OCS Study

BOEM 2014-666

Year 2011 Gulfwide Emission Inventory

Study

U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region
OCS Study

BOEM 2014-666

Year 2011 Gulfwide Emissions

Inventory Study

Authors

D. Wilson

R. Billings

R. Chang

H. Perez

J. Sellers

Prepared under BOEM Contract

M10PC00084

by

Eastern Research Group, Inc.

1600 Perimeter Park Drive

Morrisville, NC 27560

Published by

U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

New Orleans, LA

November 2014
DISCLAIMER

Study concept, oversight, and funding were provided by the US Department of the Interior, 

Bureau of Ocean Energy Management, Environmental Studies Program, Washington, DC, 

under Contract Number M10PC00084. This report has been technically reviewed by BOEM 

and it has been approved for publication. The views and conclusions contained in this 

document are those of the authors and should not be interpreted as representing the opinions 

or policies of the U.S. Government, nor does mention of trade names or commercial products 

constitute endorsement or recommendation for use.

REPORT AVAILABILITY

To download a PDF file of this Environmental Studies Program report, go to the US Department 

of the Interior, Bureau of Ocean Energy Management, Environmental Studies Program 

Information System website and search on OCS Study BOEM 2014-666.

This report can be viewed at select Federal Depository Libraries. It can also be obtained from the 

National Technical Information Service; the contact information is below.

US Department of Commerce

National Technical Information Service

5301 Shawnee Rd.

Springfield, Virginia 22312

Phone: (703) 605-6000, 1 (800) 553-6847

Fax: (703) 605-6900

Website: http://www.ntis.gov/

CITATION

Wilson, D., R. Billings, R. Chang, H. Perez, and J. Sellers. 2014. Year 2011 Gulfwide emissions 

inventory study. US Dept. of the Interior, Bureau of Ocean Energy Management, Gulf 

of Mexico OCS Region, New Orleans, LA. OCS Study BOEM 2014-666.

ACKNOWLEDGMENTS

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

Eastern Research Group: Bebhinn Do, Stacie Enoch, Karla Faught, Steve Mendenhall, Regi 

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

Engineering: Brian Boyer, Stephanie Myers, and Rachelle Suir.

iii
CONTENTS

LIST OF FIGURES ...................................................................................................................... vii

LIST OF TABLES....................................................................................................................... viii

EQUATION UNIT DEFINITIONS .............................................................................................. xi

1. SUMMARY............................................................................................................................ 13

2. INTRODUCTION .................................................................................................................. 17

2.1 Background .................................................................................................................. 17

2.2 Scope and Purpose of This Project............................................................................... 18

2.3. Study Objectives........................................................................................................... 19

2.4. Report Organization ..................................................................................................... 19

3. DATA COLLECTION FOR PLATFORM SOURCES ......................................................... 21

3.1. Introduction .................................................................................................................. 21

3.2. Improvement of the GOADS Data Collection Software.............................................. 21

3.3. Working with Users...................................................................................................... 21

3.4. GOADS Quality Assurance/Quality Control ............................................................... 21

4. QUALITY ASSURANCE/QUALITY CONTROL ............................................................... 23

4.1 Introduction .................................................................................................................. 23

4.2 Checking File Integrity................................................................................................. 23

4.3 Equipment Summary Checks....................................................................................... 23

4.3.1 User-Level Summary...................................................................................... 23

4.3.2 Structure-Level Summary............................................................................... 24

4.3.3 Equipment-Level Summary............................................................................ 24

4.4 QA/QC Checks............................................................................................................. 24

4.4.1 Pre-Processing................................................................................................. 24

4.4.2 Equipment Survey Consistency ...................................................................... 25

4.4.3 Data Range Checks......................................................................................... 26

4.4.4 Stream Analysis Between Certain Equipment................................................ 26

4.4.5 Applying Surrogate Values............................................................................. 27

4.4.6 Post-Processing of Surrogates......................................................................... 29

4.4.7 Comparison to OGOR Reports....................................................................... 29

iv
5. DEVELOPMENT OF THE PLATFORM EMISSION INVENTORY.................................. 31

5.1 Introduction .................................................................................................................. 31

5.2 Emission Estimation Procedures.................................................................................. 31

5.2.1 Amine Units.................................................................................................... 32

5.2.2 Boilers/Heaters/Burners.................................................................................. 33

5.2.3 Diesel and Gasoline Engines .......................................................................... 36

5.2.4 Drilling Rigs.................................................................................................... 38

5.2.5 Combustion Flares.......................................................................................... 39

5.2.6 Fugitives.......................................................................................................... 42

5.2.7 Glycol Dehydrators......................................................................................... 44

5.2.8 Losses from Flashing ...................................................................................... 45

5.2.9 Mud Degassing ............................................................................................... 47

5.2.10 Natural Gas Engines ....................................................................................... 48

5.2.11 Natural Gas, Diesel, and Dual-Fuel Turbines................................................. 50

5.2.12 Pneumatic Pumps............................................................................................ 52

5.2.13 Pressure/Level Controllers.............................................................................. 53

5.2.14 Storage Tanks.................................................................................................. 54

5.2.15 Cold Vents ...................................................................................................... 58

5.2.16 Minor Sources................................................................................................. 59

5.2.17 PM Augmentation........................................................................................... 60

6. DEVELOPMENT OF THE NON-PLATFORM EMISSIONS INVENTORY ..................... 63

6.1 Non-Platform Oil/Gas Production Related Sources..................................................... 65

6.1.1 Marine Diesel Emission Factors..................................................................... 65

6.1.2 Drilling Rigs.................................................................................................... 66

6.1.3 Pipelaying Operations..................................................................................... 84

6.1.4 Support Helicopters ........................................................................................ 95

6.1.5 Support Vessels............................................................................................. 101

6.1.6 Survey Vessels.............................................................................................. 121

6.2 Other Non-Platform Sources...................................................................................... 124

6.2.1 Biogenic and Geogenic Emissions................................................................ 124

6.2.2 Commercial Fishing Vessels......................................................................... 127

6.2.3 Commercial Marine Vessels......................................................................... 130

6.2.4 LOOP ............................................................................................................ 132

6.2.5 Military Vessels............................................................................................ 135

6.2.6 Vessel Lightering.......................................................................................... 139

6.2.7 Recreational Fishing ..................................................................................... 141

v
7. RESULTS ............................................................................................................................. 145

7.1 Summary of Study Approach ..................................................................................... 145

7.2 Presentation of Annual Emission Estimates............................................................... 147

7.3 Limitations.................................................................................................................. 162

7.4 Comparison with Other Studies ................................................................................. 164

7.4.1 OCS Oil and Gas Production Platforms........................................................ 164

7.4.2 Non-Platform Sources................................................................................... 167

7.5 Recommendations...................................................................................................... 171

8. REFERENCES ..................................................................................................................... 175

vi
LIST OF FIGURES

Figure 6-1. Location of drilling operations and BOEM lease blocks for 2011 ............................ 83

Figure 6-2. 2011 pipelaying activity locations and BOEM lease blocks...................................... 94

Figure 6-3. Location of active platforms with heliports............................................................. 101

Figure 6-4. Support vessel activity in the GOM......................................................................... 121

Figure 6-5. Typical geophysical survey vessel operations ......................................................... 122

Figure 6-6. Locations of negative anomalies and pockmarks..................................................... 127

Figure 6-7. NMFS fishing zones with lease blocks.................................................................... 130

Figure 6-8. Vessel traffic density in bulkers............................................................................... 133

Figure 6-9. Vessel traffic density in cargo ships......................................................................... 133

Figure 6-10. Vessel traffic density in container ships................................................................. 133

Figure 6-11. Vessel traffic density in tankers............................................................................. 133

Figure 6-12. Vessel traffic density in tugs.................................................................................. 134

Figure 6-13. Vessel traffic density in Category 3 CMVs ........................................................... 134

Figure 6-14. Vessel traffic density in Category 1 and 2 CMVs.................................................. 134

Figure 6-15. Shipping lane approach and location of LOOP...................................................... 135

Figure 6-16. Coast Guard districts used to allocate emissions. .................................................. 138

Figure 6-17. Centroid of the vessel lightering zone and shipping lane to Galveston ................. 140

vii
LIST OF TABLES

Table 4-1. Fields and range check values............................................................................... 26

Table 4-2. Surrogate stack parameters used to supplement GOADS-2011 data.................... 27

Table 5-1. Emission factors for liquid-fueled units – diesel where max rated heat input ≥

100 MMBtu/hr ...................................................................................................... 33

Table 5-2. Emission factors for liquid-fueled units – diesel where max rated heat input <

100 MMBtu/hr ...................................................................................................... 34

Table 5-3. Emission factors for liquid-fueled units – waste oil where max rated heat input ≥

100 MMBtu/hr ...................................................................................................... 34

Table 5-4. Emission factors for liquid-fueled units – waste oil where max rated heat input < 

100 MMBtu/hr ...................................................................................................... 35

Table 5-5. Emission factors for gas-fueled units – natural gas or process gas where max rated 

heat input ≥ 100 MMBtu/hr.................................................................................. 35

Table 5-6. Emission factors for gas-fueled units – natural gas or process gas where max rated 

heat input < 100 MMBtu/hr.................................................................................. 36

Table 5-7. Emission factors for gasoline engines................................................................... 37

Table 5-8. Emission factors for diesel engines where max HP < 600.................................... 37

Table 5-9. Emission factors for diesel engines where max HP ≥ 600.................................... 37

Table 5-10. Emission factors for gasoline fuel use .................................................................. 39

Table 5-11. Emission factors for diesel fuel use ...................................................................... 39

Table 5-12. Emission factors for natural gas fuel use .............................................................. 39

Table 5-13. Emission factors for combustion flaresa ............................................................... 41

Table 5-14. Emission factors for pilots.................................................................................... 41

Table 5-15. THC emission factors for oil and gas production operations 

(lb/component-day)a

.............................................................................................. 43

Table 5-16. Default speciation weight fractions for THC emissions by stream typea ............. 43

Table 5-17. Surrogate gas analysis for GLYCalcTM runs......................................................... 45

Table 5-18. Emission factors for natural gas engines where engine stroke cycle = 2-cycle and 

engine burn type = lean......................................................................................... 49

Table 5-19. Emission factors for natural gas engines where engine stroke cycle = 4-cycle and 

engine burn type = lean......................................................................................... 49

Table 5-20. Emission factors for natural gas engines where engine stroke cycle = 4-cycle and 

engine burn type = rich ......................................................................................... 50

Table 5-21. Emission factors for natural gas engines where engine burn type = clean ........... 50

Table 5-22. Emission factors for natural gas turbines.............................................................. 51

Table 5-23. Emission factors for diesel turbines...................................................................... 51

Table 5-24. Default sales gas composition............................................................................... 53

Table 5-25. Daily average ambient temperature, Taa ............................................................... 58

Table 5-26. Tank paint solar absorptance, a............................................................................. 58

Table 6-1. Marine vessel emission factors............................................................................. 67

Table 6-2. Drilling vessel activity data .................................................................................. 69

viii
Table 6-3. Equipment kW ratings by drilling rig type ........................................................... 81

Table 6-4. Seasonal drilling activity 2011.............................................................................. 83

Table 6-5. Pipelaying activity ................................................................................................ 84

Table 6-6. Average pipelaying vessel characteristics ............................................................ 85

Table 6-7. New pipelaying activity data ................................................................................ 86

Table 6-8. Pipeline Repair Activity Data ............................................................................... 90

Table 6-9. Pipelaying monthly adjustment factors................................................................. 94

Table 6-10. HSAC helicopter data ........................................................................................... 95

Table 6-11. Time-in-mode values............................................................................................ 95

Table 6-12. FOCA average emission factors by helicopter type ............................................. 96

Table 6-13. Helicopter emission factors by helicopter and helicopter type............................. 97

Table 6-14. Support vessel census, kW rating, and annual hours of operation...................... 102

Table 6-15. Mud volcano locations and emission characteristics.......................................... 126

Table 6-16. Shrimp vessel activity data ................................................................................. 127

Table 6-17. Reef fishing vessel activity data ......................................................................... 128

Table 6-18. Commercial fishing monthly adjustment factors................................................ 129

Table 6-19. LOOP hours of operation, kW rating, and load factors...................................... 132

Table 6-20. Naval vessel kW hours........................................................................................ 136

Table 6-21. Naval diesel turbine and steamship fuel consumption data and emission 

factors.................................................................................................................. 136

Table 6-22. Average horsepower and operating hours by coast guard vessel type................ 137

Table 6-23. Full service lightering barrel data for 2008 and 2011......................................... 139

Table 6-24. Number of trips near platforms........................................................................... 141

Table 6-25. Activity hours based on number of trips............................................................. 141

Table 6-26. USEPA nonroad recreational marine vessel power profile ................................ 142

Table 6-27. Annual underway emissions for recreational fishing (tons) ............................... 142

Table 6-28. Annual maneuvering emissions for recreational fishing (tons).......................... 142

Table 6-29. Annual total emissions for recreational fishing (tons)........................................ 143

Table 7-1. Total platform emission estimates for criteria pollutants ................................... 147

Table 7-2. Total non-platform emission estimates for criteria pollutants............................ 148

Table 7-3. Total platform and non-platform emission estimates for criteria pollutants....... 149

Table 7-4. Annual CO emission estimates for all sources ................................................... 150

Table 7-5. Annual NOx emission estimates for all sources.................................................. 151

Table 7-6. Annual PM10 emission estimates for all sourcesa ............................................... 152

Table 7-7. Annual SO2 emission estimates for all sources................................................... 153

Table 7-8. Annual VOC emission estimates for all sources................................................. 154

Table 7-9. Total greenhouse gas emission estimates for platform sources.......................... 155

Table 7-10. Total greenhouse gas emissions for non-platform sources................................. 156

Table 7-11. Total platform and non-platform emission estimates for greenhouse gases....... 157

Table 7-12. Annual CO2 emission estimates for all sources.................................................. 158

Table 7-13. Annual CH4 emission estimates for all sources.................................................. 159

Table 7-14. Annual N2O emission estimates for all sources.................................................. 160

Table 7-15. Annual CO2e emission estimates for all sources ................................................ 161

ix
Table 7-16. Comparison of total platform and non-platform criteria pollutant for years 2008 

and 2011 emission estimates............................................................................... 164

Table 7-17. Comparison of total platform and non-platform greenhouse gas emission 

estimates for Years 2008 and 2011..................................................................... 164

Table 7-18. Comparison of Years 2008 and 2011 OCS platform criteria pollutant emission 

estimates.............................................................................................................. 166

Table 7-19. Comparison of Years 2008 and 2011 OCS platform greenhouse gas emission 

estimates.............................................................................................................. 167

Table 7-20. Comparison of Years 2008 and 2011 OCS non-platform criteria pollutant 

emission estimates .............................................................................................. 168

Table 7-21. Comparison of Years 2008 and 2011 OCS non-platform greenhouse gas emission 

estimates.............................................................................................................. 170

x
EQUATION UNIT DEFINITIONS

Unit Definition

avg Average

bbl Barrel

Btu British thermal unit

CF conversion factor

°F degrees Fahrenheit

ft Feet

ft3 cubic feet

gal Gallon

G Gram

GOR gas-to-oil ratio

hp Horsepower

hr Hour

kW Kilowatt

kWh kilowatt-hour

lb Pound

LF load factor

LTO landing and takeoff

m

2 meter squared

MMBtu million British thermal units

Mscf thousand standard cubic feet

MMscf million standard cubic feet

MMscfd million standard cubic feet per day

ppm parts per million

ppmv parts per million volume

psig pressure per square inch gauge

°R degrees rankine

scf standard cubic feet

sec Second

tpy tons per year

μmol Micromole

wt Weight

xi

1. SUMMARY

The Bureau of Ocean Energy Management (BOEM) is responsible for assessing the potential 

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

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

OCS Lands Act (1134(a)(8)), which tasks BOEM to assure that emissions from these activities 

do not significantly affect onshore air quality. In particular, BOEM is responsible for 

determining if any OCS oil and gas exploration, development, and production sources influence 

the National Ambient Air Quality Standard (NAAQS) compliance status of onshore areas in 

Louisiana, Texas, Mississippi, Alabama, and Florida. This responsibility was mandated by the 

1990 Clean Air Act (CAA) Amendments. In addition, the CAA requires BOEM to coordinate air 

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

need for emission inventories and modeling whenever the U.S. Environmental Protection 

Agency (USEPA) updates the NAAQS, such as the eight-hour ozone, one-hour nitrogen dioxide, 

and one-hour sulfur dioxide standards. To assess the emissions of offshore oil and gas platforms 

and their associated emissions, BOEM conducted limited emission inventories in the GOM OCS 

in the 1980s. In 1995, BOEM completed the Gulf of Mexico Air Quality Study (Systems 

Applications International et al. 1995); in 2004 BOEM completed the Gulfwide Emission 

Inventory Study for the Regional Haze and Ozone Modeling Effort (Wilson et al. 2004) and the

Data Quality Control and Emissions Inventories of OCS Oil and Gas Production Activities in the 

Breton Area of the Gulf of Mexico Study (Billings and Wilson 2004); in 2007 the Year 2005 

Gulfwide Emission Inventory Study (Wilson et al. 2007) was completed; and in 2010 the Year 

2008 Gulfwide Emission Inventory Study (Wilson et al. 2010) was completed. Because the 

offshore sources are changing due to new technology and drilling in deep waters and because of 

new and updated NAAQS standards, BOEM continues to update the emissions inventories every 

three years to concide with the USEPA and State agency inventory process.

The BOEM Gulf of Mexico OCS Regional office sponsored this project, the Year 2011 

Gulfwide Emissions Inventory Study (BOEM Contract No. M10PC00084), which builds on the 

previous studies and has the goal of developing a calendar year 2011 air pollution emissions 

inventory for all OCS oil and gas production-related sources in the GOM, 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 major greenhouse gases—carbon 

dioxide (CO2), methane (CH4), and nitrous oxide (N2O). The platform and non-platform 

emission inventory files are provided in Microsoft® Access® format. Documentation of the 

structure of these files is provided in the ReadMe Word files.

Similar to the previous air quality emission inventory studies, the 2011 Gulfwide Offshore 

Activities Data System (GOADS-2011) software was created to collect monthly activity data 

from platform sources. The activity data were combined with the most recent emission factors 

published by the USEPA, 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), drilling rigs, marine vessels, and helicopters. Ultimately, State 

13
agencies and Regional Planning Organizations will use these offshore oil and gas platform and 

non-platform inventories to perform modeling for ozone and regional haze for use in their State 

Implementation Plans (SIPs), and BOEM will use the emission inventory for the cumulative 

impact analysis in National Environmental Policy Act (NEPA) Environmental Impact Statement 

(EIS) documents.

Somewhat similar to the results of the 2008 inventory, the 2011 inventory results indicate 

that OCS oil and gas production platform and non-platform sources emit the majority of criteria 

pollutants and greenhouse gases in the GOM on the OCS, with the exception of SO2 (primarily 

emitted from commercial marine vessels), and N2O (from biological sources). The OCS oil and 

gas production platform and non-platform sources account for 90% of the total CO emissions, 

73% of NOx emissions, 68% of PM10 emissions, 42% of SO2 emissions, 63% of VOC emissions, 

and 85% of the greenhouse gas emissions. Similar to the 2008 inventory, natural gas engines on 

platforms represented the largest CO emission source, accounting for 47% of the total estimated 

CO emissions, and support vessels were the highest emitters of both NOx and PM10, accounting 

for 37% and 42% of the total estimated emissions. Oil and natural gas production platform vents 

account for the highest percentage (29%) of the VOC emissions. Support vessels (32% of total 

emissions), production platform natural gas, diesel, and dual-fuel turbines (18% of total 

emissions), and commercial marine vessels (11% of total emissions) emit the majority of the 

greenhouse gas emissions.

Though the emission estimation methods and emission factors for platform sources included 

in this study are very similar to those used in the Year 2008 Gulfwide Emission Inventory Study

(Wilson et al. 2010), the emission factors used to estimate emissions for the non-platform mobile 

source categories differ, because emission factors specifically representative of 2011 were used 

in this study. The USEPA emission factors vary by year because the data take into account 

changes in the implementation of marine fuel and engine exhaust standards, and changes in the 

marine fleet due to the addition of new vessels and the retirement of older vessels. It should also 

be noted that commercial marine vessel (CMV) emission estimates for 2008 were provided by 

the USEPA using a top-down approach and only accounted larger Category 3 vessels. For 2011, 

CMV activity was developed from port entrance and clearance data for individual vessels 

(including Category 1, 2, and 3 vessels), such that the activity data used in 2011 is more 

complete and of higher quality than the top-down USEPA data provided in 2008. 

Comparisons of pollutant-specific emission estimates for oil and natural gas production 

platform and non-platform sources show that the total CO emission estimates vary slightly from 

2008 to 2011. A 12% increase is seen in the overall VOC emission estimate. Greater differences 

are seen, however, in the NOx (25% increase), PM10 (33% increase), and SO2 estimates (23% 

decrease). For greenhouse gases, the overall N2O emission estimate varies slightly from 2008 to 

2011. A significant increase is seen in the CO2 estimates (37%), while a decrease (36%) is seen 

in the CH4 estimates.

For oil and natural gas production platforms, the CO and VOC emission estimates show 

slight decreases in emissions from 2008 to 2011, and the NOx and PM10 emission estimates show 

slight increases. The SO2 emission estimate, however, shows greater than 200% increase. This 

increase is due primarily to the natural gas, diesel, and dual-fuel turbine emission estimates. The 

14
2008 turbine emission estimate included only natural gas turbines. The 2011 natural gas engine 

estimates drive the overall decrease in estimated emissions for CO, indicating a decrease in 

reported activity levels. The decrease in the 2011 emission estimates for VOC is driven by the 

fugitives and pressure level controllers emission estimates. Similar to the SO2 estimate, the 

increase seen in the NOx and PM10 emission estimates is driven by natural gas, diesel, and dualfuel turbines. Greenhouse gas emissions from oil and natural gas production platforms slightly 

increased from 2008 to 2011. Similar to the increase in the SO2 emission estimate, the increase is 

driven in large part by the natural gas, diesel, and dual-fuel turbine estimates. The CH4 emission 

estimates for flashing losses also contributed to the increase.

A comparison of the 2008 and 2011 emission estimates for non-platform sources indicates a 

significant increase in criteria pollutant emission estimates, with the exception of SO2. The SO2

reduction is due to a reduction in vessel activities, and application of the most recent USEPA 

emission factors. The USEPA factors have lower sulfur values for smaller vessels equipped with

Category 1 and 2 propulsion engines, such as pipelaying vessels, crew and coast guard patrol 

boats, commercial fishing vessels, and support vessels generators, and pumps associated with the 

Louisiana Offshore Oil Port (LOOP). The increase in CO, NOx, PM10, and VOC emission

estimates for non-platforms sources is primarily due to the use of updated USEPA emission 

factors. The application of the USEPA factors is compounded by increased activity in 2011 for 

support, survey, and commercial marine vessels. For other categories, such as commercial 

fishing, pipelaying drilling rigs, and the LOOP, reductions in activity in 2011 partially offset the 

effects of the USEPA factors. The updated emission factors and activity data yielded an overall 

increase in greenhouse gas emissions.

15

2. INTRODUCTION

2.1 BACKGROUND

The Bureau of Ocean Energy Management (BOEM) is responsible for determining if air 

pollutant emissions from Outer Continental Shelf (OCS) oil and natural gas platforms and other 

oil and natural gas sources in the Gulf of Mexico (GOM) influence the National Ambient Air 

Quality Standards (NAAQS) compliance of onshore areas. Texas and Louisiana have coastal 

areas that are designated as nonattainment for the eight-hour ozone standard. 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 BOEM 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 GOM. 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 GOM. BOEM launched a series of studies, beginning in the 1980s, to assess the 

emissions of offshore oil and gas platforms and their associated emissions. In 1991 BOEM 

sponsored a regional ozone modeling effort conducted by the U.S. Environmental Protection 

Agency (USEPA) 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 (Systems Applications International et al. 1995).

BOEM has sponsored four more recent air quality emission inventory projects. Through an 

Office of Management and Budget-approved Information Collection Request, BOEM required 

affected platform operators to collect activity data used in these studies. One study affected only 

platforms within 100 kilometers (km) of the Breton National Wilderness Area in the GOM, 

where visibility and regional haze concerns may apply. As part of its program to collect activity 

data, a Microsoft® 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. An Oracle® database management program (DBMS) was updated and used to develop the 

emissions estimates for calendar year 2000 (Billings and Wilson 2004).

The Gulfwide Emission Inventory Study for Regional Haze and Ozone Modeling Effort built 

upon the previous BOEM studies with the goal of developing criteria pollutant and greenhouse 

gas emission inventories for all oil and gas production-related sources in the entire GOM OCS

for calendar year 2000. The Gulfwide Offshore Activities Data System (GOADS) was developed 

from the BOADS Microsoft® Visual Basic® program; it was modified to request activity data for 

additional emission sources. The emission estimation procedures in the Breton Oracle® DBMS 

were also expanded (Wilson et al. 2004). The 2005 and 2008 Gulfwide Emission Inventory 

Studies covered the same sources, pollutants, and geographic area as the 2000 inventory (Wilson 

et al. 2007; 2010). Updates were made to the GOADS-2005 and GOADS-2008 programs as 

needed.

17
The BOEM Gulf of Mexico OCS Regional office sponsored this project, the “Year 2011

Gulfwide Emissions Inventory Study” (BOEM Contract No. M10PC00084), with the goal of 

developing a calendar year 2011 air pollution emissions inventory for all OCS oil and gas 

production-related sources on the GOM OCS. Pollutants covered in this inventory are the criteria 

pollutants—carbon monoxide (CO), NOx, sulfur dioxide (SO2), particulate matter-10 (PM10), 

PM2.5, and VOC; as well as major greenhouse gases—carbon dioxide (CO2), methane (CH4), and 

nitrous oxide (N2O).

2.2 SCOPE AND PURPOSE OF THIS PROJECT

BOEM is responsible for determining if GOM OCS oil and natural gas platforms and other 

oil and natural gas production sources in the central and western GOM (west of latitude 87.5o) 

influence the NAAQS compliance of onshore areas. The BOEM also has responsibilities under 

the NEPA to assess the cumulative air quality impacts of oil and natural gas production on the 

GOM OCS. The goal of this project is to develop a calendar year 2011 air pollution emissions 

inventory for all OCS oil and gas production-related sources in the GOM, including nonplatform sources. 

Through an Office of Management and Budget-approved Information Collection Request, 

BOEM required affected platform operators to collect and submit the activity data needed to 

develop air pollutant emissions estimates from platform activities for calendar year 2011. The 

activity data were collected based on BOEM NTL No. 2010-G06, “2011 Gulfwide OCS 

Emissions Inventory (Western Gulf of Mexico).”

BOEM updated and distributed a Mircosoft® Visual Basic® program for platform operators 

to use to collect activity data on a monthly basis and submit to BOEM on an annual basis. The 

program, known as the GOADS-2011, was used by operators to submit activity data for a 

number of production platform emission sources. Operators used the GOADS software to collect 

activity data for amine units, boilers/heaters/burners, diesel engines, drilling equipment, 

fugitives, combustion flares, glycol dehydrators, losses from flashing, mud degassing, natural gas 

engines, natural gas/diesel/dual-fuel turbines, pneumatic pumps, pressure/level controllers, 

storage tanks, and cold vents.

These activity data were used to calculate CO, NOx, SO2, PM10, PM2.5, and VOC emissions 

estimates; as well as CO2, CH4, and N2O. The Gulfwide Oracle® DBMS calculates and archives 

the activity data and the resulting emissions estimates. Database users can query by pollutant, 

month, equipment type, platform, etc.

Emission estimates for non-platform sources on the GOM OCS include both oil and natural 

gas production-related sources, as well as non-oil and natural gas production sources. Production 

sources consist of survey vessels, drilling rigs, pipelaying operations, and support vessels and 

helicopters. Non-oil and natural gas production sources include commercial marine vessels, the 

Louisiana Offshore Oil Platform (LOOP), and biogenic and geogenic sources. 

18
2.3 STUDY OBJECTIVES

The objectives of this study are:

• To review, modify, and provide support services for GOADS-2011 and the 

2011 Gulfwide Oracle® DBMS.

• To collect, describe, quality check, quality assure, and archive activity data 

from all platform and non-platform sources on the OCS that emit air 

pollutants over the course of one (1) calendar year (2011). Activity data from 

platform sources were collected using GOADS-2011.

• To calculate and archive a calendar year 2011 total emissions inventory using 

the most current emission factors and the 2011 Gulfwide DBMS for all 

specified platform and non-platform sources, and to compare the emissions 

inventory with previously collected emissions data.

• To provide the platform and non-platform emission inventory files in 

Microsoft® Access® format, along with documentation of the structure of the 

files in ReadMe Microsoft® Word files.

2.4 REPORT ORGANIZATION

Following this introduction, the Year 2011 Gulfwide Emissions Inventory Study report is 

organized as follows:

• Section 3 discusses how the platform activity data were collected and 

compiled.

• Section 4 summarizes the quality assurance/quality control (QA/QC) 

procedures that were implemented after receipt of the platform activity data 

files to prepare the data for use in developing emissions calculations. The 

approach used to fill in data gaps in the platform data is also discussed in 

Section 4.

• Section 5 presents calculation methods for each piece of platform equipment. 

These calculation routines are performed in the Oracle® DBMS.

• Section 6 presents the collection of activity data, QA/QC, and calculation 

methods for non-platform sources.

• Section 7 summarizes the resulting emission estimates by equipment type, 

source category, and pollutant. The limitations associated with the data and 

the emission estimates are also noted in Section 7, and the results are 

compared with the Year 2008 Gulfwide Emission Inventory Study Report 

(Wilson et al. 2010).

• Section 8 presents references cited throughout the report.

19

3. DATA COLLECTION FOR PLATFORM SOURCES

3.1 INTRODUCTION

To develop a calendar year 2011 inventory of criteria pollutant and greenhouse gas emissions 

for all OCS oil and gas production-related sources in the GOM, BOEM collected activity data 

from platform operators during the year 2011. On September 15, 2010, NTL 2010-G06 was 

published to introduce the “2011 Gulfwide OCS Emissions Inventory (Western Gulf of Mexico)” 

and inform operators about the mandatory data collection. Affected operators are lessees and 

operators of Federal oil, gas, and sulfur leases in the GOM OCS region west of latitude 87.5°. 

The USEPA jurisdiction has air quality jurisdiction east of latitude 87.5°.

This section of the report outlines the steps that BOEM took to collect the data, including 

modifying the data collection software, meeting with and training platform operators, and 

answering questions about data collection. Activity data were collected during one calendar year 

(2011) and were used to calculate and archive emissions data using the most current emission 

factors and calculation methods.

3.2 IMPROVEMENT OF THE GOADS DATA COLLECTION SOFTWARE

The GOADS data collection software that was used to collect calendar year 2000, 2005, and 

2008 platform activity data was revised for this study to address several issues uncovered during 

its use for preparing previous inventories. The largest improvement to the new version, GOADS2011, was the addition of diesel and dual-fuel turbines. 

3.3 WORKING WITH USERS

A workshop was held in New Orleans on October 8, 2010, to discuss and explain the 2011 

Gulfwide study information collection and reporting procedures. The User’s Guide for the 2011 

Gulfwide Offshore Activities Data System (GOADS-2011) (Wilson and Boyer 2011) was the 

primary source of information for operators. The guide was provided at the workshop, and made 

available to all users through the BOEM website, where it could be downloaded and printed. The 

guide contains instructions on installation, starting and exiting the GOADS program, creating 

and editing data, quality control, and saving and backing up files. For details on the GOADS2011 program, refer to the User’s Guide (Wilson and Boyer 2011).

3.4 GOADS QUALITY ASSURANCE/QUALITY CONTROL

BOEM programmed automatic QA procedures into the software in an effort to minimize the 

submittal of incomplete and erroneous activity data by the platform operators as detailed in 

Section 4. BOEM 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 BOEM.

The software also automatically runs a series of QC checks (discussed in Section 4) 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 may then correct the problem, override the QC check (and provide a 

21
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, BOEM 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 within BOEM.

22
4. QUALITY ASSURANCE/QUALITY CONTROL

4.1 INTRODUCTION

Platform operators submitted data files and QA Summary Forms generated by the GOADS2011 software. Ninety six companies submitted data for 3,051 active or inactive platforms 

(combination of complex ID and structure ID) (about 85% of OCS platforms) including minor 

sources. 2,544 structures were active (at least one month). Of these, 1,366 were flagged as minor 

sources. Thus, approximately 330 platforms are unaccounted for in the year 2011 inventory.

This section summarizes the data received, the steps BOEM took to review the GOADS2011 descriptive and monthly activity data for completeness and accuracy, and 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, BOEM attempted to reconcile the data by 

reviewing the comments, contacting the operators, or developing surrogate data.

4.2 CHECKING FILE INTEGRITY

BOEM received 101 unique data files for the 2,544 active platforms. All electronic data were 

in the prescribed Microsoft® Access® database that was created by the GOADS-2011 software. 

For comparison, 113 unique data files were submitted for the calendar year 2008 inventory for 

3,026 active platforms. Similar to the calendar year 2008 inventory, BOEM required minor 

sources to report minimal data through GOADS-2011. 

The 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). The ERG was able to 

open and review all of the files provided. 

4.3 EQUIPMENT SUMMARY CHECKS

Each GOADS-2011 submittal contained templates for up to 34 tables. The majority of these 

tables cover the descriptive and activity data for specific equipment types (amine units, boilers, 

etc.). The user-, structure-, and QC tables were appended along with the equipment tables 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.

4.3.1 User-Level Summary

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

company number assigned by BOEM. The user IDs submitted were checked against the BOEM 

master lease and company lists. 

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

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

platform. Corrections were only needed for one platform’s structure ID.

23
4.3.2 Structure-Level Summary

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

coordinates, sales gas composition, total monthly platform fuel usage, status (active or inactive 

for that month), and indicate if the platform was a minor source. A total of 36,784 records were 

submitted, and 29,887 were considered active (81%). For comparison, 35,952 active records 

were submitted for calendar year 2008.

4.3.3 Equipment-Level Summary

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

can be populated for each platform. A list of all the platform equipment submitted per equipment 

type was compiled. This composite list includes a total of 259,700 equipment surveys, of which 

152,957 were active (59%).

4.4 QA/QC CHECKS

A number of QA/QC steps were performed to identify missing and out-of-range data for each 

type of equipment. The first step of the QA/QC task consisted of reviewing the sales gas 

compositions for validity and completeness. The sum of compositions that deviated from 100% 

were evaluated and corrected. Questionable sales gas compositions were replaced with a default 

set of compositions. Less than 2% of the monthly equipment records required this correction. 

Another part of the QA/QC task for the GOADS submittals was to identify incorrect and 

missing equipment descriptive and activity data, and to correct and populate the missing 

information with surrogates. Seven 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; 6) post-processing of surrogates; and 

comparison and revision based on OGOR-reported vent and flare volumes.

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 or individual pieces of equipment as 

being inactive for each month by checking a “No Emissions to Report” checkbox. Otherwise, all 

platforms and equipment were treated as active. 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.

24
Platform/equipment 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 and other active equipment records are reported; 2) in the Losses from Flashing 

equipment tables the throughput was greater than zero; or 3) in the Mud Degassing equipment 

table, the drilling days per month were greater than zero.

45% of the monthly activity data records were revised in these pre-processing QA/QC steps. 

It is important to note that this percentage is misleadingly high because it is almost exclusively

changes where “No Emissions to Report” were assigned to a minor source, and because 

GOADS-2011 automatically flags a record as active when a monthly record is created, but its 

status is actually inactive when zero values are entered for throughput or fuel use. 

For each month, operating hours were provided for most types of equipment. A typical error 

would be to exceed the maximum hours possible for a given 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. The maximum number of hours for February (with 28 days) is 672. Two exceptions are also 

noted due to the implementation of daylight savings: 1) the number of hours possible for March 

is 743 hours; and 2) the number of hours possible for November is 721 hours. Less than 5% of 

the monthly equipment records required corrections in this process.

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 turbine, and drilling rig 

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 values for each reported 

boiler/heater/burner, diesel engine, natural gas engine, and natural gas turbine were 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. Less than 3% of the monthly 

equipment records required corrections in this process.

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. Less 

than 1% of the monthly equipment records required corrections in this process. 

25
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). Only 1% of the monthly equipment records required corrections in this process.

The GOADS-2011 QC checks flag these incorrect data, as indicated by the limited number of 

corrections needed. Unfortunately, there was clear evidence that some databases were not 

populated with the GOADS software as they contained invalid equipment type codes, 

mismatching equipment type codes, and database relational integrity errors.

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.

4.4.4 Stream Analysis Between Certain Equipment

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

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

identified; otherwise the calculations may overestimate emissions. The Amine Unit, Glycol 

Dehydrator, Losses from Flashing, Pneumatic Pumps, and Storage Tanks equipment may 

exhaust gases locally or downstream. If the Cold Vent or Combustion Flare ID is populated in 

these tables, then a downstream analysis was performed on the Cold Vent or Combustion Flare 

equipment tables to verify their existence. For Cold Vent or Combustion Flare IDs that could not 

be traced to an existing active vent or flare, the survey was updated as to being vented/flared 

locally. Only 1% of the monthly equipment records required corrections during this process.

Table 4-1. Fields and range check values

Field Range Check

API Specific Gravity Minimum value: 9 degrees API

Flare Efficiency Between 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%

Heat Input Rate Not to exceed maximum heat input rate

Inner Diameter Varies by equipment type

Operating Horsepower Not to exceed maximum rated horsepower

Stack Angle Between 0 and 180

26
4.4.5 Applying Surrogate Values

Surrogate values were used to populate missing stack parameters that are not used to 

calculate emissions, but 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 BOEM. Approximately 12% of 

the monthly equipment records required corrections in this process.

Table 4-2. Surrogate stack parameters used to supplement GOADS-2011 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 Average 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

Combustion Flare Combustion 

temperature (excluding 

upsets)

1832 oF

Combustion Flare Stack orientation 0 degrees

Combustion Flare Outlet diameter 12 inches

Combustion Flare Pilot feed rate 2.28 Mscf/day

Combustion Flare H2S concentration 3.38 ppm

27
Unit Field Default Value

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 GLYCalcTM default (usually 

212 oF)b

Glycol Dehydrator– ventilation 

system

Outlet orientation 0 degrees

Glycol Dehydrator– ventilation 

system 

Flare feed rate (scf/hr) Calculated with GLYCalcTMb

Glycol Dehydrator– ventilation 

system 

Combustion 

temperature

1832 oF

Glycol Dehydrator– ventilation 

system 

Condenser temperature 110 oF (or calculated with 

GLYCalcTM)

b

Glycol Dehydrator– ventilation 

system 

Condenser pressure 14.8 psia

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 7500 Btu/hp-hr

Natural Gas Engine Average fuel usage 7500 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 Average fuel use 10,000 Btu/hp-hr

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

28
Unit Field Default Value

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 ÷2), ft

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)

Cold Vent Outlet elevation (above 

sea level)

50 ft

Cold Vent Outlet diameter Calculated (average of 

submitted data)

Cold Vent Exit temperature 70 oF

Cold Vent Outlet orientation 0 degrees a AMINECalc is released by the American Petroleum Institute (API 1999) b GLYCalcTM is released by the Gas Technology Institute, formerly the Gas Research Institute (GRI) (GTI 2000)

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 parameters 

were recalculated using a combination of corrected and originally-submitted activity and 

descriptive data to yield values consistent with the inter-related, quality assured data parameters.

4.4.7 Comparison to OGOR Reports

The last QA/QC check implemented was a comparison of the GOADS-2011 data submittals 

for volume vented and flared with the values reported to the Office of Natural Resources 

Revenue (ONRR) through Oil and Gas Operations Report (OGOR) forms (Form ONRR-4054-

B). Operators must provide monthly OGOR forms of the volumes vented and flared for “all 

wells for a lease/agreement.” BOEM contacted 86 companies (with a total of 1,439 platforms), 

and received revised vent/flare estimates for 401 platforms. BOEM received confirmation for 

305 platforms that the submitted GOADS-2011 vent/flare volumes were correct. No response 

was provided for 72 platforms. The remaining platforms reported only to OGOR, were exempt 

from GOADS reporting, or had no vent/flare volumes.

Based on the results of this comparison, it is clear that BOEM must continue to highlight the 

need for consistent reporting with the OGOR reports for future GOADS data collection and 

inventory efforts.

29

5. DEVELOPMENT OF THE PLATFORM EMISSION INVENTORY

5.1 INTRODUCTION

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

inventories for all oil and gas production-related sources in the GOM OCS. To achieve this goal, 

BOEM revised the 2008 Gulfwide Oracle® DBMS to create the 2011 Gulfwide Oracle® DBMS. 

The 2011 Gulfwide DBMS imports the activity data provided by platform operators, and applies 

emission factors and emission estimation algorithms to calculate emissions from platform 

sources in the GOM. The 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.

The BOEM 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 

BOEM recommended values. For example, the diesel fuel sulfur content is consistent with 

BOEM “Spreadsheet for Exploration Plans.”

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 fuel heating value = 20,300 Btu/lb

Gasoline density = 6.17 lb/gal

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%

5.2 EMISSION ESTIMATION PROCEDURES

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

from those in the 2008 Gulfwide DBMS (Wilson et al. 2010), as the emission estimation 

methods for platform sources have not been revised by USEPA or other sources. The exceptions

are losses from flashing and cold vents, where adjustments were made to the emission estimation 

equations. USEPA emission factors were updated for several equipment types. The following 

sections present the methods used to calculate criteria pollutant and greenhouse gas emissions 

from platform sources in the study.

31
5.2.1 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 (Systems Applications International et al. 1995).

Activity data were submitted for five amine units. Operators were required to use the “Model 

Inputs” tab. CH4 and VOC emissions are estimated externally using AMINECalc (API 1999), 

and loaded directly into the DBMS. Emissions are adjusted for any control devices that were 

reported, such as a combustion 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:

100%

100 Eff E E c, d

c,control c,unc

− = ×∑

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 (%)

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

combustion flares, will produce emissions of SO2 as a by-product. If a combustion flare is 

present, SO2 emissions are calculated as follows (EIIP 1999; Wilson et al. 2007).





















































× ⋅ ×

⋅

= 100

Eff

lb mol

64 lb

34 lb

lb mol

E E 2 SO

2 SO

2 SO

S2 H

S2 H

,control H2S

2 SO

where:

ESO2, control = Resulting SO2 emissions (pounds per month)

EH2S = Uncontrolled emissions of H2S (pounds per month)

EffSO2 = Flare efficiency (%)

If a sulfur recovery unit is present, SO2 emissions are calculated as follows (EIIP 1999, 

Billings and Wilson 2004):





 





× − 















⋅

⋅ ×















×

















⋅ ×















 ⋅ = 100

% RE 1

3 lb mol

1lb mol

100

Eff

lb mol

64 lb

34 lb

lb mol

E E

S

SO SO

SO

SO

H S

H S

,control H S

2 2

2

2

2

2

2 SO2

32
where:

ESO2, control = Resulting SO2 emissions (pounds per month)

EH2S = Uncontrolled emissions of H2S (pounds per month)

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

5.2.2 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). Activity 

data were submitted for 583 boilers, heaters, or burners. To calculate uncontrolled emissions for 

liquid-fueled engines (waste oil or diesel) based on fuel use, Efu,liq:

E EF 10 U 7.1lb/gal liq

-3

(lb/10 gal) fu, liq = 3 × × ÷

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

gas) based on fuel use, Efu,gas:

gas

3 Efu,gas = EF(lb/MMscf) ×10 × U −

where:

E = Emissions in pounds per month

EF = Emission factor 

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. Fuel usage was calculated for 408 of the active units.

The following emission factors are used to estimate emissions (Tables 5-1 through 5-6). 

These factors come from AP-42, Sections 1.3 and 1.4 (USEPA 2010). All boilers are assumed to 

be wall-fired boilers (no tangential-fired boilers). Emission factors for No. 6 residual oil were 

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

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

Flue Gas 

Recirculation

VOC 0.2 0.2 0.2

SO2

a 142 × S 142 × S 142 × S

NOx 24 10 10

PM2.5 0.25 0.25 0.25

PM10 1 1 1

CO 5 5 5

N2O 0.26 0.26 0.26

33
Emission Factors (lb/103 gal)

Pollutant Uncontrolled

Low NOx

Burner

Flue Gas 

Recirculation

CH4 0.052 0.052 0.052

CO2 22,300 22,300 22,300 a S = Fuel sulfur content (wt%)

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

Flue Gas 

Recirculation

VOC 0.2 0.2 0.2

SO2

a 142 × S 142 × S 142 × S

NOx 20 20 20

PM2.5 0.25 0.25 0.25

PM10 2 2 2

CO 5 5 5

N2O 0.26 0.26 0.26

CH4 0.052 0.052 0.052

CO2 22,300 22,300 22,300 a S = Fuel 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

Flue Gas 

Recirculation

VOC 0.28 0.28 0.28

SO2

a 157 × S 157 × S 157 × 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 0.53 0.53 0.53

CH4 1.00 1.00 1.00

CO2 24,400 24,400 24,400 a S = Fuel sulfur content (wt%)

34
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

Flue Gas 

Recirculation

VOC 0.28 0.28 0.28

SO2

a 157 × S 157 × S 157 × S

NOx 55 55 55

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 0.53 0.53 0.53

CH4 1.00 1.00 1.00

CO2 24,400 24,400 24,400 a S = Fuel sulfur content (wt%)

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

Flue Gas 

Recirculation

VOC 5.5 5.5 5.5

SO2 0.6 0.6 0.6

NOx 280 140 100

PM10a 1.9 1.9 1.9

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 a Also represents PM2.5

35
Table 5-6. Emission factors for gas-fueled units – natural gas or process gas where max rated 

heat input < 100 MMBtu/hr

Pollutant

Emission Factors (lb/MMscf)

Uncontrolled

Low NOx

Burner

Flue Gas 

Recirculation

VOC 5.5 5.5 5.5

SO2 0.6 0.6 0.6

NOx 100 50 32

PM10a 1.9 1.9 1.9

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 a Also represents PM2.5

5.2.3 Diesel and Gasoline Engines

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

(USEPA 2010). Activity data were submitted for 2,318 engines. A user-entered value for total 

fuel usage, or a calculated value for total fuel usage based on operator-supplied hours of 

operation, average fuel usage (or a surrogate fuel consumption rate of 7,000 Btu/hp-hr), fuel 

heating value, and operating horsepower, is used to estimate emissions. The surrogate fuel 

consumption rate was only needed for four units.

To calculate uncontrolled emissions based on fuel use, Efu:

H

gal

7.1lb E EF 10 U -6

fu = (lb/MMBtu) × × × ×

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)

The following emission factors are used to estimate emissions (Tables 5-7 through 5-9). 

These factors come from AP-42, Sections 3.3 and 3.4 (USEPA 2010).

36
Table 5-7. Emission factors for gasoline engines

Pollutant

EFfu

(lb/MMBtu)

EFpo

(g/hp-hr)

VOC 3.03 9.8

SO2 0.084 0.268

NOx 1.63 4.99

PM10a 0.1 0.327

CO 0.99 3.157

CO2 154.0 489.9 a Also represents PM2.5

Table 5-8. Emission factors for diesel engines where max HP < 600

Pollutant

EFfu

(lb/MMBtu)

EFpo

(g/hp-hr)

VOC 0.33 1.04

SO2 0.29 0.93

NOx 4.41 14.1

PM10a 0.31 1

CO 0.95 3.03

CO2 164.0 521.6 a Also represents PM2.5

Table 5-9. Emission factors for diesel engines where max HP ≥ 600

Pollutant

EFfu

(lb/MMBtu)

EFpo

(g/hp-hr)

VOC 0.08 0.29

SO2

a 1.01 × S 3.67 × S

NOx 3.2 10.9

PM2.5

b 0.056 0.178

PM10 0.057 0.182

CO 0.85 2.5

CH4 0.008 0.03

CO2 165.0 526.2 a S = Fuel sulfur content (wt%)

b <3 μm

If the corresponding field is null, a surrogate fuel consumption rate of is applied.

37
5.2.4 Drilling Equipment

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. Activity data were submitted for 39 drilling units, all of which reported 

only diesel fuel usage. 

For gasoline fuel use, calculate uncontrolled emissions, Egas, as follows (Wilson et al. 2007):

lb

20,300 Btu

gal

6.17 lb E EF 10 U -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 (Wilson et. al. 2007):

lb

19,300 Btu

gal

7.1lb E EF 10 U -6

die = (lb/MMBtu) × × × ×

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:

E EF 10 U 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 (Tables 5-10 through 5-12). 

These factors come from AP-42, Sections 3.2, 3.3 and 3.4 (USEPA 2010). Diesel engines are 

assumed to be ≥ 600 hp. Natural gas engines are assumed to be four-cycle and evenly distributed 

between lean and rich burns (by averaging).

38
Table 5-10. Emission factors for gasoline fuel use

Pollutant

EFgas

(lb/MMBtu)

VOC 3.03

SO2 0.084

NOx 1.63

PM10a 0.1

CO 0.99

CO2 154 a Also represents PM2.5

Table 5-11. Emission factors for diesel fuel use

Pollutant

EFdie

(lb/MMBtu)

VOC 0.08

SO2

a 1.01 × S

NOx 3.2

PM2.5

b 0.056

PM10 0.057

CH4 0.008

CO 0.85

CO2 165 a S = Fuel sulfur content (wt%)

b <3 μm

Table 5-12. Emission factors for natural gas fuel use

Pollutant

EFng

(lb/MMscf)

VOC 75.3

SO2 0.6

NOx 2,467.5

PM10 a 4.9

CO 2,127.3

CH4 755

CO2 112,200 a Also represents PM2.5

5.2.5 Combustion 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 (Systems Applications International et al. 1995). As noted in 

Section 4.4.7 for the 2011 effort, due to the U.S. Government Accountability Office (GAO) 

report 11-34, the GOADS volumes vented were verified against and corrected if necessary with 

the ONRR OGOR data. Activity data were submitted for 144 combustion flares.

39
Flare emissions for THC, VOC, NOx, PM10, and CO are estimated according to the following 

equation:

E V H EF 1000 flare = tot × × flare ÷

where:

Eflare = Emissions in pounds per month

Vtot = Total volume of gas flared (Mscf, including upsets) 

H = Flare gas heating value (Btu/scf)

EFflare = Emission factor for flares (lb/MMBtu)

SO2 emissions are estimated using the following equation:

( ) H S

SO

6

F

flare,SO 2

2

2 1000 V' C

379.4 scf/lb mol

m

ppm

10

100%

Eff % E × × × ⋅ × × 

 



 =

−

where:

Eflare, SO2

= Emissions in pounds per month

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

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

V' = Volume of gas flared (Mscf) 

CH2S = Concentration of H2S in the flare gas (ppm) 

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

follows:

E P D EF 1000 pilot = × × pilot ÷

where:

Epilot = Pilot emissions in pounds per month

P = Pilot 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 (Tables 5-13 and 5-14). The 

CO, NOx, and THC emission factors come from AP-42, Sections 13.5 and 1.4 (USEPA 2010). 

The VOC and CH4 emission factors are derived from the default sales gas composition shown in 

Table 5-25 of this report based on the weight fraction of the volatile components.

40
Table 5-13. Emission factors for combustion flaresa

Pollutant EF (lb/MMBtu)

VOC 0.006

NOx 0.068

PM10

b 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

N2O 0.002

CH4 0.126

CO2 114.285 a Factors for N2O and CO2 were derived from pilot 

emission factors

b Also represents PM2.5

Table 5-14. Emission factors for pilots

Pollutant EF (lb/MMscf)

VOC 5.5

NOx 100

PM10a 1.9

SO2 0.6

CO 84

N2O 2.2

CH4 2.3

CO2 120,000 a Also represents PM2.5

If the corresponding fields are null, the following surrogate values (based on industry 

defaults) are applied:

Flare Smokedefault = None

Pilot Fuel Feed Rate = 2.28 Mscf/day

27 flares were assigned none as the surrogate for flare smoke, and 33 flares were assigned the 

surrogate pilot fuel feed rate. The emission factors shown in Table 5-13 are assumed to be based 

on flares operating under stable conditions, with a combustion efficiency of approximately 98%. 

Based on a comment by a Science Review Board member for the Year 2005 Gulfwide Emission 

Inventory Study (Wilson et al. 2007) that platforms may not all be operating under stable 

conditions, however, the BOEM reviewed the flare velocities to insure that all were less than 

400 fps, reflective of stable conditions (TCEQ 2000). In 2011, five flares had reported exit gas 

velocities greater than 400 fps; thus the emission factors for VOC and CH4 for these sources 

were adjusted to reflect unstable conditions and hence combustion efficiencies of 93% were 

applied (TCEQ 2006).

41
5.2.6 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 records were submitted for 92% of the active 

platforms.

Fugitive THC emissions are estimated according to the following equation:

= ∑( × ) comp

ETHC EFcomp,stream Ncomp × D

where:

ETHC = THC emissions in pounds per month

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

(lb/component-day) (Table 5-15)

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: 

EVOC = ETHC × 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 ECH4 = ETHC × 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

42
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: 1,713

Open-Ends: 285

Others: 228

These surrogates were only applied to 27 platforms. 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 THC emissions by stream typea

THC Fraction Gas

Natural 

Gas 

Liquid

Light Oil

(≥ 20 API 

Gravity)

Heavy Oil

(<20 API 

Gravity) Water/Oilb

Oil/Water/

Gas

CH4 0.8816 0.612 0.612 0.942 0.612 0.612

VOC 0.0396 0.296 0.296 0.030 0.296 0.296 a Source: API 1996 for all stream types except gas. Emission factors for gas streams derived from default sales gas 

composition.

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.

43
5.2.7 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 GRIGLYCalcTM Version 4.0 (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 GRI-GLYCalcTM Version 4.0 computer 

program runs for varying combinations of flash tank pressure and flash tank temperature. 

Activity data were submitted for 256 glycol dehydrators. Table 5-17 presents the surrogate gas 

analysis (based on industry averages) 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 GRIGLYCalcTM 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.

44
Table 5-17. Surrogate gas analysis for GLYCalcTM runs

Component Mole Percent (%)

Hydrogen Sulfide 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

5.2.8 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). Only 339 platforms 

provided activity data for losses from flashing.

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;

45
• 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 barrel (bbl) of oil throughput (optional).

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

Lf = (GOR U - GOR V )× Throughput × GD

where:

Lf = Emissions in pounds per month

GORU = Gas-to-oil ratio (scf/bbl) for upstream vessel

GORV = Gas-to-oil ratio (scf/bbl) for vessel

Throughput = Throughput volume for each vessel (bbl/month)

GD = Gas density (lb/scf)

Gas-to-oil ratio, GOR:

















+

×

= × × ×

Vessel temp 460

C API gravity

C

1

3

2 GOR C OP CSG e

where:

GOR= Gas-to-oil ratio (scf/bbl)

C1 = Vasquez-Beggs constant = 





 >

0.0362; otherwise

0.0178; if API gravity 30

OP = Vessel operating pressure (psia)

C2 = Vasquez-Beggs constant = 





 >

1.0937; otherwise

1.187; if API gravity 30

CSG = Corrected specific gravity of gas (see below) 

C3 = Vasquez-Beggs constant = 





 >

25.724; otherwise

23.931; if API gravity 30

Emissions of VOC, CO2, and CH4 are estimated using the following gas densities based on 

the average sales gas weight percent for OCS platforms:

GD,VOC = 0.0018 lb/scf

GD,CO2 = 0.000928 lb/scf

GD,CH4 = 0.04 lb/scf

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.

46
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

5.2.9 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). Activity data were reported for 22 active mud degassing 

operations. 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).

Emissions were calculated using the equation:

ETHC = EFTHC × Ddrill

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 USEPA report Atmospheric Emissions from Offshore Oil and Gas 

Development and Production (USEPA 1977):

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. Synthetic-based 

muds are used as substitutes for oil-based muds, and may occasionally be used to replace waterbased muds. Synthetic muds perform like oil-based muds, but with lower environmental impact 

and faster biodegradability (USEPA 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 USEPA estimates no change in the amount of waste cuttings between 

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

for synthetic-based muds as well.

47
THC emissions are speciated based on the average sales gas weight percent for OCS

platforms as:

Component Composition by Weight (%)

Methane 88.16

VOC 3.96

CO2 emissions are assumed to be 0.3% of the gases emitted. 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, was

applied.

5.2.10 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 (USEPA 2010). Activity data were submitted for 1,590 natural gas engines.

A user-entered value for total fuel usage, or a calculated value for total fuel usage based on

operator-supplied hours of operation, average fuel usage (or a surrogate fuel consumption rate of 

7,500 Btu/hp-hr), fuel heating value, and operating horsepower, is used to estimate emissions.

The surrogate fuel consumption rate was only needed for 3 units. 

Emissions are calculated based on fuel use as:

-3

fu (lb/MMBtu) E = EF × H × U ×10

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)

Tables 5-18 through 5-21 present the emission factors used to estimate natural gas engine 

emissions. These factors come from AP-42, Section 3.2 (USEPA 2010).

48
Table 5-18. 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)

VOC 0.12 0.41

SO2 5.88 × 10-4 2 × 10-3

NOx (<90% load) 1.94 6.6

PM10a 3.84 × 10-2 0.13

CO (<90% load) 0.353 1.2

CH4 1.45 4.9

CO2 110 374.2 a Also represents PM2.5

Table 5-19. Emission factors for natural gas engines where engine stroke cycle = 4-cycle and 

engine burn type = lean

Pollutant

EFfu

(lb/MMBtu)a

EFpo

(g/hp-hr)

VOC 0.12 0.41

SO2 5.88 × 10-4 2.00 × 10-3

NOx (<90% load) 0.85 2.89

PM10a 7.71 × 10-5 2.6 × 10–4

CO (<90% load) 0.56 1.9

CH4 1.25 4.25

CO2 110 374.2 a Also represents PM2.5

49
Table 5-20. 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)

VOC 0.03 0.1

SO2 5.88 × 10-4 2.00 × 10-3

NOx (<90% 

load

2.27 7.72

PM10a 9.5 × 10-3 0.03

CO (<90 % 

load)

3.51 11.94

CH4 0.23 0.78

CO2 110 374.22 a Also represents PM2.5

Table 5-21. Emission factors for natural gas engines where engine burn type = clean

Pollutant

EFfu

(lb/MMBtu)

EFpo

(g/hp-hr)

VOC 0.12 0.41

SO2 5.88 × 10-4 2.00 × 10-3

NOx 0.59 2.00

PM10a 7.71 × 10-5 2.6 × 10-4

CO 0.88 3.00

CH4 1.25 4.25

CO2 110 374.22 a Also represents PM2.5

5.2.11 Natural Gas, Diesel, and Dual-Fuel Turbines

A 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 (USEPA 2010). Activity data were submitted for 383 turbines. Of these, 250 

reported only natural gas use, 131 reported both natural gas and diesel fuel use, and 2 reported 

only diesel fuel use.

A user-entered value for total fuel usage, or a calculated value for total fuel usage based on 

operator-supplied hours of operation, average fuel usage (or a surrogate fuel consumption rate), 

fuel heating value, and operating horsepower, is used to estimate emissions. A surrogate natural 

gas fuel consumption rate of 10,000 Btu/hp-hr is applied as needed, and a diesel fuel 

consumption rate of 5,954 Btu/hp-hr is applied as needed. These surrogate values were assigned 

for 7 natural gas turbines and 122 diesel or dual-fuel turbines.

50
To calculate emissions based on fuel use:

E EF 10 H U -3

fu = (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)

The following emission factors are used to estimate emissions for natural gas turbines 

(Table 5-22). These factors come from AP-42 Section 3.1 (USEPA 2010).

Table 5-22. Emission factors for natural gas turbines

Pollutant

EF

(lb/MMBtu)a

VOC 2.1 × 10-3

SO2

a 0.94 × S

NOx 0.32

PM10

b 1.9 × 10-3

CO 8.2 × 10-2

N2O 0.003

CH4 8.6 × 10-3

CO2 110 a S= Fuel sulfur content (wt%). If not available, EF is 3.47 × 10-3 

lb/MMBtu b Also represents PM2.5

The following emission factors are used to estimate emissions for diesel turbines (Table 5-

23). These factors come from AP-42 Section 3.1 (USEPA 2010).

Table 5-23. Emission factors for diesel turbines

Pollutant

EF

(lb/MMBtu)

VOC 4.1 × 10-4

SO2

a 1.01 × S

NOx 0.88

PM10

b 4.3 × 10-3

CO 3.3 × 10-3

CO2 157 a S = Fuel sulfur content (wt%)

b Also represents PM2.5

51
5.2.12 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). Activity data were 

submitted for 2,417 pneumatic pumps on 608 platforms.

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 5-24 presents the 

default gas composition if not provided (applied for 25 units on 5 platforms). Table 5-24 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. This surrogate was applied for 1,059 units on 359 platforms.

52
Table 5-24. 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

Source: Developed from average sales gas weight percents for OCS platforms.

5.2.13 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). Activity data were submitted for 1,834 pressure/level controllers on 524 platforms. 

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)

53
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, and VOC), operators were 

asked to provide the sales gas composition for their structure. Table 5-24 presents the default gas 

composition if not provided (applied for 20 units on 10 platforms). Table 5-24 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. This surrogate was applied for 1,092 units on 314 platforms.

5.2.14 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. Activity data were submitted for 607 storage tanks. 

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:

Ls, THC = D× VV × WV × KE × KS

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

54
where:

VV = Vapor space volume (ft3)

HVO = Vapor space outage (ft) = Tank Shell Height − Tank Average Liquid Height

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 Tank Shell Diam H

4

V = × ×

π

where:

VV = Vapor space volume (ft3)

HVO = Vapor space outage (ft) = 











=















 



 



 + +

+ =

; if Tank Roof Type "dome"

Tank Shell Diam

Tank Roof Hgt Tank Shell Hgt Tank Avg Liquid Hgt Tank Roof Hgt

Tank Shell Hgt Tank Avg Liquid Hgt Tank Roof Hgt ; if Tank Roof Type "cone"or "peaked" 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) 

55
B = Empirical constant = 7261 − 1216 × ln(ReidVP)

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

I)

Taa = Daily average ambient temperature (°R) (See Table 5-25)

a = Tank paint solar absorptance (See Table 5-26)

Tb = Liquid bulk temperature (°R) 

I = Daily solar insulation factor (Btu/ft2

·day) = 1437 Btu/ft2·day

The vapor space expansion factor is calculated as:

KE = (Tv/TLA) + (Pv − Pb)/(Pa − Pva)

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 KS = 1/(1+ 0.053× P × H )

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:

w, THC PVA Throughput KP KN L = 0.0010×Tank VOC Mol Weight × × × ×

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) =







>

≤

+ ;for N 36

1;for N 36

6N

180 N

56
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:

Tank Shell Diam Tank Shell Length 4

V 2

LX = × ×

π

Tank maximum liquid volume for a vertical, cylindrical tank is calculated as:

Tank Shell Diam Tank Shell Hgt 4

V 2

LX = × ×

π

where:

VLX = Tank maximum liquid volume (ft3)

Emissions of CH4 and VOC are estimated using the following speciation profiles (USEPA 

2008): 0.467 for VOC, and 0.463 for CH4. 

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

Mole Fractiondefault = 0.9

Tank Avg Liquid Hgtdefault = 0.5 × Tank Shell Hgt

57
Table 5-25. Daily average ambient temperature, Taa

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

°F 53 55 66 73 76 83 83 86 80 72 65 58

°R 513 515 526 533 536 543 543 546 540 532 525 518

Source: USDOC, National Climatic Data Center 2011

Table 5-26. 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

5.2.15 Cold 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), including periods of 

upset venting in the total, and the chemical composition of the gas. As noted in Section 4.4.7, for 

the 2011 effort, due to the GAO report 11-34, the GOADS volumes vented were verified against 

and corrected if necessary with the ONRR OGOR data. Activity data were submitted for 1,169

cold vents.

Vent emissions of VOC are estimated using the following equation:

1000 (V) 379.4 scf/lb mol

m

ppm

10 E C VOC

6

vent, VOC VOC × × ⋅ = × ×

−

where:

Event, VOC = VOC emissions in pounds per month

CVOC = Concentration of VOC in the vent gas (default = 12,700 ppmv)

mVOC = Molecular weight of VOC (lb/lb∙mol)

V = Volume of gas vented from miscellaneous sources (Mscf)

58
Vent emissions of CH4 are estimated using the following equation:

1000 (V) 379.4 scf/lb mol

sales gas mole weight (lbs/lb mol) E WCH4 vent,CH4 × × ⋅⋅ = ×

where:

Event, CH4 = CH4 emissions in pounds

WCH4 = Weight percent CH4 (default = 88.165592)

V = Volume of gas vented from miscellaneous sources (Mscf) 

Vent emissions of CO2 are estimated using the following equation:

1000 (V) 379.4 scf/lb mol

sales gas mole weight (lbs/lb mol) E WCO2 vent,CO2 × × ⋅

⋅ = ×

where:

Event, CO2 = CO2 emissions in pounds

WCO2 = Weight percent CO2 (default = 2.04796139) 

V = Volume of gas vented from miscellaneous sources (Mscf) 

5.2.16 Minor Sources

To prepare a “complete” inventory of OCS oil and natural gas platforms and other sources in 

the GOM, BOEM requested that operators compiling the GOADS-2011 activity data files also 

identify minor sources, such as caissons, wellhead protectors, and living quarters, and provide 

information for the Structure and Complex ID, Area, Block, Lease No., and locational 

coordinates, so that BOEM can assign surrogate emission estimates for these sources. In this 

way, platform operators do not need to expend resources providing detailed information needed 

to develop emission estimates, yet with BOEM-supplied surrogates these sources can still be 

included in the inventory. GOADS-2011 records were submitted for 1,366 minor sources. For 

caissons and wellhead protectors, these estimates were developed based on average emissions 

from a single gas well plus average emissions from a single oil well. For minor sources that 

operators flagged as “Other,” the estimates are also based on the same surrogates as the caissons 

and wellhead protectors, as most were commented to be “fugitive sources only.” Emissions for 

living quarters were determined to be too minor to include in the inventory. If a platform was 

flagged as a minor source, and equipment records were not populated, the Technical Information 

Management System (TIMS) database was reviewed to confirm the platform type. If TIMS also 

identified the platform as a minor source, the surrogate emission estimates were used. Otherwise,

emissions were calculated using the activity data provided. Emissions were estimated based on 

populated equipment records for 6 caissons, 1 wellhead protector, and 32 minor sources flagged 

as “Other.”

59
The following surrogate emission estimates were assigned: 

Caissons and wellhead protectors: VOC: 0.141 tons/yr, CH4: 0.425 tons/yr

Other minor sources: VOC: 7.034 tons/yr, CH4: 2.536 tons/yr

5.2.17 PM Augmentation

The PM emission factors presented in this section are specifically for PM10 filterable (PM10-

FIL) and PM2.5 filterable (PM2.5-FIL). In order to incorporate the data into the USEPA National 

Emissions Inventory (NEI), emission estimates for three additional PM species must be included: 

PM condensable (PM-CON), PM10 primary (PM10-PRI), and PM2.5 primary (PM2.5-PRI). The 

relationships between these PM species are:

PM10-PRI = PM10-FIL + PM-CON; and 

PM2.5-PRI = PM2.5-FIL + PM-CON. 

Thus, PM10-PRI is always greater than or equal to PM10-FIL, and PM2.5-PRI is always greater 

than or equal to PM2.5-FIL. In addition, PM10-PRI is always equal to or greater than PM2.5-PRI. 

Emission estimates for the additional PM species were generated using the USEPA PMCalculator to apply ratios between PM10-FIL and PM-CON (USEPA 2003). Adjustments were 

made to the PM-CON emission estimates for natural gas combustion. According to information 

published by the USEPA (2005), the AP-42 emission factors (used in PM-Calculator) for 

condensable emissions from natural gas combustion are too high. 

The following example calculations illustrate how PM10-PRI, PM-CON, and PM2.5-PRI were 

estimated based on the PM10-FIL estimate for a combustion source:

EPM-CON = EPM10-FIL × adj factorPM-CON

EPM10-PRI = EPM-CON + EPM10-FIL

EPM2.5-PRI = EPM-CON + EPM2.5-FIL

where:

EPM-CON = PM-condensable emissions (tons/yr)

EPM10-FIL = PM10-filterable emissions (tons/yr)

adj factorPM-CON = PM multiplier to calculate

PM-CON from PM10-filterable

EPM10-PRI = PM10-primary emissions (tons/yr)

EPM2.5-FIL = PM2.5-filterable emissions (tons/yr)

EPM2.5-PRI = PM2.5-primary emissions (tons/yr)

60
For a given month, augmented PM emissions from a diesel engine are therefore calculated 

as:

EPM-CON = 2.468 tons (PM10-FIL) × 0.0232 (adj factorPM-CON) 

= 0.057 tons 

EPM10-PRI = 0.057 tons (PM-CON) + 2.468 tons (PM10-FIL) 

= 2.525 tons 

EPM2.5-PRI = 0.057 tons (PM-CON) + 2.425 tons (PM2.5-FIL) 

= 2.482 tons 

61

6. DEVELOPMENT OF THE NON-PLATFORM EMISSIONS 

INVENTORY

Emission estimates were developed for criteria air pollutants and greenhouse gases for nonplatform OCS sources operating in federal waters of the central and western areas of the GOM

(i.e., east of latitude 87.5°) for the 2011 calendar year. The non-platform sources included in this 

study are noted below.

Non-platform oil/gas production sources:

• Drilling rigs

• Pipelaying operations

• Support helicopters

• Support vessels

• Survey vessels

Non-platform non-oil/gas production sources:

• Biogenic and geogenic sources

• Commercial fishing vessels

• Commercial marine vessels (including lightering services)

• Louisiana Offshore Oil Platform (LOOP)

• Military vessels (Coast Guard/Navy)

• Recreational vessels

BOEM developed the Gulfwide non-platform emission estimates primarily based on work 

previously performed in the Year 2008 Gulfwide Emission Inventory Study (Wilson et al. 2010). 

The 2011 inventory is based on updated activity data to accurately represent operations in the 

GOM. Drilling rig data for 2011 were obtained from BOEM and matched to vessel 

characteristics data in RigZone. Propulsion operations for self-propelled drill ships and 

semisubmersibles were accurately estimated in the 2011 inventory for individual rigs based on 

the departure and arrival times reported by BOEM. Similarly, BOEM pipelaying data for 2011 

were downloaded and used in this inventory. The National Oceanic & Atmospheric 

Administration (NOAA) National Marine Fisheries Service (NMFS) provided new data sets of 

fishing activities.

Some source categories did not have activity data for 2011 such as biogenic and geogenic 

sources, the LOOP, and military vessels. A literature survey was implemented to identify new 

biogenic and geogenic emission source studies that could be used to enhance the 2011 estimates, 

63
but no recent or appropriate data were identified that would improve the accuracy of the 

emission estimates. BOEM did release a study of seabed anomalies in the central and western 

areas of the Gulf that provided insight into the locations of geogenic vents and seeps (USDOI, 

BOEM 2012). Though the data could not indicate when the seeps occurred it did note locations 

where seeps tended not to occur; this information was used to spatially apportion emissions away 

from blocks which did not show a history of emissions and consolidated geogenic emission 

estimates to locations where there is evidence that they occurred at one time. 

The LOOP was contacted repeatedly for data on vessels that visit the offshore platform, but 

no data were provided that could improve the accuracy of previous estimates. A study was found 

that documented a decline of 30% in LOOP total crude imports from 2008, when the platform 

was operating at full capacity, to 2011 (Fielden 2012). Most of this decline is attributed to an 

increase in domestic production that has reduced the demand for imported oil. The 2008 LOOP 

activity and emissions data were reduced by 30% to more accurately represent 2011 emissions. 

A patrol vessel was added to the LOOP recently to address security concerns, but details 

concerning the patrol vessel were not publically available, therefore emissions from this vessel 

could not be included in the 2011 inventory.

The U.S. Coast Guard was contacted to determine if any new patrol boats or cutters had been

added to their Gulf fleet or if any older vessels had been retired; there were no changes reported 

in their fleet composition for 2011. Similarly, military port closures were evaluated to determine 

if the Gulf U.S. naval fleet emission estimates should be updated to reflect changes in base 

operations. The Ingleside Naval base was officially closed in 2010; this base supported the Navy 

mine counter measures fleet. The original GOM fleet information provided by the Navy was 

adjusted to remove the anti-mine vessels (MCM and MSO) from the dataset.

The Federal Aviation Administration (FAA) was contacted several times to obtain updated 

2011 helicopter data, but no new data were provided. Data from the Helicopter Safety Advisory 

Conference survey for 2011 were used in conjunction with more detailed emission factors that 

allowed for better differentiation between medium and heavy duty twin engine helicopters.

The biggest change to the 2011 Gulfwide inventory was the use of Automatic Identification 

System (AIS) data. AIS tracks vessel movements along shipping lanes within range of Very 

High Frequency (VHF) transmitting stations. The vessel transmitters send a signal every two 

seconds that documents: vessel identification codes, radio call signs, location, direction, speed, 

and final destination. Portvision was commissioned to compile these data for this inventory. 

These data were used to develop vessel traffic contours for each vessel type (e.g., tanker, 

containership, support vessel) that was used to spatially allocation emissions. The AIS data were 

compared with the U.S. Army Corps of Engineers Entrance and Clearance data for Gulf ports to 

assess the completeness of the commercial marine vessel fleet included in the AIS dataset. The 

two datasets were comparable, but the entrance and clearance data seems to be slight more 

complete as it included smaller vessel that didn’t trigger the AIS reporting requirements. The 

Entrance and Clearance data were used to quantify hours of operation by mapping the length of 

the route in federal waters between the ports the vessels visited, divided by their reported 

cruising speed. Hours of operation were applied to the vessels power rating to get kilowatt hours.

64
Recreational vessels involved in non-commercial fishing are a new source category for the 

2011 Gulfwide inventory. Emissions for these boats was estimated by applying USEPA 

recreational marine emission factors to typical vessel power ratings and total hours of operation 

in Federal waters.

Emissions were calculated for all diesel powered vessels by applying kilowatt hours to the 

USEPA’s latest commercial vessel emission factors for the year 2011 for all vessel propulsion 

engine categories (1, 2, and 3). 

6.1 NON-PLATFORM OIL/GAS PRODUCTION RELATED SOURCES

Emission sources included in this group are preliminary drilling operations (exclusive of 

drilling associated with a platform); construction, removal or maintenance of pipelines; 

helicopters and vessels that provide supplies, equipment, and personnel for platforms; and survey 

vessels that are used to identify oil finds.

6.1.1 Marine Diesel Emission Factors

With the exception of recreational fishing and helicopters, the same set of emission factors 

were used for all marine diesel engines, whether they were for drilling rigs, pipeline 

construction, support or survey vessels, fishing boats, commercial marine vessels, or military 

vessels. These emission factors were obtained from the USEPA (USEPA 2010). The USEPA 

emission factors varied by year because the data took into account changes in the regulations, 

changes in the marine fuels, and changes in the marine fleet due to the addition of new vessels 

and the retirement of older vessels. Emission factors that were representative of 2011 were used 

in this study. It should be noted that the emission factors used in previous BOEM Gulfwide 

inventories used factors that were specific for the modes of operation. In general, most vessels in 

the Gulf operate in underway mode. At-sea maneuvering occurs when vessels are adjacent to the 

platforms; using the USEPA factors at-sea maneuvering was estimated by adjusting the load 

factor as noted in the equation below.

The USEPA emission factors varied depending upon the engine that the vessel uses for 

propulsion and fall into two groups Category 1 and 2 vessels and Category 3 vessels. These two 

groups have different emission standards that go into effect at different times. Most offshore oil 

and gas vessels are equipped with Category 1 and 2 engines which range in size from something 

equivalent to a bulldozer up to a locomotive. Commercial marine vessels tend to be equipped 

with large Category 3 engines that are similar to large utility diesel engines. For the purpose of 

this study it was assumed that marine distillate was used for the Category 1 and 2 vessels. The 

sulfur content for the Category 1 fuel was assumed to be 236 ppm and the 312 ppm for the 

Category 2 fuel. For Category 3 vessels, the USEPA data weighted their emission for ultra low 

sulfur distillate (100 ppm), low sulfur distillate (1000 ppm), and high sulfur residual 

(27,000 ppm). Commercial fishing vessels were assumed to all be Category 1. Vessels involved 

in lightering activities were assumed to be Category 3. LOOP tankers were also considered to be 

Category 3 vessels, while LOOP support vessels were Category 1 and LOOP generators and 

pumps were Category 2. Pipelying vessels, survey vessels, and tug boats were Category 2. 

Support vessels other than LOOP were a combination of Category 1 and Category 2. The Coast 

Guard buoy tenders and cutters were Category 3 and the patrol boats were Category 2.

65
Recreational fishing emission factors were pulled from the USEPA’s nonroad model for 

diesel inboard and discussed in more detail in recreational fishing section. Helicopter emission 

factors were compiled from the Swiss Federal Office of Civil Aviation (FOCA) and are also 

discussed in more detail in the helicopter section.

Vessel-specific assumptions about mode of operation, fuel type, and engine speed are 

noted in each section. The USEPA emission factors used for this study are presented in 

Table 6-1. The table also shows the load factors used in this study.

Diesel marine engine emissions were calculated for all vessel categories using the following 

equation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) (hours)

kW = Average vessel kW (totaling individual propulsion engines) (kW)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

6.1.2 Drilling Rigs

Drilling vessels are 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 barges, jack-ups, semisubmersibles, submersibles, and drill ships. Application of the 

appropriate drilling rig varies relative to the water depth where they operate. For example, barges 

tend to operate closer to shore and in inland waterways, jack-ups are able to work in water up to 

375 feet deep, semisubmersibles and submersibles operate in water with depths of 300 to 2,000 

feet, and drill ships operate in waters with depths greater than 2,000 feet.

66
Table 6-1. Marine vessel emission factors

Vessel Type Mode Load 

Factor

EF (g/kW-hr)

VOC HC CO NOx PM10 PM2.5 SO2 CO2 CH4 N2O

Commercial Fishing Vessels

Longline, Reef, and 

Shrimp Fishing 

Vessels

At Sea 0.80 0.39 0.37 2.15 12.35 0.44 0.42 0.15 1044.40 0.006 0.031

Maneuvering 0.10 0.39 0.37 2.15 12.35 0.44 0.42 0.15 1044.40 0.008 0.031

Recreational Fishing Vessels

Recreational Fishing 

Vessels

At Sea 0.80 0.59 0.56 2.01 9.30 0.35 0.34 0.22 726.90 a a

Maneuvering 0.30 0.59 0.56 2.01 9.30 0.35 0.34 0.22 726.90 a a

Vessel Lightering

Oil Tankers Maneuvering 0.10 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.012 0.031

Escort Vessels Maneuvering 0.10 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.008 0.031

At Sea 0.80 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

LOOP

Tankers

At Sea 0.55 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Maneuvering 0.10 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.012 0.031

Support Vessels Maneuvering 0.25 0.39 0.37 2.15 12.35 0.44 0.42 0.15 1044.40 0.008 0.031

LOOP Generator At Sea 0.50 0.22 0.21 3.64 16.25 0.60 0.58 0.20 1044.83 0.006 0.031

LOOP Pumps At Sea 0.10 0.22 0.21 3.64 16.25 0.60 0.58 0.20 1044.83 0.006 0.031

Pipelaying Operations

Pipelaying Vessels Maneuvering 0.75 0.22 0.21 3.64 16.25 0.60 0.58 0.20 1044.83 0.008 0.031

Drilling Rigs

Drill Ship, Jack-up, 

Semisubmersible, 

Submersible, and 

Emergency

Equipmenta

At Sea

0.75 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Drill Ship Propulsion 

(maintain position) Maneuvering 0.15 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

67
Vessel Type Mode Load 

Factor

EF (g/kW-hr)

VOC HC CO NOx PM10 PM2.5 SO2 CO2 CH4 N2O

Semisubmersible 

Propulsion (maintain 

position)

Maneuvering

0.15 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Drilling Propulsion 

(relocation) At Sea 0.75 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Semisubmersible 

Propulsion (relocation) At Sea

0.75 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Survey Vessels

Survey Vessels At Sea 0.90 0.22 0.21 3.64 16.25 0.60 0.58 0.20 1044.83 0.006 0.031

Support Vessels

Supply/crew, Lift, and 

Tugs/towing Vessels

At Sea 0.85 0.32 0.31 2.86 14.08 0.52 0.50 0.17 1043.11 0.006 0.031

Maneuvering 0.10 0.32 0.31 2.86 14.08 0.52 0.50 0.17 1043.11 0.008 0.031

Coast Guard Vessels

Buoy Tenders and 

Cutters At Sea 0.85 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Patrol Vessels At Sea 0.85 0.22 0.21 3.64 16.25 0.60 0.58 0.20 1044.83 0.006 0.031

Commercial Marine Vessels

All Except Tug Boats At Sea 0.80 0.78 0.74 1.77 19.54 0.74 0.68 5.90 776.81 0.006 0.031

Tug Boats At Sea 0.80 0.22 0.21 3.64 16.25 0.60 0.58 0.20 1044.83 0.006 0.031 a Emergency generators are assumed to operate 500 hours per year based on USEPA guidance.

68
The Operation and Analysis Branch of the Engineering and Operations Division of BOEM 

provided 2011 activity data for drilling rigs by block, which included activity for drill ships, 

jack-ups, platform rigs, semisubmersibles, and submersibles (Mathews 2012). The drilling rig 

activity data used in this study are based on the specific blocks where drilling activities took 

place, the drilling rig name, and the time drilling commenced and concluded. These data were 

extracted for the period from January 2011 through December 2011, as noted in Table 6-2.

Table 6-2. Drilling vessel activity data

Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

PF GB 426 AUGER 1/1/2011 1/13/2011 12

PF GB 426 AUGER 4/20/2011 4/28/2011 8

PF GB 426 AUGER 7/16/2011 8/9/2011 24

PF GB 426 AUGER 12/4/2011 12/30/2011 26

PF ST 316 BLAKE 1006 8/10/2011 9/27/2011 48

PF ST 316 BLAKE 1006 9/27/2011 12/31/2011 95

PF GC 608 BLAKE 1007 12/26/2011 12/31/2011 5

PF EI 175 BLAKE 14 1/1/2011 1/29/2011 28

PF EI 189 BLAKE 14 1/29/2011 3/20/2011 50

PF EI 189 BLAKE 14 3/20/2011 4/9/2011 20

PF MP 296 BLAKE 14 4/10/2011 4/16/2011 6

PF MP 296 BLAKE 14 4/16/2011 4/21/2011 5

PF SP 62 BLAKE 14 4/22/2011 5/12/2011 20

PF SP 62 BLAKE 14 5/12/2011 6/8/2011 27

PF SP 62 BLAKE 14 6/8/2011 6/17/2011 9

PF SP 62 BLAKE 14 6/17/2011 7/16/2011 29

PF SP 62 BLAKE 14 7/16/2011 8/13/2011 28

PF SP 70 BLAKE 14 8/14/2011 8/21/2011 7

PF SP 70 BLAKE 14 8/21/2011 8/31/2011 10

PF SP 70 BLAKE 14 8/31/2011 9/16/2011 16

PF WD 71 BLAKE 14 9/23/2011 10/30/2011 37

PF VR 265 BLAKE 14 10/31/2011 12/10/2011 40

PF EC 270 BLAKE 14 12/11/2011 12/31/2011 20

PF MP 308 BLAKE 1505 9/29/2011 12/31/2011 93

PF SS 216 BLAKE 210 1/1/2011 1/13/2011 12

PF EC 278 BLAKE 210 5/10/2011 5/31/2011 21

PF EC 278 BLAKE 210 5/31/2011 7/18/2011 48

PF MP 153 BLAKE 210 7/20/2011 9/6/2011 48

PF ST 206 BLAKE 210 9/14/2011 10/13/2011 29

PF ST 295 BLAKE 210 10/13/2011 12/31/2011 79

SD GC 178 CAL DIVE Q-4000 1/1/2011 1/9/2011 8

SD EW 949 CAL DIVE Q-4000 1/9/2011 1/27/2011 18

SD EW 977 CAL DIVE Q-4000 1/27/2011 2/13/2011 17

SD GC 244 CAL DIVE Q-4000 2/13/2011 2/13/2011 0

SD GC 244 CAL DIVE Q-4000 2/13/2011 3/16/2011 31

SD GC 200 CAL DIVE Q-4000 3/16/2011 3/16/2011 0

69
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

SD GC 200 CAL DIVE Q-4000 3/16/2011 3/25/2011 9

SD GC 200 CAL DIVE Q-4000 3/25/2011 4/13/2011 19

SD GC 200 CAL DIVE Q-4000 4/13/2011 4/19/2011 6

SD GC 200 CAL DIVE Q-4000 4/19/2011 4/24/2011 5

SD GB 516 CAL DIVE Q-4000 5/1/2011 5/16/2011 15

SD GB 516 CAL DIVE Q-4000 5/16/2011 5/25/2011 9

SD GB 516 CAL DIVE Q-4000 5/25/2011 5/27/2011 2

SD GB 516 CAL DIVE Q-4000 5/27/2011 5/30/2011 3

SD GB 516 CAL DIVE Q-4000 5/30/2011 6/1/2011 2

SD GB 516 CAL DIVE Q-4000 6/1/2011 6/3/2011 2

SD GB 385 CAL DIVE Q-4000 6/3/2011 6/12/2011 9

SD MC 809 CAL DIVE Q-4000 6/13/2011 6/26/2011 13

SD MC 810 CAL DIVE Q-4000 6/26/2011 7/7/2011 11

SD GB 385 CAL DIVE Q-4000 7/9/2011 7/14/2011 5

SD MC 66 CAL DIVE Q-4000 7/16/2011 8/3/2011 18

SD EB 646 CAL DIVE Q-4000 8/5/2011 8/13/2011 8

SD EB 646 CAL DIVE Q-4000 8/15/2011 9/8/2011 24

SD EB 642 CAL DIVE Q-4000 9/9/2011 9/24/2011 15

SD EB 558 CAL DIVE Q-4000 9/24/2011 10/16/2011 22

SD GB 877 CAL DIVE Q-4000 10/17/2011 11/6/2011 20

SD GC 379 CAL DIVE Q-4000 11/7/2011 11/11/2011 4

SD GC 518 CAL DIVE Q-4000 11/11/2011 12/24/2011 43

SD VK 826 CAL DIVE Q-4000 12/22/2011 12/30/2011 8

SD MC 810 CAL DIVE Q-4000 12/26/2011 12/31/2011 5

SS EI 339 CAL DIVE UNCLE JOHN 1/1/2011 1/10/2011 9

SS EC 272 CAL DIVE UNCLE JOHN 3/24/2011 3/24/2011 0

SS EI 339 CAL DIVE UNCLE JOHN 4/8/2011 4/19/2011 11

SS EI 339 CAL DIVE UNCLE JOHN 4/20/2011 7/1/2011 72

SS EC 272 CAL DIVE UNCLE JOHN 7/15/2011 9/6/2011 53

SS EC 272 CAL DIVE UNCLE JOHN 9/26/2011 10/28/2011 32

BR SM 212 COASTAL RIG 22 1/1/2011 1/14/2011 13

BR SM 217 COASTAL RIG 22 1/16/2011 7/23/2011 188

SS GC 299 DIAMOND OCEAN AMERICA 6/20/2011 6/20/2011 0

JU EI 51 DIAMOND OCEAN COLUMBIA 9/30/2011 12/31/2011 92

SS GB 515 DIAMOND OCEAN MONARCH 5/7/2011 9/1/2011 117

SS MC 20 DIAMOND OCEAN 

SARATOGA 1/1/2011 1/24/2011 23

SS MC 20 DIAMOND OCEAN 

SARATOGA 1/24/2011 1/25/2011 1

SS MC 20 DIAMOND OCEAN 

SARATOGA 1/25/2011 3/24/2011 58

SS VK 821 DIAMOND OCEAN 

SARATOGA 5/11/2011 6/2/2011 22

SS GB 302 DIAMOND OCEAN 

SARATOGA 6/5/2011 6/26/2011 21

70
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

SS GC 50 DIAMOND OCEAN 

SARATOGA 6/28/2011 7/31/2011 33

SS VK 821 DIAMOND OCEAN 

SARATOGA 11/14/2011 12/31/2011 47

JU SS 290 DIAMOND OCEAN TITAN 1/1/2011 1/11/2011 10

JU SM 73 DIAMOND OCEAN TITAN 1/11/2011 2/13/2011 33

JU SM 73 DIAMOND OCEAN TITAN 2/13/2011 3/19/2011 34

JU SS 229 DIAMOND OCEAN TITAN 3/19/2011 4/23/2011 35

JU SS 290 DIAMOND OCEAN TITAN 5/2/2011 6/15/2011 44

JU ST 264 DIAMOND OCEAN TITAN 7/22/2011 9/1/2011 41

SS EW 948 DIAMOND OCEAN VICTORY 3/5/2011 3/22/2011 17

SS GC 282 DIAMOND OCEAN VICTORY 4/14/2011 5/24/2011 40

SS MC 711 DIAMOND OCEAN VICTORY 5/26/2011 6/21/2011 26

SS GC 299 DIAMOND OCEAN VICTORY 6/21/2011 12/19/2011 181

SS EW 834 DIAMOND OCEAN VICTORY 12/19/2011 12/31/2011 12

BR EC 281 DIVE SUPPORT VESSEL (DSV) 3/16/2011 3/31/2011 15

BR WC 606 DIVE SUPPORT VESSEL (DSV) 9/12/2011 9/22/2011 10

JU MP 298 ENSCO 68 1/1/2011 1/1/2011 0

JU MP 298 ENSCO 68 1/1/2011 1/31/2011 30

JU MP 298 ENSCO 68 1/31/2011 2/12/2011 12

JU MP 298 ENSCO 68 2/12/2011 2/20/2011 8

JU MP 313 ENSCO 68 2/20/2011 3/2/2011 10

JU MP 313 ENSCO 68 3/2/2011 4/24/2011 53

JU MP 313 ENSCO 68 4/24/2011 5/14/2011 20

JU MP 313 ENSCO 68 5/14/2011 5/31/2011 17

JU MP 313 ENSCO 68 5/31/2011 7/12/2011 42

JU MP 313 ENSCO 68 7/12/2011 7/30/2011 18

JU MP 144 ENSCO 68 7/30/2011 8/18/2011 19

JU MP 144 ENSCO 68 9/11/2011 10/9/2011 28

JU MP 144 ENSCO 68 10/9/2011 10/17/2011 8

JU MP 144 ENSCO 68 10/17/2011 12/31/2011 75

JU EI 330 ENSCO 75 1/1/2011 1/2/2011 1

JU EI 330 ENSCO 75 1/2/2011 1/16/2011 14

JU EI 330 ENSCO 75 1/16/2011 2/2/2011 17

JU EI 330 ENSCO 75 2/2/2011 2/13/2011 11

JU EI 330 ENSCO 75 2/15/2011 3/11/2011 24

JU EI 330 ENSCO 75 3/11/2011 3/31/2011 20

JU EI 330 ENSCO 75 3/31/2011 4/10/2011 10

JU EI 330 ENSCO 75 4/10/2011 4/11/2011 1

JU EI 330 ENSCO 75 4/11/2011 4/22/2011 11

JU EI 330 ENSCO 75 4/22/2011 4/29/2011 7

JU EI 330 ENSCO 75 4/29/2011 6/8/2011 40

JU EI 330 ENSCO 75 7/1/2011 7/9/2011 8

JU EI 330 ENSCO 75 7/14/2011 9/25/2011 73

71
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

JU EI 330 ENSCO 75 9/25/2011 10/16/2011 21

JU EI 330 ENSCO 75 10/16/2011 11/3/2011 18

JU EI 330 ENSCO 75 11/3/2011 11/4/2011 1

JU EI 330 ENSCO 75 11/4/2011 12/31/2011 57

JU HI A 547 ENSCO 81 3/2/2011 3/23/2011 21

JU WD 106 ENSCO 81 3/28/2011 5/7/2011 40

JU WD 106 ENSCO 81 5/7/2011 6/14/2011 38

JU WD 106 ENSCO 81 6/14/2011 7/22/2011 38

JU WD 106 ENSCO 81 7/22/2011 8/2/2011 11

JU ST 265 ENSCO 81 9/14/2011 11/12/2011 59

JU ST 265 ENSCO 81 11/21/2011 12/31/2011 40

JU SM 99 ENSCO 82 1/1/2011 2/20/2011 50

JU SM 99 ENSCO 82 2/20/2011 4/3/2011 42

JU SM 90 ENSCO 82 4/3/2011 4/26/2011 23

JU EI 276 ENSCO 82 4/27/2011 5/7/2011 10

JU EI 276 ENSCO 82 5/7/2011 5/9/2011 2

JU EI 276 ENSCO 82 5/10/2011 5/11/2011 1

JU EI 276 ENSCO 82 5/12/2011 5/13/2011 1

JU EI 276 ENSCO 82 5/14/2011 6/6/2011 23

JU EI 276 ENSCO 82 6/6/2011 6/15/2011 9

JU EI 276 ENSCO 82 6/15/2011 7/25/2011 40

JU EI 276 ENSCO 82 7/25/2011 8/5/2011 11

JU EI 276 ENSCO 82 8/5/2011 8/21/2011 16

JU EI 276 ENSCO 82 8/21/2011 9/29/2011 39

JU EI 276 ENSCO 82 10/3/2011 10/15/2011 12

JU EI 276 ENSCO 82 10/15/2011 11/11/2011 27

JU VR 214 ENSCO 82 11/12/2011 12/31/2011 49

SD GC 518 ENSCO 8500 1/1/2011 1/14/2011 13

SD GC 683 ENSCO 8500 1/15/2011 3/23/2011 67

SD KC 875 ENSCO 8500 3/23/2011 6/3/2011 72

SD DC 620 ENSCO 8500 6/6/2011 7/25/2011 49

SD GC 517 ENSCO 8500 7/29/2011 8/12/2011 14

SD EB 602 ENSCO 8500 8/19/2011 12/11/2011 114

SD EB 602 ENSCO 8500 12/11/2011 12/31/2011 20

SD MC 519 ENSCO 8501 3/29/2011 7/26/2011 119

SD GC 723 ENSCO 8501 7/28/2011 11/24/2011 119

SD MC 948 ENSCO 8501 11/26/2011 12/31/2011 35

SD EB 579 ENSCO 8502 1/1/2011 1/26/2011 25

SD GC 504 ENSCO 8502 6/22/2011 12/31/2011 192

SD GC 814 ENSCO 8503 12/26/2011 12/31/2011 5

JU MI 623 ENSCO 86 1/14/2011 3/18/2011 63

JU MI 623 ENSCO 86 3/18/2011 5/17/2011 60

JU MI 623 ENSCO 86 5/17/2011 6/10/2011 24

JU WC 311 ENSCO 86 6/19/2011 7/2/2011 13

72
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

JU SM 281 ENSCO 86 7/2/2011 10/19/2011 109

JU SS 126 ENSCO 86 10/21/2011 11/13/2011 23

JU MO 830 ENSCO 86 11/18/2011 12/31/2011 43

JU WD 71 ENSCO 87 1/1/2011 2/19/2011 49

JU WD 70 ENSCO 87 2/19/2011 3/7/2011 16

JU WD 122 ENSCO 87 3/10/2011 4/23/2011 44

JU MP 315 ENSCO 87 5/14/2011 7/11/2011 58

JU SM 66 ENSCO 87 7/14/2011 10/11/2011 89

JU SS 189 ENSCO 87 10/12/2011 12/31/2011 80

JU SS 219 ENSCO 90 1/27/2011 2/13/2011 17

JU VR 267 ENSCO 90 2/14/2011 2/22/2011 8

JU VR 267 ENSCO 90 2/22/2011 3/30/2011 36

JU EI 208 ENSCO 90 3/31/2011 4/29/2011 29

JU EI 208 ENSCO 90 4/29/2011 5/16/2011 17

JU PL 25 ENSCO 90 5/16/2011 7/9/2011 54

JU MI 668 ENSCO 90 7/13/2011 9/15/2011 64

JU MI 668 ENSCO 90 9/15/2011 10/1/2011 16

JU MI 669 ENSCO 90 10/1/2011 12/31/2011 91

JU SS 93 ENSCO 99 1/1/2011 1/31/2011 30

JU GA 209 ENSCO 99 4/1/2011 4/29/2011 28

JU GA 209 ENSCO 99 4/29/2011 5/15/2011 16

JU WD 29 ENSCO 99 6/3/2011 6/24/2011 21

JU WD 29 ENSCO 99 6/24/2011 7/13/2011 19

JU WD 29 ENSCO 99 7/13/2011 7/22/2011 9

JU WD 29 ENSCO 99 7/22/2011 8/8/2011 17

JU GI 22 ENSCO 99 10/6/2011 11/26/2011 51

JU GI 23 ENSCO 99 11/26/2011 12/18/2011 22

JU GI 23 ENSCO 99 12/18/2011 12/22/2011 4

DS GC 654 GSF C.R. LUIGS 1/1/2011 3/12/2011 70

DS GC 653 GSF C.R. LUIGS 3/12/2011 5/26/2011 75

DS GC 653 GSF C.R. LUIGS 6/1/2011 10/1/2011 122

DS GC 654 GSF C.R. LUIGS 10/1/2011 12/31/2011 91

PF SP 87 H&P 105 1/1/2011 3/14/2011 72

PF SP 87 H&P 105 3/14/2011 5/11/2011 58

PF SP 87 H&P 105 5/11/2011 5/29/2011 18

PF GI 116 H&P 105 7/12/2011 12/31/2011 172

PF SS 349 H&P 107 8/12/2011 11/13/2011 93

PF SS 349 H&P 107 11/13/2011 12/31/2011 48

PF MC 807 H&P 201 1/1/2011 10/10/2011 282

PF MC 807 H&P 201 10/11/2011 12/2/2011 52

PF MC 807 H&P 201 12/2/2011 12/31/2011 29

PF GC 158 H&P 202 6/24/2011 10/5/2011 103

PF GC 158 H&P 202 10/6/2011 10/31/2011 25

PF GC 158 H&P 202 11/28/2011 12/31/2011 33

73
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

PF GC 158 H&P 202 11/28/2011 12/31/2011 33

PF MC 809 H&P 204 1/1/2011 2/13/2011 43

PF MC 809 H&P 204 2/13/2011 7/6/2011 143

PF AC 857 H&P 205 1/1/2011 2/20/2011 50

PF AC 857 H&P 205 2/24/2011 4/15/2011 50

PF AC 857 H&P 205 4/16/2011 8/27/2011 133

PF AC 857 H&P 205 8/28/2011 9/10/2011 13

PF AC 857 H&P 205 10/8/2011 12/31/2011 84

PF MC 109 H&P 206 1/1/2011 2/24/2011 54

PF MC 109 H&P 206 2/24/2011 5/1/2011 66

PF MC 109 H&P 206 5/1/2011 7/20/2011 80

PF MC 109 H&P 206 7/20/2011 11/22/2011 125

JU ST 35 HERCULES 120 1/1/2011 1/9/2011 8

JU ST 35 HERCULES 120 1/9/2011 2/11/2011 33

JU ST 37 HERCULES 120 2/11/2011 2/24/2011 13

JU ST 37 HERCULES 120 7/13/2011 9/15/2011 64

JU MP 41 HERCULES 120 9/16/2011 11/30/2011 75

JU MP 41 HERCULES 120 11/30/2011 12/31/2011 31

JU VR 39 HERCULES 150 2/7/2011 4/13/2011 65

JU EI 28 HERCULES 150 8/19/2011 9/11/2011 23

JU BM 2 HERCULES 173 3/30/2011 4/20/2011 21

JU GI 37 HERCULES 173 8/4/2011 9/26/2011 53

JU ST 23 HERCULES 173 10/22/2011 11/15/2011 24

JU BM 2 HERCULES 173 12/8/2011 12/31/2011 23

JU BM 2 HERCULES 173 12/29/2011 12/29/2011 0

JU HI 116 HERCULES 200 1/1/2011 1/22/2011 21

JU EC 265 HERCULES 200 1/22/2011 2/17/2011 26

JU SM 76 HERCULES 200 2/17/2011 4/12/2011 54

JU HI 129 HERCULES 200 5/27/2011 6/3/2011 7

JU WC 35 HERCULES 200 6/4/2011 7/4/2011 30

JU WC 165 HERCULES 200 7/4/2011 7/29/2011 25

JU HI 46 HERCULES 200 7/31/2011 9/24/2011 55

JU HI A 155 HERCULES 200 9/24/2011 10/13/2011 19

JU WC 110 HERCULES 200 10/21/2011 12/30/2011 70

JU EI 243 HERCULES 201 2/24/2011 3/11/2011 15

JU BS 55 HERCULES 201 3/14/2011 4/28/2011 45

JU MP 42 HERCULES 201 5/16/2011 6/4/2011 19

JU ST 52 HERCULES 201 7/23/2011 8/23/2011 31

JU ST 52 HERCULES 201 8/23/2011 9/1/2011 9

JU ST 52 HERCULES 201 9/2/2011 9/9/2011 7

JU ST 52 HERCULES 201 9/9/2011 10/5/2011 26

JU MP 98 HERCULES 202 1/1/2011 3/20/2011 78

JU MP 108 HERCULES 202 3/20/2011 5/13/2011 54

JU MP 108 HERCULES 202 5/13/2011 7/21/2011 69

74
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

JU MP 108 HERCULES 202 7/21/2011 9/25/2011 66

JU SS 218 HERCULES 202 10/31/2011 11/25/2011 25

JU SS 218 HERCULES 202 11/25/2011 12/31/2011 36

JU WD 68 HERCULES 204 1/1/2011 1/12/2011 11

JU EI 113B HERCULES 204 3/29/2011 4/29/2011 31

JU SS 151 HERCULES 204 5/4/2011 7/15/2011 72

JU SS 227 HERCULES 204 7/15/2011 9/26/2011 73

JU SS 119 HERCULES 204 9/26/2011 9/26/2011 0

JU SS 209 HERCULES 204 12/1/2011 12/31/2011 30

JU MU 831 HERCULES 205 1/1/2011 1/17/2011 16

JU MI 526 HERCULES 205 3/21/2011 4/13/2011 23

JU BA 375 HERCULES 205 4/14/2011 6/8/2011 55

JU HI 37 HERCULES 205 6/9/2011 7/3/2011 24

JU MP 60 HERCULES 205 7/7/2011 12/31/2011 177

JU HI 205 HERCULES 212 9/14/2011 10/31/2011 47

JU EC 160 HERCULES 212 11/24/2011 12/31/2011 37

JU SS 189 HERCULES 213 5/9/2011 8/29/2011 112

JU SS 225 HERCULES 213 10/20/2011 10/20/2011 0

JU SS 225 HERCULES 213 10/20/2011 10/20/2011 0

JU SS 72 HERCULES 213 10/20/2011 11/21/2011 32

JU SS 72 HERCULES 213 11/21/2011 12/12/2011 21

JU SS 72 HERCULES 213 12/12/2011 12/26/2011 14

JU SS 72 HERCULES 213 12/26/2011 12/31/2011 5

JU EI 224 HERCULES 214 5/3/2011 7/15/2011 73

JU MP 59 HERCULES 214 9/19/2011 10/22/2011 33

JU MP 59 HERCULES 214 10/22/2011 12/31/2011 70

JU EI 304 HERCULES 251 1/1/2011 1/14/2011 13

JU HI A 544 HERCULES 251 1/22/2011 2/5/2011 14

JU EI 266 HERCULES 251 2/21/2011 3/18/2011 25

JU WC 132 HERCULES 251 5/3/2011 5/12/2011 9

JU WC 132 HERCULES 251 5/6/2011 5/12/2011 6

JU HI A 171 HERCULES 251 11/4/2011 12/31/2011 57

JU GA 241 HERCULES 253 1/1/2011 2/19/2011 49

JU VR 170 HERCULES 253 2/22/2011 4/18/2011 55

JU VR 342 HERCULES 253 5/6/2011 6/12/2011 37

JU GA A 133 HERCULES 253 6/12/2011 6/26/2011 14

JU WC 171 HERCULES 253 7/15/2011 8/15/2011 31

JU WD 89 HERCULES 253 10/21/2011 11/19/2011 29

JU WD 89 HERCULES 253 11/19/2011 12/13/2011 24

JU WD 89 HERCULES 253 12/13/2011 12/31/2011 18

JU PL 15 HERCULES 263 6/13/2011 6/29/2011 16

JU BA A 133 HERCULES 263 8/9/2011 9/24/2011 46

JU WD 39 HERCULES 263 9/29/2011 10/26/2011 27

JU PL 13 HERCULES 263 10/27/2011 12/28/2011 62

75
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

JU ST 204 HERCULES 263 12/28/2011 12/31/2011 3

JU VR 245 HERCULES 264 1/31/2011 6/16/2011 136

JU WC 18 HERCULES 264 6/16/2011 8/12/2011 57

JU WC 18 HERCULES 264 8/12/2011 11/1/2011 81

JU VR 245 HERCULES 264 11/1/2011 12/31/2011 60

JU ST 161 HERCULES 265 5/30/2011 6/17/2011 18

JU ST 172 HERCULES 265 6/17/2011 6/17/2011 0

JU ST 172 HERCULES 265 6/17/2011 6/17/2011 0

JU ST 172 HERCULES 265 6/17/2011 6/17/2011 0

JU ST 172 HERCULES 265 6/17/2011 6/17/2011 0

JU ST 172 HERCULES 265 6/17/2011 7/5/2011 18

JU GI 82 HERCULES 265 7/7/2011 7/22/2011 15

JU GI 82 HERCULES 265 7/22/2011 7/22/2011 0

JU GI 82 HERCULES 265 7/22/2011 7/27/2011 5

JU ST 41 HERCULES 265 9/10/2011 11/19/2011 70

JU EC 111 HERCULES 265 11/19/2011 12/31/2011 42

JU EC 328 HERCULES 300 5/6/2011 8/6/2011 92

JU EC 328 HERCULES 300 8/6/2011 8/14/2011 8

JU EC 328 HERCULES 300 8/14/2011 8/22/2011 8

JU EC 328 HERCULES 300 8/22/2011 9/8/2011 17

JU EC 328 HERCULES 300 9/8/2011 9/11/2011 3

JU EC 328 HERCULES 300 9/11/2011 9/22/2011 11

JU EC 328 HERCULES 300 9/22/2011 11/21/2011 60

JU EC 328 HERCULES 300 11/21/2011 12/22/2011 31

JU SM 79 HERCULES 300 12/28/2011 12/31/2011 3

JU ST 131 HERCULES 350 1/1/2011 1/3/2011 2

JU ST 128 HERCULES 350 1/3/2011 3/13/2011 69

JU ST 188 HERCULES 350 7/31/2011 10/2/2011 63

JU ST 188 HERCULES 350 10/2/2011 12/17/2011 76

JU ST 134 HERCULES 350 12/17/2011 12/31/2011 14

SD KC 919 MAERSK DEVELOPER 3/22/2011 8/22/2011 153

SD AC 810 MAERSK DEVELOPER 8/22/2011 10/9/2011 48

SD LL 400 MAERSK DEVELOPER 10/14/2011 12/30/2011 77

PF WD 73 NABORS 17 12/21/2011 12/31/2011 10

PF MC 941 NABORS 202 3/18/2011 8/22/2011 157

PF MC 941 NABORS 202 8/22/2011 12/31/2011 131

PF GC 205 NABORS 85 (MAYRONNE 162) 4/2/2011 5/28/2011 56

PF VK 786 NABORS 87 1/1/2011 3/15/2011 73

PF VK 786 NABORS 87 3/15/2011 4/2/2011 18

PF VK 786 NABORS 87 4/2/2011 4/20/2011 18

PF VK 786 NABORS 87 4/2/2011 8/20/2011 140

PF VK 786 NABORS 87 8/20/2011 8/26/2011 6

PF VK 786 NABORS 87 8/26/2011 9/11/2011 16

PF VK 786 NABORS 87 9/11/2011 9/18/2011 7

76
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

PF VK 786 NABORS 87 9/18/2011 9/24/2011 6

PF VK 786 NABORS 87 9/24/2011 12/31/2011 98

JU WC 311 NABORS DOLPHIN 109 5/22/2011 6/23/2011 32

JU WC 132 NABORS DOLPHIN 109 10/21/2011 11/16/2011 26

JU SM 239 NABORS DOLPHIN 109 12/8/2011 12/26/2011 18

JU SP 28 NABORS DT 110 4/5/2011 4/17/2011 12

JU SP 28 NABORS DT 110 4/17/2011 4/23/2011 6

JU SP 28 NABORS DT 110 4/23/2011 4/29/2011 6

JU SP 28 NABORS DT 110 4/29/2011 6/3/2011 35

JU SP 28 NABORS DT 110 6/3/2011 6/12/2011 9

JU SS 72 NABORS DT 110 11/24/2011 12/13/2011 19

JU SS 87 NABORS DT 110 12/13/2011 12/24/2011 11

PF GC 338 NABORS MODS 200 4/7/2011 12/31/2011 268

PF AC 25 NABORS MODS 201 12/15/2011 12/31/2011 16

PF VK 826 NABORS P-10 1/4/2011 2/27/2011 54

PF VK 826 NABORS P-10 2/27/2011 3/15/2011 16

PF VK 826 NABORS P-10 3/15/2011 4/21/2011 37

PF VK 826 NABORS P-10 4/21/2011 4/23/2011 2

PF GI 102 NABORS P-10 6/13/2011 7/18/2011 35

PF GI 102 NABORS P-10 7/18/2011 8/2/2011 15

PF GI 102 NABORS P-10 8/2/2011 8/14/2011 12

PF GI 102 NABORS P-10 8/14/2011 8/27/2011 13

PF GI 102 NABORS P-10 8/27/2011 9/12/2011 16

PF GI 102 NABORS P-10 9/12/2011 9/21/2011 9

PF VR 408 NABORS S.D. IV 1/22/2011 3/15/2011 52

PF VR 408 NABORS S.D. IV 3/15/2011 4/28/2011 44

PF SM 130 NABORS S.D. IV 4/28/2011 7/18/2011 81

PF SM 130 NABORS S.D. IV 7/18/2011 8/14/2011 27

PF SM 130 NABORS S.D. IV 8/14/2011 8/31/2011 17

PF SM 130 NABORS S.D. IV 8/31/2011 10/3/2011 33

PF SM 107 NABORS S.D. IV 10/6/2011 11/18/2011 43

PF SM 107 NABORS S.D. IV 11/19/2011 12/19/2011 30

PF GB 260 NABORS S.D. XVI 12/29/2011 12/31/2011 2

SS MC 503 NOBLE AMOS RUNNER 1/1/2011 1/5/2011 4

SS MC 503 NOBLE AMOS RUNNER 1/5/2011 2/25/2011 51

SS MC 199 NOBLE AMOS RUNNER 2/26/2011 3/21/2011 23

SS MC 199 NOBLE AMOS RUNNER 3/21/2011 4/24/2011 34

SS MC 199 NOBLE AMOS RUNNER 4/24/2011 5/28/2011 34

SS MC 751 NOBLE AMOS RUNNER 5/29/2011 7/30/2011 62

SS GB 462 NOBLE AMOS RUNNER 8/25/2011 10/29/2011 65

SS ST 318 NOBLE AMOS RUNNER 11/2/2011 12/10/2011 38

SS MC 431 NOBLE AMOS RUNNER 12/13/2011 12/25/2011 12

SS MC 431 NOBLE AMOS RUNNER 12/25/2011 12/31/2011 6

SD MC 764 NOBLE DANNY ADKINS 1/1/2011 2/27/2011 57

77
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

SD AC 859 NOBLE DANNY ADKINS 5/10/2011 10/14/2011 157

SD AC 857 NOBLE DANNY ADKINS 10/14/2011 12/31/2011 78

SS MC 935 NOBLE DRILLER 8/3/2011 12/31/2011 150

JU ST 295 NOBLE EDDIE PAUL 10/22/2011 10/22/2011 0

SD MC 762 NOBLE JIM DAY 7/11/2011 8/1/2011 21

SD MC 762 NOBLE JIM DAY 8/1/2011 8/14/2011 13

SD MC 762 NOBLE JIM DAY 8/14/2011 8/25/2011 11

SD MC 762 NOBLE JIM DAY 8/25/2011 9/13/2011 19

SD MC 762 NOBLE JIM DAY 9/13/2011 9/21/2011 8

SD MC 762 NOBLE JIM DAY 9/21/2011 12/31/2011 101

SS GB 427 NOBLE JIM THOMPSON 4/7/2011 11/2/2011 209

SS GC 116 NOBLE JIM THOMPSON 11/3/2011 12/31/2011 58

BR EI 10 PARKER 72-B 5/9/2011 7/18/2011 70

DS WR 206 PRIDE DEEP OCEAN 

MENDOCINO 8/24/2011 11/16/2011 84

DS WR 206 PRIDE DEEP OCEAN 

MENDOCINO 11/30/2011 11/30/2011 0

DS WR 206 PRIDE DEEP OCEAN 

MENDOCINO 12/2/2011 12/20/2011 18

JU SS 72 PRIDE NORTH DAKOTA 11/17/2011 11/17/2011 0

JU SS 259 ROWAN CECIL PROVINE 1/1/2011 2/20/2011 50

JU WD 70 ROWAN CECIL PROVINE 2/20/2011 4/6/2011 45

JU WD 70 ROWAN CECIL PROVINE 4/6/2011 5/11/2011 35

JU WD 70 ROWAN CECIL PROVINE 5/11/2011 6/25/2011 45

JU SS 258 ROWAN CECIL PROVINE 6/29/2011 10/7/2011 100

JU SM 281 ROWAN CECIL PROVINE 10/13/2011 12/28/2011 76

JU GI 48 ROWAN CECIL PROVINE 12/30/2011 12/31/2011 1

JU BA A 23 ROWAN EXL III 2/7/2011 6/25/2011 138

JU GI 23 ROWAN EXL III 6/29/2011 7/14/2011 15

JU GI 23 ROWAN EXL III 7/14/2011 8/4/2011 21

JU GI 22 ROWAN EXL III 8/4/2011 8/28/2011 24

JU GI 22 ROWAN EXL III 8/28/2011 9/25/2011 28

JU GI 22 ROWAN EXL III 9/26/2011 10/10/2011 14

JU MP 296 ROWAN EXL IV 11/3/2011 11/28/2011 25

JU MP 296 ROWAN EXL IV 11/28/2011 12/26/2011 28

JU MP 296 ROWAN EXL IV 12/26/2011 12/31/2011 5

JU HI A 376 ROWAN GORILLA II 1/2/2011 1/9/2011 7

JU HI A 376 ROWAN GORILLA II 1/9/2011 1/10/2011 1

JU HI A 376 ROWAN GORILLA II 1/10/2011 1/20/2011 10

JU HI A 376 ROWAN GORILLA II 1/20/2011 1/31/2011 11

JU HI A 376 ROWAN GORILLA II 1/31/2011 2/13/2011 13

JU HI A 376 ROWAN GORILLA II 2/13/2011 2/20/2011 7

JU HI A 376 ROWAN GORILLA II 2/20/2011 3/10/2011 18

JU HI A 376 ROWAN GORILLA II 3/10/2011 3/16/2011 6

JU EI 302 ROWAN GORILLA II 4/2/2011 4/24/2011 22

78
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

JU EI 391 ROWAN GORILLA II 4/28/2011 5/18/2011 20

JU MP 72 ROWAN GORILLA III 3/20/2011 5/10/2011 51

JU MP 72 ROWAN GORILLA III 5/10/2011 6/15/2011 36

JU MP 72 ROWAN GORILLA III 6/15/2011 7/11/2011 26

JU EI 26 ROWAN LOUISIANA 2/19/2011 11/19/2011 273

JU SM 234 ROWAN MISSISSIPPI 1/1/2011 6/23/2011 173

JU HI A 1 SEAHAWK 2001 2/19/2011 4/14/2011 54

JU SS 90 SEAHAWK 2004 1/1/2011 1/18/2011 17

JU HI 176 SEAHAWK 2007 1/1/2011 2/14/2011 44

JU HI 88 SEAHAWK 2007 2/14/2011 2/21/2011 7

JU EI 224 SEAHAWK 2007 4/2/2011 5/1/2011 29

JU SM 50 SEAHAWK 2600 1/1/2011 4/12/2011 101

JU SM 111 SEAHAWK 2600 4/12/2011 5/4/2011 22

JU VR 245 SEAHAWK 2601 1/1/2011 1/3/2011 2

JU VR 245 SEAHAWK 2601 1/3/2011 1/18/2011 15

JU VR 245 SEAHAWK 2601 1/18/2011 1/31/2011 13

JU MP 122 SEAHAWK 2602 1/1/2011 1/3/2011 2

JU MP 120 SEAHAWK 2602 1/3/2011 2/9/2011 37

JU MP 120 SEAHAWK 2602 2/11/2011 3/7/2011 24

JU ST 161 SEAHAWK 2602 3/11/2011 4/22/2011 42

JU HI A 309 SEAHAWK 3000 1/20/2011 2/7/2011 18

JU HI A 309 SEAHAWK 3000 2/7/2011 2/21/2011 14

JU HI A 309 SEAHAWK 3000 2/21/2011 3/2/2011 9

JU EC 328 SEAHAWK 3000 3/15/2011 4/3/2011 19

JU EC 328 SEAHAWK 3000 4/4/2011 4/17/2011 13

JU EC 328 SEAHAWK 3000 4/17/2011 4/26/2011 9

JU EC 328 SEAHAWK 3000 4/26/2011 5/6/2011 10

JU EI 208 SPARTAN 208 3/26/2011 4/15/2011 20

JU SM 107 SPARTAN 208 5/27/2011 6/7/2011 11

JU HI A 264 SPARTAN 208 6/24/2011 7/21/2011 27

JU BA 502 SPARTAN 208 8/6/2011 8/19/2011 13

JU GA 424 SPARTAN 208 11/1/2011 12/27/2011 56

JU GA A 133 SPARTAN 303 1/1/2011 1/6/2011 5

PF SP 93 SUNDOWNER I 5/8/2011 6/5/2011 28

PF SP 93 SUNDOWNER I 6/5/2011 6/24/2011 19

PF SP 93 SUNDOWNER I 6/24/2011 7/10/2011 16

PF SP 93 SUNDOWNER I 7/10/2011 7/26/2011 16

PF SP 93 SUNDOWNER I 7/26/2011 8/12/2011 17

PF SP 93 SUNDOWNER I 8/12/2011 8/21/2011 9

PF SP 93 SUNDOWNER I 8/21/2011 8/26/2011 5

PF SP 93 SUNDOWNER I 8/26/2011 9/22/2011 27

PF GI 23 SUNDOWNER I 10/13/2011 11/17/2011 35

DS WR 969 T. O. DISCOVERER AMERICAS 5/9/2011 10/22/2011 166

SS EW 965 T.O. AMIRANTE 2/13/2011 3/28/2011 43

79
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

SS MC 460 T.O. AMIRANTE 3/29/2011 6/16/2011 79

SS MC 687 T.O. DEEPWATER NAUTILUS 5/19/2011 7/16/2011 58

SS MC 348 T.O. DEEPWATER NAUTILUS 7/17/2011 12/31/2011 167

DS MC 772 T.O. DEEPWATER 

PATHFINDER 3/2/2011 6/22/2011 112

DS MC 728 T.O. DEEPWATER 

PATHFINDER 6/22/2011 9/19/2011 89

DS MC 772 T.O. DEEPWATER 

PATHFINDER 9/19/2011 12/31/2011 103

SD GC 654 T.O. DEVELOPMENT DRILLER 

I 1/1/2011 6/18/2011 168

SD GC 738 T.O. DEVELOPMENT DRILLER 

I 6/19/2011 12/12/2011 176

SD AT 617 T.O. DEVELOPMENT DRILLER 

I 12/12/2011 12/31/2011 19

SD GC 743 T.O. DEVELOPMENT DRILLER 

II 9/6/2011 11/7/2011 62

SD GC 743 T.O. DEVELOPMENT DRILLER 

II 12/2/2011 12/22/2011 20

SD GC 743 T.O. DEVELOPMENT DRILLER 

II 12/30/2011 12/31/2011 1

SD MC 252 T.O. DEVELOPMENT DRILLER 

III 1/23/2011 3/9/2011 45

SD GC 743 T.O. DEVELOPMENT DRILLER 

III 7/15/2011 12/31/2011 169

DS GC 903 T.O. DISCOVERER AMERICAS 10/23/2011 11/23/2011 31

DS GC 903 T.O. DISCOVERER AMERICAS 11/23/2011 12/31/2011 38

DS GC 640 T.O. DISCOVERER CLEAR 

LEADER 1/1/2011 3/3/2011 61

DS GC 640 T.O. DISCOVERER CLEAR 

LEADER 3/3/2011 3/11/2011 8

DS GC 640 T.O. DISCOVERER CLEAR 

LEADER 6/15/2011 8/24/2011 70

DS GC 640 T.O. DISCOVERER CLEAR 

LEADER 8/24/2011 11/27/2011 95

DS WR 758 T.O. DISCOVERER CLEAR 

LEADER 11/27/2011 12/31/2011 34

DS KC 785 T.O. DISCOVERER DEEP SEAS 5/15/2011 10/8/2011 146

DS GC 640 T.O. DISCOVERER DEEP SEAS 10/9/2011 12/31/2011 83

DS VK 914 T.O. DISCOVERER 

ENTERPRISE 12/1/2011 12/31/2011 30

DS WR 758 T.O. DISCOVERER INDIA 11/5/2011 11/22/2011 17

DS WR 677 T.O. DISCOVERER INDIA 11/24/2011 11/24/2011 0

DS WR 634 T.O. DISCOVERER INDIA 11/24/2011 11/24/2011 0

DS WR 677 T.O. DISCOVERER INDIA 11/24/2011 12/6/2011 12

DS WR 29 T.O. DISCOVERER INDIA 12/6/2011 12/8/2011 2

DS WR 29 T.O. DISCOVERER INDIA 12/8/2011 12/31/2011 23

DS WR 677 T.O. DISCOVERER INDIA 12/15/2011 12/15/2011 0

80
Rig 

Type

Surface 

Area 

Code

Surface 

Block 

Number

Rig Name Rig Move on 

Date

Rig Move 

off Date Days

DS KC 736 T.O. DISCOVERER 

INSPIRATION 3/26/2011 10/4/2011 192

DS WR 143 T.O. DISCOVERER 

INSPIRATION 10/4/2011 12/7/2011 64

DS WR 634 T.O. DISCOVERER 

INSPIRATION 12/7/2011 12/16/2011 9

DS WR 677 T.O. DISCOVERER 

INSPIRATION 12/16/2011 12/31/2011 15

DS GC 726 T.O. DISCOVERER SPIRIT 1/1/2011 3/17/2011 75

DS GC 726 T.O. DISCOVERER SPIRIT 3/17/2011 6/8/2011 83

PF MC 778 THUNDER HORSE PDQ 12/23/2011 12/31/2011 8

The drilling rig names in the BOEM dataset were matched to vessel names in the RigZone 

database (RigZone Data Center 2012) and other online sources. RigZone is an oil and gas trade 

service that monitors drilling rigs, and their database includes details concerning the drilling rig 

propulsion engines, prime engines, mud pumps, draw works, and emergency power. By 

matching the BOEM drilling rig vessel names to vessel characteristics in the RigZone database, 

accurate engine and equipment data were used to estimate emissions. Where RigZone did not 

include a vessel noted in the BOEM dataset, the RigZone data were averaged by vessel type and 

used to gap-fill missing data. The average engine kW ratings used to gap-fill missing data are 

noted in Table 6-3.

Table 6-3. Equipment kW ratings by drilling rig type

Rig Type

Average Total Main 

Power (kW)

Average Total 

Emergency (kW)

Average Total 

Propulsion (kW)

Drillship 25,347 1,352 40,383

Inland Barge 3,807 42 a

Jackup 3,751 256 a

Platform Rig 4,066 b a

Semisubmersible 13,426 495 3,913

Submersible 3,849 213 a

a Not self-propelled, relocated with support vessels (see Section 6.1.5). b Unknown. 

The kilowatt (kW) rating of each rig was applied to the hours that the rig spent at a block, or, 

if vessel specific data were not available, then the data in Table 6-3 were used to get the vessel 

kW-hours. These values were applied to the emission and load factors provided in Table 6-1. In 

selecting the emission factors (USEPA 2010), it was assumed that all rig engines were classified 

as high-speed diesel engines.

It should be noted that the few drilling rigs with propulsion engines tended to be semisubmersible rigs and drill ships, which use their thrusters to maintain the vessel’s drilling 

position at the drill site; these engines tend to operate at relatively low loads to keep the vessel in 

place. It is assumed that propulsion engines operate at 15% load, as noted in Table 6-1, to 

maintain position.

81
Transit emissions for drill ships and semisubmersibles have been quantified by applying the 

kW rating of the propulsion engines to the hours that the rig spent between relocations. Some 

rigs leave the lease block where drilling activities occur and exit the GOM or return to port. For 

this reason, propulsion emissions are limited to 10 days between relocations. It is assumed that 

propulsion engines operate at 75% load while the rig is relocating.

Emissions associated with emergency power generation were quantified using USEPA 

guidance for land-based emergency generators assumes operations of 500 hours per year to 

account for maintenance checks, operator training, and power outages (USEPA 1995). This 

assumption was applied to drilling rigs.

Calendar year 2011 drilling rig annual emission estimates were developed using the approach 

discussed in Section 6.1.1. An example of how the equation in Section 6.1.1 was used for this 

vessel category is provided below.

Example Calculation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) (hours)

kW = Average vessel kW (totaling individual propulsion engines) (kW)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

In 2011, all drill ships operated 48,432 hours. Average weighted kW rating for drill ships is 

29,742, load factor is 0.75, and the emission factor for NOx is 19.54 g/kWh. 

E = 48,432 × 29,742 × 0.75 × 19.54 × 1.10231 ×10-6

E = 23,679 tons of NOx

The variation in monthly drilling activities developed using the 2011 BOEM drill rig data, as 

presented in Table 6-4. This monthly profile was applied to the annual emission estimates to 

calculate the monthly emissions.

82
Table 6-4. Seasonal drilling activity 2011

Month Total Drilling Days (%)

January 6.30

February 5.97

March 6.98

April 7.96

May 8.56

June 8.59

July 8.78

August 9.08

September 8.63

October 9.15

November 9.30

December 10.70

The drilling operation emissions were spatially allocated to the lease blocks where drilling 

occurred. Figure 6-1 maps the location of all 2011 drilling rig operations.

Figure 6-1. Location of drilling operations and BOEM lease blocks for 2011

83
6.1.3 Pipelaying Operations

Product from oil platforms is generally transported to shore through pipelines. New pipelines 

are constantly being laid, linking new well heads and platforms to shore or increasing the 

capacity of the existing pipeline network. Pipelines also require occasional maintenance and 

repair. To install, maintain, or replace sections of pipeline necessitates considerable vessel 

support. Using data from the 2009 Louisiana State University study entitled “Empirical Analysis 

of Offshore Service Vessel Utilization in the Gulf of Mexico,” (Kaiser and Snyder 2009) the 

number of vessel hours needed to lay a foot of pipe was estimated to be 0.32 hours/ft. This 

operating hours factor was applied to BOEM data documenting the segments built or maintained 

in 2011. It should be noted that this estimate includes emissions from support vessels involved in 

pipelaying. In some cases, these support vessels may be included in the support vessel emission 

estimates described in Section 6.1.5 as well.

The BOEM data documents the length and location of individual sections constructed or 

maintained from January 2011 to December 2011 (USDOI, BOEM 2013a and 2013b). These 

new pipeline segments were mapped to individual lease blocks in the GOM using Geographic 

Information System (GIS) tools (USDOI, BOEM 2013c). The total length of pipeline constructed 

within a lease block was calculated for each lease block along with the total vessel hours 

included in these activities, based on the following equation:

Tpi = Σ (Li × 0.32 hrs/ft)

where:

Tpi = Total vessel time involved in pipelaying or maintenance for lease block i (hours)

Li = Length of individual pipe segment within the boundaries of lease block i (feet)

The 2011 vessel hours associated with pipeline construction, including new pipelaying and 

pipeline repair, totaled 788,574 hours. Pipeline maintenance activities were identified as those 

segments in the BOEM master pipeline dataset with a pipeline construction date in the year 

2011. New pipelines were identified from the BOEM master pipeline dataset as those that 

showed no construction date but had an initial hydrostatic test date in 2011. These two types of 

pipelaying activities are summarized in Table 6-5.

Table 6-5. Pipelaying activity

Activity Hours of Activity in 2011

New Pipelaying 325,864

Repair 462,710

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. For this inventory, 

it was assumed that the main propulsion engines are medium-speed diesel engines. Assumptions 

about average horsepower and load factors (Table 6-6) were obtained from the Gulf of Mexico 

Air Quality Study (Systems Applications International et al. 1995) and applied to the emission 

84
factors presented in Section 6.1.1. Accidental releases of gas or oil from pipelines during 

construction or maintenance were not considered in this study.

Table 6-6. Average pipelaying vessel characteristics

Average Vessel kW Load Factor

894.84 0.75

Emission estimates were developed using the approach discussed in Section 6.1.1. An 

example of how the equation in Section 6.1.1 was used for this vessel category is provided 

below.

Example Calculation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) (hours)

kW = Average vessel kW (totaling individual propulsion engines) (kW)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

In 2011, total hours of pipeline repair activity were 462,710. Average vessel kW of 

pipelaying vessels is 894.84, load factor is 0.75, and the emission factor for NOx is 16.25 g/kWh. 

E = 462,710 × 894.84 × 0.75 × 16.25 × 1.10231 × 10-6

E = 5,563 tons of NOx

The new pipelaying activity is summarized with both total pipe length constructed and total 

hours by BOEM lease block in Table 6-7. Repair activity is summarized by total pipe length and 

hours by BOEM lease block in Table 6-8. Total pipelaying activity data are broken down by 

month in Table 6-9; these monthly data were based on construction or hydrostatic test dates and 

used to represent seasonality of pipeline-related activities.

Pipeline construction and repair emissions were mapped to the lease blocks where the 

activity occurred using data provided by BOEM and are provided in Figure 6-2 (USDOI, BOEM 

2013c).

85
Table 6-7. New pipelaying activity data

Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

18270 EB602 20110805 17.31 18.18

18271 EB602 20110805 13.98 14.67

18175 EC24 20110422 967.76 1,016.02

18175 EC33 20110422 879.32 923.17

18175 EC34 20110422 2,689.55 2,823.68

18290 EI100 20111005 1,914.44 2,009.92

18290 EI105 20111005 1,670.16 1,753.45

18290 EI106 20111005 4,536.50 4,762.73

18272 EI302 20110806 3,373.29 3,541.51

18272 EI303 20110806 1,656.87 1,739.49

18216 GAA132 20110718 1,702.75 1,787.66

18216 GAA133 20110718 285.58 299.82

18216 GAA155 20110718 2,477.89 2,601.46

18083 GC139 20110520 5,244.19 5,505.71

18083 GC182 20110520 1,067.93 1,121.19

18083 GC183 20110520 4,055.80 4,258.06

18083 GC226 20110520 5,120.21 5,375.55

18083 GC270 20110520 5,014.96 5,265.06

18083 GC314 20110520 4,891.11 5,135.02

18083 GC358 20110520 4,929.12 5,174.93

18083 GC402 20110520 4,624.97 4,855.62

18083 GC403 20110520 1,561.01 1,638.86

18083 GC447 20110520 5,439.09 5,710.33

18083 GC448 20110520 1,312.65 1,378.12

18083 GC52 20110520 302.39 317.47

18083 GC52 20110520 2,032.85 2,134.22

17778 GC640 20111025 610.98 641.45

18219 GC640 20111123 28.91 30.35

18220 GC640 20111124 26.71 28.04

17778 GC641 20111025 2,427.38 2,548.43

18319 GC743 20111128 19.31 20.27

18320 GC743 20111128 19.03 19.98

18321 GC743 20111228 22.02 23.12

18322 GC743 20111228 23.09 24.24

18323 GC743 20111219 20.21 21.22

18324 GC743 20111216 20.16 21.17

18325 GC743 20111219 12.22 12.83

18326 GC743 20111216 12.75 13.39

18329 GC743 20111120 18.97 19.92

18330 GC743 20111113 19.70 20.68

18331 GC743 20111020 17.20 18.06

18332 GC743 20111020 16.66 17.49

18333 GC743 20111030 12.28 12.90

18334 GC743 20111107 12.47 13.10

18339 GC743 20111118 17.54 18.41

86
Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

18341 GC743 20111018 28.76 30.19

18342 GC743 20110906 28.13 29.53

18345 GC743 20111128 20.58 21.60

18346 GC743 20111018 29.12 30.58

18348 GC743 20111128 15.54 16.31

18349 GC743 20111021 25.70 26.98

18351 GC743 20111212 15.06 15.81

18352 GC743 20111209 15.04 15.79

18353 GC743 20111209 15.11 15.86

18354 GC743 20111212 15.14 15.89

18355 GC743 20111208 19.35 20.32

18356 GC743 20111118 19.35 20.32

18357 GC743 20111208 19.37 20.34

18358 GC743 20111111 19.38 20.34

18083 GC95 20110520 2,748.27 2,885.33

18083 GC96 20110520 3,744.33 3,931.06

18164 MC109 20110624 3,088.51 3,242.53

18176 MC115 20110814 4,942.58 5,189.06

18177 MC115 20110814 4,943.47 5,190.00

18164 MC153 20110624 4,841.86 5,083.31

18176 MC159 20110814 4,977.71 5,225.95

18177 MC159 20110814 4,976.80 5,224.99

18164 MC197 20110624 4,842.09 5,083.56

18176 MC203 20110814 2,831.27 2,972.46

18177 MC203 20110814 2,905.30 3,050.18

18176 MC204 20110814 2,145.50 2,252.49

18177 MC204 20110814 2,072.14 2,175.48

18164 MC241 20110624 1,061.03 1,113.94

18166 MC241 20110609 11.28 11.84

18176 MC248 20110814 4,923.57 5,169.10

18177 MC248 20110814 4,922.32 5,167.79

18176 MC26 20110814 2,779.18 2,917.77

18177 MC26 20110814 2,843.58 2,985.39

18176 MC27 20110814 2,196.53 2,306.06

18177 MC27 20110814 2,132.07 2,238.40

18176 MC292 20110814 1,317.51 1,383.21

18177 MC292 20110814 1,330.58 1,396.93

18178 MC292 20110814 14.34 15.06

18179 MC292 20110814 15.72 16.50

18204 MC503 20111026 1,943.88 2,040.82

18205 MC503 20110918 2,175.66 2,284.15

18206 MC503 20110922 264.11 277.29

18210 MC503 20110309 17.75 18.63

18212 MC503 20110218 17.06 17.91

18217 MC503 20110216 18.46 19.38

18314 MC503 20110329 19.08 20.03

87
Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

18315 MC503 20110325 18.94 19.89

18265 MC519 20111120 19.22 20.18

18266 MC519 20111123 19.08 20.04

18189 MC547 20111027 2,225.92 2,336.93

18204 MC547 20111026 3,184.20 3,342.99

18205 MC547 20110918 3,248.87 3,410.88

18206 MC547 20110922 4,081.16 4,284.68

18189 MC589 20111027 2,737.02 2,873.51

18189 MC590 20111027 5,278.11 5,541.32

18189 MC591 20111027 2,044.66 2,146.62

18189 MC632 20111027 4,278.02 4,491.36

18189 MC633 20111027 2,842.29 2,984.03

18189 MC675 20111027 5,478.48 5,751.69

18189 MC676 20111027 1,977.69 2,076.31

18176 MC71 20110814 4,970.87 5,218.76

18177 MC71 20110814 4,970.83 5,218.72

16324 MC711 20110213 875.40 919.06

16335 MC711 20110213 1,940.19 2,036.95

18189 MC718 20111027 1,456.17 1,528.79

18189 MC719 20111027 818.01 858.80

18234 MC728 20110925 18.26 19.17

18235 MC728 20110925 19.33 20.30

18236 MC728 20110925 22.78 23.91

16332 MC754 20110213 20.76 21.80

16333 MC754 20110213 909.08 954.42

16335 MC754 20110213 995.97 1,045.63

16324 MC755 20110213 923.96 970.04

16333 MC755 20110213 1,023.62 1,074.67

16334 MC755 20110213 20.36 21.38

16335 MC755 20110213 1,444.46 1,516.50

18275 MC772 20110908 19.68 20.66

18198 MI622 20110703 718.36 754.18

18198 MI623 20110703 1,553.64 1,631.12

18299 MP108 20111222 1,760.95 1,848.76

16342 MP112 20110303 2,472.51 2,595.81

16342 MP113 20110303 1,145.51 1,202.63

16342 MP117 20110303 4,911.79 5,156.74

16342 MP118 20110303 3,880.52 4,074.04

16342 MP126 20110303 122.09 128.18

16342 MP127 20110303 4,608.40 4,838.21

18159 MP308 20111028 1,347.19 1,414.37

18160 MP308 20111028 1,343.22 1,410.20

18159 MP309 20111028 4,432.56 4,653.60

18160 MP309 20111028 4,432.43 4,653.47

18159 MP310 20111028 1,951.08 2,048.37

18160 MP310 20111028 1,946.46 2,043.53

88
Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

18267 MP40 20110917 3,670.03 3,853.05

18267 MP41 20110917 527.48 553.79

18267 MP59 20110917 1,446.90 1,519.06

18154 PL23 20110425 662.58 695.62

18155 PL23 20110424 662.92 695.98

18259 SS150 20111003 1,281.02 1,344.91

18186 SS153 20110708 65.02 68.26

18186 SS154 20110708 29.40 30.87

18486 SS189 20111215 569.45 597.85

18187 ST128 20110701 117.91 123.79

18187 ST134 20110701 1,135.67 1,192.30

18187 ST135 20110701 269.78 283.23

18176 VK900 20110814 3,026.41 3,177.34

18177 VK900 20110814 3,033.90 3,185.20

18176 VK944 20110814 4,975.35 5,223.46

18177 VK944 20110814 4,974.50 5,222.57

18176 VK988 20110814 4,975.19 5,223.30

18177 VK988 20110814 4,975.44 5,223.56

18286 VR170 20110806 2,270.06 2,383.27

18286 VR171 20110806 4,059.23 4,261.66

18481 WC110 20111027 885.42 929.58

18174 WC116 20110513 3,984.67 4,183.38

18174 WC117 20110513 4,108.21 4,313.08

18364 WC71 20111022 978.87 1,027.68

18129 WD106 20110821 5,073.59 5,326.61

18129 WD107 20110821 533.19 559.78

18245 WD30 20110721 824.64 865.76

18369 WD73 20111212 1,068.49 1,121.77

18196 WD89 20111229 149.56 157.02

18196 WD89 20111229 2,137.14 2,243.72

18369 WD92 20111212 1,935.79 2,032.32

18369 WD93 20111212 2,978.82 3,127.37

89
Table 6-8. Pipeline Repair Activity Data

Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

6992 BM3 20110110 499.53 524.44

8031 BM3 20110813 480.15 504.09

13468 EB602 20111022 28.99 30.44

13469 EB602 20110817 9.95 10.45

13470 EB602 20111010 29.55 31.02

14869 EC265 20110308 1,591.24 1,670.59

14870 EC265 20110308 1,591.17 1,670.52

14869 EC278 20110308 93.70 98.37

14870 EC278 20110308 93.48 98.14

11056 EI107 20110510 4,132.03 4,338.09

4792 EI307 20110424 100.67 105.69

1707 EI32 20110731 764.12 802.23

7631 EI330 20110402 876.83 920.55

11228 EI331 20110618 2,820.33 2,960.97

11228 EI336 20110618 111.33 116.88

11228 EI337 20110618 5,044.51 5,296.08

12749 EI344 20110302 488.63 513.00

12749 EI345 20110302 5,711.21 5,996.02

12749 EI347 20110302 5,223.43 5,483.92

12749 EI348 20110302 1,251.18 1,313.57

11228 EI355 20110618 5,155.30 5,412.39

11228 EI357 20110618 2,278.99 2,392.64

11228 EI358 20110618 3,292.14 3,456.32

12749 EI364 20110302 228.12 239.50

12749 EI365 20110302 5,875.02 6,168.00

12749 EI370 20110302 4,202.55 4,412.13

12749 EI371 20110302 4,830.82 5,071.73

11228 EI378 20110618 4,437.51 4,658.80

11228 EI379 20110618 3,268.04 3,431.02

12749 EI386 20110302 713.36 748.94

12749 EI386 20110302 2,238.48 2,350.11

12749 EI387 20110302 2,305.29 2,420.25

12749 EI388 20110302 4,873.83 5,116.88

4705 EI57 20110120 104.11 109.31

4705 EI57 20110120 208.13 218.50

4709 EI57 20110119 917.94 963.72

18161 EW908 20110326 1,159.80 1,217.64

18163 EW908 20110326 1,161.39 1,219.30

18161 EW952 20110326 4,203.01 4,412.61

18163 EW952 20110326 4,341.44 4,557.94

18161 EW953 20110326 1,218.36 1,279.12

18163 EW953 20110326 1,061.08 1,113.99

12749 EW981 20110302 1,425.30 1,496.38

18161 EW997 20110326 5,439.03 5,710.27

18163 EW997 20110326 5,451.11 5,722.95

90
Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

11228 GB128 20110618 1,483.66 1,557.64

11228 GB84 20110618 5,923.42 6,218.81

11228 GB85 20110618 421.62 442.65

12749 GC101 20110302 686.38 720.61

12749 GC101 20110302 2,472.07 2,595.35

12749 GC102 20110302 3,378.34 3,546.81

12749 GC11 20110302 1,675.95 1,759.53

18161 GC116 20110326 837.12 878.87

18163 GC116 20110326 975.94 1,024.61

12749 GC12 20110302 1,284.25 1,348.29

12749 GC12 20110302 3,435.26 3,606.57

12749 GC146 20110302 3,080.02 3,233.61

12749 GC147 20110302 4,033.33 4,234.47

12749 GC191 20110302 1,079.15 1,132.97

12749 GC191 20110302 1,610.41 1,690.72

12749 GC192 20110302 4,087.16 4,290.98

12749 GC236 20110302 2,244.67 2,356.61

12749 GC237 20110302 50.19 52.70

18161 GC27 20110326 3,588.71 3,767.67

18163 GC27 20110326 3,732.83 3,918.98

18161 GC28 20110326 1,836.86 1,928.46

18163 GC28 20110326 1,692.66 1,777.07

12749 GC56 20110302 2,409.72 2,529.89

12749 GC57 20110302 3,974.36 4,172.56

18161 GC72 20110326 5,354.11 5,621.11

18163 GC72 20110326 5,364.08 5,631.58

18016 GI47 20110723 906.98 952.21

18016 GI48 20110723 1,175.35 1,233.96

15653 MC919 20110620 2,947.95 3,094.96

15653 MC920 20110620 2,555.95 2,683.41

15653 MC961 20110620 3,252.42 3,414.62

15653 MC962 20110620 5,115.87 5,371.00

15653 MC963 20110620 2,227.69 2,338.78

8985 MP107 20110303 227.11 238.44

8985 MP108 20110303 3,681.64 3,865.24

8985 MP112 20110303 3,823.28 4,013.94

15811 MP117 20110314 2,669.64 2,802.77

15811 MP118 20110314 1,441.56 1,513.45

15811 MP126 20110314 1,908.06 2,003.21

15811 MP127 20110314 4,328.92 4,544.80

9149 MP64 20110119 831.35 872.81

9149 MP65 20110119 550.50 577.95

15495 SM108 20110926 3,188.95 3,347.98

15495 SM113 20110926 153.18 160.81

15495 SM114 20110926 5,934.39 6,230.34

15495 SM122 20110926 6,028.12 6,328.74

15495 SM123 20110926 459.68 482.60

91
Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

15495 SM131 20110926 407.97 428.31

15495 SM132 20110926 5,245.81 5,507.41

15495 SM137 20110926 1,587.29 1,666.45

17433 SM149 20111206 3,022.92 3,173.67

11228 SM190 20110618 3,387.49 3,556.42

11228 SM191 20110618 1,046.34 1,098.52

11228 SM192 20110618 4,205.27 4,414.98

11228 SM204 20110618 2,993.12 3,142.38

11228 SM205 20110618 3,270.17 3,433.25

13514 SM239 20111217 1,738.03 1,824.70

7608 SM41 20110531 665.79 698.99

7608 SM41 20110531 3,336.41 3,502.80

6185 SP77 20110112 3,033.38 3,184.65

6185 SP78 20110112 3,605.00 3,784.78

8284 SS153 20110715 188.34 197.73

8284 SS154 20110715 4,189.68 4,398.61

1137 SS204 20110216 801.31 841.27

1137 SS205 20110216 4,591.65 4,820.64

12749 SS205 20110302 1,518.84 1,594.58

1137 SS206 20110216 4,591.29 4,820.25

10573 SS206 20110108 1,025.52 1,076.66

10574 SS206 20110108 1,025.52 1,076.66

12749 SS206 20110302 4,739.87 4,976.24

1137 SS207 20110216 1,678.46 1,762.16

1190 SS207 20110105 1,018.68 1,069.48

3907 SS207 20110105 1,165.71 1,223.84

4241 SS207 20110105 1,325.72 1,391.83

7002 SS207 20110104 939.94 986.81

10573 SS207 20110108 2,143.99 2,250.91

10574 SS207 20110108 2,143.99 2,250.91

12749 SS207 20110302 1,369.98 1,438.30

1833 SS209 20110611 550.92 578.40

3907 SS216 20110105 1,392.65 1,462.10

12749 SS218 20110302 4,714.85 4,949.98

12749 SS219 20110302 1,228.77 1,290.05

12749 SS228 20110302 4,890.66 5,134.55

12749 SS243 20110302 3,579.12 3,757.60

12749 SS244 20110302 1,650.92 1,733.24

5902 SS247 20110927 2,603.58 2,733.42

5902 SS248 20110927 360.11 378.07

12749 SS251 20110302 5,400.19 5,669.49

12749 SS268 20110302 161.13 169.17

12749 SS269 20110302 5,501.27 5,775.61

12749 SS273 20110302 3,194.24 3,353.53

12749 SS274 20110302 2,011.34 2,111.65

12749 SS294 20110302 4,248.07 4,459.92

12749 SS295 20110302 1,149.96 1,207.31

92
Pipeline Segment 

ID

Lease Block ID

(AC_LAB)

Initial Hydrostatic 

Test Date

Length

(Meters)

Hours of 

Operation (Hrs)

12749 SS296 20110302 1,200.78 1,260.67

12749 SS296 20110302 4,312.23 4,527.28

12749 SS319 20110302 501.17 526.16

6267 SS33 20110815 2,685.92 2,819.86

14471 SS58 20111013 2,237.13 2,348.70

7802 ST295 20110331 1,943.91 2,040.85

7802 ST296 20110331 4,756.46 4,993.66

7802 ST297 20110331 1,980.39 2,079.15

18161 ST300 20110326 2,414.52 2,534.93

18163 ST300 20110326 2,514.41 2,639.80

18161 ST301 20110326 1,429.40 1,500.68

18163 ST301 20110326 1,320.74 1,386.61

18161 ST314 20110326 5,018.41 5,268.68

18163 ST314 20110326 5,021.30 5,271.71

18161 ST317 20110326 2,054.81 2,157.28

18163 ST317 20110326 2,201.70 2,311.50

18161 ST318 20110326 2,694.15 2,828.50

18163 ST318 20110326 2,546.01 2,672.97

1240 VR264 20111120 3,265.73 3,428.59

1240 VR265 20111120 2,891.65 3,035.86

1240 VR279 20111120 2,041.72 2,143.54

11002 VR279 20111115 2,572.49 2,700.77

1240 VR280 20111120 5,266.78 5,529.42

1240 VR281 20111120 587.88 617.20

1240 VR282 20111120 5,062.66 5,315.13

17934 VR282 20110916 112.57 118.19

13218 VR369 20110211 1,856.96 1,949.57

13219 VR369 20110211 1,856.96 1,949.57

10146 VR39 20110301 1,427.92 1,499.13

11350 WC110 20110414 1,696.88 1,781.51

18228 WC128 20110720 1,158.09 1,215.84

18228 WC129 20110720 5,327.27 5,592.93

18228 WC130 20110720 1,324.99 1,391.07

18228 WC153 20110720 1,491.26 1,565.63

12743 WC170 20110608 921.76 967.73

12744 WC170 20110608 921.99 967.97

14175 WC47 20110505 6,057.34 6,359.41

14175 WC48 20110505 1,364.41 1,432.45

14175 WC54 20110505 0.08 0.09

14175 WC54 20110505 2,726.81 2,862.79

6185 WD109 20110112 1,507.32 1,582.48

6185 WD110 20110112 637.19 668.97

18022 WD70 20110717 1,555.11 1,632.66

18022 WD95 20110717 4,169.88 4,377.82

Total 440,731.49 462,710.24

93
Table 6-9. Pipelaying monthly adjustment factors

Month 2011 Monthly Adjustment Factors (%)

January 3.21

February 3.14

March 33.23

April 1.14

May 10.45

June 10.85

July 4.18

August 14.42

September 5.54

October 8.85

November 2.92

December 2.07

Figure 6-2. 2011 pipelaying activity locations and BOEM lease blocks

94
6.1.4 Support Helicopters

Helicopters are used extensively in the GOM to move light supplies and personnel to and 

from platforms. The best data source for all helicopter operations in the GOM is the Helicopter 

Safety Advisory Conference (HSAC) annual safety report, Gulf of Mexico Offshore Helicopter 

Operations and Safety Review (HSAC 2012). The report contains a snapshot of all helicopter 

operations in the GOM as reported by participating operators. However, the report 

underestimates operations, as activity data are voluntarily provided by a fraction of operators. 

Based on personal communications with the government liaison committee chairman for the 

HSAC (Raaz 2009), approximately 70% of the offshore support helicopters provide activity data 

to HSAC. Therefore the 2011 HSAC activity data were corrected by multiplying the landing and 

takeoff (LTO) data by 100/70 or 1.4286. The HSAC compiled activity data are disaggregated 

into single engine, light twin engine, medium twin engine, and heavy twin engine helicopters, as 

noted in Table 6-10.

Table 6-10. HSAC helicopter data

Helicopter Type 2011 

LTO Adjusted 2011 LTOa

Single 636,058 908,654

Twin Light 92,762 132,517

Twin Medium 131,368 187,669

Twin Heavy 30,984 44,263

Total 891,172 1,273,103 a Raw LTO data adjusted to account for survey bias based on 

personal communication with Dana Raaz, government liaison 

committee chairman for the HSAC on July 20, 2009.

The primary helicopter emission factors were obtained from Switzerland FOCA’s Guidance 

on Determination of Helicopter Emissions. However, the LTO cycle used by FOCA was 

determined to be too short for typical trips taken in the GOM. The average trip length was 

relatively short (20 minutes) (HSAC 2009); therefore it was assumed that helicopters typically 

hop from platform to platform. In addition to the 20 minute flight time, it was assumed that the 

helicopters idle for an additional 15 minutes while on the platform. Therefore the time in modes 

from the FOCA were adjusted to reflect conditions in the GOM. Table 6-11 shows the original 

FOCA time in mode values and the new adjusted values for the GOM.

Table 6-11. Time-in-mode values

Source

PretakeOff Idle

(Min)

Take-Off 

Time 

(Min)

Approach 

Time 

(Min)

PostLanding 

Idle (Min)

Total Idling 

(Min)

Total Flight 

(Min)

FOCA 4.0 3.0 5.5 1.0 5.0 8.5

GOM 12 7 13 3 15 20

The FOCA emission factors were recalculated based on the new time in mode values. Then 

the LTO-based emission factors for each helicopter type were averaged to yield the emission 

factors used in this study. Table 6-12 lists the FOCA emission factors by helicopter and 

helicopter type.

95
The VOC helicopter emission factors were developed by converting the hydrocarbon (HC). 

PM2.5 factors were speciated from PM10 using USEPA aircraft speciation data. SO2 emission 

factors were developed based on typical jet fuel sulfur concentration of 0.05% (UNEP 2012). 

CO2, N2O, and CH4 emission factors were obtained from the U.S. Department of 

Transportation’s Energy Information Administration Voluntary Reporting of GHG Program. The 

compiled emission factors are summarized in Table 6-13. 

Table 6-12. FOCA average emission factors by helicopter type

Helicopter 

Type

Fuel/ 

LTO 

(kg)

Emission Factors (lbs/LTO)

NOX

1 HC1 VOC2 CO1 PM101 PM2.53 SO24 CO25 N2O5 CH45

Single 57.31 0.68 1.93 1.87 2.48 0.02 0.02 0.12 176.69 0.01 0.01

Twin Light 94.31 0.95 5.28 5.13 6.93 0.03 0.03 0.20 290.78 0.02 0.02

Twin 

Medium 134.45 1.95 4.13 4.01 5.33 0.06 0.06 0.29 414.51 0.03 0.03

Twin Heavy 327.03 8.82 2.76 2.68 3.43 0.22 0.22 0.70 1008.27 0.07 0.06

1 FOCA 2009

2 HC to VOC = * 0.9708 

3 PM2.5 = 97.6% of PM10 

4 SO2 (g/gal) = (fuel density) × (conversion factor) × (64 g SO2/32 g S) × (S content of fuel)

5 EIA 2012

The emission factors developed from this project were applied to the activity data to estimate 

emissions using the following equation:

Ei = EFi / 2000 × LTOi

where:

Ei = Helicopter emisions for helicopter type i (tons per year)

EFi = Helicopter emission factor for helicopter type i (pounds/LTO)

LTOi = Landing and take off cycle for helicopter type i (cycles per year)

i = Helicopter type (i.e., single, light, or medium)

2000 = Conversion factor pounds per ton

Example Calculation:

The emission factor of NOx for single engine helicopter is 0.6846 pounds/LTO, and the 

LTOs for single engine helicopters in 2011 were 908,654. 

ESingle = EFSingle / 2000 × LTOSingle

E = 0.6846/2000 × 908,654

E = 217.72 tons of NOx

96
Table 6-13. Helicopter emission factors by helicopter and helicopter type

Type Code Aircraft 

ICAO Aircraft Name Engine Name LTO fuel (kg)

LTO 

NOX (g)

LTO 

HC (g)

LTO 

CO (g)

LTO PM non 

volatile (g)

Single H001 ALO2 ALOUETTE II ARTOUSTE IIC5 45.6 184 1055 1372 7

Single H001 ALO2 ALOUETTE II ARTOUSTE IIC6 45.6 184 1055 1372 7

Single H001 ALO3 SA316B ALOUETTE III ARTOUSTE IIIB 53.6 264 859 1106 9

Single H001 ALO3 SA316B ALOUETTE III ASTAZOU XIVB 54.9 278 835 1073 9

Single H001 AS35 AS 350 B3 ARRIEL 2B 68.6 433 684 869 13

Single H001 AS35 AS 350 B3 ARRIEL 2B1 68.6 433 684 869 13

Single H001 AS35 AS 350 ECUREUIL ARRIEL 1B 58.7 312 806 1033 10

Single H001 AS35 AS 350B ECUREUIL ARRIEL 1D1 63.1 364 745 951 12

Single H001 AS50 AS 550 FENNEC ARRIEL 1D1 63.1 364 745 951 12

Single H001 B06 BELL 206B DDA250-C20 45.5 183 1058 1376 7

Single H001 B06 BELL 206B DDA250-C20B 46.5 192 1027 1333 7

Single H001 B06 BELL 206B DDA250-C20J 46.5 192 1027 1333 7

Single H001 B06 BELL 206B DDA250-C20R 48.0 207 984 1276 7

Single H001 B06 BELL 206B DDA250-C20R/4 48.0 207 984 1276 7

Single H001 B06 BELL 206L DDA250-C20R 48.0 207 984 1276 7

Single H001 B06 BELL 206L DDA250-C30 59.1 317 799 1024 10

Single H001 B06 BELL 206L DDA250-C30P 59.1 317 799 1024 10

Single H001 B407 Bell 407 DDA250-C47B 59.1 317 799 1024 10

Single H001 EC20 EC 120 ARRIUS 2F 47.1 198 1009 1309 7

Single H001 EC30 EC 130 B4 ARRIEL 2B1 68.6 433 684 869 13

Single H001 EN48 ENSTROM 480 DDA250-C20W 46.5 192 1027 1333 7

Single H001 GAZL SA341 GAZELLE ASTAZOU IIIA 58.8 314 804 1030 10

Single H001 GAZL SA341 GAZELLE ASTAZOU IIIN2 58.8 314 804 1030 10

Single H001 GAZL SA342 GAZELLE ASTAZOU XIVG 54.9 278 835 1073 9

Single H001 GAZL SA342 GAZELLE ASTAZOU XIVH 54.9 278 835 1073 9

Single H001 H500 HUGHES 500 DDA250-C18 41.2 145 1223 1601 6

97
Type Code Aircraft 

ICAO Aircraft Name Engine Name LTO fuel (kg)

LTO 

NOX (g)

LTO 

HC (g)

LTO 

CO (g)

LTO PM non 

volatile (g)

Single H001 H500 HUGHES 501 DDA250-C20B 46.5 192 1027 1333 7

Single H001 H500 MD 500N DDA250-C20R 48.0 207 984 1276 7

Single H001 KMAX K-1200 T53 17A-1 108.1 945 573 716 27

Single H001 LAMA SA315B LAMA ARTOUSTE IIIB 53.6 264 859 1106 9

Single H001 MD52 MD 520N DDA250-C20 45.5 183 1058 1376 7

Single H001 MD60 MD 600N DDA250-C47M 59.1 317 799 1024 10

Single H002 UH1 BELL UH-1H T53 L13 104.1 873 597 747 25

Single H013 A119 AGUSTA A119 PT6B-37 71.1 466 661 838 14

AVERAGE of Single 57.3 310.5 873.7 1125.6 10.2

Twin Light H001 A109 AGUSTA A109 DDA250-C20R/1 83.6 333 2654 3500 13

Twin Light H001 A109 AGUSTA A109 PW207C 102.9 508 2172 2834 17

Twin Light H001 A109 AGUSTA A109 K2 ARRIEL1K1 109.8 586 2007 2608 19

Twin Light H001 A109 AGUSTA A109 Power ARRIUS 2K 104.4 525 2131 2778 18

Twin Light H001 A109 AGUSTA A109A II DDA250-C20B 81.1 310 2770 3661 12

Twin Light H001 A109 AGUSTA A109C DDA250-C20R 83.6 333 2654 3500 13

Twin Light H001 AS55 AS 355 DDA250-C20F 81.1 310 2770 3661 12

Twin Light H001 AS55 AS 355 N ARRIUS 1A 86.1 356 2550 3357 13

Twin Light H001 AS55 AS 555 FENNEC ARRIEL 1D1 107.7 562 2052 2669 19

Twin Light H001 B06T Bell TWIN RANGER DDA250-C20R 83.6 333 2654 3500 13

Twin Light H001 B105 BO 105 DDA250-C20 79.5 295 2857 3781 12

Twin Light H001 B105 BO 105 DDA250-C20B 81.1 310 2770 3661 12

Twin Light H001 B222 BELL 222 DDA250-C40B 108.0 565 2047 2662 19

Twin Light H001 B222 BELL 222 LTS101-750C.1 109.5 583 2012 2615 19

Twin Light H001 EC35 EC 135 ARRIUS 2B1 101.5 493 2209 2884 17

Twin Light H001 EC35 EC 135 ARRIUS 2B2 101.5 493 2209 2884 17

Twin Light H019 EXPL MD 900 PW206A 100.6 483 2236 2921 17

Twin Light H021 A109 AGUSTA A109E PW206C 91.8 411 2348 3079 15

98
Type Code Aircraft 

ICAO Aircraft Name Engine Name LTO fuel (kg)

LTO 

NOX (g)

LTO 

HC (g)

LTO 

CO (g)

LTO PM non 

volatile (g)

AVERAGE of Twin Light 94.3 432.7 2394.7 3142.1 15.2

Twin Medium H001 AS65 AS 365 C1 DAUPHIN ARRIEL 1A1 102.2 500 2192 2860 17

Twin Medium H001 AS65 AS 365 C2 DAUPHIN ARRIEL 1A2 102.2 500 2192 2860 17

Twin Medium H001 AS65 AS 365 N DAUPHIN ARRIEL 1C 103.6 517 2152 2805 18

Twin Medium H001 AS65 AS 365 N1 DAUPHIN ARRIEL 1C1 106.8 552 2074 2699 18

Twin Medium H001 AS65 AS 365 N3 DAUPHIN ARRIEL 2C 117.7 680 1858 2404 22

Twin Medium H001 B430 Bell 430 DDA250-C40B 108.0 565 2047 2662 19

Twin Medium H001 BK17 BK117 ARRIEL 1E2 109.8 586 2007 2608 19

Twin Medium H001 BK17 BK117 C-2 ARRIEL 1E2 109.8 586 2007 2608 19

Twin Medium H001 BK17 BK117B LTS101-750B.1 108.9 576 2026 2634 19

Twin Medium H001 EC55 EC 155 B ARRIEL 2C1 117.7 680 1858 2404 22

Twin Medium H001 EC55 EC 155 B1 ARRIEL 2C2 126.0 783 1733 2235 25

Twin Medium H001 S76 SIKORSKY S76 DDA250-C30S 102.9 508 2172 2834 17

Twin Medium H001 S76 SIKORSKY S-76 C+ ARRIEL 2S1 119.1 696 1836 2374 22

Twin Medium H002 A139 AGUSTA A139 PT6C-67C 149.2 901 2098 2703 29

Twin Medium H002 H60 SIKORSKY BLACK HAWK T700-GE-700 179.9 1369 1613 2054 41

Twin Medium H002 MI8 MIL MI-8 TV2-117 173.0 1256 1698 2167 38

Twin Medium H002 S92 SIKORSKY S92A GE CT7-8A 242.4 2542 1173 1469 69

Twin Medium H011 S76 SIKORSKY S76 PT6B-36A 128.9 820 1695 2183 26

Twin Medium H014 B412 Bell 412 PT6T-3 190.0 1539 1509 1915 45

Twin Medium HF30 AS32 SUPER PUMA MAKILA 1A1 191.1 1559 1499 1901 46

AVERAGE of Twin Medium 134.4 885.6 1871.9 2418.9 27.3

Twin Heavy H001 KA27 KA-32A12 TV3-117VMA 212.4 1945 1334 1681 55

Twin Heavy H002 H53 SIKORSKY CH-53G (S-65) T 64-GE-7 307.5 4024 967 1197 99

Twin Heavy H002 H53S SIKORSKY SUPER 

STALLION T 64-GE-7 461.2 6036 1450 1795 148

AVERAGE of Twin Heavy 327.0 4001.6 1250.4 1557.6 100.7

99
The emission factors developed from this project were applied to the activity data to estimate 

emissions using the following equation:

Ei = EFi / 2000 × LTOi

where:

Ei = Helicopter emisions for helicopter type i (tons per year)

EFi = Helicopter emission factor for helicopter type i (pounds/LTO)

LTOi = Landing and take off cycle for helicopter type i (cycles per year)

i = Helicopter type (i.e., single, light, or medium)

2000 = Conversion factor pounds per ton

Example Calculation:

The emission factor of NOx for single engine helicopter is 0.6846 pounds/LTO, and the 

LTOs for single engine helicopters in 2011 were 908,654. 

ESingle = EFSingle / 2000 × LTOSingle

E = 0.6846/2000 × 908,654

E = 217.72 tons of NOx

No monthly helicopter data were identified in this effort; therefore it was assumed that 

activity was consistent through out the year therefore the annual emission estimates were 

temporally apportioned to individual months equally (i.e., 8.33%).

Helicopter emissions were assigned to lease blocks (USDOI, BOEM 2013c) with active 

platforms that have heliports (Figure 6-3), as most of the emissions associated with support 

helicopters occurs while the craft is near or at the platform. Spatial allocation of helicopter 

emissions was made using the equation below:

EHi = EH × (PHi/PHT)

where:

EHi = Support helicopter emissions associated with lease block i (tons)

EH = Total helicopter emissions (tons)

PHi = Number of platforms with heliports in lease block i

PHT = Total number of platforms with heliports

100
Figure 6-3. Location of active platforms with heliports

6.1.5 Support Vessels

Support vessels include crew boats that transport workers to and from work sites, supply 

vessels that carry supplies to offshore sites, and tug and tow boats that transport heavy equipment 

and supplies. 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.

Support vessel population data were derived from AIS data. The AIS data included 682 

offshore oil and gas platform support vessels and associated vessel characteristics data including 

main engine power rating. Unfortunately, the time-stamped AIS data had data gaps and other 

issues that complicated accurate calculation of annual hours of operation. As a result, it was 

assumed that the support vessels operated in federal waters 70% of the time. For the remaining 

30% of the time, these vessels are in state waters for refueling, loading supplies and equipment, 

unloading materials from the platforms, and for engine maintenance and repair activities. These 

operating assumptions result in 6,132 annual hours of operation in federal waters per vessel. Of 

these hours in federal waters, it was estimated that 85% of the time is spent at sea underway and 

15% of the time is spent idling adjacent to the platform. Regulations require that support vessels 

cannot tie-up to platforms; instead, they idle nearby while offloading or loading cargo (McGill 

2006).

Offshore support vessel load factors were provided by the U.S. Coast Guard National 

Offshore Safety Advisory Committee (McGill 2006). These load factors vary, with most of the 

time spent at 80% load while at-sea underway, and 10% load while idling adjacent to the 

platform.

101
The vessel population, engine kW rating, average hours of operation and typical load factor 

for the two modes (i.e., underway and at-sea idling) were used to calculate the total annual kWhours associated with support vessels operate in federal waters (Table 6-14).

Table 6-14. Support vessel census, kW rating, and annual hours of operation

Vessel Namea Call Sign Main kW Aux kW kW-HR

AARON S MCCALL WDF5812 10,247 1,025 62,834,604

ABDON CALLAIS WCY6640 1,175 745 7,205,100

ABIGAIL CLAIRE WDC7550 2,942 745 18,040,344

ABIGAIL RICHE WDE3336 1,492 300 9,148,944

ACCARDO WDD6845 4,848 485 29,727,936

ACO ARTHUR A FORET WDE4812 1,940 745 11,896,080

ACO DODIE LORRAINE WDF9818 1,174 117 7,198,968

ACO ISAURE BIENVENU WDD9103 1,174 117 7,198,968

ACO JESSICA MOORE WDF7317 2,849 1,820 17,470,068

ACO KEITH DUGGAN WDD5913 7,452 745 45,695,664

ACO LANDRY A GALIANO WDF2329 2,237 117 13,717,284

ACO TOM-BIENVENU WDD3253 1,940 745 11,896,080

ADA B CALLAIS WDC9102 7,452 745 45,695,664

ADAMS CHALLENGE 2BQX7 10,400 139 63,772,800

ADAMS VISION C6YG5 8,632 863 52,931,424

ADRIATIC WDD7795 1,250 139 7,665,000

AEGEAN WDD9236 1,268 139 7,775,376

AET DISCOVERY WDE4530 1,653 139 10,136,196

AET HARRIS WDE4530 1,653 165 10,136,196

AET INNOVATOR WDF9351 2,087 204 12,797,484

AIDEN MITCHEL WDB4507 1,029 103 6,309,828

AKIRA CHOUEST WCV3741 8,049 1,500 49,356,468

ALEX CHOUEST WCZ2532 11,186 1,119 68,592,552

ALEX G MCRAE WDE9824 1,492 139 9,148,944

ALEX GROS II WDD2670 1,250 73 7,665,000

ALIANCE IV WDF7374 805 81 4,936,260

ALICE G MCCALL WDE4782 6,715 73 41,176,380

ALICE G MCCALL WDE4782 6,715 139 41,176,380

ALICIA SUE WDC6370 820 82 5,028,240

AL-KAT WDF7462 3,282 313 20,125,224

ALLIANCE III WDF7376 805 81 4,936,260

ALLIANCE IV WDF7374 805 81 4,936,260

ALLIE CHOUEST KFHA 4,920 745 30,169,440

ALLIED ELEVATOR 2 WDD2679 447 45 2,741,004

ALLISON WAS6653 2,648 745 16,237,536

102
Vessel Namea Call Sign Main kW Aux kW kW-HR

ALYSSA CHOUEST WDF9511 5,421 139 33,241,572

AM. CONSTITUTION HP2029 5,884 139 36,080,688

AMBER WDB5838 4,920 745 30,169,440

AMERICAN TRIUMPH WDC7837 1,125 139 6,898,500

AMERICAN VICTORY WDC7838 1,125 745 6,898,500

AMETHYST WDA9537 1,386 139 8,498,952

AMPOL RECOVERY WDC6338 492 49 3,016,944

AMPOL RESPONDER WDC7028 634 63 3,887,688

ANDREA CHOUEST WDE4574 4,920 139 30,169,440

ANGELLE CENAC WDC2768 895 89 5,488,140

ANNA M WDD3952 3,972 139 24,356,304

APOLLO TIDE HQXJ5 1,653 165 10,136,196

ARCTIC WDF2734 1,268 127 7,775,376

ASHTON T WDIJ 1,141 114 6,996,612

BAILEY JANICE WDC8399 52,457 5,246 3.22E+08

BASTIAN BAY WDE3709 984 98 6,033,888

BAYOU BEE WDE9861 2,982 900 18,285,624

BAYOU STATE XCZ7836 4,848 485 29,727,936

BEE STING WDF2238 2,982 900 18,285,624

BERTHA D WDD2172 1,268 745 7,775,376

BETH E CHERAMIE WDE6767 1,940 745 11,896,080

BETTY PFANKUCH WDF7129 7,299 730 44,757,468

BEVERLY F WCX2731 2,001 139 12,270,132

BJ DISCOVERY WCY2843 2,515 139 15,421,980

BLANCHE CALLAIS WDB8917 1,492 198 9,148,944

BLUE DOLPHIN WDE9988 5,421 139 33,241,572

BLUE DOLPHIN WDE9988 5,421 745 33,241,572

BLUE TARPON WNSD 5,421 139 33,241,572

BLUE TARPON WNSD 5,421 745 33,241,572

BOA SUB C 9HUC8 24,720 139 1.52E+08

BOTRUC 33 WDC3314 2,339 745 14,342,748

BOTRUC 39 WDB9134 2,386 139 14,630,952

BOTRUC 39 WDB9134 2,386 745 14630952

BOTRUC 41 WNSG 2,982 328 18,285,624

BOTRUC19 WDC3295 1,368 73 8,388,576

BRAWLER WDC7608 2,248 139 13,784,736

BRAXTON PERRY WDC6474 507 51 3,108,924

BRAZOS EXPRESS WRB4886 1,368 139 8,388,576

BRODY PAUL WDD2761 679 68 4,163,628

103
Vessel Namea Call Sign Main kW Aux kW kW-HR

BROOK DANOS WDC8122 477 48 2,924,964

BRUTUS WBS4624 895 89 5,488,140

BULL SHARK WDC8201 746 75 4,574,472

BUMBLE BEE WRAJ 2,982 745 18,285,624

BUNNY BORDELON WDA5139 1,103 139 6,763,596

BUSY BEE WDE9328 3,432 900 21,045,024

BYWATER LUDLOW WDD7098 1,030 103 6,315,960

C ACCLAIM XCKH7 1,884 73 11,552,688

C CHALLENGER WCX7953 2,515 745 15,421,980

C CONTENDER WCY2600 2,515 745 15,421,980

C FIGHTER WDE3604 4,920 139 30,169,440

C LEADER WDB2505 4,920 745 30,169,440

C LEADER WDB2505 4,920 139 30,169,440

C LEGEND WDB3410 4,920 139 30,169,440

C LIBERTY WDB7959 5,296 745 32,475,072

C MICHAEL CALLAIS WCY6639 1,175 745 7,205,100

C TRUC 7 WDA5890 2,354 354 14,434,728

C TRUC NO 5 WDA5888 3,297 258 20,217,204

C TRUC NO 8 WDB7934 2,354 264 14,434,728

C_TRUCNO4 WDA5887 2,868 258 17,586,576

CADE CANDIES WKBG 9,400 269 57,640,800

C-ADMIRAL YJRL3 1,884 188 11,552,688

C-AGGRESSOR YJRK3 1,884 188 11,552,688

CAITLYN A CALLAIS WDD4558 1,940 745 11,896,080

CAL DIVER I WYT8527 2,574 139 15,783,768

CAL DIVER II WTS2811 1,368 139 8,388,576

CAL DIVER IV WDB6118 1,061 139 6,506,052

CALLAIS EXPLORER WDE6977 1,492 745 9,148,944

CALLAIS PROVIDER WDF3277 1,268 350 7,775,376

CALLAIS SEARCHER WDF5618 1,289 350 7,904,148

CALVIN BAYNE WCX9824 2,796 745 17,145,072

CANDY BARREL WDD4859 1,386 139 8,498,952

CANDY COUNTER WDD8297 1,386 139 8,498,952

CANDY FACTORY WDE2194 3,972 100 24,356,304

CANDY LAND WDE5133 3,972 100 24,356,304

CAPE KALA KANE WDE9703 2,207 745 13,533,324

CAPT JOHN E GRAHAM WDC2329 7,452 745 45,695,664

CAPT LEVERT WDA7416 3,972 745 24,356,304

CAPT.GLENN WDA7528 3,972 139 24,356,304

104
Vessel Namea Call Sign Main kW Aux kW kW-HR

CAPT.J.RIMES WDC6696 507 51 3,108,924

CAPTAIN TIDE WDB3662 1,368 224 8,388,576

CAPTAIN WHITEY GROS WDE8889 3,748 745 22,982,736

CARL F. THORNE WDB3673 9,032 73 55,384,224

CARLENE MCCALL WDF4273 6,711 870 41,151,852

CAROL CHOUEST WDD5159 4,920 745 30,169,440

CAROLINE G WDC3113 1,324 139 8,118,768

CAROLINE MORRISON WDC8384 1,368 139 8,388,576

CAROLYN CHOUEST WCP5628 8,386 139 51,422,952

CASPIAN WDF4690 1,268 127 7,775,376

C-CAPTAIN WCW9590 2,515 139 15,421,980

C-CARRIER WCY2601 2,515 745 15,421,980

C-CHALLENGER WCX7953 2,515 745 15,421,980

C-CHARIOT WCX7952 2,515 139 15,421,980

CCLIPPER WCX6887 2,515 745 15,421,980

C-COMMANDER WCX6345 1,118 139 6,855,576

CECELIA WDF8451 2,501 139 15,336,132

CELENA CHOUEST WDD9072 4,920 139 30,169,440

C-EXPRESS WCZ2530 2,515 254 15,421,980

C-FIGHTER WDE3604 4,920 139 30,169,440

C-FREEDOM WDE2596 4,920 745 30,169,440

CGBM 101 Missing 1,653 0 10,136,196

CGBM 101 Missing 2,515 0 15,421,980

CGBM 102 Missing 1,653 0 10,136,196

CGBM 102 Missing 1,884 0 11,552,688

CGBM 102 Missing 4,631 198 28,397,292

CGBM 104 Missing 1,268 0 7,775,376

CGBM 104 Missing 1,653 0 10,136,196

CGBM 104 Missing 2,501 0 15,336,132

CHANTISE G WDA3676 52,478 5,248 3.22E+08

CHARGER WDF7227 1,214 745 7,444,248

CHARGER WDD4671 1,214 121 7,444,248

CHARLES M CALLAIS II WDE9170 1,940 745 11,896,080

CHARLIE BYCHURCH WDE8486 1,250 745 7,665,000

CHARTRES WDD3652 4,559 745 27,955,788

CHASE WDF7418 3,533 139 21,664,356

CHERAMIE BOTRUC 34 WDC3315 2,339 745 14,342,748

CHERAMIE BOTRUC 40 WNAO 2,982 139 18,285,624

CHERAMIE BOTRUC22 WDC3313 1,368 745 8,388,576

105
Vessel Namea Call Sign Main kW Aux kW kW-HR

C-HERO WDA9706 3,800 745 23,301,600

CHLOE CANDIES WXXP 4,969 139 30,469,908

CHRIS R WDD9632 895 89 5,488,140

CHRISTIAN CHOUEST WDC7173 4,920 492 30,169,440

CHRISTOPHER CALLAIS WDA6993 1,940 198 11,896,080

CINDY BROWN TIDE KCBE 5,050 139 30,966,600

CLAIRE CANDIES WDE4319 7,140 232 43,782,480

CLAIRE M CALLAIS WDB8162 2,351 510 14,416,332

CLARA_B WBR6261 1,434 73 8,793,288

CLAY ELLA WDB7446 1,767 745 10,835,244

C-LEGACY WDB6654 4,920 745 30,169,440

C-LIBERTY WDB7959 5,296 139 32,475,072

CLIPPER WDF7572 883 745 5,414,556

COASTAL MARINER WDF4037 843 84 5,169,276

COLIN B MCCALL WDB5803 3,972 139 24,356,304

CONTENDER WDD2409 895 89 5,488,140

CORCOVADO WDE6916 5,421 139 33,241,572

COREY CAL LAIS WCY6638 1,193 119 7,315,476

C-PERFORMER WCZ6248 2,530 139 15,513,960

C-PROMOTER WCZ5472 2,530 254 15,513,960

CRAIG MICHAEL WDF7392 507 51 3,108,924

CROSBY SUN WDA3843 730 73 4,476,360

C-ROVER WCZ4365 2,515 745 15,421,980

C-ROVER WCZ4365 2,515 745 15,421,980

C-TRUC 6 WDA5889 2,354 354 14,434,728

D-32 STEVEN WAA9413 52,619 5,262 3.23E+08

DAKOTAH BILL WDD2009 2,207 139 13,533,324

DAMON B. BANKSTON WHDB 7,505 745 46,020,660

DANCER WDC7846 2,412 139 14,790,384

DANIELLE CALLAIS WDE2794 2,315 745 14,195,580

DANTE KUGY 4,920 246 30,169,440

DAVID ADAMS WDC7610 870 87 5,334,840

DAVID B WDE7890 895 89 5,488,140

DEEP BLUE RESPONDER WBO8585 1,881 139 11,534,292

DEEP SEA CHAMPION WDA9673 1,368 139 8,388,576

DEEPSTIM BRASIL I WDSQ 5,421 500 33,241,572

DELTA RUNNER WDA6057 4,119 403 25,257,708

DIAMOND BACK WDE6773 298 30 1,827,336

DICTATOR WDF7930 4,851 150 29,746,332

106
Vessel Namea Call Sign Main kW Aux kW kW-HR

DIONNE CHOUEST WDC5617 4,920 139 30,169,440

DIP WDF2482 477 48 2,924,964

DISCOVERY WDF8208 1,837 745 11,264,484

DMO PAPPY WDF8105 2,485 745 15,238,020

DRAKE WDC4654 883 139 5,414,556

DRONE BEE WDBE 2,982 900 18,285,624

DRY TORTUGAS Error 1,837 184 11,264,484

DUSTIN_DANOS WDE9077 1,342 134 8,229,144

DUTCHMAN WDE9761 5,372 403 32,941,104

DWIGHT S. RAMSAY WDF6858 7,299 139 44,757,468

DYLAN JOHN WCX2736 2,574 139 15,783,768

EDIE LAB WDF9375 2,574 139 15,783,768

ELIZABETH A. MCCALL WDB7558 4,028 139 24,699,696

ELIZABETH A. MCALL WDB7558 4,028 139 24,699,696

ELLA G WDE9523 5,421 139 33,241,572

ELSA LEIGH WDB3416 2,207 745 13,533,324

EMILY ANN WDF8996 1,368 161 8,388,576

EMILY BORDELON WDE5150 716 72 4,390,512

EMILY CANDIES WDC5786 4,784 227 29,335,488

EMILY G WDB3034 1,250 745 7,665,000

ENTERPRISE 1 WDE2858 1,368 139 8,388,576

EPIC EXPLORER WDD4415 1,653 139 10,136,196

EPIC SEAHORSE WCZ9485 1,653 139 10,136,196

ESPLANADE WDD3650 4,559 321 27,955,788

FAST BANDIT WDA5724 1,386 139 8,498,952

FAST BULLET WDA8488 1,386 139 8,498,952

FAST CAJUN WDD5116 4,854 139 29,764,728

FAST GIANT WDF6212 5,999 540 36,785,868

FAST GOLIATH WDF7625 5,999 540 36,785,868

FAST MAMMOTH WDF9442 5,999 540 36,785,868

FAST SAILOR WCX7184 4,854 492 29,764,728

FAST SCOUT WDE3301 4854 5,246 29,764,728

FAST SKIPPER WDE6367 4,854 139 29,764,728

FAST TEAM WDE6231 5,999 139 36,785,868

FAST TRACK WDE4610 4,996 139 30,635,472

FAST VIKING WDE9537 5,399 139 33,106,668

FATHERJOHNKELLER WDD3254 1,268 127 7,775,376

FOX WDC7535 1,618 119 9,921,576

GALAXIE V7VR6 2,868 300 17,586,576

107
Vessel Namea Call Sign Main kW Aux kW kW-HR

GARY CHIASSON WDF2244 403 40 2,471,196

GARY CHOUEST WCY7287 2,868 139 17,586,576

GAVEA WDE5320 5,421 139 33,241,572

GAVEA WDE5320 5,421 139 33,241,572

GAYLA GRAHAM WDD9662 5,369 73 32,922,708

GENIE LAB WPAG 3,842 1,275 23,559,144

GERTIE C WDE8134 1,653 745 10,136,196

GIS BLAKLEY WDF9706 2,001 139 12,270,132

GIS-VAYDA WDF9376 1,175 73 7,205,100

GIS-VAYDA WDF9376 1,175 139 7,205,100

GLOBAL ORION YJVL7 9,499 139 58,247,868

GLOBAL PIONEER WCW9255 2,939 139 18,021,948

GLOMAR PRIDE HP8229 1,386 139 8,498,952

GLORIA B CALLAIS WDB5625 2,315 510 14,195,580

GLORIA B CALLAIS WDB5625 2,386 239 14,630,952

GRAND SLAM WDD9838 921 92 5,647,572

GRANT WDE2204 2,248 139 13,784,736

GRANT CANDIES WDE5747 7,899 139 48,436,668

GRANVILLE C MCCALL WDB5848 6,619 139 40,587,708

GREATER SCOTT WDE2875 3,580 139 21,952,560

GREEN PROVIDER WDD3558 1,809 745 11,092,788

GREG DANOS WDA6017 1,331 73 8,161,692

GULF GRACE WDA8201 1,386 139 8,498,952

GULF HERO WDE7093 3,033 139 18,598,356

GULF HONOR WDC3481 4,028 139 24,699,696

GULF INFLUENCE WDE9705 1,653 745 10,136,196

GULF MAJESTY WDC7277 3,819 73 23,418,108

GULF PRINCESS WDE7880 5,369 170 32,922,708

GULF PROTECTOR WDD4853 5,369 139 32,922,708

GULF QUEST WDE6227 1,492 157 9,148,944

GULF SPIRIT WDB4859 3,972 139 24,356,304

GULF TIGER WNSE 5,050 505 30,966,600

GULF VICTORY WDA9647 730 73 4,476,360

GULF WIND WDB5836 1,368 139 8,388,576

GUY C. WDD6387 1,029 103 6,309,828

HANNAH CHOUEST WDD4129 4,920 139 30,169,440

HANNAH RAY WDE4972 4,119 139 25,257,708

HARLAN S MCCALL WDD7531 5,034 139 30,868,488

HARRY JOSEPH WDB7449 994 745 6,095,208

108
Vessel Namea Call Sign Main kW Aux kW kW-HR

HARVEY EXPLORER WDB4217 3,372 745 20,677,104

HARVEY PROVIDER WDB2506 3,324 745 20,382,768

HARVEY CARRIER KRTQ 3,650 850 22,381,800

HARVEY DISCOVERY WDC9728 3,494 139 21,425,208

HARVEY SPIRIT WDD4830 4,516 139 27,692,112

HARVEY SUPPLIER WDAW 4,579 745 28,078,428

HARVEY SUPPORTER WDF9689 7,299 500 44,757,468

HERCULES WDC5161 57,833 5,783 3.55E+08

HILDA LAB WKDT 3,839 1,275 23,540,748

HOLLIE MARIE WDC2042 1,044 104 6,401,808

HOLLIE MARIE WDC2042 1,044 104 6,401,808

HOMERUN WDE2977 1,386 139 8,498,952

HONDO RIVER WCZ2334 4,231 745 25,944,492

HORIZON RUNNER WDE4930 4,701 160 28,826,532

HOS ACHIEVER YJVG4 11,880 139 72,848,160

HOS BEAUFORT WDD9064 3,091 298 18,954,012

HOS BRIMSTONE WDA8419 3,722 73 22,823,304

HOS BYRD WDD9065 3,091 745 18,954,012

HOS CENTERLINE KYBZ 8,399 1,275 51,502,668

HOS CORAL WDE6625 5,050 1,420 30,966,600

HOS CORNERSTONE WCZ5505 2,942 745 18,040,344

HOS DAKOTA WCY8949 2,942 294 18,040,344

HOS DAKOTA XCRF7 2,942 294 18,040,344

HOS DAVIS WDD9066 3,091 745 18,954,012

HOS DOMINATOR WDA6788 3,310 745 20,296,920

HOS EXPLORER WDB4530 7,452 745 45,695,664

HOS EXPRESS WDB4532 2,868 745 17,586,576

HOS INNOVATOR WDA4032 3,372 745 20,677,104

HOS IRON HORSE YJQR3 11,536 139 70,738,752

HOS LODE STAR WDE7090 2,485 73 15,238,020

HOS MYSTIQUE WDE3118 4,700 139 28,820,400

HOS NORTH STAR WDE3119 2,982 1,020 18,285,624

HOS PINNACLE WDF2604 4,700 139 28,820,400

HOS PIONEER WDB4533 3,432 298 21,045,024

HOS POLESTAR WDE3121 2,985 1,020 18,304,020

HOS RIDGEWIND WDA6136 4,988 139 30,586,416

HOS SANDSTORM WDA8997 6,780 506 41,574,960

HOS SHOOTING STAR WDE3120 2,985 745 18,304,020

HOS SILVER ARROW WDE8275 5,050 298 30,966,600

109
Vessel Namea Call Sign Main kW Aux kW kW-HR

HOS SILVERSTAR WDB5655 3,310 745 20,296,920

HOS STORMRIDGE WDA8996 4,987 745 30,580,284

HOS SUPER H WCY8159 2,942 745 18,040,344

HOS SWEET WATER WDE8276 2,942 1,050 18,040,344

HOS THUNDERFOOT WCY8948 2,942 745 18,040,344

HOS WILDWING WDF2606 4,700 447 28,820,400

HOS WINDANCER WDF2605 4,700 745 28,820,400

IBERVILLE WDD3651 4,559 139 27,955,788

IMILOA WDC7061 1,653 745 10,136,196

INDEPENDENCE WDA6136 4,988 139 30,586,416

INEZ EYMARD WDF3099 447 45 2,741,004

INFANT JESUS PRAGUE WDF2951 2,237 117 13,717,284

INGRID WDF2598 4,920 139 30,169,440

INSPIRATION WCX7141 2,515 745 15,421,980

INT L DIAMOND WDD8333 895 89 5,488,140

INT.__TITAN WDD6675 895 89 5,488,140

INTL ANGEL WDF6119 4,848 485 29,727,936

INT'L BRAVE WDF5644 1,454 145 8,915,928

INT'L FALCON WDD7424 895 89 5,488,140

INT'L FORCE WDF3679 447 45 2,741,004

INTL GENERAL WDD9533 925 92 5,672,100

INT'L HUNTER WDD9571 895 89 5,488,140

INT'L QUEEN WDF5514 4,848 485 29,727,936

INT'L RAIDER WDE9276 702 139 4,304,664

INTL SEARCHER WDD4667 895 89 5,488,140

INTL THUNDER WDD6674 1,386 139 8,498,952

INT'L TRADITION WDD6853 895 89 5,488,140

INT'L TROOPER WDD8509 895 89 5,488,140

INTL VOYAGER WDD6746 1,386 139 8,498,952

IPANEMA WDE7991 5,999 139 36,785,868

IRENE B. WDC8280 1,268 745 7,775,376

ISAAC J CALLAIS WDA8444 1,940 198 11,896,080

ISLAND ENFORCER YJRG2 20,123 2,012 1.23E+08

ISLAND PIONEER LDJN 10,441 1,044 64,024,212

J.F.JETT WDB9235 2,868 499 1,7586,576

JA/SON WDE2622 883 139 5,414,556

JAMBON SUPPLIER WDC9502 1,703 153 10,442,796

JAMIE G WSA6608 1,368 745 8,388,576

JANSON R GRAHAM WDF4127 5,700 570 34,952,400

110
Vessel Namea Call Sign Main kW Aux kW kW-HR

JASON K MCCALL WDA4730 4,965 139 30,445,380

JEAN GILBERT WDB7444 1,767 745 10,835,244

JEAN PIERRE LAB WDE9670 3,788 1,275 23,228,016

JEFFREY D WDD3237 1,368 745 8,388,576

JENNY MCCALL WDC3101 5,372 139 32,941,104

JESSICA LYNSIE WDC4480 895 89 5,488,140

JOANNE MORRISON WDE6218 2,207 139 13,533,324

JOE GRIFFIN WDF3170 5,421 745 33,241,572

JOEL PAUL WDC 286 1,940 745 11,896,080

JOHN B MARTIN MCCALL WCY7082 5,958 139 36,534,456

JOHN G MCCALL WDD4719 6,619 580 40,587,708

JOHN P LAB WCY9737 2,942 340 18,040,344

JONATHAN KING BOYD WDF7273 4,848 485 29,727,936

JOSEPH G WDF9637 5,369 537 32,922,708

JOSEPHINE K MILLER WDE9978 883 745 5,414,556

JOSHUA CANDIES WJCD 1,386 269 8,498,952

JUDY FRANCES WDF2927 2,207 745 13,533,324

JUSTIN CALLAIS WCZ5803 1,767 198 10,835,244

K MARINE 22 WDD5117 2,315 139 14,195,580

K MARINE 7 WDA6850 2,574 745 15,783,768

KARLA F WDE3008 1,268 139 7,775,376

KATRINA FAGAN WDA8008 3,542 745 21,719,544

KELLY MORRISON WDC7532 1,678 139 10,289,496

KERRY GROS WDE8301 1,368 745 8,388,576

KESTREL YJUW5 7,054 705 43,255,128

KIM B WDD8579 870 87 5,334,840

KINGFISHER YJVA3 3,198 73 19,610,136

KLINE DANOS WDC4083 2,207 745 13,533,324

K-MARINE VI WDC8531 2,574 73 15,783,768

KNOCKOUT WDE2978 7,452 745 45,695,664

KOBE CHOUEST WDB9562 4,920 139 30,169,440

KOLBY D WDD3077 1,030 139 6,315,960

KRISTIN FAGAN WCY2612 2,796 745 17,145,072

KRISTIN FAYE WDD2885 343 34 2,103,276

KURT DAVID WDA3186 1,368 139 8,388,576

KYLIE D WDD3078 1,491 149 9,142,812

KYLIE WILLIAMS WDD5998 2,460 745 15,084,720

L\B MR. ALAN WDC2932 1,119 112 6,861,708

LA LOUSIANA WDC8128 1,653 745 10,136,196

111
Vessel Namea Call Sign Main kW Aux kW kW-HR

LACHNEY TIDE WDF4527 1,368 745 8,388,576

LADY MADI WDB6145 2,059 206 12,625,788

LADY OF LA SALETTE WDF5883 2,852 188 17,488,464

LAUREN LACOSTE WDD9102 1,250 198 7,665,000

LEADER WDD2064 895 89 5,488,140

LEE ADAMS WDC7434 679 68 4,163,628

LEEZA RENED' WDE3011 2,207 745 13,533,324

LINDA WDB7799 941 745 5,770,212

LOOP LIFTER WYQ7524 1,653 139 10,136,196

LOOP SECURITY WCX3304 883 139 5,414,556

LOUISIANA RESPONDER WBO8576 2,237 224 13,717,284

LOUISIANA RESPONDER WBO8576 2,237 139 13,717,284

LUCAS JOHN WDB6767 1,368 139 8,388,576

LUKE THOMAS WDE7707 969 426 5,941,908

LYMAN MARTIN WNSA 4,920 139 30,169,440

MACY LYN WDD9845 343 34 2,103,276

MADISON WDC6635 895 89 5,488,140

MAHI MAHI WDC6569 597 60 3,660,804

MAKO WDD7791 761 100 4,666,452

MAKO WDE3476 5,372 139 32,941,104

MALOY.G WYB7318 52,464 5,246 3.22E+08

MANRESA WDD5766 1,492 300 9,148,944

MARC C WDC9503 895 89 5,488,140

MARCELLE BORDELON WDC7864 1,103 139 6,763,596

MARIE ELISE WSAC 5,050 850 30,966,600

MARY DIANE MCCALL WDC8407 671 67 4,114,572

MASCO 6 WSF6561 895 89 5,488,140

MASCO ENDEAVOR WDC2519 730 73 4,476,360

MASON BEE WMBY 3,432 900 21,045,024

MATT WCW8997 895 89 5,488,140

MATTHEW D MCRAE WDF5979 1,268 127 7,775,376

MEG L SKANSI WDDL 1,250 139 7,665,000

MELINDA B. ADAMS WCZ2666 1,125 745 6,898,500

MIA WDD2870 4,920 139 30,169,440

MIA MALOY WDC7436 895 89 5,488,140

MIDNIGHT STAR YJXM9 5,296 139 32,475,072

MIKE HOOKS WDE9086 4,848 485 29,727,936

MISS AMANDA WCV5696 2,059 139 12,625,788

MISS ANGIE WDF4652 1,386 139 8,498,952

112
Vessel Namea Call Sign Main kW Aux kW kW-HR

MISS BET WDB7803 1,500 139 9,198,000

MISS DARLENE WCY6597 2,574 139 15,783,768

MISS EMMA JO WDD3627 1,492 139 9,148,944

MISS FAYE WDB7810 1,500 150 9,198,000

MISS FLO WDB7986 1,061 139 6,506,052

MISS GINGER WDC9604 1,653 139 10,136,196

MISS LILLY WDC4352 1,324 745 8,118,768

MISS LINDA LEE WDE5415 4,119 139 25,257,708

MISS MEGAN WDC7706 1,434 198 8,793,288

MISS PAM YYT4728 1,500 150 9,198,000

MISS PEARL WCV5666 2,324 73 14,250,768

MISS PEGGY ANN WCV5664 1,500 139 9,198,000

MISS SAIDY WDB7056 1,912 499 11,724,384

MISS WYNTER WDD9362 1,500 139 9,198,000

MISSISSIPPI RESPONDE WBO8584 2,237 139 13,717,284

MONICA ANN WDE7047 5,050 139 30,966,600

MONICA W CALLAIS WDF5042 1,883 1,820 11,546,556

MOTHER TERESA WDC6424 1,250 745 7,665,000

MOTHER TERESA WDC6424 1,250 745 7,665,000

MR ALEX WDE3593 537 54 3,292,884

MR DINO WDF4396 870 87 5,334,840

MR JOE WDE8716 686 69 4,206,552

MR LANNIE WDB3903 7,452 745 45,695,664

MR LIONEL WDE4348 1,492 300 9,148,944

MR LLOYD WDB9843 4,413 139 27,060,516

MR SEAMAN WCZ3468 3,972 139 24,356,304

MR VICK WDB5123 7,452 745 45,695,664

MR. ANDRE WDC8896 597 60 3,660,804

MR. COLBY WDE2343 1,103 745 6,763,596

MR. J.O. WDC5062 4,475 73 27,440,700

MR. JESSIE WCX6476 2,515 139 15,421,980

MR. MURVIN WDE2316 2,248 139 13,784,736

MR. SIDNEY WKAH 4,920 139 30,169,440

MR. SIDNEY WKAH 4,920 745 30,169,440

MR.HENRY WDB2323 1,386 139 8,498,952

MR.JAKE WDF4254 2,427 139 14,882,364

MS ADRIENNE WDC2869 2,427 139 14,882,364

MS ALISSA WDC8737 895 89 5,488,140

MS JESSICA WDE8982 3,972 139 24,356,304

113
Vessel Namea Call Sign Main kW Aux kW kW-HR

MS JILL WDE9603 5,369 537 32,922,708

MS JOY WCY2036 3,972 139 24,356,304

MS JOYCE WDF4282 1,066 150 6,536,712

MS MADISON WDA5301 917 92 5,623,044

MS MARY WDF5767 1,386 139 8,498,952

MS MEGGIE WDF9903 1,250 745 7,665,000

MS MELISSA WDF5504 1,175 198 7,205,100

MS PEARL WDB6990 730 73 4,476,360

MS RAMONA WDB4731 1,386 139 8,498,952

MS RUBY WCZ9439 3,972 139 24,356,304

MS TAMI WDD5843 1,193 119 7,315,476

MS TAYLOR WDC9501 2,051 205 12,576,732

MS VIRGIE WDE6282 4,920 139 30,169,440

MS YVONNE WDF6477 5,999 470 36,785,868

MS. LAUREN WDE7317 5,296 745 32,475,072

MS. MARY WCX2042 1,066 73 6,536,712

MS. MARY WCX2042 1,066 745 6,536,712

MS. MEGAN WDE3441 1,044 104 6,401,808

MS. JANE WAS5900 52,466 5,247 3.22E+08

MS. JOLIE WDB3176 2,942 73 18,040,344

MS. KRISTIE WDE5516 5,969 139 36,601,908

MS. LISA WDD3043 52,464 5,246 3.22E+08

MS. MAGGIE WCZ7255 1,653 745 10,136,196

MS. MIA WDD7039 4,848 485 29,727,936

MS. MONICA WDC2757 1,846 185 11,319,672

MS. NANCY WDB6287 4,413 139 27,060,516

MSROBIN WCT9171 1,703 73 10,442,796

MYSTIC VIKING C6HC5 3,972 73 24,356,304

MYSTIC VIKING C6HC5 3,972 139 24,356,304

NICHOLAS C WDE8986 1,175 745 7,205,100

NICHOLAS P CALLAIS WDF3930 1,883 188 11,546,556

NICK L SKANSI WOEA 1,250 745 7,665,000

NICKI CANDIES WDE5761 7,140 232 43,782,480

NOAH J CALLAIS WDB5266 1,193 119 7,315,476

NOAH J CALLAIS WDB5266 1,193 119 7,315,476

NOAH J CALLAIS WDB5266 3,530 745 21,645,960

NOONIE G WDC9901 1,029 103 6,309,828

NORBERT BOUZIGA WDF2074 4,922 139 30,181,704

NORMAND COMMANDER LNPW3 7,499 139 45,983,868

114
Vessel Namea Call Sign Main kW Aux kW kW-HR

NORMAND FORTRESS LIKW3 7,499 745 45,983,868

NORMAND PACIFIC 2EKX3 15,999 1,600 98,105,868

NRC ADMIRAL WCC8506 883 139 5,414,556

NRC ENERGY WDB5151 883 139 5,414,556

NRC QUEST WDF7619 1,250 127 7,665,000

OCEAN CARRIER YJRH8 5,999 139 36,785,868

OCEAN INSPECTOR WDB7674 1,250 127 7,665,000

OCEAN INTERVENTION WCY4505 4,709 139 28,875,588

OCEAN INTERVENTION 2 WCZ7505 2,985 139 18,304,020

OCEAN INTERVENTION 3 LMWK 11,408 139 69,953,856

OCEAN PATRIOT WBAH 5,440 139 33,358,080

OCEAN PROJECT WDF6447 3,530 1,700 21,645,960

OCEAN QUEST WDB2700 1,175 280 7,205,100

ODYSSEA CHAMPION WDE6600 3,432 745 21,045,024

ODYSSEA DARWIN WDE2876 1,940 745 11,896,080

ODYSSEA DEFENDER WDE7022 3,432 745 21,045,024

ODYSSEA DILIGENT WDE6273 1,250 300 7,665,000

ODYSSEA EXPLORER WDD4728 1,103 745 6,763,596

ODYSSEA FORCE WDF8169 1,492 745 9,148,944

ODYSSEA GOLD WDE8097 2,849 1,500 17,470,068

ODYSSEA RANGER WDD5847 1,175 745 7,205,100

ODYSSEA TITAN WDF8168 2,663 745 16,329,516

ODYSSEA TREK WDD6220 806 745 4,942,392

ODYSSEA*DIAMOND* WDE4687 2,999 745 18,389,868

OLIVIA RAE WDD2252 2,460 139 15,084,720

OLYMPIC CHALLENGER LAEY7 15,150 139 92,899,800

OLYMPIC INTERVENTION LAFQ3 10,000 139 61,320,000

OLYMPIC TRITON LADM3 10,020 1,002 61,442,640

OP CALLAIS WDB6392 1,492 745 9,148,944

ORLEANS WDD3648 4,559 745 27,955,788

OSV GLORIA MARIA WDE6549 1,119 112 6,861,708

PAO DE ACUCAR WDE8602 4,920 745 30,169,440

PAT TAYLOR WDD3152 3,372 745 20,677,104

PAUL CALLAIS WCY6856 1,175 139 7,205,100

PAULA MCCALL WDE8306 6,715 320 41,176,380

PAULINE T WCS2857 1,044 104 6,401,808

PENNY F WDE3007 1,268 745 7,775,376

PENNY F WDE3007 1,268 139 7,775,376

PETER CALLAIS WCY7925 1,193 119 7,315,476

115
Vessel Namea Call Sign Main kW Aux kW kW-HR

PEYTON CANDIES WTAF 7,452 269 45,695,664

PHILIP ALAN MCCALL WDB7424 5,958 139 36,534,456

PIPER WDE6779 1,007 101 6,174,924

POPE BENEDICT XVI WDE6443 1,940 745 11,896,080

POPE JOHN PAUL II WDC7969 1,250 198 7,665,000

PORT EADS WDD9878 1,268 745 7,775,376

PREDATOR WDF6591 5,034 150 30,868,488

PRESIDENT TIDE WDF4522 1,728 745 10,596,096

Q4000 WDA6676 21,121 139 1.3E+08

QB WAM2522 895 89 5,488,140

QUEEN BEE WKIR 3,432 900 21,045,024

R J COCO MCCALL WDF6648 11,521 1,024 70,646,772

R.E.B. BORDELON WDC9776 477 48 2,924,964

R/V GEOEXPLORER WDA6456 1,379 139 8,456,028

R/V PERSISTENCE WDD3089 574 73 3,519,768

R\V RACHEL CARSON WDF9370 1,386 139 8,498,952

RACHEL CALLAIS WCZ7017 1,767 198 10,835,244

RACHEL CALLAIS WCZ7017 52,466 5,247 3.22E+08

RAM CHALLENGER WCX5838 2,560 745 15,697,920

RAM 7 WBN3003 507 51 3,108,924

RANA MILLER WDE7064 1,103 745 6,763,596

RANDALL B MCCALL WDB4219 5,369 139 32,922,708

RAYMOND M WDC4224 5,296 73 32,475,072

RED LAB WCY7791 2,942 340 18,040,344

REM FORZA LASA 6,957 745 42,660,324

REM POSEIDON C6YF2 9,698 139 59,468,136

REMORA WDC6572 671 67 4,114,572

RENE WDF4268 1,795 745 11,006,940

RESOLVE PIONEER WDD8846 4,289 139 26,300,148

RESPONSE RUNNER WDC4923 4,701 160 28,826,532

RMS CITATION WDD5362 1,767 139 10,835,244

RMS CITATION WDD5362 1,767 745 10,835,244

ROMANDA SUE WDB9492 671 67 4,114,572

ROSEANNA WDB3630 1,703 139 10,442,796

ROSITE G WDF8455 956 139 5,862,192

ROSS CANDIES WDF2225 9,400 269 57,640,800

ROSS CHOUEST WCW7550 8,093 139 49,626,276

ROXANNE B MCCALL WDB6977 3,972 139 24,356,304

ROYAL WDD3653 4,559 745 27,955,788

116
Vessel Namea Call Sign Main kW Aux kW kW-HR

RUSTY EYMARD WDB4289 2,985 745 18,304,020

RW ARMSTRONG WDE3706 984 98 6,033,888

RYAN CHOUEST WDC6796 2,515 745 15,421,980

SAILFISH WDD6170 5,296 139 32,475,072

SALLY B WDC6964 895 89 5,488,140

SANTEE WDF6486 3,001 139 18,402,132

SARAH BORDELON WDC7198 1,103 745 6,763,596

SEA ANGEL WDE5879 3,580 139 21,952,560

SEA BROOKE WDC3114 1,703 745 10,442,796

SEA CECILE WDC6244 1,703 745 10,442,796

SEA HORSE VI WDB7467 1,103 745 6,763,596

SEA LEGEND J8AA5 1,030 745 6,315,960

SEA SERVICE 1 WDF9972 1,491 149 9,142,812

SEA TROUT WDC6577 671 67 4,114,572

SEABULK NEBRASKA WDF9501 3,091 745 18,954,012

SEABULK WISCONSIN WCY6329 3,091 745 18,954,012

SEABULK ACADIA WCV2233 2,427 139 14,882,364

SEABULK CARMEN WDC3918 1,940 745 11,896,080

SEABULK KANSAS WDE4694 3,091 745 18,954,012

SEABULK ST CHARLES YYT4727 2,651 265 16,255,932

SEACOR CONQUEST WDA9650 3,091 745 18,954,012

SEACOR MADISON WDD5977 3,544 740 21,731,808

SEACOR PRIDE WDB7465 2,982 745 18,285,624

SEACOR QUEST WDB7813 1,250 125 7,665,000

SEACOR RELENTLESS WCZ6034 5,346 745 32,781,672

SEACOR RELIANT WCZ2533 5,346 745 32,781,672

SEACOR RIGOROUS WCZ9586 5,344 537 32,769,408

SEACOR SPIRIT WCY3195 2,868 139 17,586,576

SEACOR WASHINGTON WDD5978 3,542 740 21,719,544

SECRETARIAT WDA4396 1,472 745 9,026,304

SETH MCCALL WDB769 5,296 139 32,475,072

SIEM SWORDFISH LAKN3 8,632 139 52,931,424

SIMON JR WDC8941 662 139 4,059,384

SISTER CLAIRE WDE7329 2,237 745 13,717,284

SISTER MARY ROLAND WDC4512 7,452 745 45,695,664

SKANDI ACHIEVER C6WC7 9,879 139 60,578,028

SKANDI NEPTUNE LASG5 10,260 139 62,914,320

SKIPPIN SUE WDC6842 1,029 103 6,309,828

SKYE FALGOUT WDF3199 1,656 745 10,154,592

117
Vessel Namea Call Sign Main kW Aux kW kW-HR

SLAM DUNK WDE2559 452 745 45,695,664

SLAP SHOT WDE2976 7,452 745 45,695,664

SOUTHER STAR WDF3098 5,372 537 32,941,104

SOUTHERN BELLE WDE7492 5,372 537 32,941,104

SOUTHERN COMET WDD5209 4,919 139 30,163,308

SOUTHERN CROSS KRTF 5,050 850 30,966,600

SOUTHERN QUEST WCZ5544 2,868 340 17,586,576

SOUTHERN SEAHORSE WCX6191 1,250 150 7,665,000

SOUTHERN SPIRIT WDC4087 4,631 139 28,397,292

SPENCER PHILIP WDE7248 1,193 119 7,315,476

SPT DEFENDER WDC6636 1,653 139 10,136,196

SPT PROTECTOR WDC6637 1,653 73 10,136,196

SPT VICTORY WDE2255 1,653 139 10,136,196

ST IGNATIUS LOYOLA WDD7860 1,492 198 9,148,944

ST JOSEPH THE WORKER WDF8656 2,237 224 13,717,284

ST LOUIS WDD3646 4,559 745 27,955,788

ST MARTIN DE PORRES WDD6206 1,250 300 7,665,000

STARFLEET PATRIOT WDA7014 2,795 139 17,138,940

STARFLEET VIKING WDE8934 4,475 418 27,440,700

STEPHANIE MORRISON WDB5472 1,986 139 12,178,152

STIM STAR 3 WDA7484 3,753 139 23,013,396

STORM WDF8260 5,669 402 34,762,308

STRIKER WDE7237 3,825 139 23,454,900

SUE LEON LAB WDE6715 4,201 73 25,760,532

SUN RIVER WDE6902 1,809 139 11,092,788

SUPERIOR FORTITUDE WDA5229 529 53 3,243,828

SUPERIOR LEGACY WDA5243 671 67 4,114,572

SURF CHALLENGER WDF5385 7,299 745 44,757,468

SUSAN WBC4105 671 67 4,114,572

SWORDFISH WDE3480 5,296 139 32,475,072

TAMPA SEAHORSE WDC5373 1,250 745 7,665,000

TEMAN WDD4228 883 139 5,414,556

TERRY BORDELON WDA5140 1,103 745 6,763,596

TEXAS RESPONDER WBO8579 2,237 139 13,717,284

THUNDER AMERICA WDD5310 1,521 152 9,326,772

TIFFANY LOUISA WDD6944 746 75 4,574,472

TIGER WDE3248 4,848 485 29,727,936

TIGER WDE3479 5,296 139 32,475,072

TIM MCCALL WDB5746 2,501 139 15,336,132

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Vessel Namea Call Sign Main kW Aux kW kW-HR

TODD G WDF8454 1,118 139 6,855,576

TOUCHDOWN WDE2561 3,365 745 20,634,180

TOULOUSE WDC5354 4,559 745 27,955,788

TRADEWIND WDE6438 1,723 139 10,565,436

TRANSPORTER WDD3838 895 89 5,488,140

TRINITY I WDF3138 1,007 101 6,174,924

TRISTAN JANICE WDC3975 895 89 5,488,140

TRITON CRUSADER WCE3923 2,207 139 13,533,324

TRITON FREEDOM WDF2983 1,434 139 8,793,288

TRITON LIBERTY WDF4755 679 68 4,163,628

TRITON PATRIOT WDF4756 1,631 139 10,001,292

TYLER STEPHEN WDE8720 3,130 850 19,193,160

UNIVERSAL SURVEYOR WBB8829 1,386 139 8,498,952

US CUSTOMS M759 Missing 579 58 3,550,428

USAV BRANDY STATION AADU 1250 139 7,665,000

VIKING POSEIDON LFKP 15,300 139 93,819,600

WARREN THOMAS WDD7841 1,268 139 7,775,376

WES BORDELON WDA5141 1,103 745 6,763,596 a Vessel information is provided by ship operators and may contain errors.

To estimate the emissions for each support vessel, the annual kilowatt hours of operation 

were applied to the USEPA emission factors provided in Table 6-1. An example of how the 

equation in Section 6.1.1 was used for this vessel category is provided below.

Example Calculation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) (hours)

kW = Average vessel kW (totaling individual propulsion engines) (kW)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

119
In 2011, a support vessel spent 5,212.2 hours operating underway at sea in the GOM. Its 

main engine has a kW rating of 3,034 kW, the load factor is 0.8, and the emission factor for NOx

is 14.08 g/kWh. 

E = 5,212.2 × 3,034 × 0.80 × 14.08 × 1.10231 × 10-6

E = 196.35 tons of NOx

Support vessel monthly emissions were estimated by applying a monthly adjustment factor 

(Table 6-13) to the annual emission estimates. Monthly AIS vessel traffic data were reviewed for 

these vessels and activity levels seem to be consistent throughout the year, therefore, annual 

emission estimates were temporally apportioned to individual months equally (i.e., 8.33%).

AIS support vessel locations were mapped in a GIS, and a density grid was calculated to 

develop an overall activity grid from a series of point locations. The BOEM lease blocks were 

overlaid on top of the density grid to obtain the proportion of activity that occurred within each 

block. Support vessel emissions were then spatially apportioned to lease blocks based on the 

density of activity within each block.

ESVi = ESV × (Sli/Slt)

where:

ESVi = Support vessel emissions associated with lease block i (tons)

ESV = Total underway emissions associated with support vessels (tons)

Sli = Density of support vessel activity within the boundaries of the lease block i

Slt = Total sum of all support vessel activity densities in GOM federal waters

Figure 6-4 shows the support vessel density derived from AIS data. As anticipated, activity is 

highest near the coast where vessels are approaching port areas and also in regions where active 

platforms are located.

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Figure 6-4. Support vessel activity in the GOM

6.1.6 Survey Vessels

Survey vessels are used in the GOM to map geologic formations and seismic properties. 

These survey mapping activities are needed to evaluate potential oil reserves. The most common 

survey technique uses blasts from underwater air guns. The sound waves from the air gun blasts 

are deflected by underground geologic strata and detected by sound wave receptors trailed 

behind the survey vessel (Figure 6-5). There are two types of surveys that can be performed: two 

dimensional (2-D) and three dimensional (3-D). 3-D surveys are the dominant and preferred 

exploration technique in the GOM. 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 2002).

121
Figure 6-5. Typical geophysical survey vessel operations

Attempts were made to obtain survey vessel data from the vessel operators. For the Year

2005 Gulfwide Emission Inventory Study (Wilson et al. 2007), the operators provided data for 

only 6 of the 16 survey vessels. Therefore, survey vessel data were developed by using average 

characteristics of the 6 vessels and applying them to the remaining 10 vessels. For the 2008 

inventory effort, one operator provided additional data about their fleet. The data also indicated 

that survey vessels remain at sea for longer periods of time than previously estimated, in fact, 

vessels remaining at sea for all but a few days of the year. Supply and crew changes occur by 

helicopters or supply boats. Accounting for the longer period of time that vessels remain at sea 

increased the estimated hours of operation associated with these vessels. For this 2011 inventory 

effort, 16 additional survey vessels were identified that were located primarily in the GOM (Penn 

Well 2012).

The survey vessel information included the number of continuous days the vessel could 

operate before heading back to port. The average number of continuous days was 62. It was 

assumed the vessel would need a week at port to be re-supplied and maintained. Therefore, it 

was estimated that in one year survey a vessel typically was at sea for approximately 328 days 

and in port for approximately 37 days. With 31 survey vessels, it was assumed that collectively 

all survey vessels operated at sea for 238,821 hours. Of the 31 survey vessels, the power ratings 

were known for 19 of the survey vessels. The average power rating for survey vessels was 

2,039 kW. These engines are assumed to be medium-speed diesel engines, and the load factor 

was assumed to be 90%, which was obtained from the Gulf of Mexico Air Quality Study 

(Systems Applications International et al. 1995).

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 and load factors to the marine engine 

emission factors provided in Table 6-1.

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Emission estimates were developed using the approach discussed in Section 6.1.1. An 

example of how the equation in Section 6.1.1 was used for this vessel category is provided 

below.

Example Calculation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) (hours)

kW = Average vessel kW (totaling individual propulsion engines) (kW)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

Total hours of operation of all survey vessels were 238,821. The average kW is 2,039, load 

factor is 0.90, and the emission factor for NOx is 16.25 g/kWh. 

E = 238,821 × 2,039 × 0.90 × 16.25 × 1.10231 × 10-6

E = 7,851.5 tons of NOx

No monthly survey data were identified in this effort; it was assumed that activity was 

consistent throughout the year, therefore, annual emission estimates were temporally apportioned 

to individual months equally (i.e., 8.33%).

Because survey data are considered proprietary, emissions were allocated to each lease block 

based on the surface area of the lease block, as noted in the following equation:

ESi = ES × (Sii/Sti)

where:

ESi = Survey vessel emissions associated with lease block i (tons)

ES = Total survey vessel emissions (tons)

Sii = Surface area of lease block i (square miles)

Sti = Total surface area of all inactive lease blocks (square miles)

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6.2 OTHER NON-PLATFORM SOURCES 

6.2.1 Biogenic and Geogenic Emissions

The primary biogenic and geogenic sources of air pollution that were evaluated for this study 

are: subsurface seeps of crude oil, subsurface seeps of natural gas (including methane hydrates), 

and emissions from bacterial processes and ocean processes. In the previous inventory effort, 

credible emission estimates could only be developed for VOC subsurface seeps of oil and N2O 

from bacterial processes. Published studies were reviewed to determine if any new data sources 

were available to improve the 2008 emission estimates for these source categories. No additional 

references were uncovered that provided new data specific for the Central and Western areas of 

the GOM, nor were any references identified that could be used to enhance the 2008 

biogenic/geogenic emission estimates. Given the nature of these emission sources, the 2008 

estimates were used to represent 2011 emissions.

Subsurface Seeps of Crude Oil

Subsurface seeps, 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 sea bed. 

These cracks and vents open and close as the result of geological activities. The volume of oil 

seeping into the ocean can be relatively significant. The total quantity 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 that use 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 of hydrocarbons consumed. After the seepage is on the surface, air 

pollutants, including VOC, CH4, CO2, and organic air toxics can be emitted through evaporation. 

Based on the data found in the literature, only VOC emissions can be estimated at this time.

BOEM and other researchers have conducted a significant amount of work to study the 

extent of oil seepage 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. 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 work places oil seepage in the northern Gulf at 2.5–6.9 × 

105 barrels/yr (Mitchell et al. 1999). Converting to tons, the average estimate of seepage in the 

northern Gulf is 73,000 tons/yr.

Using this figure, emissions can be estimated using either the oil seepage emission factor 

(105 lbs of VOC/barrel oil released) developed by the California Air Resources Board (CARB 

1993) or the average mass volatilization from oil slicks predicted by the BOEM open ocean 

weathering model (USDOI, MMS 1998). One model prediction showed that after 10 days time, 

124
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 × 294 gal/ton × 1 bbl/42 gal × 105 lbs/bbl = ~26,827 tons/yr VOC

2) 73,000 tpy × 0.34 = 24,820 tons/yr VOC

For the purposes of this BOEM non-platform inventory an average of the two estimates was 

used (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 BOEM 

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 were 13,561 tpy.

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). 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.

N2O, a potent greenhouse gas, is produced in hypoxic coastal zones by deep-water bacteria, 

and is transferred to the atmosphere through upwelling and air-sea transfer mechanisms (Nevison 

et al. 1995). The large nitrogen inputs and deoxygenation typical of these hypoxic systems create 

the potential for large N2O emissions (Walker et al. 2010). 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, total 

annual emissions for the GOM study area have been estimated to be 3,710 tons N2O as nitrogen 

(N) /Year. When adjusted to represent only the Western and Central Gulf, the N2O estimate is 

1,948 tons per year.

Mud Volcanoes

Mud volcanoes are submarine formations that emit gases or liquids. The gases they release 

often contain CH4, CO2, and VOCs. Four mud volcanoes have been identified in the GOM (Kohl 

and Roberts 1994). As information about the pollutant release rates for each volcano were not 

readily available, data concerning typical volumetric emission release rates for mud volcanoes 

were obtained from a study performed by Dimitrov (2003). The Dimitrov study also provided 

speciation values to allow for estimation of the CH4, CO2, and VOC releases. The volume of 

CH4, CO2, and VOC were converted to mass emissions using the chemical density of each 

pollutant. Most VOC emitted from mud volcanoes are higher carbon compounds such as 

isobutane, so the isobutane density was used as a surrogate for the VOC mass emission estimate. 

Adjustments were made to the methane estimate to account for the observation that 80% of the 

125
CH4 emitted by mud volcanoes is consumed by biologic organisms as reported by Zhang and 

Noakes (2006). The emission estimates and locations of the mud volcanoes are noted Table 6-15.

Table 6-15. Mud volcano locations and emission characteristics

Location Typical Emission 

Rate (M3

/yr)

CH4

Fraction (%)

CO2

Fraction (%)

VOC 

Fraction (%)

Garden Banks Block 382 3.60E+06 90 8 2

Green Canyon Block 143 3.60E+06 90 8 2

Green Canyon Block 272 3.60E+06 90 8 2

Mississippi Canyon Block 929 3.60E+06 90 8 2

It was assumed that all biogenic/geogenic emissions are consistent throughout the year, 

therefore, annual emission estimates were temporally apportioned to individual months equally 

(i.e., 8.33%).

Previously, biogenic/geogenic emissions were applied to all lease blocks based on the surface 

area of each lease block; the exception being the mud volcanoes, their emissions were assigned 

to the lease block where the volcano was located. For this 2011 inventory effort, 

biogenic/geogenic emissions were allocated based on surface area of lease blocks containing 

evidence of seepage or leakage activity using the equation below: 

Ebgi = Ebg × (Si/STNG)

where:

Ebgi = Biogenic/geogenic emissions associated with lease block i (tons)

Ebg = Total biogenic/geogenic emissions for GOM (tons)

Si = Surface area of lease block i (square miles)

STG = Surface area of total Gulf lease blocks (square miles)

BOEM’s 2011 Seismic Water Bottom Anomalies dataset was used to identify areas that 

containing evidence of activity (US DOI BOEM 2012). This study provided information about 

anomalies in the seabed that would indicate seepage or underwater explosions related to the 

release of hydrocarbons. These anomalies were mapped in GIS and joined to the lease block grid 

in order to specify which lease blocks contained activity (Figure 6-6). It was assumed that if a 

lease block does not contain an anomalies than there is no evidence of biogenic/geogenic activity 

in that lease block and emission were not be mapped to these lease blocks. Note this approach 

does not quantify the magnitude or the temporal period of the release, but it does identify 

locations where there is no evidence of activity providing an improvement over the previous 

methodology.

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Figure 6-6. Locations of negative anomalies and pockmarks

6.2.2 Commercial Fishing Vessels

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 NOAA NMFS. Separate 

activity data were provided for the three types of offshore fishing activities that occur in the 

GOM: pelagic long line, reef, and shrimp operations (Maiello 2012; Farmer 2012; Nance 2012). 

The activity data for these different fishing operations were provided as latitude and 

longitude for pelagic long line fishing operations, and in terms of NMFS statistical zones for reef 

and shrimp fishing operations. The activity data for shrimp and reef fish operations are presented 

in Table 6.16 and Table 6.17, respectively. (The line fishing activity data includes over 

3,000 records, and cannot be provided in a hardcopy format.)

Table 6-16. Shrimp vessel activity data

NMFS Zones 2011 Shrimp Fishing Vessel Hours

10 - 12 137,747

13 - 17 808,432

18 - 21 516,779

Total 1,462,957

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Table 6-17. Reef fishing vessel activity data

NMFS Zones 2011 Reef Fishing Vessel Hours

11 - 21 3,944

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 nets and lines onto the vessel. To estimate emissions from 

operating these diesel engines, the emission factors provided in Table 6-1 were used.

Assumptions about typical fishing vessel horsepower (300 HP) for pelagic long line fishing 

vessels were obtained from the Gulf of Mexico Air Quality Study (Systems Applications 

International et al. 1995). Average fishing vessel horsepower for reef (382 HP) and shrimp 

vessels (558 HP) were obtained by taking the average horsepower of the 2008 permitted shrimp 

vessels and reef fish vessels (Dudley 2012). These typical horsepower ratings were converted to 

kilowatts to match the units of the USEPA emission factors. The typical operating loads were 

assumed to be 80% for underway operations, and 10% for maneuvering while setting the nets

(Systems Applications International et al. 1995). These load factors were applied to the rated kW 

of the typical vessel engines and the total annual hours operation presented in Table 6-16 and 

6-17 to get kilowatt hours which was used to calculate emissions for this source category using 

the approach discussed in Section 6.1.1. An example of how the equation in Section 6.1.1 was 

used for this vessel category is provided below.

Example Calculation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) (hours)

kW = Average vessel kW (totaling individual propulsion engines) (kW)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

Shrimp fishing vessels spent 1,462,957 hours at sea in 2011. The average kW is 416.268, 

load factor is 0.80, and the emission factor for NOx is 12.35 g/kWh. 

E = 1,462,957 × 416.268 × 0.80 × 12.35 × 1.10231 × 10-6

E = 6,629.67 tons of NOx

128
Commercial fishing activities vary monthly depending on fishing season. In order to quantify 

temporal variations, monthly adjustment factors were calculated based on NOAA monthly 

fisheries landing data for 2011. The monthly adjustment factors were applied to the annual 

emission estimates to calculate the monthly emissions. The monthly adjustment factors are 

presented in Table 6-18.

Table 6-18. Commercial fishing monthly adjustment factors

Month 2011 Monthly Adjustment Factors (%)

January 3

February 2

March 2

April 3

May 10

June 13

July 17

August 17

September 13

October 11

November 5

December 3

Commercial fishing locations were also provided by the NMFS. Reef and shrimp fishing 

operations are delineated by NMFS statistical zones (Figure 6-7). For line fishing operations, 

operating hours were estimated based on the assumption that it takes approximately 24 hours to 

tend each set. The Southeast Fisheries Science Center (SFSC) (Maiello 2012) provided latitude 

and longitude coordinates for line fishing operations. Emissions were spatially allocated for these 

three activities by overlaying a GIS plot of BOEM lease blocks onto a map of NMFS and SFSC 

location data. Commercial fishing emission estimates for reef and shrimp fishing operations were 

spatially allocated using the following formula:

ECFi = ECFz × (Si/SCFz)

where:

ECFi = Commercial fishing emissions for lease block i (tons)

ECFz = Commercial fishing emissions for NMFS area z (tons)

Si = Surface area of lease block i (square miles)

SCFz = Total surface area of NMFS area z (square miles)

129
Figure 6-7. NMFS fishing zones with lease blocks

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, lease 

block AB is split between NMFS zones 12 and 13. 75% of lease block AB is included in zone 

12 and 25% of lease block AB is in zone 13. In this example, emissions associated with NMFS 

zones 12 and 13 would be split in lease block AB, proportional to the area with which each zone 

is associated. Line fishing emissions were assigned to individual lease blocks based on the 

latitude and longitude coordinates provided by SFSC and the estimated hours of operation.

6.2.3 Commercial Marine Vessels 

Commercial marine vessels (CMV) are involved in transporting a wide range of agricultural, 

manufacturing, and chemical products through the GOM. The majority of CMVs tend to be 

powered by diesel engines that combust marine diesel fuel or a blend of distillate and residual 

oils. For vessels operating in the Gulf in 2011, AIS data were evaluated to determine whether the 

data could be used to estimate emissions from vessels that transit the central and western areas of 

the GOM. AIS tracks vessel movements in federal and state waters within range of VHF 

transmitting stations. The vessel transmitters send a signal every two seconds that documents 

vessel identification codes, radio call signs, location, direction, and speed. PortVision was 

commissioned to compile simplified data sets for this inventory effort. The first data set included 

all “event” data: instances where a vessel was first detected by each transmitter as the vessel 

transited the area of interest. The intent was to connect the events for each vessel and map 

individual transits to calculate vessel speed and hours of operation for a bottom-up activity 

estimate. However, the event data contained too many inconsistencies and irresolvable errors, 

such as repeat events and missing data points, to be useful in this effort.

130
The AIS data were compared with the U.S. Army Corps of Engineers Entrance and 

Clearance data for Gulf ports to assess the completeness of the commercial marine vessel fleet 

included in the AIS dataset. The two datasets were comparable, but the entrance and clearance 

data seems to be slightly more complete as it included smaller freight movement vessels that 

didn’t trigger the AIS reporting requirements. The Entrance and Clearance data were used to 

quantify hours of operation by mapping the length of the routes in federal waters between the 

ports the vessels visited, divided by their reported cruising speed; adjustments were made for 

time spent transiting state waters. Hours of operation were applied to the vessels power rating to 

get kilowatt-hours. For block-level activity, the kilowatt-hours from all transits within the lease 

block were summed.

Emission estimates were developed using the approach discussed in Section 6.1.1. An 

example of how the equation in Section 6.1.1 was used for this vessel category is provided 

below.

Example Calculation:

E = kW-hr × LF × EF × CF

where:

E = Emissions (tons)

kW-hr = Summed activity for the lease block (kW-hr)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

Category 3 CMV activity in BOEM lease block AC1002 was summed to be 633,363 kW-hrs. 

The load factor for Category 3 underway is 80% and the emission factor for NOx is 19.54 g/kWhr. 

E = 633,363 × 0.8 × 19.54 × 1.10231 × 10-6

E = 10.93 tons of NOx

The second data set obtained from PortVision (AIRSIS 2012) consisted of “snapshot” files of 

vessel name, Maritime Mobile Service Identity (MMSI), number call sign, vessel type, and 

position of all vessels within the Gulf at a single point in time for each month of the year. Vessel 

type was corrected and gap-filled using several datasets including those from Lloyd’s of London 

and the Coast Guard vessel logs. These “snapshot” files were examined for seasonality in vessel 

activity throughout the year. No seasonal trends were detected either overall or by vessel type.

The snapshot files were then compiled to develop vessel traffic contours for each vessel type 

(e.g., tanker, containership, support vessel) that were used to spatially allocate emissions. This 

was accomplished by using GIS to develop density grids of the vessel point locations from the 

compiled snapshot files for each major vessel type. This approach was useful in demonstrating 

the different traffic profiles by vessel type; these density grids are shown in Figures 6-8 to 6-14. 

131
However, because some vessel types had few vessels on which the density grid was created, 

there were gaps in coverage in the study area. To ensure a more robust spatial allocation, the AIS 

data were reprocessed to provide three activity density grids: one for Category 3 commercial 

marine vessels, which included different tankers, cargo ship, bulkers and containerships, etc.; 

one for Category 1 and 2 vessels developed from tug data; and one for support vessel.

6.2.4 LOOP

The LOOP is a platform located 45 miles from shore (Figure 6-16). This offshore port allows 

large oil tankers to unload product without having to enter and maneuver inside urban ports. The 

LOOP consists of several emission sources, one 1,000 kW generator, four 7,500 hp pumps, 

support vessels, as well as the oil tankers that use the facility. The engine characteristics for 

combustion sources located on the LOOP platform, including kW rating, load factors, and hours 

of operation are summarized in Table 6-19.

Table 6-19. LOOP hours of operation, kW rating, and load factors

Vessel/Equipment Type Hours of Activity Average kW Load Factor

Generator 8,566 1,000 0.50

Pumps 3,300 22,371 1.00

The tankers and support vessels associated with the LOOP were included in the AIS data sets 

and were not calculated separately. However, vessels also emit VOCs through evaporative losses 

from tanker ballasting operations. Ballasting consists of pumping water into a vessel after the 

product has been removed, providing increased stability for the tanker. Because evaporative 

emissions from ballasting were not accounted for in the AIS-based data but were calculated in 

this effort. 2011 data were not available, 2008 data were adjusted to represent 2011 activity 

levels.

132
Figure 6-8. Vessel traffic density in bulkers Figure 6-9. Vessel traffic density in cargo ships

Figure 6-10.Vessel traffic density in container ships Figure 6-11.Vessel traffic density in tankers

133
Figure 6-12. Vessel traffic density in tugs Figure 6-13. Vessel traffic density in Category 3 CMVs

Figure 6-14. Vessel traffic density in Category 1 and 2 CMVs

Category 3 CMV

Category 1 and 2 CMV

134
The 2008 BOEM report estimated just over five calls per week, which corresponded to 

approximately 269 calls in 2008. According to the U.S. Energy Information Administration, 

crude oil imported to the LOOP declined 30% between 2008 and 2011 (EIA 2013). This 

decreased number of calls was used to calculate the appropriate hours of activity for the emission 

sources associated with the LOOP. It is assumed that for each call, 2.13 tons of VOC are emitted.

No monthly LOOP data were compiled in this effort; it was assumed that activity was 

consistent throughout the year; therefore, annual emission estimates were apportioned to each 

months equally (i.e., 8.33%). LOOP platform and evaporative emissions were all assigned to the 

latitude and longitude coordinates of the LOOP. 

Figure 6-15. Shipping lane approach and location of LOOP

6.2.5 Military Vessels

The U.S. Navy and US Coast Guard patrol the coast and have maneuvers 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. Unfortunately, no data were provided; therefore, the emission estimates developed for 

the Navy for the Gulf of Mexico Air Quality Study were used in this inventory (Systems 

Applications International et. al. 1995). Naval base closings announced in 2005 do include 

facilities located on the GOM. Two of the largest bases initially listed for closure are the Naval 

Support Activity Center New Orleans which has since been realigned and removed from the list 

of closures and the Naval Station Ingleside which completed the process of closing by 2011 

moving the operation to San Diego. The Ingleside base supported minesweeping activities; such 

135
that eight minesweeping vessels were removed from the 2011 Gulfwide inventory. Note that 

these vessels accounted for 4% of naval vessel activity in the GOM.

All remaining base closings in the Gulf region involved small reserve centers that employ 10 

to 30 people, many of which are located inland. No information on vessel activities was found 

for those small reserve centers. Given the difficulty of obtaining detailed activity data pertaining 

to naval vessels, the use AIS data was being considered as a possible source for military vessel 

tracking data. Unfortunately, military vessels rarely send signals that would identify their 

location on the public AIS. For the 2011 inventory, the naval activity data reported in the Gulf of 

Mexico Air Quality Study was applied to emission factors included in Section 6.1.1. In order to 

implement this approach, kW-hours were calculated for each naval vessel as noted in Table 6-20.

Table 6-20. Naval vessel kW hours

Vessel Engine 

Type

No. 

Engines

Average 

kW 

Rating

Total 

Engine 

Hours

kW-hrs Operating 

Load

Load 

Adjusted 

kW-hrs

PHM Diesel 2 596.56 17,520 10,451,731 0.80 8,361,385

TAG Diesel 2 1,043.98 17,520 18,290,530 0.80 14,632,424

TAG(50) Diesel 1 1,043.98 17,520 18,290,530 0.80 14,632,424

TAGS(50) Diesel 1 1,864.25 8,760 16,330,830 0.80 13,064,664

LSD Diesel 4 7,643.43 35,040 267,825,787 0.80 214,260,630

TAGS(40) Diesel 2 8,948.40 17,520 156,775,968 0.80 125,420,774

TAK(II) Diesel 2 10,066.95 17,520 176,372,964 0.80 141,098,371

Total 14 131,400 664,338,340 531,470,672

The GOM naval fleet also includes diesel turbine and steam ships; the diesel turbine factors 

used in this study were obtained from the Swedish emissions data (SEPA 2004) while the 

steamship factors were obtained from USEPA guidance (Table 6-21) (USEPA 1992). 

Table 6-21. Naval diesel turbine and steamship fuel consumption data and emission factors

Engine Type Fuel Usage 

(liters/year)

Emission factors (lbs/1000 liters)

NOX CO CO2 SO2 VOC PM

Diesel Turbine 594,230 32.19 0.12 5742.9 14.78 0.01 0.44

Steamship 8,918,610 14.38 0.977 6872.3 85.9 0.33 6.816

The Coast Guard provided data for the Year 2008 Gulfwide Emission Inventory Study that 

included the number of vessels with a homeport in the GOM, the type of vessel, and the total 

number of operating days for some of the vessels. This dataset was updated with the Coast Guard 

fleet data provided by each district as reported on their Coast Guard websites. Although the 

Coast Guard has commissioned several new vessels for use in the GOM, they are not yet in 

service, nor were any vessels retired from service in 2011. 

136
From the 2008 data set, the average number of operating hours was calculated for each type 

of ship. Engine horsepower was obtained for some but not all of the vessels through the vessel’s 

homepage. Where vessel horsepower data were not readily available, averages for vessel types 

were developed using available data for sister ships. The average hours of operation and 

horsepower ratings are summarized in Table 6-22.

Table 6-22. Average horsepower and operating hours by coast guard vessel type

Boat Class Type Horsepower Rating Hours of Operation Vessel Count

WLB 225 Buoy Tenders 6,200 2,152.8 1

WMEC 210 Cutters 5,000 3,840.0 2

WPB 87 Patrol 3,050 1,518.5 14

To estimate emissions from the Navy and Coast Guard marine diesel engines, the emission 

factors noted in Section 6.1.1 were applied to the hours of operation and the vessel kW rating. It 

was assumed that the Coast Guard vessels typically operate at a load factor of 85% while in 

federal waters.

Emission estimates were developed using the approach discussed in Section 6.1.1. An 

example of how the equation in Section 6.1.1 was used for this vessel category is provided 

below.

Example Calculation:

E = AH × kW × LF × EF × CF

where:

E = Emissions (tons)

kW-hr = Summed activity for the lease block (kW-hr)

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

Buoy tenders spent 89.7 days at sea. It is assumed that they operate 24 hours a day. 

Therefore, total hours of operation were 2,152.8. The average kW is 4,623, load factor is 0.85 

while cruising, and the emission factor for NOx is 19.54 g/kWh. 

E = 2,152.8 × 4,623× 0.85 × 19.54 × 1.10231 × 10-6

E = 182.21 tons of NOx

No monthly Navy or Coast Guard data were identified in this effort; it was assumed that 

activity was consistent throughout the year; therefore, annual emission estimates were temporally 

apportioned to individual months equally (i.e., 8.33%).

137
Because it was not possible to identify where Navy vessels operate, the emissions were 

allocated to individual lease blocks throughout the Central and Western areas of the GOM. All 

Coast Guard vessel emissions were allocated relative to each vessel’s home port and the area 

where the vessels patrol (Figure 6-17). The allocations were made based on the surface area of 

the lease blocks using the equation below: 

EMVi = EMV × (Si/STNG) 

where:

EMVi = Military vessel emissions associated with lease block i (tons) 

EMV = Total military vessel emissions for the GOM (tons) 

Si = Surface area of lease block i (square miles)

STG = Surface area of total Gulf lease blocks (square miles)

Figure 6-16. Coast Guard districts used to allocate emissions 

138 
6.2.6 Vessel Lightering

Lightering is the transfer of cargo to smaller ships that bring the product into port. Lightering 

occurs offshore in three designated areas. 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.

Combustion emissions from the propulsion engines in large tankers and shuttle tankers

involved in the lightering process are included in the AIS CMV data and were not calculated 

separately for 2011. As lightering occurs, the ships pump water into their holds to enhance the 

stability of the vessel, referred to as ballasting. As water enters the hold during ballasting,

organic vapors are displaced into the atmosphere. Activity data were collected to quantify 

ballasting and estimate evaporative emissions as described below.

Skaugen Petrotrans (SPT), OSG Lightering (OSGL), and American Eagle Tankers (AET) are 

the three major lightering companies that account for a majority of ship-to-shore transfers of 

crude oil in the Gulf of Mexico. In 2008, SPT was contacted directly to obtain the annual number 

of barrels of crude and petroleum products lightered (Tonstad 2009). Additionally, SPT provided 

their market share estimates for SPT, OSGL, and AET. In order to obtain the 2011 annual 

number of barrels of crude and petroleum products lightered in the Gulf of Mexico, SPT, OSGL, 

and AET were contacted. The number of barrels of product lightered was provided by SPT (Lenz 

2013) and OSGL (Wrenn 2013) (Table 6-23). The number of barrels of product lightered for 

AET in 2008 was adjusted to represent the number of barrels transferred in 2011, based on their 

2008 market share and accounting for an average decline in activity for SPT and OSGL of 39% 

(Table 6-23).

Table 6-23. Full service lightering barrel data for 2008 and 2011

SPTa OSGL AET

2008 Totals 2011 Totals 2008 Totals 2011 Totals 2008 Totals 2011 Totals

Annual 

barrels 200,600,000 105,000,000 250,043,662 170,000,000 527,634,507 321,982,759

a Note, at the time the 2008 Gulfwide Inventory was developed, data were only available for SPT, Inc.

The evaporative VOC emissions were calculated using the following equations. The total 

number of barrels per year transferred noted in Table 6-23 was used to quantify ballasting and 

estimate evaporative emissions using the equations listed below:

Evaporative Lightering:

Ev = PT × BBL/GAL conversion factor × TOCc × VOC/TOC conversion factor

where:

Ev = Evaporative emissions (tons)

PT = Annual amount of product transferred (barrels)

139
BBL/GAL = Barrels to gallons conversion factor (42 gallons/barrel)

TOCc = Emission factor for total organic compounds emitted from thousand gallons of

crude oil transfered (0.86 lb of TOC/103 gal of crude oil)

VOC/TOC = TOC to VOC conversion factor (0.85)

Evaporative Ballasting:

Eb = Wat × TOCc × VOC/TOC

where:

Eb = Ballasting emissions (tons)

Wat = Ratio of Density of Crude Oil to Water Equivalent Adjustment

TOCc = Emission factor for total organic compounds emitted from thousand gallons 

of crude oil transfered (0.9 lb of TOC/103 gal of crude oil)

VOC/TOC = TOC to VOC conversion factor (0.85)

Evaporative emissions were assigned to the center of the lightering zones (Figure 6-18). No 

monthly vessel lightering data were identified in this effort; it was assumed that activity was 

consistent throughout the year; therefore, annual emissions estimates were temporality 

apportioned to each month equally (i.e., 8.33%). 

Figure 6-17. Centroid of the vessel lightering zone and shipping lane to Galveston

140
6.2.7 Recreational Fishing

The GOM is also an active recreational fishing area, providing a wide range of opportunities 

to recreational anglers. Oil platforms in the GOM act as artificial reefs that fish gather at, which 

make the platforms prime destinations for anglers (Gordon 1993). Detailed recreational fishing 

data were obtained from the NOAA Marine Recreational Information Program (MRIP) (NOAA 

2012). Aside from Texas, the data were disaggregated into fishing areas (inland, ocean ≤ 3 miles, 

and ocean > 3 miles). Data for Texas are not disaggregated because Texas, not NOAA,

administers the survey. Texas reports their data to NOAA in an aggregated form. To estimate the 

number of trips into federal waters, the average percent trips were calculated for the other states 

and then applied to Texas. Table 6-24 summarizes the number of recreational fishing trips to 

federal waters. It is assumed that four hours per trip (two hours there and two hours back) are 

underway at 80% load, and six hours per trip are maneuvering at 30% load. Table 6-25 estimates 

the underway hours and maneuvering hours based on the trips.

Table 6-24. Number of trips near platforms

State Fishing Area* Trips Percent Notes

Alabama Not platform 2,245,855 90% Known

Alabama Platform 237,610 10% Known

Alabama Total 2,483,465 100% Known

Louisiana Not platform 4,479,553 98% Known

Louisiana Platform 96,694 2% Known

Louisiana Total 4,576,247 100% Known

Mississippi Not platform 1,602,195 99% Known

Mississippi Platform 13,195 1% Known

Mississippi Total 1,615,390 100% Known

Texas Not platform 96% Calculated

Texas Platform 46,882 4% Calculated

Texas Total 1,125,401 100% Known

* It is assumed that all ocean fishing > 3 miles (deep ocean) are near the platforms.

Table 6-25. Activity hours based on number of trips

State Fishing Area Trips Underway Hours Maneuvering Hours

Alabama Platform 237,610 950,440 1,425,660

Louisiana Platform 96,694 386,776 580,164

Mississippi Platform 13,195 52,780 79,170

Texas Platform 46,882 187,529 281,293

The average weighted HP was estimated for diesel inboard engines from the USEPA’s 

NONROAD (US EPA 2012) model’s average hp per bin dataset and population distribution 

dataset noted in Table 6-26.

141
Table 6-26. USEPA nonroad recreational marine vessel power profile

HP Min HP Max HP Avg Population HP * Population

6 11 9.736 9,199 89,561.464

11 16 14.92 4,514 67,348.88

16 25 21.41 9,987 213,821.67

25 40 31.2 5,464 170,476.8

40 50 42.4 1,010 42,824

50 75 56.19 8,854 497,506.26

75 100 94.22 7,456 702,504.32

100 175 144.9 61,116 8,855,708.4

175 300 223.1 100,498 22,421,103.8

300 600 387.1 4,132 1,599,497.2

600 750 677 2,925 1,980,225

750 1000 876.5 5,546 4,861,069

1000 1200 1,154 452 521,608

1200 2000 1,369 1,586 2,171,234

2000 3000 2,294 971 2,227,474

Avg Weighted HP 207.5095561

The emission factors used to calculate the emissions were obtained from the NONROAD 

model for SCCs 2282020000 and 2282020005. The emission factors are listed in Table 6-1. The 

annual emission for underway emissions, maneuvering emissions, and total emissions are 

summarized in Tables 6-27 to 6-29.

Table 6-27. Annual underway emissions for recreational fishing (tons)

State CO NOx PM10 PM2.5 VOC SO2 CO2

Alabama 260.23 1,205.67 45.40 44.04 75.87 28.89 94,274.64

Louisiana 105.90 490.64 18.47 17.92 30.88 11.76 38,364.52

Mississippi 14.45 66.95 2.52 2.45 4.21 1.60 5,235.28

Texas 51.35 237.89 8.96 8.69 14.97 5.70 18,601.08

Total 431.93 2,001.15 75.35 73.09 125.93 47.95 156,475.52

Table 6-28. Annual maneuvering emissions for recreational fishing (tons)

State CO NOx PM10 PM2.5 VOC SO2 CO2

Alabama 146.38 678.19 25.54 24.77 42.68 16.25 53,029.49

Louisiana 59.57 275.98 10.39 10.08 17.37 6.61 21,580.04

Mississippi 8.13 37.66 1.42 1.38 2.37 0.90 2,944.84

Texas 28.88 133.81 5.04 4.89 8.42 3.21 10,463.11

Total 242.96 1,125.65 42.39 41.11 70.84 26.97 88,017.48

142
Table 6-29. Annual total emissions for recreational fishing (tons)

State CO NOx PM10 PM2.5 VOC SO2 CO2

Alabama 406.62 1,883.86 70.94 68.81 118.55 45.14 147,304.13

Louisiana 165.47 766.62 28.87 28.00 48.24 18.37 59,944.56

Mississippi 22.58 104.61 3.94 3.82 6.58 2.51 8,180.12

Texas 80.23 371.70 14.00 13.58 23.39 8.91 29,064.19

Total 674.90 3,126.80 117.74 114.21 196.77 74.92 244,493.00

Example Calculation:

E = AH × HP × LF × EF × CF

where:

E = Emissions (tons)

AH = Annual hours per mode of operation (underway, maneuvering, hoteling) hours

HP = Horse power

LF = Engine load factor for specified mode of operation (%)

EF = Emission factor (g/kWH)

CF = Conversion factor (g = 1.10231 E-6 ton)

Recreational fishing vessels in Alabama spent 950,440 underway hours at sea in 2011. The 

average HP is 207.5, load factor is 0.80, and the emission factor for CO2 is 2.01 g/kW-hr. 

E = 950,440 × 207.5 × 0.80 × 2.01 × 1.10231 × 10-6

E = 94,274.64 tons of CO2

143

7.RESULTS

7.1 SUMMARY OF STUDY APPROACH

This BOEM Year 2011 Gulfwide Emissions Inventory Study includes all major oil and gas 

production platforms and non-platform sources in the Central and Western GOM on the OCS. 

Pollutants covered in the inventory are the criteria pollutants—CO, NOx, PM10, PM2.5, SO2, and 

VOC; as well as major greenhouse gases—CO2, CH4, and N2O.

BOEM attempted to collect activity data from each active major offshore oil and gas 

production platform in the GOM on the OCS. Operators were provided with the GOADS-2011

Visual Basic® activity data collection software for compiling monthly data for calendar year 

2011. A total of 2,544 oil and gas production platforms submitted active monthly equipment 

activity data files. The platform equipment surveyed includes:

• Amine units

• Boilers/heaters/burners

• Diesel engines

• Drilling equipment

• Combustion flares

• Fugitive sources

• Glycol dehydrators

• Losses from flashing

• Minor sources

• Mud degassing

• Natural gas engines

• Natural gas, diesel, and dual-fuel turbines

• Pneumatic pumps

• Pressure/level controllers

• Storage tanks

• Cold vents

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 the equipment was operational), verify and correct 

activity values such as fuel heating value, make sure that the equipment shown to be vented 

145
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 exhaust gas temperature is also presented.

Emission estimates were also developed for criteria air pollutants and greenhouse gases for 

non-platform sources operating in the GOM on the OCS for the 2011 calendar year. The nonplatform sources included in this study are noted below.

Non-platform oil/gas production sources:

• Drilling rigs

• Pipelaying operations

• Support helicopters

• Support vessels

• Survey vessels

Non-platform non-oil/gas production sources:

• Biogenic and geogenic sources

• Commercial fishing vessels

• Commercial marine vessels

• LOOP

• Military vessels (Coast Guard/Navy)

• Vessel lightering

• Recreational vessels

After intensive research and data gathering of activity data specific to each source category, 

the compiled activity data underwent detailed QA/QC. For most marine vessel source categories, 

the emission factors were developed by the USEPA (USEPA 2010b) specifically to represent 

2011 emission and fuel standards as well as vessel turn over. The resulting non-platform 

emission estimates were then disaggregated into BOEM lease blocks, suitable for use in air 

quality modeling applications. If diurnal emission curves are needed for air quality modeling, 

please refer to the Year 2008 Gulfwide Emissions Inventory Study (Wilson et al. 2010).

146
7.2 PRESENTATION OF ANNUAL EMISSION ESTIMATES

The platform and non-platform emission estimates developed for criteria pollutants and 

greenhouse gases are presented in Tables 7-1 through 7-15. For an overview of the results, 

Table 7-1 summarizes the total platform criteria pollutant emission estimates, Table 7-2 

summarizes the total non-platform criteria pollutant emission estimates, and Table 7-3 presents 

the combined platform and non-platform criteria pollutant estimates. To facilitate more detailed 

review, Tables 7-4 through 7-8 present platform and non-platform emission estimates by 

pollutant.

The greenhouse emission estimates are provided in Tables 7-9 through 7-15. The CO2

equivalent (CO2e) emission estimates shown in these tables represent the number of tons of CO2

emissions with the same global warming potential as one ton of another greenhouse gas as 

shown in the following equation:

CO2e = ∑GHGi x GWPi

where:

CO2e = Carbon dioxide equivalent, tons/year

GHGi = Mass emissions of each greenhouse gas, tons/year

GWPi = Global warming potential for each greenhouse gas in the inventory

The global warming potentials used are those required under the USEPA Final Mandatory 

Reporting of Greenhouse Gases Rule (Federal Register 2009), with a global warming potential 

of 21 for CH4, and a global warming potential of 310 for N2O. The global warming potentials 

will be updated in future BOEM inventories, as the USEPA has adopted the values of the 

Intergovernmental Panel for Climate Change, Fourth Assessment Report.

Table 7-1. Total platform emission estimates for criteria pollutants

Equipment

CO 

Emissions 

(tpy)

NOx

Emissions 

(tpy)

PM10

Emissions 

(tpy)

PM2.5

Emissions 

(tpy)

SO2 

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Amine Units 0 0 0 0 4 0.2

Boilers/heaters/

Burners 621 1,156 14 14 5 41

Diesel Engines 2,187 8,927 349 348 827 406

Drilling Equipment 396 1,493 17 17 24 37

Combustion Flares 1,252 425 5 5 3 30

Fugitives 0 0 0 0 0 16,403

Glycol Dehydrators 0 0 0 0 0 1,158

Losses From Flashing 0 0 0 0 0 640

Minor Sources 0 0 0 0 0 157

Mud Degassing 0 0 0 0 0 23

147
Equipment

CO 

Emissions 

(tpy)

NOx

Emissions 

(tpy)

PM10

Emissions 

(tpy)

PM2.5

Emissions 

(tpy)

SO2 

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Natural Gas Engines 62,024 44,863 224 224 14 1,310

Natural Gas, Diesel, 

and Dual-fuel 

Turbines

3,859 27,264 149 149 2,320 103

Pneumatic Pumps 0 0 0 0 0 2,182

Pressure/level 

Controllers 0 0 0 0 0 2,064

Storage Tanks 0 0 0 0 0 928

Cold Vents 0 0 0 0 0 29,243

Total Emissions 

(tpy)a 70,339 84,128 759 756 3,197 54,724

a Totals may not sum due to rounding.

Table 7-2. Total non-platform emission estimates for criteria pollutants

Source 

Category

CO 

Emissions 

(tpy)

NOx 

Emissions 

(tpy)

PM10 

Emissions

(tpy)

PM2.5

Emissions 

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Drilling Rigs 6,248 69,135 2,634 2,407 20,863 2,750

Pipelaying 

Operations 2,124 9,480 350 338 117 128

Support 

Helicopters 2,163 753 23 22 112 1,624

Support Vessels 35,686 175,558 6,435 6,242 2,157 4,016

Survey Vessels 1,760 7,851 290 281 97 105

Total OCS 

Oil/Gas 

Production 

Sources (tpy) 47,981 262,777 9,732 9,290 23,346 8,623

Biogenic and 

Geogenic 

Sources 0 0 0 0 0 14,357

Commercial 

Fishing Vessels 1,206 6,917 245 238 85 218

Commercial 

Marine Vessels 9,779 108,203 4,122 3,768 32,651 4,303

LOOP 313 1,399 52 50 17 420

Military 

Vessels 1,035 11,448 436 399 3,455 455

Vessel 

Lighteringa 0 0 0 0 0 17,113

148
Source 

Category

CO 

Emissions 

(tpy)

NOx 

Emissions 

(tpy)

PM10 

Emissions

(tpy)

PM2.5

Emissions 

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Recreational 

Vessels 675 3,127 118 114 75 197

Total Non-OCS 

Oil/Gas 

Production 

Sources (tpy) 13,008 131,094 4,973 4,569 36,283 37,063

Total NonPlatform 

Emissions 

(tpy)b 60,989 393,871 14,705 13,859 59,629 45,686 a Vessel estimates are reflected in commercial marine vessels. b Totals may not sum due to rounding.

Table 7-3. Total platform and non-platform emission estimates for criteria pollutants

Equipment/

Source Category

CO 

Emissions 

(tpy)

NOx

Emissions 

(tpy)

PM10

Emissions 

(tpy)

PM2.5

Emissions 

(tpy)

SO2 

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Total Platform 

Emissions 70,753 84,415 760 759 3,197 54,724

Drilling Rigs 6,248 69,135 2,634 2,407 20,863 2,750

Pipelaying 

Operations 2,124 9,480 350 338 117 128

Support 

Helicopters 2,163 753 23 22 112 1,624

Support Vessels 35,686 175,558 6,435 6,242 2,157 4,016

Survey Vessels 1,760 7,851 290 281 97 105

Total OCS 

Oil/Gas 

Production 

Source Emissions 118,734 347,192 10,492 10,049 26,543 63,347

Total Non-OCS 

Oil/Gas 

Production 

Source Emissions 13,008 131,094 4,973 4,569 36,283 37,063

Total Emissions 

(tpy)a 131,742 478,287 15,465 14,618 62,827 100,410 a Totals may not sum due to rounding.

149
Table 7-4. Annual CO emission estimates for all sources

Equipment/Source Category CO Emissions (tpy)

Natural Gas Engines 62,024

Support Vessels 35,686

Commercial Marine Vessels 9,779

Drilling Rigs 6,248

Natural Gas, Diesel, and Dual-fuel 

Turbines 3,859

Diesel Engines 2,187

Support Helicopters 2,163

Pipelaying Operations 2,124

Survey Vessels 1,760

Combustion Flares 1,252

Commercial Fishing Vessels 1,206

Military Vessels 1,035

Recreational Vessels 675

Boilers/heaters/burners 621

Drilling Equipment 396

LOOP 313

Total Emissions (tpy)a 131,328 a Totals may not sum due to rounding.

150
Table 7-5. Annual NOx emission estimates for all sources

Equipment/Source Category NOx Emissions (tpy)

Support Vessels 175,558

Commercial Marine Vessels 108,203

Drilling Rigs 69,135

Natural Gas Engines 44,863

Natural Gas, Diesel, and Dual-fuel 

Turbines 27,264

Military Vessels 11,448

Pipelaying Operations 9,480

Diesel Engines 8,927

Survey Vessels 7,851

Commercial Fishing Vessels 6,917

Recreational Vessels 3,127

Drilling Equipment 1,493

LOOP 1,399

Boilers/heaters/burners 1,156

Support Helicopters 753

Combustion Flares 425

Total Emissions (tpy)a 478,286

a Totals may not sum due to rounding.

151
Table 7-6. Annual PM10 emission estimates for all sourcesa

Equipment/Source Category PM10 Emissions (tpy)

Support Vessels 6,435

Commercial Marine Vessels 4,122

Drilling Rigs 2,634

Military Vessels 436

Pipelaying Operations 350

Diesel Engines 349

Survey Vessels 290

Commercial Fishing Vessels 245

Natural Gas Engines 224

Natural Gas, Diesel, and Dual-fuel 

Turbines 149

Recreational Vessels 118

LOOP 52

Support Helicopters 23

Drilling Equipment 17

Boilers/heaters/burners 14

Combustion Flares 5

Total Emissions (tpy)b 15,463 a Annual PM2.5 emission estimates follow a similar pattern. b Totals may not sum due to rounding.

152
Table 7-7. Annual SO2 emission estimates for all sources

Equipment/Source Category SO2 Emissions (tpy)

Commercial Marine Vessels 32,651

Drilling Rigs 20,863

Military Vessels 3,455

Support Vessels 2,157

Natural Gas, Diesel, and Dual-fuel 

Turbines 2,320

Diesel Engines 827

Pipelaying Operations 117

Support Helicopters 112

Survey Vessels 97

Commercial Fishing Vessels 85

Recreational Vessels 75

Drilling Equipment 24

LOOP 17

Natural Gas Engines 14

Boilers/heaters/burners 5

Amine Units 4

Combustion Flares 3

Total Emissions (tpy)a 62,827

a Totals may not sum due to rounding.

153
Table 7-8. Annual VOC emission estimates for all sources

Equipment/Source Category VOC Emissions (tpy)

Cold Vents 29,243

Vessel Lightering 17,113

Fugitives 16,403

Biogenic and Geogenic Sources 14,357

Commercial Marine Vessels 4,303

Support Vessels 4,016

Drilling Rigs 2,750

Losses From Flashing 640

Pneumatic Pumps 2,182

Pressure/level Controllers 2,064

Support Helicopters 1,624

Natural Gas Engines 1,310

Glycol Dehydrators 1,158

Storage Tanks 928

Military Vessels 455

LOOP 420

Diesel Engines 406

Commercial Fishing Vessels 218

Recreational Vessels 197

Minor Sources 157

Pipelaying Operations 128

Survey Vessels 105

Natural Gas, Diesel, and Dual-fuel 

Turbines 103

Mud Degassing 23

Boilers/heaters/burners 41

Drilling Equipment 37

Combustion Flares 30

Amine Units 0.2

Total Emissions (tpy)a 100,421

a Totals may not sum due to rounding.

154
Table 7-9. Total greenhouse gas emission estimates for platform sources

Equipment Types

CO2

Emissions 

(tpy)

CH4

Emissions 

(tpy)

N2O 

Emissions 

(tpy)

CO2e 

Emissions 

(tpy)a

Amine Units 0 2 0 45

Boilers/heaters/burners 891,652 17 16 896,992

Diesel Engines 407,575 13 N/Ab 407,851

Drilling Equipment 76,961 1.5 N/A 76,993

Combustion Flares 604,002 366 11 615,029

Fugitive Sources 0 61,232 0 1,285,862

Glycol Dehydrators N/A 7,859 N/A 165,048

Losses From Flashing 330 14,231 0 299,175

Minor Sources 0 476 0 9,987

Mud Degassing 2 505 0 10,615

Natural Gas Engines 2,567,943 12,619 N/A 2,832,942

Natural Gas, Diesel, and Dualfuel Turbines 7,329,476 400 140 7,381,165

Pneumatic Pumps 401 21,155 0 444,666

Pressure/level Controllers 871 16,739 0 352,384

Storage Tanks 0 877 0 18,414

Cold Vents 2,815 134,863 0 2,834,938

Total Emissions (tpy)c 11,882,029 271,355 167 17,632,106 a CO2e = 21 for CH4 and 310 for N2O. b N/A = not available c Totals may not sum due to rounding.

155
Table 7-10. Total greenhouse gas emissions for non-platform sources

Source Category

CO2

Emissions 

(tpy)

CH4

Emissions 

(tpy)

N2O

Emissions

(tpy)

CO2e 

Emissions 

(tpy)a

Drilling Rigs 2,748,279 21 110 2,782,820

Pipelaying Operations 609,535 5 18 615,220

Support Helicopters 160,752 10 11 164,373

Support Vessels 13,002,103 75 386 13,123,338

Survey Vessels 504,714 3 15 509,427

Total OCS Oil/Gas Production 

Sources (tpy) 17,025,383 114 540 17,195,178

Biogenic and Geogenic 

Sources 2,284 1,876 1,948 645,560

Commercial Fishing 585,204 2 17 590,516

Commercial Marine Vessels 4,301,312 33 172 4,355,325

LOOP 89,958 0.5 3 90,888

Military Vessels 455,071 4 18 460,735

Vessel Lighteringc 0 N/Ab 0 0

Recreational Vessels 244,483 N/A N/A 244,483

Total Emissions (tpy)d 22,703,695 2,029 2,698 23,582,684 a CO2e = 21 for CH4 and 310 for N2O. b N/A = Not available c Vessel estimates are reflected in commercial marine vessels. d Totals may not sum due to rounding.

156
Table 7-11. Total platform and non-platform emission estimates for greenhouse gases

Equipment/

Source Category

CO2

Emissions

(tpy)

CH4 

Emissions 

(tpy)

N2O 

Emissions

(tpy)

CO2e 

Emissions 

(tpy)a

Total Platform Emissions 11,882,029 271,355 167 17,632,106

Drilling Rigs 2,748,279 21 110 2,782,820

Pipelaying Operations 609,535 5 18 615,220

Support Helicopters 160,752 10 11 164,373

Support Vessels 13,002,103 75 386 13,123,338

Survey Vessels 504,714 3 15 509,427

Total OCS Oil/Gas 

Production Source 

Emissions

28,907,412 271,469 707 34,827,284

Total Non-OCS Oil/Gas 

Production Source 

Emissions

5,678,312 1,915 2,158 6,387,507

Total Emissions (tpy)b 34,585,724 273,384 2,865 41,214,791 a CO2e = 21 for CH4 and 310 for N2O. b Totals may not sum due to rounding. 

157
Table 7-12. Annual CO2 emission estimates for all sources

Equipment/Source Category CO2 Emissions (tpy)

Support Vessels 13,002,103

Natural Gas, Diesel, and Dual-fuel Turbines 7,329,476

Commercial Marine Vessels 4,301,312

Drilling Rigs 2,748,279

Natural Gas Engines 2,567,943

Boilers/heaters/burners 891,652

Pipelaying Operations 609,535

Combustion Flares 604,002

Commercial Fishing Vessels 585,204

Survey Vessels 504,714

Military Vessels 455,071

Diesel Engines 407,575

Recreational Vessels 244,483

Support Helicopters 160,752

LOOP 89,958

Drilling Equipment 76,961

Cold Vents 2,815

Biogenic and Geogenic Sources 2,284

Losses From Flashing 330

Pressure/level Controllers 871

Pneumatic Pumps 401

Mud Degassing 2

Total Emissions (tpy)a 34,585,724 a Totals may not sum due to rounding.

158
Table 7-13. Annual CH4 emission estimates for all sources

Equipment/Source Category CH4 Emissions (tpy)

Cold Vents 134,863

Fugitives 61,232

Losses From Flashing 14,231

Pneumatic Pumps 21,155

Pressure/level Controllers 16,739

Natural Gas Engines 12,619

Glycol Dehydrators 7,859

Biogenic and Geogenic Sources 1,876

Storage Tanks 877

Mud Degassing 505

Minor Sources 476

Natural Gas, Diesel, and Dual-fuel Turbines 400

Combustion Flares 366

Support Vessels 75

Drilling Rigs 21

Commercial Marine Vessels 33

Boilers/heaters/burners 17

Diesel Engines 13

Support Helicopters 10

Pipelaying Operations 5

Military Vessels 4

Survey Vessels 3

Amine Units 2

Commercial Fishing Vessels 2

Drilling Equipment 1.5

LOOP 0.5

Total Emissions (tpy)a 273,384 a Totals may not sum due to rounding.

159
Table 7-14. Annual N2O emission estimates for all sources

Equipment/Source Category N2O Emissions (tpy)

Biogenic and Geogenic Sources 1,948

Support Vessels 386

Commercial Marine Vessels 172

Natural Gas, Diesel, and Dual-fuel 

Turbines 140

Drilling Rigs 110

Military Vessels 18

Pipelaying Operations 18

Commercial Fishing Vessels 17

Boilers/heaters/burners 16

Survey Vessels 15

Combustion Flares 11

Support Helicopters 11

LOOP 3

Total Emissions (tpy)a 2,865

a Totals may not sum due to rounding.

160
Table 7-15. Annual CO2e emission estimates for all sources

Equipment/Source Category CO2eEmissions (tpy)a

Support Vessels 13,123,338

Natural Gas, Diesel, and Dual-fuel Turbines 7,381,165

Commercial Marine Vessels 4,355,325

Cold Vents 2,834,938

Natural Gas Engines 2,832,942

Drilling Rigs 2,782,820

Fugitives 1,285,862

Losses From Flashing 299,175

Boilers/heaters/burners 896,992

Biogenic and Geogenic Sources 645,560

Combustion Flares 615,029

Pipelaying Operations 615,220

Commercial Fishing Vessels 590,516

Survey Vessels 509,427

Military Vessels 460,735

Pneumatic Pumps 444,666

Diesel Engines 407,851

Pressure/level Controllers 352,384

Recreational Vessels 244,483

Glycol Dehydrators 165,048

Support Helicopters 164,373

LOOP 90,888

Drilling Equipment 76,993

Storage Tanks 18,414

Mud Degassing 10,615

Minor Sources 9,987

Amine Units 45

Vessel Lighteringb 0

Total Emissions (tpy)c 41,214,791 a CO2e = 21 for CH4 and 310 for N2O. b Vessel estimates are reflected in commercial marine vessels. c Totals may not sum due to rounding.

161
7.3 LIMITATIONS

As with previous BOEM Gulfwide emission inventory studies, the key limitation of the 2011 

OCS platform emission estimates is associated primarily with the lack of direct source test data. 

BOEM requires that platform operators provide only activity data for sources such as fugitives, 

amine units, glycol dehydrators, losses from flashing, and cold vents. BOEM then applies 

emission factors to the activity data to yield emission estimates. In compiling the GOADS-2011 

activity datasets, BOEM often must interpret inconstitently-reported data. For example, operators 

may flag a platform as inactive for a given month, yet populate fuel usage and other data fields. 

Though these inconsistencies are handled in the same manner for all platforms, it still limits the 

confidence of the resulting emission estimates. For the reported volumes vented and flared, 

BOEM conducted extensive research in order to reconcile the GOADS-2011 reported volumes 

with those reported to through the OGOR forms (Form ONRR-4054-B). Though BOEM worked 

directly with the platform operators in this effort, limitations likely still exist due to the way the 

reported data were interpreted. The requirement that platform operators submit source test data, 

calculated emission estimates based on source specific- emission factors, or calculated emission 

estimates based on industry-developed software would reduce the uncertainty in the emissions 

estimates. For fugitive sources, the current estimation method is based on out-of-date estimation 

methods and surrogate component counts. For glycol dehydrators and amine units, emission 

estimates would be improved if operators provided estimates and documentation from the GTI 

AIRCalc Software Program.

Limitations exist for some of the non-platform emission estimates based on the availability of 

activity data, as well as the quality of the emission factors. As discussed in Section 6, emission 

estimates for all marine diesel engines were developed using USEPA emission factors that 

specifically represent 2011, accounting for replacement of older vessels with new vessels that 

comply with appropriate Category 1, 2, and 3 engine regulations. To use these emission factors, 

assumptions were made about the engine category associated with each vessel type included in 

the GOM inventory. More detailed information about the different category engines used by each 

vessel type would improve the emission estimates by better matching of engines to emission 

factors.

AIS data were used to spatially allocate activity and emissions for commercial marine vessels 

(bulk, cargo, tankers, containerships, tugs), LOOP tanker traffic, lightering traffic, and support 

vessels. The AIS data are limited to locations where there are transmitters. As more transmitters 

are installed on offshore platforms, the resolution of the spatial traffic data will improve. 

Initially, attempts were made to use the AIS data to quantify activity in the GOM, but it was 

difficult to distill the data into a useful format. Instead, vessel activities were based on U.S. 

Army Corps of Engineer’s Entrance and Clearance data that documented a vessel’s previous and 

next port of call. These routes were assigned distances for transiting the central and western 

federal waters of the GOM along major shipping lanes. These distances were divided by the 

vessel’s speed to estimate hours of operation. An alternative approach using AIS time stamp data 

that documents when a vessel enters and leaves federal waters will provide more accurate 

estimate of hours of operation.

162
Support vessels represent one of the larger non-platform emissions sources. For the 2011 

inventory, vessel-specific data were compiled for all identified support vessels. These data 

quantified the number and engines used on these vessels. To estimate emissions from these 

vessels, assumptions needed to be made regarding utilization rates, hours of operation in port and 

at sea, time spend cruising and maneuverings adjacent to platform during loading and unloading 

operations, and typical engine loads for cruising and maneuvering. More detailed data related to 

these assumptions will help improve the support vessel emission estimates. 

For the LOOP, activity data that were previously available to the public are no longer 

available due to security issues, such that detailed matching of vessels and their operations was 

not possible. Instead, 2008 estimates were adjusted to reflect the recent decline in crude oil 

importation. A significant improvement was made in the 2011 inventory to lightering by 

including two other lightering services, one company provided data on the volume of crude 

transferred. The volume of crude handled by the second company was estimated based on their 

market share of lightering traffic. Actual data from all three companies would improve the 

accuracy of the lightering emission estimates. The unavailability of up-to-date vessel data for the 

U.S. Navy, especially where Naval and possibly some Coast Guard vessels have been moved 

away from the GOM to support actions in foreign countries, makes it difficult to accurately 

assess emissions from these vessels. It is likely that current estimates of Naval emissions overestimate actual emissions.

BOEM updated the compilation of helicopter emission factors using Swiss helicopter data 

that allowed for differentiation between medium and heavy duty twin engine helicopters. It 

should be noted, however, that the compiled emission factors still represent available data and 

not the complete universe of helicopters that operate in the GOM. The updated helicopter factors 

are grouped relative to size and engine configuration, but there is large variance in the emission 

factor values within each helicopter group. As more helicopter emission factor data is published 

and included in the GOM helicopter database, it will be possible to more accurately match 

helicopters and their emission factors, providing more accurate emission estimates. Another 

limitation to the helicopter data concerns the activity data; for 2011 and earlier inventories, the 

primary data source for helicopter activity is HSAC data, which is voluntarily provided by the 

helicopter service companies. These data are adjusted to include helicopter activity from 

companies that do not provide data, but more accurate helicopter fleet and activity data would 

significantly improve emission estimates for this source category. Currently, the FAA is 

developing similar datasets to that used by the AIS for marine vessels. BOEM is evaluating the 

possibility of using the FAA data to better quantify helicopter activity.

One other limitation to note is as with the previous inventories, this inventory provides 

emission estimates for directly-emitted pollutants; it does not take into account changes of the 

emissions due to in-plume chemistry. These changes are based on the reactivity of the individual 

pollutant species, and transformation rates to secondary pollutants. For example, the inventory 

does not quantify how the NOx and VOC emissions affect the chemical composition of the 

marine boundary layer, particularly in the formation of ozone and hydroxyl radicals. The

transformation of pollutants needs to be modeled in order to account for all factors that impact 

the transformation rate.

163
7.4 COMPARISON WITH OTHER STUDIES

Now that BOEM has completed four Gulfwide emission inventory studies, the inventory 

results between the studies can be compared. The comparisons provided here focus on the Year 

2008 Gulfwide Emission Inventory Study (Wilson et al. 2010). In the Year 2008 Gulfwide 

Emission Inventory Study (Wilson et al. 2007), the calendar year 2008 emission estimates were 

directly compared with those of the Year 2005 Gulfwide Emission Inventory Study (Wilson et al. 

2007). In the report for the Year 2005 Gulfwide Emission Inventory Study (Wilson et al. 2007), 

the calendar year 2005 emission estimates were directly compared with those of the 2000 

Gulfwide Emission Inventory for Regional Haze and Ozone Modeling (Wilson et al. 2004), and 

the 2000 Gulfwide Emission Inventory for Regional Haze and Ozone Modeling report (Wilson et 

al. 2004) provided a detailed comparison of the 2000 inventory with the Gulf of Mexico Air 

Quality Study (Systems Applications International et al. 1995); those comparisons are not 

reproduced here. The following discussion compares the emission estimates developed for 

calendar year 2008 and the 2011 emission estimates by equipment type, source category, and 

pollutant. Similarities and differences between the two inventories are discussed.

Overall comparisons of pollutant-specific emission estimates for platform and non-platform 

sources are presented in Table 7-16 (for criteria pollutants) and Table 7-17 (for greenhouse 

gases). For criteria pollutants, the overall CO emission estimate varies slightly from 2008 to 

2011. A 12% increase is seen in the overall VOC emission estimate. Larger differences are seen, 

however, in the NOx (25% increase), PM10 (33% increase), and SO2 estimates (23% decrease). 

For greenhouse gases, the overall N2O emission estimate varies slightly from 2008 to 2011. A 

significant increase is seen in the CO2 estimates (37%), and a decrease is seen in the CH4 

estimates (36%). The following sections examine these differences for the platform and nonplatform emission estimates.

Table 7-16. Comparison of total platform and non-platform criteria pollutant for years 2008 and 

2011 emission estimates

Calendar Year

CO 

Emissions 

(tpy)

NOX

Emissions 

(tpy)

PM10

Emissions 

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

2008 124,764 382,015 11,640 81,304 89,696

2011 131,328 478,286 15,463 62,827 100,421

Percent 

Difference 5% 25% 33% -23% 12%

Table 7-17. Comparison of total platform and non-platform greenhouse gas emission estimates for 

Years 2008 and 2011

Calendar Year CO2 Emissions 

(tpy)

CH4 Emissions 

(tpy)

N2O Emissions 

(tpy)

CO2e Emissions 

(tpy)a

2008 25,257,583 424,664 2,661 35,000,497

2011 34,585,724 273,384 2,865 41,214,791

Percent Difference 37% -36% 8% 18% a CO2e = 21 for CH4 and 310 for N2O.

164
7.4.1 OCS Oil and Gas Production Platforms

As noted previously, the emission estimation methods for platform sources are relatively 

unchanged between the 2008 and 2011 inventories. Any changes in emission levels, then, are 

due to the number of platforms included in the inventory, increases or decreases in activity 

levels, fuel type (for combustion sources), and how well the operators interpreted and completed 

the requested fields in the GOADS activity data collection software. In 2008, 113 companies 

submitted data for 3,026 active platforms; 1,538 were flagged as minor sources. In 2011, 96

companies submitted data for 2,544 active platforms; 1,366 were flagged as minor sources.

As shown in Table 7-18, for platform sources, the CO and VOC emission estimates show 

slight decreases in emissions from 2008 to 2011 (14% and 10%, respectively), while the NOx

and PM10 emission estimates show slight increases (13% and 11%, respectively). The SO2

emission estimate, however, shows greater than 200% increase. This increase is primarily due to 

the natural gas, diesel, and dual-fuel turbine emission estimates. The 2008 turbine emission 

estimate included only natural gas turbines. 

The 2011 natural gas engine estimates drive the overall decrease in estimated emissions for 

CO, indicating a decrease in reported activity levels. The decrease is counter-balanced 

somewhat, however, by an increase in reported activities (and emission estimates) for 

boilers/heaters/burners, diesel engines, and natural gas, diesel, and dual-fuel turbines.

The decrease in the 2011 emission estimates for VOC is driven by the fugitives and pressure 

level controllers emission estimates, although losses from flashing emissions increased 

significantly. Similar to the SO2 estimate, the increase seen in the NOx and PM10 emission 

estimates is driven by turbines.

Table 7-19 presents a comparison of emission estimates for greenhouse gases between the 

2008 inventory and the 2011 inventory. Overall, the CO2e emission estimate shows a 2% 

increase, as the CO2 emission estimate increased 41%. Similar to the increase in the SO2

emission estimate, the overall increase in greenhouse gas emissions is driven in large part by the 

CO2 and CH4 natural gas, diesel, and dual-fuel turbine estimates. The CH4 emission estimates for 

flashing losses also contributed to the increase.

165
Table 7-18. Comparison of Years 2008 and 2011 OCS platform criteria pollutant emission estimates

2008 2011

Source Category

CO 

Emissions 

(tpy)

NOX

Emissions 

(tpy)

PM10

Emissions 

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

CO 

Emissions 

(tpy)

NOx 

Emissions 

(tpy)

PM10 

Emissions

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Amine Units 0 0 0 3 1 0 0 0 4 0.2

Boilers/heaters/

Burners 542 910 22 8 35 621 1,156 14 5 41

Diesel Engines 1,808 7,427 306 711 351 2,187 8,927 349 827 406

Drilling Equipment 545 2,060 37 260 51 396 1,493 17 24 37

Combustion Flares 1,304 254 2 2 22 1,252 425 5 3 30

Fugitives 0 0 0 0 21,476 0 0 0 0 16,403

Glycol Dehydrators 0 0 0 0 2,573 0 0 0 0 1,158

Losses From 

Flashing 0 0 0 0 950 0 0 0 0 640

Minor Sources 0 0 0 0 213 0 0 0 0 157

Mud Degassing 0 0 0 0 25 0 0 0 0 23

Natural Gas 

Engines 75,103 52,538 250 15 1,310 62,024 44,863 224 14 1,310

Natural Gas, 

Diesel, and Dualfuel Turbines 2,844 11,096 66 21 73 3,859 27,264 149 2,320 103

Pneumatic Pumps 0 0 0 0 1,893 0 0 0 0 2,182

Pressure/level 

Controllers 0 0 0 0 3,939 0 0 0 0 2,064

Storage Tanks 0 0 0 0 909 0 0 0 0 928

Cold Vents 0 0 0 0 27,003 0 0 0 0 29,244

Total Emissions 

(tpy)a 82,146 74,286 682 1,021 60,824 70,339 84,128 759 3,197 54,724 a Totals may not sum due to rounding.

166
Table 7-19. Comparison of Years 2008 and 2011 OCS platform greenhouse gas emission estimates

2008 2011

Source 

Category

CO2

Emissions 

(tpy)

CH4

Emissions

(tpy)

N2O

Emissions

(tpy)

CO2e

Emissions

(tpy)

CO2

Emissions

(tpy)

CH4

Emissions

(tpy)

N2O

Emissions

(tpy)

CO2e

Emissions

(tpy)a

Amine Units 0 8 0 171 0 2 0 45

Boilers/Heaters/

Burners 850,228 14 14 854,806 891,652 17 16 896,992

Diesel Engines 335,392 10 N/Ab 335,608 407,575 13 N/A 407,851

Drilling 

Equipment 106,250 N/A N/A 106,250 76,961 1.5 N/A 76,993

Combustion 

Flares 419,083 442 7 430,640 604,002 366 11 615,029

Fugitives 0 91,468 0 1,920,838 0 61,232 0 1,285,862

Glycol 

Dehydrators N/A 19,505 N/A 409,615 N/A 7,859 N/A 165,048

Losses From 

Flashing 475 20,890 0 439,169 330 14,231 0 299,175

Minor Sources 0 646 0 13,561 0 476 0 9,987

Mud Degassing 1 194 0 4,076 2 505 0 10,615

Natural Gas 

Engines 2,886,612 12,244 N/A 3,143,735 2,567,943 12,619 N/A 2,832,942

Natural Gas, 

Diesel, and 

Dual-fuel 

Turbines

3,814,880 298 104 3,853,392 7,329,476 400 140 7,381,165

Pneumatic 

Pumps 414 20,426 0 429,355 401 21,155 0 444,666

Pressure/level 

Controllers 580 31,448 0 660,988 871 16,739 0 352,384

Storage Tanks 0 901 0 18,919 0 877 0 18,414

Cold Vents 3,251 224,211 0 4,711,689 2,815 134,863 0 2,834,938

Total Emissions 

(tpy)c 8,417,165 422,707 125 17,332,814 11,882,029 271,355 167 17,632,106 a CO2e = 21 for CH4 and 310 for N2O. b N/A = Not available c Totals may not sum due to rounding.

7.4.2 Non-Platform Sources

As shown in Table 7-20, when comparing 2008 and 2011 emission estimates for nonplatform sources, there is a significant increase in criteria pollutant emission estimates, with the 

exception of SO2. The SO2 emission estimate shows a 26% decrease from 2008 to 2011, due to 

reduction in vessel activities and application of the most recent USEPA emission factors. These 

USEPA factors have lower sulfur values for smaller vessels equipped with Category 1 and 2 

propulsion engines, such as commercial fishing, pipelaying, crew and coast guard patrol boats 

and support vessels, generators, and pumps associated with the LOOP.

167
Table 7-20. Comparison of Years 2008 and 2011 OCS non-platform criteria pollutant emission estimates

2008 2011

Source Category

CO 

Emissions 

(tpy)

NOX

Emissions 

(tpy)

PM10

Emissions 

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

CO 

Emissions 

(tpy)

NOx 

Emissions 

(tpy)

PM10 

Emissions

(tpy)

SO2

Emissions 

(tpy)

VOC 

Emissions 

(tpy)

Drilling Rigs 5,343 58,288 971 7,772 971 6,248 69,135 2,634 20,863 2,750

Pipelaying 

Operations 2,186 10,535 398 1,789 398 2,124 9,480 350 117 128

Support Helicopters 13,636 1,114 217 275 2,693 2,163 753 23 112 1,624

Support Vessels 12,880 135,222 2,342 18,221 2,342 35,686 175,558 6,435 2,157 4,016

Survey Vessels 141 1,690 26 204 26 1,760 7,851 290 97 105

Total OCS Oil/Gas 

Production Sources 

(tpy) 34,186 206,849 3,954 28,261 6,430 47,981 262,777 9,732 23,346 8,623

Biogenic and 

Geogenic Sources 0 0 0 0 14,358 0 0 0 0 14,357

Commercial Fishing 

Vessels 681 8,120 124 988 124 1,206 6,917 245 85 218

Commercial Marine 

Vessels 6,593 79,329 6,603 49,009 2,794 9,779 108,203 4,122 32,651 4,303

LOOP 136 1,832 33 219 613 313 1,399 52 17 420

Military Vessels 702 8,539 158 1,409 130 1,035 11,448 436 3,455 455

Vessel Lighteringa 320 3,060 86 397 4,423 0 0 0 0 17,113

Recreational 

Vessels N/A N/A N/A N/A N/A 675 3,127 118 75 197

Total Non-OCS 

Oil/Gas Production 

Sources (tpy) 8,432 100,880 7,004 52,022 22,442 13,008 131,094 4,973 36,283 37,063

Total Non-Platform 

Emissions (tpy)b 42,618 307,729 10,958 80,283 28,872 60,989 393,871 14,705 59,629 45,686 a Vessel estimates for 2011 are reflected in commercial marine vessels. b Totals may not sum due to rounding.

168
The increased CO, NOx, PM, and VOC estimates, 43%, 28%, 34%, and 58% respectively, 

are primarily due to the use of updated USEPA emission factors. The application of the USEPA 

factors is compounded by increased activity in 2011 for support, survey, and commercial marine 

vessels. For other categories such as commercial fishing, pipelaying drilling rigs and the LOOP, 

reductions in activity in 2011 partially offset the effects of the USEPA factors.

The updated USEPA emission factors and activity data yielded an overall increase in 

greenhouse gas emissions of 33% as noted in Table 7-21. Note that this increase is roughly 

similar for OCS oil and gas production sources and non-oil and gas sources. The increase in 

GHG emissions is primarily driven by source categories that had an increase in activity relative 

to 2008; these include support, survey, and commercial marine vessels.

As with all source categories in the 2011 inventory, 2011 activity data and emissions 

estimates were compared to the 2008 inventory as a quality check. The drilling rig activity data 

were obtained from BOEM for both 2008 and 2011. In 2008 there was a total of 39,805 days of 

drilling in the GOM. In 2011 there was a total of 19,863 days of drilling in the GOM. The 

drilling rig emission factors were also revised for the 2011 inventory. The combination of 

reduced activity and application of the latest USEPA emission factors yielded larger emission 

estimates between 2008 and 2011. In 2011, pipeline repair activities were in line with 2008 

levels, but new pipeline construction was approximately 50% of the 2008 level. 

Compared to 2008, the 2011 inventory provides much better coverage of support vessel 

activity due to the use of AIS data. The AIS data identified 682 unique vessels that operators 

classified as offshore support vessels. These vessels were matched to vessel characteristics data, 

providing detailed kW ratings for each vessels propulsion engine. As a result, support vessels 

form a much larger contribution of activity and emissions in the 2011 inventory than identified in 

previous inventories. The combination of a more complete inventory of support vessels and use 

of the latest USEPA emission factors has yielded higher emission estimates for 2011 than 2008. 

There was an increase in the total estimated survey vessel activity due to the identification of 

16 additional survey vessels. 

The activity data for the 2011 commercial reef fishing vessels (3,944 hours) is considerably 

less than the 2008 reef fishing vessels activity data (888,120 hours). This is due to a correction 

made by NFMS to the 2011 code that compiled the data provided to BOEM. Despite the overall 

reduction in commercial fishing activity, some pollutants have higher emissions in 2011 due to 

the use of the latest USEPA emission factors.

169
Table 7-21. Comparison of Years 2008 and 2011 OCS non-platform greenhouse gas emission estimates

2008 2011

Source Category

CO2

Emissions 

(tpy)

CH4

Emissions 

(tpy)

N2O 

Emissions 

(tpy)

CO2e 

Emissions 

(tpy)a

CO2 

Emissions 

(tpy)

CH4 

Emissions 

(tpy)

N2O

Emissions

(tpy)

CO2e

Emissions 

(tpy)a

Drilling Rigs 3,166,971 19 151 3,214,188 2,748,279 21 110 2,782,820

Pipelaying Vessels 712,570 8 31 722,348 609,535 5 18 615,220

Support Helicopters 1,373,574 N/Ab N/A 1,373,574 160,752 10 11 164,373

Support Vessels 7,418,855 47 352 7,528,962 13,002,103 75 386 13,123,338

Survey Vessels 83,500 1 4 84,761 504,714 3 15 509,427

Total OCS Oil/Gas 

Production Sources (tpy) 12,755,470 75 538 12,923,833 17,025,383 114 540 17,195,178

Biogenic and Geogenic 

Sources 2,284 1,874 1,948 645,518 2,284 1,876 1,948 645,560

Commercial Fishing 

Vessels 411,326 3 19 408,369 585,204 2 17 590,516

Commercial Marine 

Vessels 3,013,948 N/A N/A 3,013,948 4,301,312 33 172 4,355,325

LOOP 88,564 1 4 89,825 89,958 0.5 3 90,888

Military Vessels 417,677 3 20 423,940 455,071 4 18 460,735

Vessel Lighteringc 160,038 2 7 162,250 0 N/A 0 0

Recreational Vessels N/A N/A N/A N/A 244,483 N/A N/A 244,483

Total Non-OCS Oil/Gas 

Production Sources (tpy) 4,093,837 1,883 1,998 4,743,850 5,678,312 1,915 2,158 6,387,507

Total Non-Platform 

Emissions (tpy)d 16,849,307 1,958 2,536 17,667,683 22,703,695 2,029 2,698 23,582,684 a CO2e = 21 for CH4 and 310 for N2O. b N/A = Not available c 2011 vessel estimates are reflected in commercial marine vessels. d Totals may not sum due to rounding.

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Compared to the 2008, CMV emissions appear substantially higher in 2011, due to the use of 

improved vessel activity data. The 2008 CMV emission estimates were obtained from USEPA to 

ensure that the emissions developed for BOEM were consistent with emission estimates 

developed for recent rulemaking and the National Emission Inventory. The 2008 CMV 

emissions data provided by USEPA were derived from recent regulatory programs related to 

vessels equipped with Category 3 propulsion engines. The CMV component of the 2011 

inventory was developed using vessel specific entrance and clearance data from the U.S. Army 

Corps of Engineers in conjunction with AIS traffic density data. The 2011 detailed data is of 

better quality than the top-down 2008 estimates as it accountings for smaller vessels not included 

in the USEPA’s Category 3 vessel inventory. It should also be noted that the 2011 CMV 

category includes tankers involved in lightering and the LOOP. Emissions associated with the 

LOOP are accounted for in the CMV estimates derived from AIS data, thus, the 2011 LOOP 

emissions are limited to the support vessels, platform equipment and evaporative emissions. The 

2011 LOOP activity and emissions reflect a 30% decrease in crude imports which partially 

offsets the effect that the USEPA emission factors have on the emission estimates. Similarly, the 

vessel activity and emissions associated with lightering are already accounted for in the CMV 

estimates, the 2011 lightering emissions are limited to evaporative emissions resulting from 

transferring crude to the smaller shuttle tankers and ballasting activities. The 2011 lightering 

emissions, are larger than the 2008 estimates as a more complete inventory of lightering service 

providers was developed; in 2008 one company (Skaugen Petrotrans) was included in the 

inventory while in 2011 two additional companies (Overseas Shipholding Group Lightering and 

AET Lightering) were added that have higher activity levels than the Skaugen Petrotans.

7.5 RECOMMENDATIONS

As discussed in Section 7.3, a key limitation for the 2011 OCS platform emissions inventory 

is that emissions are not estimated using direct source test data. In lieu of requiring that platform 

operators submit source test data or prepare and submit emission estimates, BOEM should 

continue to make use of the most recent emission factors and research results in developing the 

emission estimates for platform equipment. For example, there are a number of ongoing USEPA 

studies examining the regulatory requirements and flare destruction and removal efficiencies, as 

well as enforcement activities targeting flare operations. In addition, OCS platforms under 

BOEM jurisdiction that are estimated to emit more than 25,000 metric tons of CO2e are subject 

to the USEPA Mandatory Reporting of Greenhouse Gases Rule (Federal Register 2009). 

USEPA summary data indicate that 106 offshore production platforms reported under the rule. 

BOEM should evaluate the data provided by these platforms to identify potential areas for 

improvement in the emission estimation methods and emission factors, especially for fugitive 

sources and flare operations. For glycol dehydrators, BOEM could require that operators submit 

emission estimates and supporting documentation from the GTI AIRCalcTM Software Program

(BOEM’s contractor runs the program for amine units, using detailed data collected from the 

operators). For losses from flashing, the BOEM collects information from the platform operators 

and calculates emissions using the Vasquez-Beggs correlation equations. BOEM could instead 

require that operators collect pressurized oil samples from separators or heater treaters and 

perform laboratory flash analyses to the obtain GOR and chemical composition, or use a process 

simulator such as Hysim® or Prosim® and provide documentation.

171
As discussed in Section 4.4.7, in addition to GOADS reporting requirements, BOEM also 

collects monthly volume vented and flared data from production operators through OGOR 

forms. 30 CFR Part 250, Oil and Gas and Sulphur Operations in the Outer Continental Shelf-Oil 

and Gas Production Requirements, now includes requirements that operators meter flared and 

vented gas volumes on facilities that process more than 2,000 barrels of oil per day, and to report 

flared gas separately from vented gas on the OGOR forms (Federal Register 2010). Future 

inventory development efforts should again rely on the use of these reported data. 

Other recommendations for future inventory efforts for OCS oil and gas production platforms 

include validating or updating the range check values, surrogate stack parameters, and surrogate 

fugitive component counts, given changes in offshore platform operations (e.g., deepwater 

platforms are more now common). In addition, an evaluation of the surrogate fuel usage rates 

used to estimate emissions for pneumatic pumps and pressure level controllers is needed, based 

on recent studies by the British Columbia Ministry of Environment and the Canadian 

Association of Petroleum Producers, and the University of Texas Center for Energy and 

Environmental Resources. There is also ongoing research specific to tank emission factors. 

Recent evidence suggests that emissions from tanks may increase due to temporary increases in 

tank pressure as liquids are dumped to tanks from separators operating at pressures greater than 

one atmosphere. 

For non-platform sources, the main recommendation for future inventory efforts is to develop 

a technique that better uses the AIS vessel tracking data to time-stamp when vessels enter and 

leave federal waters of the Central and Western areas of the GOM to accurately estimate hours of 

operation in the region. These vessel-specific data can be matched up with vessel characteristics 

using sources such as the IHS’s Registry of Ships. This will provide more accurate estimates of 

activity and emissions. Detailed AIS information about the vessels that discharge product 

through the LOOP would also be helpful in assessing the carrying capacity of the vessels that 

visit the LOOP, allowing for more accurate estimate of evaporative emissions from ballasting.

Survey vessel estimates can also be improved by compiling impact assessments for survey 

activities if publicly available. Aternatively, survey of local seismic survey companies may 

provide useful data about the GOM fleet its characterictics and operations.

An alternative approach to estimating helicopter activities and emissions is the use of the 

FAA NextGen tracking data. These data are similar to the AIS data used to track ship 

movements. Flight paths of individual helicopters can be mapped to BOEM lease blocks and 

hours of operation calculated. This approach would require purchase of helicopter flight data 

from a vendor who would distill the data into a useful format, but would provide a more accurate

assessment of helicopters, their flight paths, and an indication of monthly activity variance.

Given the limited data currently available for Navy vessel operations, it is recommended that 

a special study be developed to better quantify Naval vessel characteristics and activity in the 

GOM. To facilitate the exchange of data from the Navy, it may be necessary for senior 

Department of Interior staff to coordinate the data request with the U.S. Navy Atlantic Fleet 

command.

172
Additional research is also needed to confirm the reasonableness of the variance noted in the 

monthly drilling rig, pipelaying, support vessels, and commercial fishing temporal adjustment 

factors. Future non-platform inventory efforts should also evaluate how new pipelaying 

construction activities differ from maintenance operations with regard to required vessel support 

and hours of operation.

Another recommendation is to continue to research the availability of emission factors for 

black carbon, particularly for diesel engines and marine vessels. Black carbon is of concern 

because of health concerns and potential climate impacts. Black carbon is emitted directly into 

the atmosphere as PM2.5 and influences climate by directly absorbing light, reducing the 

reflectivity (“albedo”) of snow and ice through deposition, and interacting with clouds. A 2012 

black carbon Report to Congress and a study currently underway by the Commission for 

Environmental Cooperation should yield results that can be incorporated into future BOEM 

inventories. 

Last, at the completion of the 2014 inventory development effort, BOEM will have emission 

estimates for six consecutive inventory studies that span 2000 through2014. Detailed and 

comprehensive expanded comparisons and deviations (trends analyses) will benefit the BOEM in 

a number of ways, including preparation of NEPA documents and predicting future emission 

trends in spatial terms. In addition, it would be beneficial to perform a top-down assessment of 

the 2011 emission estimates, similar to assessments that are performed with on-shore emissions 

inventories. In this type of assessment, the bottom-up emissions inventory is evaluated by 

performing air quality modeling using the inventory, and the predictions are coupled with 

ambient observations in a top-down performance evaluation. Sources of measured ambient data 

include satellite measurements of total column masses of pollutants, and measurements made by 

aircraft overflights. This type of assessment could determine whether the inventory correctly 

predicts that specific areas are experiencing increases or decreases in emissions.

173

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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 the 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 communities.

The Bureau of Ocean Energy Management Mission

The Bureau of Ocean Energy Management (BOEM) works to manage the 

exploration and development of the nation's offshore resources in a way that 

appropriately balances economic development, energy independence, and 

environmental protection through oil and gas leases, renewable energy 

development and environmental reviews and studies.