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40 CFR 98 Subpart W – Petroleum and Natural Gas Systems

Onshore petroleum and natural gas production sector

A. GHG emissions associated with the onshore petroleum and natural gas production sector must be reported for the

following source types –

a) Venting of natural gas pneumatic devices and pumps;

b) Gas well venting for unloading of liquids;

c) Gas well venting during completions and workovers with hydraulic fracturing;

d) Gas well venting during completions and workovers without hydraulic fracturing;

e) Atmospheric condensate/oil storage tanks;

f) Venting and flaring associated with well testing;

g) Venting and flaring associated with production;

h) Flare stacks;

i) Equipment leaks;

j) Dehy vents;

k) Combustion sources

B. Calculating GHG Emissions

a) Venting of natural gas pneumatic devices and pumps

1) The total number of each type of pneumatic device – continuous low and high-bleed, and intermittent-

bleed - must be physically counted at every site over a period of three calendar years. For the first

calendar year, a percentage of each type of pneumatic device must be counted and an engineering

estimate utilized to estimate the total number of pneumatic devices, as opposed to physically counting

every device. For the second calendar year, the same methodology as the first calendar year can be

utilized. By the end of the third calendar year, each type of pneumatic device must have been physically

counted at every site.

2) For all calendar years after the third calendar year, the total count must be updated and adjusted

accordingly to reflect changes/modifications in equipment.

3) Calculation Methodology - Emissions for each type of pneumatic device are to be calculated using

published factors listed in Tables W-1A, as applicable, depending upon the operations for either Eastern

or Western US as defined in Table W-1D, and the appropriate pneumatic apparatus count.

b) Gas well venting associated with the unloading of liquids

1) Calculation Methodology #1 – The volumetric flow rate of a representative well for each unique tubing

size and producing formation combination is to be measured during atmospheric venting operations and

recorded. The total time for every well vented to the atmosphere to unload liquids is to be recorded.

GHG emissions are to be calculated using the time open to flow to the atmosphere and the established

volumetric flow rate for each unique tubing size and producing formation combination.

2) Calculation Methodology #2 – GHG emissions are to be calculated for each individual well left open to

the atmosphere to unload liquids by using the average sales line flow rate for that individual well and the

cumulative time which the individual well is vented to the atmosphere.

3) Calculation Methodology #3 – Same as Calculation Methodology #2 but specifically for wells with a

plunger lift assembly.

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c) Gas well venting during completions and workovers with hydraulic fracturing

1) Calculation Methodology #1 – The volumetric flow rate for one representative well completion and one

representative workover having each unique tubing size and producing formation combination is to be

measured and recorded. A new flow rate for one representative well completion and one representative

workover is to be measured and recorded every other year for each unique tubing size and producing

formation combination. The total time each well completion and workover is vented to the atmosphere is

to be recorded. GHG emissions are to be calculated based on total time open to flow to the atmosphere

and the established volumetric flow rate for each unique tubing size and producing formation

combination. GHG emissions are to be adjusted as appropriate if the stream is routed to a control device.

2) Calculation Methodology #2 - The flowing tubing pressure and temperature upstream and downstream of

the choke for one representative well completion and one representative workover having each unique

tubing size and producing formation combination is to be measured and recorded. The flow rate is to be

calculated using the collected data and the equation provided in the regulation. A new flow rate is to be

calculated every two years for a representative well completion and a representative workover for each

unique tubing size and producing formation combination. The total time each well completion and

workover is vented to the atmosphere is to be recorded. GHG emissions are to be calculated based on the

total time open to flow to the atmosphere for each unique tubing size and producing formation

combination, utilizing the published equation in the regulation. GHG emissions are to be adjusted as

appropriate if the stream is routed to a control device.

d) Gas well venting during completions and workovers without hydraulic fracturing

1) Calculation Methodology – GHG emissions are to be calculated utilizing the post-work average daily

flow rate for each individual well completion and workover and the total amount of time which the

specific well completion and workover is vented to the atmosphere. GHG emissions are to be adjusted as

appropriate if the stream is routed to a control device. For each workover, GHG emissions are to be

adjusted upward by assuming that an additional 2.454 MCF of natural gas is released to the atmosphere

during the workover.

e) Atmospheric condensate/oil storage tanks

1) Calculation Methodology #1 – For tanks having separators with an average daily condensate/oil

throughput greater than or equal to 10 bpd, GHG emissions are to be calculated using the site specific

operating conditions of the separator immediately prior to transfer to the tank. Flash emissions are to be

calculated. If pressurized condensate/oil compositional data, including RVP, are not available, default

values from the software program are to be utilized based on separator operating pressure, first, and API

gravity, second. GHG emissions are to be adjusted as appropriate if the stream is routed to a control

device.

2) Calculation Methodology #2 - For tanks having separators with an average daily condensate/oil

throughput greater than or equal to 10 bpd, GHG emissions can be estimated by assuming that all GHGs

in the condensate/oil stream at separator operating temperature and pressure are emitted. GHG emissions

are to be adjusted as appropriate if the stream is routed to a control device.

3) Calculation Methodology #3 – For tanks without a separator and having an average daily condensate/oil

throughput greater than or equal to 10 bpd, GHG emissions can be calculated using the latest available

compositional data and assuming that all GHGs in both the condensate/oil and gas streams are emitted

from the storage tank. If compositional data is not available, default oil and gas compositions from

software programs, such as API 4697 E&P Tanks, which most closely match the GOR and API gravity

can be utilized. It is to be assumed that all GHGs in both the condensate/oil and gas streams are emitted

from the storage tank. GHG emissions are to be adjusted as appropriate if the stream is routed to a

control device.

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4) Calculation Methodology #4 - For tanks having an offsite separator with an average daily condensate/oil

throughput greater than or equal to 10 bpd, GHG emissions can be calculated utilizing the latest available

compositional data and assuming that all GHGs in the condensate/oil stream are emitted from the storage

tank. If compositional data is not available, default oil and gas compositions from software programs,

such as API 4697 E&P Tanks, which most closely match the API gravity and operating pressure of the

offsite separator can be utilized. GHG emissions are to be adjusted as appropriate if the stream is routed

to a control device.

5) Calculation Methodology #5 – For wells with an average daily condensate/oil throughput of less than 10

bpd and either do or do not flow through a separator, GHG emissions can be calculated utilizing the

equation noted in the regulation and the given constants. GHG emissions are to be adjusted as

appropriate if the stream is routed to a control device.

6) If there are instances in which the dump valve on a separator is noted as not fully closing and thus

allowing the routing of a portion of the gas stream to the storage tanks, GHG emissions as estimated by

Calculation Methodologies #1, 2 and 5 are to be adjusted upward using the equation noted in the

regulation and the given correction factors. As such, separator dump valves should be inspected on a

frequent basis, and records denoting both proper operation and/or deficiencies maintained. The regulation

requires that the GHG emissions be calculated assuming that the dump valve was open the entire time

between an inspection record denoting improper operation of the same and a subsequent maintenance

record denoting correction of the issue. GHG emissions are to be adjusted as appropriate if the stream is

routed to a control device.

f) Venting and flaring associated with well testing (NOTE: This is primarily applicable to oil wells that are

vented to the atmosphere during testing because of the inability of the system to measure multi-phase flow.)

1) Calculation Methodology - Utilizing the GOR of the specific oil well being vented to atmosphere during

testing, GHG emissions can be calculated based on the average daily condensate/oil production rate and

the total number of days which the associated gas was vented to atmosphere during testing. GHG

emissions are to be adjusted as appropriate if the stream is routed to a control device.

g) Venting and flaring associated with production (NOTE: This is primarily applicable to areas of development

like the Williston Basin that did not or currently do not have the infrastructure in place for multi-phase flow.)

1) Calculation Methodology – Utilizing the GOR of the specific oil well being vented to atmosphere, GHG

emissions can be calculated based on the volume of condensate/oil produced during the time which the

associated gas was vented to atmosphere. GHG emissions are to be adjusted as appropriate if the stream is

routed to a control device.

h) Flare stack

1) Calculation Methodology – If equipped, data from a continuous flow measurement device must be

utilized in calculating GHG emissions. If not equipped with the same, engineering calculations based on

process data, company records and best available data can be utilized to estimate flow rates. If equipped,

data from a continuous gas composition analyzer must be utilized in calculating GHG emissions. If not

equipped with the same, the mole fraction of the specific GHG in the produced natural gas can be utilized.

If the destruction efficiency of the flare is unknown, the regulation allows for the assuming of 98%.

Utilize the equations in the regulation for calculating both combusted and un-combusted GHG emissions.

i) Equipment leaks

1) Applicable to natural gas streams with methane plus CO2 content greater than 10% by weight.

2) Calculation Methodology #1 – Count all major equipment listed in Tables W-1B and W-1C of the

regulation. Multiply the major equipment count by the average component count, denoted in Tables W-

1B and W-1C of the regulation. GHG emissions are to be calculated using published emission factors

listed in Table W-1A, as applicable, for either Eastern or Western US as defined in Table W-1D, and the

product of the major equipment count and the average component count.

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3) Calculation Methodology #2 – Physically count each component denoted in Table W-1A of the regulation

for each individual facility. GHG emissions are to be calculated using published factors listed in Table

W-1A, as applicable, for either Eastern or Western US as defined in Table W-1D, and the actual physical

component count.

j) Dehy vents

1) Calculation Methodology #1 – For dehys with a throughput greater than or equal to 400 MCFPD, GHG

emissions can be calculated using a software program which utilizes the Peng-Robinson equation of state,

including GRI GLYCalc and HYSYS. GHG emissions are to be adjusted as appropriate if the stream is

routed to a control device.

2) Calculation Methodology #2 – For dehys with a throughput less than 400 MCFPD, GHG emissions can

be estimated using the equation and emission factors provided in the regulation. GHG emissions are to be

adjusted as appropriate if the stream is routed to a control device.

k) Combustion sources

1) Applicable to combustion sources with a rated heat capacity greater than 5 MMBTU/hr.

2) Calculation Methodology #1 – For the combustion of fuel types listed in Table C-1 of 40 CFR 98 Subpart

C, GHG emissions can be calculated as per the Tier 1 methodology of 40 CFR 98 Subpart C.

3) Calculation Methodology #2 – For the combustion of pipeline quality natural gas having a minimum

high heating value of 950 BTU/scf, GHG emissions can be calculated using the natural gas emission

factor and high heat values listed in Tables C-1 and C-2 of 40 CFR 98 Subpart C.

4) Calculation Methodology #3 – For the combustion of field gas or process vent gas or any blend of field

gas or process vent gas and the fuel types listed in Table C-1 of 40 CFR 98 Subpart C, GHG emissions

are to be calculated using data from a permanent continuous flow meter and/or gas composition analyzer,

if present. If a permanent continuous flow meter is not utilized, company records or engineering

calculations using best available data can be used to estimate the volumetric flow rate. If a continuous

gas composition analyzer is not utilized, the most recent gas compositions for each stream being

combusted must be utilized.

5) Utilize the equations in the regulation for calculating both combusted and un-combusted GHG emissions.

C. Data Monitoring and QA/AC Requirements

a) Best available monitoring methods for well related emissions and specified activities

1) Best available monitoring methods, including a) supplier data; b) engineering calculations; c) other

company records; or, d) monitoring methods currently used by the facility but not meeting the

specifications of the regulation, may be utilized during the period of January 1, 2011 through June 30

2011 for -

i) gas well venting during completions/workovers with hydraulic fracturing;

ii) gas well venting during testing and flaring;

iii) dehy vents;

iv) gas well venting associated with the unloading of liquids;

v) gas well venting during completions/workovers without hydraulic fracturing;

vi) atmospheric condensate/oil storage tanks;

vii) venting and flaring associated with production;

viii) flare stack emissions;

ix) combustion emissions

2) Requests for the extension of the use of the best available monitoring methods through December 31,

2011 must be filed by April 30, 2011.

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D. Data reporting requirements

a) Natural gas pneumatic devices and pumps

1) Actual and estimated count of natural gas pneumatic devices by bleed type

2) Count of natural gas pneumatic pumps

3) GHG emissions, collectively, for all pneumatic devices, regardless of bleed type

4) GHG emissions, collectively, for all pneumatic pumps

b) Dehys with a throughput greater than or equal to 400 MCFPD

1) Natural gas throughput rate in MMSCFPD for each dehy

2) Glycol circulation pump type for each dehy

3) Whether stripping gas is used for each dehy

4) Whether a flash tank is used for each dehy

5) Type of absorbent for each dehy

6) Total operating time of each dehy in hours

7) Temperature and pressure of inlet gas stream for each dehy

8) Concentration of methane and CO2 in inlet gas stream for each dehy

9) Type of controls employed, if applicable, for each dehy

10) GHG emissions vented to atmosphere for each dehy

11) GHG emissions vented to controls for each dehy

c) Dehys with a throughput less than 400 MCFPD

1) Count of dehys with a throughput less than 400 MCFPD

2) Whether controls were used

3) GHG emissions, collectively, for all dehys having a throughput less than 400 MCFPD

d) Gas well venting associated with the unloading of liquids

1) Count of wells vented to atmosphere for unloading liquids

2) Count of wells on plunger lift

3) Total number of unloadings vented to atmosphere

4) Average flow rate of the measured well venting in ft3/hr

5) Average casing diameter in inches

6) GHG emissions, collectively

e) Gas well completions and workovers with hydraulic fracturing

1) Total count of completions and workovers, separately, in the calendar year

2) Average flow rate of the measured well venting for both completions and workovers in ft3/hr

3) Total number of days of venting to atmosphere during flow back for both completions and workovers,

separately

4) Number of completions and workovers employing reduced emission completions and an estimate of the

amount of gas recovered to sales

5) GHG emissions vented to atmosphere, collectively

6) GHG emissions vented to controls, collectively

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f) Gas well completions and workovers without hydraulic fracturing

1) Total count of completions and workovers, separately, in the calendar year

2) Total number of days of venting to atmosphere during flow back for both completions and workovers,

separately

3) GHG emissions vented to atmosphere, collectively

4) GHG emissions vented to controls, collectively

g) Atmospheric condensate/oil tanks with throughput greater than or equal to 10 bpd using Calculation

Methodologies #1 and 2

1) Number of separators sending condensate/oil to tanks on a field basis

2) Average separator temperature and pressure on a field basis

3) Average API gravity of stabilized sales condensate/oil on a field basis

4) Count of tanks at well pads on a field basis

5) Estimated count of tanks not at well pads on a field basis

6) Total volume of condensate/oil sent to tanks in bbl/yr on a field basis

7) Count of tanks with controls at well pads on a field basis

8) Estimated count of tanks with controls not at well pads on a field basis

9) Range of concentration methane and CO2 in flash gas on a field basis

10) GHG emissions, separately, for Calculation Methodologies #1 and 2 on a field basis

h) Atmospheric condensate/oil tanks with throughput greater than or equal to 10 bpd using Calculation

Methodologies #3 and 4

1) Total volume of sales oil in bbl/yr on a field basis

2) Total number of wells on a field basis sending condensate/oil directly to tanks

3) Total number of wells on a field basis sending condensate/oil to separator off well pads

4) Range of API gravity of sales condensate/oil for both wells sending condensate/oil directly to tanks and

wells sending condensate/oil to separators off well pads on a field basis

5) Count of tanks on well pads on a field basis

6) Count of tanks both on and off well pads on a field basis having controls

7) GHG emissions, collectively, for Calculation Methodologies #3 and 4 on a field basis

i) Atmospheric condensate/oil tanks with throughput less than 10 bpd using Calculation Methodology #5

1) Number of wellhead separators

2) Number of wells without separators

3) Total volume of condensate/oil throughput

4) Best estimate of percent of throughput sent to tanks with controls

5) Count of tanks on well pads

6) GHG emissions, collectively

j) Separator dump valve functions improperly

1) Count of separators that dump valve factor is applied

k) Venting and flaring associated with well testing

1) Number of wells tested per basin in calendar year

2) Average GOR of wells tested for each basin

3) Average number of days well testing is performed for each basin

4) GHG emissions, collectively, for each basin

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l) Venting and flaring associated with production

1) Number of wells venting or flaring per basin in calendar year

2) Average GOR for wells venting or flaring for each basin

3) GHG emissions, collectively, for each basin

m) Flare stacks

1) Presence of a continuous flow meter and composition analyzer for each flare

2) Volume of gas sent to each flare in ft3/yr using best available data

3) Estimated percent of gas sent to each flare when the pilot is not lit

4) Assumed combustion efficiency

5) GHG emissions, combusted and not combusted, for each flare

n) Combustion sources

1) Number of external fuel combustion units equal to or less than 5 MMBTU/hr, by unit type

2) Number of external fuel combustion units greater than 5 MMBTU/hr, by unit type

3) GHG emissions, collectively, for external fuel combustion units greater than 5 MMBTU/hr, by unit type

4) Total volume of fuel combusted by external fuel combustion units greater than 5 MMBTU/hr, by fuel

type

5) Number of internal combustion units, by unit type

6) GHG emissions, collectively, for internal combustion units, by unit type

7) Total volume of fuel combusted by internal combustion units, by fuel type

o) Annual throughput is to be reported on a company-wide basis for all onshore petroleum and natural gas

production for the calendar year

E. Recordkeeping requirements

a) The following data must be retained for five years-

1) Dates on which measurements were conducted

2) Results of all emissions detected and measurements

3) Calibration reports for detection and measurement instruments

4) Inputs and outputs of calculations or computer model runs for estimating emissions