501 Eastowne Drive, Suite 25 0  Chapel Hill, North Carolina 2751 4 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 o n 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 individu als were present at the meeting.

Industry Representatives

A merican P etroleum I

nstitute : Matt Todd

B ritish P etroleum : 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

Dav id Solomon (Phone Call

- In)501 Eastowne Drive, Suite 25 0  Chapel Hill, North Carolina 2751 4 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 O il and G as 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 provi ded 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 contr ols are curre ntly 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 c ontrol option in order as it appears in the table. This document is provided as attachment 1

. Specific concerns in r e gards to certain controls made by API are noted below.

 The use of f

l ares 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 reg ulations for optimal use in oil and gas settings. S onic
emission flares a nd 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 becau se regular technicians can perform duties. In addition, many sites in the oil and gas sector are open access . C urrent 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 25 0  Chapel Hill, North Carolina 2751 4 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 l isted as A ttachment 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 d etermining 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. T he itinerary is still in the planning stages as EPA coordinates with Colorado’s Environmental Enforcement and Wyoming’s Department of
Enviro nment. 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 25 0  Chapel Hill, North Carolina 2751 4 Telephone: (919)484

- 0222  Fax: (919) 484

- 0122 This page is intentionally left blank.

## Oil & Gas 1 

## VOC Emis sion Control Options

1 

### Characterized by dispersed 2 

### /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 Technology 3 Implementation Concerns and
Limitations Variables Impacting Control Cost Current Use Cost
Effectiveness
Factors

Flare VOC emissions

from emer gency operations, equipment blow downs, tank

vapors
, dehydration units,

etc. Naturally aspirated

pipe flare with auto ignition (spark ignited) pilot Low flow can lead to
ineffic i ent 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 t anks 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 co mpressor 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

. C ost 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 wit h 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, treat e r vents, etc. Compressor or

venturi used to pressurize gas

vapor and inject into the process

stream

. VRU is c onsider ed a part of the process and not an
emission control. Need relatively constant

flow to prevent frequent cycling of compressor

, Availability and stability of
elect r icity or gas supply to drive
VRU. Frequently cycling of VRU may

cause increased d owntime 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 c an make designing a p roperly
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 & Gas 1 

## VOC Emis sion Control Options

1 

### Characterized by dispersed 2 

### /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 Technology 3 Implementation Concerns and
Limitations Variables Impacting Control Cost Current Use Cost
Effectiveness
Factors

LDAR

- AVO (Auditory, Visual, Olfactory) Inspec tion 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 d ispersed
and remote oil and gas production faci lities

. 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 component s for leaks utilizing an organic vapor analyzer under
Method 21 May be d ifficult at times to

determine the exact source of the leak. Difficult and costly for dispersed oil and gas facilities. Cost and availability of third part y contractors (monitoring an d valve repair) are an issue in some remote areas (i.e. Alaska and Wyoming). N umber of components, number of facilities, dispersed location travel, hot work permits, etc. Gas plants subject to NSPS KKK o r 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 angle s 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

reaso nable alternative to Method 21 if recordkeeping burden is manageable. M ainly 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

pn e umatic 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 emi ssions than
needed for fuel. D ispersed oil and gas production facilities with pneumatic pumps and
controllers

## Oil & Gas 1 

## VOC Emis sion Control Options

1 

### Characterized by dispersed 2 

### /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 Technology 3 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

pn e umatic pumps that use natural gas Only available for pumps
that circulate <100 gallons/day . Sold as a

pac k age. 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 affordab le. 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 C ont r ollers at dispersed oil and gas pr oduction facilities and gas plants

Minimize manual
blow down/venting to atmosphere during maintenance/ operational

events. Depressurizing

equipment for
maintenance

. R esponse to vapor locked equipment (i.e. pumps or de

liquefying well bore)

, Have personn el 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 facilit ies.

## Oil & Gas 1 

## VOC Emis sion Control Options

1 

### Characterized by dispersed 2 

### /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 Technology 3 Implementation Concerns and
Limitations Variables Impacting Control Cost Current Use Cost
Effectiveness
Factors

Minimize upset or emergency blow down/venting to

atmos p here

. 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 ( t ypically 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

ca using 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 th rough a vent
stack or relief valve system

Glycol Dehydrator Rich Glycol Flash Sep a rator 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 ta nk can

s eparate the gas from the glycol for
use as fuel or to be
returned to the

process. Requires a low pressure

g as collection system or use, such as fuel system, low pressure gathering system, vapor recovery compressor, flare, etc. If use or system is insufficient for

g as 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 sy stem 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 & Gas 1 

## VOC Emis sion Control Options

1 

### Characterized by dispersed 2 

### /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 Technology 3 Implementation Concerns and
Limitations Variables Impacting Control Cost Current Use Cost
Effectiveness
Factors

Green Completions (i.e.

r e duction of natural gas
vented to the atmosphere during wel l 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 op en pit until the gas/oil is sellable. Green completions use specially designed s and traps and 3

- phase separators to capture the natural gas for sale quicker
than normal production equipment allows

. Sand traps and separators

m ust 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. dr illing 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 sy stem pip ing 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

– Hy drates 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

a n old er 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.Attachment2.GreenCompletionsIssuePaper“GreenCompletions”forNaturalGasIssuePaperUseofGreenCompletiontechniquescanrecoverandpreservevaluableenergyresourceswhileprotectingtheenvironment.Dependingonthefield/wellcharacteristics,itmayalsobeeconomicallypositivefortheoperatortousethesetechniques.However,applicationofGreenCompletiontechniquesarelimitedduetotechnicalbarriersinmanyinstancesandmustbewellplannedanddesignedwhereused.ProcessDescription:Flaringorventingwells,againstatmosphericpressure,forclean-upfollowingcompletionandfracturestimulationisthetraditionalpractice/methodo1ogy.Thisapproachresultsintheleastback-pressureonthewell,thehighestflowratesandvelocityupthewell-bore,andpromotesbetterflowbackofthefracturefluidsandclean-upoftheformationnearthewell-bore.Adequateclean-upofthenearwellformationiscriticaltopreventformationdamageandallowoptimumlong-termproductionfromthewell.GreenCompletionsisadeparturefromthistraditionalpracticewherethewellclean-upisdonethroughspecialtysurfaceseparationequipmentandpartofthegasandcondensate,whichwouldhavebeenflared(orgasvented),isrecoveredforsales.GasrecoveredduringGreenCompletionsoperationsisroutedtoasalesgasorgatheringlinewhichincreasesthebackpressureonthewellbywhateverpressurethelineisoperatingatalongwiththeadditionalpressuredropcausedbythesurfaceequipment.Thisresultsinmoreback-pressureonthewell,lowerstheflowratesandvelocityupthewell-bore,andmaynotallowadequateclean-upoftheformationnearthewell-bore.Duetothisaffect,theapplicabilityofGreenCompletionstechniquestoaparticulararea/fieldneedstobecarefullyconsideredandadequateclean-upwithnodamagetotheformationorlongtermwellproductivitydemonstrated.TechnicalandOperationalLimitations—Therearemanysituationsthatlimittheabilitytoutilizegreencompletionsforreducingemissionsinnaturalgasproduction.Someoftheminclude:•Sandtrapsandthreephaseseparatorsmustbedesignedandmanufacturedtoendurethehighlyerosiveconditionsassociatedwithproducinghighvolume,highpressurefluidscontainingsand.Aone-size-fitsalloroff-the-shelfdesignphilosophycanleadtooperationalproblems/delays,shortequipmentlife,and/orsafetyconcernsliketheerosioncreatedwashoutpicturedbelow.•

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

of the 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 send gas

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 WebsiteA

Sand Trap Attachment

A

Tp De-hdra1orFWeêlh.ad r

I

Flat. Unas Green Completion
Process Schematic Cc.1d4 rsate Typical Green Completion

Surface Equipment