Title 40—Protection of Environment--Volume 1
PART 98—MANDATORY GREENHOUSE GAS REPORTING
§ 98.236   Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 for data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions rather than the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure.
(a) The annual report must include the information specified in paragraphs (a)(1) through (10) of this section for each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of each GHG, for each applicable industry segment listed in paragraphs (a)(1) through (10) of this section, and each applicable emission source listed in paragraphs (b) through (z), (dd) and (ee) of this section.
(1) Onshore petroleum and natural gas production. For the equipment/activities specified in paragraphs (a)(1)(i) through (xxii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section.
(iii) Acid gas removal units and nitrogen removal units. Report the information specified in paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e) of this section.
(v) Liquids unloading. Report the information specified in paragraph (f) of this section.
(vi) Completions and workovers with hydraulic fracturing. Report the information specified in paragraph (g) of this section.
(vii) Completions and workovers without hydraulic fracturing. Report the information specified in paragraph (h) of this section.
(viii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(ix) Hydrocarbon liquids and produced water storage tanks. Report the information specified in paragraph (j) of this section.
(x) Well testing. Report the information specified in paragraph (l) of this section.
(xi) Associated natural gas. Report the information specified in paragraph (m) of this section.
(xii) Flare stacks. Report the information specified in paragraph (n) of this section.
(xiii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(xiv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(xv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(xvi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(xvii) EOR injection pumps. Report the information specified in paragraph (w) of this section.
(xviii) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this section.
(xix) Other large release events. Report the information specified in paragraph (y) of this section.
(xx) Combustion equipment. Report the information specified in paragraph (z) of this section.
(xxi) Drilling mud degassing. Report the information specified in paragraph (dd) of this section.
(xxii) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(2) Offshore petroleum and natural gas production. For the equipment/activities specified in paragraphs (a)(2)(i) and (ii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) of this section.
(ii) Other large release events. Report the information specified in paragraph (y) of this section.
(3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Acid gas removal units and nitrogen removal units. Report the information specified in paragraph (d) of this section.
(iii) Dehydrators. Report the information specified in paragraph (e) of this section.
(iv) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(v) Hydrocarbon liquids and produced water storage tanks. Report the information specified in paragraph (j) of this section.
(vi) Flare stacks. Report the information specified in paragraph (n) of this section.
(vii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(viii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(ix) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(x) Other large release events. Report the information specified in paragraph (y) of this section.
(xi) Crankcase vents. Report the information specified in paragraph (ee) of this section.
(4) Onshore natural gas transmission compression. For the equipment/activities specified in paragraphs (a)(4)(i) through (x) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Dehydrators. Report the information specified in paragraph (e) of this section.
(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iv) Condensate storage tanks. Report the information specified in paragraph (k) of this section.
(v) Flare stacks. Report the information specified in paragraph (n) of this section.
(vi) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(vii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(viii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(ix) Other large release events. Report the information specified in paragraph (y) of this section.
(x) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Dehydrators. Report the information specified in paragraph (e) of this section.
(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iv) Condensate storage tanks. Report the information specified in paragraph (k) of this section.
(v) Flare stacks. Report the information specified in paragraph (n) of this section.
(vi) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(vii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(viii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(ix) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(x) Other large release events. Report the information specified in paragraph (y) of this section.
(xi) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through (ix) of this section, report the information specified in the applicable paragraphs of this section.
(i) Acid gas removal units and nitrogen removal units. Report the information specified in paragraph (d) of this section.
(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iii) Flare stacks. Report the information specified in paragraph (n) of this section.
(iv) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(v) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(vi) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(vii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(viii) Other large release events. Report the information specified in paragraph (y) of this section.
(ix) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(7) LNG import and export equipment. For the equipment/activities specified in paragraphs (a)(7)(i) through (ix) of this section, report the information specified in the applicable paragraphs of this section.
(i) Acid gas removal units and nitrogen removal units. Report the information specified in paragraph (d) of this section.
(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iii) Flare stacks. Report the information specified in paragraph (n) of this section.
(iv) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(v) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(vi) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(vii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(viii) Other large release events. Report the information specified in paragraph (y) of this section.
(ix) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(iv) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(v) Other large release events. Report the information specified in paragraph (y) of this section.
(vi) Combustion equipment. Report the information specified in paragraph (z) of this section.
(vii) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(9) Onshore petroleum and natural gas gathering and boosting. For the equipment/activities specified in paragraphs (a)(9)(i) through (xiv) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section.
(iii) Acid gas removal units and nitrogen removal units. Report the information specified in paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e) of this section.
(v) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(vi) Hydrocarbon liquids and produced water storage tanks. Report the information specified in paragraph (j) of this section.
(vii) Flare stacks. Report the information specified in paragraph (n) of this section.
(viii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(ix) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(x) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(xi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(xii) Other large release events. Report the information specified in paragraph (y) of this section.
(xiii) Combustion equipment. Report the information specified in paragraph (z) of this section.
(xiv) Crankcase vents. Reporting the information specified in paragraph (ee) of this section.
(10) Onshore natural gas transmission pipeline. For the equipment/activities specified in paragraphs (a)(10)(i) through (iii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(ii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(iii) Other large release events. Report the information specified in paragraph (y) of this section.
(b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (6) of this section, as applicable. You must report the information specified in paragraphs (b)(1) through (6) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production), each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
(1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) The number of natural gas pneumatic devices as specified in paragraphs (b)(2)(i) through (viii) of this section, as applicable. If a natural gas pneumatic device was vented directly to the atmosphere for part of the year and routed to a flare, combustion unit, or vapor recovery system during another part of the year, then include the device in each of the applicable counts specified in paragraphs (b)(2)(ii) through (vii) of this section.
(i) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed), determined according to § 98.233(a)(5) through (7).
(ii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere, determined according to § 98.233(a)(5) through (7).
(iii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) routed to a flare, combustion, or vapor recovery system.
(iv) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1).
(v) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2).
(vi) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3).
(vii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4).
(viii) If the reported values in paragraphs (b)(2)(i) through (vii) of this section are estimated values determined according to § 98.233(a)(6), then you must report the information specified in paragraphs (b)(2)(viii)(A) through (C) of this section.
(A) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are counted.
(B) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are estimated (not counted).
(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting.
(3) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1), report the information in paragraphs (b)(3)(i) through (vi) of this section for each measurement location.
(i) Unique measurement location identification number.
(ii) Type of flow monitor (volumetric flow monitor; mass flow monitor).
(iii) Number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) downstream of the flow monitor.
(iv) An indication of whether a natural gas driven pneumatic pump is also downstream of the flow monitor.
(v) Annual CO 2 emissions, in metric tons CO 2 , for the natural gas pneumatic devices calculated according to § 98.233(a)(1) for the measurement location.
(vi) Annual CH 4 emissions, in metric tons CH 4 , for the natural gas pneumatic devices calculated according to § 98.233(a)(1) for the measurement location.
(4) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2), report the information in paragraphs (b)(4)(i) through (ii) of this section, as applicable.
(i) For onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities:
(A) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).
(B) The average number of hours each type of the natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed) was in service ( i.e., supplied with natural gas) in the calendar year.
(C) Annual CO 2 emissions, in metric tons CO 2 , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
(D) Annual CH 4 emissions, in metric tons CH 4 , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
(ii) For onshore natural gas processing facilities, onshore natural gas transmission compression facilities, underground natural gas storage facilities, and natural gas distribution facilities:
(A) The number of years used in the current measurement cycle.
(B) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler) to measure the emissions from natural gas pneumatic devices at this facility.
(C) Indicate whether the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233.
(D) If the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233, report the following information for each type of natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed).
( 1 ) The value of the emission factor for the reporting year as calculated using equation W-1A to § 98.233 (in scf/hour/device).
( 2 ) The total number of natural gas pneumatic devices measured across all years upon which the emission factor is based ( i.e., the cumulative value of “Σ y =1 n Count t,y ” in equation W-1A to § 98.233).
( 3 ) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) ( i.e., “Count t ” in equation W-1B to § 98.233).
( 4 ) The average estimated number of hours in the operating year the natural gas pneumatic devices were in service ( i.e., supplied with natural gas) (“T t ” in equation W-1B to § 98.233).
(E) Annual CO 2 emissions, in metric tons CO 2 , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
(F) Annual CH 4 emissions, in metric tons CH 4 , cumulative by type of natural gas pneumatic device for which emissions were directly measured and calculated as specified in § 98.233(a)(2)(iii) through (viii).
(G) Annual CO 2 emissions, in metric tons CO 2 , cumulative by type of natural gas pneumatic device for which emissions were calculated according to § 98.233(a)(2)(ix). Enter 0 if all devices at this facility were monitored during the reporting year.
(H) Annual CH 4 emissions, in metric tons CH 4 , cumulative by type of natural gas pneumatic device for which emissions were calculated according to § 98.233(a)(2)(ix). Enter 0 if all devices at this facility were monitored during the reporting year.
(5) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3), report the information in paragraphs (b)(5)(i) through (iv) of this section.
(i) For continuous high bleed and continuous low bleed natural gas pneumatic devices:
(A) Indicate whether you measured emissions according to § 98.233(a)(3)(i)(A) or used default emission factors according to § 98.233(a)(3)(i)(B) to calculate emissions from your continuous high bleed and continuous low bleed natural gas pneumatic devices vented directly to the atmosphere at this well-pad site, gathering and boosting site, or facility, as applicable.
(B) If measurements were made according to § 98.233(a)(3)(i)(A), indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).
(C) If default emission factors were used according to § 98.233(a)(3)(i)(B) to calculate emissions, report the following information for each type of applicable natural gas pneumatic device (continuous low bleed and continuous high bleed).
(1) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) (“Count t ” in equation W-1B to § 98.233).
(2) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service ( i.e., supplied with natural gas) (“T t ” in equation W-1B to § 98.233).
(ii) For intermittent bleed natural gas pneumatic devices:
(A) Indicate the primary monitoring method used (OGI; Method 21 at 10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) and the number of complete monitoring surveys conducted at the well-pad site or gathering and boosting site.
(B) The total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“x” in equation W-1C to § 98.233).
(C) Average time the intermittent bleed natural gas pneumatic devices were in service ( i.e., supplied with natural gas) and assumed to be malfunctioning in the calendar year (average value of “T mal,z ” in equation W-1C to § 98.233).
(D) The total number of intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“Count” in equation W-1C to § 98.233).
(E) Average time the intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year were in service ( i.e., supplied with natural gas) during the calendar year (“T avg ” in equation W-1C to § 98.233).
(iii) Annual CO 2 emissions, in metric tons CO 2 , for each type of natural gas pneumatic device calculated according to Calculation Method 3 in § 98.233(a)(3).
(iv) Annual CH 4 emissions, in metric tons CH 4 , for each type of natural gas pneumatic device calculated according to Calculation Method 3 in § 98.233(a)(3).
(6) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4), report the following information for each type of applicable natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed).
(i) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) ( i.e., “Count t ” in equation W-1B to § 98.233).
(ii) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service ( i.e., supplied with natural gas) (“T t ” in equation W-1B to § 98.233).
(iii) Annual CO 2 emissions, in metric tons CO 2 , for each type of natural gas pneumatic device calculated according to Calculation Method 4 in § 98.233(a)(4).
(iv) Annual CH 4 emissions, in metric tons CH 4 , for each type of natural gas pneumatic device calculated according to Calculation Method 4 in § 98.233(a)(4).
(c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (5) of this section. You must report the information specified in paragraphs (c)(1) through (5) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production) and each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting).
(1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) The number of natural gas driven pneumatic pumps as specified in paragraphs (c)(2)(i) through (iv) of this section, as applicable. If a natural gas driven pneumatic pump was vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery system during another part of the year, then include the device in each of the applicable counts specified in paragraphs (c)(2)(ii) through (iv) of this section.
(i) The total number of natural gas driven pneumatic pumps.
(ii) The total number of natural gas driven pneumatic pumps vented directly to the atmosphere at any point during the year (including pumps that normally routed emissions to a flare but flow bypassed the flare for part of the year).
(iii) The total number of natural gas driven pneumatic pumps routed to a flare at any point during the year.
(iv) The total number of natural gas driven pneumatic pumps routed to combustion or a vapor recovery system at any point during the year.
(3) For natural gas driven pneumatic pumps for which vented emissions were calculated using Calculation Method 1 according to § 98.233(c)(1), report the information in paragraphs (c)(3)(i) through (vi) of this section for each measurement location.
(i) Unique measurement location identification number.
(ii) Type of flow monitor (volumetric flow monitor; mass flow monitor).
(iii) Number of natural gas driven pneumatic pumps downstream of the flow monitor.
(iv) An indication of whether any natural gas pneumatic devices are also downstream of the monitoring location.
(v) Annual CO 2 emissions, in metric tons CO 2 , for the pneumatic pump(s) calculated according to § 98.233(c)(1) for the measurement location.
(vi) Annual CH 4 emissions, in metric tons CH 4 , for the pneumatic pump(s) calculated according to § 98.233(c)(1) for the measurement location.
(4) If you used Calculation Method 2 according to § 98.233(c)(2) to calculate vented emissions, report the information in paragraphs (c)(4)(i) through (ix) of this section, as applicable.
(i) The number of years used in the current measurement cycle.
(ii) The total number of natural gas driven pneumatic pumps for which emissions were measured or calculated using Calculation Method 2.
(iii) Indicate whether the emissions from the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were measured during the reporting year or if the emissions were calculated using equation W-2B to § 98.233.
(iv) If the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were measured during the reporting year, indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler).
(v) If the emissions from natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were calculated using equation W-2B to § 98.233, report the following information:
(A) The value of the emission factor for the reporting year as calculated using equation W-2A to § 98.233 (in scf/hour/pump).
(B) The total number of natural gas driven pneumatic pumps measured across all years upon which the emission factor is based ( i.e. , the cumulative value of “ S y =1 n Count y ” term used in equation W-2A to § 98.233).
(C) Total number of natural gas driven pneumatic pumps that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(c)(1) or (c)(2)(iii) ( i.e. , “Count” in equation W-2B to § 98.233).
(D) The average estimated number of hours in the operating year the pumps were pumping liquid ( i.e. , “T” in equation W-2B to § 98.233).
(vi) Annual CO 2 emissions, in metric tons CO 2 , cumulative for all natural gas driven pneumatic pumps for which emissions were directly measured and calculated as specified in § 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none of the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site were measured during the reporting year.
(vii) Annual CH 4 emissions, in metric tons CH 4 , cumulative for all natural gas driven pneumatic pumps for which emissions were directly measured and calculated as specified in § 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none of the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site were measured during the reporting year.
(viii) Annual CO 2 emissions, in metric tons CO 2 , cumulative for all natural gas driven pneumatic pumps for which emissions were calculated according to § 98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site were measured during the reporting year.
(ix) Annual CH 4 emissions, in metric tons CH 4 , cumulative for all natural gas driven pneumatic pumps for which emissions were calculated according to § 98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site were measured during the reporting year.
(5) If you used Calculation Method 3 according to § 98.233(c)(3) to calculate vented emissions, report the information in paragraphs (c)(5)(i) through (iv) of this section for the natural gas driven pneumatic pumps subject to Calculation Method 3.
(i) Number of pumps that vent directly to the atmosphere ( i.e. , “Count” in equation W-2B to § 98.233).
(ii) Average estimated number of hours in the calendar year that natural gas driven pneumatic pumps that vented directly to atmosphere were pumping liquid (“T” in equation W-2B to § 98.233).
(iii) Annual CO 2 emissions, in metric tons CO 2 , for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(3).
(iv) Annual CH 4 emissions, in metric tons CH 4 , for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(3).
(d) Acid gas removal units and nitrogen removal units. You must indicate whether your facility has any acid gas removal units or nitrogen removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. For any acid gas removal units or nitrogen removal units that vent directly to the atmosphere or to a sulfur recovery plant, you must report the information specified in paragraphs (d)(1) and (2) of this section. If the acid gas removal units or nitrogen removal units that vent directly to the atmosphere for only part of the year, report the information specified in paragraph (d)(2) if this section for the part of the year that the units vent directly to the atmosphere. For acid gas removal units or nitrogen removal units that were routed to an engine or routed to a vapor recovery system for the entire year, you must only report the information specified in paragraphs (d)(1)(i) through (v) and (x) of this section. For acid gas removal units or nitrogen removal units that were routed to flares for which you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), you must report the information specified in paragraphs (d)(1)(i) through (v) and (x) of this section, as applicable. For acid gas removal units that were routed to flares for which you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(d) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (d)(1)(i) through (vii) and (x) of this section and paragraph (d)(2) of this section.
(1) You must report the information specified in paragraphs (d)(1)(i) through (xi) of this section for each acid gas removal unit or nitrogen removal unit, as applicable.
(i) A unique name or ID number for the acid gas removal unit or nitrogen removal unit. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single acid gas removal unit or nitrogen removal unit for each location it operates at in a given year.
(ii) Whether the acid gas removal unit or nitrogen removal unit vent was routed to a flare. If so, report the information specified in paragraphs (d)(1)(ii)(A) through (D) of this section for acid gas removal units and the information specified in paragraph (d)(1)(ii)(B) of this section for nitrogen removal units.
(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(d) as specified in § 98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the acid gas removal unit or nitrogen removal unit vent was routed.
(D) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the acid gas removal unit or nitrogen removal unit vent.
(iii) Whether the acid gas removal unit or nitrogen removal unit vent was routed to combustion, and if so, whether it was routed for the entire year or only part of the year.
(iv) Whether the acid gas removal unit or nitrogen removal unit vent was routed to a vapor recovery system, and if so, whether it was routed for the entire year or only part of the year.
(v) Total feed rate entering the acid gas removal unit or nitrogen removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million standard cubic feet per year.
(vi) If the acid gas removal unit or nitrogen removal unit was routed to a flare, to combustion, or to vapor recovery for only part of the year, the feed rate entering the acid gas removal unit or nitrogen removal unit during the portion of the year that the emissions were vented directly to the atmosphere, using a meter or engineering estimate based on process knowledge or best available data, in million standard cubic feet per year.
(vii) The calculation method used to calculate CO 2 and CH 4 emissions from the acid gas removal unit or to calculate CH 4 emissions from the nitrogen removal unit, as specified in § 98.233(d).
(viii) Annual CO 2 emissions, in metric tons CO 2 , vented directly to the atmosphere from the acid gas removal unit, calculated using any one of the calculation methods specified in § 98.233(d) and as specified in § 98.233(d)(11) and (12).
(ix) Annual CH 4 emissions, in metric tons CH 4 , vented directly to the atmosphere from the acid gas removal unit or nitrogen removal unit, calculated using any one of the calculation methods specified in § 98.233(d) and as specified in § 98.233(d)(11) and (12).
(x) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit or nitrogen removal unit.
(i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) to calculate CO 2 emissions from the acid gas removal unit and Calculation Method 2 as specified in § 98.233(d) to calculate CH 4 emissions from the acid gas removal unit or nitrogen removal unit, then you must report the information specified in paragraphs (d)(2)(i)(A) through (C) of this section, as applicable.
(A) Annual average volumetric fraction of CO 2 in the vent gas exiting the acid gas removal unit.
(B) Annual average volumetric fraction of CH 4 in the vent gas exiting the acid gas removal unit or nitrogen removal unit.
(C) Annual volume of gas vented from the acid gas removal unit or nitrogen removal unit, in cubic feet.
(D) The temperature that corresponds to the reported annual volume of gas vented from the unit, in degrees Fahrenheit. If the annual volume of gas vented is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60  °F.
(E) The pressure that corresponds to the reported annual volume of gas vented from the unit, in pounds per square inch absolute. If the annual volume of gas vented is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia.
(ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO 2 or CH 4 emissions from the acid gas removal unit or nitrogen removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through (M) of this section, as applicable depending on the equation used.
(A) Indicate which equation was used (equation W-4A, W-4B, or W-4C to § 98.233).
(B) Annual average volumetric fraction of CO 2 in the natural gas flowing out of the acid gas removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
(C) Annual average volumetric fraction of CO 2 content in natural gas flowing into the acid gas removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
(D) Annual average volumetric fraction of CO 2 in the vent gas exiting the acid gas removal unit, as specified in equation W-4A or equation W-4B to § 98.233.
(E) Annual average volumetric fraction of CH 4 in the natural gas flowing out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
(F) Annual average volumetric fraction of CH 4 content in natural gas flowing into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A, equation W-4B, or equation W-4C to § 98.233.
(G) Annual average volumetric fraction of CH 4 in the vent gas exiting the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4B to § 98.233.
(H) The total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in cubic feet at actual conditions.
(I) The temperature that corresponds to the reported total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in degrees Fahrenheit. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60  °F.
(J) The pressure that corresponds to the reported total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in pounds per square inch absolute. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia.
(K) The total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in cubic feet at actual conditions.
(L) The temperature that corresponds to the reported total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in degrees Fahrenheit. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60  °F.
(M) The pressure that corresponds to the reported total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in pounds per square inch absolute. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia.
(iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO 2 or CH 4 emissions from the acid gas removal unit or nitrogen removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through (O) of this section, as applicable to the simulation software package used.
(A) The name of the simulation software package used.
(B) Annual average natural gas feed temperature, in degrees Fahrenheit.
(C) Annual average natural gas feed pressure, in pounds per square inch.
(D) Annual average natural gas feed flow rate, in standard cubic feet per minute.
(E) Annual average acid gas content of the feed natural gas, in mole percent.
(F) Annual average acid gas content of the outlet natural gas, in mole percent.
(G) Annual average methane content of the feed natural gas, in mole percent.
(H) Annual average methane content of the outlet natural gas, in mole percent.
(I) Total annual unit operating hours, excluding downtime for maintenance or standby, in hours per year.
(J) Annual average exit temperature of the natural gas, in degrees Fahrenheit.
(K) Annual average solvent pressure, in pounds per square inch.
(L) Annual average solvent temperature, in degrees Fahrenheit.
(M) Annual average solvent circulation rate, in gallons per minute.
(N) Solvent type used for the majority of the year, from one of the following options: Selexol TM , Rectisol®, Purisol TM , Fluor Solvent SM , Benfield TM , 20 wt% MEA, 30 wt% MEA, 40 wt% MDEA, 50 wt% MDEA, and other (specify).
(O) If a vent meter is installed and you elected to use Calculation Method 4 for an AGR, report the information in paragraphs (d)(2)(iii)(O)( 1 ) through ( 3 ) of this section.
( 1 ) The total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined by flow meter (“V a,meter ” from equation W-4D to § 98.233).
( 2 ) The total annual volume of vent gas flowing out of the AGR in cubic feet per year at actual conditions as determined the standard simulation software package (“V a,sim ” from equation W-4D to § 98.233).
( 3 ) If the calculated percent difference between the vent volumes (“PD” from equation W-4D to § 98.233) is greater than 20 percent, provide a brief description of the reason for the difference.
(e) Dehydrators. You must indicate whether your facility contains any of the following equipment: Glycol dehydrators for which you calculated emissions using Calculation Method 1 according to § 98.233(e)(1), glycol dehydrators for which you calculated emissions using Calculation Method 2 according to § 98.233(e)(2), and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (3) of this section. For dehydrators that were routed to flares for which you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), you must report the information specified in paragraph (e)(4) of this section. For dehydrators that were routed to flares for which you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(e) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the applicable information in paragraphs (e)(1) through (3) of this section and the information specified in paragraph (e)(4) of this section.
(1) For each glycol dehydrator for which you calculated emissions using Calculation Method 1 (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator. If reported emissions are based on more than one simulation, you must report the average of the simulation inputs.
(i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single dehydrator for each location it operates at in a given year.
(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day.
(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.
(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.
(v) Dehydrator absorbent circulation pump type ( e.g. , natural gas pneumatic, air pneumatic, or electric).
(vi) Dehydrator absorbent circulation rate, in gallons per minute.
(vii) Type of absorbent ( e.g. , triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)).
(viii) Whether stripping gas is used in dehydrator.
(ix) Whether a flash tank separator is used in dehydrator.
(x) Total time the dehydrator is operating during the year, in hours.
(xi) Temperature of the wet natural gas at the absorber inlet, in degrees Fahrenheit.
(xii) Pressure of the wet natural gas at the absorber inlet, in pounds per square inch gauge.
(xiii) Mole fraction of CH 4 in wet natural gas.
(xiv) Mole fraction of CO 2 in wet natural gas.
(xv) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(xvi) If a flash tank separator is used in the dehydrator, then you must report the information specified in paragraphs (e)(1)(xvi)(A) through (F) of this section for the emissions from the flash tank vent, as applicable. If flash tank emissions were routed to a regenerator firebox/fire tubes, then you must also report the information specified in paragraphs (e)(1)(xvi)(G) through (I) of this section for the combusted emissions from the flash tank vent.
(A) Whether any flash gas emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination.
(B) Annual CO 2 emissions, in metric tons CO 2 , from the flash tank when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, (e)(4).
(C) Annual CH 4 emissions, in metric tons CH 4 , from the flash tank when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, (e)(4).
(D) Annual CO 2 emissions, in metric tons CO 2 , that resulted from routing flash gas to a regenerator firebox/fire tubes, calculated according to § 98.233(e)(5).
(E) Annual CH 4 emissions, in metric tons CH 4 , that resulted from routing flash gas to a regenerator firebox/fire tubes, calculated according to § 98.233(e)(5).
(F) Annual N 2 O emissions, in metric tons N 2 O, that resulted from routing flash gas to a regenerator firebox/fire tubes, calculated according to § 98.233(e)(5).
(G) Indicate whether the regenerator firebox/fire tubes was monitored with a CEMS. If a CEMS was used, then paragraphs (e)(1)(xvi)(E) and (F) and (e)(1)(xvi)(H) and (I) of this section do not apply.
(H) Total volume of gas from the flash tank to a regenerator firebox/fire tubes, in standard cubic feet.
(I) Average combustion efficiency, expressed as a fraction of gas from the flash tank combusted by a burning regenerator firebox/fire tubes.
(xvii) Report the information specified in paragraphs (e)(1)(xvii)(A) through (F) of this section for the emissions from the still vent, as applicable. If still vent emissions were routed to a regenerator firebox/fire tubes, then you must also report the information specified in paragraphs (e)(1)(xvii)(G) through (I) of this section for the combusted emissions from the still vent.
(A) Whether any still vent emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination.
(B) Annual CO 2 emissions, in metric tons CO 2 , from the still vent when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1), and, if applicable, (e)(4).
(C) Annual CH 4 emissions, in metric tons CH 4 , from the still vent when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, (e)(4).
(D) Annual CO 2 emissions, in metric tons CO 2 , that resulted from routing still vent gas to a regenerator firebox/fire tubes, calculated according to §  98.233(e)(5).
(E) Annual CH 4 emissions, in metric tons CH 4 , that resulted from routing still vent gas to a regenerator firebox/fire tubes, calculated according to §  98.233(e)(5).
(F) Annual N 2 O emissions, in metric tons N 2 O, that resulted from routing still vent gas to a regenerator firebox/fire tubes, calculated according to §  98.233(e)(5).
(G) Indicate whether the regenerator firebox/fire tubes were monitored with a CEMS. If a CEMS was used, then paragraphs (e)(1)(xvii)(E) and (F) and (e)(1)(xvii)(H) and (I) of this section do not apply.
(H) Total volume of gas from the still vent to a regenerator firebox/fire tubes, in standard cubic feet.
(I) Average combustion efficiency, expressed as a fraction of gas from the still vent combusted by a burning regenerator firebox/fire tubes.
(xviii) Name of the software package used.
(2) You must report the information specified in paragraphs (e)(2)(i) through (vi) of this section for all glycol dehydrators with an annual average daily natural gas throughput greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day for which you calculated emissions using Calculation Method 2 (as specified in § 98.233(e)(2)) at the facility, well-pad site, or gathering and boosting site.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) The total number of dehydrators at the facility, well-pad site, or gathering and boosting site for which you calculated emissions using Calculation Method 2.
(iii) Whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system.
(iv) Whether any dehydrator emissions were routed to a control device that reduces CO 2 and/or CH 4 emissions other than a vapor recovery system or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a control device that reduces CO 2 and/or CH 4 emissions other than a vapor recovery system or a flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were routed to each type of control device.
(v) Whether any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(v)(A) through (E) of this section.
(A) The total number of dehydrators routed to a flare and the total number of dehydrators routed to regenerator firebox/fire tubes.
(B) Total volume of gas from the flash tank to a regenerator firebox/fire tubes, in standard cubic feet.
(C) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrators routed to a regenerator firebox/fire tubes reported in paragraph (e)(2)(v)(A) of this section, calculated according to § 98.233(e)(5).
(D) Annual CH 4 emissions, in metric tons CH 4 , for the dehydrators routed to a regenerator firebox/fire tubes reported in paragraph (e)(2)(v)(A) of this section, calculated according to § 98.233(e)(5).
(E) Annual N 2 O emissions, in metric tons N 2 O, for the dehydrators routed to a regenerator firebox/fire tubes reported in paragraph (e)(2)(v)(A) of this section, calculated according to § 98.233(e)(5).
(vi) For dehydrator emissions that were not routed to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(vi)(A) and (B) of this section.
(A) Annual CO 2 emissions, in metric tons CO 2 , for emissions from all dehydrators reported in paragraph (e)(2)(ii) of this section that were not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(2) and, if applicable, (e)(4), where emissions are added together for all such dehydrators.
(B) Annual CH 4 emissions, in metric tons CH 4 , for emissions from all dehydrators reported in paragraph (e)(2)(ii) of this section that were not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(2) and, if applicable, (e)(4), where emissions are added together for all such dehydrators.
(3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (viii) of this section for each well-pad site, gathering and boosting site, or facility, as applicable.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Count of desiccant dehydrators as specified in paragraphs (e)(3)(ii)(A) and (B) of this section that had one or more openings during the calendar year at the facility, well-pad site, or gathering and boosting site for which you calculated emissions using Calculation Method 3.
(A) The number of opened desiccant dehydrators that used deliquescing desiccant ( e.g. , calcium chloride or lithium chloride).
(B) The number of opened desiccant dehydrators that used regenerative desiccant ( e.g. , molecular sieves, activated alumina, or silica gel).
(iii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, total physical volume of all opened dehydrator vessels.
(iv) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, total number of dehydrator openings in the calendar year.
(v) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system.
(vi) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a control device that reduces CO 2 and/or CH 4 emissions other than a vapor recovery system or a flare or a non-flare combustion unit. If any dehydrator emissions were routed to a control device that reduces CO 2 and/or CH 4 emissions other than a vapor recovery system or a flare or a non-flare combustion unit, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were routed to each type of control device.
(vii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a flare or a non-flare combustion unit. If any dehydrator emissions were routed to a flare or a non-flare combustion unit, then you must report the information specified in paragraphs (e)(3)(vii)(A) through (E) of this section.
(A) The total number of dehydrators routed to a flare and the total number of dehydrators routed to a non-flare combustion unit.
(B) Total volume of gas routed to non-flare combustion units, in standard cubic feet.
(C) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrators routed to non-flare combustion units reported in paragraph (e)(3)(vii)(A) of this section, calculated according to § 98.233(e)(5).
(D) Annual CH 4 emissions, in metric tons CH 4 , for the dehydrators routed to non-flare combustion units reported in paragraph (e)(3)(vii)(A) of this section, calculated according to § 98.233(e)(5).
(E) Annual N 2 O emissions, in metric tons N 2 O, for the dehydrators routed to non-flare combustion units reported in paragraph (e)(3)(vii)(A) of this section, calculated according to § 98.233(e)(5).
(viii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section that were not routed to a flare or a non-flare combustion unit, report the information specified in paragraphs (e)(3)(viii)(A) and (B) of this section.
(A) Annual CO 2 emissions, in metric tons CO 2 , for emissions from all desiccant dehydrators reported under paragraph (e)(3)(ii) of this section that are not venting to a flare or non-flare combustion unit, calculated according to § 98.233(e)(3) and, if applicable, (e)(4), and summing for all such dehydrators.
(B) Annual CH 4 emissions, in metric tons CH 4 , for emissions from all desiccant dehydrators reported in paragraph (e)(3)(ii) of this section that are not venting to a flare or non-flare combustion unit, calculated according to § 98.233(e)(3), and, if applicable, (e)(4), and summing for all such dehydrators.
(4) For dehydrators that were routed to flares, report the information specified in paragraphs (e)(4)(i) through (iv) of this section.
(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(e) as specified in § 98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the dehydrator vent was routed.
(iv) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the dehydrator.
(f) Liquids unloading. You must indicate whether well venting for liquids unloading occurs at your facility, and if so, which methods (as specified in § 98.233(f)) were used to calculate emissions. If your facility performs well venting for liquids unloading venting to the atmosphere and uses Calculation Method 1, then you must report the information specified in paragraph (f)(1) of this section. If the facility performs liquids unloading venting to the atmosphere and uses Calculation Method 2 or 3, then you must report the information specified in paragraph (f)(2) of this section.
(1) For each well for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading vented to the atmosphere, report the information specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts by unloading type combination (with or without plunger lifts, automated or manual unloading).
(i) Well ID number.
(ii) Well tubing diameter and pressure group ID.
(iii) Unloading type combination (with or without plunger lifts, automated or manual unloading).
(iv) [Reserved]
(v) Indicate whether the monitoring period used to determine the cumulative amount of time venting to the atmosphere was not the full calendar year.
(vi) Cumulative amount of time the well was vented directly to the atmosphere (“T p ” from equation W-7A or W-7B to § 98.233), in hours.
(vii) Cumulative number of unloadings vented directly to the atmosphere for the well.
(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1).
(ix) Annual CO 2 emissions, in metric tons CO 2 , from well venting for liquids unloading, calculated according to § 98.233(f)(1) and (4).
(x) Annual CH 4 emissions, in metric tons CH 4 , from well venting for liquids unloading, calculated according to § 98.233(f)(1) and (4).
(xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (F) of this section for each individual well not using a plunger lift that was tested during the year.
(A) Well ID number of tested well.
(B) Casing pressure, in pounds per square inch absolute.
(C) Internal casing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.
(F) Unloading type (automated or manual).
(xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (F) of this section for each individual well using a plunger lift that was tested during the year.
(A) Well ID number.
(B) The tubing pressure, in pounds per square inch absolute.
(C) The internal tubing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.
(F) Unloading type (automated or manual).
(2) For each well for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading vented to the atmosphere, you must report the information in paragraphs (f)(2)(i) through (xii) of this section. Report information separately for each calculation method and unloading type combination (with or without plunger lifts, automated or manual unloadings).
(i) Well ID number.
(ii) Calculation method.
(iii) Unloading type combination (with or without plunger lifts, automated or manual unloadings).
(iv) [Reserved]
(v) Cumulative number of unloadings venting directly to the atmosphere for the well.
(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable.
(vii) Annual CO 2 emissions, in metric tons CO 2 , from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable, and § 98.233(f)(4).
(viii) Annual CH 4 emissions, in metric tons CH 4 , from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable, and § 98.233(f)(4).
(ix) Average flow-line rate of gas (average of “SFR p ” from equation W-8 or W-9 to § 98.233, as applicable), at standard conditions in cubic feet per hour.
(x) Cumulative amount of time that wells were left open to the atmosphere during unloading events (sum of “HR p,q ” from equation W-8 or W-9 to § 98.233, as applicable), in hours.
(xi) For each well without plunger lifts, the information in paragraphs (f)(2)(xi)(A) through (C) of this section.
(A) Internal casing diameter (“CD p ” from equation W-8 to § 98.233), in inches.
(B) Well depth (“WD p ” from equation W-8 to § 98.233), in feet.
(C) Shut-in pressure, surface pressure, or casing pressure (“SP p ” from equation W-8 to § 98.233), in pounds per square inch absolute.
(xii) For each well with plunger lifts, the information in paragraphs (f)(2)(xiii)(A) through (C) of this section.
(A) Internal tubing diameter (“TD p ” from equation W-9 to § 98.233), in inches.
(B) Tubing depth (“WD p ” from equation W-9 to § 98.233), in feet.
(C) Flow line pressure (“SP p ” from equation W-9 to § 98.233), in pounds per square inch absolute.
(g) Completions and workovers with hydraulic fracturing. You must indicate whether your facility had any well completions or workovers with hydraulic fracturing during the calendar year. If your facility had well completions or workovers with hydraulic fracturing during the calendar year that vented directly to the atmosphere, then you must report information specified in paragraphs (g)(1) through (10) of this section, for each well. If your facility had well completions or workovers with hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (g)(1) through (3) and (10) of this section, for each well. If your facility had well completions or workovers with hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(g) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (g)(1) through (6) and (10) of this section, for each well. Report information separately for completions and workovers.
(1) Well ID number.
(2) Well type combination (horizontal or vertical, flared or vented, reduced emission completion or not a reduced emission completion, gas well or oil well).
(3) Number of completions or workovers for each well.
(4) Calculation method used.
(5) If you used equation W-10A to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) through (v) of this section.
(i) Cumulative gas flowback time, in hours, for all completions or workovers at the well from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to enable separation (sum of “T p,i ” and sum of “T p,s ” values used in equation W-10A to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total number of hours of flowback from the well during completions or workovers.
(ii) If the well is a measured well for the sub-basin and well-type combination, the flowback rate, in standard cubic feet per hour (average of “FR s,p ” values used in equation W-12A to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured flowback rate(s) during well completion or workover for the well.
(iii) If you used equation W-12C to § 98.233 to calculate the average gas production rate for an oil well, then you must report the information specified in paragraphs (g)(5)(iii)(A) and (B) of this section.
(A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GOR p ” in equation W-12C to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the gas to oil ratio for the well.
(B) Volume of oil produced during the first 30 days of production after completion of the newly drilled well or well workover using hydraulic fracturing, in barrels (“V p ” in equation W-12C to § 98.233). You may delay the reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the volume of oil produced during the first 30 days of production after well completion or workover for the well.
(iv) Whether the flow rate during the initial flowback period was determined using:
(A) A recording flow meter (digital or analog) installed on the vent line, downstream of a separator.
(B) A multiphase flow meter upstream of the separator.
(C) Equation W-11A or W-11B to § 98.233.
(v) Whether the flow rate when sufficient quantities are present to enable separation was determined using:
(A) A recording flow meter (digital or analog) installed on the vent line, downstream of a separator.
(B) Equation W-11A or W-11B to § 98.233.
(6) If you used equation W-10B to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iii) of this section.
(i) Vented natural gas volume, in standard cubic feet (“FV s,p ” in equation W-10B to § 98.233).
(ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour (“FR p,i ” in equation W-10B to § 98.233).
(iii) If a multiphase flowmeter was used to measure the flow rate during the initial flowback period, report the average flow rate measured by the multiphase flow meter from the initiation of flowback to the beginning of the period of time when sufficient quantities of gas present to enable separation in standard cubic feet per hour.
(7) Annual gas emissions, in standard cubic feet (“E s,n ” in equation W-10A or W-10B to § 98.233).
(8) Annual CO 2 emissions, in metric tons CO 2 .
(9) Annual CH 4 emissions, in metric tons CH 4 .
(10) Indicate whether natural gas emissions from completion(s) or workover(s) with hydraulic fracturing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (g)(10)(i) through (iv) of this section.
(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(g) as specified in § 98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.
(iv) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.
(h) Completions and workovers without hydraulic fracturing. You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility had gas well completions or workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) through (4) of this section, as applicable.
(1) For each well with one or more gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this section.
(i) Well ID number.
(ii) Number of well completions that vented gas directly to the atmosphere without flaring.
(iii) Total number of hours that gas vented directly to the atmosphere during venting for all completions without hydraulic fracturing (“T p ” for completions that vented directly to the atmosphere as used in equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total number of hours that gas vented directly to the atmosphere during completions for the well.
(iv) Average daily gas production rate for all completions without hydraulic fracturing without flaring, in standard cubic feet per hour (“V p ” in equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average daily gas production rate during completions for the well.
(v) Annual CO 2 emissions, in metric tons CO 2 , that resulted from completions venting gas directly to the atmosphere (“E s,p ” from equation W-13B to § 98.233 for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)).
(vi) Annual CH 4 emissions, in metric tons CH 4 , that resulted from completions venting gas directly to the atmosphere (“E s,p ” from equation W-13B to § 98.233 for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)).
(2) If your facility had well completions without hydraulic fracturing and with flaring during the year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (h)(2)(i) through (ii) and (viii) of this section, for each well. If your facility had well completions without hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (h)(2)(i) through (iv) and (viii) of this section, for each well.
(i) Well ID number.
(ii) Number of well completions that flared gas.
(iii) Total number of hours that gas routed to a flare during venting for all completions without hydraulic fracturing (“T p ” for completions that vented to a flare from equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total number of hours that gas vented to the flare during completions for the well.
(iv) Average daily gas production rate for all completions without hydraulic fracturing with flaring, in standard cubic feet per hour (“V p ” from equation W-13B to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average daily gas production rate during completions for the well.
(v) [Reserved]
(vi) [Reserved]
(vii) [Reserved]
(viii) Report the information specified in paragraphs (h)(2)(viii)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) as specified in § 98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.
(3) For each well with one or more gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this section.
(i) Well ID number.
(ii) Number of workovers that vented gas to the atmosphere without flaring.
(iii) Annual CO 2 emissions, in metric tons CO 2 per year, that resulted from workovers venting gas directly to the atmosphere (“E s,wo ” in equation W-13A to § 98.233 for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).
(iv) Annual CH 4 emissions, in metric tons CH 4 per year, that resulted from workovers venting gas directly to the atmosphere (“E s,wo ” in equation W-13A to § 98.233 for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).
(4) If your facility had well workovers without hydraulic fracturing and with flaring during the year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each well. If your facility had well workovers without hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each well.
(i) Well ID number.
(ii) Number of workovers that flared gas.
(iii)-(v) [Reserved]
(vi) Report the information specified in paragraphs (h)(4)(vi)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) as specified in § 98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.
(i) Blowdown vent stacks. You must indicate whether your facility has blowdown vent stacks. If your facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment or event type or by using flow meters or a combination of both. If you calculated emissions by equipment or event type for any blowdown vent stacks, then you must report the information specified in paragraph (i)(1) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated by equipment or event type. If you calculated emissions using flow meters for any blowdown vent stacks, then you must report the information specified in paragraph (i)(2) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated using flow meters. For the onshore natural gas transmission pipeline segment, you must also report the information in paragraph (i)(3) of this section. You must report the information specified in paragraphs (i)(1) through (3) of this section, as applicable, for each well-pad site (for onshore production), each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
(1) Report by equipment or event type. If you calculated emissions from blowdown vent stacks by the seven categories listed in § 98.233(i)(2)(iv)(A) for onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, or onshore petroleum and natural gas gathering and boosting industry segments, then you must report the information specified in paragraphs (i)(1)(i) through (v) of this section, as applicable. If a blowdown event resulted in emissions from multiple equipment or event types, and the emissions cannot be apportioned to the different equipment or event types, then you may report the information in paragraphs (i)(1)(ii) through (v) of this section for the equipment or event type that represented the largest portion of the emissions for the blowdown event. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, if a blowdown event is not directly associated with a specific well-pad site or gathering and boosting site ( e.g. , a mid-field pipeline blowdown) or could be associated with multiple well-pad or gathering and boosting sites, then you may report the information in paragraphs (i)(1)(i) through (v) of this section for either the nearest well-pad site or gathering and boosting site upstream from the blowdown event or the well-pad site or gathering and boosting site that represented the largest portion of the emissions for the blowdown event, as appropriate. If you calculated emissions from blowdown vent stacks by the eight categories listed in § 98.233(i)(2)(iv)(B) for the natural gas distribution or onshore natural gas transmission pipeline industry segments, then you must report the information specified in paragraphs (i)(1)(ii) through (v) of this section, as applicable. If a blowdown event resulted in emissions from multiple equipment or event types, and the emissions cannot be apportioned to the different equipment or event types, then you may report the information in paragraphs (i)(1)(ii) through (v) of this section for the equipment or event type that represented the largest portion of the emissions for the blowdown event.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Equipment or event type. For the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, or onshore petroleum and natural gas gathering and boosting industry segments, use the seven categories listed in § 98.233(i)(2)(iv)(A). For the natural gas distribution or onshore natural gas transmission pipeline industry segments, use the eight categories listed in § 98.233(i)(2)(iv)(B).
(iii) Total number of blowdowns in the calendar year for the equipment or event type (the sum of equation variable “N” from equation W-14A or equation W-14B to § 98.233, for all unique physical volumes for the equipment or event type).
(iv) Annual CO 2 emissions for the equipment or event type, in metric tons CO 2 , calculated according to § 98.233(i)(2)(iii).
(v) Annual CH 4 emissions for the equipment or event type, in metric tons CH 4 , calculated according to § 98.233(i)(2)(iii).
(2) Report by flow meter. If you elect to calculate emissions from blowdown vent stacks by using a flow meter according to § 98.233(i)(3), then you must report the information specified in paragraphs (i)(2)(i) through (iii) of this section, as applicable. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, if a blowdown event is not directly associated with a specific well-pad site or gathering and boosting site ( e.g. , a mid-field pipeline blowdown) or could be associated with multiple well-pad sites or gathering and boosting sites, then you may report the information in paragraphs (i)(2)(i) through (iii) of this section for either the nearest well-pad site or gathering and boosting site upstream from the blowdown event or the well-pad site or gathering and boosting site that represented the largest portion of the emissions for the blowdown event, as appropriate.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Annual CO 2 emissions from all blowdown vent stacks at the facility, well-pad site, or gathering and boosting site for which emissions were calculated using flow meters, in metric tons CO 2 (the sum of all CO 2 mass emission values calculated according to § 98.233(i)(3), for all flow meters).
(iii) Annual CH 4 emissions from all blowdown vent stacks at the facility, well-pad site, or gathering and boosting site for which emissions were calculated using flow meters, in metric tons CH 4 , (the sum of all CH 4 mass emission values calculated according to § 98.233(i)(3), for all flow meters).
(3) Onshore natural gas transmission pipeline segment. Report the information in paragraphs (i)(3)(i) through (iii) of this section for each state.
(i) Annual CO 2 emissions in metric tons CO 2 .
(ii) Annual CH 4 emissions in metric tons CH 4 .
(iii) Annual number of blowdown events.
(j) Hydrocarbon liquids and produced water storage tanks. You must indicate whether your facility sends hydrocarbon produced liquids and/or produced water to atmospheric pressure storage tanks. If your facility sends hydrocarbon produced liquids and/or produced water to atmospheric pressure storage tanks, then you must indicate which Calculation Method(s) you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (2) of this section, as applicable. If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any atmospheric pressure storage tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and must report the information specified in paragraph (j)(3) of this section. For hydrocarbon liquids and produced water storage tanks that were routed to flares for which you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), you must report the information specified in paragraph (j)(4) of this section. For hydrocarbon liquids and produced water storage tanks that were routed to flares for which you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(j) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the applicable information in paragraphs (j)(1) through (3) of this section and the information specified in paragraph (j)(4) of this section.
(1) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j) to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (xvi) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) and by calculation method and liquid type, as applicable. Onshore petroleum and natural gas gathering and boosting and onshore natural gas processing facilities do not report the information specified in paragraph (j)(1)(ix) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Calculation method used, and name of the software package used if using Calculation Method 1.
(iii) The total annual hydrocarbon liquids or produced water volume from gas-liquid separators and direct from wells or non-separator equipment that is sent to applicable atmospheric pressure storage tanks, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells at the well-pad site with hydrocarbon liquids or produced water production flowing to gas-liquid separators or direct to atmospheric pressure storage tanks for which you used the same calculation method. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total volume of hydrocarbon liquids or produced water from all wells and the well ID number(s) for the well(s) included in this volume.
(iv) The average well, gas-liquid separator, or non-separator equipment temperature, in degrees Fahrenheit.
(v) The average well, gas-liquid separator, or non-separator equipment pressure, in pounds per square inch gauge.
(vi) For atmospheric pressure storage tanks receiving hydrocarbon liquids, the average sales oil or stabilized hydrocarbon liquids API gravity, in degrees.
(vii) If you used Calculation Method 1 of § 98.233(j) to calculate GHG emissions for atmospheric pressure storage tanks receiving hydrocarbon liquids, the flow-weighted average concentration (mole fraction) of CO 2 in flash gas from atmospheric pressure storage tanks (calculated as the sum of all products of the concentration of CO 2 in the flash gas for each storage tank times the total quantity of flash gas for that storage tank, divided by the sum of all flash gas emissions from storage tanks).
(viii) If you used Calculation Method 1 of § 98.233(j) to calculate GHG emissions for atmospheric pressure storage tanks receiving hydrocarbon liquids, the flow-weighted average concentration (mole fraction) of CH 4 in flash gas from atmospheric pressure storage tanks (calculated as the sum of all products of the concentration of CH 4 in the flash gas for each storage tank times the total quantity of flash gas for that storage tank, divided by the sum of all flash gas emissions from storage tanks).
(ix) The number of wells sending hydrocarbon liquids or produced water to gas-liquid separators or directly to atmospheric pressure storage tanks.
(x) Count of atmospheric pressure storage tanks specified in paragraphs (j)(1)(x)(A) through (F) of this section.
(A) The number of fixed roof atmospheric pressure storage tanks.
(B) The number of floating roof atmospheric pressure storage tanks.
(C) The number of atmospheric pressure storage tanks that vented gas directly to the atmosphere and did not control emissions using a vapor recovery system or one or more flares at any point during the reporting year.
(D) The number of atmospheric pressure storage tanks that routed emissions to a vapor recovery system at any point during the reporting year.
(E) The number of atmospheric pressure storage tanks that routed emissions to one or more flares at any point during the reporting year.
(F) The number of atmospheric pressure storage tanks in paragraph (j)(1)(x)(D) or (E) of this section that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare.
(xi) For atmospheric pressure storage tanks receiving hydrocarbon liquids, annual CO 2 emissions, in metric tons CO 2 , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1) and (2).
(xii) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1) and (2).
(xiii) For the atmospheric pressure storage tanks receiving hydrocarbon liquids identified in paragraphs (j)(1)(x)(D) of this section, total CO 2 mass, in metric tons CO 2 , that was recovered during the calendar year using a vapor recovery system.
(xiv) For the atmospheric pressure storage tanks identified in paragraphs (j)(1)(x)(D) of this section, total CH 4 mass, in metric tons CH 4 , that was recovered during the calendar year using a vapor recovery system.
(xv) For the atmospheric pressure storage tanks identified in paragraph (j)(1)(x)(F) of this section, the total volume of gas vented through open thief hatches, in scf, during periods while the storage tanks were also routing emissions to vapor recovery systems and/or flares.
(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section.
(i) Report the information specified in paragraphs (j)(2)(i)(A) through (H) of this section, at the facility level, for atmospheric pressure storage tanks where emissions were calculated using Calculation Method 3 of § 98.233(j).
(A) The total annual hydrocarbon liquids throughput that is sent to all atmospheric pressure storage tanks in the facility with emissions calculated using Calculation Method 3, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells at the facility with hydrocarbon liquids production that send hydrocarbon liquids to atmospheric pressure storage tanks for which emissions were calculated using Calculation Method 3. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total annual hydrocarbon liquids throughput from all wells and the well ID number(s) for the well(s) included in this volume.
(B) The total annual produced water throughput that is sent to all atmospheric pressure storage tanks in the facility with emissions calculated using Calculation Method 3, in barrels, specified in paragraphs (j)(2)(i)(B)( 1 ) through ( 3 ) of this section.
( 1 ) Total volume of produced water with pressure less than or equal to 50 psi.
( 2 ) Total volume of produced water with pressure greater than 50 psi and less than or equal to 250 psi.
( 3 ) Total volume of produced water with pressure greater than 250 psi.
(C) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with flares.
(D) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with vapor recovery systems.
(E) An estimate of the fraction of total produced water throughput reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with flares.
(F) An estimate of the fraction of total produced water throughput reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with vapor recovery systems.
(G) The number of fixed roof atmospheric pressure storage tanks in the facility.
(H) The number of floating roof atmospheric pressure storage tanks in the facility.
(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (H) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) with atmospheric pressure storage tanks receiving hydrocarbon liquids whose emissions were calculated using § 98.233(j)(3)(i).
(A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(B) The number of atmospheric pressure storage tanks that did not control emissions with flares and for which emissions were calculated using Calculation Method 3.
(C) The number of atmospheric pressure storage tanks that controlled emissions with flares and for which emissions were calculated using Calculation Method 3.
(D) The number of atmospheric pressure storage tanks that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare.
(E) The total number of separators, wells, or non-separator equipment with annual average daily hydrocarbon liquids throughput greater than 0 barrels per day and less than 10 barrels per day for which you used Calculation Method 3 (“Count” from equation W-15A to § 98.233).
(F) Annual CO 2 emissions, in metric tons CO 2 , that resulted from venting gas directly to the atmosphere, calculated using equation W-15A to § 98.233 and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(G) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere, calculated using equation W-15A to § 98.233 and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(H) The total volume of gas vented through open thief hatches, in scf, during periods while the atmospheric pressure storage tanks were also routing emissions to vapor recovery systems and/or flares.
(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (F) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for onshore natural gas processing) with atmospheric pressure storage tanks receiving produced water whose emissions were calculated using § 98.233(j)(3)(ii).
(A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(B) The number of atmospheric pressure storage tanks that did not control emissions with flares and for which emissions were calculated using Calculation Method 3.
(C) The number of atmospheric pressure storage tanks that controlled emissions with flares and for which emissions were calculated using Calculation Method 3.
(D) The number of atmospheric pressure storage tanks that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare.
(E) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere, calculated using equation W-15B to § 98.233 and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(F) The total volume of gas vented through open thief hatches, in scf, during periods while the atmospheric pressure storage tanks were also routing emissions to vapor recovery systems and/or flares.
(3) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (v) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) by liquid type.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year.
(iii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the “T dv ” values used in equation W-16 to § 98.233).
(iv) For atmospheric pressure storage tanks receiving hydrocarbon liquids, annual CO 2 emissions, in metric tons CO 2 , that resulted from dump valves on gas-liquid separators not closing properly during the calendar year, calculated using equation W-16 to § 98.233.
(v) Annual CH 4 emissions, in metric tons CH 4 , that resulted from the dump valves on gas-liquid separators not closing properly during the calendar year, calculated using equation W-16 to § 98.233.
(4) For atmospheric pressure storage tanks that were routed to flares, report the information specified in paragraphs (j)(4)(i) through (iv) of this section.
(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(j) as specified in § 98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the atmospheric pressure storage tank vent was routed.
(iv) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the atmospheric pressure storage tank.
(k) Condensate storage tanks. You must indicate whether your facility contains any condensate storage tanks. If your facility contains at least one condensate storage tank, then you must report the information specified in paragraphs (k)(1) and (2) of this section for each condensate storage tank vent stack.
(1) For each condensate storage tank vent stack, report the information specified in (k)(1)(i) through (iv) of this section.
(i) The unique name or ID number for the condensate storage tank vent stack.
(ii) Indicate if a flare is attached to the condensate storage tank vent stack.
(iii) Indicate whether scrubber dump valve leakage occurred for the condensate storage tank vent according to § 98.233(k)(1).
(iv) Which method specified in § 98.233(k)(1) was used to determine if dump valve leakage occurred.
(2) If scrubber dump valve leakage occurred for a condensate storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each condensate storage vent stack where scrubber dump valve leakage occurred.
(i) Which method specified in § 98.233(k)(2) was used to measure the leak rate.
(ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour.
(iii) Duration of time that the leak is counted as having occurred, in hours, as determined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
(iv) Annual CO 2 emissions, in metric tons CO 2 , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (4).
(v) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (4).
(l) Well testing. You must indicate whether you performed gas well or oil well testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (4) of this section, as applicable.
(1) For oil wells not routed to a flare, you must report the information specified in paragraphs (l)(1)(i) through (vii) of this section for each well tested.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the calendar year.
(iv) Average gas to oil ratio for the tested well, in cubic feet of gas per barrel of oil. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average gas to oil ratio for the tested well.
(v) Average flow rate for the tested well, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average flow rate for the tested well.
(vi) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l).
(vii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l).
(2) For oil wells routed to a flare and where you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (l)(2)(i) through (ii) and (ix) of this section, for each well tested. For oil wells routed to a flare and where you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (l)(2)(i) through (v) and (ix) of this section. All reported data elements should be specific to the well for which equation W-17A to § 98.233 was used and for which well testing emissions were routed to flares.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the calendar year.
(iv) Average gas to oil ratio for the tested well, in cubic feet of gas per barrel of oil. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average gas to oil ratio for the tested well.
(v) Average flow rate for the tested well, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average flow rate for the tested well.
(vi)-(viii) [Reserved]
(ix) Indicate whether natural gas emissions from well testing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (l)(2)(ix)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) as specified in § 98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.
(3) For gas wells not routed to a flare, you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section for each well tested.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the calendar year. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the number of well testing days for the tested well.
(iv) Average annual production rate for the tested well, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average annual production rate for the tested well.
(v) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l).
(vi) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l).
(4) For gas wells routed to a flare and where you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (l)(4)(i) through (ii) and (viii) of this section, for each well tested. For gas wells routed to a flare and where you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (l)(4)(i) through (iv) and (viii) of this section for each well tested. All reported data elements should be specific to the well for which equation W-17B to § 98.233 was used and for which well testing emissions were routed to flares.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the calendar year. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the number of well testing days for the tested well.
(iv) Average annual production rate for the tested well, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average annual production rate for the tested well.
(v)-(vii) [Reserved]
(viii) Indicate whether natural gas emissions from well testing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (l)(4)(viii)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) as specified in § 98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section.
(m) Associated natural gas. You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented during the calendar year, then you must report the information specified in paragraphs (m)(1) through (7) of this section for each well for which associated gas was vented. If associated gas was flared during the calendar year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (m)(1) through (3) of this section, for each well. If associated gas was flared and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(m) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (m)(1) through (6) of this section for each well.
(1) Well ID number.
(2) Indicate whether any associated gas was vented directly to the atmosphere without flaring.
(3) Indicate whether any associated gas was flared and emissions are reported according to paragraph (n) of this section, and, if so, provide the information specified in paragraphs (m)(3)(i) through (iv).
(i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(m) as specified in § 98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack to which associated natural gas is routed as specified in paragraph (n)(1) of this section.
(iv) The unique ID for each associated natural gas stream routed to the flare as specified in paragraph (n)(3) of this section.
(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil during the reporting year. Do not report the GOR if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare ( i.e. , if you did not use equation W-18 to § 98.233 for the well with associated gas venting or flaring emissions).
(5) Volume of oil produced by the well, in barrels, in the calendar year only during the time periods in which associated gas was vented or flared (“V p ” used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the volume of oil produced by the well during the time periods in which associated gas venting and flaring was occurring. Do not report the volume of oil produced if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare ( i.e. , if you did not use equation W-18 to § 98.233 for the well with associated gas venting or flaring emissions).
(6) Total volume of associated gas sent to sales or used on site and not sent to a vent or flare, in standard cubic feet, in the calendar year only during time periods in which associated gas was vented or flared (“SG” value used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured total volume of associated gas sent to sales for the well during the time periods in which associated gas venting and flaring was occurring. Do not report the volume of gas sent to sales if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare ( i.e. , if you did not use equation W-18 to § 98.233).
(7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (viii) of this section for each well.
(i) [Reserved]
(ii) Indicate whether the associated gas volume vented from the well was measured using a continuous flow monitor.
(iii) Indicate whether associated gas streams vented from the well were measured with a continuous gas composition analyzer.
(iv) Total volume of associated gas vented from the well, in standard cubic feet.
(v) Flow-weighted average mole fraction of CH 4 in associated gas vented from the well.
(vi) Flow-weighted average mole fraction of CO 2 in associated gas vented from the well.
(vii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(m)(3) and (4).
(viii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(m)(3) and (4).
(n) Flare stacks. You must indicate if your facility has any flare stacks. You must report the information specified in paragraphs (n)(1) through (20) of this section for each flare stack at your facility.
(1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year.
(2) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(3) Unique IDs for each stream routed to the flare and the source type that generated the stream, if you determine the flow of each stream that is routed to the flare as specified in § 98.233(n)(3)(ii) and/or you determine the gas composition for each stream routed to the flare as specified in § 98.233(n)(4)(iii). If you determine flow or composition for a combined stream from multiple source types, then report the source type that provides the most gas to the combined stream. For source types not listed in § 98.233(n)(3)(ii)(B)( 1 ) through ( 7 ), report collectively as “other.”
(4) Indicate the type of flare ( i.e. , open ground-level flare, enclosed ground-level flare, open elevated flare, or enclosed elevated flare).
(5) Indicate the type of flare assist ( i.e. , unassisted, air-assisted with single speed fan/blower, air-assisted with dual speed fan/blower, air-assisted with variable speed fan/blower, steam-assisted, or pressure-assisted).
(6) Indicate whether the pilot flame or combustion flame was monitored continuously, visually inspected, or both. If visually inspected, report the number of inspections during the year. If the pilot flame was monitored continuously, report the number of times all continuous monitoring devices were out of service or otherwise inoperable for a period of more than one week.
(7) Indicate whether you measured total flow at the inlet to the flare as specified in § 98.233(n)(3)(i) or whether you determined flow for individual streams routed to the flare as specified in § 98.233(n)(3)(ii). If you measured total flow, indicate whether the volume of gas was determined using a continuous flow measurement device or whether it was determined using parameter monitoring and engineering calculations. If you determined flow for individual streams, indicate for each stream whether flow was determined using a continuous flow measurement device, parameter monitoring and engineering calculations, or other simulation or engineering calculation methods. If you switched from one method to another during the year, then indicate multiple methods were used.
(8) Indicate whether a continuous gas composition analyzer was used at the inlet to the flare as specified in § 98.233(n)(4)(i), whether composition at the inlet to the flare was determined based on sampling and analysis as specified in § 98.233(n)(4)(ii), or if composition was determined for individual streams as specified in § 98.233(n)(4)(iii). If you determined composition for individual streams, indicate for each stream whether composition was determined using a continuous gas composition analyzer, sampling and analysis, or other simulation or engineering calculation methods. If you switched from one method to another during the year, then indicate multiple methods were used.
(9) Indicate whether you directly measured annual average HHV of the inlet stream to the flare as specified in § 98.233(n)(8)(i), calculated the annual average HHV of the inlet stream to the flare based on composition of the inlet stream as specified in § 98.233(n)(8)(ii), directly measured the annual average HHV of individual streams routed to the flare as specified in § 98.233(n)(8)(iii), or calculated the annual average HHV of individual streams based on their composition as specified in § 98.233(n)(8)(iv).
(10) Annual average HHV of the inlet stream to the flare determined as specified in § 98.233(n)(8)(i) or (ii); both the calculated flow-weighted annual average HHV of the inlet stream to the flare and each individual stream HHV determined as specified in § 98.233(n)(8)(iii)(B) or (iv)(B); or each individual stream HHV, if you determined HHVs for each individual stream routed to the flare and you used these HHVs to calculate N 2 O emissions for each stream as specified in § 98.233(n)(8)(iii)(A) or (iv)(A).
(11) Volume of gas sent to the flare, in standard cubic feet (“V s ” in equations W-19 and W-20 to § 98.233, where V s is the total flow at the flare inlet if you measure inlet flow to the flare in accordance with § 98.233(n)(3)(i) or the sum of the V s values for individual streams if you measure or determine flow of individual streams in accordance with § 98.233(n)(3)(ii)). If you measure or determine the volume of gas for each stream routed to the flare as specified in § 98.233(n)(3)(ii), then also report the annual volume of each stream, adjusted to exclude any estimated volume that bypassed the flare or determined to have leaked from the closed vent system, and indicate that the flow has been adjusted to account for bypass volume or leaks.
(12) Fraction of the feed gas sent to an un-lit flare based on total time when continuous monitoring of the pilot or periodic inspections indicated the flare was not lit and measured or calculated flow during the times when the flare was not lit (“Z U ” in equation W-19 to § 98.233).
(13) Flare destruction efficiency, expressed as the fraction of hydrocarbon compounds in gas that is destroyed by a burning flare, but may or may not be completely oxidized to CO 2 (§ 98.233(n)(1)). If you used multiple methods during the year, report the flow-weighted average destruction efficiency based on each tier that applied. Report the efficiency fraction to three decimal places.
(i) If you use tier 1, report the following:
(A) Number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in § 98.233(n)(1)(i).
(B) [Reserved]
(ii) If you use tier 2, report the following:
(A) Indicate if you are subject to part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or if you are electing to comply with the flare monitoring requirements in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
(B) If you are not required to comply with part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, indicate whether you are electing to comply with § 98.233(n)(1)(ii)(A), (B), (C), or (D).
(C) If you are not required to comply with part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and the flare is an enclosed ground level flare or an enclosed elevated flare, indicate if your most recent performance test was conducted using the method in § 60.5413b(b) of this chapter (as specified in § 98.233(n)(1)(ii)(A)), the method in § 60.5413b(d) of this chapter (as specified in § 98.233(n)(1)(ii)(C)), or if it was conducted using OTM-52.
(D) Number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in § 98.233(n)(1)(ii).
(iii) Indicate if you use an alternative test method approved under § 60.5412b(d) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. If you use an approved alternative test method, indicate the approved destruction efficiency for the method, the date when you started to use the method, and the name or ID of the method.
(14) Annual average mole fraction of CH 4 in the feed gas to the flare if you measure composition of the inlet gas as specified in § 98.233(n)(4)(i) or (ii) (“X CH4 ” in equation W-19 to § 98.233), or the annual average CH 4 mole fractions for each stream if you determine composition of each stream routed to the flare as specified in § 98.233(n)(4)(iii).
(15) Except as specified in paragraph (n)(20) of this section, annual average mole fraction of CO 2 in the feed gas to the flare if you measure composition of the inlet gas as specified in § 98.233(n)(4)(i) or (ii) (“X CO2 ” in equation W-20 to § 98.233), or the annual average CO 2 mole fractions for each stream if you determine composition of each stream routed to the flare as specified in § 98.233(n)(4)(iii).
(16) Annual CO 2 emissions, in metric tons CO 2 (refer to equation W-20 to § 98.233).
(17) Annual CH 4 emissions, in metric tons CH 4 (refer to equation W-19 to § 98.233).
(18) Annual N 2 O emissions, in metric tons N 2 O (refer to equation W-40 to § 98.233).
(19) Estimated disaggregated CH 4 , CO 2 , and N 2 O emissions attributed to each source type as determined in § 98.233(n)(10) ( i.e. , AGR vents, dehydrator vents, well venting during completions and workovers with hydraulic fracturing, gas well venting during completions and workovers without hydraulic fracturing, hydrocarbon liquids and produced water storage tanks, well testing venting and flaring, associated gas venting and flaring, other flared sources).
(20) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used, then you are not required to report the CO 2 mole fraction in paragraph (n)(15) of this section.
(o) Centrifugal compressors. You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (2) of this section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(o)(3) or (5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(o)(10)(iii) are not required to report information in paragraphs (o)(1) through (4) of this section and instead must report the information specified in paragraph (o)(5) of this section.
(1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) through (xi) of this section, as applicable, for each centrifugal compressor located at your facility.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Unique name or ID for the centrifugal compressor.
(iii) Hours in operating-mode.
(iv) Hours in standby-pressurized-mode.
(v) Hours in not-operating-depressurized-mode.
(vi) If you conducted volumetric emission measurements as specified in § 98.233(o)(1):
(A) Indicate whether the compressor was measured in operating-mode.
(B) Indicate whether the compressor was measured in standby-pressurized-mode.
(C) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(vii) Indicate whether the compressor has blind flanges installed and associated dates.
(viii) Indicate whether the compressor has wet or dry seals.
(ix) If the compressor has wet seals, the number of wet seals.
(x) If the compressor has dry seals, the number of dry seals.
(xi) Power output of the compressor driver (hp).
(2) Compressor source. (i) For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i)(A) through (C) of this section.
(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(ii) of this section.
(B) Centrifugal compressor source (wet seal, dry seal, isolation valve, or blowdown valve).
(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.
(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery system.
(B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in § 98.233(o)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)( 1 ) and ( 2 ) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery system, you are not required to report emissions under this paragraph.
(1) Annual CO 2 emissions, in metric tons CO 2 .
(2) Annual CH 4 emissions, in metric tons CH 4 .
(E) If the leak or vent is routed to flare, combustion, or vapor recovery system, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
(3) As found measurement sample data. If the measurement methods specified in § 98.233(o)(2) or (4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the calculation specified in § 98.233(o)(6)(ii) is performed, report the information specified in paragraph (o)(3)(ii) of this section.
(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-23 to § 98.233 was used to calculate emissions in equation W-22 to § 98.233, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section.
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF s,m in equation W-23 to § 98.233).
(C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count m in equation W-23 to § 98.233).
(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.
(4) Continuous measurement data. If the measurement methods specified in § 98.233(o)(3) or (5) are conducted, report the information specified in paragraphs (o)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million standard cubic feet.
(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(o)(3)(ii) and (o)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting. Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(o)(10)(iii) must report the information specified in paragraphs (o)(5)(i) through (iv) of this section. You must report the information specified in paragraphs (o)(5)(i) through (iv) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production) or each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting).
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Report the following activity data.
(A) Total number of centrifugal compressors at the facility.
(B) Number of centrifugal compressors that have wet seals.
(C) Number of centrifugal compressors that have atmospheric wet seal oil degassing vents ( i.e. , wet seal oil degassing vents where the emissions are released to the atmosphere rather than being routed to flares, combustion, or vapor recovery systems).
(iii) Annual CO 2 emissions, in metric tons CO 2 , from centrifugal compressors with atmospheric wet seal oil degassing vents.
(iv) Annual CH 4 emissions, in metric tons CH 4 , from centrifugal compressors with atmospheric wet seal oil degassing vents.
(p) Reciprocating compressors. You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(p)(10)(iii) are not required to report information in paragraphs (p)(1) through (4) of this section and instead must report the information specified in paragraph (p)(5) of this section.
(1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) through (viii) of this section, as applicable, for each reciprocating compressor located at your facility.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Unique name or ID for the reciprocating compressor.
(iii) Hours in operating-mode.
(iv) Hours in standby-pressurized-mode.
(v) Hours in not-operating-depressurized-mode.
(vi) If you conducted volumetric emission measurements as specified in § 98.233(p)(1):
(A) Indicate whether the compressor was measured in operating-mode.
(B) Indicate whether the compressor was measured in standby-pressurized-mode.
(C) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(vii) Indicate whether the compressor has blind flanges installed and associated dates.
(viii) Power output of the compressor driver (hp).
(2) Compressor source. (i) For each compressor source at each compressor, report the information specified in paragraphs (p)(2)(i)(A) through (C) of this section.
(A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section.
(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).
(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.
(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery system.
(B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in § 98.233(p)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)( 1 ) and ( 2 ) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery system, you are not required to report emissions under this paragraph.
( 1 ) Annual CO 2 emissions, in metric tons CO 2 .
( 2 ) Annual CH 4 emissions, in metric tons CH 4 .
(E) If the leak or vent is routed to a flare, combustion, or vapor recovery system, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
(3) As found measurement sample data. If the measurement methods specified in § 98.233(p)(2) or (4) are conducted, report the information specified in paragraph (p)(3)(i) of this section. If the calculation specified in § 98.233(p)(6)(ii) is performed, report the information specified in paragraph (p)(3)(ii) of this section.
(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-28 to § 98.233 was used to calculate emissions in equation W-27 to § 98.233, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section.
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF s,m in equation W-28 to § 98.233).
(C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count m in equation W-28 to § 98.233).
(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.
(4) Continuous measurement data. If the measurement methods specified in § 98.233(p)(3) or (5) are conducted, report the information specified in paragraphs (p)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million standard cubic feet.
(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(p)(3)(ii) and (p)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting that calculate emissions according to § 98.233(p)(10)(iii) must report the information specified in paragraphs (p)(5)(i) through (iv) of this section. You must report the information specified in paragraphs (p)(5)(i) through (iv) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production) or each gathering and boosting site (for onshore petroleum and natural gas gathering and boosting).
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Report the following activity data.
(A) Total number of reciprocating compressors at the facility.
(B) Number of reciprocating compressors that have rod packing emissions vented directly to the atmosphere ( i.e. , rod packing vents where the emissions are released to the atmosphere rather than being routed to flares, combustion, or vapor recovery systems).
(iii) Annual CO 2 emissions, in metric tons CO 2 , from reciprocating compressors with rod packing emissions vented directly to the atmosphere.
(iv) Annual CH 4 emissions, in metric tons CH 4 , from reciprocating compressors with rod packing emissions vented directly to the atmosphere.
(q) Equipment leak surveys. For any components subject to or complying with the requirements of § 98.233(q), you must report the information specified in paragraphs (q)(1) and (2) of this section. You must report the information specified in paragraphs (q)(1) and (2) of this section, as applicable, for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments). Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraph (q)(3) of this section.
(1) You must report the information specified in paragraphs (q)(1)(i) through (ix) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Except as specified in paragraph (q)(1)(iii) of this section, the number of complete equipment leak surveys performed during the calendar year.
(iii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle.
(iv) Except for natural gas distribution facilities and onshore natural gas transmission pipeline facilities, indicate whether any of the leak detection surveys used in calculating emissions per § 98.233(q)(2) were conducted for compliance with any of the standards in paragraphs (q)(1)(iv)(A) through (E) of this section. Report the indication per well-pad site, gathering and boosting site, or facility, not per component type, as applicable.
(A) The well site or compressor station fugitive emissions standards in § 60.5397a of this chapter.
(B) The well site, centralized production facility, or compressor station fugitive emissions standards in § 60.5397b or § 60.5398b of this chapter.
(C) The well site, centralized production facility, or compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
(D) The standards for equipment leaks at onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter.
(E) The standards for equipment leaks at onshore natural gas processing plants in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
(v) For facilities in onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment, indicate whether you elected to comply with § 98.233(q) according to § 98.233(q)(1)(iv) for any equipment components at your well-pad site, gathering and boosting site, or facility.
(vi) Report each type of method described in § 98.234(a) that was used to conduct leak surveys.
(vii) Report whether emissions were calculated using Calculation Method 1 (leaker factor emission calculation methodology) and/or using Calculation Method 2 (leaker measurement methodology).
(viii) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in table W-1 to this subpart) by service type for which leak detection surveys were conducted and emissions calculated according to § 98.233(q).
(ix) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in table W-1 to this subpart) in vacuum service as defined in § 98.238.
(2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through (8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), (j)(10), (m)(3)(ii) or (m)(4)(ii) for your facility's industry segment. For each component type and leak detection method combination that is located at your well-pad site, gathering and boosting site, or facility, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section. If a component type is located at your well-pad site, gathering and boosting site, or facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (ix) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(vi) through (ix) of this section. If you used Calculation Method 1 (leaker factor emission calculation methodology) for some complete leak surveys and used Calculation Method 2 (leaker measurement methodology) for some complete leak surveys, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section separately for component surveys using Calculation Method 1 and Calculation Method 2.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Component type.
(iii) Leak detection method used for the screening survey ( e.g. , Method 21 as specified in § 98.234(a)(2)(i); Method 21 as specified in § 98.234(a)(2)(ii); and OGI and other leak detection methods as specified in § 98.234(a)(1), (3), or (5)).
(iv) Emission factor or measurement method used ( e.g., default emission factor; facility-specific emission factor developed according to § 98.233(q)(4); or direct measurement according to § 98.233(q)(3)).
(v) Total number of components surveyed by type and leak detection method in the calendar year.
(vi) Total number of the surveyed component types by leak detection method that were identified as leaking in the calendar year (“xp” in equation W-30 to § 98.233 for the component type or the number of leaks measured for the specified component type according to the provisions in § 98.233(q)(3)).
(vii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T p,z ” from equation W-30 to § 98.233 for the component type or average duration of leaks for the specified component type determined according to the provisions in § 98.233(q)(3)(ii)).
(viii) Annual CO 2 emissions, in metric tons CO 2 , for the component type as calculated using equation W-30 to § 98.233 or § 98.233(q)(3)(vii) (for surveyed components only).
(ix) Annual CH 4 emissions, in metric tons CH 4 , for the component type as calculated using equation W-30 to § 98.233 or § 98.233(q)(3)(vii) (for surveyed components only).
(3) Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section.
(i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year.
(ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year (“Count MR,y ” from equation W-31 to § 98.233, for the current calendar year).
(iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of “T w,y ” from equation W-31 to § 98.233, for the current calendar year).
(iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle.
(v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of “Count MR,y ” from equation W-31 to § 98.233, for all calendar years in the current leak survey cycle).
(vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T w,y ” from equation W-31 to § 98.233, for all years included in the leak survey cycle).
(vii) Meter/regulator run CO 2 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CO 2 per operational hour of all meter/regulator runs (“EF s,MR,i ” for CO 2 calculated using equation W-31 to § 98.233).
(viii) Meter/regulator run CH 4 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CH 4 per operational hour of all meter/regulator runs (“EF s,MR,i ” for CH 4 calculated using equation W-31 to § 98.233).
(ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report:
(A) The total number of meter/regulator runs at above grade transmission-distribution transfer stations at your facility (“Count MR ” in equation W-32B to § 98.233).
(B) Average estimated time that each meter/regulator run at above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in equation W-32B to § 98.233).
(C) Annual CO 2 emissions, in metric tons CO 2 , for all above grade transmission-distribution transfer stations at your facility.
(D) Annual CH 4 emissions, in metric tons CH 4 , for all above grade transmission-distribution transfer stations at your facility.
(r) Equipment leaks by population count. If your facility is subject to the requirements of § 98.233(r), then you must report the information specified in paragraphs (r)(1) through (3) of this section, as applicable. You must report the information specified in paragraphs (r)(1) through (3) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
(1) You must indicate whether your facility contains any of the emission source types required to use equation W-32A to § 98.233. You must report the information specified in paragraphs (r)(1)(i) through (vi) of this section separately for each emission source type required to use equation W-32A to § 98.233 that is located at your facility. For each well-pad site and gathering and boosting site at onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities, you must report the information specified in paragraphs (r)(1)(i) through (vi) of this section separately by equipment type and service type.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Emission source type. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the equipment type and service type.
(iii) Total number of the emission source type at the well-pad site, gathering and boosting site, or facility, as applicable (“Count e ” in equation W-32A to § 98.233).
(iv) Average estimated time that the emission source type was operational in the calendar year, in hours (“T e ” in equation W-32A to § 98.233).
(v) Annual CO 2 emissions, in metric tons CO 2 , for the emission source type.
(vi) Annual CH 4 emissions, in metric tons CH 4 , for the emission source type.
(2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) through (v) of this section.
(i) Number of above grade transmission-distribution transfer stations at the facility.
(ii) Number of above grade metering-regulating stations that are not transmission-distribution transfer stations at the facility.
(iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (“Count MR ” in equation W-32B to § 98.233).
(iv) Average estimated time that each meter/regulator run at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in equation W-32B to § 98.233).
(v) If your facility has above grade metering-regulating stations that are not above grade transmission-distribution transfer stations and your facility also has above grade transmission-distribution transfer stations, you must also report:
(A) Annual CO 2 emissions, in metric tons CO 2 , from above grade metering-regulating stations that are not above grade transmission-distribution transfer stations.
(B) Annual CH 4 emissions, in metric tons CH 4 , from above grade metering regulating stations that are not above grade transmission-distribution transfer stations.
(3) You must indicate whether your facility contains any emission source types in vacuum service as defined in § 98.238. If your facility contains equipment in vacuum service, you must report the information specified in paragraphs (r)(3)(i) through (iii) of this section separately for each emission source type in vacuum service that is located at your well-pad site, gathering and boosting site, or facility, as applicable.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Emission source type.
(iii) Total number of the emission source type at the well-pad site, gathering and boosting site, or facility, as applicable.
(s) Offshore petroleum and natural gas production. You must report the information specified in paragraphs (s)(1) through (3) of this section for your facility.
(1) The BOEM Facility ID(s) that correspond(s) to your facility, if applicable.
(2) If you adjusted emissions according to § 98.233(s)(1)(ii) or (s)(2)(ii), report the information specified in paragraphs (s)(2)(i) and (ii) of this section.
(i) Facility operating hours for the year of the most recent emissions calculated according to § 98.233(s)(1)(ii) or § 98.233(s)(2)(ii) prior to the current reporting year.
(ii) Facility operating hours for the current reporting year.
(3) For each emission source type listed in the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304, report the information specified in paragraphs (s)(3)(i) through (iii) of this section.
(i) Annual CO 2 emissions, in metric tons CO 2 .
(ii) Annual CH 4 emissions, in metric tons CH 4 .
(iii) Annual N 2 O emissions, in metric tons N 2 O.
(t)-(v) [Reserved]
(w) EOR injection pumps. You must indicate whether CO 2 EOR injection was used at your facility during the calendar year and if any EOR injection pump blowdowns occurred during the year. If any EOR injection pump blowdowns occurred during the calendar year, then you must report the information specified in paragraphs (w)(1) through (8) of this section for each EOR injection pump system.
(1) Sub-basin ID.
(2) EOR injection pump system identifier.
(3) Pump capacity, in barrels per day.
(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” in equation W-37 to § 98.233).
(5) Number of blowdowns for the EOR injection pump system in the calendar year.
(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in equation W-37 to § 98.233).
(7) Mass fraction of CO 2 in critical phase EOR injection gas (“GHG CO2 ” in equation W-37 to § 98.233).
(8) Annual CO 2 emissions, in metric tons CO 2 , from EOR injection pump system blowdowns.
(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report the information specified in paragraphs (x)(1) through (4) of this section for each sub-basin category with EOR operations.
(1) Sub-basin ID.
(2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V hl ” in equation W-38 to § 98.233).
(3) Average CO 2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel under standard conditions (“S hl ” in equation W-38 to § 98.233).
(4) Annual CO 2 emissions, in metric tons CO 2 , from CO 2 retained in hydrocarbon liquids produced through EOR operations downstream of the storage tank (“MassCO 2 ” in equation W-38 to § 98.233).
(y) Other large release events. You must indicate whether there were any other large release events from your facility during the reporting year and indicate whether your facility was notified of a potential super-emitter release under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. If there were any other large release events, you must report the total number of other large release events from your facility that occurred during the reporting year and, for each other large release event, report the information specified in paragraphs (y)(1) through (10) of this section. If you received a super-emitter release notification under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter that the EPA has not determined to contain a demonstrable error according to the provisions in § 98.233(y)(6), you must include the emissions from that source or event within your subpart W report unless you can provide certification that the facility does not own or operate the equipment at the location identified in the notification using the methods specified in § 98.233(y)(6). Regardless, if you received a super-emitter release notification under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must also report the information specified in paragraph (y)(11) of this section.
(1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) Unique release event identification number ( e.g. , Event 1, Event 2).
(3) The latitude and longitude of the release in decimal degrees to at least four digits to the right of the decimal point.
(4) The approximate start date, start time, and duration (in hours) of the release event, and an indication of how the start date and time were determined (determined based on pressure monitor, temperature monitor, other monitored process parameter (specify), assigned based on last monitoring or measurement survey showing no large release (specify monitoring or measurement survey method), or used the 91-day default start date).
(5) A general description of the event. Include:
(i) Identification of the equipment involved in the release.
(ii) A description of how the release occurred, from one of the following categories: maintenance event, fire/explosion, gas well blowout, oil well blowout, gas well release, oil well release, pressure relief, large leak, and other (specify).
(iii) An indication of whether the release exceeded a threshold in § 98.233(y)(1)(i) or in § 98.233(y)(1)(ii).
(iv) A description of the technology or method used to identify the release.
(v) An indication of whether the release was identified under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and, if the release was identified under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, a unique notification ID number for the notification as assigned in paragraph (y)(11)(i) of this section.
(vi) An indication of whether a portion of the natural gas released was combusted during the release, and if so, the fraction of the natural gas released that was estimated to be combusted and the assumed combustion efficiency for the combusted natural gas.
(6) The total volume of gas released during the event in standard cubic feet.
(7) The volume fraction of CO 2 in the gas released during the event.
(8) The volume fraction of CH 4 in the gas released during the event.
(9) Annual CO 2 emissions, in metric tons CO 2 , from the release event that occurred during the reporting year.
(10) Annual CH 4 emissions, in metric tons CH 4 , from the release event that occurred during the reporting year and the maximum CH 4 emissions rate, in kilograms per hour, determined for any period of the event according to the provisions § 98.233(y)(2)(i).
(11) Report the total number of super-emitter release notifications received from the EPA under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for this facility for events that occurred during the reporting year that were not determined by the EPA to have a demonstratable error in the notification and, for each such super-emitter release notification, report the information specified in paragraphs (y)(11)(i) through (v) of this section.
(i) Unique notification identification number (e.g., Notification_01, Notification_02). If a unique notification number was provided with a notification received under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter, an applicable approved state plan, or applicable Federal plan in part 62 of this chapter, report the number associated with the event provided in the notification.
(ii) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only) to which the notification was attributed.
(iii) Based on any assessment or investigation triggered by the notification, indicate if the emissions were from normal operations, a planned maintenance event, leaking equipment, malfunctioning equipment or device, or undetermined cause.
(iv) An indication of whether the emissions identified via the notification are included in annual emissions reported under this subpart and, if so, the source type under which the emissions identified via the notification are reported (from the list of source types required to be reported as specified in § 98.232 for the facility's applicable industry segment). If the emissions were reported following the requirements of § 98.233(y) as an other large release event, report the unique release event identification number assigned to the other large release event as reported in paragraph (y)(2) of this section. If the emissions identified via the notification are not included in the annual emissions reported under this subpart, you must provide certification that the facility does not own or operate the equipment at the location identified in the notification as specified in § 98.233(y)(6)(i) or provide certification that the facility conducted a complete investigation of the site as specified in § 98.233(y)(6)(ii) and does not own or operate the emitting equipment at the location identified in the notification.
(v) Provide an indication if you received a super-emitter release notification from the EPA after December 31 of the reporting year for which investigations are on-going such that the annual report that has been submitted may be revised and resubmitted pending the outcome of the super-emitter investigation.
(z) Combustion equipment. If your facility is required by § 98.232(c)(22), (i)(7), or (j)(12) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraph (a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this section. If your facility contains any combustion units subject to reporting according to paragraph (a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this section, then you must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable. You must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable, for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
(1) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) through (iii) of this section for each unit type.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) The type of combustion unit.
(iii) The total number of combustion units.
(2) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. For each type of combustion unit at your facility, you must report the information specified in paragraphs (z)(2)(i) through (iv) and (z)(2)(viii) through (x) of this section, except for internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower) or internal fuel combustion units of any heat capacity that are compressor-drivers that combust natural gas meeting the criteria in § 98.233(z)(1) or (2) or a fuel meeting the criteria in § 98.233(z)(3), which must report the information specified in paragraphs (z)(2)(i) through (x) of this section. Information must be reported for each combustion unit type, fuel type, and method for determining the CH 4 emission factor combination, as applicable.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) The type of combustion unit including external fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers.
(iii) The type of fuel combusted.
(iv) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons.
(v) The equipment type, including reciprocating 2-stroke-lean burn, reciprocating 4-stroke lean-burn, reciprocating 4-stroke rich-burn, and gas turbine.
(vi) The method used to determine the methane emission factor, including the default emission factor from table W-7 to this subpart, OEM data, or performance tests in § 98.234(i) for natural gas described in § 98.233(z)(1) or (2), or performance tests in § 98.234(i) or default combustion efficiency for fuels described in section § 98.233(z)(3).
(vii) The value of the CH 4 emission factor (kg CH 4 /mmBtu). If multiple performance tests were performed in the same reporting year, the arithmetic average value of CH 4 emission factor (kg CH 4 /mmBtu). This information is not required if CH 4 emissions were calculated per § 98.233(z)(3)(ii)(D).
(viii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(z)(1) through (3).
(ix) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(z)(1) through (3).
(x) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(z)(1) through (3).
(aa) Industry segment-specific information. Each facility must report the information specified in paragraphs (aa)(1) through (11) of this section, for each applicable industry segment, determined using a flow meter that meets the requirements of § 98.234(b) for quantities that are sent to sale or through the facility and determined by using best available data for other quantities. If a quantity required to be reported is zero, you must report zero as the value.
(1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (iv) of this section.
(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole, unless otherwise specified.
(A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production.
(B) The quantity of natural gas produced from producing wells that is sent to sale in the calendar year, in thousand standard cubic feet.
(C) The quantity of crude oil and condensate produced from producing wells that is sent to sale in the calendar year, in barrels.
(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category.
(A) State.
(B) County.
(C) Formation type.
(D) The number of producing wells at the end of the calendar year (exclude only those wells permanently shut-in and plugged).
(E) The number of producing wells acquired during the calendar year.
(F) The number of producing wells divested during the calendar year.
(G) The number of wells completed during the calendar year.
(H) The number of wells permanently shut-in and plugged during the calendar year.
(I) Average mole fraction of CH 4 in produced gas.
(J) Average mole fraction of CO 2 in produced gas.
(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel.
(L) If an oil sub-basin, report the average API gravity of all wells.
(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge.
(iii) Report the information specified in paragraphs (aa)(1)(iii)(A) through (D) of this section for each well located in the facility.
(A) Well ID number.
(B) Well-pad ID.
(C) For each well permanently shut-in and plugged during the calendar year, the quantity of natural gas produced that is sent to sale in the calendar year, in thousand standard cubic feet.
(D) For each well permanently shut-in and plugged during the calendar year, the quantity of crude oil and condensate produced that is sent to sale in the calendar year, in barrels.
(iv) Report the information specified in paragraphs (aa)(1)(iv)(A) through (C) of this section for each well-pad site located in the facility.
(A) A unique name or ID number for the well-pad.
(B) Sub-basin ID.
(C) The latitude and longitude of the well-pad representing the geographic centroid or center point of the well-pad in decimal degrees to at least four digits to the right of the decimal point.
(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) through (iv) of this section.
(i) The quantity of natural gas produced from producing wells that is sent to sale in the calendar year, in thousand standard cubic feet.
(ii) The quantity of crude oil and condensate produced from producing wells that is sent to sale in the calendar year, in barrels.
(iii) For each well permanently shut-in and plugged during the calendar year, the quantity of natural gas produced that is sent to sale in the calendar year, in thousand standard cubic feet.
(iv) For each well permanently shut-in and plugged during the calendar year, the quantity of crude oil and condensate produced that is sent to sale in the calendar year, in barrels.
(3) For natural gas processing, if your facility fractionates NGLs and also reported as a supplier to subpart NN of this part under the same e-GGRT identification number in the calendar year, you must report the information specified in paragraphs (aa)(3)(ii) and (aa)(3)(v) through (ix) of this section. Otherwise, report the information specified in paragraphs (aa)(3)(i) through (ix) of this section.
(i) The quantity of natural gas received at the gas processing plant for processing in the calendar year, in thousand standard cubic feet.
(ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet.
(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.
(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels.
(v) Average mole fraction of CH 4 in natural gas received.
(vi) Average mole fraction of CO 2 in natural gas received.
(vii) Indicate whether the facility fractionates NGLs.
(viii) Indicate whether the facility reported as a supplier to subpart NN of this part under the same e-GGRT identification number in the calendar year.
(ix) The quantity of residue gas leaving that has been processed by the facility and any gas that passes through the facility to sales without being processed by the facility.
(4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (v) of this section.
(i) The quantity of natural gas transported through the compressor station in the calendar year, in thousand standard cubic feet.
(ii) Number of compressors.
(iii) Total compressor power rating of all compressors combined, in horsepower.
(iv) Average upstream pipeline pressure, in pounds per square inch gauge.
(v) Average downstream pipeline pressure, in pounds per square inch gauge.
(5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (iii) of this section.
(i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet.
(ii) The quantity of natural gas withdrawn from storage and sent to sale in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(6) For LNG import equipment, report the quantity of LNG imported that is sent to sale in the calendar year, in thousand standard cubic feet.
(7) For LNG export equipment, report the quantity of LNG exported that is sent to sale in the calendar year, in thousand standard cubic feet.
(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this section.
(i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet.
(ii) The quantity of LNG withdrawn from storage and sent to sale in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(9) [Reserved]
(10) For onshore petroleum and natural gas gathering and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) through (v) of this section.
(i) The quantity of gas received by the gathering and boosting facility in the calendar year, in thousand standard cubic feet.
(ii) The quantity of natural gas transported from the gathering and boosting facility in the calendar year, in thousand standard cubic feet.
(iii) The quantity of all hydrocarbon liquids received by the gathering and boosting facility in the calendar year, in barrels.
(iv) The quantity of all hydrocarbon liquids transported from the gathering and boosting facility in the calendar year, in barrels.
(v) Report the information specified in paragraphs (aa)(10)(v)(A) through (E) of this section for each gathering and boosting site located in the facility for which there were emissions in the calendar year.
(A) A unique name or ID number for the gathering and boosting site.
(B) Gathering and boosting site type (gathering compressor station, centralized oil production site, gathering pipeline, or other fence-line site).
(C) State.
(D) For gathering compressor stations, centralized oil production sites, and other fence-line sites, county.
(E) For gathering compressor stations, centralized oil production sites, and other fence-line sites, the latitude and longitude of the gathering and boosting site representing the geographic centroid or center point of the site in decimal degrees to at least four digits to the right of the decimal point.
(11) For onshore natural gas transmission pipeline facilities, report the quantities specified in paragraphs (aa)(11)(i) through (vi) of this section.
(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.
(ii) The quantity of natural gas withdrawn from underground natural gas storage and LNG storage (regasification) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to underground natural gas storage and LNG storage (liquefied) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet.
(iv) The quantity of natural gas transported through the facility and transferred to third parties such as LDCs or other transmission pipelines, in thousand standard cubic feet.
(v) The quantity of natural gas consumed by the transmission pipeline facility for operational purposes, in thousand standard cubic feet.
(vi) The miles of transmission pipeline for each state in the facility.
(bb) Missing data. For any missing data procedures used, report the information in § 98.3(c)(8) and the procedures used to substitute an unavailable value of a parameter, except as provided in paragraphs (bb)(1) and (2) of this section.
(1) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours.
(2) For annual or biannual (once every two years) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element.
(cc) Delay in reporting for wildcat wells and delineation wells. If you elect to delay reporting the information in paragraph (g)(5)(i) or (ii), (g)(5)(iii)(A) or (B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(v), (l)(2)(v), (l)(3)(iv), (l)(4)(iv), (m)(5) or (6), (dd)(1)(iii), (dd)(1)(vi)(A), (B), or (C), (dd)(3)(iii)(A), or (dd)(3)(iii)(D)( 1 ), ( 2 ), or ( 3 ) of this section, you must report the information required in that paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory text.
(dd) Drilling mud degassing. You must indicate whether there were mud degassing operations at your facility, and if so, which methods (as specified in § 98.233(dd)) were used to calculate emissions. For wells for which your facility performed mud degassing operations and used Calculation Method 1, then you must report the information specified in paragraph (dd)(1) of this section. For wells for which your facility performed mud degassing operations and used Calculation Method 2, then you must report the information specified in paragraph (dd)(2) of this section. For wells for which your facility performed mud degassing operations and used Calculation Method 3, then you must report the information specified in paragraph (dd)(3) of this section.
(1) For each well for which you used Calculation Method 1 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(1)(i) through (viii) of this section.
(i) Well ID number.
(ii) Approximate total depth below surface, in feet.
(iii) Target hydrocarbon-bearing stratigraphic formation to which the well is drilled.
(iv) Total time that drilling mud is circulated in the well (T r in equation W-41 to § 98.233 and T p in equation W-43 to § 98.233), in minutes, beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore. You may delay reporting of this data element for a representative well if you indicate in the annual report that one or more wells to which the calculated CH 4 emissions rate for the representative well (ER s,CH4,r in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. You may delay reporting of this data element for any well if you indicate in the annual report that the well is a wildcat or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total time that drilling mud is circulated in the well, in minutes.
(v) The composition of the drilling mud: water-based, oil-based, or synthetic.
(vi) If the well is not a representative well, Well ID number of the representative well used to derive the CH 4 emission rate used to calculate CH 4 emissions for this well.
(vii) If the well is a representative well, report the information specified in paragraphs (dd)(1)(vi)(A) through (D) of this section.
(A) Average mud rate (MR r in equation W-41 to § 98.233), in gallons per minute. You may delay reporting of this data element if you indicate in the annual report that one or more wells to which the calculated CH 4 emissions rate for the representative well (ER s,CH4,r in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average mud rate, in gallons per minute.
(B) Average concentration of natural gas in the drilling mud (X n in equation W-41 to § 98.233), in parts per million. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average concentration of natural gas in the drilling mud in parts per million.
(C) Measured mole fraction for CH 4 in natural gas entrained in the drilling mud (GHG CH4 in equation W-41 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured mole fraction for CH 4 in natural gas entrained in the drilling mud.
(D) Calculated CH 4 emissions rate in standard cubic feet per minute (ER s,CH4,r in equation W-42 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that that one or more wells to which the calculated CH 4 emissions rate for the representative well (ER s,CH4,r in equation W-42 to § 98.233) is applied is a wildcat or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the calculated CH 4 emissions rate in standard cubic feet per minute.
(viii) Annual CH 4 emissions, in metric tons CH 4 , from well drilling mud degassing, calculated according to § 98.233(dd)(1).
(2) For each well for which you used Calculation Method 2 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(2)(i) through (iv) of this section.
(i) Well ID number.
(ii) Total number of drilling days (DD p in equation W-44 to § 98.233).
(iii) The composition of the drilling mud: water-based, oil-based, or synthetic.
(iv) Annual CH 4 emissions, in metric tons CH 4 , from drilling mud degassing, calculated according to § 98.233(dd)(2).
(3) For each well for which you used Calculation Method 3 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(i) through (iv) of this section.
(i) Well ID number.
(ii) For the time periods you used Calculation Method 1 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(ii)(A) through (G) of this section.
(A) Approximate total depth below surface, in feet.
(B) Target hydrocarbon-bearing stratigraphic formation to which the well is drilled.
(C) Total time that drilling mud is circulated in the well (T r in equation W-41 to § 98.233 and T p in equation W-43 to § 98.233), in minutes, beginning with initial penetration of the first hydrocarbon-bearing zone until drilling mud ceases to be circulated in the wellbore. You may delay reporting of this data element for a representative well if you indicate in the annual report that that one or more wells to which the calculated CH 4 emissions rate for the representative well (ER s,CH4,r in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. You may delay reporting of this data element for any well if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total time that drilling mud is circulated in the well, in minutes.
(D) The composition of the drilling mud: water-based, oil-based, or synthetic.
(E) If the well is not a representative well, Well ID number of the representative well used to derive the CH 4 emission rate used to calculate CH 4 emissions for this well.
(F) If the well is a representative well, report the information specified in paragraphs (dd)(3)(ii)(F)( 1 ) through ( 4 ) of this section.
( 1 ) Average mud rate (MR r in equation W-41 to § 98.233), in gallons per minute. You may delay reporting of this data element if you indicate in the annual report that one or more wells to which the calculated CH 4 emissions rate for the representative well (ER s,CH4,r in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average mud rate, in gallons per minute.
( 2 ) Average concentration of natural gas in the drilling mud (X n in equation W-41 to § 98.233), in parts per million. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average concentration of natural gas in the drilling mud in parts per million.
( 3 ) Measured mole fraction for CH 4 in natural gas entrained in the drilling mud (GHG CH4 in equation W-41 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured mole fraction for CH 4 in natural gas entrained in the drilling mud.
( 4 ) Calculated CH 4 emissions rate in standard cubic feet per minute (ER s,CH4,r in equation W-42 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that one or more wells to which the calculated CH 4 emissions rate for the representative well (ER s,CH4,r in equation W-42 to § 98.233) is applied is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the calculated CH 4 emissions rate in standard cubic feet per minute.
(G) Annual CH 4 emissions, in metric tons CH 4 , from well drilling mud degassing, calculated according to § 98.233(dd)(1).
(iii) For the time periods for each well for which you used Calculation Method 2 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(iii)(A) through (C) of this section.
(A) Total number of drilling days (DD p in equation W-44 to § 98.233).
(B) The composition of the drilling mud: water-based, oil-based, or synthetic.
(C) Annual CH 4 emissions, in metric tons CH 4 , from drilling mud degassing, calculated according to § 98.233(dd)(2).
(iv) Total annual CH 4 emissions, in metric tons CH 4 , from drilling mud degassing, calculated from summing the annual CH 4 emissions calculated from § 98.233(dd)(3)(iii)(E) and § 98.233(dd)(3)(iv)(C).
(ee) Crankcase vents. You must indicate whether your facility performs any crankcase venting from reciprocating internal combustion engines. For all reciprocating internal combustion engines with crankcase vents, you must report the information specified in paragraph (ee)(1) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments). For each reciprocating internal combustion engine that you conduct measurements as specified in § 98.233(ee)(1), you must report the information specified in paragraph (ee)(2) of this section. For reciprocating internal combustion engines with CH 4 emissions calculated as specified in § 98.233(ee)(2), you must report the information specified in paragraph (ee)(3) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments).
(1) The information and number of reciprocating internal combustion engines with crankcase vents as specified in paragraphs (ee)(1)(i) through (v) of this section, as applicable. If a reciprocating internal combustion engine with crankcase vents was vented directly to the atmosphere for part of the year and routed to a flare during another part of the year, then include the engine in each of the applicable counts specified in paragraphs (ee)(1)(iii) and (iv) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) The total number of reciprocating internal combustion engines with crankcase vents.
(iii) The total number of reciprocating internal combustion engines with crankcase vents that operated and were vented directly to the atmosphere.
(iv) The total number of reciprocating internal combustion engines with crankcase vents that operated and were routed to a flare.
(v) The total number of reciprocating internal combustion engines with crankcase vents that were in a manifolded group containing a compressor vent source with emissions reported under paragraph (o) or (p) of this section.
(2) Reciprocating internal combustion engines with crankcase vents that calculate emissions according to § 98.233(ee)(1) must report the information specified in paragraphs (ee)(2)(i) and (ii) of this section, as applicable.
(i) For each measurement performed on a crankcase vent, report the information specified in paragraphs (ee)(2)(i)(A) through (F) of this section.
(A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(B) Unique name or ID for the reciprocating internal combustion engine.
(C) Measurement date.
(D) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(E) Measured flow rate, in standard cubic feet per hour.
(F) If the measurement is for a manifolded group of crankcase vent sources, indicate the number of reciprocating internal compressor engines that were operating during measurement.
(ii) Annual CH 4 emissions from the reciprocating internal combustion engine crankcase vent, in metric tons CH 4 .
(3) Reciprocating internal combustion engines with crankcase vents that calculate emissions according to § 98.233(ee)(2) must report the information specified in paragraphs (ee)(3)(i) through (iv) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(ii) Total number of reciprocating internal combustion engines with crankcase vents that were operational at some point in the calendar year at the well-pad site, gathering and boosting site, or facility, as applicable.
(iii) Total time that the reciprocating internal combustion engines with crankcase venting were operational in the calendar year, in hours (“T” in equation W-46 to § 98.233).
(iv) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(ee)(2).