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 CH4 and CO2 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 CH4 and CO2 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 CO2 only (not CH4) 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 CO2 concentration monitor and volumetric flow rate meter, they must calculate CO2 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 CO2 concentration monitor and volumetric flow rate monitor are not available, the operator may elect to install a CO2 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 CH4 and N2O 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 CO2 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 CO2 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 VolCO2 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 VolI 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 CO2 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 VolO 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 CH4, CO2, and N2O 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 CH4 and CO2 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).(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 CO2 and CH4 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 CH4, CO2 and N2O (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 CO2 or N2: | 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 (P1) and downstream (P2) 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 (Tu, P1, P2, 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 CO2 and N2 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 CO2 or N2 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 CO2 and CH4 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 CH4, CO2 and N2O (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 CH4, CO2 and N2O (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 CO2, CH4 and N2O 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 CO2 concentration monitor and volumetric flow rate monitor, calculate only CO2 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 CO2 concentration monitor and volumetric flow rate monitor are not available, the facility operator may elect to install a CO2 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, Va, in these equations.(m)Centrifugal compressor venting. Calculate CH4, CO2 and N2O (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 CH4 and CO2, and N2O (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 CH4 plus CO2 by weight. Component types 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 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 GHGi volume emissions to GHGi 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 CO2 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 CO2, CH4, and N2O 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 CH4 and CO2 emissions from natural gas emissions using Equation 31 of this section. 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, Mi, 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 CO2 pump blowdown emissions from EOR operations using critical CO2 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 CH4. The operator must calculate dissolved CO2 and CH4 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 CO2 and CH4 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 CO2 or CH4 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 CO2 and CH4 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 CO2 and CH4 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.(y)Onshore petroleum and natural gas production and natural gas distribution combustion emissions. Calculate CO2, CH4, and N2O 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 CO2, CH4, and N2O 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 N2O 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 CO2 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 CO2 emissions using the methods found in §98.33(d). This calculation method is not required when the CO2 emissions are monitored by CEMS.Cal. Code Regs. Tit. 17, § 95153
1. New section filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
2. Repealer and new section filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
3. Redesignation of subsections (c)(7)1.-3. as subsections (c)(7)(A)-(C), amendment of subsections (f), (f)(1) and (k)(2)(A), redesignation of subsection (m)(1)(D) as subsection (m)(1)(C)2. and amendment of subsections (m)(3), (o), (o)(8)(A), (p), (p)(6)(B), (u), (v) and (v)(1)(A)1., new subsection (v)(1)(A)2.e. and amendment of subsections (y)(1)-(4) filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
4. Amendment filed 12-31-2014; operative 1-1-2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
5. Amendment filed 9-1-2017; operative 1-1-2018 (Register 2017, No. 35).
6. Amendment of subsections (b), (p) and (p)(6)(B) filed 3-29-2019; operative 4-1-2019 pursuant to Government Code section 11343.4(b)(3) (Register 2019, No. 13). Note: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health and Safety Code.
1. New section filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
2. Repealer and new section filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
3. Redesignation of subsections (c)(7)1.-3. as subsections (c)(7)(A)-(C), amendment of subsections (f), (f)(1) and (k)(2)(A), redesignation of subsection (m)(1)(D) as subsection (m)(1)(C)2. and amendment of subsections (m)(3), (o), (o)(8)(A), (p), (p)(6)(B), (u), (v) and (v)(1)(A)1., new subsection (v)(1)(A)2.e. and amendment of subsections (y)(1)-(4) filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
4. Amendment filed 12-31-2014; operative 1/1/2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
5. Amendment filed 9-1-2017; operative 1/1/2018 (Register 2017, No. 35).
6. Amendment of subsections (b), (p) and (p)(6)(B) filed 3-29-2019; operative 4/1/2019 pursuant to Government Code section 11343.4(b)(3) (Register 2019, No. 13).