VOLUME II: CHAPTER 10

PREFERRED AND ALTERNATIVE

METHODS FOR ESTIMATING AIR

EMISSIONS FROM OIL AND GAS

FIELD PRODUCTION AND

PROCESSING OPERATIONS

September 1999

Prepared by:

Eastern Research Group, Inc.

Prepared for:

Point Sources Committee

Emission Inventory Improvement Program
DISCLAIMER

As the Environmental Protection Agency has indicated in Emission Inventory Improvement

Program (EIIP) documents, the choice of methods to be used to estimate emissions depends on

how the estimates will be used and the degree of accuracy required. Methods using site-specific

data are preferred over other methods. These documents are non-binding guidance and not rules. 

EPA, the States, and others retain the discretion to employ or to require other approaches that

meet the requirements of the applicable statutory or regulatory requirements in individual

circumstances.
DISCLAIMER

The oil and gas field production and processing industry sector is one in which new emission

estimation tools are rapidly being developed. Therefore, new tools may exist which are not

addressed in this document. The reader should keep informed about new tools through the

following websites:

& http://www.api.org

& http://www.gri.org

& http://www.epa.gov/ttn/chief

At the time of publication, however, the methodologies presented in this document are the best

recommendations of the Emission Inventory Improvement Program Point Source Committee.
EIIP Volume II iii

ACKNOWLEDGEMENT

This document was prepared by Eastern Research Group, Inc., for the Point Sources Committee

of the Emission Inventory Improvement Program and for Roy Huntley of the Emission Factor

and Inventory Group, U.S. Environmental Protection Agency. Members of the Point Sources

Committee contributing to the preparation of this document are:

Denise Alston-Guiden, Galson Consulting

Dennis Beauregard, Emission Factor and Inventory Group, U.S. Environmental Protection Agency

Bob Betterton, Co-Chair, South Carolina Department of Health and Environmental Control

Paul Brochi, Texas Natural Resource Conservation Commission

Alice Fredlund, Louisiana Department of Environmental Quality

Gary Helm, Air Quality Management, Inc.

Martin Hochhauser, Allegheny County Health Department

Toch Mangat, Bay Area Air Quality Management District

Ralph Patterson, Wisconsin Department of Natural Resources

Jim Southerland, North Carolina Department of Environment and Natural Resources

Eitan Tsabari, Omaha Air Quality Control Division

Bob Wooten, North Carolina Department of Environment and Natural Resources
EIIP Volume II

iv

CONTENTS

Section Page

1 Introduction ....................................................... 10.1-1

2 General Source Category Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1

2.1 Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1

2.1.1 Exploration and Production ................................ 10.2-2

2.1.2 Processing ............................................. 10.2-3

2.1.3 Combustion ............................................ 10.2-8

2.1.4 Storage and Transport .................................... 10.2-9

2.1.5 Wastewater ............................................. 10.2-9

2.2 Emission Sources .............................................. 10.2-10

2.2.1 Exploration and Production ............................... 10.2-10

2.2.2 Processing ............................................ 10.2-11

2.2.3 Combustion ........................................... 10.2-13

2.2.4 Transportation ......................................... 10.2-13

2.2.5 Storage Tanks .......................................... 10.2-14

2.2.6 Wastewater ............................................ 10.2-14

2.2.7 Fugitives .............................................. 10.2-15

2.3 Design and Operating Parameters Affecting Emissions . . . . . . . . . . . . . . 10.2-15

2.4 Control Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-17

2.4.1 Control Techniques for VOC .............................. 10.2-17

2.4.2 Control Techniques for H S2 ............................... 10.2-20

2.4.3 Control Techniques for Combustion Emissions ............... 10.2-20

3 Overview of Available Methods ....................................... 10.3-1

3.1 Description of Emission Estimation Methodologies .................. 10.3-1

3.1.1 Stack Sampling ......................................... 10.3-1

3.1.2 Emission Factors ........................................ 10.3-2

3.1.3 Calculation Programs ..................................... 10.3-2

3.1.4 Engineering Calculations .................................. 10.3-3

3.2 Comparison of Available Emission Estimation Methodologies ......... 10.3-4

3.2.1 Stack Sampling ......................................... 10.3-7

3.2.2 Emission Factors ........................................ 10.3-7
CONTENTS (CONTINUED)

Section Page

EIIP Volume II v

3.2.3 Calculation Programs ..................................... 10.3-7

3.2.4 Engineering Calculations .................................. 10.3-7

4 Preferred Methods for Estimating Emissions ............................. 10.4-1

4.1 Emission Calculations Using Emission Factors . . . . . . . . . . . . . . . . . . . . . 10.4-1

4.2 Emission Calculations Using Emission Models . . . . . . . . . . . . . . . . . . . . . 10.4-7

4.2.1 Emission Model for Glycol Dehydrators ...................... 10.4-7

4.2.2 Emission Model for Liquid Material Storage .................. 10.4-8

4.2.3 E&P TANK Emission Model for Flash Losses ................ 10.4-9

4.2.4 Emission Model for Amine Sweetening Units ................. 10.4-9

4.3 Emission Calculations Using Engineering Equations . . . . . . . . . . . . . . . . . 10.4-9

4.3.1 Displacement Equation .................................. 10.4-10

4.3.2 Emission Equations for Flash Losses from Gas Condensate

 Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-18

4.3.3 Emission Equations For Loading Losses ..................... 10.4-22

4.3.4 Emission Equations for Sulfur Recovery Units ................ 10.4-25

4.3.5 VOC and HAP Emissions from Flares ...................... 10.4-28

4.4 Emission Calculations Using Stack Sampling Data . . . . . . . . . . . . . . . . . 10.4-29

5 Alternative Methods for Estimating Emissions ............................ 10.5-1

5.1 Emission Calculations Using Emission Factors . . . . . . . . . . . . . . . . . . . . . 10.5-1

5.2 Emission Calculations Using Stack Sampling Data . . . . . . . . . . . . . . . . . . 10.5-6

5.2.1 Stack Sampling Data for Gas Sweetening Processes ............. 10.5-6

5.2.2 The Rich/Lean Method for Glycol Dehydrator and Gas 

 Sweetening Amine Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5-8

5.3 Emission Equations for Flash Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5-10

5.3.1 Vazquez-Beggs Correlation ............................... 10.5-10

5.3.2 Rollins, McCain, Creeger Correlation ....................... 10.5-11
CONTENTS (CONTINUED)

Section Page

EIIP Volume II

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6 Quality Assurance/Quality Control ..................................... 10.6-1

6.1 General Factors Involved in Emission Estimation Techniques .......... 10.6-1

6.1.1 Emission Factors ........................................ 10.6-1

6.1.2 Emission Models and Engineering Equations .................. 10.6-3

6.1.3 Testing ................................................ 10.6-3

6.2 Data Attribute Rating System (DARS) Scores . . . . . . . . . . . . . . . . . . . . . . 10.6-3

7 Data Coding Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.7-1

7.1 Source Classification Codes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.7-1

7.1.1 Process Operations ....................................... 10.7-1

7.1.2 In-Process Fuel Use ...................................... 10.7-1

7.1.3 Storage Tanks ........................................... 10.7-1

7.1.4 Fugitive Sources ......................................... 10.7-8

7.1.5 Transportation and Marketing .............................. 10.7-8

7.2 AIRS Control Device Codes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.7-8

8 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.8-1

Appendix A Example Data Collection Forms

Appendix B LADEQ Guidelines and Inspection Checklist for GRI-GLYCalc Model
EIIP Volume II vii

FIGURES AND TABLES

Figure Page

10.2-1 Cryogenic Expansion Process ...................................... 10.2-7

10.6-1 Example Emission Inventory Checklist for Oil and Gas Field Production and

Processing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6-2

Tables Page

10.2-1 Typical Oil and Gas Field Processing Emission Control Techniques ....... 10.2-18

10.3-1 Summary of Preferred Emission Estimation Methods for Oil and Gas Field

Processing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-5

10.4-1 List of Variables and Symbols ...................................... 10.4-2

10.4-2 Test Results ................................................... 10.4-30

10.5-1 List of Variables and Symbols ...................................... 10.5-2

10.5-2 Test Results - Method 11 .......................................... 10.5-7

10.6-1 DARS Scores: Emission Factors (EF) ............................... 10.6-4

10.6-2 DARS Scores: Emission Models And Engineering Equations ............. 10.6-6

10.6-3 DARS Scores: Stack Sampling ..................................... 10.6-9

10.7-1 Source Classification Codes for Oil and Gas Production ................. 10.7-2

10.7-2 AIRS Control Device Codes ....................................... 10.7-9
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1

INTRODUCTION

The purposes of the preferred methods guidelines are to describe emission estimation techniques

for stationary point sources in a clear and unambiguous manner and to provide concise example

calculations to aid in the preparation of emission inventories. While emissions estimates are not

provided, this information may be used to select an emission estimation technique best suited to a

particular application. This chapter describes these procedures and recommends approaches for

estimating emissions from most oil and gas field production and processing operations common

throughout the United States. Additional sources may exist, which are not addressed in this

chapter, such as cogeneration units, cooling towers, and non-road mobile sources (e.g.,

helicopters, and crew and supply boats). Depending on the purpose of the inventory, emissions

from these additional sources should also be included. For procedures to estimate emissions

from these sources, contact the state or local agency or EPA.

Section 2 of this chapter contains a general description of the oil and gas field production and

processing operations source category, identifies common emission sources, and overviews

available control technologies used in oil and gas field processing operations. Section 3 of this

chapter provides an overview of available emission estimation methods.

Section 4 presents the preferred methods for estimating emissions from oil and gas field

production and processing operations, while Section 5 presents the alternative emission

estimation techniques.

It should be noted that the use of site-specific emission data is preferred over the use of

industry-averaged data such as AP-42 emission factors (EPA, 1995a). Depending upon available

resources, site-specific data may not be cost effective to obtain. However, this site-specific data

may be a requirement of the State Implementation Plan (SIP) and may preclude the use of other

data. 

Quality assurance (QA) and quality control (QC) procedures are described in Section 6. Coding

procedures used for data input and storage are discussed in Section 7. Some states use their own

unique identification codes, so industry personnel using this document should contact their state

or local agency to determine the appropriate coding scheme to use. References are listed in

Section 8. Appendix A provides an example data collection form to assist in information

gathering prior to emissions calculations.
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2

GENERAL SOURCE CATEGORY

DESCRIPTION

This section provides a brief overview of most oil and gas field processing operations common

throughout the United States. The reader is referred to the Air Pollution Engineering Manual

(referred to as AP-40) and AP-42, 5th Edition, January 1995, for a more detailed discussion of

these facilities.

Additional sources may exist, which are not addressed in this chapter, such as cogeneration units,

cooling towers, and non-road mobile sources (e.g, helicopters, and crew and supply boats). In

addition, equipment and emissions from off-shore operations, although not specifically addressed

in this document, are believed to be similar to those from on-shore operations. Preferred and

alternative emission estimation methodologies for off-shore sources are, therefore, expected to be

the same as for on-shore sources. Depending on the purpose of the emission inventory, the

inventory preparer should consider inclusion of emissions from these additional source types. 

2.1 PROCESS DESCRIPTION

The petroleum industry is organized into the following four broad segments:

& Exploration and production;

& Transportation;

& Refining; and

& Marketing.

This chapter addresses only the field production and processing operations of the petroleum and

natural gas industry found in the exploration and production (E&P) and transportation segments

of the industry.

The oil and gas field production and processing operations begin with exploration to locate new

sources of crude oil and natural gas. When potential sources are located, wells are drilled to
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.2-2 EIIP Volume II

confirm the presence of oil or gas and to determine whether the reserves are economically

sufficient to support production.

During production, crude oil and/or natural gas is recovered from wells and prepared for

transportation from the field. Trucks, rail cars, barges and tankers are used to transport domestic

crude oil to refineries. Domestic crude oil can also be transported from the field to refineries by

a complex network of pipelines. Natural gas, which may be produced alone or in combination

with crude oil, often must be processed at a gas plant to make it suitable for consumer use

(Rucker and Strieter, 1992). 

Oil and gas field production and processing operations are primarily defined by the following

types of emission activities:

& Exploration and production;

& Processing;

& Combustion;

& Storage and transport; and

& Wastewater.

2.1.1 EXPLORATION AND PRODUCTION

In the E&P segment of the industry, natural gas and crude oil are recovered from underground

reservoirs. This industry segment encompasses exploration, well-site preparation, and drilling

(Rucker and Strieter, 1992).

Seismic and other geophysical methods are used to locate subterranean formations that signal the

potential presence of oil and gas reservoirs. When a likely formation is located, drilling is the

only way to confirm that oil and gas are present (Rucker and Strieter, 1992).

Drilling operations include the activities necessary to bore through the earth's crust to access

crude oil and natural gas resources. During drilling operations, specially formulated muds are

circulated through the hole to remove cuttings from around the drill bit, to provide lubrication for

the drill string, to protect the walls of the hole, and to control down-hole pressure. Cuttings are

separated from the mud at the well surface as the mud is passed through shale shakers, desanders,

desilters, and degassers. The mud flows to a tank for recycling, and the cuttings, which may be

contaminated with hydrocarbons, are pumped to a waste pit for disposal (Rucker and Strieter,

1992).
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EIIP Volume II 10.2-3

Water and drilling muds from offshore operations can be discharged overboard if they meet

various limitations and requirements set by EPA. If the water or drilling muds do not meet these

limitations and requirements, they are brought back to land for onshore treatment or disposal. 

When the desired well depth is reached, the well is completed by installing an outer annular

casing. During this process a completion fluid (typically heavy salt water) is used to prevent

premature gas/oil flow. Occasionally, the well formation pressure is greater than the completion

fluid pressure and premature gas/oil flow or blowout occurs (GRI, 1994).

Well testing occurs at exploratory wells which have unknown reservoir potential. Testing occurs 

during well completion by measuring the potential gas or oil flow. Testing is conducted to

determine the required specifications of the wellhead assembly. Gas vented during well testing is

either flared or vented directly to the atmosphere (GRI, 1994). Oil extracted during well testing

is collected in a storage tank. 

Once a well has been completed and is producing crude oil or natural gas, an arrangement of

high-pressure valves termed a "Christmas tree" is installed to control production. As the well

ages, an artificial lift device may be needed to help bring product to the well surface (Rucker and

Strieter, 1992).

2.1.2 PROCESSING

After extracting the hydrocarbons from the underground reservoirs, additional processing is

conducted in the field to prevent corrosion and other problems in downstream handling and

processing equipment (GRI, August 1994). The first processing step employed at many

production facilities involves separating the oil, gas, and water produced by the well (Rucker and

Strieter, 1992). The gas is separated from liquids either in a two-phase process, in which gas is

typically separated from water, or in a three-phase separation operation, in which gas, water, and

liquid hydrocarbons are separated. Three-phase separation is necessary when appreciable liquid

hydrocarbons are extracted with the gas and water (GRI, 1994).

Separators can be vertical, spherical, or horizontal, and typically employ a series of baffles to

separate the gas from the liquid hydrocarbons. A horizontal separator is used when the

gas-to-liquid hydrocarbons ratio is large; a vertical separator is used when the gas-to-liquid

hydrocarbon ratio is small; and a spherical separator is used when the gas-to-liquid hydrocarbon

ratio is in the intermediate range. When wellhead pressures are high, a series of separators may

be operated at sequentially reduced pressures (GRI, 1994).

Separators provide only one stage of separation, and, in many cases, additional water and gas

separation from the oil emulsion streams may be required. 
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10.2-4 EIIP Volume II

Oil Processing

Water in the oil can form an emulsion. This emulsion is broken using heat in heater treaters or

electric energy in devices such as electrostatic coalescers. Cleaned oil flows from the emulsion

breakers to crude oil storage tanks, prior to being transported to a pipeline, truck, rail car, barge,

or tanker. The water that is recovered during emulsion breaking is often recycled through

skimmers to recover remaining oil, filtered, and then stored in water tanks prior to underground

injection or other discharge (Rucker and Strieter, 1992).

Natural Gas Processing

Glycol Dehydration. Glycol dehydration units are used to remove water from natural gas

streams to prevent the formation of hydrates and corrosion in the pipeline. The natural gas

stream is passed through a stream of triethylene glycol (TEG), diethylene glycol (DEG), or

ethylene glycol (EG). Other forms of glycol, such as tetraethylene glycol, may also be used. At

the point of contact, the glycol will absorb water and water vapor from the natural gas stream. 

During the absorption process, aromatic hydrocarbons including benzene, toluene, ethyl benzene

and xylene (BTEX), hexane as well as other volatile organic compounds (VOCs) and hazardous

air pollutants (HAPs) present in the gas stream are absorbed along with the water vapor into the

glycol stream. When the glycol is saturated with water, it is considered "rich glycol." The rich

glycol is then sent to a glycol still for regeneration to remove water and liquid hydrocarbons. 

After regeneration, the glycol is considered "lean glycol" and is suitable for reuse (TNRCC,

1996).

Methanol Injection. Methanol is often added to natural gas as a hydrate point depressant and

antifreeze. The methanol is injected using a gas-powered chemical injection pump, which uses

gas pressure to drive the pump piston (GRI, 1994).

Particulate Removal. When solid impurities (particulates) are present in the raw natural gas,

they are removed by passing the gas stream through a particulate filter, such as the common

cartridge type filter (GRI, 1994).

Acid Gas Removal. The acid gases hydrogen sulfide (H S) and carbon dioxide (CO ) corrode 2 2

the pipeline and can cause safety problems if not removed from the natural gas stream. The gas

stream must be freed of these contaminants, or "sweetened", before the gas can be transported for

use (TNRCC, 1996). There are several processes available for removing the acid gases from the

natural gas stream including: 

& Amine Based Process: The most common method of acid gas removal (AGR), the

amine process, utilizes aqueous solutions of diethanolamine (DEA),

monoethanolamine (MEA), methyldiethanolamine (MDEA), and diglycolamine

(DGA). The natural gas is processed through a stream of one of the previous amine
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EIIP Volume II 10.2-5

solutions that will absorb H S, CO , and VOCs. After the amine solution is saturated 2 2

with the acid gases, it is piped to the amine regenerator. The regenerator heats the

amine solution and the acid gases are released (TNRCC, 1996).

& Selexol Process: This process uses the dimethylether of polyethylene glycol as a

solvent, which has a high physical absorption capability for CO and sulfur-based 2

compounds including H S. In the presence of CO , the Selexol process can reduce the 2 2

H S, carbonyl sulfide (COS) and mercaptan concentrations to 1 ppm, with the 2

CO content retained or reduced to any required level (GRI, 1994). 2

The solvent is regenerated by flashing and/or stripping with steam or inert gas. The

process vent stream from the flash tank usually has a high CO concentration, and is 2

typically flared to combust undesirable products such as H S, acid gases, and VOCs. 2

The vent stream from the stripper column is either vented, flared, or sent to a sulfur

recovery process.

& Fixed Bed Sorption Process: Fixed bed sorption, or molecular sieve gas sweetening,

is typically used to treat liquified natural gas plant feed gases. Molecular sieves

physically adsorb H S and/or CO , along with water, to sweeten and dehydrate the gas 2 2

stream. With two or more adsorption beds, one bed is used to treat the feed gas

stream while the other is regenerated by a heated gas stream (usually a slip stream of

dry process gas). Generally, process heaters burning natural gas are used to heat the

regeneration gas stream. The regeneration gas is usually recycled to the process after

it has been cooled and any free water and sulfur compounds have been removed in an

adsorber and flashed. The sour gas stream from the flash tank may be vented,

incinerated, or sent to sulfur recovery (GRI, 1994).

& Other Acid Gas Removal Processes: Scavenging processes, such as iron sponge,

are also used for acid gas removal, primarily where the H S content is relatively low. 2

Other processes, such as the hot potassium carbonate-based Benfield process, are

most often used for natural gas containing high concentrations of CO (GRI, 1994). 2

Other processes exist, but are used less frequently.

Sulfur Recovery. Exhaust gas from the sweetening process may be vented to a sulfur recovery

process. There are two common methods of sulfur recovery: 

& Claus Sulfur Recovery Process: The Claus sulfur recovery process is the most

widely used technology for recovering elemental sulfur from sour gas (or sour crude

oil). The Claus process is used to recover sulfur from the amine regenerator vent gas

stream in plants where large quantities of sulfur are present (GRI, 1994). The Claus

process consists of a multistage catalytic oxidation of H S. Each catalytic stage 2

consists of a gas reheater, a catalyst chamber, and a condenser. The Claus process
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10.2-6 EIIP Volume II

involves burning one-third of the H S with air in a reactor furnace to form sulfur 2

dioxide (SO ) and water. The remaining uncombusted two-thirds of the H S reacts 2 2

with SO to form elemental sulfur and water (EPA, 1995e). 2

& Liquid Redox Sulfur Recovery Process: Liquid redox sulfur recovery processes are

liquid-phase oxidation processes which use a dilute aqueous solution of iron or

vanadium to remove H S selectively by chemical absorption from sour gas streams. 2

These processes can be used on relatively small or dilute H S streams to recover 2

sulfur from the acid gas stream or, in some cases, they can be used in place of an acid

gas removal (AGR) process. The mildly alkaline lean liquid scrubs the H S from the 2

inlet gas stream, and the catalyst oxidizes the H S to elemental sulfur. The reduced 2

catalyst is regenerated by contact with air in the oxidizer(s). Sulfur is removed from

the solution by flotation or settling, depending on the process (GRI, 1994).

Hydrocarbon Recovery. Several processes are used in the industry to separate and recover nonmethane hydrocarbons from natural gas (GRI, 1994):

& Cryogenic Expansion: In the cryogenic expansion process, the gas stream is initially

treated by low-temperature separation to remove any residual water in the gas. The

dehydrated gas is split, and part of the gas is cooled to -25( Fahrenheit (F) using

residue gas. The remainder of the gas is chilled to 4(F using propane as the

refrigerant. The split streams are combined and enter the high pressure separator

where the cold liquid hydrocarbons are separated from the gas. The cold liquid

hydrocarbons leave the high pressure separator and are reduced in pressure across a

valve to lower the temperature to -45(F. This cold liquid hydrocarbon stream

provides the heat sink for the upstream heat exchangers used to chill the incoming gas

stream. After passing through these heat exchangers, the warm liquid enters the

deethanizer (GRI, 1994).

The gas stream from the high pressure separator is expanded to reduce the

temperature to -85(F. This gas stream enters the low pressure separator where the

hydrocarbon liquids are separated from the gas. The separated liquid stream is

circulated as the coolant in the condenser on the deethanizer column and reintroduced

as reflux to the deethanizer. The gas stream from the low pressure separator is used

to further cool the overhead stream from the deethanizer, and then is combined with

the deethanizer overhead stream. This combined gas stream is compressed to pipeline

pressure (GRI, 1994). Figure 10.2-1 illustrates an example cyrogenic expansion

process.
10.2-7 EIIP Volume II Figure 10.2-1 Cryogenic Expansion Process (Source: GRI, 1994)
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.2-8 EIIP Volume II

& Refrigeration Process: In the conventional refrigeration process, the inlet gas stream

is initially contacted with a lean glycol solution to remove water from the gas stream. 

The gas/glycol stream is chilled to -30(F to separate the condensible liquid

hydrocarbons from the dry gas stream. The liquid hydrocarbons are separated from

the rich glycol solution and sent to a stabilizer, where the lighter gas stream is

separated from the heavier liquid hydrocarbons. The rich glycol stream is regenerated

to remove the absorbed water and recycled to the process (GRI, 1994).

& Absorption Process: In the absorption process, the wet field gas is contacted with an

absorber oil in a packed or bubble tray column. Propane and heavier hydrocarbons

are absorbed by the oil while most of the ethane and methane pass through the

absorber. The enriched absorber oil is then taken to a fractionator where the absorbed

propane and heavier hydrocarbons are stripped from the oil. The overhead gas

product stream from the absorber is then compressed to pipeline pressure (GRI,

1994).

& Adsorption Process: The adsorption process utilizes two or more molecular sieve

beds to adsorb all hydrocarbons except methane. The beds are used alternately, with

one or more beds on-stream while the others are being regenerated by means of heat

or steam which remove the adsorbed hydrocarbons. If steam is used, the steam/

hydrocarbon vapor stream is condensed and liquid hydrocarbons fed to a fractionation

process where the various compounds are separated (GRI, 1994).

Pneumatic Devices. Pneumatic devices such as pressure and level controllers are used in gas

field production operations to control field equipment. Natural gas is typically used as the

pneumatic medium (GRI, 1994).

Blowdown. Equipment such as compressors is occasionally shutdown for emergencies and

scheduled maintenance. Any gas remaining in the equipment and corresponding pipelines must

be vented to reduce pressure prior to servicing. This process is called blowdown (GRI, 1994).

2.1.3 COMBUSTION

External Combustion. Boilers and heaters provide process heat and steam for many processes

such as electric generation, glycol dehydrator reboilers, and amine reboiler units.

Internal Combustion Engines and Gas Turbines. Compressors are often used to transport

natural gas from the field to processing plants. Reciprocating internal combustion engines (ICEs)

or gas turbines are used to drive compressors. The inlet and outlet gas streams are passed

through a scrubber/separator to remove any condensed liquids. The ICE or gas turbine driver

combusts a slip stream of the gas being transported (GRI, 1994). ICEs and gas turbines also
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EIIP Volume II 10.2-9

have many other purposes, such as compression of petroleum gases and refrigerants, electrical

generation, and pump and crane operation.

Flares. Flares are often used to control VOC emissions and to convert H S and reduced sulfur 2

compounds to SO . Flares can be used to control emissions from storage tanks, loading 2

operations, glycol dehydration units, vent collection systems, and gas sweetening amine units

(Boyer and Brodnax, 1996). Flares can also be used as a backup system for sulfur recovery units.

2.1.4 STORAGE AND TRANSPORT

Storage tanks are used to store crude oil, liquified natural gas (LNG), water or brine, process

condensate, as well as other materials used or generated during the production of oil and natural

gas. Crude oil is transported from production operations to refineries by tank trucks, rail cars,

tankers, barges, and pipelines. Loading methods include splash loading, submerged pipe fill, and

bottom loading. Natural gas is transported by pipeline.

Pipeline pigging operations are conducted to assist in product transfer and product separation, as

well as for maintenance activities. A pig is a physical device which varies in size and shape and

can be made of a variety of materials such as plastic, urethane foams, and rubber. Pigs can be

solid, inflatable, foam, or made of a viscous gel. The specific design of a particular pig depends

upon the pipeline as well as the purpose of the pigging operation (GRI, 1993).

Three types of pigging operations occur in pipelines at oil and gas field production and

processing facilities: product transfer, product separation, and maintenance. Pigging following

product transfer is used to remove residual product from the pipeline after loading occurs. Pigs

can also be used for product separation to transport more than one product, such as oil, gas, or

condensate as well as for maintenance activities such as pipeline cleaning, gauging, or

dewatering. During pigging operations, a pig is inserted into the pipeline and is forced through

the pipeline by a compressed gas, such as nitrogen. When the pig gets to the end of the line, it is

trapped in a receiver. The gas is then bled off from behind the pig (TNRCC, 1998a; TNRCC,

1998b; GRI, 1993). Depending on the specific pigging operation, waste removed from the

pipeline may also be an issue.

2.1.5 WASTEWATER

During oil and gas field production and processing operations, wastewater is generated from

processes such as product separation and glycol dehydration. The wastewater may be treated

on-site or it may be forwarded to an approved wastewater treatment facility.

Many types of units are used to treat, store, and transfer wastewater on-site. Some of these units

include sumps, pits, storage tanks, brine tanks, and oil/water separators which may be in primary,

secondary or tertiary treatment service.
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10.2-10 EIIP Volume II

2.2 EMISSION SOURCES

Emissions from oil and gas field processing operations result from both controlled (i.e., ducted)

and uncontrolled sources. Section 7 of this chapter lists the source classification codes (SCCs)

for these emission points. In addition to emissions from the sources described below, emissions

result from process upsets such as pressure relief device releases due to over-pressure, and

non-traditional sources such as cogeneration units, cooling towers and non-road mobile sources. 

In addition, equipment and emissions from off-shore operations, although not specifically

addressed in this document, are believed to be similar to those from on-shore operations. 

Preferred and alternative emission estimation methodologies for off-shore sources are, therefore,

expected to be the same as for on-shore sources. Depending on the purpose of the emission

inventory, the inventory preparer should consider inclusion of emissions from these additional

source types. 

2.2.1 EXPLORATION AND PRODUCTION

Emission sources associated with exploration and production include exploration, well-site

preparation, drilling, waste pits, blowouts, well testing, and gas/liquid separation. Fugitive dust

and combustion emissions from exploration and well-site preparation result from vehicles, heavy

equipment and engines and turbine operation.

Drilling operations are a significant source of short-term air pollutant emissions, which some

states consider to be a temporary source. During drilling, gas may seep into the well bore and

become dissolved or entrained in the drilling mud (EPA, 1977a). The gases are separated from

the mud in a separator or degasser. Gases removed from the mud are either vented to the

atmosphere or routed to a flare. Some states or local agencies may consider mud degassing a

temporary source of emissions. Pollutants of concern are H S, CH , VOC and HAPs. The use of 2 4

oil-based drilling muds also results in additional H S, CH , VOC and HAP emissions. When 2 4

using oil-based drilling muds, the mud will be dispersed in oil rather than water. When the mud

passes through the shale shaker, the oil vapors are exposed directly to the atmosphere (EPA,

1977a). Some state or local agencies may consider this a temporary source of emissions.

Waste pits storing hydrocarbon laden cuttings may be a source of VOC and HAP emissions. 

Well blowouts, although infrequent, are considered process upsets and can also be a source of

VOC, HAP, and CH emissions. Well testing can result in VOC, HAP and CH emissions. 4 4

Emissions from gas/liquid separation processes include fugitive VOC and HAP from valves and

fittings and from any operation upsets, such as pressure relief device releases due to overpressure.
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

Water-cooled condensers are generally more efficient than air-cooled condensers when 1

used in the glycol dehydration process.

EIIP Volume II 10.2-11

2.2.2 PROCESSING

Oil Industry

Emissions from heater treaters result from fuel combustion and include typical fuel combustion

pollutants: carbon monoxide (CO), carbon dioxide (CO ), nitrogen oxides (NO ), sulfur dioxide 2 x

(SO ), particulate matter less than or equal to 10 microns in diameter (PM ), particulate matter 2 10

less than or equal to 2.5 microns in diameter (PM ), VOC, lead, and HAPs. Equipment leaks 2.5

from piping components (e.g., valves, flanges and connectors) also result in fugitive VOC and

HAP emissions.

Gas Industry

Emissions associated with the glycol dehydration process may include vented emissions from the

glycol dehydrator’s flash tank as well as the glycol regenerator process vent. BTEX compounds,

as well as hexane and other HAPs present in the gas, are carried with the rich glycol to the

regenerator; thus the regenerator vent stream can be a major source of HAP emissions (GRI,

1994). Glycol regenerators either vent directly to the atmosphere or to vapor recovery or control

systems.

The glycol regenerator reboiler typically fires natural gas and is also a potential source of HAP

emissions. If the water is efficiently removed from the gas stream during the glycol dehydration

process, the glycol regenerator reboiler can be used to thermally oxidize HAPs and VOCs

emitted from the glycol regenerator process vent. Gas-driven pumps often used in glycol units 1

may produce HAP emissions. In most cases, the pump-driven gas is routed to the rich glycol

stream upstream of the flash tank. Once the glycol reaches the flash tank or regenerator, the

pump gas is separated with the gas from the absorber. Fuel combustion should be considered an

emission source separate from the glycol regenerator reboiler. Other process-related sources of

emissions include fugitive emissions from valves and fittings, and emissions from routine

maintenance activities involving equipment depressurization (blowdown) or complete purging

and filter replacement. Also, although DEG, TEG, and tetraethylene glycol are not listed HAPs,

they may degrade at the high temperatures present in the regenerator to form compounds such as

ethylene glycol, a listed HAP (GRI, 1994). If ethylene glycol is used, HAP emissions may be

released.
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10.2-12 EIIP Volume II

VOC and HAP emissions from the methanol injection process include fugitive losses from the

transfer line fittings and from the methanol storage tank. Also, the gas-powered chemical

injection pumps vent gas directly to the atmosphere and could emit VOC or HAP compounds

present in the gas (GRI, 1994).

Potential emissions of VOC and HAP from particulate removal result from fugitive losses from

valves, flanges, or other connections, and vented emissions from periodic routine maintenance to

repair or clean the filter. Disposal of the filter cartridges may also be a source of emissions due

to the volatility of some VOC or HAP compounds (GRI, 1994).

During the gas sweetening/acid gas removal process, the amine unit is a potential source of SO ,2

H S, VOC, HAP and CO emissions. As the amine regenerator heats the amine solution, the acid 2 2

gases are released through the amine still vent. The amine still vent can be vented directly to the

atmosphere, to a flare or incinerator, or to a sulfur recovery unit (SRU) (TNRCC, 1996). Amine

units designed to remove only CO from the natural gas, generally, vent directly to the 2

atmosphere. Amine units designed for the removal of H S and CO , generally, vent directly to a 2 2

sulfur recovery unit.

During sulfur recovery, emissions sources in the Selexol process include the process vent

streams, fugitive emissions from valves, flanges, and compressor seals, exhaust emissions

associated with compressor operation and vented emissions due to periodic maintenance

activities (GRI, 1994). Pollutants of concern are SO , H S, and HAPs. 2 2

Emission sources associated with the fixed bed sorption process potentially include the sour gas

vent from the flash tank associated with molecular sieve bed regeneration, exhaust emissions

from process heaters associated with the regeneration cycle, fugitive emissions, and vented

emissions from maintenance activities (GRI, 1994).

Emission sources associated with the Claus sulfur recovery process include the tail gas stream,

which is usually incinerated or which may be passed through a liquid redox sulfur recovery unit,

fugitive emissions from equipment leaks, and emissions from maintenance activities. In

addition, residual H S, carbonyl sulfide (COS), and carbon disulfide (CS ) may also be released 2 2

to the atmosphere from the recovered molten sulfur (GRI, 1994). 

In the liquid redox sulfur recovery process, vent gases from the oxidizer vessel are a potential

source of emissions. Emissions associated with fixed bed adsorption or molecular sieve

dehydration include fugitive emissions and emissions from maintenance activities which are

considered minor sources of HAP emissions. Process heaters are often used to heat the

regeneration stream, with the burner vents from these heaters being potential sources of HAP

emissions (GRI, 1994). 
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EIIP Volume II 10.2-13

Emissions from the refrigerated absorption process include flue gas from the rich oil fractionator

reboiler, exhaust emissions from the compressor driver (a reciprocating engine or a gas turbine),

fugitive emissions, and emissions from maintenance activities.

Cryogenics plant emissions primarily include exhaust from the compressor driver, flue gas from

the deethanizer reboiler, fugitive emissions, and emissions from maintenance activities.

Emissions associated with the refrigeration process include the glycol regenerator off-gas, which

is typically vented to the atmosphere and may potentially contain BTEX, as well as hexane and

other HAPs present in the gas. The flue gas stream from the glycol regenerator reboiler is also

typically vented to the atmosphere and may be a source of emissions. Other sources of emissions

include fugitive emissions and vented emissions due to maintenance activities.

Absorption process emissions include exhaust from the compressor driver, exhaust gas from the

fractionator reboiler, fugitive emissions, and vented emissions due to maintenance activities.

Emissions associated with the adsorption process primarily include exhaust gas from the

regenerator, fugitive emissions, and maintenance activities.

2.2.3 COMBUSTION

Boilers and heaters provide local process heat, process steam, steam for electric generation,

glycol dehydrator reboilers, and amine reboiler units. Internal combustion engines and gas

turbines have many other purposes, such as compression of petroleum gases, compression of

refrigerants, electrical generation, and pump and crane operation. The pollutants of concern

include NO , CO, VOC, PM , PM , SO , CH , and CO . HAPs, primarily formaldehyde and x 10 2.5 2 4 2

acetaldehyde, are also potential pollutants from these combustion sources. 

Flares convert potentially hazardous gases into less hazardous emissions. VOC, NO , CO, HAPs x

and CH are the primary pollutants of concern with flares (TNRCC, 1996). If flares are used to 4

oxidize H S and other reduced sulfur compounds, SO will also be emitted. Depending on the 2 2

level of conversion achieved, H S and other reduced sulfur compounds may also be emitted. 2

Auxiliary fuel combustion is also a source of emissions. Fuel used to fire specific process or

control equipment such as flares and incinerators result in additional combustion emissions. 

Depending on the fuel fired, pollutants may include NO , CO, PM , PM , VOC, SO , CO , X 10 2.5 2 2

CH , and HAPs. 4

2.2.4 TRANSPORTATION

Emission sources related to transporting crude oil include loading losses and fugitive pipeline

leaks. As crude oil is loaded into trucks, rail cars, barges, and tankers, vapors residing in the
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10.2-14 EIIP Volume II

vapor space are pushed out of the cargo tank. Pipeline transmission of natural gas is also an

emission source. Pollutants include VOC, HAPs, and CH contained in the material. 4

Pigging operations are also a potential source of VOC, HAP, and CH emissions if residual 4

vapors are vented to the atmosphere rather than to a flare or incinerator. As the pig travels

through the pipeline, residual vapors are pushed through the line as well. If the vapors are not

routed to a control device, they escape through openings on the device such as hatches, doors, or

vents. Emissions can be significant depending on the amount and vapor pressure of the product

(TNRCC, 1998a). Depending on the gas used to push the pig, the bleed-off step can also result

in VOC, HAP, or CH emissions if the gas is not vented to a control device. 4

Depending on the purpose of the emission inventory, pigging emissions may need to be included. 

The inventory preparer should contact the state or local agency to identify the preferred methods

to estimate emissions from pigging operations.

2.2.5 STORAGE TANKS

Storage tanks are used to store crude oil, LNG, water or brine, process condensate, as well as

other materials used at oil and gas field processing facilities, and may be a potential source of

VOC, HAP, CH emissions. Emission losses from storage tanks in the oil and gas field 4

processing industry include working losses, breathing losses, and flash losses. Working losses

refer to the combined loss from filling and emptying the tank. Filling losses occur when the

VOC contained in the saturated air are displaced from a fixed-roof vessel during loading. 

Emptying losses occur when air drawn into the tank becomes saturated and expands, exceeding

the capacity of the vapor space. Breathing losses are the expulsion of vapor from a tank through

vapor expansion caused by daily changes in temperature and pressure. Flash losses occur when

fluids exiting vessels at pressures above atmospheric enter storage tanks operating at atmospheric

pressure which are vented to the atmosphere. As the fluid pressure drops to atmospheric

pressure, the gas which is entrained in the fluid is then released (TNRCC, 1996). Flash losses

often exceed breathing and working losses (Boyer and Brodnax, 1996).

2.2.6 WASTEWATER

If open to the atmosphere, units used to treat, store and transfer wastewater on-site may also be

potential sources of VOC, HAP, CH , and H S emissions. Some of these units that may be 4 2

present at oil and gas field production and processing operations are sumps, pits, storage tanks,

brine tanks, and oil/water separators.
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EIIP Volume II 10.2-15

2.2.7 FUGITIVES

Fugitive emissions (equipment leaks), are leaks from sealed surfaces associated with process

equipment. Specific fugitive source types include various equipment components such as valves,

flanges and connectors. Equipment specific to the oil and gas field production and processing

operations which result in fugitive emissions include equipment such as heater treaters,

separators, pipelines, wellheads and pump stations. Pneumatic devices such as gas actuated

pumps and pressure/level controllers also result in fugitive emissions. Pollutants of concern

include VOC, HAPs, CH contained in the gas. 4

2.3 DESIGN AND OPERATING PARAMETERS AFFECTING EMISSIONS

In general, the primary factors affecting emissions and their estimation for sources in oil and gas

field processing operations are:

& Oil/gas composition; 

& Production rate/frequency of operation; and

& Type of control/recovery, if any.

The specific influence of each of these factors as well as other source specific parameters

affecting emissions are discussed below.

Glycol dehydrator emissions will be affected by the composition of the natural gas, particularly

the concentration of glycol-soluble hydrocarbons. As water is adsorbed into the glycol stream, so

are some glycol-soluble hydrocarbons such as BTEX. The rich glycol stream flows to the

reboiler for regeneration by heating to remove the water. Water and adsorbed hydrocarbons are

released from the glycol during the regeneration (Boyer and Brodnax, 1996).

Emissions from gas sweetening units are influenced by the concentration of acid gases in the

waste gas stream as well as the type of control or recovery process that follows the sweetening

process. The greater the H S concentration in the sour gas, the greater the potential for H S 2 2

emissions. In the amine gas sweetening process, the amine solution absorbs H S, CO , and 2 2

VOCs. After the amine solution is saturated with the acid gases, the solution is piped to the

amine regenerator. The regenerator heats the amine solution and the acid gases are released from

the amine solution through the amine still vent. If emissions from the still vent are released

directly to the atmosphere, H S, CO , and VOC emissions will be released. If amine still vent 2 2

emissions are vented to a flare or incinerator, H S will be oxidized to SO (TNRCC, 1996). 2 2

Since the flare/incineration process converts the H S to SO , the greater the H S concentration in 2 2 2

the tail gas, the greater the SO emissions. Also, CO in the waste gas stream can lower the 2 2
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10.2-16 EIIP Volume II

British thermal unit (BTU) content of the gas, thereby reducing the flare efficiency. Fuel gas can

be added to the waste gas to increase the BTU content and increase the flame's temperature. The

type of auxiliary fuel fired will also impact emissions. VOC emissions are also affected by the

control efficiency of the flare or incinerator (Boyer and Brodnax, 1996). If the still vent

emissions are vented to a SRU, the H S will be converted to elemental sulfur and SO (TNRCC, 2 2

1996). The H S content of the tail gas, as well as the efficiency of the SRU, will affect SO 2 2

emissions.

Emissions resulting from flashing are impacted by the change in pressure to which the entrained

gases are subjected as well as the volume, temperature, and composition of the material being

transferred. Flash losses occur from tanks, gun barrels, and separators, as the fluid moves from

the high pressure lines to atmospheric pressure. Under high pressure, the fluid can readily

dissolve more gases. As pressures are released from the saturated fluid, the dissolved gases will

be released (TNRCC, 1996). All other factors being equal, the greater the pressure drop, the

greater the gas volume released per barrel of oil produced (Boyer and Brodnax, 1996). The

composition of the fluid will also impact emissions.

Emissions from gas actuated pumps will be impacted by the gas composition, fuel supply

pressure, discharge head (pressure), and the flow rate of the liquid pumped, since manufacturer

pump curves estimate gas use based on these variables (Boyer and Brodnax, 1996).

The amount of gas vented by pressure and level controllers is dependent on the manufacturer,

application, age, and orifice size. In general, controllers in liquid service have larger orifices than

those in pressure service. Valves in liquid service are designed to quickly open or close to avoid

throttling which can erode the valve seat and reduce the life of the valve (Boyer and Brodnax,

1996).

Factors affecting internal combustion engine and turbine emissions include engine type/design

and size, fuel type and firing rate, and operating conditions, such as the air to fuel ratio.

Factors affecting blowdown emissions include maintenance schedules, line pressures, and the

volume of gas relieved (TNRCC, 1996). More frequent maintenance results in more frequent gas

relief. Also, since emissions are estimated using the Ideal Gas Law, the greater the line pressure

and the volume of gas to be relieved, the greater the emissions.

Material transportation and loading losses are affected by the composition of the previous

material transported and the current material to be loaded. If the empty cargo tank has not been

cleaned, any vapors remaining in the tank will be expelled during the loading process. Also, the

loading method will impact emissions. Splash loading will result in greater emissions than

submerged pipe fill loading or bottom filling.
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EIIP Volume II 10.2-17

2.4 CONTROL TECHNIQUES

Control techniques and devices typically used in oil and gas field processing operations are

described below and presented in Table 10.2-1. Control efficiency for a specific piece of

equipment will vary depending on the type of equipment and quality of the maintenance/repair

program at a particular facility.

2.4.1 CONTROL TECHNIQUES FOR VOC

VOC is probably the pollutant emitted in greatest quantities from oil and gas field processing

operations. Flares are used as a method of controlling VOC emissions throughout these facilities

when a flash tank is used in conjunction with a condenser. Vapor collection or header systems

are commonly installed at oil and gas field processing operations to collect and route vapors to a

flare or incinerator. Emissions from emergency and process vents (Boyer and Brodnax, 1996),

loading operations (TNRCC, 1996), well casing gases (Rucker and Strieter, 1992), as well as

other emission sources are typically routed to flares or incinerators. Control efficiencies of 98%

for flares (Rucker and Strieter, 1992) and 99% or greater for incinerators can be achieved.

VOC emissions from emergency and process vents may also be routed to a vapor recovery

compressor prior to pipeline injection (Boyer and Brodnax, 1996). Other devices that may be

used to control VOC emissions from storage tanks and loading operations include vapor

collection and vapor balance systems, carbon adsorption systems, and scrubbers (TNRCC, 1996). 

Submerged loading techniques will also help reduce VOC and HAP emissions. Another

technique for reducing VOC and HAP emissions from storage tanks is the use of an internal

floating roof.

Control methods for glycol dehydrators include condensers, flares, vapor recovery units, carbon

adsorption, or combinations of these. Condenser efficiencies range from 35 to 98% depending

on the type of condenser and the size of unit. Water-cooled condensers can achieve 85 to 98%

efficiency. Air-cooled condenser efficiencies range from 35 to 98%. On smaller units, air cooled

condensers are capable of achieving the upper end of this range, but efficiencies tend to decrease

as the glycol dehydrator size increases. In addition, warmer climates may decrease the efficiency

of air-cooled condensers. If the water is efficiently removed from the gas stream during the

glycol dehydration process, the glycol regenerator reboiler can also be used to thermally oxidize

VOC and HAP emissions from the glycol regenerator process vent. However, if the water is not

efficiently removed from the gas stream during glycol dehydration, the glycol regenerator

reboiler can become corroded resulting in inefficient combustion of VOC and HAP emissions. 
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10.2-18 EIIP Volume II

TABLE 10.2-1

TYPICAL OIL AND GAS FIELD PROCESSING EMISSION CONTROL TECHNIQUES

Emission Sources Pollutant Control Technique Typical

Glycol Dehydrators VOC, Condensers 35-98

HAPs

a k

Flare 98 a b

Incinerator 99

Reboiler c a,j,k

Vapor recovery systems c

Carbon adsorption c b

Amine Still Vents H S Flare 98 2

b

Incinerator 99

Sulfur recovery unit c

Emergency and VOC, Flare 98

Process Vents HAPs

a b

Incinerator 99

Vapor recovery compressor prior c a

to injection

Mud Degassing H S, CH Flares 98 2 4

l

CH4

Incinerators 99

Vapor recovery systems c l

Storage Tanks VOC, Flare 98

HAPs

a b

Incinerator 99

Vapor recovery compressor prior c a

to injection

Internal floating roof 60-99b

Vapor balance system c

Carbon adsorption c

Scrubbers c

Loading Losses VOC, Submerged loading 58

HAPs

b,d

Vapor recovery 85-95b

Flare 98 e b

Incinerator 99 e b

Vapor balance system 90 e,f b

Carbon adsorption systems c e

Scrubbers c e

Equipment Leaks VOC Leak detection and repair (LDAR) c, g
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EIIP Volume II 10.2-19

TABLE 10.2-1

(CONTINUED)

Emission Sources Pollutant Control Technique Typical

Pigging Operations VOC, Flares 98

HAP, CH4 Incinerators 99

Internal Combustion NO Non-selective catalytic reduction c

Engines, Rich-burn x

e

low emission combustion c

Internal Combustion NO Selective catalytic reduction c

Engines, Lean-burn x

Torch ignition c

Chamber redesign c

Low emission combustion c

Gas Turbines NO Water/steam injection c x

h

Selective catalytic reduction c h

Low-NO burner c x

Boilers/External NO Low NO burners 30-70

Combustion Devices

x X

i i

Flue gas recirculation 50-75 i i

Selective non-catalytic reduction 25-40 i i

Selective catalytic reduction 80-90 i i

Source: Boyer and Brodnax, 1996. a

Source: Rucker and Strieter, 1992. b

Control efficiency not documented; efficiency may vary depending on operational parameters of emission source c

and/or control technique.

Emission reduction efficiency relative to splash filling. d

Source: TNRCC, 1996. e

For vapor balance systems, the loading loss saturation factors in AP-42 equation have this reduction built into the f

calculation. Control efficiency need only be factored in to the calculation if an uncontrolled emission estimation

technique is applied.

Efficiency of LDAR will vary based on source location (attainment area vs. nonattainment area), the I/M screening g

value for leakers, and the frequency of monitoring.

Source: EPA, 1995a. h

Source: EPA, 1994a. i

The reboiler can be used to thermally oxidize VOC and HAP emissions if water is efficiently removed from the j

gas stream during the glycol dehydration process. 

Water-cooled condensers are generally more efficient than air-cooled condensers for removing water from the gas k

stream during the glycol dehydration process. On smaller units, air-cooled condensers are capable of achieving

the upper end of this range, but efficiencies tend to decrease as glycol dehydrator size increases.

Source: EPA, 1977b. l
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10.2-20 EIIP Volume II

Leak detection and repair (LDAR) programs are used to reduce equipment leak emissions from

components such as valves, pumps, and flanges. Leaking equipment is identified during periodic

inspections with a VOC-detection device. The leaking equipment is logged on a maintenance

schedule and mechanical adjustments are made to repair the leaks. The efficiency of this control

procedure is affected by how often the inspections are conducted and how soon the repairs are

made (some states assume specific LDAR control efficiencies provided certain program criteria

are met). Leakless equipment has been developed to reduce fugitive emission losses from such

equipment as valves and pump seals (Rucker and Strieter, 1992).

Flares can also be used to reduce VOC, HAP and CH emissions collected during pigging 4

operations.

2.4.2 CONTROL TECHNIQUES FOR H S2

Flares and incinerators are used to convert H S in amine still vent streams to SO . SRUs also 2 2

help reduce H S emissions from amine still vent streams. 2

2.4.3 CONTROL TECHNIQUES FOR COMBUSTION EMISSIONS

Water/steam injection, selective catalytic reduction (SCR), and low-NO burners are commonly x

used to reduce NO emissions from gas turbines. Some SCR systems utilize a CO catalyst which x

also reduces CO emissions.

NO abatement devices for rich-burn internal combustion engines primarily include non-selective x

catalytic reduction. Some rich-burn engines can also be prestratified charge engines. Lean-burn

internal combustion engines use SCR, torch ignition or chamber redesign techniques to control

NO emissions. Low emission combustion is also used on internal combustion engines. x

Low NO burners, flue gas recirculation, and selective non-catalytic reduction are control options x

for boilers and other external control devices. Selective catalytic reduction can also be used. The

reader is referred to Chapter 2 of this volume for more information on combustion sources.
EIIP Volume II 10.3-1

3

OVERVIEW OF AVAILABLE METHODS

3.1 DESCRIPTION OF EMISSION ESTIMATION METHODOLOGIES

There are several methodologies available for calculating emissions from oil and gas field

processing operations. The method used is dependent upon available data, available resources,

and the degree of accuracy required in the estimate. In general, site-specific data is preferred

over industry averaged data, such as AP-42 emission factors, for accurate emissions estimates

(EPA, 1995a). Each state may have a different preference or requirement and so it is suggested

that the reader contact the appropriate state or local air pollution agency before deciding on

which emission estimation methodology to use. This document evaluates emission estimation

methodologies with respect to relative accuracy and does not mandate any emission estimation

method. For purposes of calculating peak season daily emissions for State Implementation Plan

inventories, refer to the Environmental Protection Agency’s (EPA) Procedures manual (EPA,

1991a).

This section discusses the methods available for calculating emissions from oil and gas field

processing operations and identifies the preferred method of calculation on a pollutant basis. The

reader should not infer a preference based on the order emission estimation methodologies are

listed in this section. A discussion of the sampling and analytical methods available for

monitoring each pollutant is provided in Chapter 1, Introduction to Stationary Point Source

Emissions Inventory Development.

Emission estimation techniques for auxiliary processes, such as use of EPA's TANKS program to

calculate storage tank emissions, are also discussed in Chapter 1. For equipment leaks, the

reader is referred to the emission estimation methodologies identified in Chapter 4, Preferred

and Alternative methods for Estimating Fugitive Emissions from Equipment Leaks.

3.1.1 STACK SAMPLING

Stack sampling provides a "snapshot" of emissions during the period of the stack test. Stack tests

are typically performed during either representative (i.e., normal) or maximum load conditions,

depending upon the requirements of the state. Samples are collected from the stack using probes

inserted through a port in the stack wall, and pollutants are collected in or on various media and

sent to a laboratory for analysis. Emissions rates are then determined by multiplying the

pollutant concentration by the volumetric stack gas flow rate. Because there are many steps in
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10.3-2 EIIP Volume II

the stack sampling procedures where errors can occur, only experienced stack testers should

perform such tests.

3.1.2 EMISSION FACTORS

Emission factors are available for many source categories and are based on the results of source

tests performed at one or more facilities within an industry. Basically, an emission factor is the

pollutant emission rate relative to the level of source activity. Chapter 1 of this volume contains

a detailed discussion of the reliability, or quality, of available emission factors. EPA-developed

emission factors for criteria and hazardous air pollutants are available in AP-42, the Locating and

Estimating Series of documents, and the Factor Information REtrieval system (FIRE). Emission

factors are also available from various industrial associations such as the American Petroleum

Institute (API), the Gas Research Institute (GRI), and the Chemical Manufacturers Association

(CMA). In addition, manufacturers often conduct research to develop emission factors for

specific pieces of equipment. For a single facility, stack tests are usually preferable over

emission factors, but for estimating emissions across a source category, emission factors can be

used and may be the only reasonable means of estimating emissions due to the number of sources

or lack of individual facility emission estimates.

3.1.3 CALCULATION PROGRAMS

Several calculation programs or theoretical “models” are available for use in estimating

emissions from oil and gas field processing operations. Emission estimating programs/models

are available for the following types of emission sources:

& Glycol dehydrators;

& Gas sweetening units;

& Emergency and process vents;

& Equipment leaks;

& External combustion devices;

& Internal combustion engines/gas turbines;

& Storage tanks;

& Flash losses; and

& Loading operations.
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EIIP Volume II 10.3-3

Inputs for programs/models generally fall into the following categories: chemical/physical

properties of the material(s) involved (e.g., vapor pressure, vapor molecular weight), operating

data (e.g., amount of material processed, operating hours), and physical characteristics/properties

of the source (e.g., tank color, tank diameter).

The American Petroleum Institute (API) has developed the Exploration and Production

Emissions Calculator (EPEC) and E&P TANK models. The EPEC model integrates user input,

emissions calculations, and data summaries for many equipment types used in the oil and natural

gas production industry (API, 1998). EPEC may be used to estimate emissions of VOC, HAPs, 

criteria pollutants, and other regulated pollutants.

The E&P TANK model was developed by the API and Gas Research Institute (GRI) and is

designed to use site specific information to predict VOC and HAP emissions (flashing, working,

and standing losses) from petroleum production field storage tanks (API, 1997).

GRI developed the GRI-HAPCalc model which estimates emissions from six major process units

and from equipment leaks from the natural gas production industry. The GRI-HAPCalc model

allows the use of AP-42 emission factors, factors based on literature data, factors based on GRI

data, and user-defined factors.

API, in collaboration with GRI, developed the AMINECalc model to estimate HAP and VOC

emissions from amine-based sour gas and natural gas liquid sweetening unit.

When using any emission estimation model, the user should be cautious when collecting input

data to make sure the correct data is collected and entered into the model. In addition, most

models offer default values for some parameters if process-specific data is not available. While

simplifying the data collection process, use of the defaults that are not appropriate for a particular

unit may result in invalid or inaccurate emission estimates. In all cases, therefore, the user is

encouraged to collect and use process-specific data to obtain the most accurate estimate that the

model is capable of producing.

Also, depending on the purpose of the inventory, the user should check with the state or local

agency to confirm the model is acceptable.

3.1.4 ENGINEERING CALCULATIONS

Various engineering calculations are also used to estimate emissions from oil and gas field

processing operations. These calculations require data inputs similar to the calculation programs. 

Engineering calculations are available for the following sources:

& Emergency and process vents;
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10.3-4 EIIP Volume II

& Gas actuated pumps;

& Gas sweetening;

& Sulfur recovery units;

& Flares;

& Pneumatic devices; 

& Mud degassing;

& Glycol dehydrators;

& Flash losses;

& Blowdown;

& Well blowouts;

& Well testing; and

& Loading losses

3.2 COMPARISON OF AVAILABLE EMISSION ESTIMATION

METHODOLOGIES

Table 10.3-1 identifies the preferred and alternative emission estimation approach(es) for

selected pollutants. Table 10.3-1 is ordered according to the relative accuracy of the emission

estimation approach. The reader and the local air pollution agency must decide which emission

estimation approach is applicable based on costs and air pollution control requirements in their

area. The method chosen should also recognize the time specificity of the emission estimate and

the data quality. The quality of the data will depend on a variety of factors including the number

of data points generated, the representativeness of those data points, and the proper operation and

maintenance of the equipment being used to record the measurements. In general, source tests

are preferable over emission factors for estimating emissions from a specific source operating

under specific conditions, but for emissions across a source category, emission factors can be

used and may be the only reasonable means of estimating emissions due to the number of sources

or lack of individual emission factors. 
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EIIP Volume II 10.3-5

TABLE 10.3-1

SUMMARY OF PREFERRED EMISSION ESTIMATION METHODS FOR OIL AND GAS FIELD

PROCESSING OPERATIONS

Emission Source Pollutanta Preferred Emission Estimation

Approach Ordered by Accuracyb

Internal combustion engines CO, NO , SO , VOC, PM , 1. Measurement x 2 2.5

PM , HAPs, CH , CO 2. EPA/state/other published 10 4 2

emission factors

Gas turbines NO CO, PM , PM , CH , 1. Measurement x 2.5 10 4

CO 2. EPA/state/other published 2

emission factors

Boilers/External flame burners VOC, SO , PM PM , CH , (See Chapter 2 of this series) 2 2.5 10 4

CO , HAPs, NO , CO 2 x

Mud degassing VOC, HAPs, CH H S Displacement equation 4, 2

Shale shakers/oil-based muds VOC, HAPs, CH , H S EPA/State/other published emission 4 2

factors

Glycol dehydrator VOC, HAPs 1. GRI-GLYCalc emission model

2. Measurement

3. Rich/lean method

Gas sweetening - amine units SO , H S 1. Displacement

venting to smokeless flare or tail gas Equation/Stoichiometry

incinerator 2. EPA/state/other published

2 2

emission factors

VOC, HAPs Destruction and removal efficiency

Gas sweetening - amine units CO , H S 1. Displacement Equation

venting to atmosphere 2. Measurement 2 2

3. Rich/lean method

VOC, HAPs AMINECalc Model

Gas sweetening amine units venting SO , H S, HAPs 1. Sulfur recovery efficiency

to sulfur recovery unit 2. EPA/state/other published 2 2

emission factor
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10.3-6 EIIP Volume II

TABLE 10.3-1

(CONTINUED)

Emission Source Pollutanta Preferred Emission Estimation

Approach Ordered by Accuracyb

Emergency and process vents VOC, HAPs, CH Displacement Equation 4

Flares NO , CO, CH EPA/state/other published emission x 4

factors

VOC, HAPs Destruction and removal efficiency

SO , H S Displacement Equation/Stoichiometry 2 2

Gas actuated pumps VOC, HAPs, CH Displacement Equation 4

Loading losses VOC, HAPs, CH 1. EPA published equations 4

2. Measurement

Pigging operations VOC, HAPs, CH Measurement 4

Pneumatic devices VOC, HAPs, CH 1. Displacement Equation 4

2. EPA/state/other published

emission factors

Storage tanks VOC, HAPs, CH 1. TANKS model (See Chapter 1 of

Working losses this series)

Breathing losses 2. GRI-HAPCalc

4

3. E&P Tank

Storage tanks VOC, HAPs See methods for “Flash losses” listed

Flash losses below.

Flash losses - black oil systems VOC, HAPs 1. E&P Tank Model

2. EPEC Model

3. Vazquez-Beggs/Rollins, McCain,

and Creeger Correlations

Flash losses - gas condensate VOC, HAPs EC/R algorithm or E&P Tank model

systems

c

Blowdown VOC, HAPs, CH Displacement Equation 4

Equipment leaks VOC, HAPs, CH (See Chapter 4 of this series) 4

Blowout VOC, HAPs, CH 1. Displacement Equation 4

Well testing VOC, HAPs, CH Displacement Equation 4

VOC = Volatile organic compounds; HAPs = Hazardous air pollutants. a 

Preferred emission estimation approaches do not include considerations such as cost. The costs, benefits, and b 

relative accuracy should be considered prior to method selection. Non-regulatory agency personnel are advised to

check with their local air pollution control agency before choosing a preferred emission estimation approach.

Nizich and EC/R, 1999, reference lists results of both methods. c
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EIIP Volume II 10.3-7

3.2.1 STACK SAMPLING

Without considering cost, stack sampling is the preferred emission estimation methodology for

NO , CO, VOC, total hydrocarbons (THC), PM , PM , metals, and speciated organics. EPA x 2.5 10

reference methods and other methods of known quality can be used to obtain accurate estimates

of emissions at a given time for a particular facility. It should be noted, however, that stack

sampling provides a snapshot of emissions at the test conditions and does not address variability

over time.

3.2.2 EMISSION FACTORS

Due to their availability and acceptance in the industry, emission factors are commonly used to

prepare emission inventories. The user should recognize that, in most cases, emission factors

are averages of available industry-wide data, with varying degrees of quality, and may not be

representative of individual facilities within that industry. 

3.2.3 CALCULATION PROGRAMS

Calculation programs often provide a more accurate estimate than emission factors, although

they may require considerably more effort in some cases. Because the program inputs require

process specific information, the results are process specific estimates.

3.2.4 ENGINEERING CALCULATIONS

Similar to the calculation programs, engineering calculations often provide more accurate

estimates than emission factors, although they may also require considerably more effort in

some cases. Because the calculations are based on process specific information, the results are

process specific estimates. Engineering calculations may be less accurate than emission factors

since it may be necessary to make several assumptions when process specific data are not

available.
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EIIP Volume II 10.4-1

4

PREFERRED METHODS FOR

ESTIMATING EMISSIONS

This section describes the preferred methods for estimating emissions for specific types of

sources typically found in oil and gas field processing operations and provides examples to

illustrate the use of each calculation technique. For certain source types (e.g., material storage),

the reader is referred to other documents or other chapters in this document for details on using

the suggested methodology.

The reader is also referred to Chapter 4 of this series of documents for emission estimation

methods for equipment leaks and to Chapter 2 of this series of documents for emission

estimation methods for boilers. Emission estimation methods for wastewater sources can be

found in Chapter 5 of this series of documents. In addition, equipment and emissions from offshore operations, although not specifically addressed in this document, are believed to be similar

to those from on-shore operations. Preferred and alternative emission estimation methodologies

for off-shore sources are, therefore, expected to be the same as for on-shore sources. Depending

on the purpose of the emission inventory, the inventory preparer should consider inclusion of

emissions from these additional source types. 

Table 10.4-1 lists the variables used in Equations 10.4-1 through 10.4-16.

4.1 EMISSION CALCULATIONS USING EMISSION FACTORS

Emission factors are commonly used to calculate emissions from oil and gas field processing

operations. EPA maintains a compilation of emission factors in AP-42 for criteria pollutants

and HAPs (AP-42, 5th Edition, January 1995). The Factor Information and REtrieval system

(FIRE) (EPA, 1998) is a database containing AP-42 emission factors as well as other emission

factors that may be found in EPA documents such as the “Locating and Estimating” series for

toxic pollutants. In addition, manufacturers often provide emission factors for specific

equipment types. Emission factors for equipment leaks may be found in Protocol for 
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10.4-2 EIIP Volume II

TABLE 10.4-1

LIST OF VARIABLES AND SYMBOLS

Variable Symbol Units

Emissions E Typically lb/hr of pollutant x x

Emission factor EF Various x

Activity, production or flow rate Q Various

Volume of fuel fired V Various

Heating value of the fuel H Various

Gas molecular weight MW lb/lb-mole

Mass fraction X lb x/total lb x

Molar Volume of ideal gas C scf/lb-mole

Mole fraction of pollutant x in gas Y lb-mole x/total lb-mole

stream x

Molecular weight of pollutant x MW lb x/lb-mole x x

Molecular conversion ratio of M lb-mole x/lb-mole i

pollutant i to pollutant x x

Equilibrium ratio for component x K lb-mole x (vapor)· lb-mole x

(liquid)/lb-mole x (liquid)·

lb-mole (vapor)

Vapor pressure of component x at P (T) psia

temperature T x

Operating pressure P psia

Vapor pressure of material P pounds per square inch v

absolute (psia or atm)

Mole fraction of vapor flashed Y lb-mole (vapor)/lb-mole v

(liquid)

Density of condensate liquid 
oil lb/gallon

Days per year operation D Days/year
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EIIP Volume II 10.4-3

TABLE 10.4-1

(CONTINUED)

Variable Symbol Units

Temperature T Various

Molecular weight of vapor MW lb/lb-mole v

Loading loss saturation factor S Dimensionless

Arrival emission factor C lb/Mgal A

Generated emission factor C lb/Mgal G

Vapor growth factor G Dimensionless

Recovery/production factor F lb-mole x/lb-mole x

Recovery efficiency RE %

Destruction and removal efficiency DRE %

Stack gas concentration C Mg/m or ppmvd x

3

Equipment Leak Emission Estimates (EPA-453/R-95-017, 1995h) and Calculation Workbook

for Oil and Gas Production Equipment Fugitive Emissions (API, 1996). 

Emission factors are the preferred emission estimation methodology for the following types of

sources found in oil and gas field production and processing operations:

& Internal combustion engines/turbines; 

& Flares; and

& Shale shakers.

Much work has been done to develop emission factors for HAPs, and AP-42 revisions include

these factors (EPA, 1995a,b). Some states have developed their own HAP emission factors for

certain source categories and require their use in any inventories including HAPs. In addition,

industry organizations such as GRI and API have developed emission factors for HAPs as well

as criteria pollutants for many sources which many key gas producing states recommend for use. 
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10.4-4 EIIP Volume II

Refer to Chapter 1 of Volume III for a complete discussion of available information sources for

locating, developing, and using emission factors as an estimation technique.

Emission factors developed from measurements for a specific source may sometimes be used to

estimate emissions at other sites. For example, a company may have several units of similar

model and size; if emissions were measured from one unit, an emission factor could be

developed and applied to other similar units. It is advisable to consult with state/local agencies

or the EPA prior to selection of an emission factor.

The basic equation for using an emission factor to calculate emissions is the following:

E = EF * Q (10.4-1) x x

where:

E = Emissions of pollutant x x

EF = Emission factor of pollutant x x

Q = Activity or production rate

It should also be noted that depending on the emission factor, activity rate, and desired

emissions units, additional variables may need to be factored into the equation, such as sulfur

content of the fuel, hours per year of operation, and conversion from pounds to tons. For some

sources (e.g., combustion sources), emission factors may be based on the Btu fired rather than

volume of fuel fired. The actual Btu firing rate can be calculated based on the volume of fuel

fired and the heating value of the fuel using the following equation:

Q = V * H (10.4-2)

where:

Q = Activity or production rate to be used in equation 10.4-1

V = Volume of fuel fired

H = Heating value of the fuel

Calculations using emission factors are presented in Examples 10.4-1 through 10.4-4.

The EPEC model uses the emission factor method for estimating emissions from internal

combustion engines, turbines, boilers, flares, and heater treaters. In some cases, the user has the

choice of applying GRI or EPA AP-42 emission factors. 

The GRI-HAPCalc model also uses the emission factor method to estimate HAP as well as

criteria pollutant emissions from internal combustion engines, turbines, and external combustion

devices. Users have the choice of emission factors based on GRI literature, GRI field tests, or

EPA AP-42.
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EIIP Volume II 10.4-5

Example 10.4-2

Example 10.4-2 shows how potential hourly CO emissions may be calculated for a gas 2

turbine. The CO emission factor is from Table 3.2-2 in AP-42. The heating value of the 2

natural gas is 1,000 MMBtu/MMscf. The rated capacity of the turbine is 50 MMBtu/hr. The

turbine is operated 2,500 hours per year.

EF = 110 lb/MMBtu CO2

Q = 50 MMBtu/hr

E = EF * Q CO2 CO2

= 110 lb/MMBtu * 50 MMBtu/hr = 5,500 lb/hr

= 5,500 lb/hr * 2,500 hr/yr = 13,750,000 lb/yr

= 13,750,000 lb/yr * ton/2,000 lb = 6,875 ton/yr

= 6,875 ton/yr

Example 10.4-1

Example 10.4-1 shows how potential hourly CO emissions may be calculated for a 2

1 MMBtu/hr internal combustion engine firing natural gas. The CO emission factor is from 2

AP-42, Table 3.2-2. The heating value of the natural gas is 1,000 MMBtu/MMscf. At its

rated capacity (1 MMBtu/hr) the fuel fire rate is 0.001 MMscf/hr. The engine operates for

4,000 hours per year.

EF = 110 lb/MMBtu CO2

Q = 0.001 MMscf/hr

E = EF * Q CO2 CO2

= 110 lb/MMBtu * 0.001 MMscf/hr * 1,000 MMBtu/MMscf = 110 lb/hr

= 110 lb/hr * 4,000 hr/yr = 440,000 lb/yr

= 440,000 lb/yr * ton/2,000 lb = 220 ton/yr

= 220 ton/yr

In all cases, it is advisable to consult with state/local agencies or the EPA prior to selection of an

emission factor.
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Example 10.4-3

Example 10.4-3 illustrates the use of emission factors to calculate CO emissions from a

natural gas fired steam generator with rated capacity of 55 MMBtu/hr. At its rated capacity,

the fuel fire rate is 0.055 MMscf/hr. The CO emission factor is from Table 1.4-2 in AP-42. 

The source is operated 8,760 hours per year.

Q = 0.055 MMscf/hr

EF = 35 lb/MMscf CO

E = Q * EF CO CO

= 0.055 MMscf/hr * 35 lb/MMscf = 1.9 lb/hr

= 1.9 lb/hr * 8,760 hr/yr = 16,600 lb/yr

= 16,600 lb/yr * ton/2,000 lb = 8.3 ton/yr

= 8.3 ton/yr

The reader is referred to Chapter 3 of this volume for more information on steam generators.

Example 10.4-4

Example 10.4-4 shows how potential hourly NO emissions may be calculated for a x

smokeless flare. The NO emission factor is from the CMA flare study (CMA). The heat x

content of the inlet gas is assumed to be 1,030 MMBtu/MMscf, and the gas processing rate is

assumed to be 0.0002 MMscf/hr for 8,760 hours per year.

EF = 0.1380 lb/MMBtu NOx

V = 0.0002 MMscf/hr

H = 1,030 MMBtu/MMscf

Q = V * H

= 0.0002 MMscf/hr * 1,030 MMBtu/MMscf

= 0.206 MMBtu/hr

E = EF * Q NOx NOx

= 0.1380 lb/MMBtu * 0.206 MMBtu/hr = 0.0284 lb/hr 

= 0.0284 lb/hr * 8,760 hr/yr = 249 lb/yr

= 249 lb/yr * ton/2,000 lb = 0.124 ton/yr

= 0.124 ton/yr
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Example 10.4-5

Example 10.4-5 estimates VOC and HAP emissions from a shale shaker processing oil-based

mud. The mud flow rate is 500 gal/min and oil-based drilling muds are used 8 days per year. 

The emission factor is 0.36 lb/Mgal (Mgal = 1,000 gallons) throughput (EPA, 1977b). The

benzene content of the VOC is 25%.

Q = 500 gal/min

EF = 0.36 lb/Mgal VOC

X = 0.25 lb benzene/lb VOC benzene

E = Q * EF VOC VOC

= 500 gal/min * 0.36 lbVOC/Mgal * Mgal/1,000 gal

= 0.18 lb VOC/min * 60 min/hr * 24 hr/day * 8 days/yr = 2,074 lb VOC/yr

= 2,074 lb VOC/yr * ton/2,000 lb * 1.037 ton VOC/yr

= 1.037 ton VOC/yr

E = E * X benzene VOC benzene

= 2,074 lb VOC/yr * 0.25 lb benzene/lb VOC

= 518 lb benzene/yr * ton/2,000 lb

= 0.26 ton benzene/yr

4.2 EMISSION CALCULATIONS USING EMISSION MODELS

Emission models are the preferred emission estimation technique for glycol dehydrators, storage

tanks, flash losses from black oil systems, and VOC and HAP losses from amine-based gas

sweetening units venting to the atmosphere. The models for each of these sources are discussed

below. Depending on the purpose of the inventory, the user should check with the state or local

agency to confirm the model is acceptable.

4.2.1 EMISSION MODEL FOR GLYCOL DEHYDRATORS

VOC and HAP emissions from glycol dehydrators can be estimated using the Gas Research

Institute (GRI) model GRI-GLYCalc. GLYCalc provides users the option of applying

thermodynamic equations or the Rich/Lean method to estimate emissions. The preferred

method of estimating emissions is use of the GLYCalc thermodynamic equations. The

Rich/Lean method is discussed later in Section 5.
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The preferred method uses fundamental chemical engineering thermodynamics along with

empirical data and correlations to make emissions estimates (GRI, 1997). The software is

designed as a screening tool to determine if emissions from a unit are of concern. In addition,

GRI-GLYCalc only estimates emissions from EG and TEG units (Boyer and Brodnax, 1996). 

Therefore, if a more accurate estimate is required, or if the unit is not an EG or TEG unit, an

alternative emissions estimation method should be selected. For information to obtain GRIGLYCalc contact GRI.

GLYCalc requires process-specific data to produce an accurate emission estimate. As with any

emission estimation model, the user should be cautious when collecting this data to make sure

the correct data is collected at the right point in the process line. In addition, models including

GLYCalc offer default values for some parameters if process-specific data is not available. 

While simplifying the data collection process, use of defaults that are not appropriate for a

particular unit may result in invalid or inaccurate emission estimates. In all cases, therefore, the

user is encouraged to collect and use process-specific data to obtain the most accurate emission

estimate.

In addition, recommended guidelines for using the GLYCalc model and a Glycol Inspection

Checklist developed and used by the Louisiana Department of Environmental Quality are

included as Appendix B. Specific process parameters are listed along with acceptable ranges

and suggested guidelines when using the GLYCalc model and are based on data collected from

the field. If the acceptable ranges or the suggested guidelines are not appropriate for a particular

unit, the user should select an alternative emission estimation technique. The checklist

identifies specific data requirements for use with the GLYCalc model (LADEQ, 1998b).

4.2.2 EMISSION MODEL FOR LIQUID MATERIAL STORAGE

The preferred method for calculating working and breathing losses from storage tanks is the use

of equations presented in AP-42. EPA has developed a software package (TANKS) for

calculating these types of emissions. The TANKS computer program is based upon API

equations that were derived for petroleum products, such as, gasoline, diesel fuel, jet fuel and

stable crude oil (crude oil without dissolved gasses in solution that could be flashed from

solution at a lower pressure). The TANKS computer program is commonly used to quantify

working and breathing loss emissions. TANKS has chemical, climatological and component

loss factor databases, but still requires knowledge of data specific to tank design and operation.

You should check with your local or state authority as to whether TANKS is required for your

facility. The use of the TANKS program for calculating emissions from storage tanks is

discussed in Chapter 1 of this volume, Introduction to Stationary Point Source Emissions

Inventory Development. Flash losses from storage tanks can be estimated using several

approaches identified later in this chapter (See Sections 4.2.3, 4.3.2, and 5.3).
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4.2.3 E&P TANK EMISSION MODEL FOR FLASH LOSSES

Recommendations for preferred methodologies for flash losses are based upon information

generated by EPA’s Emission Standards Division during development of the Oil and Gas

Production NESHAP and limited datasets used for model development and verification

restricting model applicability and from information provided by API.

The preferred method for estimating VOC and HAP flash losses from petroleum production

storage tanks in black oil systems is the E&P TANK Model. The preferred emission estimation

methodologies for gas condensate systems are the EC/R algorithm and the E&P TANK Model. 

The EC/R algorithm is a more simplified method, however, either method is preferred. The

EC/R algorithm is presented in Section 4.3.2.

The E&P TANK Model developed by API and GRI, can be used for either black oil or gas

condensate systems. Black oil is a hydrocarbon (petroleum) liquid with a gas-to-oil ratio (GOR)

less than 50 cubic meters (1,750 cubic feet) per barrel and an API gravity less than 40 degrees. 

Gas condensate is a hydrocarbon (petroleum) liquid with a GOR greater than or equal to

50 cubic meters (1,750 cubic feet) per barrel and an API gravity greater than or equal to

40 degrees (FR 2/6/98). The E&P TANK Model is valid for liquids with API gravity ranging

from 15 to 68 degrees.

The E&P TANK Model estimates emissions by applying rigorous thermodynamic relationships

based on vapor-liquid equilibrium conditions from the Peng-Robinson equation-of-state

(Martino, 1997). Data requirements include liquid composition, separator temperature and

pressure, Reid Vapor Pressure of the liquid, API gravity of the liquid and the liquid production

rate. For more information or to obtain a copy of the E&P TANK model, contact API.

4.2.4 EMISSION MODEL FOR AMINE SWEETENING UNIT

The method for estimating VOC and HAP emissions from amine units for sweetening natural

gas and natural gas liquids venting to the atmosphere is use of the AMINECalc model. Data

requirements depend on the option selected for calculating emissions. The mass balance option

requires flow rates of rich and lean amine streams and composition of rich amine stream exiting

the absorption column. Gas process options require sour gas feed data, lean amine circulation

rate, and number of absorber trays.

4.3 EMISSION CALCULATIONS USING ENGINEERING EQUATIONS

Use of engineering equations is the preferred technique for estimating emissions from

emergency and process vents, gas actuated pumps, pressure/level controllers, blowdown, well

blowouts, well testing, gas sweetening units, flash losses from gas condensate systems,
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transportation loading losses, sulfur recovery units and flares. Engineering equations are also

preferred for non-amine gas sweetening units and TEG glycol dehydrators. These equations are

discussed and illustrated below.

4.3.1 DISPLACEMENT EQUATION

Use of a displacement equation is the preferred method for estimating VOC, HAP, and CH4

emissions from emergency and process vents, gas actuated pumps, pressure/level controllers,

blowdown, well blowouts, and well testing. This displacement equation can also be used to

estimate H S and CO emissions from gas sweetening units venting to the atmosphere and for 2 2

H S emissions from mud degassing operations. The following equations can be applied to 2

estimate emissions when no chemical conversion occurs:

E = Q * MW * X * 1/C (10.4-3) x x

where:

E = Emissions of pollutant x x

Q = Volumetric flow rate/volume of gas processed

MW = Molecular weight of gas

= Specific gravity of gas molecular weight of air *

X = Mass fraction of pollutant x in gas x

C = Molar volume of ideal gas, 379 scf/lb-mole at 60 degrees Fahrenheit and

1 atmosphere

Speciated VOC emissions are calculated using the following equation:

E = E * X (10.4-4) x VOC x

where:

E = emissions of pollutant x; x

E = total VOC, calculated using equation 10.4-3; and VOC

X = mass fraction of species x in VOC. x

For well blowouts, if the amount of gas processed is unknown, the references “Methane

Emissions from the U.S. Petroleum Industry” (EPA, 1996) and “Atmospheric Emissions from

Offshore Oil and Gas Development and Production” (EPA, 1977b) provide some background

information that may be of use.

Calculations using equations 10.4-3 and 10.4-4 are presented in Examples 10.4-6 through

10.4-13.
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-11

Example 10.4-6

Example 10.4-6 shows how VOC and HAP emissions can be calculated from emergency and

process vents using the displacement equation. The gas volume released is assumed to be

10,000 scf/yr, the molecular weight of the gas is assumed to be 21 lb/lb-mole, and the VOC

weight fraction is assumed to be 0.2.

Q = 10,000 scf/yr

MW = 21 lb/lb-mole

X = 0.2 lb VOC/lb VOC

C = 379 scf/lb-mole @ 60(F, 1 atm

E = Q * MW * X * 1/C VOC VOC

= 10,000 scf/yr * 21 lb/lb-mole * 0.2 lb VOC/lb * lb-mole/379 scf = 111 lb VOC/yr

= 111 lb VOC/yr * ton/2,000 lb = 0.055 ton VOC/yr

= 0.055 ton VOC/yr

Xylene content of the exhaust VOC is assumed to be 10% by weight.

X = 0.10 lb xylene/lb VOC xylene

E = 111 lb/yr VOC

E = X * E xylene xylene VOC

= 0.10 lb xylene/lb VOC * 111 lb VOC/yr = 11.1 lb xylene/yr

= 11.1 lb xylene/yr * ton/2,000 lb = 0.0055 ton xylene/yr

= 0.0055 ton xylene/yr

Example 10.4-7

Example 10.4-7 shows how VOC and HAP emissions can be calculated from gas actuated

pumps using the displacement equation. The gas volume consumed is determined from the

manufacturer's pump curve and is assumed to be 2,000 scf/hr, the molecular weight of the

gas is assumed to be 21 lb/lb-mole, and the VOC weight fraction is assumed to be 0.2. The

pumps operate 4,000 hours per year.

Q = 2,000 scf/hr

MW = 21 lb/lb-mole

X = 0.2 lb VOC/lb VOC

C = 379 scf/lb-mole @ 60(F, 1 atm
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-12 EIIP Volume II

Example 10.4-8

Example 10.4-8 shows how VOC and HAP emissions can be calculated from pressure and

level controllers using the displacement equation. The gas volume released is determined by

either obtaining the manufacturer's estimate or by assuming an average release rate per

controller. For this example, the release rate is assumed to be 20 scf/hr. The molecular weight

of the gas is assumed to be 21 lb/lb-mole, and the VOC weight fraction is assumed to be 0.1. 

The controllers are assumed to operate 8,760 hours per year.

Q = 20 scf/hr

MW = 21 lb/lb-mole

X = 0.1 lb VOC/lb VOC

C = 379 scf/lb-mole @ 60(F, 1 atm

E = Q * MW * X * 1/C VOC VOC

= 20 scf/hr * 21 lb/lb-mole * 0.1 lb VOC/lb * lb-mole/379 scf = 0.11 lb VOC/hr

= 0.11 lb VOC/hr * 8,760 hr/yr = 971 lb VOC/yr

= 971 lb VOC/yr * ton/2,000 lb = 0.49 ton VOC/yr

= 0.49 ton VOC/yr

Example 10.4-7 (Continued)

E = Q * MW * X * 1/C VOC VOC

= 2,000 scf/hr * 21 lb/lb-mole * 0.2 lb VOC/lb * lb-mole/379 scf = 22.2 lb

VOC/hr

= 22.2 lb VOC/hr * 4,000 hrs/yr = 88,654 lb VOC/yr

= 88,654 lb VOC/yr * ton/2,000 lb = 44.3 ton VOC/yr

= 44.3 ton VOC/yr

Benzene content of the exhaust VOC is assumed to be 20% by weight.

X = 0.2 lb benzene/lb VOC benzene

E = 88,654 lb/yr VOC

E = X * E benzene benzene VOC

= 0.20 lb benzene/lb VOC * 88,654 lb VOC/yr = 17,731 lb benzene/yr

= 17,731 lb benzene/yr * ton/2,000 lb = 8.87 ton benzene/yr

= 8.87 ton benzene/yr
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-13

Example 10.4-9

Example 10.4-9 calculates VOC and HAP emissions resulting from blowdown of a group of

compressor engines. Blowdown occurs 4 times per year and the total volume of gas vented

per event is 150 scf. The total annual volume of gas is 600 scf/yr. The molecular weight of

the gas is 29.2 lb/lb-mole and the mass fraction of VOC in the gas is 0.3.

Q = 600 scf/yr

MW = 29.2 lb/lb-mole

X = 0.3 lb VOC/lb VOC

C = 379 scf/lb-mole @ 60(F, 1 atm

E = Q * MW * X * 1/C VOC VOC

= 600 scf/yr * 29.2 lb/lb-mole * 0.3 lb VOC/lb * lb-mole/379 scf = 13.9 lb VOC/yr

= 13.9 lb VOC/yr * ton/2,000 lb = 0.007 ton VOC/yr

= 0.007 ton/yr

Gas analysis indicates benzene content of VOC is 25% by weight.

X = 0.25 lb benzene/lb VOC benzene

E = 13.9 lb/yr VOC

E = X * E benzene benzene VOC

= 0.25 lb benzene/lb VOC * 13.9 lb VOC/yr = 3.5 lb benzene/yr

= 3.5 lb benzene/yr * ton/2,000 lb = 0.002 ton benzene/yr

= 0.002 ton benzene/yr

Example 10.4-8 (Continued)

Xylene content of the exhaust VOC is assumed to be 10% by weight.

X = 0.10 lb xylene/lb VOC xylene

E = 971 lb/yr VOC

E = X * E xylene xylene VOC

= 0.10 lb xylene/lb VOC * 971 lb VOC/yr = 97.1 lb xylene/yr

= 97.1 lb xylene/yr * ton/2,000 lb = 0.049 ton xylene/yr

= 0.049 ton xylene/yr
930,000 scf/yr  22 lb/lb	mole  0.10 lb VOC

lb  1 lb	mole379 scf

930,000 scf/yr  22 lb/lb	mole  0.90 lb CH4

lb  1 lb	mole

379 scf

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-14 EIIP Volume II

Example 10.4-10

Example 10.4-10 calculates methane emissions from well blowout using the displacement

equation. During the year, 1 well blowout occurred which lasted for 2 days. The well

production rate is 465,000 SCF/day. It is assumed that the daily gas production rate of the well

for those 2 days is released to the atmosphere. The amount of gas released to the atmosphere,

therefore, is 930,000 SCF (465,000 SCF/day * 2 days). The mass fraction of CH in the gas is 4

0.90. The mass fraction of VOC in the gas is 0.10. The molecular weight of the gas is 22 lb/lbmole

Q = 930,000 scf/yr

C = 379 scf/lb-mole @ 60(F, 1 atm

MW = 22 lb/lb-mole

X = 0.10 VOC

X = 0.90 CH4

E = Q * MW * X * 1/C VOC VOC

= 

= 5,398 lb VOC/yr * ton/2,000 lb

= 2.70 ton VOC/yr

E = Q * MW * X * 1/C CH4 CH4

= 

/2,000 lb = 48,586 lb CH /yr * ton 4

= 24.3 ton CH /yr. 4

Example 10.4-11

Example 10.4-11 shows how VOC and HAP emissions can be estimated for well testing

operations using the displacement equation. A total of 100 gas wells are tested each year and

the total volume of gas vented is 285,000 scf/yr. The average VOC concentration of the vented

gas is 0.15 lb VOC/lb. The average toluene concentration of the VOC is 0.25 lb

toluene/lbVOC.

Q = 285,000 scf/yr

MW = 21 lb/lb-mole

X = 0.15 lb VOC/lb VOC

X = 0.25 lb toluene/lb toluene
285,000 scf/yr  21 lb/lb	mole  0.15 lb VOC

lb  lb	mole379 scf  2,369 lb VOC/yr

2,369 lb VOC/yr  ton

2,000 lb 
 1.2 ton VOC/yr

592 lb toluene/yr  ton

2,000 lb 
 0.30 ton toluene/yr

12.5 mmscf/day  18.33 lb/lb	mole  0.19 lb CO2

lb  lb	mole

379 scf  106 scfmmscf

12.5 mmscf/day  18.33 lb/lb	mole  0.01 lb H2S

lb  lb	mole

379 scf  106 scfmmscf

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-15

Example 10.4-11 (Continued)

C = 379 scf/lb-mole @ 60(F, 1 atm 

E = Q * MW * X * 1/C VOC VOC

 = 

= 

= 1.2 ton VOC/yr

E = X * E toluene toluene VOC

= 0.25 lb toluene/lb VOC * 2,369 lb VOC/yr = 592 lb toluene/yr

 = 

= 0.30 ton toluene/yr

Example 10.4-12

Example 10.4-12 illustrates the calculation of CO and H S emissions from an amine-based gas 2 2

sweetening unit that vents to the atmosphere. The sour gas flowrate is 12.5 mmscf/day. The

mass fraction of CO and H S in the sour gas is 0.19 and 0.01, respectively. The molecular 2 2

weight of the sour gas is 18.33 lb/lb-mole. The unit operates continuously for 200 days

throughout the year.

Q = 12.5 mmscf/day

MW = 18.33 lb/lb-mole

X = 0.19 lb CO /lb CO2 2

X = 0.01 lb H S/lb H2S 2

C = 379 scf/lb-mole @ 60(F, 1 atm

E = Q * MW * X * 1/C CO2 CO2

= 

= 114,865 lb CO /day * 200 days/yr * ton/ 2,000 lb = 11,486 ton CO /yr 2 2

= 11,486 ton CO /yr 2

E = Q * MW * X * 1/C H2S H2O

= 

= 6,046 lb H S/day * 200 day/yr * ton/2,000 lb = 605 ton H S/yr 2 2

= 605 ton H S/yr 2
10,000 scf/day  18.33 lb/lb	mole  lb	mole

379 scf  0.19 lb CH4

lb 
 91.9 lb CH4day

10,000 scf/day  18.33 lb/lb	mole  lb	mole

379 scf  0.05 lb H2S

lb 
 24.2 lb H2Sday

ESO2
 Q  yH2S 

1

C

 MSO2

 MWSO2

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-16 EIIP Volume II

Example 10.4-13

Example 10.4-13 estimates H S and CH emissions from a drilling mud degassing operation. 2 4

The volume of gas vented to the atmosphere is 10,000 ft . The mass fraction of H S and CH in 3

2 4

gas is 0.05 and 0.19, respectively. The molecular weight of the gas is 18.33 lb/lb-mole. The

degassing operations occurred for four days.

Q = 10,000 scf/day

X = 0.19 lb CH /lb-mole CH4 4

X = 0.05 lb H S/lb-mole H2S 2

MW = 18.33 lb/lb-mole

C = 379 scf/lb-mole

E = Q * MW * 1/C * X CH4 CH4

= 

= 91.9 lb CH /day * 4 days/yr = 368 lb CH /yr 4 4

= 368 lb CH /yr * ton/2,000 lb = 0.184 ton CH /yr 4 4

= 0.184 ton CH /yr 4

E = Q * MW * 1/C * X H2S H2S

= 

= 24.2 lb H S/day * 4 days/yr = 96.8 lb H S/yr 2 2

= 96.8 lb H S/yr * ton/2,000 lb = 0.048 ton H S/yr 2 2

= 0.048 ton H S/yr 2

(10.4-5)

For sources where a chemical conversion takes place, such as gas sweetening units venting to a

flare or incinerator, the displacement equation can be used to estimate SO and H S emissions, 2 2

however, additional factors based on stoichiometry must be applied. The following equation

can be applied to estimate SO emissions from flares or incinerators where H S is converted to 2 2

SO :2

where:

E = SO emissions, lb/yr SO2 2

Q = Volume of gas processed, scf/yr

y = Mole fraction of H S in inlet gas, lb-mole H S/lb-mole H2S 2 2
EH2S 
 Q  yH2S 

1

C

 1 	 MSO2 MWH2S

lb	mole SO2

lb	mole H2S

lb	mole SO2

lb	mole H2S

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-17

(10.4-6)

C = Molar volume of ideal gas, 379 scf/lb-mole at 60 degrees

Fahrenheit and 1 atmosphere

M = Molar conversion ratio from H S to SO , SO2 2 2

(Based on stoichiometry and assuming complete conversion of

H S to SO , M = 1) 2 2 SO2

MW = Molecular weight of SO , lb SO /lb-mole SO SO2 2 2 2

The residual H S emissions from this process can be estimated using the following equation: 2

where:

E = H S emissions, lb/yr H2S 2

Q = Volume of gas processed, scf/yr

y = Mole fraction of H S in inlet gas, lb-mole H S/lb-mole H2S 2 2

C = Molar volume of ideal gas, 379 scf/lb-mole at 60 degrees

Fahrenheit and 1 atmosphere

M = Molar conversion ratio from H S to SO , SO2 2 2

(Based on stoichiometry and assuming complete conversion of

H S to SO , M = 1) 2 2 SO2

MW = Molecular weight of H S, lb H S/lb-mole H S H2S 2 2 2

If the conversion of H S to SO is completed, no residual H S emissions would result. 2 2 2

 50,000 scf/yr  0.2 lb	mole H2S/lb	mole  lb	mole/379 scf  0.98

lb	mole SO2

lb	mole H2S

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-18 EIIP Volume II

Example 10.4-14

Example 10.4-14 shows how SO and H S emissions can be calculated from a gas sweetening 2 2

unit venting to a flare using the displacement equation and assuming 98% conversion of H S to 2

SO . The gas volume released is 50,000 scf/yr, and the mole fraction of H S in the inlet gas is 2 2

0.2.

Q = 50,000 scf/yr

y = 0.2 lb-mole H S/lb-mole H2S 2

C = 379 scf/lb-mole @ 60(F, 1 atm

M = 0.98 lb-mole SO /lb-mole H S SO2 2 2

MW = 64 lb/lb-mole SO2

E = Q * y * 1/C * M * MW SO2 H2S SO2 SO2

 

 * 64 lb SO /lb - mole SO = 1,655 lb SO /yr 2 2 2

= 1,655 lb SO /yr * ton/2,000 lb = 0.83 ton SO /yr 2 2

= 0.83 ton SO /yr 2

Residual H S emissions are calculated below. 2

E = Q * y * 1/C * (1-M ) * MW H2S H2S SO2 H2S

= 50,000 scf/yr * 0.2 lb-mole H S/lb-mole * lb-mole/379 scf * (1-0.98) 2

* 34 lb H S/lb-mole H S 2 2

= 17.94 lb H S/yr * ton/2,000 lb = 0.00897 ton H S/yr 2 2

= 0.00897 ton H S/yr 2

Example 10.4-14 illustrates the use of this equation.

4.3.2 EMISSION EQUATIONS FOR FLASH LOSSES FROM GAS CONDENSATE SYSTEMS

Recommendations for preferred methodologies for flash losses are based upon information

generated by EPA’s Emission Standards Division during development of the Oil and Gas

Production NESHAP and limited datasets used for model development and verification

restricting model applicability and from information provided by API. 

The preferred methods for estimating flash losses from gas condensate systems are the EC/R

algorithm and the E&P TANK Model. The EC/R algorithm is a more simplified method,

however, either method is preferred. The E&P TANK Model is discussed in Section 4.2.3.
Kx 
 Px (T)/P

Yv 
 0.0523(Pv	1.636)

lb	mole componenti,V  lb	molel

lb	mole componenti,l  lb	molev

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-19

(10.4-7)

(10.4-8)

The EC/R algorithm calculates flash emissions based on the pressure drop of the process stream

from the previous process vessel to a storage vessel and was derived from the behavior of the

liquid stream based on changes in stream compositions and pressure (Akin and Battye, 1994). 

This method assumes that the liquid and vapor streams reach equilibrium at standard

temperature and pressure and that the storage tank is at standard temperature and pressure. The

EC/R algorithm is valid for vapor pressure of liquid streams entering the storage tank between

1.6 atm and 5.1 atm. At vapor pressures less than 1.6 atm, flash losses can be assumed to

approach zero. At vapor pressures greater than 5.1 atm, another method should be selected (see

section 10.5.3). For more information on this method, see Akin and Battye, 1994. Procedures

for applying the EC/R algorithm to estimate VOC and HAP emissions are described below.

The first step in calculating flash losses from fixed-roof storage tanks in condensate systems is

to estimate the equilibrium ratio. The equilibrium ratio (K ) in a multi component mixture of x

liquid and vapor phases is defined as the ratio of the mole fraction of that component in the

vapor phase to the mole fraction of that component in the liquid phase. The equilibrium ratio

can be estimated using Raoult’s law and assuming ideal solution behavior:

where:

K = Equilibrium ratio for component i, x

P (T) = Vapor pressure of component i at the condensate liquid storage tank x

temperature T, psia.

P = Pressure of the storage tank, psia

Then, estimate the mole fraction of vapor flashed using the following equation:

where:

Y = Mole fraction of vapor flashed, lb-mole /lb-mole v v l

0.0523 = Coefficient, lb-mole /lb-mole atm v l .

P = Total vapor pressure of the condensate liquid stream in the v

previous vessel, atm
Ex 
 Kx  Q  
oil  Xx  Yv  D  42

lb	mole XV  lb	molel

lb	mole Xl  lb	molev

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-20 EIIP Volume II

(10.4-9)

Example 10.4-15

Example 10.4-15 calculates flash losses resulting from condensate entering a storage tank at

a total vapor pressure of 3.82 atm and a temperature of 70(F. The VOC concentration of the

condensate stream is 0.65 lb/lb. The benzene concentration of the condensate stream is

0.015 lb benzene/lb. At 70(F, the vapor pressure of VOC is 4.23 psia and the vapor pressure

of benzene is 1.54 psia. The volume of condensate processed is 135 bbl/day, and the

condensate density is 7.25 lb/gal. The storage tank is at standard temperature and pressure. 

This source operates 365 days per year.

P (T) = 4.23 psia or lb-mole VOC /lb-mole VOC voc v l

P (T) = 1.54 psia or lb-mole benzene /lb-mole benzene benzene v l

P = 14.7 psia 

P = 3.82 atm v

Q = 135 bbl/day

1.636 = Total vapor pressure of the condensate liquid stream in the

previous vessel at which the flashing losses approach zero, atm

Having estimated the equilibrium ratio and the mole fraction of vapor flashed, emissions can be

calculated as follows:

where:

E = Component x emissions, lb/year x

K = Equilibrium ratio for VOC, x

Q = Volume of condensate liquid processed, bbl/day


 = Density of the condensate liquid, lb/gal oil

X = Mass fraction of component x in the condensate liquid, lb x/lb x

Y = Mole fraction of vapor flashed, lb-mole /lb-mole v v l

D = Days per year of operation, days/year

42 = Conversion from barrels to gallons

Example 10.4-15 illustrates the use of Equations 10.4-7 through 10.4-9. 
0.288

lb	mole VOCv # lb	molel

lb	mole VOCl # lb	molev

 135 bbl/day

0.114 lb	molev

lb	molel

 365days/yr  42 gal/bbl



1 lb	mole VOCl

1 lb	mole VOCv


 320,202 lb/yr

320,202 lb/yr 

ton

2,000 lb 
 160 ton/yr

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-21

Example 10.4-15 (Continued):


 = 7.25 lb/gal oil

X = 0.65 lb/lb voc

X = 0.015 lb benzene/lb benzene

D = 365 days/yr

Calculate the equilibrium ratios:

K = P (T)/P x x

K = 4.23 psia/14.7 psia voc

= 0.288 lb-mole VOC lb-mole /lb-mole VOC lb-mole v l l v

. .

K = 1.54 psia/14.7 psia benzene

= 0.105 lb-mole benzene lb-mole /lb-mole benzene lb-mole v l l v

. .

Calculate the mole fraction of vapor flashed:

Y = 0.0523 * (P -1.636) v v

0.0523 lb-mole atm/lb-mole * (3.82 atm - 1.636 atm) v l

.

= 0.114 lb-mole /lb-mole v l

Calculate emissions:

E = K * Q * voc voc 
oil * X * Y * D * 42 voc v

 

= 

 * 7.25 lb/gal * 0.65 lb VOC/lb * 

 

 

 = 

 

= 160 ton/yr
0.105  lb	mole benzenev  lb	molel

lb	mole benzenel  lb	molev

 135 bbl/day

 7.25 lb/gal  0.015 lb benzene/lb 

 0.114 lb	molev

lb	molel

 365days/yr

 42 gal/bbl  1 lb	mole benzenel

l lb	mole benzenev


 2,694 lb benzene/yr

2,694 lb benzene/yr  ton/2000 lb 
 1.35 ton benzene/yr

1.35 ton benzene/yr

EVOC 
 12.46 

S  PV  MWV  Q

T

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-22 EIIP Volume II

Example 10.4-15 (Continued):

E = K * Q * benzene benzene 
oil * X * Y * D * 42 benzene v 

 

=

 

= 

=

(10.4-10)

4.3.3 EMISSION EQUATIONS FOR LOADING LOSSES

VOC emissions resulting from loading liquid materials into tank trucks and tank cars may be

calculated using the following loading loss equation (EPA, 1995c).

where:

E = VOC loading loss, lb/yr VOC

S = Saturation factor, see Table 5.2-1 in AP-42

P = True vapor pressure of the material in the tank at temperature T, psia V

MW = Vapor molecular weight, lb/lb-mole V

Q = Volume of material loaded, Mgal/yr (Mgal = 1,000 gallons)

T = Temperature of material in the tank, (R.
EVOC 
 (CA  CG)  Q  XVOC

CG 
 1.84  (0.44  PV 	 0.42) 

MWV G

T

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-23

(10.4-11)

(10.4-12)

Calculation of VOC emissions using Equation 10.4-10 is based on the following assumptions:

& The ideal gas law is applicable;

& The previous cargo that generated the vapors being displaced is the same as the

liquid currently being loaded; and

& There is no mass or heat transfer from the loaded liquid to the previously existing

vapors; only displacement is being modeled.

VOC emissions from the loading of crude oil into ships and ocean barges can be estimated using

the following equation (which is presented in Section 5.2 of AP-42):

where:

E = Total loading loss, lb/yr VOC

C = Arrival emission factor, contributed by vapors in the empty tank A

compartment before loading, lb/Mgal loaded. See Table 5.2-3 in AP-42.

C = Generated emission factor, contributed by evaporation during loading, G

lb/Mgal loaded. See equation 10.4-12.

Q = Volume of material loaded, Mgal/yr

X = Mass fraction of VOC in vapor, lb VOC/lb. Default per AP-42 is 0.85 VOC

The parameter C can be calculated using the following equation (per Section 5.2 in AP-42): G

where:

P = True vapor pressure of loaded crude oil, psia. See AP-42 Figure 7.1-5 and V

Table 7.1-2.

MW = Molecular weight of vapors, lb/lb-mole. See AP-42 Table 7.1-2. V

G = Vapor growth factor, 1.02 (dimensionless)

T = Temperature of vapors, (R ((F + 460)
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-24 EIIP Volume II

Example 10.4-17

Example 10.4-17 estimates emissions from a loading operation which loads crude oil into a

ship. The ship's previous cargo was volatile and the cargo tank was not cleaned. Vapor

pressure of the crude oil to be loaded is 5.4 psia and the molecular weight of vapors is

50 lb/lb-mole. Vapor temperature is assumed to be at 75(F. Annual throughput under these

conditions is 500,000 gallons. Mass fraction of VOC in vapor is 0.7.

C = 0.86 lb/Mgal (see AP-42, Table 5.2-3) A

P = 5.4 psia V

MW = 50 lb/lb-mole V

T = 435(R

G = 1.02

Example 10.4-16

Example 10.4-16 calculates loading losses resulting from splash loading crude oil into a tank

truck in dedicated vapor balance service. Tank volume loaded is 100,000 gallons, liquid

temperature is 70(F, true vapor pressure is 3.4 psia, and the molecular weight of vapors is 

50 lb/lb-mole.

Q = 100 Mgal/yr

T = 70 + 460 = 530(R

P = 3.4 psia V

MW = 50 lb/lb-mole V

S = 1.00 (see AP-42, Table 5.2-1)

E = 12.46 * [S * P * MW * Q]/T VOC v v

= 12.46 * [1.00 * 3.4 psia * 50 lb/lb-mole * 100 Mgal/yr]/530(R = 400 lb VOC/yr

= 400 lb VOC/yr * ton/2,000 lb = 0.2 ton VOC/yr

= 0.2 ton VOC/yr

Gas analysis indicates that 5% of the VOC by weight is benzene.

E = E * X benzene VOC benzene

= 400 lb VOC/yr * 0.05 lb benzene/lb VOC = 20 lb benzene/yr

= 20 lb benzene/yr * ton/2,000 lb = 0.01 ton benzene/yr

= 0.01 ton benzene/yr

Examples 10.4-16 and 10.4-17 illustrate the use of these equations.

The EPEC model uses the AP-42 method to estimate emissions from loading operations.
ESO2


 Q  yH2S  Fs  MWS 

1

C



MWSO2

MWS

 FSO2 1 	 RE

100

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-25

Example 10.4-17 (Continued):

Q = 500 Mgal/yr

X = 0.7 VOC

C = 1.84 * (0.44 * P - 0.42) * [MW * G]/T G V V

= 1.84 * (0.44 * 5.4 psia - 0.42) * [50 lb/lb-mole * 1.02]/435(R = 0.42 lb/Mgal

= 0.42 lb/Mgal

E = (C + C ) * Q * X VOC A G VOC

= (0.86 + 0.42) * 500 Mgal/yr * 0.7 lb VOC/lb = 448 lb VOC/yr

= 448 lb VOC/yr * ton/2,000 lb = 0.22 ton VOC/yr

= 0.22 ton VOC/yr

Vapor analysis indicates the mass fraction of benzene in the VOC is 0.4.

E = E * X benzene VOC benzene

= 448 lb VOC/yr * 0.4 lb benzene/lb VOC = 179 lb benzene/yr

= 179 lb benzene/yr * ton/2,000 lb = 0.09 ton benzene/yr

= 0.09 ton benzene/yr

(10.4-13)

4.3.4 EMISSION EQUATIONS FOR SULFUR RECOVERY UNITS

H S and SO emissions from the sulfur recovery process are dependent on the degree of sulfur 2 2

recovery achieved. The following equations can be used to estimate uncontrolled SRU

emissions:

where:

E = SO emission estimate, lb/hr SO2 2

Q = Gas process rate, scf/hr

y = mole fraction of H S in inlet gas stream H2S 2

F = Sulfur recovery factor (1 mole sulfur/mole H S) S 2

MW = Molecular weight of sulfur S

C = Molar volume of ideal gas, 379 scf/mole at 60 degrees Fahrenheit and

1 atmosphere

MW = Molecular weight of SO SO2 2

F = SO production factor (1 mole SO /3 moles S) SO2 2 2

RE = Sulfur recovery efficiency, %
EH2S 
 Q  yH2S  Fs  MWS 

1

C



MWH2S

MWS

 FH2S  1 	 RE

100

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-26 EIIP Volume II

(10.4-14)

Example 10.4-18

Example 10.4-18 calculates emissions from a Claus sulfur recovery unit processing

10,000 scf/hr gas with an inlet H S content of 20% by volume. The process operates 2

6,000 hours per year and has a sulfur recovery efficiency of 95%.

Q = 10,000 scf/hr

y = 0.20 lb-mole H S/lb-mole H2S 2

F = 1 lb-mole S/lb-mole H S S 2

MW = 32 lb S/lb-mole S S

C = 379 scf/lb-mole @ 60(F, 1 atm

where:

E = H S emission estimate, lb/hr H2S 2

Q = Gas process rate, scf/hr

y = mole fraction of H S in inlet gas stream, mole H S/mole H2S 2 2

F = Sulfur recovery factor, 1 mole sulfur/mole H S S 2

MW = Molecular weight of sulfur, lb/mole S

C = Molar volume of ideal gas, 379 scf/mole at 60 degrees Fahrenheit and

1 atmosphere

MW = Molecular weight H S, lb/mole H2S 2

F = H S production factor, 2 mole H S/3 moles S H2S 2 2

RE = Sulfur recovery efficiency

Example 10.4-18 illustrates the use of these equations.
Q  yH2S  FS  MWS  1

C  MWSO2

MWS

 FSO2 1 	 RE

100

10,000scf/hr 0.20lb	moleH2S

lb	mole  1lb	moleS

lb	moleH2S

 32lbS

lb	moleS  lb	mole379scf 

64lbSO2

lb	moleSO2

 1lb	moleSO2

3lb	moleS  1	 95

100

32lbS

lb	moleS


 5.63 lb SO2 hr

Q  yH2S  FS  MWS  1

C  MWH2S

MWS

 FH2S  1 	 RE

100

10,000 scf/hr 0.20lb	moleH2S

lb	mole  1lb	moleS

lb	mole H2S

 32lbS

lb	mole S  lb	mole379scf 

34lbH2S

lb	moleH2S

 2lb	moleH2S

3lb	moleS  1	 95

100

32lbS

lb	moleS


 5.98 lb H2S/hr

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-27

Example 10.4-18 (Continued)

MW = 34 lb H S/lb-mole H S H2S 2 2

F = 2 lb-mole H S/3 lb-mole S H2S 2

MW = 64 lb SO /lb-mole SO SO2 2 2

F = 1 lb-mole SO /3 lb-mole S SO2 2

RE = 95

E SO2 =

= 5.63 lb SO /hr * 6,000 hr/yr = 33,780 lb SO /yr 2 2

= 33,780 lb SO /yr * ton/2,000 lb = 17 ton SO /yr 2 2

= 17 ton SO /yr 2

E = H2S

= 5.98 lb H S/hr * 6,000 hr/yr = 35,880 lb H S/yr 2 2

= 35,880 lb H S/yr * ton/2,000 lb = 18 ton H S/yr 2 2

= 18 ton H S/yr 2
EX 
 Q  yX 

1

C

 MWX  1 	 DRE

100

QyVOC 1

C MWVOC 1	 DRE100

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-28 EIIP Volume II

(10.4-15)

Example 10.4-19

Example 10.4-19 calculates VOC and HAP emissions from a flare. The inlet gas process

rate is 200 scf/hr and contains 25% VOC and 1% toluene, by volume. The flare operates

8,760 hours per year and is 98% efficient.

Q = 200 scf/hr

y = 0.25 scf VOC/scf VOC

y = 0.01 scf xylene/scf toluene

C = 379 scf/lb-mole @ 60(F

MW = 50 lb/lb-mole VOC

MW = 92.13 lb/lb-mole toluene

DRE = 98%

E = VOC

4.3.5 VOC AND HAP EMISSIONS FROM FLARES

The preferred approach for estimating VOC and HAP emissions from sources venting VOC and

HAP emissions to flares is based on the gas processing rate and the destruction and removal

efficiency (DRE) of the flare. The following equation can be applied:

where:

E = Emission estimate for pollutant x, lb/hr x

Q = Gas process rate, scf/hr

y = Mole fraction of pollutant x in inlet stream, lb-mole x/lb-mole x

C = Molar volume of ideal gas, 379 scf/lb-mole @ 60 degrees Fahrenheit

MW = Molecular weight of pollutant x x

DRE = Destruction and removal efficiency, %

Example 10.4-19 illustrates the use of this equation.
200scf0.25 scfVOC/scf 1 lb	mole VOC

379 scf VOC  50 lb VOClb	mole VOC  1 	 98100 
0.132

Qytoluene 1

C MWtoluene 1 	 DRE100

200 scf  0.01 scf toluene/scf  1 lb	mole toluene

379 scf toluene 

92.13 lb toluene

lb	mole toluene  1 	 98100 
 0.0097 lb toluene/hr

Ex 
 Cx  Q/35.3  60/454,000

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.4-29

Example 10.4-19 (Continued)

 = 

= 0.132 lb VOC/hr * 8,760 hr/yr = 1,156 lb VOC/yr

= 1,156 lb VOC/yr * ton/2,000 lb = 0.58 ton VOC/yr

= 0.58 ton VOC/yr

E = toluene

=

= 0.0097 lb toluene/hr * 8,760 hr/yr = 85 lb toluene/yr

= 85 lb toluene/yr * ton/2,000 lb = 0.042 ton toluene/yr

= 0.042 ton toluene/yr

(10.4-16)

4.4 EMISSION CALCULATIONS USING STACK SAMPLING DATA

Stack sampling test reports often provide emissions data in terms of lb/hr or mg/m . Annual 3

emissions may be calculated from these data using Equation 10.4-16. Stack tests performed

under a proposed permit condition or a maximum emissions rate are likely to be higher than the

emissions which would result under normal operating conditions. The emission testing should

only be completed after the purpose of the testing is known. For example, emission testing for

particulate emissions may be different than emission testing for New Source Performance

Standards (NSPS) because the back-half catch portion of the sampling train (where condensable

PM is caught) is not considered in the NSPS limits.

An example summary of a stack test is shown in Table 10.4-2. The table shows the results of

three different sampling runs conducted during one test event. Pollutant concentration is

multiplied by the exhaust gas volumetric flow rate to determine the emission rate in pounds per

hour, as shown in Equation 10.4-16 and Example 10.4-20.

where:

E = hourly emissions in lb/hr of pollutant x x
6,415 lbs H2S/yr  ton

2,000 lb 
 3.2 ton H2S/yr

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.4-30 EIIP Volume II

Example 10.4-20

H S emissions are calculated using Equation 10.4-16 and the stack sampling data for Run 1 2

(presented in Table 10.4-2 are shown below). The unit is operated 8,760 hours per year.

E = C * Q/35.3 * 60/454,000 H2S H2S

= 652 mg/m * 300 scf/min/(35.3 ft /m ) * (60 min/hr)/(454,000 mg/lb) 3 3 3

= 0.73 lb H S/hr 2

= 0.73 lb H S/hr * 8,760 hrs/yr = 6,415 lb H S/yr 2 2

= 

= 3.2 ton H S/yr 2

C = stack gas concentration, mg/m x

3

Q = stack gas volumetric flow rate, scfm

35.3 = conversion factor, 35.3 ft /m3 3

60 = 60 min/hr

454,000 = conversion factor, 454,000 mg per pound

TABLE 10.4-2

TEST RESULTS

Parameter Symbol Run 1 Run 2 Run 3

Volumetric flow rate (scfm) Q 300 292 297

Concentration of H S (mg/m ) C 652 665 657 2

3

H2S

H S emission rate (lb/hr) E 0.73 0.73 0.73 2 H2S
EIIP Volume II 10.5-1

5

ALTERNATIVE METHODS FOR

ESTIMATING EMISSIONS

Alternative methods for estimating emissions from oil and gas field processing operations are

presented in this section. Table 10.5-1 lists the variables used in Equations 10.5-1 through

10.5-6.

In addition, equipment and emissions from off-shore operations, although not specifically

addressed in this document, are believed to be similar to those from on-shore operations. 

Preferred and alternative emission estimation methodologies for off-shore sources are, therefore,

expected to be the same as for on-shore sources. Depending on the purpose of the emission

inventory, the inventory preparer should also consider inclusion of emissions from these source

types. 

5.1 EMISSION CALCULATIONS USING EMISSION FACTORS

Emission factors are commonly used to calculate emissions from oil and gas field processing

operations. EPA maintains a compilation of emission factors in AP-42 for criteria pollutants

and HAPs (AP-42, 5th Edition, January 1995). Emission factors for equipment leaks may be

found in Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017, 1995) and

Calculation Workbook for Oil and Gas Production Equipment Fugitive Emissions (API, 1996). 

The Factor Information and Retrieval system (FIRE) (EPA, 1998) is a database containing

AP-42 emission factors as well as other emission factors that may be found in EPA documents

such as the “Locating and Estimating” series for toxic pollutants. In addition, manufacturers

often provide emission factors for specific pieces of equipment.

Currently, emission factors are available as an alternative method for the following types of

sources found in oil and gas field processing operations:

& SO emissions from gas sweetening amine units venting to a smokeless flare or 2

tail gas incinerator;

& SO emissions from Claus sulfur recovery units; and 2
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-2 EIIP Volume II

TABLE 10.5-1

LIST OF VARIABLES AND SYMBOLS

Variable Symbol Units

Emissions E Typically lb/hr of pollutant x x

Emission factor EF Various x

Activity, production or flow rate Q Various

Volume of fuel fired V Various

Heating value of the fuel H Various

Pollutant concentration C mg/m or ppmvd x

3

Rich sample pollutant x C Various

concentration

i

Lean sample pollutant x C Various

concentration o

Molecular weight of pollutant MW lb/lb-mole

Molar volume of ideal gas C scf/lb-mole

Annual emissions of pollutant x E ton/yr tpy,x

Annual operating hours OpHrs hour/yr

Gas/oil ratio GOR scf/ Stock tank barrel (STB)

API gravity  API degrees o

Solution gas specific gravity at  Dimensionless

actual temperature and pressure

g

Dissolved gas specific gravity at  Dimensionless

100 psig

gc

Stock tank oil specific gravity  Dimensionless os

Operating pressure P Psia
Ex 
 EFx  Q

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.5-3

(10.5-1)

TABLE 10.5-1

CONTINUED

Variable Symbol Units

Operating temperature T Various

Molecular weight of vapor MW lb/lb-mole v

Mass fraction X lb x/total lb x

Days per year operation D Days/year

& Pneumatic devices.

Much work has been done to develop emission factors for HAPs and AP-42 revisions have

included these factors (EPA, 1995a,b). In addition, many states have developed their own HAP

emission factors for certain source categories and require their use in any inventories including

HAPs. Refer to Chapter 1 of Volume II for a complete discussion of available information

sources for locating, developing, and using emission factors as an estimation technique.

Emission factors developed from measurements for a specific source may sometimes be used to

estimate emissions at other sites. For example, a company may have several units of similar

model and size; if emissions were measured from one unit, an emission factor could be

developed and applied to other similar units. It is advisable to consult with state/local agencies

or the EPA prior to selection of an emission factor.

The basic equation for using an emission factor to calculate emissions is the following:

where:

E = Emissions of pollutant x x

EF = Emission factor of pollutant x x

Q = Activity or production rate

Depending on the emission factor, activity rate, and desired emissions units, additional variables

may need to be factored into the equation, such as sulfur content of the fuel, hours per year of
Q 
 V  H

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-4 EIIP Volume II

(10.5-2)

Example 10.5-1

Example 10.5-1 shows how potential hourly SO emissions may be calculated for a 2

smokeless flare on an amine gas sweetening process with no sulfur recovery or sulfuric acid

production present. The SO emission factor is from AP-42, Table 5.3-1. H S content of the 2 2

inlet gas is assumed to be 2.5% by volume, and the gas processing rate is assumed to be 200

scf/hr for 8,760 hours per year.

EF = 1,685 * S lb/10 scf gas processed SO2

6

S = H S content of the sour gas entering the gas sweetening plant 2

(volume %)

= 2.5

Q = 200 scf/hr

operation, and conversion from pounds to tons. For some sources (e.g., combustion sources),

emission factors may be based on the Btu fired rather than volume of fuel fired. The actual Btu

firing rate can be calculated based on the volume of fuel fired and the heating value of the fuel

using the following equation:

where:

Q = Activity or production rate to be used in equation 10.5-1

V = Volume of fuel fired

H = Heating value of the fuel

Calculations using emission factors are presented in Examples 10.5-1 through 10.5-3.

The EPEC model uses the emission factor method for estimating VOC, HAP, and criteria

pollutant emissions from heater treaters and flares. In some cases, users have the choice of

applying GRI or EPA AP-42 emission factors.

The GRI-HAPCalc model also uses the emission factor method to estimate HAP as well as

criteria pollutant emissions from gas sweetening amine units. The gas sweetening emission

factors are based on GRI field test data.

In all cases, it is advisable to consult with the state/local agencies or the EPA prior to selection

of an emission factor.
103,400 lb SO2/yr  ton

2,000 lb 
 51.7 ton SO2/yr

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.5-5

Example 10.5-1 (Continued)

E = EF * S * gas processing rate SO2 SO2

= 1,685 * 2.5 * 200 = 842,500 lb-scf/hr-10 scf 6

= 842,500 lb-scf/hr-10 scf * 10 scf/1,000,000 scf = 0.8425 lb/hr 6 6

= 0.8425 lb/hr * 8,760 hr/yr = 7,380 lb/yr

= 7,380 lb/yr * ton/2,000 lb = 3.69 ton/yr

= 3.69 ton/yr

Example 10.5-3

Example 10.5-3 uses emission factors to estimate CH emissions from pneumatic devices. 4

The site estimates a total of 85,000 pneumatic devices. The emission factor is from

“Methane Emissions from the U.S. Petroleum Industry” (EPA, 1996). 

Q = 85,000 devices

EF = 345 scf CH /day/device CH4 4

E = Q * EF CH4 CH4

Example 10.5-2

Example 10.5-2 estimates SO emissions from an uncontrolled 3-stage Claus sulfur recovery 2

unit using emission factors. The SO emission factor is from AP-42, Table 8.13-1. The unit 2

produces 550 tons per year of sulfur.

EF = 188 lb/ton sulfur produced SO2

Q = 550 ton/yr

E = EF * Q SO2 SO2

= 188 lb/ton sulfur * 550 ton sulfur/yr = 103,400 lb SO /yr 2

= 

= 51.7 ton SO /yr 2
29,325,000 scf CH4/day 

lb mole CH4

379 scf



16 lb CH4

lb	mole CH4


 4,836 lb CH4/day

1,765,110 lb CH4/yr 

ton

2,000 lb 
 883 ton CH4/yr

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-6 EIIP Volume II

Example 10.5-3 (Continued)

= 85,000 devices * 345 scf CH /day/device 4

= 

 

= 4,836 lb CH /day * 365 days/yr = 1,765,110 lb CH /yr 4 4

= 

= 883 ton CH /yr 4

5.2 EMISSION CALCULATIONS USING STACK SAMPLING DATA

Stack sampling test reports often provide emissions data in terms of lb/hr or mg/m . Annual 3

emissions may be calculated from these data using Equations 10.5-3 or 10.5-4. Stack tests

performed under a proposed permit condition or a maximum emissions rate are likely to be

higher than the emissions which would result under normal operating conditions. The emission

testing should only be completed after the purpose of the testing is known. For example,

emission testing for particulate emissions may be different than emission testing for New Source

Performance Standards (NSPS) because the back-half catch portion of the sampling train (where

condensable PM is caught) is not considered in the NSPS limits.

5.2.1 STACK SAMPLING DATA FOR GAS SWEETENING PROCESSES

This section shows how to calculate emissions in lb/hr based on stack sampling data. 

Calculations involved in determining H S emissions from EPA Method 11 data are used as an 2

example. The only available methods for sampling H S emissions are EPA Method 11, a 2

stainless steel bomb or a portable gas chromatograph.

An example summary of a Method 11 test is shown in Table 10.5-2. The table shows the results

of three different sampling runs conducted during one test event. Pollutant concentration is
Ex 
 Cx  Q/35.3  60/454,000

6,415 lbs H2S/yr  ton

2,000 lb 
 3.2 ton H2S/yr

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.5-7

(10.5-3)

Example 10.5-4

H S emissions are calculated using Equation 10.5-3 and the stack sampling data for Run 1 2

(presented in Table 10.5-2 are shown below). The unit is operated 8,760 hours per year.

E = C * Q/35.3 * 60/454,000 H2S H2S

= 652 mg/m * 300 scf/min/(35.3 ft /m ) * (60 min/hr)/(454,000 mg/lb) 3 3 3

= 0.73 lb H S/hr 2

= 0.73 lb H S/hr * 8,760 hrs/yr = 6,415 lb H S/yr 2 2

= 

= 3.2 ton H S/yr 2

multiplied by the exhaust gas volumetric flow rate to determine the emission rate in pounds per

hour, as shown in Equation 10.5-3 and Example 10.5-4.

where:

E = hourly emissions in lb/hr of pollutant x x

C = stack gas concentration, mg/m x

3

Q = stack gas volumetric flow rate, scfm

35.3 = conversion factor, 35.3 ft /m3 3

60 = 60 min/hr

454,000 = conversion factor, 454,000 mg per pound

TABLE 10.5-2

TEST RESULTS - METHOD 11

Parameter Symbol Run 1 Run 2 Run 3

Volumetric flow rate (scfm) Q 300 292 297

Concentration of H S (mg/m ) C 652 665 657 2

3

H2S

H S emission rate (lb/hr) E 0.73 0.73 0.73 2 H2S
Ex 
 (Ci 	 Co

)  Q

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-8 EIIP Volume II

(10.5-4)

Example 10.5-5

Example 10.5-5 estimates benzene emissions from a glycol dehydrator with a glycol

circulation rate of 5 gpm. Sample analyses indicate a rich glycol benzene concentration prior

to the reboiler of 800 mg/L and a lean glycol benzene concentration prior to the contact tower

of 100 mg/L. The dehydrator operates 8,760 hours per year.

C = 800 mg/L i

C = 100 mg/L o

Q = 5 gal/min

E = (C - C ) * Q benzene i o

5.2.2 THE RICH/LEAN METHOD FOR GLYCOL DEHYDRATORS AND GAS SWEETENING 

AMINE UNITS

The rich/lean method can be used to estimate emissions from glycol dehydrators and gas

sweetening amine units. The rich/lean method utilizes rich and lean sample data by applying

them to either glycol or amine circulation rates. For glycol dehydrators, a rich glycol sample is

obtained prior to the reboiler and after any flash tank. A lean glycol sample is taken prior to the

contact tower (Boyer and Brodnax, 1996). The following equation can be used to calculate

emissions from either glycol dehydrators or gas sweetening amine units venting to the

atmosphere:

where:

E = Emissions of pollutant x x

C = Rich sample pollutant x concentration i

C = Lean sample pollutant x concentration o

Q = Glycol or amine circulation rate

Examples 10.5-5 and 10.5-6 illustrate the use of this equation.

The EPEC model incorporates the Rich/Lean emissions estimation method for both glycol

dehydrators and gas sweetening amine units. The GLYCalc model also provides users the

option of applying the Rich/Lean method to estimate emissions from glycol dehydrators.
(800mg/L	100mg/L)5 gal/min 1,000L

264gal

 lb

454,000mg

60min/hr
1.75 lbbenzene/hr

1.75 lb benzene/hr  8,760 hr

yr 
 15,348 lb benzene/yr

15,348 lb benzene/yr  ton

2,000 lb 
 7.67 ton benzene/yr

7.67 ton benzene/yr

(600mg/L	300mg/L)8 gal/min 1,000L

264gal

 lb

454,000mg 60min/hr
1.20 lbethylbenzene/hr

1.20 lb ethylbenzene/hr  8,760 hr

yr 
 10,525 lb ethylbenzene/yr

10,525 ton ethylbenzene/yr  ton

2,000 lb 
 5.26 ton ethylbenzene/yr

5.26 ton ethylbenzene/yr

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.5-9

Example 10.5-5 (Continued)

=

 

= 

= 

= 

Example 10.5-6

Example 10.5-6 estimates ethylbenzene emissions from a gas sweetening amine unit with an

amine circulation rate of 8 gpm. Sample analyses indicate a rich amine ethylbenzene

concentration of 600 mg/L and a lean amine ethylbenzene concentration of 300 mg/L. The

amine unit operates 8,760 hours per year.

C = 600 mg/L i

C = 300 mg/L o

Q = 8 gal/min

E = (C - C ) * Q ethylbenzene i o

 =

 

= 

=

=
GOR 
 C1  gc

 P C2  exp

C3  o

T  460

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-10 EIIP Volume II

(10.5-7)

5.3 EMISSION EQUATIONS FOR FLASH LOSSES

The dissolved Gas Oil Ratio (GOR) can also be used as an alternative method to estimate flash

losses. The GOR can be estimated using either the Vazquez-Beggs Correlation or the Rollins,

McCain, Creeger Correlation. Both techniques are detailed below (TNRCC, 1996).

5.3.1 VAZQUEZ-BEGGS CORRELATION

The Vazquez-Beggs correlation is an empirical correlation equation based on laboratory

measured pressure-volume-temperature (PVT) data and is a function of pressure, temperature,

oil gravity, and gas gravity (Martino, 1997). The Vazquez-Beggs correlation is valid for

liquids with API gravity ranging between 15 and 68 degrees. The Vazquez-Beggs correlation

is valid only within a set range of values. These values are listed below.

Parameters Range

Vessel operating pressure, P 50 to 5250 (psia)

Vessel operating temperature, T 70 to 295 (degrees F)

Vessel gas/oil ratio, GOR 20 to 2070 (scf/STB)

API gravity,  16 to 58 API o

Gas specific gravity at actual temperature and 0.56 to 1.18

pressure, g

The Vazquez-Beggs solution gas ratio correlation for a bubble point crude is shown below:

where:

GOR = Solution gas/oil ratio in vessel liquid, units are standard cubic

feet per stock tank barrel (scf/STB)

C , C , C = Empirical constants shown in table below 1 2 3

 = Dissolved gas specific gravity at 100 psig (See equation 10.5-8) gc

P = Vessel operating pressure, psia

exp = 2.718, the base “e” of the natural log system

o = API gravity of stock-tank liquid

T = Vessel operating temperature, degrees Fahrenheit
gc 
 g

 1.0  5.912 × 10	5  o  T  log P

114.7

9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.5-11

 (10.5-8)

Coefficient API  30 API > 30

C1 0.0362 0.0178

C2 1.0937 1.1870

C3 25.7240 23.9310

If the gas specific gravity was not taken at 100 psig then, the gas specific gravity, for any

pressure and temperature, may be referenced to 100 psig by using the following equation:

where:

gc = Dissolved gas specific gravity at 100 psig

g = Solution gas specific gravity at actual separator pressure and temperature

P = Vessel operating pressure, psia

o = API gravity of stock tank liquid

T = Vessel operating temperature, degrees Fahrenheit

log = 10, the base “10" of the standard log system

5.3.2 ROLLINS, MCCAIN, CREEGER CORRELATION

The Rollins, McCain, Creeger correlation is based on 301 black oil samples and is a function of

the oil specific gravity, separator gas specific gravity, and separator temperature and pressure

(Martino, 1997). The Rollins, McCain, Creeger correlation is applicable to oil with an API

gravity range of 20 to 50 degrees.

The Rollins, McCain, Creeger correlation is valid within the following range of values:

Parameter Range

Vessel gas/oil ratio, GOR  100.0 (scf/STB)

Vessel operating pressure, P 30 to 300 (psia)

Vessel operating temperature, T 65 to 140 (degrees F)

Stock tank oil specific gravity, os 0.934 to 0.780
log (GOR) 
 0.4896 	 4.916  log(os) 

3.469  log(g)  1.501  log(P) 	 0.9213  log(T)

os 
 141.5/[131.5  o

]

EVOC 
 Q  GOR  1/C  MWv  XVOC  D

CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-12 EIIP Volume II

(10.5-9)

(10.5-10)

The following equation can be used to estimate GOR:

where:

GOR = Solution gas/oil ratio in vessel liquid, scf/STB

os = Stock tank oil specific gravity

g = Vessel gas specific gravity

P = Vessel operating pressure, psia

T = Vessel operating temperature, degrees Fahrenheit

The following equation can be used to estimate  : os

where:

os = Stock tank oil specific gravity

 = API gravity of stock tank liquid, API degrees o

The EPEC model incorporates both the Vazquez-Beggs and the Rollins, McCain, Creeger

correlations for estimating the dissolved gas oil ratio. In all cases, it is advisable to consult

with state/local agencies or the EPA prior to selection of an emission estimation method.

Once the GOR has been found, the VOC emissions can be calculated as follows:

where:

E = VOC emissions lb/year VOC

Q = Volume of oil processed, bbl/day

GOR = Dissolved gas/oil ratio, scf/STB

C = Molar volume of ideal gas, 379 scf/lb-mole at 60 degrees Fahrenheit and

1 atmosphere

MW = Vapor Molecular weight, lb/lb-mole v

X = Mass fraction of VOC in vapor, lb VOC/lb vapor VOC

D = Days per year of operation
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.5-13

Example 10.5-8

Example 10.5-8 uses the Vazquez-Beggs correlation to calculate flash losses resulting from

oil entering a storage tank from a separator operating at 300 psia and 200(F. The API

gravity of the oil is 30 API, the dissolved gas specific gravity at actual conditions is 0.75.

The oil transfer rate is 120 STB/day, the vapor molecular weight is 50 lb/lb-mole and the

mass fraction of VOC in the vapor is 0.9. This source operates 365 days/yr.

P = 300 psia

T = 200(F

o = 30

g = 0.75

 =  * [1.0 + (5.912 × 10 *  * T * log (P/114.7))] gc g o

-5

= 0.75 * [1.0 + (5.912 × 10 * 30 * 200 * log (300/114.7))] -5

= 0.86

C = 0.0362 at 30 API 1

C = 1.0937 at 30 API 2

C = 25.7240 at 30 API 3

MW = 50 lb/lb-mole

Q = 120 STB/day

X = 0.9 VOC

C = 379 scf/lb-mole @ 60(F, 1 atm

GOR = C *  * P * exp [C3 *  /(T + 460)] 1 gc o

C2

= 0.0362 * 0.86 * (300) * exp [25.7240 * 30/(200 + 460)] 1.0937

= 51.31 scf/STB

E = Q * GOR * (1/C) * MW * X VOC VOC

= 120 STB/day * 51.31 scf/STB * (lb-mole/379 scf) * 50 lb/lb-mole * 0.9 lb VOC/lb

= 731.1 lb VOC/day * 365 days/yr

= 266,851 lb VOC/yr * ton/2,000 lb

= 133 ton VOC/yr

Gas analysis indicates benzene content is 5%of VOC by weight.

E = E * X benzene VOC benzene

= 266,851 lb VOC/yr * 0.05 lb benzene/lb VOC

= 13,343 lb benzene/yr * ton/2,000 lb

= 6.7 ton benzene/yr

Examples 10.5-8 and 10.5-9 illustrate the use of equations 10.5-7 through 10.5-10.
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.5-14 EIIP Volume II

Example 10.5-9

Example 10.5-9 uses the Rollins, McCain, Creeger correlation to calculate flash losses

resulting from oil entering a storage tank from a gun barrel operating at 300 psia and 200(F. 

The API gravity of the oil is 30 API degrees, the dissolved gas specific gravity at actual

conditions is 0.75. The oil transfer rate is 50 STB/day, the vapor molecular weight is 50

lb/lb-mole and the mass fraction of VOC in vapor is 0.85.

P = 300 psia

T = 200(F

o = 30

g = 0.75 @ 300 psia

MW = 50 lb/lb-mole

Q = 120 STB\day

X = 0.85 VOC

C = 379 scf/lb-mole @ 60(F, 1 atm

 = 141.5/[131.5 +  ] os o

= 141.5/[131.5 + 30]

= 0.876

 log (GOR) = 0.4896 - 4.916 * log ( ) + 3.469 * log ( ) + 1.501 * log (P) - 0.9213 * log (T) os g

= 0.4896 - 4.916 * log (0.876) + 3.469 * log (0.75) + 1.501 * log (300) - 0.9213 *

log (200)

= 1.94

GOR = log (1.94) -1

= 86.5 scf/STB

E = Q * GOR * (1/C) * MW * X VOC VOC

= 50 STB/day * 86.5 scf/STB * (lb-mole/379 scf) * 50 lb/lb-mole * 0.85 lb VOC/lb

= 485 lb VOC/day * 365 day/yr = 177,023 lb/yr

= 177,023 lb/yr * ton/2,000 lb

= 89 ton VOC/yr

Gas analysis indicates benzene content is 10% of VOC by weight.

E = E * X benzene VOC benzene

= 177,023 lb VOC/yr * 0.10 lb benzene/lb VOC

= 17,702 lb benzene/yr * ton/2,000 lb

= 8.85 ton benzene/yr
EIIP Volume II 10.6-1

6

QUALITY ASSURANCE/QUALITY

CONTROL

The consistent use of standardized methods and procedures is essential in the compilation of

reliable emission inventories. QA and QC of an inventory is accomplished through a set of

procedures that ensure the quality and reliability of data collection and analysis. These procedures

include the use of appropriate emission estimation techniques, applicable and reasonable

assumptions, accuracy/logic checks of computer models, checks of calculations, and data

reliability checks. Figure 10.6-1 provides an example completeness checklist that could aid the

inventory preparer at an oil and gas field production and processing facility. Volume VI, QA

Procedures, of this series describes additional QA/QC methods and tools for performing these

procedures.

Volume II, Chapter 1, Introduction to Stationary Point Source Emission Inventory Development,

also presents recommended standard procedures to follow to ensure that the reported inventory

data are complete and accurate. This section discusses the use of QC checklists, QA/QC

procedures for specific emission estimation methods (e.g., emission factors), and the application

of the Data Attribute Rating System (DARS).

6.1 GENERAL FACTORS INVOLVED IN EMISSION ESTIMATION

TECHNIQUES

6.1.1 EMISSION FACTORS

The use of emission factors is straightforward when the relationship between process data and

emissions is direct and relatively uncomplicated. When using emission factors, the user should be

aware of the quality indicator associated with the value. Emission factors published within EPA

documents and electronic tools have a quality rating applied to them. The lower the quality

indicator, the less confidence EPA has in the data used to develop the factor and the more cautious

the user should be using the emission estimate. When an emission factor for a specific source or

category may not provide a reasonably adequate emission estimate, it is always better to rely on

actual stack test data, where available. The reliability and uncertainty of using emission factors as 
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.6-2 EIIP Volume II

Item Y/N Date)

Corrective Action

(Complete if "N";

Describe, Sign, and

Have emissions from all sources been included? Potential sources

include external flame burners/boilers, IC engines/turbines, flares,

equipment leaks, glycol dehydrators, storage tanks, process piping,

loading losses, flash losses, sulfur recovery units, heater treaters,

blowout, separators, well heads, pipeline, pump stations, gas

sweetening units, emergency and process vents, pigging

operations, and pneumatic devices.

Has an emission estimating technique been identified for each

source?

If toxic emissions are to be calculated using testing data, are the

test methods approved?

If toxic emissions are to be calculated using emission factors, are

the emission factors from AP-42 or FIRE?

Have stack parameters been provided for each stack or vent that

emits criteria or toxic air pollutants?

If required by the state, has a site diagram been included with the

emissions inventory? This should be a detailed plant drawing

showing the location of sources/stacks with ID numbers for all

processes, control equipment, and exhaust points.

Have examples of all calculations been included?

Have all assumptions been documented?

Have references for all calculation methods been included?

Have all conversions and units been reviewed and checked for

accuracy?

FIGURE 10.6-1

EXAMPLE EMISSION INVENTORY CHECKLIST FOR

OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.6-3

an emission estimation technique are discussed in detail in the QA/QC section of Chapter 1 of this

volume and Chapter 4 of Volume VI.

6.1.2 EMISSION MODELS AND ENGINEERING EQUATIONS

The level of effort for using models and engineering equations is related to the complexity of the

equations, the types of data that must be collected, and the diversity of products manufactured at a

facility. Typically, the use of emission models involves making one or more conservative

assumptions. As a result, their use may result in an overestimation of emissions. However, the

accuracy and reliability of models can be improved by ensuring that data collected for emission

calculations (e.g., material speciation data) are of the highest possible quality.

6.1.3 TESTING

Stack tests must meet quality objectives. Test data must be reviewed to ensure that the test was

conducted under normal operating conditions, or under maximum operating conditions in some

states, and that the data were generated according to an acceptable method for each pollutant of

interest. Calculation and interpretation of accuracy for stack testing methods are described in

detail in Quality Assurance Handbook for Air Pollution Measurements Systems: Volume III,

Stationary Source Specific Methods (Interim Edition) (EPA, 1994b). 

The acceptable criteria, limits, and values for each control parameter associated with manual

sampling methods, such as dry gas meter calibration and leak rates, are summarized in tabular

format in the QA/QC section of Chapter 1 of this volume. QC procedures for all instruments used

to continuously collect emissions data are similar. The primary control check for precision of the

continuous monitors is daily analysis of control standards.

6.2 DATA ATTRIBUTE RATING SYSTEM (DARS) SCORES

One measure of emission inventory data quality is the DARS score. Four examples are given here

to illustrate DARS scoring using the preferred and alternative methods. DARS provides a

numerical ranking on a scale of 0 to 1.0 for individual attributes of the emission factor and the

activity data. Each score is based on what is known about the factor and activity data, such as the

specificity to the source category and the measurement technique employed. The composite

attribute score for the emissions estimate can be viewed as a statement of the confidence that can

be placed in the data. For a complete discussion of DARS and other rating systems, see the QA

Procedures (Volume VI, Chapter 4), and the QA/QC section of Chapter 1 of this volume.

Each of the examples below is hypothetical. A range is given where appropriate to cover different

situations. Table 10.6-1 gives a set of scores for an estimate made with an AP-42 emission factor. 

The activity data are assumed to be measured directly or indirectly. Table 10.6-2 shows scores 
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.6-4 EIIP Volume II

TABLE 10.6-1

DARS SCORES: EMISSION FACTORS (EF)

Attribute Score Score Score Assumptions Assumptions

Factor Activity Emissions Factor Activity

Measurement/ 0.90 0.80 - 1.0 0.72 - 0.90 Factor is based Lower score

Method on intermittent reflects an

measurements activity rate

of intended derived from a

pollutant and surrogate that

representative is indirectly

sampling over a related to the

range of loads. activity data

(rather than a

surrogate that

has been

directly related

and measured);

upper score

reflects direct

continuous

measurement

of activity.

Source 0.90 0.90 0.81 Factor was Activity data

Specificity developed for a are very

subset or a closely

superset of the correlated to

intended source the emission

category. activity.

Expected

variability is

low.

Spatial 0.90 1.0 0.90 Factor was Activity data

Congruity developed for a are developed

similar source. for and

specific to the
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.6-5

TABLE 10.6-1

(CONTINUED)

Attribute Score Score Score Assumptions Assumptions

Factor Activity Emissions Factor Activity

Spatial Spatial source being

Congruity variability is inventoried.

(Continued) low.

Temporal 0.70 0.90 0.63 Factor was Activity data

Congruity developed for a are

different period representative

where the of the same

temporal temporal

variability is period as the

expected to be inventory, but

moderate to are based on an

low. average of

several

repeated

periods

(activity data

are an average

of three years,

inventory is for

one year).

Composite 0.85 0.90 - 0.95 0.76 - 0.81

Scores
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.6-6 EIIP Volume II

TABLE 10.6-2

DARS SCORES: EMISSION MODELS AND ENGINEERING EQUATIONS

Attribute Score Score Score Assumptions Assumptions

Factor Activity Emissions Factor Activity

Measurement/ 0.30 0.30 - 1.0 0.09 - 0.30 Factors Lower score

Method (inputs to reflects an

model or activity rate

equation) are derived from

based on engineering or

material physical

balance, principles. 

all/most end- Upper score

points reflects direct,

accounted for. continuous

measurement

of activity.

Source 0.90 - 1.0 0.70 - 1.0 0.63 - 1.0 Lower score Lower score

Specificity reflects inputs reflects activity

developed for data for a

a subset or similar process

superset of that is highly

the intended correlated to

category. the emissions

Upper score process. 

reflects inputs Upper score

developed reflects activity

specifically data that

for the represent the

intended emission

source. process

exactly.

Spatial 1.0 1.0 1.0 Inputs were Activity data

Congruity developed for are developed

and specific for and

specific to the
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.6-7

TABLE 10.6-2

(CONTINUED)

Attribute Score Score Score Assumptions Assumptions

Factor Activity Emissions Factor Activity

Spatial to the given source being

Congruity spatial scale. inventoried.

(Continued)

Temporal 1.0 1.0 1.0 Model inputs Activity data

Congruity were are specific for

developed for the temporal

and are period

applicable to represented in

the temporal the inventory.

period

represented in

the inventory.

Composite 0.80 - 0.83 0.75 - 1.0 0.68 - .083

Scores
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.6-8 EIIP Volume II

developed from the use of emission models. Table 10.6-3 demonstrates scores determined for

testing data. 

These examples are given as an illustration of the relative quality of each method. If the same

analysis were done for an actual site, the scores could be different but the relative ranking of

methods should stay the same. Note, however, that if the source is not truly a member of the

population used to develop the EPA correlation equations or the emission factors, these

approaches are less appropriate and the DARS scores will drop.

If sufficient data are available, the uncertainty in the estimate should be evaluated. Qualitative

and quantitative methods for conducting uncertainty analyses are described in the QA Procedures

(Volume VI, Chapter 4).
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.6-9

TABLE 10.6-3

DARS SCORES: STACK SAMPLING

Attribute Score Score Score Assumptions Assumptions

Factor Activity Emissions Factor Activity

Measurement/ 0.70 - 0.90 0.90 - 1.0 0.63 - 0.90 Lower score Lower score

Method reflects a small reflects direct,

number of intermittent

tests at typical measurement

loads; upper of activity. 

score Upper score

represents reflects direct,

numerous tests continuous

over a range of measurement

loads. of activity. 

Source 1.0 1.0 1.0 Factor is Activity data

Specificity developed represents the

specifically for emission

the intended process

source. exactly.

Spatial 1.0 1.0 1.0 Factor is Activity data

Congruity developed for are developed

and is specific for and

to the given specific to the

spatial scale. inventory area.

Temporal 0.70 - 1.0 0.70 - 1.0 0.49 - 1.0 Lower score Lower score

Congruity reflects a reflects activity

factor data

developed for representative

a shorter time of a short

period with period of time;

moderate to upper score

low temporal represents 

variability; activity data

upper score specific for the
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.6-10 EIIP Volume II

TABLE 10.6-3

(CONTINUED)

Attribute Score Score Score Assumptions Assumptions

Factor Activity Emissions Factor Activity

Temporal reflects a temporal

Congruity factor period

(Continued) developed for represented in

and applicable the inventory.

to the same

temporal scale.

Composite 0.85 - 0.98 0.90 - 1.0 0.78 - 0.98

Scores
EIIP Volume II 10.7-1

7

DATA CODING PROCEDURES

This section describes the methods and codes available for characterizing emission sources at oil

and gas field production and processing operations. Consistent categorization and coding will

result in greater uniformity among inventories. In addition, the procedures described here will

assist the reader who is preparing data for input to the Aerometric Information Retrieval System

(AIRS) or a similar database management system. For example, the use of the Source

Classification Codes (SCCs) provided in Table 10.7-1 are recommended for describing oil and gas

field production and processing operations. Refer to the CHIEF for a complete

listing of SCCs.

7.1 SOURCE CLASSIFICATION CODES

SCCs for oil and gas field production and processing operations are presented in Table 10.7-1. A

brief description of each source listed in the table is given below.

7.1.1 PROCESS OPERATIONS

Process operations consist of well operations, separation, drilling, heating, sweetening, sulfur

recovery, glycol dehydration, reboiler, and equipment leaks. The SCCs that correspond to these

activities appear in Table 10.7-1 under the Oil Production, Natural Gas Production, Natural Gas

Processing, Liquid Waste Treatment, Process Heaters, and Steam Generators source descriptions. 

7.1.2 IN-PROCESS FUEL USE

In-process fuel use consists of internal combustion engines. The SCCs that correspond to these

activities appear in Table 10.7-1 under the Internal Combustion Engines and Control Device Fuel

source descriptions. 

7.1.3 STORAGE TANKS

At oil and gas field production and processing facilities oil is stored in fixed roof, floating roof, or

underground storage tanks. The SCCs that correspond to these activities appear in Table 10.7-1

under the Fixed Roof 67,000 Barrel Fuel Tanks: Standing Losses, Fixed Roof 250,000 Barrel

Fuel Tanks: Standing Losses, Fixed Roof Fuel Tanks: Working Losses, Floating Roof 67,000

Barrel Fuel Tanks: Standing Losses, Floating Roof 250,000 Barrel Fuel Tanks: Standing Losses, 
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.7-2 EIIP Volume II

TABLE 10.7-1

SOURCE CLASSIFICATION CODES FOR OIL AND GAS PRODUCTION

Source Description Process Description SCC Units

Process Emissions

Oil Production Miscellaneous Well: General 3-10-001-02 Wells/Year in Operation

Wells: Rod Pumps 3-10-001-03 Wells/Year in Operation

Crude Oil Sumps 3-10-001-04 Square Feet Sump Area/Year

Crude Oil Pits 3-10-001-05 Square Feet Sump Area/Year

Enhanced Wells, Water 3-10-001-06 1000 Gallons Water

Reinjection

Oil/Gas/Water/Separation 3-10-001-07 1000 Gallons Crude Transfer

Evaporation from Liquid Leaks 3-10-001-08 Square Feet of Surface Area

into Oil Well Cellars

Site Preparation 3-10-001-21 100 Acres Prepared

Drilling and Well Completion 3-10-001-22 Wells/Year Drilled

Wellhead Casing Vents 3-10-001-23 Wells/Year in Operation

Valves - General 3-10-001-24 1000 Barrels Oil Produced

Relief Valves 3-10-001-25 1000 Barrels Oil Produced

Pump Seals 3-10-001-26 1000 Barrels Oil Produced

Flanges and Connections 3-10-001-27 1000 Barrels Oil Produced

Oil Heating 3-10-001-28 1000 Barrels Oil Produced

Gas/Liquid Separation 3-10-001-29 1000 Barrels Oil Produced

Atmospheric Wash Tank 3-10-001-32 1000 Gallons of Crude Oil Processed

(Second Stage of Gas-Oil

Separation): Flashing Loss

Waste Sumps - Primary Light 3-10-001-40 1000 Barrels Oil Produced

Crude

Waste Sumps - Primary Heavy 3-10-001-41 1000 Barrels Oil Produced

Crude

Waste Sumps - Secondary 3-10-001-42 1000 Barrels Oil Produced

Light Crude

Waste Sumps - Secondary 3-10-001-43 1000 Barrels Oil Produced

Heavy Crude
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.7-3

TABLE 10.7-1

(CONTINUED)

Source Description Process Description SCC Units

Oil Production Waste Sumps - Tertiary Light 3-10-001-44 1000 Barrels Oil Produced

(Continued) Crude

Waste Sumps - Tertiary Heavy 3-10-001-45 1000 Barrels Oil Produced

Crude

Gathering Lines 3-10-001-46 1000 Miles of Pipeline

Flares 3-10-001-60 1000 Barrels Oil Produced

Processing Operations: Not 3-10-001-99 1000 Barrels Produced

Classified

Natural Gas Gas Sweetening: Amine 3-10-002-01 Million Cubic Feet Sour Gas

Production Produced

Gas Stripping Operations 3-10-002-02 Million Cubic Feet Gas Produced

Compressor Operation 3-10-002-03 Million Cubic Feet Gas Processed

Well Vents 3-10-002-04 Million Cubic Feet Gas Produced

Flares 3-10-002-05 Million Cubic Feet Gas Produced

Gas Lift 3-10-002-06 Million Cubic Feet Gas Produced

Valves - General 3-10-002-07 Million Cubic Feet Gas Produced

Sulfur Recovery Unit 3-10-002-08 Tons 100% Sulfur

Site Preparation 3-10-002-21 100 Acres Prepared

Drilling and Well Completion 3-10-002-22 Wells/Year Drilled

Relief Valves 3-10-002-23 Million Cubic Feet Gas Produced

Pump Seals 3-10-002-24 Million Cubic Feet Gas Produced

Compressor Seals 3-10-002-25 Million Cubic Feet Gas Produced

Flanges and Connections 3-10-002-26 Million Cubic Feet Gas Produced

Glycol Dehydrator Reboiler 3-10-002-27 Million Cubic Feet Gas Produced

Still Stack

Glycol Dehydrator Reboiler 3-10-002-28 Million Cubic Feet Gas Produced

Burner

Gathering Lines 3-10-002-29 Million Cubic Feet Gas Produced

Hydrocarbon Skimmer 3-10-002-30 Million Cubic Feet Gas Produced
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.7-4 EIIP Volume II

TABLE 10.7-1

(CONTINUED)

Source Description Process Description SCC Units

Natural Gas Glycol Dehydrators: Reboiler 3-10-003-01 Million Cubic Feet Gas Produced

Processing Still Vent: Triethylene Glycol

Glycol Dehydrators: Reboiler 3-10-003-02 Million Cubic Feet Gas Produced

Burner Stack: Triethylene

Glycol

Glycol Dehydrators: Phase 3-10-003-03 Million Cubic Feet Gas Produced

Separator Vent: Triethylene

Glycol

Glycol Dehydrators: Ethylene 3-10-003-04 Million Cubic Feet Gas Produced

Glycol: General

Gas Sweetening: Amine 3-10-003-05 Million Cubic Feet Gas Produced

Process

Process Valves 3-10-003-06 Million Cubic Feet Gas Produced

Relief Valves 3-10-003-07 Million Cubic Feet Gas Produced

Open-ended Lines 3-10-003-08 Million Cubic Feet Gas Produced

Compressor Seals 3-10-003-09 Million Cubic Feet Gas Produced

Pump Seals 3-10-003-10 Million Cubic Feet Gas Produced

Ranges and Connections 3-10-003-11 Million Cubic Feet Gas Produced

Liquid Waste Flotation Units 3-10-005-01 Barrels Waste Liquid

Treatment

Liquid - Liquid Separator 3-10-005-02 Barrels Waste Liquid

Oil - Water Separator 3-10-005-03 Barrels Waste Liquid

Oil-Sludge-Waste Water Pit 3-10-005-04 Barrels Waste Liquid

Sand Filter Operation 3-10-005-05 Barrels Waste Liquid

Oil-Water Separation 3-10-005-06 Square Feet of Surface Area

Wastewater Holding Tanks

Process Heaters Distillate Oil 3-10-004-01 1000 Gallons Burned

Residual Oil 3-10-004-02 1000 Gallons Burned

Crude Oil 3-10-004-03 1000 Gallons Burned

Natural Gas 3-10-004-04 Million Cubic Feet Burned

Process Gas 3-10-004-05 Million Cubic Feet Burned
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.7-5

TABLE 10.7-1

(CONTINUED)

Source Description Process Description SCC Units

Steam Generators Distillate Oil 3-10-004-11 1000 Gallons Burned

Residual Oil 3-10-004-12 1000 Gallons Burned

Crude Oil 3-10-004-13 1000 Gallons Burned

Natural Gas 3-10-004-14 Million Cubic Feet Burned

Process Gas 3-10-004-15 Million Cubic Feet Burned

In-Process Fuel Use

Internal Gas Turbines 2-02-002-01 Lb/MMBtu

Combustion

Engines 2-Cycle Lean Burn 2-02-002-52 Lb/MMBtu

4-Cycle Lean Burn 2-02-002-53 Lb/MMBtu

4-Cycle Rich Burn 2-02-002-54 Lb/MMBtu

Storage Tanks

Fixed Roof 67,000 Grade 6 Oil 4-03-010-25 1000 Gallons Storage Capacity

Barrel Fuel Tanks:

Standing Losses Grade 5 Oil 4-03-010-26 1000 Gallons Storage Capacity

Grade 4 Oil 4-03-010-27 1000 Gallons Storage Capacity

Grade 2 Oil 4-03-010-28 1000 Gallons Storage Capacity

Grade 1 Oil 4-03-010-29 1000 Gallons Storage Capacity

Fixed Roof Grade 6 Oil 4-03-010-65 1000 Gallons Storage Capacity

250,000 Barrel Fuel

Tanks: Standing

Losses

Grade 5 Oil 4-03-010-66 1000 Gallons Storage Capacity

Grade 4 Oil 4-03-010-67 1000 Gallons Storage Capacity

Grade 2 Oil 4-03-010-68 1000 Gallons Storage Capacity

Grade 1 Oil 4-03-010-69 1000 Gallons Storage Capacity

Fixed Roof Fuel Grade 6 Oil 4-03-010-75 1000 Gallons Throughput

Tanks: Working

Losses Grade 5 Oil 4-03-010-76 1000 Gallons Throughput

Grade 4 Oil 4-03-010-77 1000 Gallons Throughput

Grade 2 Oil 4-03-010-78 1000 Gallons Throughput

Grade 1 Oil 4-03-010-79 1000 Gallons Throughput
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.7-6 EIIP Volume II

TABLE 10.7-1

(CONTINUED)

Source Description Process Description SCC Units

Floating Roof Grade 6 Oil 4-03-011-25 1000 Gallons Storage Capacity

67,000 Barrel Fuel

Tanks: Standing

Losses

Grade 5 Oil 4-03-011-26 1000 Gallons Storage Capacity

Grade 4 Oil 4-03-011-27 1000 Gallons Storage Capacity

Grade 2 Oil 4-03-011-28 1000 Gallons Storage Capacity

Grade 1 Oil 4-03-011-29 1000 Gallons Storage Capacity

Floating Roof Grade 6 Oil 4-03-011-65 1000 Gallons Storage Capacity

250,000 Barrel Fuel

Tanks: Standing

Losses

Grade 5 Oil 4-03-011-66 1000 Gallons Storage Capacity

Grade 4 Oil 4-03-011-67 1000 Gallons Storage Capacity

Grade 2 Oil 4-03-011-68 1000 Gallons Storage Capacity

Grade 1 Oil 4-03-011-69 1000 Gallons Storage Capacity

Floating Roof Fuel Grade 6 Oil 4-03-011-75 1000 Gallons Throughput

Tanks: Working

Losses Grade 5 Oil 4-03-011-76 1000 Gallons Throughput

Grade 4 Oil 4-03-011-77 1000 Gallons Throughput

Grade 2 Oil 4-03-011-78 1000 Gallons Throughput

Grade 1 Oil 4-03-011-79 1000 Gallons Throughput

Bulk Plants

Oil Field Storage of Fixed Roof Tank: Breathing 4-04-003-01 1000 Gallons Storage Capacity

Crude Loss

Fixed Roof Tank: Working 4-04-003-02 1000 Gallons Throughput

Loss

External Floating Roof Tank 4-04-003-03 1000 Gallons Storage Capacity

with Primary Seals: Standing

Loss

External Floating Roof Tank 4-04-003-04 1000 Gallons Storage Capacity

with Secondary Seals: Standing

Loss

Internal Floating Roof Tank: 4-04-003-05 1000 Gallons Storage Capacity

Standing Loss

Underground Tanks Crude Oil RVP 5: Breathing 4-04-004-07 1000 Gallons Storage Capacity

Loss
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.7-7

TABLE 10.7-1

(CONTINUED)

Source Description Process Description SCC Units

Underground Tanks Crude Oil RVP 5: Working 4-04-004-08 1000 Gallons Throughput

(Continued) Loss

Fugitive Emissions

Oil Production Complete Well 3-10-001-01 Wells/Year in Operation

Compressor Seals 3-10-001-30 Number of Seals

Drains 3-10-001-31 Number of Drains

Miscellaneous Fugitive 3-10--888-01 Process Unit - Year

Emissions to -04

Miscellaneous Fugitive 3-10-888-05 1000 Barrels Feed Produced

Emissions - Oil

Natural Gas Valves 3-10-002-07 Million Cubic Feet Gas Produced

Production

Drains 3-10-002-31 Number of Drains

Miscellaneous Fugitive 3-10-888-11 Million Cubic Feet Produced

Emissions - Gas

Control Device Fuel

Control Device Fuel Afterburners - Distillate Oil 3-06-099-01 1000 Gallons Burned

No. 2

Transportation and Marketing

Tank Cars and Gasoline: Submerged 4-06-001-31 1000 Gallons Transferred

Trucks Loading, Normal Service

Crude Oil: Submerged 4-06-001-32 1000 Gallons Transferred

Loading, Normal Service

Gasoline: Splash Loading, 4-06-001-36 1000 Gallons Transferred

Normal Service

Crude Oil: Splash Loading, 4-06-001-37 1000 Gallons Transferred

Normal Service

Gasoline: Submerged 4-06-001-41 1000 Gallons Transferred

Loading, Balanced Service

Crude Oil: Submerged 4-06-001-42 1000 Gallons Transferred

Loading, Balanced Service
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.7-8 EIIP Volume II

TABLE 10.7-1

(CONTINUED)

Source Description Process Description SCC Units

Tank Cars and Gasoline: Splash Loading, 4-06-001-44 1000 Gallons Transferred

Trucks (Continued) Balanced Service

Crude Oil: Splash Loading, 4-06-001-45 1000 Gallons Transferred

Balanced Service

Gasoline: Submerged Loading, 4-06-001-47 1000 Gallons Transferred

Clean Trucks

Crude Oil: Submerged 4-06-001-48 1000 Gallons Transferred

Loading, Clean Trucks

Marine Vessels Crude Oil: Loading Tankers 4-06-002-43 1000 Gallons Transferred

Crude Oil: Loading Barges 4-06-002-48 1000 Gallons Transferred

Floating Roof Fuel Tanks: Working Losses, Oil Field Storage of Crude, and Underground Tanks

source descriptions. 

7.1.4 FUGITIVE SOURCES

Fugitive sources consist of wells, equipment leaks, and other miscellaneous sources. The SCCs

that correspond to these activities appear in Table 10.7-1 under the Oil Production and the Natural

Gas Production source descriptions. 

7.1.5 TRANSPORTATION AND MARKETING

Transportation and marketing consists of loading materials onto trucks, barges, and tankers. The

SCCs that correspond to these activities appear in Table 10.7-1 under the Tank Cars and Trucks

and Marine Vessels source descriptions. 

7.2 AIRS CONTROL DEVICE CODES

Control device codes applicable to oil and gas field production and processing operations are

presented in Table 10.7-2. These should be used to enter the type of applicable emission control

device into the AIRS Facility Subsystem (AFS). The "099" control code may be used for

miscellaneous control devices that do not have a unique identification code. 
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.7-9

TABLE 10.7-2

AIRS CONTROL DEVICE CODES

Control Device Code

Gas Scrubber 013

Catalytic Afterburner 019

Catalytic Afterburner with Heat Exchanger 020

Direct Flame Afterburner 021

Direct Flame Afterburner with Heat Exchanger 022

Flaring 023

Sulfur Plant 045

Process Change 046

Vapor Recovery System 047

Catalytic Reduction 065

Tube and Shell Condenser 072

Refrigerated Condenser 073

Barometric Condenser 074

Conservation Vent 088

Bottom Filling 089

Conversion to Variable Vapor Space Tank 090

Conversion to Floating Roof Tank 091

Conversion to Pressurized Tank 092

Submerged Filling 093

Underground Tank 094

White Paint 095

Miscellaneous Control Devices 099
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

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EIIP Volume II 10.8-1

8

REFERENCES

API. 1998. Emissions Estimation Sotware. American Petroleum Institute. 

http://www.api.org/ehs/old%20rh/E&PTANK&EPEC.htm#EPEC. September 1998.

API. 1996. Calculation Workbook for Oil and Gas Production Equipment Fugitive Emissions. 

American Petroleum Institute, API Publication Number 4638. Washington, D.C.

API. 1995. Emission Factors for Oil and Gas Production Operations. American Petroleum

Institute, API Publication Number 4615. Washington, DC.

Akin, Tom and William H. Battye, 1994. Memorandum to Martha E. Smith, U.S. Environmental

Protection Agency. Environmental Consultants and Research, Incorporated. October 18, 1994. 

Durham, North Carolina.

Boyer, Brian E. and Kenneth Brodnax, 1996. Oil and Gas Production Emission Factors and

Estimation Methods. Complete Oil Field Management and Maintenance, Inc., Lafayette,

Louisiana, and Mobil Exploration and Production Company, Houston, Texas. Presented at the

Emission Inventory: Key to Planning Permits, Compliance and Reporting Conference, Air and

Waste Management Association, September 4-6, 1996, New Orleans, Louisiana.

Corbeille, Robert, 1997. Hydrogen Sulfide Occurrences in the Gulf of Mexico, Outer

Continential Shelf Operations. U.S. Department of the Interior, Minerals Management Service,

Gulf of Mexico OCS Regional Office, New Orleans.

EIIP. 1996. Preferred and Alternative Methods for Estimating Air Emissions from Hot-Mix

Asphalt Plants, Final Report. Prepared for the Point Sources Committee, Emission Inventory

Improvement Program under EPA Contract No. 68-D2-0160, Work Assignment No. 82. U.S.

Environmental Protection Agency, Office of Air Quality Planning and Standards. Research

Triangle Park, North Carolina.

EPA. 1998. Factor Information and Retrieval System (FIRE), Version 6.01. Updated Annually. 

U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research

Triangle Park, North Carolina.
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.8-2 EIIP Volume II

EPA. 1996. Methane Emissions from the U.S. Petroleum Industry, Draft Report. U.S.

Environmental Protection Agency, Office of Air Quality Planning and Standards, Research

Triangle Park, North Carolina.

EPA. 1995a. Compilation of Air Pollutant Emission Factors. Volume I: Stationary Point and

Area Sources, Fifth Edition, AP-42. Section 7.1, Organic Liquid Storage Tanks. U.S.

Environmental Protection Agency, Office of Air Quality Planning and Standards. Research

Triangle Park, North Carolina.

EPA. 1995b. Compilation of Air Pollutant Emission Factors. Volume I: Stationary Point and

Area Sources, Fifth Edition, AP-42. Section 5.3, Natural Gas Processing. U.S. Environmental

Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park, North

Carolina.

EPA. 1995c. Compilation of Air Pollutant Emission Factors. Volume I: Stationary Point and

Area Sources, Fifth Edition, AP-42. Section 5.2, Transportation and Marketing of Petroleum

Liquids. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. 

Research Triangle Park, North Carolina.

EPA. 1995d. Compilation of Air Pollutant Emission Factors. Volume I: Stationary Point and

Area Sources, Fifth Edition, AP-42. Section 4.7, Waste Solvent Reclamation. U.S. Environmental

Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park, North

Carolina.

EPA. 1995e. Compilation of Air Pollutant Emission Factors. Volume I: Stationary Point and

Area Sources, Fifth Edition, AP-42. Section 8.13, Sulfur Recovery. U.S. Environmental

Protection Agency, Office of Air Quality Planning and Standards. Research Triangle Park, North

Carolina.

EPA. 1995f. State Workbook, Methodologies for Estimating Greenhouse Gas Emissions, Second

Edition. U.S. Environmental Protection Agency, Office of Policy, Planning and Evaluation,

EPA-230-B-95-001. Washington, D.C.

EPA. 1995g. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1994. U.S.

Environmental Protection Agency, Office of Policy, Planning and Evaluation,

EPA-230-R-96-006. Washington, D.C.

EPA. 1995h. Protocol for Equipment Leak Emission Estimates. U.S. Environmental Protection

Agency, Office of Air Quality Planning and Standards, EPA-453/R-95-017. Research Triangle

Park, North Carolina.
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II 10.8-3

EPA. 1994a. Alternative Control Techniques Document - NO Emissions from x

Industrial/Commercial/Institutional Boilers. U.S. Environmental Protection Agency, Office of

Air Quality Planning and Standards, EPA-453/R-94-022. Research Triangle Park, North

Carolina.

EPA. 1994b. Quality Assurance Handbook for Air Pollution Measurements Systems: Volume III,

Stationary Source Specific Methods (Interim Edition). U.S. Environmental Protection Agency,

Office of Research and Development, EPA-600/R-94-038c. Washington, D.C.

EPA. 1994c. Air Emissions Models for Waste and Wastewater. U.S. Environmental Protection

Agency, Office of Air Quality Planning and Standards, EPA-453/R-94-080A. Research Triangle

Park, North Carolina.

EPA. 1991a. Procedures for the Preparation of Emission Inventories for Carbon Monoxide and

Precursors of Ozone. Volume I: General Guidance for Stationary Sources. U.S. Environmental

Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North

Carolina.

EPA. 1991b. Control Technologies for Hazardous Air Pollutants Handbook. 

U.S. Environmental Protection Agency, Air and Energy Engineering Research Laboratory,

EPA-625/6-91/014. Research Triangle Park, North Carolina.

EPA. 1987. Estimating Releases and Waste Treatment Efficiencies for the Toxic Chemical

Release Inventory Form. U.S. Environmental Protection Agency, Office of Pesticides and Toxic

Substances, EPA-560/4-88-002. Washington, D.C.

EPA. 1977a. Industrial Process Profiles for Environmental Use: Chapter 2, Oil and Gas

Production Industry. U.S. Environmental Protection Agency, Office of Research and

Development, EPA-600/2-77-023b. Cincinnati, Ohio.

EPA. 1977b. Atmospheric Emissions from Offshore Oil and Gas Development and Production. 

U.S. Environmental Protection Agency. Research Triangle Park, North Carolina.

GRI. 1998. GRI-HAPCalcTM and GRI-HAPDataTM Software. Gas Research Institute. 

http://www.gri.org/pub/content/apr/19980406/204648/hapcalc.html.

GRI. 1997. GRI-GLYCalcTM Version 3.0 Computer Program. Gas Research Institute. 

http://www.gri.org/tech/e+s/airprj.htm#aquevalmeth3.

GRI. 1994. Preliminary Assessment of Air Toxic Emissions in the Natural Gas Industry, Phase I,

Topical Report. Gas Research Institute, GRI-94/0268. Chicago, IL.
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

10.8-4 EIIP Volume II

GRI. 1993. In-line Inspection of Natural Gas Pipelines, Topical Report. Gas Research Institute,

GRI-91/0365. Chicago, IL.

LADEQ. 1998a. Memorandum from Jim Courville to LADEQ. August 12, 1998.

 

LADEQ. 1998b. Memorandum from Mike Alegro to Regional Coordinators. July 17, 1998.

Martino, Paul, 1997. Petroleum Production Emission Estimating Techniques and Software. 

American Petroleum Institute. Washington, D.C. Presented at the Emission Inventory: Planning

for the Future, October 28-30, 1997, Research Triangle Park, North Carolina.

Mian, M.A. 1992. Petroleum Engineering Handbook for the Practicing Engineer, Volume I. 

PennWell Publishing Company. Tulsa, Oklahoma.

Nizich, Greg and EC/R. 1999. Table 1. Comparison of Measured HAP Emissions to Emissions

Predicted Using E&P TANK and EC/R Algorithm. U.S. Environmental Protection Agency,

Emission Standards Division, Research Triangle Park, NC and Environmental Consulting and

Research, Durham, NC, July 1999.

Rucker, J. Eldon and Robert P. Strieter, 1992. The Petroleum Industry Air Pollution Engineering

Manual, AP-40. Air and Waste Management Association. Pittsburgh, Pennsylvania.

TNRCC. 1998a. Determination of Applicable Requirements for Pigging Operations at Marine

Transfer Facilities. Texas Natural Resource Conservation Commission. 

http://www.tnrcc.state.tx.us/air/opd/state/115/211/irim08.htm.

TNRCC. 1998b. Applicability of Vent Gas Control Rules to Pipeline Pigging Activities. Texas

Natural Resource Conservation Commission.

http://www.tnrcc.state.tx.us/air/opd/state/115/121/rim07.htm

TNRCC. 1996. Technical Guidance Package for Annual Air Emissions Inventory

Questionnaires, Oil and Gas Industry, Draft. Texas Natural Resource Conservation Commission. 

Austin, Texas.
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-1

APPENDIX A

EXAMPLE DATA 

COLLECTION FORMS
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10.A-3

EXAMPLE DATA COLLECTION FORMS INSTRUCTIONS -

OIL AND NATURAL GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

MANUFACTURING FACILITIES

1. These forms may be used as a work sheet to aid the plant engineer in collecting the

information necessary to calculate emissions from oil and natural gas field production and

processing operations. The information requested on the forms relate to the methods

(described in Sections 3, 4, and 5) for quantifying emissions. These forms may also be

used by the regulatory agency to assist in area wide inventory preparation.

2. The completed forms should be maintained in a reference file by the plant engineer with

other supporting documentation.

3. If the information requested is unknown, write "unknown" in the blank. If the information

requested does not apply to a particular unit or process, write "NA" in the blank.

4. If you want to modify the form to better serve your needs, an electronic copy of the form

may be obtained through the EIIP on the Clearinghouse for Inventories and Emission

Factors (CHIEF) system.

5. Collect all Manufacturer's Technical Data Sheets (TDSs) for all materials containing

potential air contaminants that are used at the facility.

6. The plant engineer should maintain all material usage information and TDSs in a reference

file.
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.A-4

EXAMPLE DATA COLLECTION FORM 

FORM A: GENERAL INFORMATION

Facility/Plant Name:

SIC Code:

SCC:

SCC Description:

Location:

County:

City:

State:

Plant Geographical coordinates:

 Latitude: 

 Longitude: 

 UTM Zone: 

 UTM Easting: 

 UTM Northing: 

Contact Name:

Title:

Telephone Number:
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-5

EXAMPLE DATA COLLECTION FORM 

FORM B: SOURCE INFORMATION

Unit ID:

Permit No.:

Location:

Unit Description:

Manufacturer:

Date Installed:

Date Modified:

Operating Schedule:

Hours/Day:

Days/Week:

Weeks/Year:
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.A-6

EXAMPLE DATA COLLECTION FORM 

FORM C: CONTROL DEVICE INFORMATION

 Unit ID:

 Permit No.: 

 Location: 

 Pollutant Controlled:

 Control Efficiency (Indicate source of information):

 Type of Control Device:

 a Baghouse

 a Carbon Adsorber

 a Condenser

 a Flare

 a Scrubbers (indicate type) ______________________________

 a Thermal Incinerator

 a Other (indicate type) ______________________________

 

 Manufacturer: 

 Date Installed:

 Date Modified: 

 Operating Schedule: 

Hours/Day: 

Days/Week: 

Weeks/Year: 

 Source(s) Linked to this Control Device: 
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-7

EXAMPLE DATA COLLECTION FORM 

FORM D: STACK INFORMATION

 Stack ID:

 Unit ID:

 Stack (Release) Height (ft):

 Stack Diameter (inch):

 Stack Gas Temperature ((F):

 Stack Gas Velocity (ft/sec):

 Stack Gas Flow Rate (ascf/min):

 Source(s) Linked to this Stack:
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.A-8

EXAMPLE DATA COLLECTION FORM 

FORM E: PRODUCTION INFORMATION 

Product Name Year Amount Produced (lb/yr)
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-9

EXAMPLE DATA COLLECTION FORM

FORM F: DATA NEEDED FOR EMISSIONS FROM COMBUSTION OPERATIONS

Unit ID No.: Fuel A Fuel B Fuel C Comments

Fuel Type:

Sulfur Content (%):

Heating Value of Fuel (MMBtu/MMscf or

MMBtu/Mgal):

Maximum Hourly Fuel Use (units):

Total Annual Fuel Use (units):

Maximum Capacity (Million Btu/hr):

Note: Complete this form for each unit.
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.A-10

EXAMPLE DATA COLLECTION FORM 

FORM G: DATA FOR EMERGENCY AND PROCESS VENTS, GAS ACTUATED PUMPS,

PRESSURE/LEVEL CONTROLLERS, BLOWDOWN, WELL BLOWOUTS, WELL TESTING,

TRANSPORTATION LOADING LOSS, AND STORAGE TANK FLASH LOSS EMISSIONS

Equipment Processed Molecular Weight Fraction in VOC Fraction in

 ID (scf/yr) of Gas Gas Constituent VOC

Volume of Gas VOC Mass Mass

VOC

Constituent
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-11

EXAMPLE DATA COLLECTION FORM 

FORM H: DATA FOR GAS SWEETENING/FLARE EMISSIONS

Equipment ID (scf/yr) Constituent Constituent in Inlet Gas

Volume of Gas

Processed Mole Fraction of
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.A-12

EXAMPLE DATA COLLECTION FORM

FORM I: DATA FOR SULFUR RECOVERY UNIT EMISSIONS

Unit ID (scf/hr) Inlet Stream (%)

Volume of Gas Sulfur Recovery 

Processed Mole Fraction of H S in Efficiency 2
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-13

EXAMPLE DATA COLLECTION FORM 

FORM J: DATA FOR EMISSIONS FROM FUGITIVE SOURCES (HEATER TREATERS,

BLOWOUT, SEPARATORS, WELLHEADS, PIPELINE, PUMP STATIONS

Source Type Events Constituent

Number of Components or
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.A-14

EXAMPLE DATA COLLECTION FORM 

FORM K: DATA NEEDED FOR LOADING LIQUID MATERIALS INTO TANK TRUCKS AND

TANK CARS

Volume of Type of Pressure of

Material Loading Material Vapor Constituent

Loaded (submerged, Loaded Molecular Temp. Mass

(Mgal/yr) Material splash, etc.) (psia) Weight ((R) Constituent Fraction

True Vapor
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.A-15

EXAMPLE DATA COLLECTION FORM 

FORM L: DATA NEEDED FOR EMISSIONS FROM LOADING CRUDE OIL INTO SHIPS AND

BARGES

Volume True Vapor

of Mass Pressure of

Material Fraction Material Temp. of Molecular Constituent

Loaded of VOC in Loaded Vapors Weight of Mass

(Mgal/yr) Material Vapor (psia) ((R) Vapors Constituent Fraction
EIIP Volume II

10.A-16 EXAMPLE DATA COLLECTION FORM FORM M: EMISSION RESULTS Equipment ID:____

Pollutant

Emission

Estimation

Methodb Emissions

Emissions

Units

Emission

Factorc

Emission

Factor

Units Co

Pollutants include VOCs, PM/PM , H S, SO , NO , CO , CH , CO, and HAPs (list individually). a 10 2 2 x 2 4Use the following codes to indicate which emission estimation method is used for each pollutant: b

Emission Factor = EF Emission Model = EMMass Balance = MB Engineering Equation = EEOther Method (indicate) = O Stack Test = ST

Continuous Emission Monitoring Systems = (CEMS)

Where applicable, enter the emission factor and provide full citation of the reference or source of information from where th

c

came. Include edition, version, table and page numbers if AP-42 is used.
9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

EIIP Volume II

10.B-1

APPENDIX B

LADEQ GUIDELINES AND INSPECTION

CHECKLIST FOR

GRI-GLYCALC MODEL
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9/3/99 CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS

These guidelines are used by the Louisiana Department of Environmental Quality (LADEQ) and are 1

based on data collected from the field.

EIIP Volume II

10.B-3

LADEQ GUIDELINES FOR GRI-GLYCALC MODEL1

Process Parameter Guidelines

A. Wet Gas

1. Temperature Range: 80(F to 120(F

2. Pressure Range: 850 psig to 1,400 psig

3. Water content Always saturated

4 All data Based on actual information

5. Sample Must be obtained at inlet for analysis and include BTEX analysis

6. Composition Always check composition if benzene mole % is less than 0.03; if

below 0.03%, the sample may have been taken in the wrong

location.

B. Dry Gas

1. Flow rate Range: 1.0 to 500 MMscf/day

2. Water content Range: 2.0 to 7.0 lb H O/MMscf (never over 7.0) 2

C. Lean Glycol

1. Circulation rate Obtain from chart with strokes per minute information (gpm)

2. Water content Range: 0.1 to 0.5 wt%

3. Lean glycol Always use 3.0 gal/lb H 02

4. Pump type Electric or gas driven with meter on electric pump

5. Pump gas ratio Obtain from chart called gas composition

D. Flash Tank (Separator):

1. Temperature Range: 100.0 to 150.0(F

2. Pressure Range: 30 to 70 psig

3. All data Obtained from actual data at facility

E. Stripping gas Normally none

F. Control device (if applicable)

1. Condenser temperature Range: 80 to 200(F; if steam is coming out, use 200(F; if water

cooled, use 80(F

2. Condenser pressure Always use 14.7 psia
CHAPTER 10 - OIL AND GAS FIELD PRODUCTION AND PROCESSING OPERATIONS 9/3/99

EIIP Volume II

10.B-4

LADEQ GLYCOL INSPECTION CHECKLIST

July 17, 1998

MEMORANDUM

TO: Regional Coordinators

Air Quality Compliance Division

FROM: Mike Algero

Surveillance Program Manager

Air Quality Compliance Division

SUBJECT: Glycol Inspection Checklist

The Air Quality Engineering Section has developed the following checklist for glycol units. 

Please review it with you staff.

When glycol dehydrators are inspected by your staff, the following information is needed to

evaluate compliance using the Glycale software.

1. Inlet wet gas flow rate and composition (speciated for BTEX).

2. Temperature and pressure of glycol contact tower.

3. Glycol circulation - obtained by timing strokes of the glycol pump and converting to flow rate

using pump vendor information obtained from facility. If circulation cannot be determined this

way, then facility must provide other means of measuring flow, if Glycalc is to be used.

4. If the unit is controlled with a condenser, documentation that the annual average temperature of

the condenser outlet is less than 110(F (as specified in 2116.F.3).

Please contact me if you have any questions.

MA/vh