U.S. Department of the Interior

Minerals Management Service 

Gulf of Mexico OCS Region 

OCS Study 

MMS 2004-072 

Gulfwide Emission Inventory Study 

for the Regional Haze and 

Ozone Modeling Efforts 

Final Report 

Authors 

Darcy Wilson 

Joseph Fanjoy 

Richard Billings 

Prepared under MMS Contract 

1435-01-00-CT-31021 

by 

Eastern Research Group, Inc. 

1600 Perimeter Park Drive 

Morrisville, North Carolina 27560 

Published by 

New Orleans

October 2004 
iii 

DISCLAIMER 

This report was prepared under contract between the Minerals Management Service (MMS) and 

Eastern Research Group, Inc. This report has been technically reviewed by the MMS and 

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: 

Wilson, D.L., J.N. Fanjoy, and R.S. Billings. 2004. Gulfwide Emission Inventory Study for the 

Regional Haze and Ozone Modeling Effort: Final Report. U.S. Dept. of the Interior, 

Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS 

Study MMS 2004-072. 273 pp. 

ACKNOWLEDGMENTS 

This report would not have been possible without the contributions of the following staff at ERG, 

Inc.: Andy Blackard, Regi Oommen, Roger Chang, Robin Mongero, Heather Perez, Jaime 

Hauser, and Jody Tisano. Invaluable assistance was also provided by the staff of COMM 

Engineering, Inc., particularly Brian Boyer and Christy Chadick. 
v 

TABLE OF CONTENTS 

Section Page

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

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

1. EXECUTIVE SUMMARY ............................................................................................. 1-1 

2. INTRODUCTION ........................................................................................................... 2-1 

3. DATA COLLECTION .................................................................................................... 3-1 

 3.1 Introduction.......................................................................................................... 3-1 

 3.2 Expansion and Testing of the BOADS Data Collection Software ...................... 3-1 

 3.3 Working with Users ............................................................................................. 3-2 

 3.4 Operator Use of GOADS Software to Collect Data ............................................ 3-2 

 3.5 Quality Assurance/Quality Control...................................................................... 3-2 

4. QUALITY ASSURANCE/QUALITY CONTROL ........................................................ 4-1 

 4.1 Introduction.......................................................................................................... 4-1 

 4.2 Checking File Integrity and Matching QA Summary.......................................... 4-1 

 4.3 Equipment Summary Checks............................................................................... 4-1 

 4.3.1 User-Level Summary............................................................................... 4-2 

 4.3.2 Survey-Level Summary ........................................................................... 4-2 

 4.3.3 Structure-Level Summary........................................................................ 4-2 

 4.3.4 Equipment-Level Summary..................................................................... 4-2 

 4.4 QA/QC Checks .................................................................................................... 4-3 

 4.4.1 Pre-Processing.......................................................................................... 4-3 

 4.4.2 Equipment Survey Consistency ............................................................... 4-4 

 4.4.3 Data Range Checks.................................................................................. 4-5 

 4.4.4 Stream Analysis Between Certain Equipment......................................... 4-6 

 4.4.5 Applying Surrogate Values...................................................................... 4-6 

 4.4.6 Post-Processing of Surrogates.................................................................. 4-6 
vi 

TABLE OF CONTENTS (CONTINUED) 

Section Page

5. DEVELOPMENT OF THE EMISSION INVENTORY................................................. 5-1 

 5.1 Introduction.......................................................................................................... 5-1 

 5.2 Expansion of the Draft Breton Study Oracle DBMS........................................... 5-1 

 5.3 Emission Estimation Procedures.......................................................................... 5-3 

 5.3.1 Amine Units............................................................................................. 5-3 

 5.3.2 Boilers/Heaters/Burners........................................................................... 5-4 

 5.3.3 Diesel and Gasoline Engines ................................................................... 5-8 

 5.3.4 Drilling Rigs........................................................................................... 5-10 

 5.3.5 Flares...................................................................................................... 5-12 

 5.3.6 Fugitives................................................................................................. 5-14 

 5.3.7 Glycol Dehydrators................................................................................ 5-17 

 5.3.8 Loading Operations................................................................................ 5-18 

 5.3.9 Losses from Flashing ............................................................................. 5-20 

 5.3.10 Mud Degassing ...................................................................................... 5-21 

 5.3.11 Natural Gas Engines .............................................................................. 5-23 

 5.3.12 Natural Gas Turbines ............................................................................. 5-25 

 5.3.13 Pneumatic Pumps................................................................................... 5-27 

 5.3.14 Pressure/Level Controllers..................................................................... 5-28 

 5.3.15 Storage Tanks......................................................................................... 5-29 

 5.3.16 Vents ...................................................................................................... 5-33 

6. NON-PLATFORM SOURCE CATEGORIES................................................................ 6-1 

7. DEVELOPMENT OF THE DIURNAL EMISSION CURVES ..................................... 7-1 

 7.1 Introduction.......................................................................................................... 7-1 

 7.2 Approach.............................................................................................................. 7-1 

 7.3 Source Category Groupings and Diurnal Patterns............................................... 7-2 

8. RESULTS ........................................................................................................................ 8-1 

 8.1 Summary of Study Approach............................................................................... 8-1 

 8.2 Presentation of Annual Emission Estimates ........................................................ 8-2 

 8.3 Limitations ........................................................................................................... 8-2 

 8.4 Recommendations................................................................................................ 8-4 

 8.5 Comparison with Other Studies........................................................................... 8-6 

 8.5.1 OCS Oil and Gas Production Platforms................................................... 8-7

 8.5.2 Non-Platform Sources.............................................................................. 8-7 
vii 

TABLE OF CONTENTS 

Section Page

9. REFERENCES ................................................................................................................ 9-1 

APPENDICES: GULFWIDE NON-PLATFORM EMISSION SOURCES 

Appendix A Survey Vessels ............................................................................................... A-1 

Appendix B Drilling Rigs ....................................................................................................B-1 

Appendix C Support Vessels ...............................................................................................C-1 

Appendix D Support Helicopters ....................................................................................... D-1 

Appendix E Pipelaying Operations ....................................................................................E-1 

Appendix F Louisiana Offshore Oil Port ...........................................................................F-1 

Appendix G Vessel Lightering .......................................................................................... G-1 

Appendix H Commercial Fishing ...................................................................................... H-1 

Appendix I Military Vessel Operations ..............................................................................I-1 

Appendix J Commercial Marine Vessels ...........................................................................J-1 

Appendix K Biogenic/Geogenic Sources .......................................................................... K-1 

Appendix L Platform Construction and Removal ..............................................................L-1 

Appendix M Spatial Allocation Methods for Non-Platform Sources ................................M-1 

 
ix 

LIST OF FIGURES 

Figure Page

5-1 Oracle Database Information Flow.................................................................................. 5-2 

7-1 Diurnal Emission Curve for Sources of Constant Activity.............................................. 7-3 

7-2 Diurnal Emission Curve for Boilers/Heaters/Burners ..................................................... 7-5 

7-3 Diurnal Emission Curve for Natural Gas Turbines and Internal 

Combustion Engines ........................................................................................................ 7-6 

7-4 Diurnal Emission Curve for Temperature-Dependent Activities .................................... 7-7 

7-5 Average Air and Water Temperatures for 17 Gulf of Mexico Buoys in 

 August 2000..................................................................................................................... 7-8 

7-6 Diurnal Emission Curve for Helicopters and Support Vessels........................................ 7-9 

M-1 NMFS Fishing Zones with MMS Lease Blocks.............................................................M-5 

M-2 Commercial Marine Vessel Shipping Lanes and Lease Blocks Associated with the 

MMS Western and Central Gulf Areas...........................................................................M-6 

M-3 Location of Drilling Operations and MMS Lease Blocks for 2000................................M-7 

M-4 Shipping Lane Approach and Location of LOOP...........................................................M-8 

M-5 Pipeline Locations and MMS Lease Blocks .................................................................M-10 

M-6 Location of Active Platforms with Helipads ................................................................M-11 

M-7 Support Vessel Fairways...............................................................................................M-12 

M-8 Inactive MMS Lease Blocks.........................................................................................M-13 

M-9 Vessel Lightering Area and Shipping Fairway to Port .................................................M-14 

M-10 Location of Platform Construction and Removal during 2000.....................................M-15 
xi 

LIST OF TABLES 

Table Page

4-1 Fields and Range Check Values........................................................................................ 4-5 

4-2 Surrogate Stack Parameters Used to Supplement GOADS Data ...................................... 4-7 

5-1 Emission Factors for Liquid-Fueled Units – Diesel where Max Rated Heat 

 Input > 100 MMBtu/hr...................................................................................................... 5-5 

5-2 Emission Factors for Liquid-Fueled Units – Diesel where Max Rated Heat 

 Input < 100 MMBtu/hr...................................................................................................... 5-6 

5-3 Emission Factors for Liquid-Fueled Units – Waste Oil where Max Rated Heat 

 Input > 100 MMBtu/hr...................................................................................................... 5-6 

5-4 Emission Factors for Liquid-Fueled Units – Waste Oil where Max Rated Heat 

 Input < 100 MMBtu/hr...................................................................................................... 5-7 

5-5 Emission Factors for Gas-Fueled Units – Natural Gas or Process Gas where 

 Max Rated Heat Input > 100 MMBtu/hr........................................................................... 5-7 

5-6 Emission Factors for Gas-Fueled Units – Natural Gas or Process where 

 Max Rated Heat Input < 100 MMBtu/hr........................................................................... 5-8 

5-7 Emission Factors for Gasoline Engines............................................................................. 5-9 

5-8 Emission Factors for Diesel Engines where Max HP < 600 ............................................. 5-9 

5-9 Emission Factors for Diesel Engines where Max HP > 600 ........................................... 5-10 

5-10 Emission Factors for Gasoline Fuel Use ......................................................................... 5-11 

5-11 Emission Factors for Diesel Fuel Use. ............................................................................ 5-12 

5-12 Emission Factors for Natural Gas Fuel Use .................................................................... 5-12 

5-13 Emission Factors for Flares............................................................................................. 5-14 

5-14 Emission Factors for Pilots.............................................................................................. 5-14 

5-15 THC Emission Factors for Oil and Gas Production Operations ..................................... 5-16 
xii 

LIST OF TABLES (CONTINUED) 

Table Page

5-16 Default Speciation Weight Fractions for Total Hydrocarbon (THC) Emissions by 

Steam Type...................................................................................................................... 5-16 

5-17 Surrogate Gas Analysis for GLYCalc Runs.................................................................... 5-18 

5-18 Daily Average Ambient Temperature, Taa ...................................................................... 5-19 

5-19 Tank Paint Solar Absorptance, a ..................................................................................... 5-19 

5-20 Emission Factors for Natural Gas Engines where Engine Stroke Cycle = 

 2-Cycle and Engine Burn Type = Lean........................................................................... 5-24 

5-21 Emission Factors for Natural Gas Engines where Engine Stroke Cycle = 

 4-Cycle and Engine Burn Type = Lean........................................................................... 5-24 

5-22 Emission Factors for Natural Gas Engines where Engine Stroke Cycle = 

 4-Cycle and Engine Burn Type = Rich ........................................................................... 5-25 

5-23 Emission Factors for Natural Gas Engines where Engine Burn Type = Clean............... 5-25 

5-24 Emission Factors for Natural Gas Turbines .................................................................... 5-26 

5-25 Default Sales Gas Composition....................................................................................... 5-28 

5-26 Daily Average Ambient Temperature, Taa ...................................................................... 5-31 

5-27 Tank Paint Solar Absorptance, a ..................................................................................... 5-31 

7-1 Diurnal Emission Percentages for Activity Groups ........................................................ 7-10 

7-2 SCCs of Interest for Platform Operations (Diurnal Patterns).......................................... 7-11 

8-1 Total Platform Emission Estimates for Criteria Pollutants ............................................. 8-12 

8-2 Total Non-Platform Emission Estimates for Criteria Pollutants ..................................... 8-13 

8-3 Total Platform and Non-Platform Emission Estimates for Criteria Pollutants ............... 8-14 
xiii 

LIST OF TABLES (CONTINUED) 

Table Page

8-4 Annual CO Emission Estimates for Platform Sources.................................................... 8-15 

8-5 Annual NOx Emission Estimates for Platform Sources .................................................. 8-15 

8-6 Annual PM10 Emission Estimates for Platform Sources ................................................. 8-15 

8-7 Annual PM2.5 Emission Estimates for Platform Sources ................................................ 8-16 

8-8 Annual SOx Emission Estimates for Platform Sources ................................................... 8-16 

8-9 Annual VOC Emission Estimates for Platform Sources................................................. 8-16 

8-10 Annual Emission Estimates for Amine Units.................................................................. 8-17 

8-11 Annual Emission Estimates for Boilers/Heaters/Burners ............................................... 8-17 

8-12 Annual Emission Estimates for Diesel Engines.............................................................. 8-17 

8-13 Annual Emission Estimates for Drilling Equipment....................................................... 8-17 

8-14 Annual Emission Estimates for Flares ............................................................................ 8-18 

8-15 Annual Emission Estimates for Natural Gas Engines ..................................................... 8-18 

8-16 Annual Emission Estimates for Natural Gas Turbines.................................................... 8-18 

8-17 Annual Emission Estimates for Vents............................................................................. 8-18 

8-18 Total Greenhouse Gas Emission Estimates for Platform Sources .................................. 8-19 

8-19 Total Greenhouse Gas Emission Estimates for Non-Platform Sources .......................... 8-19 

8-20 Comparison of OCS Platform Emission Estimates......................................................... 8-20 

8-21 Comparison of OCS Platform Fuel Combustion Emission Factors................................ 8-20 

8-22 Comparison of Non-Platform Emission Estimates ......................................................... 8-21 

8-23 Comparison of Commercial Marine Vessel Emission Estimates.................................... 8-21 
xiv 

LIST OF TABLES (CONTINUED) 

Table Page

1-1 Summary of Non-Platform Emission Estimates ...................................................................2 

A-1 Calculation of Hours Worked........................................................................................... A-5 

A-2 Activity Data and Emission Factors for Survey Vessels - 2D Seismic............................ A-5 

A-3 Emission Factors for Survey Vessels – 3D Seismic......................................................... A-6 

A-4 Summary of Total Emission Estimates for Survey Vessels ............................................. A-6 

B-1 Vessel Rig Activity ...........................................................................................................B-4 

B-2 Drill Ship Emission Factors ............................................................................................B-16

B-3 Jackup Rig Emission Factors ..........................................................................................B-17 

B-4 Semisubmersible Rig Emission Factors..........................................................................B-18 

B-5 Submersible Rig Emission Factors..................................................................................B-19 

B-6 Emission Estimates for Exploratory Drill Ship Operations ............................................B-19 

C-1 2000 Data on Support Vessels...........................................................................................C-5 

C-2 Determination of Load Factor for Supply Boats in the Gulf of Mexico ...........................C-5 

C-3 Activity Data and Emission Factors for Crew Boats ........................................................C-6 

C-4 Activity Data and Emission Factors for Supply Vessels...................................................C-6 

C-5 Activity Data and Emission Factors for Tugs with Diesel Engines ..................................C-7 

C-6 Activity Data and Emission Factors for Barges with Diesel Engines...............................C-7 

C-7 Summary of Emission Estimates for Support Vessels ......................................................C-8 

D-1 Single-Engine Helicopter Emission Factors..................................................................... D-4 

D-2 Twin-Engine Helicopter Emission Factors ...................................................................... D-5

D-3 Heavy Twin-Engine Helicopter Emission Factors........................................................... D-6 
xv 

LIST OF TABLES (CONTINUED) 

Table Page

D-4 Summary of Helicopter Activity and Emissions Data ..................................................... D-7 

E-1 Determination of Time to Lay One Foot of Pipe ..............................................................E-4 

E-2 Activity Data and Emission Factors for Pipelaying Vessels.............................................E-4 

E-3 Allocation of Pollutant by Segment Number ....................................................................E-5 

F-1 1000kW Generator ............................................................................................................F-5 

F-2 Four 7,500 hp Pumps.........................................................................................................F-6 

F-3 LOOP Vessel Activity Data ..............................................................................................F-6 

F-4 Summary of Vessel Activity ...........................................................................................F-15 

F-5 Emission Factors for Approaching Tankers....................................................................F-16 

F-6 Emission Factors for Idle Tankers...................................................................................F-16 

F-7 Emission Factors for Support Vessels.............................................................................F-17 

F-8 LOOP Emissions .............................................................................................................F-17 

G-1 Summary of Lightering Activity Data.............................................................................. G-5 

G-2 Location of Lightering Zones and Average Travel Distance ........................................... G-5 

G-3 Large Oil Vessel Emission Factors .................................................................................. G-6 

G-4 Escort Vessels (Traveling to Lightering Zone and Back to Port) Emission Factors........ G-6 

G-5 Escort Vessels (Idle) Emission Factors ............................................................................ G-7 

G-6 Emission Estimates for Lightering Operations ................................................................ G-7 

H-1 Reef Fishing Activity and Emissions Data....................................................................... H-4 

H-2 Shrimp Fishing Activity and Emissions Data .................................................................. H-5 

H-3 Reef Fishing Emission Factors......................................................................................... H-6 
xvi 

LIST OF TABLES (CONTINUED) 

Table Page

H-4 Shrimp Fishing Emission Factors..................................................................................... H-6 

H-5 Long Line Emission Factors............................................................................................. H-7 

H-6 Emission Estimates for Commercial Fishing Operations................................................. H-7 

I-1 Coast Guard Vessels...........................................................................................................I-6 

I-2 87-Foot Coast Guard Vessels.............................................................................................I-6

I-3 110-Foot Coast Guard Vessels...........................................................................................I-7 

I-4 175-Foot Coast Guard Vessels...........................................................................................I-7 

I-5 Emission Estimates for Coast Guard Vessels.....................................................................I-8 

I-6 Naval Vessel: MSO............................................................................................................I-8 

I-7 Naval Vessel: MCM...........................................................................................................I-9 

I-8 Naval Vessel: PHM ............................................................................................................I-9 

I-9 Naval Vessel: TAG ..........................................................................................................I-10 

I-10 Naval Vessel: TAGS(50)..................................................................................................I-10 

I-11 Naval Vessel: LSD ...........................................................................................................I-11 

I-12 Naval Vessel: TAGS(40)..................................................................................................I-11 

I-13 Naval Vessel: TAK(II) .....................................................................................................I-12 

I-14 Summary of Emission Estimates for Naval Diesel Vessels.............................................I-12 

I-15 Diesel Turbine Fuel Consumption ...................................................................................I-12 

I-16 Naval Steamship Fuel Consumption ................................................................................I-13 

I-17 Naval Diesel Turbine Emission Factor Conversions .......................................................I-13 

I-18 Steamship Emission Factors.............................................................................................I-13 
xvii 

LIST OF TABLES (CONTINUED) 

Table Page

I-19 Emission Estimates for Naval Turbine Engines...............................................................I-14 

I-20 Emission Estimates for Naval Steam Engines .................................................................I-14 

I-21 Total Emission Estimates from All Naval Vessels ..........................................................I-14 

I-22 Summary of Emission Estimates from All Military Vessels ...........................................I-15 

J-1 Emission Factors and Estimates for Marine Diesel Engines..............................................J-4 

J-2 Steamship Ton-Miles and Emission Estimates .................................................................J-4 

J-3 Summary of CMV Emission Estimates..............................................................................J-4 

L-1 Fuel Usage and Time Spent by Vessels in Support of Platform Construction and RemovalL-3 

L-2 Daily Fuel Consumption and Operating Hours by Vessel Type .......................................L-4 

L-3 Total Days for Construction or Removal of Platforms in the Year 2000..........................L-4 

L-4 Estimate of Total Operating Hours by Vessel Type for Platform Construction and 

Removal.............................................................................................................................L-5 

L-5 Weighted Operating Loads for Each Vessel Type ............................................................L-5 

L-6 Barge Emission Factors.....................................................................................................L-7 

L-7 Crew Boat Emission Factors .............................................................................................L-7 

L-8 Supply Boat Emission Factors ..........................................................................................L-7 

L-9 Tug Boat Emission Factors ...............................................................................................L-8

L-10 Emission Summary by Vessel Type..................................................................................L-8 
1-1

1. EXECUTIVE SUMMARY

The Minerals Management Service (MMS) is responsible for assessing the potential 

impacts of air pollutant emissions from offshore oil and gas exploration, development, and 

production sources in the Outer Continental Shelf (OCS). This responsibility is driven by the 

OCS Lands Act, which directs the MMS to regulate OCS emission sources to assure that they do 

not significantly affect onshore air quality. The MMS air quality regulations are contained in 30 

CFR 250.302 through 304. In particular, MMS is responsible for determining if platform and 

other emissions from the Gulf of Mexico OCS influence the ozone attainment (or nonattainment) 

status of onshore areas in Louisiana and Texas. This responsibility was mandated by the 1990 

Clean Air Act Amendments (CAAA). In addition, the 1990 CAAA requires MMS to coordinate 

air pollution control activities with the State regulatory agencies. Thus there will be a continuing 

need for emission inventories and modeling in the future, especially with the implementation of 

the 8-hour ozone standard. The future area of interest is not just Louisiana and Texas, but also 

includes Mississippi, Alabama, and Florida. To assess the emissions of offshore oil and gas 

platforms and their associated emissions, the MMS conducted some limited emission inventories 

in the Gulf of Mexico in the 1980s. In 1991 the MMS sponsored a regional ozone modeling 

effort conducted by the U.S. Environmental Protection Agency (EPA) using the Regional 

Oxidant Model (ROM). The Gulf of Mexico Air Quality Study was initiated that same year, and 

activity data for a Gulfwide emissions inventory were collected for a one-year period in 1991-92. 

The MMS’ Gulf of Mexico Outer Continental Shelf Regional office sponsored this 

project, the Gulfwide Emission Inventory Study (MMS Contract No. 00-01-CT-31021), which 

builds upon these studies with the goal of developing a base year 2000 air pollution emissions 

inventory for all OCS oil and gas production-related sources in the Gulf of Mexico, including 

non-platform sources. Pollutants covered in this inventory are the criteria pollutants—carbon 

monoxide (CO), nitrogen oxides (NOx), sulfur dioxide (SO2), particulate matter-10 (PM10), 

PM2.5, and volatile organic compounds (VOC); as well as greenhouse gases—carbon dioxide 

(CO2), methane (CH4), and nitrous oxide (N2O). 

To develop the inventory, the Gulfwide Offshore Activities Data System (GOADS) was 

created, which was used to collect monthly activity data from platform sources. The activity 

data were combined with the most recent emission factors published by the EPA, and Emission 

Inventory Improvement Program (EIIP) emission estimation methods to develop a 

comprehensive criteria pollutant and greenhouse gas emissions inventory. Non-platform 

emission estimates were developed for sources such as the Louisiana Offshore Oil Platform 

(LOOP), commercial marine vessels, and helicopters. Diurnal emission profiles were also 

developed for the major categories of sources inventoried. The profiles will allow inventory 

emission estimates for a given category to be temporally allocated, across a 24-hour time period, 

on a 1-hour basis. Ultimately, State agencies will use this information to perform modeling for 

ozone and regional haze for use in their State Implementation Plans (SIPs). 
2-1

2. INTRODUCTION 

Measurements of ozone concentrations in onshore areas of Texas and Louisiana 

periodically exceed the national standard for one-hour ozone in nonattainment areas, with some 

observations nearly three times the national standard. Shoreline and inland locations in Texas 

and Louisiana could potentially be influenced by emission sources in the Gulf of Mexico. The 

Minerals Management Service (MMS) is responsible for determining if air pollutant emissions 

from Outer Continental Shelf (OCS) oil and natural gas platforms and other sources in the Gulf 

of Mexico influence the ozone attainment and nonattainment status of onshore areas. Ozone 

forms in the presence of sunlight from the reaction of volatile organic compounds (VOC) and 

oxides of nitrogen (NOx). 

The Clean Air Act Amendments of 1990 (CAAA Title VIII, Sec 801(b)) specifically 

mandate that MMS conduct a research study to assess the potential for onshore impacts of 

certain types of air pollutant emissions from offshore oil and gas exploration, development, and 

production in regions of the Gulf of Mexico. This mandate grew out of concerns regarding the 

cumulative onshore impacts of air pollutant emissions from more than 3,000 offshore facilities in 

the central and western Gulf of Mexico. MMS launched a series of studies, beginning in the 

1980s, to assess the emissions of offshore oil and gas platforms and their associated emissions. 

MMS undertook the Gulf of Mexico Air Quality Study (GMAQS) to assess the potential 

impacts of emissions from oil and gas exploration, development, and production in the OCS 

region of the Gulf of Mexico. The overall goal of the study was to assess, through computer 

simulation modeling, the effects that OCS development has on ozone concentrations in the 

onshore areas of Texas and Louisiana that are designated by the U.S. Environmental Protection 

Agency (EPA) as nonattainment for one-hour average ozone. The study covered many types of 

offshore emission sources, focusing on oil and gas production platform emissions. Results are 

summarized in the 1995 report, Gulf of Mexico Air Quality Study (U.S. DOI, MMS 1995). 

MMS is currently sponsoring several additional atmospheric sciences studies, including 

two air quality emission inventory projects that affect only platforms within 100 kilometers (km) 

of the Breton National Wilderness Area in the Gulf of Mexico. Through an Office of 

Management and Budget-approved Information Collection Request, MMS required affected 

platform operators to collect activity data used in both studies. As part of its program to collect 

activity data, a Visual Basic program was developed, known as the Breton Offshore Activities 

Data System (BOADS), for platform operators to submit activity data on a monthly basis. 

Activity data were collected for a number of production platform emission sources and used to 

estimate air pollutant emissions on a monthly basis (Coe et al. 2003). 
3-1

3. DATA COLLECTION 

3.1 INTRODUCTION 

To develop a base year 2000 inventory of criteria pollutant and greenhouse gas emissions 

for all OCS oil and gas production-related sources in the Gulf of Mexico, MMS collected activity 

data from platform operators during the year 2000. On June 30, 1999, MMS published Notice to 

Lessees and Operators (NTL) 99-G15 to inform operators about the mandatory data collection 

and a meeting to learn more about the data request. Affected operators are lessees and operators 

of federal oil, gas, and sulfur leases in the Gulf of Mexico OCS region. 

This section of the report outlines the steps that MMS and ERG, Inc. took to collect the 

data, including modifying and testing the data collection software, meeting with and training 

platform operators, and answering questions about data collection. Activity data were collected 

over one calendar year (year 2000) and were used to calculate and archive emissions data using 

the most current emission factors and calculation methods. 

3.2 EXPANSION AND TESTING OF THE BOADS DATA COLLECTION 

SOFTWARE 

ERG expanded the BOADS data collection software to add several emission sources: 

mud degassing, pneumatic pumps, and pressure/level controllers. Two emission sources—losses 

from flashing and fugitives—already existed in BOADS, but were modified for the Gulfwide 

Offshore Activities Data System (GOADS). These modifications were made to improve the 

reporting of flashing occurences, and to simplify the reporting associated with fugitives (only 

annual reporting is needed, not monthly). Another parameter, sales gas composition, was added 

to the Structure Screen for operators to report composition of gas processed and transferred off 

the structure. 

The GOADS data collection software was designed to mimic the BOADS interface, thus 

reducing operator retraining. ERG expanded the BOADS data collection software, written in 

Visual Basic, to collect additional activity data that would be necessary to calculate the 

additional pollutants. To reduce duplication, ERG designed GOADS to import BOADS data. 

The objective was to collect, perform quality control, and archive activity data from platform 

sources that emit carbon monoxide (CO), sulfur dioxide (SO2), NOx, particulate matter-10 

(PM10), PM2.5, VOC, carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O). Ammonia 

emissions are not included because there were no selective catalytic reduction (SCR) or selective 

noncatalytic reduction (SNCR) air pollution controls reported. SCR and SNCR are NOx

emission controls for combustion sources and may be sources of ammonia emissions, because 

ammonia, or an ammonia derivative such as urea, is used as the reducing gas to react with NOx

to form molecular nitrogen and water. SNCR differs from SCR in that no catalyst (a base metal 

or zeolite) is used. 

To add an emission source, ERG merely added it to the already existing drop-down 

menu. For each new emission source, an equipment screen was created that contained fields for 

the parameters to be recorded. As an example, the pneumatic pumps and pressure/level 
3-2

controllers equipment screens require operators to enter parameters such as the manufacturer, 

model, hours operated, and equipment elevation. For details on equipment parameters, see 

section 2.2 of the User’s Guide for the Gulfwide Offshore Activities Data System for Air Quality 

(http://www.gomr.mms.gov/homepg/regulate/environ/airquality/goad.html). 

3.3 WORKING WITH USERS 

A workshop was held in New Orleans on November 15, 1999 to discuss and explain the 

Gulfwide study information collection and reporting procedures, the pollutants to be covered, 

and the reasons the Gulfwide study was undertaken. To assist users in submitting data, ERG and 

COMM Engineering staff provided GOADS Inventory Data Sheets that identified the type of 

data to be entered into the GOADS software. The sheets included company/facility data, 

parameters for emission sources, and a summary of equipment parameters to be recorded to 

calculate annual fugitive emissions for the facility. COMM Engineering staff also distributed a 

handout to participants that contained standard units of measure, calculation of exit velocity, 

methods to determine fuel usage, stack temperature ranges, and frequently asked questions. 

The “User’s Guide for the Gulfwide Offshore Activities Data System (GOADS) for Air 

Quality” (Wilson et al. 2001) was the primary source of information for operators. The guide 

was made available to all users via the MMS web site, where it could be downloaded and 

printed. The guide contains instructions on installation, starting and exiting GOADS, creating 

and editing data, quality control, and saving and backing up files. 

A second workshop was held in New Orleans on March 15, 2001. ERG staff walked 

operators through installing the software, entering data, and reporting data. The purpose of this 

workshop was to allow users to install and use the software firsthand, and ask questions. ERG 

also directed operators to other sources of information for future questions. 

3.4 OPERATOR USE OF GOADS SOFTWARE TO COLLECT DATA 

Once operators obtained the software and attended the training workshops, they were 

ready to begin entering data. MMS communicated with operators through the MMS web site 

using Frequently Asked Questions (FAQs) and electronic mail (e-mail). ERG drafted FAQs that 

were distributed at the second workshop, posted on the Web site, and periodically updated. The 

designated MMS support staff were Dr. Chester Huang, Mr. Joe Perryman, and Mr. YP Desai. 

3.5 QUALITY ASSURANCE/QUALITY CONTROL 

ERG programmed automatic quality assurance (QA) procedures into the software in an 

effort to minimize the submittal of incomplete and erroneous activity data by the platform 

operators. ERG requested that operators submit a printout of their Quality Assurance Summary 

Form along with their monthly activity files. The QA Summary focuses on identification of 

critical data that the operators need to complete prior to submitting their data to MMS. 
3-3

The software also automatically runs a series of quality control (QC) checks on the data 

when the operator saves it. If the operator leaves a field blank, provides data that are out of 

range, or enters a value that is not consistent on a month-to-month basis, an error message will 

appear. The operator can either correct the problem, override the QC check (and provide a 

comment), or ignore the message and save the changes. When operators entered data that 

appeared in the QC results or on the QA Summary Form, ERG attempted to reconcile the 

missing, atypical, or suspect data by reviewing the comments, contacting the operators, or 

developing surrogate data as described in Section 4 of this report. Surrogate data were 

developed primarily for the stack parameters requested for the emission release point for each 

piece of equipment. These parameters are needed for air quality modeling efforts. The 

surrogates were developed based on industry averages, and through discussions with MMS. 
4-1

4. QUALITY ASSURANCE/QUALITY CONTROL 

4.1 INTRODUCTION 

Platform operators submitted data files and QA Summary Forms generated by the 

GOADS software. Ninety-three companies submitted data for 3,154 active or inactive platforms 

(combination of complex ID and structure ID). Included in the submittal were 1,150 survey 

records and 35,198 structure records. A unique survey record is a combination of user ID and 

month. A unique structure record is a combination of complex ID, structure ID, and month. A 

total of 239 unique monthly and annual files were provided by 93 companies. 

This section summarizes the data received, the steps ERG took to review the monthly 

GOADS data for completeness and accuracy, the types of errors encountered. Also discussed in 

this section are the procedures used to correct and gap-fill missing data, including stack 

parameter data provided by the operators. When operators failed to enter data or entered data that 

were atypical or suspect, ERG attempted to reconcile the data by reviewing the comments, 

contacting the operators, or developing surrogate data. 

4.2 CHECKING FILE INTEGRITY AND MATCHING QA SUMMARY 

MMS sent 239 unique data files to ERG primarily on two compact disks (CDs) and all 

files were logged onto a tracking sheet. The first CD (CD-1) contained 81 files and the second 

(CD-2) contained 237 files (including 80 duplicate/replacement files for files on CD-1). An 

additional CD was sent containing a replacement GOADS submittal with 12 files, and a new 

submittal (1 file) was provided via file transfer protocol (FTP). All electronic data were in the 

prescribed Microsoft Access 2000 database that was created by the GOADS software. 

ERG checked file integrity to verify that the file submitted could be opened, and that it 

matched its QA Summary Form (same user, structure, and complex IDs). ERG was able to open 

and review all of the files provided. Companies were also required to submit a hardcopy of their 

QA Summary Form. Of the 239 files submitted, 222 were accompanied by a hardcopy of their 

QA summary results (93%). For the submittals missing hard-copy QA Summary Forms, ERG 

was able to print the form for review. 

4.3 EQUIPMENT SUMMARY CHECKS 

Each GOADS submittal contained templates for up to 23 tables. The majority of these 

tables covered specific equipment types (amine units, boilers, etc.). However, additional user-, 

structure-, and survey-level tables, as well as quality assurance tables, were also appended into 

one composite database. Primary keys (user ID, month, year, complex ID, structure ID, and 

equipment ID) were retained in all tables to ensure that no duplicate data were added. 
4-2

4.3.1 User-Level Summary 

The first data entry page in GOADS is for user information. The user ID should be the 

MMS company number assigned by MMS; however, at least 10% of the user IDs submitted were 

incorrect when checked against the MMS master lease and company lists. ERG prepared a 

matrix of submitted vs. “correct” user IDs, and identified IDs that are incorrect. The official 

MMS list of companies, leases, and platforms was retrieved from the MMS Web site: 

http://www.gomr.mms.gov/homepg/pubinfo/freeasci/platform/freeplat.html.

ERG used these master lists to check and correct the lease, company, and platform IDs. 

Additionally, ERG checked and corrected the locational data (latitude/longitude pairs) for each 

platform. 

4.3.2 Survey-Level Summary 

After entering the user ID, the next data entry page in GOADS is for a new survey. 

There are two types of surveys that can be submitted: 1) the monthly equipment data set, and 2) 

annual submittals for fugitive information. A survey contains the activity parameters by 

equipment type (including fugitives), user information, and structure-level information. Ideally, 

13 submittals are to be completed for each platform. 

All 93 companies submitted survey-level data. Nearly 85% of the submittals completed 

all 13 surveys. The remaining 14 companies submitted between 3 and 12 surveys, which may 

indicate changes in ownership during the inventory year. 

4.3.3 Structure-Level Summary 

For each survey, the user was required to enter platform-level data that includes location 

coordinates, fuel usage, and status (active or inactive for that month). A total of 35,198 records 

were submitted. Of this total, 31,473 records were labeled as “active” (89%). 

All 93 companies submitted structure-level data, and the number of unique surveys was 

the same as in the survey table (85% completed all 13 surveys). Files for 3,154 unique active or 

inactive platforms (combination of complex ID and structure ID) were submitted. Forty-three 

(43) platforms submitted survey information for more than one user ID. Possible explanations 

may be use of incorrect IDs, or a change in ownership. After numerous QA/QC checks to 

remove incorrect or duplicate structure-level records, a total of 3,096 unique active or inactive 

platforms remained. 

4.3.4 Equipment-Level Summary 

Equipment information and activity-level data for 15 different types of equipment can be 

populated for each platform-survey combination. A list of all the platform equipment submitted 

per equipment type was compiled. This composite list includes 2,873 unique, active, platforms, 

indicating that 223 platforms were inactive, or were “satellite” platforms with no emission 

sources (operators were asked to include records for these platforms regardless). 
4-3

4.4 QA/QC CHECKS 

Part of the QA task for the GOADS submittals was to identify incorrect and missing data, 

and to correct and populate the missing information with surrogates. Early into the QA analysis, 

all of the equipment survey data were appended into single database; a number of QA steps to 

identify the missing data were then performed on all the data to boost efficiency. Once the 

missing data were identified, MMS-approved surrogate values and approaches were used to 

provide as complete an inventory as possible. 

Six types of data analyses were performed: 1) pre-processing of the data; 2) equipment 

survey consistency; 3) data range checks; 4) stream analysis between certain equipment; 5) 

applying surrogate values; and 6) post-processing of surrogates. 

4.4.1 Pre-Processing 

Three pre-processing steps occurred before the rigorous data analysis could begin. First, 

the activity status of each survey was confirmed. Second, the reported number of operating 

hours for each piece of equipment was checked to make sure it did not exceed the maximum 

number of hours in the month. Third, the reported fuel usage at the equipment level was 

compared to the maximum capacity of the equipment and the reported fuel usage for the entire 

platform. 

Operators had the opportunity to identify a platform as being either active or inactive for 

each of the monthly surveys. Inactive data are not considered for emissions calculations, so this 

step is extremely important. For equipment surveys that request hours of operation, platform 

surveys were labeled as active if any of the equipment the operating hours were greater than 

zero. Conversely, a platform survey was labeled as inactive if all of the equipment operating 

hours were zero. 

The Flare and Vent Occurrence tables were reviewed to help verify the activity status of 

each survey, although hours of operation are requested in the Flare and Vent equipment tables. 

A platform survey was considered active and emissions were calculated if the flare and vent 

hours of operation are zero, but there was an upset record in the Flare or Vent Occurrence tables. 

This scenario is possible because the operators were asked to report operating hours, excluding 

process upsets, and also number of upsets that occurred for each survey month. 

Platform surveys were also considered active based on a review of the following 

equipment data if: 1) in the Fugitive equipment table, the component count provided was greater 

than zero; 2) in the Loading and Losses from Flashing equipment tables the throughputs were 

greater than zero; or 3) in the Mud Degassing equipment table, the drilling days per month were 

greater than zero. 

For the equipment surveys, over 86% of the equipment-level records were identified as 

being entered with the correct status. Less than 3% of the equipment records were changed from 

inactive to active. The Fugitive table required the most of these changes, with nearly 67% of the 

records requiring a status change. All of the other equipment tables only had less than 1% of the 

records requiring this status change. The remaining 11% of the equipment records were changed 
4-4

from active to inactive. In the Vent table, over 56% of the records required a status change, 

while the other equipment tables had up to 30% of the records requiring this status change. 

For each month, operating hours were to be provided for most types of equipment. A 

typical error would be to exceed the maximum hours possible for each month. Similarly, hours 

of operation may not have been populated. For both of these errors, data were corrected in the 

same manner by populating with the maximum number of hours possible. The maximum 

number of hours for months with 31 days (January, March, May, July, August, October, and 

December) is 744; for months with 30 days (April, June, September, and November), the 

maximum number of hours is 720. In year 2000, the maximum amount of hours for February 

(29 days) is 696. Overall, 4% of the Hours of Operation data submittals needed to be corrected. 

The last pre-processing step focused on the reported fuel usage. Platform operators 

provided estimates of total fuel used for each month for the entire platform, and for each 

boiler/heater/burner, diesel engine, natural gas engine, natural gas turbines, and drilling 

operation. Additionally, operators were asked to provide fuel equipment parameters such as 

hours operated, fuel usage rate (average and maximum), operating horsepower (average and 

maximum), and heat input rate. 

The average and theoretical maximum fuel usage for each reported boiler/heater/burner, 

diesel engine, natural gas engine, and natural gas turbine was calculated by multiplying the hours 

operated by the average or maximum heat input or fuel usage rate and operating horsepower, and 

dividing by the fuel heating value. These values were compared to the total fuel used value 

submitted for each month. When the reported fuel usage exceeded the theoretical maximum fuel 

usage, the submitted values were replaced with the calculated theoretical maximum fuel usage 

values. When the reported fuel usage fell below calculated average fuel usage value by more 

than 15%, the submitted values were replaced with the calculated average fuel usage values. 

After correcting the individual equipment fuel usage values, the reported monthly total 

fuel used for the platform was compared to the sum of the individual pieces of equipment by fuel 

type. For the most part, the goal of this comparison was to make the two reported totals 

somewhat consistent. If the sum of reported (or corrected) fuel usage in the equipment tables 

was greater than the reported platform total, the platform total was revised to equal the 

equipment sum. If the reported platform total was not populated, it was populated with the 

equipment sum. 

4.4.2 Equipment Survey Consistency 

A platform may contain several pieces of equipment that operate year-round, but data 

parameters may not have been populated for every month. In this situation, the entire platform 

equipment dataset was examined. For example, 11 of the 12 monthly surveys may be populated 

for a boiler with the same fuel heating value, while one month, although marked active, may be 

null or provide a different fuel heating value. The missing or different value was populated to 

match the other platform equipment surveys if ERG believed a data entry error occurred. 

Certain parameters will not vary on a monthly basis, such as stack outlet inner diameter 

and equipment elevation, while other parameters can vary monthly, such as fuel usage rate and 
4-5

hours of operation. For each of the non-varying parameters, the data were grouped at the 

platform-equipment level to determine where inconsistent data may have been entered; data 

entry errors were then corrected. 

4.4.3 Data Range Checks 

After the equipment surveys were checked for survey consistency, the parameters were 

checked to ensure that they were within an acceptable data range. For example, some operators 

mistakenly entered incorrect fuel heating values. Natural gas has a fuel heating value on average 

of 1,050 Btu/scf. However, some equipment surveys had entered 105 Btu/scf as their fuel 

heating value, or even 19,300, which is the average fuel heating value of diesel fuel (in units of 

Btu/lb, however). 

This type of error would not be detected through the equipment survey consistency step if 

all the incorrect data were entered the same for each survey. It is believed that some operators 

did not run the QC check correctly or at all within the GOADS program; this would explain why 

these incorrect data were not flagged initially. 

The ranges were checked for the fields listed in Table 4-1. These ranges are based on the 

relationship between the parameters noted in Table 4-1 (e.g., actual fuel usage rate cannot exceed 

the reported maximum fuel usage rate), and typical fuel and control device efficiency values. 

The exhaust outlet inner diameter and number of flare and vent occurrences data fields required 

the most corrections (21.4%, 18.3%, and 18%, respectively), while the operating horsepower 

needed the fewest corrections (<0.10%).

Table 4-1. Fields and Range Check Values. 

Field Range Check 

API Specific Gravity Minimum value: 9 degrees API 

Average Liquid Height Not to exceed outlet height 

Flare Efficiency 90 and 99% 

Fuel Heating Value 

Natural gas: 500 to 1500 Btu/scf 

Diesel: 18,000 to 22,000 Btu/lb 

Fuel Usage Rate 

Not to exceed maximum fuel 

usage rate 

Fuel H2S Content 0 to 5 ppmv 

Fuel Sulfur Content 0 to 5 percent 

Heat Input Rate 

Not to exceed maximum heat 

input rate 

Inner Diameter Greater than 5 inches 

Number of Occurrences 

Must match upsets in Flare or 

Vent tables 

Operating Horsepower 

Not to exceed maximum rated 

horsepower 

Stack Angle Between 0 and 360 
4-6

4.4.4 Stream Analysis Between Certain Equipment 

Certain pieces of equipment may not be vented locally, but rather piped downstream to a 

vent or flare. It is important for the downstream exhaust vents to be correctly identified; 

otherwise the calculations may overestimate emissions. Additionally, the low-pressure vent/flare 

ID field must include the necessary prefix characters of “VEN” if directed to a vent or “FLA” if 

directed to a flare. 

The Amine Unit, Glycol Dehydrator, Loading, Losses from Flashing, Pneumatic Pumps, 

and Storage Tanks equipment may exhaust gases locally or downstream. If the Vent or Flare ID 

is populated in these tables, then a downstream analysis was performed on the Vent or Flare 

equipment tables to verify their existence. For Vent or Flare ID’s that could not be traced to an 

existing active vent or flare, the survey was updated as to being vented/flared locally. 

Over 75% of the data records were labeled incorrectly for the applicable tables. The 

Losses from Flashing equipment table required the highest number of data corrections (33%). 

4.4.5 Applying Surrogate Values 

Surrogate values were used to populate missing stack parameters that are needed for air 

quality modeling. These parameters are listed in Table 4-2 by equipment type. As shown in 

Table 4-2, surrogate values could be calculated for exit velocity and exhaust volume flow rate 

from the submitted data. Other surrogate data were developed from industry averages, and 

through discussions with MMS. 

4.4.6 Post-Processing of Surrogates 

After all the missing data have been populated through quality assurance checks and 

surrogates, two calculations were performed to check the overall quality of the data. The first 

calculation was for exit velocity; the second was for total fuel usage. Both of these 

recalculations were checked against the submitted data. 
4-7

Table 4-2. Surrogate Stack Parameters Used to Supplement GOADS Data. 

Unit Field Default Value 

Amine Unit Elevation (above sea 

level) 

50 ft 

Amine Unit– ventilation system 

for acid gas from reboiler 

Exit velocity (ft/sec) Calculated with AMINECalca

Amine Unit– ventilation system 

for acid gas from reboiler 

Exit temperature 110 oF 

Amine Unit–ventilation system for 

acid gas from reboiler 

Combustion 

temperature 

1832 oF 

Boiler/heater/burner Elevation (above sea 

level) 

50 ft 

Boiler/heater/burner – exhaust 

System 

Exit temperature 400 oF 

Boiler/heater/burner – exhaust 

system 

Outlet orientation 0 degrees 

Boiler/heater/burner – exhaust 

system 

Outlet diameter 12 inches 

Boiler/heater/burner – exhaust 

system 

Exit velocity Calculated 

Diesel Engine Elevation (above sea 

level) 

50 ft 

Diesel Engine Max rated fuel use 7000 Btu/hp-hr 

Diesel Engine Avg fuel use 7000 Btu/hp-hr 

Diesel Engine– exhaust system Outlet height 7 ft above engine 

Diesel Engine– exhaust system Exit velocity Calculated 

Diesel Engine– exhaust system Exit temperature 900 oF 

Diesel Engine– exhaust system Outlet orientation 0 degrees 

Diesel Engine– exhaust system Outlet diameter 12 inches 

Flare Combustion 

temperature (excluding 

upsets) 

1832 oF 

Flare Stack orientation 0 degrees 

Flare Outlet diameter 12 inches 

Glycol Dehydrator Elevation (above sea 

level) 

50 ft 

Glycol Dehydrator– flash tank Temperature 120 oF 

Glycol Dehydrator– flash tank Pressure 60 psig

Glycol Dehydrator– ventilation 

system 

Exit temperature GLYCalc default (usually 

212 o

F)b
4-8

Table 4-2. Surrogate Stack Parameters Used to Supplement GOADS Data (Continued). 

Unit Field Default Value 

Glycol Dehydrator– ventilation 

system 

Outlet orientation 0 degrees 

Glycol Dehydrator– ventilation 

system 

Flare feed rate (scf/hr) Calculated with GLYCalcb

Glycol Dehydrator– ventilation 

system 

Combustion 

temperature 

1832 oF 

Glycol Dehydrator– ventilation 

system 

Condenser temperature 110 oF (or calculated with 

GLYCalc)b

Glycol Dehydrator– ventilation 

system 

Condenser pressure 14.8 psia 

Loading – barge Elevation (above see 

level) 

0 

Loading – ventilation system Exit temperature 70 oF 

Loading– ventilation system Outlet orientation 0 degrees 

Loading– ventilation system Outlet diameter 3 in. 

Loading– ventilation system Exit velocity Calculated 

Loading– ventilation system Flare feed rate Calculated (use loading exhaust 

vol. flow rate if controlled by 

flare) 

Loading– ventilation system Combustion 

temperature 

1832 oF 

Losses from Flashing– ventilation 

system 

Exhaust volume flow 

rate 

Calculated 

Losses from Flashing– ventilation 

system 

Exit velocity Calculated 

Losses from Flashing– ventilation 

system 

Exit temperature 70 oF 

Losses from Flashing– ventilation 

system 

Outlet diameter Use Tank Vent Outlet Diameter 

Natural Gas Engine Max rated fuel usage 7000 Btu/hp-hr 

Natural Gas Engine Avg fuel usage 7000 Btu/hp-hr 

Natural Gas Engine– exhaust 

system 

Exit velocity Calculated 

Natural Gas Engine– exhaust 

system 

Exit temperature 4-cycle rich burn: 1100 oF 

Natural Gas Engine– exhaust 

system 

Exit temperature 2-cycle lean burn: 700 oF 

Natural Gas Engine– exhaust 

system 

Outlet diameter 12 inches 

Natural Gas Turbine Max rated fuel use 10,000 Btu/hp-hr 

Natural Gas Turbine Avg fuel use 10,000 Btu/hp-hr 
4-9

Table 4-2. Surrogate Stack Parameters Used to Supplement GOADS Data (Continued). 

Unit Field Default Value 

Natural Gas Turbine– exhaust 

system 

Exit velocity Calculated 

Natural Gas Turbine– exhaust 

system 

Outlet diameter 12 inches 

Natural Gas Turbine– exhaust 

system 

Exit temperature 1000 oF 

Pneumatic Pumps Elevation (above sea 

level) 

50 ft 

Pneumatic Pumps– ventilation 

system 

Exit velocity Calculated 

Pneumatic Pumps– ventilation 

system 

Exit temperature 70 oF 

Pressure/level Controllers Elevation (above sea 

level) 

50 ft 

Storage tank – General 

Information 

Roof Height above 

Shell (ft) 

0.0625*(Tank Diameter, ft / 2) 

Storage tank– ventilation system Exit velocity Calculated 

Storage tank– ventilation system Exit temperature 70 oF 

Storage tank– ventilation system Outlet orientation 0 degrees 

Storage tank– ventilation system Flare feed rate Calculated (or use the 

calculated storage tank exhaust 

vol. flow rate) 

Vent Outlet elevation (above 

sea level) 

50 ft 

Vent Outlet diameter Calculated (average of 

submitted data) 

Vent Exit temperature 70 oF 

Vent Outlet orientation 0 degrees 

Vent– upsets Exit temperature 70 oF a

 AMINECalc is released by the Gas Technology Institute as part of the AIRCalc Air Emissions 

Inventory Report Management Software Program (GTI 2001) 

b

 GLYCalc is released by the Gas Technology Institute, formerly the Gas Research Institute 

(GRI) (GTI 2000) 
5-1

5. DEVELOPMENT OF THE EMISSION INVENTORY 

5.1 INTRODUCTION 

The goal of the current study is to develop criteria pollutant and greenhouse gas emission 

inventories for all oil and gas production-related sources in the Gulf of Mexico. To achieve this 

goal, ERG revised the draft the Breton study Oracle database management program (DBMS) to 

create the Gulfwide Oracle DBMS. The Gulfwide DBMS imports the activity data described in 

Section 3 of this report, then applies emission factors to calculate emissions from platform 

sources in the Gulf of Mexico. This section of the report concentrates on efforts to revise the 

Breton study DBMS to create the Gulfwide study DBMS. 

Using the Breton study DBMS as the starting point for calculating the Gulfwide 

emissions for the year 2000, ERG added calculation routines for several equipment types, added 

greenhouse gas emission factors to correspond to the available activity data, updated emission 

factors, and corrected errors. 

The expanded database calculates emissions of CO, SO2, NOx, PM10, PM2.5, VOC, CO2, 

CH4, and N2O, which contribute to regional haze, ozone, or greenhouse gas effects. Ammonia 

emissions were investigated, but are not expected from these emission sources. 

The final Gulfwide study Oracle DBMS contains platform activity data and other data 

needed to calculate Gulfwide emissions, as well as non-platform emission estimates. Nonplatform activity data and calculation methods are discussed in Section 6 and the appendices of 

this report. Figure 5-1 illustrates the flow of information into and out of the Oracle database. 

5.2 EXPANSION OF THE DRAFT BRETON STUDY ORACLE DBMS 

ERG refined and expanded the existing procedures in the draft Breton DBMS and 

created the GOADS DBMS. Specifically, ERG completed the following steps to 

improve and expand the Breton DBMS: 

• Examined each calculation and corrected mathematical and typographical errors; 

• Added emission factors and calculation routines for new equipment types; 

• Added calculations to estimate additional pollutants for all equipment types; 

• Updated emission factors with the latest information in AP-42 (EPA 2002); 

• Standardized the calculations to be consistent with the units of measure in AP-42 (EPA 

2002) ; and 

• Compared calculation methods to current Emission Inventory Improvement Program 

(EIIP) methods and updated where calculations did not agree with current methods (EIIP 

1999).

5-3

In addition, MMS provided surrogates for values such as fuel sulfur content, fuel heating 

value, fuel density, and control efficiency. These surrogate values are based on industry 

averages and/or MMS recommended values. For example, the diesel fuel sulfur content is 

consistent with MMS' “Spreadsheet for Exploration Plans” 

(http://www.gomr.mms.gov/homepg/regulate/environ/requirement/html). 

Natural gas hydrogen sulfide (H2S) content = 3.38 ppmv 

Diesel fuel sulfur content = 0.4 wt%

Natural gas heating value = 1050 Btu/scf 

Diesel fuel heating value = 19,300 Btu/lb 

Diesel fuel density = 7.1 lb/gal 

Gasoline density = 6.17 lb/gal 

Flare efficiency for VOCs = 98% 

Flare efficiency for H2S = 95% 

Vapor recovery/condensor (VR/C) efficiency 

for total hydrocarbons (THC) and VOCs = 80% 

Sulfur recovery (SR) + VR/C efficiency for THC 

and VOCs = 80% 

SR efficiency for THC and VOCs = 0% 

5.3 EMISSION ESTIMATION PROCEDURES 

For the most part, the emission estimation procedures presented in this section are 

unchanged from those in the draft Breton DBMS (Coe et al. 2003). The major revisions 

reflected here are the addition of new equipment types (mud degassing, pneumatic pumps, and 

pressure/level controllers) as emission sources, the addition of greenhouse gas emission factors 

to correspond to the available activity data, updating emission factors with final AP-42

information, and correcting errors in the draft Breton DBMS. 

The following sections present the methods used to calculate criteria pollutant and 

greenhouse gas emissions from platform sources in the study. 

5.3.1 Amine Units 

Some platforms produce natural gas containing unacceptable amounts of hydrogen 

sulfide. While most platform operators pipe the sour gas onshore for sulfur removal, a few 

remove the sulfur on the platform using the amine process. Various amine solutions are used to 

absorb H2S. After the H2S has been separated out, it is vented, flared, incinerated, or used for 

feedstock in elemental sulfur production (U.S. DOI, MMS 1995). 

Operators were given the option of using the “Model Inputs” tab if requested data were 

not readily available. CH4 and VOC emissions are estimated externally using AMINECalc (GTI 

2001), and loaded directly into the DBMS. Emissions are adjusted for any control devices that 

were reported, such as a flare, a vapor recovery system/condenser, or a sulfur recovery unit, and 

other user-specified control devices. Controlled emissions of VOC are calculated as follows: 
5-4

%100

 Eff100 EE dc,

controlc, uncc,

− ×= ∑

where: 

Ec,control = Controlled VOC emissions (pounds per month) 

Ec,unc = Uncontrolled VOC emissions (pounds per month) 

Effc,d = Control efficiency of control device d for VOCs (percent) 

Devices that are intended to control H2S emissions, such as sulfur recovery units or 

flares, will produce emissions of SOx as a by-product. Thus, if a flare is present, SOx emissions 

are calculated as follows (EIIP 1999, Coe et al. 2003): 

















×















⋅ ×













 ⋅ = 100

Eff

 mollb

lb 64

 lb 34

 mollb

E E x

x

x

2

2

SOx

SO

SO

SO

SH

SH

control, H2S

where: 

ESOx, control = Resulting SOx emissions (pounds per month) 

EH2S = Uncontrolled emissions of H2S (pounds per month) 

EffSOx = Flare efficiency (%) 

If a sulfur recovery unit is present, SOx emissions are calculated as follows (EIIP 1999, 

Coe et al. 2003): 





 





−×















⋅

⋅ ×















×















⋅ ×













 ⋅ = 100

RE % 1

mollb 3

mollb 1

100

Eff

mollb

lb 64

 lb 34

 mollb

E E

S

SO SO

SO

SO

SH

SH

control, SH

x x

x

x

2

2

2 SOx

where: 

ESOx, control = Resulting SOx emissions (pounds per month) 

EH2S = Uncontrolled emissions of H2S (pounds per month) 

% RE = Recovery efficiency of the sulfur recovery unit (%) 

5.3.2 Boilers/Heaters/Burners 

Boilers, heaters, and burners provide process heat and steam for many processes such as 

electricity generation, glycol dehydrator reboilers, and amine reboiler units (EIIP 1999). To 

calculate uncontrolled emissions for liquid-fueled engines (waste oil or diesel) based on fuel use, 

Efu,liq: 

EFE liq lb/gal 7.1U10-3

liq fu, gal) (lb/10 = 3 ÷××

To calculate uncontrolled emissions for gas-fueled engines (natural gas, process gas, or 

waste gas) based on fuel use, Efu,gas: 
5-5

gas

3

gasfu, = EFE (lb/MMscf) ×× U10−

where: 

E = Emissions in pounds per month 

EF = Emission factor 

Uliq = Fuel usage (pounds/month) 

Ugas = Fuel usage (Mscf/month) 

If fuel usage is not provided, it is calculated based on hours operated, max rated or average heat 

input, and fuel heating value. 

The following emission factors are used to estimate emissions. These factors 

come from AP-42, Sections 1.3 and 1.4 (EPA 2002). All boilers are assumed to be wallfired boilers (no tangential-fired boilers). Emission factors for No. 6 residual oil were 

used to estimate emissions from waste-oil-fueled units. 

Table 5-1. Emission Factors for Liquid-Fueled Units – Diesel 

 where Max Rated Heat Input ≥ 100 MMBtu/hr. 

 Emission Factors (lb/103

 gal) 

Pollutant Uncontrolled 

Low NOx

Burner 

Flu Gas 

Recirculation 

THC 0.252 0.252 0.252 

VOC 0.2 0.2 0.2 

SOx 162.7 × S 162.7 × S 162.7 × S

SO2 157 × S 157 × S 157 × S 

SO3 5.7 × S 5.7 × S 5.7 × S 

NOx 24 10 10 

PM2.5 0.25 0.25 0.25 

PM10 2.0 2.0 2.0 

CO 5 5 5 

N2O 0.11 0.11 0.11 

CH4 0.052 0.052 0.052 

CO2 22,300 22,300 22,300 

S = Fuel oil sulfur content (wt%) 
5-6

Table 5-2. Emission Factors for Liquid-Fueled Units – Diesel 

where Max Rated Heat Input < 100 MMBtu/hr. 

 Emission Factors (lb/103

 gal) 

Pollutant Uncontrolled

Low NOx

Burner 

Flu Gas 

Recirculation 

THC 0.252 0.252 0.252 

VOC 0.2 0.2 0.2 

SOx 144 × S 144 × S 144 × S

SO2 142 × S 142 × S 142 × S 

SO3 2 × S 2 × S 2 × S 

NOx 20 20 20 

PM2.5 0.25 0.25 0.25 

PM10 2 2 2 

CO 5 5 5 

N2O 0.11 0.11 0.11 

CH4 0.052 0.052 0.052 

CO2 22,300 22,300 22,300 

S = Fuel oil sulfur content (wt %) 

Table 5-3. Emission Factors for Liquid-Fueled Units – Waste Oil 

where Max Rated Heat Input ≥ 100 MMBtu/hr. 

 Emission Factors (lb/103

 gal) 

Pollutant Uncontrolled 

Low NOx

Burner 

Flu Gas 

Recirculation 

THC 1.28 1.28 1.28 

VOC 0.28 0.28 0.28 

SOx 162.7 × S 162.7 × S 162.7 × S

SO2 157 × S 157 × S 157 × S 

SO3 5.7 × S 5.7 × S 5.7 × S 

NOx 47 40 40 

PM2.5 5.23 × S + 

1.73 

5.23 × S + 

1.73 

5.23 × S + 

1.73 

PM10 9.19 × S + 

3.22 

9.19 × S + 

3.22 

9.19 × S + 3.22 

CO 5 5 5 

N2O 0.11 0.11 0.11 

CH4 1.00 1.00 1.00 

CO2 (high S)a 24,400 24,400 24,400 

S = Fuel oil sulfur content (wt%) 

a

 As opposed to oil that has been desulfurized 
5-7

Table 5-4. Emission Factors for Liquid-Fueled Units – Waste Oil 

where Max Rated Heat Input < 100 MMBtu/hr. 

 Emission Factors (lb/103

 gal) 

Pollutant Uncontrolled 

Low 

NOx

Burner 

Flu Gas 

Recirculation 

THC 1.28 1.28 1.28 

VOC 0.28 0.28 0.28 

SOx 159 × S 159 × S 159 × S

SO2 157 × S 157 × S 157 × S

SO3 2 × S 2 × S 2 × S

NOx 55 55 55 

PM2.5 0.37 × S + 

0.12 

0.37 × S 

+ 0.12 

0.37 × S + 

0.12 

PM10 9.19 × S + 

3.22 

9.19 × S 

+ 3.22 

9.19 × S + 

3.22 

CO 5 5 5 

N2O 0.11 0.11 0.11 

CH4 1.00 1.0 1.0 

CO2 (high S)a 24,400 24,400 24,400 

S = Fuel oil sulfur content (wt%) 

a

 As opposed to oil that has been desulfurized 

Table 5-5. Emission Factors for Gas-Fueled Units – Natural Gas or 

Process Gas where Max Rated Heat Input ≥ 100 MMBtu/hr. 

 Emission Factors (lb/MMscf) 

Pollutant Uncontrolled

Low NOx

Burner 

Flu Gas 

Recirculation 

THC 11 11 11 

VOC 5.5 5.5 5.5 

SOx 0.6 0.6 0.6 

NOx 280 140 100 

PM10** 7.6 7.6 7.6 

CO 84 84 84 

N2O 2.2 0.64 0.64 

CH4 2.3 2.3 2.3 

CO2 120,000 120,000 120,000 

** = Also represents PM2.5
5-8

Table 5-6. Emission Factors for Gas-Fueled Units – Natural Gas or 

Process Gas where Max Rated Heat Input < 100 MMBtu/hr. 

 Emission Factors (lb/MMscf) 

Pollutant Uncontrolled

Low NOx

Burner 

Flu Gas 

Recirculation 

THC 11 11 11 

VOC 5.5 5.5 5.5 

SOx 0.6 0.6 0.6 

NOx 100 50 32 

PM10** 7.6 7.6 7.6 

CO 84 84 84 

N2O 2.2 0.64 0.64 

CH4 2.3 2.3 2.3 

CO2 120,000 120,000 120,000 

** Also represents PM2.5 

5.3.3 Diesel and Gasoline Engines 

Diesel and gasoline engines are used to run generators, pumps, compressors, and 

well-drilling equipment. Most of the pollutants emitted from these engines are from the 

exhaust. Evaporative losses are insignificant in diesel engines due to the low volatility of 

diesel fuels (EPA 2002). 

If a user-entered value for total fuel used is available, or if it can be estimated 

from default values then emissions are estimated based upon fuel use. Otherwise, if 

operating HP and hours operated are both available, then emissions are estimated based 

upon power output. 

To calculate uncontrolled emissions based on fuel use, Efu: 

H

gal

lb 7.1 EFE U10 6-

fu = (lb/MMBtu) ××××

To calculate uncontrolled emissions based on power output, Epo: 

453.6g

lb

po EFE hr)-(g/hp tHP ×××=

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (gallons/month) 

H = Fuel heating value (Btu/lb) 
5-9

HP = Engine horsepower (hp) 

t = Engine operating time (hr/month) 

The following emission factors are used to estimate emissions. These factors 

come from AP-42, Sections 3.3 and 3.4 (EPA 2002). 

Table 5-7. Emission Factors for Gasoline Engines. 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 3.03 9.8 

VOC 3.03 9.8 

SOx 0.084 0.268 

NOx 1.63 4.99 

PM10** 0.1 0.327 

CO 62.7 199 

CO2 154.0 489.9 

** Also represents PM2.5

Table 5-8. Emission Factors for Diesel Engines 

where Max HP < 600. 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 0.36 1.14 

VOC 0.33 1.04 

SOx 1.01 × S 3.67 × S

NOx 4.41 14.1 

PM10** 0.31 1 

CO 0.95 3.03 

CO2 164.0 521.6 

** Also represents PM2.5 

S = Fuel oil sulfur content (wt%) 
5-10

Table 5-9. Emission Factors for Diesel Engines 

where Max HP ≥ 600. 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 0.09 0.32 

VOC 0.08 0.29 

SOx 1.01 × S 3.67 × S 

NOx 3.2 10.9 

PM2 5* 0.056 0.178 

PM10 0.057 0.182 

CO 0.85 2.5 

CH4 0.008 0.03 

CO2 165.0 526.2 

 S = Fuel oil sulfur content (wt%) 

 * <3 μm 

If the corresponding field is null, a surrogate fuel consumption rate of 7,000 Btu/hp-hr is 

applied. 

5.3.4 Drilling Rigs 

Drilling activities associated with an existing facility or from a jack-up rig 

adjacent to a platform are included because of their emissions associated with gasoline, 

diesel, and natural gas fuel usage in engines. Total emissions equal the sum of emissions 

due to gasoline, diesel, and natural gas fuel usage. 

For gasoline fuel use, calculate uncontrolled emissions, Egas, as follows (Coe et al. 

2003): 

lb

Btu 300,20

gal

lb 6.17 EFE U10 6-

(lb/MMBtu) gas = ××××

where: 

E = Emissions in pounds per month 

EF = Emission factor (units shown in parentheses) 

U = Fuel usage (gallons) 

For diesel fuel use, calculate uncontrolled emissions, Edie, as follows (Coe et al. 2003): 

lb

Btu 19,300

gal

lb 7.1 EFE U10 6-

die = (lb/MMBtu) ××××
5-11

where: 

E = Emissions in pounds per month 

EF = Emission factor (units shown in parentheses) 

U = Fuel usage (gallons) 

For natural gas fuel use, calculate uncontrolled emissions, Eng, as follows: 

EFE U10 3

ng = (lb/MMscf) ×× −

where: 

E = Emissions in pounds per month 

EF = Emission factor (units shown in parentheses) 

U = Fuel usage (Mscf) 

The following emission factors are used to estimate emissions. These factors come from 

AP-42, Sections 3.2, 3.3 and 3.4 (EPA 2002). Diesel engines are assumed to be ≥ 600 hp. 

Natural gas engines are assumed to be 4-cycle and evenly distributed between lean and rich 

burns (by averaging). 

Table 5-10. Emission Factors for Gasoline Fuel Use. 

Pollutant 

EFgas

(lb/MMBtu) 

THC 3.03 

VOC 3.03 

SOx 0.084 

NOx 1.63 

PM10** 0.1 

CO 62.7 

CO2 154 

** Also represents PM2.5
5-12

Table 5-11. Emission Factors for Diesel Fuel Use. 

Pollutant 

EFdie

(lb/MMBtu) 

THC 0.09 

VOC 0.08 

SOx 1.01 × S 

NOx 3.2 

PM2.5* 0.056 

PM10 0.057 

CO 0.85 

CO2 165 

S = Fuel oil sulfur content (wt%) 

* <3 μm 

Table 5-12. Emission Factors for Natural Gas Fuel Use. 

Pollutant 

EFng 

(lb/MMscf) 

THC 932.3 

VOC 75.3 

SOx 0.6 

NOx 2467.5 

PM10 ** 4.9 

CO 2127.3 

CH4 755 

CO2 112,200 

 ** Also represents PM2.5

5.3.5 Flares 

A flare is a burning stack used to dispose of hydrocarbon vapors. Flares can be used to 

control emissions from storage tanks, loading operations, glycol dehydration units, vent 

collection system, and amine units. Flares usually operate continuously; however, some are used 

only for process upsets (U.S. DOI, MMS 1995). 

Flare emissions for total hydrocarbons (THC), VOC, NOx, PM10, and CO are estimated 

according to the following equation: 

EFHVE 1000 flare = tot × × flare ÷
5-13

where: 

Eflare = Emissions in pounds per month 

Vtot = Total volume of gas flared (Mscf) = vol flared (Mscf, excluding upsets) + 

 ∑ (upset flare feed rate (Mscf/hr) × hours operated) 

H = Flare gas heating value (Btu/scf) 

EFflare = Emission factor for flares (lb/MMBtu) 

SOx emissions are estimated using to the following equation: 





 





××+××× ⋅  ××



 



 = ∑=

− n

1i

SH iS,Hii

SO

6

F

SOflare, 2 2

2

x C tFC V'1000

molb379.4scf/l

m

ppm

10

100%

%Eff E

where: 

Eflare, SOx = Emissions in pounds per month 

EffF% = The combustion efficiency of the flare (percent) 

mSO2 = Molecular weight of SO2 = 64 lb/lb·mol 

V' = Non-upset volume of gas flared (Mscf) 

CH2S = Non-upset concentration of H2S in the flare gas (ppm) 

Fi = Upset flare feed rate for occurrence i (Mscf/hr) 

ti = Duration of occurrence i (hr) 

C H2S,i = H2S concentration for upset occurrence i (ppm) 

If the user indicates there is a continuous flare pilot, pilot light emissions are estimated as 

follows: 

pilot = × × EFDPE pilot ÷1000

where: 

Epilot = Pilot emissions in pounds per month 

P = Flare feed rate (Mscf/day) 

D = Number of days in month 

EFpilot = Emission factor for pilot (lb/MMscf) 

The following emission factors are used to estimate emissions. These factors come from 

AP-42, Sections 13.5 and 1.4 (EPA 2002). The VOC emission factor is based on the assumption 

that the flare composition is 45% C2/C3 and 55% C1 by volume (Coe et al. 2003). 
5-14

Table 5-13. Emission Factors for Flares.a

Pollutant EF (lb/MMBtu) 

THC 0.14 

VOC 0.052 

NOx 0.068 

PM10 0; where flare smoke = none 

 0.002; where flare smoke = light 

 0.01; where flare smoke = medium 

 0.02; where flare smoke = heavy 

CO 0.37 

CH4 0.126 a

 Factors are not available for PM2.5, N2O or CO2. 

Table 5-14. Emission Factors for Pilots. 

Pollutant EF (lb/MMscf) 

THC 11 

VOC 5.5 

NOx 100 

PM10 7.6 

SOx 0.6 

CO 84 

N2O 2.2 

CH4 2.3 

CO2 120,000 

If the corresponding fields are null, the following surrogate values are applied: 

Flare Smokedefault = None 

Pilot Fuel Feed Rate = 2.28 Mscf/day 

5.3.6 Fugitives 

Fugitive emissions are leaks from sealed surfaces associated with process equipment. 

Specific fugitive source types include equipment components such as valves, flanges, and 

connectors (EIIP 1999). Operators were required to delineate the stream type (gas, heavy oil, 

light oil, or water/oil) and average VOC weight percent of fugitives, and provide an equipment 

inventory (number of components). 

Fugitive THC emissions are estimated according to the following equation: 

= ∑( × )

comp

ETHC EFcomp,stream Ncomp

× D 
5-15

where: 

ETHC = THC emissions in pounds per month 

EFcomp,stream = Emission factor unique the type of component and process stream 

(lb/component-day) 

Ncomp = Count of components of a given type present on the facility. (Note: Null 

values are treated as zero.) 

D = Number of days in month 

Fugitive VOC emissions are estimated according to the following equation: 

VOC = E E THC × WtFrVOCcomp,stream

where: 

EVOC = VOC emissions in pounds per month 

ETHC = THC emissions in pounds per month 

WtFrVOCcomp,stream= Weight fraction of VOC unique to the process stream 

Fugitive CH4 emissions are estimated according to the following equation: 

comp, stream 4 CH4 = E E THC × WtFrCH

where: 

ECH4 = CH4 emissions in pounds per month 

ETHC = THC emissions in pounds per month 

WtFrCH4comp,stream = Weight fraction of CH4 unique to the process stream 
5-16

Table 5-15. THC Emission Factors for Oil and Gas Production Operations 

(lb/component-day).a 

Component Gas 

Natural 

Gas 

Liquid

Heavy Oil 

(<20 API 

Gravity) 

Light Oil 

(≥ 20 API 

Gravity) Water/Oil 

Oil/Water/ 

Gasc 

Connector 1.1E-02 1.1E-02 4.0E-04 1.1E-02 5.8E-03 1.1E-02 

Flange 2.1E-02 5.8E-03 2.1E-05 5.8E-03 1.5E-04 2.1E-02 

Open-end 1.1E-01 7.4E-02 7.4E-02 7.4E-02 1.3E-02 1.1E-01 

Otherb 4.7E-01 4.0E-01 1.7E-03 4.0E-01 7.4E-01 7.4E-01 

Pump 1.3E-01 6.9E-01 6.9E-01 6.9E-01 1.3E-03 1.3E-01 

Valve 2.4E-01 1.3E-01 4.4E-04 1.3E-01 5.2E-03 2.4E-01 

a Source: API 1996 

b Includes compressor seals, diaphragms, drains, dump arms, hatches, instruments, meters, 

pressure relief valves, polished rods, and vents c Assumed to be equal to either gas or water/oil, whichever is greater 

If a component count is not provided, the following surrogate component counts are used 

(derived from API 1993, average number of offshore platform components, and percentage of 

total components by type): 

Connectors: 9,194 

Valves: 1713 

Open-Ends: 285 

Others: 228 

If stream type is not provided, emissions are calculated assuming the stream type is light 

oil. The default values in Table 5-16 are assigned if the average VOC weight percent field is 

blank. 

Table 5-16. Default Speciation Weight Fractions for Total Hydrocarbon (THC) 

Emissions By Stream Type.a 

THC Fraction Gas 

Natural 

Gas 

Liquid

Light Oil 

(≥ 20 API 

Gravity) 

Heavy Oil 

(<20 API 

Gravity) Water/Oilb

Oil/Water/ 

Gas

Methane 0.945 0.612 0.612 0.942 0.612 0.612 

VOC 0.0137 0.296 0.296 0.030 0.296 0.296 

a Source: API 1996 

b Water/oil refers to water streams in oil service with a water content greater than 50% from the point of 

origin to the point where the water content reaches 99%. For water streams with a water content greater 

than 99%, the emission rate is considered negligible 
5-17

5.3.7 Glycol Dehydrators 

Glycol dehydrators remove excess water from natural gas streams to prevent the 

formation of hydrates and corrosion in the pipeline (EIIP 1999). Surrogate VOC glycol 

dehydrator still column vent emission estimates were calculated based on regression 

equations from GRI-GLYCalc version 4 (GTI 2000) computer program runs for varying 

combinations of wet gas pressure and wet gas temperature. Surrogate glycol dehydrator 

flash tank vent emissions were also calculated based on regression equations from GRIGLYCalc version 4 computer program runs for varying combinations of flash tank 

pressure and flash tank temperature. Table 5-17 presents the surrogate gas analysis used 

in the runs. 

The VOC emission rate in pounds per hour is directly proportional to the volume of gas 

dehydrated if all other variables are held constant. Thus, emission factors from the GRIGLYCalc runs were developed to express VOC emissions in pounds per hour per million 

standard cubic feet per day gas (lbs/hr-MMSCFD) processed. For still column vents, VOC 

emission factors were developed for over 60 combinations of wet gas pressure and temperature. 

The emission factors range from 0.0126 lb VOC/hr-MMSCFD at a pressure of 1200 psig and 

temperature of 50° F, to 0.3357 lb VOC/hr-MMSCFD at a pressure of 600 psig and temperature 

of 130°F. 

For glycol dehydrator flash tanks, VOC emission factors were developed for over 

120 combinations of wet gas pressure and temperature, and flash tank pressure and 

temperature. The lowest emission factor is 0.03457 lb VOC/hr-MMSCFD at a wet gas 

pressure of 1100 psig and temperature of 70°F, and flash tank pressure of 100 psig and 

temperature of 75°F. The highest emission factor is 0.09282 lb VOC/hr-MMSCFD at a 

wet gas pressure of 800 psig and temperature of 90°F, and flash tank pressure of 50 psig 

and temperature of 125°F. 

The following assumptions were used to estimate emissions: 

• The wet gas is saturated; 

• The volume of dry gas was constant at 10 MMSCFD; 

• The dry gas water content is 7 lbs water per MMSCF gas; 

• The triethylene glycol (TEG) circulation rate is 3 gallons/lb water removed; 

• A gas injection pump is used to recirculate the TEG; 

• If a flash tank is present, the flash tank is vented to the atmosphere; and 

• No stripping gas used. 
5-18

Table 5-17. Surrogate Gas Analysis for GLYCalc Runs. 

Component Mole Percent (%) 

H2S 0.000 

Nitrogen 0.100 

Carbon Dioxide 0.800 

Methane 94.500 

Ethane 3.330 

Propane 0.750 

n-Butane 0.150 

Iso-Butane 0.150 

N-Pentane 0.050 

Iso-Pentane 0.050 

Iso-Hexanes 0.077 

N-Hexane 0.018 

Benzene 0.004 

Toluene 0.003 

Ethylbenzene 0.000 

Xylenes 0.001 

Trimethylpentane 0.003 

Heptanes 0.008 

Octanes 0.006 

Nonanes 0.000 

Decanes + 0.000 

5.3.8 Loading Operations 

Emissions due to loading operations are generated by the displacement of the vapor space 

in the receiving cargo hold by liquid product. Loading losses are due to: 1—liquids displacing 

vapors already residing in the cargo tank, and 2—vapors generated by the liquid being loaded 

into the cargo tank (EIIP 1999, Boyer and Brodnax 1996). The calculations below assume that 

ships arrive in uncleaned, ballasted condition and that the previously carried loads were crude 

oil. 

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

gal 42.0 Q TmG E 0.42)P(0.441.840.46 − ×××















×−××+=
5-19

where: 

ETHC = THC emissions (pounds per month) 

PVA = True vapor pressure of the loaded liquid (psia) = exp[A − (B/TLA)] 

m = Average molecular weight of vapors (lb/lb-mol) 

G = Vapor growth factor = 1.02 

Tb = Liquid bulk temperature (°R) 

Q = The amount transferred (bbl) 

A = Empirical constant = 12.82 − 0.9672 × ln(Reid VP) 

B = Empirical constant = 7261 − 1216 × ln(Reid VP) 

TLA = Daily average liquid surface temperature (°R) = 0.44 × Taa + (0.56 × Tb) + (0.0079 

× a × I) 

Taa = Daily average ambient temperature (°R) 

a = Tank paint solar absorptance 

I = Daily solar insulation factor (Btu/ft2

·day) = 1437 Btu/ft2·dayA

Table 5-18. 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/), Comprehensive Ocean-Atmosphere Data 

Set (COADS). Average monthly temperatures for the period 1980-1992 for Marsden Square 81, 10° Box 241, 2° Box 5537 

Table 5-19. Tank Paint Solar Absorptance, a. 

Solar Absorptance by 

Paint Color and 

Condition 

Paint Condition 

Paint Color 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 

VOC emissions (EVOC, in pounds) are calculated as a percent of THC emissions: 

VOC E100/ntVOC THC E = TankVaporWeightPerce ×

 

A Annual average for New Orleans 
5-20

The following surrogates are assigned or estimated if the corresponding fields are null: 

Reid Vapor Pressuredefault = 5 

Tb,default = Taa + 6 × a – 1 

Tank Bulk Liquid Tempdefault = Taa 

Tank VOC Molecular Weightdefault = 50 

Tank Vapor Weight Percent VOCdefault = 85 

5.3.9 Losses from Flashing 

Flash gas is a natural gas that is liberated when an oil stream undergoes a pressure drop. 

Flash gas is associated with high, intermediate, and low pressure separators, heater treaters, surge 

tanks, accumulators, and fixed roof atmospheric storage tanks. Flash gas emissions are only 

estimated for gas that is vented to the atmosphere or burned in a flare. No emissions are 

associated with flash gas that is routed back into the system (e.g., sales gas). 

If a pressure drop occurs between vessels, flash gas emissions are estimated using 

the Vasquez-Beggs correlation equations to estimate tank vapors in standard cubic feet 

per barrel of oil produced. Operators were asked to report the following parameters for 

each part of the process: 

• API gravity of stored oil; 

• Operating pressure (psig) of each vessel and immediately upstream (i.e., separator, heater 

treater, surge tank, storage tank); 

• Operating temperature (°F) of each vessel and immediately upstream; 

• Actual throughput of oil for each vessel; 

• Disposition of flash gas from each vessel – routed to system (e.g., sales pipeline, gas-lift), 

vented to atmosphere, or burned in flare; and 

• SCF of flash gas per bbl of oil throughput (optional).

Flashing losses of THC, in pounds, are calculated according to the following equation: 

f = GORL × Throughput × GD

where: 

Lf = THC emissions in pounds per month 

GOR = Gas-to-oil ratio (scf/bbl) – see discussion below if not provided by operator 

Throughput = The actual throughput volume for each vessel for the survey period 

GD = Tank vent hydrocarbon gas density (lb/ft3

) = tank mol weight of gas ÷ 379.4 
5-21

Gas-to-oil ratio, GOR: 

















+

×

×××=

460 tempVessel

gravity APIC expCSGOPCGOR C 3

1 2

where: 

C1 = Vasquez-Beggs constant = 





 >

otherwise 0.0362;

30 gravity API if 0.0178; 

OP = Vessel operating pressure (psia) 

C2 = Vasquez-Beggs constant = 





 >

otherwise 1.0937;

30 gravity API if 1.187;

CSG = Corrected specific gravity of gas (see below) 

C3 = Vasquez-Beggs constant = 





 >

otherwise 25.724;

30 gravity API if 23.931;

Emissions of CO2, CH4, and VOC are estimated using speciation profiles from API publication 

no. 4638: 

Lf,VOC = Lf,THC × 0.04 

Lf,CO2 = Lf,THC × 0.02 

Lf,CH4 = Lf,THC × 0.88 

If the corresponding field is null, a default API gravity of 37 is applied. A default tank molecular 

gas weight of 24.994 lbs/lb·mole is also assumed as an industry average. 

The following surrogate values are used for the corrected specific gravity of gas (CSG): 

API Gravity 

Gas Specific Gravity 

(at 100 psig) 

>30 0.93 

<30 1.08 

5.3.10 Mud Degassing 

Hydrocarbon emissions from mud degassing occur when gas that has seeped into the well 

bore and dissolved or become entrained in the drilling mud is separated from the mud and vented 

to the atmosphere (EIIP 1999). To estimate mud degassing emissions, operators were asked to 

provide: 

• Number of days that drilling operations occurred; and 

• Type of drilling mud used (water-based, synthetic, oil-based). 
5-22

Emissions were calculated using the equation: 

THC = THC × DEF E drill

where: 

ETHC = THC emissions (pounds per month) 

EFTHC = THC emission factor (lbs/day) 

Ddrill = Number of days in the month that drilling occurred 

For water-based and oil-based muds, hydrocarbon emissions are estimated using 

emission factors provided in the 1977 EPA report: Atmospheric Emissions from Offshore 

Oil and Gas Development and Production: 

Water-based muds: 881.84 lbs THC/day 

Oil-based muds: 198.41 lbs THC/day 

Synthetic based muds: 198.41 lbs THC day

For synthetic-based muds, no information is available on air emission rates. Syntheticbased muds are used as substitutes for oil-based muds, and may occasionally be used to replace 

water-based muds. Synthetic muds perform like oil-based muds, but with lower environmental 

impact and faster biodegradability (EPA 2000). No information was found, however, on a 

possible reduction in THC emissions. Because most emissions are associated with the release of 

entrained hydrocarbons, and EPA estimates no change in the amount of waste cuttings between 

synthetic- and oil-based muds (EPA 2000), the oil-based mud THC emission factor is used for 

synthetic-based muds as well. 

THC emissions are speciated as follows (EPA 1977): 

Component 

Percent Composition by 

Volume (%) 

Methane 83.85 

Ethane 5.41 

Propane 6.12 

Butane 3.21 

Pentane 1.40 

If the type of mud used was specified but the number of days that drilling 

occurred is left blank, a surrogate for number of drilling days per month, developed from 

the activity data submitted for all platforms, is applied: 
5-23

Water-based muds: 16 

Oil-based muds: 14 

Synthetic-based muds: 13 

5.3.11 Natural Gas Engines 

Like diesel and gasoline engines, natural gas engines are used to run generators, 

pumps, compressors, and well-drilling equipment. Most of the pollutants emitted from 

these engines are from the exhaust (EPA 2002). 

If a user-entered value for total fuel used is available, or if it can be estimated 

from the default values (below), then emissions are estimated based upon fuel use. 

Otherwise, if operating horsepower and hours operated are both available, then emissions 

are estimated based upon power output. 

Emissions are calculated based on fuel use as: 

-3

fu (lb/MMBtu) = EFE ××× 10UH

Emissions are calculated based on power output as: 

453.6g

lb

po EFE hr)-(g/hp tHP ×××=

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

H = Fuel heating value (Btu/scf) 

U = Fuel usage (Mscf/month) 

HP = Engine horsepower (hp) 

t = Engine operating time (hr/month) 

Tables 5-20 through 5-23 present the emission factors used to estimate natural gas engine 

emissions. These factors come from AP-42, Section 3.2 (EPA 2002). 
5-24

Table 5-20. Emission Factors for Natural Gas Engines 

where Engine Stroke Cycle = 2-Cycle and Engine 

Burn Type = Lean. 

Pollutant 

EFfu

(lb/MMBtu)

EFpo

(g/hp-hr) 

THC 1.64 5.6 

VOC 0.12 0.41 

SO2 5.88 × 10-4 2 × 10-3

NOx (<90% load) 1.94 6.6 

PM10** 3.84 × 10-2 0.13 

CO (<90% load) 0.353 1.2 

CH4 1.45 4.9 

CO2 110 374.2 

** Also represents PM2.5

Table 5-21. Emission Factors for Natural Gas Engines 

where Engine Stroke Cycle = 

4-Cycle and Engine Burn Type = Lean. 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 1.47 5.00 

VOC 0.12 0.41 

SO2 5.88 × 10-4 2.00 × 10-3

NOx (<90% load) 0.85 2.89 

PM10 ** 7.71 × 10-5 2.6 × 10–4

CO (<90% load) 0.56 1.9 

CH4 1.25 4.25 

CO2 110 374.2 

** Also represents PM2.5
5-25

Table 5-22. Emission Factors for Natural Gas Engines 

where Engine Stroke Cycle = 

4-Cycle and Engine Burn Type = Rich. 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 0.36 1.25 

VOC 0.03 0.1 

SO2 5.88 × 10-4 2.00 × 10-3

NOx (<90% 

load 

2.27 7.72 

PM10 ** 9.5 × 10-3 0.03 

CO (<90 % 

load) 

3.51 11.94 

CH4 0.23 0.78 

CO2 110 374.22 

**Also represents PM2.5

Table 5-23. Emission Factors for Natural Gas Engines 

where Engine Burn Type = Clean. 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 1.47 5.00 

VOC 0.12 0.41 

SO2 5.88 × 10-4 2.00 × 10-3

NOx 0.59 2.00 

PM10 ** 7.71 × 10-5 2.6 × 10-4

CO 0.88 3.00 

CH4 1.25 4.25 

CO2 110 374.22 

**Also represents PM2.5

If the corresponding field is null, a fuel consumption rate of 7,000 Btu/hp-hr is applied. 

5.3.12 Natural Gas Turbines 

A gas turbine is an internal combustion engine that operates with rotary rather 

than reciprocating motion. Turbines are primarily used to power compressors rather than 

generate electricity (Boyer and Brodnax 1996). A turbine’s operating load has a 

considerable effect on the resulting emission levels. With reduced loads, there are lower 

thermal efficiencies and more incomplete combustion (EPA 2002). 
5-26

If a user-entered value for total fuel used is available, then emissions are 

estimated based upon fuel use. Otherwise, if operating horsepower and hours operated 

are both available, then emissions are estimated based upon power output. 

To calculate emissions based on fuel use: 

E EF 10 UH 3-

fu = (lb/MMBtu) ×××

To calculate emissions based on power output: 

EFE tHPFU 10 6

po = (lb/MMBtu) ×××× −

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

H = Fuel heating value (Btu/scf) 

U = Fuel usage (Mscf/month) 

FU = Average fuel usage (Btu/hp-hr) 

HP = Turbine horsepower (hp) 

t = Turbine operating time (hr/month) 

The following emission factors are used to estimate emissions. These factors come from 

AP-42 Section 3.1(EPA 2002). 

Table 5-24. Emission Factors for Natural Gas Turbines. 

Pollutant 

EF 

(lb/MMBtu) 

THC 1.1 × 10-2

VOC 2.1 × 10-3

SOx* 0.94 × S 

NOx 0.32 

PM10** 6.6 × 10-3 

CO 8.2 × 10-2 

N2O 0.003 

CH4 8.6 × 10-3

CO2 110 

* S= (CH2S) × (1.78 × 10-4), %S. CH2S = ppmv H2S in fuel.

If not available, EF is 3.47 × 10-3 lb/MMBtu 

** Also represents PM2.5
5-27

If the corresponding field is null, a fuel consumption rate of 10,000 Btu/hp-hr is applied. 

5.3.13 Pneumatic Pumps 

A readily-available supply of compressed natural gas is used to power gas actuated 

pumps. There is no combustion of the gas because the energy is derived from the gas pressure. 

These pumps include reciprocating pumps such as diaphragm, plunger, and piston pumps. Most 

gas actuated pumps vent directly to the atmosphere (Boyer and Brodnax 1996). 

Operators were asked to provide the following information for pumps that are in natural 

gas service: 

• Manufacturer and model; 

• Amount of natural gas consumed in SCF/hr (optional); 

• Hours of operation in the reporting period; and 

• Whether it is vented to a manifold, a flare, or the atmosphere. 

CO2, CH4, THC, and VOC emissions (in pounds) for pneumatic pumps are developed 

using equation 10.4-3, from Chapter 10, “Preferred and Alternative Methods for Estimating Air 

Emissions from Oil and Gas Field Production and Processing Operations” (EIIP 1999): 

E = t × FU × (mole weight of gas, lbs/lb-mole) × (1 lb-mole/379.4 SCF) 

where: 

E = Emissions in pounds per month 

t = Operating time (hr/month) 

FU = Fuel usage rate (SCF/hr)

Mole weight of gas = mole percent of constituent/100 × mole weight of constituent/gas MW 

To determine the mole percent of each constituent (CH4, CO2, THC, and VOC), operators 

were asked to provide the sales gas composition for their structure. Table 5-25 presents the 

default gas composition if not provided. Table 5-25 also presents the mole weight for each gas 

constituent. 

If the fuel usage rate is not provided, an average value for each make and model is 

assigned based on reported manufacturer data, or an average surrogate based on the manufacturer 

is applied. 
5-28

Table 5-25. Default Sales Gas Composition. 

Component Default Mol% 

Mole Weight 

(lb/lb-mole) 

CO2 0.80 44.010 

CH4 94.50 16.043 

C2 3.33 30.070 

C3 0.75 44.097 

i-C4 0.15 58.124 

n-C4 0.15 58.124 

i-C5 0.05 72.150 

n-C5 0.05 72.150 

C6 0.099 86.177 

C7 0.011 100.272 

C8+ 0.007 114.231 

5.3.14 Pressure/Level Controllers 

Devices that control both pressure and liquid levels on vessels and flow lines are 

used extensively in production operations. The units are designed to open or close a 

valve when a preset pressure or liquid level is reached. The valves are automatically 

actuated by bleeding compressed gas from a diaphragm or piston. The gas is vented to 

the atmosphere in the process. Most production facilities use natural gas to actuate the 

controllers. The amount of gas vented is dependent on several factors, including the 

manufacturer and application (Boyer and Brodnax 1996). 

Operators were asked to provide the following information for controllers that are 

in natural gas service: 

• Service type (pressure control vs. level control); 

• Manufacturer and model; 

• Amount of natural gas consumed in SCF/hr (optional); and 

• Hours of operation in the reporting period. 

Similar to pneumatic pumps, CO2, CH4, THC, and VOC emissions estimates (in 

pounds) for pressure and level controllers are developed using the following equation 

(EIIP 1999): 

E = No. of units × t × FU × (mole weight of gas, lbs/lb-mole) × (1 lb-mole/379.4 SCF) 

where: 

E = Emissions in pounds per month 

t = Operating time (hr/month) 

FU = Fuel usage rate (SCF/hr)
5-29

Mole weight of gas = mole percent of constituent/100 × mole weight of constituent/gas MW 

To determine the mole percent of each constituent (CH4, CO2, THC, and VOC), 

operators were asked to provide the sales gas composition for their structure. Table 5-25 

presents the default gas composition if not provided. Table 5-25 also presents the mole 

weight for each gas constituent. 

If the fuel usage rate is not provided, an average value for each make and model is 

assigned based on reported manufacturer data, or an average surrogate based on the 

manufacturer and service type is applied. 

5.3.15 Storage Tanks 

VOC and THC may be lost from storage tanks as a result of flashing, working, and 

standing losses. This discussion only addresses working and standing losses (Lw and Ls). 

Flashing losses are estimated separately. 

Standing losses result from the expulsion of vapors due to vapor expansion and 

contraction resulting from temperature and barometric pressure changes. Working losses result 

from filling and emptying operations (Boyer and Brodnax 1996). These calculations assume that 

all tanks are fixed roof tanks. 

Standing losses of THC in pounds are calculated according to the following equation: 

THC s, = × × × × KKWVDL SEVV

where: 

Ls = Standing losses (lbs/month) 

D = Number of days in the month 

VV = Tank vapor space volume (ft3

) 

WV = Stock vapor density (lb/ft3

) 

KE = Calculated vapor space expansion factor (unitless) 

KS = Calculated vented vapor saturation factor (unitless) 

Vapor space volume for a horizontal, rectangular tank is calculated as: 

VV = Tank Shell Length × Tank Shell Width1 × HVO

where: 

VV = Vapor space volume (ft3

)

HVO = Vapor space outage (ft) = Tank Shell Height − Tank Average Liquid Height 
5-30

Vapor space volume for a vertical, rectangular tank is calculated as: 

VV = Tank Shell Width1 × Tank Shell Width2 × HVO

where: 

VV = Vapor space volume (ft3

)

HVO = Vapor space outage (ft) = Tank Shell Height − Tank Average Liquid Height 

Vapor space for a horizontal, cylindrical tank is calculated as: 

V Tank Shell Diam Tank Shell Length H

4 0.785 v

VO = × × ×

×

π

where: 

VV = Vapor space volume (ft3

) 

HVO = Vapor space outage (ft) = 0.5 × Tank Shell Diameter 

Vapor space for a vertical, cylindrical tank is calculated as: 

VO

2

V HDiam ShellTank 

4

V ×= ×

π

where: 

VV = Vapor space volume (ft3

) 

HVO = Vapor space outage (ft) = 











=















 



 



 + +

+ =

dome"" Type RoofTank if ; Diam ShellTank 

Hgt RoofTank Hgt RoofTank Hgt Liquid AvgTank Hgt ShellTank 

Hgt Liquid AvgTank Hgt ShellTank peaked""or cone"" Type RoofTank if ;Hgt RoofTank 2

6

1

2

1

3

1

-

-

 TankShell Hgt-TankAvgLiquidHgt; if Tank Roof Type = “Flat”

Stock vapor density is calculated as: 

Wv = (Tank VOC Molecular Weight × PVA) ÷ (10.731 × TLA) 

where: 

WV = Stock vapor density (lb/ft3

) 

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) 

TLA = Daily average liquid surface temperature (°R) = 0.44 × Taa + (0.56 × Tb) + (0.0079 × a ×

I) 

Taa = Daily average ambient temperature (°R) 

a = Tank paint solar absorptance 
5-31

Tb = Liquid bulk temperature (°R) 

I = Daily solar insulation factor (Btu/ft2

·day) = 1437 Btu/ft2·dayA

Table 5-26. 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 5-27. Tank Paint Solar Absorptance, a. 

 Solar Absorptance by

Paint Condition 

Paint Color 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 

The vapor space expansion factor is calculated as: 

= LAvE + − − vaabv )PP/()P(P)/TT(K

where: 

KE = Vapor space expansion factor 

Tv = Daily vapor temperature range (°R) = 0.72 × Ta+ 0.028 × a × I 

TLA= Daily average liquid surface temperature (°R) 

Pv = Daily pressure range (psia)= 0.50 × B × Pva × Tv/TLA

2

Pb = Breather vent pressure setting range (psig) = Breather vent pressure − breather vent 

vacuum 

Pa = Atmospheric pressure (psia) 

Pva = Vapor pressure at daily average liquid surface temperature (psia) 

The vented vapor saturation factor is calculated as: 

VA VO S = + × × HP053.01/(1K ) 

 

A Annual average for New Orleans 
5-32

where: 

KS = Vented vapor saturation factor 

PVA = Vapor pressure at daily average liquid surface temperature (psia) 

HVO = Vapor space outage (ft) 

Working losses of THC in pounds are calculated according to the following equation: 

L THC w, 0.0010×= Mol VOCTank × P Weight VA ×Throughput ×× KK NP

where: 

Lw = Working losses 

PVA = Vapor pressure at daily average liquid surface temperature (psia) 

KP = Working loss product factor (unitless) = 0.75 

KN = Working loss turnover factor (unitless) =







>

≤

+ 36 Nfor ;

36 Nfor 1;

6N

N180 

N = Number of turnovers per month = 5.614 × throughput/VLX

VLX = Tank maximum liquid volume (ft3

) 

Tank maximum liquid volume for a horizontal, rectangular tank is calculated as: 

VLX = Tank Shell Length × Tank Shell Width1 × Tank Shell Height 

Tank maximum liquid volume for a vertical, rectangular tank is calculated as: 

VLX = Tank Shell Width1 × Tank Shell Width2 × Tank Shell Height 

Tank maximum liquid volume for a horizontal, cylindrical tank is calculated as: 

Diam ShellTank Length ShellTank 4V 2

LX ×= ×

π

Tank maximum liquid volume for a vertical, cylindrical tank is calculated as: 

Diam ShellTank Hgt ShellTank 4V 2

LX ×= ×

π
5-33

where: 

VLX = Tank maximum liquid volume (ft3

)

The following surrogates are assigned or estimated if the corresponding fields are null: 

Product type = Crude oil

Paint Color = Grey

Condition = Good

Roof type = Fixed

Roof Shape = Cone

API Gravitydefault = 37 

Reid VPdefault = −1.699 + 0.179 × API Gravity (or 5, if no other information is available)

Tb,default = Taa + 6 × a – 1 (or 530o R, if no other information is available) 

Breather Vent Pressuredefault = 0.03 

Breather Vent Vacuumdefault = −0.03 

Tank Bulk LiqTdefault = Taa 

Tank VOC Mol Weightdefault = 50 

Tank Vapor Weight Percent VOCdefault = 85 

Mole Fractiondefault = 0.9 

Tank Avg Liquid Hgtdefault = 0.5 × Tank Shell Hgt

Flare Efficiencydefault = 98 

5.3.16 Vents 

Production facilities often discharge natural gas to the atmosphere via vents. The 

discharges can be due to routine or emergency releases. Vents receive exhaust streams from 

miscellaneous sources, as well as manifold exhaust streams from other equipment on the same 

platform such as amine units, glycol dehydrators, loading operations, and storage tanks. 

Emissions from vents are calculated based on the volume of gas vented from miscellaneous 

equipment (less the volume from the manifold equipment, which are reported with the other 

equipment) and the chemical composition of the gas. 

Vent emissions of VOC are estimated using the following equation: 





 





×+×× ⋅ ××= ∑=

− n

1i

ii

VOC

6

VOC vent, VOC tF V'1000

molb379.4scf/l

m

ppm

10 E C

where: 

Event, VOC = VOC emissions in pounds per month 

CVOC = Concentration of VOC in the vent gas (ppmv) 

mVOC = Molecular weight of VOC (lb/lb·mol) 

V' = Non-upset volume of gas vented from miscellaneous sources (Mscf) 
5-34

Fi = Upset vent feed rate for occurrence i (Mscf/hr) 

ti = Duration of occurrence i 

Vent emissions of H2S are estimated using the following equation: 





 





××+××× ⋅ ×= ∑=

− n

1i

iS,H H2S ii

H2S

6

SH vent, 2 2 C tFC V'1000

molb379.4scf/l

m

ppm

10 E

where: 

Event, H2S = H2S emissions in pounds 

CH2S = Concentration of H2S in the vent gas (ppmv) 

mH2S = Molecular weight of H2S = 34 lb/lb mol 

CH2S,I = H2S concentration of upset occurrence i 

V' = Non-upset volume of gas vented from miscellaneous sources (Mscf) 

Fi = Upset vent feed rate for occurrence i (Mscf/hr) 

ti = Duration of occurrence i 

Vent emissions of CH4 are estimated using the following equation: 





 





×+×× ⋅ ××= ∑=

− n

1i

ii

CH4

6

CH4 vent, CH4 tF V'1000

molb379.4scf/l

m

ppm

10 CE

where: 

Event, CH4 = CH4 emissions in pounds 

CCH4 = Concentration of CH4 in the vent gas (ppmv) 

MCH4 = Molecular weight of CH4 = 16 lb/lb · mol 

CH2S,I = H2S concentration of upset occurrence i 

V' = Non-upset volume of gas vented from miscellaneous sources (Mscf) 

Fi = Upset vent feed rate for occurrence i (Mscf/hr) 

ti = Duration of occurrence i 

If a flare is used: 

100%

Eff Event Event FLARE

controlled ×=

The following surrogates are assigned or estimated if the corresponding fields are null: 

VOC concentration = 12,700 ppmv (=1.27 mol %) 

H2S concentration = 3.38 ppmv 

CH4 concentration = 945,000 ppmv (=94.5 mol %) 
6-1

6. NON-PLATFORM SOURCE CATEGORIES 

In addition to compiling activity data from platform operators, ERG compiled activity 

data for OCS as well as non-OCS non-platform sources in the Gulf of Mexico, and developed 

emission estimates for each source category. Non-platform sources include: 

• Biogenic/Geogenic Sources; 

• Commercial Marine Vessels; 

• Drill Ships; 

• Fishing Vessels; 

• Helicopters; 

• The Louisiana Offshore Oil Platform (LOOP); 

• Military Vessels; 

• Pipelaying Vessels; 

• Platform Construction and Removal; 

• Survey Vessels; and 

• Vessel Lightering. 

The appendices to this report contain documentation for the non-platform sources, 

activity data, emission factors, and emission estimates developed in this study. As discussed in 

Appendix M, the resulting emission estimates have also been spatially allocated to MMS lease 

blocks. 

The accuracy of the non-platform emission estimates is dependent on the accuracy of the 

activity data and the emission factors used. Although activity data used in this study were 

specific and reasonably accurate for the 2000 base year, some of the activity data are based on 

adjustments made to activity data that were presented in the 1995 MMS study (U.S. DOI, MMS 

1995), which may have been derived from a 1992 Survey of Offshore Operators undertaken by 

the Offshore Operators Committee. In addition, the marine diesel emission factors are based on 

typical horsepower and load factors obtained from the 1995 report. These values are considered 

averages, and actual emissions from specific vessels may differ significantly. Limitations of the 

non-platform inventory and recommended improvements are discussed in Section 8 and in the 

appendices.
7-1

7. DEVELOPMENT OF THE DIURNAL EMISSION CURVES 

7.1 INTRODUCTION 

Diurnal emission curves allow inventory emission estimates for a given category to be 

temporally allocated, across a 24-hour time period, on a 1-hour basis. Hour-by-hour emission 

estimates of this nature are required in order to run advanced photochemical simulation models 

such as the Urban Airshed Model. State agencies and the EPA may run such models, inclusive 

of Gulf of Mexico offshore sources, to address ozone and regional haze issues. 

Source operations (and in turn their emissions) are, by their nature, inherently continuous 

and reasonably uniform or intermittent and non-uniform. For example, production processes are 

typically continuous (24 hours/day) and consistent because companies want to maximize the 

utilization of resources and obtain as much return on their investment as possible. Fluctuating 

operational levels are not consistent with these missions. 

Other source types that are not directly production-driven may only operate to fulfill a 

specific need and may have an operation that is limited by other physical conditions (e.g., is only 

done in daylight). Meteorological conditions, for example, may also affect a source’s daily 

temporal profile (e.g., higher temperatures at mid day could mean higher emissions than at 

midnight). 

ERG developed diurnal emission curves for all sources in this study, platform as well as 

non-platform. Since the objective of having diurnal profiles is to support photochemical 

modeling, the temporal profiles presented in this section are for a typical day in August, during 

the ozone season. Like onshore situations, the Gulf of Mexico offshore source population 

consists of large stationary point sources, and various mobile and natural source types. 

7.2 APPROACH

The Gulfwide study source population consists of point sources, mobile sources, and 

natural sources. Because it is infeasible to survey every individual piece of equipment in the 

study area, offshore industry trends in daily operation were developed for a subset of sources 

within each major category grouping. This information was then applied to the category as a 

whole. 

The temporal profiles presented here were developed for a typical day in the ozone 

season. In a typical summer day, activity for production platforms, drilling, tanker-shipping, 

space cooling, drill rig mobilization, and setting of new platforms were expected to be fairly 

continuous on a 24-hour basis. This would be especially true for the latter two categories, since 

companies want to maximize such activities during the good summer weather months. Activities 

such as helicopter traffic and supply boats are not continuous and generally cycle in conjunction 

with daylight hours. 

ERG obtained the temporal profiling data from a number of sources. Activity levels and 

diurnal variations are best determined through surveys or estimated using engineering judgement 
7-2

by people familiar with the sources. Direct monthly survey data are available for platform 

equipment: the monthly hours of operation for each piece of equipment were provided by 

platform operators through GOADS data collection. 

For non-platform sources, information was derived from published industry statistics and 

the 1995 MMS study Gulf of Mexico Air Quality Study, Final Report (U.S. DOI, MMS 1995). 

COMM Engineering provided information on the daily operational patterns and characteristics of 

the sources based on their permitting experience with offshore oil and gas operations. Lastly, 

default allocation algorithms and values were obtained from EPA guidance documents dealing 

with modeling inventories and modeling requirements for the new ozone and PM-2.5 National 

Ambient Air Quality Standards (NAAQS) (EPA 1991, 1999, 2001). These guidance documents 

are designed to help inventory preparers determine hourly emissions. 

7.3 SOURCE CATEGORY GROUPINGS AND DIURNAL PATTERNS

The following platform operations are estimated to have essentially constant and uniform 

operation, with no significant variation in emissions throughout a 24-hour ozone season day 

(Figure 7-1). The assumed uniform operations for the platform sources are based on information 

provided by COMM Engineering and in the EPA study Procedures or the Preparation of 

Emission Inventories for Carbon Monoxide and Precursor’s of Ozone (EPA 2001): 

• Amine units; 

• Drilling operations; 

• Flares; 

• Fugitive emissions; 

• Glycol dehydrators; 

• Losses from flashing; 

• Mud degassing; 

• Pneumatic pumps; 

• Pressure and level controllers; and 

• Vents. 

The following non-platform operations are also estimated to have essentially constant and 

uniform operations. For the most part, the assumed uniform operation for these sources is based 

on information in the 1995 U.S. DOI MMS study: 

• Commercial marine vessels; 

• LOOP activities; 

• Military vessels; 

• Oceangoing barges; and 

• Survey and exploration vessels. 
7-3 

0.000.501.001.502.002.503.003.504.004.505.00

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 

Hour in Local Time

Percent of Emissions (%)

Figure 7-1. Diurnal Emission Curve for Sources of Constant Activity. 

Significant Sources of Constant Activity incluAmine Units Pressure/Level ContDrilling Equipment Vents Flares Commercial Marine Fugitives LOOP activities Glycol Dehydrators Military Vessels Losses from Flashing Oceangoing Barges Mud Degassing Survey and ExploratPneumatic Pumps 
7-4

Figures 7-2 and 7-3 represent diurnal emission curves for equipment groups that have 

slight diurnal variation: boilers/heaters/burners, internal combustion engines, and turbines. 

Diurnal curves are expressed as the percentage of total emissions that occur at each 1-hour 

interval for each emission source. 

Figure 7-4 presents the diurnal curve for source categories whose variation is 

temperature-driven throughout a 24-hour ozone season day: 

• Biogenic Ocean Processes 

• Loading Losses 

• Oil Seeps 

• Storage Tanks 

This curve is based on the fluctuation in average air and water temperature 

(recommended by COMM Engineering) in the GOM (NOAA 2001), as shown in Figure 7-5. 

Figure 7-6 presents the diurnal curve for two non-platform operations which average 21 

hours of operation per day. This information is based on an offshore operators committee 

survey, as summarized in the U.S. DOI MMS 1995 report. No further information was found for 

these operations. The curve assumes no significant activity between the hours of midnight and 

three a.m. This assumption is simply based on “engineering judgement.” 

• Helicopters 

• Support Vessels - Crew Boats, Supply Boats, Tugs, Barges

Table 7-1 presents the hourly data as a percent of total emissions for each equipment 

group, and a short explanation as to the data sources used to develop the pattern. Table 7-2 

presents the Source Classification Codes (SCCs) used to develop the curves from the EPA 

(2001) study. 
7-5 

0.000.501.001.502.002.503.003.504.004.505.00

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 

Hour in Local Time

Percent of Emissions (%)

Figure 7-2. Diurnal Emission Curve for Boilers/Heaters/Burners. 
7-6 

0.000.501.001.502.002.503.003.504.004.505.00

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 

Hour in Local Time

Percent of Emissions (%)

Figure 7-3. Diurnal Emission Curve For Natural Gas Turbines and Internal Combustion Engin
0.00

0.501.001.502.002.503.003.504.004.505.00

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 

Hour in Local Time

Percent of Emissions (%)

Figure 7-4. Diurnal Emission Curve for Temperature Dependent Activities. 

7-7 Temperature-Dependent Sources of Emissi

Biogenic Ocean Processes Loading Losses Oil Seeps Storage Tanks 
27.00

27.2527.5027.7528.0028.2528.5028.7529.0029.2529.5029.75

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Hour of Day (Local Time)

Temperature (C) 

Figure 7-5. Average Air and Water Temperatures for 17 Gulf of Mexico Buoys in August 20

7-8 
0.00

0.501.001.502.002.503.003.504.004.505.00

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 

Hour in Local Time

Percent of Emissions (%)

Figure 7-6. Diurnal Emission Curve for Helicopters and Support Vessels. 

7-9 
7-10

Table 7-1. Diurnal Emission Percentages for Activity Groups. 

1

 = Using information provided by MMS (1995), temporal profiles from U.S. EPA (2001), and by engineering judgement, 

 hourly emissions are assumed to be constant and uniform 2

 = Temporal profiles from U.S. EPA (2001) were used to calculate these percentages for boilers, heaters, and burners 3

 = Temporal profiles from U.S. EPA (2001) were used to calculate these percentages for natural gas turbines 4

 = Hourly temperature data were retrieved from NOAA to create a profile for sources dependent upon temperature 5

 = Using information provided by MMS (1995) and by engineering judgement, activities for these sources are assumed to 

 operate continuously from 4 a.m. to midnight

Percentage of Emissions (%) 

Hour 

(Local 

Time) 

Constant 

Activity 

Sources1

Boiler/Heater/ 

Burners2

Natural Gas 

Turbines 

and ICEs3

TemperatureDependent 

Sources4

Helicopters & 

Supply Vessels5

0 4.17 3.98 4.04 4.16 4.76 

1 4.17 3.89 3.98 4.15 0.00 

2 4.17 3.82 3.93 4.15 0.00 

3 4.17 3.79 3.91 4.14 0.00 

4 4.17 3.78 3.90 4.14 4.76 

5 4.17 3.80 3.92 4.13 4.76 

6 4.17 3.87 3.97 4.12 4.76 

7 4.17 3.98 4.04 4.11 4.76 

8 4.17 4.13 4.14 4.13 4.76 

9 4.17 4.21 4.20 4.14 4.76 

10 4.17 4.29 4.25 4.16 4.76 

11 4.17 4.35 4.29 4.17 4.76 

12 4.17 4.37 4.31 4.18 4.76 

13 4.17 4.39 4.32 4.19 4.76 

14 4.17 4.40 4.33 4.20 4.76 

15 4.17 4.42 4.34 4.21 4.76 

16 4.17 4.41 4.33 4.21 4.76 

17 4.17 4.40 4.33 4.21 4.76 

18 4.17 4.38 4.31 4.21 4.76 

19 4.17 4.34 4.29 4.19 4.76 

20 4.17 4.33 4.28 4.18 4.76 

21 4.17 4.31 4.27 4.17 4.76 

22 4.17 4.24 4.21 4.17 4.76 

23 4.17 4.11 4.13 4.16 4.76 
7-11 

Table 7-2. SCCs of Interest for Platform Operations (Diurnal Patterns). 

MMS Group 

Category SCC SCC DESCRIPTION 

3-10-002-01 Industrial Processes: Oil and Gas Production - Natural Gas Production, Gas Sweetening: Amine Proc

Amine Units 3-10-003-05 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Gas Sweeting: Ami

 1-01-006-01 External Combustion Boilers: Electric Generation - Natural Gas, Boilers > 100 Million Btu/hr except  1-01-006-02 External Combustion Boilers: Electric Generation - Natural Gas, Boilers < 100 Million Btu/hr except  1-01-006-04 External Combustion Boilers: Electric Generation - Natural Gas, Tangentially Fired Units  1-010-07-01 External Combustion Boilers: Electric Generation - Process Gas, Boilers > 100 Million Btu/hr  1-010-07-02 External Combustion Boilers: Electric Generation - Process Gas, Boilers < 100 Million Btu/hr  1-020-06-01 External Combustion Boilers: Industrial - Natural Gas, > 100 Million Btu/hr  1-020-06-02 External Combustion Boilers: Industrial - Natural Gas, 10-100 Million Btu/hr 

 1-020-06-03 External Combustion Boilers: Industrial - Natural Gas, < 10 Million Btu/hr 

Boilers/Heaters/ 1-020-06-04 External Combustion Boilers: Industrial - Natural Gas, Cogeneration 

Burners 1-020-07-01 External Combustion Boilers: Industrial - Process Gas, Petroleum Refinery Gas 

 1-03-006-01 External Combustion Boilers: Commercial/Institutional - Natural Gas, > 100 Million Btu/hr  1-030-06-02 External Combustion Boilers: Commercial/Institutional - Natural Gas, 10-100 Million Btu/hr  1-030-06-03 External Combustion Boilers: Commercial/Institutional - Natural Gas, < 10 Million Btu/hr  3-100-04-04 Industrial Processes: Oil and Gas Production - Process Heaters, Natural Gas  3-100-04-05 Industrial Processes: Oil and Gas Production - Process Heaters, Process Gas  3-100-04-14 Industrial Processes: Oil and Gas Production - Process Heaters, Natural Gas: Steam Generators  3-100-04-15 Industrial Processes: Oil and Gas Production - Process Heaters, Process Gas: Steam Generators 

3-100-01-22 Industrial Processes: Oil and Gas Production - Crude Oil Production, Drilling and Well Completion Drilling 3-100-02-22 Industrial Processes: Oil and Gas Production - Natural Gas Production, Drilling and Well Completion 3-100-01-60 Industrial Processes: Oil and Gas Production - Crude Oil Production, Flares 3-100-02-05 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flares 3-100-02-15 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flares Combusting Gases >10

Flares 

3-100-02-16 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flares Combusting Gases <10

 3-100-01-01 Industrial Processes: Oil and Gas Production - Crude Oil Production, Complete Well: Fugitive Emiss 3-100-01-24 Industrial Processes: Oil and Gas Production - Crude Oil Production, Valves: General  3-100-01-25 Industrial Processes: Oil and Gas Production - Crude Oil Production, Relief Valves 

Fugitives 3-100-01-26 Industrial Processes: Oil and Gas Production - Crude Oil Production, Pump Seals 

 3-100-01-27 Industrial Processes: Oil and Gas Production - Crude Oil Production, Ranges and Connections 
7-12 

Table 7-2. SCCs of Interest for Platform Operations (Diurnal Patterns). (Continued) 

MMS Group 

Category SCC SCC DESCRIPTION 

Fugitive (Continued) 3-100-01-30 Industrial Processes: Oil and Gas Production - Crude Oil Production, Fugitives: Compressor Seals 

3-100-01-31 Industrial Processes: Oil and Gas Production - Crude Oil Production, Fugitives: Drains 3-100-02-07 Industrial Processes: Oil and Gas Production - Natural Gas Production, Valves: Fugitive Emissions 

 3-10-002-02 Industrial Processes: Oil and Gas Production - Natural Gas Production, All Equipment Leak Fugitive

Connections, Seals, Drains) 

3-100-02-23 Industrial Processes: Oil and Gas Production - Natural Gas Production, Relief Valves 3-100-02-24 Industrial Processes: Oil and Gas Production - Natural Gas Production, Pump Seals 3-100-02-25 Industrial Processes: Oil and Gas Production - Natural Gas Production, Compressor Seals 3-100-02-26 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flanges and Connections 3-100-02-31 Industrial Processes: Oil and Gas Production - Natural Gas Production, Fugitives: Drains 3-100-03-06 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Process Valves 3-100-03-07 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Relief Valves 3-100-03-08 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Open-ended Lines 3-100-03-09 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Compressor Seals 3-100-03-10 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Pump Seals 3-100-03-11 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Flanges and Connec3-100-02-27 Industrial Processes: Oil and Gas Production - Natural Gas Production, Glycol Dehydrator Reboiler S3-100-02-28 Industrial Processes: Oil and Gas Production - Natural Gas Production, Glycol Dehydrator Reboiler B

 3-100-03-01 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

Triethylene Glycol 

 3-100-03-02 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

Triethylene Glycol 

Glycol Dehydrators 3-100-03-03 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

Triethylene Glycol 

 3-100-03-04 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

General 

 3-100-03-21 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

(Mich.) 

 3-100-03-22 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

Formation (Mich.) 

 3-100-03-23 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators

(Mich.) 

 3-100-01-32 Industrial Processes: Oil and Gas Production - Crude Oil Production, Atmospheric Wash Tank (2nd S

Separation): Flashing Loss 
7-13 

Table 7-2. SCCs of Interest for Platform Operations (Diurnal Patterns). (Continued) 

MMS Group 

Category SCC SCC DESCRIPTION 

Losses from Flashing 4-04-003-12 Petroleum and Solvent Evaporation: Petroleum Liquids Storage (non-Refinery) – Oil and Gas Field S

Tanks, Fixed Roof Tank, Crude Oil, working+breathing+flashing losses 

 4-04-003-22 Petroleum and Solvent Evaporation: Petroleum Liquids Storage (non-Refinery) – Oil and Gas Field S

Tanks, External Floating Roof Tank, Crude Oil, working+breathing+flashing 

 4-04-003-32 Petroleum and Solvent Evaporation: Petroleum Liquids Storage (non-Refinery) – Oil and Gas Field S

Tanks, Internal Floating Roof Tank, Crude Oil, working+breathing+flashing 

Natural Gas 

Turbines 2-010-02-01 Internal Combustion Engines: Electric Generation - Natural Gas, Turbine 

and ICEs 2-010-02-08 Internal Combustion Engines: Electric Generation - Natural Gas, Turbine: Evaporative Losses (Fuel D

2-010-02-09 Internal Combustion Engines: Electric Generation - Natural Gas, Turbine: Exhaust 2-02-002-01 Internal Combustion Engines: Industrial - Natural Gas, Turbine 2-02-002-03 Internal Combustion Engines: Industrial - Natural Gas, Turbine: Cogeneration 2-02-002-08 Internal Combustion Engines: Industrial - Natural Gas, Turbine: Evaporative Losses (Fuel Delivery S2-02-002-09 Internal Combustion Engines: Industrial - Natural Gas, Turbine: Exhaust 2-03-002-02 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine 2-03-002-03 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine: Cogeneration 2-03-002-04 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Cogeneration 2-03-002-05 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Reciprocating: Crankcase Blo

 2-03-002-06 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Reciprocating: Evaporative Lo

System) 

2-03-002-07 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Reciprocating: Exhaust 2-03-002-08 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine: Evaporative Losses (2-03-002-09 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine: Exhaust 
8-1

8. RESULTS 

8.1 SUMMARY OF STUDY APPROACH 

MMS’ Gulfwide Emission Inventory Study required an extensive inventory development 

effort. The study includes all oil and gas production platforms and non-platform sources in the 

entire Gulf of Mexico. Pollutants covered in the inventory are the criteria pollutants—CO, SOx, 

NOx, PM10, PM2.5, and VOC; as well as greenhouse gases—CO2, CH4, and N2O. 

MMS attempted to collect activity data from each and every active offshore oil 

production platform in the Gulf. Operators were provided with the GOADS Visual Basic 

activity data collection software for compiling monthly data for calendar year 2000. Nearly 

2,900 oil and gas production platforms submitted monthly equipment activity data files. The 

platform equipment surveyed includes: 

• Amine units; 

• Boilers/heaters/burners; 

• Diesel engines; 

• Drilling equipment; 

• Flares; 

• Flashing losses; 

• Fugitive sources; 

• Glycol dehydrators; 

• Loading operations; 

• Mud degassing; 

• Natural gas engines; 

• Natural gas turbines; 

• Pneumatic pumps; 

• Pressure/level controllers; 

• Storage tanks; and 

• Vents. 

Non-platform sources covered in the inventory are: 

• Biogenic/geogenic sources; 

• Commercial fishing; 

• Commercial marine vessels; 

• Drilling rigs; 

• The Louisiana Offshore Oil Platform (LOOP); 

• Military vessel operations; 

• Pipe laying operations; 

• Platform construction and removal vessels; 

• Support helicopters; 

• Support vessels; 
8-2

• Survey vessels; and 

• Vessel lightering. 

Rigorous QA/QC was performed on the activity data collected from platform operators. 

Tasks were implemented to correct the number of operating hours provided for a given month, 

fill in missing monthly operating data (if equipment was operational), verify and correct activity 

values such as fuel heating value, make sure that the equipment shown to be vented included a 

vent ID and activity record, fill in missing stack parameters with surrogates, and double check 

exit velocity and fuel usage totals by recalculating the parameters. The monthly activity data 

collected from the platform operators were then combined with emission factors and algorithms 

to develop the platform production equipment emission estimates. 

Inventory data files were compiled with the oil and gas production platform data, suitable 

for use in air quality modeling applications. In addition to monthly emission estimates by 

pollutant and individual piece of equipment, the files include the company, structure, and 

complex ID, lease number, block and area number, and latitude/longitude. For each piece of 

equipment, stack parameter information such as outlet height, exit velocity, and exit temperature 

is also presented. 

ERG compiled base year 2000 activity data and developed emission estimates for nonplatform sources in the Gulf. For the most part, the emission factors used to calculate the 

emissions from all of the engines for these sources were obtained from the EPA’s Office of 

Transportation and Air Quality (OTAQ) in Ann Arbor, Michigan. OTAQ published the 

emission equations along with their Diesel Marine Vessel Rule in 2002. The resulting emission 

estimates are also disaggregated to MMS lease blocks. 

8.2 PRESENTION OF ANNUAL EMISSION ESTIMATES

The platform and non-platform emission estimates developed for criteria pollutants and 

greenhouse gases are presented in Tables 8-1 through 8-19. For an overview of the results, Table 

8-1 summarizes the total platform criteria pollutant emission estimates, Table 8-2 summarizes 

the total non-platform criteria pollutant emission estimates, and Table 8-3 presents the combined 

platform and non-platform criteria pollutant estimates. To facilitate more detailed review, Tables 

8-4 through 8-9 present platform emission estimates by pollutant. Tables 8-10 through 8-17 

present platform emission estimates by type of equipment. The greenhouse emission estimates 

are provided in Tables 8-18 and 8-19. 

8.3 LIMITATIONS 

As with the development of any inventory of activity data or emission estimates, the 

accuracy can vary considerably depending upon the accuracy of the activity data obtained and 

the emission factors used. The key limitation and source of uncertainty associated with OCS 

oil/gas production platform inventory effort pertains to the completeness of the platform activity 

data gathered and used to develop emission estimates. It is difficult to confirm that all affected 

lessees and operators of federal oil, gas, and sulfur leases in the Gulf of Mexico OCS region 

provided GOADS files to MMS as required. It is also difficult to track active versus inactive 
8-3

platforms on an annual basis. For example, operators were told to submit records for “satellite” 

platforms that have no emission sources on them. There may have been no equipment activity 

data records associated with these platforms, but MMS records show the platform as active in 

2000. Platform ownership changes make it difficult to track month-to-month completeness. 

At the equipment level, there is no way of knowing how well the operators understood 

what activity data were being requested. For example, losses from flashing occur at all points 

where an oil stream undergoes a pressure drop. Operators were asked to determine all sources of 

flash gas that are vented or flared. Each point of separation/treatment had to be examined as a 

potential source of flash gas. Flash gas can be vented to the atmosphere or burned in flares from 

the following equipment: high, intermediate, and low-pressure separators; heater treaters; surge 

tanks; accumulators; and fixed roof atmospheric storage tanks. It is believed that emissions from 

flashing are underestimated because operators did not completely report the sources. 

In addition, some emission estimates were developed based on the use of surrogates if the 

actual data needed to estimate emissions were not provided directly. Uncertainty is introduced 

when the survey respondent lacks an understanding of the data request or incorrectly interprets 

the data request, and when conflicting survey data are reviewed and adjusted for use in 

developing emission estimates. Typographical data entry errors also probably occurred in the 

monthly activity data that were not identified by the equipment survey consistency or data range 

checks discussed in Section 4 of this report. 

This project included the development of two software programs; the GOADS software 

to gather OCS oil and gas production platform activity data, and the DBMS software to calculate 

air emissions based on this activity data and current emission factors. In a recent review of the 

draft GOADS 2000 inventory, a discrepancy was noticed between reported GOADS venting and 

flaring activity data and the vented and flared gas volumes reported on the Oil and Gas 

Operations Report (OGOR), Form MMS-4054. Based on an extensive quality control of records 

for several platforms, the GOADS software used to collect activity data was adjusted to improve 

flaring and venting volume estimates in the GOADS inventory. The adjustments to the software 

resulted in considerably more accurate accounting of flaring and venting volumes, and volumes 

closer to the OGOR values. The emissions from these sources in the GOADS inventory may 

still be higher than actual values, however. MMS has made several modifications to the GOADS 

software to reduce these errors in the future. The software has been modified to simplify the data 

requested each month to only the equipment variables that change monthly. This will reduce 

data entry volume, processing time, and the likelihood of data entry errors. 

The estimates for some non-platform source categories such as support vessels and naval 

operations were based on adjustments made to activity data that were included in the Gulf of 

Mexico Air Quality Study (GMAQS) (U.S. DOI, MMS 1995). Much of the non-platform activity 

data used in the 1995 study were derived from a 1992 Survey of Offshore Operators undertaken 

by the Offshore Operators Committee (OOC). This 1992 report contains useful information, and 

it would have been helpful if a similar study could have been performed for this 2000 inventory 

effort. 
8-4

In addition, most of the non-platform sources are powered by marine diesel engines. In 

this study, marine diesel emission factors were developed using recent EPA emission equations 

derived from a large number of “in use” vessel test data. These emission equations require 

horsepower and operating load factors. Typical horsepower and load factors were obtained from 

the GMAQS. These values are averages, such that actual emissions from specific vessels may be 

significantly different. These averages lend uncertainty to the estimates for drill ships and 

pipelaying operations, among others. It should also be noted that the activity data used to 

estimate emissions from survey vessels were only for surveys implemented at non-active lease 

blocks. Survey activity for active lease blocks is considered confidential and not tracked by 

MMS; therefore actual Gulfwide survey vessel activity will be larger than the activity quantified 

in this inventory. 

8.4 RECOMMENDATIONS 

Based on the limitations discussed above, recommendations for future inventory efforts 

for platform sources in the Gulf of Mexico focus on the data gathering tools used. The 

uncertainty associated with the flashing, vent, and flare emission estimates is due to the 

interpretation of the data requested by the operators. Plans are already in place to improve the 

GOADS software for these equipment types. In addition, an overall improvement will be made 

to the software to simplify the data requested each month to only the equipment variables that 

change monthly. This will reduce data entry volume, processing time, and the likelihood of data 

entry errors. 

Improvements in the data collection software, continued operator education and training, 

use of the MMS web site to post Frequently Asked Questions (FAQs), and increased efforts to 

identify companies that need to respond to the data request will reduce much of the uncertainty 

associated with future inventory efforts. 

For non-platform sources, the following recommendations are provided to improve the 

accuracy of the emission estimates or enhance the spatial allocation of the estimates. These 

suggestions are provided by source category in order of significance relative to total emissions. 

• Implementation of Support Vessels Survey - Implementation of a survey of marine 

vessels supporting offshore oil platforms can provide important data that would allow 

for the development of a more accurate estimate of emissions from these vessels. 

This support vessel survey could collect detailed information about vessel size, 

horsepower rating, and typical operating loads, as well as annual and seasonal 

activity. This information could be used to update the OOC’s survey performed in 

1992 for the GMAQS. The new survey vessel inventory could be used to develop 

emission estimates in terms that can be readily applied to state-of-the-art geographic 

information system (GIS) tools to spatially allocate emissions with greater accuracy. 

• Development of Drill Ship Database - Currently, MMS collects very specific data 

on where specific drill ships operate and the length of time they spend at a given site. 

In the Gulfwide inventory, the average horsepower and load data were used to 

estimate emissions from these sources. Some vessels may be significantly larger or 
8-5

smaller than these average values, however, such that actual emissions may differ 

significantly from the estimated emissions. A drill ship database could contain 

information about vessel size, the number and horsepower of the primary propulsion 

engine and ancillary engines, and better estimates on typical operating loads. This 

database could be linked up with MMS’s drill ship-specific activity data and available 

emission factors to provide more accurate emission estimates. 

• Implementation of Pipelaying Survey – MMS maintains an excellent GIS file of 

pipelaying construction and maintenance activities which is very useful in assigning 

emissions to appropriate lease blocks. The emission estimates that have been 

developed for the Gulfwide inventory for this source category are based on many 

assumptions that were carried over from the GMAQS, particularly regarding the 

number of vessels needed for pipeline construction and maintenance and the 

horsepower rating and typical load of the primary propulsion and ancillary engines. 

Emission estimates can be improved upon by updating these assumptions through 

interviews with companies involved in these activities. 

• Platform Construction and Removal Vessels – The current approach to estimating 

emissions associated with the construction and removal of offshore oil platforms is 

based on the number of pilings that a platform has and the ocean depth at the 

platform. These data are not readily available and the data set developed for this 

source category in the Gulfwide inventory is not complete. Approximately 20 

percent of the data do not include the number of platform pilings; for these cases, a 

surrogate was developed that is based on the number of floors associated with a given 

platform. There is also a concern that piling drilling associated with platform 

construction is not included in the emission estimates. An emission estimation 

approach needs to be developed to account for drilling associated with platform 

construction, or to determine if the drilling emissions are already associated with the 

drill ships category. It is important to insure that these drilling estimates do not 

double count with emission estimates for the drill ship source category. There is a 

similar concern of double counting with support vessels that may be involved with 

the construction or removal of platforms. To resolve these issues it will be necessary 

to study this source category more fully and meet with staff from companies involved 

with these activities. 

• Implementation of Survey Vessel Survey - MMS maintains excellent records of 

survey vessel activity; the problem is that these records are only required for nonactive lease blocks. Survey activities related to active lease blocks are considered 

confidential information and are not tracked by MMS. It should be pointed out that 

there are a relatively small number of survey vessels operating in the Gulf. In order 

to develop an estimate of survey activities associated with active lease blocks, it is 

necessary to survey the companies that provide geophysical surveying services to 

estimate annual operating hours (excluding activities in the Eastern Gulf area, state, 

and international waters) and typical operating loads to develop a Gulfwide estimate 

for this source category. Survey vessel activity and emissions associated with the 

non-active lease blocks can be removed from the Gulfwide estimate to approximate 
8-6

emissions in the active lease blocks. These emissions can be applied equally to the 

active lease blocks based on a surrogate, such as surface area, in order to maintain the 

confidentiality of these data, while still providing complete emission estimates for 

this source category. 

• Development of Military Vessel Database - As noted in this report, obtaining 

detailed data from the military can sometimes be very difficult. In the current 

inventory, emission estimates for the Navy are based on conservative estimates of the 

amount of time vessels operate in the Gulf; actual emissions may be significantly 

lower than these estimates. Unfortunately, the Navy did not provide any additional 

information to adjust these estimates to more accurately reflect actual emissions. 

It is recommended that a database be developed with all of the data required to 

estimate emissions and spatially and temporally adjust these estimates to represent 

activity in the Gulf. The database could include assumptions about the current vessel 

fleet operating in the Gulf, the horsepower of the primary and ancillary engines of 

each vessel, typical operating loads, and estimates of seasonal and annual hours of 

operation, as well as information concerning the geographic area where these vessels 

typically operate. This database could be shared with the Navy and Coast Guard, and 

they hopefully would update it with their own, more accurate data and submit it to 

MMS for inclusion in the Gulfwide inventory. 

• Implementation of Support Helicopter Survey - As with support vessels, 

implementation of a detailed survey of support helicopters that service offshore oil 

platforms would allow for better quantification of the types of helicopters currently 

used, a better estimate of the hours of operation, as well as information to help 

spatially distribute estimated emissions. The data obtained from such a study should 

be compiled in a format compatible with GIS data files associated with the current 

inventory. 

• Incorporation of New Biogenic/Geogenic Data - Biogenic/geogenic studies 

continue to be developed, particularly with regard to greenhouse gas emissions. 

Much of these data are site specific or provided in terms that do not easily convert 

into typical emission factors. Still, it is important to incorporate the latest emissions 

data to better quantify these emission sources and evaluate associated emission sinks. 

Particular attention should be placed on development of spatially allocated emission 

estimates using the latest GIS tools to more accurately define the location of these 

significant emission sources. This will probably require evaluating satellite remote 

sensing data or space shuttle photographs. 

8.5 COMPARISON WITH OTHER STUDIES 

At the completion of any emissions inventory effort, one final, useful QA/QC check is to 

compare the inventory results with those from similar inventories. The most applicable 

inventory to compare the results presented here is the GMAQS (U.S. DOI, MMS 1995). The 

GMAQS was developed for sources in the OCS and state waters, and included oil and gas 
8-7

production facilities, crew and supply boats and helicopters, recreational and commercial 

shipping, pipeline vessels, military vessels, inter-coastal barges, and the LOOP. 

8.5.1 OCS Oil and Gas Production Platforms 

For OCS oil and gas production platforms, survey forms were designed to solicit the data 

needed to estimate emissions. The resulting platform database had information for 1,855 

platforms (U.S. DOI, MMS 1995). The Gulfwide Study discussed in this report included 2,873 

platforms, an increase of 55%. For CO, emissions reported in this study increased four-fold, 

primarily because of natural gas engines. Emission did not show an increase for all pollutants, 

however. For VOC, emissions in the Gulfwide Study are slightly lower than in the GMAQS. 

The two studies have a similar number of boiler, diesel and natural gas engine, and natural gas 

turbine units (irrespective of the increased number of platforms included), but emissions of NOx

and PM are higher in the GMAQS, as shown in Table 8-20. Emissions of SOx decreased 

significantly in the Gulfwide Study primarily due to the amine unit estimates. 

Table 8-21 presents a summary of emission factors used to estimate fuel combustion 

emissions in both studies. The higher natural gas engine emission factor accounts at least in part 

for the increased CO emissions. The primary sources of NOx and PM in both studies are 

boilers/heaters/burners, diesel engines, natural gas engines, and natural gas turbines. As noted 

above, the number of fuel combustion units included in the two studies are similar, even though 

55% more platforms reported in the Gulfwide study. Aside from the reported activity data for 

each equipment type, a review of the emission factors used in each study provides a good 

indication of why NOx and PM emissions are lower in the current study. Estimates for both 

studies were developed based on AP-42 emission factors (EPA 2002), but the emission factors 

have been changed for natural gas engines and natural gas turbines. For example, the average 

NOx emission factor for natural gas engines is 50% lower than the factor applied in the GMAQS. 

The contribution of natural gas engines to total NOx emissions accounts for a large portion of the 

decrease in emissions compared to the GMAQS. In addition, the PM emission factor is 65% 

lower for natural gas engines. 

The discrepancy in the SOx estimates, almost entirely because of the amine unit 

estimates, is not so clearly understood; however, as discussed in Section 5 of this report, the 

emission estimates in the current study were developed using operator-supplied data and the Gas 

Technology Institute’s AMINECalc program (GTI 2001). The level of confidence in these 

results is quite high. 

8.5.2 Non-Platform Sources 

This Gulfwide Study non-platform inventory built upon the GMAQS inventory such that 

many of the assumptions made in the earlier inventory were used in this study, especially with 

regard to typical vessel horsepower and operating load, seasonal variation, and hours of 

operation. However, the Gulfwide Study estimates were based on more recent emission factors, 

and activity data specific to 2000. 
8-8

Table 8-22 compares the GMAQS and 2000 Gulfwide Study non-platform emission 

estimates for individual source categories. In many cases, the difference between the GMAQS 

estimates and those in the Gulfwide Study are due to the use of different marine diesel emission 

factors. The GMAQS was based on older EPA AP-42 emission factors, while the Gulfwide 

Study estimates were based on the marine diesel emission factors derived from regression 

analysis performed on recent marine diesel emissions testing data. These new emission factors 

were recently developed to support the EPA’s new marine diesel rule making. The new emission 

factors tend to be significantly higher for NOx and CO, and in many cases, though not all, lower 

for VOC, than those that are reported in the AP-42 (EPA 2002). The situation for VOCs is 

further complicated because it is unclear how the hydrocarbon estimates in the GMAQS were 

converted to represent VOC estimates. 

Much of the activity data developed for non-platform sources in the GMAQS were 

derived from a survey implemented by the OOC. The data collected during the survey is 

reasonably helpful in quantifying the fleet composition and activity of several hard to quantify 

emission sources, such as support vessels and helicopters. When better data were not available, 

the 1992 survey data were adjusted to approximate activity in 2000. 

For most of the other source categories it is particularly difficult to discern what activity 

data were used in the GMAQS, as the results are rarely summarized in a fashion that facilitates 

comparisons. Emission comparisons between the two studies are discussed below in greater 

detail for each non-platform source category. 

• Survey Vessels/Drilling Vessels - In this study, this source category is disaggregated 

into two categories. The estimates were combined in Table 8-22 to be comparable 

with the estimates in the GMAQS. The biggest difference between these two studies 

for this source category concerns the VOC emission estimates. Much of the 

difference can be accounted for due to the use of different emission factors. For 

example, the VOC emission factor used in the Gulfwide Study is 37% lower for 

survey vessels, 13% lower for drill ships, 45% lower for jack-ups, and 17% lower for 

semisubmersibles than the factors used in the GMAQS. The remainder of the 

difference is probably due to differences in activity data. Unfortunately, it was not 

possible to directly compare the data used in the two studies, but it appears that the 

GMAQS included activities occurring in state waters; these were excluded from the 

2000 Gulfwide Study area. 

• Support Vessels - In both inventories, support vessels included supply vessels, tugs, 

and barges. The NOx and CO emissions were significantly higher in the current 

study, while VOC was slightly lower. The vessel population used in the Gulfwide 

Study is 17% higher than the vessel population reported in the GMAQS. This 

adjustment was made to reflect the increase in the number of active oil platforms 

between 1992 and 2000 and the associated need for additional support vessels. This 

adjustment accounts for some of the NOx and CO increase in the 2000 inventory. The 

newer emission factors for NOx and CO are significantly larger than the factors used 

in the GMAQS. For example, for supply boats, NOx emission factors used in the 

Gulfwide Study are approximately 160% higher and CO emission factors are 85% 
8-9

higher than those used in the GMAQS. It is important to realize that supply boats 

represent approximately 60% of the support vessel fleet. The remaining difference 

between the two studies probably is due to the use of different activity data. In the 

GMAQS, emissions were estimated based on fuel usage as provided by the OOC. 

For the Gulfwide Study, emissions are estimated based on hours of operation, which 

used the assumption noted in the GMAQS that the vessels typically operate 21 hours 

per day. This assumption does not account for periods of time when the support 

vessels are in port for normal maintenance or due to inclement weather, such that the 

Gulfwide Study activity may overestimate actual emissions. 

• Support Helicopters - The support helicopter emission estimates in the Gulfwide 

Study is significantly higher than the estimates in the GMAQS. The Gulfwide Study 

estimates are based on more recent helicopter emission factors that tend to be 

significantly higher than the factors used in the GMAQS. For example, the average 

VOC emission factor used in the Gulfwide Study is 315% higher; the average NOx

emission factor is 950% higher, and the average CO emission factor is 548% higher 

than the average factors used in the GMAQS. A more detailed assessment is not 

possible at this time as the GMAQS documentation did not include information 

showing how the helicopters in the 1995 activity dataset were matched to the 

helicopters which had emission factors. Some of the difference between the two 

studies may also be due to increased helicopter activity between 1992 and 2000. 

Unfortunately, it is difficult to compare the activity data used in the GMAQS with 

that used in the Gulfwide Study, as summary information is not provided in the 

GMAQS report. 

• Pipelaying Vessels - One of the six vessels used in typical pipelaying activities was a 

supply vessel, which was already accounted for in the supply vessel source category. 

Therefore the typical number of vessels used to lay pipe was reduced to avoid double 

counting. This would account for a decline of approximately 15% of the difference 

between the two inventories. Most of the remaining difference between the data in 

the GMAQS and the Gulfwide Study are due to use of different emission factors. For 

example, the VOC emission factor used in the Gulfwide Study is 73% less than the 

factor used in the GMAQS. 

• LOOP - Emission estimates for all pollutants are lower in the Gulfwide Study 

inventory, significantly lower for NOx, despite the fact that the number of vessels 

visiting the LOOP in 2000 was 275, which is roughly similar to the number of vessels 

used in the GMAQS (265). The difference may be explained partially due to the use 

of different emission factors in conjunction with different hours of operation. The 

current study used vessel-specific hours of operation, which were 40% less than the 

hours of operation assumed in the GMAQS. 

• Fishing - Emissions associated with commercial fishing operations are lower in the 

Gulfwide Study. Much of this may be explained by the fact that the GMAQS 1995 

fishing emission estimates included inshore shrimp, oyster, crab, and miscellaneous 

fin-fishing activities that are not included in the Gulfwide Study, as they occur within 
8-10

state waters. Given the different geographical range of the two studies, it is not 

surprising that the GMAQS emission totals for this source category are significantly 

larger than the Gulfwide Study estimates. Shallow water commercial fishing 

operations use a variety of marine gasoline and diesel engines, while offshore 

commercial fishing operations primarily use diesel powered vessels. It should be 

noted that gasoline engines tend to emit significantly more VOC and CO, particularly 

two-stroke gasoline engines, than marine diesel engines. In developing the Gulfwide 

Study, it was determined that the majority of recreational fishing occurs within state 

waters and therefore are not included in the 2000 inventory. The amount of 

recreational fishing that occurs in federal waters could not be quantified, but it was 

assumed to be small. The GMAQS did quantify recreational fishing, but the 

estimates are not included in this comparison in order to get a more accurate source 

category match between the two inventory efforts. 

• Military Vessels - A considerable amount of resources were devoted early in this 

inventory development effort to update the military vessel emission estimates. This 

was anticipated to be a very challenging task, as military agencies tend not to provide 

appropriate data to estimate vessel emissions, if they provide any data at all. For this 

Gulfwide Study inventory, the Coast Guard provided very useful data that supported 

development of ship-specific emission estimates for the Gulf fleet. In the GMAQS, 

emission estimates for Coast Guard activities were not included, which accounts for 

part of the increase in emissions for this source category. Despite repeated attempts 

to get accurate activity data from the naval fleet operating in the Gulf, the Navy did 

not provided any data to estimate emissions. The data that were developed in the 

GMAQS were applied to the latest EPA marine diesel emission factor to get hourly 

emission factors. As the Navy did not provide activity data, it was assumed that the 

naval fleet operating in the Gulf operated 8760 hours per year. This is likely an 

overestimate of Gulf activities, but without assistance from the Navy it was not 

possible to accurately discern the composition of the fleet and actual hours of 

operation. Residual-fueled vessel emission estimates are developed using available 

fuel-based emission factors. The gas turbine emission factors were recently updated 

in EPA’s AP-42 due to extensive testing associated with the development of EPA’s 

gas turbine regulatory standard. These new gas turbine emission factors are also 

provided in terms of fuel usage. Note, both the residual-fueled vessels and the gas 

turbine-powered vessels account for a relatively small portion of the naval fleet and 

emissions. 

• Commercial Marine Vessels - All pollutant emissions for commercial marine 

vessels were significantly lower in the 2000 Gulfwide Study. Some of this can be 

accounted for by the fact that the GMAQS seems to include all commercial marine 

vessel activity, including those occurring in state waters. This is a particularly 

significant addition, as state waters include traffic along the inter-coastal waterway 

and vessel traffic entering and leaving the Mississippi delta. Based on the Army 

Corps of Engineer’s data, traffic within state waters account for over 50% of the total 

activity in the Gulf. The GMAQS commercial marine vessel activity data may also 

have included shipping traffic associated with the Eastern Gulf. Table 8-23 provides 
8-11

a comparison of the data with 2000 Gulfwide Study estimates in federal OCS 

production waters (i.e., Western and Central Gulf areas) and an estimate using the 

Gulfwide Study methodology for shipping traffic in the Eastern Gulf and state waters. 

Also included in Table 8-23 are emission estimates developed for oceangoing and 

coastal vessels obtained from Corbett and Fischbeck (2000). These national estimates 

were adjusted to approximate Gulf emissions by taking into consideration that 37% of 

the cargo tonnage is handled in the Gulf as documented in a U.S. Maritime 

Administration Office of Statistical and Economic Analysis report entitled U.S. 

Vessel Calls at U.S. Ports – 2000 (U.S. Maritime Administration 2002). Note the 

Corbett study used older AP-42 emission factors, similar to those used in GMAQS. 
8-12

Table 8-1. Total Platform Emission Estimates for Criteria Pollutants. 

Equipment 

CO 

Emissions 

(tpy) 

NOx

Emissions 

(tpy) 

PM10

Emissions 

(tpy) 

PM2.5

Emissions 

(tpy) 

SOx 

Emissions 

(tpy) 

VOC 

Emissions 

(tpy) 

Amine Units 0 0 0 0 2,100 1 

Boilers/heaters/ 

Burners 

511 446 29 29 2 21 

Diesel Engines 894 4,043 194 193 143 217 

Drilling 

Equipment 

7,759 9,783 176 173 1,197 487 

Flares 471 90 2 0 1 8 

Fugitives 0 0 0 0 0 29,826 

Glycol 

Dehydrators 

0 0 0 0 0 2,572 

Loading Losses 0 0 0 0 0 7 

Losses From 

Flashing 

0 0 0 0 0 3,625 

Mud Degassing 0 0 0 0 0 353 

Natural Gas 

Engines 

80,679 56,546 241 241 17 1,542 

Natural Gas 

Turbines 

1,830 7,141 147 147 12 47 

Pneumatic Pumps 0 0 0 0 0 2,316 

Pressure/level 

Controllers 

0 0 0 0 0 990 

Storage Tanks 0 0 0 0 0 5,627 

Vents 0 0 0 0 0 11,897 

Total Emissions 

(tpy) 92,144 78,049 789 783 3,472 59,536 
8-13

Table 8-2. Total Non-Platform Emission Estimates for Criteria Pollutants.

Source Category 

CO 

Emissions 

(tpy) 

NOx

Emissions 

(tpy) 

PM10

Emissions 

(tpy) 

SO2

Emissions 

(tpy) 

VOC 

Emissions 

(tpy) 

Drilling Rigs 2,147 20,453 508 3,440 197 

Helicopters 6,060 1,438 107 177 2,285 

Pipelaying Vessels 1,408 13,416 333 2,257 129 

Platform Construction 

and Removal Vessels 284 2,257 56 384 29 

Support Vessels 7,314 56,660 1,415 9,680 757 

Survey Vessels 15 151 4 25 1 

Total OCS Oil/Gas 

Production Sources (tpy) 17,228 94,375 2,423 15,963 3,400 

Biogenic/geogenic 

Sources 13,561 

Commercial Marine 

Vessels 1,936 19,487 498 3,545 182 

Fishing Vessels 150 1,519 38 255 13 

LOOP 294 1,159 31 204 646 

Military Vessels 361 3,674 103 774 33 

Vessel Lightering 1,190 5,086 134 2,547 7,639 

Total Non-OCS Oil/Gas 

Production Sources (tpy) 3,931 30,925 804 7,325 22,074 

Total Non-Platform 

Emissions (tpy) 21,159 125,300 3,227 23,288 25,472 
8-14

Table 8-3. Total Platform and Non-Platform Emission Estimates for Criteria Pollutants.

Equipment/Source 

Category 

CO 

Emissions 

(tpy) 

NOx

Emissions 

(tpy) 

PM10

Emissions 

(tpy) 

SO2

Emissions 

(tpy) 

VOC 

Emissions 

(tpy) 

Total Platform 

Emissions 92,144 78,049 789 3,472 59,536 

Drilling Rigs 2,147 20,453 508 3,440 197 

Helicopters 6,060 1,438 107 177 2,285 

Pipelaying Vessels 1,408 13,416 333 2,257 129 

Platform Construction 

and Removal Vessels 284 2,257 56 384 29 

Support Vessels 7,314 56,660 1,415 9,680 757 

Survey Vessels 15 151 4 25 1 

Total OCS Oil/Gas 

Production Source 

Emissions 109,372 172,424 3,212 19,435 62,934 

Total Non-OCS Oil/Gas 

Production Source 

Emissions 3,931 30,925 804 7,325 22,074 

Total Emissions (tpy) 113,303 203,349 4,016 26,760 85,008 
8-15

Table 8-4. Annual CO Emission 

Estimates for Platform Sources. 

Equipment CO Emissions (tpy) 

Natural Gas Engines 80,679 

Drilling Equipment 7,759 

Natural Gas Turbines 1,830 

Diesel Engines 894 

Boilers/heaters/burners 511 

Flares 471 

Total Emissions (tpy) 92,144 

Table 8-5. Annual NOx Emission 

Estimates for Platform Sources. 

Equipment NOx Emissions (tpy)

Natural Gas Engines 56,546 

Drilling Equipment 9,783 

Natural Gas Turbines 7,141 

Diesel Engines 4,043 

Boilers/heaters/burners 446 

Flares 90 

Total Emissions (tpy) 78,049 

Table 8-6. Annual PM10 Emission Estimates 

for Platform Sources. 

Equipment PM10 Emissions (tpy)

Natural Gas Engines 241 

Diesel Engines 194 

Drilling Equipment 176 

Natural Gas Turbines 147 

Boilers/heaters/burners 29 

Flares 2 

Total Emissions (tpy) 789 
8-16

Table 8-7. Annual PM2.5 Emission 

Estimates for Platform Sources. 

Equipment PM2.5 Emissions (tpy)

Natural Gas Engines 241 

Diesel Engines 193 

Drilling Equipment 173 

Natural Gas Turbines 147 

Boilers/heaters/burners 29 

Total Emissions 783 

Table 8-8. Annual SOx Emission 

Estimates for Platform Sources. 

Equipment 

SOx Emissions 

(tpy) 

Amine Units 2,100 

Drilling Equipment 1,197 

Diesel Engines 143 

Natural Gas Engines 17 

Natural Gas Turbines 12 

Boilers/heaters/burners 2 

Flares 1 

Total Emissions (tpy) 3,472 

Table 8-9. Annual VOC Emission 

Estimates for Platform Sources. 

Equipment VOC Emissions (tpy) 

Fugitives 29,826 

Vents 11,897 

Storage Tanks 5,627 

Losses From Flashing 3,625 

Glycol Dehydrators 2,572 

Pneumatic Pumps 2,316 

Natural Gas Engines 1,542 

Pressure/Level Controllers 990 

Drilling Equipment 487 

Mud Degassing 353 

Diesel Engines 217 

Natural Gas Turbines 47 

Boilers/heaters/burners 21 

Loading Losses 7 

Flares 8 

Amine Units 1 

Total Emissions (tpy) 59,536 
8-17

Table 8-10. Annual Emission Estimates for Amine Units. 

Pollutant Emissions (tpy) 

SO2 2,100 

VOC 1 

Table 8-11. Annual Emission Estimates for Boilers/Heaters/Burners. 

Pollutant Emissions (tpy) 

CO 511 

NOX 446 

PM10 29 

PM2.5 29 

SOx 2 

VOC 21 

Table 8-12. Annual Emission Estimates for Diesel Engines. 

Pollutant Emissions (tpy) 

CO 894 

NOX 4,043 

PM10 194 

PM2.5 193 

SOX 143 

VOC 217 

Table 8-13. Annual Emission Estimates for Drilling Equipment. 

Pollutant Emissions (tpy) 

CO 7,759 

NOX 9,783 

PM10 176 

PM2.5 173 

SOX 1,197 

VOC 487 
8-18

Table 8-14. Annual Emission Estimates for Flares. 

Pollutant Emissions (tpy) 

CO 471 

NOX 90 

PM10 2 

SOX 1 

VOC 8 

Table 8-15. Annual Emission Estimates for Natural Gas Engines. 

Pollutant Emissions (tpy) 

CO 80,679 

NOX 56,546 

PM10 241 

PM2.5 241 

SOX 17 

VOC 1,542 

Table 8-16. Annual Emission Estimates for Natural Gas Turbines. 

Pollutant Emissions (tpy) 

CO 1,830 

NOX 7,141 

PM10 147 

PM2.5 147 

SOX 12 

VOC 47 

Table 8-17. Annual Emission Estimates for Vents. 

Pollutant Emissions (tpy) 

H2S 3 

VOC 11,897 
8-19

Table 8-18. Total Greenhouse Gas Emission Estimates for Platform 

Sources.a

Equipment Types 

CH4 Emissions 

(tpy) 

CO2 Emissions 

(tpy) 

N2O Emissions 

(tpy) 

Amine Units 18 0 0 

Boilers/heaters/burners 9 741,563 9 

Diesel Engines 5 168,906 N/Ab

Drilling Equipment 69 508,714 N/A 

Flares 159 290 0 

Fugitives 107,141 0 0 

Glycol Dehydrators 11,400 0 0 

Lossing From Flashing 79,756 1,812 0 

Mud Degassing 1,836 7 0 

Natural Gas Engines 15,112 3,377,352 N/A 

Natural Gas Turbines 192 2,454,703 67 

Pneumatic Pumps 15,480 298 0 

Pressure/level Controllers 11,796 217 0 

Vents 330,780 7,047 0 

Total Emissions (tpy) 573,753 7,260,909 76 

a

 Emission factors for these pollutants were not available for loading losses and 

storage tanks. 

b N/A = not available. 

Table 8-19. Total Greenhouse Gas Emission Estimates for 

for Non-Platform Sources.a 

Category 

CO2 Emissions 

(tpy) 

N20 Emissions 

(tpy) 

Biogenic/Geogenic Sources 0 1,948 

Commercial Marine Vessels 1,258,433 N/A 

Drilling Rigs 1,359,432 N/A 

Fishing Vessels 100,599 N/A 

LOOP 80,377 N/A 

Military Vessels 241,742 N/A 

Pipelaying Vessels 891,699 N/A 

Platform Construction and Removal Vessels 151,629 N/A 

Support Helicopters 130,077 N/A 

Support Vessels 3,814,905 N/A 

Survey Vessels 9,975 N/A 

Vessel Lightering 350,196 N/A 

Total Emissions (tpy) 8,389,064 1,948 

a CH4 emissions were not estimated for non-platform sources. 

N/A = not available.
8-20

Table 8-20. Comparison of OCS Platform Emission Estimates. 

1995 GMAQS 2000 Gulfwide Study 

NOx 

(tpy) 

SOx 

(tpy) 

TSP 

(tpy) 

CO 

(tpy) 

VOC 

(tpy)a

NOx

(tpy) 

SOx 

(tpy) 

PM10

(tpy) 

CO 

(tpy) 

VOC 

(tpy) 

94,483 15,869 1,720 21,988 80,374 78,049 3,472 789 92,144 59,536 

a VOC estimate is based on U.S. DOI MMS (1995) THC value, adjusted for vented % CH4

Table 8-21. Comparison of OCS Platform Fuel Combustion Emission Factors. 

1995 GMAQS 2000 Gulfwide Study Equipment 

Type NOx SOx TSP CO THC NOx SOx PM10 CO VOC 

Natural Gas 

Engines 

a

(lb/MMBtu)

2.71 2.86E-04 3.33E-02 5.90E-01 1.24 1.41 5.88E-04 1.20E-02 1.32 9.75E-02

Diesel 

Engines 

<600 hp 

(lb/1000 gal)

604 40 43 130 49 604.30 N/A 42.48 130.18 45.22 

Diesel 

Engines 

>600 hp 

(lb/1000 gal)

425 28 10.45 111 12.3 438.49 N/A 7.8 116.47 10.96 

Diesel-fired 

Boilers 

(lb/1000 gal)

20 28.5 2 5 0.2052 22 N/A 2 5 0.2 

Natural Gasfired 

Boilers<100 

MMBtu/hr 

(lb/MMscf) 

140 0.6 13.7 35 5.8 100

b

0.6 7.6 84 5.5 

Natural Gasfired 

Boilers>100 

MMBtu/hr 

(lb/MMscf) 

550 0.6 5 40 1.7 280

b

0.6 7.6 84 5.5 

a

Average of all NGE emission factors for 2000 study 

b

Uncontrolled emission factors only 

N/A= Not applicable for this comparison (emission factors based on fuel sulfur content) 

Where needed, conversions are based on 1050 Btu /scf natural gas, 7.1 lb/gal diesel fuel, and 

19,300 Btu/lb 
8-21

Table 8-22. Comparison of Non-Platform Emission Estimates.

1995 GMAQS 2000 Gulfwide Study 

Source Type 

NOx

(tpy) 

VOC 

(tpy) 

CO 

(tpy) 

NOx

(tpy) 

VOC 

(tpy) 

CO 

(tpy) 

Survey 

Vessels/Drilling Rigs 26,276 1,048 2,989 20,603 199 2,162 

Support Vessels 9,709 770 2,362 56,660 757 7,314 

Support Helicopters 288 212 694 1,438 2,285 6,060 

Pipelaying Vessels 18,042 3,070 2,843 13,416 129 1,408 

Platform 

Construction and 

Removal Vessels 2,257 29 284 

OCS Non-Platform 

Total 54,315 5,100 8,888 94,373 3,400 17,228 

LOOP 2,602 701 299 1,159 646 294 

Vessel Lightering 5,086 7,639 1,190 

Fishing Vessels 14,483 1,191 5,964 1,519 13 150 

Military Vessels 108 12 3,674 33 361 

Commercial Marine 

Vessels 85,961 3,745 9,563 19,487 182 1,936 

Biogenic/Geogenic 

Sources 13,561 

Non-OCS NonPlatform Total 103,154 5,637 15,838 30,925 22,074 3,931 

Total Non-Platform 

Emissions 157,469 10,737 24,726 125,298 25,474 21,159 

Table 8-23. Comparison of Commercial Marine Vessel Emission Estimates. 

Pollutant 

Study NOx VOC CO 

2000 Gulfwide Study 

Western & Central Gulf 19,487 182 1,936 

Eastern Gulf 16,934 149 1,669 

State Waters 41,054 360 4,046 

Gulfwide Total 77,475 691 7,651 

1995 GMAQS 

Gulfwide Total 85,961 3,745 9,563 

Percentage Difference -10% -82% -20% 

Corbett & Fischbeck/Maritime Administration 

Gulfwide Estimated Total 65,675 1,924 5,700 
9-1

9. REFERENCES 

API. 1993. Fugitive Hydrocarbon Emissions from Oil and Gas Production Operations. Health 

and Environmental Sciences Department, American Petroleum Institute (API) 

Publication Number 4589. 

API. 1996. Calculation Workbook for Oil and Gas Production Equipment Fugitive Emissions. 

Health and Environmental Sciences Department. American Petroleum Institute (API) 

Publication Number 4638. 

Boyer, B. and D.K. Brodnax. 1996. Emission Estimation Methods for Oil and Gas Operations. 

Presented at the Air and Waste Management Association Specialty Conference, The 

Emission Inventory: Key to Planning, Permits, Compliance, and Reporting. October 4-

6, New Orleans, LA. 

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

of OCS Production and Development Activities in the Gulf of Mexico. U.S. Department 

of the Interior, Mineral Management Service, Gulf of Mexico OCS Region, New Orleans, 

LA. OCS Study MMS 2002-073. 

Corbett, J. and P. Fischbeck. 2000. Emissions from Water Based Commerce Vessels in United 

States Continental and Inland Waterways. Environmental Science and Technology, 

34: 3254-3260. 

Gas Technology Institute (GTI). 2001. AMINECalc Software Program. Consolidated within 

the AIRCALC Version 1.0 Air Emissions Inventory Report Management Software 

Program. Chicago, IL. GTI-01/0025. http://www.gastechnology.org. 

Gas Technology Institute (GTI). 2000. GRI-GLYCalc, Version 4.0. Chicago, IL. GTI00/0102. http://www.gastechnology.org. 

EIIP. 1999. Emission Inventory Improvement Program. Volume II. Point Sources. Chapter 10. 

Oil and Gas Field Production and Processing Operations. 

http://www.epa.gov/ttn/chief/eiip/techreport/index.html

National Oceanic and Atmospheric Administration (NOAA). 2001. National Data Buoy Center. 

http://www.ndbc.noaa.gov/Maps/rmd/shtml. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III. U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 

95-0039, and 95-0040. 
9-2

U.S. Environmental Protection Agency (EPA). 2002. Compilation of Air Pollutant Emission 

Factors, Volume I: Stationary Point and Area Sources. AP-42. U.S. Environmental 

Protection Agency, Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. http://www.epa.gov/ttn/chief/ap42/index.html

U.S. Environmental Protection Agency (EPA). 2001. Temporal Allocation of Annual Emissions 

Using Emissions Modeling Clearinghouse Temporal Profiles. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. 

http://www.epa.gov/ttn/chief/emch/temporal/index.html. 

U.S. Environmental Protection Agency (EPA). 2000. Environmental Assessment of Final 

Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and 

Other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category. 

U.S. Environmental Protection Agency, Office of Water, Washington, D.C.EPA – 821-B00-014. 

U.S. Environmental Protection Agency (EPA). 1999. Emissions Inventory Guidance for 

Implementation of Ozone and Particulate Matter National Ambient Air Quality 

Standards (NAAQS) and Regional Haze Regulations. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. EPA-454/R-99-006. 

U.S. Environmental Protection Agency (EPA). 1991. Procedures for the Preparation of 

Emission Inventories for Carbon Monoxide and Precursors of Ozone, Volume II: 

Emission Inventory Requirements for Photochemical Air Quality Simulation 

Models. Office of Air Quality Planning and Standards, Research Triangle Park, 

NC. EPA-450/4-91-014. 

U.S. Environmental Protection Agency (EPA). 1977. Atmospheric Emissions from Offshore Oil 

and Gas Development and Production. U.S. Environmental Protection Agency, Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. PB272268. 

U.S. Maritime Administration. 2002. Vessel Calls at U.S. Ports-2000. Office of Statistical and 

Economical Analysis. http://www.marad.dot.gov/marad_statistics. 

Wilson D., A. Blackard, S. Finn, and B. Boyer. 2001. User’s Guide for the Gulfwide 

Offshore Activities Data System (GOADS) for Air Quality. U.S. Department of 

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

Orleans, LA. OCS Study MMS 2001-052. 
APPENDICES 

GULFWIDE NON-PLATFORM EMISSION SOURCES 

2 

Note all PM emission estimated in this report are as PM10. Additional detailed data for each of 

the non-platform source categories are provided in the appendices of this report. 

Table 1-1. Summary of Non-Platform Emission Estimates. 

Emissions (tpy) 

Source Category PM NOx SO2 CO VOC CO2 N2O 

OCS Production Related Sources 

Survey Vessels 4 151 25 15 1 9,975 * 

Drilling Rigs 508 20,453 3,440 2,147 197 1,359,432 * 

Support Vessels 1,415 56,660 9,680 7,314 757 3,814,905 * 

Support Helicopters 107 1,438 177 6,060 2,285 130,077 * 

Pipelaying Vessels 333 13,416 2,257 1,408 129 891,699 * 

Platform Construction & 

Removal Vessels 56 2,257 384 284 29 151,629 

OCS Total 2,428 94,375 15,963 17,228 3,400 6,357,716 * 

Non-OCS Production Related Sources 

LOOP 31 1,159 204 294 646 80,377 * 

Vessel Lightering 134 5,086 2,547 1,190 7,639 350,196 * 

Fishing Vessels 38 1,519 255 150 13 100,599 * 

Military Vessels 103 3,674 774 361 33 241,742 * 

Commercial Marine Vessels 498 19,487 3,545 1,936 182 1,258,433 * 

Biogenic/Geogenic 13,561 1,948 

Non-OCS Total 804 30,925 7,325 3,931 22,074 2,031,348 1,948 

Grand Total 3,227 125,300 23,288 21,159 25,472 8,389,064 1,948 

* N2O emission factors were not identified for these source categories. 

Emissions data were then disaggregated to MMS lease blocks. The latest marine diesel emission 

factors developed by the EPA in support of recent marine diesel regulations for all marine diesel 

engines were used in this study. Emission factors for residual oil-fueled vessels were derived 

from methods used in the 1999 National Emission Inventory (NEI) Commercial Marine Vessel 

Documentation. Helicopter emission factors were developed specifically for this inventory and 

are discussed in detail in the Appendix D of this report. 

Section 3.0 notes the limitations of the current study and identifies areas for potential 

improvement. Section 4.0 of this report provides a complete list of all references used in this 

inventory effort. 
3 

2.0 Summary of Non-platform Source Categories 

2.1 Survey Vessels

Survey vessels are used in the Gulf of Mexico (GOM) to map geologic formations and seismic 

properties. These survey mapping activities are needed to evaluate potential oil reserves in the 

GOM. The most common survey technique uses blasts from underwater air guns. The sound 

wave from the air gun blasts are deflected by underground geologic strata and detected by sound 

wave receptors associated with the survey vessel. There are two types of surveys that can be 

performed (i.e., two dimensions (2-D) and three dimensions (3-D)). 3-D surveys have been the 

dominant and preferred exploration technique in the Gulf, though quite a few permits were 

issued for high resolution 2-D surveys. Most modern survey vessels tow multiple streamers 

(sound wave reception devices) such that for every linear mile traveled, they acquire data for a 

square mile of subsurface area (Brinkman 2002a, 2002b). 

Survey vessel activity was provided by the Operation and Analysis Branch of the Engineering 

and Operations Division of MMS. Survey activities require a permit from MMS if the survey is 

intended for blocks not currently under lease. The Operation and Analysis Branch provided 

summary permit data for survey activities in these inactive lease blocks. Operators do not need 

to notify MMS if they intend to survey blocks they currently lease, such that the survey vessel 

activity used in this report underestimates actual activity. Due to issues of confidentiality, 

information about the location of permitted surveys could not be provided (Dellagiarino 2001). 

The total hours of survey activity were estimated based on the total number of miles surveyed for 

2-D surveys and total surface area surveyed for 3-D surveys. It was assumed that underway 

vessel speed for both 2-D and 3-D surveys is approximately 5 MPH (Brinkman 2002b). 

Emissions associated with survey vessels are primarily from marine diesel engines used for 

propulsion and to provide electricity and compressed air to operate the survey equipment. 

Emissions were estimated by applying the activity hours to marine engine emission factors. The 

emission factors used for this source category were based on emission equations included in 

support of the EPA’s diesel marine vessel rule (EPA 2000). These equations depend on 

horsepower and loading factor assumptions provided in the U.S. Department of the Interior 

Minerals Management Service’s 1995 Gulf of Mexico Air Quality Study (GMAQS) (U.S. DOI, 

MMS 1995). Appendix A provides details concerning the activity data and emission factors used 

and the emission estimates calculated for survey vessels. 

2.2 Drilling Rigs 

Drilling rigs are vessels used for exploratory drilling to supplement the geologic information 

provided by survey vessels. The drilling rig drills a hole in the ocean floor by turning a drill bit 

attached to lengths of tubular pipe. Several different types of drill rigs operate in the GOM 

including jack-ups, semisubmersibles, submersibles, and drill ships. Drilling rigs vary relative to 
4 

the water depth where they are intending to operate. For example, jack-ups are able to work in 

water up to 375 feet, semisubmersibles and submersibles operate in water with depths of 300 to 

2,000 ft and drill ships operate in waters with depths greater than 2,000 ft. 

The Operation and Analysis Branch of the Engineering and Operations Division of MMS 

provided activity data for drilling rigs by block, which included activity for jack-ups, semisubmersibles, submersibles, and drill ships (Mayes 2002). 

Emissions from drilling rigs are associated with the operation of medium- to high-speed marine 

diesel engines that are used for propulsion, generating electricity, operating mud pumps, and 

draw works. MMS activity data were applied to emission factors derived from EPA marine 

diesel engine emission equations (EPA 2000). To use these EPA emission equations, 

assumptions about vessel horsepower and typical operating loads were obtained from the 

GMAQS. The emission factors obtained from these equations were applied to the compiled 

activity data to estimate emissions for the portion of GOM where MMS has lease blocks. 

Appendix B provides detailed information about the activity data and emission factors used in 

calculating emission estimates for drilling rigs. 

2.3 Support Vessels 

Support vessels include crew boats that transport workers to and from work sites, supply vessels 

that carry supplies to offshore sites, and tugs and barges that transport heavy equipment and 

supplies. 

Data characterizing the support vessel fleet for 2000 are not available. The number of support 

vessels for the year 1992 was obtained from the GMAQS. In the GMAQS it was estimated that 

approximately 3,400 platforms were in operation (in 1992). It should be noted that the 1992 

support vessel survey had a response rate of 64 percent, such that actual vessel numbers maybe 

larger than those reported in the study. Currently, MMS estimates that the number of active 

platforms is 3,987, an increase of approximately 17 percent from 1992. It is assumed that as the 

number of platforms increase, the support vessel fleet increases proportionally, therefore, the 

1992 support vessel fleet was increased 17 percent in order to approximate the size of the 2000 

support vessel fleet. The GMAQS assumed that support vessels operate 21 hours per day, this 

assumption was also used in this 2000 study. The vessel population estimate and the average 

hours of operation were used to calculate the total annual hours that support vessels operate. 

Emissions associated with support vessels are attributed to the operation of the primary diesel 

engine used for propulsion and other smaller diesel engines that are used to run generators or 

small cranes and winches for loading and unloading the vessels. 
5 

The amount of time that each type of support vessel typically spends in each of the operating 

modes (i.e., hoteling, maneuvering, and cruising), the load factor associated with each operating 

mode, and typical engine horsepower rating was assumed to be the same in 2000 as was 

documented in the GMAQS. The operating mode times, load factors, and typical horsepower 

ratings were applied to the EPA marine diesel engine equations (EPA 2000) to obtain 

representative emission factors. These emission factors were applied to the activity data to 

estimate emissions. Appendix C provides detailed information about the activity data and 

emission factors used to estimate emissions from support vessels. 

2.4 Helicopter Traffic

Helicopters are used extensively in the GOM to move light supplies and personnel to and from 

platforms. Activity data for 2000 were obtained from the Helicopter Safety Advisory 

Conference’s (HSAC) Gulf of Mexico Offshore Helicopter Operations and Safety Review. This 

reference provided data on the number of helicopter trips taken, number of passengers carried, 

and duration of trips. The activity data were disaggregated into single engine, twin engine, and 

heavy twin engine helicopters. 

The average trip length was relatively short (16 minutes) (HSAC 2001); it is assumed that 

helicopters typically hop from platform to platform, therefore the emission estimates are based on 

a short landing and take off (LTO) cycle that is appropriate for the documented average trip 

length. Gulfwide activity was estimated by applying the number of helicopter trips to the average 

trip time to get total hours of operation. 

The helicopter emission factors were obtained from multiple sources including the Final Air 

Quality Management Plan, 1991 Revision, Final Technical Report III-G, 1987 Aircraft Emission 

Inventory in the South Coast Air Basin developed by the California South Coast Air Quality 

Management District. Staff at the California Air Resources Board noted that these emission 

factors have not been updated since 1991. Additional helicopter emission factors were obtained 

from U.S. EPA’s Procedures for Emission Inventory Preparation Volume IV: Mobile Sources 

(EPA 1992), as well as data from the Allison helicopter engine manufacturer, and helicopter test 

data from the Department of the Navy’s Environmental Assessments (Department of Navy 1999). 

Staff at the EPA’s Office of Transportation and Air Quality (OTAQ) were contacted to insure 

that all data sources of helicopter emission factors were identified in this effort. 

The emission factors were disaggregated into the helicopter types used in the HSAC=s activity 

data. LTO-based emission factors for each helicopter type were averaged providing the emission 

factors used in this study. The data obtained for military helicopters were not included in the 

average for two reasons. First, some of the emission factors were more than an order of 

magnitude different from the factors obtained from other data sources and a credible explanation 

for the difference could not be provided. Second, most of the helicopters used to support oil 

platform activities are commercial, not military helicopters. 
6 

The helicopter activity data were applied to the emission factors developed in this study to 

estimate emissions from this source category. Appendix D provides detailed information about 

the activity data and emission factors used to calculate helicopter emission estimates. 

2.5 Pipelaying Vessels

Product from oil platforms is generally transported to shore via pipeline. New pipeline is 

constantly being laid linking new platforms to shore. Pipelines also require occasional 

maintenance and repair. To install, maintain, or replace sections of pipeline necessitates 

considerable vessel support. The GMAQS estimated the number of vessels needed to lay a given 

length of pipe in 24 hours. From these assumptions, it was calculated that it takes 0.4 total vessel 

hours to lay one foot of pipe. This value was applied to the geographic information system (GIS) 

data provided by the MMS Pipeline Section to estimate hours of operation. The MMS data 

documents the length and location of individual sections constructed or maintained from January 

1 to December 31, 2000 (Froomer 2002). 

Emissions associated with pipelaying vessels are attributed to the operation of the primary diesel 

engine used for propulsion and other smaller diesel engines that are used to run generators, air 

compressors, welding equipment, or small cranes and winches. Releases of gas or oil from 

pipelines that required repair or accidental releases during construction or maintanance were not 

considered in this study. 

Assumptions about average horsepower and load factors were obtained from the GMAQS and 

applied to EPA emission equations (EPA 2000). This provided an hourly emission factor that 

was applied to the calculated hours of operation to estimate emissions. Appendix E provides 

detailed information about the activity data and emission factors used to calculate emission 

estimates for pipelaying vessels. 

2.6 LOOP

The Louisiana Offshore Oil Port (LOOP) is a platform located 18 miles south of Grand Isle, 

Louisiana. This offshore port allows large oil tankers to unload product without having to 

navigate into and out of a port. The LOOP consists of several emission sources: one 1000 kW 

generator, four 7,500 hp pumps, support vessels, as well as the oil tankers that use the facility. 

Hours of operation for the generator, pumps, and vessels were obtained from the LOOP’s website 

(www.loopllc.com). This site also included detailed information about the individual vessels that 

used the platform in 2000 and the line vessels that assisted the oil tankers in getting to and from 

the mooring points. 
7 

The LOOP website also provided detailed geographic data identifying the shipping approach 

used by vessels, the waiting area, and the mooring points as well as latitude and longitude 

coordinates for the platform itself. 

Marine diesel emission factors were developed for each emission source associated with the 

LOOP based on new EPA emission equations developed in support of the recent marine diesel 

engine rules (EPA 2000). To develop specific emission factors for the LOOP’s marine diesel 

engines, it was necessary to use average engine horsepower and assumptions about engine load 

factors provided in the GMAQS. The hours of operation were applied to these emission factors 

to estimate emissions from the diesel sources associated with the LOOP. 

Vessels also emit VOCs through evaporative losses from tanker ballasting operations. Ballasting 

is the pumping of water into a vessel after the product has been removed, the added water 

improves the stability of a tanker. As water is pumped into a vessel, volatile organics are 

displaced. Evaporative emissions from ballasting were also calculated in this effort. These 

estimates were derived from product transfer data for each vessel that used the LOOP and 

emission factors included in the EPA Emission Inventory Improvement Program (EIIP) guidance 

documents. 

Appendix F provides detailed information about the activity data and emission factors used to 

calculate emission estimate for all emissions sources associated with the LOOP. 

2.7 Lightering 

Lightering is the transfer of cargo to smaller ships that bring the product into port. Lightering 

occurs off-shore in three designated areas, which are defined by latitude and longitude 

coordinates. Emissions associated with lightering are attributed to primary propulsion engines of 

the vessels involved in lightering, secondary engines (e.g., pumps and winches), and evaporative 

emissions associated with ballasting and product transfer. 

The Coast Guard is responsible for monitoring lightering activities and was the data source for 

the GOM vessel lightering activity data used in this report. To calculate the emissions from the 

ships involved in the lightering process, the activity data provided, which included hours of 

operation and number of vessels, were compiled and applied to diesel emission factors derived 

from EPA marine diesel engine equations. These equations used assumptions about engine 

horsepower and load factors that were obtained from the GMAQS. 

Organic vapors are displaced into the atmosphere while ships ballast or while transferring 

product into the escort vessels. In this report, activity data were collected to quantify ballasting 

and estimate associated emissions. Appendix G provides detailed information about the activity 

data and emission factors used to calculate emission estimates for all sources associated with 

lightering activities. 
8 

2.8 Commercial Fishing/Recreational Fishing 

The GOM is an active commercial fishing area, providing a wide range of fish and seafood 

products. Detailed commercial fishing data were obtained from the National Oceanic & 

Atmospheric Administration’s National Marine Fisheries Service (NMFS). Separate activity 

data were provided for the three different types of offshore fishing activities that occur in the 

GOM, pelagic long line, reef, and shrimp fishing operations (Cramer 2001, Pattela 2001, 

Poffenberger, 2001). The activity data for these different fishing operations were provided as 

latitude and longitude for pelagic long line fishing operations and NMFS= geographic grid for 

reef and shrimp fishing. The associated activity data were provided in terms of hours of 

operation and can be applied directly to emission factors to estimate emissions. 

Emissions associated with commercial fishing vessels are attributed to the operation of diesel 

engines used for propulsion and other smaller diesel engines that are used to run generators or 

small cranes and winches to lift fish nets and lines onto the vessel. 

Assumptions about fishing vessel horsepower and typical load factors were provided in the 

GMAQS. This information was applied to EPA marine diesel emission equations (EPA 2000) 

to derive emission factors. These emission factors were applied to the hours of operation 

provided by the NMFS to calculate emissions for this source category. 

Appendix H provides detailed information about the activity data and emission factors used in 

calculating emission estimate for commercial fishing operations. 

After careful study, it was decided that the majority of recreational fishing occurs within state 

waters and therefore this source category was not included in this inventory. It is recognized that 

some small portion of recreational fishing occurs near platforms that are not in state waters. 

Unfortunately, data could not be identified to quantify recreational fishing near oil platforms. 

2.9 Military Vessel Operations

The U.S. Navy and Coast Guard frequently patrol and have manuevers in the GOM. The U.S. 

military vessel fleet consists of vessels powered by a variety of engines including older residual 

fueled steam turbines, marine diesel engines, and high speed diesel turbines. 

Contacts were made with the Navy to obtain activity data necessary to estimate vessel emissions. 

Despite these repeated data requests and promises to provide the required data, the Navy has not 

submitted any activity data at this time. Therefore, the data the Navy provided for the GMAQS 

were used in this inventory. It was assumed that naval vessel activity remained constant during 

this period and no adjustments were made to the activity data. Hours of operation for each vessel 

were assumed to be 24 hours per day, 365 days per year. 
9 

Navy vessel emission estimates were developed for marine diesel engines using the EPA marine 

diesel equations. A load factor of 80% was assumed and engine horsepower for each vessel was 

obtained in the GMAQS. 

Steamship and turbine engine vessel emission estimates were determined differently. Fuel 

consumption data for these vessel types were supplied by the Navy in the GMAQS. Emissions 

factors for residual oil-fueled steamship vessels were obtained from the EPA’s Documentation 

for Aircraft, Commercial Marine Vessel, Locomotive, and other Nonroad Components of the 

National Emission Inventory (EPA 2003). For turbine-powered vessels, updated emission 

factors were obtained from the EPA’s AP-42, Volume 1, Chapter 3 for turbines operating with 

distillate fuels (EPA 2002). 

The Coast Guard provided data that included the number of boats operating in the GOM, the type 

of boat, the number of engines, and horsepower of each engine, the total number of operating 

hours for each, and the percentage of time each vessel spent in the OCS (McClellan 2002, 

Peschke 2002, Thomas 2001). From this data, the total number of operating hours was 

calculated for each type of boat. Assuming a load factor of 80%, and using the provided 

horsepower data, emission factors were derived using the EPA’s marine diesel equations (EPA 

2000). Emissions from each boat type were calculated and totaled to estimate emissions for all 

Coast Guard vessels operating in the Gulf. 

Appendix I provides detailed information about the activity data and emission factors used to the 

calculate the emission estimate for military vessels. 

2.10 Commercial Marine Vessels

Commercial marine vessels (CMV) are involved in transporting a wide range of agricultural, 

manufacturing, and chemical products through the Gulf. CMVs tend to be powered by either 

diesel engines that combust diesel or residual oil fuels or steam ships that burn residual fuel. 

Though some emissions may occur due to evaporative losses of volatile chemical products, most 

of the emissions associated with CMVs are from the combustion of the fuels used to propel the 

marine vessels. 

In this inventory of non-platform emission sources, CMV emission estimates for diesel-powered 

vessels were estimated by using ton-mileage emission factors developed from EPA data (EPA 

2003) and ship lane activity data obtained from the Army Corps of Engineers. Steamship 

emission estimates were extrapolated from the EPA’s NEI (EPA 2003). 

Appendix J provides detailed information about the activity data and emission factors used to 

calculate emission estimates for CMVs. 
10 

2.11 Biogenics/Geogenic Emission Sources 

Emission estimates for seeps of crude oil (MacDonald et al. 1993, Kennicutt 1989, Mitchell 

1999) and subsurface bacterial processes (Nevison et al. 1995, Bouwman 1995) were calculated. 

However, oceanic processes venting of natural gas, and emissions from methane hydrates could 

not be estimated in this study because useful quantitative information could not be found during 

this project’s literature search. 

Appendix K provides detailed information about the methods used to estimate emissions from oil 

seepage. This appendix is somewhat different than the other appendices as it summarizes much 

of the current literature on this topic. It is hoped that in the future this information will be 

valuable to estimate emissions from biogenic and geogenic sources. 

2.12 Platform Construction and Removal 

A variety of vessels are needed to transfer equipment, materials, and structural platform 

components, as well as workers and technicians, during the construction and removal of offshore 

oil platforms. The methods used to estimate emissions from these vessels were adapted from 

another MMS study, Emission Inventories of OCS Production and Development Activities in the 

Gulf of Mexico – Final Report (Coe et al. 2003). As the vessels involved in platform 

construction and removal activities are similar to support vessels discussed in Appendix C of this 

report, many of the same assumptions about vessel characteristics and operations were used to 

estimate emissions. 

Platforms that were installed or removed during 2000 were identified using MMS’s platform 

structure database. Additional data were provided by MMS quantifying the water depth at the 

platform and the number of pilings associated with individual platforms. This information was 

used in conjunction with data included in Coe et al. (2003), to estimate the total vessel hours 

associated with platform construction and removal. Assumptions about typical vessel 

horsepower and operating loads used in the support vessel calculations were also used to develop 

emission factors for vessels associated with this source category. These hourly emission factors 

were applied to the estimate of total vessel hours of operation to calculate total emissions. For 

more details regarding the calculation of emissions for vessels involved in platform construction 

and removal see Appendix L. 

2.13 Spatial Allocation of Emissions 

Appendix M documents the methods used to spatially allocate emissions to MMS lease blocks. 

The approach varied by source category to insure that the most appropriate surrogates were used. 

For example, the survey vessel emission estimates were only for non-active lease blocks, 

therefore, emissions were allocated to non-active lease blocks based on their surface area. For 

drilling rigs, activity data were provided for individual blocks, therefore emissions could be 

allocated to lease blocks based on hours of operation. Support vessel emissions were allocated to 
11 

lease blocks with active platforms, while support helicopter emissions were allocated to lease 

blocks with active platforms that had helipads. MMS maintains a GIS data set of 2000 pipeline 

activities. Pipeline emissions were allocated based on the length of pipeline constructed or 

maintained within the lease block boundaries. Similarly, for platform construction and 

maintenance activities, MMS maintains a data set that includes the date of installation or removal 

and the platform latitude and longitude coordinates. Emissions were assigned to individual 

platforms based on the estimated hours of operation calculated for the platform’s construction or 

removal. 

Similar approaches were used to spatially allocate emissions to non-OCS production related 

sources. For example, the LOOP provided information to accurately map vessel approach 

shipping lanes, as well as latitude and longitude coordinates for the platform itself. Vessel 

lightering emissions were spatially allocated relative to the vessel type and the activity. Where 

product was off loaded, emissions were allocated to the centroid of the lightering zone. For 

emissions associated with escort vessels shuttling product to port, the fairway was mapped and 

emissions allocated to associated lease blocks based on the length of the vessel fairway within 

the lease block boundaries. Commercial fishing emissions were applied to lease blocks 

associated with NMFS’s fishing areas based on the activity data provided. Military vessel 

emissions and biogenic and geogenic emissions were applied to all northern Gulf federal waters 

based on the amount of surface area associated with each lease block. For these two source 

categories it was assumed that the emissions were spread over the whole region including 

MMS’s western, central, and eastern Gulf areas. (Note, Table 1 only summarizes emissions 

associated with the western and central MMS areas.) Commercial marine vessel emissions were 

allocated to shipping lanes based on cargo traffic; these emissions were allocated to individual 

lease blocks based on the length of shipping lane within the lease block boundaries. For more 

details on the spatial allocation procedures used, see Appendix M. 

3.0 Limitations of the Non-platform Inventory 

As with the development of any inventory of activity data or emission estimates, the accuracy of 

the study can vary considerably depending upon the accuracy of the activity data obtained and the 

emission factors used. 

For some source categories, such as the LOOP, commercial fishing, and the Coast Guard, the 

activity data used in this study were specific and reasonably accurate for the 2000 base year. But 

many of the other source categories are based on adjustments made to activity data that were 

included in the earlier GMAQS. Much of the non-platform activity data used in the 1995 study 

were derived from a 1992 Survey of Offshore Operators undertaken by the Offshore Operators 

Committee. This 1992 report contains useful information, and it would have been helpful if a 

similar study could have been performed for this 2000 inventory effort. 

Given the methods used to calculate the emission estimates, an important factor influencing the 

quality of the estimate is the validity of the emission factors, both in terms of absolute accuracy, 
12 

as well as representativeness for each source type. Most of the non-platform sources are powered 

by marine diesel engines. In this study, marine diesel emission factors were developed using 

recent EPA emission factor equations derived from a large number of “in use” vessel test data. 

These emission factor equations require horsepower and operating load factors. Typical 

horsepower and load factors were obtained from the GMAQS. These values are considered 

averages such that actual emissions from specific vessels may be significantly different than 

emissions from an average vessel. 

As with most inventory efforts, use of better quality data can improve the accuracy of the 

emission estimates. Improvements can be made in this study in the following areas: 

• If the 1992 Survey of Offshore Operators developed by the Offshore Operators Committee is 

revised, the new data will help clarify whether vessels involved with platform construction 

and removal are included. Data from the updated survey should be incorporated into this 

inventory; 

• Rather than use typical horsepower rating, it is recommended that horsepower ratings should 

be compiled for individual survey vessels, drilling rigs, pipelaying vessels, and commercial 

fishing boats; 

• The Navy activity data needs to be updated to represent actual 2000 activity; 

• Helicopter data needs to be collected for the Navy and Coast Guard operations; 

• The helicopter emission factors should be updated as new data become available; and 

• The biogenic and geogenic estimating procedures should be updated as new data become 

available.

4.0 References 

Brinkman, Ron. June 19, 2002a. Telephone conversation with Jaime Hauser of Eastern Research 

Group. U.S. Dept. of the Interior, Minerals Management Service. 

Brinkman, Ron. July 2, 2002b. Email entitled Re: some more on survey vessels, to Jaime Hauser 

of Eastern Research Group. U.S. Dept. of the Interior, Minerals Management Service. 

Bouwman, A.F., K.W. Van der Hoek, and J.G.J. Olivier. 1995. Uncertainties in the global 

source distribution of nitrous oxide. Journal of Geophysical Research, vol. 100, no. D2, 

pp.2785-2800. 
13 

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

Inventories of OCS Production and Development Activities in the Gulf of 

Mexico. U.S. Department of the Interior, Mineral Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Study MMS 2002-073. 

Cramer, Jean. June 18, 2001. E-mail entitled Re: fishing locations in the GOM, to Amy 

Alexander of Eastern Research Group Inc. National Oceanic & Atmospheric 

Administration. 

Dellagiarino, George. June 21, 2001. E-mail entitled Re: more on seismic surveys, to Jaime 

Hauser of Eastern Research Group Inc. U.S. Dept. of the Interior, Minerals Management 

Service.

Department of the Navy. 1999. Environmental assessment/ overseas environmental assessment 

of the SH-60R Helicopter/ALFS test program. 

http://envplan.nfesc.navy.mil/documents/SH60R%20EA.PDF. Accessed October 30, 

2001. 

Froomer, Norman. May 10, 2002. E-mail entitled 2000 Pipelines, to Richard Billings of Eastern 

Research Group. U.S. Dept. of the Interior, Minerals Management Service.

Helicopter Safety Advisory Conference (HSAC). 2001. “Helicopter safety advisory conference 

(HSAC) Gulf of Mexico offshore helicopter operations and safety review.” 

http://www.hsac.org/stats.html. Accessed October 30, 2001. 

Kennicutt, II, M.C., J.M. Brooks, and R.A. Burke, Jr. 1989. Hydrocarbon seepage, gas hydrates, 

and authigenic carbonate in the Northwestern Gulf of Mexico. 21st Annual Offshore 

Technology Conference Proceedings, pp. 649-654. 

Louisiana Offshore Oil Platform (LOOP). 2001. http://www.loopllc.com/f1.htm. Accessed 

October 2001. 

MacDonald, I.R., N.L. Guinasso, Jr., S.G. Ackeson, J.F. Amos, R. Duckworth, R. Sassen, and 

J.M. Brooks. 1993. Natural oil slicks in the Gulf of Mexico visible from space. Journal 

of Geophysical Research, vol. 98, no. C9, pp. 16,351-16,364. 

Mayes, Melinda. March 14, 2002. E-mail entitled Rig Information, to Roger Chang of Eastern 

Research Group. Operations Analysis Branch, Minerals Management Service. 

McClellan, Sheridan. January 9, 2002. Telephone conversation with Roger Chang of Eastern 

Research Group. USCS Marine Safety Unit, Galveston. 
14 

Mitchell, R., I.R. MacDonald, and K. Kvenvolden. 1999. Estimates of total hydrocarbon 

seepage into the Gulf of Mexico based on satellite remote sensing images. Paper OS411-

02. Presented at the 2000 Ocean Sciences Meeting, American Geophysical Union. 

Nevison, R., R. F. Weiss, and D. J. Erickson III. 1995. Global oceanic emissions of nitrous 

oxide. Journal of Geophysical Research, vol. 100, no. C8, pp. 15,809-15,820. 

Patella, Frank. October 22, 2001. E-mail entitled Re: fishing locations in the GOM, to Roger 

Chang of Eastern Research Group Inc. National Oceanic & Atmospheric Administration. 

Peschke, May 6, 2002. Facsimile to Roger Chang of Eastern Research Group. Quarter Master, 

Eighth Coast Guard District, New Orleans, LA. 

Poffenberger, John. May 3, 2001. E-mail entitled Re: fishing effort, to Amy Alexander of 

Eastern Research Group. National Oceanic & Atmospheric Administration. 

Thomas, P.F. December 21, 2001. Response to letter from Robert Chang of Eastern Research 

Group dated December 6, 2001. Commanding Officer USCG Marine Safety Unit, 

Galveston. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III. U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 1992. Procedures for Emission Inventory 

Preparation, Volume IV: Mobile sources. Office of Air and Radiation. Ann Arbor, MI. 

EPA420-R-92-009. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 

U.S. Environmental Protection Agency (EPA). 2002. Compilation of Air Pollutant Emission 

Factors, Volume I: Stationary Point and Area Sources. AP-42. U.S. Environmental 

Protection Agency, Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. http://www.epa.gov/ttn/chief/ap42/index.html

U.S. Environmental Protection Agency (EPA). 2003. Documentation for Aircraft, Commercial 

Marine Vessel, Locomotive, and Other Nonroad Components of the National Emission 

Inventory. Volume I – Methodology. Emission Factor and Inventory Group, Research 

Triangle Park, NC. http://www.epa.gov/ttn/chief/net/1999 inventory.html
APPENDIX A 

SURVEY VESSELS 
A-3

Due to issues of confidentiality only limited activity data were available for survey vessels. The 

Operation and Analysis Branch of the Engineering and Operations Division of MMS does not 

keep records of survey vessels operating in areas which are leased to an operator, nor can they 

release information on recent individual survey permits (Dellagiarino 2001). However, summary 

survey information is available through the U.S Department of the Interior’s Minerals 

Management Service’s Resource Evaluation Division’s Geological and Geophysical Data 

Acquisition-Outer Continental Shelf through 2000 report (U.S. DOI, MMS 2001). The report 

contained the number of miles and/or blocks that had been surveyed, prior to lease sale, during 

2000. This information is divided into the two types of survey’s implemented in the Gulf, 2-D 

seismic surveys and 3-D seismic surveys. 

Web sites of companies who do seismic surveying in the GOM were viewed to obtain data on the 

number of engines a survey vessel generally has (Fugro GeoServices, Inc. 2002). Typical survey 

vessel cruising speed (5 mph) was provided by MMS staff (Brinkman 2002a, 2002b). By 

dividing the number of miles surveyed by the vessel cruising speed, the number of operating 

hours were estimated for each survey type, as shown in Table A-1. 

The average horsepower of survey vessels was obtained from the GMAQS, and was applied to 

the 2000 inventory. A load factor of 80 percent was assumed based on engineering judgement. 

The total engine hours operated, the average load factor, and the average horsepower were 

applied to the following emission equations from the U.S. EPA’s Analysis of Commercial 

Marine Vessels Emissions and Fuel Consumption Data (EPA 2000) in order to derive a 

representative emission factor.

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables A-2, and A-3 were obtained 

from Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels Emissions and 

Fuel Consumption Data report (EPA, 2000). The emission factors reported in these 

tables do not always agree with the coefficients, due to round-off error.

Example Calculation 

EPM = 0.01 (Operating load)-1.5 + 0.26 

= 0.01 (0.80)-1.5 + 0.26 

= 0.27 g/kW-hr 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 
A-4

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A* (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). It should be noted that the A coefficient for the sulfur emission estimate 

was corrected in this study to 1.9899 (which is rounded to 2.00), based on discussions 

with EPA staff concerning the correct value that should be used. 

Tables A-2 and A-3 show how the emission factors were developed. The emission factors 

reported in these tables do not always agree with the coefficients, due to round-off error. These 

emission factors were applied to the hours of operation and typical horsepower to estimate 

emissions. 

Example Calculation 

Emission Estimate = EPM * Load Factor *Average kW Rating * Total Engine Hours 

= 0.27 g/kW-hr * 578.66 kW * 25,884 hours * 0.80 

= 3,235 Kg 

= 3.57 Tons 

These emission estimates for both 2-D and the 3-D survey vessels were added together to get the 

total estimate of emissions from surveying vessels shown in Table A-4. 
A-5

Table A-1. Calculation of Hours Worked. 

2D Survey Vessels 

Miles Surveyed in 

2000 

Speed of Vessel 

(mi/hr) 

Number Hrs Req'd to 

Survey all Miles 

64,710 5 12,942

3D Survey Vessels 

Blocks 

Surveyed 

in 2000 

Miles 

Surveyed* 

Speed of 

Vessel 

(mi/hr) 

Number Hrs Req'd to 

Survey all Blocks 

1,578 4,734 5 946.8

*Assumption that it requires 3 miles to survey 1 block. 

Table A-2. Activity Data and Emission Factors for Survey Vessels - 2D Seismic. 

Summary Data for Survey Vessels-2D Seismic 

Engines 

Operating 

Load Avg. HP Avg. kW Total Engine Hrs 

2 80% 776 578.66 25,884

Emission Factors for Survey Vessels-2D Seismic 

Pollutant

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) 

Average 

kW rating Kg/hr lbs/hr 

Adjusted

Emission 

Rate 

(lbs/hr)**

PM 0.27 1.50 0.26 0.01 578.66 0.15 0.34 0.27

NOx 10.62 1.50 10.45 0.13 578.66 6.15 13.55 10.84

SO2* 1.78 N/A 0.00 2.00 578.66 1.03 2.27 1.82

CO 1.05 1.00 0.00 0.84 578.66 0.61 1.34 1.07

VOC 0.09 1.50 0.00 0.07 578.66 0.05 0.12 0.10

CO2 703.73 1.00 648.60 44.10 578.66 407.22 897.76 718.21

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 
A-6

Table A-3. Emission Factors for Survey Vessels - 3D Seismic. 

Summary Data for Survey Vessels-3D Seismc 

Engines 

Operating 

Load Avg. HP Avg. kW 

Total Engine 

Hrs 

2 80% 776 578.66 1,893.60 

Emission Factors for Survey Vessels-3D Seismic 

Pollutant

E 

(g/kW-hr) Exponent (x) Intercept (B)

Coefficient 

(A) 

Average 

kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.27 1.50 0.26 0.01 578.66 0.15 0.34 0.27

NOx 10.62 1.50 10.45 0.13 578.66 6.15 13.55 10.84

SO2* 1.78 N/A 0.00 2.00 578.66 1.03 2.27 1.82

CO 1.05 1.00 0.00 0.84 578.66 0.61 1.34 1.07

VOC 0.09 1.50 0.00 0.07 578.66 0.05 0.12 0.10

CO2 703.73 1.00 648.60 44.10 578.66 407.22 897.76 718.21

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 

Table A-4. Summary of Total Emission Estimates for Survey Vessels. 

2D Seismic 3D Seismic Total 

Pollutant Emissions (tons/year) 

PM 3.48 0.26 3.74

NOx 140.34 10.26 150.60

SO2 23.52 1.72 25.24

CO 13.83 1.01 14.84

VOC 1.23 0.09 1.32

CO2 9,295.02 680.00 9,975.02

References 

Brinkman, Ron. June 19, 2002a. Telephone conversation with Jaime Hauser of Eastern Research 

Group. U.S. Dept. of the Interior, Minerals Management Service. 
A-7

Brinkman, Ron. July 2, 2002b. Email entitled Re: some more on survey vessels, to Jaime Hauser 

of Eastern Research Group. U.S. Dept. of the Interior, Minerals Management Service. 

Dellagiarino, George. June 21, 2001. E-mail entitled Re: more on seismic surveys, to Jaime 

Hauser of Eastern Research Group Inc. U.S. Dept. of the Interior, Minerals Management 

Service.

Fugro GeoServices, Inc. 2002. “R/V Seis Surveyor Technical Information.” 

http://www.fgsi.fugro.com/html/seistech.htm. Accessed June 21, 2002. 

U.S DOI, Minerals Management Service (MMS). 2001 Geological and Geophysical Data 

Acquisition-Outer Continental Shelf Through 2000. U.S. Department of the Interior, 

Minerals Management Service, Resource Evaluation Division, New Orleans, LA. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX B 

DRILLING RIGS 
B-3

The Operation and Analysis Branch of the Engineering and Operations Division of MMS 

provided detailed rig activity data by block (Mayes 2002). Separate activity data were provided 

for the five different types of Mobile Offshore Drilling Units (MODUs) that are used in the 

GOM: barges, drill ships, jack-up rigs, semisubmersible rigs, and submersible rigs. Barges 

operate in swallow waters, which were assumed to be within the 3-mile state waters and not 

included in this study. Table B-1 summarizes the provided activity data. 

The hours of operation for each of the four different drilling rigs were applied to diesel emission 

factors based on new EPA emission factor equations. These marine diesel emission factors are 

based on the following linear algorithm: 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables B-2, B-3, B-4 and 

B-5 were obtained from Table 5-1 of the U.S. EPA report Analysis of Commercial 

Marine Vessels Emissions and Fuel Consumption Data (EPA 2000). The emission 

factors reported in these tables do not always agree with the coefficients, due to round-off 

error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A* (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 
B-4

These power-based emission factors were applied to average horsepower ratings for the different 

drilling rigs and hours of operation to estimate emissions. This emission estimating approach 

used assumptions about horsepower and load factors provided in the GMAQS (U.S. DOI, MMS 

1995). Table B-6 summarizes the emission estimates for each of the different types of drilling 

rigs included in this study. 

Table B-1. Vessel Rig Activity. 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

DS AT 24 Falcon Deepwater Pathfinder 06/26/00 08/14/00 50 1200

DS AT 336 Falcon Deepwater Millennuim 03/16/00 05/26/00 72 1728

DS GB 460 Transocean Discoverer Spirit 09/05/00 09/14/00 10 240

DS GB 783 Falcon Deepwater Pathfinder 08/15/00 10/20/00 67 1608

DS GB 783 Falcon Deepwater Pathfinder 10/20/00 11/15/00 27 648

DS GB 783 Falcon Deepwater Pathfinder 11/15/00 12/10/00 26 624

DS GC 506 Glomar Explorer 12/16/00 12/31/00 16 384

DS GC 743 Glomar C.R. Luigs 04/22/00 10/16/00 178 4272

DS GC 782 Transocean Discoverer 534 01/01/00 02/15/00 46 1104

DS MC 305 Transocean Discoverer 534 02/15/00 04/14/00 60 1440

DS MC 348 Falcon Deepwater Millennium 01/01/00 02/09/00 40 960

DS MC 776 Transocean Discoverer 534 04/14/00 09/05/00 145 3480

DS MC 822 Discoverer Enterpri 01/01/00 06/10/00 162 3888

DS MC 822 Discoverer Enterpri 06/28/00 12/06/00 162 3888

DS MC 876 Falcon Deepwater Pathfinder 12/11/00 12/31/00 21 504

DS ST 250 Glomar C.R. Luigs 11/15/00 12/27/00 43 1032

DS WR 165 Falcon Deepwater Millennium 02/09/00 03/15/00 36 864

DS WR 425 Glomar C.R. Luigs 10/16/00 10/19/00 4 96

DS WR 456 Glomar Explorer 07/05/00 12/12/00 161 3864

DS WR 678 Discoverer Spirit 09/18/00 12/31/00 105 2520

JU BA 437 Falcon Seahawk 07/16/00 07/24/00 9 216

JU BA 577 Pride Louisiana 04/28/00 06/21/00 55 1320

JU BA A 1 R&B Falcon 254 09/16/00 10/28/00 43 1032

JU BA A 19 Pride Alabama 01/01/00 03/02/00 62 1488

JU BA A 71 Pride Arkansas 02/14/00 03/01/00 17 408

JU EC 33 Pool 53 10/03/00 10/26/00 24 576

JU EC 38 Marine III 03/13/00 04/20/00 39 936

JU EC 60 Diamond Ocean Columbia 01/01/00 02/03/00 34 816

JU EC 65 Falcon 18 01/01/00 04/24/00 115 2760

JU EC 83 Marine XVI 02/15/00 04/09/00 55 1320

JU EC 84 Glomar Main Pass I 01/06/00 03/17/00 72 1728

JU EC 122 Hercules 22 03/20/00 05/10/00 52 1248

JU EC 151 Pride Louisiana 01/01/00 01/04/00 4 96
B-5

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU EC 161 Falcon 19 06/27/00 07/18/00 22 528

JU EC 192 Rowan California 09/04/00 12/31/00 119 2856

JU EC 195 Falcon 85 01/10/00 05/21/00 133 3192

JU EC 224 Cliff Drilling 152 04/07/00 05/08/00 32 768

JU EC 245 Rowan Houston 05/22/00 06/13/00 23 552

JU EC 263 Marine 304 12/30/00 12/31/00 2 48

JU EC 275 Marine XVI 01/01/00 01/16/00 16 384

JU EC 275 Pride Colorado 10/02/00 10/28/00 27 648

JU EC 282 Pride Oklahoma 11/03/00 11/14/00 12 288

JU EC 283 Pride Oklahoma 10/01/00 10/16/00 16 384

JU EC 305 Marine XVI 08/03/00 08/17/00 15 360

JU EC 305 Marine XVI 08/04/00 08/18/00 15 360

JU EC 305 Marine XVI 09/29/00 10/08/00 10 240

JU EC 313 Ensco 55 08/21/00 08/25/00 5 120

JU EC 313 Ensco 55 08/25/00 12/31/00 129 3096

JU EC 332 Rowan Middletown 01/01/00 02/20/00 51 1224

JU EC 344 Ensco 67 02/05/00 03/11/00 36 864

JU EC 347 Rowan Charles Rowan 01/11/00 01/30/00 20 480

JU EC 347 Rowan Gilbert Rowe 11/09/00 12/01/00 23 552

JU EC 364 Chiles Columbus 10/22/00 10/25/00 4 96

JU EC 364 Ensco 67 01/08/00 02/01/00 25 600

JU EI 28 Cliff Drilling 150 02/03/00 03/14/00 41 984

JU EI 28 Cliff Drilling 150 03/14/00 04/14/00 32 768

JU EI 45 Ensco 64 09/05/00 09/29/00 25 600

JU EI 45 Ensco 64 09/29/00 11/15/00 48 1152

JU EI 45 Ensco 64 11/15/00 12/10/00 26 624

JU EI 56 Hercules 14 07/23/00 08/24/00 33 792

JU EI 57 Cliff Drilling 150 01/01/00 02/02/00 33 792

JU EI 71 Hercules 25 03/24/00 04/07/00 15 360

JU EI 87 Rowan Texas 03/28/00 05/30/00 64 1536

JU EI 88 Diamond Ocean Titan 06/21/00 06/21/00 1 24

JU EI 88 Nabors Dolphin 105 06/15/00 07/13/00 29 696

JU EI 95 Nabors Dolphin 105 07/24/00 08/07/00 15 360

JU EI 95 Nabors Dolphin 105 08/29/00 09/20/00 23 552

JU EI 95 Nabors Dolphin 105 09/20/00 10/16/00 27 648

JU EI 97 Glomar High Island VIII 09/28/00 10/16/00 19 456

JU EI 98 Rowan Texas 05/31/00 07/09/00 40 960

JU EI 105 Glomar High Island VIII 02/06/00 03/11/00 35 840

JU EI 105 Nabors Dolphin 106 05/14/00 05/24/00 11 264

JU EI 105 Nabors Dolphin 106 08/31/00 09/12/00 13 312

JU EI 105 Sundowner Dolphin 106 05/12/00 05/24/00 13 312

JU EI 106 Glomar High Island VIII 11/23/00 12/31/00 39 936
B-6

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU EI 119 Glomar High Island VIII 07/23/00 09/25/00 65 1560

JU EI 119 Nabors Dolphin 105 10/16/00 12/03/00 49 1176

JU EI 147 Marine 225 05/05/00 06/13/00 40 960

JU EI 156 Ensco 84 02/25/00 05/26/00 92 2208

JU EI 156 Ensco 84 04/12/00 05/31/00 50 1200

JU EI 156 Ensco 84 05/03/00 06/16/00 45 1080

JU EI 156 Rowan Juneau 12/31/00 12/31/00 1 24

JU EI 162 Ensco 51 02/06/00 03/01/00 25 600

JU EI 189 R&B Falcon 251 12/23/00 12/31/00 9 216

JU EI 199 Marine 301 01/01/00 03/06/00 66 1584

JU EI 202 Marine XVIII 01/12/00 02/16/00 36 864

JU EI 202 Marine XVIII 02/16/00 02/18/00 3 72

JU EI 202 Marine XVIII 02/18/00 02/25/00 8 192

JU EI 202 Marine XVIII 02/25/00 03/13/00 18 432

JU EI 202 R&B Falcon 253 11/03/00 11/13/00 11 264

JU EI 203 Glomar Main Pass I 01/01/00 01/02/00 2 48

JU EI 224 Diamond Ocean King 05/26/00 08/30/00 97 2328

JU EI 224 Diamond Ocean King 08/30/00 11/22/00 85 2040

JU EI 224 Diamond Ocean King 11/25/00 12/31/00 37 888

JU EI 227 R&B Falcon 253 11/13/00 12/04/00 22 528

JU EI 247 Marine 225 10/04/00 10/24/00 21 504

JU EI 271 Ensco 67 01/01/00 01/07/00 7 168

JU EI 271 Ensco 67 08/01/00 08/11/00 11 264

JU EI 288 Glomar Adriatic IV 02/12/00 03/24/00 42 1008

JU EI 297 Marine XV 01/25/00 02/06/00 13 312

JU EI 307 Noble Johnnie Hoffman 01/05/00 01/05/00 1 24

JU EI 307 Noble Johnnie Hoffman 01/12/00 02/29/00 49 1176

JU EI 315 Glomar Adriatic IV 05/11/00 06/16/00 37 888

JU EI 333 Rowan Paris 06/21/00 08/22/00 63 1512

JU EI 362 Rowan-Alaska 09/01/00 09/15/00 15 360

JU EI 385 Rowan Arch Rowan 05/01/00 05/21/00 21 504

JU EI 385 Rowan Arch Rowan 05/21/00 09/30/00 133 3192

JU EI 385 Rowan Arch Rowan 09/30/00 12/01/00 63 1512

JU EW 305 Ensco 69 03/12/00 09/01/00 174 4176

JU GA 209 Ensco 89 02/11/00 03/09/00 28 672

JU GA 389 Ensco 83 09/07/00 10/12/00 36 864

JU GA 418 R&B Falcon C.E.Thornton 10/12/00 12/04/00 54 1296

JU GC 165 Diamond Ocean Columbia 08/29/00 12/01/00 95 2280

JU GI 31 R&B Falcon 203 09/04/00 11/20/00 78 1872

JU GI 41 Marine XV 02/23/00 03/21/00 28 672

JU GI 41 Marine XV 02/23/00 05/25/00 93 2232

JU GI 68 Glomar Adriatic IX 01/01/00 03/01/00 61 1464
B-7

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU GI 77 Marine IV 12/16/00 12/31/00 16 384

JU GI 85 Marine XV 01/01/00 01/19/00 19 456

JU GI 85 Marine XV 01/01/00 01/05/00 5 120

JU GI 93 Diamond Ocean Concord 07/15/00 07/29/00 15 360

JU GI 94 Diamond Ocean Warwick 08/02/00 08/02/00 1 24

JU GI 103 Ensco 68 01/17/00 04/18/00 93 2232

JU GI 103 Rowan-Alaska 06/08/00 08/29/00 83 1992

JU GI 106 Chiles Magellan 03/03/00 05/06/00 65 1560

JU GI 109 Ensco 68 05/27/00 06/14/00 19 456

JU GI 109 Ensco 68 08/20/00 09/05/00 17 408

JU GI 109 Ensco 68 09/24/00 10/17/00 24 576

JU GI 116 Rowan Gorilla VI 09/10/00 12/28/00 110 2640

JU GI 116 Rowan Gorilla VI 12/28/00 12/31/00 4 96

JU HI 37 Marine IV 04/22/00 11/03/00 196 4704

JU HI 71 Pool 50 04/06/00 04/14/00 9 216

JU HI 85 Rowan Halifax 04/07/00 05/14/00 38 912

JU HI 90 Marine IV 11/05/00 11/30/00 26 624

JU HI 115 R&B Falcon 202 08/19/00 11/02/00 76 1824

JU HI 131 Nabors Dolphin 105 12/05/00 12/31/00 27 648

JU HI 132 R&B Falcon 204 11/01/00 12/31/00 61 1464

JU HI 154 Chiles Columbus 01/01/00 03/13/00 73 1752

JU HI 162 Marine 301 10/02/00 12/31/00 91 2184

JU HI 202 Cliff Drilling 152 11/13/00 12/31/00 49 1176

JU HI 202 Ensco 64 01/01/00 05/08/00 129 3096

JU HI 202 Pride Wyoming 05/22/00 09/19/00 121 2904

JU HI 235 Falcon Phoenix I 07/10/00 08/24/00 46 1104

JU HI A 3 Diamond Ocean Titan 12/08/00 12/31/00 24 576

JU HI A 3 R&B Falcon C.E.Thornton 03/29/00 12/31/00 278 6672

JU HI A 3 R&B Falcon C.E.Thornton 12/04/00 12/31/00 28 672

JU HI A 5 Marine IV 01/01/00 01/20/00 20 480

JU HI A 7 Marine III 08/09/00 12/15/00 129 3096

JU HI A 7 Marine III 12/15/00 12/31/00 17 408

JU HI A 20 Chiles Magellan 08/10/00 12/31/00 144 3456

JU HI A 232 R&B Falcon 253 12/24/00 12/31/00 8 192

JU HI A 244 Pride Arkansas 01/01/00 02/09/00 40 960

JU HI A 327 R&B Falcon F.G.Mclintock 08/04/00 09/24/00 52 1248

JU HI A 343 Rowan Louisiana 11/05/00 11/11/00 7 168

JU HI A 343 Rowan Louisiana 11/11/00 11/30/00 20 480

JU HI A 354 Chiles Magellan 01/01/00 02/29/00 60 1440

JU HI A 415 Noble Tom Jobe 03/04/00 05/31/00 89 2136

JU HI A 441 Marine XVI 09/07/00 09/24/00 18 432

JU HI A 442 Falcon 18 04/24/00 05/14/00 21 504
B-8

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU HI A 442 Marine IV 03/27/00 03/30/00 4 96

JU HI A 442 Pride Texas 10/26/00 11/17/00 23 552

JU HI A 465 Diamond Ocean Nugget 01/11/00 01/17/00 7 168

JU HI A 472 Marine XVI 11/03/00 11/30/00 28 672

JU HI A 472 Marine XVI 11/30/00 12/20/00 21 504

JU HI A 472 Marine XVI 12/22/00 12/31/00 10 240

JU HI A 497 Glomar Adriatic X 04/06/00 04/17/00 12 288

JU HI A 517 Rowan Charles Rowan 09/01/00 12/01/00 92 2208

JU HI A 521 Marine III 04/20/00 04/27/00 8 192

JU HI A 523 Glomar Adriatic X 03/08/00 04/03/00 27 648

JU HI A 530 R&B Falcon F.G.Mclintock 09/24/00 12/04/00 72 1728

JU HI A 554 Ensco 60 11/22/00 12/12/00 21 504

JU HI A 567 Ensco 60 09/05/00 11/21/00 78 1872

JU MI 519 Ensco 93 12/23/00 12/31/00 9 216

JU MI 670 R&B Falcon 254 10/28/00 12/31/00 65 1560

JU MI 704 Ensco 84 09/08/00 12/19/00 103 2472

JU MO 991 Pride Kansas 02/03/00 03/27/00 54 1296

JU MP 7 Falcon Phoenix IV 08/20/00 09/24/00 36 864

JU MP 20 Ensco 68 12/05/00 12/31/00 27 648

JU MP 20 Marine 300 10/27/00 10/30/00 4 96

JU MP 61 Pride Wyoming 10/15/00 11/20/00 37 888

JU MP 61 Pride Wyoming 11/01/00 11/14/00 14 336

JU MP 61 Pride Wyoming 11/20/00 12/10/00 21 504

JU MP 64 Pool Ranger VII 05/14/00 05/28/00 15 360

JU MP 86 R&B Falcon 251 10/23/00 12/01/00 40 960

JU MP 86 R&B Falcon 251 12/01/00 12/21/00 21 504

JU MP 114 Marine 200 10/13/00 11/30/00 49 1176

JU MP 114 Marine 200 10/13/00 11/19/00 38 912

JU MP 131 Ensco 98 12/23/00 12/31/00 9 216

JU MP 139 Ensco 54 08/16/00 08/30/00 15 360

JU MP 150 Ensco 68 10/18/00 12/05/00 49 1176

JU MP 151 Noble Leonard Jones 06/01/00 07/12/00 42 1008

JU MP 159 Pride Wyoming 12/11/00 12/31/00 21 504

JU MP 188 Diamond Ocean Champion 10/19/00 11/11/00 24 576

JU MP 200 Diamond Ocean Titan 08/26/00 10/05/00 41 984

JU MP 217 Rowan-Alaska 10/05/00 10/22/00 18 432

JU MP 226 Diamond Ocean Spur 01/01/00 04/05/00 96 2304

JU MP 226 Marine 300 09/10/00 10/27/00 48 1152

JU MP 233 Rowan-Alaska 10/23/00 12/31/00 70 1680

JU MP 241 Ensco 60 05/09/00 05/21/00 13 312

JU MP 264 Glomar Adriatic II 01/01/00 01/14/00 14 336

JU MP 264 Rowan Paris 03/04/00 04/10/00 38 912
B-9

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU MP 275 Marine 303 03/28/00 07/16/00 111 2664

JU MP 277 Glomar Main Pass IV 01/01/00 01/10/00 10 240

JU MP 277 Glomar Main Pass IV 09/05/00 10/25/00 51 1224

JU MP 299 Glomar Adriatic II 01/18/00 01/21/00 4 96

JU MP 312 Chiles Tonala 10/20/00 12/06/00 48 1152

JU MU 726 Diamond Ocean Tower 08/04/00 12/18/00 137 3288

JU MU 738 Noble Sam Noble 02/19/00 03/01/00 12 288

JU PL 5 Hercules 20 01/01/00 03/19/00 79 1896

JU PL 5 Hercules 20 08/11/00 10/27/00 78 1872

JU PL 5 Parker 20 J 12/23/00 12/31/00 9 216

JU PL 6 Marine 225 01/26/00 03/22/00 57 1368

JU PL 11 Diamond Ocean Spartan 07/01/00 07/25/00 25 600

JU PL 11 Diamond Ocean Spartan 07/25/00 09/14/00 52 1248

JU PL 11 Diamond Ocean Spartan 09/14/00 10/14/00 31 744

JU PL 15 Hercules 20 03/19/00 04/21/00 34 816

JU SM 8 Nobel Carl Norberg 12/23/00 12/31/00 9 216

JU SM 66 Falcon 85 05/26/00 07/07/00 43 1032

JU SM 80 Glomar High Island VIII 04/14/00 05/12/00 29 696

JU SM 80 Glomar High Island VIII 05/12/00 06/05/00 25 600

JU SM 81 Falcon 85 01/07/00 01/21/00 15 360

JU SM 105 Falcon 85 04/25/00 04/25/00 1 24

JU SM 111 Glomar High Island VIII 06/06/00 07/23/00 48 1152

JU SM 176 Rowan Odessa 08/28/00 09/12/00 16 384

JU SM 235 Hercules 14 06/20/00 07/20/00 31 744

JU SM 235 Parker 14-J15 10/31/00 11/19/00 20 480

JU SM 236 Pool Ranger V 12/01/00 12/21/00 21 504

JU SM 240 Ensco 90 01/16/00 02/07/00 23 552

JU SM 253 Pool 50 11/12/00 12/04/00 23 552

JU SM 255 Sundowner Dolphin 106 04/29/00 05/14/00 16 384

JU SM 261 Cliffs Drilling 153 01/01/00 01/31/00 31 744

JU SM 261 Falcon 20 01/31/00 02/05/00 6 144

JU SM 261 Falcon 20 02/05/00 03/27/00 52 1248

JU SM 261 Hercules 11 07/06/00 07/24/00 19 456

JU SM 276 Pride Alabama 11/24/00 12/17/00 24 576

JU SP 31 Pride Kansas 01/01/00 02/03/00 34 816

JU SP 38 Marine XVIII 11/28/00 12/31/00 34 816

JU SP 62 Noble Leonard Jones 07/13/00 07/28/00 16 384

JU SS 27 Parker 14-J15 09/14/00 10/31/00 48 1152

JU SS 32 Ensco 93 12/20/00 12/23/00 4 96

JU SS 68 Diamond Ocean Spartan 05/22/00 06/05/00 15 360

JU SS 68 Pool 53 01/01/00 01/15/00 15 360

JU SS 76 Rowan Texas 07/09/00 08/06/00 29 696
B-10

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU SS 76 Rowan Texas 07/09/00 07/09/00 1 24

JU SS 79 Rowan Texas 08/29/00 09/18/00 21 504

JU SS 86 Marine 300 12/18/00 12/20/00 3 72

JU SS 100 Glomar High Island IV 01/31/00 02/28/00 29 696

JU SS 107 Parker 20 J 12/15/00 12/23/00 9 216

JU SS 126 Diamond Ocean Spartan 03/01/00 04/26/00 57 1368

JU SS 139 Diamond Ocean Champion 04/19/00 06/17/00 60 1440

JU SS 139 Falcon Phoenix III 04/04/00 04/25/00 22 528

JU SS 148 Marine XVII 05/28/00 06/10/00 14 336

JU SS 207 Rowan Gilbert Rowe 09/25/00 11/09/00 46 1104

JU SS 209 Glomar High Island II 07/12/00 10/16/00 97 2328

JU SS 209 Glomar High Island II 11/20/00 12/31/00 42 1008

JU SS 209 Glomar High Island II 11/21/00 12/05/00 15 360

JU SS 246 Chiles Tonala 09/25/00 10/20/00 26 624

JU SS 278 Falcon 20 01/01/00 01/09/00 9 216

JU SS 283 Pride Wyoming 09/26/00 11/01/00 37 888

JU SS 296 Rowan Odessa 06/01/00 07/28/00 58 1392

JU SS 296 Rowan Odessa 07/28/00 08/15/00 19 456

JU SS 313 Ensco 69 01/14/00 02/14/00 32 768

JU SS 349 Rowan Gorilla IV 09/17/00 11/19/00 64 1536

JU ST 26 Falcon Phoenix III 04/26/00 05/18/00 23 552

JU ST 31 Glomar High Island VIII 01/01/00 01/13/00 13 312

JU ST 31 Glomar High Island VIII 01/01/00 02/02/00 33 792

JU ST 33 Ensco 90 11/05/00 12/10/00 36 864

JU ST 67 Ensco 94 08/29/00 12/31/00 125 3000

JU ST 72 Falcon 85 02/25/00 05/21/00 87 2088

JU ST 139 Rowan Charles Rowan 01/31/00 06/15/00 137 3288

JU ST 143 Falcon Phoenix I 01/01/00 01/11/00 11 264

JU ST 162 Glomar Main Pass IV 01/01/00 01/31/00 31 744

JU ST 176 Ensco 94 07/19/00 08/29/00 42 1008

JU ST 204 Glomar Main Pass I 07/31/00 11/27/00 120 2880

JU ST 204 Glomar Main Pass I 11/29/00 12/31/00 33 792

JU ST 204 Glomar Main Pass I 12/31/00 12/31/00 1 24

JU ST 212 Marine 200 02/04/00 03/22/00 48 1152

JU ST 213 Falcon 20 01/09/00 02/02/00 25 600

JU ST 213 R&B Falcon 252 08/27/00 09/22/00 27 648

JU ST 238 Marine III 05/25/00 07/28/00 65 1560

JU ST 250 Marine III 07/28/00 08/09/00 13 312

JU ST 250 Marine III 07/28/00 08/16/00 20 480

JU ST 254 Ensco 68 09/06/00 09/25/00 20 480

JU ST 266 R&B Falcon 252 09/22/00 10/13/00 22 528

JU VK 69 Pride Kansas 04/06/00 06/02/00 58 1392
B-11

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU VK 158 Diamond Ocean Drake 11/01/00 12/31/00 61 1464

JU VK 205 Falcon Phoenix I 05/28/00 07/06/00 40 960

JU VK 251 Pride Kansas 07/10/00 07/16/00 7 168

JU VK 251 Pride Texas 03/13/00 04/06/00 25 600

JU VK 252 Pride Kansas 07/20/00 08/15/00 27 648

JU VK 384 Falcon Phoenix III 01/01/00 02/15/00 46 1104

JU VK 385 Falcon Phoenix III 05/19/00 07/29/00 72 1728

JU VK 475 Falcon Phoenix I 04/22/00 05/27/00 36 864

JU VK 565 Noble Johnnie Hoffman 11/11/00 12/31/00 51 1224

JU VR 47 Glomar High Island I 03/18/00 06/30/00 105 2520

JU VR 47 Rowan Juneau 01/01/00 03/01/00 61 1464

JU VR 56 Cliffs Drilling 153 02/21/00 05/18/00 88 2112

JU VR 63 Marine 201 07/11/00 08/31/00 52 1248

JU VR 88 Ensco 54 03/17/00 04/18/00 33 792

JU VR 114 Falcon 20 06/01/00 06/19/00 19 456

JU VR 130 Pool 54 01/01/00 02/10/00 41 984

JU VR 144 Marine 300 03/13/00 04/29/00 48 1152

JU VR 161 Hercules 11 01/13/00 02/03/00 22 528

JU VR 161 Hercules 11 02/03/00 05/10/00 98 2352

JU VR 161 Pride Arkansas 12/18/00 12/31/00 14 336

JU VR 161 Rowan Middletown 02/22/00 07/21/00 151 3624

JU VR 252 Diamond Ocean Nugget 02/11/00 03/19/00 38 912

JU VR 253 Rowan Cecil Provine 01/01/00 03/24/00 84 2016

JU VR 261 Pride Texas 12/07/00 12/31/00 25 600

JU VR 263 Pride Arkansas 10/30/00 12/17/00 49 1176

JU VR 267 Marine XVIII 02/13/00 03/12/00 29 696

JU VR 309 Noble Johnnie Hoffman 01/01/00 01/05/00 5 120

JU VR 320 R & B Falcon F G Mcclintock 12/11/00 12/31/00 21 504

JU VR 326 Ensco 51 01/01/00 01/01/00 1 24

JU VR 336 Ensco 55 01/01/00 02/19/00 50 1200

JU VR 356 Glomar Adriatic X 11/27/00 12/31/00 35 840

JU VR 356 Rowan Louisiana 01/01/00 02/15/00 46 1104

JU VR 369 Ensco 67 09/28/00 10/21/00 24 576

JU VR 375 Ensco 67 08/09/00 09/25/00 48 1152

JU WC 19 Noble Earl Fredrickson 08/13/00 12/27/00 137 3288

JU WC 28 Diamond Ocean Titan 01/01/00 03/05/00 65 1560

JU WC 28 Rowan Anchorage 06/11/00 07/15/00 35 840

JU WC 28 Rowan Anchorage 07/15/00 07/15/00 1 24

JU WC 45 Cliff Drilling 200 06/06/00 06/13/00 8 192

JU WC 48 Noble Earl Fredrickson 12/27/00 12/31/00 5 120

JU WC 65 Marine 303 01/01/00 01/19/00 19 456

JU WC 110 Diamond Ocean Spur 07/15/00 10/25/00 103 2472
B-12

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU WC 110 Diamond Ocean Spur 07/15/00 07/15/00 1 24

JU WC 164 Cliff Drilling 200 05/02/00 06/04/00 34 816

JU WC 170 Noble Johnnie Hoffman 03/01/00 04/05/00 36 864

JU WC 170 Noble Johnnie Hoffman 06/09/00 10/21/00 135 3240

JU WC 170 Nobel Johnnie Hoffman 06/11/00 06/11/00 1 24

JU WC 192 Marine XVII 10/12/00 12/06/00 56 1344

JU WC 201 Marine XVI 04/09/00 08/01/00 115 2760

JU WC 248 Marine XVI 01/17/00 02/15/00 30 720

JU WC 277 Pride Louisiana 07/12/00 07/18/00 7 168

JU WC 297 Hercules 15 06/23/00 12/31/00 192 4608

JU WC 297 Parker Rig 15 06/22/00 06/23/00 2 48

JU WC 300 Cliff Drilling 200 01/01/00 01/15/00 15 360

JU WC 300 Cliff Drilling 200 01/15/00 05/02/00 109 2616

JU WC 367 Pride Louisiana 07/30/00 09/04/00 37 888

JU WC 368 Pool 50 01/01/00 01/09/00 9 216

JU WC 368 Pride Louisiana 07/20/00 07/28/00 9 216

JU WC 370 Marine 201 10/16/00 12/05/00 51 1224

JU WC 370 Marine 201 12/20/00 12/29/00 10 240

JU WC 379 Falcon 18 05/14/00 06/17/00 35 840

JU WC 379 Falcon 18 05/14/00 06/16/00 34 816

JU WC 440 Rowan Odessa 11/06/00 11/29/00 24 576

JU WC 492 Marine 301 07/30/00 09/30/00 63 1512

JU WC 494 Marine 201 09/01/00 10/16/00 46 1104

JU WC 498 Glomar High Island I 07/02/00 08/01/00 31 744

JU WC 498 Glomar High Island I 08/01/00 09/10/00 41 984

JU WC 515 Glomar Adriatic III 05/28/00 05/30/00 3 72

JU WC 515 Glomar Adriatic X 05/30/00 10/26/00 150 3600

JU WC 516 Rowan-Alaska 02/03/00 03/09/00 36 864

JU WC 523 Rowan Louisiana 01/09/00 03/16/00 68 1632

JU WC 526 Rowan-Alaska 03/09/00 06/07/00 91 2184

JU WC 537 Rowan Houston 01/01/00 05/20/00 141 3384

JU WC 598 Rowan Louisiana 07/21/00 08/17/00 28 672

JU WC 598 Rowan Louisiana 08/18/00 09/22/00 36 864

JU WC 613 Glomar Adriatic IX 01/01/00 02/01/00 32 768

JU WC 613 Rowan Halifax 06/27/00 07/30/00 34 816

JU WD 23 Pool Ranger V 08/12/00 10/29/00 79 1896

JU WD 23 Pool Ranger VII 06/01/00 07/06/00 36 864

JU WD 39 Falcon Phoenix III 07/30/00 09/05/00 38 912

JU WD 58 Diamond Ocean Crusader 05/06/00 09/19/00 137 3288

JU WD 58 Diamond Ocean Crusader 10/01/00 11/27/00 58 1392

JU WD 59 Diamond Ocean Crusader 01/01/00 01/01/00 1 24

JU WD 59 Diamond Ocean Crusader 04/25/00 05/04/00 10 240
B-13

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

JU WD 59 Marine 300 11/01/00 12/11/00 41 984

JU WD 59 Marine XVIII 09/19/00 11/28/00 71 1704

JU WD 63 Diamond Ocean Crusader 01/02/00 01/20/00 19 456

JU WD 98 Diamond Ocean Crusader 02/29/00 04/24/00 56 1344

JU WD 109 Noble Leonard Jones 01/28/00 02/23/00 27 648

JU WD 112 Glomar Adriatic X 01/01/00 03/08/00 68 1632

JU WD 117 Marine XV 11/01/00 11/10/00 10 240

JU WD 136 Ensco 68 01/01/00 01/16/00 16 384

JU WD 137 Rowan Gorilla IV 06/19/00 06/26/00 8 192

JU WD 137 Rowan Gorilla IV 07/03/00 09/13/00 73 1752

SS AC 195 Noble Max Smith 07/23/00 08/25/00 34 816

SS AC 627 Noble Max Smith 01/01/00 02/24/00 55 1320

SS AC 627 Noble Max Smith 01/15/00 02/28/00 45 1080

SS AT 8 Diamond Ocean Quest 11/28/00 11/30/00 3 72

SS AT 63 Diamond Ocean Star 01/01/00 05/23/00 144 3456

SS AT 113 Transocean Marianas 07/06/00 08/20/00 46 1104

SS EB 201 Diamond Ocean Saratoga 11/10/00 12/31/00 52 1248

SS EB 430 Noble Max Smith 04/09/00 05/10/00 32 768

SS EB 599 Ensco E7500 12/01/00 12/31/00 31 744

SS EB 602 Diamond Ocean Star 07/09/00 11/21/00 136 3264

SS EB 602 Noble Amos Runner 01/01/00 01/16/00 16 384

SS EB 643 Diamond Ocean Quest 12/21/00 12/31/00 11 264

SS EB 832 Noble Homer Ferrington 12/13/00 12/31/00 19 456

SS EB 945 Marine 700 11/25/00 12/31/00 37 888

SS EC 345 R&B C. Kirk Rhein, Jr. 07/26/00 08/26/00 32 768

SS EI 346 Rowan Midland 04/16/00 06/21/00 67 1608

SS EI 397 R&B C. Kirk Rhein, Jr. 08/27/00 10/01/00 36 864

SS EI 397 R&B C. Kirk Rhein, Jr. 10/01/00 11/11/00 42 1008

SS EW 871 Diamond Ocean Concord 09/22/00 11/10/00 50 1200

SS EW 871 Diamond Ocean Concord 11/10/00 12/31/00 52 1248

SS EW 878 Diamond Ocean Saratoga 06/08/00 09/26/00 111 2664

SS EW 965 Diamond Ocean Endeavor 01/01/00 04/24/00 115 2760

SS EW 966 Noble Homer Ferrington 04/08/00 05/10/00 33 792

SS EW 1010 Noble Paul Romano 07/03/00 07/29/00 27 648

SS GB 73 Noble Homer Ferrington 03/14/00 04/07/00 25 600

SS GB 74 Ocean Ambassador 01/16/00 01/31/00 16 384

SS GB 158 Diamond Ocean Valiant 05/09/00 06/16/00 39 936

SS GB 158 Diamond Ocean Valiant 06/23/00 07/09/00 17 408

SS GB 215 Diamond Ocean Valiant 07/09/00 07/12/00 4 96

SS GB 215 Diamond Ocean Valiant 12/16/00 12/31/00 16 384

SS GB 215 Noble Max Smith 12/12/00 12/16/00 5 120
B-14

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

SS GB 240 Diamond Ocean Ambassador 02/01/00 02/13/00 13 312

SS GB 272 Transocean 96 11/28/00 12/31/00 34 816

SS GB 297 Noble Jim Thompson 11/05/00 12/12/00 38 912

SS GB 297 Noble Jim Thompson 12/12/00 12/31/00 20 480

SS GB 303 Diamond Ocean Valiant 03/22/00 05/05/00 45 1080

SS GB 344 Glomar Arctic I 08/28/00 09/28/00 32 768

SS GB 344 Glomar Arctic I 09/29/00 12/19/00 82 1968

SS GB 367 Diamond Ocean Voyager 11/08/00 11/08/00 1 24

SS GB 367 Diamond Ocean Voyager 11/08/00 12/31/00 54 1296

SS GB 385 Glomar Arctic I 01/01/00 05/05/00 126 3024

SS GB 385 Glomar Arctic I 05/05/00 08/11/00 99 2376

SS GB 562 Noble Amos Runner 08/10/00 09/26/00 48 1152

SS GB 668 Noble Amos Runner 04/06/00 07/04/00 90 2160

SS GB 668 Noble Amos Runner 09/27/00 11/16/00 51 1224

SS GB 668 Transocean Richardson 12/01/00 12/31/00 31 744

SS GB 754 Diamond Ocean Valiant 02/07/00 03/22/00 45 1080

SS GB 782 Diamond Ocean Victory 03/25/00 04/26/00 33 792

SS GB 782 Diamond Ocean Victory 04/26/00 05/12/00 17 408

SS GB 782 Diamond Ocean Victory 05/12/00 05/26/00 15 360

SS GB 782 Diamond Ocean Victory 05/26/00 06/01/00 7 168

SS GB 782 Diamond Ocean Victory 06/01/00 06/05/00 5 120

SS GB 782 Diamond Ocean Victory 06/05/00 07/03/00 29 696

SS GB 782 Diamond Ocean Victory 07/03/00 07/16/00 14 336

SS GB 782 Diamond Ocean Victory 07/16/00 08/11/00 27 648

SS GB 782 Diamond Ocean Victory 08/11/00 09/01/00 22 528

SS GC 7 Borgny Dolphin 09/08/00 10/01/00 24 576

SS GC 90 Rowan Midland 06/23/00 08/12/00 51 1224

SS GC 155 Diamond Ocean Worker 05/10/00 05/11/00 2 48

SS GC 165 Diamond Ocean Amercia 05/12/00 08/29/00 110 2640

SS GC 165 Diamond Ocean America 08/31/00 12/31/00 123 2952

SS GC 237 Falcon 100 08/30/00 12/09/00 102 2448

SS GC 288 Diamond Ocean Star 05/23/00 07/06/00 45 1080

SS GC 297 Attwood Hunter 08/18/00 11/11/00 86 2064

SS GC 338 Noble Amos Runner 11/19/00 12/31/00 43 1032

SS GC 473 Noble Paul Romano 02/24/00 03/27/00 33 792

SS GC 505 Diamond Ocean Quest 09/13/00 09/28/00 16 384

SS GC 505 Diamond Ocean Quest 09/28/00 10/28/00 31 744

SS GC 506 Diamond Ocean Quest 10/28/00 11/21/00 25 600

SS GC 563 Glomar Celtic Sea 03/14/00 07/01/00 110 2640

SS GC 563 Glomar Celtic Sea 04/01/00 11/07/00 221 5304

SS GC 608 Transocean Richardson 03/13/00 09/20/00 192 4608
B-15

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

SS GC 608 Transocean Richardson 09/20/00 11/29/00 71 1704

SS GC 737 Noble Homer Ferrington 08/13/00 09/13/00 32 768

SS GC 783 Diamond Ocean Victory 09/01/00 12/15/00 106 2544

SS GI 111 Transocean 96 09/01/00 11/23/00 84 2016

SS GI 116 Transocean 96 01/21/00 03/14/00 54 1296

SS HI 154 R&B C. Kirk Rhein, Jr. 01/01/00 01/18/00 18 432

SS HI A 582 Rowan Midland 09/24/00 12/31/00 99 2376

SS KC 199 Noble Amos Runner 07/05/00 08/10/00 37 888

SS MC 68 Diamond Ocean Saratoga 05/08/00 06/04/00 28 672

SS MC 248 Diamond Ocean Quest 01/01/00 03/23/00 83 1992

SS MC 321 Diamond Ocean Concord 08/16/00 09/20/00 36 864

SS MC 379 Noble Amos Runner 01/12/00 03/31/00 80 1920

SS MC 401 Diamond Ocean Lexington 12/18/00 12/31/00 14 336

SS MC 582 Diamond Ocean Concord 01/19/00 05/10/00 113 2712

SS MC 595 Noble Homer Ferrington 10/14/00 12/09/00 57 1368

SS MC 632 Diamond Ocean Quest 08/16/00 09/10/00 26 624

SS MC 657 Transocean Marianas 01/04/00 02/28/00 56 1344

SS MC 705 Diamond Ocean Quest 12/01/00 12/10/00 10 240

SS MC 705 Diamond Ocean Rover 01/01/00 01/27/00 27 648

SS MC 711 Noble Max Smith 03/04/00 04/05/00 33 792

SS MC 711 Noble Max Smith 05/10/00 07/23/00 75 1800

SS MC 711 Noble Max Smith 09/06/00 10/31/00 56 1344

SS MC 727 Transocean Marianas 08/20/00 12/31/00 134 3216

SS MC 727 Transocean Marianas 08/21/00 12/31/00 133 3192

SS MC 764 Noble Jim Thompson 03/09/00 09/12/00 188 4512

SS MC 773 Noble Homer Ferrington 05/14/00 07/09/00 57 1368

SS MC 988 Noble Paul Romano 03/30/00 07/01/00 94 2256

SS PI 167 Diamond Ocean Worker 07/14/00 08/11/00 29 696

SS SP 90 Diamond Ocean Lexington 11/17/00 12/03/00 17 408

SS SS 313 Rowan Midland 08/12/00 08/29/00 18 432

SS ST 317 Transocean Richardson 08/23/00 11/29/00 99 2376

SS VK 739 Borgny Dolphin 06/27/00 09/08/00 74 1776

SS VK 740 Diamond Ocean Lexington 09/11/00 10/11/00 31 744

SS VR 408 Diamond Ocean Ambassador 07/11/00 11/23/00 136 3264

SS VR 408 Rowan Midland 01/01/00 04/16/00 107 2568

SU EI 39 Attwood Richmond 01/02/00 03/11/00 70 1680

SU EI 39 Attwood Richmond 03/11/00 04/05/00 26 624
B-16

Table B-1. Vessel Rig Activity (Continued). 

Rig 

Type*

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move 

on Date 

Rig Move off 

Date Days Hours

SU EI 60 R&B Falcon 75 11/10/00 12/27/00 48 1152

SU EI 60 R&B Falcon 75 12/27/00 12/31/00 5 120

SU SS 32 Noble Joe Alford 06/11/00 09/11/00 93 2232

SU WC 57 Attwood Richmond 10/13/00 11/13/00 32 768

*DS = Drill Ship 

 JU = Jack up 

 SS = Semisubmersible 

 SU = Submersible 

Table B-2. Drill Ship Emission Factors. 

Activity Data 

Avg. HP Avg. kW

Prime 2,500.00 1,864.25

Pumps 1,600.00 1,193.12

Drawworks 3,000.00 2,237.10

Total 7,100.00 5,294.47

Operating Load 75%

Emission Factors 

Pollutant

E 

(g/kW-hr) 

Exponent 

(x) 

intercept 

(B) 

Coefficient 

(A) 

Average 

kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 5,294.47 1.40 3.08 2.31

NOx 10.64 1.50 10.45 0.13 5,294.47 56.35 124.23 93.17

SO2* 1.79 N/A 0.00 2.00 5,294.47 9.48 20.90 15.67

CO 1.12 1.00 0.00 0.84 5,294.47 5.91 13.04 9.78

VOC 0.10 1.50 0.00 0.07 5,294.47 0.54 1.20 0.90

CO2 707.40 1.00 648.60 44.10 5,294.47 3,745.31 8,256.91 6,192.68

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 75% load factor. 
B-17

Table B-3. Jackup Rig Emission Factors. 

Activity Data 

Avg. HP Avg. kW

Prime 1,660.00 1,237.86

Pumps 1,600.00 1,193.12

Drawworks 2,000.00 1,491.40

Total 5,260.00 3,922.38

Operating Load 75%

Emission Factors 

Pollutant

E 

(g/kW-hr) 

Exponent 

(x) 

intercept 

(B) 

Coefficient 

(A) 

Average 

kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 3,922.38 1.04 2.28 1.71

NOx 10.64 1.50 10.45 0.13 3,922.38 41.75 92.03 69.02

SO2* 1.79 N/A 0.00 2.00 3,922.38 7.02 15.48 11.61

CO 1.12 1.00 0.00 0.84 3,922.38 4.38 9.66 7.24

VOC 0.10 1.50 0.00 0.07 3,922.38 0.40 0.89 0.67

CO2 707.40 1.00 648.60 44.10 3,922.38 2,774.69 6,117.09 4,587.82

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 75% load factor. 
B-18

Table B-4. Semisubmersible Rig Emission Factors. 

Activity Data 

Avg. HP Avg. kW

Prime 2,034.00 1,516.75

Pumps 1,600.00 1,193.12

Drawworks 3,000.00 2,237.10

Total 6,634.00 4,946.97

Operating Load 75%

Emission Factors 

Pollutant

E 

(g/kW-hr) 

Exponent 

(x) 

intercept 

(B) 

Coefficient 

(A) 

Average 

kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 4,946.97 1.31 2.88 2.16

NOx 10.64 1.50 10.45 0.13 4,946.97 52.65 116.07 87.05

SO2* 1.79 N/A 0.00 2.00 4,946.97 8.86 19.52 14.64

CO 1.12 1.00 0.00 0.84 4,946.97 5.53 12.18 9.13

VOC 0.10 1.50 0.00 0.07 4,946.97 0.51 1.12 0.84

CO2 707.40 1.00 648.60 44.10 4,946.97 3,499.49 7,714.97 5,786.23

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 75% load factor. 
B-19

Table B-5. Submersible Rig Emission Factors. 

Activity Data 

Avg. HP Avg. kW

Prime 2,034.00 1,516.75

Pumps 1,600.00 1,193.12

Drawworks 3,000.00 2,237.10

Total 6,634.00 4,946.97

Operating Load 75%

Emission Factors 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) 

Average 

kW rating Kg/hr lbs/hr 

Adjusted

Emission

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 4,946.97 1.31 2.88 2.16

NOx 10.64 1.50 10.45 0.13 4,946.97 52.65 116.07 87.05

SO2* 1.79 N/A 0.00 2.00 4,946.97 8.86 19.52 14.64

CO 1.12 1.00 0.00 0.84 4,946.97 5.53 12.18 9.13

VOC 0.10 1.50 0.00 0.07 4,946.97 0.51 1.12 0.84

CO2 707.40 1.00 648.60 44.10 4,946.97 3,499.49 7,714.97 5,786.23

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 75% load factor. 

Table B-6. Emission Estimates for Exploratory Drill Ship Operations (tons/year). 

Drill Ship Type* 

Pollutant Drill Jackup Semi Submersible Total 

PM 39.71 309.12 151.75 7.10 507.68

NOx 1,599.89 12,453.24 6,113.26 286.23 20,452.62

SO2 269.11 2,094.71 1,028.29 48.14 3,440.24

CO 167.93 1,307.09 641.65 30.05 2,146.70

VOC 15.44 120.16 58.99 2.76 197.34

CO2 106,340.69 827,733.80 406,332.26 19,025.12 1,359,431.87

* Hours of operation: Drill 34,344, Jackup 360,840, Semi 140,448, Submersible 6,576. 
B-20

References 

Mayes, Melinda. March 14, 2002. Email entitled Rig Information, to Roger Chang of Eastern 

Research Group. Operations Analysis Branch, Minerals Management Service, Herndon, 

VA. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III. U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX C 

SUPPORT VESSELS 
C-3

Support vessels include several different types of vessels that operate at various power levels 

throughout a typical work day. The number of each of these types of vessels operating in the 

offshore Gulf areas in 1992 was provided in the GMAQS (U.S. DOI, MMS 1995). It should be 

noted that the vessel numbers used in the 1995 report were derived from a survey which had a 

response rate of 64 percent, such that, the actual number of support vessels operating in the Gulf 

may be larger than numbers reported in the GMAQS. 

To determine the number of support vessels operating in 2000, it was assumed that the vessel 

population varied proportionally with the number of active platforms in the Gulf. Since 1992, 

the number of platforms has increased 17% (U.S. DOI, MMS 1995, Coe et al. 2003), therefore, 

the 1992 support vessel fleet population was increased 17% to represent the fleet size in 2000 

(see Table C-1). Note that this increased number of platforms in the Gulf is not related to the 

number of platforms that reported in the Gulfwide Study vs. the GMAQS. 

The GMAQS also provided an estimate of the average number of hours worked for all vessels 

(21 hours/day), the average horsepower of each vessel type, the percentage of time each vessel 

spent in a specific operating mode (hoteling, maneuvering, and cruising), and the percent of total 

power used in each mode. It is assumed that these numbers have not changed significantly since 

1992. For each vessel type, each power setting is associated with different engine load values. 

The aggregated load factor was calculated using the following equation: 

Aggregated Operating Load Factor = (10% of power used) (% of time hoteling) + 

(55% of power used) (% of time maneuvering) + 

(100% of power used) (% of time cruising) 

These calculations are shown in Table C-2. 

Emission factors for each type of support vessel were derived using the EPA marine diesel 

emission equation: 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables C-3, C-4, C-5, and C-6 were 

obtained from Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data report (EPA 2000). The emission factors 

reported in these tables do not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 
C-4

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A* (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 

The equations provided power-based emission factors that are applied to the average horsepower 

of the vessel and the total hours of operations to estimate emissions. Emission estimates for each 

type of support vessel are noted in Table C-7.
C-5

Table C-1. 2000 Data on Support Vessels.a

1992 2000 

Vessel Type 

Number of 

Vessels 

Number of 

Vessels 

Average 

Number of 

Engines 

Per Vessel 

Average 

Engine HP 

Average HP 

Per Vessel Load Factor

Crew Boats 88 103 4.9 480 2,436 87%

Supply Boats 326 382 2.4 868 2,037 55%

Tugs 60 70 2.1 2,234 4,618 54%

Barges 27 32 3.2 308 990 55%

Total 501 588 3,890 10,081

a Note: 2000 data derived by calculating the percent increase (17.21%) between 1992 and 2000 of oil 

 platforms and applying to the 1992 numbers. 

Table C-2. Determination of Load Factor for Supply Boats in the Gulf of Mexico. 

Operation 

Mode 

Operating 

Load % Time at each Operation Mode Weighted Operating Load ** 

Crew Supply Tugs* Barges* Crew Supply Tugs* Barges* 

Hoteling 10% 10% 45% 33% 50% 1% 4.5% 3.3% 5% 

Maneuvering 55% 10% 10% 33% 0% 5.5% 5.5% 18.2% 0% 

Cruising 100% 80% 45% 33% 50% 80% 45% 33% 50% 

Aggregated Weighted Load *** 86.5% 55% 54.4% 55% 

* Tugs and barges with diesel engines. 

** Weighted Operating Load = Operating load x time at each operation model. 

***Aggregated Operating Load Factor = Sum of weighted operating load. 
C-6

Table C-3. Activity Data and Emission Factors for Crew Boats.

Summary Data for Crew Boats 

Vessels Operating Load 

Avg. Total 

HP per 

Vessel 

Avg. Total 

kW per Vessel Total Engine Hrs 

103 86.5% 2,436 1,817 790,973.8941

Emission Factors for Crew Boats 

Pollutant 

E 

(g/kW-hr) Exponent (x)

Intercept 

(B) 

Coefficient 

(A) Avg kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.2624 1.5 0.2551 0.0059 357.9 0.09 0.21 0.18

NOx 10.6056 1.5 10.4496 0.1255 357.9 3.80 8.37 7.24

SO2* 1.7702 N/A 0 1.998 357.9 0.63 1.40 1.21

CO 0.9686 1 0 0.8378 357.9 0.35 0.76 0.66

VOC 0.0829 1.5 0 0.0667 357.9 0.03 0.07 0.06

CO2 699.5827 1 648.6 44.1 357.9 250.41 552.0 477.48

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 86.5% load factor. 

Table C-4. Activity Data and Emission Factors for Supply Vessels. 

Summary Data for Supply Vessels 

Vessels Operating Load 

Avg. Total 

HP per 

Vessel 

Avg. Total 

kW per Vessel Total Engine Hrs 

382 55% 2,037 3,700 2,930,198.744

Emission Factors for Supply Vessels 

Pollutant 

E 

(g/kW-hr) Exponent (x)

Intercept 

(B) 

Coefficient 

(A) Avg kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.2696 1.5 0.2551 0.0059 647.3 0.17 0.38 0.21

NOx 10.7573 1.5 10.4496 0.1255 647.3 6.96 15.35 8.44

SO2* 1.8449 N/A 0 1.998 647.3 1.19 2.63 1.45

CO 1.5233 1 0 0.8378 647.3 0.99 2.17 1.19

VOC 0.1635 1.5 0 0.0667 647.3 0.11 0.23 0.13

CO2 728.7818 1 648.6 44.1 647.3 471.72 1,039.9 571.94

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study 

 the fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 55% load factor. 
C-7

Table C-5. Activity Data and Emission Factors for Tugs with Diesel Engines.

Summary Data for Tugs with Diesel Engines 

Vessels 

Operating 

Load 

Avg. Total 

HP per 

Vessel 

Avg. Total 

kW per Vessel Total Engine Hrs

70 54.4% 4,618 3,443 539,300.4

Emission Factors for Tugs with Diesel Engines 

Pollutant 

E 

(g/kW-hr) Exponent (x)

Intercept 

(B) 

Coefficient 

(A) Avg kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.2698 1.5 0.2551 0.0059 1665.9 0.45 0.99 0.54

NOx 10.7620 1.5 10.4496 0.1255 1665.9 17.93 39.52 21.50

SO2* 1.8470 N/A 0 1.998 1665.9 3.08 6.78 3.69

CO 1.5387 1 0 0.8378 1665.9 2.56 5.65 3.07

VOC 0.1660 1.5 0 0.0667 1665.9 0.28 0.61 0.33

CO2 729.5917 1 648.6 44.1 1665.9 1215.42 2,679.5 1,457.65

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 54.4% load factor. 

Table C-6. Activity Data and Emission Factors for Barges with Diesel Engines. 

Summary Data for Barges with Diesel Engines 

Vessels Operating Load 

Avg. Total 

HP per 

Vessel 

Avg. Total 

kW per Vessel Total Engine Hrs 

32 55% 990 738 242,685

Emission Factors for Barges with Diesel Engines 

Pollutant 

E 

(g/kW-hr) Exponent (x)

Intercept 

(B) 

Coefficient 

(A) Avg kW rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.2696 1.5 0.2551 0.0059 229.7 0.06 0.14 0.08

NOx 10.7573 1.5 10.4496 0.1255 229.7 2.47 5.45 3.00

SO2* 1.8449 N/A 0 1.998 229.7 0.42 0.93 0.51

CO 1.5233 1 0 0.8378 229.7 0.35 0.77 0.42

VOC 0.1635 1.5 0 0.0667 229.7 0.04 0.08 0.04

CO2 728.7818 1 648.6 44.1 229.7 167.38 369.0 202.95

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 55% load factor.
C-8

Table C-7. Summary of Emission Estimates for Support Vessels (tons/year).

Pollutant Crew BoatsaSupply BoatsaTugs

a Bargesa

Total 

PM 359.22 726.78 300.21 29.25 1,415.47

NOx 14,516.28 29,001.51 11,974.55 1,167.38 56,659.71

SO2 2,429.98 4,987.80 2,060.97 200.77 9,679.52

CO 1,326.27 4,108.48 1,714.26 165.38 7,314.40

VOC 113.53 441.05 185.04 17.75 757.37

CO2 957,960.53 1,965,628.06 812,195.25 79,120.92 3,814,904.75

a

Assumed typical crew boat has 4.9 engines, supply boat has 2.4 engines, tugs 2.1 engines, and barges 

 3.2 engines. 

References 

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

Inventories of OCS Production and Development Activities in the Gulf of 

Mexico. U.S. Department of the Interior, Mineral Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Study MMS 2002-073. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX D 

SUPPORT HELICOPTERS 
D-3

Helicopter activity data for 2000 were obtained from the Helicopter Safety Advisory 

Conference’s (HSAC) Gulf of Mexico Offshore Helicopter Operations and Safety Review (HSAC 

2001). The activity data were disaggregated into single engine, twin-engine, and heavy twin 

engine helicopters providing estimates for the number of helicopter trips taken and the average 

duration of a trip (see Table D-1). The average trip length was approximately 16 minutes that 

equated to a landing and take-off (LTO) cycle consisting of 2 minutes for takeoff, 7 minutes for 

climbout, 7 minutes for approach, and 20 minutes in idle. 

The helicopter emission factors used in this inventory were derived from the report Air Quality 

Management Plan, 1991 Revision, Final Technical Report III-G, 1987 Aircraft Emission 

Inventory in the South Coast Air Basin (developed by the South Coast Air Quality Management 

District), the U.S. EPA’s Procedures for Emission Inventory Preparation Volume IV: Mobile 

Sources (EPA 1992), data from the Allison helicopter engine manufacturer (Allison 2002), and 

the Department of the Navy’s Environmental Assessments (Department of the Navy 1999). 

These emission factors are compiled in Tables D-1, D-2, and D-3. The emission factors were 

disaggregated into the helicopter types used in HSAC=s activity data. The LTO emission factors 

for each helicopter type were averaged to obtain the aggregated emission factors used in this 

study. The data obtained from the military were not included in the average emission factor for 

two reasons. First, some of the emission factors were more than an order of magnitude different 

from the factors obtained from other data sources and a credible explanation for the difference 

could not be provided. Second, most of the helicopters used to support oil platform activities are 

commercial not military helicopters. 

The emission test data were converted to LTO-based emission factors by weighting the lb/min 

test results by the amount of minutes the helicopter spent in each mode as noted in the following 

equation: 

EFLTO = ∑ TDi x Pi

where 

EFLTO = LTO-Based emission factor (lb/LTO) 

TDi = Test data for Mode i (lb/min) 

i = Mode (i.e., take off, climbout, approach and idle) 

Pi = Period helicopter is in mode (minutes/LTO) 

The LTO-based emission factors were averaged to get a representative factor. 
D-4

The developed emission factors were applied to HSAC’s activity data to estimate emissions as 

noted in the following example. 

Example Calculation 

Single-engine helicopter VOC estimate: 

Emission Estimate = Emission Factor x LTO 

VOC Emission Estimate = 0.808 lb VOC/LTO x 922,597 LTOs 

 = 745, 458 lbs VOC 

 = 372 tons VOC 

Emission estimates for each helicopter type are provided in Table D-4. 

Table D-1. Single-Engine Helicopter Emission Factors. 

Helicopter Engine

VOC 

(lb/LTO)

CO 

(lb/LTO)

NOx

(lb/LTO)

SO2

(lb/LTO)

Allison 250-C40B 0.971 4.465 0.851

Allison 250-C20S 0.310 2.437 0.426

Bell UH-1, AH-1 T53-L-11D 3.773 5.391 1.752 0.187*

Bell 206 L3 Allison 250 C30P 0.204 1.400 0.190

MBB B0105CBS Allison C20B 0.398 2.800 0.380

Bell 206 B3 Allison 250 C20J 0.204 1.400 0.190

Aerospatiale AS355 Allison C20B 0.398 2.800 0.380

Bell 206 Allison 250 C28 0.204 1.400 0.190

Average single 0.808 2.762 0.545 0.187

* SO2 data for single-engine helicopter was only available for Bell UH-1/AH-1 helipcoter equipped 

 with T53-L-11D engines. 
D-5

D-2. Twin-Engine Helicopter Emission Factors. 

Helicopter Model T58-GE-8F T58-GE-16 T58-GE-5 

Mode 

VOC 

(lb/min) 

VOC 

(lb/min) 

VOC 

(lb/min) Average 

Takeoff 0.01 0.044 0.027

Climbout 0.021 0.016 0.022

Approach 0.017 0.008 0.022

Idle 0.557 0.199 0.418

EF/LTO 11.484 4.348 8.82 8.217

Helicopter Model T58-GE-8F T58-GE-16 T58-GE-5 

Mode 

CO 

(lb/min) 

CO 

(lb/min) 

CO 

(lb/min) Average 

Takeoff 0.237 0.263 0.250

Climbout 0.335 0.283 0.167

Approach 0.295 0.318 0.167

Idle 0.785 0.699 0.751

EF/LTO 21.688 19.832 18.687 20.069

Helicopter Model T58-GE-8F T58-GE-16 T58-GE-5 

Mode 

NOx

(lb/min) 

NOx

(lb/min) 

NOx

(lb/min) Average 

Takeoff 0.143 0.394 0.269

Climbout 0.087 0.246 0.213

Approach 0.098 0.172 0.213

Idle 0.006 0.015 0.007

EF/LTO 2.174 5.225 4.621 4.007

Helicopter Model T58-GE-8F T58-GE-16 T58-GE-5 

Mode 

SO2

(lb/min) 

SO2

(lb/min) 

SO2 

(lb/min) Average 

Takeoff 0.014 0.018 0.016

Climbout 0.010 0.014 0.016

Approach 0.011 0.012 0.016

Idle 0.002 0.003 0.002

EF/LTO 0.278 0.334 0.368 0.327
D-6

D-2. Twin-Engine Helicopter Emission Factors (Continued). 

Helicopter Model T58-GE-5 

Mode PM* Average 

Takeoff 

Climbout 0.027

Approach 0.027

Idle 0.003

EF/LTO 0.492 0.492

* LTO emission factor based on available data for climb 

 out approach and idle, note there were no values for take 

 off. 

D-3. Heavy Twin-Engine Helicopter Emission Factors. 

Helicopter 

Model* Mode

Power 

Setting

Fuel Flow 

(lb/min)

VOC 

(lb/1000 

lb fuel)

CO 

(lb/1000 

lb fuel)

NOx

(lb/1000 lb 

fuel)

SO2 

(lb/1000 lb 

fuel)

VOC 

(lb/min)

CO 

(lb/min)

NOx 

(lb/min)

SO2

(lb/min)

Takeoff

 

33.42 0.18 1.47 10.83 0.54 0.018 0.147 1.086 0.054

Climbout Military 31.93 0.272 1.29 9.99 0.54 0.026 0.124 0.957 0.052

Approach 0.8 24.88 0.126 2.1 8.09 0.54 0.009 0.157 0.604 0.040

Idle Idle 4.48 23.64 74.33 2.12 0.54 0.318 0.999 0.028 0.007

Sikorsky H-53 

Sea 

Stallion/Super 

Stallion (3 

engine)

lb/LTO 6.712 22.812 17.399 1.098

*Assumption: 3 engine helicopter approximates a heavy twin helicopter. 
D-7

Table D-4. Summary of Helicopter Activity and Emissions Data. 

Year 2000 Single Twin

Heavy 

Twin Total

Helicopters 385 182 15 582

LTOs 922,597 436,137 35,945 1,394,679

Emission Factors 

Type 

VOC 

(lb/LTO) 

CO 

(lb/LTO) 

NOx

(lb/LTO) 

SO2 

(lb/LTO) 

PM10 

(lb/LTO) 

CO2 

(lb/LTO)* 

Single 0.808 2.762 0.545 0.187 128.46

Twin 8.217 20.069 4.007 0.327 0.492 263.22

Heavy 

Twin 

6.712 22.812 17.399 1.098 589.22

Emissions 

Type 

VOC 

(tons/year)

CO 

(tons/year)

NOx 

(tons/year)

SO2

(tons/year)

PM10

(tons/year)

CO2

(tons/year) 

Single 372.729 1,273.972 251.351 86.113 64,429.381

Twin 1,791.868 4,376.406 873.755 71.254 107.284 55,621.681

Heavy 

Twin

120.633 409.991 312.713 19.733 10,025.510

Total 2,285.220 6,060.370 1,437.819 177.117 107.284 130,076.572

* Note CO2 emission factors were was derived by assuming that almost all carbon in the fuel 

 is emitted as CO2 and helicopter fuel is 87% carbon.

References 

Allison. 2002. Allison Helicopter Engine Manufacturer. Test data for Allison Model 250 

helicopter engines. 

Department of the Navy. 1999. Environmental assessment/overseas environmental assessment 

of the SH-60R Helicopter/ALFS test program. 

http://envplan.nfesc.navy.mil/documents/SH60R%20EA.PDF Accessed October 30, 

2001. 

Helicopter Safety Advisory Conference (HSAC). 2001. Helicopter safety advisory conference 

(HSAC) Gulf of Mexico offshore helicopter operations and safety review. 

http://www.hsac.org/stats.html. Accessed October 30, 2001. 

U.S. Environmental Protection Agency (EPA). 1992. Procedures for Emission Inventory 

Preparation, Volume IV: Mobile sources. Office of Air and Radiation. Ann Arbor, MI. 

EPA420-R-92-009. 
APPENDIX E 

PIPELAYING OPERATIONS 
E-3

It is estimated in the GMAQS that 5 boats can lay 300 feet of pipe in a 24-hour period, such that 

it takes a total of 0.4 hours, or 24 minutes, to lay one foot of pipe (see Table E-1). 

A load factor of 75 percent was assumed based on data provided in the GMAQS (U.S. DOI, 

MMS 1995). An average horsepower rating of 1,200 for all types of pipelaying vessels was 

provided in the GMAQS. It was assumed that this value would not change significantly in 2000. 

 The load factor was used in the EPAs marine diesel emission factor equation (EPA 2000): 

 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables E-2 were obtained from Table 

5-1 of the U.S. EPA Analysis of Commercial Marine Vessels Emissions and Fuel 

Consumption Data report (EPA 2000). The emission factors reported in these tables do 

not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A * (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 
E-4

The developed emissions factors were applied to the average horsepower and total time to lay 1 

foot of pipe to derive an emission factor that could be applied to the total length of pipe repaired 

or replaced. 

GIS data provided by MMS listed the length of pipe constructed in 2000 for all of the offshore 

lease blocks (Froomer 2002). By applying the pipe length emission factor to the MMS data set, 

total emissions were calculated for each segment, and then summed for the Gulf of Mexico (see 

Table E-3). 

Table E-1. Determination of Time to Lay One Foot of Pipe. 

Boats* Feet per Day

Operating 

Hrs per Day

Amount of 

Pipe per 

Hour (ft)

No. of Hours 

per Foot per 

Vessel

No. of Hours 

per Foot of 

Pipe

5 300 24 12.5 0.08 0.4

*Note: Number of boats was previously 6 and included 1 supply vessel, which has already 

 been accounted for in the support vessel calculations and was therefore removed from the 

 pipelaying calculation. 

Table E-2. Activity Data and Emission Factors for Pipelaying Vessels (per foot of pipe). 

Summary Data for Pipelaying Vessels

Operating 

Load Avg. HP Avg. kW Total Hrs per Foot

75% 1200 894.84 0.4

Emission Factors for Pipelaying Vessels (per foot of pipe)

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating lbs/hr Hrs/ft

Emission 

Factor 

(lbs/ft)

Adjusted 

Emission 

Rate 

(lbs/ft)**

PM 0.26 1.50 0.26 0.01 894.84 0.52 0.40 0.21 0.16

NOx 10.64 1.50 10.45 0.13 894.84 21.00 0.40 8.40 6.30

SO2* 1.79 N/A 0.00 2.00 894.84 3.53 0.40 1.41 1.06

CO 1.12 1.00 0.00 0.84 894.84 2.20 0.40 0.88 0.66

VOC 0.10 1.50 0.00 0.07 894.84 0.20 0.40 0.08 0.06

CO2 707.40 1.00 648.60 44.10 894.84 1,395.53 0.40 558.21 418.66

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 75% load factor. 
E-5

Table E-3. Allocation of Pollutant by Segment Number. 

Pollutant PM NOx SO2 CO VOC CO2

Pollutant per foot of 

pipe (tons/ft) 7.82E-05 3.15E-03 5.30E-04 3.31E-04 3.04E-05 2.09E-01

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

5475 6,000 0.47 18.90 3.18 1.98 0.18 1,255.98

10242 12,731 1.00 40.09 6.74 4.21 0.39 2,664.98

10243 12,731 1.00 40.09 6.74 4.21 0.39 2,664.98

11874 83,712 6.54 263.64 44.35 27.67 2.54 17,523.43

11875 87,321 6.83 275.01 46.26 28.86 2.65 18,278.91

11876 88,963 6.95 280.18 47.13 29.41 2.70 18,622.63

11877 12,185 0.95 38.38 6.45 4.03 0.37 2,550.69

11903 454,203 35.51 1,430.45 240.61 150.14 13.80 95,078.32

11952 723,354 56.55 2,278.11 383.19 239.11 21.98 151,419.70

12048 24,579 1.92 77.41 13.02 8.12 0.75 5,145.12

12050 5,752 0.45 18.12 3.05 1.90 0.17 1,204.07

12133 13,235 1.03 41.68 7.01 4.37 0.40 2,770.48

12222 32,702 2.56 102.99 17.32 10.81 0.99 6,845.51

12280 44,393 3.47 139.81 23.52 14.67 1.35 9,292.79

12320 1,861 0.15 5.86 0.99 0.62 0.06 389.56

12321 1,861 0.15 5.86 0.99 0.62 0.06 389.56

12349 3,667 0.29 11.55 1.94 1.21 0.11 767.61

12350 17,715 1.38 55.79 9.38 5.86 0.54 3,708.28

12351 17,722 1.39 55.81 9.39 5.86 0.54 3,709.75

12354 12,669 0.99 39.90 6.71 4.19 0.38 2,652.00

12355 9,724 0.76 30.62 5.15 3.21 0.30 2,035.53

12356 9,726 0.76 30.63 5.15 3.21 0.30 2,035.94

12357 3,555 0.28 11.20 1.88 1.18 0.11 744.17

12358 3,555 0.28 11.20 1.88 1.18 0.11 744.17

12383 12,402 0.97 39.06 6.57 4.10 0.38 2,596.11

12385 5,014 0.39 15.79 2.66 1.66 0.15 1,049.58

12386 13,779 1.08 43.40 7.30 4.55 0.42 2,884.36

12388 14,178 1.11 44.65 7.51 4.69 0.43 2,967.88

12392 354 0.03 1.11 0.19 0.12 0.01 74.10

12394 13,639 1.07 42.95 7.23 4.51 0.41 2,855.05

12395 24,305 1.90 76.55 12.88 8.03 0.74 5,087.77
E-6

Table E-3. Allocation of Pollutant by Segment Number (Continued). 

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

12397 7,982 0.62 25.14 4.23 2.64 0.24 1,670.87

12411 11,827 0.92 37.25 6.27 3.91 0.36 2,475.75

12415 3,025 0.24 9.53 1.60 1.00 0.09 633.22

12416 3,025 0.24 9.53 1.60 1.00 0.09 633.22

12418 4,296 0.34 13.53 2.28 1.42 0.13 899.28

12419 4,296 0.34 13.53 2.28 1.42 0.13 899.28

12427 4,579 0.36 14.42 2.43 1.51 0.14 958.52

12428 36,275 2.84 114.24 19.22 11.99 1.10 7,593.45

12429 36,277 2.84 114.25 19.22 11.99 1.10 7,593.86

12431 3,461 0.27 10.90 1.83 1.14 0.11 724.49

12436 18,134 1.42 57.11 9.61 5.99 0.55 3,795.99

12437 22,013 1.72 69.33 11.66 7.28 0.67 4,607.98

12445 9,663 0.76 30.43 5.12 3.19 0.29 2,022.76

12448 11,102 0.87 34.96 5.88 3.67 0.34 2,323.98

12450 45,941 3.59 144.69 24.34 15.19 1.40 9,616.83

12451 17,051 1.33 53.70 9.03 5.64 0.52 3,569.29

12455 5,005 0.39 15.76 2.65 1.65 0.15 1,047.70

12458 3,951 0.31 12.44 2.09 1.31 0.12 827.06

12459 3,952 0.31 12.45 2.09 1.31 0.12 827.27

12461 17,074 1.33 53.77 9.04 5.64 0.52 3,574.10

12462 20,811 1.63 65.54 11.02 6.88 0.63 4,356.37

12469 9,181 0.72 28.91 4.86 3.03 0.28 1,921.86

12471 5,547 0.43 17.47 2.94 1.83 0.17 1,161.15

12472 2,227 0.17 7.01 1.18 0.74 0.07 466.18

12477 16,731 1.31 52.69 8.86 5.53 0.51 3,502.30

12478 5,046 0.39 15.89 2.67 1.67 0.15 1,056.28

12479 3,970 0.31 12.50 2.10 1.31 0.12 831.04

12480 3,929 0.31 12.37 2.08 1.30 0.12 822.46

12481 4,788 0.37 15.08 2.54 1.58 0.15 1,002.27

12483 5,023 0.39 15.82 2.66 1.66 0.15 1,051.46

12484 5,024 0.39 15.82 2.66 1.66 0.15 1,051.67

12485 5,021 0.39 15.81 2.66 1.66 0.15 1,051.05

12488 8,307 0.65 26.16 4.40 2.75 0.25 1,738.90

12489 2,320 0.18 7.31 1.23 0.77 0.07 485.65
E-7

Table E-3. Allocation of Pollutant by Segment Number (Continued). 

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

12492 7,940 0.62 25.01 4.21 2.62 0.24 1,662.08

12502 20,262 1.58 63.81 10.73 6.70 0.62 4,241.44

12503 6,470 0.51 20.38 3.43 2.14 0.20 1,354.37

12507 1,000 0.08 3.15 0.53 0.33 0.03 209.33

12513 29,914 2.34 94.21 15.85 9.89 0.91 6,261.90

12515 5,031 0.39 15.84 2.67 1.66 0.15 1,053.14

12517 4,282 0.33 13.49 2.27 1.42 0.13 896.35

12519 7,783 0.61 24.51 4.12 2.57 0.24 1,629.22

12533 24,843 1.94 78.24 13.16 8.21 0.75 5,200.39

12534 24,697 1.93 77.78 13.08 8.16 0.75 5,169.82

12536 5,298 0.41 16.69 2.81 1.75 0.16 1,109.03

12544 1,909 0.15 6.01 1.01 0.63 0.06 399.61

12545 5,092 0.40 16.04 2.70 1.68 0.15 1,065.91

12546 11,070 0.87 34.86 5.86 3.66 0.34 2,317.28

12553 32,851 2.57 103.46 17.40 10.86 1.00 6,876.70

12559 4,062 0.32 12.79 2.15 1.34 0.12 850.30

12563 4,510 0.35 14.20 2.39 1.49 0.14 944.08

12564 4,163 0.33 13.11 2.21 1.38 0.13 871.44

12565 4,163 0.33 13.11 2.21 1.38 0.13 871.44

12572 7,253 0.57 22.84 3.84 2.40 0.22 1,518.27

12574 36,932 2.89 116.31 19.56 12.21 1.12 7,730.98

12575 2,844 0.22 8.96 1.51 0.94 0.09 595.33

12576 22,997 1.80 72.43 12.18 7.60 0.70 4,813.96

12582 16,367 1.28 51.55 8.67 5.41 0.50 3,426.10

12583 16,365 1.28 51.54 8.67 5.41 0.50 3,425.69

12639 6,241 0.49 19.66 3.31 2.06 0.19 1,306.43

12640 8,488 0.66 26.73 4.50 2.81 0.26 1,776.79

12641 1,864 0.15 5.87 0.99 0.62 0.06 390.19

12662 7,009 0.55 22.07 3.71 2.32 0.21 1,467.19

12693 11,626 0.91 36.61 6.16 3.84 0.35 2,433.67

12530 56,730 4.43 178.66 30.05 18.75 1.72 11,875.29

12531 23,739 1.86 74.76 12.58 7.85 0.72 4,969.29

12532 23,798 1.86 74.95 12.61 7.87 0.72 4,981.64

12549 7,752 0.61 24.41 4.11 2.56 0.24 1,622.73
E-8

Table E-3. Allocation of Pollutant by Segment Number (Continued). 

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

12550 7,752 0.61 24.41 4.11 2.56 0.24 1,622.73

12651 37,966 2.97 119.57 20.11 12.55 1.15 7,947.42

12490 26,750 2.09 84.25 14.17 8.84 0.81 5,599.58

12491 26,755 2.09 84.26 14.17 8.84 0.81 5,600.62

12542 32 0.00 0.10 0.02 0.01 0.00 6.70

12552 861 0.07 2.71 0.46 0.28 0.03 180.23

12695 12,153 0.95 38.27 6.44 4.02 0.37 2,543.99

12765 11,439 0.89 36.03 6.06 3.78 0.35 2,394.53

12253 14,766 1.15 46.50 7.82 4.88 0.45 3,090.97

12420 13,786 1.08 43.42 7.30 4.56 0.42 2,885.82

12338 8,052 0.63 25.36 4.27 2.66 0.24 1,685.53

12391 5,036 0.39 15.86 2.67 1.66 0.15 1,054.19

12396 9,392 0.73 29.58 4.98 3.10 0.29 1,966.03

12426 4,621 0.36 14.55 2.45 1.53 0.14 967.31

12433 4,240 0.33 13.35 2.25 1.40 0.13 887.56

12446 5,776 0.45 18.19 3.06 1.91 0.18 1,209.09

12604 2,651 0.21 8.35 1.40 0.88 0.08 554.93

12605 2,649 0.21 8.34 1.40 0.88 0.08 554.52

12652 5,013 0.39 15.79 2.66 1.66 0.15 1,049.37

12406 9,974 0.78 31.41 5.28 3.30 0.30 2,087.86

12409 9,974 0.78 31.41 5.28 3.30 0.30 2,087.86

12508 33,783 2.64 106.40 17.90 11.17 1.03 7,071.80

12509 5,337 0.42 16.81 2.83 1.76 0.16 1,117.19

12742 15,764 1.23 49.65 8.35 5.21 0.48 3,299.88

12743 3,135 0.25 9.87 1.66 1.04 0.10 656.25

12405 117,990 9.22 371.59 62.50 39.00 3.59 24,698.85

12626 76,180 5.96 239.92 40.36 25.18 2.31 15,946.76

12650 99 0.01 0.31 0.05 0.03 0.00 20.72

12631 4,201 0.33 13.23 2.23 1.39 0.13 879.40

12402 13,009 1.02 40.97 6.89 4.30 0.40 2,723.17

12101 4,838 0.38 15.24 2.56 1.60 0.15 1,012.74

12467 5,480 0.43 17.26 2.90 1.81 0.17 1,147.13

12468 5,480 0.43 17.26 2.90 1.81 0.17 1,147.13

12778 29,269 2.29 92.18 15.50 9.68 0.89 6,126.88
E-9

Table E-3. Allocation of Pollutant by Segment Number (Continued). 

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

12506 59,077 4.62 186.06 31.30 19.53 1.80 12,366.59

12612 18,024 1.41 56.76 9.55 5.96 0.55 3,772.96

12613 18,024 1.41 56.76 9.55 5.96 0.55 3,772.96

12620 15,731 1.23 49.54 8.33 5.20 0.48 3,292.97

12750 10,851 0.85 34.17 5.75 3.59 0.33 2,271.44

12751 10,850 0.85 34.17 5.75 3.59 0.33 2,271.23

12580 8,243 0.64 25.96 4.37 2.72 0.25 1,725.51

12547 7,108 0.56 22.39 3.77 2.35 0.22 1,487.92

12557 5,274 0.41 16.61 2.79 1.74 0.16 1,104.01

12711 14,028 1.10 44.18 7.43 4.64 0.43 2,936.48

12775 4,153 0.32 13.08 2.20 1.37 0.13 869.35

12398 2,175 0.17 6.85 1.15 0.72 0.07 455.29

12399 2,175 0.17 6.85 1.15 0.72 0.07 455.29

12694 17,169 1.34 54.07 9.10 5.68 0.52 3,593.99

12781 4,390 0.34 13.83 2.33 1.45 0.13 918.96

12689 54,763 4.28 172.47 29.01 18.10 1.66 11,463.54

12579 72,525 5.67 228.41 38.42 23.97 2.20 15,181.66

12697 5,531 0.43 17.42 2.93 1.83 0.17 1,157.80

12654 10,637 0.83 33.50 5.63 3.52 0.32 2,226.64

12655 10,552 0.82 33.23 5.59 3.49 0.32 2,208.85

12571 26,233 2.05 82.62 13.90 8.67 0.80 5,491.35

12560 1,937 0.15 6.10 1.03 0.64 0.06 405.47

12335 8,473 0.66 26.68 4.49 2.80 0.26 1,773.65

12343 6,270 0.49 19.75 3.32 2.07 0.19 1,312.50

12403 16,436 1.28 51.76 8.71 5.43 0.50 3,440.55

12441 20,730 1.62 65.29 10.98 6.85 0.63 4,339.41

12443 20,737 1.62 65.31 10.99 6.85 0.63 4,340.88

12444 20,803 1.63 65.52 11.02 6.88 0.63 4,354.69

12621 16,228 1.27 51.11 8.60 5.36 0.49 3,397.01

12634 1,753 0.14 5.52 0.93 0.58 0.05 366.96

12653 4,652 0.36 14.65 2.46 1.54 0.14 973.80

12380 2,475 0.19 7.79 1.31 0.82 0.08 518.09

12378 7,219 0.56 22.74 3.82 2.39 0.22 1,511.15

12764 3,331 0.26 10.49 1.76 1.10 0.10 697.28
E-10

Table E-3. Allocation of Pollutant by Segment Number (Continued). 

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

12628 76,109 5.95 239.70 40.32 25.16 2.31 15,931.90

12618 7,260 0.57 22.86 3.85 2.40 0.22 1,519.74

12619 13,967 1.09 43.99 7.40 4.62 0.42 2,923.71

12423 8,556 0.67 26.95 4.53 2.83 0.26 1,791.03

12709 9,590 0.75 30.20 5.08 3.17 0.29 2,007.47

12658 5,416 0.42 17.06 2.87 1.79 0.16 1,133.73

12744 3,135 0.25 9.87 1.66 1.04 0.10 656.25

11607 123 0.01 0.39 0.07 0.04 0.00 25.75

12581 18,771 1.47 59.12 9.94 6.20 0.57 3,929.33

12363 17,360 1.36 54.67 9.20 5.74 0.53 3,633.97

12367 2,373 0.19 7.47 1.26 0.78 0.07 496.74

12642 10,611 0.83 33.42 5.62 3.51 0.32 2,221.20

12643 1,801 0.14 5.67 0.95 0.60 0.05 377.00

12644 12,512 0.98 39.40 6.63 4.14 0.38 2,619.14

12645 23,637 1.85 74.44 12.52 7.81 0.72 4,947.93

12594 9,856 0.77 31.04 5.22 3.26 0.30 2,063.16

12596 9,856 0.77 31.04 5.22 3.26 0.30 2,063.16

12682 354 0.03 1.11 0.19 0.12 0.01 74.10

12705 10,596 0.83 33.37 5.61 3.50 0.32 2,218.06

12706 10,592 0.83 33.36 5.61 3.50 0.32 2,217.22

12707 10,591 0.83 33.35 5.61 3.50 0.32 2,217.01

12463 8,096 0.63 25.50 4.29 2.68 0.25 1,694.74

12464 8,097 0.63 25.50 4.29 2.68 0.25 1,694.95

12466 8,099 0.63 25.51 4.29 2.68 0.25 1,695.36

12496 918 0.07 2.89 0.49 0.30 0.03 192.16

12597 585 0.05 1.84 0.31 0.19 0.02 122.46

12688 8,961 0.70 28.22 4.75 2.96 0.27 1,875.81

12690 13,667 1.07 43.04 7.24 4.52 0.42 2,860.91

12728 1,652 0.13 5.20 0.88 0.55 0.05 345.81

12635 5,000 0.39 15.75 2.65 1.65 0.15 1,046.65

12648 4,477 0.35 14.10 2.37 1.48 0.14 937.17

12726 11,976 0.94 37.72 6.34 3.96 0.36 2,506.94

12401 9,491 0.74 29.89 5.03 3.14 0.29 1,986.75

12482 3,607 0.28 11.36 1.91 1.19 0.11 755.05
E-11

Table E-3. Allocation of Pollutant by Segment Number (Continued). 

Pollutant per segment (tons/segment) 

Segment

Segment 

Length 

(ft) PM NOx SO2 CO VOC CO2

12647 7,816 0.61 24.62 4.14 2.58 0.24 1,636.12

12578 7,311 0.57 23.03 3.87 2.42 0.22 1,530.41

12636 6,374 0.50 20.07 3.38 2.11 0.19 1,334.27

12659 3,876 0.30 12.21 2.05 1.28 0.12 811.36

12607 7,526 0.59 23.70 3.99 2.49 0.23 1,575.42

12608 7,524 0.59 23.70 3.99 2.49 0.23 1,575.00

12767 37,637 2.94 118.53 19.94 12.44 1.14 7,878.55

12449 23,254 1.82 73.24 12.32 7.69 0.71 4,867.76

12504 60,301 4.71 189.91 31.94 19.93 1.83 12,622.81

12135 64 0.01 0.20 0.03 0.02 0.00 13.40

12136 52 0.00 0.16 0.03 0.02 0.00 10.89

12754 121 0.01 0.38 0.06 0.04 0.00 25.33

13345 10,622 0.83 33.45 5.63 3.51 0.32 2,223.50

12657 12,924 1.01 40.70 6.85 4.27 0.39 2,705.38

12610 1,650 0.13 5.20 0.87 0.55 0.05 345.39

12630 15,662 1.22 49.33 8.30 5.18 0.48 3,278.53

12632 15,665 1.22 49.33 8.30 5.18 0.48 3,279.15

12629 15,663 1.22 49.33 8.30 5.18 0.48 3,278.74

12703 8,277 0.65 26.07 4.38 2.74 0.25 1,732.62

12616 23,610 1.85 74.36 12.51 7.80 0.72 4,942.28

12745 13,610 1.06 42.86 7.21 4.50 0.41 2,848.98

Total 4,259,777 333.01 13,415.60 2,256.58 1,408.10 129.45 891,699.19

References 

Froomer, Norman. May 10, 2002. E-mail entitled 2000 Pipelines to Richard Billings of Eastern 

Research Group. U.S. Dept. of the Interior, Minerals Management Service.

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002.
APPENDIX F 

LOUISIANA OFFSHORE OIL PORT 
F-3

The Louisiana Offshore Oil Port (LOOP) has multiple emission sources including some that are 

directly associated with the platform, such as generators and pumps. The LOOP also includes 

emission sources that are associated with the vessels that use the platform. The vessels would 

include the tankers that offload their product to the LOOP as well as support vessels that help 

guide the tankers to and from the mooring points. Details concerning platform and vessel 

activity were obtained from the LOOP website (LOOP 2001). 

Detailed geographic data provided on the LOOP website identifies the approach used by vessels, 

the waiting area, and the mooring points as well as latitude and longitude coordinates for the 

platform itself (LOOP 2001). 

Platform Sources 

The LOOP platform operates one 1000 kW generator and four 7,500 hp pumps. Hours of 

operation for the generator and pumps were obtained from the GMAQS (U.S. DOI, MMS, 1995); 

the generator was assumed to run continuously (8,760 hrs/yr) and the pumps operate a total of 

13,500 hours/year. It was assumed that 2000 activity was similar to 1995 level. Marine diesel 

emission factors for these sources were developed based on EPA’s marine diesel emission factor 

equation (EPA 2000): 

E (g/kW-hr) = A * (Engine Load Factor) –x +B 

Where: 

E is the power base emission factor; 

Constant A, intercept B, and exponential x, noted in Tables A-1 and A-2 were obtained 

from Table 5-1 of the U.S. EPA Office of Air and Radiation’s Analysis of Commercial 

Marine Vessels Emissions and Fuel Consumption Data report (EPA 2000). The emission 

factors reported in these tables do not always agree with the coefficients, due to round-off 

error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 
F-4

SO2 Emission Rate (g/kW-hr) = A* (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 

Engine load factors required in this algorithm were obtained from the GMAQS (U.S. DOI, MMS 

1995). The values obtained from this algorithm were converted to horsepower and applied to the 

horsepower data provided to develop the emission factors shown in Tables F-1 and F-2. These 

emission factors were applied to hours of operation to estimate emissions. 

Vessel Emissions 

The LOOP also provided detailed information about the individual vessels that used the platform 

in 2000 (Table F-3) and the line vessels that assisted the oil tankers in getting to and from the 

mooring points. The same approach used to develop the diesel marine emission factors for the 

LOOP platform sources was used for the associated vessel emission sources. 

The average hours tankers spent approaching the platform in the designated shipping lane were 

estimated based on the data provided and are summarized in Table F-4. 

Where it was reported that two vessels arrived at the LOOP on the same day, it was 

conservatively assumed that both vessels arrived at the same time. In this study one vessel was 

assumed to be moored at the LOOP offloading product, while the second vessel waited in the 

anchorage area. It was also assumed that once the first vessel moved away from the mooring 

point and maneuvered itself to return to the approach fairway and the mooring master, crew and 

equipment boarded the second vessel, the second vessel would move out of anchorage and up to 

the unloading mooring point. Typically it would take 24 hours for the first vessel to unload and 

2 hours (or approximately 10% of unloading time) to maneuver away from the mooring which 

equals 26 hours that the second vessel waited on average at anchorage. Note, this approach 

provides a conservative estimate of emissions as the second vessel may arrive hours after the first 

vessel, such that the second vessel's time at anchorage may be less than 26 hours and the actual 

emissions would be somewhat less than those estimated using these assumptions. Unfortunately, 

there are no data to quantify how much less actual emissions are from these potential emissions. 

It was assumed that the load factor for the approach to the platform was 55% of full engine load. 

Time spent hoteling and offloading to the platform was estimated based on data provided by the 

LOOP. It was assumed that during the period of hoteling and offloading the engine load factor 

was 10% of full engine load. 
F-5

As with the LOOP platform sources, diesel emission factors were derived from the EPA’s marine 

diesel emission factor equation (see Tables F-5 and F-6) (EPA 2000) and applied to average 

vessel horsepower and time in mode to estimate emissions (LOOP 2001). 

While offloading product to the LOOP, water is pumped into the tanker to provide ballast for the 

vessels. During this procedure volatile compounds are displaced into the atmosphere. Emissions 

from ballasting activities were estimated based on the approach used in the GMAQS (U.S. DOI, 

MMS 1995). 

For the support vessels, calculations were developed for the loader and the line vessels. Based 

on information provided in the LOOP’s website (LOOP 2001), it was assumed that each vessel 

was equipped with two 600 HP engines and operated on average at 25% of full engine load. 

Diesel emission factors developed for these vessels were derived from EPA’s marine diesel 

emission factor equation (see Table F-7). These emission factors were applied to vessel 

horsepower rating and hours of operation to estimate emissions. Lifter and responder vessels 

were not included in the calculations, as hours of operation were not readily available and it was 

thought that they operated on a less frequent basis than the other support vessels, thus their 

emissions would be relatively small. 

Emission estimates for all sources associated within the LOOP are noted in Table F-8. 

Table F-1. 1000kW Generator. 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted

Emission

Rate 

(lbs/hr)**

PM 0.27 1.50 0.2551 0.0059 1,000.00 0.27 0.60 0.30

NOx 10.80 1.50 10.4496 0.1255 1,000.00 10.80 23.82 11.91

SO2* 1.87 N/A 0 1.998 1,000.00 1.87 4.11 2.05

CO 1.68 1.00 0 0.8378 1,000.00 1.68 3.69 1.84

VOC 0.19 1.50 0 0.0667 1,000.00 0.19 0.42 0.21

CO2 736.80 1.00 648.6 44.1 1,000.00 736.80 1624.35 812.17

Assumed operating load = 50% 

*For SO2 fuel sulfur flow (g/kW-hr) = (14.12/(Fractional load) + 205.717)*0.4% or 0.004, using the fuel 

 sulfur concentration of 0.4%. 

**Adjusted based on a 50% load factor. 
F-6

Table F-2. Four 7,500 hp Pumps. 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

PM 0.26 1.50 0.2551 0.0059 5,592.75 1.46 3.22

NOx 10.58 1.50 10.4496 0.1255 5,592.75 59.14 130.39

SO2* 1.75 N/A 0 1.998 5,592.75 9.80 21.61

CO 0.84 1.00 0 0.8378 5,592.75 4.69 10.33

VOC 0.07 1.50 0 0.0667 5,592.75 0.37 0.82

CO2 692.70 1.00 648.6 44.1 5,592.75 3874.10 8540.84

Assumed operating load = 100% 

*For SO2 fuel sulfur flow (g/kW-hr) = (14.12/(Fractional load) + 205.717)*0.4% or 0.004, using a fuel 

 sulfur concentration of 0.4%. 

Table F-3. LOOP Vessel Activity Data. 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Front Breaker 1,049,582 38.05 166,474 1/1/00 25,883.87 19,309.37

Nisyros 950,450 19.9 141,659 1/1/00 1 23,377.56 17,439.66

Kapetan Giorgis 3,259,353 57.48 449,182 1/2/00 54,437.38 40,610.29

Corona Star 1,607,607 38.42 229,073 1/5/00 32,206.37 24,025.95

Alta 945,171 21.7 143,960 1/6/00 23,609.96 17,613.03

Front Warrior 960,420 30.4 150,906 1/7/00 24,311.51 18,136.38

Astro Capella 1,052,221 19.6 157,190 1/8/00 24,946.19 18,609.86

World Phoenix 757,281 10.95 253,988 1/11/00 34,722.79 25,903.20

Front Fighter 828,143 23 150,906 1/12/00 24,311.51 18,136.38

Media Star 1,006,847 20.78 405,010 1/13/00 49,976.01 37,282.10

Maersk Navarin 1,384,944 28 251,280 1/15/00 34,449.28 25,699.16

Star Ohio 948,426 22.7 141,480 1/15/00 1 23,359.48 17,426.17

Argo Elektra 941,494 19.77 281,255 1/16/00 37,476.76 27,957.66

Olympic Sponsor 199,349 6.7 95,022 1/17/00 18,667.22 13,925.75

Alta 939,203 21.9 143,960 1/22/00 23,609.96 17,613.03

Meridian Lion 996,283 18.3 269,445 1/23/00 36,283.95 27,067.82

Astro Canopus 1,050,667 19.68 155,505 1/27/00 24,776.01 18,482.90

Berge Pioneer 523,335 12.2 355,020 1/27/00 1 44,927.02 33,515.56

Phoenix Star 1,012,534 19.63 286,832 1/27/00 1 38,040.03 28,377.86

Atlantic Prosperity 1,137,215 16.3 306,766 1/28/00 40,053.37 29,879.81

New Vision 999,428 16.23 293,327 1/30/00 38,696.03 28,867.24

Safaniy AH 2,125,803 36.3 294,720 1/30/00 1 38,836.72 28,972.19
F-7

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Magnolia 543,267 26 280,325 1/31/00 37,382.83 27,887.59

Libra Star 1,553,630 24.1 286,832 2/6/00 38,040.03 28,377.86

Alta 998,891 23.27 143,960 2/7/00 23,609.96 17,613.03

Harriet 815,067 20.18 133,826 2/7/00 1 22,586.43 16,849.47

Empress Des Mers 2,468,182 45.54 417,008 2/8/00 51,187.81 38,186.10

Hawtah 1,114,317 18.8 294,720 2/9/00 38,836.72 28,972.19

Andros Georgios 502,113 14.8 229,043 2/11/00 32,203.34 24,023.69

Astro Canopus 1,048,750 19.1 158,000 2/12/00 25,028.00 18,670.89

Kapetan Michalis 1,229,955 23.1 508,268 2/12/00 1 60,405.07 45,062.18

Front Lady 1,326,618 24.73 279,994 2/14/00 37,349.39 27,862.65

Beryl 248,682 7.1 93,652 2/16/00 18,528.85 13,822.52

Jupiter Glory 1,574,440 26.1 294,096 2/19/00 38,773.70 28,925.18

Polar 985,945 31 151,706 2/21/00 24,392.31 18,196.66

Pacific Ruby 248,569 7.62 94,654 2/22/00 18,630.05 13,898.02

Columba Star 622,119 8.54 299,811 2/23/00 39,350.91 29,355.78

Jahre Viking 1,330,678 19.5 555,843 2/26/00 65,210.14 48,646.77

New Wisdom 2,116,708 35.84 293,326 2/26/00 1 38,695.93 28,867.16

Astro Canopus 1,048,661 18 158,000 2/29/00 25,028.00 18,670.89

Kapetan Hiotis 2,926,900 58.33 406,592 2/29/00 1 50,135.79 37,401.30

Alta 1,013,976 23.8 143,960 3/2/00 23,609.96 17,613.03

Neptune Glory 549,045 7.4 299,127 3/2/00 1 39,281.83 29,304.24

Wilmington 576,919 24.8 86,272 3/5/00 17,783.47 13,266.47

Shaula Star 2,097,631 37.27 296,828 3/6/00 39,049.63 29,131.02

Front Fighter 478,023 7.53 150,906 3/10/00 24,311.51 18,136.38

Luxembourg 1,362,760 20.4 300,000 3/11/00 39,370.00 29,370.02

Narova 826,353 19.5 141,622 3/12/00 23,373.82 17,436.87

Lillo 994,182 27 138,334 3/14/00 23,041.73 17,189.13

Nord Jahre Target 449,084 8.1 139,788 3/14/00 1 23,188.59 17,298.69

Auriga 1,559,074 41.4 404,105 3/15/00 49,884.61 37,213.92

World Prelude 1,325,000 21.58 249,988 3/15/00 1 34,318.79 25,601.82

J. Dennis Bonney 414,104 7.07 152,653 3/18/00 24,487.95 18,268.01

Sks Tweed 521,629 18.6 108,170 3/21/00 19,995.17 14,916.40
F-8

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

British Vigilance 1,249,495 38 294,967 3/22/00 38,861.67 28,990.80

Berge Enterprise 2,007,405 36.5 355,003 3/23/00 44,925.30 33,514.28

Soro 1,333,011 20 294,984 3/23/00 1 38,863.38 28,992.08

British Hawk 997,399 22.66 149,066 3/25/00 24,125.67 17,997.75

Mira Star 1,502,794 36.7 416,950 3/26/00 51,181.95 38,181.73

British Harrier 1,025,075 23.1 149,066 3/30/00 24,125.67 17,997.75

Media Star 1,498,540 34.73 405,010 3/30/00 1 49,976.01 37,282.10

Siam 908,690 17.7 295,261 3/30/00 1 38,891.36 29,012.96

Ramlah 2,122,494 34.8 294,720 4/1/00 38,836.72 28,972.19

Atlantic Prosperity 1,599,303 22.7 164,373 4/3/00 25,671.67 19,151.07

Atlantic Liberty 2,115,749 35.1 306,703 4/4/00 40,047.00 29,875.06

Emma Maersk 1,574,419 29.96 294,179 4/6/00 38,782.08 28,931.43

Alta 937,418 23.17 143,960 4/7/00 23,609.96 17,613.03

Berge Pioneer 1,711,155 28.57 355,020 4/8/00 44,927.02 33,515.56

Front Champion 950,662 15.47 303,824 4/8/00 1 39,756.22 29,658.14

Alda Wha 515,328 8.9 280,039 4/10/00 37,353.94 27,866.04

Olymipic Legacy 1,384,367 31.1 298,007 4/10/00 1 39,168.71 29,219.86

Chanda 939,158 20.2 146,155 4/12/00 23,831.66 17,778.41

Equatorial Lion 408,334 12.4 269,219 4/12/00 1 36,261.12 27,050.79

Agios Nikolaos 1,542,218 22.4 277,301 4/13/00 37,077.40 27,659.74

British Harrier 1,023,982 20.77 149,066 4/14/00 24,125.67 17,997.75

Ellen Maersk 924,743 17.4 307,190 4/15/00 40,096.19 29,911.76

Kapetan Giannis 1,001,201 19.9 508,731 4/16/00 60,451.83 45,097.07

New Wisdom 947,015 16.4 293,326 4/17/00 38,695.93 28,867.16

Luxembourg 490,302 7.08 300,000 4/18/00 39,370.00 29,370.02

Almudaina 448,729 9.2 144,927 4/19/00 23,707.63 17,685.89

Libra Star 994,805 19.52 286,832 4/19/00 1 38,040.03 28,377.86

Sabine 845,490 19.79 154,846 4/19/00 1 24,709.45 18,433.25

Princess Susana 1,014,038 27.47 149,890 4/20/00 24,208.89 18,059.83

Orion Star 1,595,124 29.25 300,953 4/21/00 39,466.25 29,441.82

Empress Des Mers 2,447,203 45.4 417,008 4/28/00 51,187.81 38,186.10
F-9

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Volans 1,993,274 33.9 356,399 4/28/00 1 45,066.30 33,619.46

Kapetan Panagiotis 1,995,647 33.91 449,842 5/2/00 54,504.04 40,660.02

Alphard Star 1,562,443 24.7 297,094 5/3/00 39,076.49 29,151.06

Andros Georgios 582,426 17.1 229,043 5/3/00 1 32,203.34 24,023.69

British Vigilance 1,461,611 30.4 294,967 5/4/00 38,861.67 28,990.80

Chanda 1,001,302 23.6 146,155 5/4/00 1 23,831.66 17,778.41

Watban 1,955,273 40.42 294,720 5/8/00 38,836.72 28,972.19

Golar Dundee 1,572,916 36.9 297,641 5/11/00 39,131.74 29,192.28

Limburg 1,010,290 23.5 300,000 5/11/00 1 39,370.00 29,370.02

Chios 491,357 10.81 297,051 5/13/00 39,072.15 29,147.82

World Pendant 1,844,414 41.4 249,988 5/13/00 1 34,318.79 25,601.82

Front Breaker 1,049,175 24.8 159,000 5/14/00 25,129.00 18,746.23

Atlantic Liberty 1,892,474 49.73 306,703 5/15/00 40,047.00 29,875.06

New World 539,753 10.3 134,367 5/15/00 1 22,641.07 16,890.24

Kapetan Hiotis 2,467,120 46.71 406,692 5/18/00 50,145.89 37,408.84

Astro Centaurus 1,067,975 19.3 295,552 5/20/00 38,920.75 29,034.88

Sacramento 477,046 8.3 156,000 5/22/00 24,826.00 18,520.20

Argo Elektra 859,673 13.23 281,255 5/25/00 37,476.76 27,957.66

Geres 999,862 25.4 130,770 5/30/00 22,277.77 16,619.22

Luxembourg 1,393,315 19.9 300,000 5/30/00 1 39,370.00 29,370.02

Phoenix Star 1,981,440 36.3 286,832 5/31/00 38,040.03 28,377.86

Eagle Auriga 527,799 17.7 98,421 6/2/00 19,010.52 14,181.85

New Wisdom 907,271 17.4 293,326 6/3/00 38,695.93 28,867.16

Berge Stavanger 2,114,139 44.4 301,590 6/7/00 39,530.59 29,489.82

Boree 900,679 15.4 279,378 6/7/00 1 37,287.18 27,816.23

British Hawk 1,015,528 21.5 149,066 6/8/00 24,125.67 17,997.75

Sovereign Unity 535,242 10.8 302,151 6/10/00 39,587.25 29,532.09

Columba Star 997,103 25.8 299,811 6/13/00 39,350.91 29,355.78

Nordmillennium 1,335,641 25.9 301,342 6/13/00 1 39,505.54 29,471.13

Auriga 842,843 19.9 404,105 6/14/00 49,884.61 37,213.92

Front Rider 598,269 15.1 166,474 6/16/00 25,883.87 19,309.37
F-10

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Jahre Viking 1,224,204 46 555,843 6/16/00 1 65,210.14 48,646.77

Chanda 997,223 22.3 146,155 6/17/00 23,831.66 17,778.41

Media Star 2,115,728 37.1 405,010 6/17/00 1 49,976.01 37,282.10

Limburg 1,289,297 23.95 299,364 6/20/00 39,305.76 29,322.10

Nord Jahre Target 387,591 17.3 139,788 6/22/00 23,188.59 17,298.69

Berge Pioneer 1,523,689 29.54 355,020 6/23/00 44,927.02 33,515.56

Golar Glasgow 1,286,960 20.05 297,643 6/24/00 39,131.94 29,192.43

Markab Star 567,580 9.1 296,469 6/24/00 1 39,013.37 29,103.97

Welsh Venture 474,302 14.2 276,601 6/24/00 1 37,006.70 27,607.00

Lillo 949,323 24.8 138,334 6/25/00 23,041.73 17,189.13

Front Maple 948,518 21 132,868 6/28/00 22,489.67 16,777.29

Magdelaine 955,347 16.1 269,451 6/28/00 1 36,284.55 27,068.28

Erati 562,644 16.7 157,196 6/29/00 24,946.80 18,610.31

Paola I 629,742 19.1 104,451 6/29/00 1 19,619.55 14,636.19

Front Climber 529,602 13 166,474 6/30/00 25,883.87 19,309.37

Crown Unity 2,079,200 41.75 295,803 7/1/00 38,946.10 29,053.79

Kraka 2,025,174 48.83 351,952 7/3/00 44,617.15 33,284.40

Ascona 1,491,039 26.27 294,472 7/5/00 38,811.67 28,953.51

Hydra Star 1,064,941 15.4 301,015 7/5/00 1 39,472.52 29,446.50

Chanda 1,021,955 22 146,155 7/6/00 23,831.66 17,778.41

Genmar Zoe 1,004,202 20.1 155,103 7/6/00 1 24,735.40 18,452.61

Pherkad Star 2,072,901 47 296,629 7/7/00 39,029.53 29,116.03

Front Breaker 501,041 14.17 159,000 7/8/00 25,129.00 18,746.23

Else Maersk 1,016,601 16.55 307,190 7/11/00 40,096.19 29,911.76

Nisyros 490,616 11.9 141,659 7/13/00 23,377.56 17,439.66

Alta 1,018,037 23.5 143,960 7/15/00 23,609.96 17,613.03

Front Pride 385,132 6.6 147,322 7/15/00 1 23,949.52 17,866.34

Ghawar 1,603,528 28.6 294,720 7/15/00 1 38,836.72 28,972.19

Polar 980,164 52.45 151,076 7/17/00 24,328.68 18,149.19

British Valour 1,240,462 20.3 294,967 7/18/00 38,861.67 28,990.80

Ramlah 1,068,200 18.7 294,720 7/18/00 1 38,836.72 28,972.19
F-11

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Golar Stirling 1,001,764 19.2 297,663 7/19/00 39,133.96 29,193.94

Olympic Breeze 518,111 15.2 268,777 7/20/00 36,216.48 27,017.49

Astro Canopus 530,058 8 155,505 7/24/00 24,776.01 18,482.90

Moscliff 740,003 18.8 252,658 7/26/00 34,588.46 25,802.99

Front Tarim 1,274,798 29.5 295,620 7/27/00 38,927.62 29,040.00

Atlantis 1,027,295 18.99 141,950 7/28/00 23,406.95 17,461.58

Kapetan Giorgis 1,057,985 24.8 449,182 7/29/00 54,437.38 40,610.29

Astro Centaurus 2,087,702 38.65 295,552 7/30/00 38,920.75 29,034.88

Chanda 946,635 20.5 146,155 7/30/00 1 23,831.66 17,778.41

Crown Jewel I 1,829,699 43.9 253,401 8/1/00 34,663.50 25,858.97

Genmar Zoe 1,001,993 21.2 155,103 8/4/00 24,735.40 18,452.61

Front Rider 995,535 22.33 166,474 8/5/00 25,883.87 19,309.37

Overseas Donna 1,079,206 21.93 308,700 8/5/00 1 40,248.70 30,025.53

Kapetan Panagiotis 901,456 16.9 449,842 8/6/00 54,504.04 40,660.02

Alrehab 1,955,291 34 296,246 8/8/00 38,990.85 29,087.17

Safaniyah 2,118,654 36.96 294,720 8/9/00 38,836.72 28,972.19

Raphael 1,623,072 25.97 309,614 8/10/00 40,341.01 30,094.40

Columbia Spirit 548,753 23.2 83,501 8/11/00 17,503.60 13,057.69

Front Driver 525,135 11.5 132,867 8/11/00 1 22,489.57 16,777.22

Alda Wha 1,025,267 40.57 136,623 8/13/00 22,868.92 17,060.22

Jupiter Glory 539,402 10.7 294,097 8/13/00 1 38,773.80 28,925.25

Berge Odel 875,747 26.87 278,801 8/14/00 37,228.90 27,772.76

Arctic Blue 1,819,717 27.2 467,627 8/15/00 56,300.33 42,000.04

Alta 903,209 20.5 143,960 8/19/00 23,609.96 17,613.03

Olympic Legacy 1,038,744 18 298,007 8/19/00 1 39,168.71 29,219.86

North Star 534,345 16.5 146,215 8/20/00 23,837.72 17,782.94

New World 575,539 10.97 134,367 8/21/00 22,641.07 16,890.24

Hellespont 

Embassy 

1,921,781 37.13 400,070 8/22/00 49,477.07 36,909.89

Red Seagull 505,627 15.7 399,843 8/23/00 49,454.14 36,892.79

Margaux 1,509,046 38 269,833 8/26/00 36,323.13 27,097.06
F-12

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Atlantic Liberty 1,060,661 20 305,104 8/28/00 39,885.50 29,754.59

Hawtah 1,122,099 20.8 294,720 8/28/00 1 38,836.72 28,972.19

Maersk Estelle 1,413,157 27.7 294,967 8/28/00 1 38,861.67 28,990.80

Chanda 904,679 18.47 146,155 8/30/00 23,831.66 17,778.41

Gemini Star 2,054,840 44.1 297,094 8/30/00 1 39,076.49 29,151.06

James N. Sullivan 500,034 8.4 133,768 8/31/00 22,580.57 16,845.10

Berge Fuji 1,036,878 19.3 296,000 9/2/00 38,966.00 29,068.64

Front Maple 1,005,394 20.4 132,868 9/2/00 1 22,489.67 16,777.29

Nisyros 351,556 9.8 141,659 9/2/00 1 23,377.56 17,439.66

Agios Nikolaos 1,544,747 25.2 277,301 9/3/00 37,077.40 27,659.74

Media Star 2,879,289 52.3 405,010 9/6/00 49,976.01 37,282.10

Mira Star 887,416 24.7 416,950 9/8/00 51,181.95 38,181.73

Andros Georgios 1,131,218 22.1 299,043 9/10/00 39,273.34 29,297.91

Genmar Macedon 1,072,946 27.6 153,090 9/13/00 24,532.09 18,300.94

Eli Maersk 1,010,337 15.9 308,491 9/15/00 40,227.59 30,009.78

Hellespont Capitol 1,535,339 32.4 375,881 9/15/00 1 47,033.98 35,087.35

Polar 963,087 31.6 151,076 9/16/00 24,328.68 18,149.19

Columba Star 2,106,259 43.8 299,811 9/18/00 39,350.91 29,355.78

Jahre Viking 1,108,526 30.6 555,843 9/21/00 65,210.14 48,646.77

Kapetan Hatzis 2,630,417 51.1 406,099 9/21/00 1 50,086.00 37,364.16

Majestic Unity 924,043 16.1 300,549 9/23/00 39,425.45 29,411.38

Marble 535,009 10.1 132,868 9/25/00 22,489.67 16,777.29

Olympia 550,090 15.3 105,488 9/25/00 1 19,724.29 14,714.32

Astro Lyra 919,954 16.4 284,410 9/27/00 37,795.41 28,195.38

Front Guider 1,050,982 21.6 166,474 9/28/00 25,883.87 19,309.37

Corona Star 1,604,596 51.9 229,073 9/29/00 32,206.37 24,025.95

Genmar Macedon 1,080,063 28.9 153,090 9/29/00 1 24,532.09 18,300.94

Maersk Eleo 1,021,982 22.9 294,179 10/1/00 38,782.08 28,931.43

Astro Gamma 784,260 23.6 264,073 10/3/00 35,741.37 26,663.06

Front Chief 982,004 13.5 308,700 10/4/00 40,248.70 30,025.53

Minerva Nounou 1,009,438 18.7 147,450 10/5/00 23,962.45 17,875.99

Sea Splendor 2,880,839 78.2 402,936 10/6/00 49,766.54 37,125.84

Empress Des Mers 1,983,991 36.2 417,008 10/11/00 51,187.81 38,186.10

Genmar Spartiate 1,058,928 26.4 152,700 10/13/00 24,492.70 18,271.55
F-13

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Narova 984,572 20.1 141,622 10/13/00 1 23,373.82 17,436.87

J. Bennett Johnston 1,118,992 20.9 305,099 10/15/00 39,885.00 29,754.21

Kapetan Giorgis 600,090 9.9 449,182 10/15/00 1 54,437.38 40,610.29

Wilma Yangtze 525,146 11.1 149,591 10/16/00 24,178.69 18,037.30

Kapetan Giannis 1,090,077 14.5 508,731 10/17/00 60,451.83 45,097.07

Shaula Star 2,060,297 37.4 296,828 10/19/00 39,049.63 29,131.02

Berge Boss 518,144 15.2 310,713 10/20/00 40,452.01 30,177.20

British Progress 996,645 20.4 306,397 10/21/00 40,016.10 29,852.01

Jupiter Glory 1,588,377 30.8 294,097 10/22/00 38,773.80 28,925.25

Sks Tagus 600,199 20.8 108,170 10/23/00 19,995.17 14,916.40

Berge Ichiban 1,079,006 14.3 298,522 10/26/00 39,220.72 29,258.66

Eirini L 566,083 13.6 147,276 10/27/00 23,944.88 17,862.88

Golar Glasgow 1,600,182 24.5 297,643 10/28/00 39,131.94 29,192.43

Moscliff 1,804,613 47.2 252,658 10/29/00 34,588.46 25,802.99

Alta 978,432 21.6 143,960 11/1/00 23,609.96 17,613.03

Seasprite 850,196 19.1 148,500 11/1/00 1 24,068.50 17,955.10

AL Balistar 1,197,193 18.8 286,832 11/2/00 38,040.03 28,377.86

Carina Star 2,105,303 34 300,840 11/3/00 39,454.84 29,433.31

Andros Georgios 571,655 13.9 229,043 11/6/00 32,203.34 24,023.69

Lillo 614,387 20.7 138,334 11/6/00 1 23,041.73 17,189.13

Mirfak Star 2,068,725 39.3 296,779 11/6/00 1 39,044.68 29,127.33

Maersk Estelle 1,459,434 29.4 294,967 11/11/00 38,861.67 28,990.80

Overseas New York 499,265 12.9 90,393 11/11/00 1 18,199.69 13,576.97

Gemini Star 537,197 11.9 297,967 11/12/00 39,164.67 29,216.84

Front Ardenne 1,018,460 24.8 150,733 11/13/00 24,294.03 18,123.35

Golar Edinburgh 1,128,117 26.2 297,656 11/13/00 1 39,133.26 29,193.41

Hellespont 

Paramount 

2,266,125 40.8 369,932 11/16/00 46,433.13 34,639.12

Skyros 481,121 7.8 323,100 11/18/00 41,703.10 31,110.51

Overseas New York 502,775 11.6 90,393 11/19/00 18,199.69 13,576.97

Kapetan Michalis 2,092,402 39.5 508,268 11/20/00 60,405.07 45,062.18

Star Ohio 734,623 18.1 141,480 11/20/00 1 23,359.48 17,426.17

Front Brabant 1,044,042 22.6 154,855 11/22/00 24,710.36 18,433.92

Astro Gamma 1,850,755 49.2 264,073 11/24/00 35,741.37 26,663.06
F-14

Table F-3. LOOP Vessel Activity Data (Continued). 

Vessel Name Cargo (BBL) Hrs 

Dead 

Weight 

Tonnage Call Date Overlap Avg. HP Avg. kW 

Emilie Maersk 1,036,489 14.7 303,619 11/24/00 1 39,735.52 29,642.70

Overseas New York 503,177 12.2 90,393 11/25/00 18,199.69 13,576.97

Berge Stadt 475,435 8.3 302,103 11/27/00 39,582.40 29,528.47

Alta 939,890 21 143,960 11/29/00 23,609.96 17,613.03

Senang Spirit 666,374 17.2 94,138 11/29/00 1 18,577.94 13,859.14

Ishwari 467,116 10.6 137,294 12/1/00 22,936.69 17,110.77

Media Star 746,885 12 405,010 12/1/00 1 49,976.01 37,282.10

Hydra Star 2,111,721 40.7 310,015 12/3/00 40,381.52 30,124.61

Overseas New York 501,131 12.2 90,393 12/3/00 1 18,199.69 13,576.97

Hamal Star 1,576,319 26.5 296,796 12/6/00 39,046.40 29,128.61

Auriga 2,457,762 50 404,105 12/9/00 49,884.61 37,213.92

Kristhild 1,820,362 45.3 253,999 12/9/00 1 34,723.90 25,904.03

Mira Star 1,000,202 22.8 416,950 12/11/00 51,181.95 38,181.73

Mosocean 840,013 13.3 252,662 12/12/00 34,588.86 25,803.29

Licorne Pacifique 1,385,086 21.4 264,758 12/14/00 35,810.56 26,714.68

Millennium Maersk 1,030,083 15.2 308,492 12/14/00 1 40,227.69 30,009.86

New Horizon 1,005,229 34.9 132,703 12/14/00 1 22,473.00 16,764.86

Alta 1,006,427 21.5 143,960 12/15/00 23,609.96 17,613.03

Pherkad Star 1,081,456 25.6 296,629 12/17/00 39,029.53 29,116.03

Berge Pioneer 2,233,418 36.4 360,717 12/18/00 45,502.42 33,944.80

Astro Capella 829,565 17.2 157,190 12/19/00 24,946.19 18,609.86

Corona Star 1,052,272 23.1 229,073 12/20/00 32,206.37 24,025.95

Chanda 631,786 17.8 141,155 12/21/00 23,326.66 17,401.68

Andros Georgios 603,007 12 229,043 12/22/00 32,203.34 24,023.69

Harriet 977,829 27.8 132,826 12/22/00 1 22,485.43 16,774.13

Front Breaker 1,081,267 25.4 159,000 12/23/00 25,129.00 18,746.23

Jahre Viking 1,580,041 26.5 555,843 12/23/00 1 65,210.14 48,646.77

Front Champion 1,164,645 23.5 306,274 12/24/00 40,003.67 29,842.74

Olympic Legacy 1,057,873 17.8 298,007 12/25/00 39,168.71 29,219.86

Christina 461,211 10.9 308,000 12/28/00 40,178.00 29,972.79

Sea Splendor 2,084,445 35.8 402,936 12/30/00 49,766.54 37,125.84

Sums: 316,338,690 6612 255,268 275 71 9,584,315.47 7,149,899.34

Source: LOOP 2001.
F-15

Table F-4. Summary of Vessel Activity. 

Idling (10% of full engine load)

Number of calls: 275

Average hours per unload: 24

Total hours at unloading: 6,612

Percentage vessels to anchorage: 26

Total time at anchorage: 1,878

Total hours at idle 8,489

Approach (55% of full engine load)

Number of calls: 275

Distance of safety fairway (km): 65

Vessel speed (km/hr): 10.186

Time to approach: 6.38

Total time at approach 1,754.86

Ballasting

Number of calls: 275

VOC emissions per call (tons): 2.13

Total annual VOC from ballasting (tons) 585.75

Ave. HP Ave. kW

Average Dead Weight Tonnage of tanker: 255,268 34,852.06 25,989.18

Source: LOOP 2001. 
F-16

Table F-5. Emission Factors for Approaching Tankers. 

Activity Data 

Avg. HP Avg. kW

Average DWT* of tanker 255,268 34,852 25,989

* DWT = Dead weight tonnage. 

Approach 

Pollutant

E 

(g/kW-hr) 

Exponent

(x) 

Intercept 

(B) 

Coefficient 

(A) 

Avg. kW 

rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.2696 1.5 0.2551 0.0059 25,989 7,005.8 15.44 8.49

NOx 10.7573 1.5 10.4496 0.1255 25,989 279,572.7 616.35 339.00

SO2* 1.8493 N/A 0 1.998 25,989 48,060.9 105.95 58.27

CO 1.5233 1 0 0.8378 25,989 39,588.6 87.27 48.00

VOC 0.1635 1.5 0 0.0667 25,989 4,249.9 9.36 5.15

CO2 728.7818 1 648.6 44.1 25,989 18,940.4 41,756.10 22,965.85

Assumed operating load = 55% 

*For SO2 fuel sulfur flow (g/kW-hr) = (14.12/(Fractional load) + 205.717)*0.4% or 0.004, using a fuel sulfur 

 concentration of 0.4%. 

**Adjusted based on a 55% load factor. 

Table F-6. Emission Factors for Idle Tankers. 

Activity Data 

Avg. HP Avg. kW

Average DWT of tanker 255,268 34,852 25,989

Idle 

Pollutant

E 

(g/kW-hr)

Exponent

(x)

Intercept 

(B)

Coefficient 

(A)

Avg kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.4417 1.5 0.2551 0.0059 25,989 11.48 25.31 2.53

NOx 14.41826 1.5 10.4496 0.1255 25,989 374.72 826.10 82.61

SO2* 2.768189 N/A 0 1.998 25,989 71.94 158.61 15.86

CO 8.378 1 0 0.8378 25,989 217.74 480.02 48.00

VOC 2.109239 1.5 0 0.0667 25,989 54.81 120.85 12.08

CO2 1089.6 1 648.6 44.1 25,989 28,317.81 62,429.44 6,242.94

Assumed operating load = 10% 

*Fuel sulfur flow (g/kW-hr) = (14.12/(Fractional load) + 205.717)*0.4% or 0.004, using a fuel sulfur concentration 

 of 0.4%. 

**Adjusted based on a 10% load factor. 
F-17

Table F-7. Emission Factors for Support Vessels. 

Support Vessels (2) with total brake horsepower of 1200 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.3023 1.5 0.2551 0.0059 894.84 0.27 0.60 0.15

NOx 11.4536 1.5 10.4496 0.1255 894.84 10.25 22.60 5.65

SO2* 2.091107 N/A 0 1.998 894.84 1.87 4.1 1.02

CO 3.3512 1 0 0.8378 894.84 3.00 6.61 1.65

VOC 0.5336 1.5 0 0.0667 894.84 0.48 1.05 0.26

CO2 825 1 648.6 44.1 894.84 738.24 1,627.53 406.88

Assumed operating load = 25% 

* For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study 

 the fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 25% load factor. 

Table F-8. LOOP Emissions. 

Platform Tankers Support Vessels*

Pollutant 

Generator

(tons/year)

Pumps 

(tons/year) 

Idle 

(tons/year) 

Approach 

(tons/year) 

Line Vessels 

(tons/year) 

Total 

(tons/year) 

PM 1.31 10.86 10.74 7.45 0.49 30.86

NOx 52.17 440.06 350.65 297.44 18.67 1,158.99

SO2 9.03 73.11 67.43 51.13 3.42 204.11

CO 8.09 34.87 203.75 42.12 5.46 294.29

VOC 0.91 2.78 51.30 4.52 0.87 60.37

CO2 3,557.33 28,825.32 26,498.86 20,150.92 1,345.06 80,377.48

Ballasting 

Number of calls: 275.00

VOC emissions per call (tons): 2.13

Total annual VOC from ballasting (tons) 585.75

* Assumes 6,566 hours of operation for support vessels. 

 1,755 hours of operation for tanker approach to/from LOOP. 

 8,489 hours of operation for tanker idling at LOOP. 

 8,760 hours of operation for platform generators. 

 13,500 hours of operation for platform pumps. 
F-18

References 

LOOP. 2001. “Louisiana Offshore Oil Platform.” http://www.loopllc.com/f1.htm. Accessed 

October 2001. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX G 

VESSEL LIGHTERING 
G-3

The Coast Guard provided activity data for vessel lightering in the GOM (Thomas 2001, 

McClellan 2002). As lightering occurs, the ships are also ballasting, so ballasting emissions 

were included with the lightering emissions. To calculate the emissions from the ships involved 

in the lightering process, activity data was obtained, which included the amount of petroleum 

product lightered, the time period tankers spend in lightering zone, and the number of ships 

involved in the process. Vessel lightering occurs with two types of vessels; large oil tankers 

which offload the oil product, typically having an average dead weight tonnage (DWT) of 

250,000, and smaller escort vessels that have an average DWT of 75,000. These smaller vessels 

carry on average 500,000 barrels of product from the oil tankers to port. The total number of 

escort vessel trips was estimated by dividing the total number of barrels of product handeled in 

the lightering zones by the average storage capacity of the escort vessels (see Table G-1). 

Specific activity data for individual lightering zones were not available, but Coast Guard staff did 

provide approximate estimates for each zone (see Table G-2). 

The location of each of the lightering zones was identified and the distance to port was 

calculated. It was assumed that escort vessels would travel at 12 miles per hour. Based on this 

assumed speed and the calculated distance from port of each lightering zones, hours were 

calculated for the vessel to make the round trip from port to lightering zone and back to port. 

Time spent (1 hour) traveling in Texas state waters (extending 12 miles from shore seaward) was 

excluded from our activity estimates. 

The collected activity data were applied to diesel emission factors based on the EPA marine 

diesel emission factor equation (EPA 2000): 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables G-3, G-4, and G-5 were 

obtained from Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data report (EPA 2000). The emission factors 

reported in these tables do not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 
G-4

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A * (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 

The emission factor equation used assumptions about engine horsepower and load factors 

provided in the GMAQS. These power-based emission factors were applied to average 

horsepower ratings for the large cargo vessels and the smaller escort vessels to estimate 

emissions. 

Evaporative emissions associated with the lightering and ballasting operations were calculated by 

applying total organic carbon (TOC) emission factors obtained from EIIP documents (EIIP 2001) 

to the amount of oil lightered: 

Evaporative Lightering Emission Equation 

Emissions = Crude oil * EF 

= 344,252,000 barrels * 42 gallons/barrel * 0.86 lbs of TOC/103gal of crude oil * 

ton/2000 * (0.85 VOC/TOC) 

= 5,284.61 tons of VOC 

Evaporative Ballasting Emission Equation

Emissions = Capacity * 40% of capacity ballasted * EF 

= 344,252,000 barrels *0.4* 42 gallons/barrel * 0.86 lbs of VOC /103gal of crude 

oil * ton/2000 * (0.85 VOC/TOC) 

= 2,113.84 tons of VOC 

All vessel lightering emissions are summarized in Table G-6. 
G-5

Table G-1. Summary of Lightering Activity Data. 

Large Oil Vessels

Time 2-6 days, average = 4 days (96 hours) Thomas 2001

Ships 246 ships in 2000 McClellan 2002

DWT 200,000 to 300,000, average 250,000 McClellan 2002

Escort Vessels

Time 2-6 days, average = 4 days (96 hours) Thomas 2001

Trips* 344,252,000/500,000 = 688.5 McClellan 2002; Thomas 2001

DWT 50,000 to 100,000, average 75,000 McClellan 2002

*Total barrels in 2000 was 344,252,000. Escort vessels carry 500,000 barrels.

Table G-2. Location of Lightering Zones and Average Travel Distance. 

Zone Latitude Longitude Use Distance 

South Sabine Lightering Zone 28.30 N 93.40 W 20% 290.86 miles

Galveston Lightering Zone 1 28.35 N 94.30 W 40% 282.55 miles

Galveston Lightering Zone 2 28.40 N 94.10 W 40% 287.64miles

Average Distance: 286.25 miles

Average Roundtrip Distance: 572.49 miles

Roundtrip minus state: 548.5 miles

Roundtrip time minus state: 45.7 hrs

Total hours for all ships: 31,469 hrs
G-6

Table G-3. Large Oil Vessel Emission Factors. 

Activity Data

DWT Avg. HP Avg. kW Operating 

Load 

250,000.00 34,320.00 25,592.42 10%

Emission Factors

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) Coefficient (A)

Ave kW 

rating Kg/hr lbs/hr 

Adjusted

Emission

Rate 

(lbs/hr)**

PM 0.44 1.50 0.26 0.01 25,592 11.30 24.92 2.49

NOx 14.42 1.50 10.45 0.13 25,592 369.00 813.49 81.35

SO2* 2.77 N/A 0.00 2.00 25,592 70.84 156.18 15.62

CO 8.38 1.00 0.00 0.84 25,592 214.41 472.70 47.27

VOC 2.11 1.50 0.00 0.07 25,592 53.98 119.01 11.90

CO2 1,089.60 1.00 648.60 44.10 25,592 27,885.51 61,476.38 6,147.64

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 10% load factor. 

Table G-4. Escort Vessels (Traveling to Lightering Zone and Back to Port) 

Emission Factors. 

Activity Data

DWT Avg. HP Avg. kW Operating 

Load 

75,000.00 16,645.00 12,412.18 80%

Emission Factors

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) Coefficient (A)

Avg. kW 

rating Kg/hr lbs/hr 

Adjusted

Emission

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 12,412.18 3.27 7.21 5.77

NOx 10.62 1.50 10.45 0.13 12,412.18 131.88 290.74 232.59

SO2* 1.78 N/A 0.00 2.00 12,412.18 22.10 48.73 38.98

CO 1.05 1.00 0.00 0.84 12,412.18 13.00 28.66 22.93

VOC 0.09 1.50 0.00 0.07 12,412.18 1.16 2.55 2.04

CO2 703.73 1.00 648.60 44.10 12,412.18 8,734.76 19,256.65 15,405.32

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.
G-7

Table G-5. Escort Vessels (Idle) Emission Factors. 

Activity Data

DWT Avg. HP Avg. kW Operating 

Load 

75,000 16,645 12,412 10%

Emission Factors

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) Coefficient (A)

Avg. kW 

rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.44 1.50 0.26 0.01 12,412.18 5.48 12.09 1.21

NOx 14.42 1.50 10.45 0.13 12,412.18 178.96 394.54 39.45

SO2* 2.77 N/A 0.00 2.00 12,412.18 34.36 75.75 7.57

CO 8.38 1.00 0.00 0.84 12,412.18 103.99 229.25 22.92

VOC 2.11 1.50 0.00 0.07 12,412.18 26.18 57.72 5.77

CO2 1,089.60 1.00 648.60 44.10 12,412.18 13,524.31 29,815.69 2,981.57

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 10% load factor.

Table G-6. Emission Estimates for Lightering Operations (tons/year). 

Evaporative Escort Vessels 

Pollutant Transfer Ballasting Tankers Travel Idle Total 

PM -- -- 29.43 90.72 14.27 134.42

NOx -- -- 960.57 3,659.78 465.87 5,086.22

SO2 -- -- 1,844.22 613.40 89.44 2,547.06

CO -- -- 558.16 360.77 270.70 1,189.63

VOC 5,284.61 2,113.84 140.52 32.10 68.15 7,639.22

CO2 -- -- 72,591.32 242,398.74 35,206.37 350,196.42
G-8

References 

EIIP. 2001. Emission Inventory Improvement Program. Volume III. Area Sources. Chapter 12. 

Marine Vessel Loading, Ballasting, and Transit. 

http://www.epa.gov/ttn/chief/eiip/techreport/volume 03. 

McClellan, Sheridan. January 9, 2002. Telephone conversation with Roger Chang of Eastern 

Research Group. USCS Marine Safety Unit Galveston. 

Thomas, P.F. December 21, 2001. Response to letter from Robert Chang of Eastern Research 

Group dated December 6, 2001. Commanding Officer USCG Marine Safety Unit, 

Galveston. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX H 

COMMERCIAL FISHING 
H-3

Commercial fishing data for 2000 were provided by the National Oceanic & Atmospheric 

Administration’s National Marine Fisheries Service (NMFS). Separate activity data were 

provided for the three different types of offshore fishing activities that occur in the GOM, pelagic 

long line, reef, and shrimp fishing (Cramer 2001, Patella 2001, Poffenberger 2001). It should be 

noted that fishing operations have significant seasonal variation, the annual emission estimates 

developed in this report need to be carefully evaluated to get seasonal emission estimates. 

The long line activity data set was very large and is not included in this report, but will be 

included in the electronic activity data set. Note, even though the long line data set provides a lot 

of vessel-specific data, collectively long line emissions are relatively small. The activity data for 

reef and shrimp fishing operations are included in Tables H-1 and H-2, respectively. 

The activity data for these different fishing operations were provided in spatial terms of latitude 

and longitude of pelagic long line fishing operations and in NMFS= geographic grid for reef and 

shrimp fishing. 

For each of the three different fishing activities, diesel emission factors were derived based on 

the EPA marine diesel emission factor equation (EPA 2000): 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables H-3, H-4, and H-5 were 

obtained from Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data report (EPA 2000). The emission factors 

reported in these tables do not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 
H-4

SO2 Emission Rate (g/kW-hr) = A * (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 

These power-based emission factors are applied to average horsepower ratings for commercial 

fishing vessels and hours of operation to estimate emissions (see Table H-6). This emission 

estimating approach used assumptions about horsepower and load factors provided in the 

GMAQS (U.S. DOI, MMS 1995). 

Table H-1. Reef Fishing Activity and Emissions Data (tons/year). 

NMFS

Area Vessels Trips 

Duration 

(days) 

Duration 

(hours) PM NOx SO2 CO VOC CO2

10 86 724 2,334 56,016 3.63 146.46 24.55 14.44 1.28 9,700.48

11 70 615 1,623 38,952 2.52 101.84 17.07 10.04 0.89 6,745.45

12 14 82 225 5,400 0.35 14.12 2.37 1.39 0.12 935.14

13 73 984 1,744 41,856 2.71 109.44 18.34 10.79 0.96 7,248.34

14 78 474 1,381 33,144 2.15 86.66 14.52 8.54 0.76 5,739.66

15 54 371 1,031 24,744 1.60 64.70 10.84 6.38 0.57 4,285.00

16 55 411 1,194 28,656 1.86 74.92 12.56 7.38 0.66 4,962.46

17 55 712 2,118 50,832 3.29 132.91 22.28 13.10 1.17 8,802.75

18 43 391 1,142 27,408 1.78 71.66 12.01 7.06 0.63 4,746.34

19 35 238 678 16,272 1.05 42.54 7.13 4.19 0.37 2,817.88

20 25 170 569 13,656 0.88 35.71 5.98 3.52 0.31 2,364.86

21 18 115 248 5,952 0.39 15.56 2.61 1.53 0.14 1,030.73

Total 606 5,287 14,287 342,888 22.22 896.52 150.26 88.37 7.87 59,379.06
H-5

Table H-2. Shrimp Fishing Activity and Emissions Data (tons/year). 

NMFS 

Area 

Activity 

(hrs) PM NOx SO2 CO VOC CO2 

1 1,051 0.07 2.75 0.46 0.27 0.02 182.07

2 7,856 0.51 20.54 3.44 2.02 0.18 1,360.53

3 1,874 0.12 4.90 0.82 0.48 0.04 324.52

4 918 0.06 2.40 0.40 0.24 0.02 159.03

5 441 0.03 1.15 0.19 0.11 0.01 76.29

6 1,782 0.12 4.66 0.78 0.46 0.04 308.55

7 2,599 0.17 6.80 1.14 0.67 0.06 450.08

8 1,763 0.11 4.61 0.77 0.45 0.04 305.27

9 721 0.05 1.88 0.32 0.19 0.02 124.79

10 6,406 0.42 16.75 2.81 1.65 0.15 1,109.39

11 20,853 1.35 54.52 9.14 5.37 0.48 3,611.22

12 10,201 0.66 26.67 4.47 2.63 0.23 1,766.59

13 36,869 2.39 96.40 16.16 9.50 0.85 6,384.74

14 35,858 2.32 93.76 15.71 9.24 0.82 6,209.70

15 14,153 0.92 37.00 6.20 3.65 0.32 2,450.91

16 16,345 1.06 42.74 7.16 4.21 0.37 2,830.55

17 30,655 1.99 80.15 13.43 7.90 0.70 5,308.70

18 30,000 1.94 78.44 13.15 7.73 0.69 5,195.19

19 33,900 2.20 88.64 14.86 8.74 0.78 5,870.61

20 10,779 0.70 28.18 4.72 2.78 0.25 1,866.57

21 9,008 0.58 23.55 3.95 2.32 0.21 1,560.00

Total 274,034 17.76 716.49 120.09 70.62 6.29 47,455.30
H-6

Table H-3. Reef Fishing Emission Factors. 

Pollutant

E 

(g/kW-hr) Exponent (x)

Intercept 

(B)

Coefficient 

(A)

Average 

kW rating kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 223.71 0.06 0.13 0.10

NOx 10.62 1.50 10.45 0.13 223.71 2.38 5.23 4.18

SO2* 1.78 N/A 0.00 2.00 223.71 0.04 0.88 0.70

CO 1.05 1.00 0.00 0.84 223.71 0.23 0.52 0.42

VOC 0.09 1.50 0.00 0.07 223.71 0.02 0.05 0.04

CO2 703.73 1.00 648.60 44.10 223.71 157.43 346.35 277.08

Assumed operating load is 80% (EPA 2000). 

From GMAQS, diesels range from 100 to 500 hp average assumed to be 300 hp = 223.71Kw 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.

H-4. Shrimp Fishing Emission Factors. 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Average 

kW rating kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 223.71 0.06 0.13 0.10

NOx 10.62 1.50 10.45 0.13 223.71 2.38 5.23 4.18

SO2* 1.78 N/A 0.00 2.00 223.71 0.40 0.88 0.70

CO 1.05 1.00 0.00 0.84 223.71 0.23 0.52 0.42

VOC 0.09 1.50 0.00 0.07 223.71 0.21 0.05 0.04

CO2 703.73 1.00 648.60 44.10 223.71 157.43 346.35 277.08

Assumed operating load is 80% (EPA 2000). 

From GMAQS, diesels range from 100 to 500 hp average assumed to be 300 hp = 223.71 Kw 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.
H-7

Table H-5. Long Line Emission Factors. 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Average kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 223.71 0.06 0.13 0.10

NOx 10.62 1.50 10.45 0.13 223.71 2.38 5.23 4.18

SO2* 1.78 N/A 0.00 2.00 223.71 0.40 0.88 0.70

CO 1.05 1.00 0.00 0.84 223.71 0.23 0.52 0.42

VOC 0.09 1.50 0.00 0.07 223.71 0.02 0.05 0.04

CO2 703.73 1.00 648.60 44.10 223.71 157.43 346.35 277.08

Assumed operating load is 80% (EPA 2000). 

From GMAQS, diesel range from 100 to 500 hp average assumed to be 300 hp = 223.71 Kw. 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 

Table H-6. Emission Estimates for Commercial Fishing Operations. 

Pollutant

Longline 

Emissions 

(tons)

Reef Emissions 

(tons)

Shrimp 

Emissions 

(tons)

Total Emissions 

(tons)

PM 5.66 17.78 14.21 37.65

NOx 228.46 717.22 573.19 1,518.87

SO2 38.29 120.21 96.07 254.57

CO 22.52 70.70 56.50 149.71

VOC 2.01 6.30 5.03 13.34

CO2 15,131.75 47,503.25 37,964.24 100,599.24

Note: total hours of operation for: long line fishing is 109,208 hours/year, 

reef fishing is 342,888 hours/year, shrimp is 274,034 hours year. 
H-8

References 

Cramer, Jean. June 18, 2001. E-mail entitled Re: fishing locations in the GOM, to Amy 

Alexander of Eastern Research Group Inc. National Oceanic & Atmospheric 

Administration. 

Patella, Frank. October 22, 2001. E-mail entitled Re: fishing locations in the GOM, to Roger 

Chang of Eastern Research Group Inc. National Oceanic & Atmospheric Administration. 

Poffenberger, John, May 3, 2001. E-mail entitled Re: fishing effort, to Amy Alexander of Eastern 

Research Group. National Oceanic & Atmospheric Administration. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX I 

MILITARY VESSEL OPERATIONS 
I-3

Coast Guard Vessels 

The Coast Guard provided activity data for their vessels operating in the Gulf of Mexico 

(Peschke 2002). The data included size of boat (i,e., either 87 foot, 110 foot, or 175 foot), the 

number of engines for each boat type, the horsepower of each engine, the total number of 

operating hours, and the percentage of time each vessel spent in the OCS. These data are shown 

in Table I-1. From these data, the total number of hours operating in the OCS were calculated for 

each type of boat. Using the total operating hours and assuming a load factor of 80%, emission 

estimates for each boat type were calculated using emission factors derived from the EPA’s 

marine diesel emission factor equation. This emission factor equation is based on the following 

algorithm (EPA 2000) 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables I-2, I-3, and I-4 were obtained 

from Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels Emissions and 

Fuel Consumption Data report (EPA 2000). The emission factors reported in these tables 

do not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A * (Fuels Sulfur Flow in g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 
I-4

These power based emission factors were applied the vessel horsepower ratings and hours of 

operation to estimate emissions. Total emissions for all Coast Guard vessels operating in the 

Gulf of Mexico’s OCS were then determined. These estimates are given in Table I-5. 

Naval Vessels 

Repeated and unsuccessful attempts to obtain activity data from the Navy necessitated that gross 

assumptions be made for the purpose of this inventory. These assumptions include that naval 

vessel fleet remained constant over the period from 1995 to 2000, that vessel type, engine type, 

and horsepower also remained the same. These 1995 activity data were provided in the GMAQS 

report in Table N-19 (U.S. DOI, MMS 1995). 

In 1995, the Navy reported activity data for vessels of three engine types, diesel engines, steam 

engines, and turbine engines. Diesel engines emission factors were updated using the EPA’s 

marine diesel emission factor equation (EPA 2000). 

E (g/kW-hr) = A * (Load Factors) –x +B 

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables I-6 to I-12 were obtained from 

Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels Emissions and Fuel 

Consumption Data report (EPA 2000). The emission factors reported in these tables do 

not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A * (Fuels Sulfur Flow in g/kW-hr) + B 
I-5

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 

A load factor of 80% was used, based on the assumption that naval vessels would operate at a 

similar power load to Coast Guard vessels. Hours of operation were assumed, for the purposes 

of this inventory, to be 24 hours per day, 365 days per year as more accurate activity data were 

not provided by the Navy. It is acknowledged that this is probably an overestimation of activity 

and actual activity would be somewhat less. The derived emission factors were applied to vessel 

horsepower and hours of operation to estimate emissions. The estimated emissions from these 

marine diesel engines are provided in Table I-13. 

Steamship and turbine vessel emission estimates were determined differently as the associated 

emission factors have not been updated, therefore, the older fuel-based factors were used. The 

emission estimation equation used for this source category is given as follows: 

Emission Rate = Emission Factor * Fuel Consumption 

Diesel turbine and steamship fuel consumption data supplied by the Navy in the GMAQS report 

is noted in Table I-14 and I-15, respectively. It should be noted that residual fuel consumption 

reported in the GMAQS seems relatively low, and it is anticipated that actual fuel consumption 

rates would be higher. Updated emission factors from the EPA’s AP-42, Volume 1, Chapter 3 

(EPA 2002) were used for turbines, and data from the EPA’s Documentation for Aircraft, 

Commercial Marine Vessel, Locomotive, and other Nonroad Components of the National 

Emission Inventory (EPA 2003) were used for steam engines (see Table I-17). A conversion 

from pounds per year to tons per year was performed. Emissions calculated for each pollutant 

type for turbines and steam engines are shown in Table I-18 and Table I-19, respectively. Note, 

the vessel types shown in Tables I-6 to I-13 are abbreviations used in the GMAQS (U.S. DOI, 

MMS 1995). 

Once emission estimates were calculated for each engine type, total emissions for all naval 

vessels are summarized in Table I-20. Total estimates for each pollutant for all military vessels 

in the Gulf of Mexico are summarized in Table I-21. It should be noted that as the Navy data 

have not been updated with more recent activity data, there is considerable uncertainty associated 

with the estimates. 
I-6

Table I-1. Coast Guard Vessels. 

Vessel 

Size

No. of 

Boats

No. of 

Engines

Total No. 

of Engines

Horsepower per 

Engine

Operating 

Hours per 

Boat

Total 

Operating 

Hrs for all 

Engines

Percent of 

Time Spent 

in OCS

Total 

Operating 

Hrs in OCS 

per yr

87 Ft 14 2 28 1,475 1,800 50,400 80% 40,320

110 Ft 1 2 2 6,800 1,800 3,600 80% 2,880

175 Ft 2 2 4 1,700 1,200 4,800 80% 3,840

Table I-2. 87-Foot Coast Guard Vessels. 

Activity Data 

Operating 

Load Avg. HP Avg. kW

Total Engine 

Hrs

80% 1,475 1,099.91 40,320

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 1,099.91 0.29 0.64 0.51

NOx 10.62 1.50 10.45 0.13 1,099.91 11.69 25.76 20.61

SO2* 1.78 N/A 0.00 2.00 1,099.91 1.96 4.32 3.46

CO 1.05 1.00 0.00 0.84 1,099.91 1.15 2.54 2.03

VOC 0.09 1.50 0.00 0.07 1,099.91 0.10 0.23 0.18

CO2 703.73 1.00 648.60 44.10 1,099.91 774.03 1,706.43 1,365.14

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study 

 the fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 
I-7

Table I-3. 110-Foot Coast Guard Vessels. 

Activity Data 

Operating 

Load Avg. HP Avg. kW

Total 

Engine Hrs

80% 6,800.00 5,070.76 2,880.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 5,070.76 1.34 2.94 2.35

NOx 10.62 1.50 10.45 0.13 5,070.76 53.88 118.78 95.02

SO2* 1.78 N/A 0.00 2.00 5,070.76 9.03 19.91 15.93

CO 1.05 1.00 0.00 0.84 5,070.76 5.31 11.71 9.37

VOC 0.09 1.50 0.00 0.07 5,070.76 0.47 1.04 0.83

CO2 703.73 1.00 648.60 44.10 5,070.76 3,568.42 7,866.94 6,293.55

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this 

 study the fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 

Table I-4. 175-Foot Coast Guard Vessels. 

Activity Data 

Operating 

Load Avg. HP Avg. kW

Total 

Engine Hrs

80% 1,700.00 1,267.69 3,840.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 1,267.69 0.33 0.74 0.59

NOx 10.62 1.50 10.45 0.13 1,267.69 13.47 29.69 23.75

SO2* 1.78 N/A 0.00 2.00 1,267.69 2.26 4.98 3.98

CO 1.05 1.00 0.00 0.84 1,267.69 1.33 2.93 2.34

VOC 0.09 1.50 0.00 0.07 1,267.69 0.12 0.26 0.21

CO2 703.73 1.00 648.60 44.10 1,267.69 892.11 1,966.74 1,573.39

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this 

 study the fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.
I-8

Table I-5. Emission Estimates for Coast Guard Vessels (tons/year). 

Pollutant 87 Ft Vessel 110 Ft Vessel 175 Ft Vessel Total for All Vessels

PM 10.03 3.39 1.13 14.82

NOx 415.52 136.83 45.61 597.96

SO2* 69.64 22.94 7.65 100.22

CO 40.95 13.49 4.50 58.94

VOC 3.65 1.20 0.40 5.25

CO2 27,521.34 9,062.71 3,020.90 39,604.95

Table I-6. Naval Vessel: MSO. 

Activity Data 

Engines

Operating 

Load Avg. HP Avg. kW

Total Engine 

Hrs

4 80% 575.00 428.78 35,040.00

Emission Factors 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) 

Avg. kW 

rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 428.78 0.11 0.25 0.20

NOx 10.62 1.50 10.45 0.13 428.78 4.56 10.04 8.03

SO2* 1.78 N/A 0.00 2.00 428.78 0.76 1.68 1.34

CO 1.05 1.00 0.00 0.84 428.78 0.45 0.99 0.79

VOC 0.09 1.50 0.00 0.07 428.78 0.04 0.09 0.07

CO2 703.73 1.00 648.60 44.10 428.78 301.74 665.22 532.18

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.
I-9

Table I-7. Naval Vessel: MCM. 

Activity Data 

Engines

Operating 

Load Avg. HP Avg. kW

Total Engine 

Hrs

4 80% 600 447.42 35,040

Emission Factors 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) 

Avg. kW 

rating Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.5 0.2551 0.0059 447.4 0.12 0.26 0.21

NOx 10.62 1.5 10.4496 0.1255 447.4 4.75 10.48 8.38

SO2* 1.78 N/A 0 1.998 447.4 0.80 1.76 1.41

CO 1.05 1 0 0.8378 447.4 0.47 1.03 0.82

VOC 0.09 1.5 0 0.0667 447.4 0.04 0.09 0.07

CO2 703.73 1 648.6 44.1 447.4 314.86 694.1 555.28

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.

Table I-8. Naval Vessel: PHM. 

Activity Data 

Engines

Avg. Load 

Factor Avg. HP Avg. kW

Total Engine 

Hrs

2 80% 800 596.56 17,520

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.5 0.2551 0.0059 596.6 0.16 0.35 0.28

NOx 10.62 1.5 10.4496 0.1255 596.6 6.34 13.97 11.18

SO2* 1.78 N/A 0 1.998 596.6 1.06 2.34 1.87

CO 1.05 1 0 0.8378 596.6 0.62 1.38 1.10

VOC 0.09 1.5 0 0.0667 596.6 0.06 0.12 0.09

CO2 703.73 1 648.6 44.1 596.6 419.81 925.5 740.40

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 
I-10

Table I-9. Naval Vessel: TAG. 

Activity Data 

Engines

Avg. Load 

Factor Avg. HP Avg. kW

Total Engine 

Hrs

2 80% 1,400.00 1,043.98 17,520.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kw 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 1,043.98 0.27 0.61 0.49

NOx 10.62 1.50 10.45 0.13 1,043.98 11.09 24.45 19.56

SO2* 1.78 N/A 0.00 2.00 1,043.98 1.86 4.10 3.28

CO 1.05 1.00 0.00 0.84 1,043.98 1.09 2.41 1.93

VOC 0.09 1.50 0.00 0.07 1,043.98 0.10 0.21 0.17

CO2 703.73 1.00 648.60 44.10 1,043.98 734.67 1,619.66 1,295.73

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor. 

Table I-10. Naval Vessel: TAGS(50). 

Activity Data 

Engines

Operating 

Factor Avg. HP Avg. kW

Total Engine 

Hrs

1 80% 2,500.00 1,864.25 8,760.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 1,864.25 0.49 1.08 0.86

NOx 10.62 1.50 10.45 0.13 1,864.25 19.81 43.67 34.94

SO2* 1.78 N/A 0.00 2.00 1,864.25 3.32 7.32 5.86

CO 1.05 1.00 0.00 0.84 1,864.25 1.95 4.30 3.44

VOC 0.09 1.50 0.00 0.07 1,864.25 0.17 0.38 0.30

CO2 703.73 1.00 648.60 44.10 1,864.25 1,311.92 2,892.26 2,313.81

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.
I-11

Table I-11. Naval Vessel: LSD. 

Activity Data 

Engines

Operating 

Load Avg. HP Avg. kW

Total Engine 

Hrs

4.00 80% 10,250.00 7,643.43 35,040.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 7,643.43 2.01 4.44 3.55

NOx 10.62 1.50 10.45 0.13 7,643.43 81.21 179.04 143.23

SO2* 1.78 N/A 0.00 2.00 7,643.43 13.61 30.01 24.01

CO 1.05 1.00 0.00 0.84 7,643.43 8.00 17.65 14.12

VOC 0.09 1.50 0.00 0.07 7,643.43 0.71 1.57 1.26

CO2 703.73 1.00 648.60 44.10 7,643.43 5,378.87 11,858.26 9,486.61

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.

Table I-12. Naval Vessel: TAGS(40). 

Activity Data 

Engines

Operating 

Load Avg. HP Avg. kW

Total Engine 

Hrs

2 80% 12,000.00 8,948.40 17,520.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Factor 

(lbs/hr)** 

PM 0.26 1.50 0.26 0.01 8,948.40 2.36 5.20 4.16

NOx 10.62 1.50 10.45 0.13 8,948.40 95.08 209.61 167.69

SO2* 1.78 N/A 0.00 2.00 8,948.40 15.94 35.13 28.10

CO 1.05 1.00 0.00 0.84 8,948.40 9.37 20.66 16.53

VOC 0.09 1.50 0.00 0.07 8,948.40 0.83 1.84 1.47

CO2 703.73 1.00 648.60 44.10 8,948.40 6,297.21 13,882.84 11,106.27

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.
I-12

Table I-13. Naval Vessel: TAK(II). 

Activity Data 

Engines

Avg. Load 

Factor Avg. HP Avg. kW

Total Engine 

Hrs

2 80% 13,500.00 10,066.95 17,520.00

Emission Factors 

Pollutant

E 

(g/kW-hr)

Exponent 

(x)

Intercept 

(B)

Coefficient 

(A)

Avg. kW 

rating Kg/hr lbs/hr

Adjusted 

Emission 

Rate 

(lbs/hr)**

PM 0.26 1.50 0.26 0.01 10,066.95 2.65 5.84 4.67

NOx 10.62 1.50 10.45 0.13 10,066.95 106.96 235.81 188.65

SO2* 1.78 N/A 0.00 2.00 10,066.95 17.93 39.52 31.62

CO 1.05 1.00 0.00 0.84 10,066.95 10.54 23.24 18.59

VOC 0.09 1.50 0.00 0.07 10,066.95 0.94 2.07 1.66

CO2 703.73 1.00 648.60 44.10 10,066.95 7,084.36 15,618.19 12,494.55

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the 

 fuel sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 80% load factor.

Table I-14. Summary of Emission Estimates for Naval Diesel Vessels (tons/year). 

Vessel 

Pollutant MSO MCM PHM TAG TAGS(50) LSD TAGS(40) TAK(II) Total 

PM 3.49 3.64 2.42 4.25 3.79 62.20 36.41 40.96 157.16

NOx 140.77 146.89 97.93 171.38 153.02 2,509.40 1,468.92 1,652.54 6,340.83

SO2 23.59 24.62 16.42 28.72 25.65 420.58 246.19 276.97 1,062.74

CO 13.87 14.48 9.66 16.89 15.08 247.34 144.78 162.88 624.98

VOC 1.23 1.29 0.86 1.50 1.34 22.02 12.89 14.50 55.62

CO2 9,323.71 9,729.09 6,486.06 11,350.61 10,134.47 166,205.30 97,290.91 109,452.27 419,972.43

Table I-15. Diesel Turbine Fuel Consumption. 

Vessel Fuel Used (1000 L/yr)

CG 333.84 

DD 129.08 

FFG 131.31 
I-13

Table I-16. Naval Steamship Fuel Consumption. 

Vessel

Fuel Consumption 

(1000L)

LPH 93.79

FF 393.45

AVT 8431.37

Table I-17. Naval Diesel Turbine Emission Factor Conversions.* 

Pollutant lb/MMBtu lb/1000gal lb/1000L

NOx 0.88 122.32 32.19

CO 0.00 0.46 0.12

CO2 157.00 21,823.00 5,742.89

SO2 0.40 56.16 14.78

VOC 0.00 0.06 0.01

PM 0.01 1.67 0.44

*Note: obtained from AP-42 (EPA 2002). 

Table I-18. Steamship Emission Factors. 

Pollutant Emission Factor 

lbs/1000L 

NOx 14.38 

CO 0.977 

SO2 85.9 

VOC 0.33 

PM 6.816 

Source: EPA 2002. 
I-14

Table I-19. Emission Estimates for Naval Turbine Engines (tons/year). 

Vessel 

Pollutant CG DD FFG Total 

PM 0.06 0.02 0.02 0.10

NOx 4.30 1.66 1.69 7.65

SO2 1.98 0.76 0.78 3.51

CO 0.02 0.01 0.01 0.03

VOC 0.00 0.00 0.00 0.00

CO2 766.88 296.52 301.64 1,365.04

Table I-20. Emission Estimates for Naval Steam Engines (tons/year). 

Vessel 

Pollutant LPH FF AVT Total 

PM 0.26 1.07 22.98 24.31

NOx 0.54 2.26 48.50 51.30

SO2 3.22 13.52 289.70 306.45

CO 0.04 0.15 3.30 3.49

VOC 0.02 0.05 1.11 1.18

Table I-21. Total Emission Estimates from All Naval Vessels (tons/year). 

Pollutant Diesel Steamships* Turbine Total 

PM 157.16 24.31 0.10 181.58

NOx 6,340.83 51.30 7.65 6,399.78

SO2 1,062.74 306.44 3.51 1,372.70

CO 624.98 3.49 0.03 628.50

VOC 55.63 1.18 0.00 56.81

CO2 419,972.42 386.72 1,365.04 421,337.46

* Emission estimates are not available for CO2. 
I-15

Table I-22. Summary of Emission Estimates from All Military Vessels (tons/year). 

Pollutant 

Naval 

Vessels 

Coast 

Guard 

Vessels 

Northern 

Gulf Total* 

Central and 

Western 

Gulf Total 

PM 182 15 197 103

NOx 6,400 598 6,998 3,674

SO2 1,373 100 1,473 774

CO 628 59 687 361

VOC 57 5 62 33

CO2 421,337 39,605 460,942 241,742

*Note these emissions cover the whole Northern Gulf Region including the MMS’ 

 Eastern Gulf area. The northern Gulf military vessel estimates were adjusted to 

 represent only activity in the central and western Gulf areas. For more information 

 on how the emissions were spatially allocated see Appendix M. 

References 

Peschke, May 6, 2002. Facsimile to Roger Chang of Eastern Research Group. Quarter Master, 

Eighth Coast Guard District, New Orleans, La. 

U.S. DOI, Minerals Management Service (MMS). 1995. Gulf of Mexico Air Quality Study: 

Final Report, Volumes I-III U.S. Department of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 95-0038, 95-

0039, and 95-0040. 

U.S. Environmental Protection Agency (EPA). 2002. Compilation of Air Pollutant Emission 

Factors, Volume I: Stationary Point and Area Sources. AP-42. U.S. Environmental 

Protection Agency, Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. http://www.epa.gov/ttn/chief/ap42/index.html

U.S. Environmental Protection Agency (EPA). 2003. Documentation for Aircraft, Commercial 

Marine Vessel, Locomotive, and Other Nonroad Components of the National Emission 

Inventory. Volume I – Methodology. Emission Factor and Inventory Group, Research 

Triangle Park, NC. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX J 

COMMERCIAL MARINE VESSELS 
J-3

CMV emission estimates were calculated for vessels powered with marine diesel engines and 

residual-fueled steamships. The marine diesel calculation was performed by applying ton 

mileage emission factors to shipping lane activity data for the GOM, while the steamship 

emission estimates were developed by extrapolating data from EPA’s 2000 National Emission 

Inventory (EPA 2002). 

The coastal ports of the GOM include some of the busiest ports in the U.S. (e.g., Corpus Christi, 

Houston/Galveston, Beaumont, New Orleans, Biloxi, and Mobile), but the majority of 

commercial marine vessel traffic (thus estimated emissions) occurs in State waters or the Eastern 

portion of the Gulf of Mexico. 

Estimating shipping lane activity requires in-depth evaluation of the actual shipping routes that 

vessels use. Although the GOM has a large number of shipping routes, most of the traffic is 

associated with a relatively smaller number of shipping fairways. Traffic into the Gulf occurs 

along two general paths; vessels using the Panama Canal to the south and vessels from Europe 

and the Middle Eastern Countries to the east. 

Most of the traffic from the Panama Canal travels to the east of Cuba and up the east coast. 

Vessels from Panama that visit ports in the Western Gulf area travel along a shipping lane that 

only impacts the south western corner of the MMS Western Gulf area. As they approach land, 

they tend to travel near the shore or in the intercontinental waterway (neither are included in the 

current inventory) to their final destinations. The remaining traffic that uses the Panama Canal 

travels through MMS lease blocks and is included in this inventory effort. 

Vessels coming from the Europe and the Middle East tend to enter the Gulf near the Florida 

Keys, and travel along the coast or in the intercontinental waterways (not included in this 

inventory effort) to destinations in the central and western portions of the Gulf. 

The marine diesel emission factors developed for this study are compiled in Table J-1. These 

emission factors apply to all marine diesel engines (Category 1, 2, and 3) and are provided in 

terms compatible with available GIS data. These factors were developed using the emission 

factor equation created during EPA’s marine diesel rulemaking and assumptions about the 

national fleet servicing U.S. ports. These emission factors were applied to shipping lane traffic 

data provided by the Army Corps of Engineer as a GIS data file (BTS 2000). It should be noted 

that shipping traffic associated with the approach to the LOOP were not included in this section, 

but were developed for Appendix F which addresses emission sources associated with the LOOP. 

To develop an estimate of CMV emissions for the portion of the Gulf that is of interest in this 

study, the ton miles for each shipping lane that transverses the MMS lease blocks were totaled 

and applied to the emission factors noted in Table J-1. 

The CMV fleet also includes older steamships that burn residual fuel to generate steam which is 

used for propulsion. Steamships account for less than one percent of the CMV fleet. 2000 

emission estimates were developed for steamships in the 2000 National Emission Inventory 

(EPA 2003). These steamship estimates were used to estimate emissions for the GOM by 
J-4

ratioing the national estimate to the Central and Western portions of the Gulf, based on cargo 

traffic provided by the Army Corps of Engineers (See Table J-2) (BTS 2000). This approach 

thus uses cargo traffic as a surrogate for emissions, and assumes that the proportion of cargo 

handled by residual-powered vessels is similar throughout the U.S. 

 

Combined emissions for marine diesel engines and steamships are noted in Table J-3. 

Table J-1. Emission Factors and Estimates for Marine Diesel Engines (tons/year). 

MMS Gulf area ton 

mileage 

3.6457 x 1010

Pollutant VOC CO NOx PM SO2* CO2

Emission Factor 

(g/ton-nautical mile) 

0.0041 0.0466 0.4727 0.0117 0.0792 31.3147 

Emission Estimate 166.69 1,812.74 19,000.08 470.92 3,184.47 1,258,432.54 

*For this study the fuel sulfur concentration was assumed to be 0.4%. 

Table J-2. Steamship Ton-Miles and Emission Estimates (tons/year). 

MMS Gulf area 

ton mileage 

3.6457 x 1010

National ton 

mileage 

4.0700 x 1012

Pollutant** VOC CO NOX PM SO2* 

National 

Steamship 

Emission 

Estimate 

1,690.57 7,060.79 54,374.83 3,019.08 40,258.87* 

MMS Gulf area 

emissions 

15.14 63.25 487.06 27.04 360.62 

* For this study the fuel sulfur concentration of residual fuel was assumed to be 2.7%. 

**CO2 was not one of the pollutants included in the 2000 National Emission Inventory. 

Table J-3. Summary of CMV Emission Estimates (tons/year). 

CMV Type VOC CO NOX PM SO2 CO2

Marine Diesel 166.69 1,872.74 19,000.08 470.92 3,184.47 1,258,432.54

Steamship 15.14 63.25 487.06 27.04 360.62 -- 

Total 181.83 1,935.99 19,487.14 497.96 3,545.09 1,258,432.54
J-5

References 

Bureau of Transportation Statistics (BTS). 2000. National Transportation Atlas Databases – 

National Waterway Network. Department of Transportation, Washington, DC. BTS 00-

003. 

U.S. Environmental Protection Agency (EPA). 2003. Documentation for Aircraft, Commercial 

Marine Vessel, Locomotive, and Other Nonroad Components of the National Emission 

Inventory. Volume I – Methodology. Emission Factor and Inventory Group. Research 

Triangle Park, NC. 
APPENDIX K 

BIOGENIC/GEOGENIC SOURCES 
K-3

The primary natural sources of air pollution that were evaluated for this Gulfwide study are: 

subsurface seeps of crude oil, subsurface seeps of natural gas (including methane hydrates), 

emissions from bacterial processes, and from ocean processes. Each of these source types 

presents unique problems in terms of characterization of the emission sources and estimating the 

associated emissions. Credible VOC emission estimates could only be developed for subsurface 

seeps of oil and N2O emission estimates for bacterial processes. 

Subsurface Seeps of Crude Oil 

Subsurface seeps of oil, more commonly referred to as oil seeps, occur when crude oil deposits 

beneath the ocean floor escape into the ocean waters because of cracks and vents in the floor. 

Cracks can open and close as the result of several geological activities. The volume of oil 

seeping into the ocean can be relatively significant though. The total amount of oil that is 

released into the ocean does not, however, find its way to the surface and end up as air emissions. 

Some ocean-dwelling biota develop communities surrounding oil seeps and utilize the 

hydrocarbons as a source of nutrients. Other free floating organisms in the water column 

consume portions of the escaping oil as the material rises to the surface. Although these 

processes do mitigate the amount of oil that reaches the surface for possible volatilization, there 

is significant uncertainty and variability on the amounts that do reach the surface. Air pollutants 

that can be emitted from oil seeps include VOC, methane, CO2, and air toxics. Based on the data 

found in the literature, only VOC emissions can be estimated at this time. 

The MMS and other researchers have conducted a significant amount of work to study the extent 

of oil seeps in the GOM and off the coast of California. Much of this investigation has focused 

on the occurrence of communities of chemosynthetic organisms and oil slicks. Both factors have 

been shown to correspond to significant oil seep activity. A major study on the natural seepage 

of crude oil into the marine environment is being prepared by the National Academy of Sciences 

(NAS) and due to be released in the spring of 2002. Some preliminary information from this 

effort relates to the GOM. This NAS report and much of our research into emission estimates for 

oil seeps is making use of key papers and reports (MacDonald et al. 1993, MacDonald et al. 

1995, MacDonald et al. 1996, Kennicutt et al. 1989, Mitchell et al. 1999). 

Estimates have been made of the total quantity of oil seeping into various ocean waters based on 

studies of oil slicks both at the ocean level and from satellite and space shuttle photography. 

These data have been input to models capable of estimating overall oil seepage rates. Crucial 

variables in the models include wind speed, oil layer thickness, and the oil degradation half-life. 

Over the last 10 years several different and sometimes highly variable estimates of total oil 

seepage into the GOM have been prepared. With improvements in remote sensing technology, 

better estimates are being made possible. Some of the most recent work places oil seepage in the 

northern GOM at 2.5 – 6.9 x 105 barrels/yr (Mitchell et al. 1999). Converting to tons, the average 

estimate of seepage in the northern GOM is 73,000 tons/yr. 
K-4

Using this figure, emissions can be estimated using either the oil seepage emission factor (105 

lbs/barrel oil released) developed by the California Air Resources Board (CARB 1993) or the 

average mass volatilization from oil slicks predicted by the MMS open ocean weathering model 

(U.S. DOI, MMS 1998, Kirstein 1992). One model prediction showed that after 10 days time, 

34% of the oil mass from a slick would have evaporated. The application of these methods 

results in similar mass emission estimates as shown below. 

1) 73,000 tpy x 294 gal/ton x 1 bbl/42 gal x 105 lbs/bbl = ~26,827 tons/yr VOC 

2) 73,000 tpy x 0.34 = 24,820 tons/yr VOC 

For the purposes of this MMS non-platform inventory we will use an average of the two 

estimates (25,823.5 tons/yr). It should also be noted that none of the studies provided accurate 

definitions of the Northern Gulf, such that it was not possible to map the study area to MMS 

lease blocks. In which case it is assumed that these emission estimates are for the whole 

Northern Gulf area. When adjusted to represent only the Central and Western Gulf, the VOC 

emissions decline to 13,561 tpy (see Appendix M). 

Subsurface Seeps of Natural Gas 

The phenomena of natural gas seeps are very similar to that described above for oil. Gas vents 

can occur in the ocean floor thereby releasing gas of geologic origin into the water column. 

Quantitative information on the levels of methane that may be seeping into GOM waters could 

not be located during the literature search conducted for this project. For this reason, it was not 

possible to formulate an estimate of emissions for this source type. Methane can also be formed 

by sediment bacteria; however, quantification of these rates is very difficult to determine. 

Studies are underway to evaluate biological methane generation and scavenging; however, no 

estimates of air emissions are currently available. 

Methane released through ocean floor vents or from biological processes can also form methane 

hydrates. Hydrates form as frozen structures at low temperatures and high pressures, conditions 

indicative of the deep waters of the GOM. Methane hydrates represent an overall storage of both 

methane and carbon. Sporadic emissions of methane could occur under specialized conditions 

such as ocean floor landslides, elevations in water temperature, or reductions in water pressure; 

however, these occurrences are expected to be minimal. Methane hydrates have not generally 

been viewed as sources of concern for methane air emissions (EPA 1993). 
K-5

Bacterial Processes 

Bacterial process sources include plankton producing dimethylsulfide (DMS) and sediment 

bacteria producing methane. DMS released from protozoa and zooplankton has been linked to 

the formation of tropospheric aerosols and cloud condensation nuclei, which can result in 

negative influences on global warming (Gabric et al. 1993). Estimates of DMS flux from the 

GOM range from 9.2 μmol/m2/day (in January) to 13.8 μmol/m2/day (in July) (Andreae 1997). 

Note, DMS is not one of the pollutants included in this study. As described previously, sediment 

bacteria methane generation and potential atmospheric release is not well characterized and 

cannot be estimated for the purposes of this inventory. 

Nitrous oxide (N2O) is produced by deep-water bacteria, and is transferred to the atmosphere 

through upwelling and air-sea transfer mechanisms (Nevison et al. 1995). Bouwman et al. 

(1995) compared several earlier inventories of ocean N2O to create a gridded annual N2O 

inventory available as part of the Global Emission Inventory Activity (GEIA) data set. Based on 

this information (Nevison et al. 1995), total annual emission for the GOM study area have been 

estimated to be 3,710 tons N2O –N/Year. When adjusted to represent only the Western and 

Central Gulf, the N2O estimate is 1,948 tons. 

Ocean Processes 

The action of ocean processes can emit a diverse variety of air pollutants. In addition to being a 

source of air pollutants, marine processes can also remove nitrogen and carbon species from the 

atmosphere and function as a sink for these compounds (Hood et al. 2000). 

Carbonyl sulfide (COS) is emitted from dissolved organic matter in ocean water through 

photochemical processes. In deep water, transition, and upwelling zones, the COS flux can range 

from 16 nmol/m2/d to 72 nmol/m2/d (Andreae and Ferek 1992). COS is the longest-lived sulfur 

species in the atmosphere. Since it is not altered in the troposphere, it has the potential to be 

transported into the stratosphere and increase the sulfate aerosol layer, thereby affecting the 

Earth’s radiation budget. Note, COS is not a criteria pollutant nor is it a greenhouse gas 

therefore, it is not one of the pollutants included in this study. 

References 

Andreae, M.O. 1997. Global Distribution of DMS Concentrations in the Surface Ocean and 

Sea-to-Air Flux of DMS. From: http://www/cco/caltech./edu:80/~moa/dms.htm. 

Andreae, M.O. and R.J. Ferek. 1992. Photochemical Production of Carbonyl Sulfide in Seawater 

and its Emission to the Atmosphere. Global Biogeochemical Cycles, Vol. 6, No. 2, 

pp. 175-183. 
K-6

Bouwman, A.F., K.W. Van der Hoek, and J.G.J. Olivier. 1995. Uncertainties in the Global 

Source Distribution of Nitrous Oxide. Journal of Geophysical Research, Vol. 100, 

No. D2, pp. 2785-2800. 

CARB. 1993. Section 9.2 Geogenic Sources Petroleum Seeps. California Air Resources 

Board, Sacramento, CA. 

Gabric, A., C.N. Murray, L. Stone, and M. Kohl. 1993. Modelling the Production of 

Dimethylsulphide During a Phytoplankton Boom. Journal of Geophysical Research, 

Vol. 98, C12, pp. 22,805-22,816. 

Hood, R.R., A.F. Michaels, and D.G. Capone. 2000. Answers Sought to the Enigma of Marine 

Nitrogen Fixation. EOS, Transactions of the American Geophysical Union, Vol. 81, 

No. 13. 

Kennicutt II, M.C., J.M. Brooks, and R.A. Burke, Jr. 1989. Hydrocarbon seepage, gas hydrates, 

and authigenic carbonate in the Northwestern Gulf of Mexico. 21st Annual Offshore 

Technology Conference Proceedings, pp. 649-654. 

Kirstein, B.E. 1992. Adaptation of the Minerals Management Service’s Oil-Weathering Model 

for Use in the Gulf of Mexico Region. U.S. Department of the Interior, Minerals 

Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 

92-0023. 

MacDonald, I.R., J.F. Reilly, Jr., S.E. Best, R. Venkataramaiah, R. Sassen, N.L. Guinasso, Jr., 

and J. Amos. 1996. Remote Sensing Inventory of Active Oil Seeps and Chemosynthetic 

Communities in the Northern Gulf of Mexico. In: D. Schumacher and M.S. Abrams, 

eds., Hydrocarbon migration and its near-surface expression: AAPG Memoir 66, pp. 27-

37. 

MacDonald, I.R., W.W. Schroeder, and J.M. Brooks. 1995. Chemosynthetic Ecosystems Study: 

Final Report. Volume I: Executive Summary. U.S. Department of the Interior, Minerals 

Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 

95-0021. 

MacDonald, I.R., N.C. Guinasso, Jr., S.G. Ackleson, J.F. Amos, R. Duckworth, R. Sassen, and 

J.M. Brooks. 1993. Natural Oil Slicks in the Gulf of Mexico Visible from Space. 

Journal of Geophysical Research, Vol. 98, No. C9, pp. 16,351-16,364. 

Mitchell, R., I.R. MacDonald, and K. Kvenvolden. 1999. Estimates of total hydrocarbon 

seepage into the Gulf of Mexico based on satellite remote sensing images. Paper OS411-

02. Presented at the 2000 Ocean Sciences Meeting, American Geophysical Union. 
K-7

Nevison, R., R. F. Weiss, and D. J. Erickson III. 1995. Global oceanic emissions of nitrous oxide. 

Journal of Geophysical Research, vol. 100, no. C8, pp. 15,809-15,820. 

U.S. DOI, Minerals Management Service (MMS). 1998. Gulf of Mexico OCS Oil and Gas Lease 

Sales 171, 174, 177, and 180 - Western Planning Area, Final Environmental Impact 

Statement. U.S. Dept. of Interior, Minerals Management Service, Gulf of Mexico 

Region, New Orleans, LA. OCS Study MMS 98-0008. 

U.S. Environmental Protection Agency (EPA). 1993. Current and Future Methane Emissions 

From Natural Sources – Report to Congress. EPA/430-R-93-001. Office of Air and 

Radiation, Washington, D.C. 
APPENDIX L 

PLATFORM CONSTRUCTION AND REMOVAL 
L-3

During the construction and removal of offshore oil platforms, a variety of vessels are needed to 

transfer equipment, materials, and platform structures, as well as workers and technicians. The 

methods used to estimate emissions from these vessels were adapted from an earlier MMS study, 

Emission Inventories of OCS Production and Development Activities in the Gulf of Mexico – 

Final Report (Coe et al. 2003). 

Platforms that were installed or removed during 2000 were identified by querying MMS’ 

platform structure database. This database provided latitude and longitude coordinates of each 

for each of the identified platforms and was linked to the master MMS database to obtain water 

depth information at each of the identified platforms. MMS staff also helped quantify the 

number of pilings associated with each of the platforms that was constructed or removed in 2000. 

As the vessels involved in platform construction and removal activities are similar to those 

discussed in Appendix C of this report, many of the same assumptions about vessel 

characteristics and operations were used. For example, the amount of time spent and fuel used in 

hoteling, cruising, and at full power for each of the vessel types was assumed to be the same as in 

Appendix C (see Table L-1). 

Table L-1. Fuel Usage and Time Spent by Vessels in Support of Platform 

Construction and Removal. 

Vessel Type Mode Fuel 1000 L/hr 

Fraction of 

Time Weight Fuel L/hr 

Hotel 0.01 0.5

Cruising 0.04

Barge 

 

 Full 0.07 0.5

40

 

 

Hotel 0.01 0.1

Cruising 0.04 0.1

Crew 

 

 Full 0.08 0.8

69

 

 

Hotel 0.01 0.45

Cruising 0.08 0.1

Supply 

 

 Full 0.14 0.45

75.5

 

 

Hotel 0.04 0.33

Cruising 0.21 0.33

Tug 

 

 Full 0.39 0.33

213.33

 

 

The number of pilings and the water depth at the platform were used to estimate the total number 

of hours that each of the four vessel types operated in support of platform construction and 

removal activities as noted in Table L-2. Some of the daily hour estimates are larger than 

24 hours suggesting that more than one vessel is supporting platform construction and removal 

activities. 
L-4

Table L-2. Daily Fuel Consumption and Operating Hours by Vessel Type. 

Fuel Consumption (L/day) Operating Hours (hrs/day) 

Water Depth (Ft) Water Depth (Ft) 

Vessel Type <300 300 to 600 >600 <300 300 to 600 >600 

Barge 1514 1514 7919 37.85 37.85 197.98 

Crew 2907 2907 2907 42.13 42.13 42.13 

Supply 2735 2735 2735 36.23 36.23 36.23 

Tug 1367 2790 5323 6.41 13.08 24.95 

Total 8523 9946 18884 122.61 129.28 301.28 

To estimate the number of activity days associated with the construction or removal of each of 

the identified platforms, the depth and piling data compiled by MMS for individual platforms 

were applied to estimates of the number of activity days associated with different water depths 

and platform pilings. These activity data were summed for the MMS central and western Gulf 

areas and are noted in Table L-3. 

Table L-3. Total Days for Construction or Removal of Platforms in the Year 2000. 

Water Depth (Ft) 

<300 300 to 600 >600 

Total 

Days 

Total Days to Install or 

Remove 4,023 332 413 4,768

The daily operating hours, noted in Table L-2, for each vessel type were applied to the total days 

for construction or removal of platforms as noted in Table L-3 to estimate total hours of 

operation by vessel type. These estimates are summarized in Table L-4, below. 
L-5

Table L-4. Estimate of Total Operating Hours by Vessel Type for Platform 

Construction and Removal. 

Daily Hours Total Hours 

Water Depth (Ft) Water Depth (Ft) 

Vessel Type <300 

300 to 

600 >600 <300 

300 to 

600 >600 

Total 

Hours 

Barge 37.85 37.85 197.98 152,270.6 12,566.2 81,763.68 246,600.4

Crew 42.13 42.13 42.13 169,490.7 13,987.3 17,399.87 200,877.9

Supply 36.23 36.23 36.23 145,733.8 12,026.75 14,960.99 172,721.6

Tug 6.41 13.08 24.95 25,778.66 4,341.942 10,305.01 40,425.6

Total 493,273.8 42,922.2 124,429.5 660,625.5

To use the EPA’s latest marine diesel emission factors, it is necessary to estimate the operating 

load of each of the vessel types included in Table L-4. It was assumed that the time in mode and 

operating load for each mode for each vessel type were similar to support vessels discussed in 

Appendix C. These operating loads and time in mode values are summarized in Table L-5. As 

in Appendix C, the operating load for each vessel type was weighted based on the amount of 

time spent in each mode. These weighted operating loads are noted in Table L-5. 

Table L-5. Weighted Operating Loads for Each Vessel Type. 

These weighted operating loads, in conjunction with the typical horsepower ratings noted in 

Appendix C, were used to calculate hourly emission factors for each of the vessels. These 

estimates will be comparable with other vessel estimates where time in mode data were not 

available. These emission factors were developed using the following emission equations from 

the U.S. EPA’s 2000 Analysis of Commercial Marine Vessels Emissions and Fuel Consumption 

Data (EPA 2000) in order to derive a representative emission factor.

E (g/kW-hr) = A * (Load Factors) –x +B 

Fraction of Time in Operating Mode Component Load Factors 

Operating 

Mode 

% 

Total 

power Barges Crew Supply Tugs Barges Crew Supply Tugs 

Hoteling 0.1 0.5 0.1 0.45 0.33 0.05 0.01 0.045 0.0330 

Cruising 0.55 0.0 0.1 0.1 0.33 0.0 0.055 0.055 0.1815 

Full Power 1 0.5 0.8 0.45 0.33 0.5 0.8 0.45 0.3300 

Weighted Load Factor 0.55 0.865 0.55 0.5445 
L-6

Where: 

E is the power-based emission factor; 

Constant A, intercept B, and exponential x noted in Tables C-3 to C-6 were obtained 

from Table 5-1 of the U.S. EPA Analysis of Commercial Marine Vessels Emissions and 

Fuel Consumption Data report (EPA 2000). The emission factors reported in these tables 

do not always agree with the coefficients, due to round-off error. 

For SO2, it is necessary to first calculate Fuel Consumption using the following equation: 

Fuels Consumption (g/kW-hr) = 14.12/(fractional load) + 205.717 

It is assumed that diesel fuel, modeled after distillate fuel oil #2, is used in marine 

applications. Such fuel is assumed to have a sulfur content of 0.4 percent. This 

percentage of sulfur in the fuel should be multiplied by the Fuel Consumption calculated 

above, to estimate the Fuel Sulfur Flow as noted below: 

Fuel Sulfur Flow (g/kW-hr) = Fuel Consumption (g/kW-hr) * 0.004 

The fuel sulfur flow is thus applied to the following equation to obtain a SO2 emission 

rate: 

SO2 Emission Rate (g/kW-hr) = A* Fuel Sulfur Flow (g/kW-hr) + B 

Where A and B are dimensionless constants provided in Table 5-1 of the U.S. EPA 

Analysis of Commercial Marine Vessels Emissions and Fuel Consumption Data report 

(EPA 2000). The emission factors reported in these tables do not always agree with the 

coefficients, due to round-off error. 

These emission factor calculations are noted in Tables L-6 through L-9 below. 
L-7

Table L-6. Barge Emission Factors. 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) kW Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** Hours Tons 

PM 0.2696 1.5 0.2551 0.0059 229.7 0.06 0.14 0.08 246,600 9.26 

NOx 10.7573 1.5 10.4496 0.1255 229.7 2.47 5.45 3.00 246,600 369.38 

SO2* 1.8449 N/A 0 1.998 229.7 0.42 0.93 0.51 246,600 63.35 

CO 1.5233 1 0 0.8378 229.7 0.35 0.77 0.42 246,600 52.31 

VOC 0.1635 1.5 0 0.0667 229.7 0.04 0.08 0.04 246,600 5.62 

CO2 728.7818 1 648.6 44.1 229.7 167.38 369.0 202.95 246,600 25,024.69 

Average HP 308 = 229.7 kW 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the fuel 

sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 55% load factor. 

Table L-7. Crew Boat Emission Factors. 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coeffici

ent (A) kW Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** Hours Tons 

PM 0.2624 1.5 0.2551 0.0059 357.9 0.09 0.21 0.18 200,878 17.99 

NOx 10.6056 1.5 10.4496 0.1255 357.9 3.80 8.37 7.24 200,878 727.09 

SO2* 1.7702 N/A 0 1.998 357.9 0.63 1.40 1.21 200,878 121.36 

CO 0.9686 1 0 0.8378 357.9 0.35 0.76 0.66 200,878 66.40 

VOC 0.0829 1.5 0 0.0667 357.9 0.03 0.07 0.06 200,878 5.68 

CO2 699.5827 1 648.6 44.1 357.9 250.41 552.0 477.48 200,878 47,961.47 

Average HP 480 = 357.9 kW 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the fuel 

sulfur concentration was assumed to be 0.4%. 

**Adjusted based on an 86.5% load factor. 

Table L-8. Supply Boat Emission Factors. 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) kW Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** Hours Tons 

PM 0.2696 1.5 0.2551 0.0059 647.3 0.17 0.38 0.21 172,722 18.27 

NOx 10.7573 1.5 10.4496 0.1255 647.3 6.96 15.35 8.44 172,722 729.11 

SO2* 1.8449 N/A 0 1.998 647.3 1.19 2.63 1.45 172,722 125.04 

CO 1.5233 1 0 0.8378 647.3 0.99 2.17 1.19 172,722 103.25 

VOC 0.1635 1.5 0 0.0667 647.3 0.11 0.23 0.13 172,722 11.08 

CO2 728.7818 1 648.6 44.1 647.3 471.72 1,039.9 571.94 172,722 49,395.86 

Average HP 868 = 647.3 kW 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the fuel 

sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 55% load factor.
L-8

Table L-9. Tug Boat Emission Factors. 

Pollutant 

E 

(g/kW-hr) 

Exponent 

(x) 

Intercept 

(B) 

Coefficient 

(A) kW Kg/hr lbs/hr 

Adjusted 

Emission 

Rate 

(lbs/hr)** Hours Tons 

PM 0.2698 1.5 0.2551 0.0059 1665.9 0.45 0.99 0.54 40,426 10.82 

NOx 10.7620 1.5 10.4496 0.1255 1665.9 17.93 39.52 21.52 40,426 431.41 

SO2* 1.8470 N/A 0 1.998 1665.9 3.08 6.78 3.69 40,426 74.04 

CO 1.5387 1 0 0.8378 1665.9 2.56 5.65 3.08 40,426 61.68 

VOC 0.1660 1.5 0 0.0667 1665.9 0.28 0.61 0.33 40,426 6.65 

CO2 729.5917 1 648.6 44.1 1665.9 1215.42 2,679.5 1,458.99 40,426 29,246.73 

Average HP 2234 = 1665.9 kW 

*For SO2 fuel sulfur flow (g/kW-hr) = 14.12/fractional load + 205.717* fuel sulfur concentration. For this study the fuel 

sulfur concentration was assumed to be 0.4%. 

**Adjusted based on a 54.45% load factor.

The above hourly emission factors presented in Tables L-6 through L-9 were applied to the total 

hour estimates noted in Table L-3 to estimate total annual emissions associated with the 

construction and removal of offshore oil platforms. These estimates are summarized in 

Table L-10. 

Table L-10. Emission Summary by Vessel Type. 

Pollutant 

Barges 

(tpy) 

Crew 

Boats 

(tpy) 

Supply 

Boats 

(tpy) 

Tugs 

(tpy) Total (tpy) 

PM 9.26 17.99 18.27 10.82 56.34

NOx 369.38 727.09 729.11 431.41 2,256.99

SO2 63.35 121.36 125.04 74.04 383.79

CO 52.31 66.40 103.25 61.68 283.63

VOC 5.62 5.68 11.08 6.65 29.03

CO2 25,024.69 47,961.47 49,395.86 29,246.73 151,628.75

Further study is needed to determine whether these estimates double count with the support 

vessels emission estimates included in Appendix C of this report. Support vessels utilize many 

of the same vessels used in platform construction and removal such as barges, crew boats, supply 

ships and tugs. This inventory does not include drill ships used for setting the platform pilings as 

they were not included in Coe et al. (2003), and it was thought they would double count with the 

drill ship estimates included in Appendix B of this report, further study is needed to confirm this 

assumption. 
L-9

References 

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

Inventories of OCS Production and Development Activities in the Gulf of 

Mexico. U.S. Department of the Interior, Mineral Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Study MMS 2002-073. 

U.S. Environmental Protection Agency (EPA). 2000. Analysis of Commercial Marine Vessels 

Emissions and Fuel Consumption Data. Office of Transportation and Air Quality, Ann 

Arbor, MI. EPA 420-R-00-002. 
APPENDIX M 

SPATIAL ALLOCATION METHODS FOR NON-PLATFORM SOURCES 
M-3

In this section, the approaches used to spatially allocate emissions are discussed for each of the 

source categories. Mostly, Geographic Information System (GIS) tools were used to develop 

these allocations, and the data were disaggregated to individual lease blocks or latitude and 

longitude coordinates when available. 

The GIS data which were used to spatially allocate emissions were obtained from MMS and the 

Army Corps of Engineers (ACE). It should be noted that the GIS calculations that were 

implemented in developing these methods to spatially allocate emissions, particularly for length 

of shipping lane and surface area, do not necessarily match the original length/area values. 

Theoretically, a waterway can be disaggregated to the individual lease blocks it travels through. 

As a quality check, the individual segments should add up to the original length of the shipping 

lane. The sum of the individual lengths do not always match the original ACE data. ACE has 

been contacted to better appreciate how the data set was developed. This issue of the lengths not 

matching introduces to the inventory a relatively small error, however, between 2 and 5 percent. 

Biogenic/Geogenic Sources 

Emissions from biogenic/geogenic sources have been calculated for VOCs and N2O. For VOC 

emitted from subsurface crude oil seeps, emissions were allocated equally throughout the federal 

waters in the Gulf, based on the surface area of each lease block, as noted in the equation below. 

For N2O emissions from bacterial processes, an estimate that covers the entire Gulf was derived 

from Nevison et al. (1995). This report did not clearly indicate the geographic area for which the 

emissions were estimated; therefore the emissions were equally distributed throughout the Gulf 

based on the surface area of each lease block. 

EBi = EBG * (Si/STNG) 

Where: 

EBi = Biogenic/geogenic emissions for lease block i 

EBG = Biogenic/geogenic emissions for Northern Gulf area 

Si = Surface area of lease block i 

STNG = Surface area of total Northern Gulf lease blocks 
M-4

Commercial Fishing 

Commercial fishing locations were provided by the National Marine Fisheries Service (NMFS). 

Reef and shrimp fishing operations are delineated by NMFS statistical zones. NMFS also 

provided latitude and longitude coordinates for line fishing operations. Emissions were spatially 

allocated for these three fishing activities by overlaying a GIS shape file of the MMS lease blocks 

onto the NMFS fishing zone data, as noted in the equation below. 

ECFi = ECFz * (Si/SCFz) 

Where: 

ECFi = Commercial fishing emissions for lease block i 

ECFz = Commercial fishing emissions for NMFS area z 

Si = Surface area of lease block i 

SCFz = Total surface area of NMFS area z 

The associated NMFS zone was attributed to each lease block within the NMFS area, as noted in 

Figure M-1. Where a lease block was included in two NMFS areas, the assignment was made 

proportional to the area of the NMFS zone that the lease block occupied. For example, a lease 

block AB is split between NMFS Zone 15 and Zone 16. Seventy five percent of lease block AB 

is included in Zone 15 and 25 percent of lease block AB is in Zone 16. In this example, 

emissions associated with NMFS zones 15 and 16 would be split in lease block AB, proportional 

to the area with which each zone is associated. 
M-5

Figure M-1. NMFS Fishing Zones with MMS Lease Blocks. 

Commercial Marine Vessels 

The commercial marine vessel (CMV) shipping lane activity data were obtained from the ACE as 

a GIS data set. Emissions were apportioned to individual links included in the ACE data set 

based on the cargo miles attributed to the links, which is the amount of cargo handled per link 

multiplied by the length of the link. Figure M-2 shows the CMV shipping lanes included in the 

ACE dataset. Shipping lanes in state waters were included, though they were not included in the 

emission estimates for the inventory, to show how shipping lanes in federal waters match up to 

shipping lanes in state waters. 
M-6

The data used were provided as thousand cargo tons, in terms of tons upward and tons downward 

along the link. The MMS lease blocks were defined by their protraction and block numbers, and 

mapped onto the GIS shipping lane data set; and emissions were apportioned to individual lease 

blocks based on the amount of cargo miles lying within the lease block boundaries, as noted in 

the following equation. 

ECMVi = CMi * EFCMV

Where: 

ECMVi = Commercial marine vessel emissions for lease block i 

CMi = Total cargo miles for lease block i 

EFCMV = Commercial marine vessel emission factors 

As mentioned earlier, there are some minor problems with the segment lengths reported in the 

ACE data set. To try to minimize the error, the original lengths were used whenever possible. 

The length of each waterway segment was calculated as a portion of the entire waterway, and 

these percentages were applied to the original length of the waterway to estimate the length of 

each segment. If only part of a waterway was contained within the MMS area, then length was 

based on the GIS calculations. 

Figure M-2. Commercial Marine Vessel Shipping Lanes and Lease Blocks Associated with the 

MMS Western and Central Gulf Areas. 
M-7

Drilling Rigs 

The drilling rig activity provided by MMS included the specific lease blocks where drilling 

occurred as noted in Figure M-3 below. Emissions were calculated for each drilling operation as 

described in Appendix B and assigned to the lease blocks where the drilling occurred. 

Figure M-3. Location of Drilling Operations and MMS Lease Blocks for 2000. 
M-8

LOOP 

The Louisiana Offshore Oil Platform (LOOP) website provided detailed geographic data 

identifying the shipping approach used by vessels, and the latitude and longitude coordinates for 

the platform itself (see Figure M-4). 

Figure M-4. Shipping Lane Approach and Location of LOOP. 

Emissions were spatially allocated to lease blocks by matching the shipping routes and platform 

coordinates to the MMS GIS shape file of the Central Gulf lease blocks. All emissions 

associated with the platform were assigned to the platform coordinates, while transit emissions 

associated with the approach and departure of tankers were assigned to lease blocks that intersect 

the approach lane as noted in the following equation. 
M-9

ELPi = ELP * (Li/LT) 

Where: 

ELPi = Tanker emissions for lease block i 

ELP = Total emissions for tanks approaching and departing the LOOP 

Li = Length of shipping land in lease block i 

LT = Total length of approach and departure shipping lane 

Military Vessels 

Military activity data and emissions were estimated Gulfwide, and were allocated equally 

throughout the federal waters of the Gulf (Eastern, Central and Western Gulf areas), as noted in 

the equation below. This allocation was made based on the surface area of the lease blocks. 

EMVi = EMV * (Si/STNG) 

Where: 

EMVi = Military vessel emissions associated with lease block i 

EMV = Total military vessel emissions for total northern Gulf area 

Si = Surface area of lease block i 

STNG = Surface area of total Northern Gulf lease blocks 

Pipelaying Operations 

MMS maintains GIS data for pipeline construction and maintenance activities. These 2000 

activity data were used to map emissions to the individual lease blocks by intersecting the MMS 

lease block shape file with the MMS pipeline data. Emissions were attributed to individual lease 

blocks based on the length of pipeline constructed or maintained within the boundaries of the 

lease blocks, as noted in the following equation. Figure M-5 shows the location of the pipeline 

lengths and the associated MMS lease blocks. 

EPi = LPi * EFP

Where: 

EPi = Emissions associated with pipelaying for lease block i 

LPi = Length of pipe constructed or maintained in lease block i 

EFP = Emission factor for pipelaying activity 
M-10

Figure M-5. Pipeline Locations and MMS Lease Blocks. 

Support Helicopters

Helicopter emissions can be apportioned by assigning emissions to lease blocks with active 

platforms that have heliports, as most of the emissions associated with support helicopters occurs 

while the craft is near or at the platform, as noted in the equation below. The active platforms 

with helipads are noted in Figure M-6. 

EHi = EH * (PHi/PHT) 

Where: 

EHi = Support helicopter emissions associated with lease block i 

EH = Total helicopter emissions 

PHi = Number of platforms with heliports in lease block i 

PHT = Total number of platforms with heliports 
M-11

Figure M-6. Location of Active Platforms with Helipads. 

Support Vessels 

In order to allocate support vessel emissions to the lanes that these vessels use to and from local 

ports, emissions were first disaggregated into hoteling and underway activities. Hoteling 

emissions occur while the vessel is waiting at the offshore platform. During this period, the 

diesel engine is operating under less than optimal design parameters, generating elevated NOx

and PM emissions. The period that vessels are hoteling can vary significantly depending upon 

the material that is being off loaded. In some cases, support vessels stop their marine diesel 

engines during hoteling. Unfortunately, there is currently no information that can help quantify 

the extent of this practice. For the purpose of this inventory, it was assumed that 25 percent of 

support vessel emissions occur while hoteling. The hoteling emissions were applied equally to 

each active platform. The platform latitude and longitude coordinates were used to spatially 

define the emission point. 
M-12

The remaining 75 percent of support vessel emissions were assigned to links from the platforms 

to the local ports. To allocate support vessel underway emissions, individual links were defined 

for each active platform. The first step was to define the closest home port for each platform. 

The following ports were defined as home ports for support vessels: 

• Corpus Christi, TX; 

• Freeport, TX; 

• Houston/Galveston, TX; 

• Beaumont, TX; 

• Morgan City, LA; 

• New Orleans, LA; 

• Biloxi, MS; and 

• Mobile, AL. 

Next, the pathway from the home port to the platform was defined. Once the links were defined 

(see Figure M-7), the length of each link occurring in each lease block was summed, and 

emissions were apportioned to individual lease blocks, based on the fraction of the total miles of 

shipping lane, as noted in the following equation: 

ESVi = ESV * (SLi/SLT) 

Where: 

ESVi = Support vessel emissions associated with lease block i 

ESV = Total underway emissions associated with support vessels 

SLi = Sum of the lengths of all shipping lanes within the boundaries of lease block i 

SLT = Total sum of all shipping lanes in the western and central areas of the Gulf 

Figure M-7. Support Vessel Fairways. 
M-13

Survey Vessels 

For survey vessels, emissions were developed for the inactive lease blocks. Emissions were 

allocated to each inactive block based on the surface area of the lease block, as noted in the 

following equation. The lease blocks that were flagged as inactive during the 2000 period are 

noted in Figure M-8. 

ESi = ES * (Sii/Sti) 

Where: 

ESi = Survey vessel emissions associated with lease block i 

ES = Total survey vessel emissions 

Sii = Surface area of inactive lease block i 

Sti = Total surface area of all inactive lease blocks 

Figure M-8. Inactive MMS Lease Blocks. 
M-14

Vessel Lightering 

Vessel lightering occurs in three designated zones in the Gulf and is monitored by the U.S. Coast 

Guard. Ballasting and tanker emissions were spatially allocated to each zone using the latitude 

and longitude coordinates for the centroid of the lightering zone. Escort vessel emissions were 

spatially allocated by mapping the vessel fairway from the centroid of the lightering zone to the 

nearest port, as noted in Figure M-9. Emissions were assigned to individual lease blocks that 

overlapped with the escort vessel fairway based on the length of the fairway within the 

boundaries of the individual lease block as noted in the equation below. 

EVLi = EVLZ * (LSi/LSZ) 

Where: 

EVLi = Vessel lightering emissions associated with lease block i 

EVLZ = Total vessel lightering emission from lightering zone z to port 

LSi = Length of lightering vessel fairway in lease block i 

LSZ = Total length of escort vessel fairway from lightering zone z to port 

Figure M-9. Vessel Lightering Area and Shipping Fairway to Port. 
M-15

Platform Construction and Removal 

Emission estimates were developed for six different platform sizes and matched to individual 

platforms that were either constructed or removed during 2000. The emission estimates were 

spatially assigned to the platform’s latitude and longitude coordinates (see Figure M-10) based 

on the number of pilings of each platform as discussed in Appendix L. 

Figure M-10. Location of Platform Construction and Removal During 2000. 
M-16

References 

Nevison, R., R.F. Weiss, and D.J. Erickson III. 1995. Global oceanic emissions of 

nitrous oxide. Journal of Geophysical Research, vol. 100, no. C8, pp. 15,809-

15,820. 
The Department of the Interior Mission

As the Nation's principal conservation agency, the Department of the Interior has responsibility 

for most of our nationally owned public lands and natural resources. This includes fostering 

sound use of our land and water resources; protecting our fish, wildlife, and biological diversity; 

preserving the environmental and cultural values of our national parks and historical places; 

and providing for the enjoyment of life through outdoor recreation. The Department assesses 

our energy and mineral resources and works to ensure that their development is in the best 

interests of all our people by encouraging stewardship and citizen participation in their care. 

The Department also has a major responsibility for American Indian reservation communities 

and for people who live in island territories under U.S. administration. 

The Minerals Management Service Mission 

As a bureau of the Department of the Interior, the Minerals Management Service's (MMS) 

primary responsibilities are to manage the mineral resources located on the Nation's Outer 

Continental Shelf (OCS), collect revenue from the Federal OCS and onshore Federal and Indian 

lands, and distribute those revenues. 

Moreover, in working to meet its responsibilities, the Offshore Minerals Management Program 

administers the OCS competitive leasing program and oversees the safe and environmentally 

sound exploration and production of our Nation's offshore natural gas, oil and other mineral 

resources. The MMS Minerals Revenue Management meets its responsibilities by ensuring the 

efficient, timely and accurate collection and disbursement of revenue from mineral leasing and 

production due to Indian tribes and allottees, States and the U.S. Treasury. 

The MMS strives to fulfill its responsibilities through the general guiding principles of: (1) being 

responsive to the public's concerns and interests by maintaining a dialogue with all potentially 

affected parties and (2) carrying out its programs with an emphasis on working to enhance the 

quality of life for all Americans by lending MMS assistance and expertise to economic 

development and environmental protection.