol activity. In an analysis of the BOADS inventory, it was found that the amount of 

natural gas processed by glycol dehydrator units constituted almost 100% of reported gas 

produced. Based on this, the THC and VOC emissions were estimated by multiplying natural 

gas production (being equal to natural gas processed by glycol units) by glycol unit emission 

factors, as shown below. 

Glycol_Emis (VOC) = 6.6 lbsVOC/MMscf × NG Production (Mcf) ÷ 1000 

To derive the total hydrocarbon emissions: the relative concentrations of methane, 

ethane, and VOC were used. The composition of methane and ethane relative to VOC was 

determined from BOADS survey results. A ratio of methane to VOC concentrations and ethane 

to VOC was used to scale the VOC emissions and then adjust the emission factor for the glycol 

affinity to these compounds. The glycol affinities are based on the most commonly used type of 

glycol: Triethylene Glycol. 

Glycol_Emisx = Glycol_EmisVOC × ConcentrationX/ ConcentrationVOC × Molecular 

WeightX/Molecular WeightVOC ÷ Glycol Affinity for X 

Glycol_EmisCH4 = Glycol_EmisVOC ×(91.0/ 6.2 × 16/90) ÷ 400 

Glycol_Emisethane = Glycol_EmisVOC ×(2.8/ 6.2 × 30/90) ÷ 100 

Glycol_EmisTHC = Glycol_EmisVOC + Glycol_EmisCH4 + Glycol_Emisethane 

Natural Gas Release: Venting and Flaring

Overall Methodology: 

The OGOR-B reports provide information about the total amount of gas sent to flares and 

vents in a given month; however, the amount sent to vents versus flares cannot be distinguished 
 A-21

from the available data. The apportionment of gas sent to vents or flares is important for the 

determination of emissions. As no information was available to determine the relative amount of 

each activity, outside references were consulted. Brian Shannon, a member of the OOC, 

recommended a methodology to estimate the relationship between venting and flaring based on 

results of a recent inventory and his personal experience within the oil and gas industry. The 

BOADS inventory reported amount of gas vented and flared, individually. Brian Shannon has a 

high-level of confidence in the BOADS emission inventory because of considerable training that 

was performed prior to the inventory and the companies’ use of consultants to prepare input data. 

Brian Shannon also confirmed our opinion that the trend since 1977 is toward venting rather than 

flaring. Brian Shannon’s rationale is: “During the 1980's the MMS had an increased emphasis 

on conservation of resources, limited the both number of long-term well tests and the flaring of 

gas associated with oil production. Flaring today is generally only used on high flow-rate 

releases of natural gas. Normal production equipment blow down and upset releases are sent to 

the platform vent.” Another concern is that the use of the word “flare” was misinterpreted in the 

MOADS inventory. Based on these considerations, the BOADS data were used as the basis for 

the estimation of current year venting and flaring practices, from which a trend is applied to 

estimate past venting and flaring. 

The following methodology is used to backcast the calculated ratio of gas flared to gas 

vented from BOADS inventory data. Brian Shannon suggested increasing the ratio of flared to 

vented gas historically by 50% to 75% in 1977. This percentage increase is based on an assumed 

linear rate of change over time. The range of 50% to 75% is fairly arbitrary; however, with a 

lack of information, this is the best method available. Applying both ends of the range produces 

high flare/low vent and low flare/high vent estimates. The mid-points of these estimates were 

also calculated (see Table A-13). A Gulf Adjustment factor was applied to the low flare/high 

vent estimate to reflect the fact that in the 1991 inventory, platforms in the vicinity of the BNWA 

had a greater tendency to flare gas than did all platforms throughout the Gulf, taken as a whole. 

The Gulf Adjustment factor tends to lower the estimated ratio of flaring to venting; therefore, it 

was applied only to the lower end of the uncertainty range. In other words, it is treated as a 

factor that increases the level of uncertainty in the emissions estimates rather than a simple 

scaling factor. The equation developed to perform the estimated increase in flaring ratio for any 

given year is as follows: 

Ratiohi = (RatioBOADS × [75 ÷ (2000 - 1977) × (2000 - year)] ÷ 100) + RatioBOADS 

Ratiolo = [(RatioBOADS × [50 ÷ (2000 - 1977) × (2000 - year)] ÷ 100) + RatioBOADS] ×

Gulf_Adjustment 

Ratiomid = (Ratiohi + Ratiolo) ÷ 2 

RatioBOADS = Volume FlaredBOADS ÷ Volume VentedBOADS

Gulf_Adjustment= (Volume FlaredMOADS 3 ÷ Volume VentedMOADS 3) ÷ (Volume 

FlaredMOADS 3INBRETON ÷ Volume VentedMOADS 3INBRETON) = 0.713 
 A-22

Use the ratio estimated for the year of interest to determine the relative percent vented or 

flared. Multiply the percent vented or flared by the total amount released as reported by the 

OGOR-B reports, listed in Table A-2. 

%Vented= 100 ÷ (1 + Ratio) 

%Flared= 100 ÷ (1+ 1/Ratio) 

The total gas released to either vents or flares was divided by yearly natural gas 

production to determine the annual percent released as a function of production. The percent 

released in 1977 was then extrapolated from the trend developed from data for 1985 through 

2000. This trend estimated that 0.95% of all gas produced was released in 1977. To quality 

assure the validity of both the reported OGOR-B data and the developed trend, the percent of gas 

released as reported in OGOR-B was compared to the percent of gas released on a national level 

as reported by EIA. The data from the EIA was for the period from 1954 to 2000. The two 

trends developed from the separate datasets were similar, but the percentage released nationally 

was higher, in general, than that for offshore platforms. Despite this national trend being higher 

on average than Gulf specific data indicates, the results of extrapolating the national trend for the 

year 1977 produced a lower estimate of percent of gas released in 1977. The national trend 

estimated that 0.82% of natural gas production was released in 1977. Realistically, the percent 

of gas released in 1977 from offshore platforms was influenced both by offshore conditions 

(pipeline infrastructure) and national trends (i.e. natural gas price, lack of regulation, safety 

issues, etc.). It is likely that the percent of natural gas released in 1977 is a combination of 

factors underlying both trends. To generate an estimate of total natural gas released, the midpoint of the two trend lines was used to calculate total estimated natural gas released in 1977. 
 A-23

Table A-13. Estimates of volume of gas vented and flared by year. 

Estimate by Year 

Total Volume 

Released (Mcf) 

Estimated 

Volume Flared 

(MCF) 

Estimated 

Volume Vented 

(MCF) 

Ratio of Volume 

Flared to Volume 

Vented 

High Flare/Low 

Vent Estimate 

 

1977 33,814,584 15,988,535 17,826,050 0.897 

1988 16,869,964 7,022,220 9,847,744 0.713 

1991-92 11,924,751 4,825,220 7,099,531 0.680 

2000 12,834,605 4,349,059 8,485,546 0.513 

Mid Flare 

Estimate 

 

1977 33,814,584 14,183,523 19,631,061 0.723 

1988 16,869,964 6,239,167 10,630,796 0.587 

1991-92 11,924,751 4,291,638 7,633,114 0.562 

2000 12,834,605 3,915,237 8,919,368 0.439 

Low Flare/High 

Vent Estimate 

 

1977 33,814,584 11,971,788 21,842,796 0.548 

1988 16,869,964 5,320,828 11,549,136 0.461 

1991-92 11,924,751 3,671,332 8,253,419 0.445 

2000 12,834,605 3,434,666 9,399,938 0.365 

Emission factors for all pollutants were applied to the estimated quantity of gas vented 

and gas flared; this results in the total emissions by year from venting and flaring activities. The 

above methodology was used to replace the venting and flaring emissions estimate developed for 

the MOADS inventory. In comparing the MOADS 3 inventory and the results of this 

methodology, the total quantity of gas vented and flared does not vary substantially, but the 

proportion of gas vented versus flared does, as do emission factors for some pollutants: namely, 

SOx and THC. 

Nitrogen Oxides, Carbon Monoxide, Sulfur Oxides, and Particulate Matter 

After the above methodology was used to generate estimated quantities of natural gas 

flared in each year, the amount of gas flared is multiplied by emission factors to generate total 

emissions from flaring. Emission factors used to estimate emissions for gas flared are listed in 

Table A-14. A natural gas heating value of 1050 Btu/scf is assumed. For the 1988 inventory, 

yearly total emissions are apportioned to leases by monthly OGOR-B reported gas vented and 

flared. For the 1977 inventory, when no OGOR-B data is available, the yearly emissions are 

apportioned to leases based on natural gas production and evenly distributed throughout the year. 

The lease emissions are allocated to platforms evenly among number of active platforms for each 

lease. 
 A-24

VolFlared(yr) = %Flared(yr) ÷ 100% × Total_Released(yr) 

NOx Emis_Flared = VolFlared (Mcf) ÷ 1000 × 1050 Btu/scf × 0.068 lb NOx /MMBtu 

Table A-14. Emission factors for natural gas flares. 

Emission Type Emission factor ( lb/MMBtu) 

NOx 0.068 

CO 0.37 

PM (equal to PM10 and PM2.5 )a 9.4 × 10-4

a The emission factor for PM is derived from BOADS survey results and EPA AP-42 

smoky flares. 

SOx emissions from flaring of natural gas depend on the amount of H2S of the gas sent to 

the flare. It is assumed that all H2S is converted to SOx in the combustion process. For the 

purposes of SOx emissions estimation, a hydrogen sulfide content of 4125 ppmv is assumed. 

This is the mid-point of the average range determined from BOADS survey results. It is 

important to note that this assumed sulfur content is much greater than the default value used in 

MOADS 3. 

SOx Emis(lb) = VolFlared(Mscf) × 1000 × H2S Conc × 10-6 × 0.98 × 64 lb/lb.mol ÷

379.4 scf/lb.mol 

Total Hydrocarbons and Volatile Organic Compounds 

After the estimated quantities of natural gas vented in each year were generated, the 

amount of gas vented is multiplied by emission factors to generate total emissions from venting. 

Emission factors used to estimate emissions for gas vented are described below. A natural gas 

heating value of 1050 Btu/scf is assumed. For the 1988 inventory, yearly total emissions are 

apportioned to leases by monthly OGOR-B reported gas vented and flared. For the 1977 

inventory, when no OGOR-B data is available, the yearly emissions are apportioned to leases 

based on natural gas production and evenly distributed throughout the year. The lease emissions 

are allocated evenly to platforms among number of active platforms for each lease. 

The emission factors used to estimate emissions from venting activities differ from those 

used in MOADS 3 inventory in several ways. First of all, the MOADS 3 inventory only 

calculated the THC emissions from venting activities, and did not include an estimate of VOC 

emissions. Secondly, the MOADS 3 inventory assumed that the natural gas sent to vents was 

composed of 100% hydrocarbons. To determine the VOC portion of the natural gas stream 

several sources of information were consulted: BOADS survey results, a speciation profile for 

flashing losses, and a report of the composition of gulf natural gas. Based on the data reported 

from BOADS surveyed VOC content of gas sent to vents, there seemed to be two different 

natural gas speciation profiles. The BOADS inventory contained 90 vents with non-zero, nonnull values for VOC content of the natural gas stream. Of these 90 vents, an average VOC 

concentration of around 30,000 ppmv was reported (with a standard deviation of around 30,000. 
 A-25

Vents in the BOADS database with high VOC concentrations (e.g., >200,000) are probably 

similar to the profile for flashing losses. Vents with low VOC concentrations (e.g., <50,000) are 

probably similar to the profile for GOM natural gas. As the low VOC concentration gas 

predominates the vent stream, the profile for Gulf-specific natural gas was used to estimate both 

THC and VOC emissions. It is important to note that due to the reported natural gas composition 

of the Gulf, not all the gas reportedly sent to vents is considered to be composed of hydrocarbons 

(as compared with the MOADS inventory assumption). 

SAI (1995) shows that the composition of Gulf natural gas is 

0.8% by weight non-hydrocarbons (or around 0.3% by volume = 3,000 ppmv) 

90.5% by weight methane (or around 96% by volume = 960,000 ppmv) 

3.5% by weight ethane (or around 1.7% by volume = 17,000 ppmv) 

5.2% by weight VOCs (or around 2% by volume = 20,000 ppmv) 

Conc Methane 960,000 ppmv; MWTme = 16 lb/lb.mol 

Conc Ethane 17,000 ppmv; MWTet = 30 lb/lb.mol 

Conc VOC 20,000 ppmv; MWTvoc = 47 lb/lb.mol 

Emis(lb) = VolVented(scf) × Conc × 10-6 ÷ 379.4 scf/lb.mol × MWT 

EF voc=2.4776 lbs/Mcf 

THC_Emis = VOC_Emis + Me_Emis + Et_Emis 

EF THC= 44.3068 lbs/Mcf (compare to MOADS 3 THC emission factor of 47 lbs/Mcf) 

Storage Tanks

Total Hydrocarbons and Volatile Organic Compounds 

The most accurate inventory to-date of storage tanks and their associated emissions for 

the Gulf of Mexico region is from the MOADS 3 inventory. To scale these emissions 

historically, the most appropriate activity surrogate is oil production. As more oil is produced, 

potentially there is more stored at any given time on platforms and, additionally, the working 

losses from transferring oil into and out of tanks will be increased. (1:1 relationship for emissions 

from working losses and production, breathing losses minor). Thus, to generate historical 

emissions estimates, the emissions from storage tanks are scaled according to the change in oil 

production. The historical storage tank emissions are then apportioned to leases based on oil 

production and these emissions are apportioned evenly year round. The potential emissions 

variation from seasonal changes was found to be insignificant based on Gulf-specific 

meteorological data and emissions estimation software. 

The emissions from MOADS 3 inventory from both crude oil tanks and diesel storage 

tanks are estimated only for THC. The MOADS 3 emissions for storage tanks are scaled linearly 

according to oil production. The VOC emissions are estimated by multiplying the ratio of VOC 

and THC emissions to the estimated historical THC emissions. As discussed previously, a 

speciation profile for flashing loses is available to estimate the portion VOC in THC emissions. 

The profile for flashing losses is particularly applicable to the estimation of VOC emissions from 
 A-26

storage tanks as the volatile component of emissions is likely to be much higher than that 

typically found in natural gas or oil. The calculation of VOC component of THC emissions is 

below. 

VOC_Emis = THC_Emis × 92.84 ÷ 100 

Spatial and Temporal Allocation

Estimated annual emissions from platform specific equipment, including engines, gas 

processing equipment, and storage tanks, were first spatially allocated based on lease specific 

data. Lease emissions were then distributed spatially to platform sources based on the platform 

list provided by MMS. The lease emissions were distributed evenly to the number of active 

platforms within a lease in each year. For example, if there were three active platforms within a 

lease in 1977, a third of the total emissions for the lease were apportioned evenly to each of those 

three platforms. If the MMS records did not indicate that a lease had any active platforms within 

a given year, then all of the lease’s emissions were allocated to the closest platform as 

determined with ArcView GIS analysis tools. Emissions were distributed temporally in different 

ways, depending upon the type of activity data available. 
 B-1

APPENDIX B 

GRIDDED EMISSIONS FOR MOBILE SOURCES, 1977 AND 1988 
MOBILE SOURCE EMISSION GRID 

Grid was defined as follows: 

Grid dimension was 45 x 26, 

total number of cells 1170, counting from left to right from SW corner, last cell (1170) is 

NE corner 

SW corner at 97.2 E, 25.616 N 

NE corner at 87.81 E, 30.694 N 

MAP PROJECTION 

Map projected used was ALBERS, parameters as follows: 

Zunits NO 

Units METERS 

Spheroid CLARKE1866 

Xshift 0.0000000000 

Yshift 0.0000000000 

Parameters 

29 30 0.000 /* 1st standard parallel 

45 30 0.000 /* 2nd standard parallel 

-96 0 0.000 /* central meridian 

23 0 0.000 /* latitude of projection's origin 

0.00000 /* false easting (meters) 

0.00000 /* false northing (meters) 
 B-5
 B-6

` 
 B-7
 B-8
 B-9
 B-10
 B-11
 B-12
 B-13
 B-14
 B-15
 B-16
 B-17
 C-1

APPENDIX C 

EMISSION PLOTS FOR PLATFORMS, 1977, 1988, AND 1993 

The following plots depict emissions from platform sources in the Gulf of Mexico. The 

emissions quantities are displayed in tons per year. The maps are in geographic longitude and 

latitude format. All coordinates are NAD 27. 
 C-3
 C-4
 C-5
 C-6
 C-7
 C-8
 C-9
 C-10
 C-11
 C-12
 C-13
D-1 

APPENDIX D 

DATA STRUCTURE AND FORMAT FOR 1977 AND 

1988 EMISSION INVENTORIES 
D-3

The database contains five tables: HI_FLARING_ESTIMATES, MID_FLARING_ESTIMATES, LOW_FLARING_ESTIMATES, LOCATION, AND PARAMETER_DEFINITIONS. These tables and their relationships are described below. The LOCATION table has 5,446 records. The primary key for this table is one unique identification field called SHORT_ID. This identification field is a code that represents each platform or well and its associated locational information. The columns in LOCATION are described in the table below. Column Name Type Size Possible 

Values 

Description Units 

SHORT_ID Long 

Integer 

4 1 - 15,267 Numbers <10,000 are a platform 

id code, >10,000 are a well id code. This code corresponds to the SHORT_ID field in the “Location” Table. 

N/A 

MMS_ID Text 14 Variable MMS approved platform number 

(a concatenation of the complex id and structure number) or the API Well Number for boreholes 

N/A 

LATITUDE Single 4 26.25186 - 

30.18895 

The latitude of the platform or well. Well coordinates are from the reported surface latitude. 

Decimal degrees 

LONGITUDE Single 4 -97.13476 – 

(-84.05186) 

The longitude of the platform or well. Well coordinates are from the reported surface longitude. 

Decimal degrees 

AC_LAB Text 10 Variable The two-digit MMS area code is 

joined with the block number to provide locational information for each platform and well. 

N/A 

OPERATOR_CODE Long 

Integer 

4 1 – 20643; 

Null 

The MMS operator code provided with the Borehole and Platform datasets. Is Null when not available. 

N/A 
D-4

INSTALL_DATEa Date/Time 8 1/1/48 - 

2/15/98; Null 

The MMS provided the installation date with the platform dataset and the “Total Depth Date” in the borehole dataset is used here as the installation date. Is Null when not available. 

Date 

REMOVAL_DATEa Date/Time 8 12/31/75 - 

7/5/01; Null 

The MMS provided the removal date with the platform dataset. The closure of boreholes is not relevant to drilling emissions and is left null. Is Null when not available. 

Date 

SOURCE_TYPE Text 10 PLATFORM; 

BOREHOLE 

Identifies whether the locational information is for a borehole or platform source. 

N/A 

a Platforms with reported installation subsequent to the inventory years (1977-1992) were included in the MOAD

emissions inventory. Additionally, platforms with a reported removal date prior to inventory years were also incin MOADS inventory. As the origin of this inconsistency is not evident, the MOADS platform data was retained final database. However, it is important to note that there are inconsistencies between the MOADS platform invand the platform installation/removal dates reported by MMS. The platforms that have this conundrum are outlinAppendix C. The LOCATION table is related to the tables HI_FLARING_ESTIMATES, MID_FLARING_ESTIMATES, and LOW_FLARING_ESTIMATES by the “SHORT_ID” field. This field is the platform or well identifier and repr

the same source in all tables. There is a one-to-many relationship between the LOCATION table and each of the emissions tables. This means that for every one “SHORT_ID” in the LOCATION table, there are many record wsame SHORT_ID in the emissions tables. However, for each of the many “SHORT_ID”s in the emissions tables record is unique for the year, month, emissions type, and equipment source type. HI_FLARING_ESTIMATES has 1,287,129 records. The primary key for this table is a combination of the coluSHORT_ID, LEASE, EQUIP_TYPE, POLL_TYPE, YEAR, MONTH. This primary key assures that no monthlemissions from a platform for a specific lease is duplicated. Every record contains a unique value for monthly pl

emissions for each source type from each active lease. 
D-5

The columns in HI_FLARING_ESTIMATES are described below. Column Name Type Size Possible Values Description Units SHORT_ID Long Integer 4 1 - 15,267 Numbers <10,000 are a 

platform id code, >10,000 are a well id code. This code corresponds to the SHORT_ID field in the “Location” Table. 

N/A 

LEASE Text 10 Variable MMS Lease number N/A EQUIP_TYPE Text 5 BOI, CON, DIE, 

DRILL, EQ, FL, GLY, GV, MUD, NGE, NGT, STO 

Emissions source type: activity descriptor 

N/A 

POLL_TYPE Text 4 CO, NOx, SOx, PM, 

PM10, PM2.5, THC, VOC 

Emission type N/A 

YEAR Integer 2 1977, 1988, 1993 Year emissions occurred N/A MONTH Byte 1 1 - 12 Month emissions occurred N/A QUANTITY Single 4 0 - 6,514,791 Quantity of emissions emitted 

by each emission source for each pollutant type 

Poundmonth 

Column values are listed below and are the same for HI_FLARING_ESTIMATES, MID_FLARING_ESTIMATand LOW_FLARING_ESTIMATES. 

Parameter Column Name Definition Comments 

BOI EQUIP_TYPE Boiler equipment, all fuel 

type 

Emission source type "BOI" is boiler related emisspecific to PM, PM10, and PM2.5 

CO POLL_TYPE Carbon Monoxide The emission type "Carbon Monoxide" is associat

with flares, platform equipment, drilling rigs, and 
D-6

platform construction activities. 

CON EQUIP_TYPE Platform construction 

equipment 

Emissions source type "CON" is platform construrelated emissions and includes NOx, CO, SOx, THVOC, PM, PM10, and PM2.5 

DIE EQUIP_TYPE Diesel powered engines Emissions source type "DIE" is diesel fueled 

reciprocating engines and turbines for PM, PM10PM2.5 specific emissions. 

DRILL EQUIP_TYPE Drilling equipment Emissions source type "DRILL" is drilling rig 

equipment and emissions include NOx, CO, SOx, THC, VOC, PM, PM10, and PM2.5 

EQ EQUIP_TYPE All engines, boilers, and 

turbines 

Emissions source type "EQ" groups emissions froboilers, turbines, and reciprocating engines and includes all emissions types except PM, PM10, anPM2.5. 

FL EQUIP_TYPE Flare equipment Emissions source type "FL" is flare related activit

includes emissions types NOx, SOx, CO, PM, PMand PM2.5 

GLY EQUIP_TYPE Glycol units Emissions source type "GLY" is glycol dehydrato

activity related emissions and includes THC and Vemission types 

GV EQUIP_TYPE Gas venting equipment Emissions source type "GV" is gas venting related 

activity and includes THC and VOC emission typ

MUD EQUIP_TYPE Mud degassing Emissions source type "MUD" is mud degassing 

activity and includes THC emissions 

NGE EQUIP_TYPE Natural gas powered 

engines 

Emissions source type "NGE" is natural gas fuelereciprocating engine activity and includes PM, PMand PM2.5 emission types 

NGT EQUIP_TYPE Natural gas powered 

turbines 

Emissions source type "NGT" is natural gas poweturbine activity and includes PM, PM10, and PM2emission types. 

NOx POLL_TYPE Oxides of Nitrogen The emission type "NOx" is associated with flares

platform equipment, drilling rigs, and platform construction activities. 
D-7

PM POLL_TYPE Total Particulate Matter The emission type "PM" is associated with flares, 

platform equipment (type specific), drilling rigs, aplatform construction activities. 

PM10 POLL_TYPE Particulate Matter of 

diameter 10 microns or less 

The emission type "PM10" is associated with flarplatform equipment (type specific), drilling rigs, aplatform construction activities. 

PM25 POLL_TYPE Particulate Matter of 

diameter 2.5 microns or less 

The emission type "PM2.5" is associated with flarplatform equipment (type specific), drilling rigs, aplatform construction activities. 

SOx POLL_TYPE Oxides of Sulfur The emission type "SOx" is associated with flares

platform equipment, drilling rigs, and platform construction activities. 

STO EQUIP_TYPE Storage Tanks Emissions source type "STO" is storage tank relat

emissions for THC and VOC emission types. 

THC POLL_TYPE Total Hydrocarbon 

Compounds 

The emission type "THC" is associated with gas venting, platform equipment, glycol units, storage tanks, drilling rigs, mud degassing, and platform construction activities. 

VOC POLL_TYPE Volatile Organic 

Compounds 

The emission type "VOC" is associated with gas venting, platform equipment, glycol units, storage tanks, drilling rigs, and platform construction acti

MID_FLARING_ESTIMATES has 1,287,129 records. The primary key for this table is a combination of the coSHORT_ID, LEASE, EQUIP_TYPE, POLL_TYPE, YEAR, MONTH. This primary key assures that no monthlemissions from a platform for a specific lease is duplicated. Every record contains a unique value for monthly pl

emissions for each source type from each active lease. The columns in MID_FLARING_ESTIMATES are the same as HI_FLARING_ESTIMATES and are described Column Name Type Size Possible Values Description Units 

SHORT_ID Long Integer 4 1 - 15,267 Numbers <10,000 are a 

platform id code, >10,000 are a well id 

N/A 
D-8

code. This code corresponds to the SHORT_ID field in the “Location” Table. 

LEASE Text 10 Variable MMS Lease number N/A EQUIP_TYPE Text 5 BOI, CON, DIE, DRILL, 

EQ, FL, GLY, GV, MUD, NGE, NGT, STO 

Emissions source type: activity descriptor 

N/A 

POLL_TYPE Text 4 CO, NOx, SOx, PM, PM10, 

PM2.5, THC, VOC 

Emission type N/A 

YEAR Integer 2 1977, 1988, 1993 Year emissions occurred N/A MONTH Byte 1 1 - 12 Month emissions 

occurred 

N/A 

QUANTITY Single 4 0 – 6,644,437 Quantity of emissions 

emitted by each emission source for each pollutant type 

Poundmonth 

LOW_FLARING_ESTIMATES has 1,287,129 records. The primary key for this table is a combination of the columns: SHORT_ID, LEASE, EQUIP_TYPE, POLL_TYPE, YEAR, MONTH. This primary key assures that nmonthly emissions from a platform for a specific lease is duplicated. Every record contains a unique value for mplatform emissions for each source type from each active lease. The columns in LOW_FLARING_ESTIMATES are described below. Column Name Type Size Possible Values Description Units SHORT_ID Long Integer 4 1 - 15,267 Numbers <10,000 are a 

platform id code, >10,000 are a well id code. This code corresponds to the SHORT_ID field in the “Location” Table. 

N/A 
D-9

LEASE Text 10 Variable MMS Lease number N/A EQUIP_TYPE Text 5 BOI, CON, DIE, 

DRILL, EQ, FL, GLY, GV, MUD, NGE, NGT, STO 

Emissions source type: activity descriptor 

N/A 

POLL_TYPE Text 4 CO, NOx, SOx, PM, 

PM10, PM2.5, THC, VOC 

Emission type N/A 

YEAR Integer 2 1977, 1988, 1993 Year emissions occurred N/A MONTH Byte 1 1 - 12 Month emissions occurred N/A QUANTITY Single 4 0 – 7,640,350 Quantity of emissions emitted 

by each emission source for each pollutant type 

Poundmonth 
 E-1

APPENDIX E 

EMISSIONS CALCULATION PROCEDURES AND QUALITY CONTROL 

PROCEDURES FOR THE DATABASE MANAGEMENT SYSTEM 
E-3 

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

January 10, 2000 (revised September 17, 2000) 

TO: Gaylen Drapé STI Ref. No. 998202 

FROM: Dana Coe and Lyle Chinkin 

SUBJECT: Emissions calculations for amine units 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

Summary: 

Uncontrolled emissions of VOC and THC are calculated as follows: 

379.4 scf

lb mol Q 10 m

100%

EF

100%

C

E c

c c 6

c,unc

⋅ = × × × × ×

where: 

Ec,unc = Uncontrolled emissions of analyte c (pounds per month) 

Cc = Concentration of analyte c in the natural gas, measured at the inlet to the amine unit (percent by volume) 

EFc = Quantity analyte c emitted when uncontrolled (percent) 

Q = Volume of natural gas processed this month (million standard cubic feet, MMscf) 

mc = Molecular weight of analyte c (lb/lb-mol) 

Emissions must be adjusted for any control devices that are installed, such as a flare, a pre-defined control device (a 

vapor recovery system/condenser, or a sulfur recovery unit), and/or some other user-specified control device. 

Controlled emissions of VOC and THC are calculated as follows: 

= ×∏

d

c,d

c,control c,unc 100%

100 - Eff

E E

where: 

Ec,control = Controlled emissions of analyte c (pounds per month) 

Effc,d = Control efficiency of control device d for analyte c (percent) 

Devices that are intended to control hydrogen sulfide (H2S) emissions, such as sulfur recovery units or flares, will 

produce emissions of SOx as a by-product. Thus, if a flare and/or a sulfur recovery unit is present, SOx emissions 

are calculated as follows. (If neither is present, the result of this equation will be zero.) 
E-4 

lb mol

64 lb

100

Eff

2

A A

100

%RE 1

2

A

2

3

3

2

379.4 scf

lb mol Q 10

100%

EF

100%

C

E H S H S 6 H S

,control

2 2 2

SOx ⋅ ×













  × + 

 



  × − ×  



 × × − ⋅ = × × × ×

where: 

%RE = Sulfur recovery efficiency of the Claus unit. 

C = Concentration of H2S in the Claus process stream (percent by volume) 

A = 







1;if a sulfur recovery unit is present 

0;if no sulfur recovery unit is present

Assumptions: 

Hydrocarbons are comprised of straight-chain, saturated hydrocarbons. 

C9 or longer hydrocarbons are negligible. 

Equations and Default Values: 

New variables are shown in bold font. Variable names that exist in the BOADS tables are shown in italic font. 

Conditional values are preceded by IF (condition = TRUE) THEN statements. 

Uncontrolled Emissions: 

ETHC, unc = ((ConcMethane × EmittedMethane × 16.04) + (ConcEthane × EmittedEthane × 30.07) 

+ (ConcC3HC × EmittedC3HC × 44.10) + (ConcC4HC × EmittedC4HC × 58.12) 

+ (ConcC5HC × EmittedC5HC × 72.15) + (ConcC6HC × EmittedC6HC × 86.18) 

+ (ConcC7HC × EmittedC7HC × 100.21) + (ConcC8plusHC × EmittedC8plusHC × 114.23) ) 

× TotalGasThru × 10^6 ÷ 379.4 

EVOC, unc = ( (ConcC3HC × EmittedC3HC × 44.10) + (ConcC4HC × EmittedC4HC × 58.12) 

+ (ConcC5HC × EmittedC5HC × 72.15) + (ConcC6HC × EmittedC6HC × 86.18) 

+ (ConcC7HC × EmittedC7HC × 100.21) + (ConcC8plusHC × EmittedC8plusHC × 114.23) ) 

× TotalGasThru × 10^6 ÷ 379.4 

If values are not provided for any or all of ConcC3HC, ConcC4HC,..., ConcC8plusHC, estimate default values as 

follows (where Nmissing = the number of values among ConcC3HC, ConcC4HC,..., ConcC8plusHC that are null): 

ConcC3HCdef = (100 – ( ConcMethane + ConcEthane + ConcC3HC + ConcC4HC + ConcC7HC + 

ConcC8plusHC ) ÷ Nmissing ) ÷ 3 

ConcC4HCdef = (100 – ( ConcMethane + ConcEthane + ConcC3HC + ConcC4HC + ConcC7HC + 

ConcC8plusHC ) ÷ Nmissing ) ÷ 4 

ConcC5HCdef = (100 – ( ConcMethane + ConcEthane + ConcC3HC + ConcC4HC + ConcC7HC + 

ConcC8plusHC ) ÷ Nmissing ) ÷ 5 

ConcC6HCdef = (100 – ( ConcMethane + ConcEthane + ConcC3HC + ConcC4HC + ConcC7HC + 

ConcC8plusHC ) ÷ Nmissing ) ÷ 6 

ConcC7HCdef = 0 

ConcC8plusHCdef = 0

(Note: Treat null values as 0.) 

If values are not provided for any or all of EmittedC3HC, EmittedC4HC,..., EmittedC8plusHC, assign default values 

in the following order: 

EmitttedC3HC = EmittedEthane

EmittedC4HC = Emitted C3HC

EmittedC5HC = Emitted C4HC

EmittedC6HC = Emitted C5HC 

EmittedC7HC = EmittedC6HC 

EmittedC8plusHC = EmittedC7HC 

Controlled Emissions: 
E-5 

ETHC, control = ETHC, unc × (1 – EffTHC,VF ÷100) × (1 – EffTHC,CT ÷100) × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, unc × (1 – EffVOC,VF ÷100) × (1 – EffVOC,CT ÷100) × (1 – EffVOC,Oth ÷100) 

ESOx, control = ConcNGH2S ÷ 100 × EmittedH2S × 100 × TotalGasThru × 10^6 ÷ 379.4 × 2 ÷ 3 × (1.5 − A/2) 

× (1 − SRURecoveryEff ÷ 100 × A) × (0.5 × A + EffH2S,VF ÷ 100) × 64 × (1 − EffSOx,Oth ÷100) 

IF GasesVentOrFlare = “Vented” THEN 

EffTHC,VF = EffVOC,VF = EffH2S,VF = 0 

IF GasesVentOrFlare = “Flared” or IF VentedToID is like *FLA* THEN 

EffTHC,VF = EffVOC,VF = 98 

EffH2S,VF = 95 

IF ControlTechnology = “none” THEN 

EffTHC,CT = EffVOC,CT = 0 

A = 0 

IF ControlTechnology = “VR/C” THEN 

EffTHC,CT = EffVOC,CT = 80 

A = 0 

IF ControlTechnology = “SR + VR/C” THEN 

EffTHC,CT = EffVOC,CT = 80 

A = 1 

IF ControlTechnology = “SR” THEN 

EffTHC,CT = EffVOC,CT = 0 

A = 1 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = EffVOC,Oth = 0

EffSOx,Oth = 0

Statistics: 

Percentiles of emissions magnitudes (THC, VOC, and SOx) among the population of amine units. 

Pro-rated THC, VOC, and SOx emissions per processed throughput (pounds per MMscf per month), and their 

population percentiles. 

Quality Control: 

See BOADS QC specifications (Excel spreadsheet). 

Flag if population percentiles are ≥ 98%. 
E-6 

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

March 21, 2001 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Boilers, Heaters, and Burners 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

NOx = Nitrogen oxides (as nitrogen dioxide, NO2) 

PM10 = Particulate matter (with aerodynamic diameter of 10 μm or less) 

CO = Carbon monoxide 

Summary: 

To calculate uncontrolled emissions for liquid-fueled engines (waste oil or diesel) based 

on fuel use, Efu,liq: 

E EF 10 U 7.1lb/gal liq

-3

(lb/10 gal) fu, liq = 3 × × ÷ 

To calculate uncontrolled emissions for gas-fueled engines (natural gas, process gas, or 

waste gas) based on fuel use, Efu,gas: 

gas

3 Efu,gas = EF(lb/MMscf) ×10 × U − 

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

Uliq = Fuel usage (pounds) = TotalFuelUsedOil

Ugas = Fuel usage (Mscf) = TotalFuelUsed
 E-7

Emission Factors for Liquid-Fueled Units – Diesel 

where MaxRatedHeatInputRate ≥ 100, 

and EmissionControls as indicated. 

EmissionControls

 "None" "Low NOx 

Burner" 

"Flu Gas 

Recirc" 

Pollutant 

EFliq

(lb/103

 gal) 

THC n/a n/a n/a 

VOC n/a n/a n/a 

SOx 142 × S1 142 × S1 142 × S1 

NOx 24 10 10 

PM10 2 2 2 

CO 5 5 5 

The SOx emission factor varies with fuel sulfur content (ppmv) 

(S1 = FuelH2ScontentOil). 

Emission Factors for Liquid-Fueled Units – Diesel 

where MaxRatedHeatInputRate < 100, 

and EmissionControls as indicated. 

EmissionControls

 "None" "Low NOx 

Burner" 

"Flu Gas 

Recirc" 

Pollutant 

EFliq

(lb/103

 gal) 

THC n/a n/a n/a 

VOC n/a n/a n/a 

SOx 142 × S1 142 × S1 142 × S1 

NOx 20 20 20 

PM10 2 2 2 

CO 5 5 5 

The SOx emission factor varies with fuel sulfur content (ppmv) 

(S1 = FuelH2ScontentOil). 
 E-8

Emission Factors for Liquid-Fueled Units – Waste Oil 

where MaxRatedHeatInputRate ≥ 100, 

and EmissionControls as indicated. 

EmissionControls

 "None" "Low NOx 

Burner" 

"Flu Gas 

Recirc" 

Pollutant 

EFgas

(lb/MMscf) 

THC n/a n/a n/a 

VOC n/a n/a n/a 

SOx 157 × S1 157 × S1 157 × S1 

NOx 47 40 40 

PM10 9.19 × S1 + 

3.22 

9.19 × S1 + 

3.22 

9.19 × S1 + 

3.22 

CO 5 5 5 

The SOx emission factor varies with fuel sulfur content (ppmv) 

(S1 = FuelH2ScontentOil). 

Emission Factors for Liquid-Fueled Units – Waste Oil 

where MaxRatedHeatInputRate < 100, 

and EmissionControls as indicated. 

EmissionControls

 "None" "Low NOx 

Burner" 

"Flu Gas 

Recirc" 

Pollutant 

EFgas

(lb/MMscf) 

THC n/a n/a n/a 

VOC n/a n/a n/a 

SOx 157 × S1 157 × S1 157 × S1 

NOx 55 55 55 

PM10 9.19 × S1 + 

3.22 

9.19 × S1 + 

3.22 

9.19 × S1 + 

3.22 

CO 5 5 5 

The SOx emission factor varies with fuel sulfur content (ppmv) 

(S1 = FuelH2ScontentOil). 
 E-9

Emission Factors for Gas-Fueled Units – Natural Gas or Process Gas, 

where MaxRatedHeatInputRate ≥ 100, 

and EmissionControls as indicated. 

EmissionControls

 "None" "Low NOx 

Burner" 

"Flu Gas 

Recirc" 

Pollutant 

EFgas

(lb/MMscf) 

THC 11 11 11 

VOC 5.5 5.5 5.5 

SOx 0.19 × S2 0.19 × S2 0.19 × S2

NOx 280 140 100 

PM10 7.6 7.6 7.6 

CO 84 84 84 

The SOx emission factor varies with fuel sulfur content (ppmv) 

(S2 = FuelH2SContent). 

Emission Factors for Gas-Fueled Units – Natural Gas or Process Gas, 

where MaxRatedHeatInputRate < 100, 

and EmissionControls as indicated. 

EmissionControls

 "None" "Low NOx 

Burner" 

"Flu Gas 

Recirc" 

Pollutant 

EFgas

(lb/MMscf) 

THC 11 11 11 

VOC 5.5 5.5 5.5 

SOx 0.19 × S2 0.19 × S2 0.19 × S2

NOx 100 50 32 

PM10 7.6 7.6 7.6 

CO 84 84 84 

The SOx emission factor varies with fuel sulfur content (ppmv) 

(S2 = FuelH2SContent). 

These factors come from AP-42, Sections 1.3 and 3.4, dated September 1998 (with corrections/errata posted on 

EPA's website, 4/28/2000). All boilers are assumed to be wall-fired boilers (no tangential-fired boilers). Emission 

factors for No. 6 residual oil were used to estimate emissions from waste-oil-fueled units because waste oil 

combustion factors were in the same ballpark, but required ash content to calculate, and had no options for controls. 

Note that No. 2 fuel oil is the same thing as diesel. 

 If FuelType is "NATURAL GAS", "PROCESS GAS", or "WASTE GAS", then a 

value for TotalFuelUsed must be available or emissions cannot be calculated. Likewise, if 

FuelType is "WASTE OIL", or "DIESEL", then a value for TotalFuelUsedOil must be available 

or emissions cannot be calculated. Note that you cannot calculate SOx emissions unless values 

for FuelH2SContent (if gas-fueled) or FuelH2SContentOil (if liquid-fueled) are available. 
 E-10

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

FuelH2Scontentdefault = 3.18 

FuelH2ScontentOildefault = 0.4

FuelHeatingValuedefault = 1050 

FuelHeatingValueOildefault = 19,300 

FuelUsageRatedefault = HeatInputRate ÷ FuelHeatingValue × 106 

FuelUsageRateOildefault = HeatInputRate ÷ FuelHeatingValueOil × 106 

TotalFuelUseddefault = FuelUsageRate × HrsOperated ÷ 1000 

TotalFuelUsedOildefault = FuelUsageRateOil × HrsOperated 

where Fuel Usage Rate is expressed in terms of Mscf/hr 

Controlled Emissions:

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

ESOx, control = ESOx, uncontrolled × (1 – EffSOx,Oth ÷100) 

ENOx, control = ENOx, uncontrolled × (1 – EffNOx,Oth ÷100) 

EPM10, control = EPM10, uncontrolled × (1 – EffPM10,Oth ÷100) 

ECO, control = ECO, uncontrolled × (1 – EffCO,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

EffNOx,Oth = OtherControlEffNOx 

EffPM10,Oth = OtherControlEffPM10 

EffCO,Oth = OtherControlEffCO 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

EffSOx,Oth = 0 

EffNOx,Oth = 0 

EffPM10,Oth = 0 

EffCO,Oth = 0 
 E-11

New QC Checks:

MaxRatedHeatInputRate ≥ HeatInputRate

MaxRatedFuelUsage ≥ FuelUsageRate

MaxRatedFuelUsageOil ≥ FuelUsageRateOil

0.8 × TotalFuelUsed ≤ HeatInputRate ÷ FuelHeatingValue × HrsOperated × 103 ≤ 1.2 ×

TotalFuelUsed

0.8 × TotalFuelUsedOil ≤ HeatInputRate ÷ FuelHeatingValueOil × 106 × HrsOperated ≤ 1.2 ×

TotalFuelUsedOil
 E-12

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

April 20, 2000 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for diesel and gasoline engines 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

NOx = Nitrogen oxides (as nitrogen dioxide, NO2) 

PM10 = Particulate matter (with aerodynamic diameter of 10 μm or less) 

CO = Carbon monoxide 

Summary: 

To calculate uncontrolled emissions based on fuel use, Efu: 

H

gal

7.1lb E EF 10 U -6

fu = (lb/MMBtu) × × × × 

To calculate uncontrolled emissions based on power output, Epo: 

453.6g

lb E EF HP t po = (g/hp-hr) × × × 

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (gallons) = TotalFuelUsed

H = Fuel heating value (BTU/lb) = FuelHeatingValue

HP = Engine horsepower (hp) = OperatingHP

t = Engine operating time (hr/month) = HrsOperated
 E-13

Emission Factors for Gasoline Engines 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 3.03 9.8 

VOC 2.64 8.53 

SOx 0.084 0.268 

NOx 1.63 4.99 

PM10 0.1 0.327 

CO 62.7 199 

Emission Factors for Diesel Engines 

where MaxHP < 600 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 0.36 1.14 

VOC 0.313 0.993 

SOx 0.29 0.93 

NOx 4.41 14.1 

PM10 0.31 1 

CO 0.95 3.03 

Emission Factors for Diesel Engines 

where MaxHP ≥ 600 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 0.09 0.32 

VOC 0.0792 0.282 

SOx 1.01 × S 3.67 × S 

NOx 3.2 10.9 

PM10 0.057 0.182 

CO 0.85 2.5 

Note: The SOx emission factor varies with 

fuel sulfur content (% by mass) 

(S = FuelSulfurContent). 

These factors come from AP-42, Sections 3.3 and 3.4, dated October 1996. 
 E-14

 If a user-entered value for TotalFuelUsed is available or if it can be estimated from the 

default values (below), then estimate emissions based upon fuel use. Otherwise, if OperatingHP

and HrsOperated are both available, then estimate emissions based upon power output. If none 

of these conditions are met, don't calculate emissions. Note also that you cannot calculate 

emissions for natural gas engines unless the MaxHP is supplied. And, you cannot calculate SOx

emissions for natural gas engines where MaxHP ≥ 600 unless the FuelSulfurContent is supplied. 

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

FuelHeatingValuedefault = 19300 

 Fuel Usage Rate = 7000 

TotalFuelUseddefault = FuelUsageRate × 1/FuelHeatingValue × 1/7.1 × OperatingHP ×

HrsOperated

FuelSulfurContent = 0.4 

where Fuel Usage Rate is expressed in terms of Btu/hp-hr.

Controlled Emissions:

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

ESOx, control = ESOx, uncontrolled × (1 – EffSOx,Oth ÷100) 

ENOx, control = ENOx, uncontrolled × (1 – EffNOx,Oth ÷100) 

EPM10, control = EPM10, uncontrolled × (1 – EffPM10,Oth ÷100) 

ECO, control = ECO, uncontrolled × (1 – EffCO,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

EffNOx,Oth = OtherControlEffNOx 

EffPM10,Oth = OtherControlEffPM10 

EffCO,Oth = OtherControlEffCO 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

EffSOx,Oth = 0 

EffNOx,Oth = 0 

EffPM10,Oth = 0 

EffCO,Oth = 0 
 E-15

New QC Checks:

0.8 × TotalFuelUsed ≤ FuelUsageRate × 1/FuelHeatingValue × 1/7.1 × OperatingHP ×

HrsOperated ≤ 1.2 × TotalFuelUsed

FuelUsageRate ≤ MaxRatedFuelUsage

OperatingHP ≤ MaxHP
 E-16

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

September 14, 2000 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions calculations for drilling rigs 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

NOx = Nitrogen oxides (as nitrogen dioxide, NO2) 

PM10 = Particulate matter (with aerodynamic diameter of 10 μm or less) 

CO = Carbon monoxide 

Summary: 

Total emissions equal the sum of emissions due to gasoline, diesel, and natural gas fuel 

usages (Etot = Egas + Edie + Eng). 

For gasoline fuel use, calculate uncontrolled emissions, Egas, as follows: 

lb

20,300 Btu

gal

7.1lb E EF 10 U -6

gas = (lb/MMBtu) × × × × 

where: 

E = Emissions in pounds 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (gallons) = GasolineUsage

For diesel fuel use, calculate uncontrolled emissions, Edie, as follows: 

lb

19,300 Btu

gal

7.1lb E EF 10 U -6

die = (lb/MMBtu) × × × × 
 E-17

where: 

E = Emissions in pounds 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (gallons) = DieselUsage

For natural gas fuel use, calculate uncontrolled emissions, Eng, as follows: 

 U E EF 10 3

ng = (lb/MMscf) × × −

where: 

E = Emissions in pounds 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (Mscf) = NGUsage

Emission Factors for Gasoline Fuel Use 

Pollutant 

EFgas

(lb/MMBtu) 

THC 3.03 

VOC 2.64 

SOx 0.084 

NOx 1.63 

PM10 0.1 

CO 62.7 

Emission Factors for Diesel Fuel Use 

Pollutant 

EFdie

(lb/MMBtu) 

THC 0.09 

VOC 0.0792 

SOx 0.40 

NOx 3.2 

PM10 0.057 

CO 0.85 
 E-18

Emission Factors for Natural Gas Fuel Use 

Pollutant 

EFng 

(lb/MMscf) 

THC 1350 

VOC 66 

SOx 0.57 

NOx 2743 

PM10 13 

CO 880 

These factors come from AP-42, Sections 3.2, 3.3, and 3.4, dated June 1997 and October 1996. Assume diesel 

engines are ≥ 600 hp. Assume NG engines are 4-cycle and evenly distributed between lean, clean, and rich burns 

(by averaging). Fuel sulfur contents are assumed to be 0.4% by mass for diesel engines and 3.18 ppmv for natural 

gas engines. For natural gas combustion, mid-range values were selected from the emission factors presented for the 

various engine designs. 
 E-19

Default Values:

No default values are necessary. 

Controlled Emissions:

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

ESOx, control = ESOx, uncontrolled × (1 – EffSOx,Oth ÷100) 

ENOx, control = ENOx, uncontrolled × (1 – EffNOx,Oth ÷100) 

EPM10, control = EPM10, uncontrolled × (1 – EffPM10,Oth ÷100) 

ECO, control = ECO, uncontrolled × (1 – EffCO,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

EffNOx,Oth = OtherControlEffNOx 

EffPM10,Oth = OtherControlEffPM10 

EffCO,Oth = OtherControlEffCO 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

EffSOx,Oth = 0 

EffNOx,Oth = 0 

EffPM10,Oth = 0 

EffCO,Oth = 0 

New QC Checks:

No new QC checks will be defined. 
 E-20

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

July 26, 2000 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Flares 

For flares, note that some variables come from the eqFLA table, while others come from 

the eqFLAOCC table. Variables from the eqFLAOCC table are denoted with an asterisk (*). 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

NOx = Nitrogen oxides (as nitrogen dioxide, NO2) 

PM10 = Particulate matter (with aerodynamic diameter of 10 μm or less) 

CO = Carbon monoxide 

Summary: 

Estimate flare emissions for THC, VOC, NOx, PM10, and CO according to the following 

equation. 

 1000 Eflare = Vtot × H × EFflare ÷ 

where: 

E = Emissions in pounds 

Vtot = Total volume of gas flared (Mscf) = VolFlared + ∑(AvgFeed* × HrsOperated*) 

H = Flare gas heating value (Btu/scf), assume equal to 1050 Btu/scf 

EFflare = Emission factor for flares (lb/MMBtu) 
 E-21

Estimate flare emissions of SOx according to the following expression. 





 



	

× × × + × × ⋅ × ×



 



	 = =

− n

i 1

*

H S,i

*

i

*

H S i

SO

6

F

flare,SO 2 2

2

x 1000 V' C F t C

379.4scf/lb mol

m

ppm

10

100%

Eff % E 

where: 

EffF% = The combustion efficiency of the flare (percent) = FlareEfficiency

mSO2 = Molecular weight of SO2 = 64 lb/lb·mol 

V' = Non-upset volume of gas flared (Mscf) = VolFlared 

CH2S = Non-upset concentration of H2S in the flare gas (ppmv) = ConcH2S 

* F = Upset flare feed rate for occurrence i (Mscf/hr) = i AvgFeed* 

*

i t = Duration of occurrence i = HrsOperated* 

*

H S,i 2 C = H2S concentration for upset occurrence i = ConcH2S * 

If HasContFlarePilot = "YES", estimate pilot light emissions according the following 

expression. (Otherwise, pilot light emissions are zero.) 

E P 30 EF 1000 pilot = × × pilot ÷

where: 

P = Flare feed rate (Mscf/day) 

EFpilot = Emission factor for pilot (lb/MMscf) 

Emission Factors for Flares 

where FlareSmoke as indicated. 

Pollutant EF (lb/MMBtu) 

THC 0.14 

VOC 0.052 

NOx 0.068 

PM10 0; where FlareSmoke = "NONE" 

 0.002; where FlareSmoke = "LIGHT" 

 0.01; where FlareSmoke = "MEDIUM" 

 0.02; where FlareSmoke = "HEAVY" 

CO 0.37

Emission Factors for Pilots. 

Pollutant EF (lb/MMscf) 

THC 11 

VOC 5.5 

NOx 100 

PM10 7.6 

SOx 0.6 

CO 84 

These factors come from AP-42, Section 13.5 (dated September 1991) and Section 1.4 (dated July 1998). Assume 

flare composition 45% C2/C3 and 55% C1 by volume to estimate VOC EF. For the pilot, a fuel sulfur content 

of 3.18 ppmv is assumed.
 E-22

Default Values:

The following default values should be assigned or estimated if the corresponding fields 

are null. 

ConcH2Sdefault = 3.18 

ConcH2S*default = 3.18 

FlareEfficiencydefault = 98 

FlareSmokedefault = "LIGHT" 

VolFlareddefault = StackExitVel × π ÷ 4 × (StackInnerDiam)

2

÷ 144 

Controlled Emissions:

Note: For the following equations, E denotes total emissions (Eflare + Epilot). 

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

ESOx, control = ESOx, uncontrolled × (1 – EffSOx,Oth ÷100) 

ENOx, control = ENOx, uncontrolled × (1 – EffNOx,Oth ÷100) 

EPM10, control = EPM10, uncontrolled × (1 – EffPM10,Oth ÷100) 

ECO, control = ECO, uncontrolled × (1 – EffCO,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

EffNOx,Oth = OtherControlEffNOx 

EffPM10,Oth = OtherControlEffPM10 

EffCO,Oth = OtherControlEffCO 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

EffSOx,Oth = 0 

EffNOx,Oth = 0 

EffPM10,Oth = 0 

EffCO,Oth = 0 

New QC Check:

0.8 × StackExitVel × π ÷ 4 × (StackInnerDiam)2÷ 144 ≤ VolFlared ≤ 1.2 × StackExitVel × π ÷

4 × (StackInnerDiam)2

÷ 144
 E-23

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

July 26, 2000 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Fugitives 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

Summary: 

If any component counts are provided, estimate uncontrolled fugitive THC emissions 

according to the following equation. (Note that the sum is taken over 16 component types.) 

= ( )× ( ) ×

comp

THC EFcomp,stream Ncomp E 720 hr/month

where: 

EFcomp,stream = Emission factor unique the type of component and process stream 

(lb/hr-component) 

stream = StreamType 

Ncomp = Count of components of a given type present on the facility. There are 16 

component types, with counts given the following variable names: Valves, 

PumpSeals, Connectors, Flanges, OpenEndedLines, Compressors, 

Diaphragms, Drains, DumpArms, Hatches, Instruments, Meters, 

PressureReliefValves, PolishedRods, OtherReliefValves, Vents. (Note: Treat 

null values as zero.) 

If any component counts are provided, estimate uncontrolled fugitive VOC emissions 

according to the following equation. (Note that the sum is taken over 16 component types.) 

= ( )× ( ) × ×

comp

VOC EFcomp,stream Ncomp WtFrcomp,stream E 720 hr/month

where: 

WtFrcomp,stream = Weight fraction of VOC unique to the type of component and process stream 
 E-24

THC emission factors and VOC weight fractions are included in an excel spreadsheet 

(FugitiveFactors.xls).1,2

If no component counts are provided, estimate emissions according to the following 

equations. 

( ) ETHC = 720 hr/month × EFdefault × Ndefault

( ) E VOC = 720 hr/month × EFdefault × Ndefault × WtFrdefault

where: 

EFdefault = 0.0308 lb/hr-component 

Ndefault = 











=

=

=

100,000; if FacilitySize "Large (> 10,000 components)"

10,000; if FacilitySize "Medium (1000 -10,000 components)"

1000;if FacilitySize "Small (<= 1000 components)"

WtFrdefault = The default VOC weight fraction = WeightPercentVOC ÷ 100 

Default Values:

The following default value should be assigned or estimated if the field is null. 

WeightPercentVOC = 29.6 

Controlled Emissions:

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

 (Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

New QC Check:

There are no new QC checks. 

 

1

 Note that the emission factor for Comp=Pumps, Stream=Heavy Oil was assumed to be equal to the emission 

factor for Comp=Pumps, Stream=Light Oil. No published emission factor is available. This assumption will 

produce a conservatively high estimate. 

2

 Also note that the emission factors and VOC weight fractions for Stream=Gas/Oil/Water were assumed to be 

equal to the larger of the EFs and/or WFs for Stream=Gas and Stream=Oil/Water. Again, no published data are 

available. However, these assumptions will produce conservatively high estimates. 
 E-25

Emission factors and VOC weight fractions for fugitive emissions. (See FugitiveFactors.xls) 

Component Type Stream Type EF(lb/hr-comp) 

VOC Weight 

Fraction 

Connectors Gas 0.000458 0.171 

Connectors NGL 0.000458 0.296 

Connectors Light Oil (>=20 API gr.) 0.000458 0.296 

Connectors Heavy Oil (<20 API gr.) 0.0000167 0.03 

Connectors Oil/Water 0.000242 0.296 

Connectors Oil/Water/Gas 0.000458 0.296 

Flanges Gas 0.000875 0.171 

Flanges NGL 0.000242 0.296 

Flanges Light Oil (>=20 API gr.) 0.000242 0.296 

Flanges Heavy Oil (<20 API gr.) 0.000000875 0.03 

Flanges Oil/Water 0.00000625 0.296 

Flanges Oil/Water/Gas 0.000875 0.296 

Open-ended Lines Gas 0.00458 0.171 

Open-ended Lines NGL 0.00308 0.296 

Open-ended Lines Light Oil (>=20 API gr.) 0.00308 0.296 

Open-ended Lines Heavy Oil (<20 API gr.) 0.00308 0.03 

Open-ended Lines Oil/Water 0.000542 0.296 

Open-ended Lines Oil/Water/Gas 0.00458 0.296 

Pumps Gas 0.00542 0.171 

Pumps NGL 0.0288 0.296 

Pumps Light Oil (>=20 API gr.) 0.0288 0.296 

Pumps Heavy Oil (<20 API gr.) 0.0288 0.03 

Pumps Oil/Water 0.0000542 0.296 

Pumps Oil/Water/Gas 0.00542 0.296 

Valves Gas 0.01 0.171 

Valves NGL 0.00542 0.296 

Valves Light Oil (>=20 API gr.) 0.00542 0.296 

Valves Heavy Oil (<20 API gr.) 0.0000183 0.03 

Valves Oil/Water 0.000217 0.296 

Valves Oil/Water/Gas 0.01 0.296 

Sample Connections Gas 0.00458 0.171 

Sample Connections NGL 0.00308 0.296 

Sample Connections Light Oil (>=20 API gr.) 0.00308 0.296 

Sample Connections Heavy Oil (<20 API gr.) 0.00308 0.03 

Sample Connections Oil/Water 0.000542 0.296 

Sample Connections Oil/Water/Gas 0.00458 0.296 

Compressor Seals Gas 0.0196 0.171 

Compressor Seals NGL 0.0167 0.296 

Compressor Seals Light Oil (>=20 API gr.) 0.0167 0.296 

Compressor Seals Heavy Oil (<20 API gr.) 0.0000708 0.03 

Compressor Seals Oil/Water 0.0308 0.296 
 E-26

Component Type Stream Type EF(lb/hr-comp) 

VOC Weight 

Fraction 

Compressor Seals Oil/Water/Gas 0.0308 0.296 

Diaphragms Gas 0.0196 0.171 

Diaphragms NGL 0.0167 0.296 

Diaphragms Light Oil (>=20 API gr.) 0.0167 0.296 

Diaphragms Heavy Oil (<20 API gr.) 0.0000708 0.03 

Diaphragms Oil/Water 0.0308 0.296 

Diaphragms Oil/Water/Gas 0.0308 0.296 

Drains Gas 0.0196 0.171 

Drains NGL 0.0167 0.296 

Drains Light Oil (>=20 API gr.) 0.0167 0.296 

Drains Heavy Oil (<20 API gr.) 0.0000708 0.03 

Drains Oil/Water 0.0308 0.296 

Drains Oil/Water/Gas 0.0308 0.296 

Dump Arms Gas 0.0196 0.171 

Dump Arms NGL 0.0167 0.296 

Dump Arms Light Oil (>=20 API gr.) 0.0167 0.296 

Dump Arms Heavy Oil (<20 API gr.) 0.0000708 0.03 

Dump Arms Oil/Water 0.0308 0.296 

Dump Arms Oil/Water/Gas 0.0308 0.296 

Hatches Gas 0.0196 0.171 

Hatches NGL 0.0167 0.296 

Hatches Light Oil (>=20 API gr.) 0.0167 0.296 

Hatches Heavy Oil (<20 API gr.) 0.0000708 0.03 

Hatches Oil/Water 0.0308 0.296 

Hatches Oil/Water/Gas 0.0308 0.296 

Instruments Gas 0.0196 0.171 

Instruments NGL 0.0167 0.296 

Instruments Light Oil (>=20 API gr.) 0.0167 0.296 

Instruments Heavy Oil (<20 API gr.) 0.0000708 0.03 

Instruments Oil/Water 0.0308 0.296 

Instruments Oil/Water/Gas 0.0308 0.296 

Meters Gas 0.0196 0.171 

Meters NGL 0.0167 0.296 

Meters Light Oil (>=20 API gr.) 0.0167 0.296 

Meters Heavy Oil (<20 API gr.) 0.0000708 0.03 

Meters Oil/Water 0.0308 0.296 

Meters Oil/Water/Gas 0.0308 0.296 

Pressure Relief Valves Gas 0.0196 0.171 

Pressure Relief Valves NGL 0.0167 0.296 

Pressure Relief Valves Light Oil (>=20 API gr.) 0.0167 0.296 

Pressure Relief Valves Heavy Oil (<20 API gr.) 0.0000708 0.03 

Pressure Relief Valves Oil/Water 0.0308 0.296 

Pressure Relief Valves Oil/Water/Gas 0.0308 0.296 
 E-27

Component Type Stream Type EF(lb/hr-comp) 

VOC Weight 

Fraction 

Other Relief Valves Gas 0.0196 0.171 

Other Relief Valves NGL 0.0167 0.296 

Other Relief Valves Light Oil (>=20 API gr.) 0.0167 0.296 

Other Relief Valves Heavy Oil (<20 API gr.) 0.0000708 0.03 

Other Relief Valves Oil/Water 0.0308 0.296 

Other Relief Valves Oil/Water/Gas 0.0308 0.296 

Polished Rods Gas 0.0196 0.171 

Polished Rods NGL 0.0167 0.296 

Polished Rods Light Oil (>=20 API gr.) 0.0167 0.296 

Polished Rods Heavy Oil (<20 API gr.) 0.0000708 0.03 

Polished Rods Oil/Water 0.0308 0.296 

Polished Rods Oil/Water/Gas 0.0308 0.296 

Vents Gas 0.0196 0.171 

Vents NGL 0.0167 0.296 

Vents Light Oil (>=20 API gr.) 0.0167 0.296 

Vents Heavy Oil (<20 API gr.) 0.0000708 0.03 

Vents Oil/Water 0.0308 0.296 

Vents Oil/Water/Gas 0.0308 0.296 
 E-28

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

June 22, 2001 (revised July 20, 2001) 

TO: Gaylen Drapé STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Glycol Dehydrator Units 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides 

Summary: 

At this time, we are unable to interface GRI-GlyCalc with the DBMS. (EPA’s preferred 

method of calculating emissions is to use GRI-GlyCalc.) Instead, we are going to use a rough, 

back-of-the-envelope approach to estimate emissions. These estimates are going to be very 

rough approximations. Emissions of VOCs will be based upon an emission factor that was 

derived from a survey of facilities that was conducted by the Louisiana DEQ in 1991*

 (data 

summary provided by David Scalfano). Emissions of THC and H2S will be extrapolated from 

some molar glycol affinities (THC:VOC and H2S:VOC) that were modeled using GRI-GlyCalc. 

Uncontrolled Regenerator Emissions:: 

Calculate uncontrolled VOC emissions for glycol regenerators based on processed 

throughput as follows. 

E VOC,GR = EF(lb/MMscf) × Q 

where: 

EVOC,GR = Emissions of VOC from the glycol regenerator in pounds per month 

EF = Emission factor = 6.6 lb VOC/MMscf 

Q = Processed throughput (MMscf) = TotalGasThru 

 

*Louisiana Dept. of Environmental Quality, personal communication, 2001. 
 E-29

In lieu of emission factors for H2S, methane, and ethane, we are going to make some 

rough assumptions about the relative affinity of glycol for these species (see Table 1). 

(Calculations of methane and ethane emissions are done as a mid-step to calculate THC 

emissions, and calculation of H2S emissions is done as a mid-step to calculate SOx emissions.) 

These estimated affinities are based on some modeled results using GRI-GlyCalc 4.0. Also, we 

will assume that the average molecular weight of VOC emissions is 90 lb/lb-mol (also based on 

modeled GRI-GlyCalc 4.0 results). 

Table 1. Assumed affinities of glycol to various species. 

 Affinity of Glycol Type for Species 

Species 

Molecular Weight 

(lb/lb·mol) 

Triethylene Glycol 

(GlycolType = TEG) 

Ethylene Glycol

(GlycolType = EG) 

Methane 16 1/400 1/20 

Ethane 30 1/100 2/5 

H2S 34 6/5 6/5 

Example interpretation: With a TEG regenerator, a molecule of methane in the wet gas is 400 times 

less likely to be emitted to the atmosphere than would be a VOC molecule in the wet gas. 

Calculate uncontrolled glycol regenerator emissions for methane, ethane, and H2S as 

follows. 

90 lb/lb mol

mwt

Vol%

Vol% E E A X

VOC

X

X,GR VOC,GR G,X ⋅ = × × × 

where: 

X = Species (H2S, methane, or ethane) 

EX,GR = Emissions of species X from the glycol regenerator in pounds per month. 

G = Glycol type (“TEG” or “EG”) = GlycolType

AG,X = Affinity of glycol type G for species X (see Table 1). 

Vol%X = Volume percent of species X in the wet gas = 











=

=

=

; if X ethane

; if X methane

2 ; if X H2S

ConcEthane

ConcMethane

ConcNGH S

 

Vol%VOC = Volume percent of VOC in the wet gas = ConcC3HC + ConcC4HC + ConcC5HC + 

ConcC6HC + ConcC7HC + ConcC8plusHC

mwtX = Molecular weight of species X in lb/lb·mol. 

Calculate uncontrolled glycol regenerator emissions for THC as follows. 

 ETHC,GR = EVOC,GR + Emethane,GR + Eethane,GR 
 E-30

Uncontrolled Flash Tank Emissions: 

We will have to use some very roughly approximated ratios in order to estimate 

emissions for flash tanks (Table 2). These also are based on some GRI-GlyCalc modeling 

results. 

Table 2. Relative ratios of flash tank emissions 

to glycol regenerator emissions. 

Species Relative Ratio 

Methane 1 

Ethane 1 

VOCs 4.3 

H2S 2.3 

Calculate uncontrolled flash tank emissions of VOC, H2S, methane and ethane as 

follows. 

EX,FT = EX,GR × RX 

where: 

X = Species (VOC, H2S, methane, or ethane) 

EX,FT = Emissions of species X from the flash tank in pounds per month. 

R = Relative ratio of flash tank emissions to glycol regenerator emissions for species X 

(see Table 2). 

Calculate uncontrolled flash tank emissions of THC as follows. 

 ETHC,FT = EVOC,FT + Emethane,FT + Eethane,FT 

Total Uncontrolled Emissions: 

Calculate total uncontrolled emissions of VOC, THC, and H2S by summing emissions 

from the flash tank and the glycol regenerator as follows. 

EX,total = EX,GR + EX,FT

Emissions Controls: 

SOx emissions only arise as a by-product of flaring (which is an emissions control for 

VOC, THC, and H2S) from the conversion of H2S to SOx in the flare. Thus, if the flare has no 

emissions controls, then SOx emissions are zero ( E 0 SOx ,uncontrolled = ). Controlled emissions of 

SOx are calculated as follows only when GasesVentOrFlare = “Flared”. 

















× − ⋅

⋅ = × ×

100%

Eff

1

34 lb/lb mol

64 lb/lb mol

100%

Eff

E E SO ,other flare

SO ,control H S,total

x

x 2 
 E-31

where: 

ESOx, control = Emissions of SOx in pounds per month (when an emissions control in the form of a 

flare is present) 

EH2S,total = Total uncontrolled emissions of H2S in pounds per month 

Effflare = Combustion efficiency of the flare (assume 95%) 

ESOx, other = SOx control efficiency of other control devices installed. 

Controlled emissions of VOC and THC are calculated as follows. 

∏ 



 



 = × −

100%

Eff E E 1 i

x,control x,total

where: 

EX, control = Controlled emissions of species X in pounds per month 

Effi = The control efficiency of technology or strategy i in percent. 

Further specific details are provided below (see “Controlled Emissions” section). 

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

In addition, use the default values for ConcC3HC through ConcC8plusHC if their sum equals 

zero (ConcC3HC + ConcC4HC + ConcC5HC + ConcC6HC + ConcC7HC + ConcC8plusHC = 

0). 

ConcNGH2Sdefault = 3.18 × 10-4

ConcMethane = 90 

ConcEthane = 3.8 

ConcC3HC = 1.8 

ConcC4HC = 1.2 

ConcC5HC = 0.6 

ConcC6HC = 0.4 

ConcC7HC = 0.1 

ConcC8plusHC = 0.2 

GlycolType = “TEG” 
 E-32

Controlled Emissions:

ETHC, control = ETHC, unc × (1 – EffTHC,VF ÷100) × (1 – EffTHC,CT ÷100) × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, unc × (1 – EffVOC,VF ÷100) × (1 – EffVOC,CT ÷100) × (1 – EffVOC,Oth ÷100) 

ESOx, control = EH2S, unc × EffH2S,VF ÷100 × 64 ÷ 34 × (1 – EffSOx,Oth ÷100) 

IF GasesVentOrFlare = “Vented” THEN 

EffTHC,VF = EffVOC,VF = EffH2S,VF = 0 

IF GasesVentOrFlare = “Flared” THEN 

EffTHC,VF = EffVOC,VF = 98 

EffH2S,VF = 95 

IF ControlTechnology = “none” THEN 

EffTHC,CT = EffVOC,CT = 0 

IF ControlTechnology = “VR/C” THEN 

EffTHC,CT = EffVOC,CT = 80 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = EffVOC,Oth = 0

EffSOx,Oth = 0

New QC Checks:

0 < ConcNGH2Sdefault +ConcMethane + ConcEthane + ConcC3HC + ConcC4HC + ConcC5HC

+ ConcC6HC + ConcC7HC + ConcC8plusHC ≤ 100 

0 < ConcC3HC + ConcC4HC + ConcC5HC + ConcC6HC + ConcC7HC + ConcC8plusHC ≤ 20 

80 ≤ ConcMethane
 E-33

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

September 16, 2000 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions calculations for loading operations 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

Uncontrolled THC Emissions:

Emissions due to loading operations are generated by the displacement of the vapor space 

in the receiving cargo hold by liquid product. Vapor losses may include gases that (1) evolved 

from the residue of the previous cargo, (2) were entrained to the cargo hold during vapor balance 

operations, or (3) evaporated during the loading of the fresh cargo. For this project, we will 

assume that ships arrive in uncleaned, ballasted condition and that the previously carried loads 

were crude oil. 

Calculations

For marine loading of crude petroleum and gasoline, AP-42 recommends the following 

equation to calculate THC emissions due to loading of fresh cargo. 

3

b

THC VA 10

bbl

42.0gal Q T

mG E 0.46 1.84 (0.44 P 0.42) − × × × 













 = + × × − ×

where: 

ETHC = THC emissions (pounds) 

PVA = True vapor pressure of the loaded liquid (psia) = exp[A − (B/TLA)] 

m = Average molecular weight of vapors (lb/lb-mol) = TankVOCMolWeight 

G = Vapor growth factor = 1.02 

Tb = Liquid Bulk Temperature (°R) = TankBulkLiqT + 460 

Q = The amount transferred (bbl) = VolLoaded 
 E-34

A = Empirical Constant = 12.82 − 0.9672 × ln(ReidVP) 

B = Empirical Constant = 7261 − 1216 × ln(ReidVP) 

TLA = Daily average liquid surface temperature (°R) = 0.44 × Taa + (0.56 × Tb) + (0.0079 × a × I) 

Taa = Daily Average Ambient Temperature (°R). (See 2nd row of Table 1.) 

a = Tank Paint Solar Absorptance. (See Table 2.) 

I = Daily Solar Insulation Factor (Btu/ft2

·day) = 1437 Btu/ft2·dayA

Table 1. Daily Average Ambient Temperature, Taa. 

 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

°F 63 64 67 71 77 81 84 84 82 76 71 66 

°R 523 524 527 531 537 541 544 544 542 536 531 526 

Source: National Climate Data Center (ftp://ftp ncdc noaa.gov/pub/datasets/coadsdata/), ComprehensiveOceanAtmosphere Data Set (COADS). Average monthly temperatures for the period 1980-1992 for Marsden Square 81, 

10° Box 241, 2° Box 5537. 

Table 2. Tank Paint Solar Absorptance, a. 

 Solar Absorptance by 

Paint Color and 

Condition 

 Paint Condition 

(TankPaintCondition) 

Paint Color 

(TankPaintColor) Good Poor 

Aluminum/Specular 0.39 0.49 

Aluminum/Diffuse 0.6 0.68 

Grey/Light 0.54 0.63 

Grey/Medium 0.68 0.74 

Red/Primer 0.89 0.91 

White 0.17 0.34 

Uncontrolled VOC Emissions:

VOC emissions (EVOC, in pounds) are calculated as a percent of THC emissions. 

VOC ETHC 100%

TankVaporWeightPercentVOC E = ×

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

ReidVPdefault = 5

TankBulkLiqTdefault = Taa (from Table 1, first row) + 6 × a –1 

TankVOCMolWeightdefault = 50 

TankVaporWeightPercentVOCdefault = 85 

 

A Annual average for New Orleans 
 E-35

FlareEfficiencydefault = 98 

Controlled Emissions:

ETHC, control = ETHC, unc × (1 – EffTHC,VF ÷100) × (1 – EffTHC,CT ÷100) × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, unc × (1 – EffVOC,VF ÷100) × (1 – EffVOC,CT ÷100) × (1 – EffVOC,Oth ÷100) 

IF GasesVentOrFlare = “Vented” THEN 

EffTHC,VF = EffVOC,VF = 0 

IF GasesVentOrFlare = “Flared” THEN 

EffTHC,VF = EffVOC,VF = FlareEfficiency

IF ControlTechnology = “none” THEN 

EffTHC,CT = EffVOC,CT = 0 

IF ControlTechnology = “Vapor Recovery and/or Condenser (VR/C)” THEN 

EffTHC,CT = EffVOC,CT = 80 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = EffVOC,Oth = OtherControlEffVOC 

 (Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = EffVOC,Oth = 0

New QC Checks:

No new QC checks will be defined. 
 E-36

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

April 26, 2000 (revised April 1, 2002) 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for natural gas engines 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

NOx = Nitrogen oxides (as nitrogen dioxide, NO2) 

PM10 = Particulate matter (with aerodynamic diameter of 10 μm or less) 

CO = Carbon monoxide 

Summary: 

To calculate emissions based on fuel use: 

 U E EF 10 3 = (lb/MMscf) × × −

To calculate emissions based on power output: 

453.6g

lb E EF HP t = (g/hp-hr) × × ×

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (Mscf) = TotalFuelUsed

HP = Engine horsepower (hp) = OperatingHP

t = Engine operating time (hr/month) = HrsOperated
E-37 

Emission Factors for Natural Gas Engines 

where EngineStrokeCycle = "2-Cycle" and 

EngineBurnType = "Lean" 

Pollutant 

EFfu

(lb/MMscf) 

EFpo

(g/hp-hr) 

THC 2100 8.2 

VOC 230 0.95 

SOx 0.179 × S 0.00091 × S

NOx 3100 12 

PM10 neg neg 

CO 310 1.2 

Emission Factors for Natural Gas Engines 

where EngineStrokeCycle = "2-Cycle" and 

EngineBurnType = "Clean" 

Pollutant 

EFfu

(lb/MMscf) 

EFpo

(g/hp-hr) 

THC 1900 6.4* 

VOC 88 0.31 

SOx 0.179 × S 0.00060 × S

NOx 330 1.1 

PM10 29 0.10 

CO 350 1.2 

Emission Factors** for Natural Gas Engines 

where EngineStrokeCycle = "2-Cycle" and 

EngineBurnType = "Rich" 

Pollutant 

EFfu

(lb/MMscf) 

EFpo

(g/hp-hr) 

THC 350 1.5 

VOC 29 0.22 

SOx 0.179 × S 0.00079 × S

NOx 4400 21 

PM10 13 0.044 

CO 1800 7.3 

Emission Factors for Natural Gas Engines 

where EngineStrokeCycle = "4-Cycle" and 

EngineBurnType = "Lean" 

Pollutant 

EFfu

(lb/MMscf) 

EFpo

(g/hp-hr) 

THC 1100 4.5 

VOC 78 0.31 

SOx 0.179 × S 0.00085 × S

NOx 3700 15 

PM10 10 0.036 

CO 310 1.2 

Emission Factors for Natural Gas Engines 

where EngineStrokeCycle = "4-Cycle" and 

EngineBurnType = "Clean" 

Pollutant 

EFfu

(lb/MMscf) 

EFpo

(g/hp-hr) 

THC 2600 11 

VOC 92 0.39 

SOx 0.179 × S 0.00075 × S

NOx 130 0.54 

PM10 17 0.068 

CO 530 2.2 

Emission Factors for Natural Gas Engines 

where EngineStrokeCycle = "4-Cycle" and 

EngineBurnType = "Rich" 

Pollutant 

EFfu

(lb/MMscf) 

EFpo

(g/hp-hr) 

THC 350 1.5 

VOC 29 0.22 

SOx 0.179 × S 0.00079 × S

NOx 4400 21 

PM10 13 0.044 

CO 1800 7.3 

The SOx emission factors vary with fuel sulfur content (ppmv) (S = FuelH2SContent). 

*I suspect a type-O in the AP-42 draft section, which (if used) would have made this value 6.4 × 10-4. This should 

be double-checked later, if possible. 

**AP-42 does not provide emission factors for these combinations, therefore, the emission factors for the 4-

cycle/rich engine type were applied. 

These factors come from AP-42, Draft Section 3.2, Dated June 1997.
E-38 

 If a user-entered value for TotalFuelUsed is available or if it can be estimated from the 

default values (below), then estimate emissions based upon fuel use. Otherwise, if OperatingHP

and HrsOperated are both available, then estimate emissions based upon power output. If none 

of these conditions are met, don't calculate emissions. Note that you cannot calculate SOx

emissions unless the FuelH2SContent is supplied. 

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

FuelHeatingValuedefault = 1050 

TotalFuelUseddefault = FuelUsageRate × 1/FuelHeatingValue ÷ 1000 × OperatingHP ×

HrsOperated

FuelSulfurContent = 3.18

Controlled Emissions:

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

ESOx, control = ESOx, uncontrolled × (1 – EffSOx,Oth ÷100) 

ENOx, control = ENOx, uncontrolled × (1 – EffNOx,Oth ÷100) 

EPM10, control = EPM10, uncontrolled × (1 – EffPM10,Oth ÷100) 

ECO, control = ECO, uncontrolled × (1 – EffCO,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

EffNOx,Oth = OtherControlEffNOx 

EffPM10,Oth = OtherControlEffPM10 

EffCO,Oth = OtherControlEffCO 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

EffSOx,Oth = 0 

EffNOx,Oth = 0 

EffPM10,Oth = 0 

EffCO,Oth = 0 
 E-39

New QC Checks:

0.8 × TotalFuelUsed ≤ FuelUsageRate × 1/FuelHeatingValue × 1000 × OperatingHP ×

HrsOperated ≤ 1.2 × TotalFuelUsed

FuelUsageRate ≤ MaxRatedFuelUsage

OperatingHP ≤ MaxHP
E-40 

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

April 26, 2000 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Natural Gas Turbines 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

SOx = Sulfur oxides (as sulfur dioxide, SO2) 

NOx = Nitrogen oxides (as nitrogen dioxide, NO2) 

PM10 = Particulate matter (with aerodynamic diameter of 10 μm or less) 

CO = Carbon monoxide 

Summary: 

To calculate emissions based on fuel use: 

 U E EF 10 3 = (lb/MMscf) × × −

To calculate emissions based on power output3: 

HP t

H

1

125 lb/MMBtu

lb/hp - hr E = EF(lb/MMscf) × × × ×

 

3

 A conversion factor of ~125 was used to convert from lb/MMBtu to lb/hp-hr (see Table 3.1-1 Section 3.1), 

thus H is included in the equation 
 E-41

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (Mscf) = TotalFuelUsed

H = Fuel heating value (Btu/scf) = FuelHeatingValue 

HP = Engine horsepower (hp) = OperatingHP

t = Engine operating time (hr/month) = HrsOperated 

Emission Factors for Natural Gas Turbines 

Pollutant 

EFfu

(lb/MMscf) 

THC 8.5 

VOC 2.8 

SOx 0.72 × S 

NOx 410 

PM10 7.4 

CO 88 

The SOx emission factor varies with fuel sulfur content (ppmv) (S = FuelH2SContent). 

These factors come from AP-42, Draft Section 3.1, Dated July 1998. 

 If a user-entered value for TotalFuelUsed is available or if it can be estimated from 

the default values (below), then estimate emissions based upon fuel use. Otherwise, if 

OperatingHP and HrsOperated are both available, then estimate emissions based upon power 

output. If none of these conditions are met, don't calculate emissions. Note that you cannot 

calculate SOx emissions unless the FuelH2SContent is supplied. 

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

FuelHeatingValuedefault = 1050 

TotalFuelUseddefault = FuelUsageRate × 1/FuelHeatingValue × 1000 × OperatingHP ×

HrsOperated

FuelSulfurContent = 3.18
 E-42

Controlled Emissions:

ETHC, control = ETHC, uncontrolled × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC,Oth ÷100) 

ESOx, control = ESOx, uncontrolled × (1 – EffSOx,Oth ÷100) 

ENOx, control = ENOx, uncontrolled × (1 – EffNOx,Oth ÷100) 

EPM10, control = EPM10, uncontrolled × (1 – EffPM10,Oth ÷100) 

ECO, control = ECO, uncontrolled × (1 – EffCO,Oth ÷100) 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

EffSOx,Oth = OtherControlEffSOx 

EffNOx,Oth = OtherControlEffNOx 

EffPM10,Oth = OtherControlEffPM10 

EffCO,Oth = OtherControlEffCO 

(Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

EffSOx,Oth = 0 

EffNOx,Oth = 0 

EffPM10,Oth = 0 

EffCO,Oth = 0 

New QC Checks:

0.8 × TotalFuelUsed ≤ FuelUsageRate × 1/FuelHeatingValue × 1000 × OperatingHP ×

HrsOperated ≤ 1.2 × TotalFuelUsed

FuelUsageRate ≤ MaxRatedFuelUsage

OperatingHP ≤ MaxHP
E-43 

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

September 14, 2000 (revised February 15, 2002) 

TO: Gaylen Drapé and Suryamani Lingamallu STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Storage Tanks 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

Uncontrolled THC Emissions:

VOC and THC may be lost from storage tanks as a result of flashing, working, and 

standing losses (Lf, Lw, and Ls). Total emissions = Ls + Lw + Lf. I am assuming that all tanks are 

fixed roof tanks because I really doubt if there are going to be a significant number of offshore 

floating-roof storage tanks. 

Standing Losses. Standing losses (Ls) of THC in pounds are calculated according to the 

following equation: 

s, THC VV WV KE KS L = 365× × × ×

where: 

VV = Tank vapor space volume (ft3

) – see discussion below 

WV = Stock vapor density (lb/ft3

) – see discussion below 

KE = Calculated vapor space expansion factor (unitless) – see discussion below 

KS = Calculated vented vapor saturation factor (unitless) – see discussion below 

Note: If the tank has a floating roof, standing losses are assumed to be reduced 90%. 
 E-44

Vapor Space Volume, VV. 

For a horizontal, rectangular tank, with a flat roof (where TankShape = rectangular, 

TankOrientation = horizontal, and TankRoofType = flat) 

VV = TankShellLength × TankShellWidth1 × HVO

where: 

HVO = Vapor Space Outage (ft) = TankShellHgt − TankAvgLiquidHgt

For a vertical, rectangular tank with a flat roof (where TankShape = rectangular, TankOrientation

= vertical and TankRoofType = flat) 

VV = TankShellWidth1 × TankShellWidth2 × HVO

where: 

HVO = Vapor Space Outage (ft) = TankShellHgt − TankAvgLiquidHgt

For a horizontal, cylindrical tank (where TankShape = rectangular and TankOrientation = 

vertical): 

4 0.785

π H V VO

V ×

× × × = TankShellDiam TankShellLength

where: 

HVO = Vapor Space Outage (ft) = 0.5 × TankShellDiam (This assumes that the tank is half-full 

on average.) 

For a vertical, cylindrical tank (where TankShape = cylindrical and TankOrientation = vertical) 

VO

2

V H

4

π V = ×TankShellDiam ×

where: 

HVO = Vapor space outage (ft) = 











=













	


 




 



 + +

+ =

; if "dome"

; if "cone"

2

3

2

2

1

3

1

TankRoofType TankShellDiam

TankRoofHgt TankShellHgt-TankAvgLiquidHgt TankRoofHgt

TankShellHgt-TankAvgLiquidHgt TankRoofHgt TankRoofType

Stock vapor density, WV. 

Wv = (TankVOCMolWeight × PVA) ÷ (10.731 × TLA) 
 E-45

where: 

TLA = daily average liquid surface temperature (°R) = 0.44 × Taa + (0.56 × Tb) + (0.0079 × a × I) 

Taa = Daily Average Ambient Temperature (°R). (See 2nd row of Table 1.) 

a = Tank Paint Solar Absorptance. (See Table 2.) 

Tb = Liquid Bulk Temperature (°R) = TankBulkLiqT + 460 

I = Daily Solar Insulation Factor (Btu/ft2

·day) = 1437 Btu/ft2·dayA

PVA = True Vapor Pressure (psia) = exp[A − (B/TLA)] 

A = Empirical Constant = 12.82 − 0.9672 × ln(ReidVP) 

B = Empirical Constant = 7261 − 1216 × ln(ReidVP) 

Table 1. Daily Average Ambient Temperature, Taa. 

 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

°F 63 64 67 71 77 81 84 84 82 76 71 66 

°R 523 524 527 531 537 541 544 544 542 536 531 526 

Source: National Climate Data Center (ftp://ftp ncdc noaa.gov/pub/datasets/coadsdata/), ComprehensiveOceanAtmosphere Data Set (COADS). Average monthly temperatures for the period 1980-1992 for Marsden Square 81, 

10° Box 241, 2° Box 5537. 

Table 2. Tank Paint Solar Absorptance, a. 

 Solar Absorptance by 

Paint Color and 

Condition 

 Paint Condition 

(TankPaintCondition) 

Paint Color 

(TankPaintColor) Good Poor 

Aluminum/Specular 0.39 0.49 

Aluminum/Diffuse 0.6 0.68 

Grey/Light 0.54 0.63 

Grey/Medium 0.68 0.74 

Red/Primer 0.89 0.91 

White 0.17 0.34 

Calculated vapor space expansion factor, KE.

KE = (Tv/TLA) + (Pv − Pb)/(Pa − PVA) 

where: 

Tv = Daily Vapor Temperature Range (°R) = 0.72 × Ta+ 0.028 × a × I 

Ta = Daily Ambient Temperature Range (°R) = 10°R (assumed) 

Pv = Daily Pressure Range (psia)= 0.50 × B × Pva × Tv/TLA

2

 

A Annual average for New Orleans 
 E-46

Pb = Breather Vent Pressure Setting Range (psig) 

= BreatherVentPressure − BreatherVentVacuum

Pa = Atmospheric Pressure (psia) = 14.7 psia 

Note: If KE is calculated as above to be a negative value, then set to zero. 

Calculated vented vapor saturation factor, KS. 

Ks=1/(1+ 0.053 × PVA × HVO) 

Working Losses. Working losses (Lw) of THC in pounds are calculated according to the 

following equation: 

w, THC PVA KP KN L = 0.0010×TankVOCMolWeight × ×Throughput × ×

where: 

Kp = Working loss product factor (unitless) = 0.75 

KN = Working loss turnover factor (unitless) = 







>

≤

+ ;for N 36

1;for N 36

6N

180 N 

N = Number of Turnovers = 5.614 × Throughput / VLX

VLX = Tank Maximum Liquid Volume (ft3

) – see discussion below 

Note: If the tank has a floating roof, working losses are assumed to be reduced by 90%. 

Tank Maximum Liquid Volume, VLX. 

For a horizontal, rectangular tank, with a flat roof (where TankShape = rectangular, 

TankOrientation = horizontal, and TankRoofType = flat) 

VLX = TankShellLength × TankShellWidth1 × TankShellHgt

For a vertical, rectangular tank with a flat roof (where TankShape = rectangular, TankOrientation

= vertical, and , and TankRoofType = flat) 

VLX = TankShellWidth1 × TankShellWidth2 × TankShellHgt

For a horizontal, cylindrical tank (where TankShape = rectangular and TankOrientation = 

horizontal): 

= ×TankShellDiam ×TankShellLength 2

LX 4

π V
 E-47

For a vertical, cylindrical tank (where TankShape = cylindrical and TankOrientation = vertical) 

= ×TankShellDiam ×TankShellHgt 2

V 4

π V

Flashing Losses. If HasFlashingLosses = "no" then flashing losses (Lf) are estimated to 

be zero. Otherwise, flashing losses of THC in pounds are calculated according to the following 

equation: 

Lf, THC = GOR ×Throughput × GD

where: 

GOR = Gas-to-oil ratio (scf/bbl) – see discussion below 

GD = Tank vent hydrocarbon gas density (lb/ft3

) = MoleFraction ÷ 100 ×

TankVOCMolWeight ÷ 379 

Gas-to-oil ratio, GOR. 

















+

× = × × ×

460

C GOR C UP CSG exp C 3

1 2

SeparatorFluidT 

APIGravity 

where: 

C1 = Vasquez-Beggs Constant = 





 >

0.0362; otherwise

0.0178;if APIGravity 30 

UP = Separator pressure (psia) = LowestSeparatorPressure + 14.7 

C2 = Vasquez-Beggs Constant = 





 >

1.0937; otherwise

1.187; if APIGravity 30

CSG = Corrected Specific Gravity of Gas 

= SeparatorOilSpecGrvty × [1.0 + 0.00005912 × APIGravity × SeparatorFluidT

× LOG(UP/114.7)] 

C3 = Vasquez-Beggs Constant = 





 >

25.724; otherwise

23.934;if APIGravity 30

Uncontrolled VOC Emissions:

 Emissions of VOC are estimated using speciation profiles from an API publication no. 

4683. 

Ls,VOC = Ls,THC × 0.67 

Lw,VOC = Lw,THC × 0.67 

Lf,VOC = Lf,THC × 0.73 
 E-48

Default Values:

The following default values should be assigned or estimated if the corresponding fields are null. 

APIGravitydefault = 37 

ReidVPdefault = −1.699 + 0.179 × APIGravity 

BreatherVentPressuredefault = 0.03 

BreatherVentVacuumdefault = −0.03 

TankBulkLiqTdefault = Taa (from Table 1, first row) + 6 × a − 1 

TankVOCMolWeightdefault = 50 

TankVaporWeightPercentVOCdefault = 85 

MoleFractiondefault = 90 

TankAvgLiquidHgtdefault = 0.5 × TankShellHgt 

FlareEfficiencydefault = 98 

Controlled Emissions:

ETHC, control = ETHC, unc × (1 – EffTHC,VF ÷100) × (1 – EffTHC,CT ÷100) × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, unc × (1 – EffVOC,VF ÷100) × (1 – EffVOC,CT ÷100) × (1 – EffVOC,Oth ÷100) 

IF GasesVentOrFlare = “Vented” THEN 

EffTHC,VF = EffVOC,VF = 0 

IF GasesVentOrFlare = “Flared” THEN 

EffTHC,VF = EffVOC,VF = FlareEfficiency

IF ControlTechnology = “none” THEN 

EffTHC,CT = EffVOC,CT = 0 

IF ControlTechnology = “Vapor Recovery and/or Condenser (VR/C)” THEN 

EffTHC,CT = EffVOC,CT = 80 

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = EffVOC,Oth = OtherControlEffVOC 

 (Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = EffVOC,Oth = 0
 E-49

New QC Checks:

Revise ReidVP QC check to be: 0.5 ≤ ReidVP < 14 

Taa − 40 ≤ TankBulkLiqT ≤ Taa + 40 

0 ≤ TankAvgLiquidHgt ≤ TankShellHgt

TankRoofHgt ≤ 0.2 × TankShellHgt 
E-50 

MEMORANDUM

1360 Redwood Way, Suite C 

Petaluma, CA 94954-1169 

707/665-9900 

FAX 707/665-9800 

www.sonomatech.com

June 1, 2001 

TO: Gaylen Drapé STI Ref. No. 998202 

FROM: Dana Coe 

SUBJECT: Emissions Calculations for Vents 

Pollutants: 

THC = Total hydrocarbons (methane plus ethane, C3, C4, ..., C8+) 

VOC = Volatile organic compounds (or, non-methane, non-ethane hydrocarbons) 

Summary: 

(Note: For vents, some variables come from the eqVEN table, while others come from 

the eqVENOCC table. Variables from the eqVENOCC table are denoted with an asterisk, *.) 

In addition to miscellaneous sources, vents can receive exhaust streams that are 

manifolded from other equipment units on the same platform. In order to avoid double counting 

the emissions from these manifolded equipment units (which are calculated with the methods 

prescribed in previous memoranda), we will have to subtract their emissions from the total vent 

gas stream.4

 The first step is to estimate total VOC emissions for a vent (manifolded emissions 

plus other emissions) according to the following equation. 





 





× × + × ⋅ = × × =

− n

i 1

*

i

*

i

VOC

6

vent, VOC VOC 1000 V' F t

379.4scf/lb mol

m

ppm

10 E C

 

4 Note for air quality modelers: For air quality modeling purposes, emissions from manifolded units should be 

treated as having the same exhaust elevation, exit velocity, and exit temperature as the vent to which they are 

directed.
 E-51

where: 

E = Emissions in pounds per month 

CVOC = Concentration of VOC in the vent gas (ppmv) = ConcVOC 

mVOC = Molecular weight of VOC (lb/lb·mol) = VOCMolWeight 

V' = Non-upset volume of gas vented (Mscf) = VolVented * F = Upset vent feed rate for occurrence i (Mscf/hr) = i AvgFeed* 

*

i t = Duration of occurrence i = HrsOperated* 

The second step is to determine whether a vent receives manifolded emissions. Vents 

can receive manifolded emissions amine units, fugitives, loading operations, storage tanks, and 

glycol dehydrators. Data tables for equipment units of these types, which also are collocated on 

the same platform as the vent, will need to be examined to determine if the vent receives their 

emissions. If the following three conditions are true, then a vent is receiving emissions via 

manifold from another equipment unit of type, “XXX”. 

• EqXXX:IsVentedtoLPCollectSystem = “yes” 

• EqXXX: VentedToID* = “VEN” 

• EqVEN:UserID:Month:Year:CmplxID:StructID:EquipID = 

EqXXX:UserID:MonthYear:CmplxID:StructID:VentedToID** 

where: 

XXX = “AMI”, “FUG”, “LOA”, “STO”, or “GLY” 

VentedToID* = The first 3 characters of the field VentedToID 

VentedToID** = The remaining characters of VentedToID after the first 3 characters have 

been truncated. 

The third step is to calculate the emissions from miscellaneous sources that are directed 

to this vent (Emisc,VOC). 







≤

> = 0;if D 0D;if D 0

E misc,VOC

where: 

D = Event,VOC − Eman,VOC ; (pounds per month) 

Eman,VOC = The sum of VOC emissions for all equipment units that are manifolded to this 

vent (pounds per month), if any. If none, Eman,VOC = 0. 

This method to estimate THC emissions is based upon a data analysis that STI performed 

for the American Petroleum Institute a couple of years ago (Ryan et al., 1998) and my suggested 

assumption that miscellaneous vent emissions arise mostly from flashing losses5

. Our data 

 

5

 Flashing losses arise when a large pressure drop occurs and dissolved gases escape from a liquid oil stream, 

similar to the way that carbon dioxide escapes from an opened can of soda pop. Flashing losses occur when oil is 

pumped to the surface from deep underground, where it is at immense pressure, and allowed to equilibrate to a 

lower pressure or atmospheric pressure. 
 E-52

analysis covered emissions data for flashing losses and storage tank working/breathing losses for 

a set of 103 storage tanks located on exploration and production facilities. The analysis of 

measured data indicated that, on average, 90 percent (on a molar basis) of flashing emissions 

were hydrocarbon emissions. In addition, on average, the molar ratio of ethane:methane:VOC 

was modeled with API software (E&P Tank) to be 17:41:42. We can use this information to 

estimate emissions of THC and methane. 

First, convert miscellaneous VOC emissions to a molar basis as follows: 

Emisc,molVOC = Emisc,VOC ÷ 44 lb/lb·mol 

Then, estimate miscellaneous vented emissions of methane (Me) and ethane (Et) as follows 

(pounds per month): 

Emisc,Me = Emisc,molVOC ×

42

41

× 16 lb/lb·mol 

Emisc,Et = Emisc,molVOC ×

42

17

× 30 lb/lb·mol 

Finally, estimate miscellaneous vented emissions of THC as follows (pounds per month): 

Emisc,THC = Emisc,Me + Emisc,Et + Emisc,VOC 

Default Values:

The following default values should be assigned or estimated if the corresponding fields 

are null. 

VOCMolWeight = 44 

Controlled Emissions:

Note: For the following equations, E denotes total emissions (Eflare + Epilot). 

ETHC, control = ETHC, uncontrolled × (1 – EffTHC ÷100) × (1 – EffTHC,Oth ÷100) 

EVOC, control = EVOC, uncontrolled × (1 – EffVOC ÷100) × (1 – EffTHC,Oth ÷100) 

IF ControlTechnology = “condenser” THEN 

EffVOC = 80

EffTHC = 80

IF ControlTechnology = “none” THEN 

EffVOC = 0

EffTHC = 0
 E-53

IF OtherControlDevice = “yes” THEN 

EffTHC,Oth = OtherControlEffVOC 

EffVOC,Oth = OtherControlEffVOC 

 (Note: Treat null values as 0.) 

IF OtherControlDevice = “no” THEN 

EffTHC,Oth = 0 

EffVOC,Oth = 0 

New QC Check:

0.8 × StackExitVel × π ÷ 4 × (StackInnerDiam)

2

÷ 144 ≤ VolVented≤ 1.2 × StackExitVel × π ÷ 4 

× (StackInnerDiam)

2

÷ 144 

References

Ryan P.A., Coe D.L., and Chinkin L.R. (1998) Correlation equations to predict Reid vapor 

pressure and properties of gaseous emissions for exploration and production facilities. Report 

prepared for American Petroleum Institute, Washington, DC by Sonoma Technology, Inc., 

Petaluma, CA, STI-997340-1798-FR, March. 
 F-1

APPENDIX F 

DOCUMENTATION AND GUIDE FOR THE DATABASE 

MANAGEMENT SYSTEM 
GS-01-40 

Annotated 

User’s Manual 

For the Emissions Inventory of 

Outer Continental Shelf Platform Activities 

Adjacent to the Breton National Wilderness Area 

of the Gulf of Mexico 

August 17, 2001 

(annotated by STI, July 2002) 

Prepared for the Minerals Management Service 

Under Subcontract to Sonoma Technology, Inc. 

Prime Contract Number 01-98-CT-30856 

by ENSCO, Inc. 

445 Pineda Ct. 

Melbourne, Florida 32940 
User’s Manual for Emissions Inventory DBMS 

i 

Table of Contents 

1 Introduction ................................................................................................................. 1 

2 Intended Audience....................................................................................................... 2 

3 Procedure for Creating the Emissions Database ......................................................... 2 

4 Database Table Definitions ......................................................................................... 6 

4.1 Amine Gas Sweetening Unit............................................................................... 6 

4.2 Boiler/Heater/Burner........................................................................................... 8 

4.3 Diesel or Gasoline Engine................................................................................... 9 

4.4 Drilling Rig ....................................................................................................... 10 

4.5 Flares ................................................................................................................. 11 

4.6 Flare Upsets....................................................................................................... 12 

4.7 Fugitives............................................................................................................ 13 

4.8 Fugitive Factors................................................................................................. 14 

4.9 Glycol Dehydrator Unit..................................................................................... 15 

4.10 Loading Operations........................................................................................... 17 

4.11 Natural Gas Engine ........................................................................................... 18 

4.12 Natural Gas Turbine.......................................................................................... 19 

4.13 Pollutants........................................................................................................... 21 

4.14 Storage Tank ..................................................................................................... 22 

4.15 Structure Information ........................................................................................ 24 

4.16 Survey Information ........................................................................................... 26 

4.17 QC Survey Information..................................................................................... 26 

4.18 Vents.................................................................................................................. 27 

4.19 Vent Upsets ....................................................................................................... 28 

5 Entity-Relationship Diagram (ERD)......................................................................... 30 

5.1 ERD – Permanent Tables .................................................................................. 30 

5.2 ERD – Temporary Tables ................................................................................. 31 
User’s Manual for Emissions Inventory DBMS 

1 

1 Introduction 

As a deliverable to Minerals Management Service (MMS) Contract 01-98-CT-30856, 

ENSCO, Inc., under subcontract to Sonoma Technology, Inc., developed a Database 

Management System (DBMS) to construct emissions inventories from oil platform 

activities adjacent to the Breton National Wilderness Area in the Gulf of Mexico. The 

DBMS processes data collected by the Breton Offshore Activities Data System (BOADS) 

survey tool developed by STI, a Visual Basic program allowing offshore operators to 

report monthly equipment activity emitting primary air pollutants. The BOADS program 

generates MS-Access files (in *.mdb format) that serve as input to the DBMS. The 

DBMS performs simple QC functions and creates a database containing the emissions 

inventory. DBMS specifications included QC validation criteria for the reported activity 

data as well as emissions calculation algorithms (consistent with EPA standards) of 

primary pollutant species (see Table 1) for 12 major types of equipment (see Table 2). 

The DBMS design provides a comprehensive relational table structure containing 

platform activity data for the 12 equipment categories and pollutant emissions data. 

Emission factors are stored in separate Oracle tables for easy access and modification by 

the user. 

Section 2 describes the intended audience for this manual, while Section 3 provides the 2-

step procedure for creating the emissions inventory. Database table descriptions and 

entity-relationship diagrams are provided in Sections 4 and 5, respectively. 

Table 1: Primary Pollutant Species 

Carbon Monoxide (CO) 

Nitrogen Oxide (NOx) 

Sulphur Dioxide (SO2) 

Total Suspended Particles (TSP) 

Particulate Matter below 10μm in diameter (PM-10) 

Total Hydrocarbons (THC) 

Volatile Organic Hydrocarbons (VOC) 

Table 2: Types of Platform Equipment 

Amine Gas Units 

Boilers, Heaters, and Burners 

Diesel and Gas Engines 

Drilling Rigs 

Flares 

Fugitives 

Glycol Dehydrating Units 

Loading Operations 

Natural Gas Engines 

Natural Gas Turbines 

Storage Tanks 

Vents 
User’s Manual for Emissions Inventory DBMS 

2 

2 Intended Audience 

This User’s Manual provides instructions for an Oracle database administrator, or an 

experienced database application specialist, to create an emissions inventory. To operate 

the DBMS, it is necessary that the user be familiar with the PL/SQL language and be able 

to run script procedures from the operating system command line. 

3 Procedure for Creating the Emissions Database 

STI Added Note: On the distribution CD in directory ‘Oracle Emissions Export’ is an 

export file (& Log) ready for import into you Oracle database. For this export to work do 

the following: 

1. Create Tablespace ‘SNMDATA’ 150mb 

2. Create Tablespace ‘SNMINDX’ 200mb 

3. Create a user ‘EMISSIONS’ with the default Tablespace ‘SNMDATA’. 

The export is a user ‘EMISSIONS’ export only. 

The emissions inventory is created via a stored procedure written in PL/SQL to perform 

batch processing of user data sets. Typically a data set consists of a single user (possibly 

reporting multiple complexes/structures) for a one-month period. Processing is done in 

two steps as described below. 

Step 1: Retrieve Survey Data files for the Emissions database: 

STI Added Note: The procedure for Step 1 is specific only to the STI project. This text 

should be replaced as appropriate if the DBMS is applied to a new scenario or project. 

(For example, the ftp site, ftp.sonomatech.com, which is maintained by STI, was set up 

for use on this project. It is not available for public use.) 

 Login to an Unix server 

 Connect to the ftp site to receive the *.mdb files, type the following: 

ftp <ftp.sonomatech.com> 

Userid: 

PWD: 

CD mmsgomr 

CD ‘subdirectory’ 

 Download *.mdb files from ftp site subdirectory, type the following: 

 prompt (turns off the Interactive mode.) 

 bin (to download files as binary) 

 mget * (retrieves all the files and downloads) 

 mdel * (only when files have been successfully downloaded) 

 Place *.mdb files into appropriate survey month folder. (Note: Pay attention 

to files that are named revision or email messages that point out a certain file 

is a revision and for which month.) 

 Prior to moving the revision file into a specific folder, remove the originally 

submitted file into the appropriate survey month update folder. (Note: This is for 

archiving purposes.)
User’s Manual for Emissions Inventory DBMS 

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Step 2: Load Individual “ mdb” Files to the Emissions Database 

(Note: Load one survey month of data at a time into the Oracle temp tables.) 

STI Added Note: You can load more than one month at a time into the Oracle temp 

tables. 

 

 If the Access mdb file is not version 2000, first convert the mdb file. 

 For one mdb file at a time, import dblinkqrysprod.mdb as follows: 

o First, select the Tables tab in Access under objects, then new and 

Import tables. Then choose the above import file to get the linked 

tables to Oracle. (Note: Prior to retrieving the linked tables must login 

into the Production database.) 

o Next, select the Queries tab under objects, the File menu option, get 

external data and Import. Then choose the above import file to get the 

query objects. 

 Execute each dblink query by double clicking. 

STI Added Note: A shortcut for the step immediately above and below. The Access macro 

’Load all Tables’ found in either the dblinkqrysprod.mdb or ‘MergedData_QC.mdb’ 

databases will perform all the necessary steps. 

 Execute XXEXECQCCHKS query last. (Note: Even though copying data 

from Access database to Oracle database done manually, all other processes 

will run automatically for that set of data if this query is executed last.) 

STI Added Note: All other processes will not run automatically. The final step is to 

Execute <PROCEDURE> emgnrc.exec_all_load_qc_em via SQL*Plus, which is 

discussed further below, to complete the process. 

 The following is a list of the Oracle temp tables vs. Access tables: 

o EQAMIORC - eqAMI 

o EQBOIORC - eqBOI 

o EQDIEORC - eqDIE 

o EQDRIORC - eqDRI 

o EQFLA2ORC - eqFLAOCC 

o EQFLAORC - eqFLA 

o EQFUGORC - eqFUG 

o EQGLYORC - eqGLY 

o EQLOAORC - eqLOA 

o EQNGEORC - eqNGE 

o EQNGTORC - eqNGT 

o EQQCORC - eqQC 

o EQSTOORC - eqSTO 

o EQSTORC - Structures 

o EQSVORC - Surveys 

o EQUSRORC - User 

o EQVEN2ORC - eqVENOCC 

o EQVENORC - eqVEN 

o EXEC_QC_CHECKS - (note: data from Surveys is copied.) 
User’s Manual for Emissions Inventory DBMS 

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 The Oracle database automatically reads information from 

EXEC_QC_CHECKS table and begins to run QC validations and range 

checks for each set of survey data for a specific month. All QC related 

problems are Inserted as records into the QC_SURVEYS table. 

 The following is a list of actual Oracle database tables vs. temp tables: 

o Amine_Gas_Units(AMI) - EQAMIORC 

o Boil_Heat_Burners(BOI) - EQBOIORC 

o Diesel_Gas_Engines(DIE) – EQDIEORC 

o Drilling_Rigs(DRI) – EQDRIORC 

o Flares(FLA) – EQFLAORC 

o Flare_Upsets(FLA2) – EQFLA2ORC 

o Fugitives(FUG) – EQFUGORC 

o Glycol_Dehyd_Units(GLY) – EQGLYORC 

o Loading_Operations(LOA) – EQLOAORC 

o Natural_Gas_Engines(NGE) – EQNGEORC 

o Natural_Gas_Turbines(NGT) – EQNGTORC 

o Pollutants(PO) – (note: New table for emission calculations.) 

o QC_Surveys(QC) – EQQCORC 

o Storage_Tanks(STO) – EQSTOORC 

o Structures(ST) – EQSTORC 

o Surveys(SV) – EQSVORC and EQUSRORC loaded into Surveys 

o Vents(VEN) – EQVENORC 

o Vent_Upsets(VEN2) – EQVENOCC 

 The following is a list of Oracle support tables for the Emissions database: 

o Em_Log (note: This table keeps track of all the database procedures 

that have been executed for each survey set of data.) 

o Em_Error_Log (note: Keeps track of file I/O problems/concerns.) 

o Emission_Factors (note: Various constants used to compute emissions 

for the various equipment types. These factors can be modified by a 

responsible user which can modify future calculations for the specific 

equipment type(s).) 

o Fugitive_Factors (note: Emission factors used specifically for the 

Fugitives table. Separate table was created since this data involved a 

different format from the Emission_Factors table.) 

o Emissions_Ref_Codes (note: Domain Values are stored in this table.) 

o Exec_QC_Checks (note: This table keeps track of all data that needs 

to be validated(QC) and when the validation checks are completed, a 

status of complete is updated to each survey data record.) 
User’s Manual for Emissions Inventory DBMS 

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 Execute <PROCEDURE> emgnrc.exec_all_load_qc_em via SQL*Plus.

This procedure will check for null status records in the

EXEC_QC_CHECKS table. If any null status surveys(i.e. 

Userid/Month/Year) exist in this table, then the Oracle database automatically 

begins to copy from the temp tables into the Oracle perm. Tables and also 

runs QC on each table. When processing is complete for this survey set of 

data, the check status field in EXEC_QC_CHECKS table is updated to ‘C’ for 

complete. A QC report/flat file of data is written to indicate what fields in the 

various tables did not pass the validation/range tests. Also the emissions 

calculations for the various equipment types per survey set are computed and 

stored in the Pollutants table. 

STI Added Note: The above automatic process creates *.dat files. The Oracle 

DBA may create, if needed, a data directory by assigning a file directory path 

to the initialization parameter ‘UTL_FILE_DIR’ (Oracle PL/SQL file I/O 

directory). To match the above parameter entry, the DBA will need to modify 

the package body ‘emissions.EMGNRC’: 

 Source Line & column (8,28) for the drive path 

 Source Line & column (9,31) for the file folder path 

 Repeat the cycle from opening the next mdb file and follow all the above 

steps. 

 Some mdb files have multiple months of surveys for the same user. In this 

case just update Exec_QC_Checks and set chk_status = ‘X’ where the survey 

record does not match the month which is currently being loaded. There are 

also cases where multiple mdb files reflect the same survey set of data(i.e. for 

the same user just spread across two or three mdb files.) In this case, execute 

all the querys to load data to Oracle for each mdb file except the Surveys, 

Users and the XX queries. These should only be executed once so that only 

one record is inserted into the Exec_QC_Checks table. 

 At the end of the specific Survey Month, make sure to clear all Oracle temp. 

tables data to prepare for the Next Survey Month 
User’s Manual for Emissions Inventory DBMS 

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4 Database Table Definitions 

4.1 Amine Gas Sweetening Unit 

Table Name: AMINE_GAS_UNITS 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. HRS_OPERATED NUMBER(7,3) Hours 

9. TOTAL_GAS_THRU NUMBER(7,3) MMscf 

10. CONC_NGH2S NUMBER(7,3) % by volume 

11. CONC_METHANE NUMBER(7,3) % by volume 

12. CONC_ETHANE NUMBER(7,3) % by volume 

13. CONC_C3HC NUMBER(7,3) % by volume 

14. CONC_C4HC NUMBER(7,3) % by volume 

15. CONC_C5HC NUMBER(7,3) % by volume 

16. CONC_C6HC NUMBER(7,3) % by volume 

17. CONC_C7HC NUMBER(7,3) % by volume 

18. CONC_C8PLUS_HC NUMBER(7,3) % by volume 

19. EMITTED_H2S NUMBER(7,3) Uncontrolled % emitted 

20. EMITTED_METHANE NUMBER(7,3) Uncontrolled % emitted 

21. EMITTED_ETHANE NUMBER(7,3) Uncontrolled % emitted 

22. EMITTED_C3HC NUMBER(7,3) Uncontrolled % emitted 

23. EMITTED_C4HC NUMBER(7,3) Uncontrolled % emitted 

24. EMITTED_C5HC NUMBER(7,3) Uncontrolled % emitted 
User’s Manual for Emissions Inventory DBMS 

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25. EMITTED_C6HC NUMBER(7,3) Uncontrolled % emitted 

26. EMITTED_C7HC NUMBER(7,3) Uncontrolled % emitted 

27. EMITTED_C8PLUS_HC NUMBER(7,3) Uncontrolled % emitted 

28. CONTROL_TECH VARCHAR2(4) None; Vapor Recovery and/or Condenser 

(VR/C); Sulfur Recovery (SR); SR + VR/C 

29. CONDENSERT NUMBER(7,3) Degrees F 

30. CONDENSERP NUMBER(8,3) psia 

31. SRU_RECOVERY_EFF NUMBER(6,3) % of S 

32. IS_VENT_TO_LPCSYS VARCHAR2(1) 

33. VENTED_TO_ID VARCHAR2(11) Equip type & ID of Vent/Flare on same structure 

(vent/flare record must exist first) 

34. GASES_VENT_FLARE VARCHAR2(1) VENT; FLARE 

35. EQUIP_ELEV NUMBER(7,3) ft above msl *No Collection System 

36. EXHAUST_OUTLET_HGT NUMBER(7,3) ft *No Collection System 

37. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches *No Collection System 

38. EXHAUST_OT_EXITVEL NUMBER(8,3) scfh *No Collection System *Vent only 

39. EXHAUST_OT_ANGLE NUMBER(7,3) degrees *No Collection System *Vent only 

40. EXHAUST_OUTLETT NUMBER(7,3) Deg F *No Collection System *Vent only 

41. FLARE_FEED_RATE NUMBER(8,3) scfh *No Collection System *Flare only 

42. FLARE_COMBUSTIONT NUMBER(8,3) Deg F *No Collection System *Flare only 

43. FLARE_EFFICIENCY NUMBER(6,3) % (default 90%) *No Collection System *Flare 

Only 

44. OTHER_CNT_DEV VARCHAR2(1) 

45. OTHER_CNT_DESC VARCHAR2(255) 

46. OTHER_CNT_EFFSOX NUMBER(6,3) % 

47. OTHER_CNT_EFFNOX NUMBER(6,3) % 

48. OTHER_CNT_EFFCO NUMBER(6,3) % 

49. OTHER_CNT_EFFVOC NUMBER(6,3) % 

50. OTHER_CNT_EFFPM10 NUMBER(6,3) % 
User’s Manual for Emissions Inventory DBMS 

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4.2 Boiler/Heater/Burner 

Table Name: BOIL_HEAT_BURNERS 

Column names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. MAX_RATED_HIRATE NUMBER(7,3) MMbtu/hr 

9. HEAT_INPUT_RATE NUMBER(7,3) MMbtu/hr 

10. HRS_OPERATED NUMBER(7,3) Hrs 

11. FUEL_TYPE VARCHAR2(2) NATURAL GAS; PROCESS GAS; WASTE 

GAS; WASTE OIL;

12. MAX_RATED_FUEL_USE NUMBER(10,3) scf/hr 

13. MAX_RATED_FUEL_USE_OIL NUMBER(9,3) lb/hr 

14. FUEL_USAGE_RATE NUMBER(10,3) scf/hr 

15. FUEL_USE_RATE_OIL NUMBER(9,3) lb/hr 

16. TOTAL_FUEL_USED NUMBER(10,3) Mscf 

17. TOTAL_FUEL_USED_OIL NUMBER(10,3) lb 

18. FUEL_HEATING_VALUE NUMBER(8,3) btu/scf 

19. FUEL_HEATING_VALUE_OIL NUMBER(9,3) btu/lb 

20. FUEL_H2S_CONTENT NUMBER(9,4) ppmv 

21. FUEL_H2S_CONTENT_OIL NUMBER(5,3) % by mass 

22. EMISSION_CONTROLS VARCHAR2(1) NONE; LOW NOX BURNER; FLU GAS RECIRC

23. EQUIP_ELEV NUMBER(7,3) ft above msl 

24. EXHAUST_OUTLET_HGT NUMBER(7,3) ft 

25. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches 
User’s Manual for Emissions Inventory DBMS 

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26. EXHAUST_OT_EXITVEL NUMBER(8,3) ft/s 

27. EXHAUST_OT_EXITT NUMBER(8,3) Deg F 

28. EXHAUST_OT_ANGLE NUMBER(7,3) degrees 

29. OTHER_CNT_DEV VARCHAR2(1) 

30. OTHER_CNT_DESC VARCHAR2(255) 

31. OTHER_CNT_EFFSOX NUMBER(6,3) % 

32. OTHER_CNT_EFFNOX NUMBER(6,3) % 

33. OTHER_CNT_EFFCO NUMBER(6,3) % 

34. OTHER_CNT_EFFVOC NUMBER(6,3) % 

35. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.3 Diesel or Gasoline Engine 

Table Name: DIESEL_GAS_ENGINES 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. MFR VARCHAR2(50) 

9. MODEL VARCHAR2(50) 

10. FUEL_TYPE VARCHAR2(2) DIESEL; GASOLINE; WASTE OIL/SOLVENT

11. MAX_HP NUMBER(8,3) horsepower 

12. OPERATING_HP NUMBER(8,3) horsepower 

13. HRS_OPERATED NUMBER(7,3) hours 

14. MAX_RATED_FUEL_USE NUMBER(9,3) btu/hp-hr 
User’s Manual for Emissions Inventory DBMS 

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15. FUEL_USAGE_RATE NUMBER(9,3) btu/hp-hr 

16. TOTAL_FUEL_USED NUMBER(10,3) gal 

17. FUEL_HEATING_VALUE NUMBER(9,3) btu/lb (default 19,300 for Diesel, 20,300 for 

gasoline)

18. FUEL_SULFUR_CONTENT NUMBER(5,3) % mass 

19. EQUIP_ELEV NUMBER(7,3) ft above msl 

20. EXHAUST_OUTLET_HGT NUMBER(7,3) ft 

21. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches 

22. EXHAUST_OT_EXITVEL NUMBER(8,3) ft/s 

23. EXHAUST_OT_EXITT NUMBER(8,3) Deg F 

24. EXHAUST_OT_ANGLE NUMBER(7,3) degrees 

25. OTHER_CNT_DEV VARCHAR2(1) 

26. OTHER_CNT_DESC VARCHAR2(255) 

27. OTHER_CNT_EFFSOX NUMBER(6,3) % 

28. OTHER_CNT_EFFNOX NUMBER(6,3) % 

29. OTHER_CNT_EFFCO NUMBER(6,3) % 

30. OTHER_CNT_EFFVOC NUMBER(6,3) % 

OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.4 Drilling Rig 

Table Name: DRILLING_RIGS 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 
User’s Manual for Emissions Inventory DBMS 

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8. HRS_OPERATED NUMBER(6,3) hours 

9. DIESEL_USAGE NUMBER(9,3) Total Diesel Fuel Usage (gal)

10. GAS_USAGE NUMBER(9,3) Total Gasoline Fuel Usage (gal)

11. NG_USAGE NUMBER(9,3) Total Natural Gas Fuel Usage (Mscf) 

12. OTHER_CNT_DEV VARCHAR2(1) 

13. OTHER_CNT_DESC VARCHAR2(255) 

14. OTHER_CNT_EFFSOX NUMBER(6,3) % 

15. OTHER_CNT_EFFNOX NUMBER(6,3) % 

16. OTHER_CNT_EFFCO NUMBER(6,3) % 

17. OTHER_CNT_EFFVOC NUMBER(6,3) % 

18. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.5 Flares 

Table Name: FLARES 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. STACK_OUTLET_ELEV NUMBER(7,3) ft above msl 

9. STACK_ANGLE NUMBER(3) degrees; 0=vert, 90=horiz; 180=down (range 1-

180)

10. STACK_INNER_DIAM NUMBER(6,3) inches 

11. STACK_EXIT_VEL NUMBER(8,3) ft/s 

12. STACK_EXITT NUMBER(8,3) Deg F 

13. NUM_FLARE_OCCUR NUMBER(4,0) Number of upset flare occurances. For each, track 

the start date, duration (hrs), peak flare feed rate (Mscf/hr).
User’s Manual for Emissions Inventory DBMS 

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14. HRS_OPERATED NUMBER(7,3) hours 

15. VOL_FLARED NUMBER(9,3) Mscf 

16. FLARE_EFFICIENCY NUMBER(6,3) % 

17. CONC_H2S NUMBER(11,4) ppmv 

18. FLARE_SMOKE VARCHAR2(1) NONE; LIGHT; MEDIUM; HEAVY

19. HAS_CONT_FLARE_PILOT VARCHAR2(1) 

20. PILOT_FUEL_FEED_RATE NUMBER(7,3) Mscf 

21. OTHER_CNT_DEV VARCHAR2(1) 

22. OTHER_CNT_DESC VARCHAR2(255) 

23. OTHER_CNT_EFFSOX NUMBER(6,3) % 

24. OTHER_CNT_EFFNOX NUMBER(6,3) % 

25. OTHER_CNT_EFFCO NUMBER(6,3) % 

26. OTHER_CNT_EFFVOC NUMBER(6,3) % 

27. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.6 Flare Upsets 

Table Name: FLARE_UPSETS 

Column Names: 

1. TIME_STAMP DATE Date and time 

2. HRS_OPERATED NUMBER(7,3) hours 

3. AVG_FEED NUMBER(9,3) Mscf/hr 

4. CONC_H2S NUMBER(11,4) ppmv 

5. COMB_TEMP NUMBER(9,3) Deg F 

6. COMMENTS VARCHAR2(255) 

7. ST_ID_FK NUMBER(20) 

8. EQUIP_ID_FK VARCHAR2(8) 

9. EQUIP_TYPE_FK VARCHAR2(3) 
User’s Manual for Emissions Inventory DBMS 

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4.7 Fugitives 

Table Name: FUGITIVES 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. FACILITY_SIZE VARCHAR2(1) SMALL (<=1000 components); MEDIUM (1000-

10,000 components); LARGE (>10,000 components)

9. STREAM_TYPE VARCHAR2(2) Light Oil (>=20 APIG); Heavy Oil (<20 APIG); 

OIL/WATER; OIL/WATER/GAS; GAS; NGL

10. VALVES NUMBER(8,3) Count 

11. PUMP_SEALS NUMBER(7,3) Count 

12. CONNECTORS NUMBER(8,3) Count 

13. FLANGES NUMBER(8,3) Count 

14. OPEN_ENDED_LINES NUMBER(7,3) Count 

15. COMPRESSORS NUMBER(7,3) Count 

16. DIAPHRAGMS NUMBER(8,3) Count 

17. DRAINS NUMBER(7,3) Count 

18. DUMP_ARMS NUMBER(8,3) Count 

19. HATCHES NUMBER(7,3) Count 

20. INSTRUMENTS NUMBER(8,3) Count 

21. METERS NUMBER(7,3) Count 

22. PRESSURE_RELIEF_VALVES NUMBER(8,3) Count 

23. POLISHED_RODS NUMBER(7,3) Count 

24. OTHER_RELIEF_VALVES NUMBER(7,3) Count 

25. VENTS NUMBER(7,3) Count 
User’s Manual for Emissions Inventory DBMS 

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26. IS_VENT_TO_LPCSYS VARCHAR2(1) 

27. VENTED_TO_ID VARCHAR2(11) Equip type & ID of Vent/Flare on same structure 

(vent/flare record must exist first)

28. GASES_VENT_FLARE VARCHAR2(1) VENTED; FLARED

29. EQUIP_ELEV NUMBER(7,3) ft above msl *No Collection System

30. EXHAUST_OUTLET_HGT NUMBER(7,3) ft *No Collection System

31. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches *No Collection System

32. EXHAUST_OT_EXITVEL NUMBER(8,3) scfh *No Collection System *Vent only

33. EXHAUST_OT_ANGLE NUMBER(7,3) degrees *No Collection System *Vent only

34. EXHAUST_OT_EXITT NUMBER(8,3) Deg F *No Collection System *Vent only

35. FLARE_FEED_RATE NUMBER(9,3) scfh *No Collection System *Flare only

36. FLARE_COMBUSTIONT NUMBER(8,3) Deg F *No Collection System *Flare only

37. FLARE_EFFICIENCY NUMBER(6,3) % (default 90%) *No Collection System *Flare 

Only

38. OTHER_CNT_DEV VARCHAR2(1) 

39. OTHER_CNT_DESC VARCHAR2(255) 

40. OTHER_CNT_EFFSOX NUMBER(6,3) % 

41. OTHER_CNT_EFFNOX NUMBER(6,3) % 

42. OTHER_CNT_EFFCO NUMBER(6,3) % 

43. OTHER_CNT_EFFVOC NUMBER(6,3) % 

44. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

45. WEIGHT_PER_VOC NUMBER(7,3) % 

4.8 Fugitive Factors 

Table Name: FUGITIVE_FACTORS 

Column Names: 

1. COMPONENT_TYPE VARCHAR2(30) 

2. STREAM_TYPE VARCHAR2(30) 

3. EF_COMP NUMBER() 

4. WT_FRAC_VOC NUMBER() 
User’s Manual for Emissions Inventory DBMS 

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4.9 Glycol Dehydrator Unit 

Table Name: GLYCOL_DEHYD_UNITS 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. HRS_OPERATED NUMBER(7,3) hours 

9. TOTAL_GAS_THRU NUMBER(9,3) Mscf 

10. CONC_NGH2S NUMBER(7,3) ppmv 

11. CONC_METHANE NUMBER(7,3) % by volume 

12. CONC_ETHANE NUMBER(7,3) % by volume 

13. CONC_C3HC NUMBER(7,3) % by volume 

14. CONC_C4HC NUMBER(7,3) % by volume 

15. CONC_C5HC NUMBER(7,3) % by volume 

16. CONC_C6HC NUMBER(7,3) % by volume 

17. CONC_C7HC NUMBER(7,3) % by volume 

18. CONC_C8PLUS_HC NUMBER(7,3) % by volume 

19. GLYCOL_TYPE VARCHAR2(1) TEG; EG

20. RECIRC_RATE NUMBER(6,3) gal/min 

21. LEAN_GLY_WATER_CONT NUMBER(9,3) % by weight 

22. WET_GAS_WATER_CONT NUMBER(8,3) lb/MMscf

23. DRY_GAS_WATER_CONT NUMBER(7,3) lb/MMscf (TEG units only)

24. WET_GAST NUMBER(7,3) Deg F 

25. WET_GASP NUMBER(8,3) psig 
User’s Manual for Emissions Inventory DBMS 

16 

26. COLD_SEPARATORT NUMBER(8,3) Deg F 

27. COLD_SEPARATORP NUMBER(8,3) psig 

28. GLYCOL_PUMP_TYPE VARCHAR2(1) ELECTRIC; GAS

29. USE_FLASH_TANK VARCHAR2(1) YES/No 

30. FLASH_TANKT NUMBER(7,3) Deg F 

31. FLASH_TANKP NUMBER(8,3) psig 

32. STRIPPING_GAS VARCHAR2(2) NONE; DRY GAS; FLASH GAS; NITROGEN

33. STRIPPING_GAS_FLOW_RT NUMBER(9,3) scfm 

34. CONTROL_TECH VARCHAR2(4) Vapor Recovery and/or Condenser (VR/C); None

35. CONDENSERT NUMBER(7,3) Deg F 

36. CONDENSERP NUMBER(7,3) psia 

37. IS_VENT_TO_LPCSYS VARCHAR2(1) yes/no 

38. VENTED_TO_ID VARCHAR2(11) Equip type & ID of Vent/Flare on same structure 

(vent/flare record must exist first)

39. GASES_VENT_FLARE VARCHAR2(1) VENTED; FLARED

40. EQUIP_ELEV NUMBER(7,3) ft above msl *No Collection System

41. EXHAUST_OUTLET_HGT NUMBER(7,3) ft *No Collection System

42. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches *No Collection System

43. EXHAUST_OT_EXITVEL NUMBER(8,3) scfh *No Collection System *Vent only

44. EXHAUST_OT_ANGLE NUMBER(7,3) degrees *No Collection System *Vent only

45. EXHAUST_OT_EXITT NUMBER(8,3) Deg F *No Collection System *Vent only

46. FLARE_FEED_RATE NUMBER(9,3) scfh *No Collection System *Flare only

47. FLARE_COMBUSTIONT NUMBER(8,3) Deg F *No Collection System *Flare only

48. FLARE_EFFICIENCY NUMBER(6,3) % (default 90%) *No Collection System *Flare 

Only

49. OTHER_CNT_DEV VARCHAR2(1) 

50. OTHER_CNT_DESC VARCHAR2(255) 

51. OTHER_CNT_EFFSOX NUMBER(6,3) % 

52. OTHER_CNT_EFFNOX NUMBER(6,3) % 

53. OTHER_CNT_EFFCO NUMBER(6,3) % 
User’s Manual for Emissions Inventory DBMS 

17 

54. OTHER_CNT_EFFVOC NUMBER(6,3) % 

55. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.10 Loading Operations 

Table Name: LOADING_OPERATIONS 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. VOL_LOADED NUMBER(11,3) bbl 

9. TANK_PAINT_COLOR VARCHAR2(2) ALUMINUM/SPECULAR; ALUMINUM/DIFFUSE; 

GREY/LIGHT; GREY/MED; RED/PRIMER; WHITE/NA

10. TANK_PAINT_CND VARCHAR2(1) GOOD; POOR

11. TANK_BULK_LIQT NUMBER(7,3) Deg F 

12. REID_VP NUMBER(6,3) psia 

13. TANK_VOC_MOLWGT NUMBER(7,3) lb/lb-mol (defualt 50)

14. TANK_VAPWGT_PVOC NUMBER(7,3) % (default 85%, range 55-100)

15. CONTROL_TECH VARCHAR2(4) Vapor Recovery and/or Condenser (VR/C); None

16. CONDENSERT NUMBER(7,3) Deg F 

17. CONDENSERP NUMBER(8,3) psia 

18. IS_VENT_TO_LPCSYS VARCHAR2(1) yes/no 

19. VENTED_TO_ID VARCHAR2(11) Equip type & ID of Vent/Flare on same structure 

(vent/flare record must exist first)

20. GASES_VENT_FLARE VARCHAR2(1) VENT; FLARE

21. EQUIP_ELEV NUMBER(7,3) ft above msl *No Collection System

22. EXHAUST_OUTLET_HGT NUMBER(7,3) ft *No Collection System
User’s Manual for Emissions Inventory DBMS 

18 

23. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches *No Collection System

24. EXHAUST_OT_EXITVEL NUMBER(8,3) scfh *No Collection System *Vent only

25. EXHAUST_OT_ANGLE NUMBER(7,3) degrees *No Collection System *Vent only

26. EXHAUST_OT_EXITT NUMBER(8,3) Deg F *No Collection System *Vent only

27. FLARE_FEED_RATE NUMBER(9,3) scfh *No Collection System *Flare only

28. FLARE_COMBUSTIONT NUMBER(8,3) Deg F *No Collection System *Flare only

29. FLARE_EFFICIENCY NUMBER(6,3) % (default 90%) *No Collection System *Flare 

Only

30. OTHER_CNT_DEV VARCHAR2(1) 

31. OTHER_CNT_DESC VARCHAR2(255) 

32. OTHER_CNT_EFFSOX NUMBER(6,3) % 

33. OTHER_CNT_EFFNOX NUMBER(6,3) % 

34. OTHER_CNT_EFFCO NUMBER(6,3) % 

35. OTHER_CNT_EFFVOC NUMBER(6,3) % 

36. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.11 Natural Gas Engine 

Table Name: NATURAL_GAS_ENGINES 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. MFR VARCHAR2(50) 

9. MODEL VARCHAR2(50) 

10. MAX_HP NUMBER(9,3) horsepower 
User’s Manual for Emissions Inventory DBMS 

19 

11. OPERATING_HP NUMBER(9,3) horsepower 

12. ENGINE_STROKE_CYCLE NUMBER(1) "2-Cycle" Or "4-Cycle" Or Is Null

13. ENGINE_BURN_TYPE VARCHAR2(1) LEAN; CLEAN; RICH

14. HRS_OPERATED NUMBER(7,3) hours 

15. MAX_RATED_FUEL_USE NUMBER(8,3) btu/hp-hr

16. FUEL_USAGE_RATE NUMBER(8,3) btu/hp-hr

17. TOTAL_FUEL_USED NUMBER(10,3) Mscf

18. FUEL_HEATING_VALUE NUMBER(8,3) Btu/scf (Default 1050)

19. FUEL_H2S_CONTENT NUMBER(10,4) ppmv 

20. EQUIP_ELEV NUMBER(7,3) ft above msl 

21. EXHAUST_OUTLET_HGT NUMBER(7,3) ft 

22. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches 

23. EXHAUST_OT_EXITVEL NUMBER(8,3) ft/s 

24. EXHAUST_OT_EXITT NUMBER(8,3) Deg F 

25. EXHAUST_OT_ANGLE NUMBER(7,3) degrees 

26. OTHER_CNT_DEV VARCHAR2(1) 

27. OTHER_CNT_DESC VARCHAR2(255) 

28. OTHER_CNT_EFFSOX NUMBER(6,3) % 

29. OTHER_CNT_EFFNOX NUMBER(6,3) % 

30. OTHER_CNT_EFFCO NUMBER(6,3) % 

31. OTHER_CNT_EFFVOC NUMBER(6,3) % 

32. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.12 Natural Gas Turbine 

Table Name: NATURAL_GAS_TURBINES 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 
User’s Manual for Emissions Inventory DBMS 

20 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. MFR VARCHAR2(50) 

9. MODEL VARCHAR2(50) 

10. MAX_HP NUMBER(9,3) horsepower 

11. OPERATING_HP NUMBER(9,3) horsepower 

12. PURPOSE VARCHAR2(2) ELECTRICITY GENERATION; PRODUCT 

PRESSURIZATION;

13. HRS_OPERATED NUMBER(7,3) hours 

14. MAX_RATED_FUEL_USE NUMBER(8,3) btu/hp-hr

15. FUEL_USAGE_RATE NUMBER(8,3) btu/hp-hr

16. TOTAL_FUEL_USED NUMBER(10,3) Mscf

17. FUEL_HEATING_VALUE NUMBER(8,3) Btu/scf (Default 1050)

18. FUEL_H2S_CONTENT NUMBER(10,4) ppmv 

19. EQUIP_ELEV NUMBER(7,3) ft above msl 

20. EXHAUST_OUTLET_HGT NUMBER(7,3) ft 

21. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches 

22. EXHAUST_OT_EXITVEL NUMBER(8,3) ft/s 

23. EXHAUST_OT_EXITT NUMBER(8,3) Deg F 

24. EXHAUST_OT_ANGLE NUMBER(7,3) degrees 

25. OTHER_CNT_DEV VARCHAR2(1) 

26. OTHER_CNT_DESC VARCHAR2(255) 

27. OTHER_CNT_EFFSOX NUMBER(6,3) % 

28. OTHER_CNT_EFFNOX NUMBER(6,3) % 

29. OTHER_CNT_EFFCO NUMBER(6,3) % 

30. OTHER_CNT_EFFVOC NUMBER(6,3) % 

31. OTHER_CNT_EFFPM10 NUMBER(6,3) % 
User’s Manual for Emissions Inventory DBMS 

21 

4.13 Pollutants 

Table Name: POLLUTANTS 

Column Names: 

1. PO_ID NUMBER(20,0) Unique Identifier or sequence for each record in 

the pollutants table. 

2. PO_TYPE VARCHAR(4) A specific type of pollutant being computed 

(CO, NOx, SOx, VOC, PM10, THC etc.) 

3. PO_DEFAULT_COMP VARCHAR2(1) A flag to indicate (Y)es/(N)o that this specific 

pollutant was computed using default values. 

4. AIR_POLLUTANT NUMBER(20,4) Emission calculation value for a specific 

pollutant already defined. 

5. EMISSION_TYPE VARCHAR2(2) Emission calculation is of type Controlled or 

Uncontrolled. 

6. PO_CALC_TYPE VARCHAR2(2) Emission calculation based on fuel usage. 

7. ST_ID_FK NUMBER(20) 

8. EQUIP_ID_FK VARCHAR2(8) 

9. EQUIP_TYPE_FK VARCHAR2(3) 
User’s Manual for Emissions Inventory DBMS 

22 

4.14 Storage Tank 

Table Name: STORAGE_TANKS 

Column Names: 

1. EQUIP_ID VARCHAR2(8) 

2. EQUIP_TYPE VARCHAR2(3) 

3. STATUS VARCHAR2(1) 

4. STATUS_EFF_DATE DATE 

5. COMMENTS VARCHAR2(255) 

6. QC_DATE DATE 

7. ST_ID_FK NUMBER(20) 

8. TANK_SHAPE VARCHAR2(1) CYLINDRICAL; RECTANGULAR

9. TANK_ORIENTATION VARCHAR2(1) HORIZONTAL; VERTICAL (default vertical)

10. TANK_SHELL_DIAM NUMBER(6,3) ft *cylindrical

11. TANK_SHELL_HGT NUMBER(6,3) ft *vertical

12. TANK_SHELL_LENGTH NUMBER(6,3) ft *horizontal

13. TANK_SHELL_WIDTH1 NUMBER(6,3) ft *rectangular

14. TANK_SHELL_WIDTH2 NUMBER(6,3) ft *rectangular

15. FIXED_ROOF VARCHAR2(1) Fixed = yes, floating - no

16. TANK_ROOF_TYPE VARCHAR2(1) CONE, DOME, FLAT, PEAKED

17. TANK_ROOF_HGT NUMBER(6,3) ft 

18. TANK_PAINT_COLOR VARCHAR2(2) ALUMINUM/SPECULAR; ALUMINUM/DIFFUSE; 

GREY/LIGHT; GREY/MED; RED/PRIMER; WHITE/NA

19. TANK_PAINT_CND VARCHAR2(1) GOOD; POOR

20. BREATH_VENT_PRES NUMBER(6,3) psig 

21. BREATH_VENT_VAC NUMBER(6,3) psig 

22. TANK_AVG_LIQ_HGT NUMBER(6,3) ft 

23. TANK_BULK_LIQT NUMBER(7,3) Deg F 

24. PRODUCT_TYPE VARCHAR2(2) CRUDE; CONDENSATE

25. API_GRAVITY NUMBER(6,3) Product API Gravity, measured in oAPI
User’s Manual for Emissions Inventory DBMS 

23 

26. REID_VP NUMBER(6,3) Product Reid Vapor Pressure, measured in psia

27. THROUGH_PUT NUMBER(11,3) bbl 

28. HAS_FLASH_LOSS VARCHAR2(1) yes/no 

29. TANK_VOC_MOLWGT NUMBER(7,3) lb/lb-mol (defualt 50)

30. TANK_VAPWGT_PVOC NUMBER(6,3) % (default 85%, range 55-100)

31. MOLE_FRACTION NUMBER(7,3) Mole Fraction THC in vented Gas; between 0-1 *if 

Flashing Losses

32. LOW_SEP_PRESSURE NUMBER(6,3) Separator Pressure, measured in psig *if Flashing 

Losses

33. SEPARATOR_FLUIDT NUMBER(7,3) Separator Fluid Temp, measured in F *if Flashing 

Losses

34. SEP_OIL_SPEC_GRVTY NUMBER(5,3) Separator Oil Specific Gravity, *if Flashing Losses

35. SEP_OIL_H2S_CONTENT NUMBER(5,3) mol% H2S 

36. SEP_OIL_O2_CONTENT NUMBER(6,3) mol% oxygen 

37. SEP_OIL_CO2_CONTENT NUMBER(6,3) mol% carbon dioxide 

38. SEP_OIL_N2_CONTENT NUMBER(6,3) mol% nitrogen 

39. SEP_OIL_C1_CONTENT NUMBER(6,3) mol% methane 

40. SEP_OIL_C2_CONTENT NUMBER(6,3) mol% ethane 

41. SEP_OIL_C3_CONTENT NUMBER(6,3) mol% propane 

42. SEP_OIL_IC4_CONTENT NUMBER(6,3) mol% isobutane 

43. SEP_OIL_NC4_CONTENT NUMBER(6,3) mol% n-butane 

44. SEP_OIL_IC5_CONTENT NUMBER(6,3) mol% isopentane 

45. SEP_OIL_NC5_CONTENT NUMBER(6,3) mol% n-pentane 

46. SEP_OIL_C6_CONTENT NUMBER(6,3) mol% C6 hydrocarbons 

47. SEP_OIL_C7_CONTENT NUMBER(6,3) mol% C7 hydrocarbons 

48. SEP_OIL_C8_CONTENT NUMBER(6,3) mol% C8 hydrocarbons 

49. SEP_OIL_C9_CONTENT NUMBER(6,3) mol% C9 hydrocarbons 

50. SEP_OIL_C10_PLCONT NUMBER(6,3) mol% C10 hydrocarbons 

51. CONTROL_TECH VARCHAR2(4) Vapor Recovery and/or Condenser (VR/C); None

52. CONDENSERT NUMBER(7,3) Deg F 
User’s Manual for Emissions Inventory DBMS 

24 

53. CONDENSERP NUMBER(7,3) psia 

54. IS_VENT_TO_LPCSYS VARCHAR2(1) yes/no 

55. VENTED_TO_ID VARCHAR2(15) Equip type & ID of Vent/Flare on same structure 

(vent/flare record must exist first)

56. GASES_VENT_FLARE VARCHAR2(1) VENTED; FLARED

57. EQUIP_ELEV VARCHAR2(7) ft above msl *No Collection System

58. EXHAUST_OUTLET_HGT NUMBER(7,3) ft *No Collection System

59. EXHAUST_OT_INNER_DIAM NUMBER(6,3) inches *No Collection 

System

60. EXHAUST_OT_EXITVEL NUMBER(8,3) scfh *No Collection System *Vent only

61. EXHAUST_OT_ANGLE NUMBER(7,3) degrees *No Collection System *Vent only

62. EXHAUST_OT_EXITT NUMBER(8,3) Deg F *No Collection System *Vent only

63. FLARE_FEED_RATE NUMBER(9,3) scfh *No Collection System *Flare only

64. FLARE_COMBUSTIONT NUMBER(8,3) Deg F *No Collection System *Flare only

65. FLARE_EFFICIENCY NUMBER(6,3) % (default 90%) *No Collection System *Flare 

Only

66. OTHER_CNT_DEV VARCHAR2(1) 

67. OTHER_CNT_DESC VARCHAR2(255) 

68. OTHER_CNT_EFFSOX NUMBER(6,3) % 

69. OTHER_CNT_EFFNOX NUMBER(6,3) % 

70. OTHER_CNT_EFFCO NUMBER(6,3) % 

71. OTHER_CNT_EFFVOC NUMBER(6,3) % 

72. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.15 Structure Information 

Table name: STRUCTURES 

Column Names: 

1. ST_ID NUMBER(20) 

2. COMPLEX_ID_NUM VARCHAR2(7) 

3. STRUCTURE_NUMBER VARCHAR2(2) 
User’s Manual for Emissions Inventory DBMS 

25 

4. AREA VARCHAR2(50) 

5. BLOCK VARCHAR2(50) 

6. NAME VARCHAR2(50) 

7. LONGITUDE NUMBER(13,8) 

8. LATITUDE NUMBER(12,8) 

9. DIST_TO_SHORE NUMBER(3,0) 

10. LEASE_NUMBER VARCHAR2(25) 

11. CONTACT VARCHAR2(25) 

12. PHONE VARCHAR2(25) 

13. EMAIL VARCHAR2(50) 

14. PROD_OIL NUMBER(11,3) 

15. PROD_NG NUMBER(9,3) 

16. PROD_NGH2S NUMBER(11,4) 

17. THRU_OIL NUMBER(11,3) 

18. THRU_NG NUMBER(12,3) 

19. THRU_NGH2S NUMBER(11,4) 

20. ADD_THRU_OIL NUMBER(11,3) 

21. OIL_PROC_CMPLXID VARCHAR2(50) 

22. OIL_PROC_STRUCTID VARCHAR2(50) 

23. OIL_PROC_STRTYPE VARCHAR2(3) 

24. TOTAL_FUEL_USE_NG NUMBER(11,3) 

25. TOTAL_FUEL_USE_GAS NUMBER(11,3) 

26. TOTAL_FUEL_USE_DIE NUMBER(10,3) 

27. STATUS VARCHAR2(1) 

28. STATUS_EFF_DATE DATE 

29. COMMENTS VARCHAR2(255) 

30. MMS_COMPANY_NUM_FK VARCHAR2(5) 

31. SURVEY_DATE_FK DATE 

32. QC_DATE DATE 
User’s Manual for Emissions Inventory DBMS 

26 

4.16 Survey Information 

Table Name: SURVEYS 

Column Names: 

1. MMS_COMPANY_NUM VARCHAR2(5) 

2. SURVEY_DATE DATE 

3. BUS_ASC_NAME VARCHAR2(50) 

4. LINE_1_ADDRESS VARCHAR2(50) 

5. LINE_2_ADDRESS VARCHAR2(50) 

6. CITY_NAME VARCHAR2(50) 

7. STATE VARCHAR2(50) 

8. ZIP_CODE VARCHAR2(50) 

9. CONTACT VARCHAR2(50) 

10. PHONE VARCHAR2(50) 

11. FAX VARCHAR2(50) 

12. EMAIL VARCHAR2(50) 

13. STATUS VARCHAR2(1) DEFAULT 'C' 

14. COMMENTS VARCHAR2(255) 

15. LAST_UPDATED DATE 

16. LAST_QC DATE 

17. LAST_EXPORTED DATE 

18. INSTALL_DATE DATE 

19. PROGRAM_LAST_RUN DATE 

20. PROGRAM_VERSION VARCHAR2(10) 

4.17 QC Survey Information 

Table Name: QC_SURVEYS 

Column Names: 
User’s Manual for Emissions Inventory DBMS 

27 

1. QC_ID NUMBER(20,0) 

2. COMPLEX_ID_NUM VARCHAR2(7) 

3. STRUCTURE_NUMBER VARCHAR2(8) 

4. QC_LEVEL VARCHAR2(2) DEFAULT 'SU' 

5. EQUIP_TYPE VARCHAR2(3) 

6. EQUIP_ID VARCHAR2(8) 

7. FIELD_ID VARCHAR2(50) 

8. QC_DESC VARCHAR2(255) 

9. COMMENTS VARCHAR2(255) 

10. MMS_COMPANY_NUM_FK VARCHAR2(5) 

11. SURVEY_DATE_FK DATE 

4.18 Vents 

Table Name: VENTS 

Column Names: 

1. VENT_TYPE VARCHAR2(1) HIGH PRESSURE; LOW PRESSURE

2. EQUIP_ID VARCHAR2(8) 

3. EQUIP_TYPE VARCHAR2(3) 

4. STATUS VARCHAR2(1) 

5. STATUS_EFF_DATE DATE 

6. COMMENTS VARCHAR2(255) 

7. QC_DATE DATE 

8. ST_ID_FK NUMBER(20) 

9. STACK_OUTLET_ELEV NUMBER(7,3) ft above msl 

10. STACK_ANGLE NUMBER(3) degrees; 0=vert, 90=horiz; 180=down (range 1-

180)

11. STACK_INNER_DIAM NUMBER(6,3) inches 

12. STACK_EXIT_VEL NUMBER(8,3) ft/s 

13. STACK_EXITT NUMBER(7,3) Deg F 
User’s Manual for Emissions Inventory DBMS 

28 

14. NUM_VENT_OCCUR NUMBER(4,0) Number of upset vent occurances. For each, track 

the start date, duration (hrs), peak vent rate (Mscf/day).

15. HRS_OPERATED NUMBER(7,3) hours 

16. VOL_VENTED NUMBER(9,3) Mscf 

17. CONTROL_TECH VARCHAR2(4) CONDENSER; NONE

18. CONDENSERT NUMBER(7,3) Deg F 

19. CONDENSERP NUMBER(8,3) psia 

20. CONC_VOC NUMBER(11,3) ppmv 

21. CONC_H2S NUMBER(11,4) ppmv 

22. VOC_MOL_WGT NUMBER(7,3) lb/lb-mol

23. OTHER_CNT_DEV VARCHAR2(1) 

24. OTHER_CNT_DESC VARCHAR2(255) 

25. OTHER_CNT_EFFSOX NUMBER(6,3) % 

26. OTHER_CNT_EFFNOX NUMBER(6,3) % 

27. OTHER_CNT_EFFCO NUMBER(6,3) % 

28. OTHER_CNT_EFFVOC NUMBER(6,3) % 

29. OTHER_CNT_EFFPM10 NUMBER(6,3) % 

4.19 Vent Upsets 

Table Name: VENT_UPSETS 

Column Names: 

1. TIME_STAMP DATE date/time 

2. HRS_OPERATED NUMBER(7,3) hours 

3. AVG_FEED NUMBER(9,3) Mscf/hr 

4. CONC_H2S NUMBER(11,4) H2S Concentration (ppmv)

5. EXIT_TEMP NUMBER(9,3) Deg F 

6. COMMENTS VARCHAR2(255) 

7. ST_ID_FK NUMBER(20) 

8. EQUIP_ID_FK VARCHAR2(8) 
User’s Manual for Emissions Inventory DBMS 

29 

9. EQUIP_TYPE_FK VARCHAR2(3) 
User’s Manual for Emissions Inventory DBMS 

30 

5 Entity-Relationship Diagram (ERD) 

5.1 ERD – Permanent Tables 

SURVEY

# MMS COMPANY NUM

# SURVEY DATE

...

STRUCTURE

# ST_ID

* COMPLEX ID NUM

...

EQUIPMENT

# EQU P D

# EQU P TYPE

o STATUS

o STATUS EFF DATE

o COMMENTS

o QC DATE

QC SURVEY

# QC_ID

...

POLLUTANT

# PO ID

* PO TYPE

o PO DEFAULT COMP

...

FLARE UPSE

T

# T ME STAMP

...

VENT UPSE

T

# TIME STAMP

...

EMISSIONS REF

CODE

# RV DOMAIN

...

EMISSION FACTORS

o UNIT_TYPE

o SOURCE

o CATEGORY

o SUB_CATEGORY

o UNITS

...

EXEC QC CHECKS

# CHK_ D

* USERID

...

FUGITIVE FACTORS

o COMPONENT_TYPE

o STREAM_TYPE

o EF_COMP

o WT_FRAC_VOC

LOADING

OPERATION

...

NATURAL

GAS

TURBINE

...

NATURAL

GAS ENGIN

E

...

GLYCOL

DEHYD

UNIT

...

FUGITIVE

...

DRILLING

RIG

...

STORAGE

TANK

...

FLARE

o STACK OUT

...

VENT

...

DIESEL

GAS

ENGINE

...

BOIL HEAT

BURNER

...

AMINE GAS

UNIT

...

belong to

contain

exist

have

computed by

compute

emitted by

emit

occuring

cause

occuring

cause
User’s Manual for Emissions Inventory DBMS 

31 

5.2 ERD – Temporary Tables 

EM ERROR LOG

o FILE_PATH

o FILE_NAME

o ERR_TYPE

EM LOG

o RECNUM

o NEW_LINE

EQAMIORC

o USERID

o MONTH

o YEAR

...

EQBOIORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQDIEORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQDRIORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

o EQUIPID

o HRSOPERATED

...

EQFLA2ORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

o EQUIPID

o T MESTAMP

...

EQFLAORC

o USERID

o MONTH

o YEAR

...

EQFUGORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQGLYORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQLOAORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQNGEOR

C

o USERID

o MONTH

o YEAR

o CMPLXID

...

EQNGTORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQQCORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQSTOORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQSTORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQSVORC

o USERID

o MONTH

o YEAR

o COMPANY

o ADDRESS1

...

EQUSRORC

o USERID

o COMPANY

o ADDRESS1

o ADDRESS2

o CITY

...

EQVEN2ORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...

EQVENORC

o USERID

o MONTH

o YEAR

o CMPLXID

o STRUCTID

...