The operator of a facility must calculate and report
annual GHG emissions as prescribed in this section. The facility operator who
is a local distribution company reporting under section
95122 of this article must comply
with section
95153 for reporting emissions from
the applicable source types in section
95152(i) of this
article.
(a)
Metered Natural
Gas Pneumatic Device and Pneumatic Pump Venting. The operator of a
facility who is subject to the requirements of sections
95153(a) and (b)
must calculate emissions from a natural gas powered continuous high bleed
control device and pneumatic pump venting using the method specified in
paragraph (a)(1) below when the natural gas flow to the device is metered. By
January 1, 2015, natural gas consumption must be metered for all of the
operator's pneumatic continuous high bleed devices and pneumatic pumps. The
operator may choose to also meter flow to any or all low bleed and intermittent
bleed natural gas powered devices. By January 1, 2019, all continuous bleed
pneumatic devices must meet the accuracy requirements of section
95103(k) by
installation of metering or by measuring, at least annually, the volume of
natural gas emitted in cubic feet per hour using a temporary meter, or
calibrated bag, or high volume sampler according to the methods set forth in
sections
95154(b), (c), and
(d) respectively. The operator must calculate
the annual natural gas volumetric emissions at standard conditions using
calculations in paragraph (r) of this section and calculate both
CH
4 and CO
2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations in
paragraphs (s) and (t) of this section. For unmetered devices the operator must
use the method specified in section
95153(b). Vented
emissions from natural gas driven pneumatic pumps covered in paragraph (d) of
this section do not have to be reported under paragraph (a) of this section.
(1) The operator must calculate vented
emissions for all metered natural gas powered pneumatic devices and pumps using
the following equation:
Click
here to view image
Eq.1)
Where:
Em = Annual natural gas
emissions at standard conditions, in cubic feet, for all metered natural gas
powered pneumatic devices.
n = Total number of meters.
Bn = Natural gas consumption for
meter n.
(2) For both
metered and unmetered natural gas powered devices, CH4
and CO2 volumetric and mass emissions must be calculated
from volumetric natural gas emissions using methods in paragraphs (s) and (t)
of this section.
(b)
Non-metered Natural Gas Pneumatic Device Venting. Through
calendar year 2018, the operator must calculate CH
4 and
CO
2 emissions from all un-metered natural gas powered
pneumatic intermittent bleed and continuous low and high bleed devices using
the following method:
Click
here to view image
Eq.
2)
Where:
Enm,i,x = Annual natural gas
emissions at standard conditions for all unmetered natural gas powered devices
and pumps (in scf).
i = Total number of unmetered component types.
x = Total number of component type i.
EFi = Population emission factor
for natural gas pneumatic device type i (scf/hour/component) listed in Tables
1A, 3, and 4 of Appendix A for onshore petroleum and natural gas production,
onshore natural gas transmissions compression, and underground natural gas
facilities, respectively.
Ti,x = Total number of hours
type i component x was in service. Default is 8760 hours; or 8784 for a leap
year.
(1) GHG
(CO2 and CH4) volumetric and mass
emissions must be calculated from volumetric natural gas emissions using
methods in paragraphs (s) and (t) of this section.
(2) Beginning January 1, 2019, the operator
must continue to use Equation 2 of this section to quantify emissions from all
intermittent bleed devices.
(c)
Acid gas removal (AGR)
vents. For AGR vents (including processes such as amine, membrane,
molecular sieve or other absorbents and adsorbents), the operator must
calculate emissions for CO
2 only (not
CH
4) vented directly to the atmosphere or emitted
through a flare, engine (e.g. permeate from a membrane or de-adsorbed gas from
a pressure swing adsorber used as fuel supplement), or sulfur recovery plant
using the applicable calculation methodologies described in paragraphs
(c)(1)-(c)(10) below.
(1)
Calculation
Methodology 1. If the operator operates and maintains a CEMS that has
both a CO
2 concentration monitor and volumetric flow
rate meter, they must calculate CO
2 emissions under this
subarticle by following the Tier 4 Calculation Methodology and all associated
calculation, quality assurance, reporting, and recordkeeping requirements for
Tier 4 in section
95115 (stationary fuel combustion
sources). Alternatively, the operator may follow the manufacturer's
instructions or industry standard practice. If a CO
2
concentration monitor and volumetric flow rate monitor are not available, the
operator may elect to install a CO
2 concentration
monitor and a volumetric flow rate monitor that comply with all the
requirements specified for the Tier 4 Calculation Methodology in section
95115 (stationary fuel combustion
sources). The calculation and reporting of CH
4 and
N
2O emissions is not required as part of the Tier 4
requirements for AGRs.
(2)
Calculation Methodology 2. If CEMS is not available but a vent
meter is installed, the operator must use the CO
2
composition and annual volume of vent gas to calculate emissions using Equation
3 of this section.
|
E[ALPHA],CO2
= Vs *
VolCO2 |
(Eq. 3) |
Where:
Ea,CO2 = Annual volumetric
CO2 emissions at actual conditions, in cubic feet per
year.
Vs = Total annual volume of vent
gas flowing out of the AGR unit in cubic feet per year at actual conditions as
determined by flow meter using methods set forth in section
95154(b).
Alternatively, the facility operator may follow the manufacturer's instructions
for calibration of the vent meter.
VolCO2 = Annual average
volumetric fraction of CO2 content in the vent gas out
of the AGR unit as determined in (c)(5) of this section.
(3)
Calculation Methodology
3. If CEMS or a vent meter is not installed, the operator may use the
inlet or outlet gas flow rate of the acid gas removal unit to calculate
emissions for CO
2 using Equations 4A or 4B of this
section. If inlet gas flow rate is known, use Equation 4A. If outlet gas flow
rate is known, use Equation 4B.
|
E[ALPHA],CO2
= Vin * [(VolI -
VolO)/(1-VolO)] |
(Eq.
4A) |
|
E[ALPHA],CO2 =
Vout * [(VolI -
VolO)/(1-VolI)] |
(Eq.
4B) |
Where:
E[ALPHA],CO2= Annual volumetric
CO2 emissions at actual conditions, in cubic feet per
year.
Vin= Total annual volume of
natural gas flow into the AGR unit in cubic feet per year at actual condition
as determined using methods specified in paragraph (c)(4) of this
section.
Vout= Total annual volume of
natural gas flow out of the AGR unit in cubic feet per year at actual condition
as determined using methods specified in paragraph (c)(4) of this
section.
VolI= Volume fraction of
CO2 content in natural gas into the AGR unit as
determined in paragraph (c)(6) of this section.
Volo= Volume fraction of
CO2 content in natural gas out of the AGR unit as
determined in paragraph (c)(7) of this section.
(4) Record the gas flow rate of the inlet and
outlet natural gas stream of an AGR unit using a meter according to methods set
forth in section
95154(b). If the
operator does not have a continuous flow meter, either install a continuous
flow meter or use an engineering calculation to determine the flow
rate.
(5) If continuous gas
analyzer is not available on the vent stack, either install a continuous gas
analyzer or take gas samples from the vent gas stream to determine
Vol
CO2 according to methods set forth in section
95154(b). Samples
must be collected once during each three-month period of the calendar year,
with at least 30 days between successive samples.
(6) If a continuous gas analyzer is installed
on the inlet gas stream, then the continuous gas analyzer results must be used.
If continuous gas analyzer is not available, either install a continuous gas
analyzer or take gas samples from the inlet gas stream to determine
Vol
I according to methods set forth in section
95154(b). Samples
must be collected once during each three-month period of the calendar year,
with at least 30 days between successive samples.
(7) Determine volume fraction of
CO
2 content in natural gas out of the AGR unit using one
of the methods specified in paragraph (c)(7) of this section.
(A) If a continuous gas analyzer is installed
on the outlet gas stream, then the continuous gas analyzer results must be
used. If a continuous gas analyzer is not available, the operator may install a
continuous gas analyzer.
(B) If a
continuous gas analyzer is not available or installed, gas samples may be taken
from the outlet gas stream to determine Vol
O according
to methods set forth in section
95154(b). Samples
must be collected once during each three-month period of the calendar year,
with at least 30 days between successive samples.
(C) Use sales line quality specification for
CO2 in natural gas.
(8) Calculate CO2
volumetric emissions at standard conditions using calculations in paragraph (r)
of this section.
(9) Mass
CO2 emissions shall be calculated from volumetric
CO2 emissions using calculations in paragraph (t) of
this section.
(10) Determine if
emissions from the AGR unit are recovered and transferred outside the facility.
Adjust the emission estimated in paragraphs (c)(1) through (c)(10) of this
section downward by the magnitude of emission recovered and transferred outside
the facility.
(d)
Dehydrator vents. For dehydrator vents, calculate annual
CH
4, CO
2, and
N
2O emissions using any of the calculation methodologies
described in paragraph (d) of this section.
(1) Calculate annual mass emissions from
dehydrator vents using a software program which applies the Peng-Robinson
equation of state (Equation 38 of section
95154) to calculate the
equilibrium coefficient, speciates CH
4 and
CO
2 emissions from dehydrators, and has provisions to
include regenerator control devices, a separator flash tank, stripping gas and
a gas injection pump or gas assist pump. A minimum of the following parameters
determined by engineering estimate based on best available data must be used to
characterize emissions from dehydrators.
(A)
Feed natural gas flow rate.
(B)
Feed natural gas water content.
(C)
Outlet natural gas water content.
(D) Absorbent circulation pump type (natural
gas pneumatic/air pneumatic/electric).
(E) Absorbent circulation rate.
(F) Absorbent type: including triethylene
glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
(G) Use of stripping gas.
(H) Use of flash tank separator (and
disposition of recovered gas).
(I)
Hours operated.
(J) Wet natural gas
temperature and pressure.
(K) Wet
natural gas composition. Determine this parameter by selecting one of the
methods described in subparagraphs (1) - (4) below.
1. Use the wet natural gas composition as
defined in section
95153(s)(2).
2. If wet natural gas composition cannot be
determined using paragraph 95153(s)(2) of this section, select a representative
analysis.
3. The facility operator
may use an appropriate standard method published by a consensus-based standards
organization or the facility operator may use an industry standard practice as
specified in section
95154(b) to
sample and analyze wet natural gas composition.
4. If only composition data for dry natural
gas is available, assume the wet natural gas is
saturated.
(2)
Determine if the dehydrator unit has vapor recovery. Adjust the emissions
estimated in paragraphs (d)(1) or (d)(4) of this section downward by the
magnitude of emissions captured.
(3) Calculate annual emissions from
dehydrator vents to flares or regenerator fire-box/fire tubes as follows:
(A) Use the dehydrator vent volume and gas
composition as determined in paragraph (d)(1) of this section.
(B) Use the calculation methodology of flare
stacks in paragraph (l) of this section to determine
dehydrator vent emissions from the flare or regenerator combustion gas
vent.
(4) In the case of
dehydrators that use desiccant, operators must calculate emissions from the
amount of gas vented from the vessel when it is depressurized for the desiccant
refilling process using Equation 5 of this section.
|
Es,n =
n(H * D2 * [PHI] * % G *
P2/(4 *
P1)) |
(Eq. 5) |
Where:
ES,n = Annual natural gas
emissions at standard conditions in cubic feet.
n = number of fillings in reporting period.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
[PHI] = pi (3.1416).
%G = Percent of packed vessel volume that is gas
(expressed as a decimal, e.g.,15% = 0.15).
P1 = Atmospheric pressure
(psia).
P2 = Pressure of the gas
(psia).
(5) For glycol
dehydrators, both CH4 and CO2
mass emissions must be calculated from volumetric GHGi
emissions using calculations in paragraph (t) of this section. For dehydrators
that use desiccant, both CH4 and
CO2 volumetric and mass emissions must be calculated
from volumetric natural gas emissions using calculations in paragraphs (s) and
(t) of this section.
(e)
Well venting for liquids unloadings. Calculate
CO
2 and CH
4 emissions from well
venting for liquids unloading using one of the calculation methodologies
described in paragraphs (e)(1), (e)(2) or (e)(3) of this section.
(1)
Calculation Methodology
1. Calculate the total emissions for well venting for liquids
unloading without plunger lift assist using Equation 6 of this section.
Click
here to view image
Eq. 6)
Where:
ES,n = Annual natural gas
emissions at standard conditions, in cubic feet/year.
W = Total number of well venting events for liquids
unloading for each basin.
0. 37x10-3 =
{3.14(pi)/4}/{14.7x144}(psia converted to pounds per square feet).
p = wells 1 through W with well
venting for liquids unloading in the basin.
CDp = Casing diameter for each
well, p, in inches.
WDp = Well depth from either the
top of the well or the lowest packer to the bottom of the well, for each well,
p, in feet.
SPp = For each well, p, shut-in
pressure or surface pressure for wells with tubing production and no packers or
casing pressure for each well, p, in pounds per square inch absolute
(psia).
Vp = Number of unloading events
per year per well, p.
SFRp = Average flow-line rate of
gas for well p, at standard conditions in cubic feet per hour. Use Equation 29
to calculate the average flow-rate at standard conditions.
HRp,q = Hours that each well, p,
was left open to the atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume
at shut-in pressure.
Zp,q = If
HRp,q is less than 1.0 then Zp,q
is equal to 0. If HRp,q is greater than or equal to 1.0
then Zp,q is equal to 1.
(A) Both CH4 and
CO2 volumetric and mass emissions shall be calculated
from volumetric natural gas emissions using calculations in paragraphs (s) and
(t) of this section.
(2)
Calculation Methodology 2. Calculate emissions from each well
venting to the atmosphere for liquids unloading with plunger lift assist using
Equation 7 of this section.
Click
here to view image
Eq. 7)
Where:
ES,n = Annual natural gas
emissions at standard conditions, in cubic feet/year.
W = Total number of well venting liquid unloading
events at wells using plunger lift assist technology for each basin.
0.37 x 10-3 =
{3.14(pi)/4}/{14.7 x 144} (psia converted to pounds per square feet).
TDp = Tubing internal diameter
for each well, p, in inches.
WDp = Tubing depth to plunger
bumper for each well, p, in feet.
SPp = Flow-line pressure for
each well, p, in pounds per square inch absolute (psia).
Vp = Number of unloading events
per year for each well, p.
SFRp = Average flow-line rate of
gas for well, p, at standard conditions in cubic feet per hour. Use Equation 29
to calculate the average flow-line rate at standard conditions.
HRp,q = Hours that each well, p,
was left open to the atmosphere during each unloading, q.
0.5 = Hours for average well to blowdown tubing volume
at flow-line pressure.
Zp,q = If
HRp,q is less than 0.5, then Zp,q
is equal to 0. If HRp,q is greater than or equal to 0.5,
then Zp,q is equal to 1.
(3) Both CH4 and
CO2 volumetric and mass emissions shall be calculated
from volumetric natural gas emissions using calculations in paragraphs (s) and
(t) of this section.
(f)
Gas well venting during well completions and well workovers.
Using one of the calculation methodologies in this paragraph (f)(1) through
(f)(5) below, operators must calculate CH
4,
CO
2 and N
2O (when flared) annual
emissions from gas well venting during both conventional completions and
completions involving hydraulic fracturing in wells and during both
conventional well workovers and well workovers involving hydraulic fracturing.
(1)
Calculation Methodology
1. Measure total gas flow with a recording flow meter (analog or
digital) installed in the vent line ahead of a flare or vent id used. The
facility operator must correct total gas volume vented for the volume of
CO
2 or N
2:
|
E[ALPHA]
= VM - VCO2 or
N2 |
(Eq. 8) |
Where:
Ea = Gas emissions during the
well completion or workover at actual conditions
(m3).
VM= Volume of vented gas
measured during well completion or workover
(m3).
VCO2 or N2 = Volume of
CO2 or N2 injected during well
completion or workover (m3).
(A) All gas volumes must be corrected to
standard temperature and pressure using methods in section (r).
(B) Calculate CO2 and
CH4 volumetric and mass emissions using the
methodologies in sections (s) and (t).
(2)
Calculation Methodology
2.
(A) Record the well flowing
pressure upstream (P
1) and downstream
(P
2) of a well choke, upstream temperature and elapsed
time of venting according to methods set forth in section
95154(b) to
calculate the well backflow during well completions and workovers.
(B) The operator must record this data at a
time interval (e.g., every five minutes) suitable to accurately describe both
sonic and subsonic flow regimes.
(C) Sonic flow is defined as the flow regime
where P2/P1 [LESS THAN EQUAL TO]
0.542.
(D) Calculate the average
flow rate during sonic conditions using Equation 9 of this section.
Click
here to view image
Eq. 9)
Where:
FRa = Average flow rate in cubic
feet per hour, under actual sonic flow conditions.
A = Cross sectional open area of the restriction
orifice (m2).
Tu = Upstream temperature
(degrees Kelvin).
187.08 = Constant with units of
m2/(sec2x K).
1.27 x 105 = Conversion from
m3/second to
ft3/hour.
(E) Calculate total gas volume vented during
sonic flow conditions as follows:
Where:
Vs = Volume of gas vented during
sonic flow conditions (scf).
TS = Length of time that the
well vented under sonic conditions (hours).
(F) For each of the sets of data points
(T
u, P
1,
P
2, and elapsed time under subsonic flow conditions)
recorded as the well vented under subsonic flow conditions, calculate the
instantaneous gas flow rate as follows:
Click
here to view image
Eq. 11)
Where:
FRa = Instantaneous flow rate in
cubic feet per hour, under actual subsonic flow conditions.
A = Cross sectional open area of the restriction
orifice (m2).
P1 = Upstream pressure
(psia).
Tu = Upstream temperature
(degrees Kelvin).
P2 = Downstream pressure
(psia).
3430 = Constant with units of
m2/(sec2xK).
1.27 x 105 = Conversion from
m3/second to
ft3/hour.
(G) Calculate the total gas volume vented
during subsonic flow conditions, VSS, as the total
volume under the curve of a plot of FRa and elapsed time
under subsonic flow conditions.
(H)
Correct VSS to standard conditions using the methodology
found in paragraph (r) of this section.
(I) Sum the vented volumes during subsonic
and sonic flow and adjust vented emissions for the volume of
CO
2 and N
2 injected and the
volume of gas recovered to a sales line as follows:
Click
here to view image
Eq. 12)
Where:
Es = Total volume of gas vented
during the well completion or workover (scf).
Vs = Volume of gas vented during
sonic flow conditions for the well completion or workover (scf) (see Eq.
10).
Vss = Volume of gas vented
during subsonic flow conditions for the well completion or workover (scf) (see
95153(f)(2)(G) above).
VCO2/N2 = Volume of
CO2 or N2 injected during the
well completion or workover (scf).
VSG = Volume of gas recovered to
a sales line during the well completion or workover
(scf).
(3) The
volume of CO
2 or N
2 injected into
the well reservoir during energized hydraulic fractures must be measured using
an appropriate meter as described in section
95154(b) or using
receipts of gas purchases that are used for the energized fracture job.
(A) Calculate gas volume at standard
conditions using calculations in paragraph (r) of this
section.
(4) Determine if
the backflow gas from the well completion or workover is recovered with purpose
designed equipment that separates natural gas from the backflow, and sends this
natural gas to a flow-line (
e.g., reduced emissions completion
or workover).
(A) Use the factor
VSG in Equation 12 of this section to adjust the
emissions estimated in paragraphs (f)(1) through (f)(4) of this section by the
magnitude of emissions captured using purpose designed equipment that separates
saleable gas from the backflow as determined by engineering estimate based on
best available data.
(B) Calculate
gas volume at standard conditions using calculations in paragraph (r) of this
section.
(5) Both
CH4 and CO2 volumetric and mass
emissions must be calculated from volumetric total emissions using calculations
in paragraphs (s) and (t) of this section.
(g)
Equipment and pipeline
blowdowns. Calculate CO
2 and
CH
4 blowdown emissions from depressurizing equipment and
natural gas pipelines to reduce system pressure for planned or emergency
shutdowns resulting from human intervention or to take equipment out of service
for maintenance (excluding depressurizing to a flare, over-pressure relief,
operating pressure control venting and blowdown of non-GHG gases; desiccant
dehydrator blowdown venting before reloading is covered in paragraphs (d)(4) of
this section) as follows:
(1) Calculate the
unique physical volume (including pipelines, compressor case or cylinders,
manifolds, suction bottles, discharge bottles, and vessels) between isolation
valves determined by engineering estimates based on best available data.
Engineering estimates based on best available data may also be used to
determine the temperature and pressure variables used in the Equations 13 and
14 if monitoring data is unavailable. Equipment blowdowns with a unique
physical volume (including pipelines, compressor case or cylinder manifolds,
suction bottles, discharge bottles and vessels) of less than 50 cubic feet (cf)
between isolation valves are not subject to the requirements of
95153(g).
(2) Calculate the total
annual venting emissions for unique volumes using either Equation 13 or 14 of
this section.
Click
here to view image
Eq. 13)
Where:
Es,n = Annual natural gas
venting emissions at standard conditions from blowdowns in cubic feet.
N = Number of occurrences of blowdowns for each unique
physical volume in the calendar year.
V = Unique physical volume (including pipelines,
compressors and vessels) between isolation valves in cubic feet.
C = Purge factor that is 1 if the unique physical
volume is not purged or zero if the unique physical volume is purged using
non-GHG gases.
Ts = Temperature at standard
conditions (60°F).
Ta = Temperature at actual
conditions in the unique physical volume (°F).
Ps = Absolute pressure at
standard conditions (14.7 psia).
Pa = Absolute pressure at actual
conditions in the unique physical volume (psia).
Click
here to view image
Eq. 14)
Where:
Es,n = Annual natural gas
venting emissions at standard conditions from blowdowns in cubic feet.
PV = Number of unique physical volumes
blowndown.
N = Number of occurrences of blowdowns for each unique
physical volume.
V = Total physical volume (including pipelines,
compressors and vessels) between isolation valves in cubic feet for each
blowdown "p".
Ts = Temperature at standard
conditions (60°F).
Ta,p = Temperature at actual
conditions in the unique physical volume (°F).
Ps = Absolute pressure at
standard conditions (14.7 psia).
Pa,b,p = Absolute pressure at
actual conditions in the unique physical volume (psia) at the beginning of the
blowdown "p".
Pa,e,p = Absolute pressure at
actual conditions in the unique physical volume (psia) at the end of the
blowdown "p"; 0 if blowdown volume is purged using non-GHG
gases.
(3) Calculate both
CH4 and CO2 volumetric and mass
emissions using calculations in paragraph (s) and (t) of this
section.
(4) Calculate total annual
venting emissions for all blowdown vent stacks by adding all standard
volumetric and mass emissions determined by Equation 13 or 14 and paragraph
(g)(3) of this section.
(h) Dump Valves. Calculate emissions from
occurrences of gas-liquid separator liquid dump valves not closing during the
calendar year by using the method found in 95153(i).
(i)
Transmission storage
tanks. For vent stacks connected to one or more transmission
condensate storage tanks, either water or hydrocarbon, without vapor recovery,
in onshore natural gas transmission compression and onshore petroleum and
natural gas production, the operator of a facility must calculate CH4, CO2 and
N2O annual emissions from condensate scrubber dump valve leakage as follows:
(1) Monitor the tank vapor vent stack
annually for emissions using an optical gas imaging instrument according to
methods set forth in section
95154(a)(1) or by
directly measuring the tank vent using a flow meter or high volume sampler
according to methods in section
95154(b) through
(d) for a duration of five minutes, or a
calibrated bag according to methods in section
95154(b). Or the
facility operator may annually monitor leakage through compressor scrubber dump
valve(s) into the tank using an acoustic leak detection device according to
methods in paragraph 95154(a)(5).
(2) If the tank vapors from the vent stack
are continuous for five minutes, or the acoustic leak detection device detects
a leak, then use one of the following two methods in paragraph (i)(2) of this
section to quantify annual emissions:
(A) Use
a meter, such as a turbine meter, calibrated bag, or high flow sampler to
estimate tank vapor volumes from the vent stack according to methods set forth
in section
95154(b) through
(d). If a continuous flow measurement device
is not installed, the facility operator may install a flow measuring device on
the tank vapor vent stack. If the vent is directly measured for five minutes
under paragraph (i)(1) of this section to detect continuous leakage, this
serves as the measurement.
(B) Use
an acoustic leak detection device on each scrubber dump valve connected to the
tank according to the method set forth in section
95154(a)(5).
(C) Use the appropriate gas composition in
paragraph (s)(2)(C) of this section.
(D) Calculate GHG volumetric and mass
emissions at standard conditions using calculations in paragraphs (r), (s), and
(t) of this section, as applicable to the monitoring equipment
used.
(3) If a leaking
dump valve is identified, the leak must be counted as having occurred since the
beginning of the calendar year, or from the previous test that did not detect
leaking in the same calendar year. If the leaking dump valve is fixed following
leak detection, the leak duration will end upon being repaired. If the leaking
dump valve is identified and not repaired, the leak must be counted as having
occurred through the rest of the calendar year.
(4) Calculate annual emissions from storage
tanks to flares as follows:
(A) Use the
storage tank emissions volume and gas composition as determined in paragraphs
(i)(1) through (i)(3) of this section.
(B) Use the calculation methodology of flare
stacks in paragraph (l) of this section to determine storage
tank emissions sent to a flare.
(j)
Well testing venting and
flaring. Calculate CH
4,
CO
2 and N
2O (when flared) gas and
oil well testing venting and flaring emissions as follows:
(1) Determine the total gas-to-oil ratio
(GOR) of the hydrocarbon production from all oil well(s) tested. Determine the
production rate from all gas well(s) tested.
(2) If total GOR cannot be determined from
available data, then the facility operator must measure quantities reported in
this section according to one of the two procedures in paragraph (j)(2) of this
section to determine total GOR.
(A) The
facility operator may use an appropriate standard method published by a
consensus-based standards organization if such a method exists, including ARB's
sampling methodology and flash liberation test procedure in Appendix B of this
regulation (if flash liberation testing is representative of all produced
associated gas); or
(B) The
facility operator may use an industry standard practice as described in section
95154(b).
(3) Estimate venting emissions using Equation
15 (for oil wells) or Equation 16 (for gas wells) of this section.
|
ES,n
= Total GOR * FR * D |
(Eq.15) |
|
E[ALPHA],n = PR *
D |
(Eq.16) |
Where:
ES,n = Annual volume of gas
emissions from well(s) testing in standard cubic feet.
Ea,n = Annual volumetric natural
gas emissions from well(s) testing in cubic feet under actual
conditions.
Total GOR = Gas-to-oil ratio, for well p in basin q, in
standard cubic feet of gas per barrel of oil; oil here refers to hydrocarbon
liquids produced of all API gravities.
FR = Annual average flow rate in barrels of oil per day
for the oil well(s) being tested.
PR = Average annual production rate in actual cubic
feet per day for the gas well(s) being tested.
D = Number of days during the year the well(s) is
tested.
(4) For equation 16
calculate natural gas volumetric emissions at standard conditions using
calculations in paragraph (r) of this section.
(5) Calculate both CH4
and CO2 volumetric and mass emissions from volumetric
natural gas emissions using the calculations in paragraphs (s) and (t) of this
section.
(6) Calculate emissions
from well testing to flares as follows:
(A)
Use the well testing emissions volume and gas composition as determined in
paragraphs (j)(1) through (3) of this section.
(B) Use the calculation methodology of flare
stacks in paragraph (l) of this section to determine well
testing emissions from the flare.
(k)
Associated gas venting and
flaring. Calculate CH
4,
CO
2 and N
2O (when flared)
associated gas venting and flaring emissions not in conjunction with well
testing as follows:
(1) Determine the total
GOR of the hydrocarbon production from each well whose associated natural gas
is vented or flared. If total GOR from each well is not available, the total
GOR from a cluster of wells in the same basin shall be used.
(2) If total GOR cannot be determined from
available data, then use one of the two procedures in paragraph (k)(2) of this
section to determine total GOR.
(A) Use an
appropriate standard method published by a consensus-based standards
organization if such a method exists, including ARB's sampling methodology and
flash liberation test procedure in Appendix B of this regulation (if flash
liberation testing is representative of all produced associated gas);
or
(B) The facility operator may
use an industry standard practice as described in section
95154(b).
(3) Estimate venting emissions using Equation
17 of this section.
Click
here to view image
Eq. 17)
Where:
Ea,n = Annual volumetric natural
gas emissions, at the facility level, from associated gas venting in standard
cubic feet.
Total GORp,q = Gas-to-oil ratio,
for well p in basin q, in standard cubic feet of gas per barrel of oil; oil
here refers to hydrocarbon liquids produced of all API gravities.
Vp,q = Volume of oil produced,
for well p in basin q, in barrels in the calendar year during which associated
gas was vented or flared. x = Total number of wells in the basin that vent or
flare associated gas.
(4)
Calculate both CH4 and CO2
volumetric and mass emissions from volumetric natural gas emissions using
calculations in paragraphs (s) and (t) of this section.
(5) Calculate emissions from associated gas
to flares as follows:
(A) Use the associated
natural gas volume and composition as determined in paragraph (k)(1) through
(k)(3) of this section.
(B) Use the
calculation methodology of flare stacks in paragraph (l) of
this section to determine associated gas emissions from the
flare.
(l)
Flare stack or other destruction device emissions. Calculate
CO
2, CH
4 and
N
2O emissions from a flare stack or other destruction
device as follows:
(1) For the purposes of
this reporting requirement, the facility operator must calculate emission from
all flares, incinerators, oxidizers and vapor combustion units.
(2) If a continuous flow measurement device
is installed on the flare or destruction device, the measured flow volumes must
be used to calculate the flare gas emissions. If all of the gas or liquid sent
to the flare or destruction device is not measured by the existing flow
measurement device, then the flow not measured can be estimated using
engineering calculations based on best available data or company records. If a
continuous flow measurement device is not installed on the flare or destruction
device, a flow measuring device can be installed on the flare or destruction
device or engineering calculations based on process knowledge, company records,
or best available data may be used to quantify the flare volume.
(3) If a continuous gas composition analyzer
is not installed on gas or liquid supply to the flare or destruction device,
use the appropriate gas composition for each stream of hydrocarbons going to
the flare as follows:
(A) For onshore natural
gas processing, when the stream going to the flare is natural gas, use the GHG
mole percent in feed natural gas for all streams upstream of the de-methanizer
or dew point control, and GHG mole percent in facility specific residue gas to
transmissions pipeline systems for all emissions sources downstream of the
de-methanizer overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely fractionate a
liquid stream, use the GHG mole percent in feed natural gas liquid for all
streams.
(B) For any applicable
industry segment, when the stream going to the flare is a hydrocarbon product
stream, such as methane, ethane, propane, butane, pentane-plus and mixed light
hydrocarbons, then the facility operator may use a representative composition
from the source for the stream determined by engineering calculation based on
process knowledge and best available data.
(4) Determine flare combustion efficiency
from manufacturer specifications. If not available, assume that flare
combustion efficiency is 98 percent.
(5) Calculate GHG volumetric emissions at
actual conditions using Equations 18 and 19 of this section.
Click
here to view image
Eq. 18)
Click
here to view image
Eq. 19)
Where:
Ea,CH4 = Annual
CH4 emissions from flare stack in cubic feet, under
actual conditions.
Ea,CO2 = Annual
CO2 emissions from flare stack in cubic feet, under
actual conditions.
Va = Volume of gas sent to flare
in cubic feet, during the year.
η = Fraction of gas combusted by a
burning flare (default is 0.98). For gas sent to an unlit flare,
η is zero.
XCH4 = Mole fraction of
CH4 in gas to the flare.
ZL = Fraction of the feed gas
sent to a burning flare (equal to 1 - ZU).
ZU = Fraction of the feed gas
sent to an unlit flare determined by engineering estimate and process knowledge
based on best available data and operating records.
XCO2 = Mole fraction of
CO2 in gas to the flare.
Yj = Mole fraction of gas
hydrocarbon constituents j (such as methane, ethane, propane, and
pentanes-plus).
Rj = Number of carbon atoms in
the gas hydrocarbon constituent j: 1 for methane, 2 for ethane, 3 for propane,
4 for butane, and 5 for pentanes-plus.
(6) Calculate GHG volumetric emissions at
standard conditions using calculations in paragraph (r) of this
section.
(7) Calculate both
CH4 and CO2 mass emissions from
volumetric CH4 and CO2 emissions
using calculation in paragraph (t) of this section.
(8) Calculate N2O
emissions from flare stacks using Equation 37 in paragraph (y) of this
section.
(9) If the facility
operator operates and maintains a CEMS that has both a
CO
2 concentration monitor and volumetric flow rate
monitor, calculate only CO
2 emissions for the flare. The
facility operator must follow the Tier 4 Calculation Methodology and all
associated calculation, quality assurance, reporting, and record keeping
requirements for Tier 4 in section
95115. If a CEMS is used to
calculate flare stack emissions, the requirements specified in paragraphs
(
l)(1) through (
l)(8) are not required. If a
CO
2 concentration monitor and volumetric flow rate
monitor are not available, the facility operator may elect to install a
CO
2 concentration monitor and a volumetric flow rate
monitor that comply with all of the requirements specified for the Tier 4
Calculation Methodology in section
95115 of this article (stationary
fuel combustion sources).
(10) The
flare emissions determined under paragraph (l) of this section
must be corrected for flare emissions calculated and reported under other
paragraphs of this section to avoid double counting of these
emissions.
(11) If source types in
section
95153 use Equations 18 and 19 of
this section, use volume under actual conditions for the parameter,
V
a, in these equations.
(m)
Centrifugal compressor
venting. Calculate CH
4,
CO
2 and N
2O (when flared)
emissions from both wet seal and dry seal centrifugal compressor vents as
follows:
(1) For each centrifugal compressor
with a rated horsepower of 250hp or greater covered by sections
95152(c)(12), (d)(5), (e)(6), (f)(5), (g)(3), and
(h)(3) the operator must conduct an annual
measurement in each operating mode in which it is found for more than 200 hours
in a calendar year. Measure emissions from all vents (including emissions
manifolded to common vents) including wet seal oil degassing vents, unit
isolation valve vents, and blowdown valve vents. Record emissions from the
following vent types in the specified compressor modes during the annual
measurement:
(A) Operating mode, blowdown
valve leakage through the blowdown vent, wet seal and dry seal compressors. For
all centrifugal compressor start-ups where natural gas is used as spin-up or
starting gas (i.e. not combusted in the compressor), venting of this gas must
be quantified and reported as follows:
Click
here to view image
Eq. 20)
Where:
ESGi = Annual
GHGi (CO2 and
CH4) vented emissions at standard conditions in cubic
feet.
n = number of compressor start-ups using spin
gas.
Vsg = Volume of spin-up gas in
standard cubic feet determined by metering or engineering estimates based on
best available data.
CF = Fraction of spin-up gas that is sent to vapor
recovery or fuel gas as determined by keeping logs of the number of operating
hours for the vapor recovery system and the amount of gas that is directed to
the fuel gas or vapor recovery system.
Yi = Mole fraction of
GHGi in the vent gas.
Calculate both CH4 and
CO2 mass emissions from volumetric emissions using
calculations in paragraph (t) of this section.
(B) Operating mode, wets seal oil degassing
vents.
(C) Not operating
depressurized mode, unit isolation valve leakage through open blowdown vent,
without blind flanges, wet seal and dry seal compressors.
1. For the not operating depressurized mode,
each compressor must be measured at least once in any three consecutive
calendar years. If a compressor is not operated and has blind flanges in place
throughout the three year period, measurement is not required in this mode. If
the compressor is in standby depressurized mode without blind flanges in place
and is not operated throughout the three year period, it must be measured in
the standby depressurized mode.
2.
An engineering estimate approach based on similar equipment specifications and
operating conditions may be used to determine the MTm
variable in place of actual measured values for centrifugal compressors that
are operated for no more than 200 hours in a calendar year and used for peaking
purposes in place of metered gas emissions if an applicable meter is not
present on the compressor.
(2) For wet seal oil degassing vents,
determine vapor volumes sent to an atmospheric vent or flare, using a temporary
meter such as a vane anemometer or permanent flow meter according to section
95154(b) of this
section. If a permanent flow meter is not installed, the operator may install a
permanent flow meter on the wet seal oil degassing tank vent.
(3) For blowdown valve leakage and isolation
valve leakage to open ended vents, use one of the following methods: Calibrated
bagging or high volume sampler according to methods set forth in sections
95154(c) and
95154(d),
respectively. For through valve leakage, such as isolation valves, the facility
operator may install a port for insertion of a temporary meter, or a permanent
flow meter, on the vents.
(4) To
determine Yi, use gas composition data from a continuous
gas analyzer if a continuous gas analyzer is installed, or measurements of gas
composition where a continuous gas analyzer is not installed. Samples must be
collected once during each three-month period of the calendar year, with at
least 30 days between successive samples.
(5) Estimate annual emissions using the flow
measurement and Equation 21 of this section.
Click
here to view image
Eq. 21)
Where:
Es,i,m = Annual GHG (either
CH4 or CO2) volumetric emissions
at standard conditions, in cubic feet.
MTm = Measured gas emissions in
standard cubic feet per hour during operating mode m as described in sections
(m)(1)(A) through (m)(1)(C).
Tm = Total time the compressor
is in the mode for which Es,i is being calculated, in
the calendar year in hours.
Yi = Mole fraction of
GHGi in the vent gas.
CF = Fraction of centrifugal compressor vent gas that
is sent to vapor recovery or fuel gas as determined by keeping logs of the
number of operating hours for the vapor recovery system and the amount of gas
that is directed to the fuel gas or vapor recovery system.
(6) For each centrifugal compressor with a
rated horsepower of less than 250hp covered by sections
95152(c)(12), (d)(5), (e)(6), (f)(5), (g)(3), and
(h)(3), the operator must calculate annual
emissions from both wet seal and dry seal centrifugal compressor vents using
Equation 22 of this section.
|
Es,i =
Count * EFi |
(Eq. 22) |
Where:
Es,i = Annual total volumetric
GHG emissions at standard conditions from centrifugal compressors ( <250hp)
in cubic feet.
Count = Total number of centrifugal
compressors less than 250hp.
EFi = Emission factor for GHGi.
Use 1.2 x 107 standard cubic feet per year per
compressor for CH4 and 5.30 x
105 standard cubic feet per year per compressor for
CO2 at 60°F and 14.7 psia.
(7) Calculate both CH4
and CO2 mass emissions from volumetric emissions using
calculations in paragraph (t) of this section.
(8) Calculate emissions from seal oil
degassing vent vapors to flares as follows:
(A) Use the seal oil degassing vent vapor
volume and gas composition as determined in paragraphs (m)(2) through (m)(4) of
this section.
(B) Use the
calculation methodology of flare stacks in paragraph (l) of
this section to determine degassing vent vapor emissions from the
flare.
(n)
Reciprocating compressor venting. Calculate
CH
4 and CO
2, and
N
2O (when flared) emissions from all reciprocating
compressor vents as follows:
(1) For each
reciprocating compressor with a rated horsepower of 250hp or greater covered in
sections
95152(c)(13), (d)(6), (e)(7), (f)(6), (g)(4), and
(h)(4) the facility operator must conduct an
annual measurement for each compressor in each operating mode in which it is
found for more than 200 hours in a calendar year. Measure emissions from
(including emissions manifolded to common vents) reciprocating rod packing
vents, unit isolation valve vents, and blowdown valve vents. Record emissions
from the following vent types in the specified compressor modes during the
annual measurement as follows:
(A) Operating
or standby pressurized mode, blowdown vent leakage through the blowdown vent
stack.
(B) Operating mode,
reciprocating rod packing emissions.
(C) Not operating depressurized mode, unit
isolation valve leakage through the blowdown vent stack, without blind flanges.
1. For the not operating, depressurized mode,
each compressor must be measured at least once in any three consecutive
calendar years if this mode is not found in the annual measurement. If a
compressor is not operated and has blind flanges in place throughout the three
year period, measurement is not required in this mode. If the compressor is in
standby depressurized mode without blind flanges in place and is not operated
throughout the three year period, it must be measured in the standby
depressurized mode.
2. An
engineering estimate approach based on similar equipment specifications and
operating conditions may be used to determine the MTm
variable in place of actual measured values for reciprocating compressors that
are operated for no more than 200 hours in a calendar year and used for peaking
purposes in place of metered gas emissions if an applicable meter is not
present on the compressor.
(2) If reciprocating rod packing and blowdown
vent are connected to an open-ended vent line, use one of the following two
methods to calculate emissions:
(A) Measure
emissions from all vents (including emissions manifolded to common vents)
including rod packing, unit isolation valves, and blowdown vents using either
calibrated bagging or high volume sampler according to methods set forth in
sections
95154(c) and
95154(d),
respectively.
(B) Use a temporary
meter such as a vane anemometer or a permanent meter such as an orifice meter
to measure emissions from all vents (including emissions manifolded to a common
vent) including rod packing vents and unit isolation valve leakage through
blowdown vents according to methods set forth in section
95154(b). If a
permanent flow meter is not installed, the facility operator may install a port
for insertion of a temporary meter or a permanent flow meter on the vents. For
throughvalve leakage to open ended vents such as unit isolation valves on not
operating, depressurized compressors, use an acoustic detection device
according to methods set forth in section
95154(a).
(3) If reciprocating rod packing is not
equipped with a vent line use the following method to calculate emissions:
(A) The facility operator must use the
methods described in section
95154(a) to
conduct annual leak detection of equipment leaks from the packing case into an
open distance piece, or from the compressor crank case breather cap or other
vent with a closed distance piece.
(B) Measure emissions found in paragraph
(n)(2)(A) of this section using an appropriate meter, or calibrated bag, or
high volume sampler according to the methods set forth in sections
95154(b), (c), and
(d) respectively.
(4) To determine Yi,
use gas composition data from a continuous gas analyzer if a continuous gas
analyzer is installed, or measurements of gas composition where a continuous
gas analyzer is not installed. Samples must be collected once during each
three-month period of the calendar year, with at least 30 days between
successive samples.
(5) Estimate
annual emissions using the flow measurement and Equation 23 of this section.
Click
here to view image
)
Eq. 23
Where:
Es,i,m = Annual
GHGi (either CH4 or
CO2) volumetric emissions, in standard cubic
feet.
MTm = Measured gas emissions in
standard cubic feet per hour during operating mode m as described in sections
(n)(1)(A) through (n)(1)(C).
Tm = Total time the compressor
is in the mode for which Es,i,m is being calculated, in
the calendar year in hours.
Yi = Mole fraction of
GHGi in the vent gas.
CF = Fraction of reciprocal compressor vent gas that is
sent to vapor recovery or fuel gas as determined by keeping logs of the number
of operating hours for the vapor recovery system and the amount of gas that is
directed to the fuel gas or vapor recovery system.
(6) For each reciprocating compressors with a
rated horsepower of less than 250hp, the operator must calculate annual
emissions using Equation 24 of this section.
|
Es,i =
Count * EFi |
(Eq. 24) |
Where:
Es,i = Annual total volumetric
GHG emissions at standard conditions from reciprocating compressors in cubic
feet.
Count = Total number of reciprocating compressors for
the facility operator.
EFi = Emission factor for
GHGi. Use 9.48 x 103 standard
cubic feet per year per compressor for CH4 and 5.27 x
102 standard cubic feet per year per compressor for
CO2 at 60°F and 14.7 psia.
(7) Estimate CH4 and
CO2 volumetric and mass emissions from volumetric
natural gas emissions using the calculations in paragraphs (s) and (t) of this
section.
(o)
Leak
detection and leaker emission factors. The operator must use the
methods described in section
95154(a) to
conduct leak detection(s) of equipment leaks from all components types listed
in sections
95152(c)(16), (d)(7), (e)(8), (f)(7), (g)(5),
(h)(5), and (i)(1). This paragraph (o)
applies to component types in streams with gas content greater than 10 percent
CH
4 plus CO
2 by weight. Component
types in streams with gas content less than 10 percent
CH
4 plus CO
2 by weight do not
need to be reported. Tubing systems equal to or less than one half inch
diameter are exempt from the requirements of this paragraph (o) and do not need
to be reported. If equipment leaks are detected for sources listed in this
paragraph (o), calculate equipment leak emissions per component type per
reporting facility using Equations 25 or 26 of this section for each component
type. Use Equation 25 for industry segments listed in section
95150(a)(1) -
(a)(7). Use Equation 26 for natural gas
distribution facilities as defined in section
95150(a)(8). Use
methods found in section
95153(t) to
convert GHG
i volume emissions to
GHG
i mass emissions.
Click
here to view image
Eq. 25)
Click
here to view image
Eq. 26)
Where:
Es,i = Annual total volumetric
GHG emissions at standard conditions from each component type in cubic feet, as
specified in (o)(1) through (o)(8) of this section.
X = Total number of each component type.
EF = Leaker emission factor for specific component
types listed in Table 1A and 2 through 7 of Appendix A.
GHGi = For onshore petroleum and
natural gas production facilities, concentration of
GHGi, CH4 or
CO2, in produced natural gas as defined in paragraph
(s)(2)(A) of this section; For onshore natural gas processing facilities,
concentration of GHGi, CH4 or
CO2, in the total hydrocarbon of the feed natural gas;
for onshore natural gas transmission compression and underground natural gas
storage, GHGi equals 0.975 for
CH4 and 1.1 x 10-2 for
CO2; for LNG storage and LNG import and export
equipment, GHGi equals 1 for CH4
and 0 for CO2; and for natural gas distribution,
GHGi equals 1 for CH4 and 1.1 x
10-2 for CO2 or use the
experimentally determined gas composition for CO2 and
CH4.
Tp = The total time the
component, p, was found leaking and operational, in hours. If one leak
detection survey is conducted, assume the component was leaking for the entire
calendar year. If multiple leak detection surveys are conducted, assume that
the component found to be leaking has been leaking since the previous survey
(if not found leaking in the previous survey) or the beginning of the calendar
year (if it was found leaking in the previous survey) or the beginning of the
calendar year (if it was found leaking in the previous survey). For the last
leak detection survey in the calendar year, assume that all leaking components
continue to leak until the end of the calendar year.
t = Calendar year of reporting.
n = The number of years over which one complete cycle
of leak detection is conducted over all the Transmission - Distribution (T-D)
transfer stations in a natural gas distribution facility; 0 < n [LESS THAN
EQUAL TO] 5. For the first (n-1) calendar years of reporting the summation in
Equation 26 should be for years that the data is available.
Tp,q = The total time the
component, p, was found leaking and operational, in hours, in year q. If one
leak detection survey is conducted, assume the component was leaking for the
entire period n. If multiple leak detection surveys are conducted, assume the
component found to be leaking has been leaking since the previous survey) or
the beginning of the calendar year (if it was found to be leaking in the
previous survey). For the last leak detection survey in the cycle, assume that
all leaking components continue to leak until the end of the cycle.
(1) The operator must select to conduct
either one leak detection survey in a calendar year or multiple complete leak
detection surveys in a calendar year. The number of leak detection surveys
selected must be conducted during the calendar year.
(2) Onshore petroleum and natural gas
production facilities must use the appropriate default leaker emissions factors
listed in Table 1A of Appendix A for all leaks from equipment types in the
table.
(3) Onshore natural gas
processing facilities must use the appropriate default leaker emission factors
listed in Table 2 of Appendix A for equipment leaks detected from valves,
connectors, open ended lines, pressure relief valves, and meters.
(4) Onshore natural gas transmission
facilities shall use the appropriate default leaker emission factors listed in
Table 3 of Appendix A for equipment leaks detected from valves, connectors,
open ended lines, pressure relief valves, and meters.
(5) Underground natural gas storage
facilities for storage stations shall use the appropriate default leaker
emission factors listed in Table 4 of Appendix A for equipment leaks detected
from valves, connectors, open ended lines, pressure relief valves, and
meters.
(6) LNG storage facilities
shall use the appropriate default leaker emission factors listed in Table 5 of
Appendix A for equipment leaks detected from valves, pump seals, connectors,
and other equipment.
(7) LNG import
and export facilities shall use the appropriate default leaker emission factors
listed in Table 6 of Appendix A for equipment leaks detected from valves, pump
seals, connectors, and other equipment.
(8) Natural gas distribution facilities for
above ground transmission-distribution transfer stations, shall use the
appropriate default leak emission factors listed in Table 7 of Appendix A for
equipment leaks detected from connectors, block valves, control valves,
pressure relief valves, orifice meters, regulators, and open ended lines. Leak
detection at natural gas distribution facilities is only required at above
grade stations that qualify as transmission-distribution transfer stations.
Below grade transmission-distribution transfer stations and all
metering-regulating stations that do meet the definition of
transmission-distribution transfer stations are not required to perform
component leak detection under this section.
(A) Natural gas distribution facilities may
choose to conduct leak detection at the T-D transfer stations over multiple
years, not exceeding a five year period to cover all T-D transfer stations. If
the facility operator chooses to use the multiple year option then the number
of T-D transfer stations that are monitored in each year should be
approximately equal across all years in the cycle without monitoring the same
station twice during the multiple year survey.
(p)
Population count and emission
factors. This paragraph applies to emissions sources listed in
sections
95152(c)(16), (f)(7), (g)(5), (h)(5), (i)(2),
(i)(3), (i)(4), (i)(5), (i)(6), and (i)(10)
on streams with gas content greater than 10 percent CH4 plus CO2 by weight.
Emissions sources in streams with gas content less than 10 percent CH4 plus CO2
by weight do not need to be reported. Tubing systems equal to or less than one
half inch diameter are exempt from the requirements of paragraph (p) of this
section and do not need to be reported. Calculate emissions from all sources
listed in this paragraph using Equation 27 of this section.
|
Es,i =
Counts * EFs *
GHGi * Ts |
(Eq.
27) |
Where:
Es,i = Annual volumetric GHG
emissions at standard conditions from each component type in cubic feet.
Counts = Total number of this
type of emission source at the facility. Underground natural gas storage shall
count the components listed for population emission factors in Table 4. LNG
storage shall count the number of vapor recovery compressors. LNG import and
export shall count the number of vapor recovery compressors. Natural gas
distribution shall count the meter/regulator runs and the number of customer
meters as described in paragraph (p)(6) of this section.
EFs = Population emission factor
for the specific component type, as listed in Table 1A and Tables 3 through
Table 7 of Appendix A. Use appropriate emission factor for operations in
Western U.S., according to Table 1(A) - 1(C) of Appendix A. EF for
meter/regulator runs at above grade metering-regulator stations is determined
in Equation 28 of this section.
GHGi = For onshore petroleum and
natural gas production facilities, concentration of
GHGi, CH4 or
CO2, in produced natural gas as defined in paragraph
(s)(2) of this section; for onshore natural gas transmission compression and
underground natural gas storage, GHGi equals 0.975 for CH4 and 1.1 x 10-2 for
CO2; for LNG storage and LNG import and export
equipment, GHGi equals 1 for CH4
and 0 for CO2; for natural gas distribution,
GHGi equals 1 for CH4 and 1.1 x
10-2 for CO2 or use the experimentally determined gas
composition for CO2 and
CH4.
Ts = Total time that each
component type associated with the equipment leak emission was operational in
the calendar year, in hours, using engineering estimate based on best available
data, assume Ts = 8760 hours (or 8784 hours for a leap
year) for section
95152(i)(10).
(1) Calculate both CH4
and CO2 mass emissions from volumetric emissions using
calculations in paragraph (t) of this section.
(2) Onshore petroleum and natural gas
production facilities must use the appropriate default population emission
factors listed in Table 1A of Appendix A for equipment leaks from valves,
connectors, open ended lines, pressure relief valves, pump, flanges, and other.
Major equipment and components associated with gas wells are considered gas
service components in reference to Table 1A of Appendix A and major natural gas
equipment in reference to Table 1B of Appendix A. Major equipment and
components associated with crude oil wells are considered crude service
components in reference to Table 1A of Appendix A and major crude oil equipment
in reference to Table 1C of Appendix A. Where facilities conduct EOR operations
the emissions factor listed in Table 1A of Appendix A shall be used to estimate
all streams of gases, including recycle CO
2 stream. The
component count can be determined using either of the methodologies described
in this paragraph (p)(2). The same methodology must be used for the entire
calendar year.
(A)
Component Count
Methodology 1. For all onshore petroleum and natural gas production
operations in the facility perform the following activities:
1. Count all major equipment listed in Table
1B and Table 1C of Appendix A. For meters/piping, use one meters/piping per
well-pad.
2. Multiply major
equipment counts by the average component counts listed in Table 1B and 1C of
Appendix A for onshore natural gas production and onshore oil production,
respectively. Use the appropriate factor in Table 1A of Appendix A for
operations in Eastern and Western U.S. according to the mapping in Table 1B of
Appendix A.
(B)
Component Count Methodology 2. Count each component
individually for the facility. Use the appropriate factor in Table 1A of
Appendix A for operations in the Western U.S.
(3) Underground natural gas storage
facilities for storage wellheads must use the appropriate default population
emission factors listed in Table 4 of Appendix A for equipment leak from
connectors, valves, pressure relief valves and open ended lines.
(4) LNG storage facilities must use the
appropriate default population emission factors listed in Table 5 of Appendix A
for equipment leak from vapor recovery compressors.
(5) LNG import and export facilities must use
the appropriate emission factor listed in Table 6 of Appendix A for equipment
leak from vapor recovery compressors.
(6) Natural gas distribution facilities must
use the appropriate emission factors as described in paragraph (p)(6) of this
section.
(A) Below grade metering-regulating
stations; distribution mains; distribution services; and customer meters must
use the appropriate default population emission factors listed in Table 7 of
Appendix A. Below grade T-D transfer stations must use the emission factor for
below grade metering-regulating stations.
(B) Emissions from all above grade
metering-regulating stations (including above grade T-D transfer stations) must
be calculated by applying the emission factor calculated in Equation 28 and the
total count of metering/regulator runs at all above grade metering-regulating
stations (inclusive of T-D transfer stations) to Equation 27. The facility wide
emission factor in Equation 28 will be calculated by using the total volumetric
GHG emissions at standard conditions for all equipment leak sources calculated
in Equation 26 and the count of meter/regulator runs located at above grade
transmission-distribution transfer stations that were monitored over the years
that constitute one complete cycle as per (p)(1) of this section. A meter on a
regulator run is considered one meter regulator run. Facility operators that do
not have above grade T-D transfer stations shall report a count of above grade
metering-regulating stations only and do not have to comply with section
95157(c)(16)(T).
|
EF =
Es,i/(8760 * Count) |
(Eq. 28) |
Where:
EF = Facility emission factor for a meter/regulator run
per component type at above grade meter/regulator run for GHGi in cubic feet
per meter/regulator run per hour.
Es,i = Annual volumetric
GHGi emissions, CO2 or
CH4, at standard condition from each component type at
all above grade T-D transfer stations, from Equation 26.
Count = Total number of meter/regulator runs at all T-D
transfer stations that were monitored over the years that constitute one
complete cycle as per paragraph (o)(8)(A) of this section.
8760 = Conversion to hourly emissions (use 8784 for a
leap year).
(q)
Offshore petroleum and natural
gas production facilities. Operators must report
CO
2, CH
4, and
N
2O emissions for offshore petroleum and natural gas
production from all equipment leaks, vented emission, and flare emission source
types as identified in the data collection and emissions estimate study
(
Year 2008 Gulfwide Emission Inventory Study (GOADS) (December
2010)) conducted by BOEMRE in compliance with
30 CFR §§
250.302 through
304 (July 1, 2011), which is
hereby incorporated by reference.
(1)
Offshore production facilities under BOEMRE jurisdiction must report the same
annual emissions as calculated and reported by BOEMRE in data collection and
emissions estimate study published by BOEMRE and referenced in
30 CFR §§
250.302 through
304 (July 1, 2011) Gulfwide
Offshore Activities Data System (GOADS).
(A)
The BOEMRE data is collected and reported every other year. In years where the
BOEMRE data is not available, use the previous year's BOEMRE data and adjust
the emissions based on the operating time for the facility relative to the
operating time in the previous year's BOEMRE data.
(2) Offshore production facilities that are
not under BOEMRE jurisdiction must use monitoring methods and calculation
methodologies published by BOEMRE and referenced in
30 CFR §§
250.302 through
304 (July 1, 2011) to calculate
and report emissions (GOADS).
(A) The BOEMRE
data is collected and reported every other year. In years where the BOEMRE data
is not available, use the previous year's BOEMRE data and adjust the emissions
based on the operating time for the facility relative to the operating time in
the previous year's BOEMRE data.
(3) If BOEMRE discontinues or delays their
data collection effort by more than 4 years, then offshore operators must once
in every 4 years use the most recent BOEMRE data collection and emissions
estimation methods to report emission from the facility sources.
(4) For either the first or subsequent year
of reporting, offshore facilities either within or outside of BOEMRE
jurisdiction that were not covered in the previous BOEMRE data collection cycle
must use the BOEMRE data collection and emissions estimation methods published
by BOEMRE and referenced in 30 CFR §§
250.302
through
304 (July 1, 2011) (GOADS) to
calculate and report.
(r)
Volumetric emissions. If equation parameters in section
95153 are already at standard
conditions, which results in volumetric emissions at standard conditions, then
this paragraph does not apply. Calculate volumetric emissions at standard
conditions as specified in paragraphs (r)(1) or (2) of this section, with
actual pressure and temperature determined by engineering estimates based on
best available data unless otherwise specified.
(1) Calculate natural gas volumetric
emissions at standard conditions using actual natural gas emission temperature
and pressure, and Equation 29 of this section.
|
Es,n =
Ea,n * (459.67 + Ts) *
Pa/((459.67 + Ta) *
Ps) |
(Eq. 29) |
Where:
Es,n = Natural gas volumetric
emissions at standard temperature and pressure (STP) conditions in cubic feet
except Es,n equals (FRs,p) for
each well p, when calculating either subsonic or sonic flow rates under section
95153(f).
Ea,n = Natural gas volumetric
emissions at actual conditions in cubic feet.
Ts = Temperature at standard
conditions (60°F).
Ta = Temperature at actual
conditions (°F).
Ps = Absolute pressure at
standard conditions (14.7 psia).
Pa = Absolute pressure at actual
conditions (psia).
(2)
Calculate GHG volumetric emissions at standard conditions using actual GHG
emissions temperature and pressure, and Equation 30 of this section.
|
Es,i =
Ea,i * (459.67 + Ts) *
Pa/((459.67 +
Ta) *
Ps) |
(Eq. 30) |
Where:
Es,i = GHG i volumetric
emissions at standard conditions in cubic feet.
Ea,i = GHG i volumetric
emissions at actual conditions in cubic feet.
Ts = Temperature at standard
conditions (60°F).
Ps = Absolute pressure at
standard conditions (14.7 psia).
Pa = Absolute pressure at actual
conditions (Psia).
(3)
Facility operators using 68°F for standard temperature may use the ratio
519.67/527.67 to convert volumetric emissions from 68°F to
60°F.
(s)
GHG
volumetric emissions. Calculate GHG volumetric emissions at standard
conditions as specified in paragraphs (s)(1) and (s)(2) of this section, with
mole fraction of GHGs in the natural gas determined by engineering estimate
based on best available data unless otherwise specified.
(1) Estimate CH
4 and
CO
2 emissions from natural gas emissions using Equation
31 of this section.
|
Es,i =
Es,n * Mi |
(Eq.
31) |
Where:
Es,i = GHG i (either
CH4 or CO2) volumetric emissions
at standard conditions in cubic feet.
Es,n = Natural gas volumetric
emissions at standard conditions in cubic feet.
Mi = Mole fraction of GHG i in
the natural gas.
(2) For
Equation 31 of this section, the mole fraction, M
i, must
be the annual average mole fraction for each basin or facility, as specified in
paragraphs (s)(2)(A) through (s)(2)(G) of this section.
(A) GHG mole fraction in produced pipeline
quality natural gas for onshore petroleum and natural gas production
facilities. If the facility has a continuous gas composition analyzer for
produced natural gas, the facility operator must use an annual average of these
values for determining the mole fraction. If the facility does not have a
continuous gas composition analyzer, then it must use an annual average gas
composition based on the most recent available analysis of the
facility.
(B) GHG mole fraction in
feed natural gas for all emissions sources upstream of the de-methanizer or dew
point control and GHG mole fraction in facility specific residue gas to
transmission pipeline system for all emissions sources downstream of the
de-methanizer overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely fractionate a
liquid stream, use the GHG mole percent in feed natural gas liquid for all
streams. If the facility has a continuous gas composition analyzer on feed
natural gas, the facility operator must use these values for determining the
mole fraction. If the facility does not have a continuous gas composition
analyzer, then annual samples must be taken according to methods set forth in
section
95154(b).
(C) GHG mole fraction in transmission
pipeline natural gas that passes through the facility for the onshore natural
gas transmission compression industry segment. If the facility has a continuous
gas composition analyzer, the facility operator must use these values for
determining the mole fraction. If the facility does not have a continuous gas
composition analyzer, then annual samples must be taken according to methods
set forth in section
95154(b).
(D) GHG mole fraction in natural gas stored
in the underground natural gas storage industry segment. If the facility has a
continuous gas composition analyzer, the facility operator must use these
values for determining the mole fraction. If the facility does not have a
continuous gas composition analyzer, then annual samples must be taken
according to methods set forth in section
95154(b).
(E) GHG mole fraction in natural gas stored
in the LNG storage industry segment. If the facility has a continuous gas
composition analyzer, the facility operator must use these values for
determining the mole fraction. If the facility does not have a continuous gas
composition analyzer, then annual samples must be taken according to methods
set forth in section
95154(b).
(F) GHG mole fraction in natural gas stored
in the LNG import and export industry segment. If the facility has a continuous
gas composition analyzer, the facility operator must use these values for
determining the mole fraction. If the facility does not have a continuous gas
composition analyzer, then annual samples must be taken according to methods
set forth in section
95154(b).
(G) GHG mole fraction in local distribution
pipeline natural gas that passes through the facility for natural gas
distribution facilities. If the facility has a continuous gas composition
analyzer, the facility operator must use these values for determining the mole
fraction. If the facility does not have a continuous gas composition analyzer,
then annual samples must be taken according to methods set forth in section
95154(b).
(t)
GHG mass emissions.
Calculate GHG mass emissions by converting the GHG volumetric emissions at
standard conditions into mass emissions using Equation 32 of this section.
|
Massi =
Es,i * [RHO]i*
10-3 |
(Eq. 32) |
Where:
Massi =
GHGi (either CH4,
CO2, or N2O) mass emissions in
metric tons GHGi.
Es,i =
GHGi (either CH4,
CO2, or N2O) volumetric emissions
at standard conditions, in cubic feet.
Pi = Density of
GHGi. Use 0.0526 kg/ft3 for
CO2 and N2O, and 0.0192
kg/ft3 for CH4 at 60°F
and 14.7 psia.
(u)
EOR injection pump blowdown. Calculate
CO
2 pump blowdown emissions from EOR operations using
critical CO
2 injection as follows:
|
MassCO2
= N * Vv * Rc *
GHGi *
10-3 |
(Eq. 33) |
Where:
MassCO2 = Annual EOR injection
gas venting emissions in metric tons from blowdowns.
N = Number of blowdowns for the equipment in the
calendar year.
Rc = Density of critical phase
EOR injection gas in kg/ft3. The facility operator
may use an appropriate standard method published by published by a consensus
based organization if such a method exists or the facility operator may use an
industry standard practice to determine density of super-critical
emissions.
Vv = Total volume in cubic feet
of blowdown equipment chambers (including pipelines, manifolds and vessels)
between isolation valves.
GHGi = Mass fraction of
GHGi in critical phase injection gas.
1x 10-3 = Conversion factor
from kilograms to metric tons.
(v)
Crude Oil, Condensate, and
Produced Water Dissolved CO2 and
CH
4. The operator must calculate dissolved
CO
2 and CH
4 in crude oil,
condensate, and produced water. This reporting requirement includes emissions
from hydrocarbon liquids and water produced using EOR operations. Emissions
must be reported for crude oil, condensate, and produced water sent to storage
tanks, ponds, and holding facilities. The facility operator must also report
the volume of produced water in barrels per year.
(1) Calculate CO
2 and
CH
4 emissions from crude oil, condensate, and produced
water using Equation 33A:
|
ECO2/CH4
= (S * V)(1 - (VR * CE)) |
(Eq. 33A) |
Where:
ECO2/CH4 = Annual
CO2 or CH4 emissions in metric
tons.
S = Mass of CO2 or
CH4 liberated in a flash liberation test per barrel of
crude oil, condensate, and produced water (as determined in paragraph
(v)(1)(A)1. or mass of CO2 or CH4
recovered in a vapor recovery system per barrel of crude oil, condensate, or
produced water (as determined in paragraph (v)(1)(A)2.
V = Barrels of crude oil, condensate, or produced water
sent to tanks, ponds, or holding facilities annually.
VR = Percentage of time the vapor recovery unit was
operational (expressed as a decimal).
CE = Collection efficiency of the vapor recovery system
(expressed as a decimal).
(A) S (the
mass of CO
2 or CH
4 per barrel of
crude oil, condensate, or produced water) shall be determined using one of the
following methods:
1. Flash liberation test.
Measure the amount of CO2 and CH4
liberated from crude oil, condensate, or produced water when the crude oil,
condensate, or produced water changes temperature and pressure from well stream
to standard atmospheric conditions, using ARB's sampling methodology and flash
liberation test procedure entitled "Flash Emissions of Greenhouse Gases and
Other Compounds from Crude Oil and Natural Gas Separator and Tank Systems,"
which is included as Appendix B of this article. The flash liberation test
results must provide the metric tons of CO2 and
CH4 liberated per barrel of crude oil, condensate, or
produced water. The test results from the flash liberation test must be
submitted to ARB as part of the emissions data report. When required to
quantify emissions, flash liberation test samples must be collected at least
annually. Flash liberation test samples may be collected from a single
location/separator system, or from multiple locations; however, the sample(s)
must be reasonably representative of the liquids to which the results are
applied. A sufficient number of samples must be collected to reasonably
represent the ratio of gas-to-oil, water, and condensate that are separated at
multiple locations within a facility.
2. Vapor recovery system method. For storage
tank systems connected to a vapor recovery system, calculate the mass of
CO
2 and CH
4 liberated from crude
oil, condensate, or produced water as follows:
a. Measure the annual gas stream volume
captured by the vapor recovery system.
b. Calculate the annual mass of
CO2 and CH4 in the gas stream
using the gas stream volume and mole percentage of CO2
and CH4 as determined by a laboratory analysis of an
annual gas stream sample.
c.
Calculate S by dividing the total mass of CO2 and
CH4 in the gas stream by the total volume, in barrels,
of the crude oil, condensate, or produced water throughput of the storage tank
system.
d. Vapor recovery system
measurements and analyses may include gases from crude oil, condensate, and
produced water.
e. The vapor
recovery system method is included in Appendix B.
(B) Emissions resulting from the destruction
of the vapor recovery system gas stream shall be reported using the Flare Stack
reporting provisions in paragraph (l) of this
section.
(2) EOR
operations that route produced water from separation directly to re-injection
into the hydrocarbon reservoir are exempt from paragraph (v) of this
section.
(w)
Pipeline dig-ins. For reporting pipeline dig-in emissions as
specified in section
95152(i)(11),
operators may either use measured data or use engineering estimation based on
best available data to quantify the volume of natural gas released from
pipeline dig-in events. Volumetric emissions must be converted into mass
emissions of CO
2 and CH
4 using
the applicable methods in paragraphs (r), (s), and (t) of this section. If the
natural gas escaping from a pipeline dig-in ignites, the operator is not
required to quantify and report the GHG emissions from the combustion of the
escaping gas.
(x)
Reserved
(y)
Onshore petroleum and natural gas production and natural gas
distribution combustion emissions. Calculate
CO
2, CH
4, and
N
2O combustion-related emissions from stationary or
portable equipment, except as specified in paragraph (y)(3) and (y)(4) of this
section as follows:
(1) If a fuel combusted in
the stationary or portable equipment is listed in Table C-1 of Subpart C of 40
CFR Part
98 , or is a blend completely consisting of one or more fuels listed
in Table C-1, calculate emissions according to paragraph (y)(1)(A). If the fuel
combusted is natural gas and is of pipeline quality specification, use the
calculation methodology described in paragraph (y)(1)(A) and the facility
operator may use the emission factor provided for natural gas as listed in
Subpart C, Table C-1. If the fuel is natural gas, and is not pipeline quality
calculate emissions according to paragraph (y)(2). The operator must use the
appropriate gas composition for each stream of hydrocarbon going to the
combustion unit as specified in paragraph (s)(2) of this section. If the fuel
is field gas, process vent gas, or a blend containing field gas or process vent
gas, calculate emissions according to paragraph (y)(2).
(A) For fuels listed in Table C-1 or a blend
completely consisting of one or more fuels listed in Table C-1 of Subpart C,
calculate CO
2, CH
4, and
N
2O emissions according to any Tier listed in section
95115.
(2) For fuel combustion units that combust
field gas, process vent gas, a blend containing field gas or process vent gas,
or natural gas that is not of pipeline quality, calculate combustion emissions
as specified below:
(A) The operator may use
company records, which includes the common pipe method, to determine the volume
of fuel combusted in the unit during the reporting year.
(B) If a continuous gas composition analyzer
is installed and operational on fuel supply to the combustion unit, the
operator must use these compositions for determining the concentration of gas
hydrocarbon constituent in the flow of gas to the unit. If a continuous gas
composition analyzer is not installed on gas to the combustion unit, the
facility operator must use the appropriate gas compositions for each stream of
hydrocarbons going to the combustion unit.
(C) Calculate GHG volumetric emissions at
actual conditions using Equations 35 and 36 of this section:
Click
here to view image
Eq. 35)
Click
here to view image
Eq. 36)
Where:
Ea,CO2 = Contribution of annual
CO2 emissions from portable or stationary fuel
combustion sources in cubic feet, under actual conditions.
Va = Volume of fuel gas sent to
combustion unit in cubic feet, during the month.
YCO2 = Monthly concentration of
CO2 constituent in gas sent to combustion unit.
Ea,CH4 = Contribution of annual
CH4 emissions from portable or stationary fuel
combustion sources in cubic feet, under actual conditions.
η= Fraction of gas combusted for portable
and stationary equipment. A default value of 0.995 can be used for all internal
and external combustion devices. The operator may use an alternative
engineering estimation value based on chemical analysis data,
equipment-specific specifications, or industry standard references
demonstrating the combustion efficiency of the unit type (e.g. boiler, heater,
etc.).
Yj = Monthly concentration of
gas hydrocarbon constituent j (such as methane, ethane, propane, butane and
pentanes plus) in gas sent to combustion unit.
Rj = Number of carbon atoms in
the gas hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for propane,
4 for butane, and 5 for pentanes plus, in gas sent to combustion unit.
YCH4 = Monthly concentration of
methane constituent in gas sent to combustion unit.
n = Month of the year
Calculate CO2 and
CH4, volumetric emissions at standard conditions using
the provisions of section
95153(r). Use the
provisions in sections
95153(s) and (t)
to convert volumetric gas emissions to GHG volumetric and GHG mass emissions
respectively.
(D) Calculate
N
2O mass emissions using Equation 37 of this section.
|
MassN2O =
(1 x 10-3) * Fuel * HHV * EF |
(Eq.
37) |
Where:
MassN2O = Annual
N2O emissions from the combustion of a particular type
of fuel (metric tons N2O).
Fuel = Mass or volume of the fuel combusted (mass or
volume per year, choose appropriately to be consistent with the units of
HHV).
HHV = For the higher heating value for field gas or
process vent gas, use either a weighted average of measurements of HHV or a
default value of 1.235 x 10-3 MMBtu/scf for HHV.
Samples must be collected once during each three-month period of the calendar
year, with at least 30 days between successive samples.
EF = Use 1.0 x 10-4 kg
N2O/MMBtu.
1 x 10-3 = Conversion factor
from kilograms to metric tons.
(3) External fuel combustion sources with a
rated heat capacity equal to or less than 5 MMBtu/hr do not need to report
combustion emissions or include these emissions for threshold determination in
section
95101(e). The
operator must report the type and number of each external fuel combustion
unit.
(4) Internal fuel combustion
sources, not compressor-drivers, with a rated heat capacity equal to or less
than 1 MMBtu/hr (or equivalent of 130 horsepower), do not need to report
combustion emissions or include these emissions for threshold determination in
section
95101(e). The
operator must report the type and number of each internal fuel combustion
unit.
(5) If the chemical reaction
between the acid gas and the sorbent produces CO
2
emissions, when a unit is a fluidized bed boiler, is equipped with a wet flue
gas desulfurization system, or uses other acid gas emission controls with
sorbent injection to remove acid gases, calculate sorbent
CO
2 emissions using the methods found in §
98.33(d). This
calculation method is not required when the CO
2
emissions are monitored by CEMS.