Cal. Code Regs. Tit. 17, § 95157 - Activity Data Reporting Requirements

In addition to the information required by section 95103, each annual report must contain reported emissions and related information as specified in this section.

(a) Report annual emissions in metric tons per year for each GHG separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section:
(1) Onshore petroleum and natural gas production.
(2) Offshore petroleum and natural gas production
(3) Onshore natural gas processing.
(4) Onshore natural gas transmission compression.
(5) Underground natural gas storage.
(6) LNG storage.
(7) LNG import and export.
(8) Natural gas distribution.
(b) For offshore petroleum and natural gas production, report emissions of CH4, CO2, and N2O as applicable to the source type (in metric tons per year at standard conditions) individually for all of the emissions source types listed in the most recent BOEMRE study.
(c) Report the information listed in this paragraph for each applicable source type in metric tons for each GHG type. If a facility operates under more than one industry segment, each piece of equipment should be reported under the unit's respective majority use segment. When a source type listed under this paragraph routes gas to flare, separately report the emissions that were vented directly to the atmosphere without flaring, and the emissions that resulted from flaring of the gas. Both the vented and flared emissions will be reported under respective source types and not under flare source type.
(1) For natural gas pneumatic devices (refer to Equations 1 and 2 of section 95153), report the following:
(A) Actual count and estimated count separately of natural gas pneumatic high bleed devices, as applicable.
(B) Actual count and estimated count separately of natural gas low bleed devices, as applicable.
(C) Actual count and estimated count separately of natural gas pneumatic intermittent bleed devices, as applicable.
(D) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons for each gas, for each of the following pieces of equipment: high bleed pneumatic devices; intermittent bleed pneumatic devices; low bleed pneumatic devices.
(2) For natural gas driven pneumatic pumps (refer to Equation 1 and 2 of section 95153), report the following:
(A) Count of natural gas driven pneumatic pumps.
(B) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons for each gas, for all natural gas driven pneumatic pumps combined.
(3) For each acid gas removal unit (refer to Equation 3 and Equations 4A-B of section 95153), report the following:
(A) Total throughput of the acid gas removal unit using a meter or engineering estimate based on process knowledge or best available data in million cubic feet per year.
(B) For Calculation Methodology 1 and Calculation Methodology 2 of section 95153(c), annual fraction of CO2 content in the vent from acid gas removal unit (refer to section 95153(c)(6)).
(C) For Calculation Methodology 3 of section 95153(c), annual average volume fraction of CO2 content of natural gas into and out of the acid gas removal unit (refer to section 95153(c)(6)).
(D) Report the annual quantity of CO2, expressed in metric tons that was recovered from the AGR unit and transferred outside the facility, under section 95153.
(E) Report annual CO2 emissions for the AGR unit, expressed in metric tons.
(F) For the onshore natural gas processing industry segment only, report a unique name or ID number for the AGR unit.
(G) An indication of which methodology was used for the AGR unit.
(4) For dehydrators, report the following:
(A) For each Glycol dehydrator (refer to section 95153(d)(1)), report the following:
1. Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data.
2. Glycol dehydrator absorbent circulation pump type.
3. Whether stripper gas is used in glycol dehydrator.
4. Whether a flash tank separator is used in glycol dehydrator.
5. Type of absorbent.
6. Total time the glycol dehydrator is operating in hours.
7. Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas.
8. Concentration of CH4 and CO2 in wet natural gas.
9. What vent gas controls are used (refer to sections 95153(d)(3) and (d)(4)).
10. For each glycol dehydrator, report annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons for each gas.
11. For each glycol dehydrator, report annual CO2, CH4, and N2O emissions that resulted from flaring process gas from the dehydrator, expressed in metric tons for each gas.
12. For the onshore natural gas processing industry segment only, report a unique name or ID number for (each) glycol dehydrator.
(B) For absorbent desiccant dehydrators (refer to Equation 5 of section 95153), report the following:
1. Count of desiccant dehydrators.
2. Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons for each gas, for all absorbent desiccant dehydrators combined.
(5) For well venting for liquids unloading, report the following:
(A) For Calculation Methodology 1 (refer to Equation 6 of section 95153(e)), report the following:
1. Count of wells vented to the atmosphere for liquids unloading.
2. Count of plunger lifts. Whether the well had a plunger lift (yes/no).
3. Cumulative number of unloadings vented to the atmosphere.
4. Internal casing diameter or internal tubing diameter in inches, where applicable, and well depth of each well, in feet.
5. Casing pressure, in psia, of each well that does not have a plunger lift.
6. Tubing pressure, in psia, of each well that has a plunger lift.
7. Report annual CO2 and CH4 emissions, expressed in metric tons for each gas.
(B) For Calculation Methodologies 2 (refer to Equation 7 of section 95153(e)), report the following for each basin:
1. Count of wells vented to the atmosphere for liquids unloading.
2. Count of plunger lifts.
3. Cumulative number of unloadings vented to the atmosphere.
4. Average internal casing diameter, in inches, of each well, where applicable.
5. Report annual CO2 and CH4 emissions, expressed in metric tons for each GHG gas.
(6) For well completions and workovers, report the following for each basin category:
(A) Total field count of gas well completions and total field count of oil well completions by average depth (in thousands of feet) in calendar year.
1. Total number of gas well completions by average depth (in thousands of feet) using hydraulic fracturing;
2. Total number of oil well completions by average depth (in thousands of feet) using hydraulic fracturing;
(B) Total field count of gas well workovers and total field count of oil well workovers by average depth (in thousands of feet) in calendar year.
1. Total number of gas well workovers by average depth (in thousands of feet) using hydraulic fracturing;
2. Total number of oil well workovers by average depth (in thousands of feet) using hydraulic fracturing;
(C) Report number of completions employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineering estimate based on best available data.
(D) Report number of workovers employing purposely designed equipment that's separates natural gas from the backflow and the amount of natural gas recovered using engineering estimate based on best available data.
(E) Annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons for each gas.
(F) Annual CO2, CH4, and N2O emissions that resulted from flares, expressed in metric tons for each gas.
(G) The following field average activity data for oil wells:
1. Casing diameter;
2. Tubing diameter;
3. Typical pressure inside the well at the wellhead, immediately prior to removing the wellhead for well work activities;
4. Typical producing temperature inside the well;
5. Time, in hours, to complete well work (workover or completion).
(7) For each equipment and pipeline blowdown event (refer to Equation 13 and Equation 14 of section 95153(g)), report the following:
(A) For each unique physical volume that is blowdown more than once during the calendar year, report the following:
1. Total number of blowdowns for each unique physical volume, expressed in metric tons for each gas.
2. Annual CO2 and CH4 emissions for each unique physical blowdown volume, expressed in metric tons for each gas.
3. A unique name or ID number for the unique physical volume.
(B) For all unique volumes that are blow down once during the calendar year, report the following:
1. Total number of blowdowns for all unique physical volumes in the calendar year.
2. Annual CO2 and CH4 emissions from all unique physical volumes as an aggregate per facility, expressed in metric tons for each gas.
(8) For gas emitted from produced oil sent to atmospheric tanks:
(A) If a wellhead separator dump valve is functioning improperly during the calendar year (refer to section 95153(i)), report the following:
1. Count of wellhead separators that dump valve factor is applied.
2. Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons for each gas, at the basin level for improperly functioning dump valves.
(9) For transmission tank emissions identified using optical gas imaging instrument pursuant to section 95154(a) (refer to section 95153(i)), or acoustic leak detection of scrubber dump valves, report the following:
(A) For each vent stack, report annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons for each gas.
(B) For each transmission storage tank, report annual CO2, CH4 and N2O emissions that resulted from flaring process gas from the transmission storage tank, expressed in metric tons for each gas.
(C) A unique name or ID number for the vent stack monitored according to section 95153(i).
(10) For well testing venting and flaring (refer to Equation 15 or 16 of section 95153(j)), report the following:
(A) Number of wells tested per basin in calendar year.
(B) Average gas-to-oil ratio for each basin.
(C) Average number of days the well is tested in a basin.
(D) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons for each gas, emissions from well testing venting.
(E) Report annual CO2, CH4 and N2O emissions at the facility level, expressed in metric tons for each gas, emissions from well testing flaring.
(11) For associated natural gas venting and flaring (refer to Equation 17 of section 95153), report the following for each basin:
(A) Number of wells venting or flaring associated natural gas in a calendar year.
(B) Average gas-to-oil ratio for each basin.
(C) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons for each gas, emissions from associated natural gas venting.
(D) Report annual CO2, CH4 and N2O emissions at the facility level, expressed in metric tons for each gas, emissions from associated natural gas flaring.
(12) For flare stacks (refer to Equation 18, 19, and 20 of section 95153 (l)), report the following for each flare:
(A) Whether flare has a continuous flow monitor.
(B) Volume of gas sent to flare in cubic feet per year.
(C) Percent of gas sent to un-lit flare determined by engineering estimate and process knowledge based on best available data and operating records.
(D) Whether flare has a continuous gas analyzer.
(E) Flare combustion efficiency.
(F) Report CH4 emissions, in metric tons (refer to Equation 18 of section 95153).
(G) Report CO2 emissions, in metric tons (refer to Equation 19 of section 95153).
(H) Report N2O emissions, in metric tons.
(I) For the natural gas processing industry segment, a unique name or ID number for the flare stack.
(J) In the case that a CEMS is used to measure CO2 emissions for the flare stack, indicate that a CEMS was used in the annual report and report the combusted CO2 and uncombusted CO2 as a combined number.
(13) For each centrifugal compressor:
(A) For compressors with wet seals in operational mode (refer to Equation 21 and 22 of section 95153(m)), report the following for each degassing vent:
1. Number of wet seals connected to the degassing vent.
2. Fraction of vent gas recovered for fuel or sales or flared.
3. Annual throughput in million scf, use an engineering calculation based on best available data.
4. Type of meters used for making measurements.
5. Total time the compressor is operating in hours.
6. Report seal oil degassing vent emissions for compressors measured (refer to Equation 21 of section 95153) and for compressors not measured (refer to Equation 22 of section 95153).
(B) For wet and dry seal centrifugal compressors in operating mode, (refer to Equation 21 and 22 of section 95153(m)), report the following:
1. Total time in hours the compressor is in operating mode.
2. Report blowdown vent emissions when in operating mode (refer to Equation 21 and 22 of section 95153).
(C) For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations 21 and 22 of section 95153(m)), report the following:
1. Total time in hours the compressor is in shutdown, depressurized mode.
2. Report the isolation valve leakage emissions in not operating, depressurized mode in cubic feet per hour (refer to Equations 21 and 22 of section 95153).
(D) Report total annual compressor emissions from all modes of operation.
(14) For reciprocating compressors:
(A) For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following:
1. Annual throughput in million scf, use an engineering calculation based on best available data.
2. Total time in hours the reciprocating compressor is in operating mode.
3. Report rod packing emissions for compressors measured (refer to Equation 23 of section 95153).
(B) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode, report the following:
1. Total time in hours the compressor is in standby, pressurized mode.
2. Report blowdown vent emissions when in operating and standby modes.
(C) For reciprocating compressors in not operating, depressurized mode report the following:
1. Total time the compressor is in not operating depressurized mode.
2. Facility operator emission factor for isolation valve emissions in not operating mode, depressurized mode in cubic feet per hour.
3. Report the isolation valve leakage emissions in not operating, depressurized mode.
(D) Report total annual compressor emissions from all modes of operation.
(E) For reciprocating compressors in onshore petroleum and natural gas production report the following:
1. Count of compressors.
2. Report emissions collectively.
(15) For each component type (major equipment type for onshore production) that uses emission factors for estimating emissions (refer to sections 95153(o) and (p)).
(A) For equipment leaks found in each leak survey (refer to section 95153(o)), report the following:
1. Total count of leaks found in each complete survey listed by date of survey and each component type for which there is a leak emission factor in Tables 2, 3, 4, 5, 6, and 7 of Appendix A.
2. For onshore natural gas processing, range of concentrations of CH4 and CO2.
3. Annual CO2 and CH4 emissions, in metric tons for each gas by component type.
(B) For equipment leaks calculated using population counts and factors (refer to section 95153(p)), report the following:
1. For source categories listed in sections 95150(a)(4), (a)(5), (a)(6), and (a)(7), total count for each component type in Tables 2, 3, 4, 5, and 6 of Appendix A for which there is a population emission factor, listed by major heading and component type.
2. For onshore production (refer to section 95150(a)(2)), total count for each type of major equipment in Table 1B and Table 1C of Appendix A, by facility.
3. Annual CO2 and CH4 emissions, in metric tons for each gas by component type.
(16) For local distribution companies, report the following:
(A) Total number of above grade T-D transfer stations in the facility.
(B) Number of years over which all T-D transfer stations will be monitored at least once.
(C) Number of T-D stations monitored in calendar year.
(D) Total number of below grade T-D transfer stations in the facility.
(E) Total number of above grade metering-regulating stations (this count will include above grade T-D transfer stations) in the facility.
(F) Total number of below grade metering-regulating stations (this count will include below grade T-D transfer stations) in the facility.
(G) Leak factor for meter/regulator run developed in Equation 28 of section 95153.
(H) Number of miles of unprotected steel distribution mains.
(I) Number of miles of protected steel distribution mains.
(J) Number of miles of plastic distribution mains.
(K) Number of miles of cast iron distribution mains.
(L) Number of unprotected steel distribution services.
(M) Number of protected steel distribution services.
(N) Number of plastic distribution services.
(O) Number of copper distribution services.
(P) Annual CO2 and CH4 emissions, in metric tons for each gas, from all below grade T-D transfer stations combined.
(Q) Annual CO2 and CH4 emissions, in metric tons for each gas, from all above grade metering-regulating stations (including T-D transfer stations) combined.
(R) Annual CO2 and CH4 emissions, in metric tons for each gas, from all below grade metering-regulating stations (including T-D transfer stations) combined.
(S) Annual CO2 and CH4 emissions, in metric tons for each gas, from all distribution mains combined.
(T) Annual CO2 and CH4 emissions, in metric tons for each gas, from all distribution services combined.
(U) Annual CO2 and CH4 emissions, in metric tons for each gas, from customer meters serving residential, commercial, and industrial customers, respectively.
(V) Annual CO2 and CH4 emissions, in metric tons for each gas, from pipeline dig-ins.
(W) Number of customer meters at residential, commercial, and industrial premises, respectively.
(X) Number of pipeline dig-ins.
(17) For each EOR injection pump blowdown (refer to Equation 33 of section 95153), report the following:
(A) Pump capacity, in barrels per day.
(B) Volume of critical phase gas between isolation valves.
(C) Number of blowdowns per year.
(D) Critical phase EOR injection gas density.
(E) For each EOR pump, report annual CO2 and CH4 emissions, expressed in metric tons for each gas.
(18) For crude oil, condensate, and produced water dissolved CO2 and CH4 (refer to section 95153(v)), report the following:
(A) Volume of crude oil produced in barrels per year.
(B) Report annual CO2 and CH4 emissions at the basin level.
(19) For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the following:
(A) Cumulative number of external fuel combustion units with a rated heat capacity equal to or less than 5 MMBtu/hr, by type of unit.
(B) Cumulative number of external fuel combustion units with a rated heat capacity larger than 5 MMBtu/hr, by type of unit.
(C) Report annual CO2, CH4, and N2O emissions from external fuel combustion units with a rated heat capacity larger than 5 MMBtu/hr, expressed in metric tons for each gas, by type of unit.
(D) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 MMBtu/hr, by type of unit.
(E) Cumulative number of internal fuel combustion units, not compressor-drivers, with a rated heat capacity equal to or less than 1 MMBtu/hr or 130 horsepower, by type of unit.
(F) Report annual CO2, CH4 and N2O emissions from internal fuel combustion units with a rated heat capacity larger than 5 MMBtu/hr, expressed in metric tons for each gas, by type of unit.
(G) Cumulative volume of fuel combusted in internal combustion units with a rated heat capacity larger than 1 MMBtu/hr or 130 horsepower, by fuel type.
(H) Annual volume of associated gas produced in Mscf using thermal enhanced oil recovery and non-thermal enhanced oil recovery.
(I) Onshore petroleum and natural gas production facilities may voluntarily report total thermal input (MMBtu) to EOR wells generated using renewable energy source(s) as defined in section 95102(a).
(d) Report annual throughput as determined by engineering estimate based on best available data for each industry segment listed in paragraphs (a)(1) through (a)(8) of this section.
(e) For onshore petroleum and natural gas production, report the best available estimate of API gravity, best available estimate of total gas-to-oil ratio, and best available estimate of average low pressure separator pressure for each oil basin category.

Notes

Cal. Code Regs. Tit. 17, § 95157
1. New section filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
2. Renumbering of former section 95157 to new section 95158 and new section 95157 filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
3. Amendment of subsections (c)(6)(A) and (c)(6)(B), new subsections (c)(6)(A)1.-2., (c)(6)(B)1.-2. and (c)(6)(G)-(c)(6)(G)5., amendment of subsections (c)(9) and (c)(18), repealer of subsection (c)(18)(B), subsection relettering, amendment of newly designated subsection (c)(18)(B) and new subsection (c)(19)(H) filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
4. Amendment of subsections (b), (c)(10)(B), (c)(11)(B) and (c)(12)(F)-(G), repealer of subsection (c)(12)(H), subsection relettering, new subsections (c)(16)(U)-(X), amendment of subsection (c)(19)(F), new subsection (c)(19)(I) and amendment of subsection (e) filed 12-31-2014; operative 1-1-2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
5. Amendment of subsections (c)(13)(A)1., (c)(15), (c)(19)(H) and (e) filed 9-1-2017; operative 1-1-2018 (Register 2017, No. 35).

Note: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health and Safety Code.
1. New section filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
2. Renumbering of former section 95157 to new section 95158 and new section 95157 filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
3. Amendment of subsections (c)(6)(A) and (c)(6)(B), new subsections (c)(6)(A)1.-2., (c)(6)(B)1.-2. and (c)(6)(G)-(c)(6)(G)5., amendment of subsections (c)(9) and (c)(18), repealer of subsection (c)(18)(B), subsection relettering, amendment of newly designated subsection (c)(18)(B) and new subsection (c)(19)(H) filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
4. Amendment of subsections (b), (c)(10)(B), (c)(11)(B) and (c)(12)(F)-(G), repealer of subsection (c)(12)(H), subsection relettering, new subsections (c)(16)(U)-(X), amendment of subsection (c)(19)(F), new subsection (c)(19)(I) and amendment of subsection (e) filed 12-31-2014; operative 1/1/2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
5. Amendment of subsections (c)(13)(A)1., (c)(15), (c)(19)(H) and (e) filed 9-1-2017; operative 1/1/2018 (Register 2017, No. 35).

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