501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

MEMORANDUM

Date: July 23, 2010

Subject: Summary of the July 21, 2010 Meeting Between the EPA and API 

Representatives Regarding Emission Control Technologies

From: Denise Grubert, EC/R Incorporated

To: Bruce Moore, EPA/OAQPS/SPPD/CCG

I. PURPOSE

This memorandum summarizes the July 21, 2010 meeting between the Environmental Protection 

Agency (EPA) and industry representatives from the American Petroleum Institute (API). The 

meeting allowed API an opportunity to provide information to EPA on emission control options 

for the oil and gas sector, which is comprised of four segments: production, processing, 

transmission, and distribution. 

II. DATE

The meeting took place on July 21, 2010 from 11 a.m. to 12:30 p.m. at the United States 

Environmental Protection Agency in Research Triangle Park, North Carolina. 

III. ATTENDEES

The following individuals were present at the meeting.

Industry Representatives

American Petroleum Institute: Matt Todd

British Petroleum: Jeffrey A. Adams

Chevron: Clay Fleeberg,

 Janet Bounds (Phone Call-In)

ConocoPhillips: Clint Gill

ExxonMobil: Tom Monahan

Marathon Oil: Jenny Yang

Shell: George Deeley

U.S. Environmental Protection Agency (EPA/OAQPS/SPPD/CCG)

Bruce Moore

Nick Parsons

David Solomon (Phone Call-In)
501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

EC/R Incorporated

Denise Grubert

Karen Marsh

Phil Norwood

IV. SUMMARY OF DISCUSSION

EPA met with API representatives in order to gain information regarding emission control 

options currently used within the Oil and Gas industry. After introductions, Bruce Moore from 

EPA provided an update on the current status of the project and the timeline moving forward. 

The purpose of the meeting was to gather useful information regarding control technologies. 

API provided a table of control techniques for limiting VOC emissions, as this would also 

capture other hazardous air pollutants in the emissions plume. The table includes those control 

options API assumed EPA would find during EPA’s research as these controls are currently used 

within the oil and gas industry. All technologies included in the table have been proven to 

control emissions in various applications, and have the potential to be cost-effective under 

certain conditions. Discussion began on each control option in order as it appears in the table.

This document is provided as attachment 1. Specific concerns in regards to certain controls made 

by API are noted below.

 The use of flares as an emission control was discussed in detail due to current 

regulations outlined in 40 CFR 60.18. API mentioned more flexibility is required 

beyond the current regulations for optimal use in oil and gas settings. Sonic 

emission flares and electric igniter flares could be more desirable for controlling 

emissions versus the standard in certain situations. It was also noted a generic 

flare ruling is also due out by EPA this fall.

 Vapor recovery units (VRU) are economical if there is available electricity and 

high flow rates. VRUs become oversized as production declines.

 Audio, Visual, and Olfactory Inspection (AVO) is the desired method of leak 

inspection because regular technicians can perform duties. In addition, many sites 

in the oil and gas sector are open access. Current tags (required under Method 21) 

on emission sources may go missing. Multiple companies stated their current 

operations include inspection a minimum of once a month, if not more. 

 OSHA has a “log out, tag out” system already in place for worker safety. 

 Solar panel theft is a major issue in remote and/or open access areas. 

 API said they would be willing to meet again to discuss any additional questions 

EPA may have in the upcoming months. EPA suggested sometime in early fall. 
501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

 Green Completions comments will be sent in a separate document at a later date. 

This document is listed as Attachment 2. 

In addition, API expressed concern on the future regulation of methane. At this time, methane is 

not a regulated pollutant under the Clean Air Act. Information on methane emissions from Oil 

and Gas emission sources will be used in determining levels of criteria and hazardous pollutants 

(HAP).

API also asked questions on upcoming public meetings EPA is holding to gain public feedback 

in review of the current air regulations. These meetings will be held on August 2 in Arlington, 

Texas and on August 3 in Denver, Colorado. API will not be in attendance to provide comment 

due to the nature of the meeting today.

API also inquired about sites in Colorado and Wyoming that EPA plans to visit following the 

public meetings. EPA is looking forward to visiting the sites and gaining additional perspective 

on various emission sources and controls. The itinerary is still in the planning stages as EPA 

coordinates with Colorado’s Environmental Enforcement and Wyoming’s Department of 

Environment. Both these groups enforce oil and gas air regulations in these states. 

EPA informed API there was a conference call scheduled with representatives of the 

Environmental community the following week.
501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

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Oil & Gas1 VOC Emission Control Options

1 Characterized by dispersed2

/remote operations.

2 Dispersed – typically small facilities spread out over large areas.

3 Space and weight limitations limit the retrofitting of existing offshore platforms

Emission 

Control 

Technology

Applicable 

Emission 

Sources

Description of 

Control

Limitations of Control 

Technology3

Implementation Concerns and 

Limitations

Variables Impacting 

Control Cost

Current Use Cost 

Effectiveness 

Factors

Flare VOC emissions 

from emergency 

operations, 

equipment blow

downs, tank 

vapors, 

dehydration units, 

etc.

Naturally aspirated 

pipe flare with auto 

ignition (spark 

ignited) pilot

Low flow can lead to 

inefficient combustion for 

flare designed for high 

flows. Low BTU gases (i.e. 

amine overhead) may have 

low combustion efficiencies

and require use of “assist

gas” (also referred to as 

make-up or power gas) to 

boost BTU.

Remote, unmanned operations

may lead to safety and pilot 

monitoring concerns for continuous 

operation. 

When tying in tanks or other 

sources that may contain air, 

proper flame arrestor design must 

be included to mitigate explosion 

potential. 

Maximum expected flow for 

flare size, minimum BTU 

content for operational cost 

of enrichment gas.

Mainly at gas plants and 

larger compressor 

stations and sour gas 

treating facilities. May 

also be used at tank 

batteries. Portable flares 

may be used for 

temporary maintenance 

and gathering system 

blow down. Spark ignition

system often used in lieu 

of continuous flame pilots 

to overcome safety 

concerns of remote 

operations.

Cost effective for

routine operations

blow downs or 

upset/emergency 

use.

Smokeless 

Combustion 

Chambers (vapor 

flares)

VOC emissions 

from tank flash, 

dehydration units, 

pneumatic 

pumps, etc.

An enclosed 

combustor with air 

intake flame 

arrestor

Heat input capacity per 

stack height and diameter 

per manufacturer's 

information.

Remote, unmanned operations 

lead to safety and pilot monitoring 

concerns for continuous operation

Maximum hourly heat input Controlling tank flash, 

dehydration units, and 

pneumatic pumps in 

Wyoming.

Vapor Recovery 

Unit

VOC emissions 

from tank flash

and vapors, 

dehydration still 

vents, treater 

vents, etc.

Compressor or 

venturi used to 

pressurize gas

vapor and inject 

into the process 

stream.

VRU is considered 

a part of the 

process and not an 

emission control.

Need relatively constant 

flow to prevent frequent 

cycling of compressor, 

Availability and stability of 

electricity or gas supply to drive 

VRU.

Frequently cycling of VRU may 

cause increased downtime of gas 

fired engines particularly at

unmanned operations.

Venturi type VRUs require high 

pressure motive gas. 

Low pressure gas system needed 

for discharge.

Wide variation in gas flow, 

suction pressure and 

discharge pressure can 

make designing a properly 

sized VRU difficult.

Mainly at gas plants and 

compressor stations, and 

some tank batteries

Availability of 

electricity at site as 

well as sufficient 

vapors to meet 

minimum design 

volume 

requirements.
Oil & Gas1 VOC Emission Control Options

1 Characterized by dispersed2

/remote operations.

2 Dispersed – typically small facilities spread out over large areas.

3 Space and weight limitations limit the retrofitting of existing offshore platforms

Emission 

Control 

Technology

Applicable 

Emission 

Sources

Description of 

Control

Limitations of Control 

Technology3

Implementation Concerns and 

Limitations

Variables Impacting 

Control Cost

Current Use Cost 

Effectiveness 

Factors

LDAR - AVO 

(Auditory, Visual, 

Olfactory)

Inspection

Fugitive 

components

Audio/Visual/Olfact

ory inspection of 

fugitive 

components for 

leaks

Small leaks can be missed. Low to no cost, depending 

on recordkeeping 

requirements. 

Common operator 

inspection at dispersed

and remote oil and gas 

production facilities. 

Typically documented by 

exception only (i.e. work 

order completed when 

maintenance is required). 

Required for NSPS, 

Subpart KKK regulated 

gas plants for heavy liquid 

streams.

LDAR - Method 

21

Fugitive 

components

Inspection of 

fugitive 

components for 

leaks utilizing an 

organic vapor 

analyzer under 

Method 21

May be difficult at times to 

determine the exact source 

of the leak.

Difficult and costly for dispersed oil 

and gas facilities. Cost and 

availability of third party

contractors (monitoring and valve 

repair) are an issue in some 

remote areas (i.e. Alaska and 

Wyoming). 

Number of components, 

number of facilities, 

dispersed location travel, 

hot work permits, etc.

Gas plants subject to 

NSPS KKK or HAP Major 

subject to NESHAP, 

Subpart HH

Increased 

operating expense 

for all upstream 

facilities. potential 

for little emission 

reduction

LDAR - Infrared 

Camera

Fugitive 

components

Inspection of 

fugitive 

components for 

leaks utilizing an 

infrared camera.

Requires viewing the 

component from different 

angles and good weather 

conditions. No 

quantification of flow.

Must be trained in proper use of 

the camera and able to distinguish 

between water vapor and 

emissions.

Number of cameras and 

operators needed to scan 

dispersed oil and gas 

facilities. May be 

reasonable alternative to 

Method 21 if recordkeeping 

burden is manageable. 

Mainly for equipment 

integrity purposes. 

Costly equipment 

and operator 

training required

Collection of low 

pressure gases

into fuel supply.

Pneumatic

pumps and 

controllers

Routing of 

emissions from 

pneumatic pumps 

and controllers that 

use natural gas to a 

collection line for

fuel supply. 

Process, not 

emission control.

Sufficient pressure must be 

available to enter the closed loop 

system. If routing to a fuel system, 

may have more emissions than 

needed for fuel.

Dispersed oil and gas 

production facilities with 

pneumatic pumps and 

controllers
Oil & Gas1 VOC Emission Control Options

1 Characterized by dispersed2

/remote operations.

2 Dispersed – typically small facilities spread out over large areas.

3 Space and weight limitations limit the retrofitting of existing offshore platforms

Emission 

Control 

Technology

Applicable 

Emission 

Sources

Description of 

Control

Limitations of Control 

Technology3

Implementation Concerns and 

Limitations

Variables Impacting 

Control Cost

Current Use Cost 

Effectiveness 

Factors

Solar Pumps Replace small 

pneumatic pumps 

(<100 

gallons/day)

Using solar pumps 

in place of 

pneumatic pumps 

that use natural gas 

Only available for pumps 

that circulate <100 

gallons/day. Sold as a 

package. 

Solar panels are often stolen. Chemical and methanol 

pumps at dispersed oil 

and gas production 

facilities.

Installation of air 

compression to 

replace natural 

gas driven (i.e. 

pressure drop) 

equipment

Instruments, 

controls, starting 

air and 

pneumatic pump 

services

Provide 

compressed air to 

drive pressure drop 

driven equipment to 

replace natural gas 

that is vented to 

atmosphere

Requires availability of 

electricity to be reliable and 

affordable. 

Certain weather conditions 

may require air dehydrators 

for instrument systems to 

prevent condensate 

blocking the signal. High 

cost of manpower for 

frequent inspection. 

Gas plants and some 

central tank batteries and 

compressor stations.

Low Bleed/No 

Bleed Controllers

controllers Install, replace, or 

retrofit low bleed/no 

bleed controllers in 

place of high bleed 

controllers

Some old high bleed controllers 

can not be retrofitted and would 

have to be replaced

Controllers at dispersed 

oil and gas production 

facilities and gas plants

Minimize manual 

blow 

down/venting to 

atmosphere 

during 

maintenance/ 

operational 

events.

Depressurizing 

equipment for 

maintenance.

Response to 

vapor locked 

equipment (i.e. 

pumps or deliquefying well 

bore),

Have personnel on 

site during the blow

down/venting, 

operator training, 

etc. to ensure that 

minimal gas 

venting occurs

Over restrictive procedures may 

cause reoccurrence (vapor locked 

equipment) or safety concerns 

(depressurizing equipment). 

Distance between facilities.
Oil & Gas1 VOC Emission Control Options

1 Characterized by dispersed2

/remote operations.

2 Dispersed – typically small facilities spread out over large areas.

3 Space and weight limitations limit the retrofitting of existing offshore platforms

Emission 

Control 

Technology

Applicable 

Emission 

Sources

Description of 

Control

Limitations of Control 

Technology3

Implementation Concerns and 

Limitations

Variables Impacting 

Control Cost

Current Use Cost 

Effectiveness 

Factors

Minimize upset or 

emergency blow 

down/venting to 

atmosphere. 

Upsets include 

loss of electricity, 

loss of distribution 

point without 

ability to shut off 

source, or 

process event.

Natural gas 

released to 

atmosphere due 

to emergency 

event or upset 

(typically a third 

party event out of 

the operators 

control).

Prior contingency 

planning for 

predictable events. 

Communication 

with third parties to 

determine duration, 

thus select option 

to minimize 

emissions.

Operator does not have 

control of the event 

causing the blow 

down/venting. Cooperation 

of third parties required. 

May have contractual 

limitations. 

Source of natural gas is typically a 

gathering system with dispersed 

well locations. Significant time is 

required to shut each well in. 

Stopping the flow in many wells 

may require atmospheric venting 

to de-liquefy the well to start flow 

(resolve vapor lock). 

Venting or blow downs 

during an emergency or 

upset situation is a 

common occurrence in 

upstream oil and gas 

operations, venting is 

usually through a vent 

stack or relief valve 

system

Glycol Dehydrator 

Rich Glycol Flash 

Separator

Water saturated 

glycol in dehy.

must drop the 

pressure from 

contactor pres. to 

near atmospheric 

pressure before 

the water can be 

cooked off in the 

still. 

A flash tank can 

separate the gas 

from the glycol for 

use as fuel or to be 

returned to the 

process. 

Requires a low pressure 

gas collection system or 

use, such as fuel system, 

low pressure gathering 

system, vapor recovery 

compressor, flare, etc.

If use or system is insufficient for 

gas volume generated, then gas 

must be vented

Secondary 

Separator for 

liquid stream

High pressure 

production 

separators where 

a low pressure 

gas handling 

system is 

available. 

Condensate/crude 

oil from a high 

pressure prod. 

separator is flashed 

at a lower pressure, 

so flash gas can be 

collected for use or 

return to the 

process. 

Requires a low pressure 

gas collection system or 

use, such as fuel system, 

low pressure gathering 

system, vapor recovery 

compressor, flare, etc.

If use or system is insufficient for 

gas volume generated, then gas 

must be vented

Process system and 

stability of gas volume

Primarily fuel systems and 

vapor recovery 

compressors. 
Oil & Gas1 VOC Emission Control Options

1 Characterized by dispersed2

/remote operations.

2 Dispersed – typically small facilities spread out over large areas.

3 Space and weight limitations limit the retrofitting of existing offshore platforms

Emission 

Control 

Technology

Applicable 

Emission 

Sources

Description of 

Control

Limitations of Control 

Technology3

Implementation Concerns and 

Limitations

Variables Impacting 

Control Cost

Current Use Cost 

Effectiveness 

Factors

Green 

Completions (i.e. 

reduction of 

natural gas 

vented to the 

atmosphere 

during well 

completion 

operations)

Venting and 

flaring during 

completions (flow 

back of hydraulic 

fracturing fluids)

After hydraulic 

fracturing the much 

of the injected 

fluids must “flow 

back” out of the 

well. Historic 

operations produce 

flow back fluids into 

an open pit until the 

gas/oil is sellable. 

Green completions 

use specially 

designed sand 

traps and 3-phase 

separators to 

capture the natural 

gas for sale quicker 

than normal

production 

equipment allows.

Sand traps and separators 

must be designed to 

handle the highly erosive 

conditions associated with 

producing high volume, 

high pressure completion 

fluids.

Produced gas must meet 

the gathering system 

specifications before 

natural gas can be 

delivered into the pipeline. 

Certain well completion 

activities (i.e. drilling out 

frac. plugs and running 

production tubing) must be 

completed must be 

completed before space is 

available for the equipment 

required for “green 

completions”, requiring well 

fluids to be routed to the pit 

during these operations. 

Gathering system piping must be 

run to the well before the well test 

is complete and production 

volumes are known.

Gas pressure is typically below 

pipeline pressure during initial flow 

back operations. Pipeline 

pressure may limit how soon 

natural gas can be delivered to the 

pipeline.

Hydrate formation – Hydrates are 

a solid ice/hydrocarbon mixture 

that forms because of high 

pressure and/or low temperature. 

Hydrates can form for many 

reasons including cold weather, 

pressure reduction from high 

pressure reservoirs, and excessive 

moisture due to dehydration 

equipment not being available. 

Location of well – Green 

completions are most 

economical during infield 

drilling projects (drilling 

wells to reduce “well 

spacing” to allow remaining 

reserves to be produced in 

an older reservoir), due to 

gather system availability. 

Gathering system will not be 

available before well testing 

on wild cat wells or reservoir 

boundary exploration wells. 

See attached issue paper. See attached issue 

paper.
application of Green Completion techniques are limited due to technical barriers in many

instances and must be well planned and designed where used.

Process Description:Flaring or venting wells, against atmospheric pressure, for clean-up following completion

and fracture stimulation is the traditional practice/methodo1ogy. This approach results in

the least back-pressure on the well, the highest flow rates and velocity up the well-bore,

and promotes better flow back ofthe fracture fluids and clean-up ofthe formation near

the well-bore. Adequate clean-up ofthe near well formation is critical to prevent

formation damage and allow optimum long-term production from the well.Green Completions is a departure from this traditional practice where the well clean-up isdone through specialty surface separation equipment and part ofthe gas and condensate,

which would have been flared (or gas vented), is recovered for sales. Gas recovered

during Green Completions operations is routed to a sales gas or gathering line which

increases the back pressure on the well by whatever pressure the line is operating at along

with the additional pressure drop caused by the surface equipment. This results in more

back-pressure on the well, lowers the flow rates and velocity up the well-bore, and maynot allow adequate clean-up ofthe formation near the well-bore. Due to this affect, the

applicability of Green Completions techniques to a particular area/field needs to becarefully considered and adequate clean-up with no damage to the formation or long termwell productivity demonstrated.Technical and Operational Limitations — There are many situations that limit the

ability to utilize green completions for reducing emissions in natural gas production.

Some ofthem include:

• Sand traps and three phase separators must be designed and manufactured to

endure the highly erosive conditions associated with producing high volume, highpressure fluids containing sand. A one-size-fits all or off-the-shelf designphilosophy can lead to operational problems/delays, short equipment life, and/or

safety concerns like the erosion created washout pictured below.
• In order to deliver gas to the sales pipeline or gathering system, gas must meet quality specifications. Many well stimulations are energized with nitrogen or carbon dioxide to assist the flow back and cleanup. Since these gases come back with the well production, gas cannot be routed to the pipeline.

• A pipeline must be laid to the well in advance of the completion, which results in

a capital outlay risk for the pipeline company since the results of the well are not

fully understood until the completion is performed. It is difficult for a pipeline

company to size the pipeline and spend capital in advance without fully understanding the production potential ofthe well.

• Gas gathering pipelines are not in close proximity to all drilling locations. Wild

cat wells are drilled in areas where O&G reserves have not been proven or developed. Gas gathering lines must be run many miles to the nearest gas transmission line or consumer, which will not be done until sufficient gas reserves

are proven to make the pipeline economical. Reservoir boundary exploration wells seek to extend the production area outside the area of existing gathering system infrastructure. Again, the well must be completed and tested to have reasonable confidence that running a pipeline to the well will be economical.

Typically, only infield drilling projects (inside known production areas, often to reduce well spacing to completely produce remaining reserves) have sufficient certainty of production volumes and close availability of gathering system to make green completions viable.

• When each stage of a stimulation program is initially completed, the pressure of the gas may not be high enough to overcome pipeline pressure. Any time this

occurs, the well will be flared or vented until enough pressure is available to sendgas to the pipeline. This allows clean up of the wellbore and is critical to

minimize the potential for formation damage. Once a fracture stimulation is

pumped, flowback and clean-up must proceed regardless of sufficient pressure to enter pipeline system.

Therefore, green completions should be encouraged where possible, but understood that they are only feasible in certain situations.

EPA Natural Gas Star Website
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Flat. Unas

Green Completion Process Schematic

Cc.1d4 rsate

Typical Green Completion Surface Equipment