U.S. Department of the Interior

Bureau of Ocean Energy Management, 

 Regulation and Enforcement 

Gulf of Mexico OCS Region 

OCS Study 

BOEMRE 2010-045 

Year 2008 Gulfwide Emission Inventory 

Study 

Authors 

Darcy Wilson 

Richard Billings 

Regi Oommen 

Bryan Lange 

Jennifer Marik 

Susan Mcclutchey 

Heather Perez 

Prepared under BOEMRE Contract 

M07PC13189 

by 

Eastern Research Group 

1600 Perimeter Park Drive 

Morrisville, NC 27560 

Published by 

New Orleans 

December 2010
iii 

DISCLAIMER 

This report was prepared under contract between the Bureau of Ocean Energy Management, 

Regulation and Enforcement (BOEM) and Eastern Research Group, Inc. (ERG). This report has 

been technically reviewed by BOEM, and it has been approved for publication. Approval does 

not signify that the contents necessarily reflect the views and policies of BOEM, nor does 

mention of trade names or commercial products constitute endorsement or recommendation for 

use. It is, however, exempt from review and compliance with BOEM editorial standards. 

REPORT AVAILABILITY 

This report is available only in compact disc format from the Bureau of Ocean Energy 

Management, Regulation and Enforcement, Gulf of Mexico OCS Region, at a charge of $15.00, 

by referencing OCS Study BOEMRE 2010-045. The report may be downloaded from the 

BOEM website through the Environmental Studies Program Information System (ESPIS). You 

will be able to obtain this report also from the National Technical Information Service in the near 

future. Here are the addresses. You may also inspect copies at selected Federal Depository 

Libraries. 

 U.S. Department of the Interior U.S. Department of Commerce 

 Bureau of Ocean Energy Management, National Technical Information Service 

 Regulation and Enforcement 5285 Port Royal Road 

 Gulf of Mexico OCS Region Springfield, Virginia 22161 

 Public Information Office (MS 5034) Phone: (703) 605-6040 

 1201 Elmwood Park Boulevard Fax: (703) 605-6900 

 New Orleans, Louisiana 70123-2394 Email: bookstore@ntis.gov

Telephone requests may be placed at 

 (504) 736-2519, 1-800-200-GULF, or 

Rush Orders: 1-800-553-6847 

 Fax: (504) 736-2620 

CITATION 

Suggested citation: 

Wilson, D., R. Billings, R. Oommen, B. Lange, J. Marik, S. McClutchey, and H. Perez. 2010. 

Year 2008 Gulfwide emission inventory study. U.S. Dept. of the Interior, Bureau of 

Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico OCS Region, 

New Orleans, LA. OCS Study BOEMRE 2010-045. 186 pp. 

ACKNOWLEDGMENTS 

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

Eastern Research Group: Stacie Enoch, Robin Mongero Weyl, Steve Mendenhall, and 

Jody Tisano. Invaluable assistance was also provided by the staff of COMM Engineering, Inc., 

particularly Brian Boyer and Stephanie Kinning. 
v 

TABLE OF CONTENTS 

Page

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

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

EQUATION UNIT DEFINITIONS........................................................................................... xv 

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

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

2.1 Background ...................................................................................................... 2-1 

2.2 Scope and Purpose of this Project ..................................................................... 2-2 

2.3 Study Objectives .............................................................................................. 2-2 

2.4 Report Organization ......................................................................................... 2-3 

3. DATA COLLECTION FOR PLATFORM SOURCES ................................................ 3-1 

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

3.2 Improvement of the GOADS Data Collection Software .................................... 3-1 

3.3 Working with Users ......................................................................................... 3-1 

3.4 GOADS Quality Assurance/Quality Control .................................................... 3-2 

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

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

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

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

4.3.1 User-Level Summary ............................................................................ 4-1 

4.3.2 Structure-Level Summary ..................................................................... 4-2 

4.3.3 Equipment-Level Summary .................................................................. 4-2 

4.4 QA/QC Checks ................................................................................................ 4-2 

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

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

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

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

4.4.5 Applying Surrogate Values ................................................................... 4-5 

4.4.6 Post-Processing of Surrogates ............................................................... 4-5 

4.4.7 Comparison to OGOR Reports ............................................................. 4-5 
vi 

TABLE OF CONTENTS (CONTINUED) 

Page

5. DEVELOPMENT OF THE PLATFORM EMISSIONS INVENTORY ....................... 5-1 

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

5.2 Emission Estimation Procedures ...................................................................... 5-1 

5.2.1 Amine Units ......................................................................................... 5-1 

5.2.2 Boilers/Heaters/Burners ........................................................................ 5-3 

5.2.3 Diesel and Gasoline Engines................................................................. 5-7 

5.2.4 Drilling Rigs ......................................................................................... 5-9 

5.2.5 Combustion Flares ...............................................................................5-12 

5.2.6 Fugitives..............................................................................................5-14 

5.2.7 Glycol Dehydrators .............................................................................5-16 

5.2.8 Losses from Flashing ...........................................................................5-18 

5.2.9 Mud Degassing ....................................................................................5-19 

5.2.10 Natural Gas Engines ............................................................................5-20 

5.2.11 Natural Gas Turbines ...........................................................................5-24 

5.2.12 Pneumatic Pumps ................................................................................5-25 

5.2.13 Pressure/Level Controllers ...................................................................5-27 

5.2.14 Storage Tanks ......................................................................................5-27 

5.2.15 Cold Vents ...........................................................................................5-32 

5.2.16 Minor Sources ......................................................................................5-33 

5.2.17 PM Augmentation ................................................................................5-33 

6. DEVELOPMENT OF THE NON-PLATFORM EMISSIONS INVENTORY ............ 6-1 

6.1 Non-Platform Oil/Gas Production Related Sources .......................................... 6-2 

6.1.1 Marine Diesel Emission Factors ........................................................... 6-2 

6.1.2 Drilling Rigs ......................................................................................... 6-6 

6.1.3 Pipelaying Operations..........................................................................6-31 

6.1.4 Support Helicopters .............................................................................6-47 

6.1.5 Support Vessels ...................................................................................6-52 

6.1.6 Survey Vessels ....................................................................................6-56 

6.2 Non-Platform Non-Oil/Gas Production Related Sources..................................6-58 

6.2.1 Biogenic and Geogenic Emissions .......................................................6-59 

6.2.2 Commercial Fishing Vessels ................................................................6-61 

6.2.3 Commercial Marine Vessels ................................................................6-65 

6.2.4 LOOP ..................................................................................................6-66 

6.2.5 Military Vessels...................................................................................6-68 

6.2.6 Vessel Lightering ................................................................................6-72 
vii 

TABLE OF CONTENTS (CONTINUED) 

Page

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

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

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

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

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

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

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

8.3 Limitations ......................................................................................................8-14 

8.4 Comparison with Other Studies .......................................................................8-15 

8.4.1 OCS Oil and Gas Production Platforms ...............................................8-16 

8.4.2 Non-Platform Sources .........................................................................8-19 

8.5 Recommendations ...........................................................................................8-24 

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

LIST OF FIGURES 

Figure Page

6-1 Location of drilling operations and BOEM lease blocks for 2008 ...............................6-31 

6-2 Pipeline locations and BOEM lease blocks .................................................................6-33 

6-3 Location of active platforms with heliports .................................................................6-52 

6-4 Active offshore platforms with BOEM lease blocks ....................................................6-56 

6-5 Typical geophysical survey vessel operations .............................................................6-57 

6-6 NMFS fishing zones with lease blocks ........................................................................6-65 

6-7 Commercial marine vessel shipping lanes ...................................................................6-66 

6-8 Shipping lane approach and location of LOOP ............................................................6-68 

6-9 Coast Guard districts used to allocate emissions .........................................................6-72 

6-10 Centroid of the vessel lightering zone and shipping lane to Galveston .........................6-75 

7-1 Diurnal emission curve for sources of constant activity ................................................ 7-3 

7-2 Diurnal emission curve for boilers/heaters/burners ....................................................... 7-5 

7-3 Diurnal emission curve for natural gas turbines and internal 

combustion engines ..................................................................................................... 7-6 

7-4 Diurnal emission curve for temperature dependent activities ........................................ 7-7 

7-5 Average air and water temperatures for 17 Gulf of Mexico buoys in 

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

7-6 Diurnal emission curve for helicopters and support vessels .......................................... 7-9 
xi 

LIST OF TABLES 

Table Page

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

4-2 Surrogate Stack Parameters Used to Supplement GOADS-2008 Data .......................... 4-6 

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

Input > 100 MMBtu/hr ................................................................................................ 5-4 

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

Input < 100 MMBtu/hr ................................................................................................ 5-4 

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

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

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

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

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

Max Rated Heat Input > 100 MMBtu/hr ...................................................................... 5-6 

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

Max Rated Heat Input < 100 MMBtu/hr ...................................................................... 5-6 

5-7 Emission Factors for Gasoline Engines ........................................................................ 5-8 

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

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

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

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

5-12 Emission Factors for Natural Gas Fuel Use .................................................................5-11 

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

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

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

LIST OF TABLES (CONTINUED) 

Table Page

5-16 Default Speciation Weight Fractions for THC Emissions by Stream Type ..................5-16 

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

5-18 Emission Factors for Natural Gas Engines where Engine Stroke Cycle = 

2-Cycle and Engine Burn Type = Lean .......................................................................5-22 

5-19 Emission Factors for Natural Gas Engines where Engine Stroke Cycle = 

4-Cycle and Engine Burn Type = Lean .......................................................................5-22 

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

4-Cycle and Engine Burn Type = Rich........................................................................5-23 

5-21 Emission Factors for Natural Gas Engines where Engine Burn Type = Clean .............5-23 

5-22 Emission Factors for Natural Gas Turbines .................................................................5-25 

5-23 Default Sales Gas Composition...................................................................................5-26 

5-24 Daily Average Ambient Temperature, Taa ...................................................................5-31 

5-25 Tank Paint Solar Absorptance, a .................................................................................5-31 

5-26 Surrogate Emission Estimates Applied to Minor Sources ............................................5-33 

6-1 Marine Vessel Emission Factors .................................................................................. 6-4 

6-2 Drilling Vessel Activity Data ....................................................................................... 6-6 

6-3 Equipment kW Ratings by Drilling Rig Type .............................................................6-29 

6-4 Seasonal Drilling Activity...........................................................................................6-30 

6-5 Pipelaying Activity .....................................................................................................6-32 

6-6 Average Pipelaying Vessel Characteristics .................................................................6-32 

6-7 New Pipelaying Activity Data ....................................................................................6-34 

6-8 Pipe Repair Activity Data ...........................................................................................6-42 

6-9 Pipelaying Monthly Adjustment Factors .....................................................................6-47 
xiii 

LIST OF TABLES (CONTINUED) 

Table Page

6-10 HSAC Helicopter Data ...............................................................................................6-48 

6-11 Helicopter Emission Factors by Helicopter Type ........................................................6-50 

6-12 Support Vessel Census, kW rating, and Annual Hours of Operation ...........................6-53 

6-13 Support Vessel Monthly Adjustment Factors ..............................................................6-55 

6-14 Mud Volcano Locations and Emission Characteristics ................................................6-61 

6-15 Shrimp Vessel Activity Data .......................................................................................6-62 

6-16 Reef Fishing Vessel Activity Data ..............................................................................6-62 

6-17 Commercial Fishing Monthly Adjustment Factors ......................................................6-63 

6-18 LOOP Hours of Operation, kW Rating, and Load Factors ...........................................6-67 

6-19 Naval Vessels kW Hours ............................................................................................6-69 

6-20 Naval Diesel Turbine and Steamship Fuel Consumption Data and Emission 

Factors ........................................................................................................................6-70 

6-21 Average Horsepower and Operating Hours by Coast Guard Vessel Type ....................6-70 

6-22 Lightering Times ........................................................................................................6-73 

6-23 Lightering Vessel Characteristics ................................................................................6-73 

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

7-2 SCCs of Interest for Platform Operations (diurnal patterns) ........................................7-11 

8-1 Total Platform Emission Estimates for Criteria Pollutants ............................................ 8-3 

8-2 Total Non-Platform Emission Estimates for Criteria Pollutants .................................... 8-4 

8-3 Total Platform and Non-Platform Emission Estimates for Criteria Pollutants ............... 8-5 

8-4 Annual CO Emission Estimates for All Sources ........................................................... 8-6 

8-5 Annual NOx Emission Estimates for All Sources ......................................................... 8-7 
xiv 

LIST OF TABLES (CONTINUED) 

Table Page

8-6 Annual PM10 Emission Estimates for All Sources ........................................................ 8-8 

8-7 Annual PM2.5 Emission Estimates for All Sources ....................................................... 8-9 

8-8 Annual SO2 Emission Estimates for All Sources .........................................................8-10 

8-9 Annual VOC Emission Estimates for All Sources .......................................................8-11 

8-10 Total Greenhouse Gas Emission Estimates for Platform Sources ................................8-12 

8-11 Total Greenhouse Gas Emission Estimates for Non-Platform Sources ........................8-13 

8-12 Total Platform and Non-Platform Emission Estimates for Greenhouse Gases .............8-13 

8-13 Comparison of Total Platform and Non-Platform Criteria Pollutant for Base Years 

 2008 and 2005 Emission Estimates .............................................................................8-16 

8-14 Comparison of Total Platform and Non-Platform Greenhouse Gas Emission Estimates 

 for Base Years 2008 and 2005 ....................................................................................8-16 

8-15 Comparison of Base Years 2008 and 2005 OCS Platform Criteria Pollutant 

 Emission Estimates .....................................................................................................8-18 

8-16 Comparison of Base Years 2008 and 2005 OCS Platform Greenhouse Gas 

 Emission Estimates .....................................................................................................8-19 

8-17 Comparison of Base Years 2008 and 2005 OCS Non-Platform Criteria Pollutant 

 Emission Estimates .....................................................................................................8-20 

8-18 Comparison of Base Years 2008 and 2005 Drilling Days by Rig Type........................8-21 

8-19 Comparison of Base Years 2008 and 2005 Helicopter Emission Factors .....................8-21 

8-20 Comparison of Base Years 2008 and 2005 Activity Data for Shrimp and Reef 

 Fishing Operations......................................................................................................8-22 

8-21 Comparison of Base Years 2008 and 2005 OCS Non-Platform Greenhouse Gas 

 Emission Estimates .....................................................................................................8-23 
xv 

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 
1-1

1. EXECUTIVE SUMMARY 

The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEM) 

(formerly the Minerals Management Service or MMS) 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, which directs the BOEM to regulate OCS emission sources to assure that they 

do not significantly affect onshore air quality. The BOEM air quality regulations are contained in 

30 CFR 250.302 through 250.304. In particular, the BOEM is responsible for determining if any 

facility that is used for exploration, development, and production of oil, gas, or sulfur from the 

Gulf of Mexico OCS influences the attainment (or nonattainment) 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 with the implementation of the 8-hour ozone 

standard. To assess the emissions of offshore oil and gas platforms and their associated 

emissions, the MMS conducted limited emission inventories in the Gulf of Mexico OCS in the 

1980s. In 1995 the MMS completed the Gulf of Mexico Air Quality Study (Systems Applications 

International et al. 1995); in 2004 the MMS 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); and in 2007 the Year 2005 Gulfwide 

Emission Inventory Study (Wilson et al. 2007) was completed. 

The BOEM Gulf of Mexico Outer Continental Shelf Regional office sponsored this 

project, the Year 2008 Gulfwide Emission Inventory Study (BOEM Contract No. M07PC13189), 

which builds upon the previous studies and has the goal of developing a base year 2008 air 

pollution emissions inventory for all OCS oil and gas production-related sources in the Gulf of 

Mexico, including non-platform sources. Pollutants covered in this inventory are the criteria 

pollutants—carbon monoxide (CO), nitrogen oxides (NOx), sulfur dioxide (SO2), particulate 

matter-10 (PM10), PM2.5, and volatile organic compounds (VOC); as well as major greenhouse 

gases—carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O). The platform and nonplatform 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 more-recent air quality emission inventory studies, the 2008 Gulfwide 

Offshore Activities Data System (GOADS-2008) 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 

agencies and Regional Planning Organizations will use this information to perform modeling for 

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

Somewhat similar to the results of the 2005 inventory, the inventory results indicate that 

OCS oil and gas production platform and non-platform sources emit the majority of criteria 
1-2

pollutants and greenhouse gases in the Gulf of Mexico on the OCS, with the exception of PM 

and 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 93% of the total 

CO emissions, 74% of NOx emissions, 75% of VOC emissions, 99% of CH4 emissions, and 84% 

of CO2 emissions. Natural gas engines on platforms represented the largest CO emission source, 

accounting for 60% of the total estimated CO emissions, support vessels were the highest 

emitters for NOx accounting for 35% of the total estimated NOx emissions, and platform vents 

and fugitive sources account for the highest percentage of the VOC and CH4 emissions. Support 

vessels (29% of total emissions), platform natural gas turbines (15% of total emissions), and 

drilling rigs (13% of total emissions) emit the majority of the CO2 emissions. 

While the emission estimation methods for platform sources included in this study are 

very similar to those used to develop the Year 2005 Gulfwide Emission Inventory Study (Wilson 

et al. 2007), emission estimation methods for several non-platform source categories differ, 

particularly for commercial marine vessels, where the USEPA has updated their methods to 

better incorporate the latest emission factors and detailed data on fuels used by marine vessels. 

Overall comparisons of pollutant-specific emission estimates for platform and non-platform 

sources show that the total CO and NOx emission estimates vary slightly from 2005 to 2008. A 

slight difference is seen in the VOC emission estimates. Large differences are seen, however, in 

the PM10 estimates (91% increase) and SO2 estimates (100% increase). These increases are 

primarily from the commercial marine vessel emission estimates. For greenhouse gases, the 

overall CO2 and N2O emission estimates vary slightly from 2005 to 2008. A very pronounced 

increase is seen in the CH4 (96%) estimates. This increase is primarily due to increases in the 

platform vent, fugitive, glycol dehydrator, pneumatic pump, and pressure level controller 

emission estimates. 

For platform sources, the CO, NOx, and PM emission estimates show slight decreases in 

emissions from 2005 to 2008 (less than 10%). The SO2 emission estimate, however, shows a 

48% decrease. This decrease is primarily due to the amine unit emission estimates. The VOC 

emission estimate shows a 19% increase (up over 9,000 tons) from 2005 to 2008. The majority 

of this increase is from vents, fugitives, glycol dehydrators, pneumatic pumps, and pressure level 

controllers. In contrast, a 12,000 ton VOC decrease was seen from 2000 to 2005. The decrease 

seen in 2005 may be indicative of the severe hurricane activity in 2005, which impacted 

production operations, as numerous platforms were shut in for several months. A comparison of 

emission estimates for greenhouse gases in the 2008 inventory and the 2005 inventory reveals 

that the CO2 and N2O emission estimates are consistent with the 2005 estimates. The CH4

estimates, however, almost doubled. Similar to the increase in the VOC emission estimates, this 

increase is from vents, fugitive sources, glycol dehydrators, pneumatic pumps, and pressure level 

controllers. 

The 2008 emission estimates for several types of platform equipment are similar to those 

in the 2005 inventory, including losses from flashing, diesel engines, natural gas engines, and 

natural gas turbines. Emission estimates for some equipment types, such as amine units, drilling 

equipment, and mud degassing show a decline in emissions, primarily due to decreased activity. 

For amine units, the almost 100% decrease in emissions is because one unit that was operating in 

2005 is no longer operating. Overall emission increases are seen in a number of equipment 
1-3

categories, including vents, fugitive sources, glycol dehydrators, pneumatic pumps, and pressure 

level controllers, as noted above, and boilers/heaters/burners and combustion flares. For 

boilers/heaters/burners, the 2005 and 2008 inventories have activity reported for a similar 

number of units, but the overall 2008 activity level (i.e., amount of fuel combusted) increased. 

Similarly for combustion flares, the 2005 and 2008 inventories have activity reported for a 

similar number of units, but the overall 2008 activity level (i.e., volume flared) increased. 

For non-platform sources, the overall NOx and VOC emission estimates show slight 

differences in emissions from 2005 to 2008 (less than 2%). The CO emission estimate shows a 

31% increase from 2005 to 2008, primarily from drilling rigs, helicopters, and commercial 

marine vessels. The increased PM and SO2 estimates, both over 100%, are due to the commercial 

marine vessel estimates. All non-platform sources had larger greenhouse gas emissions than 

estimated in 2005, except for support vessels, which is indicative of a reduction in the Gulf fleet. 

The largest increase in greenhouse gas estimates for OCS oil/gas related sources is seen in the 

helicopter emission estimates, which is based on the updated helicopter emission factors, and 

drilling rigs, which is due to the increase in drilling activity between 2005 and 2008. 

The 2008 emission estimates for several non-platform categories are similar to those in 

the 2005 inventory, including pipelaying, biogenic and geogenic sources, and the LOOP. Some 

source categories, such as support vessels and vessel lightering, have declining emissions due to 

a reduction in the fleet size and reduced activity levels, respectively. Survey vessel emissions 

increased due to better information about the fleet and the number of days-at-sea that vessels 

typically operate. The increase in drilling rig emissions reflects the 69% increase in drilling 

activity. Helicopter activity declined slightly (5%) between 2005 and 2008, but the latest 

helicopter emission factors from the Federal Aviation Administration are significantly different, 

particularly with regard to CO, VOC and CO2, than those used in the Year 2005 Gulfwide 

Emission Inventory Study (Wilson et al. 2007). For commercial fishing, the 2008 activity data for 

shrimp and reef fishing are significantly higher than in previous inventories, thus increasing the 

emission estimates. As noted above, the emission estimation methods for commercial marine 

vessels differ from the methods used to develop the base year 2005 estimates, yielding higher 

emission estimates for all pollutants except NOx. Previous commercial marine vessel emissions 

estimates were based on older fuel-based emission factors. The 2008 estimates are considerably 

more accurate because they are based on the most up-to-date international emission factors for 

specific vessel types that account for different engine types, engine speeds, and fuels. For 

military vessels, the activity data have not been changed between 2005 and 2008; the increase in 

emissions for these sources is due to the application of updated emission factors. 
2-1 

2. INTRODUCTION 

2.1 BACKGROUND 

The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEM) is 

responsible for determining if air pollutant emissions from Outer Continental Shelf (OCS) oil 

and natural gas platforms and other sources in the Gulf of Mexico influence the attainment and 

nonattainment status of onshore areas. Measurements of ozone concentrations in onshore areas 

of Texas and Louisiana periodically exceed the national standard for eight-hour ozone (1997 

standard) in nonattainment areas, with the Beaumont-Port Arthur, Texas, and Baton Rouge, 

Louisiana, areas classified as moderate, and the Houston-Galveston-Brazoria, Texas, area 

classified as severe. Shoreline and inland locations in Texas and Louisiana, as well as 

Mississippi, Alabama, and Florida, could potentially be influenced by emission sources in the 

Gulf of Mexico. 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 Gulf of Mexico. This mandate grew out of concerns regarding the 

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

the central and western Gulf of Mexico. 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 the 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 three 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 Gulf of Mexico, where visibility and regional haze concerns may apply. As part of its 

program to collect activity data, a Visual Basic program was developed, known as the Breton 

Offshore Activities Data System (BOADS), for platform operators to submit activity data on a 

monthly basis. An Oracle database management program (DBMS) was created to develop the 

emissions estimates (Billings and Wilson 2004). 

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

built upon the previous MMS studies with the goal of developing criteria pollutant and 

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

Gulf of Mexico OCS. The Gulfwide Offshore Activities Data System (GOADS) was developed 

from the BOADS 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). 
2-2 

The 2005 Gulfwide Emission Inventory Study covered the same sources, pollutants, and 

geographic area as the 2000 inventory. Updates were made to the GOADS-2005 program to 

simplify reporting by platform operators (Wilson et al. 2007). 

The BOEM Gulf of Mexico Outer Continental Shelf Regional office sponsored this 

project, the “Year 2008 Gulfwide Emission Inventory Study” (BOEM Contract No. 

M07PC13189), with the goal of developing a base year 2008 air pollution emissions inventory 

for all OCS oil and gas production-related sources in the Gulf of Mexico. 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 

Through an Office of Management and Budget-approved Information Collection 

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

needed to develop air pollutant emissions estimates from platform activities. The activity data 

were collected based on MMS NTL No. 2007-G25, “2008 Gulfwide OCS Emissions Inventory 

(Western Gulf of Mexico).” 

The BOEM developed and distributed a Visual Basic program for platform operators to 

use to collect and submit activity data on a monthly basis. The program, known as the GOADS, 

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 and 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. 

2.3 STUDY OBJECTIVES 

The objectives of this study are: 

• To review, modify, and provide support services for GOADS-2008 and the 

2008 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 (2008). Activity data from 

platform sources were collected using GOADS-2008. 
2-3 

• To calculate and archive a calendar year 2008 total emissions inventory using 

the most current emission factors and the 2008 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 Word files. 

2.4 REPORT ORGANIZATION 

Following this introduction, the Year 2008 Gulfwide Emission 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 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 calculation methods for non-platform sources. 

• Section 7 presents diurnal emissions curves developed for all source 

categories covered in the inventory. 

• Section 8 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 8, and the results are 

compared with the Year 2005 Gulfwide Emission Inventory Study Report

(Wilson et al. 2007). 

• Section 9 presents references cited throughout the report. 
3-1 

3. DATA COLLECTION FOR PLATFORM SOURCES 

3.1 INTRODUCTION 

To develop a base year 2008 inventory of criteria pollutant and greenhouse gas emissions 

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

activity data from platform operators during the year 2008. On September 24, 2007, NTL 2007-

G25 was published to introduce the “2008 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 Gulf of Mexico OCS region. 

This section of the report outlines the steps that the BOEM and Eastern Research Group, 

Inc. (ERG) 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 over one calendar year (2008) 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 base year 2000 and 2005 

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

use for preparing the 2005 inventory. The new version, GOADS-2008, was improved to make 

data entry less cumbersome for operators. The BOEM and ERG staff worked closely with 

members of the Offshore Operators Committee (OOC) to identify and implement these 

improvements. Examples include requesting operating horsepower, fuel use rate, and heat input 

rate as description fields, rather than activity fields which require data entry for each month; 

removing loading operations; scaling back the data requested for amine units and glycol 

dehydrators to focus solely on information needed to calculate emissions; and allowing operators 

to identify minor sources (caissons, living quarters, and wellhead protectors) so that BOEM can 

develop surrogate emission estimates for these sources. 

3.3 WORKING WITH USERS 

A workshop was held in New Orleans on October 24, 2007, to discuss and explain the 

2008 Gulfwide study information collection and reporting procedures. The User’s Guide for the 

2008 Gulfwide Offshore Activities Data System (GOADS-2008) (Wilson and Boyer 2007) was 

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

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

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

data, quality control, and saving and backing up files. For details on the GOADS-2008 program, 

refer to the User’s Guide, which can be found at: http://www.gomr.mms.gov/PI/PDFImages 

/ESPIS/4/4282.pdf. 
3-2 

3.4 GOADS QUALITY ASSURANCE/QUALITY CONTROL 

The ERG programmed automatic QA procedures into the software in an effort to 

minimize the submittal of incomplete and erroneous activity data by the platform operators. The 

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

with their monthly activity files. The QA Summary focuses on identification of critical data that 

the operators need to complete prior to submitting their data to the BOEM. 

The software also automatically runs a series of QC checks on the data when the operator 

saves it. If the operator leaves a field blank, provides data that are out of range, or enters a value 

that is not consistent on a month-to-month basis, an error message will appear. The operator can 

then correct the problem, override the QC check (and provide a comment), or ignore the message 

and save the changes. When operators entered data that appeared in the QC results or on the QA 

Summary Form, the ERG attempted to reconcile the missing, atypical, or suspect data by 

reviewing the comments, contacting the operators, or developing surrogate data as described in 

Section 4 of this report. Surrogate data were developed primarily for the stack parameters 

requested for the emission release point for each piece of equipment. These parameters are 

needed for air quality modeling efforts. The surrogates were developed based on industry 

averages and through discussions with the BOEM. 
4-1 

4. QUALITY ASSURANCE/QUALITY CONTROL 

4.1 INTRODUCTION 

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

GOADS-2008 software. One hundred three (out of 161 with leases) companies submitted data 

for 3,304 active or inactive platforms (combination of complex ID and structure ID) (about 85% 

of platforms OCS) including minor sources. 3,026 structures were active (at least one month). Of 

these, 1,538 were flagged as minor sources. 

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

GOADS-2008 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, the ERG attempted to reconcile 

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

4.2 CHECKING FILE INTEGRITY AND MATCHING QA SUMMARY 

The BOEM sent 113 unique data files to the ERG for 3,026 active platforms. All 

electronic data were in the prescribed Microsoft Access database that was created by the 

GOADS-2008 software. For comparison, 134 unique data files were submitted for the base year 

2005 inventory for 1,585 active platforms. For the base year 2005 inventory, minor sources were 

permitted to be excluded from reporting via GOADS-2005. For the base year 2008 inventory, the 

BOEM required minor sources to report minimal data via GOADS-2008. Thus, many more 

platforms are included in the 2008 inventory. 

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. Companies were also required to submit a hardcopy of 

their QA Summary Form. Of the 113 files submitted, 99 were accompanied by a hardcopy of 

their QA summary results (88%). For the submittals missing hard-copy QA Summary Forms, the 

ERG was able to print the form for review. 

4.3 EQUIPMENT SUMMARY CHECKS 

Each GOADS-2008 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. 
4-2 

4.3.1 User-Level Summary 

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

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

the BOEM master lease and company lists. The official BOEM list of companies, leases, and 

platforms was retrieved from the website: 

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

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

IDs. Additionally, the ERG checked and corrected the locational data (latitude/longitude pairs) 

for each platform. 

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 39,329 records were 

submitted, and 35,952 were considered active (91%). For comparison, 16,882 active records 

were submitted for base year 2005. 

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 279,964 equipment surveys, 

of which 180,921 were active (65%). 

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. 

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 to OGOR reports. 
4-3 

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. 

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; 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. 

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 29 days) is 696. 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 745 hours. 

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. 
4-4 

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. 

Approximately 47% of the monthly equipment records required corrections in this process. 

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). Approximately 3% of the records required corrections in this process. 

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

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

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

these incorrect data were not flagged initially. Additionally, 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 Vent or Flare ID is populated in these tables, then a 

downstream analysis was performed on the Vent or Flare equipment tables to verify their 

existence. For Vent or Flare IDs that could not be traced to an existing active vent or flare, the 

survey was updated as to being vented/flared locally. Less than 1% of the records required 

corrections during this process. 
4-5 

Table 4-1 

Fields and Range Check Values 

Field Range Check 

API Specific Gravity Minimum value: 9 degrees API 

Average Liquid Height Not to exceed outlet height 

Flare Efficiency 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 Greater than 5 inches 

Operating Horsepower Not to exceed maximum rated horsepower 

Stack Angle Between 0 and 360 

4.4.5 Applying Surrogate Values 

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

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

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

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

through discussions with the BOEM. 

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-2008 data 

submittals for volume vented and flared with the values reported to the BOEM via Oil and Gas 

Operations Report (OGOR) forms (Form MMS 4058). Operators must provide monthly OGOR 

forms of the volumes vented and flared for “all wells for a lease/agreement.” The BOEM 

provided OGOR data for 39 platforms. For 21 of these platforms, there was somewhat close 

(within 15%) agreement between the OGOR-reported total volume vented and flared with the 

reported GOADS-2008 volume vented and flared. For the other 18 platforms, there were 

significant differences (ranging from not reported in GOADS-2008, to over 100% disagreement). 

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. 
4-6 

Table 4-2 

Surrogate Stack Parameters Used to Supplement GOADS-2008 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 

Glycol Dehydrator Elevation (above sea 

level) 

50 ft 

Glycol Dehydrator– flash tank Temperature 120 oF 
4-7 

Table 4-2. Surrogate Stack Parameters Used to Supplement GOADS-2008 Data (continued). 

Unit Field Default Value 

Glycol Dehydrator– flash tank Pressure 60 psig

Glycol Dehydrator– ventilation 

system 

Exit temperature GLYCalc default (usually 

212 oF)b

Glycol Dehydrator– ventilation 

system 

Outlet orientation 0 degrees 

Glycol Dehydrator– ventilation 

system 

Flare feed rate (scf/hr) Calculated with GLYCalcb

Glycol Dehydrator– ventilation 

system 

Combustion 

temperature 

1832 oF 

Glycol Dehydrator– ventilation 

system 

Condenser temperature 110 oF (or calculated with 

GLYCalc)b

Glycol Dehydrator– ventilation 

system 

Condenser pressure 14.8 psia 

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 
4-8 

Table 4-2. Surrogate Stack Parameters Used to Supplement GOADS-2008 Data (continued). 

Unit Field Default Value 

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 

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 Gas Technology Institute as part of the AIRCalc Air Emissions 

Inventory Report Management Software Program (GTI 2001) 

b

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

(GRI) (GTI 2000) 
5-1 

5. DEVELOPMENT OF THE 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 Gulf of Mexico OCS. To achieve 

this goal, the ERG revised the 2005 Gulfwide Oracle Database Management System (DBMS) to 

create the 2008 Gulfwide Oracle DBMS. The 2008 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 Gulf of Mexico. 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” 

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

Natural gas hydrogen sulfide (H2S) content = 3.38 ppmv 

Diesel fuel sulfur content = 0.4 wt%

Natural gas heating value = 1050 Btu/scf 

Diesel fuel heating value = 19,300 Btu/lb 

Diesel fuel density = 7.1 lb/gal 

Gasoline 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 2005 Gulfwide DBMS (Wilson et al. 2007), as the emission factors 

and emission estimation methods have not been revised by USEPA or other sources. The 

exception is storage tanks—the VOC speciation profile was revised, and a profile for CH4 was 

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

greenhouse gas emissions from platform sources in the study, and highlight any changes in the 

emission estimation procedures. 

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 
5-2 

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). 

Operators were required to use the “Model Inputs” tab. CH4 and VOC emissions are 

estimated externally using AMINECalc (GTI 2001), and loaded directly into the DBMS. 

Emissions are adjusted for any control devices that were reported, such as a 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%

 Eff100

EE

dc,

controlc, uncc,

−

×= ∑

where: 

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

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

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

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

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

 mollb

lb 64

 lb 34

 mollb

E E

2

SO

2

SO

2

SO

S

2

H

S

2

H

control, H2S

2

SO

where: 

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

EH2

S = 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

mollb 3

mollb 1

100

Eff

mollb

lb 64

 lb 34

 mollb

E E

S

SO SO

SO

SO

SH

SH

control, SH

2 2

2

2

2

2

2 SO2

where: 

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

EH2

S = Uncontrolled emissions of H2S (pounds per month) 

% RE = Recovery efficiency of the sulfur recovery unit (%) 
5-3 

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). To 

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

Efu,liq: 

EFE lb/gal 7.1U10 liq

-3

liq fu, gal) (lb/10

= 3 ÷××

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

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

gas

3

gasfu, = EFE (lb/MMscf) 0 ×× U1

−

where: 

E = Emissions in pounds per month 

EF = Emission factor 

Uliq = Fuel usage (pounds/month) 

Ugas = Fuel usage (Mscf/month) 

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

input, and fuel heating value. 

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

These factors come from AP-42, Sections 1.3 and 1.4 (USEPA 2002). 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. 
5-4 

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 

THC 0.252 0.252 0.252 

VOC 0.2 0.2 0.2 

SO2 157 × S 157 × S 157 × S 

NOx 24 10 10 

PM2.5 0.25 0.25 0.25 

PM10 2 2 2 

CO 5 5 5 

N2O 0.11 0.11 0.11 

CH4 0.052 0.052 0.052 

CO2 22,300 22,300 22,300 

S = Fuel oil sulfur content (wt%) 

Table 5-2 

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 

THC 0.252 0.252 0.252 

VOC 0.2 0.2 0.2 

SO2 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 0.11 0.11 0.11 

CH4 0.052 0.052 0.052 

CO2 22,300 22,300 22,300 

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

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 

THC 1.28 1.28 1.28 

VOC 0.28 0.28 0.28 

SO2 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 0.11 0.11 0.11 

CH4 1.00 1.00 1.00 

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

S = Fuel oil sulfur content (wt%) 

a

 As opposed to oil that has been desulfurized 

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 

THC 1.28 1.28 1.28 

VOC 0.28 0.28 0.28 

SO2 157 × S 157 × S 157 × S

NOx 55 55 55 

PM2.5 0.37 × S + 

0.12 

0.37 × S 

+ 0.12 

0.37 × S + 

0.12 

PM10 9.19 × S + 

3.22 

9.19 × S 

+ 3.22 

9.19 × S + 

3.22 

CO 5 5 5 

N2O 0.11 0.11 0.11 

CH4 1.00 1.0 1.0 

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

S = Fuel oil sulfur content (wt%) 

a

 As opposed to oil that has been desulfurized
5-6 

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)a

Pollutant Uncontrolled

Low NOx

Burner 

Flue Gas 

Recirculation 

THC 11 11 11 

VOC 5.5 5.5 5.5 

SO2 0.6 0.6 0.6 

NOx 280 140 100 

PM10

b

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

 To convert from lb/MMscf to lb/MMBtu, divide by

1,050

b

 Also represents PM2.5

Table 5-6 

Emission Factors for Gas-Fueled Units – Natural Gas or 

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

Emission Factors (lb/MMscf)a

Pollutant Uncontrolled

Low NOx

Burner 

Flue Gas 

Recirculation 

THC 11 11 11 

VOC 5.5 5.5 5.5 

SO2 0.6 0.6 0.6 

NOx 100 50 32 

PM10

b

 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

 To convert from lb/MMscf to lb/MMBtu, divide by

1,050

b

 Also represents PM2.5
5-7 

5.2.3 Diesel and Gasoline Engines 

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

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

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

diesel fuels (USEPA 2002). 

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

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

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

upon power output. 

To calculate uncontrolled emissions based on fuel use, Efu: 

H

gal

lb 7.1

EFE U10

6-

fu = (lb/MMBtu) ××××

To calculate uncontrolled emissions based on power output, Epo: 

453.6g

lb

po EFE hr)-(g/hp

tHP ×××=

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

U = Fuel usage (gallons/month) 

H = Fuel heating value (Btu/lb) 

HP = Engine horsepower (hp) 

t = Engine operating time (hr/month) 

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 2002). 
5-8 

Table 5-7 

Emission Factors for Gasoline Engines 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 3.03 9.8 

VOC 3.03 9.8 

SOx 0.084 0.268 

NOx 1.63 4.99 

PM10

a

0.1 0.327 

CO 62.7 199 

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) 

THC 0.36 1.14 

VOC 0.33 1.04 

SOx 1.01 × S 3.67 × S

NOx 4.41 14.1 

PM10

a

0.31 1 

CO 0.95 3.03 

CO2 164.0 521.6 

a Also represents PM2.5 

S = Fuel oil sulfur content (wt%) 
5-9 

Table 5-9 

Emission Factors for Diesel Engines 

where Max HP ≥ 600 

Pollutant 

EFfu

(lb/MMBtu) 

EFpo

(g/hp-hr) 

THC 0.09 0.32 

VOC 0.08 0.29 

SOx 1.01 × S 3.67 × S 

NOx 3.2 10.9 

PM2.5

a

0.056 0.178 

PM10 0.057 0.182 

CO 0.85 2.5 

CH4 0.008 0.03 

CO2 165.0 526.2 

S = Fuel oil sulfur content (wt%) 

a

 <3 μm 

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

applied. 

5.2.4 Drilling Rigs 

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

platform are included because of their emissions associated with gasoline, diesel, and natural gas 

fuel usage in engines. Total emissions equal the sum of emissions due to gasoline, diesel, and 

natural gas fuel usage. 

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

2007): 

H

gal

lb 6.17

EFE U10

6-

(lb/MMBtu) gas = ××××

where: 

E = Emissions in pounds per month 

EF = Emission factor (units shown in parentheses) 

U = Fuel usage (gallons) 

H = Fuel heating value (Btu/lb) 

For diesel fuel use, calculate uncontrolled emissions, Edie, as follows (Wilson et. al. 

2007): 
5-10 

H

gal

lb 7.1

EFE U10

6-

die = (lb/MMBtu) ××××

where: 

E = Emissions in pounds per month 

EF = Emission factor (units shown in parentheses) 

U = Fuel usage (gallons) 

H = Fuel heating value (Btu/lb) 

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

EFE U10

3

ng = (lb/MMscf) ××

−

where: 

E = Emissions in pounds per month 

EF = Emission factor (units shown in parentheses) 

U = Fuel usage (Mscf) 

The following emission factors are used to estimate emissions (Tables 5-10 through 5-

12). These factors come from AP-42, Sections 3.2, 3.3 and 3.4 (USEPA 2002). Diesel engines 

are assumed to be ≥ 600 hp. Natural gas engines are assumed to be 4-cycle and evenly 

distributed between lean and rich burns (by averaging). 
5-11 

Table 5-10 

Emission Factors for Gasoline Fuel Use 

Pollutant 

EFgas

(lb/MMBtu) 

THC 3.03 

VOC 3.03 

SOx 0.084 

NOx 1.63 

PM10

a

0.1 

CO 62.7 

CO2 154 

a Also represents PM2.5

Table 5-11 

Emission Factors for Diesel Fuel Use 

Pollutant 

EFdie

(lb/MMBtu) 

THC 0.09 

VOC 0.08 

SOx 1.01 × S 

NOx 3.2 

PM2.5

a

0.056 

PM10 0.057 

CO 0.85 

CO2 165 

S = Fuel oil sulfur content (wt%) 

a

 <3 μm

Table 5-12 

Emission Factors for Natural Gas Fuel Use 

Pollutant 

EFng 

(lb/MMscf)a

THC 932.3 

VOC 75.3 

SO2 0.6 

NOx 2467.5 

PM10 

b

4.9 

CO 2127.3 

CH4 755 

CO2 112,200 

a To convert from lb/MMscf to lb/MMBtu, divide by 1,050

b

 Also represents PM2.5
5-12 

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). 

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

following equation: 

EFHVE 1000 flare flare ÷××=

where: 

Eflare = Emissions in pounds per month 

V = Total volume of gas flared (Mscf) = vol 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: 

( ) SH

SO

6

F

SOflare, 2

2

2

V1000 C 

molscf/lb 379.4

m

ppm

10

100%

%Eff

E ×××

⋅

 ××











=

−

where: 

Eflare, SO2 = Emissions in pounds per month 

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

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

V = Volume of gas flared (Mscf) 

CH2

S = 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: 

pilot EFDPE pilot ÷××= 1000

where: 

Epilot = Pilot emissions in pounds per month 

P = Flare feed rate (Mscf/day) 

D = Number of days in month 

EFpilot = Emission factor for pilot (lb/MMscf) 
5-13 

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 

2002). 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. 

Table 5-13 

Emission Factors for Flaresa

Pollutant EF (lb/MMBtu) 

THC 0.14 

VOC 0.006 

NOx 0.068 

PM10 0; where flare smoke = none 

 0.002; where flare smoke = light 

 0.01; where flare smoke = medium 

 0.02; where flare smoke = heavy 

CO 0.37 

N2O 0.002 

CH4 0.126 

CO2 114.285 

a

Factors are not available for PM2.5. N2O and CO2 

factors were derived from pilot emission factors. 

Table 5-14 

Emission Factors for Pilots 

Pollutant EF (lb/MMscf)a

THC 11 

VOC 5.5 

NOx 100 

PM10 7.6 

SO2 0.6 

CO 84 

N2O 2.2 

CH4 2.3 

CO2 120,000 

a To convert from lb/MMscf to lb/MMBtu, divide by 1,050 

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 
5-14 

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 ERG reviewed the flare velocities to insure that all were less than 400 fps, 

reflective of stable conditions (TCEQ 2000). Five flares had reported exit gas velocities greater 

than 400 fps; thus the emission factors for VOC, THC, and CH4 for these sources were adjusted 

to reflect unstable conditions and hence combustion efficiencies of 93% (TCEQ 2006). 

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 THC emissions are estimated according to the following equation: 

= ∑( × )

comp

E THC EFcomp,stream Ncomp × D 

where: 

ETHC = THC emissions in pounds per month 

EFcomp,stream = Emission factor unique 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: 

VOC = E E THC × WtFrVOCcomp, stream

where: 

EVOC = VOC emissions in pounds per month 

ETHC = THC emissions in pounds per month 

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

Fugitive CH4 emissions are estimated according to the following equation: 

comp, stream 4CH4 E E THC ×= WtFrCH
5-15 

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 

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 

Otherb4.7E-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 

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. 
5-16 

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 0.945 0.612 0.612 0.942 0.612 0.612 

VOC 0.0137 0.296 0.296 0.030 0.296 0.296 

a Source: API 1996 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. 

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 GRI-GLYCalc version 4 (GTI 2000) computer program runs for varying combinations of 

wet gas pressure and wet gas temperature. Surrogate glycol dehydrator flash tank vent emissions 

were also calculated based on regression equations from GRI-GLYCalc version 4 computer 

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

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 GRIGLYCalc runs were developed to express VOC emissions in pounds per hour per million 

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

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

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

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

130°F. 

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

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

The lowest emission factor is 0.03457 lb VOC/hr-MMscfd at a wet gas pressure of 1100 psig and 

temperature of 70°F, and flash tank pressure of 100 psig and temperature of 75°F. The highest 

emission factor is 0.09282 lb VOC/hr-MMscfd at a wet gas pressure of 800 psig and temperature 

of 90°F, and flash tank pressure of 50 psig and temperature of 125°F. 
5-17 

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. 

Table 5-17 

Surrogate Gas Analysis for GLYCalc Runs 

Component Mole Percent (%)

H2S 0.000

Nitrogen 0.100

CO2 0.800

CH4 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
5-18 

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). 

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

Vasquez-Beggs correlation equations to estimate tank vapors in standard cubic feet per barrel of 

oil produced. Operators were asked to report the following parameters for each part of the 

process: 

• API gravity of stored oil; 

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

separator, heater treater, surge tank, storage tank); 

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

• Actual throughput of oil for each vessel; 

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

pipeline, gas-lift), vented to atmosphere, or burned in flare; and 

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

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

f GORL ×= Throughput × GD

where: 

Lf = THC emissions in pounds per month 

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

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

GD = Tank vent hydrocarbon gas density (lb/ft3) = tank mol weight of gas ÷ 379.4 

Gas-to-oil ratio, GOR: 

















+

×

×××=

Vessel 460 temp

gravity APIC

C

1

3

2 SGOPCGOR eC
5-19 

where: 

C1 = Vasquez-Beggs constant = 





 >

otherwise 0.0362;

30 gravity API if 0.0178;

OP = Vessel operating pressure (psia) 

C2 = Vasquez-Beggs constant = 





 >

otherwise 1.0937;

30 gravity API if 1.187;

CSG = Corrected specific gravity of gas (see below) 

C3 = Vasquez-Beggs constant = 





 >

otherwise 25.724;

30 gravity API if 23.931;

Emissions of CO2, CH4, and VOC are estimated using the following speciation profiles 

based on the average sales gas weight percent for OCS platforms: 

Lf,VOC = Lf,THC × 0.04 

Lf,CO2 = Lf,THC × 0.02 

Lf,CH4 = Lf,THC × 0.88 

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

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

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

API Gravity 

Gas Specific Gravity 

(at 100 psig) 

>30 0.93 

<30 1.08 

5.2.9 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). 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: 

THC THC ×= DEF E drill
5-20 

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. Syntheticbased muds are used as substitutes for oil-based muds, and may occasionally be used to replace 

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

impact and faster biodegradability (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. 

THC emissions are speciated as follows (USEPA 1977): 

Component 

Percent Composition by 

Volume (%) 

Methane 83.85 

Ethane 5.41 

Propane 6.12 

Butane 3.21 

Pentane 1.40 

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 2002). 

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

default values (below), then emissions are estimated based upon fuel use. Otherwise, if operating 

horsepower and hours operated are both available, then emissions are estimated based upon 

power output. 
5-21 

Emissions are calculated based on fuel use as: 

-3

fu = EFE (lb/MMBtu) ××× 10UH

Emissions are calculated based on power output as: 

453.6g

lb

po EFE hr)-(g/hp

tHP ×××=

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

H = Fuel heating value (Btu/scf) 

U = Fuel usage (Mscf/month) 

HP = Engine horsepower (hp) 

t = Engine operating time (hr/month) 

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

emissions. These factors come from AP-42, Section 3.2 (USEPA 2002). 
5-22 

Table 5-18 

Emission Factors for Natural Gas Engines 

where Engine Stroke Cycle = 2-Cycle and Engine 

Burn Type = Lean 

Pollutant 

EFfu

(lb/MMBtu)a

EFpo

(g/hp-hr) 

THC 1.64 5.6 

VOC 0.12 0.41 

SO2 5.88 × 10-4

 2 × 10-3

NOx (<90% load) 1.94 6.6 

PM10

b

3.84 × 10-2

0.13 

CO (<90% load) 0.353 1.2 

CH4 1.45 4.9 

CO2 110 374.2 

a

 To convert from lb/MMBtu to lb/MMscf, multiply

by 1,050

b

 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) 

THC 1.47 5.00 

VOC 0.12 0.41 

SO2 5.88 × 10-4

 2.00 × 10-3

NOx (<90% load) 0.85 2.89 

PM10

b

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

 To convert from lb/MMBtu to lb/MMscf, multiply by 

1,050

b

 Also represents PM2.5
5-23 

Table 5-20 

Emission Factors for Natural Gas Engines 

where Engine Stroke Cycle = 

4-Cycle and Engine Burn Type = Rich 

Pollutant 

EFfu

(lb/MMBtu)a

EFpo

(g/hp-hr) 

THC 0.36 1.25 

VOC 0.03 0.1 

SO2 5.88 × 10-4

 2.00 × 10-3

NOx (<90% 

load 

2.27 7.72 

PM10

b

9.5 × 10-3

0.03 

CO (<90 % 

load) 

3.51 11.94 

CH4 0.23 0.78 

CO2 110 374.22 

a

 To convert from lb/MMBtu to lb/MMscf, multiply

by 1,050

b

 Also represents PM2.5

Table 5-21 

Emission Factors for Natural Gas Engines 

where Engine Burn Type = Clean 

Pollutant 

EFfu

(lb/MMBtu)a

EFpo

(g/hp-hr) 

THC 1.47 5.00 

VOC 0.12 0.41 

SO2 5.88 × 10-4

 2.00 × 10-3

NOx 0.59 2.00 

PM10

b

7.71 × 10-5 2.6 × 10-4

CO 0.88 3.00 

CH4 1.25 4.25 

CO2 110 374.22 

a

 To convert from lb/MMBtu to lb/MMscf, multiply

by 1,050

b

 Also represents PM2.5

If the corresponding field is null, a fuel consumption rate of 7,000 Btu/hp-hr is applied. 
5-24 

5.2.11 Natural Gas Turbines 

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

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

electricity (Boyer and Brodnax 1996). A turbine’s operating load has a considerable effect on the 

resulting emission levels. With reduced loads, there are lower thermal efficiencies and more 

incomplete combustion (USEPA 2002). 

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

upon fuel use. Otherwise, if operating horsepower and hours operated are both available, then 

emissions are estimated based upon power output. 

To calculate emissions based on fuel use: 

E EF 10 UH

3-

fu = (lb/MMBtu) ×××

To calculate emissions based on power output: 

EFE tHPFU 10

6

po = (lb/MMBtu) ××××

−

where: 

E = Emissions in pounds per month 

EF = Emission factor (units are shown in parentheses) 

H = Fuel heating value (Btu/scf) 

U = Fuel usage (Mscf/month) 

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

HP = Turbine horsepower (hp) 

t = Turbine operating time (hr/month) 

The following emission factors are used to estimate emissions (Table 5-22). These factors 

come from AP-42 Section 3.1 (USEPA 2002). 
5-25 

Table 5-22 

Emission Factors for Natural Gas Turbines 

Pollutant 

EF 

(lb/MMBtu)a

THC 1.1 × 10-2

VOC 2.1 × 10-3

SO2 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 

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

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

a To convert from lb/MMBtu to lb/MMscf, multiply by 

 1,050

b Also represents PM2.5

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

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). 

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. 
5-26 

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 5-23 presents the 

default gas composition if not provided. Table 5-23 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. 

Table 5-23 

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. 
5-27 

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). 

Operators were asked to provide the following information for controllers that are in 

natural gas service: 

• Service type (pressure control vs. level control); 

• Manufacturer and model; 

• Amount of natural gas consumed in scf/hr (optional); and 

• Hours of operation in the reporting period. 

Similar to pneumatic pumps, CO2, CH4, THC, and VOC emissions estimates (in pounds) 

for pressure and level controllers are developed using the following equation (EIIP 1999): 

E = No. of units × t × FU × (mole weight of gas, lbs/lb-mole) × (1 lb-mole/379.4 scf) 

where: 

E = Emissions in pounds per month 

t = Operating time (hr/month) 

FU = Fuel usage rate (scf/hr)

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 5-23 presents the default gas 

composition if not provided. Table 5-23 also presents the mole weight for each gas constituent. 

If the fuel usage rate is not provided, an average value for each make and model is 

assigned based on reported manufacturer data, or an average surrogate based on the manufacturer 

and service type is applied. 

5.2.14 Storage Tanks 

VOC and CH4 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. 
5-28 

Standing losses result from the expulsion of vapors due to vapor expansion and 

contraction resulting from temperature and barometric pressure changes. Working losses result 

from filling and emptying operations (Boyer and Brodnax 1996). These calculations assume that 

all tanks are fixed roof tanks. 

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

THC s, ××××= KKWVDL SEVV

where: 

Ls = Standing losses (lbs/month) 

D = Number of days in the month 

VV = Tank vapor space volume (ft3) 

WV = Stock vapor density (lb/ft3) 

KE = Calculated vapor space expansion factor (unitless) 

KS = Calculated vented vapor saturation factor (unitless) 

Vapor space volume for a horizontal, rectangular tank is calculated as: 

VV = Tank Shell Length × Tank Shell Width1 × HVO

where: 

VV = Vapor space volume (ft3)

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

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: 
5-29 

VO

2

V HDiam ShellTank 

4

V ×= ×

π

where: 

VV = Vapor space volume (ft3) 

HVO = Vapor space outage (ft) = 











=





























+ +

+ =

dome"" Type RoofTank if ; 

Diam ShellTank 

Hgt RoofTank 

Hgt RoofTank Hgt Liquid AvgTank Hgt ShellTank 

Hgt Liquid AvgTank Hgt ShellTank peaked""or cone"" Type RoofTank if ;Hgt RoofTank 

2

6

1

2

1

3

1

-

-

 TankShell Hgt-TankAvgLiquidHgt; if Tank Roof Type = “Flat”

Stock vapor density is calculated as: 

Wv = (Tank VOC Molecular Weight × PVA) ÷ (10.731 × TLA) 

where: 

WV = Stock vapor density (lb/ft3) 

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

A = Empirical constant = 12.82 − 0.9672 × ln(ReidVP) 

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

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

I) 

Taa = Daily average ambient temperature (°R) (See Table 5.24) 

a = Tank paint solar absorptance (See Table 5.25) 

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: 

= LAvE + − − vaabv )PP/()P(P)/TT(K

where: 

KE = Vapor space expansion factor 

Tv = Daily vapor temperature range (°R) = 0.72 × Ta+ 0.028 × a × I 

TLA= Daily average liquid surface temperature (°R) 

Pv = Daily pressure range (psia)= 0.50 × B × Pva × Tv/TLA

2

Pb = Breather vent pressure setting range (psig) = Breather vent pressure − breather vent 

vacuum 

Pa = Atmospheric pressure (psia) 

Pva = Vapor pressure at daily average liquid surface temperature (psia) 

The vented vapor saturation factor is calculated as: 
5-30 

VA VO S ××+= HP053.01/(1K ) 

where: 

KS = Vented vapor saturation factor 

PVA = Vapor pressure at daily average liquid surface temperature (psia) 

HVO = Vapor space outage (ft) 

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

L THC w, 0.0010×= Mol VOCTank P Weight VA ×× Throughput ×× KK NP

where: 

Lw = Working losses 

PVA = Vapor pressure at daily average liquid surface temperature (psia) 

KP = Working loss product factor (unitless) = 0.75 

KN = Working loss turnover factor (unitless) =







>

≤

+ 36 Nfor ;

36 Nfor 1;

6N

N180

 

N = Number of turnovers per month = 5.614 × throughput/VLX

VLX = Tank maximum liquid volume (ft3) 

Tank maximum liquid volume for a horizontal, rectangular tank is calculated as: 

VLX = Tank Shell Length × Tank Shell Width1 × Tank Shell Height 

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

VLX = Tank Shell Width1 × Tank Shell Width2 × Tank Shell Height 

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

Diam ShellTank Length ShellTank 

4

V

2

LX ×= ×

π

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

Diam ShellTank Hgt ShellTank 

4

V

2

LX ×= ×

π

where: 

VLX = Tank maximum liquid volume (ft3)
5-31 

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

(USEPA 2008): 0.467 for VOC, and 0.463 for CH4. Need to mention Tables 5-24 and 5-25. 

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

Table 5-24 

Daily Average Ambient Temperature, Taa

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

°F 54 61 63 70 77 82 83 82 79 72 64 58 

°R 514 521 523 530 537 542 543 542 539 533 524 518 

Source: USDOC, National Climatic Data Center 2009 

Table 5-25 

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 
5-32 

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. 

Vent emissions of VOC are estimated using the following equation: 

V1000

molscf/lb 379.4

m

ppm

10 E C

VOC

6

VOC vent, VOC ××

⋅

××=

−

where: 

Event, VOC = VOC emissions in pounds per month 

CVOC = Concentration of VOC in the vent gas (ppmv) 

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

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

Vent emissions of H2S are estimated using the following equation: 

( ) H2S

H2S

6

SH vent, 000 CV1

molscf/lb 379.4

m

ppm

10 E 2

×××

⋅

×=

−

where: 

Event, H2S = H2S emissions in pounds 

CH2S = Concentration of H2S in the vent gas (ppmv) 

mH2S = Molecular weight of H2S = 34 lb/lb mol 

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

Vent emissions of CH4 are estimated using the following equation: 

V1000

molscf/lb 379.4

m

ppm

10 CE

CH4

6

CH4 vent, CH4 ××

⋅

××=

−

where: 

Event, CH4 = CH4 emissions in pounds 

CCH4 = Concentration of CH4 in the vent gas (ppmv) 

MCH4 = Molecular weight of CH4 = 16 lb/lb mol 

V = Volume of gas vented from miscellaneous sources (Mscf) 
5-33 

If a flare is used: 

100%

Eff Event Event FLARE

controlled ×=

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

VOC concentration = 12,700 ppmv (= 1.27 mol %) 

H2S concentration = 3.38 ppmv 

CH4 concentration = 945,000 ppmv (= 94.5 mol %) 

5.2.16 Minor Sources 

In order to prepare a “complete” inventory of OCS oil and natural gas platforms and other 

sources in the Gulf of Mexico, the BOEM requested that operators compiling the GOADS-2008 

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. Table 5-26 provides the surrogate VOC and CH4 emission 

estimates assigned to the 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, but equipment records 

were 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. If TIMS did not identify the platform as a minor source, 

emissions were calculated using the activity data provided and surrogate estimates were not 

assigned. 

Table 5-26 

Surrogate Emission Estimates Applied to Minor Sources 

Minor Source 

VOC 

(tons/year) 

CH4 

(tons/year) 

Caisson 0.141 0.426 

Wellhead Protector 0.141 0.426 

Other 0.141 0.426 

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 
5-34 

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 current 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) 

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

calculated as: 
5-35 

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 
6-1 

6. DEVELOPMENT OF THE NON-PLATFORM EMISSIONS INVENTORY 

Emission estimates were developed for criteria air pollutants and greenhouse gases for 

non-platform OCS sources operating in the Gulf of Mexico for the 2008 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 

• Louisiana Offshore Oil Platform (LOOP) 

• Military vessels (Coast Guard/Navy) 

• Vessel lightering 

The ERG developed the Gulfwide non-platform emission estimates primarily based on 

work previously performed in the Year 2005 Gulfwide Emission Inventory Study (Wilson et al. 

2007). The 2008 inventory is based on updated activity data to accurately represent operations in 

the Gulf of Mexico. Drilling rig data for 2008 were obtained from BOEM and matched to vessel 

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

semisubmersibles were more accurately estimated in the 2008 inventory for individual rigs based 

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

2008 were downloaded and used in this inventory. The support vessels fleet was updated for 

2008 where possible, using data provided by the Offshore Marine Service Association. 

Additional data were also provided by one survey vessel company that allowed for a more 

accurate estimates of emissions by updating the fleet compositions and day-at-sea assumptions. 

The National Marine Fisheries Service provided new data sets of fishing activities. Skaugen 

Petrotrans provided 2008 data for vessels lightering operations. The USEPA provided 2008 

emission estimates for large commercial marine vessels (CMVs) that operate in U.S. waters. 

It should be noted that 2008 activity data were not available for some source categories 

such as biogenic and geogenic sources, the LOOP, and military vessels. A literature survey was 

implemented to identify new biogenic and geogenic studies that could be used to enhance the 

2008 estimates, but no recent or appropriate data were identified in this effort. 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. The US Coast Guard was 

contacted to determine if any of the new patrol boats or cutters were added to their Gulf fleet or 

if any older vessels were retired; there were no changes reported in their 2008 fleet composition. 
6-2 

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; none of the closures 

that are currently being implemented would affect naval operations in 2008. The Federal 

Aviation Administration (FAA) was contacted several times to obtain updated 2008 helicopter 

data, but no new data were provided. FAA data for 2005 were adjusted to reflect an increase in 

activity based on the Helicopter Safety Advisory Conference 2008 survey. 

Enhancements made in the 2008 inventory include use of new USEPA CMV estimates 

for 2008 for Federal waters. These estimates were developed based on European emission factors 

similar to the Swedish emission factors that are used in this report for other marine diesel 

engines. Emergency generators associated with drilling rigs were also added to the 2008 

inventory. The BOEM was able to provide data on new pipelaying construction and maintenance 

activities; in previous inventories new construction and maintenance activities were aggregated. 

The helicopter emission factors used in this inventory were also updated incorporating recent test 

data from several recent U.S. and European data sources. For naval vessels, emissions were 

estimated using the Swedish Environmental Protection Agency (SEPA) emission factors rather 

than carry over the estimates from previous years. One last enhancement for the 2008 nonplatform inventory is that the annual emissions were disaggregated into monthly estimates using 

2008 data on monthly activity levels. It is important that the monthly non-platform estimates are 

now comparable with the temporal resolution of the platform data. For some source categories 

such as support vessels and CMVs, Automatic Identification System (AIS) data were used that 

document the movement of all large vessels. 

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 CMVs, 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, or military vessels. These emission factors were obtained from the 

Swedish Environmental Protection Agency (SEPA 2004). The 2002 base year factors were 

chosen because the base factors represent uncontrolled emissions, but also account for 

International Maritime Organization (IMO) NOx emission standards. Also, the 2002 emission 

factors were broken out into the modes of operation. Unless otherwise noted, the at-sea emission 

factors were used, as the amount of time vessels spend maneuvering or hotelling at sea is 

relatively small compared to the amount of time spent underway. The emission factors also vary 

depending upon whether the engine is a low, medium, or high speed engine, and the type of fuel 

that is being used. Unless otherwise noted, it was assumed that the marine distillate fuel was used 

(distillate fuel oil #2), with a sulfur content of 0.4% was used for drilling rigs, pipeline 

construction, support and survey vessels, fishing boats and military vessels. Vessel-specific 

assumptions about mode of operation, fuel type, and engine speed are noted in each section 
6-3 

below. The SEPA emission factors used for this study are presented in Table 6-1. The table also 

shows the engine speed and fuel type assumptions for each vessel category. 

Several alternative emission factor references were also considered for the 2008 

inventory, including the IMO’s recent (IMO 2009) greenhouse gas study. The factors included in 

this study were appropriate for global fuel based assessments where vessel types and engine 

configurations are aggregated. The emission factors included in the IMO study were obtained 

from the European Environmental Agency (EEA) Emission Inventory Guidebook (EEA 2007), 

and the IPPC Guidelines for National Greenhouse Gas Inventories (IPCC 2006). Both of these 

data sources were considered as a supplemental source of emission factors. Unfortunately, both 

the EEA and IPCC emission factors are aggregated fuel-based factors and considered 

inappropriate for the detailed power-based activity data compiled for this inventory. 

Data from the 2006 TexAQS/GoMACCS, Comprehensive Chemical Analysis of TexAQS 

II Data (USDOC NOAA 2007), in conjunction with a presentation “Impact of Emissions from 

Commercial Shipping during TexAQS II” (Williams et al. 2007), confirm that the SEPA 

emission factors for high speed engines using residual fuels are within the range of results 

obtained from a large number of vessel plume sampling implemented in the Gulf area. One 

notable exception concerns the SO2 emission factors, which are higher in the SEPA study for 

medium speed vessels. This discrepancy is due to the different sulfur fuel content assumptions in 

the different studies. 

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 (percent) 

EF = Emission factor (g/kWH) 

CF = Conversion factor (g = 1.10231 E-6 ton) 
6-4 

Table 6-1 

Marine Vessel Emission Factors 

Vessel Type Mode 

Engine 

typea

Load 

Factor 

Emission Factors (g/kWh) 

NOx CO VOC SO2 NH3 PM10 PM2.5 C

Commercial Fishing VesselsLongline Fishing Vessels 

At Sea MSD 0.80 13.2 1.1 0.2 1.6 0.003 0.2 0.2 6

Maneuvering MSD 0.10 10.6 2.2 0.4 1.8 0.003 0.4 0.4 7

Reef Fishing Vessels 

At Sea MSD 0.80 13.2 1.1 0.2 1.6 0.003 0.2 0.2 6

Maneuvering MSD 0.10 10.6 2.2 0.4 1.8 0.003 0.4 0.4 7

Shrimp Fishing Vessels At Sea MSD 0.80 13.2 1.1 0.2 1.6 0.003 0.2 0.2 6Vessel LighteringOil Tankers Maneuvering SSD 0.10 13.6 1 0.6 1.6 0.003 0.4 0.4 6Escort Vessels Maneuvering MSD 0.10 10.6 2.2 0.4 1.8 0.003 0.4 0.4 7

At Sea MSD 0.80 13.2 1.1 0.2 1.6 0.003 0.2 0.2 6

LOOPTankers 

At Sea SSD 0.55 17.0 0.5 0.3 1.5 0.003 0.2 0.2 5

Idling SSD 0.10 13.6 1 0.6 1.6 0.003 0.4 0.4 6

Support Vessels Maneuvering HSD 0.25 9.6 2.2 0.4 1.8 0.003 0.4 0.4 7LOOP Generator N/A HSD 0.50 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6LOOP Pumps N/A HSD 1.00 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Pipelaying Operations Pipelaying At Sea MSD 0.75 10.6 2.2 0.4 1.8 0.003 0.4 0.4 7Drilling RigsDrill Ship Equipment At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Jack-up Equipment At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Semisubmersible Equipment At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Submersible Equipment At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Emergency Equipmentb At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Drill Ship Propulsion (maintain position) Maneuvering HSD 0.15 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Semisubmersible Propulsion(maintain position) Maneuvering HSD 0.15 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Drilling Propulsion (relocation) At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6
6-5 

Table 6-1 

Marine Vessel Emission Factors (continued). 

Vessel Type Mode 

Engine 

typea

Load 

Factor 

Emission Factors (g/kWh) 

NOx CO VOC SO2 NH3 PM10 PM2.5 C

Semisubmersible Propulsion(relocation) At Sea HSD 0.75 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6Survey VesselsSurvey Vessels At Sea MSD 0.90 13.2 1.1 0.2 1.6 0.003 0.2 0.2 6Support Vessels Supply/Crew Boats 

At Sea HSD 0.85 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6

Maneuvering HSD 0.10 9.6 2.2 0.4 1.8 0.003 0.4 0.4 7

Lift Boats 

At Sea HSD 0.85 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6

Maneuvering HSD 0.10 9.6 2.2 0.4 1.8 0.003 0.4 0.4 7

Tugs/Towing Boats 

At Sea HSD 0.85 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6

Maneuvering HSD 0.10 9.6 2.2 0.4 1.8 0.003 0.4 0.4 7

Military Vessels Buoy Tenders At Sea SSD 0.85 17.0 0.5 0.3 1.5 0.003 0.2 0.2 5Cutters/Naval Vessels At Sea MSD 0.85 13.2 1.1 0.2 1.6 0.003 0.2 0.2 6Patrol At Sea HSD 0.85 12.0 1.1 0.2 1.6 0.003 0.2 0.2 6

a SSD = Slow Speed Diesel Engine  MSD = Medium Speed Diesel Engine  HSD = High Speed Diesel Engine b Emergency generators are assumed to operate 500 hours per year based on USEPA guidance. 
6-6 

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 Gulf of 

Mexico, 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. 

The Operation and Analysis Branch of the Engineering and Operations Division of 

BOEM provided 2008 activity data for drilling rigs by block, which included activity for drill 

ships, jack-ups, platform rigs, semisubmersibles, and submersibles (Mathews 2009). 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 2008 through December 2008 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 

SU EI 29 ATWOOD RICHMOND 2/22/2008 4/5/2008 43 

SU EI 10 ATWOOD RICHMOND 9/15/2008 11/16/2008 62 

SU SS 186 ATWOOD RICHMOND 11/16/2008 12/31/2008 45 

PF GB 426 AUGER 1/1/2008 1/5/2008 4 

PF GB 426 AUGER 7/6/2008 7/26/2008 20 

PF GB 426 AUGER 10/17/2008 12/31/2008 75 

JU EI 28 BLAKE 101 1/1/2008 1/27/2008 26 

JU EI 28 BLAKE 101 2/8/2008 2/21/2008 13 

JU WD 29 BLAKE 101 3/24/2008 4/5/2008 12 

JU GA 301 BLAKE 151 1/1/2008 3/25/2008 84 

JU WC 168 BLAKE 151 4/6/2008 5/4/2008 28 

JU GA 209 BLAKE 151 5/5/2008 6/24/2008 50 

JU ST 67 BLAKE 151 7/7/2008 8/3/2008 27 

JU ST 67 BLAKE 151 9/19/2008 10/8/2008 19 

JU ST 67 BLAKE 151 10/8/2008 11/28/2008 51 

JU WD 31 BLAKE 151 11/29/2008 12/28/2008 29 

JU WD 30 BLAKE 151 12/30/2008 12/31/2008 1 

JU WC 78 BLAKE 202 1/1/2008 2/1/2008 31 

JU WC 20 BLAKE 202 4/21/2008 9/24/2008 156 

JU WC 20 BLAKE 202 9/24/2008 10/7/2008 13 

JU EC 84 BLAKE 202 12/8/2008 12/22/2008 14 

JU HI A 260 BLAKE 303 1/1/2008 2/10/2008 40 
6-7 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU HI A 198 BLAKE 303 2/9/2008 2/22/2008 13 

JU GA A 155 BLAKE 303 3/20/2008 4/5/2008 16 

JU VR 338 BLAKE 303 5/5/2008 6/17/2008 43 

JU EI 164 BLAKE 303 6/17/2008 8/26/2008 70 

JU EC 246 BLAKE 303 8/28/2008 9/29/2008 32 

JU EC 246 BLAKE 303 9/29/2008 11/13/2008 45 

JU SS 179 BLAKE 303 11/15/2008 12/5/2008 20 

JU EI 100 BLAKE 303 12/7/2008 12/31/2008 24 

PF EI 342 BLAKE INTERNATIONAL 7/2/2008 8/8/2008 37 

PF EI 342 BLAKE INTERNATIONAL 8/8/2008 12/31/2008 145 

BR MC 583 CAL DIVE Q-4000 6/10/2008 6/28/2008 18 

BR MC 705 CAL DIVE Q-4000 6/26/2008 7/8/2008 12 

BR MC 705 CAL DIVE Q-4000 7/8/2008 7/28/2008 20 

BR GB 197 CAL DIVE Q-4000 8/20/2008 10/7/2008 48 

BR EB 157 CAL DIVE Q-4000 10/18/2008 10/24/2008 6 

BR GC 200 CAL DIVE Q-4000 10/24/2008 10/24/2008 0 

BR GC 200 CAL DIVE Q-4000 10/24/2008 11/8/2008 15 

BR GC 200 CAL DIVE Q-4000 11/8/2008 11/26/2008 18 

BR GC 200 CAL DIVE Q-4000 11/26/2008 11/26/2008 0 

BR GC 200 CAL DIVE Q-4000 11/27/2008 12/9/2008 12 

BR GC 200 CAL DIVE Q-4000 12/9/2008 12/26/2008 17 

BR GC 248 CAL DIVE Q-4000 12/26/2008 12/31/2008 5 

SS ST 151 CAL DIVE UNCLE JOHN 1/1/2008 6/15/2008 166 

SS ST 151 CAL DIVE UNCLE JOHN 6/15/2008 10/8/2008 115 

SS EC 272 CAL DIVE UNCLE JOHN 10/8/2008 10/26/2008 18 

SS EC 272 CAL DIVE UNCLE JOHN 12/15/2008 12/31/2008 16 

BR SM 212 COASTAL RIG 22 1/1/2008 4/5/2008 95 

BR SM 212 COASTAL RIG 22 4/5/2008 10/23/2008 201 

BR SM 217 COASTAL RIG 22 10/24/2008 12/31/2008 68 

SS MC 353 

DIAMOND OCEAN 

AMBASSADOR 4/22/2008 5/12/2008 20 

SS MC 20 

DIAMOND OCEAN 

AMBASSADOR 12/29/2008 12/31/2008 2 

SS MC 72 DIAMOND OCEAN AMERICA 1/1/2008 1/24/2008 23 

SS MC 761 DIAMOND OCEAN AMERICA 1/24/2008 3/17/2008 53 

SS GB 462 DIAMOND OCEAN AMERICA 3/21/2008 3/27/2008 6 

SS GB 462 DIAMOND OCEAN AMERICA 3/27/2008 6/20/2008 85 

SS GB 462 DIAMOND OCEAN AMERICA 6/20/2008 8/7/2008 48 

SS GB 462 DIAMOND OCEAN AMERICA 8/8/2008 8/13/2008 5 

SS GB 462 DIAMOND OCEAN AMERICA 8/13/2008 10/8/2008 56 
6-8 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

SS GB 462 DIAMOND OCEAN AMERICA 10/8/2008 11/9/2008 32 

SS GB 462 DIAMOND OCEAN AMERICA 11/9/2008 12/31/2008 52 

SS GC 468 DIAMOND OCEAN BARONESS 1/1/2008 7/20/2008 201 

SS KC 596 DIAMOND OCEAN BARONESS 7/21/2008 12/31/2008 163 

JU SS 119 DIAMOND OCEAN CHAMPION 1/4/2008 1/14/2008 10 

JU SS 120 DIAMOND OCEAN CHAMPION 1/14/2008 2/1/2008 18 

JU SS 112 DIAMOND OCEAN CHAMPION 2/1/2008 5/26/2008 115 

JU ST 38 DIAMOND OCEAN CHAMPION 5/26/2008 6/18/2008 23 

JU SS 119 DIAMOND OCEAN CHAMPION 6/18/2008 9/28/2008 102 

JU SS 119 DIAMOND OCEAN CHAMPION 9/28/2008 10/31/2008 33 

JU SS 119 DIAMOND OCEAN CHAMPION 10/31/2008 12/16/2008 46 

SS MC 683 

DIAMOND OCEAN 

CONFIDENCE 1/1/2008 2/13/2008 43 

SS MC 734 

DIAMOND OCEAN 

CONFIDENCE 2/18/2008 3/30/2008 41 

SS MC 734 

DIAMOND OCEAN 

CONFIDENCE 3/31/2008 4/11/2008 11 

SS MC 734 

DIAMOND OCEAN 

CONFIDENCE 4/11/2008 5/27/2008 46 

SS MC 736 

DIAMOND OCEAN 

CONFIDENCE 5/27/2008 6/9/2008 13 

SS LL 268 

DIAMOND OCEAN 

CONFIDENCE 6/10/2008 6/16/2008 6 

SS LL 370 

DIAMOND OCEAN 

CONFIDENCE 6/17/2008 6/22/2008 5 

SS LL 268 

DIAMOND OCEAN 

CONFIDENCE 6/22/2008 7/11/2008 19 

SS LL 370 

DIAMOND OCEAN 

CONFIDENCE 7/11/2008 7/31/2008 20 

SS LL 511 

DIAMOND OCEAN 

CONFIDENCE 8/1/2008 8/18/2008 17 

SS DC 47 

DIAMOND OCEAN 

CONFIDENCE 8/19/2008 8/28/2008 9 

SS DC 47 

DIAMOND OCEAN 

CONFIDENCE 9/4/2008 10/9/2008 35 

SS MC 734 

DIAMOND OCEAN 

CONFIDENCE 10/10/2008 12/28/2008 79 

SS MC 734 

DIAMOND OCEAN 

CONFIDENCE 12/28/2008 12/31/2008 3 

JU WC 225 DIAMOND OCEAN CRUSADER 1/1/2008 1/6/2008 5 

JU WC 225 DIAMOND OCEAN CRUSADER 1/6/2008 2/7/2008 32 

JU WC 369 DIAMOND OCEAN CRUSADER 2/7/2008 3/3/2008 25 

JU SS 105 DIAMOND OCEAN CRUSADER 3/3/2008 3/28/2008 25 
6-9 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU EI 175 DIAMOND OCEAN CRUSADER 3/30/2008 4/10/2008 11 

JU EI 175 DIAMOND OCEAN CRUSADER 4/10/2008 4/27/2008 17 

JU EI 175 DIAMOND OCEAN CRUSADER 4/27/2008 6/8/2008 42 

JU ST 68 DIAMOND OCEAN CRUSADER 6/9/2008 8/19/2008 71 

JU ST 219 DIAMOND OCEAN CRUSADER 8/19/2008 9/4/2008 16 

JU VR 141 DIAMOND OCEAN CRUSADER 9/5/2008 10/5/2008 30 

JU EI 224 DIAMOND OCEAN CRUSADER 10/20/2008 12/31/2008 72 

JU SS 219 DIAMOND OCEAN DRAKE 1/1/2008 2/4/2008 34 

JU SS 219 DIAMOND OCEAN DRAKE 2/21/2008 2/26/2008 5 

JU SS 219 DIAMOND OCEAN DRAKE 2/26/2008 3/29/2008 32 

JU SS 219 DIAMOND OCEAN DRAKE 3/29/2008 4/13/2008 15 

JU SS 219 DIAMOND OCEAN DRAKE 4/13/2008 4/28/2008 15 

JU SS 219 DIAMOND OCEAN DRAKE 4/28/2008 5/8/2008 10 

JU SS 228 DIAMOND OCEAN DRAKE 5/10/2008 8/1/2008 83 

JU EI 215 DIAMOND OCEAN DRAKE 11/3/2008 12/31/2008 58 

SS WR 278 DIAMOND OCEAN ENDEAVOR 1/1/2008 3/16/2008 75 

SS WR 758 DIAMOND OCEAN ENDEAVOR 3/17/2008 11/22/2008 250 

SS WR 249 DIAMOND OCEAN ENDEAVOR 11/23/2008 12/31/2008 38 

SS EW 963 DIAMOND OCEAN QUEST 1/1/2008 2/22/2008 52 

SS MC 800 DIAMOND OCEAN QUEST 2/22/2008 6/3/2008 102 

SS MC 285 DIAMOND OCEAN QUEST 6/4/2008 7/8/2008 34 

SS MC 292 DIAMOND OCEAN QUEST 7/8/2008 10/21/2008 105 

SS MC 292 DIAMOND OCEAN QUEST 10/21/2008 10/28/2008 7 

SS MC 292 DIAMOND OCEAN QUEST 10/28/2008 11/7/2008 10 

SS GC 385 DIAMOND OCEAN QUEST 11/11/2008 11/30/2008 19 

SS MC 711 DIAMOND OCEAN QUEST 12/5/2008 12/31/2008 26 

SS GC 6 DIAMOND OCEAN SARATOGA 1/1/2008 3/7/2008 66 

SS GC 6 DIAMOND OCEAN SARATOGA 3/7/2008 3/20/2008 13 

SS GC 6 DIAMOND OCEAN SARATOGA 3/20/2008 3/21/2008 1 

SS GC 6 DIAMOND OCEAN SARATOGA 3/21/2008 4/25/2008 35 

SS GC 97 DIAMOND OCEAN SARATOGA 4/25/2008 7/14/2008 80 

SS EW 871 DIAMOND OCEAN SARATOGA 7/14/2008 10/30/2008 108 

SS GB 339 DIAMOND OCEAN SARATOGA 11/1/2008 12/13/2008 42 

SS EW 998 DIAMOND OCEAN SARATOGA 12/13/2008 12/31/2008 18 

JU EI 173 DIAMOND OCEAN SPARTAN 1/1/2008 2/20/2008 50 

JU EI 173 DIAMOND OCEAN SPARTAN 2/20/2008 3/19/2008 28 

JU EI 175 DIAMOND OCEAN SPARTAN 3/19/2008 4/13/2008 25 

JU EI 175 DIAMOND OCEAN SPARTAN 4/13/2008 6/16/2008 64 

JU SM 102 DIAMOND OCEAN SPARTAN 6/16/2008 6/26/2008 10 

JU SM 102 DIAMOND OCEAN SPARTAN 6/26/2008 7/14/2008 18 
6-10 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU SM 102 DIAMOND OCEAN SPARTAN 7/14/2008 8/20/2008 37 

JU SM 102 DIAMOND OCEAN SPARTAN 8/20/2008 10/1/2008 42 

JU SM 102 DIAMOND OCEAN SPARTAN 10/2/2008 10/19/2008 17 

JU SM 102 DIAMOND OCEAN SPARTAN 10/20/2008 10/29/2008 9 

JU SM 102 DIAMOND OCEAN SPARTAN 10/29/2008 11/7/2008 9 

JU VR 272 DIAMOND OCEAN SPARTAN 11/8/2008 12/16/2008 38 

JU VR 272 DIAMOND OCEAN SPARTAN 12/18/2008 12/31/2008 13 

SS GB 302 DIAMOND OCEAN STAR 1/1/2008 1/6/2008 5 

SS GB 667 DIAMOND OCEAN STAR 1/9/2008 3/6/2008 57 

SS GB 667 DIAMOND OCEAN STAR 3/6/2008 3/19/2008 13 

SS GB 667 DIAMOND OCEAN STAR 3/19/2008 4/12/2008 24 

SS GB 215 DIAMOND OCEAN STAR 4/14/2008 5/13/2008 29 

SS GB 215 DIAMOND OCEAN STAR 5/13/2008 7/23/2008 71 

SS GC 643 DIAMOND OCEAN STAR 7/31/2008 12/31/2008 153 

JU ST 46 DIAMOND OCEAN SUMMIT 1/13/2008 3/25/2008 72 

JU ST 26 DIAMOND OCEAN SUMMIT 3/26/2008 4/20/2008 25 

JU ST 26 DIAMOND OCEAN SUMMIT 4/20/2008 6/7/2008 48 

JU ST 26 DIAMOND OCEAN SUMMIT 6/7/2008 9/28/2008 113 

JU EI 277 DIAMOND OCEAN SUMMIT 9/28/2008 10/22/2008 24 

JU SS 233 DIAMOND OCEAN SUMMIT 10/22/2008 11/17/2008 26 

JU HI A 538 DIAMOND OCEAN SUMMIT 11/24/2008 12/16/2008 22 

JU VR 320 DIAMOND OCEAN SUMMIT 12/17/2008 12/31/2008 14 

JU EI 158 DIAMOND OCEAN TITAN 1/1/2008 2/23/2008 53 

JU EI 158 DIAMOND OCEAN TITAN 2/23/2008 3/20/2008 26 

JU EI 158 DIAMOND OCEAN TITAN 4/20/2008 6/1/2008 42 

JU EI 158 DIAMOND OCEAN TITAN 6/1/2008 6/21/2008 20 

JU WD 95 DIAMOND OCEAN TITAN 6/21/2008 8/17/2008 57 

JU WD 95 DIAMOND OCEAN TITAN 8/17/2008 11/9/2008 84 

JU WD 95 DIAMOND OCEAN TITAN 11/9/2008 12/31/2008 52 

JU EC 272 DIAMOND OCEAN TOWER 1/1/2008 1/21/2008 20 

JU EI 338 DIAMOND OCEAN TOWER 1/21/2008 5/8/2008 108 

JU ST 176 DIAMOND OCEAN TOWER 5/12/2008 7/4/2008 53 

JU VR 245 DIAMOND OCEAN TOWER 7/5/2008 10/16/2008 103 

SS GC 448 DIAMOND OCEAN VALIANT 1/1/2008 2/2/2008 32 

SS EB 688 DIAMOND OCEAN VALIANT 2/2/2008 3/19/2008 46 

SS EB 646 DIAMOND OCEAN VALIANT 3/19/2008 4/7/2008 19 

SS EB 646 DIAMOND OCEAN VALIANT 4/7/2008 5/9/2008 32 

SS EB 646 DIAMOND OCEAN VALIANT 5/9/2008 5/29/2008 20 

SS EB 646 DIAMOND OCEAN VALIANT 5/29/2008 6/17/2008 19 

SS EB 646 DIAMOND OCEAN VALIANT 6/19/2008 7/12/2008 23 
6-11 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

SS EB 599 DIAMOND OCEAN VALIANT 12/10/2008 12/31/2008 21 

SS MC 538 DIAMOND OCEAN VICTORY 2/23/2008 4/5/2008 42 

SS MC 538 DIAMOND OCEAN VICTORY 4/5/2008 5/25/2008 50 

SS GC 516 DIAMOND OCEAN VICTORY 5/25/2008 7/8/2008 44 

SS GC 646 DIAMOND OCEAN VICTORY 7/8/2008 8/13/2008 36 

SS GB 782 DIAMOND OCEAN VICTORY 8/13/2008 12/19/2008 128 

JU EI 152 ENSCO 60 1/1/2008 2/22/2008 52 

JU HI 170 ENSCO 60 2/26/2008 8/8/2008 164 

JU HI 170 ENSCO 60 8/8/2008 10/31/2008 84 

JU VR 344 ENSCO 60 11/1/2008 12/13/2008 42 

JU SM 111 ENSCO 60 12/14/2008 12/31/2008 17 

JU SS 315 ENSCO 68 1/1/2008 2/5/2008 35 

JU SS 315 ENSCO 68 2/5/2008 3/30/2008 54 

JU SS 315 ENSCO 68 3/30/2008 6/16/2008 78 

JU ST 229 ENSCO 68 6/17/2008 9/23/2008 98 

JU EI 261 ENSCO 68 9/27/2008 12/27/2008 91 

JU EI 360 ENSCO 68 12/27/2008 12/31/2008 4 

JU MU A 85 ENSCO 74 1/1/2008 3/13/2008 72 

JU HI A 376 ENSCO 74 3/26/2008 4/14/2008 19 

JU SS 317 ENSCO 74 4/21/2008 6/1/2008 41 

JU VR 332 ENSCO 74 6/4/2008 8/7/2008 64 

JU SM 149 ENSCO 74 8/7/2008 9/13/2008 37 

JU EI 318 ENSCO 75 1/1/2008 1/8/2008 7 

JU EI 318 ENSCO 75 1/8/2008 1/13/2008 5 

JU EI 318 ENSCO 75 1/13/2008 2/16/2008 34 

JU EI 318 ENSCO 75 2/16/2008 3/20/2008 33 

JU EI 346 ENSCO 75 3/20/2008 5/5/2008 46 

JU EI 346 ENSCO 75 5/5/2008 5/26/2008 21 

JU EI 346 ENSCO 75 5/26/2008 6/15/2008 20 

JU EI 346 ENSCO 75 6/15/2008 7/8/2008 23 

JU VR 372 ENSCO 75 7/9/2008 9/5/2008 58 

JU WC 130 ENSCO 75 9/7/2008 11/7/2008 61 

JU ST 268 ENSCO 75 11/10/2008 12/31/2008 51 

SS WR 29 ENSCO 7500 1/1/2008 2/3/2008 33 

SS AT 138 ENSCO 7500 2/4/2008 8/30/2008 208 

SS AT 138 ENSCO 7500 9/3/2008 9/8/2008 5 

SS AT 138 ENSCO 7500 9/15/2008 9/25/2008 10 

JU EI 307 ENSCO 82 1/1/2008 1/6/2008 5 

JU EI 315 ENSCO 82 1/7/2008 2/7/2008 31 

JU MP 61 ENSCO 82 2/10/2008 3/7/2008 26 
6-12 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU MP 61 ENSCO 82 3/7/2008 4/30/2008 54 

JU MP 61 ENSCO 82 4/30/2008 6/10/2008 41 

JU MP 61 ENSCO 82 6/10/2008 6/26/2008 16 

JU MP 73 ENSCO 82 6/26/2008 7/23/2008 27 

JU MP 73 ENSCO 82 7/23/2008 8/23/2008 31 

JU ST 130 ENSCO 82 9/20/2008 10/6/2008 16 

JU ST 130 ENSCO 82 10/6/2008 10/26/2008 20 

JU ST 130 ENSCO 82 10/26/2008 11/5/2008 10 

JU ST 130 ENSCO 82 11/9/2008 12/6/2008 27 

JU ST 130 ENSCO 82 12/6/2008 12/18/2008 12 

JU ST 130 ENSCO 82 12/18/2008 12/30/2008 12 

JU EI 71 ENSCO 83 1/1/2008 2/15/2008 45 

JU EC 178 ENSCO 83 2/29/2008 6/15/2008 107 

JU SM 44 ENSCO 83 6/16/2008 10/17/2008 123 

JU SM 40 ENSCO 83 10/17/2008 12/27/2008 71 

JU SM 73 ENSCO 83 12/27/2008 12/31/2008 4 

JU HI 38 ENSCO 86 1/1/2008 6/14/2008 165 

JU MO 830 ENSCO 86 6/17/2008 12/31/2008 197 

JU MU A 31 ENSCO 87 1/1/2008 4/20/2008 110 

JU MP 72 ENSCO 87 4/27/2008 6/3/2008 37 

JU MP 301 ENSCO 87 8/10/2008 12/25/2008 137 

JU WD 107 ENSCO 87 12/26/2008 12/31/2008 5 

JU MO 992 ENSCO 89 1/1/2008 1/13/2008 12 

JU EI 64 ENSCO 89 1/13/2008 3/1/2008 48 

JU EI 252 ENSCO 89 3/2/2008 10/7/2008 219 

JU EI 246 ENSCO 89 10/9/2008 11/15/2008 37 

JU EI 246 ENSCO 89 11/15/2008 11/25/2008 10 

JU EI 246 ENSCO 89 11/25/2008 12/28/2008 33 

JU ST 217 ENSCO 90 1/1/2008 2/1/2008 31 

JU WC 68 ENSCO 90 2/4/2008 3/16/2008 41 

JU SS 129 ENSCO 90 3/16/2008 3/20/2008 4 

JU SM 281 ENSCO 90 3/20/2008 8/24/2008 157 

JU SS 129 ENSCO 90 8/25/2008 10/3/2008 39 

JU SS 129 ENSCO 90 10/3/2008 11/29/2008 57 

JU SS 129 ENSCO 90 11/29/2008 12/31/2008 32 

JU MP 125 ENSCO 93 3/12/2008 10/17/2008 219 

JU MP 112 ENSCO 93 10/17/2008 11/22/2008 36 

JU WD 45 ENSCO 93 11/24/2008 12/20/2008 26 

JU EI 184 ENSCO 98 1/1/2008 4/12/2008 102 

JU EI 184 ENSCO 98 4/12/2008 8/20/2008 130 
6-13 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU EI 184 ENSCO 98 8/20/2008 8/24/2008 4 

JU EI 184 ENSCO 98 8/25/2008 10/4/2008 40 

JU EI 184 ENSCO 98 10/4/2008 12/31/2008 88 

JU PL 21 ENSCO 99 1/1/2008 3/14/2008 73 

JU ST 81 ENSCO 99 3/14/2008 4/19/2008 36 

JU SS 116 ENSCO 99 4/19/2008 6/27/2008 69 

JU SS 99 ENSCO 99 6/27/2008 7/31/2008 34 

JU ST 100 ENSCO 99 8/1/2008 9/6/2008 36 

JU ST 75 ENSCO 99 9/6/2008 11/17/2008 72 

JU WD 30 ENSCO 99 11/17/2008 12/31/2008 44 

JU HI A 351 GSF ADRIATIC III 1/1/2008 2/21/2008 51 

DS GC 652 GSF C.R. LUIGS 1/1/2008 1/8/2008 7 

DS GC 653 GSF C.R. LUIGS 1/8/2008 1/14/2008 6 

DS GC 652 GSF C.R. LUIGS 1/14/2008 3/29/2008 75 

DS GC 653 GSF C.R. LUIGS 3/29/2008 4/24/2008 26 

DS GC 654 GSF C.R. LUIGS 4/24/2008 5/21/2008 27 

DS GC 653 GSF C.R. LUIGS 5/21/2008 6/13/2008 23 

DS GC 652 GSF C.R. LUIGS 6/13/2008 7/29/2008 46 

DS GC 610 GSF C.R. LUIGS 7/30/2008 8/5/2008 6 

DS GC 654 GSF C.R. LUIGS 8/5/2008 8/9/2008 4 

DS GC 653 GSF C.R. LUIGS 8/9/2008 9/26/2008 48 

DS GC 610 GSF C.R. LUIGS 9/28/2008 11/22/2008 55 

DS GC 654 GSF C.R. LUIGS 11/22/2008 12/21/2008 29 

DS GC 653 GSF C.R. LUIGS 12/21/2008 12/31/2008 10 

SS MC 460 GSF CELTIC SEA 1/1/2008 5/21/2008 141 

SS GC 517 GSF CELTIC SEA 5/21/2008 7/8/2008 48 

SS AT 618 GSF DEVELOPMENT DRILLER I 1/1/2008 2/28/2008 58 

SS AT 574 GSF DEVELOPMENT DRILLER I 2/28/2008 5/10/2008 72 

SS GC 652 GSF DEVELOPMENT DRILLER I 5/18/2008 5/25/2008 7 

SS GC 654 GSF DEVELOPMENT DRILLER I 5/25/2008 5/26/2008 1 

SS GC 653 GSF DEVELOPMENT DRILLER I 5/26/2008 10/31/2008 158 

SS GC 653 GSF DEVELOPMENT DRILLER I 11/1/2008 11/20/2008 19 

SS GC 653 GSF DEVELOPMENT DRILLER I 11/20/2008 12/31/2008 41 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 1/1/2008 1/6/2008 5 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 1/6/2008 2/18/2008 43 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 2/18/2008 4/17/2008 59 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 4/18/2008 6/18/2008 61 
6-14 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 7/5/2008 8/16/2008 42 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 8/17/2008 11/22/2008 97 

SS GC 743 

GSF DEVELOPMENT 

DRILLER II 11/22/2008 12/31/2008 39 

JU WC 57 GSF HIGH ISLAND I 1/1/2008 1/28/2008 27 

JU WD 68 GSF HIGH ISLAND VIII 1/1/2008 1/11/2008 10 

JU WD 68 GSF HIGH ISLAND VIII 1/11/2008 1/17/2008 6 

JU WC 61 GSF HIGH ISLAND VIII 1/28/2008 5/20/2008 113 

PF EW 826 H&P 100 1/1/2008 3/18/2008 77 

PF EW 826 H&P 100 3/18/2008 6/1/2008 75 

PF EW 826 H&P 100 6/1/2008 9/22/2008 113 

PF EW 826 H&P 100 11/3/2008 11/28/2008 25 

PF EW 826 H&P 100 11/28/2008 12/8/2008 10 

PF EW 826 H&P 100 12/8/2008 12/31/2008 23 

PF EW 826 H&P 100 9/22/2008 11/3/2008 42 

PF ST 308 H&P 105 2/24/2008 3/23/2008 28 

PF ST 308 H&P 105 3/23/2008 12/31/2008 283 

PF SP 83 H&P 107 1/1/2008 1/5/2008 4 

PF SP 83 H&P 107 1/5/2008 1/24/2008 19 

PF SP 83 H&P 107 1/24/2008 2/4/2008 11 

PF SP 83 H&P 107 2/4/2008 2/22/2008 18 

PF SP 83 H&P 107 2/22/2008 2/24/2008 2 

PF SP 83 H&P 107 2/24/2008 2/25/2008 1 

PF SP 83 H&P 107 2/25/2008 2/27/2008 2 

PF SP 83 H&P 107 2/27/2008 3/24/2008 26 

PF SP 83 H&P 107 3/25/2008 3/31/2008 6 

PF SP 83 H&P 107 3/31/2008 4/7/2008 7 

PF SP 83 H&P 107 4/7/2008 4/16/2008 9 

PF SP 83 H&P 107 4/16/2008 5/20/2008 34 

PF SP 83 H&P 107 5/20/2008 6/7/2008 18 

PF SP 83 H&P 107 6/7/2008 8/9/2008 63 

PF SP 83 H&P 107 8/9/2008 9/29/2008 51 

PF SP 83 H&P 107 9/29/2008 10/8/2008 9 

PF SP 83 H&P 107 10/8/2008 10/21/2008 13 

PF SP 83 H&P 107 10/21/2008 12/2/2008 42 

PF SP 83 H&P 107 12/2/2008 12/21/2008 19 

PF SP 83 H&P 107 12/21/2008 12/31/2008 10 

PF MC 807 H&P 201 1/1/2008 1/8/2008 7 
6-15 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

PF MC 807 H&P 201 1/8/2008 1/24/2008 16 

PF MC 807 H&P 201 1/24/2008 10/26/2008 276 

PF MC 807 H&P 201 10/26/2008 12/8/2008 43 

PF MC 807 H&P 201 12/8/2008 12/31/2008 23 

PF GC 158 H&P 202 1/1/2008 3/15/2008 74 

PF GC 158 H&P 202 3/15/2008 5/23/2008 69 

PF GC 158 H&P 202 7/14/2008 12/18/2008 157 

PF MP 283 H&P 206 3/21/2008 8/10/2008 142 

PF MP 283 H&P 206 8/10/2008 12/10/2008 122 

PF MP 283 H&P 206 12/10/2008 12/31/2008 21 

JU SP 28 HERCULES 101 3/10/2008 4/8/2008 29 

JU SP 28 HERCULES 101 8/15/2008 10/19/2008 65 

JU SP 28 HERCULES 101 10/19/2008 11/11/2008 23 

JU SP 28 HERCULES 101 11/11/2008 11/25/2008 14 

JU MP 60 HERCULES 101 11/25/2008 12/31/2008 36 

JU ST 37 HERCULES 120 1/1/2008 1/23/2008 22 

JU ST 36 HERCULES 120 1/23/2008 6/8/2008 137 

JU ST 52 HERCULES 120 6/8/2008 7/10/2008 32 

JU ST 36 HERCULES 120 7/10/2008 7/21/2008 11 

JU ST 51 HERCULES 120 7/21/2008 7/28/2008 7 

JU ST 51 HERCULES 120 7/28/2008 8/30/2008 33 

JU MP 30 HERCULES 120 9/22/2008 9/30/2008 8 

JU MO 904 HERCULES 120 10/1/2008 11/3/2008 33 

JU MO 918 HERCULES 120 11/3/2008 11/3/2008 0 

JU BS 55 HERCULES 120 11/4/2008 12/16/2008 42 

JU MP 41 HERCULES 120 12/16/2008 12/22/2008 6 

JU MP 41 HERCULES 120 12/22/2008 12/31/2008 9 

JU EI 31 HERCULES 150 3/21/2008 4/21/2008 31 

JU EI 57 HERCULES 150 4/22/2008 5/17/2008 25 

JU EI 57 HERCULES 150 5/17/2008 6/26/2008 40 

JU EI 57 HERCULES 150 6/26/2008 7/11/2008 15 

JU EI 57 HERCULES 150 7/11/2008 7/17/2008 6 

JU VR 31 HERCULES 150 10/27/2008 11/20/2008 24 

JU EI 33 HERCULES 150 11/21/2008 12/14/2008 23 

JU EI 32 HERCULES 150 12/14/2008 12/31/2008 17 

JU GA 283 HERCULES 152 4/21/2008 7/30/2008 100 

JU EC 37 HERCULES 152 8/1/2008 9/17/2008 47 

JU GA 321 HERCULES 152 12/5/2008 12/31/2008 26 

JU BA 341 HERCULES 153 11/23/2008 12/19/2008 26 

JU BA 342 HERCULES 153 12/19/2008 12/31/2008 12 
6-16 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU ST 23 HERCULES 173 2/8/2008 3/12/2008 33 

JU ST 23 HERCULES 173 3/12/2008 3/31/2008 19 

JU ST 23 HERCULES 173 3/31/2008 4/28/2008 28 

JU ST 23 HERCULES 173 4/28/2008 5/7/2008 9 

JU BM 2 HERCULES 173 6/5/2008 6/15/2008 10 

JU ST 24 HERCULES 173 6/20/2008 6/28/2008 8 

JU ST 24 HERCULES 173 6/28/2008 7/17/2008 19 

JU ST 23 HERCULES 173 7/17/2008 8/10/2008 24 

JU BM 2 HERCULES 173 10/17/2008 11/10/2008 24 

JU BM 2 HERCULES 173 11/28/2008 12/21/2008 23 

JU EI 120 HERCULES 200 1/29/2008 4/5/2008 67 

JU EI 120 HERCULES 200 4/6/2008 5/19/2008 43 

JU WC 414 HERCULES 200 5/21/2008 6/13/2008 23 

JU WC 401 HERCULES 200 6/13/2008 7/2/2008 19 

JU WC 401 HERCULES 200 7/3/2008 7/29/2008 26 

JU WC 401 HERCULES 200 7/29/2008 8/8/2008 10 

JU BA 502 HERCULES 200 8/8/2008 9/17/2008 40 

JU BA 502 HERCULES 200 9/17/2008 10/9/2008 22 

JU BA 502 HERCULES 200 10/9/2008 10/25/2008 16 

JU BA 502 HERCULES 200 10/25/2008 10/29/2008 4 

JU BA 502 HERCULES 200 10/29/2008 11/9/2008 11 

JU MU 845 HERCULES 200 11/9/2008 12/3/2008 24 

JU SS 104 HERCULES 201 1/17/2008 5/9/2008 113 

JU SS 233 HERCULES 201 5/9/2008 5/10/2008 1 

JU SS 233 HERCULES 201 5/14/2008 10/2/2008 141 

JU ST 198 HERCULES 201 10/5/2008 10/6/2008 1 

JU EI 119 HERCULES 201 11/22/2008 12/31/2008 39 

JU HI 110 HERCULES 202 3/8/2008 7/8/2008 122 

JU EI 186 HERCULES 202 7/10/2008 11/13/2008 126 

JU ST 198 HERCULES 202 11/14/2008 12/31/2008 47 

JU PL 23 HERCULES 203 3/13/2008 4/3/2008 21 

JU PL 23 HERCULES 203 4/3/2008 5/10/2008 37 

JU PL 23 HERCULES 203 5/10/2008 6/8/2008 29 

JU WD 64 HERCULES 203 6/8/2008 7/4/2008 26 

JU WD 64 HERCULES 203 7/5/2008 7/16/2008 11 

JU ST 21 HERCULES 203 7/16/2008 8/1/2008 16 

JU ST 21 HERCULES 203 8/1/2008 9/21/2008 51 

JU ST 21 HERCULES 203 9/21/2008 12/19/2008 89 

JU ST 21 HERCULES 203 12/19/2008 12/31/2008 12 

JU GI 47 HERCULES 204 2/11/2008 4/9/2008 58 
6-17 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU GI 47 HERCULES 204 4/29/2008 6/26/2008 58 

JU GI 47 HERCULES 204 6/26/2008 7/21/2008 25 

JU MP 107 HERCULES 204 8/23/2008 11/22/2008 91 

JU MP 107 HERCULES 204 11/22/2008 12/31/2008 39 

JU BA A 70 HERCULES 207 5/26/2008 9/5/2008 102 

JU PN 969 HERCULES 207 9/6/2008 12/2/2008 87 

JU PS 1111 HERCULES 207 12/30/2008 12/31/2008 1 

JU PN 969 HERCULES 207 12/3/2008 12/21/2008 18 

JU ST 21 HERCULES 211 1/1/2008 1/23/2008 22 

JU ST 72 HERCULES 211 2/14/2008 3/13/2008 28 

JU VR 171 HERCULES 211 5/9/2008 5/27/2008 18 

JU WC 479 HERCULES 211 8/23/2008 8/26/2008 3 

JU WC 479 HERCULES 211 8/26/2008 9/6/2008 11 

JU WC 479 HERCULES 211 9/6/2008 9/28/2008 22 

JU WC 479 HERCULES 211 9/28/2008 10/12/2008 14 

JU SM 27 HERCULES 211 10/11/2008 10/25/2008 14 

JU WC 366 HERCULES 250 3/20/2008 5/11/2008 52 

JU WC 366 HERCULES 250 5/11/2008 6/23/2008 43 

JU WC 366 HERCULES 250 6/23/2008 7/13/2008 20 

JU WC 366 HERCULES 250 7/13/2008 8/8/2008 26 

JU GA A 57 HERCULES 250 8/8/2008 9/28/2008 51 

JU VR 229 HERCULES 250 10/25/2008 12/31/2008 67 

JU WC 289 HERCULES 251 3/12/2008 5/27/2008 76 

JU SS 90 HERCULES 251 5/27/2008 8/12/2008 77 

JU EI 98 HERCULES 251 8/13/2008 12/31/2008 140 

JU ST 187 HERCULES 252 2/8/2008 3/12/2008 33 

JU MP 107 HERCULES 252 3/13/2008 6/20/2008 99 

JU MP 107 HERCULES 252 6/20/2008 7/5/2008 15 

JU MP 107 HERCULES 252 7/6/2008 7/31/2008 25 

JU MP 107 HERCULES 252 7/6/2008 12/29/2008 176 

JU WC 157 HERCULES 253 1/30/2008 3/29/2008 59 

JU HI 47 HERCULES 253 3/30/2008 6/3/2008 65 

JU WC 202 HERCULES 253 6/10/2008 10/20/2008 132 

JU WC 116 HERCULES 253 10/20/2008 12/31/2008 72 

JU HI 131 HERCULES 257 1/1/2008 2/1/2008 31 

JU WC 379 HERCULES 257 2/27/2008 3/27/2008 29 

JU EI 123 HERCULES 257 3/29/2008 5/19/2008 51 

JU MP 126 HERCULES 257 5/19/2008 8/17/2008 90 

JU WD 77 HERCULES 257 10/11/2008 11/4/2008 24 

JU WC 540 HERCULES 350 6/9/2008 9/26/2008 109 
6-18 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU WC 498 HERCULES 350 9/26/2008 12/5/2008 70 

JU EI 315 HERCULES 350 11/27/2008 12/31/2008 34 

SU WC 110 HERCULES 77 2/27/2008 5/31/2008 94 

SU EC 14 HERCULES 77 5/31/2008 8/17/2008 78 

JU SS 97 HERCULES 85 1/1/2008 2/10/2008 40 

JU SS 86 HERCULES 85 6/12/2008 7/8/2008 26 

PF GC 645 HOLSTEIN SPAR RIG 1/1/2008 1/2/2008 1 

PF GC 645 HOLSTEIN SPAR RIG 1/2/2008 3/25/2008 83 

PF GC 645 HOLSTEIN SPAR RIG 3/25/2008 4/4/2008 10 

PF GC 645 HOLSTEIN SPAR RIG 4/4/2008 4/10/2008 6 

PF GC 645 HOLSTEIN SPAR RIG 4/4/2008 4/11/2008 7 

PF GC 645 HOLSTEIN SPAR RIG 4/11/2008 6/14/2008 64 

PF GC 645 HOLSTEIN SPAR RIG 6/14/2008 8/14/2008 61 

PF GC 645 HOLSTEIN SPAR RIG 8/17/2008 12/21/2008 126 

PF GC 645 HOLSTEIN SPAR RIG 12/21/2008 12/31/2008 10 

PF HI A 589 NABORS 17 1/1/2008 4/7/2008 97 

PF HI A 589 NABORS 17 4/7/2008 6/29/2008 83 

PF HI A 589 NABORS 17 6/29/2008 7/17/2008 18 

PF GC 205 NABORS 85 (MAYRONNE 162) 1/1/2008 6/12/2008 163 

PF GC 205 NABORS 85 (MAYRONNE 162) 6/12/2008 9/25/2008 105 

PF GC 205 NABORS 85 (MAYRONNE 162) 10/15/2008 10/15/2008 0 

PF VK 786 NABORS 87 1/1/2008 3/5/2008 64 

PF VK 786 NABORS 87 3/5/2008 3/13/2008 8 

PF VK 786 NABORS 87 3/13/2008 3/25/2008 12 

PF VK 786 NABORS 87 3/25/2008 3/31/2008 6 

PF VK 786 NABORS 87 3/31/2008 4/15/2008 15 

PF VK 786 NABORS 87 5/15/2008 12/31/2008 230 

PF VK 786 NABORS 87 5/19/2008 8/11/2008 84 

PF VK 786 NABORS 87 8/11/2008 11/1/2008 82 

PF VK 786 NABORS 87 11/1/2008 12/31/2008 60 

JU ST 37 NABORS DOLPHIN 106 1/1/2008 1/17/2008 16 

JU ST 52 NABORS DOLPHIN 106 1/18/2008 2/10/2008 23 

JU ST 37 NABORS DOLPHIN 106 2/10/2008 3/14/2008 33 

JU ST 37 NABORS DOLPHIN 106 3/14/2008 4/16/2008 33 

JU ST 37 NABORS DOLPHIN 106 4/16/2008 4/17/2008 1 

JU ST 37 NABORS DOLPHIN 106 4/17/2008 6/12/2008 56 

JU MP 30 NABORS DOLPHIN 106 6/12/2008 8/12/2008 61 

JU SS 100 NABORS DOLPHIN 106 8/14/2008 10/3/2008 50 

JU SS 150 NABORS DOLPHIN 106 10/2/2008 10/11/2008 9 

JU SS 150 NABORS DOLPHIN 106 10/11/2008 10/31/2008 20 
6-19 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU SS 62 NABORS DOLPHIN 106 10/31/2008 11/4/2008 4 

JU SS 62 NABORS DOLPHIN 106 11/4/2008 11/17/2008 13 

JU EC 62 NABORS DOLPHIN 109 12/30/2008 12/31/2008 1 

PF GC 338 NABORS MODS 200 1/1/2008 4/29/2008 119 

PF GC 338 NABORS MODS 200 4/29/2008 8/3/2008 96 

PF GC 338 NABORS MODS 200 8/3/2008 8/22/2008 19 

PF GC 338 NABORS MODS 200 8/22/2008 9/26/2008 35 

PF GC 338 NABORS MODS 200 9/26/2008 12/22/2008 87 

PF GC 338 NABORS MODS 200 12/22/2008 12/31/2008 9 

PF GB 783 NABORS MODS 201 3/1/2008 6/5/2008 96 

PF GB 783 NABORS MODS 201 6/5/2008 8/13/2008 69 

PF GB 783 NABORS MODS 201 8/13/2008 12/16/2008 125 

PF GB 783 NABORS MODS 201 12/16/2008 12/31/2008 15 

PF EB 602 NABORS MODS RIG 150 2/16/2008 6/14/2008 119 

PF EB 602 NABORS MODS RIG 150 6/19/2008 7/12/2008 23 

PF EB 602 NABORS MODS RIG 150 12/30/2008 12/31/2008 1 

PF VK 915 NABORS P-10 4/19/2008 6/2/2008 44 

PF WD 93 NABORS P-10 7/3/2008 10/23/2008 112 

PF WD 93 NABORS P-10 10/23/2008 12/12/2008 50 

PF WD 93 NABORS P-10 12/12/2008 12/31/2008 19 

PF EW 910 NABORS P-16 6/26/2008 12/31/2008 188 

PF MC 773 NABORS POOL 140 1/1/2008 1/30/2008 29 

PF EI 327 NABORS POOL 140 4/8/2008 6/25/2008 78 

PF EI 327 NABORS POOL 140 6/25/2008 7/29/2008 34 

PF EI 327 NABORS POOL 140 7/29/2008 10/30/2008 93 

PF EI 327 NABORS POOL 140 10/30/2008 12/31/2008 62 

PF SP 57 NABORS POOL 143 1/1/2008 1/2/2008 1 

PF VK 900 NABORS POOL 143 4/25/2008 6/18/2008 54 

PF VK 900 NABORS POOL 143 6/18/2008 7/24/2008 36 

PF VK 900 NABORS POOL 143 7/24/2008 8/25/2008 32 

PF VK 900 NABORS POOL 143 8/25/2008 10/1/2008 37 

PF VK 900 NABORS POOL 143 10/3/2008 11/26/2008 54 

PF VK 900 NABORS POOL 143 11/26/2008 12/31/2008 35 

JU WC 153 NABORS POOL 54 4/30/2008 5/20/2008 20 

JU WC 291 NABORS POOL 54 7/18/2008 7/30/2008 12 

PF EI 333 NABORS S.D. IV 1/1/2008 3/3/2008 62 

PF EI 315 NABORS S.D. IV 3/4/2008 4/9/2008 36 

PF SP 70 NABORS S.D. IV 10/27/2008 12/5/2008 39 

PF SP 70 NABORS S.D. IV 12/5/2008 12/7/2008 2 
6-20 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

PF SP 70 NABORS S.D. IV 12/8/2008 12/31/2008 23 

PF EC 334 NABORS S.D. V 8/16/2008 10/8/2008 53 

PF EC 334 NABORS S.D. V 10/8/2008 10/17/2008 9 

PF EC 334 NABORS S.D. V 10/17/2008 11/13/2008 27 

PF ST 301 NABORS S.D. XVI 1/1/2008 1/10/2008 9 

PF ST 301 NABORS S.D. XVI 1/10/2008 1/17/2008 7 

PF ST 301 NABORS S.D. XVI 1/17/2008 2/18/2008 32 

PF ST 301 NABORS S.D. XVI 2/18/2008 3/22/2008 33 

PF ST 301 NABORS S.D. XVI 3/22/2008 4/28/2008 37 

PF ST 301 NABORS S.D. XVI 4/28/2008 5/26/2008 28 

PF ST 301 NABORS S.D. XVI 5/26/2008 6/24/2008 29 

PF ST 301 NABORS S.D. XVI 6/24/2008 8/13/2008 50 

PF WD 89 NABORS S.D. XVI 10/1/2008 11/25/2008 55 

PF WD 89 NABORS S.D. XVI 11/26/2008 12/19/2008 23 

PF WD 89 NABORS S.D. XVI 12/19/2008 12/19/2008 0 

PF WD 89 NABORS S.D. XVI 12/19/2008 12/31/2008 12 

PF MC 243 NABORS SUPER S.D. XIX 1/1/2008 6/20/2008 171 

PF MC 243 NABORS SUPER S.D. XIX 12/3/2008 12/31/2008 28 

PF SS 300 

NABORS SUPER SUNDOWNER 

XXI 1/1/2008 3/24/2008 83 

PF WD 80 

NABORS SUPER SUNDOWNER 

XXI 5/28/2008 8/10/2008 74 

PF WD 80 

NABORS SUPER SUNDOWNER 

XXI 8/10/2008 8/21/2008 11 

PF WD 80 

NABORS SUPER SUNDOWNER 

XXI 10/2/2008 12/1/2008 60 

PF WD 80 

NABORS SUPER SUNDOWNER 

XXI 12/1/2008 12/9/2008 8 

PF WD 80 

NABORS SUPER SUNDOWNER 

XXI 12/9/2008 12/31/2008 22 

PF GC 608 

NABORS SUPER SUNDOWNER 

XXII 1/24/2008 4/7/2008 74 

PF GC 608 

NABORS SUPER SUNDOWNER 

XXII 4/7/2008 4/20/2008 13 

PF GC 608 

NABORS SUPER SUNDOWNER 

XXII 4/22/2008 6/9/2008 48 

PF SA 13 

NABORS SUPER SUNDOWNER 

XXII 9/21/2008 10/19/2008 28 

PF SA 13 

NABORS SUPER SUNDOWNER 

XXII 10/19/2008 11/26/2008 38 

PF SA 13 

NABORS SUPER SUNDOWNER 

XXII 11/26/2008 12/31/2008 35 

SS WR 30 NOBLE AMOS RUNNER 1/1/2008 1/13/2008 12 
6-21 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

SS MC 561 NOBLE AMOS RUNNER 4/28/2008 7/10/2008 73 

SS GC 955 NOBLE AMOS RUNNER 7/10/2008 11/4/2008 117 

SS GC 859 NOBLE AMOS RUNNER 11/4/2008 12/31/2008 57 

SS AC 857 NOBLE CLYDE BOUDREAUX 1/1/2008 1/18/2008 17 

SS AC 857 NOBLE CLYDE BOUDREAUX 1/18/2008 5/16/2008 119 

SS AC 815 NOBLE CLYDE BOUDREAUX 5/16/2008 9/20/2008 127 

SS AC 815 NOBLE CLYDE BOUDREAUX 9/20/2008 11/8/2008 49 

SS AC 815 NOBLE CLYDE BOUDREAUX 11/8/2008 12/31/2008 53 

SS GB 778 NOBLE JIM THOMPSON 1/1/2008 2/24/2008 54 

SS MC 809 NOBLE JIM THOMPSON 2/28/2008 5/20/2008 82 

SS MC 809 NOBLE JIM THOMPSON 5/20/2008 7/19/2008 60 

SS MC 765 NOBLE JIM THOMPSON 7/22/2008 12/28/2008 159 

SS MC 809 NOBLE JIM THOMPSON 12/29/2008 12/31/2008 2 

SU HI 37 NOBLE JOE ALFORD 4/19/2008 8/19/2008 122 

SU ST 49 NOBLE JOE ALFORD 8/22/2008 9/10/2008 19 

SU ST 49 NOBLE JOE ALFORD 9/15/2008 12/31/2008 107 

SU SS 189 NOBLE LESTER PETTUS 1/1/2008 3/23/2008 82 

SU HI 138 NOBLE LESTER PETTUS 3/23/2008 8/7/2008 137 

SU HI 170 NOBLE LESTER PETTUS 8/7/2008 12/12/2008 127 

SU GA 317 NOBLE LESTER PETTUS 12/12/2008 12/31/2008 19 

SS GC 82 NOBLE LORRIS BOUZIGARD 1/1/2008 1/12/2008 11 

SS EW 989 NOBLE LORRIS BOUZIGARD 1/12/2008 2/20/2008 39 

SS VK 821 NOBLE LORRIS BOUZIGARD 2/25/2008 6/23/2008 119 

SS GB 378 NOBLE LORRIS BOUZIGARD 6/28/2008 7/9/2008 11 

SS GB 378 NOBLE LORRIS BOUZIGARD 7/9/2008 8/13/2008 35 

SS GB 378 NOBLE LORRIS BOUZIGARD 8/17/2008 11/18/2008 93 

SS GC 157 NOBLE LORRIS BOUZIGARD 11/19/2008 12/31/2008 42 

SS GC 452 NOBLE MAX SMITH 1/1/2008 1/5/2008 4 

SS GB 344 NOBLE MAX SMITH 1/7/2008 1/29/2008 22 

SS MC 754 NOBLE MAX SMITH 2/1/2008 2/15/2008 14 

SS MC 754 NOBLE MAX SMITH 2/15/2008 5/4/2008 79 

SS GC 953 NOBLE PAUL ROMANO 1/1/2008 1/8/2008 7 

SS GC 654 NOBLE PAUL ROMANO 1/8/2008 4/15/2008 98 

SS GC 518 NOBLE PAUL ROMANO 4/17/2008 5/26/2008 39 

SS WR 52 NOBLE PAUL ROMANO 5/26/2008 12/31/2008 219 

SS WR 848 OCEAN EIRIK RAUDE 1/1/2008 2/15/2008 45 

SS WR 584 OCEAN EIRIK RAUDE 2/15/2008 6/25/2008 131 

SS KC 964 OCEAN EIRIK RAUDE 6/26/2008 10/8/2008 104 

BR SM 212 PARKER 76-B 1/1/2008 6/28/2008 179 
6-22 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

BR SM 212 PARKER 76-B 6/28/2008 12/31/2008 186 

PF GI 116 PRIDE 1006 1/1/2008 4/11/2008 101 

PF GI 116 PRIDE 1006 4/11/2008 6/22/2008 72 

PF GI 116 PRIDE 1006 6/22/2008 6/25/2008 3 

PF GI 116 PRIDE 1006 6/25/2008 8/9/2008 45 

PF VR 380 PRIDE 1501E 1/1/2008 2/24/2008 54 

PF VR 380 PRIDE 1501E 2/24/2008 4/4/2008 40 

PF VR 380 PRIDE 1501E 4/4/2008 5/11/2008 37 

PF VR 380 PRIDE 1501E 5/11/2008 5/25/2008 14 

PF VR 380 PRIDE 1501E 5/25/2008 7/26/2008 62 

PF EI 342 PRIDE 1502E 1/1/2008 2/27/2008 57 

PF EI 342 PRIDE 1502E 2/27/2008 3/21/2008 23 

PF EI 342 PRIDE 1502E 3/21/2008 4/26/2008 36 

PF EI 342 PRIDE 1502E 4/26/2008 7/2/2008 67 

PF GI 41 PRIDE 210 1/12/2008 2/17/2008 36 

PF GI 41 PRIDE 210 2/17/2008 3/1/2008 13 

PF GI 48 PRIDE 210 3/4/2008 4/25/2008 52 

PF GI 48 PRIDE 210 4/25/2008 5/21/2008 26 

PF GI 48 PRIDE 210 5/21/2008 6/2/2008 12 

PF GI 48 PRIDE 210 6/2/2008 7/5/2008 33 

PF GI 47 PRIDE 210 7/5/2008 8/15/2008 41 

PF GI 47 PRIDE 210 8/15/2008 11/3/2008 80 

PF WD 71 PRIDE 210 11/7/2008 12/31/2008 54 

JU WD 117 PRIDE ALASKA 1/1/2008 1/5/2008 4 

JU WD 117 PRIDE ALASKA 1/5/2008 1/16/2008 11 

JU WD 117 PRIDE ALASKA 1/16/2008 2/22/2008 37 

JU MP 297 PRIDE ALASKA 2/23/2008 3/24/2008 30 

JU MP 141 PRIDE ALASKA 3/25/2008 4/9/2008 15 

JU MP 242 PRIDE ALASKA 4/16/2008 7/26/2008 101 

JU VK 519 PRIDE ALASKA 7/27/2008 9/29/2008 64 

JU VR 225 PRIDE ALASKA 10/1/2008 12/29/2008 89 

JU VR 23 PRIDE ALASKA 12/29/2008 12/31/2008 2 

JU SM 108 PRIDE ARIZONA 1/1/2008 1/9/2008 8 

JU EI 100 PRIDE ARIZONA 1/10/2008 1/16/2008 6 

JU EI 100 PRIDE ARIZONA 1/20/2008 2/20/2008 31 

JU EI 100 PRIDE ARIZONA 2/21/2008 4/3/2008 42 

JU EI 100 PRIDE ARIZONA 4/3/2008 5/7/2008 34 

JU EI 100 PRIDE ARIZONA 5/7/2008 5/25/2008 18 

JU VR 72 PRIDE ARIZONA 5/25/2008 6/15/2008 21 

JU VR 72 PRIDE ARIZONA 6/15/2008 8/9/2008 55 
6-23 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU GI 83 PRIDE ARIZONA 8/15/2008 9/28/2008 44 

JU GI 83 PRIDE ARIZONA 9/28/2008 10/30/2008 32 

JU GI 83 PRIDE ARIZONA 10/31/2008 12/31/2008 61 

JU SM 251 PRIDE FLORIDA 4/2/2008 5/20/2008 48 

JU SS 63 PRIDE FLORIDA 5/20/2008 5/20/2008 0 

JU SS 63 PRIDE FLORIDA 5/20/2008 7/19/2008 60 

JU SS 63 PRIDE FLORIDA 7/21/2008 8/3/2008 13 

JU SS 63 PRIDE FLORIDA 8/3/2008 12/5/2008 124 

JU MP 61 PRIDE FLORIDA 12/31/2008 12/31/2008 0 

JU MI 656 PRIDE GEORGIA 1/8/2008 1/26/2008 18 

JU MI 657 PRIDE GEORGIA 1/26/2008 3/6/2008 40 

JU MI 657 PRIDE GEORGIA 3/6/2008 4/13/2008 38 

JU MI 632 PRIDE GEORGIA 4/13/2008 6/2/2008 50 

JU WC 548 PRIDE GEORGIA 6/16/2008 7/10/2008 24 

JU WC 548 PRIDE GEORGIA 7/10/2008 8/8/2008 29 

JU WC 548 PRIDE GEORGIA 8/8/2008 9/17/2008 40 

JU WC 44 PRIDE GEORGIA 9/18/2008 11/1/2008 44 

JU HI A 242 PRIDE GEORGIA 11/2/2008 11/26/2008 24 

JU EI 46 PRIDE GEORGIA 11/27/2008 12/31/2008 34 

JU HI 140 PRIDE KANSAS 1/1/2008 1/3/2008 2 

JU HI 140 PRIDE KANSAS 1/3/2008 2/8/2008 36 

JU SM 41 PRIDE KANSAS 2/12/2008 5/10/2008 88 

JU SS 189 PRIDE KANSAS 5/10/2008 11/13/2008 187 

JU ST 219 PRIDE KANSAS 11/13/2008 12/28/2008 45 

PF GC 782 PRIDE MAD DOG SPAR RIG 1/1/2008 1/27/2008 26 

PF GC 782 PRIDE MAD DOG SPAR RIG 1/27/2008 2/8/2008 12 

PF GC 782 PRIDE MAD DOG SPAR RIG 2/9/2008 4/10/2008 61 

PF GC 782 PRIDE MAD DOG SPAR RIG 4/10/2008 4/16/2008 6 

PF GC 782 PRIDE MAD DOG SPAR RIG 4/16/2008 4/18/2008 2 

PF GC 782 PRIDE MAD DOG SPAR RIG 4/18/2008 8/12/2008 116 

PF GC 782 PRIDE MAD DOG SPAR RIG 8/16/2008 9/24/2008 39 

JU WC 552 PRIDE MICHIGAN 1/1/2008 3/12/2008 71 

JU WC 548 PRIDE MICHIGAN 3/12/2008 4/5/2008 24 

JU HI A 264 PRIDE MICHIGAN 7/6/2008 7/27/2008 21 

JU HI A 247 PRIDE MICHIGAN 7/27/2008 8/20/2008 24 

JU HI A 264 PRIDE MICHIGAN 8/20/2008 8/25/2008 5 

JU GA 283 PRIDE MICHIGAN 8/27/2008 11/4/2008 69 

JU WC 212 PRIDE MICHIGAN 11/4/2008 12/16/2008 42 

JU EC 266 PRIDE MICHIGAN 12/17/2008 12/31/2008 14 

JU SM 76 PRIDE MISSOURI 1/13/2008 4/6/2008 84 
6-24 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU SM 76 PRIDE MISSOURI 4/6/2008 6/7/2008 62 

JU SM 76 PRIDE MISSOURI 6/7/2008 6/21/2008 14 

JU GI 85 PRIDE MISSOURI 6/22/2008 7/22/2008 30 

JU SS 202 PRIDE MISSOURI 7/22/2008 8/14/2008 23 

JU HI A 309 PRIDE MISSOURI 8/16/2008 10/17/2008 62 

JU HI A 309 PRIDE MISSOURI 10/17/2008 12/8/2008 52 

JU HI A 309 PRIDE MISSOURI 12/8/2008 12/31/2008 23 

JU SM 79 PRIDE NEVADA 11/20/2008 12/12/2008 22 

JU ST 197 PRIDE NEVADA 5/6/2008 5/31/2008 25 

JU ST 196 PRIDE NEVADA 5/31/2008 7/3/2008 33 

JU WC 229 PRIDE NEVADA 7/6/2008 8/3/2008 28 

JU SM 79 PRIDE NEVADA 8/6/2008 8/26/2008 20 

JU SM 79 PRIDE NEVADA 8/26/2008 10/14/2008 49 

JU SM 79 PRIDE NEVADA 10/14/2008 11/20/2008 37 

JU WD 28 PRIDE NEW MEXICO 1/1/2008 1/13/2008 12 

JU WD 28 PRIDE NEW MEXICO 1/13/2008 3/30/2008 77 

JU WD 27 PRIDE NEW MEXICO 3/30/2008 4/21/2008 22 

JU MP 108 PRIDE NEW MEXICO 4/20/2008 7/5/2008 76 

JU MP 108 PRIDE NEW MEXICO 7/5/2008 11/10/2008 128 

JU MP 108 PRIDE NEW MEXICO 11/10/2008 12/31/2008 51 

JU SS 235 PRIDE WYOMING 1/10/2008 1/14/2008 4 

JU SS 235 PRIDE WYOMING 1/14/2008 2/4/2008 21 

JU SS 235 PRIDE WYOMING 2/4/2008 2/14/2008 10 

JU SS 105 PRIDE WYOMING 2/16/2008 3/10/2008 23 

JU SS 125 PRIDE WYOMING 3/10/2008 4/5/2008 26 

JU SS 283 PRIDE WYOMING 4/5/2008 4/11/2008 6 

JU SS 283 PRIDE WYOMING 4/11/2008 4/21/2008 10 

JU GI 48 PRIDE WYOMING 4/20/2008 8/21/2008 123 

JU SS 283 PRIDE WYOMING 8/22/2008 9/24/2008 33 

JU MO 826 ROWAN ALASKA 1/1/2008 1/13/2008 12 

JU EW 305 ROWAN ALASKA 1/23/2008 2/24/2008 32 

JU EW 305 ROWAN ALASKA 2/24/2008 4/18/2008 54 

JU EW 305 ROWAN ALASKA 4/18/2008 5/23/2008 35 

JU EW 305 ROWAN ALASKA 5/23/2008 6/7/2008 15 

JU EW 305 ROWAN ALASKA 6/7/2008 7/27/2008 50 

JU EW 305 ROWAN ALASKA 7/27/2008 8/16/2008 20 

JU EW 305 ROWAN ALASKA 8/16/2008 11/22/2008 98 

JU EW 305 ROWAN ALASKA 11/22/2008 11/27/2008 5 

JU EW 305 ROWAN ALASKA 11/27/2008 12/31/2008 34 

JU EC 282 ROWAN ANCHORAGE 1/1/2008 3/1/2008 60 
6-25 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU GI 54 ROWAN ANCHORAGE 3/6/2008 5/31/2008 86 

JU HI 163 ROWAN ANCHORAGE 6/1/2008 8/9/2008 69 

JU VR 201 ROWAN ANCHORAGE 8/10/2008 9/13/2008 34 

JU SX 18 ROWAN BOB KELLER 1/1/2008 1/11/2008 10 

JU PN A 94 

ROWAN BOB PALMER 

(GORILLA RIG) 1/1/2008 1/26/2008 25 

JU HI A 119 

ROWAN BOB PALMER 

(GORILLA RIG) 3/22/2008 12/31/2008 284 

JU HI 130 ROWAN CECIL PROVINE 1/1/2008 2/11/2008 41 

JU EC 278 ROWAN CECIL PROVINE 2/11/2008 3/5/2008 23 

JU EC 278 ROWAN CECIL PROVINE 3/5/2008 4/12/2008 38 

JU EC 278 ROWAN CECIL PROVINE 4/12/2008 6/4/2008 53 

JU EC 278 ROWAN CECIL PROVINE 6/4/2008 6/15/2008 11 

JU EC 264 ROWAN CECIL PROVINE 6/15/2008 7/13/2008 28 

JU EC 264 ROWAN CECIL PROVINE 7/13/2008 8/17/2008 35 

JU GI 93 ROWAN CECIL PROVINE 8/19/2008 11/8/2008 81 

JU GI 93 ROWAN CECIL PROVINE 11/8/2008 12/30/2008 52 

JU WD 68 ROWAN CECIL PROVINE 12/31/2008 12/31/2008 0 

JU EI 333 ROWAN GORILLA II 1/1/2008 3/29/2008 88 

JU EI 383 ROWAN GORILLA II 4/22/2008 6/25/2008 64 

JU EI 383 ROWAN GORILLA II 6/25/2008 8/18/2008 54 

JU HI A 368 ROWAN GORILLA II 8/19/2008 10/26/2008 68 

JU HI A 351 ROWAN GORILLA II 10/27/2008 12/31/2008 65 

JU HI A 545 ROWAN GORILLA III 6/12/2008 7/8/2008 26 

JU HI A 557 ROWAN GORILLA III 7/8/2008 9/28/2008 82 

JU EC 346 ROWAN GORILLA III 9/28/2008 11/20/2008 53 

JU WC 575 ROWAN GORILLA III 11/20/2008 12/31/2008 41 

JU ST 168 ROWAN GORILLA IV 2/17/2008 11/22/2008 279 

JU SS 349 ROWAN GORILLA IV 11/22/2008 12/31/2008 39 

JU SM 149 ROWAN JP BUSSELL 11/27/2008 12/26/2008 29 

JU SM 149 ROWAN JP BUSSELL 12/29/2008 12/31/2008 2 

JU WC 149 ROWAN JUNEAU 1/1/2008 1/9/2008 8 

JU MP 233 ROWAN JUNEAU 1/11/2008 4/24/2008 104 

JU SS 216 ROWAN JUNEAU 4/24/2008 8/19/2008 117 

JU SS 216 ROWAN JUNEAU 8/19/2008 12/21/2008 124 

JU SM 260 ROWAN JUNEAU 12/30/2008 12/31/2008 1 

JU HI A 545 ROWAN LOUISIANA 1/1/2008 1/11/2008 10 

JU SS 224 ROWAN LOUISIANA 1/11/2008 5/19/2008 129 

JU SS 224 ROWAN LOUISIANA 5/19/2008 7/25/2008 67 

JU SS 224 ROWAN LOUISIANA 7/25/2008 11/9/2008 107 
6-26 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

JU WC 606 ROWAN LOUISIANA 11/9/2008 12/26/2008 47 

JU SS 290 ROWAN LOUISIANA 12/31/2008 12/31/2008 0 

JU SM 251 ROWAN MISSISSIPPI 11/14/2008 12/31/2008 47 

SS MC 941 SEADRILL WEST SIRIUS 8/3/2008 8/18/2008 15 

SS MC 941 SEADRILL WEST SIRIUS 8/18/2008 8/22/2008 4 

SS MC 941 SEADRILL WEST SIRIUS 8/22/2008 9/8/2008 17 

SS MC 941 SEADRILL WEST SIRIUS 9/8/2008 9/20/2008 12 

SS MC 941 SEADRILL WEST SIRIUS 9/21/2008 10/25/2008 34 

SS MC 941 SEADRILL WEST SIRIUS 10/25/2008 10/25/2008 0 

SS MC 941 SEADRILL WEST SIRIUS 10/25/2008 10/26/2008 1 

SS WR 249 SEADRILL WEST SIRIUS 10/27/2008 11/3/2008 7 

SS WR 206 SEADRILL WEST SIRIUS 11/3/2008 11/13/2008 10 

SS KC 291 SEADRILL WEST SIRIUS 11/15/2008 12/31/2008 46 

DS KC 872 STENA DRILLMAX 8/23/2008 12/31/2008 130 

PF HI A 557 SUNDOWNER I 1/1/2008 1/9/2008 8 

PF SM 130 SUNDOWNER I 1/11/2008 1/19/2008 8 

PF SM 130 SUNDOWNER I 1/19/2008 2/5/2008 17 

PF SS 349 SUNDOWNER I 3/1/2008 4/1/2008 31 

PF WD 73 SUNDOWNER I 8/11/2008 10/6/2008 56 

PF WD 73 SUNDOWNER I 10/6/2008 10/24/2008 18 

PF WD 73 SUNDOWNER I 11/13/2008 11/28/2008 15 

PF WD 73 SUNDOWNER I 11/28/2008 12/31/2008 33 

SS GB 506 T.O. AMIRANTE 1/1/2008 3/2/2008 61 

SS GC 385 T.O. AMIRANTE 6/28/2008 8/15/2008 48 

SS MC 502 T.O. AMIRANTE 8/16/2008 9/8/2008 23 

SS MC 546 T.O. AMIRANTE 9/26/2008 11/7/2008 42 

SS MC 502 T.O. AMIRANTE 11/7/2008 12/27/2008 50 

SS MC 502 T.O. AMIRANTE 12/27/2008 12/31/2008 4 

SS MC 696 T.O. CAJUN EXPRESS 1/1/2008 1/19/2008 18 

SS MC 696 T.O. CAJUN EXPRESS 1/19/2008 2/18/2008 30 

SS MC 696 T.O. CAJUN EXPRESS 2/23/2008 5/3/2008 70 

SS GC 640 T.O. CAJUN EXPRESS 5/10/2008 8/18/2008 100 

SS WR 581 T.O. CAJUN EXPRESS 8/18/2008 11/11/2008 85 

SS WR 29 T.O. CAJUN EXPRESS 11/11/2008 12/31/2008 50 

SS MC 727 T.O. DEEPWATER HORIZON 1/1/2008 3/28/2008 87 

SS MC 129 T.O. DEEPWATER HORIZON 3/29/2008 4/24/2008 26 

SS WR 724 T.O. DEEPWATER HORIZON 4/25/2008 5/5/2008 10 

SS GB 873 T.O. DEEPWATER HORIZON 5/6/2008 5/11/2008 5 

SS MC 948 T.O. DEEPWATER HORIZON 5/16/2008 5/23/2008 7 

SS MC 948 T.O. DEEPWATER HORIZON 5/23/2008 8/30/2008 99 
6-27 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

SS MC 948 T.O. DEEPWATER HORIZON 9/3/2008 9/8/2008 5 

SS MC 948 T.O. DEEPWATER HORIZON 9/16/2008 10/21/2008 35 

SS MC 727 T.O. DEEPWATER HORIZON 10/21/2008 12/24/2008 64 

SS GC 823 T.O. DEEPWATER HORIZON 12/24/2008 12/31/2008 7 

DS WR 155 T.O. DEEPWATER MILLENNIUM 1/1/2008 1/2/2008 1 

DS LL 399 T.O. DEEPWATER MILLENNIUM 1/4/2008 3/2/2008 58 

DS GB 877 T.O. DEEPWATER MILLENNIUM 3/4/2008 4/8/2008 35 

DS GB 877 T.O. DEEPWATER MILLENNIUM 4/8/2008 4/18/2008 10 

SS WR 464 T.O. DEEPWATER NAUTILUS 1/1/2008 4/7/2008 97 

SS MC 807 T.O. DEEPWATER NAUTILUS 4/10/2008 5/29/2008 49 

SS DC 486 T.O. DEEPWATER NAUTILUS 5/31/2008 9/23/2008 115 

SS WR 464 T.O. DEEPWATER NAUTILUS 9/23/2008 12/6/2008 74 

SS MC 810 T.O. DEEPWATER NAUTILUS 12/25/2008 12/31/2008 6 

DS WR 677 T.O. DISCOVERER DEEP SEAS 1/1/2008 2/28/2008 58 

DS WR 678 T.O. DISCOVERER DEEP SEAS 2/29/2008 5/4/2008 65 

DS WR 678 T.O. DISCOVERER DEEP SEAS 5/31/2008 11/19/2008 172 

DS WR 316 T.O. DISCOVERER DEEP SEAS 11/20/2008 12/31/2008 41 

DS MC 777 T.O. DISCOVERER ENTERPRISE 1/1/2008 2/26/2008 56 

DS MC 775 T.O. DISCOVERER ENTERPRISE 2/26/2008 5/3/2008 67 

DS MC 778 T.O. DISCOVERER ENTERPRISE 5/4/2008 6/26/2008 53 

DS MC 822 T.O. DISCOVERER ENTERPRISE 6/30/2008 8/30/2008 61 

DS MC 822 T.O. DISCOVERER ENTERPRISE 9/3/2008 9/7/2008 4 

DS MC 822 T.O. DISCOVERER ENTERPRISE 9/14/2008 10/30/2008 46 

DS MC 777 T.O. DISCOVERER ENTERPRISE 10/31/2008 11/8/2008 8 

DS MC 776 T.O. DISCOVERER ENTERPRISE 11/8/2008 11/12/2008 4 

DS MC 777 T.O. DISCOVERER ENTERPRISE 11/12/2008 11/24/2008 12 

DS MC 776 T.O. DISCOVERER ENTERPRISE 11/24/2008 12/27/2008 33 

DS MC 777 T.O. DISCOVERER ENTERPRISE 12/27/2008 12/31/2008 4 

DS WR 371 T.O. DISCOVERER SPIRIT 1/1/2008 3/30/2008 89 

DS KC 292 T.O. DISCOVERER SPIRIT 3/30/2008 6/27/2008 89 

DS GC 726 T.O. DISCOVERER SPIRIT 6/29/2008 11/13/2008 137 

DS LL 5 T.O. DISCOVERER SPIRIT 11/14/2008 12/31/2008 47 

SS GC 244 T.O. HENRY GOODRICH 1/1/2008 4/23/2008 113 

SS GB 515 T.O. HENRY GOODRICH 4/24/2008 7/16/2008 83 

SS MC 522 T.O. MARIANAS 1/1/2008 5/1/2008 121 

SS VK 915 T.O. MARIANAS 5/2/2008 6/12/2008 41 

SS VK 915 T.O. MARIANAS 6/16/2008 6/26/2008 10 

SS GC 516 T.O. MARIANAS 7/5/2008 9/19/2008 76 

SS MC 129 T.O. MARIANAS 11/2/2008 12/6/2008 34 

SS VK 915 T.O. MARIANAS 12/6/2008 12/23/2008 17 
6-28 

Table 6-2. Drilling Vessel Activity Data (continued). 

Rig 

Type 

Surface 

Area 

Code 

Surface 

Block 

Number Rig Name 

Rig Move on 

Date 

Rig Move 

off Date Days 

SS VK 915 T.O. MARIANAS 12/28/2008 12/31/2008 3 

BR HI 134 TETRA DB-1 7/31/2008 7/31/2008 0 

BR HI 134 TETRA DB-1 7/31/2008 7/31/2008 0 

BR HI 134 TETRA DB-1 8/1/2008 9/3/2008 33 

PF MP 311 TETRA RIG 7 1/1/2008 1/13/2008 12 

PF MP 311 TETRA RIG 7 1/13/2008 1/21/2008 8 

PF MP 296 TETRA RIG 7 1/21/2008 1/29/2008 8 

PF MP 296 TETRA RIG 7 1/29/2008 2/5/2008 7 

PF SP 62 TETRA RIG 7 2/6/2008 2/19/2008 13 

PF SP 62 TETRA RIG 7 2/19/2008 3/20/2008 30 

PF MP 289 TETRA RIG 7 3/21/2008 4/20/2008 30 

PF WD 105 TETRA RIG 7 4/21/2008 5/5/2008 14 

PF HI 179 TETRA RIG 7 5/7/2008 5/21/2008 14 

PF HI 179 TETRA RIG 7 5/21/2008 6/1/2008 11 

PF HI 179 TETRA RIG 7 6/1/2008 6/8/2008 7 

PF HI 179 TETRA RIG 7 6/8/2008 6/13/2008 5 

PF WD 122 TETRA RIG 7 6/14/2008 6/26/2008 12 

PF MI 681 TETRA RIG 7 6/26/2008 7/29/2008 33 

PF MI 681 TETRA RIG 7 7/29/2008 8/26/2008 28 

PF MU 787 TETRA RIG 7 8/27/2008 9/30/2008 34 

PF HI A 572 TETRA RIG 7 10/1/2008 12/18/2008 78 

PF HI A 572 TETRA RIG 7 12/18/2008 12/31/2008 13 

JU WC 230 THE 152 1/1/2008 1/2/2008 1 

JU EI 226 THE 200 1/1/2008 2/1/2008 31 

JU ST 27 THE 203 1/1/2008 2/6/2008 36 

JU GI 47 THE 204 1/1/2008 2/11/2008 41 

JU GA 312 THE 207 1/1/2008 1/17/2008 16 

JU GA 151 THE 251 1/1/2008 2/2/2008 32 

JU HI 73 THE 252 1/1/2008 2/1/2008 31 

SU SS 150 THE 78 8/1/2008 10/2/2008 62 

PF MC 778 THUNDER HORSE PDQ 1/1/2008 2/16/2008 46 

PF MC 778 THUNDER HORSE PDQ 2/16/2008 8/24/2008 190 

PF MC 778 THUNDER HORSE PDQ 8/25/2008 11/28/2008 95 

PF MC 778 THUNDER HORSE PDQ 11/28/2008 12/12/2008 14 

PF MC 778 THUNDER HORSE PDQ 12/13/2008 12/31/2008 18 
6-29 

The drilling rig names in the BOEM dataset were matched to vessel names in the 

RigZone database (RigZone Data Center 2009) 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 population of active drill ships and submersibles was 

too small to provide representative information; therefore average power ratings for these two rig 

types were obtained from the 2005 Gulfwide Emission Inventory Study (Wilson et al. 2007). 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 

Type 

Drill 

Ships a

JackUps Semisubmersibles Submersibles a

Prime 1,864 1,238 1,517 1,517 

Pumps 1,193 1,193 1,193 1,193 

Drawworks 2,237 1,491 2,237 2,237 

Emergency 

Generator 1,986 481 765 266 

Propulsion 46,152 b 13,694 b

a

 Historical analysis of rig information (Wilson et al. 2007). 

b

 Relocated with support vessels (see Section 6.1.5). 

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 6-2. In selecting the emission factors (SEPA 2004), 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 percent load, as noted in Table 6-1, to 

maintain position. 

Prior drilling rig emission estimates have been enhanced in two ways. First, relocation 

emissions for drill ships and semisubmersibles have been quantified. The kW rating of 

propulsion engines was applied to the hours that the rig spent between relocations. Some rigs 

leave the lease block where drilling activities occur and exit the Gulf of Mexico 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 percent load while the rig is relocating. 
6-30 

The second enhancement was to quantify emission estimates associated with emergency 

power. 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. 

Base year 2008 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: 

In 2008, all drill ships operated 39,408 hours. Average kW rating for draw works of drill 

ships is 2,237, load factor is 0.75, and the emission factor for NOx is 12.0 g/kWh. 

E = AH × kW × LF × EF × CF 

E = 39,408 × 2,237 × 0.75 × 12.0 × 1.10231 ×10-6

E = 875 tons of NOx

The variation in monthly drilling activities developed using the 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. 

Table 6-4 

Seasonal Drilling Activity 

Month Percent of Total 

Drilling Days 

January 10.3% 

February 6.87% 

March 7.99% 

April 7.83% 

May 8.66% 

June 8.45% 

July 8.75% 

August 8.59% 

September 7.96% 

October 8.13% 

November 8.08% 

December 8.33% 

The drilling operation emissions were spatially allocated to the lease blocks where 

drilling occurred. Figure 6-1 maps the location of all 2008 drilling rig operations. 
6-31 

Figure 6-1. Location of drilling operations and BOEM lease blocks for 2008. 

6.1.3 Pipelaying Operations 

Product from oil platforms is generally transported to shore via pipelines. New pipelines 

are constantly being laid linking new 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. Previously, vessel hours needed to lay a 

foot of pipe were estimated in the 2000 and 2005 inventories to be 0.40 hours. The updated 

operating hours factor was applied to BOEM data documenting the segments built or maintained 

in 2008. 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 2008 to December 2008 (USDOI, MMS 2008a and 2008b). These new 

pipeline segments were mapped to individual lease blocks in the Gulf of Mexico using 

Geographic Information System (GIS) tools (USDOI, MMS 2008c). 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: 
6-32 

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 2008 vessel hours associated with new pipelaying and pipeline repair are 

summarized in Table 6-5. 

Table 6-5 

Pipelaying Activity 

Activity 

Hours of 

Activity in 

2008 

New Pipelaying 896,227 

Repair 447,150 

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 Swedish 

emission factors (SEPA 2004) as noted in Table 6-1. 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: 

In 2008, total hours of new pipelaying activity were 896,227. Average vessel kW of 

pipelaying vessels is 894.84, load factor is 0.75, and the emission factor for NOx is 10.6 g/kWh. 
6-33 

E = AH × kW × LF × EF × CF 

E = 896,227 × 894.84 × 0.75 × 10.6 × 1.10231 × 10-6

E = 7,028 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 used to adjust the apportion the annual emission 

estimates to individual months. 

Pipeline construction and repair emissions were mapped to the lease blocks where the 

activity occurred using data provided by the BOEM and are provided in Figure 6-2 (USDOI, 

MMS 2008c). 

Figure 6-2. Pipeline locations and BOEM lease blocks. 
6-34 

Table 6-7 

New Pipelaying Activity Data 

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

17111 LA1 168 WC168 5372 1719

17112 LA1 168 WC168 5375 1720

17336 LA1 176 WC176 5474 1752

17337 LA1 176 WC176 5476 1752

17392 LA1 250 WC250 6131 1962

17392 LA1 251 WC251 178 57

17392 LA1 252 WC252 12010 3843

17465 LA1 225 WC225 5112 1636

17468 LA1 230 WC230 3530 1130

17480 LA1 149 WC149 9579 3065

17292 LA10 120 MP120 6438 2060

17292 LA10 121 MP121 1005 322

17292 LA10 122 MP122 17910 5731

17292 LA10 133 MP133 978 313

17645 LA10 108 MP108 6137 1964

17667 LA10 108 MP108 3928 1257

15918 LA10A 175 MP175 2530 810

15918 LA10A 176 MP176 14395 4606

15918 LA10A 177 MP177 14159 4531

15918 LA10A 178 MP178 14526 4648

15918 LA10A 179 MP179 3096 991

15918 LA10A 181 MP181 5327 1705

15918 LA10A 182 MP182 12626 4040

15919 LA10A 178 MP178 1493 478

17013 LA10A 299 MP299 5581 1786

17272 LA10A 299 MP299 5147 1647

16043 LA1A 414 WC414 10841 3469

17123 LA1A 401 WC401 8638 2764

17153 LA1A 401 WC401 9761 3123

17153 LA1A 402 WC402 1176 376

17153 LA1A 414 WC414 914 292

17275 LA1A 431 WC431 8204 2625

17275 LA1A 432 WC432 9623 3079

17503 LA1A 366 WC366 4333 1387

17503 LA1A 367 WC367 1717 549

17503 LA1A 368 WC368 7590 2429

17614 LA1A 157 WC157 3674 1176

17172 LA1B 479 WC479 12366 3957

17509 LA1B 548 WC548 3587 1148

17336 LA2 64 EC64 8576 2744

17337 LA2 64 EC64 8576 2744

17692 LA2 14 EC14 1623 519

17180 LA2A 325 EC325 6604 2113

17180 LA2A 326 EC326 7199 2304

15821 LA3 52 VR52 2447 783
6-35 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

15821 LA3 71 VR71 16902 5409

15821 LA3 72 VR72 11748 3759

16141 LA3 31 VR31 3314 1060

16142 LA3 31 VR31 3315 1061

17381 LA3 200 VR200 8877 2841

17381 LA3 201 VR201 4653 1489

16133 LA3A 66 SM66 13780 4410

17424 LA3A 66 SM66 3423 1095

15252 LA3B 329 VR329 1854 593

15252 LA3B 338 VR338 12406 3970

17162 LA3B 340 VR340 9848 3151

17162 LA3B 348 VR348 5627 1801

17162 LA3B 349 VR349 10032 3210

17180 LA3B 344 VR344 9841 3149

17649 LA3B 371 VR371 5810 1859

17649 LA3B 372 VR372 10064 3220

16133 LA3C 76 SM76 3926 1256

17176 LA3C 205 SM205 2156 690

17290 LA3C 189 SM189 90 29

17290 LA3C 190 SM190 2774 888

17290 LA3C 192 SM192 18246 5839

17391 LA3C 109 SM109 1392 446

17391 LA3C 110 SM110 12941 4141

17391 LA3C 111 SM111 2864 917

17432 LA3C 149 SM149 9918 3174

17433 LA3C 149 SM149 9918 3174

17506 LA3C 78 SM78 123 39

17506 LA3C 79 SM79 1874 600

17253 LA3D 212 SM212 4414 1412

17253 LA3D 217 SM217 8299 2656

17254 LA3D 212 SM212 4409 1411

17254 LA3D 217 SM217 8303 2657

17255 LA3D 212 SM212 4405 1410

17255 LA3D 217 SM217 8307 2658

17399 LA3D 256 SM256 5388 1724

17399 LA3D 257 SM257 14065 4501

17399 LA3D 265 SM265 13683 4378

17399 LA3D 266 SM266 8393 2686

17399 LA3D 268 SM268 4174 1336

17399 LA3D 269 SM269 10042 3213

17401 LA3D 212 SM212 4947 1583

17401 LA3D 217 SM217 8315 2661

17402 LA3D 212 SM212 4953 1585

17402 LA3D 217 SM217 8323 2663

17434 LA3D 212 SM212 5848 1871

17435 LA3D 212 SM212 5853 1873
6-36 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

17436 LA3D 212 SM212 5857 1874

17437 LA3D 212 SM212 4230 1354

17438 LA3D 212 SM212 4238 1356

17439 LA3D 212 SM212 4238 1356

17103 LA4 252 EI252 10256 3282

17103 LA4 260 EI260 8613 2756

17103 LA4 261 EI261 9064 2900

17104 LA4 252 EI252 10233 3274

17104 LA4 260 EI260 8527 2729

17104 LA4 261 EI261 9146 2927

17273 LA4 11 EI11 5611 1796

17273 LA4 22 EI22 11050 3536

17273 LA4 23 EI23 11666 3733

17273 LA4 29 EI29 9831 3146

17273 LA4 30 EI30 8216 2629

17273 LA4 42 EI42 6563 2100

17273 LA4 43 EI43 13954 4465

17273 LA4 53 EI53 12885 4123

17273 LA4 54 EI54 8737 2796

17273 LA4 63 EI63 8761 2804

17378 LA4 64 EI64 5962 1908

17378 LA4 65 EI65 782 250

17379 LA4 64 EI64 5964 1908

17379 LA4 65 EI65 782 250

17388 LA4 11 EI11 1488 476

17446 LA4 11 EI11 1012 324

17575 LA4 11 EI11 1062 340

17583 LA4 11 EI11 938 300

17599 LA4 120 EI120 61 20

17600 LA4 120 EI120 741 237

17652 LA4 100 EI100 8518 2726

17653 LA4 100 EI100 8521 2727

17039 LA4A 318 EI318 413 132

17103 LA4A 275 EI275 14497 4639

17103 LA4A 276 EI276 1847 591

17104 LA4A 275 EI275 14713 4708

17104 LA4A 276 EI276 2084 667

17105 LA4A 275 EI275 4390 1405

17105 LA4A 276 EI276 9189 2941

17106 LA4A 275 EI275 4427 1416

17106 LA4A 276 EI276 9194 2942

17181 LA4A 351 EI351 5193 1662

17181 LA4A 362 EI362 8057 2578

17181 LA4A 363 EI363 10169 3254

17181 LA4A 372 EI372 11466 3669

17348 LA4A 346 EI346 6445 2062
6-37 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

17593 LA4A 315 EI315 4876 1560

17593 LA4A 316 EI316 6809 2179

17613 LA4A 315 EI315 4884 1563

17613 LA4A 316 EI316 6815 2181

17185 LA5 235 SS235 3879 1241

17382 LA5 93 SS93 7811 2499

17382 LA5 114 SS114 555 178

17383 LA5 93 SS93 7805 2498

17383 LA5 114 SS114 552 176

17504 LA5 111 SS111 8368 2678

17504 LA5 120 SS120 7976 2552

17643 LA5 63 SS63 1277 409

17644 LA5 63 SS63 1277 409

17696 LA5 90 SS90 61 20

17697 LA5 90 SS90 61 20

17698 LA5 90 SS90 61 20

15876 LA5A 332 SS332 3808 1219

15876 LA5A 355 SS355 15886 5084

17185 LA5A 236 SS236 13967 4469

17185 LA5A 259 SS259 8061 2579

15426 LA6 26 ST26 5251 1680

15680 LA6 24 ST24 1638 524

17256 LA6 187 ST187 7495 2398

17414 LA6 68 ST68 12650 4048

17414 LA6 81 ST81 1244 398

15876 LA6A 316 ST316 13813 4420

15876 LA6A 317 ST317 917 293

17502 LA6B 21 PL21 3861 1235

17502 LA6B 22 PL22 2819 902

15680 LA6C 2 BM2 8230 2634

15680 LA7 26 GI26 1286 411

15680 LA7 37 GI37 379 121

17179 LA7 43 GI43 1008 323

17190 LA7 41 GI41 8707 2786

17191 LA7 41 GI41 8708 2787

17198 LA7 41 GI41 7621 2439

17351 LA7 31 GI31 2176 696

17351 LA7 32 GI32 12437 3980

17351 LA7 33 GI33 7523 2407

17352 LA7 31 GI31 2176 696

17352 LA7 32 GI32 12437 3980

17352 LA7 33 GI33 7523 2407

17353 LA7 31 GI31 2176 696

17353 LA7 32 GI32 12437 3980

17353 LA7 33 GI33 7523 2407

17422 LA7 83 GI83 3871 1239
6-38 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

17179 LA8 68 WD68 6203 1985

17314 LA8 71 WD71 9163 2932

17314 LA8 94 WD94 6560 2099

17315 LA8 71 WD71 9163 2932

17315 LA8 94 WD94 6560 2099

17351 LA8 68 WD68 4424 1416

17352 LA8 68 WD68 4424 1416

17353 LA8 68 WD68 4424 1416

17371 LA8 29 WD29 1944 622

17444 LA8 28 WD28 37 12

17445 LA8 28 WD28 43 14

17494 LA8 28 WD28 7901 2528

17494 LA8 29 WD29 35 11

17588 LA9A 62 SP62 1103 353

17329 NG15-02 258 GB258 8428 2697

17329 NG15-02 259 GB259 15879 5081

17329 NG15-02 260 GB260 2032 650

17329 NG15-02 302 GB302 5486 1755

17332 NG15-02 258 GB258 6802 2177

17332 NG15-02 259 GB259 16059 5139

17332 NG15-02 260 GB260 2304 737

17332 NG15-02 302 GB302 7010 2243

17417 NG15-02 506 GB506 2524 808

17417 NG15-02 507 GB507 4064 1301

17419 NG15-02 506 GB506 141 45

17420 NG15-02 506 GB506 145 46

17421 NG15-02 506 GB506 77 25

17497 NG15-02 302 GB302 59 19

17498 NG15-02 302 GB302 56 18

15497 NG15-03 19 GC19 9247 2959

15497 NG15-03 63 GC63 16074 5144

15497 NG15-03 106 GC106 9640 3085

15497 NG15-03 107 GC107 6341 2029

15497 NG15-03 150 GC150 15971 5111

15497 NG15-03 194 GC194 14089 4509

15497 NG15-03 195 GC195 2892 925

15497 NG15-03 239 GC239 16877 5401

15497 NG15-03 240 GC240 12462 3988

15497 NG15-03 284 GC284 5135 1643

15497 NG15-03 285 GC285 20629 6601

15497 NG15-03 329 GC329 9005 2882

15497 NG15-03 330 GC330 6912 2212

15497 NG15-03 374 GC374 15918 5094

15497 NG15-03 418 GC418 15920 5094

15497 NG15-03 462 GC462 15920 5094

15497 NG15-03 506 GC506 16929 5417
6-39 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

15497 NG15-03 550 GC550 6005 1922

15497 NG15-03 551 GC551 15434 4939

15497 NG15-03 552 GC552 19440 6221

15497 NG15-03 553 GC553 496 159

15497 NG15-03 597 GC597 19755 6321

15497 NG15-03 641 GC641 11570 3702

15876 NG15-03 28 GC28 3472 1111

15876 NG15-03 29 GC29 20214 6469

15876 NG15-03 30 GC30 1508 483

15876 NG15-03 74 GC74 21264 6804

15876 NG15-03 118 GC118 229 73

15876 NG15-03 119 GC119 17475 5592

15876 NG15-03 163 GC163 17155 5490

15876 NG15-03 164 GC164 478 153

15876 NG15-03 208 GC208 17314 5540

15876 NG15-03 252 GC252 17301 5536

15876 NG15-03 253 GC253 746 239

15876 NG15-03 297 GC297 17670 5654

15876 NG15-03 341 GC341 16189 5181

15876 NG15-03 342 GC342 1443 462

15876 NG15-03 386 GC386 21230 6794

15876 NG15-03 387 GC387 7022 2247

15876 NG15-03 431 GC431 9067 2901

15876 NG15-03 432 GC432 17559 5619

15876 NG15-03 476 GC476 5386 1724

15876 NG15-03 477 GC477 15088 4828

15876 NG15-03 521 GC521 10223 3271

15876 NG15-03 522 GC522 7673 2455

15876 NG15-03 565 GC565 8185 2619

15876 NG15-03 566 GC566 8564 2740

15876 NG15-03 608 GC608 13228 4233

15876 NG15-03 609 GC609 15546 4975

15876 NG15-03 651 GC651 9918 3174

15876 NG15-03 652 GC652 8126 2600

15876 NG15-03 653 GC653 3202 1025

15876 NG15-03 696 GC696 15376 4920

15876 NG15-03 697 GC697 1853 593

16011 NG15-03 653 GC653 9593 3070

17212 NG15-03 653 GC653 9517 3045

17213 NG15-03 653 GC653 9381 3002

17214 NG15-03 653 GC653 58 19

17218 NG15-03 653 GC653 57 18

17219 NG15-03 653 GC653 120 38

17220 NG15-03 653 GC653 97 31

17221 NG15-03 653 GC653 78 25

17222 NG15-03 653 GC653 78 25
6-40 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

17223 NG15-03 653 GC653 97 31

17224 NG15-03 653 GC653 124 40

17225 NG15-03 653 GC653 63 20

17226 NG15-03 653 GC653 94 30

17227 NG15-03 653 GC653 72 23

17229 NG15-03 653 GC653 10503 3361

17230 NG15-03 653 GC653 10307 3298

17231 NG15-03 653 GC653 10125 3240

17233 NG15-03 653 GC653 56 18

17234 NG15-03 653 GC653 89 28

17235 NG15-03 653 GC653 105 34

17236 NG15-03 653 GC653 60 19

17237 NG15-03 653 GC653 92 29

17238 NG15-03 653 GC653 77 25

17240 NG15-03 653 GC653 4362 1396

17240 NG15-03 654 GC654 4298 1375

17241 NG15-03 653 GC653 4205 1346

17241 NG15-03 654 GC654 4195 1342

17242 NG15-03 654 GC654 58 18

17243 NG15-03 654 GC654 56 18

17244 NG15-03 654 GC654 59 19

17248 NG15-03 654 GC654 123 39

17249 NG15-03 654 GC654 98 31

17261 NG15-03 338 GC338 8192 2621

17347 NG15-03 652 GC652 68 22

15963 NG16-01 618 AT618 58 19

16065 NG16-01 25 AT25 17723 5671

16065 NG16-01 69 AT69 16366 5237

16065 NG16-01 113 AT113 12853 4113

16065 NG16-01 114 AT114 3728 1193

16065 NG16-01 158 AT158 16860 5395

16065 NG16-01 202 AT202 16856 5394

16065 NG16-01 246 AT246 7279 2329

16065 NG16-01 247 AT247 11350 3632

16065 NG16-01 291 AT291 13864 4437

16065 NG16-01 292 AT292 6115 1957

16065 NG16-01 336 AT336 18752 6001

16065 NG16-01 337 AT337 1691 541

16065 NG16-01 381 AT381 18779 6009

16065 NG16-01 382 AT382 4982 1594

16065 NG16-01 426 AT426 13177 4217

17482 NG16-01 574 AT574 47 15

15876 NH15-12 907 EW907 6365 2037

15876 NH15-12 951 EW951 6139 1965

15876 NH15-12 952 EW952 19200 6144

15876 NH15-12 953 EW953 1900 608
6-41 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

15876 NH15-12 997 EW997 18028 5769

15876 NH15-12 998 EW998 13009 4163

17306 NH15-12 963 EW963 49 16

17196 NH16-04 914 MO914 4777 1529

17196 NH16-04 958 MO958 16962 5428

17196 NH16-04 1002 MO1002 13244 4238

17196 NH16-04 1003 MO1003 1699 544

17197 NH16-04 1003 MO1003 48 15

17473 NH16-04 826 MO826 2219 710

17474 NH16-04 826 MO826 2218 710

16065 NH16-10 773 MC773 8541 2733

16065 NH16-10 817 MC817 7086 2268

16065 NH16-10 818 MC818 12356 3954

16065 NH16-10 862 MC862 17180 5498

16065 NH16-10 905 MC905 17117 5478

16065 NH16-10 906 MC906 547 175

16065 NH16-10 949 MC949 16492 5277

16065 NH16-10 993 MC993 16281 5210

16091 NH16-10 765 MC765 1321 423

16091 NH16-10 809 MC809 16010 5123

16093 NH16-10 809 MC809 1688 540

16094 NH16-10 809 MC809 73 23

16095 NH16-10 809 MC809 310 99

16095 NH16-10 810 MC810 4336 1387

17327 NH16-10 538 MC538 43 14

17457 NH16-10 705 MC705 12846 4111

17457 NH16-10 706 MC706 15963 5108

17457 NH16-10 707 MC707 12975 4152

17458 NH16-10 705 MC705 12852 4112

17458 NH16-10 706 MC706 15962 5108

17458 NH16-10 707 MC707 12970 4150

17271 TX3 757 MU757 13109 4195

17271 TX3 758 MU758 7843 2510

17271 TX3 763 MU763 14730 4714

17271 TX3 764 MU764 3847 1231

17271 TX3 782 MU782 9527 3049

17567 TX4 632 MI632 11726 3752

17601 TX4 632 MI632 948 303

17602 TX5 502 BA502 119 38

17602 TX5 A 1 BAA1 13071 4183

17063 TX7 140 HI140 206 66

17063 TX7 156 HI156 7544 2414

17456 TX7 73 HI73 11944 3822

17469 TX7 140 HI140 7942 2541

17470 TX7 140 HI140 7942 2541

17614 TX7 73 HI73 16369 5238
6-42 

Table 6-7. New Pipelaying Activity Data (continued).

Segment 

Number Prot_Number Block_Number Area Code Length (ft) Hours

17666 TX7 47 HI47 1718 550

17666 TX7 73 HI73 18286 5852

17440 TX7A A 247 HIA247 3160 1011

17440 TX7A A 256 HIA256 15840 5069

17614 TX7A 45 HI45 13247 4239

17614 TX7A 46 HI46 1709 547

17614 TX7A 74 HI74 15311 4899

16057 TX7B A 581 HIA581 6727 2153

16057 TX7B A 582 HIA582 7904 2529

16057 TX7B A 588 HIA588 13971 4471

16057 TX7B A 589 HIA589 2915 933

17263 TX7B A 545 HIA545 9862 3156

17263 TX7B A 547 HIA547 4616 1477

17263 TX7B A 548 HIA548 6089 1949

17385 TX7C A 263 HIA263 4047 1295

17385 TX7C A 264 HIA264 4255 1361

17386 TX7C A 263 HIA263 4047 1295

17386 TX7C A 264 HIA264 4255 1361

17387 TX7C A 263 HIA263 4047 1295

17387 TX7C A 264 HIA264 4255 1361

17440 TX7C A 263 HIA263 15247 4879

Table 6-8 

Pipe Repair Activity Data 

Segment 

Number Prot_number Block_Number Area Code Pipe Length (ft) Hours

138 LA10 41 MP41 1732 554

222 LA6 23 ST23 4699 1504

302 LA8 28 WD28 521 167

302 LA8 29 WD29 5826 1864

393 LA10 42 MP42 2329 745

458 LA10 132 MP132 4272 1367

458 LA10 133 MP133 10245 3278

458 LA10 135 MP135 15323 4903

458 LA10 144 MP144 11631 3722

543 LA8 71 WD71 5195 1662

553 LA8 71 WD71 4945 1582

624 LA7 43 GI43 7830 2506

1835 LA4 32 EI32 1214 388

1932 LA3A 48 SM48 10508 3363

1964 LA6 21 ST21 2048 655

1964 LA6 28 ST28 280 90
6-43 

Table 6-8. Pipe Repair Activity Data (continued).

Segment 

Number Prot_number Block_Number Area Code Pipe Length (ft) Hours

2044 LA6 21 ST21 1970 630

3141 LA10 152 MP152 2104 673

3141 LA10 153 MP153 1705 545

3141 LA9A 65 SP65 3323 1063

3142 LA10 152 MP152 837 268

3142 LA10 153 MP153 2579 825

3142 LA9A 65 SP65 2723 871

4018 LA4A 307 EI307 4913 1572

4566 LA3 67 VR67 11383 3643

4806 LA6 21 ST21 2182 698

4855 LA3A 48 SM48 1933 618

5003 LA3D 217 SM217 4258 1362

5870 LA3B 369 VR369 1830 585

5870 LA3B 370 VR370 12833 4106

6426 LA6B 10 PL10 2335 747

6606 LA4A 276 EI276 7467 2389

6609 LA4A 276 EI276 7269 2326

6656 LA4 63 EI63 3498 1119

6656 LA4 76 EI76 580 186

6656 LA4 77 EI77 8217 2629

7133 LA8 24 WD24 634 203

7134 LA8 24 WD24 606 194

7273 LA6 22 ST22 11391 3645

7273 LA6 27 ST27 1569 502

7490 LA6 72 ST72 6947 2223

7491 LA10 153 MP153 1384 443

7492 LA10 152 MP152 42 13

7492 LA10 153 MP153 2497 799

7492 LA9A 65 SP65 3021 967

7493 LA10 153 MP153 1574 504

7860 LA2 160 EC160 5419 1734

7988 LA6 23 ST23 3856 1234

7988 LA6 24 ST24 1251 400

8027 LA10 59 MP59 9044 2894

8451 LA6 24 ST24 2383 763

8581 LA6 21 ST21 1694 542

8609 LA6 52 ST52 471 151

8830 LA4 125 EI125 2110 675

8831 LA4 125 EI125 2110 675

8902 LA10 108 MP108 4841 1549

9203 LA6 24 ST24 4255 1361

9203 LA6C 2 BM2 1927 617

9203 LA7 37 GI37 4418 1414

9246 LA10 71 MP71 3523 1127

9246 LA10 72 MP72 10174 3256

9246 LA10 73 MP73 10246 3279
6-44 

Table 6-8. Pipe Repair Activity Data (continued).

Segment 

Number Prot_number Block_Number Area Code Pipe Length (ft) Hours

9246 LA10 146 MP146 10249 3280

9246 LA10 147 MP147 10256 3282

9246 LA10A 300 MP300 11652 3729

9899 LA4 120 EI120 5513 1764

10055 TX3 786 MU786 3135 1003

10055 TX3 787 MU787 5097 1631

10235 LA1 198 WC198 7148 2287

10498 LA8 29 WD29 10087 3228

10539 LA3D 217 SM217 4785 1531

10539 LA3D 218 SM218 3877 1241

10539 LA3D 221 SM221 3395 1087

10597 LA3C 190 SM190 621 199

10597 LA3C 191 SM191 9167 2933

10597 LA3C 192 SM192 13001 4160

10597 LA3C 205 SM205 1518 486

10597 LA4A 368 EI368 14506 4642

10597 LA4A 369 EI369 14508 4642

10597 LA4A 370 EI370 14508 4643

10597 LA4A 371 EI371 14703 4705

10597 LA4A 372 EI372 14944 4782

10597 LA4A 373 EI373 14908 4771

10597 LA4A 374 EI374 7485 2395

10597 LA4A 380 EI380 15015 4805

10597 LA4A 381 EI381 15208 4867

10597 LA4A 382 EI382 14918 4774

10597 LA4A 383 EI383 7430 2378

10597 LA4A 393 EI393 17901 5728

10597 LA5A 332 SS332 2802 897

10597 LA5A 333 SS333 9750 3120

10597 LA5A 344 SS344 15077 4825

10597 LA5A 345 SS345 15067 4821

10597 LA5A 346 SS346 15110 4835

10597 LA5A 347 SS347 15354 4913

10597 LA5A 348 SS348 7421 2375

10597 LA5A 351 SS351 3761 1203

10597 LA5A 352 SS352 15959 5107

10597 LA5A 353 SS353 15962 5108

10597 LA5A 354 SS354 6173 1975

10597 LA5A 357 SS357 12193 3902

10597 LA5A 358 SS358 15265 4885

10597 LA5A 359 SS359 15087 4828

10597 LA5A 360 SS360 9610 3075

10662 LA4 175 EI175 1419 454

10700 LA6B 5 PL5 11070 3543

10700 LA6B 6 PL6 12956 4146

10798 LA7 39 GI39 14329 4585
6-45 

Table 6-8. Pipe Repair Activity Data (continued).

Segment 

Number Prot_number Block_Number Area Code Pipe Length (ft) Hours

10798 LA7 48 GI48 8631 2762

10917 LA10 6 MP6 1207 386

10917 LA10 90 MP90 14322 4583

10917 LA10 91 MP91 14698 4704

10995 LA2A 334 EC334 13159 4211

11006 LA5A 349 SS349 1904 609

11006 LA5A 359 SS359 6543 2094

11067 LA2A 278 EC278 10769 3446

11271 LA3D 229 SM229 4017 1285

11271 LA3D 236 SM236 5067 1622

11340 LA4 74 EI74 8967 2869

11350 LA1 110 WC110 5567 1782

11566 TX5 544 BA544 6361 2036

12357 LA3 131 VR131 3548 1135

12681 LA3D 217 SM217 3168 1014

12681 LA3D 218 SM218 2764 884

13347 LA3D 217 SM217 2789 893

13363 LA3A 27 SM27 15596 4991

14073 LA4 188 EI188 952 305

14100 LA4 120 EI120 8131 2602

14202 LA5 63 SS63 1828 585

14204 LA5 63 SS63 1828 585

14284 LA10A 287 MP287 1780 570

14284 LA10A 288 MP288 12059 3859

14486 LA1 44 WC44 3160 1011

14559 LA1 66 WC66 1361 435

14559 LA1 71 WC71 11185 3579

14796 NH16-10 538 MC538 16021 5127

14796 NH16-10 582 MC582 326 104

15078 LA6 21 ST21 13169 4214

15237 LA6 23 ST23 6141 1965

15427 LA6 41 ST41 4395 1406

15453 LA1A 293 WC293 4341 1389

15453 LA1A 294 WC294 3025 968

15756 LA6 41 ST41 5613 1796

15793 LA6 41 ST41 770 247

15921 LA5 72 SS72 8425 2696

16079 LA6 21 ST21 3482 1114

16080 LA6 21 ST21 3473 1111

16174 LA8 79 WD79 2000 640

17205 LA10 108 MP108 8674 2776

17205 LA10 109 MP109 14163 4532

17205 LA10A 181 MP181 9510 3043

17208 LA4A 337 EI337 5517 1766

17208 LA4A 354 EI354 1574 504

17208 LA4A 355 EI355 14887 4764
6-46 

Table 6-8. Pipe Repair Activity Data (continued).

Segment 

Number Prot_number Block_Number Area Code Pipe Length (ft) Hours

17269 LA10A 252 MP252 5620 1798

17269 LA10A 256 MP256 15610 4995

17269 NH16-07 696 VK696 9360 2995

17269 NH16-07 739 VK739 12071 3863

17269 NH16-07 740 VK740 6033 1931

17269 NH16-07 783 VK783 14454 4625

17270 LA10A 252 MP252 5608 1795

17270 LA10A 256 MP256 15613 4996

17270 NH16-07 696 VK696 9360 2995

17270 NH16-07 739 VK739 12145 3886

17270 NH16-07 740 VK740 5956 1906

17270 NH16-07 783 VK783 14452 4624

17288 LA4A 337 EI337 5506 1762

17288 LA4A 354 EI354 1547 495

17288 LA4A 355 EI355 14912 4772

17407 LA3B 315 VR315 16345 5230

17407 LA3B 316 VR316 1985 635

17407 LA3B 329 VR329 14437 4620

17413 LA1 225 WC225 10819 3462

17415 LA4 120 EI120 8259 2643

17443 TX4 657 MI657 8283 2651

17606 LA1B 548 WC548 4189 1340

17606 LA1B 549 WC549 7016 2245

17606 LA1B 564 WC564 11361 3636

17607 LA1B 548 WC548 4188 1340

17607 LA1B 549 WC549 7016 2245

17607 LA1B 564 WC564 11308 3619

17672 LA5 52 SS52 5617 1797

17672 LA5 58 SS58 12153 3889

17672 LA5 59 SS59 9358 2995

17771 TX7C A 273 HIA273 5308 1699

17771 TX7C A 274 HIA274 13288 4252

17776 LA4 167 EI167 4513 1444

17776 LA4 189 EI189 11234 3595

17776 LA5 105 SS105 1738 556

17776 LA5 126 SS126 337 108

17776 LA5 127 SS127 18681 5978

17776 LA5 128 SS128 3512 1124

17870 LA8 79 WD79 8956 2866

17906 LA6 23 ST23 2502 801
6-47 

Table 6-9 

Pipelaying Monthly Adjustment Factors 

Month 

2008 

Monthly 

Adjustment 

Factors 

January 9.5%

February 6.7%

March 7.0%

April 8.4%

May 5.5%

June 16.8%

July 8.4%

August 16.5%

September 1.9%

October 10.5%

November 6.4%

December 2.4%

6.1.4 Support Helicopters 

Helicopters are used extensively in the Gulf of Mexico to move light supplies and 

personnel to and from platforms. The best data source for all helicopter operations in the Gulf of 

Mexico is the Helicopter Safety Advisory Conference (HSAC) annual safety report (HSAC, 

2009). The report contains a snapshot of all helicopter operations in the Gulf of Mexico as 

reported by participating operators. It should be noted, however, that the report underestimates 

operations, as activity data are voluntarily provided by a fraction of operators. For the 2005 

inventory, more comprehensive activity data were obtained from the FAA (USDOT, FAA 2006). 

2008 FAA data were unavailable for this inventory, but HSAC records show that since 2005, 

hours flown have increased 5% and the number of landing and takeoffs (LTOs) has decreased 

5%. These changes were applied to the FAA 2005 activity data to develop the 2008 activity 

estimates. 

Data on the categories of helicopters used to support offshore oil platforms in the Gulf of 

Mexico were obtained from the HSAC Gulf of Mexico Offshore Helicopter Operations and 

Safety Review (HSAC 2009). The HSAC compiled activity data disaggregated into single engine, 

light twin engine, medium twin engine, and heavy twin engine helicopters, as noted in 

Table 6-10. 
6-48 

Table 6-10 

HSAC Helicopter Data 

Type 

Adjusted 

FAA Data 

HSAC Operations 

Profile (%) 

Single 1,713,698 78.394 

Light Twin 144,298 6.601 

Medium/Heavy Twin 328,006 15.005 

Total 2,186,002 100 

The helicopter emission factors were obtained from multiple sources, including: 

• FAA Emission Dispersion and Modeling System (EDMS) software (USDOT, 

FAA 2009; USDOT 2009) 

• Switzerland Federal Office of Civil Aviation (FOCA) - Guidance on the 

Determination of Helicopter Emissions (Switzerland FOCA 2009) 

• Allison helicopter engine manufacturer (Allison Helicopter Engine 

Manufacture 2002) 

• USEPA Procedures for Emission Inventory Preparation Volume IV: Mobile 

Sources (USEPA 1992) 

• Helicopter test data from the Department of the Navy Environmental 

Assessments (US Department of the Navy 1999) 

• Final Air Quality Management Plan, 1991 Revision, Final Technical Report 

III-G, 1987 Aircraft Emission Inventory in the South Coast Air Basin, 

developed by the California South Coast Air Quality Management District 

(SCAQMD 1991). (Staff at the California Air Resources Board noted that 

these emission factors have not been updated since 1991.) 

It was determined that the EDMS helicopter emission factors were the most up to date 

and comprehensive. The EDMS emission factors were disaggregated into the helicopter types in 

the HSAC data. The emission test data for each aircraft type were converted to LTO-based 

emission factors by weighting the pounds/minutes test results by the amount of minutes the 

helicopter spent in each mode using the following equation: 

EFLTO = ∑ TDi × Pi

where: 

EFLTO = LTO-Based emission factor (pound per LTO) 

TDi = Test data for Mode i (pound per minute) 

i = Mode (i.e., take off, climbout, approach and idle) 

Pi = Period helicopter is in mode (minute/LTO) 

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 helicopter idles for an additional 15 minutes while on the 
6-49 

platform. Therefore the emission estimates and factors are based on a short LTO cycle of 

35 minutes. 

The LTO-based emission factors for each helicopter type were averaged to yield the 

emission factors used in this study. These average emission factors are summarized in 

Table 6-11. CO2 emission factors were developed based on fuel usage (Wilson et al. 2007). It 

also was assumed that helicopters with three engines were similar to medium/heavy twin-engine 

helicopters. Data obtained for military helicopters were not included in the average because some 

of the emission factors were more than an order of magnitude different from the factors obtained 

from other data sources and a credible explanation for the difference could not be provided; also 

most of the helicopters used to support oil platform activities are commercial, not military 

helicopters. 

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 0.31 pounds/LTO, and the 

LTOs for single engine helicopters in 2008 were 976,611. 

ESingle = EFSingle / 2000 × LTOSingle

E = 0.31/2000 × 976,611 

E = 151 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 percent). 
6-50 

Table 6-11 

Helicopter Emission Factors by Helicopter Type 

Type Helicopter Engine 

CO

(lb/LTO) 

HC

(lb/LTO) 

NOX

(lb/LTO) 

SO2

(lb/LTO) 

(

Single

Unspecified Allison 250-C40B 3.92 0.981 0.537 - Unspecified Allison 250-C20S 2.12 0.304 0.272 - 

Bell UH-1, AH-1 T53-L-11D 2.75 1.95 0.951 0.099 Bell 206 JetRanger 250B17 7.08 1.72 0.328 0.141 

Unspecified Allison C20B 2.80 0.410 0.380 - 

Bell 407 250B17 14.0 3.40 0.647 0.277 

Unspecified 250B17B 2.57 0.463 0.215 0.030 

Robinson R22 IO360 9.22 0.401 0.044 0.020 Robinson R22 O320 13.4 0.366 0.015 0.023 Robinson R22 TSIO36 9.72 1.58 0.064 0.029 Robinson R22 IO320 6.64 0.288 0.069 0.019 Robinson R44 Raven TIO540 80.6 3.44 0.057 0.118 Hughes 500D 250B17 7.06 1.71 0.335 0.141 UH-1N Iroquois T400-CP-400 1.758 0.576 0.375 0.050 

Average 11.7 1.26 0.306 0.086 

Light Twin

Boelkow BO-105 250B17 14.1 3.41 0.666 0.281 Agusta A-109 250B17 14.1 3.42 0.668 0.282 Sikorsky S-76 Spirit T70070 16.2 20.4 2.00 0.613 Bell AH-1J Cobra T400 0.355 0.062 4.67 0.764 Bell AH-1S Cobra T5311D 2.91 5.97 0.303 0.173 Bell AH-1S Cobra T53L13 2.91 6.93 0.303 0.173 

Unspecified T58-GE-8F 19.0 11.7 1.255 0.175 

Boeing CH-46 Sea Knight Unspecified 23.2 14.6 1.62 0.578 Sikorsky UH-60 Black Hawk T70070 7.96 9.91 1.18 0.324 

Unspecified T58-GE-5 18.4 8.08 1.754 0.190 

Average 11.9 8.45 1.44 0.355 
6-51 

Table 6-11. Helicopter Emission Factors by Helicopter Type (continued).

Type Helicopter Engine 

CO

(lb/LTO) 

HC

(lb/LTO) 

NOX

(lb/LTO) 

SO2

(lb/LTO) 

Medium/Heavy Twin

Sikorsky SH-60 Sea Hawk T70041 4.72 0.302 4.84 0.853 Sikorsky CH-53 Sea Stallion Unspecified 20.5 7.67 2.18 0.689 Sikorsky CH-53E Super Stallion Unspecified 25.3 12.4 6.67 1.669 

Average 16.8 6.79 4.56 1.07 

a More aircraft had hydrocarbons (HC) emission data than VOC. Therefore, VOC was calculated directly from HC usin factor.
6-52 

Helicopter emissions were assigned to lease blocks (USDOI, MMS 2008c) 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 

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. 
6-53 

Support vessel population data for supply vessels, utility vessels, and lift boats were 

obtained from the Offshore Marine Service Association (OSMA 2009, Wells 2009). Vessel 

population data for 2008 were not available for anchor handling vessels, crew boats, or tugs and 

tow boats. Therefore, population data for anchor handling vessels, crew boats, tugs and tow boats 

were grown to represent 2008 data by using Gulf of Mexico oil production for 2005 and 2008 

(USDOI, MMS 2009) yielding a growth factor of 0.902.

The support vessel dataset did not include information about vessel characteristics. Some 

vessel characteristics data were obtained from A-Z of Offshore Support Vessels of the World

published by the Oilfield Publications Limited (2004). Most of the vessel characteristics data 

used in this study were obtained from the USEPA CMV studies (USEPA 2007a). The USEPA 

groups vessels based on the cylinder displacement of the main propulsion engine: 

• Category 1: 1-5 liters per cylinder displacement 

• Category 2: 5-30 liters per cylinder displacement 

• Category 3: over 30 liters per cylinder displacement

Most of the support vessels are propelled with Category 1 (44.8%) or Category 2 (51.1%) 

engines. On average, these vessels have 2.22 engines with a total vessel horsepower range 

between 740 and 7,502, with the typical value being 2,289 horsepower, derived from data 

obtained from the USEPA report: Category 2 Vessel Census, Activity and Spatial Allocation 

Assessment and Category 1 and Category 2 In-port/at Sea Split (USEPA 2007b). 

Based on the USEPA vessel study (USEPA 2007b), it was estimated that support vessels 

operated at sea 232 days per year, 66 days per year they were in port, and 67 days per year they 

were involved in required maintenance activities. Because the vast majority of these vessels are 

provided through leasing agreements, it was assumed that for the days these vessels are available 

that they operate for 24 hours a day. 

The vessel population estimate and the average hours of operation were used to calculate 

the total annual hours that support vessels operate in Federal waters (Table 6-12). 

Table 6-12 

Support Vessel Census, kW rating, and Annual Hours of Operation 

Type 

Vessel Count Average Total kW Typical at 

Sea 

Underway 

Hours 

Typical at 

Sea Idle 

Hours Category 

1 

Category 

2 

Category 

3 

Category 

1 

Category 

2 

Category 

3 

Anchor 

Handling Boats 4 18 2 2,995 3,393 5,123 5,568 1,584 

Supply/ Crew/ 

Utility Boats 357 235 2 1,779 2,516 2,984 5,568 1,584 

Lift Boats 31 62 0 1,342 1,581 - 5,568 1,584 

Tugs/Tow 

Boats 15 145 20 3,418 3,320 6,016 5,568 1,584 

Total 407 460 23 
6-54 

Offshore support vessel load factors were provided by the US Coast Guard National 

Offshore Safety Advisory Committee (McGill 2006). The load factors for offshore support 

vessels vary, with most of the time spent at 85% load while at sea underway, and 10% load while 

idling adjacent to the platform. Regulations require that support vessels can not tie-up to 

platforms, instead they idle nearby while offloading their cargo, and hence they do not shut down 

their engines while loading and unloading at the platform (McGill 2006). 

The operating mode times, load factors, and typical horsepower ratings were applied to 

the Swedish Emission Factors (SEPA 2004) as provided in Table 6-1 to obtain the emissions for 

each support vessel type. 

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: 

Four Category 1 anchor handling vessels spent 22,272 hours at sea in total. Average kW 

of Category 1 anchor handling vessels is 2,994.73 kW, load factor is 0.85, and the emission 

factor for NOx is 12.0 g/kWh. These data can be applied to the marine vessel equation presented 

in Section 6.1.1. 

E = AH × kW × LF × EF × CF 

E = 22,272 × 2,994.73 × 0.85 × 12.0 × 1.10231 × 10-6

E = 749.93 tons of NOx

Support vessel monthly emissions were estimated by applying a monthly adjustment 

factor (Table 6-13) to the annual emission estimates. The monthly adjustment factors were 

developed from temporal traffic pattern data obtained from the Automatic Identification System 

(AIS). 
6-55 

Table 6-13 

Support Vessel Monthly Adjustment Factors 

Month 

2008 

Monthly 

Adjustment 

Factors 

January 15.24%

February 18.41%

March 12.38%

April 2.86%

May 3.17%

June 2.54%

July 3.17%

August 1.90%

September 3.81%

October 5.40%

November 10.16%

December 20.95%

Support vessel emissions were assigned equally to all active platforms. Underway 

support vessel emissions were spatially apportioned based on the location of active offshore 

platform and the location of the closest port using the equation below: 

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 = Sum of the lengths of all support vessel fairways within the 

 boundaries of the lease block i (miles) 

Slt = Total sum of all support vessel fairways in the Gulf of Mexico (miles) 

Figure 6-4 shows the active lease blocks to which support vessels travel (USDOI, MMS 

2008c). Emissions for lease blocks closer to shore are probably overestimated using the above 

methods, as it is assumed that support vessels only travel between local ports and specific 

platforms. Support vessels may actually travel to multiple platforms before returning to port. At 

this time, data are not readily available to map actual support vessel routes. 
6-56 

Figure 6-4. Active offshore platforms with BOEM lease blocks. 

6.1.6 Survey Vessels 

Survey vessels are used in the Gulf of Mexico 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 Gulf of Mexico. Most modern survey vessels tow 

multiple streamers (sound wave reception devices), such that for every linear mile traveled, they 

acquire data for a square mile of subsurface area (Brinkman 2002a, 2002b). 
6-57 

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 only provided data 

for 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 this 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 then 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. 

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 16 survey vessels, it was assumed that collectively 

all survey vessels operated at sea for 125,941 hours. The 2005 survey data also included engine 

kW ratings. The survey results noted that the average power rating for survey vessels was 

1,025 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. 

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. 
6-58 

Example Calculation: 

Total hours of operation of all survey vessels were 125,941. The average kW is 1,025, 

load factor is 0.90, and the emission factor for NOx is 13.2 g/kWh. These data can be applied to 

the marine vessel equation presented in Section 6.1.1. 

E = AH × kW × LF × EF × CF 

E = 125,941 × 1,025 × 0.90 × 13.2 × 1.10231 × 10-6

E = 1,690.5 tons of NOx

No monthly survey data were identified in this effort; it was assumed that activity was 

consistent through out the year, therefore, annual emission estimates were temporally 

apportioned to individual months equally (i.e., 8.33 percent). 

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) 

6.2 NON-PLATFORM NON-OIL/GAS PRODUCTION RELATED SOURCES 

Non-OCS oil and gas production sources include biogenic and geogenic sources, as well 

as vessels related to commercial fishing, CMVs, the LOOP, military operations, and vessel 

lightering activities. 
6-59 

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 2005 emission estimates for these source categories. No 

additional references were uncovered that provided new data specific for the Central and 

Western areas of the Gulf of Mexico, nor were any references identified that could be used to 

enhance the base year 2005 biogenic/geogenic emission estimates. Given the nature of these 

emission sources, the 2005 estimates were used to represent 2008 emissions. 

Subsurface Seeps of Crude Oil 

Subsurface seeps of oil, more commonly referred to as oil seeps, occur when crude oil 

deposits beneath the ocean floor escape into the ocean waters because of cracks and vents in the 

floor. Cracks can open and close as the result of several geological activities. The volume of oil 

seeping into the ocean can be relatively significant though. The total amount of oil that is 

released into the ocean does not, however, find its way to the surface and end up as air 

emissions. Some ocean-dwelling biota develop communities surrounding oil seeps and utilize the 

hydrocarbons as a source of nutrients. Other free floating organisms in the water column 

consume portions of the escaping oil as the material rises to the surface. Although these 

processes do mitigate the amount of oil that reaches the surface for possible volatilization, there 

is significant uncertainty and variability on the amounts that do reach the surface. Air pollutants 

that can be emitted from oil seeps include VOC, CH4, CO2, and air toxics. Based on the data 

found in the literature, only VOC emissions can be estimated at this time. 

The BOEM and other researchers have conducted a significant amount of work to study 

the extent of oil seeps in the Gulf of Mexico and off the coast of California. Much of this 

investigation has focused on the occurrence of communities of chemosynthetic organisms and oil 

slicks. Both factors have been shown to correspond to significant oil seep activity. 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 

Gulf of Mexico 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/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, 34% of the 
6-60 

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 decline to 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) (Andreae and 

Ferek 1992). 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 (Nevison et al. 1995), 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 excrete gases or liquids. The gases they 

release often contain CH4, CO2, and VOCs. Four mud volcanoes have been identified in the Gulf 

of Mexico (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 to for the VOC mass emission estimate. 

Adjustments were made to the methane estimate to account for the observation that 80% of the 
6-61 

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 6-14. 

Table 6-14 

Mud Volcano Locations and Emission Characteristics 

Location 

Typical 

Emission Rate 

CH4

Fraction 

CO2

Fraction 

VOC 

Fraction 

M

3

/yr (%) (%) (%) 

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 through out the year, 

therefore, annual emission estimates were temporally apportioned to individual months equally 

(i.e., 8.33 percent). 

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. Except for volcanoes, the emissions were allocated 

for all other biogenic/geogenic sources based on the surface area of the lease blocks 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) 

6.2.2 Commercial Fishing Vessels 

The Gulf of Mexico is an active commercial fishing area, providing a wide range of fish 

and seafood products. Detailed commercial fishing data were obtained from the National 

Oceanic & Atmospheric Administration (NOAA) National Marine Fisheries Service (NMFS). 

Separate activity data were provided for the three types of offshore fishing activities that occur in 

the Gulf of Mexico: pelagic long line, reef, and shrimp operations (USDOC, NMFS 2009a and b; 

Farmer 2009; Nance 2009). 

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 
6-62 

in Table 6.15 and Table 6.16, respectively. (The line fishing activity data includes over 3,000 

records, and cannot be provided in a hardcopy format.) 

Table 6-15 

Shrimp Vessel Activity Data 

NMFS Zones 

2008 Shrimp 

Fishing Vessel

Hours 

10 - 12 207,810 

13 - 17 707,009 

18 - 21 479,106 

Total 1,393,926 

Table 6-16 

Reef Fishing Vessel Activity Data 

NMFS Zones 

2008 Reef 

Fishing Vessel

Hours 

11 - 21 888,120 

Emissions associated with commercial fishing vessels are attributed to the operation of 

diesel engines used for propulsion and other smaller diesel engines that are used to run 

generators or small cranes and winches to lift fish nets and lines onto the vessel. 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 (373 HP) and shrimp 

vessels (514 HP) were obtained by taking the average horsepower of the 2008 permitted shrimp 

vessels and reef fish vessels (Dudley 2009). 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 emission and load factors were applied to the kW-hours of 

operation developed from the NMFS data to calculate emissions for this source category. 

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. 
6-63 

Example Calculation: 

Shrimp fishing vessels spent 1,393,926 hours at sea in 2008. The average kW is 384.05, 

load factor is 0.80, and the emission factor for NOx is 13.2 g/kWh. These data can be applied to 

the marine vessel equation presented in Section 6.1.1. 

E = AH × kW × LF × EF × CF 

E = 1,393,926 × 384.05 × 0.80 × 13.2 × 1.10231 × 10-6

E = 6,231.46 tons of NOx

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 2008. The monthly adjustment factors were applied to the 

annual emission estimates to calculate the monthly emissions. The monthly adjustment factors 

are presented in Table 6-17. 

Table 6-17 

Commercial Fishing Monthly Adjustment Factors 

Month 

2008 Monthly 

Adjustment 

Factors 

January 1% 

February 1% 

March 1% 

April 6% 

May 12% 

June 20% 

July 19% 

August 16% 

September 6% 

October 11% 

November 3% 

December 2% 

Commercial fishing locations were also provided by the NMFS. Reef and shrimp fishing 

operations are delineated by NMFS statistical zones (Figure 6-6). 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 (USDOC, NOAA 2009b) 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. 
6-64 

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) 

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 NMFS and the estimated hours of operation. 

With regard to recreational fishing, it was determined that the majority of recreational 

fishing occurs within State waters, and therefore this source category was not included in this 

inventory. It is recognized that some small portion of recreational fishing occurs near platforms 

that are not in State waters. Unfortunately, data could not be identified to quantify recreational 

fishing near oil platforms. 
6-65 

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

6.2.3 Commercial Marine Vessels 

CMVs are involved in transporting a wide range of agricultural, manufacturing, and 

chemical products through the Gulf of Mexico. The majority of CMVs tend to be powered by 

diesel engines that combust marine diesel fuel or a blend of distillate and residual oils. The CMV 

emission estimates for diesel-powered vessels were developed by the USEPA in support of 

recent Category 3 marine vessel regulations (USEPA 2009a). These emission estimates use 

emission factors similar to those provided by the Swedish EPA. The USEPA has implemented a 

number of studies to more accurately quantify the fuels used by these larger vessels. 
6-66 

Figure 6-7. Commercial marine vessel shipping lanes. 

The CMV emission estimates provided by USEPA included emissions associated with 

interport, approach, and reduced speed zone (RSZ) activities (Carey 2009a, 2009b). Approach 

and RSZ emissions were provided as shipping lane segments; a GIS layer of the lease block 

boundaries was overlaid upon the shipping lanes (Figure 6-7), and emissions within each lease 

block boundary were summed. Interport emissions were provided as pollutant-specific rasters 

with 4km grid cells that represent interport activity by all Category 3 vessels. Again, a GIS layer 

of the lease block boundaries was overlaid upon the grids, and zonal statistics tools were used to 

find the total emissions per lease block. 

The grids were originally provided in a user-defined projected coordinate system, but the 

North American Equidistant Conic projection was selected for use in this analysis as this was the 

projection used in calculating or allocating emissions for all other categories in this effort. 

Ultimately, CMV emissions within Federal waters for approach, RSZ, and interport activities 

were summed to a single value per lease block. 

6.2.4 LOOP 

The LOOP is a platform located 45 miles from shore. 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 1000 kW generator, four 7,500 hp pumps, support 

vessels, as well as the oil tankers that use the facility. 

Unfortunately, neither 2005 nor 2008 activity data were available for this inventory 

effort. Therefore, base year 2000 LOOP activity data were adjusted to reflect 2008 activity. The 
6-67 

base year 2000 hours of operation for the generator and pumps were previously obtained from 

the LOOP website (www.loopllc.com). This site included detailed information about the 

individual vessels that used the platform in 2000, and the line vessels that assisted the oil tankers 

in getting to and from the mooring points. The 2000 data represents the facility operating at full 

capacity, operating 365 days per year and averaged 0.75 vessel calls per day. These 2000 data 

were adjusted to show a decrease in activity to account for the 7 days in 2008 that the platform 

was not operating due to power failures associated with hurricanes; this included one day of 

closure following Hurricane Eduardo (Baltimore 2008), 4 days following Hurricane Gustav 

(Legendre 2008) and 2 days following Hurricane Ike (Capo 2009). With an estimate of just over 

5 calls per week, this corresponded to approximately 269 calls in 2008, down from 275 in 2000. 

This decreased number of calls was used to calculate the appropriate hours of activity for the 

emission sources associated with the LOOP. 

The LOOP engine characteristics, including kW rating, load factors, and hours of 

operation are summarized in Table 6-18. 

Table 6-18 

LOOP Hours of Operation, kW Rating, and Load Factors 

Vessel/Equipment

Type Mode Hours of Activity 

Average 

kW 

Load 

Factor 

Tankers Approach 1,716 25,989 0.55 

Tankers Idling 8,301 25,989 0.10 

Support Vessels Maneuvering 6,465 895 0.25 

Generator -- 8,566 1,000 0.50 

Pumps -- 3,300 22,371 1.00 

The emissions for the LOOP were calculated by applying the Swedish emission factors 

(SEPA 2004) noted in Table 6-1 to the hours of activity for each emission source, with the 

average kW rating and load factor also taken into account. 

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: 

All tankers spent 1,716 hours at sea in 2008. The average kW of tankers is 25,989, load 

factor is 0.55 for approaching mode, and the emission factor for NOx is 17.0 g/kWh. These data 

can be applied to the marine vessel equation presented in Section 6.1.1. 

E = AH × kW × LF × EF × CF 

E = 1,716 × 25,989 × 0.55 × 17.0 × 1.10231 × 10-6

E = 459.6 tons of NOx
6-68 

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. Evaporative emissions from ballasting were also calculated in 

this effort. These estimates were derived from product transfer data for each vessel that used the 

LOOP and emission factors included in the EIIP guidance documents (EIIP 1999). Again, 2008 

data were not available, and 2000 data were adjusted according to the number of days the facility 

was able to operate in 2008. 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 through out the year, therefore, annual emission estimates were temporally 

apportioned to individual months equally (i.e., 8.33 percent). 

Platform, ballasting, support vessel, and tanker idling emissions were all assigned to the 

latitude and longitude coordinates of the LOOP. Emissions associated with the vessel approach 

were assigned to the associated shipping lane as noted in Figure 6-8. 

Figure 6-8. Shipping lane approach and location of LOOP. 

6.2.5 Military Vessels 

The US Navy and Coast Guard patrol the coast and have maneuvers in the Gulf of 

Mexico. The US 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. 
6-69 

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 US 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 Gulf of Mexico. Of the two largest bases initially listed for closure, the 

Naval Support Activity Center New Orleans has since been realigned and removed from the list 

of closures, and the Naval Station Ingleside has begun the process of closing; however, by 2008 

the phase-out of this base had only begun and there was no indication that vessel activity had 

diminished as a result. All remaining base closings in the Gulf region involved small reserve 

centers that employ 10 to 30 people. No information on vessel utilization was found for those 

small reserve centers. 

For the 2008 inventory, the Naval activity data reported in the Gulf of Mexico Air Quality 

Study was applied to the Swedish emission factors to be consistent with the emission estimation 

methods used for the other marine vessel categories. In order to implement this approach, kW 

hours were calculated for each Naval vessel as noted in Table 6-19. 

Table 6-19 

Naval Vessel kW Hours 

Vessel Engine Type No. 

Engines 

Average 

kW 

Rating 

Total 

Engine 

Hours 

kW-hrs Operating 

Load 

Load 

Adjusted 

kW-hrs 

MSO Diesel 4 428.78 35,040 15,024,451 0.80 12,019,561 

MCM Diesel 4 447.42 35,040 15,677,597 0.80 12,542,077 

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 22 201,480 695,040,388 556,032,310 

As noted above, the Gulf of Mexico Naval fleet includes diesel turbine and steam ships. 

The previous Gulfwide inventories included estimates of annual fuel usage for these vessels. 

These fuels usage data and associated fuel-based emission factors are presented in Table 6-20. 

Note the diesel turbine factors were obtained from the Swedish study (SEPA 2004) while the 

steamship factors were obtained from USEPA guidance (USEPA 1992). 
6-70 

Table 6-20 

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 

Given the difficulty of obtaining detailed activty data pertaining to Naval vessels, the use 

of Automatic Identification Systems (AIS) data is 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. 

The Coast Guard provided data for the Year 2005 Gulfwide Emission Inventory Study

(Wilson et al. 2007) that included the number of vessels with a homeport in the Gulf of Mexico, 

the type of vessel, the name of the vessel, and the total number of operating days for some of the 

vessels. Although the Coast Guard has commissioned several new vessels for use in the Gulf of 

Mexico, they are not yet in service. Therefore, it is assumed that the 2005 data accurately reflects 

Coast Guard activity in 2008. 

From the previously provided data, the average number of operating hours was calculated 

for each type of ship. Engine horsepower was obtained for some of but not all of the vessels via 

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 6-21. 

Table 6-21 

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 Naval and Coast Guard marine diesel engines, the 

Swedish emission factors noted in Table 6-1 were applied to the hours of operation and the 

vessel kW rating (which was converted from the horsepower). It was assumed that the Coast 

Guard vessels typically operate at a load factor of 85% while in Federal waters.
6-71 

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: 

Buoy tenders spent 89.7 days at sea in 2005. 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 for approaching mode, and the emission factor for NOx is 17.0 g/kWh. These data can be 

applied to the marine vessel equation presented in Section 6.1.1. 

E = AH × kW × LF × EF × CF 

E = 2,152.8 × 4,623× 0.85 × 17.0 × 1.10231 × 10-6

E = 158.53 tons of NOx

No monthly Naval or Coast Guard data were identified in this effort; it was assumed that 

activity was consistent through out the year, therefore, annual emission estimates were 

temporally apportioned to individual months equally (i.e., 8.33 percent). 

Because it was not possible to identify where Navy vessels operate, the emissions were 

allocated to individual lease blocks through out the Central and Western areas of the Gulf of 

Mexico. All Coast Guard vessel emissions were allocated by vessel relative to the home port and 

the area where the vessels patrol (Figure 6-9). 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 Gulf of Mexico (tons) 

Si = Surface area of lease block i (square miles) 

STG = Surface area of total Gulf lease blocks (square miles) 
6-72 

Figure 6-9. Coast Guard districts used to allocate emissions. 

6.2.6 Vessel Lightering 

Lightering is the transfer of cargo to smaller ships that bring the product into port. 

Lightering occurs off-shore 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. 

Skaugen Petrotrans is the largest lightering company in the world, and provides ship-toshore transfers of crude oil to Houston. In 2005, vessel lightering activity was obtained from the 

Skaugen website and included the number of lightering operations, the total number of lightering 

days, and the daily lightered volume of product. Since 2005, the website has been reformatted 

and no longer includes vessel lightering activity data. In order to obtain 2008 vessel lightering 

activity data, Skaugen Petrotrans were contacted directly. 

To calculate the emissions from the large tanker ships involved in the lightering process, 

the activity data obtained from the Skaugen Petrotrans (Tonstad 2009) were converted into hours 

of operation. It was assumed that each operating day was 24 hours long. For the escort vessels, 

the total volume of product transferred was divided by the average escort capacity, which was 

obtained from the US Coast Guard in order to estimate the total number of escort vessel trips 

made annually. This was then multiplied by the average escort trip time. The average escort trip 

time was calculated based on the distance in Federal waters between the centroid of the three 

lightering areas and Galveston, Texas, divided by the average escort vessel speed (12 miles an 
6-73 

hour) (Systems Applications International et al. 1995). The tanker operating time and the escort 

vessel time are summarized in Table 6-22. 

Table 6-22 

Lightering Times 

Tanker operating days 1,900 days

Tanker operating hrs 45,600 hours

Escort trip hrs 4,494 days

The emission factors used are presented in Table 6-1; assumptions about engine 

horsepower and load factors that were obtained from the Gulf of Mexico Air Quality Study

(Systems Applications International et al. 1995) are presented in Table 6-23. 

Table 6-23 

Lightering Vessel Characteristics 

Type 

Avg. 

kW Load Factor – Idling Load Factor – At Sea 

Large Oil Tanker 25,592 0.1 -- 

Escort 12,412 0.1 0.8 

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: 

The total hours of operation of large oil tankers were 93,696. The average kW rating is 

25,592, load factor is 0.1 for idling mode, and the emission factor for NOx is 13.6 g/kWh. These 

data can be applied to the marine vessel equation presented in Section 6.1.1. 

E = AH × kW × LF × EF × CF 

E = 45,600 × 25,592 × 0.1 × 13.6 × 1.10231 × 10-6

E = 1,749.49 tons of NOx

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 also were collected to quantify ballasting and 

estimate evaporative emissions using the equations listed below: 
6-74 

Evaporative Lightering: 

Ev = PT × TOCc × VOC/TOC conversion factor 

where: 

Ev = Evaporative emissions (tons) 

PT = Annual amount of product transferred (gallons) 

TOCc = Total organic compound content of crude oil (0.86 lb of TOC/103

 gal of 

 crude oil) 

VOC/TOC = TOC to VOC conversion factor (0.85) 

Evaporative Ballasting: 

Eb = Cap × 0.40 × TOCc × VOC/TOC 

where: 

Eb = Ballasting emissions (tons) 

Cap = Capacity (gallons) 

0.40 = Percent of capacity (percent) 

TOCc = Total organic compound content of crude oil (0.86 lb of VOC/103

 gal of 

 crude oil) 

VOC/TOC = TOC to VOC conversion factor (0.85) 

No monthly vessel lightering data were identified in this effort; it was assumed that 

activity was consistent through out the year; therefore, annual emissions estimates were 

temporality apportioned to individual months equally (i.e., 8.33 percent). 

Tanker, escort idling, and evaporative emissions were assigned to the center of the 

lightering zones. Escort underway emissions were assigned to the shipping lanes that line the 

lightering zones to the port of Galveston/Houston as noted in Figure 6-10. 
6-75 

Figure 6-10. Centroid of the vessel lightering zone and shipping lane to Galveston.
7-1 

7. DEVELOPMENT OF THE DIURNAL EMISSIONS CURVES 

7.1 INTRODUCTION 

Diurnal emission curves allow inventory emission estimates for a given category to be 

temporally allocated, across a 24-hour time period, on a 1-hour basis. Hour-by-hour emission 

estimates of this nature are required in order to run advanced photochemical simulation models 

such as the Urban Airshed Model. State agencies and the USEPA may run such models, 

inclusive of Gulf of Mexico offshore sources, to address ozone and regional haze issues. 

Source operations (and in turn their emissions) are, by their nature, inherently continuous 

and reasonably uniform or intermittent and non-uniform. For example, production processes are 

typically continuous (24 hours/day) and consistent because companies want to maximize the 

utilization of resources and obtain as much return on their investment as possible. Fluctuating 

operational levels are not consistent with these missions. 

Other source types that are not directly production-driven may only operate to fulfill a 

specific need and may have an operation that is limited by other physical conditions (e.g., is only 

done in daylight). Meteorological conditions, for example, may also affect a source’s daily 

temporal profile (e.g., higher temperatures at mid day could mean higher emissions than at 

midnight). 

The ERG developed diurnal emission curves for all sources in this study, platform as well 

as non-platform. Since the objective of having diurnal profiles is to support photochemical 

modeling, the temporal profiles presented in this section are for a typical day in August, during 

the ozone season. Like onshore situations, the Gulf of Mexico offshore source population 

consists of stationary point sources, and various mobile and natural source types. 

7.2 APPROACH 

The Gulfwide study source population consists of point sources, mobile sources, and 

natural sources. Because it is infeasible to survey every individual piece of equipment in the 

study area, offshore industry trends in daily operation were developed for a subset of sources 

within each major category grouping. This information was then applied to the category as a 

whole. 

The temporal profiles presented here were developed for a typical day in the ozone 

season. In a typical summer day, activity for production platforms, drilling, tanker-shipping, 

space cooling, drill rig mobilization, and setting of new platforms were expected to be fairly 

continuous on a 24-hour basis. This would be especially true for the latter two categories, since 

companies want to maximize such activities during the good summer weather months. Activities 

such as helicopter traffic and supply boats are not continuous and generally cycle in conjunction 

with daylight hours. 

The ERG obtained the temporal profiling data from a number of sources. Activity levels 

and diurnal variations are best determined through surveys or estimated using engineering 
7-2 

judgement by people familiar with the sources. Direct monthly survey data are available for 

platform equipment: the monthly hours of operation for each piece of equipment were provided 

by platform operators through GOADS data collection. 

For non-platform sources, information was derived from published industry statistics and 

the 1995 MMS study Gulf of Mexico Air Quality Study (Systems Applications International et al. 

1995). COMM Engineering provided information on the daily operational patterns and 

characteristics of the sources based on their permitting experience with offshore oil and gas 

operations. Lastly, default allocation algorithms and values were obtained from USEPA 

guidance documents dealing with modeling inventories and modeling requirements for the ozone 

and PM2.5 National Ambient Air Quality Standards (NAAQS) (USEPA 1991, 1999, 2001). 

These guidance documents are designed to help inventory preparers determine hourly emissions. 

7.3 SOURCE CATEGORY GROUPINGS AND DIURNAL PATTERNS 

The following platform operations are estimated to have essentially constant and uniform 

operation, with no significant variation in emissions throughout a 24-hour ozone season day 

(Figure 7-1). The assumed uniform operations for the platform sources are based on information 

provided by COMM Engineering and in the USEPA report Procedures for the Preparation of 

Emission Inventories for Carbon Monoxide and Precursor’s of Ozone (USEPA 2001): 

• Amine units 

• Drilling operations 

• Combustion flares 

• Fugitive emissions 

• Glycol dehydrators 

• Losses from flashing 

• Mud degassing 

• Pneumatic pumps 

• Pressure and level controllers 

• Cold vents 

The following non-platform operations are also estimated to have essentially constant and 

uniform operations. For the most part, the assumed uniform operation for these sources is based 

on information in the Gulf of Mexico Air Quality Study (Systems Applications International et al. 

1995): 

• Commercial marine vessels 

• LOOP activities 

• Military vessels 

• Oceangoing barges 

• Survey and exploration vessels 

7-4

Figures 7-2 and 7-3 represent diurnal emission curves for equipment groups that have 

slight diurnal variation: boilers/heaters/burners, internal combustion engines, and turbines. 

Diurnal curves are expressed as the percentage of total emissions that occur at each 1-hour 

interval for each emission source. Temporal profiles from the USEPA were used to calculate 

these percentages (USEPA, 2001). 

Figure 7-4 presents the diurnal curve for source categories whose variation is 

temperature-driven throughout a 24-hour ozone season day: 

• Biogenic Ocean Processes 

• Oil Seeps 

• Storage Tanks 

This curve is based on the fluctuation in average air and water temperature 

(recommended by COMM Engineering) in the Gulf of Mexico (USDOC, NOAA 2001), as 

shown in Figure 7-5. 

Figure 7-6 presents the diurnal curve for two non-platform operations which average 21 

hours of operation per day. This information is based on an offshore operators committee survey, 

as summarized in the Systems Applications International et al. 1995 report. No further 

information was found for these operations. The curve assumes no significant activity between 

the hours of midnight and three a.m. This assumption is simply based on “engineering 

judgement.” 

• Helicopters 

• Support Vessels - Crew Boats, Supply Boats, Tugs, Barges

Table 7-1 presents the hourly data as a percent of total emissions for each equipment 

group, and a short explanation as to the data sources used to develop the pattern. Table 7-2 

presents the Source Classification Codes (SCCs) used to develop the curves from the report 

Procedures for the Preparation of Emission Inventories for Carbon Monoxide and Precursor’s 

of Ozone (USEPA 2001). 





7-10

Table 7-1 

Diurnal Emission Percentages for Activity Groups 

Percentage of Emissions (%) 

Hour 

(Local 

Time) 

Constant 

Activity 

Sources1

Boiler/Heater/ 

Burners2

Natural Gas 

Turbines 

and ICEs3

TemperatureDependent 

Sources4

Helicopters & 

Supply Vessels5

0 4.17 3.98 4.04 4.16 4.76 

1 4.17 3.89 3.98 4.15 0.00 

2 4.17 3.82 3.93 4.15 0.00 

3 4.17 3.79 3.91 4.14 0.00 

4 4.17 3.78 3.90 4.14 4.76 

5 4.17 3.80 3.92 4.13 4.76 

6 4.17 3.87 3.97 4.12 4.76 

7 4.17 3.98 4.04 4.11 4.76 

8 4.17 4.13 4.14 4.13 4.76 

9 4.17 4.21 4.20 4.14 4.76 

10 4.17 4.29 4.25 4.16 4.76 

11 4.17 4.35 4.29 4.17 4.76 

12 4.17 4.37 4.31 4.18 4.76 

13 4.17 4.39 4.32 4.19 4.76 

14 4.17 4.40 4.33 4.20 4.76 

15 4.17 4.42 4.34 4.21 4.76 

16 4.17 4.41 4.33 4.21 4.76 

17 4.17 4.40 4.33 4.21 4.76 

18 4.17 4.38 4.31 4.21 4.76 

19 4.17 4.34 4.29 4.19 4.76 

20 4.17 4.33 4.28 4.18 4.76 

21 4.17 4.31 4.27 4.17 4.76 

22 4.17 4.24 4.21 4.17 4.76 

23 4.17 4.11 4.13 4.16 4.76 

1

 Using information provided by Systems Applications International et al. (1995), temporal profiles 

 from USEPA (2001), and by engineering judgement, hourly emissions are assumed to be constant 

 and uniform 

2 Temporal profiles from USEPA (2001) were used to calculate these percentages for boilers, heaters, 

 and burners 

3 Temporal profiles from USEPA (2001) were used to calculate these percentages for natural gas 

 turbines 

4 Hourly temperature data were retrieved from NOAA to create a profile for sources dependent upon 

temperature 

5 Using information provided by Systems Applications International et al. (1995) and by engineering 

judgement, activities for these sources are assumed to operate continuously from 4 a.m. to midnight. 
7-11 

Table 7-2 

SCCs of Interest for Platform Operations (diurnal patterns) 

BOEM Group 

Category SCC SCC DESCRIPTION 

Amine Units 3-10-002-01 Industrial Processes: Oil and Gas Production - Natural Gas Production, Gas Sweetening: Amine Proc

3-10-003-05 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Gas Sweeting: Ami

 1-01-006-01 External Combustion Boilers: Electric Generation - Natural Gas, Boilers > 100 Million Btu/hr except  1-01-006-02 External Combustion Boilers: Electric Generation - Natural Gas, Boilers < 100 Million Btu/hr except  1-01-006-04 External Combustion Boilers: Electric Generation - Natural Gas, Tangentially Fired Units  1-010-07-01 External Combustion Boilers: Electric Generation - Process Gas, Boilers > 100 Million Btu/hr  1-010-07-02 External Combustion Boilers: Electric Generation - Process Gas, Boilers < 100 Million Btu/hr  1-020-06-01 External Combustion Boilers: Industrial - Natural Gas, > 100 Million Btu/hr  1-020-06-02 External Combustion Boilers: Industrial - Natural Gas, 10-100 Million Btu/hr 

 1-020-06-03 External Combustion Boilers: Industrial - Natural Gas, < 10 Million Btu/hr 

Boilers/Heaters/ 1-020-06-04 External Combustion Boilers: Industrial - Natural Gas, Cogeneration 

Burners 1-020-07-01 External Combustion Boilers: Industrial - Process Gas, Petroleum Refinery Gas 

 1-03-006-01 External Combustion Boilers: Commercial/Institutional - Natural Gas, > 100 Million Btu/hr  1-030-06-02 External Combustion Boilers: Commercial/Institutional - Natural Gas, 10-100 Million Btu/hr  1-030-06-03 External Combustion Boilers: Commercial/Institutional - Natural Gas, < 10 Million Btu/hr  3-100-04-04 Industrial Processes: Oil and Gas Production - Process Heaters, Natural Gas  3-100-04-05 Industrial Processes: Oil and Gas Production - Process Heaters, Process Gas  3-100-04-14 Industrial Processes: Oil and Gas Production - Process Heaters, Natural Gas: Steam Generators  3-100-04-15 Industrial Processes: Oil and Gas Production - Process Heaters, Process Gas: Steam Generators 

Drilling 3-100-01-22 Industrial Processes: Oil and Gas Production - Crude Oil Production, Drilling and Well Completion 3-100-02-22 Industrial Processes: Oil and Gas Production - Natural Gas Production, Drilling and Well Completion 

Flares 

3-100-01-60 Industrial Processes: Oil and Gas Production - Crude Oil Production, Flares 3-100-02-05 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flares 3-100-02-15 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flares Combusting Gases >103-100-02-16 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flares Combusting Gases <10

 3-100-01-01 Industrial Processes: Oil and Gas Production - Crude Oil Production, Complete Well: Fugitive Emiss 3-100-01-24 Industrial Processes: Oil and Gas Production - Crude Oil Production, Valves: General  3-100-01-25 Industrial Processes: Oil and Gas Production - Crude Oil Production, Relief Valves 
7-12 

Table 7-2. SCCs of Interest for Platform Operations (diurnal patterns) (continued).

BOEM Group 

Category SCC SCC DESCRIPTION 

Fugitives

(Continued) 3-100-01-26 Industrial Processes: Oil and Gas Production - Crude Oil Production, Pump Seals 

 3-100-01-27 Industrial Processes: Oil and Gas Production - Crude Oil Production, Ranges and Connections 

3-100-01-30 Industrial Processes: Oil and Gas Production - Crude Oil Production, Fugitives: Compressor Seals 3-100-01-31 Industrial Processes: Oil and Gas Production - Crude Oil Production, Fugitives: Drains 3-100-02-07 Industrial Processes: Oil and Gas Production - Natural Gas Production, Valves: Fugitive Emissions 3-10-002-02 Industrial Processes: Oil and Gas Production - Natural Gas Production, All Equipment Leak Fugitive

Connections, Seals, Drains) 

3-100-02-23 Industrial Processes: Oil and Gas Production - Natural Gas Production, Relief Valves 3-100-02-24 Industrial Processes: Oil and Gas Production - Natural Gas Production, Pump Seals 3-100-02-25 Industrial Processes: Oil and Gas Production - Natural Gas Production, Compressor Seals 3-100-02-26 Industrial Processes: Oil and Gas Production - Natural Gas Production, Flanges and Connections 3-100-02-31 Industrial Processes: Oil and Gas Production - Natural Gas Production, Fugitives: Drains 3-100-03-06 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Process Valves 3-100-03-07 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Relief Valves 3-100-03-08 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Open-ended Lines 3-100-03-09 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Compressor Seals 3-100-03-10 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Pump Seals 3-100-03-11 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Flanges and Connec3-100-02-27 Industrial Processes: Oil and Gas Production - Natural Gas Production, Glycol Dehydrator Reboiler S3-100-02-28 Industrial Processes: Oil and Gas Production - Natural Gas Production, Glycol Dehydrator Reboiler B3-100-03-01 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

Triethylene Glycol 

3-100-03-02 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

Triethylene Glycol 

Glycol 

Dehydrators 3-100-03-03 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

Triethylene Glycol 

3-100-03-04 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

General 

3-100-03-21 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

(Mich.) 
7-13 

Table 7-2. SCCs of Interest for Platform Operations (diurnal patterns) (continued).

BOEM Group 

Category SCC SCC DESCRIPTION 

3-100-03-22 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

Formation (Mich.) 

3-100-03-23 Industrial Processes: Oil and Gas Production - Natural Gas Processing Facilities, Glycol Dehydrators: 

(Mich.) 

3-100-01-32 Industrial Processes: Oil and Gas Production - Crude Oil Production, Atmospheric Wash Tank (2nd St

Separation): Flashing Loss 

Losses from 

Flashing 4-04-003-12 Petroleum and Solvent Evaporation: Petroleum Liquids Storage (non-Refinery) – Oil and Gas Field S

Tanks, Fixed Roof Tank, Crude Oil, working+breathing+flashing losses 

4-04-003-22 Petroleum and Solvent Evaporation: Petroleum Liquids Storage (non-Refinery) – Oil and Gas Field S

Tanks, External Floating Roof Tank, Crude Oil, working+breathing+flashing 

4-04-003-32 Petroleum and Solvent Evaporation: Petroleum Liquids Storage (non-Refinery) – Oil and Gas Field S

Tanks, Internal Floating Roof Tank, Crude Oil, working+breathing+flashing 

Natural Gas 

Turbines 2-010-02-01 Internal Combustion Engines: Electric Generation - Natural Gas, Turbine 

and ICEs 2-010-02-08 Internal Combustion Engines: Electric Generation - Natural Gas, Turbine: Evaporative Losses (Fuel D

2-010-02-09 Internal Combustion Engines: Electric Generation - Natural Gas, Turbine: Exhaust 2-02-002-01 Internal Combustion Engines: Industrial - Natural Gas, Turbine 2-02-002-03 Internal Combustion Engines: Industrial - Natural Gas, Turbine: Cogeneration 2-02-002-08 Internal Combustion Engines: Industrial - Natural Gas, Turbine: Evaporative Losses (Fuel Delivery S2-02-002-09 Internal Combustion Engines: Industrial - Natural Gas, Turbine: Exhaust 2-03-002-02 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine 2-03-002-03 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine: Cogeneration 2-03-002-04 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Cogeneration 2-03-002-05 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Reciprocating: Crankcase Blow2-03-002-06 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Reciprocating: Evaporative Lo

System) 

2-03-002-07 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Reciprocating: Exhaust 2-03-002-08 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine: Evaporative Losses (F2-03-002-09 Internal Combustion Engines: Commercial/Institutional - Natural Gas, Turbine: Exhaust 
8-1 

8. RESULTS 

8.1 SUMMARY OF STUDY APPROACH 

This BOEM Year 2008 Gulfwide Emission Inventory Study includes all major oil and gas 

production platforms and non-platform sources in the Central and Western Gulf of Mexico 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. 

The BOEM attempted to collect activity data from each active major offshore oil and gas 

production platform in the Gulf of Mexico on the OCS. Operators were provided with the 

GOADS-2008 Visual Basic activity data collection software for compiling monthly data for 

calendar year 2008. A total of 3,026 oil and gas production platforms submitted monthly 

equipment activity data files. The platform equipment surveyed includes: 

• Amine units 

• Boilers/heaters/burners 

• Diesel engines 

• Drilling equipment 

• Combustion flares 

• Fugitive sources 

• Glycol dehydrators 

• Losses from flashing 

• Minor sources 

• Mud degassing 

• Natural gas engines 

• Natural gas 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 

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. 
8-2 

Emission estimates were also developed for criteria air pollutants and greenhouse gases 

for non-platform sources operating in the Gulf of Mexico on the OCS for the 2008 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 

• LOOP 

• Military vessels (Coast Guard/Navy) 

• Vessel lightering 

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 used to calculate the vessel emissions from the engines were 

obtained from a study performed by the Swedish Environmental Protection Agency (SEPA 

2004). The resulting non-platform emission estimates were then disaggregated into BOEM lease 

blocks, suitable for use in air quality modeling applications. 

8.2 PRESENTATION OF ANNUAL EMISSION ESTIMATES 

The platform and non-platform emission estimates developed for criteria pollutants and 

greenhouse gases are presented in Tables 8-1 through 8-12. For an overview of the results, 

Table 8-1 summarizes the total platform criteria pollutant emission estimates, Table 8-2 

summarizes the total non-platform criteria pollutant emission estimates, and Table 8-3 presents 

the combined platform and non-platform criteria pollutant estimates. To facilitate more detailed 

review, Tables 8-4 through 8-9 present platform and non-platform emission estimates by 

pollutant. 

The greenhouse emission estimates are provided in Tables 8-10, 8-11, and 8-12. 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
8-3 

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. 

Table 8-1 

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 3 1 

Boilers/heaters/ 

Burners 542 910 22 13 8 35 

Diesel Engines 1,808 7,427 306 305 711 351 

Drilling Equipment 545 2,060 37 36 260 51 

Combustion Flares 1,304 254 2 2 2 22 

Fugitives 0 0 0 0 0 21,476 

Glycol Dehydrators 0 0 0 0 0 2,573 

Losses From Flashing 0 0 0 0 0 950 

Minor Sources 0 0 0 0 0 213 

Mud Degassing 0 0 0 0 0 25 

Natural Gas Engines 75,103 52,538 250 250 15 1,310 

Natural Gas Turbines 2,844 11,096 66 66 21 73 

Pneumatic Pumps 0 0 0 0 0 1,893 

Pressure/level 

Controllers 0 0 0 0 0 3,939 

Storage Tanks 0 0 0 0 0 909 

Cold Vents 0 0 0 0 0 27,003 

Total Emissions (tpy)a82,146 74,286 682 672 1,021 60,824 

a Totals may not sum due to rounding.
8-4 

Table 8-2 

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 5,343 58,288 971 971 7,772 971 

Pipelaying 

Operations 2,186 10,535 398 398 1,789 398 

Support Helicopters 13,636 1,114 217 217 275 2,693 

Support Vessels 12,880 135,222 2,342 2,342 18,221 2,342 

Survey Vessels 141 1,690 26 26 204 26 

Total OCS Oil/Gas 

Production Sources 

(tpy) 34,186 206,849 3,954 3,954 28,261 6,430 

Biogenic and 

Geogenic Sources 0 0 0 0 0 14,358 

Commercial Fishing 

Vessels 681 8,120 124 124 988 124 

Commercial Marine 

Vessels 6,593 79,329 6,603 6,080 49,009 2,794 

LOOP 136 1,832 33 33 219 613 

Military Vessels 702 8,539 158 158 1,409 130 

Vessel Lightering 320 3,060 86 86 397 4,423 

Total Non-OCS 

Oil/Gas Production 

Sources (tpy) 8,432 100,880 7,004 6,481 52,022 22,442 

Total Non-Platform 

Emissions (tpy)a 42,618 307,729 10,958 10,435 80,283 28,872 

a Totals may not sum due to rounding. 
8-5 

Table 8-3 

Total Platform and Non-Platform Emission Estimates for Criteria Pollutants

Equipment/ 

Source Category 

CO 

Emissions 

(tpy) 

NOx

Emissions 

(tpy) 

PM10

Emissions 

(tpy) 

PM2.5

Emissions 

(tpy) 

SO2 

Emissions 

(tpy) 

VOC 

Emissions 

(tpy) 

Total Platform 

Emissions 82,146 74,286 682 672 1,021 60,824 

Drilling Rigs 5,343 58,288 971 971 7,772 971 

Pipelaying 

Operations 2,186 10,535 398 398 1,789 398 

Support Helicopters 13,636 1,114 217 217 275 2,693 

Support Vessels 12,880 135,222 2,342 2,342 18,221 2,342 

Survey Vessels 141 1,690 26 26 204 26 

Total OCS Oil/Gas 

Production Source 

Emissions 116,332 281,135 4,636 4,626 29,282 67,254 

Total Non-OCS 

Oil/Gas Production 

Source Emissions 8,432 100,880 7,004 6,481 52,022 22,442 

Total Emissions 

(tpy)a 124,764 382,015 11,640 11,107 81,304 89,696 

a Totals may not sum due to rounding. 
8-6 

Table 8-4 

Annual CO Emission Estimates for All Sources 

Equipment/Source Category 

CO 

Emissions 

(tpy) 

Natural Gas Engines 75,103 

Support Helicopters 13,636 

Support Vessels 12,880 

Commercial Marine Vessels 6,593 

Drilling Rigs 5,343 

Natural Gas Turbines 2,844 

Pipelaying Operations 2,186 

Diesel Engines 1,808 

Combustion Flares 1,304 

Military Vessels 702 

Commercial Fishing Vessels 681 

Drilling Equipment 545 

Boilers/heaters/burners 542 

Vessel Lightering 320 

Survey Vessels 141 

LOOP 136 

Total Emissions (tpy)a 124,764 

a Totals may not sum due to rounding.
8-7 

Table 8-5 

Annual NOx Emission Estimates for All Sources 

Equipment/Source Category 

NOx

Emissions 

(tpy) 

Support Vessels 135,222 

Commercial Marine Vessels 79,329 

Drilling Rigs 58,288 

Natural Gas Engines 52,538 

Natural Gas Turbines 11,096 

Pipelaying Operations 10,535 

Military Vessels 8,539 

Commercial Fishing Vessels 8,120 

Diesel Engines 7,427 

Vessel Lightering 3,060 

Drilling Equipment 2,060 

LOOP 1,832 

Survey Vessels 1,690 

Support Helicopters 1,114 

Boilers/heaters/burners 910 

Combustion Flares 254 

Total Emissions (tpy)a382,015 

a Totals may not sum due to rounding.
8-8 

Table 8-6 

Annual PM10 Emission Estimates for All Sources 

Equipment/Source Category 

PM10

Emissions 

(tpy) 

Commercial Marine Vessels 6,603 

Support Vessels 2,342 

Drilling Rigs 971 

Pipelaying Operations 398 

Diesel Engines 306 

Natural Gas Engines 250 

Support Helicopters 217 

Military Vessels 158 

Commercial Fishing Vessels 124 

Vessel Lightering 86 

Natural Gas Turbines 66 

Drilling Equipment 37 

LOOP 33 

Survey Vessels 26 

Boilers/heaters/burners 22 

Combustion Flares 2 

Total Emissions (tpy)a11,640 

a Totals may not sum due to rounding.
8-9 

Table 8-7 

Annual PM2.5 Emission Estimates for All Sources 

Equipment/Source Category 

PM2.5

Emissions 

(tpy) 

Commercial Marine Vessels 6,080 

Support Vessels 2,342 

Drilling Rigs 971 

Pipelaying Operations 398 

Diesel Engines 305 

Natural Gas Engines 250 

Support Helicopters 217 

Military Vessels 158 

Commercial Fishing Vessels 124 

Vessel Lightering 86 

Natural Gas Turbines 66 

Drilling Equipment 36 

LOOP 33 

Survey Vessels 26 

Boilers/heaters/burners 13 

Combustion Flares 2 

Total Emissions (tpy)a11,107 

a Totals may not sum due to rounding. 
8-10 

Table 8-8 

Annual SO2 Emission Estimates for All Sources 

Equipment/Source Category 

SO2 

Emissions 

(tpy) 

Commercial Marine Vessels 49,009 

Support Vessels 18,221 

Drilling Rigs 7,772 

Pipelaying Operations 1,789 

Military Vessels 1,409 

Commercial Fishing Vessels 988 

Diesel Engines 711 

Vessel Lightering 397 

Support Helicopters 275 

Drilling Equipment 260 

LOOP 219 

Survey Vessels 204 

Natural Gas Turbines 21 

Natural Gas Engines 15 

Boilers/heaters/burners 8 

Amine Units 3 

Combustion Flares 2 

Total Emissions (tpy)a81,304 

a Totals may not sum due to rounding.
8-11 

Table 8-9 

Annual VOC Emission Estimates for All Sources 

Equipment/Source Category 

VOC 

Emissions 

(tpy) 

Cold Vents 27,003 

Fugitives 21,476 

Biogenic and Geogenic Sources 14,358 

Vessel Lightering 4,423 

Pressure/level Controllers 3,939 

Glycol Dehydrators 2,573 

Commercial Marine Vessels 2,794 

Support Helicopters 2,693 

Support Vessels 2,342 

Pneumatic Pumps 1,893 

Natural Gas Engines 1,310 

Drilling Rigs 971 

Losses From Flashing 950 

Storage Tanks 909 

Pipelaying Operations 398 

Diesel Engines 351 

Minor Sources 213 

Military Vessels 130 

Commercial Fishing Vessels 124 

Natural Gas Turbines 73 

Drilling Equipment 51 

Boilers/heaters/burners 35 

LOOP 40 

Survey Vessels 26 

Mud Degassing 25 

Combustion Flares 22 

Amine Units 1 

Total Emissions (tpy)a89,696 

a Totals may not sum due to rounding.
8-12 

Table 8-10 

Total Greenhouse Gas Emission Estimates for Platform Sources 

Equipment Types 

CO2 Emissions 

(tpy) 

CH4 Emissions 

(tpy) 

N2O Emissions 

(tpy) 

CO2e Emissions 

(tpy) 

Amine Units 0 8 0 171 

Boilers/heaters/burners 850,228 14 14 854,806 

Diesel Engines 335,392 10 N/A 335,608 

Drilling Equipment 106,250 N/Aa N/A 106,250 

Combustion Flares 419,083 442 7 430,640 

Fugitive Sources 0 91,468 0 1,920,838 

Glycol Dehydrators N/A 19,505 N/A 409,615 

Losses From Flashing 475 20,890 0 439,169 

Minor Sources 0 646 0 13,561 

Mud Degassing 1 194 0 4,076 

Natural Gas Engines 2,886,612 12,244 N/A 3,143,735 

Natural Gas Turbines 3,814,880 298 104 3,853,392 

Pneumatic Pumps 414 20,426 0 429,355 

Pressure/level Controllers 580 31,448 0 660,988 

Storage Tanks 0 901 0 18,919 

Cold Vents 3,251 224,211 0 4,711,689 

Total Emissions (tpy)b8,417,165 422,707 125 17,332,814 

a

N/A = not available

b Totals may not sum due to rounding.
8-13 

Table 8-11 

Total Greenhouse Gas Emission Estimates for Non-Platform Sources 

Source Category 

CO2 Emissions 

(tpy) 

CH4 Emissions 

(tpy) 

N2O Emissions 

(tpy) 

CO2e Emissions 

(tpy) 

Biogenic and Geogenic 

Sources 2,284 1,874 1,948 645,518 

Commercial Fishing 402,437 2 19 408,369 

Commercial Marine 

Vessels 3,013,948 N/Aa N/A 3,013,948 

Drilling Rigs 3,166,971 19 151 3,214,188 

LOOP 88,564 1 4 89,825 

Military Vessels 417,677 3 20 423,940 

Pipelaying Operations 712,570 8 31 722,348 

Support Helicopters 1,373,574 N/A N/A 1,373,574 

Support Vessels 7,418,855 47 352 7,528,962 

Survey Vessels 83,500 1 4 84,761 

Vessel Lightering 160,038 2 7 162,250 

Total Emissions (tpy)b16,840,418 1,957 2,536 17,667,683 

a

N/A = Not available

b

Totals may not sum due to rounding 

Table 8-12 

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) 

Total Platform Emissions 8,417,165 422,707 125 17,332,814 

Drilling Rigs 3,166,971 19 151 3,214,188 

Pipelaying Operations 712,570 8 31 722,348 

Support Helicopters 1,373,574 N/Aa N/A 1,373,574 

Support Vessels 7,418,855 47 352 7,528,962 

Survey Vessels 83,500 1 4 84,761 

Total OCS Oil/Gas 

Production Source 

Emissions 21,172,635 422,782 663 30,256,647 

Total Non-OCS Oil/Gas 

Production Source 

Emissions 4,084,948 1,882 1,998 4,743,850 

Total Emissions (tpy)a25,257,583 424,664 2,661 35,000,497 

a

N/A = Not available

b

Totals may not sum due to rounding.
8-14 

8.3 LIMITATIONS 

The key limitations associated with the 2008 OCS platform emission estimates are most 

directly associated with the lack of direct source test data. The BOEM requires that platform 

operators provide only activity data for sources such as fugitives, amine units, glycol 

dehydrators, losses from flashing, and cold vents. The BOEM then applies emission factors to 

the activity data to yield emission estimates. The requirement that platform operators submit 

source test data, or calculated emission estimates based on industry-developed software, at least 

for key emission sources, 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. 

As discussed in the report for the Year 2005 Gulfwide Emission Inventory Study (Wilson 

et al. 2007), the ERG investigated the possibility that NOx emission estimates from combustion 

equipment on offshore platforms may need to be adjusted to take into consideration the impact of 

humidity in reducing NOx emissions. Based on the studies reviewed, it was concluded that the 

information available for combustion equipment in the inventory was not sufficient to develop 

NOx correction factors with any reasonable level of certainty at this time. The studies indicated 

that the application of correction factors could result in emission reductions of less than 10% for 

affected sources. 

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 marine diesel engines were developed using the same set of 

emission factors used in the Year 2005 Gulfwide Emission Inventory Study (Wilson et al. 2007). 

The marine vessel emission factors for NOx, CO, SO2, VOC, CH4, and N2O have uncertainty 

ratings between 10 and 20%. The PM emission factors have uncertainty ratings between 20 and 

50%. For this study, the ERG developed an updated compilation of helicopter emission factors 

using the latest FAA emission factors, which allowed for the removal or replacement of some of 

the older emission factors. 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 Gulf of 

Mexico. 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. Actual 

emissions could be significantly different than the values estimated in this study. To get a more 

accurate estimate of helicopter emissions, it would be necessary to get more details about the 

Gulf fleet and it operations. 

For some source categories such as the LOOP and vessel lightering, activity data that 

previously had been available to the public are no longer available, such that detailed matching 

of vessels and their operations is not possible. Due to the proprietary nature of survey data for the 

Gulf of Mexico, geophysical survey vessel emissions were allocated to each lease block based on 

the surface area of the lease block. This approach will overestimate emissions where geophysical 

surveys were not implemented and underestimate emissions where surveys were implemented. 

The unavailability of up-to-date vessel data for the US Navy, especially where Naval and 
8-15 

possibly some Coast Guard vessels have been moved away from the Gulf of Mexico, make it 

difficult to accurately assess emissions from these vessels. 

The ERG used commercial marine vessel emission data from the USEPA (Carey 2009a, 

2009b). These data were developed in support of the Category 3 vessel regulations; use of these 

data are considered appropriate for the BOEM inventory because these large vessels tend to 

operate further out to sea in Federal waters (USEPA 2009a). The USEPA emission estimates do 

not include smaller vessels, which are assumed to operate primarily in State waters. The ERG 

was able to separately account for the operation of smaller vessels in Federal waters, specifically 

fishing boats, support vessels, drilling rigs, ships involved in pipelaying, and geophysical survey 

vessels. But small bulkers, tankers and containerships that may operate in Federal waters are not 

accounted for in this inventory, and at this time it is uncertain to what portion of these vessels 

operate in Federal waters. 

One last limitation to note is that while this inventory provides emission estimates for 

directly-emitted pollutants, it does not take into account changes of the emissions due to inplume 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. Such transformation of pollutants 

will need to be modeled in order to account for all factors that impact the transformation rate. 

8.4 COMPARISON WITH OTHER STUDIES 

Now that the 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 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 base 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 base year 2005 and the base 

year 2008 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 nonplatform sources are presented in Table 8-13 (for criteria pollutants) and Table 8-14 (for 

greenhouse gases). For criteria pollutants, the overall CO and NOx emission estimates vary 

slightly from 2005 to 2008. A slight difference is seen in the VOC emission estimates. Large 

differences are seen, however, in the PM10 estimates (91% increase) and SO2 estimates (100% 

increase). For greenhouse gases, the overall CO2 and N2O emission estimates vary slightly from 

2005 to 2008. A very pronounced increase is seen in the CH4 (96%) estimates. The following 

sections examine these differences for the platform and non-platform emission estimates. 
8-16 

Table 8-13 

Comparison of Total Platform and Non-Platform Criteria Pollutant 

for Base Years 2008 and 2005 Emission Estimates 

Base 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 

2005 122,295 392,961 6,088 40,559 80,933 

Percent 

Difference 2% -3% 91% 100% 11% 

Table 8-14 

Comparison of Total Platform and Non-Platform Greenhouse Gas 

Emission Estimates for Base Years 2008 and 2005 

Base Year 

CO2

Emissions 

(tpy) 

CH4

Emissions 

(tpy) 

N2O 

Emissions 

(tpy) 

CO2e 

Emissions 

(tpy) 

2008 25,257,583 424,664 2,661 35,000,497

2005 24,334,447 216,484 2,803 29,749,541

Percent 

Difference 4% 96% -5% 18% 

8.4.1 OCS Oil and Gas Production Platforms 

As noted previously, the emission estimation methods for platform sources are relatively 

unchanged between the 2005 and 2008 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 2005, 114 companies 

submitted data for 1,585 active platforms. In 2008, 113 companies submitted data for 3,026 

active platforms; 1,538 were flagged as minor sources. These sources are included in the 

inventory, but their emissions are insignificant. 

As shown in Table 8-15, for platform sources, the CO, NOx, and PM emission estimates 

show slight decreases in emissions from 2005 to 2008 (10% or less). The SO2 emission estimate, 

however, shows a 48% decrease. This decrease is primarily due to the amine unit emission 

estimates. The VOC emission estimate shows a 19% increase (up over 9,000 tons) from 2005 to 

2008. The majority of this increase is from vents, pneumatic pumps, pressure level controllers, 

glycol dehydrators, and fugitives. In contrast, a 12,000 ton VOC decrease was seen from 2000 to 

2005. The decrease seen in 2005 may be indicative of the severe hurricane activity in 2005, 

which impacted production operations, as numerous platforms were shut in for several months. 
8-17 

Table 8-16 presents a comparison of emission estimates for greenhouse gases in the 2008 

inventory and the 2005 inventory. The CO2 and N2O emission estimates are consistent with the 

2005 estimates. The CH4 estimates, however, almost doubled. Similar to the increase in the VOC 

emission estimate, this increase is from vents, pneumatic pumps, pressure level controllers, 

glycol dehydrators, and fugitives. 

The 2008 emission estimates for several types of platform equipment are similar to those 

in the 2005 inventory, including losses from flashing, diesel engines, natural gas engines, and 

natural gas turbines. Emission estimates for other equipment types, such as amine units, drilling 

equipment, and mud degassing show a decline in emissions, primarily due to decreased activity 

(or reported activity). For amine units, the almost 100% decrease in SO2 emissions is because 

one unit that was operating in 2005 (and equipped with a flare) is no longer operating. Drilling 

equipment emission estimates decreased approximately 50% for all pollutants, indicating a 

decrease in activity levels. Mud degassing VOC estimates thus show a similar percent decrease. 

Overall emission increases are seen in a number of equipment categories, including vents, 

fugitive sources, glycol dehydrators, pneumatic pumps, and pressure level controllers, as noted 

above; and boilers/heaters/burners and combustion flares. VOC emission estimates for vents 

increased 49%, fugitives sources 22%, glycol dehydrators 158%, pneumatic pumps 59%, and 

pressure level controllers over 300%. These increases are likely due to increased activity levels, 

combined with more complete reporting by the operators. For boilers/heaters/burners, the 2005 

and 2008 inventories have activity reported for a similar number of units, but the overall 2008 

activity level (i.e., amount of fuel combusted) increased, or different types of fuel were 

combusted. Similarly for combustion flares, the 2005 and 2008 inventories have activity reported 

for a similar number of units, but the overall 2008 activity level (i.e., volume flared) increased. 
8-18 

Table 8-15 

Comparison of Base Years 2008 and 2005 OCS Platform Criteria Pollutant Emission Estimat

2008 2005

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) 

E

Amine Units 0 0 0 3 1 0 0 0 Boilers/heaters/

Burners 542 910 22 8 35 456 780 10 

Diesel Engines 1,808 7,427 306 711 351 1,908 6,915 309 Drilling 

Equipment 545 2,060 37 260 51 1,174 4,420 79 

Combustion 

Flares 1,304 254 2 2 22 964 185 <1 

Fugitives 0 0 0 0 21,476 0 0 0 Glycol 

Dehydrators 0 0 0 0 2,573 0 0 0 

Loading Losses 0 0 0 0 0 0 0 0 Losses From 

Flashing 0 0 0 0 950 0 0 0 

Minor Sources 0 0 0 0 213Mud Degassing 0 0 0 0 25 0 0 0 Natural Gas 

Engines 75,103 52,538 250 15 1,310 82,073 57,647 272 

Natural Gas 

Turbines 2,844 11,096 66 21 73 3,237 12,633 75 

Pneumatic 

Pumps 0 0 0 0 1,893 0 0 0 

Pressure/level 

Controllers 0 0 0 0 3,939 0 0 0 

Storage Tanks 0 0 0 0 909 0 0 0 Cold Vents 0 0 0 0 27,003 0 0 0 Total Emissions 

(tpy)a 82,146 74,286 682 1,021 60,824 89,813 82,581 746 

a Totals may not sum due to rounding.
8-19 

Table 8-16 

Comparison of Base Years 2008 and 2005 OCS Platform Greenhouse Gas 

Emission Estimates

2008 2005

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) 

Amine Units 0 8 0 171 0 4 0 84 

Boilers/heaters/Burners 850,228 14 14 854,806 651,640 12 12 655,612 

Diesel Engines 335,392 10 N/Aa 335,608 305,921 8 N/A 306,089 

Drilling Equipment 106,250 N/A N/A 106,250 227,917 N/A N/A 227,917 

Combustion Flares 419,083 442 7 430,640 10,786 326 <1 17,632 

Fugitives 0 91,468 0 1,920,838 0 84,201 0 1,768,221 

Glycol Dehydrators N/A 19,505 N/A 409,615 N/A 6,811 N/A 143,031 

Losses From Flashing 475 20,890 0 439,169 435 19,149 0 402,564 

Minor Sources 0 646 0 13,561 N/A N/A N/A N/A 

Mud Degassing 1 194 0 4,076 1 316 0 6,637 

Natural Gas Engines 2,886,612 12,244 N/A 3,143,735 3,307,482 15,582 N/A 3,634,704 

Natural Gas Turbines 3,814,880 298 104 3,853,392 4,342,651 340 118 4,386,371 

Pneumatic Pumps 414 20,426 0 429,355 245 12,114 0 254,639 

Pressure/level 

Controllers 580 31,448 0 660,988 136 6,141 0 129,097 

Storage Tanks 0 901 0 18,919 0 N/A 0 N/A 

Cold Vents 3,251 224,211 0 4,711,689 1,565 69,494 0 1,460,939 

Total Emissions (tpy)b8,417,165 422,707 125 17,332,814 8,848,779 214,499 130 13,393,537 

a N/A = Not available 

b Totals may not sum due to rounding. 

Greenhouse gas emission estimates for platform equipment follow a similar trend to the 

criteria pollutant emission estimates—estimates for losses from flashing, diesel engines, natural 

gas engines, and natural gas turbines are relatively unchanged; estimates for drilling equipment, 

and mud degassing show a decline in emissions; and estimates for vents, fugitive sources, glycol 

dehydrators, pneumatic pumps, and pressure level controllers, boilers/heaters/burners, and 

combustion flares show an increase in emissions. 

8.4.2 Non-Platform Sources 

As shown in Table 8-17, for non-platform sources, the overall NOx and VOC emission 

estimates show slight differences in emissions from 2005 to 2008 (less than 2%). The CO 

emission estimate shows a 31% increase from 2005 to 2008, primarily from drilling rigs, 

helicopters, and commercial marine vessels. The increased PM and SO2 estimates, both over 

100%, are due to the commercial marine vessel estimates. All non-platform sources had larger 

greenhouse gas emissions than estimated in 2005, except for support vessels, which is indicative 

of a reduction in the Gulf fleet. The largest increase in greenhouse gas estimates for OCS oil/gas 

related sources is seen in the helicopter emission estimates, which is based on the updated 

helicopter emission factors, and drilling rigs, which is due to the increase in drilling activity 

between 2005 and 2008. 
8-20 

Table 8-17 

Comparison of Base Years 2008 and 2005 OCS Non-Platform Criteria Pollutant Emission Estim

2008 2005

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) 

Em

Drilling Rigs 5,343 58,288 971 7,772 971 3,372 36,787 613 Pipelaying 

Operations 2,186 10,534 398 1,789 398 2,016 9,714 367 

Support 

Helicopters 13,636 1,114 217 275 2,693 7,729 1,307 199 

Support Vessels 12,880 135,222 2,342 18,221 2,342 14,379 150,958 2,614 Survey Vessels 141 1,690 26 204 26 101 1,214 18 Total OCS 

Oil/Gas Production Sources (tpy) 34,186 206,849 3,954 28,261 6,430 25,597 199,979 3,812 

Biogenic and 

Geogenic Sources 0 0 0 0 14,358 0 0 0 

Commercial 

Fishing Vessels 681 8,120 124 988 124 89 1,009 16 

Commercial 

Marine Vessels 6,593 79,329 6,603 49,009 2,794 3,494 94,756 1,159 

LOOP 136 1,832 33 219 613 169 3,339 46 Military Vessels 702 8,539 158 1,409 130 492 5,213 135 Vessel 

Lightering 320 3,060 86 397 4,423 641 6,084 174 

Total Non-OCS 

Oil/Gas Production Sources (tpy) 8,432 100,880 7,004 52,022 22,442 4,885 110,402 1,530 

Total Non- Platform 

Emissions (tpy)a 42,618 307,729 10,958 80,283 28,872 32,482 310,380 5,342 

a Totals may not sum due to rounding.
8-21 

Table 8-18 

Comparison of 2008 and 2005 Drilling Days by Rig Type 

Base Year 

Barges 

(no. days) 

Drill Ships

(no. days) 

Jack-Ups 

(no. days) 

Semisubmersibles

(no. days) 

Submersibles

(no. days) 

Total 

(no. days) 

2008 933 1,642 18,900 8,504 997 30,976 

2005 241 1,344 10,451 705 5,620 18,361 

Percent Difference 287% 22.2% 80.8% 1,106% -82.3% 68.7% 

The 2008 criteria pollutant emission estimates for several non-platform categories are 

similar to those in the 2005 inventory, including pipelaying, biogenic and geogenic sources, and 

the LOOP. Some source categories, such as support vessels and vessel lightering, have declining 

emissions due to a 10% reduction in the fleet size and 42% reduced activity levels, respectively. 

Survey vessel emissions have increased 39% due to better information about the fleet and the 

actual number of days-at-sea that vessels typically operate. 

Emission estimates for 2008 are significantly different for several other non-platform 

categories including drilling rigs, helicopters, fishing vessels, CMVs, and military vessels. Based 

on the drilling rig data ERG received from the BOEM, activity increased in aggregate by 69% as 

noted in Table 8-18, which accounts for the increase in emissions for this source category. 

Helicopter activity declined slightly (5%) between 2005 and 2008, but the latest 

helicopter emission factors from the FAA EDMS are significantly different than those used in 

the 2005 Gulfwide Emission Inventory, as noted in Table 8-19. In general, the new helicopter 

emission factors are higher than the older ones for CO, VOC, and CO2. They are also higher for 

NOx and SO2 for single engine helicopters, but lower for light and medium duty helicopters. 

Table 8-19 

Comparison of 2008 and 2005 Helicopter Emission Factors 

Helicopter Type CO 

lb/LTO 

VOC 

lb/LTO 

NOx 

lb/LTO 

SO2

lb/LTO 

PM 

lb/LTO 

CO2

lb/LTO 

2008 

Single Engine Average 11.7 1.22 0.31 0.09 N/A 351 

Light Duty Average 11.9 7.85 1.44 0.36 0.918 1,774 

Medium Duty Average 16.8 6.60 4.56 1.07 0.918 5,762 

2005 

Single Engine Average 5.7 0.54 0.29 0.03 N/A 58 

Light Duty Average 9.6 6.17 2.24 0.96 0.918 269 

Medium Duty Average 11.4 4.94 5.68 2.46 0.918 689 
8-22 

For the 2000 Gulfwide Inventory, detailed information was provide by the National 

Marine Fisheries Service that quantified hours of operation for reef, shrimp and pelagic long line 

fishing operations. New data were provided for 2005 pelagic fishing, while reef and shrimp 

activity were adjusted using 2005 fish landing data for ports in the Central and Western areas of 

the Gulf of Mexico. For 2008, the National Marine Fisheries Service provided new activity data 

for all three types of fishing. The new activity data for the shrimp and reef fishing are 

significantly higher than that provided in previous efforts (see Table 8-20), but were confirmed 

by staff at the National Marine Fisheries Service. 

Table 8-20 

Comparison of 2008 and 2005 Activity Data for Shrimp and Reef Fish Operations 

Fishing Type 

2008 

Fishing 

Vessel 

Hours 

2005 

Fishing 

Vessel 

Hours 

Shrimp 1,393,926 189,441 

Reef Fish 888,120 94,804 

2008 CMV emission estimates were obtained from the USEPA to ensure that the 

emissions developed for the BOEM were consistent with emission estimates developed for 

recent rulemaking and the National Emission Inventory. The 2008 CMV emissions data provided 

by the USEPA were derived from recent regulatory programs related to vessels equipped with 

Category 3 propulsion engines. The USEPA regulatory impact assessment (USEPA 2009a) in 

support of these regulations includes a careful evaluation of the fuels used by large ocean going 

vessels, specifically the use of higher sulfur residual oil blends. The fuel usage assessments have 

allowed for better matching of vessel emission factors to the appropriate fuels. 

The 2005 Gulfwide inventory assumed a higher level of low sulfur distillate marine fuels 

than reported in the new USEPA data. The USEPA data provide much higher sulfur emissions 

due to the more accurate fuel data which were not available at the time the 2005 inventory was 

developed. It should be noted that the USEPA emission factors used in their regulatory impact 

assessment are consistent with factors presented in recent port emission inventory guidance 

(USEPA 2009b) and a recent global emission inventory developed by the International Maritime 

Organization (IMO 2009). It should also be noted that the 2005 Gulfwide inventory was based 

on customs Entrance and Clearance data obtained from MARAD. Vessels involved in domestic 

cargo traffic would not have gone through customs procedures and therefore were not included 

in the 2005 inventory. The USEPA interport component of the regulatory impact assessment 

quantified all large vessel traffic (international and domestic) operating in Federal waters, thus it 

is not surprising that their activity data may be larger than activity data used in the 2005 

inventory. Furthermore, their inventory included the operation of auxillary engines, which were 

not accounted for in the 2005 Gulfwide inventory. 
8-23 

Table 8-21 

Comparison of Base Year 2008 and 2005 OCS Non-Platform Greenhouse Gas Emission Estim

2008 2005

Source Category 

CO2

Emissions 

(tpy) 

CH4

Emissions 

(tpy) 

N2O 

Emissions 

(tpy) 

CO2e 

Emissions 

(tpy) 

CO2 

Emissions 

(tpy)

CH4 

Emissions 

(tpy) 

N2O

Emission

(tpy) 

Drilling Rigs 3,166,971 19 151 3,214,188 1,998,734 12 95 Pipelaying Vessels 712,570 8 31 722,348 657,052 7 28 Support Helicopters 1,373,574 N/Aa N/A 1,373,574 180,684 N/A N/A Support Vessels 7,418,855 47 352 7,528,962 8,282,197 52 392 Survey Vessels 83,500 1 4 84,761 59,953 <1 3 Total OCS Oil/Gas 

Production Sources (tpy) 12,755,470 75 538 12,923,833 11,178,620 71 518 

Biogenic and Geogenic 

Sources 2,284 1,874 1,948 645,518 2,284 1,874 1,948 

Commercial Fishing 

Vessels 411,326 3 19 408,369 50,536 <1 2 

Commercial Marine 

Vessels 3,013,948 N/A N/A 3,013,948 3,471,670 33 180 

LOOP 88,564 1 4 89,825 137,376 1 7 Military Vessels 417,677 3 20 423,940 326,398 <1 2 Vessel Lightering 160,038 2 7 162,250 318,784 4 15 Total Non-OCS Oil/Gas 

Production Sources (tpy) 4,093,837 1,883 1,998 4,743,850 4,307,048 1,913 2,154 

Total Non-Platform 

Emissions (tpy)b 16,849,307 1,958 2,536 17,667,683 15,485,668 1,984 2,672 

a N/A = Not available b Totals may not sum due to rounding. 
8-24 

For military vessels, neither the US Coast Guard nor the Navy activity data have changed 

between 2005 and 2008. The increase in emissions noted in Table 8-17 is due to the application 

of the Swedish emission factors to the Naval vessel activity data. In the previous inventory, the 

Naval emission estimates were carried over from the 2000 Gulfwide inventory; in this effort the 

activity and vessel characteristics data from the 2000 inventory were applied to the factors 

presented in Section 6.1.1 to ensure that all emission estimates were comparable. This 

improvement also yielded high emission estimates for the 2008 inventory. 

For non-platform sources, the updated emission factors and activity data yield an overall 

increase in greenhouse gas emissions of 8%. This is mostly driven by sources related to OCS 

oil/gas production, because non-OCS oil/gas sources show a 5% decline in greenhouse gas 

emissions, with the largest declines associated with CMV, the LOOP, and vessel lightering 

activities. These declines offset a significant increase in greenhouse gas emissions associated 

with the revised activity data for commercial fishing. For non-platform sources associated with 

OCS oil/gas production, greenhouse gas emissions increased in aggregate by 14%. All nonplatform sources had larger greenhouse gas emissions than estimated in 2005, except for support 

vessels, which is indicative of a reduction in the Gulf fleet. The largest increase in greenhouse 

gas estimates for OCS oil/gas related sources is seen in the helicopter emission estimates, which 

is based on the updated helicopter emission factors, and drilling rigs, which is due to the increase 

in drilling rig activity between 2005 and 2008. 

8.5 RECOMMENDATIONS 

As discussed in Section 8.3, a key limitation for the 2008 OCS platform emissions 

inventory is that emissions are not estimated using direct source test data. For fugitive emissions 

in particular, a requirement that emissions be monitored using direct measurement would greatly 

improve the quality of the emission estimates. The current estimation method is based on out-ofdate emission factors and surrogate equipment component counts. Because a number of the 

larger platforms will likely be subject to the USEPA Mandatory Reporting of Greenhouse Gases 

Rule (Federal Register 2009), the BOEM should coordinate with the Offshore Operators 

Committee (OOC) to evaluate potential areas for improvement in fugitive emission estimation 

methods. For glycol dehydrators, the BOEM could require that operators submit emission 

estimates and supporting documentation from the GTI AIRCalc Software Program 

(ERG/COMM Engineering 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. The BOEM 

could instead require that operators collect pressurized oil samples from separators or heater 

treaters and perform laboratory flash analyses to the obtain gas to oil ratio (GOR) and chemical 

composition, or use the API/GTI EPTANK simulation program and provide documentation. 

In lieu of requiring direct source testing or use of GTI software programs that require 

detailed source-specific operating parameters, the BOEM should continue to review emission 

factor publications and available emissions data (including data published based on the USEPA 

Greenhouse Gas Reporting Rule) to make sure the most up-to-date emission factors, including 

greenhouse gas emission factors, are used in future emission inventories. There are a number of 

ongoing studies, such as the University of Texas Greenhouse Gas Emission Factor Development 
8-25 

Project (http://www.utexas.edu/research/ceer/GHG/), and greenhouse gas source testing to 

support the California Air Resources Board Mandatory Greenhouse gas emissions reporting 

program, which should provide updated emission factors for the oil and natural gas industry. In 

addition, the pending USEPA Mandatory Greenhouse Gas Reporting Rule will require annual 

reporting for combustion sources, fugitive emissions, and other greenhouse gas emission sources 

at large OCS platform sources. The BOEM should directly obtain the information provided to 

the USEPA by these companies, evaluate the data provided for possible use in developing 

updated emission factors for non-reporting platforms, and consider using the reporting rule 

emission estimates directly in the BOEM inventory. 

As discussed in Section 4.4.7, in addition to GOADS reporting requirements, the BOEM 

also collects monthly volume vented and flared data from production operators via 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 rely on the use of these reported data in lieu of GOADS activity data. 

Another potential source of information for emissions from OCS oil and gas production 

platforms may be available in the future as a result of the USEPA final rule: Alternative Work 

Practice To Detect Leaks From Equipment (Federal Register 2008). While the final rule requires 

annual leak detection monitoring using optical gas imaging for petroleum refineries and chemical 

manufacturers, it is possible that the practice may be expanded to offshore platform sources in 

the future, and provide yet another key data set for evaluating the magnitude of fugitive 

emissions. 

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); and continue tracking studies of flare combustion 

efficiencies. 

For non-platform sources, future inventory development efforts will continue to build 

upon the foundation developed in previous MMS inventories. Possible areas for future 

enhancements for non-platform sources include implementation formal surveys of helicopter 

operations and geophysical survey vessels in the Gulf of Mexico. Previously, informal 

approaches were taken where information was obtained from service providers’ websites, and 

followed-up with requests for additional data over the phone and via e-mail, with very limited 

results. A formal request for information from the BOEM and OOC should encourage better 

participation and provide more complete and higher quality data. Information about monthly 

helicopter and survey vessel activity levels will provide more accurate estimates of monthly 

variance in activity. The survey can also provide useful information about daily traffic patterns, 

to update the diurnal profile. 

Another recommendation for future inventory efforts is to match AIS vessel tracking data 

with vessel characterization data. This will provide more accurate estimates of activity, and 
8-26 

hence emissions, providing the area of coverage can be extended to include Federal waters in the 

Gulf of Mexico. AIS data can be useful for the following vessel categories as they would meet 

the system’s reporting thresholds: tankers visiting the LOOP, survey vessels, lightering activities, 

and ocean-going commercial marine vessels. It should be noted that much of the offshore 

support vessel fleet is below current AIS reporting thresholds, but the OMSA is encouraging its 

membership to participate voluntarily in this program to enhance navigation and reduce at-sea 

collisions, therefore support vessels operating in the Gulf of Mexico, may be better represented 

than one would anticipate based on threshold requirements. Because AIS data provides detailed 

information about a vessel’s position every two seconds, such information can also be used to 

update the diurnal profiles. 

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 Gulf of Mexico. 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 US Navy Atlantic Fleet 

command. 

Additional research is also needed to confirm the reasonableness of the variance noted in 

the monthly drilling rig, pipelaying, support vessels, and commercial fishing adjustment factors. 

For some of the larger vessel types, AIS data may be useful in quantifying monthly traffic 

patterns. This will be particularly valuable for ocean-going commercial marine vessels, for which 

monthly traffic data were not compiled in the 2008 inventory. Alternative data sources such as 

RigZone can also be used to validate BOEM monthly drilling rig activity data. Last, future nonplatform inventory efforts should evaluate how pipelaying new construction activities differ from 

maintenance operations with regard to required vessel support and hours of operation. 

Other recommendations for future inventory efforts include developing black carbon 

emission estimates. Black carbon has become a concern over the past several years because of 

health concerns and potential climate impacts. Consideration should also be given to assessing 

the potential formation of ammonium sulfate, and providing background information for users of 

the inventory concerning VOC speciation. 

The last recommendations are to assess the uncertainly of the emissions estimates (and 

the diurnal profiles) for each source type in the inventory, and perform top-down assessments of 

the inventory results. An uncertainty assessment of the emission estimates and diurnal profiles 

would help air quality modelers and other users of the inventory understand which categories 

have major uncertainties associated with their estimates. A top-down assessment of the 2008 

Gulfwide emission inventory could be done using satellite measurements and/or NOAA vessel 

measurements. In this type of assessment, the inventory estimates would be modeled to predict 

ambient concentrations. The predicted concentrations would then be compared to ambient 

observations in a “top-down” performance evaluation. This type of comparison could be used to 

assess how accurate the inventory data are for identifying specific areas with significant 

increases or decreases in emissions. The results of this top-down assessment could then be used 

to pinpoint areas in the inventory development process that need improvement. 
9-1 

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