Oil and Gas Emission Invent

for the Western States

Jam

Alis

Greg 

ENVIRON International C
Today’s Presentation

• Background• 2002 Inventory Methodology• 2018 Inventory Methodology• Oil and Gas Controls• Additional Projects
Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background

• Evaluate existing inventories• Develop consistent oil and gas 

inventory methodology

• Update the baseline (2002) inven• Project emissions for future year 

(2018) inventory

Project Goals
Previous Inventory Coverage, P

• Facilities extracted:

– Compressor stations– Gas plants– Storage tanks– Other smaller sources 

depending upon inventory thresholds

• Inventory thresholds 

from 1 tpy to 100 tpy

• Irregularities

Well locations were not obtained for California as CAlevel emissions estimates

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Previous Inventory Coverage, A

• Covered

– California and Wyoming– Colorado and Alaska point source 

inventories include most sources

• Not covered

– New Mexico, Montana, Utah, etc...– Sources such as drill rigs and pump 

engines are not included in the exis2002 inventories

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Base Year (2002) Inventory Proc

• Adopt point source emissions from exi

state inventories

• Estimate area source emissions for:

– Important NOx sources

• Drill rig engines• Natural gas compressor engines• CBM pump engines

– Minor NOx and VOC wellhead processes

• Incorporate emission controls• Reconcile point and area inventories

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Drill Rig Engines

Data Collection

• Drilling companies contacted• Oil and gas commission data

– Well depth– Spud date – date drilling begins– Completion date – date well 

preparation is finalized

• WYDEQ survey of drilling 

emissions in Jonah-Pinedale

– 13.5 tons NOx/well– 3.3 tons SO2/well

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Drill Rig Engines

Emissions Calculation

EFA = EFJ x ( DA / DJ) x ( TA / TJ ) 

where: 

EFA = The emission factor for another formation 

 EFJ = The Jonah-Pinedale emission factor  DA = The average depth of wells drilled in another area  Dj = The average depth of wells drilled in Jonah-Pinedale  TA = The duration of drilling in another area 

 Tj = The duration of drilling in Jonah-Pinedale

E = EF x W 

where:  E = The 2002 emission for a given formation  EF = The formation specific emission factor  W = The number of wells drilled in the formation in 2002.

1. Adjust emission factor based on the characteristicformation

2. Estimate emissions using formation-specific emissi

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Natural Gas Compressor Engin

Data Collection

• Compressor operators 

contacted

• Oil and gas commission data• Existing inventories

– Colorado 2002 point source 

inventory (2004)

– New Mexico Oil and Gas 

Association inventory (2003)

– BLM environmental impact 

statements

– 2002 East Texas inventory (2005)

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Natural Gas Compressor Engin

Emissions Calculation

• Emission factor: 2.3x10-5 tons NOx/M

derived from NMOGA inventory

• Activity data: Gas production obtained 

oil and gas commissions

 Emission Calculation 

E = P x EF 

Where: E = 2002 NOx emission P = 2002 gas production (MCF) EF = Emission factor, 2.3x10-5 tons NOx / MCF

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
CBM Pump Engines

Data Collection

• Wyoming Generator 

databases

• Field power supply• Pertinent oil and gas 

commission data

– Well depth– Water produced

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
CBM Pump Engines

1: Estimate Engine Activity

• First estimate used 

scaling of WY activity

• Improved estimate uses 

engineering calculations and water production

• Assumptions

– Pump operation– Well design

P

H

H z g

P z P L 2

2 

2

2

1 1

1

γ

ν

γ

+

+

+

−

=

+

+

g

V

D

L

H

f L 2

2

=

× 

H

P

=

HP ×

Q

×

γ / 550

1. Energy in System 

2. Calculate Frictional Loss

or

3. Calculate Pump Power

4

Modified Bernoulli

Darcy-Weisbach Ha

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
CBM Pump Engines

2: Estimate Engine Emissions

=

∑

∗

∗

+

∗

E

w

EF

A

w

H

A

A

w

H

I

(

0.1

*

)

Where:E = 2002 county NOx emission EF = Emission factor, see table below (g/hp-hr) A

w = Engine power for pumping at county well w (hp) 

HA = Hours of pumping (4,380 hr) 

HI = Hours of idling (4,380 hr)

Wyoming 6.1 g/hp-hr* WY DEQ

Colorado & New Mexico 12 g/hp-hr NONROAD 

States Engine EF Sourc

*Natural gas engines in Wyoming are controlled

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Minor NOx & VOC Wellhead Proc

Data Collection

• WYDEQ emission factors

– Glycol dehydrators– Completions, flaring & venting– Heaters– Tanks– Pneumatic devices

• State control requirements• Alternative local emission factors• Oil and gas commission production data

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Minor NOx & VOC Wellhead Proc

Emissions Calculations

• Divided production 

between oil wells and gas wells based on OGC data

• Estimated emissions at oil 

wells by combining production with WYDEQ oil well emission factors*

• Estimated emissions at 

gas wells by combining production with WYDEQ gas well emission factors*

 Calculation of Wellhead Emissions f

Gas Well E = SUMi(Pg x EFg,i) + SUMj(Pc x EFc

Where: E = The 2002 emission Pg = 2002 gas production 

EFg,i = Emission factor for gas process Pc = 2002 condensate production 

EFc,j = Emission factor for condensate 

EFw = Per well emission factor Oil Well E = SUMi(Po x EFg,i) + SUM(EF

w) 

Where: E = The 2002 emission Po = 2002 oil production 

EFo,i = Emission factor for oil process EFw = Per well emission factor

*If provided, alternate local factors were used

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Point vs. Area Reconciliation

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background

Created scaling factor based on NM inventory and gas production 

South Dakota PTE 100 TPY& Utah

Gathered additional data from states sources with a PTE between 25 and 

North Dakota PTE 100 TPY& OregonOther States PTE 25 TPY No reconciliation required.

Removed compressor, condensate tadehydrator emissions from area sour

2 TPY actual emissions

Colorado

No compressor engines include in Sinventory => no reconciliation requi

Nevada 5 TPYAlaska PTE 100 TPY Smaller equipment grouped in large 

Reconciliation

Inventory 

States Thresholds
2002 Oil and Gas Emissions

WRAP Total 36,550 215,662 103,792 374,715 93,371 46

Point 

Source 

Total T

Area 

Source 

Oil Wells Gas Wells Total

Condensate 

Tanks

WRAP Total 54,828 21,536 42,800 3,141 130,376 181

 

Compressor 

Engines

Drill 

Rigs Wellhead

CBM 

Pump 

Engines

Poin

Sour

Tota

Area 

Source 

Total

Area Point Total Area Point Total To

WRAP Total 130,376 181,191 311,566 14,479 181,191 195,670 115

 

WRAP Oil and Gas Inventory

Oil and Gas in Previous 

Inventory

Cha

Ga

VOC Emissions (tpy)

NOx Emissions (tpy)

Change in 2002 Oil and Gas NOx Emissions

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
• Grow county and tribal level emissions 

based on estimated growth in oil and gproduction

• Sources of data

– Local, Bureau of Land Management– Regional, Energy Information Administrat

• Adjust for post-2002 on-the-books con• Special cases

Future Year (2018) Inventory Proc

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Resource Management Area

( )

02

02

W

W

W

W

G

+

f

−

P

=

 where: 

G = the 2002 to 2018 groW02 = the wells (oil/gas/C

Wf = the wells (oil/gas/C

added by 2018 

W

P = the wells (oil/gas/C

plugged and abando

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Resulting Areas of Growth

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
2018 Oil and Gas Emissions

VOC Emissions (tpy)

NOx Emissions (tpy)

Change in NOx Emissions, 2002 to 2018

Change in VOC Emissions, 2002 to 2018

WRAP Total 166,009 27,082 84,932 1,348 279,370 126,536 

CBM Pump 

Engines

Area Source 

Total

Point Source 

Total 

Compressor 

Engines Drill Rigs Wellhead

WRAP Total 43,248 648,762 194,895 886,904 100,811 98

Area Source 

Total

Point Source 

Oil Wells Gas Wells Total T

Condensate 

Tanks

WRAP Total 203% 26% 98% -57% 114% -30% 

CBM Pump 

Engines

Area Source 

Total

Point Sourc

Total 

Compressor 

Engines Drill Rigs Wellhead

WRAP Total 18% 201% 88% 137% 8% 1

Point Source 

Total To

Area Source 

Oil Wells Gas Wells Total

Condensate 

Tanks

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Controls Included in WRAP Inve

Federal estandards

Drill rigs

control with flare or vapor All statesrecovery (50 – 90% effective)

Completion: Flaring & Venting

Glycol Dehydrators control with 90% efficiency Colorado*

Montana, Colorado*North Dakota, Wyoming

control with 98% efficiency using combustion, vapor recovery, etc...

Condensate Tanks

use line power Montana, Utah

Federal estandards

emission limits on gas Wyomingengines of 1-2 g/bhp-hr

Pump Engines

Federal estandards

Wyoming, Utah

Compressors emission limits of 1-2 g/bhp-hr

Process Control 2002 Post 

*Will apply only in nonattainment areas

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
• Controls under development

– Montana, proposed 25 tpy site cap– Utah, reporting and control requirements– Wyoming considering drill rig requirements

• EPA Natural Gas Star Program

– Industry developed strategies to control em

from many oil and gas processes

– http://www.epa.gov/gasstar/index.htm

• Northeast Texas compressor control demo

Additional Control Informatio

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Compressor Engine Control Op

System Design

Control System

Power Supp

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
Compressor Engine Control Op

Cost Effectiveness

• Annual emission reduction = 12.3 tons N• Annualized costs = $2,250• $2,250 / 12.3 tons NOx = $183 / ton NOx

96%

0.5

13.3

70024

97%

0.4

12.7

75558

NOx Control Efficiency 97% 96% 

0.5

13.0

74236

After (g NOx/hp-hr) 0.3 

Before (g NOx/hp-hr) 11.6 

Engine 70640 

Emissions Reductions Achieved

*Assumes 3% discount rate and five year project life

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
• Northwest New Mexico area source 

inventory

– Cover additional processes– Obtain improved activity data and emissio

factors

– Estimate SO2 emissions from additional so

• Upcoming four corners PSD increment 

analysis expected to establish historicainventories

Additional Projects

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background
• WRAP oil and gas inventory documentation: 

http://www.wrapair.org/forums/ssjf/documents/eictts/oilg

• WRAP emissions database: http://www.wrapedms.org• Contacts: jrussell@environcorp.com or 

apollack@environcorp.com

Additional Information

Oil and Gas 

Controls

2018 Inventory 

Methodology

2002 Inventory 

Methodology

Background