Greenhouse Gas Reporting Program

Transcription

1 Greenhouse Gas Reporting Program Subpart W Petroleum and Natural Gas Systems Akachi Imegwu, EPA December 8,

2 For a copy of the presentation slides, visit:

3 Agenda Background and Subpart A- General Rule Requirements (applicability, reporting, monitoring, and recordkeeping) Subpart W- Petroleum and Natural Gas Systems Subpart C- Stationary Fuel Combustion More Information 3

4 Purpose of 40 CFR Part 98 Part 98 requires reporting of greenhouse gas (GHG) emissions and other relevant information from certain source categories in the United States Better understand relative emissions of specific industries, and of individual facilities within those industries Better understand factors that influence GHG emission rates and actions facilities could take to reduce emissions Does not require control of GHG emissions 4

5 More Than 13,000 U.S. Facilities Covered 5

6 Key Elements of Part 98 Annual reporting of GHG by: Direct emitting source categories Suppliers of certain products that would result in GHG emissions if released, combusted or oxidized. 25,000 metric tons CO 2 e or more per year reporting threshold for most sources; capacity-based thresholds where feasible Direct reporting to EPA electronically EPA verification of emissions data 6

7 Applicability 7

8 Applicability for Direct Emitters is Facility-based In most cases, a facility* is defined as Physical property, plant, building, structure, source, or stationary equipment; on contiguous or adjacent properties; in actual physical contact or separated solely by public roadway or other public right of way; and under common ownership or common control *The Onshore Petroleum and Natural Gas Industry Segment and the Natural Gas Distribution Industry Segment of subpart W have a definition of facility that differs from the subpart A definition. 8

9 Assessing Applicability Facility can have multiple source categories. You must evaluate each source category to assess applicability to the rule. If rule applies to any source category, report emissions for all source categories for which methods are provided in the rule. 9

10 Does the Rule Apply to My Facility? SOURCE CATEGORY IN TABLE 1? YES NO SOURCE CATEGORY IN TABLE 2? YES Emit > 25,000 metric tons/yr CO 2 e? YES SUBJECT TO RULE NO STATIONARY COMBUSTION UNITS? NO YES NO YES Is the aggregate maximum rated heat input capacity > 30 mmbtu/hr? NO NOT SUBJECT TO RULE 10

11 Table 1: All-in Source Categories Electricity Generation if report CO 2 year-round through Part 75 Adipic Acid Production Aluminum Production Ammonia Manufacturing Cement Production Fluorinated GHG processes* HCFC-22 Production/ HFC-23 Destruction Processes Lime Manufacturing Nitric Acid Production Petrochemical Production Petroleum Refineries Phosphoric Acid Production Silicon Carbide Production Soda Ash Production Titanium Dioxide Production Municipal Solid Waste Landfills Manure Management Systems** Underground Coal Mines* that are subject to quarterly sampling by MSHA *Applies in reporting year 2011 and beyond. **EPA will not be implementing subpart JJ of 40 CFR part 98 using funds provided in its FY2010 appropriations or Continuing Appropriations Act, 2011 (Public Law ), due to a Congressional restriction prohibiting the expenditure of funds for this purpose. 11

12 Table 2: Threshold Source Categories 1 Electronics Production 2 Ferroalloy Production Fluorinated GHG Production 2 Glass Production Hydrogen Production Industrial Wastewater 2 Treatment Industrial Waste Landfills 2 Iron and Steel Production Lead Production Magnesium Production 2 Petroleum and Natural Gas systems 2 Pulp and Paper Manufacturing Zinc Production 1 >25,000 metric tons CO 2 e per year from all source categories, combustion units, and miscellaneous use of carbonates. 2 Data collection beginning in calendar year

13 Applicability Example #1 Facility Description Required to Report? An offshore petroleum and 2011 (collect data in 10) natural gas production No for subpart W platform has stationary combustion emissions Yes for subpart C exceeding 25,000 metric tons of CO 2 e/year 2012 (collect data in 11) Yes for subpart W Yes for subpart C Explanation The facility must report combustion emissions in 2011 because emissions from stationary combustion are 25,000 metric tons/yr CO 2 e or more. Emissions from both combustion and production would be reported in 2012 because the facility emits 25,ooo metric tons/yr CO 2 e For more examples: 13

14 Applicability Example #2 Facility Description A natural gas transmission compression station emits 24,000 metric tons of CO 2 e/year from stationary combustion and 2,000 metric tons of CO 2 e/year from equipment leaks and vented sources. Required to Report? 2012 (collect data in 11) Yes for subpart W Yes for subpart C Explanation This facility must report under subpart C and subpart W in 2012 because combined emissions from stationary combustion and equipment leaks and vents are 25,000 metric tons/yr CO 2 e or more. For more examples: 14

15 Applicability Tool To help determine if facilities must report Check-off list of source categories Combustion calculator Subpart W calculator Uses easy-to-access information Addresses all industry segments except LNG import/export terminals Provides conservatively high emission estimates 15

16 General Reporting, Monitoring, and Recordkeeping Requirements 16

17 What are the Reporting Requirements? Subpart A: General Provisions Applicability provisions Schedule Reporting and recordkeeping requirements common to all reporters Definitions Report submission procedures Other (e.g., calibration procedures, monitoring plan) Subparts C-UU: Source-Specific Requirements Definition of source category GHG to report Calculation methods Monitoring and QA/QC Missing data procedures Reporting and recordkeeping elements unique to each subpart 17

18 What Do Facilities Report? Identifying information Annual GHG emissions excluding biomass CO 2, metric tons CO 2 e Annual CO 2 emissions from biomass combustion, metric tons Annual emissions of each GHG for each source category, metric tons each gas Other emissions data required by an applicable subpart (e.g., by unit or process line) Verification data required by each subpart (e.g., data used to calculate emissions) Data elements for which a missing data procedure was used Certification by the Designated Representative 18

19 What Is Not Reported? Indirect emissions (e.g., electricity use) Mobile source emissions* (e.g., fleet emissions) Emission offsets *Emissions from portable equipment must be reported under subpart W for the onshore petroleum and natural gas production industry segment. In addition, flare emissions are covered under specified source categories. 19

20 Retain These Records for 3 Years: List of all units, operations, processes, and activities for which GHG emission were calculated All data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type The annual GHG reports Missing data computations Written GHG Monitoring Plan Certification and QA tests Maintenance records for measurement equipment Other data required by applicable subparts 20

21 Monitoring Plan Identifies responsibilities (i.e., job titles) for data collection Explains processes and methods used for data collection Describes QA/QC procedures for monitors May rely on references to existing corporate documents (e.g., existing QA plans, standard operating procedures) Monitoring Plans must be prepared by April 1, 2011 for subpart W reporters 21

22 How Will Emissions Be Verified? Self certification Designated representative certifies and submits report Rule requires one designated representative for each facility and supplier EPA verification Reports submitted through an electronic system Built-in completeness checks for reporters Electronic QA and consistency checks On-site audits 22

23 Electronic Reporting System All reporting under the GHG Reporting Program will be electronic. Web-based system for facility/supplier to EPA reporting Web-forms will guide reporters through data entry and submission. Will include a mechanism to submit file directly using Extensible Markup Language (XML) format. Draft XML schema is available on the EPA website. For updates on the data system, training schedule, and to view the draft XML schema: 23

24 e-ggrt User and Facility Registration On screen directions explain each step of user registration. Additional context sensitive help links

25 Subpart W Petroleum and Natural Gas Systems 25

26 Subpart W Module Topics I. Background on Subpart W II. Industry Segments Covered by Subpart W III.Greenhouse Gases to be Reported IV.Emissions Monitoring and Quantification Methods V. Data Monitoring, Reporting, Recordkeeping, and Missing Data Requirements VI. Special Considerations 26

27 Background: Petroleum and Natural Gas Systems Reporting Rule (Subpart W) Initial petroleum and natural gas systems proposal included in GHG RP (FR 4/10/09) EPA received significant comments on burden, technical approach, and implications for data quality, etc. Re-Proposed petroleum and natural gas systems reporting rule: Published in the Federal Register on April 12, 2010 Public Hearing held April 19, day comment period closed on June 11 Final petroleum and natural gas systems reporting rule: Signed by the Administrator on November 8, 2010 Annual data collection to begin in January 2011; reports due to EPA March

28 II. Industry Segments Covered by Subpart W 28

29 Which petroleum and natural gas industry segments must report under Subpart W? Reporting is required by facilities in specific segments of the petroleum and natural gas industry that emit GHGs 25,000 metric tons carbon dioxide equivalent (CO 2 e) per year: Offshore petroleum and natural gas production Onshore petroleum and natural gas production facilities, basin level reporting* Natural gas processing facilities Natural gas transmission compression Underground natural gas storage Liquefied natural gas (LNG) storage LNG import and export terminals Natural gas distribution, owned or operated by Local Distribution Companies (LDCs)* * Due to their unique characteristics, the facility definition for onshore petroleum and natural gas production and natural gas distribution differs from the definition of facility in subpart A. 29

30 Offshore Petroleum and Natural Gas Production Offshore Petroleum and Natural Gas Production: Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary platform structures connected to the platform structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platforms. Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE reference in 30 CFR through 304 (GOADS). Offshore production facilities that are not under BOEMRE jurisdiction shall use the monitoring methods and calculation methodologies published by BOEMRE referenced in 30 CFR through 304 to calculate and report emissions (GOADS). 30

31 Onshore Petroleum and Natural Gas Production Onshore Petroleum and Natural Gas Production*: Onshore petroleum and natural gas production means all equipment on a well pad or associated with a well pad (including compressors, generators, or storage facilities), and portable non-selfpropelled equipment on a well pad or associated with a well pad (including well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non-transportation-related equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels and all enhanced oil recovery (EOR) operations using CO2, and all petroleum and natural gas production located on islands, artificial islands, or structures connected by a causeway to land, an island, or artificial island. 31

32 Facility Onshore Petroleum and Natural Gas Production Facility with respect to onshore petroleum and natural gas production for purposes of this subpart and for subpart A means all petroleum or natural gas equipment on a well pad or associated with a well pad and CO 2 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility. Onshore petroleum and natural gas production facilities consider only those emissions sources listed in (c) in the rule when determining their threshold 32

33 Onshore Natural Gas Processing Natural gas processing separates and recovers natural gas liquids (NGLs) and/or other non-methane gases and liquids from a stream of produced natural gas using equipment performing one or more of the following processes: oil and condensate removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO2 separated from natural gas streams. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing facility, whether inside or outside the processing facility fence. This source category does not include reporting of emissions from gathering lines and boosting stations. This source category includes: (i) All processing facilities that fractionate. (ii) All processing facilities that do not fractionate with throughput of 25 MMscf per day or greater. 33

34 Natural Gas Transmission Compression Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities in transmission pipelines to natural gas distribution pipelines or into storage. In addition, transmission compressor station may include equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression operated by natural gas processing facilities are included in the onshore natural gas processing segment and are excluded from this segment. This source category also does not include reporting of emissions from gathering lines and boosting stations these sources are currently not covered by subpart W. 34

35 Onshore Natural Gas Underground Storage Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject and recover natural gas into and from the underground storage reservoirs. 35

36 LNG Storage & LNG Import and/or Export Terminals LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and reliquefy boil-off-gas, re-condensers, and vaporization units for regasification of the liquefied natural gas. LNG import equipment means all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers regasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States. 36

37 Natural Gas Distribution Natural gas distribution means the distribution pipelines (not interstate transmission pipelines or intrastate transmission pipelines) and metering and regulating equipment at city gate stations, and excluding customer meters, that physically deliver natural gas to end users and is operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that is operated as an independent municipally-owned distribution system. This segment excludes customer meters and infrastructure and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and "farm taps" upstream of the local distribution company inlet. 37

38 Facility Natural Gas Distribution Facility with respect to natural gas distribution for purposes of this subpart and for subpart A means the collection of all distribution pipelines, metering stations, and regulating stations that are operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system. Natural gas distribution facilities consider only those emissions sources listed in (i) in the rule when determining their threshold. 38

39 III. Greenhouse Gases to Be Reported 39

40 What GHGs will be Reported? Equipment leaks and vented carbon dioxide (CO 2 ) and methane (CH 4 ) emissions. CO 2, CH 4 and nitrous oxide (N 2 O) emissions from flares; Emissions from sources that are listed in Subpart W that are routed to a flare are reported under that particular emission source CO 2, CH 4, and N 2 O combustion emissions For Onshore Petroleum and Natural Gas Production and Natural Gas Distribution, follow subpart W calculation methods. Onshore production industry segment to include portable emissions. For all other industry segments, follow subpart C. 40

41 IV. Emissions Monitoring and Quantification Methods 41

42 How will emissions be calculated? Source Type Natural gas pneumatic device venting Natural gas driven pneumatic pump venting Engineering Estimates Direct Measurement Well venting for liquids unloading X X Gas well venting during well completions without hydraulic fracturing Gas well venting during well completions with hydraulic fracturing Gas well venting during well workovers without hydraulic fracturing Gas well venting during well workovers with hydraulic fracturing X X X X X Leak Detection and Leaker Emission Factor Equipment Count and Population Emission Factor Onshore production storage tanks X X X X X Transmission storage tanks X 42

43 How will emissions be calculated? (cont d) Source Type Well testing venting and flaring Engineering Estimates X Direct Measurement Leak Detection and Leaker Emission Factor Equipment Count and Population Emission Factor Associated gas venting and flaring X Dehydrator vent stacks X X EOR injection pump blowdown X Acid gas removal vent X X Enhanced Oil Recovery (EOR) X X hydrocarbon liquids dissolved CO 2 Centrifugal compressor venting X X X Other emissions from equipment leaks X 2,3,4,5,6,7 X 1,4,5,6,7 Note: Applicable only to the industry segments enumerated as follows: 1. Production 2. Processing 3. Transmission Compression 4. Underground storage 5. LNG storage 6. LNG Import and Export 7. Dis tribution. Sources with multiple methods indicate options for monitoring. 43

44 How will emissions be calculated? (cont d) Source Type Engineering Estimates Direct Measurement Leak Detection and Leaker Emission Factor Equipment Count and Population Emission Factor Blowdown vent stacks X Reciprocating compressor rod packing venting X X X Flare stacks X X Stationary and portable combustion emissions X X Above ground meters and regulators at city gate station equipment leaks X Below ground meter and regulator station equipment leaks Pipeline main equipment leaks Service line equipment leaks X X X 44

45 V. Data Monitoring, Reporting, Recordkeeping, and Missing Data Requirements 45

46 What are the Monitoring and QA/QC Requirements? Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250. All other industry segments must follow the monitoring requirements prescribed in subpart W for: Optical gas imaging instruments Method 21 Infrared laser beam illuminated instruments Acoustic leak detection devices Flow meters, composition analyzers, and pressure gauges Calibrated bags High volume samplers 46

47 Schedule for Monitoring and Reporting for Subpart W Date January 1, 2011 April 1, 2011 April 30, 2011 June 30, 2011 September 30, 2011 January 30, 2012 March 31, 2012 Monitoring/Reporting Item Data collection begins Monitoring plans completed Deadline for BAMM request beyond June 30, 2011 Start collecting data using the required methods (unless BAMM extension is granted) Deadline for BAMM request beyond December 31, 2011 Certificate of Representation due Annual Report Due 47

48 What must be reported? Report activity data and emissions (in metric tons CO2e per year at standard conditions) for each industry segment, as specified Activity counts (e.g. leaking components, equipment counts, pneumatic device counts, miles of pipeline) Activity throughput (e.g. natural gas or crude oil throughput for dehydrators and storage tanks) Measured GHG concentrations (e.g. CO 2 concentration leaving AGR) Where applicable, reporter developed emission factors E.g. well completions, reciprocating compressor rod packing venting, compressor blowdown vents 48

49 What must be recorded? In addition to the reporting requirements reporters must retain the following records: Dates on which measurements were conducted. Results of all emissions detected and measurements. Calibration reports for detection and measurement instruments used. Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. 49

50 Missing Data Requirements If data are lost during annual emissions estimation or measurements, reporter must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting is obtained (data used to substitute for missing data cannot be used for that subsequent year s emissions estimation) For procedures used for obtaining missing data for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection For missing data which are continuously monitored or measured, reporter may use best available data for use in emissions determinations. The reporter must record and report the basis for the best available data in these cases. 50

51 VI. Special Considerations 51

52 Best Available Monitoring Methods Provisions Best available monitoring methods (BAMM) are any of the following methods: monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart; supplier data; engineering calculations; or other company records BAMM are available for three specific instances as well as providing a catch-all provision in the case of unanticipated issues or circumstances. 52

53 BAMM Categories Well related emissions (Automatic Jan Jun ) Eligible sources: Gas well venting during completions and workovers with hydraulic fracture, Well testing venting and flaring Activity data in the first six months ( Automatic Jan Jun 2011) Cumulative hours of venting, days, or times of operation as specified for specific emission sources. Number of blowdowns, completions, workovers, or other events. Cumulative volume produced, volume input or output, or volume of fuel used. Eligible Sources: see (f)(3) for complete listing of eligible sources. Leak detection or emissions measurement (Upon approval for 2011) Eligible sources: compressor venting, acid gas removal units, equipment leaks (excluding onshore production), and transmission storage tanks. Unique or extreme circumstances (Upon approval for 2011) Eligible sources: Sources for which data collection methodologies do not meet safety regulations, or are technically infeasible, or where there are specific laws or regulations that conflict with subpart W data collection methodologies. 53

54 BAMM Subpart W Deadlines April 30, 2011 is the deadline by which owners/operators must submit a request to the Administrator to use BAMM For the period of June 30, 2011 to December 31, 2011 for well related emissions. For the period of June 30, 2011 to December 31, 2011 for specified activity data For the period of January 1, 2011 to December 31, 2011 for leak detection and measurement For the use of BAMM for unique and extreme circumstances September 30, 2011 is the deadline by which owners/operators must submit a request to the Administrator to use BAMM Beyond December 31, 2011 for well related emissions, specified activity data, leak detection and measurement, and for unique and extreme circumstances The administrator will only approve requests that meet the BAMM provisions in the rule. 54

55 Submit all questions to: 55

56 Subpart C*- Stationary Fuel Combustion Sources *All industry segments under subpart W, except for onshore petroleum and natural gas production, and natural gas distribution, are required to report emissions from stationary combustion under subpart C. 56

57 What Units are Covered? Devices that combust solid, liquid, or gaseous fuel for: producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter Examples: Boilers Stationary Internal Combustion Engines Process Heaters/Coal Dryers Combustion Turbines Incinerators Other Stationary Fuel Combustion Equipment (e.g. control devices) Covers any fuel combustion device, unless specifically exempted 57

58 Subpart C does not apply to: Portable equipment* Emergency generators and emergency equipment Agricultural irrigation devices Flares, unless otherwise required by another subpart (Flares must be reported under Subpart W) Electricity Generating Units subject to subpart D Hazardous waste combustion (co-fired fossil fuels only) Pilot fuels *Subpart W requires reporting of portable emissions from the onshore production industry segment. 58

59 How to Report Combustion Emissions Industry Segment Natural Gas Distribution Subpart to follow Include portable equipment? Report emissions from external combustion units 5 MMBtu/hr? Subpart W 1 No No Onshore Production All other industry segments under Subpart W Subpart W 1 Yes No Subpart C No Yes 1 Section (z). 59

60 What GHGs are Reported? CO 2 from stationary combustion Four different methods (Tiers) for calculating CO 2 emissions Different tiers used based on unit size, fuel type, other factors Separately estimate CO2 from sorbent used for acid gas control (unless CO2 is measured with CEMS) CH4 and N2O Emission factors 60

61 CO2 Emission Calculation Tiers Tier For this fuel Measure these parameters And use a default factor for 55 fuels 1 Annual fuel use HHV CO2 emission factor 55 fuels 1 Annual fuel use HHV CO2 emission factor MSW Steam generation CO2 emission factor Solid/liquid Gas Annual fuel use Carbon content Annual fuel use Carbon content Molecular weight All CO Any of the 55 fuels listed in Table C-1 of subpart C, except MSW units that generate steam. 61

62 CH4 and N2O Calculation Methods If you use this Tier for CO2 Tier 1 or Tier 3 Tier 2 Fuel Option Tier 2 Steam Option Tier 4 Measure these parameters 1 Annual fuel use (Eq.C-8) Annual fuel use HHV (Eq. C-9a) Annual steam generation MMBtu/lb steam output (Eq.C-9b) Annual heat input (Eq.C-10) And use a default factor for HHV CH4 emission factor N2O emission factor CH4 emission factor N2O emission factor CH4 emission factor N2O emission factor CH4 emission factor N2O emission factor 1 Use same values as used for CO 2 calculations 62

63 More Information 63

64 Hotline 64 64

65 Web site Information sheets and monitoring checklists for each subpart FAQs (by topic areas) Preamble and rule Technical background documents on source categories Comment response documents Training and Webinar schedule Other technical assistance materials (e.g. applicability tool) Hotline Applicability Tool This document is provided solely for informational purposes. It does not provide legal advice, have legally binding effect, or expressly or implicitly create, expand, or limit any legal rights, obligations, responsibilities, expectations, or benefits in regard to any person. 65

66 Appendix A: What Emissions Sources will be Reported? 66

67 What emission sources will be reported? Source Type Natural gas pneumatic device venting Natural gas driven pneumatic pump venting Acid gas removal vent stack Offshore Production Onshore Production Natural Gas Processing Natural Gas Transmission Compression Underground Storage X X X X X X LNG Storage LNG Import and Export Equipment Distribution Dehydrator vent stacks X X Well venting for liquids unloading X Gas well venting during well completions and workovers with hydraulic fracturing X 67

68 What emissions sources will be reported? (cont d) Source Type Gas well venting during well completions and workovers without hydraulic fracturing Blowdown vent stacks Onshore production storage tanks Transmission storage tanks Well testing venting and flaring Associated gas venting and flaring Offshore Production Onshore Production X Natural Gas Processing Flare stacks X X X X X Natural Gas Transmission Compression Underground Storage LNG Storage LNG Import and Export Equipment X X X X Distribution 68

69 What emissions sources will be reported? (cont d) Source Type Centrifugal compressor venting Reciprocating compressor rod packing venting Other emissions from equipment leaks Population Count and Emissions Factor Vented, Equipment Leaks and Flare Emissions Identified in BOEMRE GOADS Study Offshore Production X Onshore Production Natural Gas Processing Natural Gas Transmission Compression Underground Storage LNG Storage LNG Import and Export Equipment X X X X X X X X X X X X Distribution X X X X X X X X X X X X 69

70 What emissions sources will be reported? (cont d) Source Type Enhanced Oil Recovery hydrocarbon liquids dissolved CO 2 Enhanced Oil Recovery injection pump blowdown Onshore Petroleum and Natural Gas Production and Natural Gas Distribution Combustion Emissions Offshore Production Onshore Production X X X Natural Gas Processing Natural Gas Transmission Compression Underground Storage LNG Storage LNG Import and Export Equipment Distribution X 70