§ 98.233 Calculating GHG emissions.
You must calculate and report the annual GHG emissions as prescribed in this section. For calculations that specify measurements in actual conditions, reporters may use a flow or volume measurement system that corrects to standard conditions and determine the flow or volume at standard conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section.
(a) Natural gas pneumatic device venting. Calculate CH4 and CO2 volumetric emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W–1 of this section.
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Where:
(1) For all industry segments, determine “Countt” for Equation W–1 of this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the devices, except as specified in paragraph (a)(2) of this section. The reported number of devices must represent the total number of devices for the reporting year.
(2) For the onshore petroleum and natural gas production industry segment, you have the option in the first two consecutive calendar years to determine “Countt” for Equation W–1 of this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best available data. For the onshore petroleum and natural gas gathering and boosting industry segment, you have the option in the first two consecutive calendar years to determine “Countt” for Equation W–1 for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best available data.
(3) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information.
(4) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(b) [Reserved]
(c) Natural gas driven pneumatic pump venting. (1) Calculate CH4 and CO2 volumetric emissions from natural gas driven pneumatic pump venting using Equation W–2 of this section. Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under this paragraph (c).
![er25no14.059.gif](/sites/default/files/inline-images/er25no14.059.gif)
Where:
(2) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(d) Acid gas removal (AGR) vents. For AGR vents (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), 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 any of the calculation methods described in this paragraph (d), as applicable.
(1) Calculation Method 1. If you operate and maintain a continuous emissions monitoring system (CEMS) that has both a CO2 concentration monitor and volumetric flow rate monitor, you must calculate CO2 emissions under this subpart by following the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may follow the manufacturer's instructions or industry standard practice. If a CO2 concentration monitor and volumetric flow rate monitor are not available, you 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 Method in subpart C of this part (General Stationary Fuel Combustion Sources). The calculation and reporting of CH4 and N2O emissions is not required as part of the Tier 4 requirements for AGR units.
(2) Calculation Method 2. If a CEMS is not available but a vent meter is installed, use the CO2 composition and annual volume of vent gas to calculate emissions using Equation W–3 of this section.
![er25no14.060.gif](/sites/default/files/inline-images/er25no14.060.gif)
Where:
(3) Calculation Method 3. If a CEMS or a vent meter is not installed, you may use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO2 using Equations W–4A or W–4B of this section. If inlet gas flow rate is known, use Equation W–4A. If outlet gas flow rate is known, use Equation W–4B.
![er25no14.027.gif](/sites/default/files/inline-images/er25no14.027.gif)
Where:
(4) Calculation Method 4. If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software package, such as AspenTech HYSYS®, or API 4679 AMINECalc, that uses the Peng-Robinson equation of state and speciates CO2 emissions. A minimum of the following, determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best available data, must be used to characterize emissions:
(i) Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii) Acid gas content of outlet natural gas.
(iv) Unit operating hours, excluding downtime for maintenance or standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature, circulation rate, and weight.
(5) For Calculation Method 3, determine the gas flow rate of the inlet when using Equation W–4A of this section or the gas flow rate of the outlet when using Equation W–4B of this section for the natural gas stream of an AGR unit using a meter according to methods set forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate.
(6) For Calculation Method 2, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream for each quarter that the AGR unit is operating to determine VolCO2 in Equation W–3 of this section, according to the methods set forth in § 98.234(b).
(7) For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream for each quarter that the AGR unit is operating to determine VolI in Equation W–4A or W–4B of this section, according to the methods set forth in § 98.234(b).
(8) For Calculation Method 3, determine annual average volumetric fraction of CO2 content in natural gas flowing out of the AGR unit using one of the methods specified in paragraphs (d)(8)(i) through (d)(8)(iii) of this section.
(i) 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, you may install a continuous gas analyzer.
(ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream for each quarter that the AGR unit is operating to determine VolO in Equation W–4A or W–4B of this section, according to the methods set forth in § 98.234(b).
(iii) If a continuous gas analyzer is not available or installed, you may use the outlet pipeline quality specification for CO2 in natural gas.
(9) Calculate annual volumetric CO2 emissions at standard conditions using calculations in paragraph (t) of this section.
(10) Calculate annual mass CO2 emissions using calculations in paragraph (v) of this section.
(11) Determine if CO2 emissions from the AGR unit are recovered and transferred outside the facility. Adjust the CO2 emissions estimated in paragraphs (d)(1) through (d)(10) of this section downward by the magnitude of CO2 emissions recovered and transferred outside the facility.
(e) Dehydrator vents. For dehydrator vents, calculate annual CH4 and CO2 emissions using the applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this section. If emissions from dehydrator vents are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (e)(5) of this section. If emissions from dehydrator vents are routed to a flare or regenerator fire-box/fire tubes, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (e)(6) of this section.
(1) Calculation Method 1. Calculate annual mass emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a software program, such as AspenTech HYSYS® or GRI–GLYCalc TM, that uses the Peng-Robinson equation of state 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. The following parameters must be determined by engineering estimate based on best available data and must be used at a minimum to characterize emissions from dehydrators:
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (e.g., natural gas pneumatic/air pneumatic/electric).
(v) Absorbent circulation rate.
(vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG)).
(vii) Use of stripping gas.
(viii) Use of flash tank separator (and disposition of recovered gas).
(ix) Hours operated.
(x) Wet natural gas temperature and pressure.
(xi) Wet natural gas composition. Determine this parameter using one of the methods described in paragraphs (e)(1)(xi)(A) through (D) of this section.
(A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or (ii) of this section.
(B) If the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (ii) of this section, select a representative analysis.
(C) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition.
(D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated.
(2) Calculation Method 2. Calculate annual volumetric emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day using Equation W–5 of this section:
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Where:
(3) Calculation Method 3. For dehydrators of any size that use desiccant, you must calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation W–6 of this section. Desiccant dehydrator emissions covered in this paragraph do not have to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
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Where:
(4) For glycol dehydrators that use the calculation method in paragraph (e)(2) of this section, calculate both CH4 and CO2 mass emissions from volumetric GHGi emissions using calculations in paragraph (v) of this section. For desiccant dehydrators that use the calculation method in paragraph (e)(3) of this section, calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
(5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1), (2), and (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows:
(i) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) through (5) of this section, as applicable.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent.
(f) Well venting for liquids unloadings. Calculate annual volumetric natural gas emissions from well venting for liquids unloading using one of the calculation methods described in paragraphs (f)(1), (2), or (3) of this section. Calculate annual CH4 and CO2 volumetric and mass emissions using the method described in paragraph (f)(4) of this section.
(1) Calculation Method 1. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. For at least one well of each unique well tubing diameter group and pressure group combination in each sub-basin category (see § 98.238 for the definitions of tubing diameter group, pressure group, and sub-basin category), where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, install a recording flow meter on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate the total emissions from well venting to the atmosphere for liquids unloading using Equation W–7A of this section. For any tubing diameter group and pressure group combination in a sub-basin where liquids unloading occurs both with and without plunger lifts, Equation W–7A will be used twice, once for wells with plunger lifts and once for wells without plunger lifts.
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Where:
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(i) Determine the well vent average flow rate (“FR” in Equation W–7A of this section) as specified in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub-basin category. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately.
(A) Calculate the average flow rate per hour of venting for each unique tubing diameter group and pressure group combination in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere.
(B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this section to all wells in the same pressure group that have the same tubing diameter group, for the number of hours of venting these wells.
(C) Calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in the first year of production.
(ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(2) Calculation Method 2. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading without plunger lift assist using Equation W–8 of this section.
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Where:
(3) Calculation Method 3. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W–9 of this section.
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(4) Calculate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section.
(g) Well venting during completions and workovers with hydraulic fracturing. Calculate annual volumetric natural gas emissions from gas well and oil well venting during completions and workovers involving hydraulic fracturing using Equation W–10A or Equation W–10B of this section. Equation W–10A applies to well venting when the gas flowback rate is measured from a specified number of example completions or workovers and Equation W–10B applies when the gas flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two periods, an initial period when flowback is routed to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use Equation W–10A, you must follow the procedures specified in paragraph (g)(1). If you elect to use Equation W–10B, you must use a recording flow meter installed on the vent line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback. For either equation, emissions must be calculated separately for completions and workovers, for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this section. You must calculate CH4 and CO2 volumetric and mass emissions as specified in paragraph (g)(3) of this section. If emissions from well venting during completions and workovers with hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (g)(4) of this section.
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(1) If you elect to use Equation W–10A of this section on gas wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRMs and FRMi. If you elect to use Equation W–10A of this section on oil wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) to determine the value of FRMs and FRMi. These values must be based on the flow rate for flowback gases, once sufficient gas is present to enable separation. The number of measurements or calculations required to estimate FRMs and FRMi must be determined individually for completions and workovers per sub-basin and well type combination as follows: Complete measurements or calculations for at least one completion or workover for less than or equal to 25 completions or workovers for each well type combination within a sub-basin; complete measurements or calculations for at least two completions or workovers for 26 to 50 completions or workovers for each sub-basin and well type combination; complete measurements or calculations for at least three completions or workovers for 51 to 100 completions or workovers for each sub-basin and well type combination; complete measurements or calculations for at least four completions or workovers for 101 to 250 completions or workovers for each sub-basin and well type combination; and complete measurements or calculations for at least five completions or workovers for greater than 250 completions or workovers for each sub-basin and well type combination.
(i) Calculation Method 1. You must use Equation W–12A of this section as specified in paragraph (g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W–12B of this section as specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The procedures specified in paragraphs (g)(1)(v) and (vi) of this section also apply. When making gas flowback measurements for use in Equations W–12A and W–12B of this section, you must use a recording flow meter (digital or analog) installed on the vent line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback rates in units of standard cubic feet per hour according to methods set forth in § 98.234(b).
(ii) Calculation Method 2 (for gas wells). You must use Equation W–12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W–12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The procedures specified in paragraphs (g)(1)(v) and (vi) also apply. When calculating the flowback rates for use in Equations W–12A and W–12B of this section based on well parameters, you must record the well flowing pressure immediately upstream (and immediately downstream in subsonic flow) of a well choke according to methods set forth in § 98.234(b) to calculate the well flowback. The upstream pressure must be surface pressure and reservoir pressure cannot be assumed. The downstream pressure must be measured after the choke and atmospheric pressure cannot be assumed. Calculate flowback rate using Equation W–11A of this section for subsonic flow or Equation W–11B of this section for sonic flow. You must use best engineering estimates based on best available data along with Equation W–11C of this section to determine whether the predominant flow is sonic or subsonic. If the value of R in Equation W–11C of this section is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FRa values from actual conditions upstream of the restriction orifice to standard conditions (FRs,p and FRi,p) for use in Equations W–12A and W–12B of this section using Equation W–33 in paragraph (t) of this section.