Petroleum and Natural Gas Systems Monitoring Checklist for Onshore Petroleum and Natural Gas Production Final Rule: Mandatory Reporting of Greenhouse Gases (40 CFR Part 98)


United States
Environmental Protection
Agency

Petroleum and Natural Gas Systems &EFA
Monitoring Checklist for Onshore Petroleum
and Natural Gas Production	

Final Rule: Mandatory Reporting of Greenhouse Gases (40 CFR Part 98)

What must be monitored?

If emissions are going to flares, need data elements under the source flare stacks.

Record these parameters on an annual basis, unless specified otherwise.

1.	Natural Gas Pneumatic Device Venting

~	Actual and estimated counts of high ~ Concentration of CO2
bleed devices

~	Actual and estimated counts of low ~ Concentration of CH4
bleed devices

~	Actual and estimated counts of	~ Have performed estimates consistent with
intermittent bleed devices instructions in 98.233 (a)(1)

2.	Natural Gas Driven Pneumatic Pump Venting

~	Count of natural gas driven	~ Concentration of CO2 in produced natural
pneumatic pumps gas

~	Concentration of CH4 in produced
natural gas

3.	Well Venting for Liquids Unloading

If Using Calculation Methodology 1:

For Methodology 1, record these parameters once

~	Count of wells vented to the atmosphere
for liquids unloading

~	Cumulative amount of time of venting
from all wells of same tubing diameter

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in two years.

~	Count of plunger lifts.

~	Average flow rate of measured well
venting for the recorded time of one

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and producing horizon/formation
combination during the year (hours)

~	Average casing diameter (inches)

~	Actual pressure (psia)

representative well venting to the
atmosphere under actual conditions for
each unique tubing diameter and
producing horizon/formation
combination during the year (cubic feet
per hour of venting)

~	Actual temperature (°F)

~	Cumulative number of unloadings
vented to the atmosphere

If Using Calculation Methodology 2:

~	Count of wells vented to the atmosphere
for liquids unloading

~	Number of vents per year

~	Well depth to first producing horizon (feet)

~	Time that the well was left open to the
atmosphere during unloading (hours)

~	Actual pressure (psia)

~	Cumulative number of unloadings vented
to the atmosphere

~	Count of plunger lifts.

~	Casing diameter (inches)

~	Shut-in pressure (psia)

~	Average sales flow rate of gas well
(cubic feet per hour)

~	Actual temperature (°F)

If Using Calculation Methodology 3:

~	Count of wells vented to the atmosphere
for liquids unloading

~	Number of vents per year

~	Tubing depth to plunger bumper (feet)

~	Time that well was left open to the
atmosphere during unloading (hours)

~	Actual pressure (psia)

~	Cumulative number of unloadings
vented to the atmosphere

~	Count of plunger lifts

~	Tubing diameter (inches)

~	Sales-line pressure (psia)

~	Average sales flow rate of the measured
well venting (cubic feet per hour)

~	Actual temperature (°F)

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4. Gas Well Venting During Completions without Hydraulic Fracturing

~	Average daily gas production rate of all
wells completed during the reporting
year (cubic feet/hour)

~	Cumulative amount of time of all well
completions venting (hours)

~	Actual pressure (psia)

~	Total number of days of gas venting to
the atmosphere during backflow for
completion

~	Total count of completions in calendar
year

~	Actual temperature (°F)

~	Vent and flared emissions separately
(cubic feet)

5. Gas Well Venting During Workovers without Hydraulic Fracturing

~	Actual pressure (psia)

~	Total count of workovers in calendar
year

~	Total number of days of gas venting to
the atmosphere during backflow for
workover

~	Actual temperature (°F)

~	Vent and flared emissions separately
(cubic feet)

6. Gas Well Venting During Well Completions with Hydraulic Fracturing

For Methodologies 1 & 2, record these parameters once in two years.

~	Cumulative amount of time of all well ~
completion venting in a field during

the year (hours)

~	Number of completions employing ~
reduced emissions completions and
engineering estimate based on best
available data of the amount of gas
recovered to sales

Average flow rate of the measured well
completion venting under actual conditions
converted to standard conditions (cubic
feet per hour)

Total count of completions in Calendar
Year

~	Actual pressure (psia)

~	Vent and flared emissions separately
at standard conditions (cubic feet)

~	Actual temperature (°F)

~	Volume of CO2 or N2 injected gas at
standard conditions that was injected into
the reservoir during an energized fracture
job (cubic feet)

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~	Volume of natural gas at standard ~ Total number of days of gas venting to the
conditions that was recovered into a	atmosphere during backflow for completion
sales pipeline (cubic feet)

If Using Calculation Methodology 1:

~	Average flow rate of venting to
atmosphere or routing to flare by
recording flow meter (cubic feet per
hour)

If Using Calculation Methodology 2:

~	Average flow rate under	~ Actual pressure (psia)
subsonic/sonic flow conditions (cubic

feet per hour)

~	Cross sectional area of orifice (m2) ~ Upstream temperature (K)

~	Upstream pressure (psia)	~ Downstream pressure (psia)

7. Gas Well Venting During Well Workovers with Hydraulic Fracturing

For Methodologies 1 & 2, record these parameters once in two years.

~	Cumulative amount of time of all well ~
workover venting in a field during the
year (hours)

~	Number of workovers employing	~
reduced emissions completions and
engineering estimate based on best
available data of the amount of gas
recovered to sales

Average flow rate of the measured well
workover venting under actual conditions
converted to standard conditions (cubic feet
per hour)

Total count of workovers in calendar year

~	Actual pressure (psia)	~

~	Vent and flared emissions separately ~
at standard conditions (cubic feet)

~	Volume of natural gas at standard ~
conditions that was recovered into a

sales pipeline (cubic feet)

Actual temperature (°F)

Volume of CO2 or N2 injected gas at
standard conditions that was injected into
the reservoir during an energized fracture
job (cubic feet)

Total number of days of gas venting to the
atmosphere during backflow for workovers

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If Using Calculation Methodology 1:

~	Average flow rate of venting to
atmosphere or routing to flare by
recording flow meter (cubic feet per
hour)

If Using Calculation Methodology 2:

~	Average flow rate under
subsonic/sonic flow conditions (cubic
feet per hour)

~	Cross sectional area of orifice (m2)

~	Upstream pressure (psia)

~	Actual pressure (psia)

~	Upstream temperature (K)

~	Downstream pressure (psia)

8. Flare Stack Emissions

~ Continuous flow monitor on flare
(Y/N)

~ Continuous gas analyzer on the gas to the
flare (Y/N)

~	Volume of gas sent to flare annually ~ Percent of gas sent to un-lit flare
(cubic feet)

~	Flare combustion efficiency (98% if ~ Mole fraction of CO2 in gas to the flare
manufacturer data not available)

~	Mole fraction of gas hydrocarbon
constituents (such as methane, ethane,
propane, butane, and pentanes-plus)

~	Actual Process Pressure (psia)

9. Storage Tanks Emissions

~ Actual Process Temperature (°F)

Storage tank receiving separator oil
have a vapor recovery system (Y/N)

Total time well head gas-liquid
separator liquid dump valve is not
closing properly in the calendar year
(hours)

~	Count of wellhead separators that dump
valve factor is applied to, if well head gas-
liquid separator liquid dump valve is not
functioning properly during the calendar
year

~	Percent of gas sent to un-lit flare

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If Using Calculation Methodology 1:

~	Range of concentrations of flash gas,
for CH4 and CO2

~	Average separator temperature (°F)

~	Average separator pressure (psig)

~	Average sales oil or stabilized oil API
gravity (°)

~	Number of wellhead separators
sending oil to atmospheric tanks

~	Best estimate of count of stock tanks
not at well pads receiving oil

~	Count of tanks with emissions control
measures, either vapor recovery
system or flaring, for tanks at well
pads

~	Sales oil or stabilized oil production rate
(barrels per day)

~	Ambient air temperature (°F)

~	Ambient air pressure (psig)

~	Separator oil composition and Reid vapor
pressure

~	Count of hydrocarbon tanks at well pads

~	Total volume of oil from all wellhead
separators sent to tank(s) annually (barrels)

~	Best estimate of count of stock tanks
assumed to have emissions control
measures not at well pads, receiving oil

If Using Calculation Methodology 2:

~	Number of wellhead separators
sending oil to atmospheric tanks

~	Separator pressure (psig)

~	Count of hydrocarbon tanks at well
pads

~	Best estimate of count of stock tanks
not at well pads receiving oil

~	Best estimate of count of stock tanks
assumed to have emissions control
measures not at well pads, receiving
oil

~	Separator oil composition at separator
pressure and temperature (for the
assumption that all of the CH4 and

~	Separator temperature (°F)

~	Sales oil or stabilized oil API gravity (°)

~	Total volume of oil from all wellhead
separators sent to tank(s) annually (barrels)

~	Count of tanks with emissions control
measures, either vapor recovery system or
flaring, for tanks at well pads

~	Range of concentrations of flash gas, for
CH4 and C02

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C02 in solution in the separator oil is
emitted)

If Using Calculation Methodology 3:

~	Total volume of sales oil from all
wells annually (barrels)

~	Total number of wells sending oil to
separators off the well pads

~ Count of hydrocarbon tanks on
wellpads

~	Produced oil and gas compositions
(for the assumption that all of the
CH4 and C02 in both oil and gas are
emitted from the tank)

If Using Calculation Methodology 4:

~	Total volume of sales oil from all
wells annually (barrels)

~	Total number of wells sending oil to
separators off the well pads

~	Count of hydrocarbon tanks on
wellpads

~	Well production oil and gas
compositions (for the assumption
that all of the CH4 and C02 in the
oil are emitted from the tank)

If Using Calculation Methodology 5:

~	Number of wellhead separators

~	Total volume of oil production
annually (barrels)

~	Total number of wells sending oil directly to
tanks

~	Sales oil API gravity range for wells sending
oil directly to tanks and for wells sending
oils to separators off the well pads (°)

~	Count of hydrocarbon tanks, both on and off
well pads assumed to have emissions control
measures: either vapor recovery system or
flaring of tank vapors

Total number of wells sending oil directly to
tanks

Sales oil API gravity range for wells sending
oil directly to tanks and for wells sending
oils to separators off the well pads (°)

Count of hydrocarbon tanks, both on and off
well pads assumed to have emissions control
measures: either vapor recovery system or
flaring of tank vapors

Number of wells without wellhead
separators

Best estimate of fraction of production sent
to tanks with assumed control measures:
either vapor recovery system or flaring of
tank vapors

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~	Count of hydrocarbon tanks on well
pads

10.	Reciprocating Compressor Rod Packing Venting

~	Count of compressors

11.	Well Testing Venting and Flaring

~	Average gas -to-oil ratio (GOR) of	~
the hydrocarbon production from
each well tested (cubic feet of gas
per barrel of oil)

~	Duration of the well test (number of	~
days during the year)

~	Actual Process Pressure (psia)	~

~	Venting gas emissions

12. Associated Gas Venting and Flaring

~	GOR of the hydrocarbon
production from each well whose
associated natural gas is vented or
flared (cubic feet of gas per barrel
of oil)

~	Number of wells venting or
flaring associated natural gas in
calendar year

~	Actual Process Pressure (psia)

Flow rate for the well being tested
(barrels of oil per day)

Number of wells tested per basin in
calendar year

Actual Process Temperature (°F)

~ Volume of oil produced in the calendar
year during which associated gas was
vented or flared (barrels)

~ Actual Process Temperature (°F)

~ Flaring gas emissions

13. Dehydrator Vents

For glycol dehydrator with a throughput greater than or equal to 0.4 million cubic feet per
day:

~ Feed natural gas flow rate	~ Feed natural gas water content

(million standard cubic feet per

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day)

~ Outlet natural gas water content

~ Absorbent circulation rate

~	Absorbent circulation pump type (natural
gas pneumatic/air pneumatic/ electric)

~	Absorbent type (TEG/DEG/EG)

~ Use of stripping natural gas (Y/N) ~ Use of flash tank separator (Y/N)

~ Total time of operation (hours)

~ Wet natural gas temperature (°F)

~ Wet natural gas composition

~ Wet natural gas pressure (psig)

~	Concentration of CH4 in natural

gas

~	Vent gas controls used

~ Concentration of CO2 in natural gas

~ Vent and flared emissions separately
(cubic feet)

For glycol dehydrator with a throughput less than to 0.4 million standard cubic feet per
year:

~ Count of glycol dehydrators

~ Vent gas controls used

~ Vent emissions (cubic feet)

For absorbent desiccant dehydrators:

~ Count of desiccant dehydrators

~ Vent gas controls used

~ Time between refilling (days)

~ Pressure of the gas (psia)

~	Height of the dehydrator vessel

(ft)

~	Percent of packed vessel volume
that is gas

~ Inside diameter of the vessel (ft)

14. EOR Injection Pump Slowdown

~ Total volume of blowdown
equipment chambers between
isolation valves (cubic feet)

~ Number of blowdowns per calendar year

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~	Density of critical phase EOR
injection gas (kg/ft3)

~	Pump capacity (barrels per day)

15. Acid Gas Removal (AGR) Vents

If using Calculation Methodology 1:

~	Total throughput into the AGR
unit and/or total throughput out of
the AGR unit (cubic feet per year)

~	Emissions recovered and
transferred outside the facility

If using Calculation Methodology 2:

~	Total throughput out of the AGR
unit at actual conditions (cubic
feet)

~	Emissions recovered and
transferred outside the facility

If using Calculation Methodology 3:

~	Total throughput through the
AGR unit at actual conditions
(cubic feet)

~

~

If using Calculation Methodology 4:

~	Natural gas feed temperature

~	Natural gas flow rate

~	Unit operating hours, excluding
downtime for maintenance or

~ Mass fraction of GHG in critical phase
injection gas

~ Volume fraction of C02 content in the
vent from the AGR unit

~ Volume fraction of CO2 content in vent
gas from the AGR unit

~ Volume fraction of CO2 content in natural
gas into the AGR unit

~	Natural gas feed pressure

~	Acid gas content of feed natural gas

~	Acid gas content of outlet natural gas

Volume fraction of CO2 content	~ Actual pressure (psia)

in natural gas out of the AGR unit

Actual Temperature (°F )	~ Emissions recovered and transferred

outside the facility

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standby

~	Solvent pressure	~ Exit temperature of natural gas

~	Solvent circulation rate	~ Solvent temperature

~	Solvent weight

16.	EOR Hydrocarbon Liquids Dissolved C02

~	Volume of crude oil produced	~ Amount of CO2 retained in hydrocarbon
annually (barrels) liquids at STP conditions (metric tons per

barrel)

17.	Centrifugal Compressor Wet Seal Degassing Venting

~	Count of compressors

18.	Valves Equipment Leaks Using Population Count and Factors

~	Concentration of CH4 in produced ~ Concentration of CO2 in produced natural
natural gas	gas

~	Report CO2 emissions from all ~ Report CH4 emissions from all valves
valves (standard cubic feet)	(standard cubic feet)

~	Operating time of component	~ Total number of components
(hours)

19.	Connectors Equipment Leaks Using Population Count and Factors

~	Concentration of CH4 in produced	~ Concentration of CO2 in produced natural
natural gas gas

~	Report CO2 emissions from all	~ Report CH4 emissions from all connectors
connectors (standard cubic feet) (standard cubic feet)

~	Operating time of component	~ Total number of components
(hours)

20.	Open Ended Lines Equipment Leaks	Using Population Count and Factors

~	Concentration of CH4 in produced	~ Concentration of C02 in produced natural
natural gas gas

~	Report C02 emissions from all	~ Report CH4 emissions from all open ended
open ended lines (standard cubic lines (standard cubic feet)

feet)

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~ Total number of components
21. Pressure Relief Valves Equipment Leaks Using Population Count and Factors

~ Operating time of component
(hours)

~	Concentration of CH4 in produced
natural gas

~	Report CO2 emissions from all
pressure relief valves (standard
cubic feet)

~	Operating time of component
(hours)

~	Concentration of CO2 in produced natural
gas

~	Report CH4 emissions from all pressure
relief valves (standard cubic feet)

~	Total number of components

22. Pumps Equipment Leaks Using Population Count and Factors

~	Concentration of CH4 in produced ~
natural gas

~	Report CO2 emissions from all ~
pumps (standard cubic feet)

~	Operating time of component	~
(hours)

Concentration of CO2 in produced natural
gas

Report CH4 emissions from all pumps

(standard cubic feet)

Total number of components

23. Flanges Equipment Leaks Using Population Count and Factors

~	Concentration of CH4 in produced ~
natural gas

~	Report CO2 emissions from all ~
flanges (standard cubic feet)

~	Operating time of component	~
(hours)

Concentration of CO2 in produced natural
gas

Report CH4 emissions from all flanges

(standard cubic feet)

Total number of components

24. Other Equipment Leaks Using Population Count and Factors

~	Concentration of CH4 in produced ~
natural gas

~	Report CO2 emissions from all ~
instruments (standard cubic feet)

~	Operating time of component	~
(hours)

Concentration of CO2 in produced natural
gas

Report CH4 emissions from all instruments

(standard cubic feet)

Total number of components

25. Stationary or Portable Fuel Combustion Emissions

~ Cumulative number of external ~ Cumulative number of external fuel

fuel combustion units with a rated	combustion units with a rated heat capacity

heat capacity equal to or less than	larger than 5 MMBtu/hr, by type of unit

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5 MMBtu/hr, by type of unit

~	Cumulative emissions from	~
external fuel combustion units

with a rated heat capacity larger
than 5 MMBtu/hr, by type of unit
(cubic feet)

~	Cumulative number of all internal ~
combustion units, by type of units

~	Cumulative mass/volume of fuel ~
combusted in internal combustion
units, by fuel type

Cumulative volume of fuel combusted in
external fuel combustion units with a rated
heat capacity larger than 5 MMBtu/hr, by
fuel type (cubic feet)

Cumulative emissions from internal
combustion units, by type of unit (cubic
feet)

Concentration of gas hydrocarbon
constituents (such as methane, ethane,
propane, butane and pentanes plus)

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