### Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems 1 of 206

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460 OFFICE OF AIR AND RADIATION 

# 40 CFR Part 98 **Subpart W Ru le Redline** 

This document shows the following proposed amendments: 1. 2011 Proposed Technical Corrections to Provisions in Subpart W: Amendments shown with no highlighting. **Comments on proposed technical correction must be submitted according to the instructions in the**  **preamble to that rule. See 76 FR 47392.** 2. 2011 Proposed Technical Revisions to Provisions in Subpart W: Amendments shown with yellow highlighting. **Comments on proposed technical revisions must be submitted according to the instructions in the**  **preamble to that rule.** 3. 2011 Proposed Amendments to Provisions Related to Best Available Monitoring Methods: Amendments shown with green highlighting. **Comments on proposed amendments to provisions related to best available monitoring**  **methods were to be submitted according to the instructions in the preamble to that rule. See 76 FR**  **37300.** Mandatory Reporting of Greenhouse Gases: Technical Revisions to the Electronics Manufacturing and the Petroleum and Natural Gas Systems Categories of the Greenhouse Gas Reporting Rule. Docket: EPA-HQ-OAR-2011-0512



## DRAFT -- **This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011**  Formatted: ___GHG PARAGRAPH, Left

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 2 of 206 Formatted: Font: 8 pt

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### For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows:
PART 98

– [AMENDED] [AMENDED] 1. The authority citation for part 98 continues to
read as follows: **Authority:** 42 U.S.C. 7401-7671q. **Subpart A— [Amended]**  **General Provision [AMENDED]**  2. Section 98.1 is amended by adding paragraph (c) to
read as follows: §98.1 Purpose and scope. (a) This part establishes mandatory greenhouse gas (GHG) reporting requirments for owners and operators of certain facilities that directly emit GHG as well as for certain suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied. (b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of this subpart and all applicable subparts of this part. If a conflict exists between a provision in subpart A and Formatted: Do not check spelling or grammar, Highlight Formatted: Do not check spelling or grammar, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 3 of 206 Formatted: Font: 8 pt

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### any other applicable subpart, the requirements of the applicable subpart shall take precedence. (c) For facilities required to report under onshore petroleum and natural gas production under subpart W of this part, the terms Owner and Operator used in subpart A have the same definitions as Onshore petroleum and natural gas production owner or operator, as defined in §98.238 of this part. 2. Section 98.2 is amended by revising the introductory text to paragraph (a) to read as follows: §98.2 Who must report? (a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C. 1331) and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section: (d) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 

### per year threshold for importerts and Formatted: Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 4 of 206 Formatted: Font: 8 pt

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### exporters of coal-to-liquid products under paragraph (a)(4) of this section, calculate the mass in metric tons per year of CO 2 

### that would result from the complete combustion or oxidation of the quantity of the quantity of coal-to-liquid products that are imported during the reporting year and, that exported during the reporting year. Compare the imported quantities and exported quantities separately to the 25,000 metric ton CO 2 

### per year threshold. Calculate the quantities using the methodologuy specified in subpart LL of this part. (e) To calculate GHG quanitities for comparison to the 25,000 metric ton CO 2 

### e per year threshold for impoerters and exporters of pretroleum products under paragraph (a)(4)(ii) of this section, calculate the mass in metric tons per year
of CO 2 

### that would result from the complete combustion or oxidation of the combined volume of petroleum products and natural gas liquids that are imported during the reporting year and that are exported during the reporting year. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO 2 

### per year threshold. Calculate quantities using the methodology specified in subpart MM of this part.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 5 of 206 Formatted: Font: 8 pt

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### (f) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 

### e per year threshold under paragraph (a)(4) of this section for importers and exporters of industrial greenhouse gases and for importers and exporters of CO 2 

### , the owner or operator shall calculate the mass in metric tons per year of CO 2 

### e imports and exports as described in paragraphs (f)(1) through (f)(3) of this section. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO 2 

### per year threshold. (h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements, if a facility or supplier exceeds the applicability requirments of paragraph (a) of this section at a later time pursuant to §98.3(b)(3). Thus, the owner or operator should reevaluate the applicability to this part (including the revisisng of any relevant emissions caclulations or other calculations) whenever there is any change that could casuse a facility or supplier to meet the applicability requirements ofDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 6 of 206 Formatted: Font: 8 pt

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### paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion. (i) (3) If the operations of a facility or supplier are changed such that all applicable GHG-emitting processes and operations listed in paragraphs (a)(1) through (a)(4) of this section cease to operate, then the owner or operator is exempt from reporting in the years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all GHG-emitting processes and operations no later than March 31 of the year following such changes. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This parargraph (i)(3) does not apply to facilities with municipal solid waster landfills or industrial waste land fills, or to underground coal mines. The owner or operator must resumeDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 7 of 206 Formatted: Font: 8 pt

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### reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.

* * * * * §98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part?

(b) Schedule. The annual GHG report for reporting year 2010 must be submitted no later than September 30, 2011. The annual report for reporting years 2011 and beyond must be submitted no later than March 31 of each calendar year for GHG emissions in the previous calendar year, except as provided in paragraph (b)(1) of this section. (1) For reporting year 2011, GHG information required by the subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section must be submitted no later than September 28, 2012. This reporting date applies only to the data reporting requirements indentified in the listed subparts and does not affect data reporting requirements of other subparts that apply to a facility or supplier. (i) Electronics Manufacturing (subpart I). (ii) Fluorinated Gas Production (subpart L).DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 8 of 206 Formatted: Font: 8 pt

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### (iii) Magnesium Production (subpart T). (iv) Petroleum and Natural Gas Systems (subpart W). (v) Use of Electronic Transmission and Distribution Equipment (subpart DD). (vi) Underground Coal Mines (subpart FF). (vii) Industrial Wastewater Treatment (subpart II). (viii) Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ). (ix) Geologic Sequestration of Carbon Dioxide (subpart RR). (x) Manufacture of Electric Transmission and Distribution (subpart SS). (xi) Industrial Waste Landfills (subpart TT). (xii) Injection of Carbon Dioxide (subpart UU). (4) Unless otherwise stated, if the final day of any time period falls on a weekend or a Federal holiday, the time shall be extended to the next business day.

(c) Content of the annual report. (5)DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 9 of 206 Formatted: Font: 8 pt

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### (ii) Quantity of each GHG from each applicable supply category in Table A-5 of this subpart, expressed in metric tons of each GHG. For fluorinated GHG, report quantities ofall fluorinated GHG, including those not listed in Table A1 of this subpart. (7) A brief description of each “best available monitoring method” used, the parameter measured using the method, and the time period during which the “best available monitoring method” was used, if applicable. (10) NAICS code(s) that apply to the facility or supplier. (i) Primary NAICS code. Report the NAICS code that most accurately describes the facility or supplier’s primary product/activity/service. This primary product/activity/service is the principal source of revenue for the facility or supplier. A facility or supplier that has two distinct products/activities/services providing comparable revenue may report a second primary NAICS code. (ii) Additional NAICS code(s). Report all additional NAICS codes that describe all product(s)/activity(s)/service(s) at the facility orDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 10 of 206 Formatted: Font: 8 pt

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### supplier that are not related to the principal source of

revenue. (11) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the facility or supplier and the percentage of ownership interest for each listed parent company as of December 31 of the year for which data are being reported according to the following instructions: (i) If the facility or supplier is entirely owned by a single United States company that is not owned by another company, provide that company’s legal name and physical address as the United States parent company and report 100 percent ownership. (ii)If the facility or supplier is entirely owned by a single United States company that is, itself, owned by a another company (e.g., it is a division or subsidiary of a higher-level company), provide the legal name and physical address of the highest-level company in the ownership hierarchy as the United States parent company and report 100 percent ownership. (iii) If the facility or supplier is owned by more than one United States company (e.g., company A owns 40DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 11 of 206 Formatted: Font: 8 pt

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### percent, company B owns 35 percent, and company C owns 25 percent), provide the legal names and physical addresses of all the highest-level companies with an ownership interest as the United States parent companies, and report the percent ownership of each company. (iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative. (v) If the facility or supplier is entirely owned by a foreign company, provide the legal name and physical address of the foreign company’s highest-level company based in the United States as the United States parent company, and report 100 percent ownership. (vii) If the facility or supplier is a federally owned facility, report “U.S. Government” and do not report physical address or percent ownership. (g) Recordkeeping. An owner or operator that is required to report GHGs under this part must keep records as specified in this paragraph. Retain all required recordsDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 12 of 206 Formatted: Font: 8 pt

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### for at least 3 years from the date of submission of the annual GHG report for the reporting year in which the record was generated. The records shall be kept in an electronic or hard-copy format (as appropriate) and recorded in a form that is suitable for expeditious inspection and review. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may be retained off site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA, electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part:

3. Section 98.6 is amended by adding the following definitions in alphabetical order and revising the definition of “United States” to read as follows:DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 13 of 206 Formatted: Font: 8 pt

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### 3. Section 98.6 is amended by revising the definitions for “Continuous bleed” and “Intermittent bleed pneumatic devices” to read as follows: §98.6 Definitions. All the terms used in this part shall have the same meaning given in the Clean Air Act and in this section. Absorbent circulation pump means a pump commonly powered by natural gas pressure that circulates the absorbent liquid between the absorbent regenerator and natural gas contactor.
* * * * * Air injected flare means a flare in which air is blown into the base of a flare stack to induce complete combustion of gas.
* * * * * Blowdown vent stack emissions mean natural gas and/or
CO 2 

### released due to maintenance and/or blowdown operations including compressor blowdown and emergency shut-down (ESD) system testing. Emissions from emergency events are not eincluded.
* * * * * Formatted: HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

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### Calibrated bag means a flexible, non-elastic, antistatic bag of a calibrated volume that can be affixed to an emitting source such that the emissions inflate the bag to its calibrated volume.
* * * * * Centrifugal compressor means any equipment that increases the pressure of a process natural gas or CO 2 

### by centrifugal action, employing rotating movement of the driven shaft. Centrifugal compressor dry seals mean a series of rings around the compressor shaft where it exits the compressor case that operates mechanically under the opposing forces to prevent natural gas or CO 2 

### from escaping to the atmosphere. Centrifugal compressor dry seal emissions mean natural gas or CO 2 

### released from a dry seal vent pipe and/or the seal face around the rotating shaft where it exits one or both ends of the compressor case. Centrifugal compressor wet seal degassing vent emissions means emissions that occur when the high-pressure oil barriers for centrifugal compressors are depressurized to release absorbed natural gas or CO 2 

### . High-pressure oilDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 15 of 206 Formatted: Font: 8 pt

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### is used as a barrier against escaping gas in centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated. The separated gas is commonly vented to the atmosphere.
* * * * * Continuous bleed means a continuous flow of pneumatic supply gas to the process measurement control device (e.g. level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flows to the valve controller where the signal is compared with the process set-point to adjust gas pressure in the valve actuator.
* * * * * Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas stream to absorb water vapor. Dehydrator vent emissions means natural gas and CO 2 

### released from a natural gas dehydrator system absorbent Formatted: HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 16 of 206 Formatted: Font: 8 pt

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### (typically glycol) reboiler or regenerator to the atmosphere or a flare, including stripping natural gas and motive natural gas used in absorbent circulation pumps.
* * * * * De-methanizer means the natural gas processing unit that separates methane rich residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in feed natural gas stream.
* * * * * Desiccant means a material used in solid-bed dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include activated alumina, pelletized calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 17 of 206 Formatted: Font: 8 pt

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### * * * * * Gas conditions mean the actual temperature, volume, and pressure of a gas sample.
* * * * * Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.
* * * * * High-bleed pneumatic devices are automated, continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour.
* * * * * Intermittent bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and
used for automatically maintaining a process condition such Formatted: HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

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### as liquid level, pressure, delta-pressure and temperature. These are snap-acting or throttling devices that discharge all or a portion of the full volume of the actuator intermittently when control action is necessary, but does not bleed continuously.
* * * * * Low-bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet per hour.
* * * * * Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm.
* * * * * Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath Formatted: HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 19 of 206 Formatted: Font: 8 pt

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### navigable waters as defined in 43 U.S.C. §1331, and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
* * * * * Reciprocating compressor means a piece of equipment that increases the pressure of a process natural gas or CO 2 

### by positive displacement, employing linear movement of a shaft driving a piston in a cylinder. Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas or CO 2 

### that escapes to the atmosphere. Re-condenser means heat exchangers that cool compressed boil-off gas to a temperature that will condense natural gas to a liquid.
* * * * * Sales oil means produced crude oil or condensate measured at the production lease automatic custody transfer (LACT) meter or custody transfer tank gauge.
* * * * *DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 20 of 206 Formatted: Font: 8 pt

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### Sour natural gas means natural gas that contains significant concentrations of hydrogen sulfide (H 2 

### S)and/or carbon dioxide (CO 2 

### ) that exceed the concentrations specified for commercially saleable natural gas delivered from transmission and distribution pipelines.
* * * * * Supplier mean a producer, importer, or exporter in any supply category included in Table A-5, as defined by the corresponding subpart of this part.

Sweet Gas is natural gas with low concentrations of hydrogen sulfide (H 2 

### S) and/or carbon dioxide (CO 2 

### ) that does not require (or has already had) acid gas treatment to meet pipeline corrosion-prevention specifications for transmission and distribution.
* * * * * United States means the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territorial sea as defined by Presidential Proclamation No. 5928.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 21 of 206 Formatted: Font: 8 pt

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### United States Parent Company(s) means the highestlevel United States company(s) with an ownership interest in the facility or supplier as of December 31 of the year for which data are being reported.
* * * * * Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow-inducing devices, and that is used for routing the gas back into the process as a product and/or
fuel. Vaporization unit means a process unit that performs controlled heat input to vaporize LNG to supply transmission and distribution pipelines or consumers with natural gas.
* * * * * Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 22 of 206 Formatted: Font: 8 pt

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### Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not significantly vent natural gas to the atmosphere. This process may also include high-rate flowback of injected gas, water, oil, and proppant used to fracture or re-fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere.
Well workover means the process(es) of performing one or more of a variety of remedial operations on producing petroleum and natural gas wells to try to increase production. This process also includes high-rate flowbackof injected gas, water, oil, and proppant used to refracture and prop-open new fractures in existing low permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere. Wellhead means the piping, casing, tubing and connected valves protruding above the earth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. Wellhead equipment includes all equipment, permanent and portable,DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 23 of 206 Formatted: Font: 8 pt

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### located on the improved land area (i.e. well pad) surrounding one or multiple wellheads. Wet natural gas means natural gas in which water vapor exceeds the concentration specified for commercially saleable natural gas delivered from transmission and distribution pipelines. This input stream to a natural gas dehydrator is referred to as “wet gas.” 4. Section 98.7 is amended by reserving paragraphs (n) and (o), and by adding paragraphs (p) and q) to read as
follows: 4. Section 98.7 is amended by removing paragraph (q). §98.7 What standardized methods are incorporated by reference into this part?
* * * * * (n) [Reserved] (o) [Reserved] (p) The following material is available for purchase from the American Association of Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584- 2555, http://www.aapg.org

. (1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Formatted: HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 24 of 206 Formatted: Font: 8 pt

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### Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR approved for §98.238. (2) Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 1978, IBR approved for §98.238. (q) The following material is available from the Energy Information Administration (EIA), 1000 Independence Ave., SW, Washington, DC 20585, (202) 586

- 8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publica tions/field_code_master_list/current/pdf/fcml_all.pdf

. (1) Oil and Gas Field Co de Master List 2008, DOE/EIA0370(08), January 2009, IBR approved for §98.238. (2) [Reserved] 5. Table A-4 to subpart A is amended by adding an entry for “Petroleum and Natural Gas Systems (subpart W)” at the end of the table to read as follows: **Table A-4 to Subpart A—Source Category List for §98.2(a)(2)** Source Categories a Applicable in 2010 and Future Years 

### * * * * * * * Additional Source Categories a Applicable in 2011 and Future Years Petroleum and Natural Gas Systems (subpart W)

a Source categories are defined in each applicable subpart 

### . Formatted: Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 25 of 206 Formatted: Font: 8 pt

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### §98.9 Addresses. All requests, notifications, and communications to the Administrator pursuant to this part, other than submittal of the annual GHG report; the certificate of representation; and other requests, notifications or communications that can be submitted through the electric greenhouse gas reporting tool, shall be submitted to the following address: (a) For U.S. mail. Director, Climate Change Division 1200 Pennsylvania Ave., NW Mail Code: 6207J Washington, DC 20460 (b) For package deliveries. Director, Climate Change Division 1310 L St., NW Washington, DC 20005

**Subpart I – [AMENDED]** 5. Section 98.90 is ameneded by revising paragraph (a)(5) to read as follows: Formatted: Indent: First line: 0"

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 26 of 206 Formatted: Font: 8 pt

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### §98.90 Definition of the sourece category. (a) * * * (5) Any electronics manufacturing production process in which fluorinated heat transfer fluids are used to cool process equipment, to control temperature during device testing, to clean substrate surfaces and other parts, and for soldering (e.g., vapor phase reflow). 6. Section 98.92 is amended by revising paragraph (a) introductory text and paragraph (a)(5) to read as follows: §98.92 GHGs to report. (a) You must report emissions of fluorinated GHGs (as defined in §98.6), N 2 

### O, and fluorinated heat transfer fluids (as defined in §98.98). The fluorinated GHGs and fluorinated heat transfer fluids that are emitted from electronics manufacturing production processes include, but are not limited to, those listed in Table I–2 to this subpart. You must individually report, as appropriate:
* * * * (5) Emissions of fluorinated heat transfer fluids.
* * * * Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Numbered + Level: 1 + Numbering Style: a, b, c, ... + Start at: 1 + Alignment: Left + Aligned at: 0.5" + Indent at: 1" Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Indent: First line: 0.5" Formatted: Highlight Formatted: Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Indent: Left: 0", First line: 0.5"

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 27 of 206 Formatted: Font: 8 pt

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### 7. Section 98.93 is amended by revising parargraph (h) introductory text and the definition of “EH i 

### ” in Equation I16 to read as follows: §98.93 Calculating GHG Emissions. (h) If you use fluorinated heat transfer fluids, you must report the annual emissions of fluorinated heat transfer fluids using the mass balance approach described in Equation I-16 of this subpart.
* * * *

EH i 

### = Emissions of fluorinated heat transfer fluids i, (metric tons/year). * * * * 8. Section 98.94 is amended by revising paragraph (h) introductory text to read as follows: §98.94 Monitoring and QA/QC requirements.
* * * * * (h) You must adhere to the QA/QC procedures of this paragraph (h) when calculating annual gas consumption for each fluorinated GHG and N 2 

### O used at your facility and emissions from the use of fluorinated heat transfer fluids.
* * * * * Formatted: No underline, Font color: Auto, Highlight Formatted: Indent: First line: 0.5" Formatted: Font color: Auto, Highlight Formatted: Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 28 of 206 Formatted: Font: 8 pt

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### 9. Section 98.96 is amended by revising paragraph (r)
to read as follows:

§98.96 Data Reporting requirements.
* * * * * (r) For heat transfer fluid emissions, inputs to the heat transfer fluid mass balance equation, Equation I–16 of this subpart, for each fluorinated heat transfer fluid used.
* * * * * 10. Section 98.98 is amended by removing the definition of “Heat transfer fluids” and adding the definition of “Fluorinated heat transfer fluids” in alphabetical order to read as follows: §98.98 Definitions.
* * * * * Fluorinated heat transfer fluids means fluorinated GHGs used for temperature control, device testing, cleaning substrate surfaces and other parts, and soldering in certain types of electronics manufacturing production processes. For fluorinated heat transfer fluids under this subpart I, the lower vapor pressure limit of 1 mm of Hg inDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 29 of 206 Formatted: Font: 8 pt

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### absolute at 25 degrees C in the definition of Fluorinated greenhouse gas in 40 CFR 98.6 shall not apply. Fluorinated heat transfer fluids used in the electronics manufacturing sector include, but are not limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers.
* * * * * **Table I-2 to Subpart I of Part 98—Examples of Fluorinated GHGs and Fluorinated Heat Transfer Fluids Used by the**  **Electronics Industry Product Type**  **Fluorinated GHGs and Fluorinated Heat Transfer Fluids Used During Manufacture**  Electronics CF 4 

### , C 2 

### F 6 

### , C 3 

### F 8 

### , c-C 4 

### F 8 

### , c-C 4 

### F 8 

### O, C 4 

### F 6 

### , C 5 

### F 8 

### , CHF 3 

### , CH 2 

### F 2 

### , NF 3 

### , SF 6 

### , and HTFs(CF 3 

### -(O-CF(CF 3 

### )- CF 2 

### ) n 

### -(O-CF 2 

### ) m 

### -O-CF 3 

### , C n 

### F 2n+2 

### , C n 

### F 2n+1 

### (O)C m 

### F 2m+1 

### , C n 

### F 2n 

### O, (C n 

### F 2 n+1 

### ) 3 N 

### )



### 6. Add subpart W – Petroleum and Natural Gas Systems to read as follows: Formatted: No underline, Font color: Auto, Check spelling and grammar, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Check spelling and grammar, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Check spelling and grammar, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Check spelling and grammar, Highlight Formatted: Indent: First line: 0"DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 30 of 206 Formatted: Font: 8 pt

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### Subpart W—Petroleum and Natural Gas Systems Sec. 98.230 Definition of the source category. 98.231 Reporting threshold. 98.232 GHGs to report. 98.233 Calculating GHG emissions. 98.234 Monitoring and QA/QC requirements. 98.235 Procedures for estimating missing data. 98.236 Data reporting requirements. 98.237 Records that must be retained. 98.238 Definitions.

§98.230 Definition of the source category **.** (a) This source category consists of the following industry segments: (1) 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 floatingDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 31 of 206 Formatted: Font: 8 pt

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### 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. (2) 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 but not limited to compressors, generators, dehydrators, storage vessels, or storage facilities), and portable non-self-propelled equipment which includes on a well pad or associated with a well pad (including well drilling and completion equipment, workover equipment,gravity separation equipment, auxiliary non-transportationrelated 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 CO 2 

### , 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. Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 32 of 206 Formatted: Font: 8 pt

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### (3) Onshore natural gas processing . Natural gas processing means the separation of separates and recovers natural gas liquids (NGLs) and/ or other non-methane gases and liquids from a stream of from produced natural gas , or the separation of NGLs into one or more component mixtures. Separation includes using equipmen t performing one or more of the following processes : forced extraction of natural gas liquids, sulfur and carbon dioxide removal, 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 CO 2 

### separated from natural gas streams. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing plant. facility, whether inside or o utside the processing facility fence. This industry segment includes processing plants that fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual average throughput of 25 MMscf per day or great. source categ ory does not include reporting of emissions from gathering lines and boosting stations. This source category includes: Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 33 of 206 Formatted: Font: 8 pt

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### (i) All processing facilities that fractionate. (ii) All processing facilities that do not fractionate with annual average throughput of 25 MMscf per day or greater. (4) Onshore 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 plants, facilities or in other transmission compressors through transmission pipelines to natural gas distribution pipelines , LNG storage facilities, or into underground storage. In addition, transmission compressor station may include s equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of operated by natural gas processing facilities are included in the onshore natural gas processing plants 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 n ot covered by subpart W
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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 34 of 206 Formatted: Font: 8 pt

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### (5) Underground natural gas 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 reservoirs. (6) Liquefied natural gas (LNG) storage . LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas. (7) LNG import and export equipment . LNG import equipment means all onshore or offshore equipment thatreceives imported LNG via ocean transport, stores LNG, regasifies LNG, and delivers re-gasified natural gas to aDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 35 of 206 Formatted: Font: 8 pt

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### 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. (8) 

### Natural gas distribution . Natural gas distribution means the distribution pipelines (not interstate transmission pipelines or intrastate transmission pipelines) and metering and regulating equipment at metering-regulating city gate stations , and excluding customer meters, that physically deliver natural gas to end users and is that are operated by a Local Distribution Company (LDC) within a single state 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 also excludes customer meters and regulators, 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. (b) [Reserved] §98.231 Reporting threshold. Formatted: No underline, Font color: Auto, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 36 of 206 Formatted: Font: 8 pt

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### (a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of §98.2(a)(2). Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in paragraph §98.232(c) emit 25,000 metric tons of CO 2 

### equivalent or more per year. Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in paragraph §98.232(i) emit 25,000 metric tons of CO 2 

### equivalent or more per year. (b) For applying the threshold defined in §98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment.

§98.232 GHGs to report **.** (a) You must report CO 2 

### , CH 4 

### , and N 2 

### O emissions from each industry segment specified in paragraph (b) through (i) of this section, CO 2 

### , CH 4 

### , and N 2 

### O emissions from each flare as specified in paragraph (j) of this section, andDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 37 of 206 Formatted: Font: 8 pt

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### stationary and portable combustion emissions as applicable as specified in paragraph (k) of this section. (b) For offshore petroleum and natural gas production, report CO 2, 

### CH 4, 

### and N 2 

### O emissions from equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. Offshore platforms do not need to report portable emissions. (c) For an onshore petroleum and natural gas production facility, report CO 2, 

### CH 4 

### , and N 2 

### O emissions from only the following source types on a single well

- pad or associated with a well pad: (1) Natural gas pneumatic device venting. (2) [Reserved] (3) Natural gas driven pneumatic pump venting. (4) Well venting for liquids unloading. (5) Gas well venting during well completions without hydraulic fracturing. (6) Gas well venting during well completions with hydraulic fracturing. Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 38 of 206 Formatted: Font: 8 pt

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### (7) Gas well venting during well workovers without hydraulic fracturing. (8) Gas well venting during well workovers with hydraulic fracturing. (9) Flare stack emissions. (10) Storage tanks vented emissions from produced hydrocarbons. (11) Reciprocating compressor rod packing venting. (12) Well testing venting and flaring. (13) Associated gas venting and flaring from produced hydrocarbons. (14) Dehydrator vents. (15) [Reserved] (16) EOR injection pump blowdown. (17) Acid gas removal vents. (18) EOR hydrocarbon liquids dissolved CO 2 

### . (19) Centrifugal compressor venting. (20) [Reserved] (21) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equipment leak sources (such as instruments, loadingDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 39 of 206 Formatted: Font: 8 pt

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### arms, stuffing boxes, compressor seals, dump lever arms, and breather caps). (22) You must use the methods in §98.233(z) and report under this subpart the emissions of CO 2 

### , CH 4 

### , and N 2 

### O from stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train, and that are located at an onshore petroleum and natural gas production facility as defined in §98.238. production well pad. Stationary or portable equipment are the following equipment which are integral to the extraction, processing or movement of oil or natural gas: well drilling and completion equipment, workover equipment, natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters. (d) For onshore natural gas processing, report CO 2 

### , and CH 4 

### , and N 2 

### O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Dehydrator vents. (5) Acid gas removal vents. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 40 of 206 Formatted: Font: 8 pt

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### (6) Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (e) For onshore natural gas transmission compression, report CO 2 

### , and CH 4 

### , and N 2 

### O emissions from the following

sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Transmission storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) [Reserved] (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (f) For underground natural gas storage, report CO 2 

### , and CH 4 

### , and N 2 

### O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Natural gas pneumatic device venting. (4) [Reserved] (5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 41 of 206 Formatted: Font: 8 pt

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### (g) For LNG storage, report CO 2 

### , and CH 4 

### , and N 2 

### O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other equipment
leak sources. (h) LNG import and export equipment, report CO 2 

### , and
CH 4 

### , and N 2 

### O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Equipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other equipment
leak sources. (i) For natural gas distribution, report CO 2 

### , and CH 4 

### , and N 2 

### O emissions from the following sources: (1) Meters, regulators, and associated equipment at above grade transmission-distribution transfer stations, Above ground meters and regulators at custody transfer city gate stations, including equipment leaks from connectors, block valves, control valves, pressure relief valves, Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 42 of 206 Formatted: Font: 8 pt

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### orifice meters, regulators, and open ended lines. Customer meters are excluded. (2) Equipment leaks from vaults at below grade transmission-distribution transfer stations. ( 3 2 ) Meters, regulators, and associated equipment at above grade metering-regulating station. Above ground meters and regulators at non

- custody transfer city gate stations, including station equipment leaks. Customer meters are excluded. ( 4 3 ) Equipment leaks from vaults at below grade metering-regulating stations. Below ground meters and regulators and vault equipment leaks. Customer meters are excluded. ( 5 4 ) Pipeline main equipment leaks. ( 6 5 ) Service line equipment leaks. ( 7 6 ) Report under subpart W of this part the emissions of CO 2 

### , CH 4 

### , and N 2 

### O emissions from stationary fuel combustion sources following the methods in §98.233(z). (j) [Reserved] All applicable industry segments must report the CO 2 

### , CH 4 

### , and N 2 

### O emissions from each flare. Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 43 of 206 Formatted: Font: 8 pt

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### (k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 

### , CH 4 

### , and N 2 

### O from each stationary fuel combustion unit by following the requirements of subpart C except for facilities under onshore petroleum and natural gas production and natural gas distribution . Onshore petroleum and natural gas production facilities must report stationary and portable combustion emissions as specified in paragraph (c) of this section. Natural gas distribution facilities must report stationary combustion emissions as specified in paragraph (i) of this section. (l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO 2 

### emissions captured and transferred off site by following the requirements of subpart PP. §98.233 Calculating GHG emissions **.** You must calculate and report the annual GHG emissions as prescribed in this section. For actual conditions, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 44 of 206 Formatted: Font: 8 pt

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### (a) Natural gas pneumatic device venting . Calculate
CH 4 

### and CO 2 

### emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W-1 of this section.



## T Conv GHG EF Count Mass i i i s 

## * * * *

, 

##  (Eq. W-1) Where:

Mass s,i 

### = Annual total mass GHG emissions in metric tons CO 2 

### e per year at standard conditions from a natural gas pneumatic device vent, for GHG i. Count = Total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each type as determined in paragraph (a)(1) and (a)(2) of this section. EF = Population emission factors for natural gaspneumatic device venting listed in Tables W1A, W-3, and W-4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission compression, and underground natural gas storage facilities, respectively. GHG i 

### = For onshore petroleum and natural gas production facilities, onshore natural gas transmission compression, and underground natural gas storage, concentration of GHG i 

### i , CH 4 

### , or CO 2 

### , in produced natural gas as defined in paragraph (u)(2)(i) of this section. ; for facilities listed in §98.230(a)( 4 3) and through (a)( 5 8), GHG i 

### equals 1 0.952 for CH 4 

### and 1x10 - 2 

### for CO 2 

### . Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 45 of 206 Formatted: Font: 8 pt

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### Conv i 

### = Conversion from standard cubic feet to metric tons CO 2 

### e; 0.000410 for CH 4 

### , and 0.00005357 for CO 2 

### . T = Total number of hours in the operating year the devices were operational. 24 * 365 = Conversion to yearly emissions estimate. (1) For onshore petroleum and natural gas production, provide the total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each type as follows: (i) In the first calendar year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (ii) In the second consecutive year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (iii) In the third consecutive calendar year, complete the count of all pneumatic devices, including any changes to equipment counted in prior years. Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 46 of 206 Formatted: Font: 8 pt

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### (iv) For the calendar year immediately following the third consecutive calendar year, and for calendar years thereafter, facilities must update the total count of pneumatic devices and adjust accordingly to reflect any modifications due to changes in equipment. (2) For onshore natural gas transmission compression and underground natural gas storage, all natural gas pneumatic devices must be counted in the first year and updated every calendar year. (3) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information.
(b) [Reserved] (c) Natural gas driven pneumatic pump venting.
Calculate CH 4 

### and CO 2 

### emissions from natural gas driven pneumatic pump venting using Equation W-2 of this section. Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under paragraph (c) of this section.



## T Conv GHG EF Count Mass i i i s 

## * * * *

, 

##  (Eq. W-2) Where: Formatted: No underline, Font color: Auto, Check spelling and grammar, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 47 of 206 Formatted: Font: 8 pt

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### Mass s,i 

### = Annual total mass GHG emissions in metric tons CO 2 

### e per year at standard conditions from all natural gas pneumatic pump venting, for GHG i. Count = Total number of natural gas pneumatic pumps. EF = Population emission factors for natural gas pneumatic pump venting listed in Tables W-1A of this subpart for onshore petroleum and natural gas production. GHG i 

### = Concentration of GHG i 

### i , CH 4 

### , or CO 2 

### , in produced natural gas as defined in paragraph (u)(2)(i) of this section
. Conv i 

### = Conversion from standard cubic feet to metric tons CO 2 

### e; 0.000410 for CH 4 

### , and 0.00005357 for CO 2 

### . T = Total number of hours in the operating year the pumps were operational. 24 * 365 = Conversion to yearly emissions estimate. (d) Acid gas removal (AGR) vents . For AGR vent (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO 2 

### only (not CH 4 

### ) vented directly to the atmosphere or through a flare, engine (e.g. permeate from a membrane or de-adsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant using any of the calculation methodologies described in paragraph (d) of this section , as applicable
. (1) Calculation Methodology 1. If you operate and maintain a CEMS that has both a CO 2 

### concentration monitor Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 48 of 206 Formatted: Font: 8 pt

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### and volumetric flow rate monitor measures CO 2 

### emissions according to subpart C of this part , you must calculate CO 2 

### emissions under this subpart by following the Tier 4 Calculation Methodology and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CO 2 

### concentration monitor and CEMS and/or volumetric flow rate monitor are not available, you may elect to install a CO 2 

### concentration monitor and a volumetric flow rate monitor
CEMS that compl y ies with all of the requirements specified for the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion). The calculation and reporting of CH 4 

### and N 2 

### O emissions is not required as part of the Tier 4 requirements for AGRs. (2) Calculation Methodology 2. If CEMS is not available but a vent meter is available , use the CO 2 

### composition and annual volume of vent gas to calculate emissions using Equation W-3 of this section.

E a,CO2 

### = V S 

### * Vol CO2 

### (Eq. W-3)

Where: Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 49 of 206 Formatted: Font: 8 pt

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### E a,CO2 

### = Annual volumetric CO 2 

### emissions at actual conditions, in cubic feet per year. V S 

### = Total annual volume of vent gas flowing out of the AGR unit in cubic feet per year at actual conditions as determined by flow meter using methods set forth in §98.234(b). Vol CO2 

### = Volume fraction of CO 2 

### content in vent gas out of the AGR unit as determined in (d)(6) of this section. (3) Calculation Methodology 3. If using CEMS or a vent meter is not an option available , you may use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO 2 

### using Equation W-4 of this section. 

#   O I O I CO a 

### Vol Vol Vol Vol V E

      



  * ) ( 1 2 , 

### (Eq. W-4)

Where:

E a,CO2 

### = Annual volumetric CO 2 

### emissions at actual condition, in cubic feet per year. V = Total annual volume of natural gas flow into or out of the AGR unit in cubic feet per year at actual condition as determined using methods specified in paragraph (d)(5) of this section.

α = Factor is 1 if the outlet stream flow is measured. Factor is 0 if the inlet stream flow is measured. Vol I 

### = Volume fraction of CO 2 

### content in natural gas into the AGR unit as determined in paragraph (d)(7) of this section.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 50 of 206 Formatted: Font: 8 pt

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### Vol O 

### = Volume fraction of CO 2 

### content in natural gas out of the AGR unit as determined in paragraph (d)(8) of this section. (4) Calculation Methodology 4. If CEMS or a vent meter is not available, you may C c alculate emissions using any standard simulation software packages, such as AspenTech HYSYS ® 

### and API 4679 AMINECalc, that uses the PengRobinson equation of state, and speciates CO 2 

### emissions. A minimum of the following determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best available data must be used to characterize emissions: (i) Natural gas feed temperature, pressure, and flow
rate. (ii) Acid gas content of feed natural gas. (iii) Acid gas content of outlet natural gas. (iv) Unit operating hours, excluding downtime for maintenance or standby. (v) Exit temperature of natural gas. (vi) Solvent pressure, temperature, circulation rate, and weight. (5) Record the gas flow rate of the inlet and outlet natural gas stream of an AGR unit using a meter accordingDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 51 of 206 Formatted: Font: 8 pt

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### to methods set forth in §98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate. (6) If continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream to determine Vol CO2 

### according to methods set forth in §98.234(b). (7) If a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream to determine Vol I 

### according to methods set forth in §98.234(b). (8) Determine volume fraction of CO 2 

### content in natural gas out of the AGR unit using one of the methods specified in paragraph (d)(8) of this section. (i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 52 of 206 Formatted: Font: 8 pt

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### (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream to determine Vol O 

### according to methods set forth in §98.234(b). (iii) Use sales line quality specification for CO 2 

### in natural gas. (9) Calculate CO 2 

### volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (10) Mass CO 2 

### emissions shall be calculated from volumetric CO 2 

### emissions using calculations in paragraph (v) of this section. (11) Determine if emissions from the AGR unit are recovered and transferred outside the facility. Adjust the emission estimated in paragraphs (d)(1) through (d)(10) of this section downward by the magnitude of emission recovered and transferred outside the facility. (e) Dehydrator vents . For dehydrator vents, calculate annual CH 4 

### , CO 2 

### and N 2 

### O (when flared) emissions using any of the calculation methodologies described in paragraph s (e) (1) or (e)(2) of this section.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 53 of 206 Formatted: Font: 8 pt

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### (1) Calculation Methodology 1. Calculate annual mass emissions from dehydrator vents with annual average daily throughput greater than or equal to 0.4 million standard cubic feet per day using a software program, such asAspenTech HYSYS® or GRI-GLYCalc, that uses the PengRobinson equation of state to calculate the equilibrium coefficient, speciates CH 4 

### and CO 2 

### emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump. A minimum of the following parameters determined by engineering estimate based on best available data must be used to characterize emissions from dehydrators: (i) Feed natural gas flow rate. (ii) Feed natural gas water content. (iii) Outlet natural gas water content. (iv) Absorbent circulation pump type (natural gas pneumatic/ air pneumatic/ electric). (v) Absorbent circulation rate. (vi) Absorbent type: including triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG). (vii) Use of stripping natural gas. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 54 of 206 Formatted: Font: 8 pt

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### (viii) Use of flash tank separator (and disposition of recovered gas). (ix) Hours operated. (x) Wet natural gas temperature and pressure. (xi) Wet natural gas composition. Determine this parameter by selecting one of the methods described under paragraph (e)(2)(xi) (e)(1)(xi) of this section. (A) Use the wet natural gas composition as defined in paragraph (u)(2)(i) or (u)(2)(ii) of this section. (B) If wet natural gas composition cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a representative analysis. (C) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in §98.234(b) (1) to sample and analyze wet natural gas composition. (D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated. (2) Calculation Methodology 2. Calculate annual CH 4 

### and CO 2 

### emissions from glycol dehydrators with annualDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 55 of 206 Formatted: Font: 8 pt

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### average daily throughput less than 0.4 million cubic feet per day using Equation W-5 of this section:



## 100 0 * *

, 

## Count EF E i i s 

##  (Eq. W-5) Where:

E s,i 

### = Annual total volumetric GHG emissions (either CO 2 

### or CH 4 

### ) at standard conditions in cubic feet. EF i 

### = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 74.5 for CH 4 

### and 3.26 for CO 2 

### at 68 ° F and 14.7 psia or 73.4 for CH 4 

### and 3.21 for CO 2 

### at 60 ° F and 14.7 psia. Count = Total number of glycol dehydrators with throughput less than 0.4 million cubic feet. 1000 = Conversion of EF i 

### in thousand standard cubic feet to cubic feet. (3) Determine if dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1) or (e)(2) of this section downward by the magnitude of emissions captured. (4) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows: (A) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) and (e)(2) of this section. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 56 of 206 Formatted: Font: 8 pt

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### (B) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas
vent. (5) Dehydrators that use desiccant shall calculate emissions from the amount of gas vented from the vessel every time it is depressurized for the desiccant refilling process using Equation W-6 of this section. Desiccant dehydrators covered in (e)(5) of this section do not have to report emissions under (i) of this section.

E s,n 

### = (H*D 2 

### *P*P 2 

### *%G*365days/yr) (Eq. W-6) (4*P 1 

### *T*1,000cf/Mcf*100)

Where:

E s,n 

### = Annual natural gas emissions at standard conditions in cubic feet. H = Height of the dehydrator vessel (ft). D = Inside diameter of the vessel (ft). P 1 

### = Atmospheric pressure (psia). P 2 

### = Pressure of the gas (psia). P = pi (3.14). %G = Percent of packed vessel volume that is gas. T = Time between refilling (days). 100 = Conversion of %G to fraction.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 57 of 206 Formatted: Font: 8 pt

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### (6) For glycol dehydrators, both CH 4 

### and CO 2 

### mass emissions shall be calculated from volumetric GHG i 

### emissions using calculations in paragraph (v) of this section. For dehydrators that use desiccant, b B oth CH 4 

### and CO 2 

### volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (f) Well venting for liquids unloadings . Calculate
CO 2 

### and CH 4 

### emissions from well venting for liquids unloading using one of the calculation methodologies described in paragraphs (f)(1), (f)(2) or (f)(3) of this section. (1) Calculation Methodology 1 . For one well of each unique well tubing diameter grouping and pressure grouping in each sub-basin category producing horizon/formation combination in each gas producing field (see §98.238 for the definition s of tubing diameter grouping, pressure grouping, and sub-basin category Field ) , where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, a recording flow meter shall be installed on the vent line used to vent gas from the well (e.g. on the vent line off the wellhead separator or atmospheric storage Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 58 of 206 Formatted: Font: 8 pt

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### tank) according to methods set forth in §98.234(b). Calculate emissions from well venting for liquids unloading using Equation W-7 of this section. 

#   h t t h t h n a 

### FR T E

, , , 

### * (Eq. W-7)

Where:

E a,n 

### = Annual natural gas emissions for wells of the same tubing diameter grouping and pressure grouping at actual conditions in cubic feet. T h,t 

### = Cumulative amount of time in hours of venting from all wells of the same tubing diameter grouping p and pressure grouping q (t) and producing horizon (h)/formation combination during the year. FR h,t 

### = Average flow rate in cubic feet per hour of the measured well venting for the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section. h = Total number of different tubing diameter groupings. p = Tubing diameter grouping 1 through h. t = Total number of pressure groupings. q = Pressure grouping 1 through t. (i) Determine the well vent average flow rate as specified under paragraph (f)(1)(i) of this section. (A) The average flow rate per hour of venting is calculated for each unique tubing diameter grouping and pressure grouping in each sub-basin category producing Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 59 of 206 Formatted: Font: 8 pt

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### horizon/formation combination in each producin g field by averaging dividing the recorded total flow rates for by the the recorded time (in hours) of one representative well venting to the atmosphere for a single liquid unloading with venting to the atmosphere
. (B) This average flow rate is applied to all wells in
the field that have the same tubing diameter and producing horizon/formation combination pressure grouping that have the same tubing diameter grouping , for the number of hours of venting these wells. (C) A new average flow rate is calculated every other calendar year for each reporting field and horizon sub-basin category starting the first calendar year of data collection. For a new producing sub-basin category, an average flow rate is calculated beginning in the first year of production. (ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (2) Calculation Methodology 2 . Calculate the total emissions for from each well venting for liquids unloading using Equation W-8 of this section. Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 60 of 206 Formatted: Font: 8 pt

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#          

   

###         
         W

p V

q p q p q q p p p p n s p 

### Z HR SFR SP WD CD V E 1 1 , , 2 3

, 

### 0

. 1 10 37

. 0 (Eq. W-8)

E a,n 

### = {(0.37×10

- 3 

### )*CD 2 

### *WD*SP*N V 

### }+{SFR*(HR

- 1.0)*Z} 

### (Eq. W

- 8)

Where:

E s a ,n 

### = Annual natural gas emissions at actual conditions, in cubic feet/year. W = Total nN umber of wells with well venting for liquids unloading at the facility 0.37×10 -3 

### = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). CD pW 

### = Casing diameter for each well, p, in ( inches )
. WD pW 

### = Well depth from the lowest packer to the bottom of the well to first producing horizon for each well , in ( feet )
. SP pW 

### = Shut-in pressure for each well, p, in pounds square inch atmoshphere (psia). V pW 

### N V 

### = Number of vents per year per well, p
. SFR pW 

### = Average sales flow rate of each gas well , p, at standard conditions in cubic feet per hour. Use Equation W-33 to calculate the sales in cubic feet per hour. HR QV ,PW 

### = Hours that each the well , p, was left open to the atmosphere during each unloading event q . 1.0 = Hours for average well to blowdown casing volume at shut-in pressure. Z V,W Q,P 

### = If HR V,W Q,P 

### is less than 1.0 then Z V,W Q,P 

### is equal to 0. If HR V,W Q,P 

### is greater than or equal to 1.0 then Z V,W Q,P 

### is equal to 1. Formatted: Centered Field Code Changed Formatted: No underline, Font color: Black, Highlight Formatted: No underline, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted ... [1] Formatted ... [2] Formatted ... [3] Formatted ... [4] Formatted ... [5] Formatted ... [6] Formatted ... [7] Formatted ... [8] Formatted ... [9] Formatted ... [10] Formatted ... [11]DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 61 of 206 Formatted: Font: 8 pt

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### (i) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (ii) [Reserved] (3) Calculation Methodology 3 . Calculate emissions from each well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W-9 of this section. 

#          

   

###       
         W

p V

q p q p q q p p p p n s p 

### Z HR SFR SP WD TD V E 1 1 , , 2 3

, 

### 5

. 0 10 37

. 0 (Eq. W-9)

E a,n 

### = {(0.37×10
- 3 

### )*TD 2 

### *WD*SP*N V 

### }+{SFR*(HR

- 0.5)*Z} (Eq. W

- 9)

Where:

E a,n s,n 

### = Annual natural gas emissions at actual standard conditions, in cubic feet/year. W = Number of wells with well venting for liquids unloading at the facility. 0.37×10 -3 

### = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). TD W p 

### = Tubing diameter for each well, p, in ( inches )
. WD W p 

### = Tubing depth to plunger bumper for each well, p, in ( feet )
. SP W p 

### = Sales line pressure for each well, p, in pounds per square in atmospheric (psia). N V 

### V p 

### = Number of vents per year per well for each well, p
. Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: Centered Field Code Changed Formatted: No underline, Font color: Black, Highlight Formatted: Font: Not Italic Formatted: No underline, Font color: Black, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 62 of 206 Formatted: Font: 8 pt

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### SFR W p 

### = Average sales flow rate of each gas well , p, at standard conditions in cubic feet per hour. Use Equation W-33 to calculate the sales flow rate at standard conditions. HR V,W Q,P 

### = Hours that each the well , p, was left open to the atmosphere during each unloading event q . 0.5 = Hours for average well to blowdown tubing volume at sales line pressure. Z V,W Q,P 

### = If HR V,W Q,P 

### is less than 0.5 then Z V,W Q,P 

### is equal to 0. If HR V,W Q,P 

### is greater than or equal to 0.5 then Z V,W Q,P 

### is equal to 1.

(i) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (ii) [Reserved] (4) Both CH 4 

### and CO 2 

### volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (g) Gas well venting during completions and workovers from hydraulic fracturing . Calculate CH 4 

### , CO 2 

### and N 2 

### O (when flared) annual emissions from gas well venting during completions involving hydraulic fracturing in wells and well workovers using Equation W-10 of this section. Both CH 4 

### and CO 2 

### volumetric and mass emissions shall be calculated Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 63 of 206 Formatted: Font: 8 pt

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### from volumetric total gas emissions using calculations in paragraphs (u) and (v) of this section.

ܧ ௔ ௡ , 

### ൌ ∑ ሾ ܶ ܯܴܨ כ כ ܴܲ ݅ 

### െ ܨ݊ܧ ݅ 

### െ ܩܵ ݅ 

### ሿ ݅ 

### (-10W .Eq (

E a,n 

### = (T * FR)

– EnF

- SG (Eq. W

- 10)

Where:

E a,n 

### = Annual volumetric total gas emissions in cubic feet at standard conditions from gas well venting during completions or workovers following hydraulic fracturing for each sub-basin and well type combination
. T = Cumulative amount of time in hours of each all well (p) completion or workover venting in a subbasin and well type combination field during the year reporting. FRM = Venting to 30-day production ratio from Equation W-12. P F R p 

### = First 30-day a A verage production flow rate in standard cubic feet per hour of each well (p) , under actual conditions, converted to standard conditions, as required in paragraph (g)(1) of this section. EnF p 

### = Volume of CO 2 

### or N 2 

### injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job for each well (p) . If the fracture process did not inject gas into the reservoir, then EnF is 0. If injected gas is CO 2 

### then EnF is 0. SG p 

### = Volume of natural gas in cubic feet at standard conditions that was recovered into a sales pipeline for well p as per paragraph (g)(3) of Formatted: Centered Formatted: No underline, Font color: Black, Highlight Formatted ... [12] Formatted ... [13] Formatted ... [14] Formatted ... [15] Formatted ... [16]

Formatted ... [17] Formatted ... [18]

Formatted ... [19] Formatted ... [20] Formatted ... [21] Formatted ... [22] Formatted ... [23] Formatted ... [24] Formatted ... [25] Formatted: No underline, Highlight Formatted ... [26] Formatted ... [27] Formatted ... [28] Formatted ... [29] Formatted ... [30] Formatted ... [31] Formatted ... [32] Formatted ... [33] Formatted ... [34] Formatted ... [35] Formatted ... [36] Formatted ... [37] Formatted ... [38]

Formatted ... [39]

Formatted ... [40]DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 64 of 206 Formatted: Font: 8 pt

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### this section . If no gas was recovered for sales, SG is 0. W = Total number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type combination.

(1) The average flow rate for gas well venting to the atmosphere or to a flare during well completions and workovers from hydraulic fracturing shall be determined using measurement(s) from either of the calculation methodologies described in this paragraph (g)(1) of this section. The number of measurements shall be determined as follows: One measurement for less than or equal to 25 completions/workovers; two measurements for 26 to 50 completions/workovers; three measurements for 51 to 100 completions/workovers; four measurements for 101 to 250 completions/workovers; and five measurements for greater than 250 completions/workovers. (i) Calculation Methodology 1 . For one well completion (s) in each gas producing sub-basin category and well type (horizontal or vertical)combination field and for one well workover in each gas producing field , a recording flow meter (digital or analog) shall be installed on the vent line, ahead of a flare if used, to measure the Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 65 of 206 Formatted: Font: 8 pt

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### backflow venting event according to methods set forth in §98.234(b). (A) The average flow rate in cubic feet per hour of venting to the atmosphere or routed to a flare is determined from the flow recording over the period of backflow venting. (B) The respective flow rates are applied to all well completions in the producing field and to all well workovers in the producing field for the total number of hours of venting of each of these wells. (C) New flow rates for completions and workovers a re measured every other calendar year for each reporting gas producing field and gas producing geologic horizon in each gas producing field starting in the first calendar year of data collection. (D) Calculate total volumetric flow rate at standard condi tions using calculations in paragraph (t) of this section. (ii) Calculation Methodology 2 . For one horizontal well completion and one vertical well completion in each gas producing field sub-basin category and for one well horizontal workover and one well vertical workover in each Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 66 of 206 Formatted: Font: 8 pt

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### gas producing sub-basin category field , record the well flowing pressure upstream(and downstream in subsonic flow) of a well choke according to methods set forth in §98.234(b) to calculate intermittent well flow rate of gas during venting to the atmosphere or a flare. Calculate emissions using Equation W-11 A of this section for subsonic flow or Equation W-1 1B 2 of this section for sonic flow
. : Use equation W-11C of this section to determine whetherflow is sonic or subsonic. If the value of R in Equation W11C is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic:

               

        

 758

. 1

1 2 515

. 1

1 2 5 

### * * 3430 * * 10 * 27

. 1 P P P P T A FR u 

### (Eq. W-11 A )

Where : FR = Average flow rate in cubic feet per hour, under subsonic flow conditions. A = Cross sectional area of orifice (m 2 

### ). P 1 

### = Upstream pressure (psia). T u 

### = Upstream temperature (degrees Kelvin). P 2 

### = Downstream pressure (psia). 3430 = Constant with units of m 2 

### /(sec 2 

### * K). 1.27*10 5 

### = Conversion from m 3 

### /second to ft 3 

### /hour. Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Do not check spelling or grammar, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 67 of 206 Formatted: Font: 8 pt

Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Tab stops: 2.66", Left u 

### T A FR * 08

. 187 * * 10 * 27

. 1 5 

###  

### (Eq. W-1 1B 2 ) Where: FR = Average flow rate in cubic feet per hour, under sonic flow conditions. A = Cross sectional area of orifice (m 2 

### ).
T u 

### = Upstream temperature (degrees Kelvin). 187.08 = Constant with units of m 2 

### /(sec 2 

### * K). 1.27*10 5 

### = Conversion from m 3 

### /second to ft 3 

### /hour.

2 1 P P R  

### (Eq. W-11C) Where: R = Pressure ratio P1 = Pressure upstream of the restriction orifice in pounds per square inch absolute. P2 = Pressure downstream of the restriction orifice in pounds per square inch absolute. ( iii A ) The average flow rate in cubic feet per hour of venting across the choke is calculated for one well completion in each gas producing field and for one well workover in each gas producing field by averaging the gas flow rates during venting to the atmospher e or routing to a flare. The emissions to 30-day production ratio is calculated using Equation W-12 of this section. Formatted: No underline, Highlight Formatted: Indent: First line: 0"

Formatted: Indent: Left: 2.5" Field Code Changed Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Indent: First line: 0" Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Indent: Left: 0", Hanging: 0.5" Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 68 of 206 Formatted: Font: 8 pt

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#  

  

###  W

p p W

p p 

### PR FR FRM

1 1 

### (Eq. W-12)

Where: FRM = Emissions to 30-day production ratio. FR p 

### = Measured flow rate from Calculation Methodology 1 or estimated flow rate from Calculation Methodology 2 in standard cubic feet per hour for well(s) p for each sub-basin and well type (horizontal or vertical) combination. PR p 

### = First 30-day production rate in standard cubic feet per hour for each well p that was measured in the sub-basin and well type combination. W = Number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type formation.

( iv B ) The respective flow rates for horizontal and vertical wells are applied to all horizontal and vertical well completions in the gas producing field sub-basin and well type combination and to all horizontal and vertical
well workovers , respectively, in the gas producing field sub-basin and well type combination for the total number of hours of venting of each of these wells. Field Code Changed

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 69 of 206 Formatted: Font: 8 pt

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### ( v C ) New f F low rates for horizontal and vertical gas
well completions and horizontal and vertical gas well workovers in each field sub-basin category shall be calculated once every two years for each reporting gas producing field and geologic horizon in each gas producing field starting in the first calendar year of data collection. (D) Calculate total volumetric flow rate at standard conditions using calculations in paragraph (t) of this section.
(2) The volume of CO 2 

### or N 2 

### injected into the well reservoir during energized hydraulic fractures will be measured using an appropriate meter as described in 98.234(b) or using receipts of gas purchases that are used for the energized fracture job. (i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. (ii) [Reserved] (3) The volume of recovered completion or workover gas sent to a sales line will be measured using existing Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 70 of 206 Formatted: Font: 8 pt

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### company records. If data does not exist on sales gas, then an appropriate meter as described in 98.234(b) may be used. (i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section.
(ii) [Reserved]
(4) Both CH 4 

### and CO 2 

### volumetric and mass emissions shall be calculated from volumetric total emissions using calculations in paragraphs (u) and (v) of this section. (5) Determine if the well completion or workover from hydraulic fracturing recovered gas with purpose designed equipment that separates saleable gas from the backflow, and sent this gas to a sales line (e.g. reduced emissions completion or workovers ). (i) Use the factor SG in Equation W-10 of this section, to adjust the emissions estimated in paragraphs (g)(1) through (g)(4) of this section by the magnitude of emissions captured using reduced emission completions as determined by engineering estimate based on best available
data. (ii) [Reserved] Formatted: No underline, Font color: Auto, Check spelling and grammar, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 71 of 206 Formatted: Font: 8 pt

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### (6) Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing to flares as follows: (i) Use the total gas well venting volume during well completions and workovers as determined in paragraph (g) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers using hydraulic fracturing emissions from the flare. This adjustment to emissions from completions using flaring versus completions without flaring accounts for the conversion of CH 4 

### to CO 2 

### in the flare. (h) Gas well venting during completions and workovers without hydraulic fracturing . Calculate CH 4 

### , CO 2 

### and N 2 

### O (when flared) emissions from each gas well venting during well completions and workovers not involving hydraulic fracturing and well workovers not involving hydraulic fracturing using Equation W-13 of this section:

f f f wo wo n s 

### T V EF N E * *

, 

#    

### (Eq. W-13)

Where: Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 72 of 206 Formatted: Font: 8 pt

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### E s a ,n 

### = Annual natural gas emissions in standard cubic feet at actual conditions from a gas well venting during well completions and workovers without hydraulic fracturing. N wo 

### = Number of workovers per field not involving hydraulic fracturing in the reporting year. EF wo 

### = Emission Factor for non-hydraulic fracture well workover venting in actual standard cubic feet per workover. EF wo 

### = 3114 2,454 standard cubic feet per well workover without hydraulic fracturing. f = Total number of well completions without hydraulic fracturing in a field sub-basin category . V f 

### V p 

### = Average daily gas production rate in standard cubic feet per hour of each well completion without hydraulic fracturing , p . This is the total annual gas production volume divided by total number of hours the wells produced to the sales line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is completed less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used. T f 

### T p 

### = Time each well completion without hydraulic fracturing , p, was venting in hours during the year. (1) Calculate natural gas volumetric emissions at standard conditions using calculati ons in paragraph (t) of this section. ( 1 2 ) Both CH 4 

### and CO 2 

### v V olumetric and mass emissions
for both CH 4 

### and CO 2 

### shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 73 of 206 Formatted: Font: 8 pt

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### and (v) of this section. Mass emissions for both CH 4 

### and CO 2 

### shall be calculated from volumetric natural gas emissions using calculation in paragraphs (v) of this section. ( 2 3 ) Calculate annual emissions from gas well venting during well completions and workovers not involving hydraulic fracturing to flares as follows: (i) Use the gas well venting volume during well completions and workovers as determined in paragraph (h) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers emissions without hydraulic fracturing from the flare. (i) Blowdown vent stacks . Calculate CO 2 

### and CH 4 

### blowdown vent stack emissions from depressurizing equipment
to reduce system pressure for planned or emergency shutdowns or to take equipment out of service for maintenance the atmosphere (excluding depressurizing to a flare, over-pressure relief, operating pressure control venting and blowdown of non-GHG gases; desiccant dehydrator blowdown venting before reloading is covered in paragraph Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 74 of 206 Formatted: Font: 8 pt

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### (e)(5) of this section) as follows (Emissions from emergency vents are not included.) : (1) Calculate the total physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves determined by engineering estimate based on best available data. (2) If the total physical volume between isolation valves is greater than or equal to 50 standard cubic feet, retain logs of the number of blowdowns for each equipment unique physical volume type (including but not limited to compressors, vessels, pipelines, headers, fractionators, and tanks). Blowdown Physical volumes smaller than 50 standard cubic feet are exempt from reporting under paragraph (i) of this section. (3) Calculate the total annual venting emissions for each equipment type using Equation W-14 of this section: 

#            

            C V P T P T V N E v s a a s v n s 

### * 67

. 459 67

. 459 *

, 

### (Eq. W-14 A )

Where:

E s,n 

### = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet. Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 75 of 206 Formatted: Font: 8 pt

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### N = Number of repetitive blowdowns for each equipment type of a unique volume in calendar year. V v 

### = Total physical volume of blowdown equipment chambers (including pipelines, compressors and vessels) between isolation valves in cubic feet. C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using non-GHG gases. T s 

### = Temperature at standard conditions ( o 

### F). T a 

### = Temperature at actual conditions in the blowdown equipment chamber ( o 

### F). P s 

### = Absolute pressure at standard conditions (psia). P a 

### = Absolute pressure at actual conditions in the blowdown equipment chamber (psia).



#   

#     

# 

 

###                
  
 N

p s a p e a p s a s v n s 

### P T P P T V E 1 , , , ,

, 

### 67

. 459 67

. 459 

### (Eq. W-14B)

Where: E s,n 

### = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet. N = Number of repetitive blowdowns for each unique volume in calendar year. V v 

### = Total volume of blowdown equipment chamber (including pipelines, compressors and vessels) between isolation valves in cubic feet for each blowdown “i.” Field Code Changed Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 76 of 206 Formatted: Font: 8 pt

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### C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using non-GHG gases. T s 

### = Temperature at standard conditions ( o 

### F). T a 

### = Temperature at actual conditions in the blowdown equipment chamber ( o 

### F) for each blowdown “i”. P s 

### = Absolute pressure at standard conditions (psia). P a,s,p 

### = Absolute pressure at actual conditions in the blowdown equipment chamber (psia) at the start of the blowdown “p”. P a,e,p 

### = Absolute pressure at actual conditions in the blowdown equipment chamber (psia) at the end of the blowdown “p”; 0 if blowdown volume is purged using non-GHG gases.

(4) Calculate both CH 4 

### and CO 2 

### volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraph (u) and (v) of this section. (5) Calculate total annual venting emissions for all blowdown vent stacks by adding all standard volumetric and mass emissions determined in Equation W-14 A or W-14B and paragraph (i)(4) of this section. (j) Onshore production storage tanks . Calculate CH 4 

### , CO 2 

### and N 2 

### O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas production facilities (including stationary liquid storage Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 77 of 206 Formatted: Font: 8 pt

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### not owned or operated by the reporter), calculate annual CH 4 

### and CO 2 

### emissions using any of the calculation methodologies described in this paragraph (j). (1) Calculation Methodology 1. For separators with oil annual average daily throughput of oil greater than or equal to 10 barrels per day. Calculate annual CH 4 

### and CO 2 

### emissions from onshore production storage tanks using operating conditions in the last wellhead gas-liquid separator before liquid transfer to storage tanks. Calculate flashing emissions with a software program, such as AspenTech HYSYS® or API 4697 E&P Tank, that uses the Peng-Robinson equation of state, models flashing emissions, and speciates CH 4 

### and CO 2 

### emissions that will result when the oil from the separator enters an atmospheric pressure storage tank. A minimum of the following parameters determined for typical operating conditions over the year by engineering estimate and process knowledge based on best available data must be used to characterize emissions from liquid transferred to tanks. (i) Separator temperature. (ii) Separator pressure. (iii) Sales oil or stabilized oil API gravity.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 78 of 206 Formatted: Font: 8 pt

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### (iv) Sales oil or stabilized oil production rate. (v) Ambient air temperature. (vi) Ambient air pressure. (vii) Separator oil composition and Reid vapor pressure. If this data is not available, determine these parameters by selecting one of the methods described under paragraph (j)(1)(vii i ) of this section. (A) If separator oil composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator pressure first, and API gravity secondarily. (B) If separator oil composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the field sub-basin category . (C) Analyze a representative sample of separator oil in each field subin-basin category for oil composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization. (2) Calculation Methodology 2. Calculate annual CH 4 

### and CO 2 

### emissions from onshore production storage tanks for Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 79 of 206 Formatted: Font: 8 pt

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### wellhead gas-liquid separators with annual average daily oil throughput of oil greater than or equal to 10 barrels per day by assuming that all of the CH 4 

### and CO 2 

### in solution at separator temperature and pressure is emitted from oil sent to storage tanks. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as described in §98.234(b) (1) to sample and analyze separator oil composition at separator pressure and temperature. (3) Calculation Methodology 3 . For wells with annual average daily oil production greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks without passing through a wellhead separator,
calculate annual CH 4 

### and CO 2 

### emissions by either of the methods in paragraph (j)(3) of this section: (i) If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of produced oil and gas from the field sub-basin category and assume all of the CH 4 

### and CO 2 

### in both oil and gas are emitted from the
tank. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 80 of 206 Formatted: Font: 8 pt

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### (ii) If well production oil and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match your well production gas/oil ratio and API gravity and assume all of the CH 4 

### and CO 2 

### in both oil and gas are emitted from the tank. (4) Calculation Methodology 4 . For wells with annual average daily oil production greater than or equal to 10 barrels per day that flow to a separator not at the well pad, calculate annual CH 4 

### and CO 2 

### emissions by either of the methods in paragraph (j)(4) of this section: (i) If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of oil at separator pressure determined by best available data and assume all of the CH 4 

### and CO 2 

### in the oil is emitted from the tank. (ii) If well production oil composition is not available, use default oil composition in software programs, such as API 4697 E&P Tank, that most closely match your well production API gravity and pressure in the off-well pad separator determined by best available data.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 81 of 206 Formatted: Font: 8 pt

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### Assume all of the CH 4 

### and CO 2 

### in the oil phase is emitted
from the tank. (5) Calculation Methodology 5. For well pad gasliquid separators and for wells flowing off a well pad without passing through a gas-liquid separator with throughput less than 10 barrels per day use Equation W-15 of this section:



## 1000 * *

, 

## Count EF E i i s 

##  (Eq. W-15) Where:

E s,i 

### = Annual total volumetric GHG emissions (either CO 2 

### or CH 4 

### ) at standard conditions in cubic feet. EF i 

### = Populations emission factor for separators or and wells in thousand standard cubic feet per separator or well per year, for crude oil use 4.3 for CH 4 

### and 2.9 for CO 2 

### at 68 ° F and 14.7 psia, and for gas condensate use 17.8 for CH 4 

### and 2.9 for CO 2 

### at 68 ° F and 14.7 psia. Count = Total number of separators or and wells with throughput less than 10 barrels per day. 1000 = Conversion to cubic feet (6) Determine if the storage tank receiving your separator oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j)(1) through (j)(5) of this section downward by theDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 82 of 206 Formatted: Font: 8 pt

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### magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved] (7) Determine if the storage tank receiving your separator oil is sent to flare(s). (i) Use your separator flash gas volume and gas composition as determined in this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine your contribution to storage tank emissions from the flare. (8) Calculate emissions from occurrences of well pad gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section. 

#     n n n n n i s 

### T E T E CF E

       

 8760 * * 8760 *

, 

### (Eq. W-16)

Where:

E s,i 

### = Annual total volumetric GHG emissions at standard conditions from each storage tank in cubic feet. E n 

### = Storage tank emissions as determined in Calculation Methodologies 1, 2, or 4 5 in paragraphs (j)(1) , (j)(2) and through (j)( 4 5 ) of this section (with wellhead separators) during time T n 

### in cubic feet per year hour
.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 83 of 206 Formatted: Font: 8 pt

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### T n 

### = Total time the dump valve is not closing properly in the calendar year in hours. T n 

### is estimated by maintenance or operations records (records) such that when a record shows the valve to be open improperly, it is assumed the valve was open for the entire time period preceding the record starting at either the beginning of the calendar year or the previous record showing it closed properly within the calendar year. If a subsequent record shows it is closing properly, then assume from that time forward the valve closed properly until either the next record of it not closing properly or, if there is no subsequent record, the end of the calendar year. CF n 

### = Correction factor for tank emissions for time period T n 

### is 3.87 for crude oil production. Correction factor for tank emissions for time period T n 

### is 5.37 for gas condensate production. Correction factor for tank emissions for time period T n 

### is 1.0 for periods when the dump valve is closed. 8,760 = Conversion to hourly emissions.

E t 

### = Storage tank emissions as determined in C alculation M ethod ologie s 1, 2, or 3 in paragraphs (j)(1) through (j)(5) of this section at maintenance or operations during the time the dump valve is closing properly (ie.8760

- T n 

### ) in cubic feet per hour. (9) Calculate both CH 4 

### and CO 2 

### mass emissions from volumetric natural gas emissions using calculations in paragraph (v) of this section. (k) Transmission storage tanks . For condensate storage tanks, either water or hydrocarbon, without vapor recovery or thermal control devices in onshore natural gasDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 84 of 206 Formatted: Font: 8 pt

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### transmission compression facilities calculate CH 4 

### , CO 2 

### and
N 2 

### O (when flared) annual emissions from compressor scrubber dump valve leakage as follows: (1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging instrument according to methods set forth in §98.234(a)(1) or by directly measuring the tank vent using a flow meter, calibrated bag, or high volume sampler according to methods in §98.234(b) through (d) for a duration of 5 minutes. for a duration of 5 minutes. Or you may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in §98.234(a)(5). (2) If the tank vapors are continuous for 5 minutes, or the acoustic leak detection device detects a leak, then use one of the following two methods in paragraph (k)(2) of this section to quantify annual emissions: (i) Use a meter, such as a turbine meter, calibrated bag, or high flow sampler to estimate tank vapor volumes according to methods set forth in §98.234(b) through (d)
. If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 85 of 206 Formatted: Font: 8 pt

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### vent stack. If the vent is directly measured for five minutes under paragraph §98.233(k)(1) of this section to detect continuous leakage, this serves as the measurement. (ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in §98.234(a)(5). (iii) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. (3) If the leaking dump valve(s) is fixed following leak detection, the annual emissions shall be calculated from the beginning of the calendar year to the time the valve(s) is repaired. (4) Calculate annual emissions from storage tanks to
flares as follows: (i) Use the storage tank emissions volume and gas composition as determined in either paragraph (j)(1) of this section or with an acoustic leak detection device in paragraphs (k)(1) through (k)(3) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine storage tank emissions sent to a from the flare. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 86 of 206 Formatted: Font: 8 pt

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### (l) Well testing venting and flaring. Calculate CH 4 

### , CO 2 

### and N 2 

### O (when flared) well testing venting and flaring emissions as follows: (1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from each well tested. (2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the two procedures in paragraph (l)(2) of this section to determine GOR: (i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (ii) Or you may use an industry standard practice as described in §98.234(b). (3) Estimate venting emissions using Equation W-17 of this section.



## D FR GOR E n

a 

## * *

, 

##  (Eq. W-17)

Where:

E a,n 

### = Annual volumetric natural gas emissions from well testing in cubic feet under actual conditions. GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 87 of 206 Formatted: Font: 8 pt

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### FR = Flow rate in barrels of oil per day for the well being tested. D = Number of days during the year, the well is tested.

(4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (5) Calculate both CH 4 

### and CO 2 

### volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (6) Calculate emissions from well testing to flares
as follows: (i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (3) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare. (m) Associated gas venting and flaring . Calculate
CH 4 

### , CO 2 

### and N 2 

### O (when flared) associated gas venting and flaring emissions not in conjunction with well testingDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 88 of 206 Formatted: Font: 8 pt

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### (refer to paragraph (l): Well testing venting and flaring of this section) as follows: (1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, the GOR from a cluster of wells in the same field sub-basin category shall be used. (2) If GOR cannot be determined from your available data, then use one of the two procedures in paragraph (m)(2) of this section to determine GOR: (i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (ii) Or you may use an industry standard practice as described in §98.234(b). (3) Estimate venting emissions using Equation W-18 of this section.



## V GOR E n

a 

## *

, 

##  (Eq. W-18)

Where:

E a,n 

### = Annual volumetric natural gas emissions from associated gas venting under actual conditions, in cubic feet. Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 89 of 206 Formatted: Font: 8 pt

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### GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. V = Volume of oil produced in barrels in the calendar year during which associated gas was vented or flared. (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (5) Calculate both CH 4 

### and CO 2 

### volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (6) Calculate emissions from associated natural gas
to flares as follows: (i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through (4) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare. (n) Flare stack emissions . Calculate CO 2 

### , CH 4 

### , and
N 2 

### O emissions from a flare stack as follows: (1) If you have a continuous flow measurement device on the flare, you must use the measured flow volumes toDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 90 of 206 Formatted: Font: 8 pt

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### calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records. If you do not have a continuous flow measurement device on the flare, you can install a flow measuring device on the flare or use engineering calculations based on process knowledge, company records, and best available data. (2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follows: (i) For onshore natural gas production, determine natural gas composition using (u)(2)(i) of this section. (ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole percent in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole percent in facility specific residue gas to transmission pipelineDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 91 of 206 Formatted: Font: 8 pt

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### systems for all emissions sources downstream of the demethanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all
streams. (iii) For any applicable industry segment, w W hen the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data. (3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 98 percent. (4) Calculate GHG volumetric emissions at actual conditions using Equations W-19, W-20, and W-21 of this section. 

##   4 4 , 

### * ) 1 ( * CH a CH a 

### X V combusted un E     

### (Eq. W-19)



#   2 2 , 

### * CO a CO a 

### X V combusted un E   

### (Eq. W-20) Formatted: No underline, Font color: Auto, Highlight

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Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 92 of 206 Formatted: Font: 8 pt

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#   

#   

 

###  5

1 2 , 

### * * * J j j a CO a 

### R Y V combusted E  

#   

#   j j j a CO a 

### R Y V combusted E * * * 2 , 

###  

### (Eq. W-21)

Where:

E a,CH4 

### (un-combusted) = Contribution of annual un-combusted CH 4 

### emissions from flare stack in cubic feet, under actual conditions. E a,CO2 

### (un-combusted) = Contribution of annual un-combusted CO 2 

### emissions from flare stack in cubic feet, under actual conditions. E a,CO2 

### (combusted) = Contribution of annual combusted CO 2 

### emissions from flare stack in cubic feet, under actual conditions. V a 

### = Volume of gas sent to flare in cubic feet, during the year. η = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, η is zero. X CH4 

### = Mole fraction of CH 4 

### in gas to the flare. X CO2 

### = Mole fraction of CO 2 

### in gas to the flare. Y j 

### = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus). R j 

### = Number of carbon atoms in the gas hydrocarbon constituent j : 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus). Field Code ChangedDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 93 of 206 Formatted: Font: 8 pt

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### (5) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (6) Calculate both CH 4 

### and CO 2 

### mass emissions from volumetric CH 4 

### and CO 2 

### emissions using calculation in paragraph (v) of this section. (7) Calculate total annual emission from flare stacks by summing Equation W-40, Equation W-19, Equation W-20 and Equation W-21 of this section. (8) Calculate N 2 

### O emissions from flare stacks using Equation W-40 in paragraph (z) of this section. (9) The flare emissions determined under paragraph (n) of this section must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions. If you operate and maintain a CEMS that has both a CO 2 

### concentration monitor and volumetric flow rate monitor, you must calculate CO 2 

### emissions for the flare by following the Tier 4 Calculation Methodology and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 94 of 206 Formatted: Font: 8 pt

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### CEMS is used to calculate flare stack emissions, the requirements specified in paragraphs (n)(1) through (n)(7) are not required. If a CO 2 

### concentration monitor and volumetric flow rate monitor are not available, you may elect to install a CO 2 

### concentration monitor and a volumetric flow rate monitor that comply with all of the requirements specified for the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion). (10) The flare emissions determined under paragraph (n) of this section must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions. (11) If source types in §98.233 use Equations W-19 through W-21 of this section, use estimate of emissions under actual conditions for the parameter, V a 

### , in these equations. (o) Centrifugal compressor venting . Calculate CH 4 

### , CO 2 

### and N 2 

### O (when flared) emissions from both wet seal and dry seal centrifugal compressor vents as follows: (1) For each centrifugal compressor covered by §98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must Formatted: Highlight

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Formatted: Highlight

Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 95 of 206 Formatted: Font: 8 pt

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### conduct an annual measurement in the operating mode in which it is found. Measure emissions from all vents (including emissions manifolded to common vents) including wet seal oil degassing vents, unit isolation valve vents, and blowdown valve vents. Record emissions from the following vent types in the specified compressor modes during the annual measurement. (i) Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compressors. (ii) Operating mode, wet seal oil degassing vents. (iii) Not operating, depressurized mode, unit isolation valve leakage through open blowdown vent, without blind flanges, wet seal and dry seal compressors. (A) For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years. If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode. If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 96 of 206 Formatted: Font: 8 pt

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### (2) For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flare, using a temporary meter such as a vane anemometer or permanent flow meter according to 98.234(b) of this section. If you do not have a permanent flow meter, you may install a permanent flow meter on the wet seal oil degassing tank
vent. (3) For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the following methods: calibrated bagging or high volume sampler according to methods set forth in §98.234(c) and §98.234(d), respectively. For through valve leakage, such as isolation valves, you may use an acoustic leak detection device according to methods set forth in §98.234(a). If you do not have a flow meter, you may install a port for insertion of a temporary meter, or a permanent flow meter, on the vents. (4) Estimate annual emissions using the flow measurement and Equation W-22 of this section. 

## ) 1 ( * * *

, , , m m i m m m i s 

## B M T MT E

  (Eq. W-22)

Where:DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 97 of 206 Formatted: Font: 8 pt

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### E s,i,m 

### = Annual GHG i (either CH 4 

### or CO 2 

### ) volumetric emissions at standard conditions, in cubic feet. MT m 

### = Measured gas emissions in standard cubic feet per hour. T m 

### = Total time the compressor is in the mode for which E s,i 

### is being calculated, in the calendar year in hours. M i,m 

### = Mole fraction of GHG i in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section. B m 

### = Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as determined by keeping logs of the number of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or sales. (5) Calculate annual emissions from each centrifugal compressor using Equation W-23 of this section. 

#  
m i m m m 

### GHG T EF EF * * (Eq. W-23)

Where:

E s,i 

### = Annual total volumetric GHG emissions at standard conditions from each centrifugal compressor in cubic feet. EF m 

### = Reporter emission factor for each mode m, in cubic feet per hour, from Equation W-24 of this section as calculated in paragraph 6. T m 

### = Total time in hours per year the compressor was in each mode, as listed in paragraph (o)(1)(i) through (o)(1)(iii). GHG i 

### = For onshore natural gas processing facilities, concentration of GHG i, CH 4 

### or CO 2 

### , in produced natural gas or feed natural gas; for otherDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 98 of 206 Formatted: Font: 8 pt

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### facilities listed in §98.230(a)(4) through (a)(8),GHG i 

### equals 1. (6) You shall use the flow measurements of operating mode wet seal oil degassing vent, operating mode blowdown valve vent and not operating depressurized mode isolation valve vent for all the reporter’s compressor modes not measured in the calendar year to develop the following emission factors using Equation W-24 of this section for each emission source and mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). 

#  

m m m 

### Count MT EF (Eq. W-24)

Where:

EF m 

### = Reporter emission factors for compressor in the three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii)) in cubic feet per hour. MT m 

### = Flow Measurements from all centrifugal compressor vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section in standard cubic feet per hour. Count m 

### = Total number of compressors measured. m = Compressor mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). (i) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 99 of 206 Formatted: Font: 8 pt

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### totaling three consecutive calendar years of measurements in paragraph (o)(6) of this section. (ii) [Reserved] (7) Onshore petroleum and natural gas production shall calculate emissions from centrifugal compressor wet seal oil degassing vents as follows:

i i s 

## EF Count E *

, 

##  (Eq. W-25)

Where:

E s,i 

### = Annual total volumetric GHG emissions at standard conditions from centrifugal compressor wet seals in cubic feet. Count = Total number of centrifugal compressors for the reporter. EF i 

### = Emission factor for GHG i. Use 12.2 million standard cubic feet per year per compressor for CH 4 

### and 538 thousand standard cubic feet per year per compressor for CO 2 

### at 68°F and 14.7 psia or 12 million standard cubic feet per year per compressor for CH 4 

### and 530 thousand standard cubic feet per year per compressor for CO 2 

### at 60°F and 14.7 psia.

(8) Calculate both CH 4 

### and CO 2 

### mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (9) Calculate emissions from seal oil degassing vent vapors to flares as follows:DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 100 of 206 Formatted: Font: 8 pt

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### (i) Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(5) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare. (p) Reciprocating compressor venting . Calculate CH 4 

### and CO 2 

### emissions from all reciprocating compressor vents as follows. For each reciprocating compressor covered in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual measurement for each compressor in the mode in which it is found during the annual measurement, except as specified in paragraph (p)(9) of this section. Measure emissions from (including emissions manifolded to common vents) reciprocating rod packing vents, unit isolation valve vents, and blowdown valve vents. Record emissions from the following vent types in the specified compressor modes during the annual measurement as follows: (1) Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack. (2) Operating mode, reciprocating rod packing emissions.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 101 of 206 Formatted: Font: 8 pt

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### (3) Not operating, depressurized mode, unit isolation valve leakage through the blowdown vent stack, without blind flanges. (i) For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years if this mode is not found in the annual measurement. If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode. If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode. (ii) [Reserved] (4) If reciprocating rod packing and blowdown vent are connected to an open-ended vent line use one of the following two methods to calculate emissions: (i) Measure emissions from all vents (including emissions manifolded to common vents) including rod packing, unit isolation valves, and blowdown vents using either calibrated bagging or high volume sampler accordingDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 102 of 206 Formatted: Font: 8 pt

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### to methods set forth in §98.234 (c) and §98.234(d), respectively. (ii) Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter to measure emissions from all vents (including emissions manifolded to a common vent) including rod packing vents and unit isolation valve leakage through blowdown vents according to methods set forth in §98.234(b). If you do not have a permanent flow meter, you may install a port for insertion of a temporary meter or a permanent flow meter on the vents. For through-valve leakage to open ended vents, such as unit isolation valves on not operating, depressurized compressors and blowdown valves on pressurized compressors, you may use an acoustic detection device according to methods set forth in §98.234(a). (5) If reciprocating rod packing is not equipped with a vent line use the following method to calculate emissions: (i) You must use the methods described in §98.234 (a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from theDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 103 of 206 Formatted: Font: 8 pt

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### compressor crank case breather cap or other vent with a closed distance piece. (ii) Measure emissions found in paragraph (p)(5)(i) of this section using an appropriate meter, or calibrated bag, or high volume sampler according to methods set forth in §98.234(b), (c), and (d), respectively. (6) Estimate annual emissions using the flow measurement and Equation W-26 of this section.

m i m m m i s 

### M T MT E

, , , 

### * *  (Eq. W-26)

Where:

E s,i,m 

### = Annual GHG i (either CH 4 

### or CO 2 

### ) volumetric emissions at standard conditions, in cubic feet. MT m 

### = Measured gas emissions in standard cubic feet per hour. T m 

### = Total time the compressor is in the mode for which E s,i,m 

### is being calculated, in the calendar year in hours. M i,m 

### = Mole fraction of GHG i in gas; use the appropriate gas compositions in paragraph (u)(2) of this section. (7) Calculate annual emissions from each reciprocating compressor using Equation W-27 of this section. 

#  
m i m m i s 

### GHG T EF E * *

, 

### (Eq. W-27)DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 104 of 206 Formatted: Font: 8 pt

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### Where:

E s,i 

### = Annual total volumetric GHG emissions at standard conditions from each reciprocating compressor in cubic feet. EF m 

### = Reporter emission factor for each mode, m, in cubic feet per hour, from Equation W-28 of this section as calculated in paragraph (p)(7)(i) of this section. T m 

### = Total time in hours per year the compressor was in each mode, m, as listed in paragraph (p)(1) through (p)(3). GHG i 

### = For onshore natural gas processing facilities, concentration of GHG i, CH 4 

### or CO 2 

### , in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHG i 

### equals 1. m = Compressor mode as listed in paragraph (p)(1) through (p)(3).

(i) You shall use the flow meter readings from measurements of operating and standby pressurized blowdown vent, operating mode vents, not operating depressurized isolation valve vent for all the reporter’s compressor modes not measured in the calendar year to develop the following emission factors using Equation W-28 of this section for each mode as listed in paragraph (p)(1) through (p)(3). 

#  

m m m 

### Count MT EF (Eq. W-28)DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 105 of 206 Formatted: Font: 8 pt

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### Where:

EF m 

### = Reporter emission factors for compressor in the three modes, m, in cubic feet per hour. MT m 

### = Meter readings from all reciprocating compressor vents in each and mode, m, in standard cubic feet per hour. Count m 

### = Total number of compressors measured in each mode, m. m = Compressor mode as listed in paragraph (p)(1) through (p)(3). (A) You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes. (B) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements. (ii) [Reserved] (8) Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (p)(7) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved]DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 106 of 206 Formatted: Font: 8 pt

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### (9) Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors as follows:

i i s 

## EF Count E *

, 

##  (Eq. W-29)

Where:

E s,i 

### = Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in cubic feet. Count = Total number of reciprocating compressors for the reporter. EF i 

### = Emission factor for GHG i. Use 9.63 thousand standard cubic feet per year per compressor for CH 4 

### and 0.535 thousand standard cubic feet per year per compressor for CO 2 

### at 68°F and 14.7 psia or 9.48 thousand standard cubic feet per year per compressor for CH 4 

### and 0.527 thousand standard cubic feet per year per compressor for CO 2 

### . at 60°F and 14.7 psia. (10) Estimate CH 4 

### and CO 2 

### volumetric and mass emissions from volumetric natural gas emissions using the calculations in paragraphs (u) and (v) of this section. (q) Leak detection and leaker emission factors . You must use the methods described in §98.234(a) to conduct leak detection(s) of equipment leaks from all sources listed in **§** 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies to emissionsDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 107 of 206 Formatted: Font: 8 pt

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### sources in streams with gas content greater than 10 percent
CH 4 

### plus CO 2 

### by weight. Emissions sources in streams with gas content less than 10 percent CH 4 

### plus CO 2 

### by weight do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported. If equipment leaks are detected for sources listed in this paragraph (q), calculate equipment leak emissions per source per reporting facility using Equation W-30 of this section for each source with equipment leaks. 

#   

 

###  x

p p i i s 

### T EF GHG E 1

, 

### * * 

#  
x x s i i s 

### T EF GHG E * *

, 

### (Eq. W-30)

Where:

E s,i 

### = Annual total volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet. x = Total number of this type of emissions source found to be leaking during T x 

### each equipment leak source . EF s 

### = Leaker emission factor for specific sources listed in Table W-2 through Table W-7 of this subpart. GHG i 

### = For onshore natural gas processing facilities, concentration of GHG i 

### , CH 4 

### or CO 2 

### , in the total hydrocarbon of the feed natural gas; for other facilities listed in §98.230(a)(4) and (a)(5),GHG i 

### equals 0.974 for CH 4 

### and 1.0 × 10 -2 Field Code Changed

Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 108 of 206 Formatted: Font: 8 pt

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### for CO 2 

### ; for facilities listed in §98.230(a)(6) and (a)(7), GHG i 

### equals 1 for CH 4 

### and 0 for CO 2 

### ; and for facilities listed in §98.230(a)(8), GHG i 

### equals 1 for CH 4 

### and 1.1×10 -2 

### CO 2 

### . through (a)(8), GHG i 

### equals 1 for CH 4 

### and 1.1 × 10 - 2 

### for CO 2 

### . T x 

### T p 

### = The total time the component , p, was found leaking and operational, in hours. If one leak detection survey is conducted, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey or the beginning of the entire calendar year. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey or the beginning of the calendar year. For the last leak detection survey in the calendar year, assume that all leaking components continue to leak until the end of the calendar year. (1) You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year. The number of leak detection surveys selected must be conducted during the calendar year. (2) Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions using calculations in paragraph (v) of this section. (3) Onshore natural gas processing facilities shall use the appropriate default leaker emission factors listed in Table W-2 of this subpart for equipment leaks detected Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight

Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, Highlight Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 109 of 206 Formatted: Font: 8 pt

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### from valves, connectors, open ended lines, pressure relief valves, and meters. (4) Onshore natural gas transmission compression facilities shall use the appropriate default leaker emission factors listed in Table W-3 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters. (5) Underground natural gas storage facilities for storage stations shall use the appropriate default leaker emission factors listed in Table W-4 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters. (6) LNG storage facilities shall use the appropriate default leaker emission factors listed in Table W-5 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other. (7) LNG import and export facilities shall use the appropriate default leaker emission factors listed in Table W-6 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other. (8) Natural gas distribution facilities for above ground meters and regulators at city gate stations at Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 110 of 206 Formatted: Font: 8 pt

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### custody transfer grade transmission-distribution transfer stations , shall use the appropriate default leaker emission factors listed in Table W-7 of this subpart for equipment leak detected from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines. Leak detection at natural gas distribution facilities is only required at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and metering-regulating stations that do not meet the definition of transmission-distribution transfer stations are not required to perform component leak detection under this section. (r) Population count and emission factors . This paragraph applies to emissions sources listed in **§** 98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4) and (i)(5), on streams with gas content greater than 10 percent
CH 4 

### plus CO 2 

### by weight. Emissions sources in streams with gas content less than 10 percent CH 4 

### plus CO 2 

### by weight do not need to be reported. Tubing systems equal or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be Formatted: No underline, Font color: Auto, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 111 of 206 Formatted: Font: 8 pt

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### reported. Calculate emissions from all sources listed in this paragraph using Equation W-31 of this section.

s i s s i s 

## T GHG EF Count E * * *

, 

##  (Eq. W-31)

Where:

E s,i 

### = Annual volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet. Count s 

### = Total number of this type of emission source at the facility. For onshore petroleum and natural gas production, a A verage component counts are provided by major equipment piece in Tables W-1B and Table W-1C of this subpart. Use average component counts as appropriate for operations in Eastern and Western U.S., according to Table W-1D of this subpart. Underground natural gas storage shall count the components listed for population emission factors in Table W-4. LNG Storage shall count the number of vapor recovery compressors. LNG import and export shall count the number of vapor recovery compressors. Natural gas distribution shall count the respective component for each emission factor as described in paragraph (r)(6) of this section. EF s 

### = Population emission factor for the specific source, s listed in Table W-1A and Tables W-3 through Table W-7 of this subpart. Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W-1D of this subpart. EF formeter/regulator runs at above grade meteringregulating stations is determined in Equation W32 of this section. EF for non

- custody transfer city gate stations is determined in Equation W

32. Formatted: No underline, Font color: Auto, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 112 of 206 Formatted: Font: 8 pt

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### GHG i 

### = For onshore petroleum and natural gas production facilities and onshore natural gas processing facilities, concentration of GHG i, CH 4 

### or CO 2 

### , in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHG i 

### equals 1 for CH 4 

### and 1.1 × 10 -2 

### for CO 2 

### . T s 

### = Total time the specific source s associated with the equipment leak emission was operational in the calendar year, in hours.

(1) Calculate both CH 4 

### and CO 2 

### mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (2) Onshore petroleum and natural gas production facilities shall use the appropriate default population emission factors listed in Table W-1A of this subpart for equipment leaks from valves, connectors, open ended lines, pressure relief valves, pump, flanges, and other. Major equipment and components associated with gas wells are considered gas service components in reference to Table 1-A of this subpart and major natural gas equipment in reference to Table W-1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table 1-A of this subpart and major crude oil equipment inDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 113 of 206 Formatted: Font: 8 pt

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### reference to Table W-1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO 2 

### stream. The component count can be determined using either of the methodologies described in this paragraph (r)(2). The same methodology must be used for the entire calendar year. (i) Component Count Methodology 1 . For all onshore petroleum and natural gas production operations in the facility perform the following activities: (A) Count all major equipment listed in Table W-1B and Table W-1C of this subpart. For meters/piping, use one meters/piping per well-pad. (B) Multiply major equipment counts by the average component counts listed in Table W-1B and W-1C of this subpart for onshore natural gas production and onshore oil production, respectively. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart. (ii) Component Count Methodology 2 . Count each component individually for the facility. Use the Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 114 of 206 Formatted: Font: 8 pt

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### appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart. (3) Underground natural gas storage facilities for storage wellheads shall use the appropriate default population emission factors listed in Table W-4 of this subpart for equipment leak from connectors, valves, pressure relief valves, and open ended lines. (4) LNG storage facilities shall use the appropriate default population emission factors listed in Table W-5 of this subpart for equipment leak from vapor recovery
compressors. (5) LNG import and export facilities shall use the appropriate default population emission factor listed in Table W-6 of this subpart for equipment leak from vapor
recovery compressors. (6) Natural gas distribution facilities shall use the appropriate emission factors as described in paragraph (r)(6) of this section. (i) Below grade metering-regulating stations (including below grade T-D transfer stations); distribution mains; and distribution services, shall use the appropriate Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 115 of 206 Formatted: Font: 8 pt

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### default population emission factors listed in Table W-7 of this subpart. Below grade meters and regulators; mains; and services, shall use the appropriate default population emission factors listed in Table W

- 7 of this subpart. (ii) Emissions from all above grade meteringregulating stations (including above grade TD transfer stations) shall be calculated by applying the emission factor calculated in Equation W-32 and the total count of meter/regulator runs at all above grade metering-regulatingstations (inclusive of TD transfer stations) to Equation W31. The facility wide emission factor in Equation W-32 will be calculated by using the total volumetric GHG emissions at standard conditions for all equipment leak sources calculated in paragraph (q)(8) of this section and the count of meter/regulator runs located at above grade transmission-distribution transfer stations. Above grade meters and regulators at city gate stations not at custody transfer as listed in §98.232(i)(2), shall use the total volumetric GHG emissions at standard conditions for all equipment leak sources calculated in paragraph (q)(8) of this section to develop facility emission factors using Equation W

- 32 of this section. The calculated facility Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 116 of 206 Formatted: Font: 8 pt

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### emission factor from Equation W

- 32 of this section shall be used in Equation W

- 31 of t his section.

Count E EF i s 

### 8760

, 

###   

#  Count E EF i s , 

#   

### (Eq. W-32)

Where:

EF i 

### EF = Facility emission factor for a meter/regulator run at above grade metering-regulating for GHG i 

### in cubic feet per meter/regulator run per hour. meter at above grade M&R at city gate stations not at custody transfer in cubic feet per meter per year. E s,i 

### = Annual volumetric GHG i 

### emissions , CO 2 

### or CH 4 

### at standard condition from all equipment leak sources at all above grade M&R city gate TD transfer stations at custody transfer , from paragraph (q) of this section. Count = Total number of meter /regulator runs at all above grade M&R city gate stations at custody transfer. TD transfer stations. 8760 = Conversion to hourly emissions (s) Offshore petroleum and natural gas production facilities. Report CO 2 

### , CH 4 

### , and N 2 

### O emissions for offshore petroleum and natural gas production from all equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. Field Code Changed

Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 117 of 206 Formatted: Font: 8 pt

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### (1) 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 referenced in 30 CFR 250.302 through 304 (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study. (ii) [Reserved] (2) Offshore production facilities that are not under BOEMRE jurisdiction shall use monitoring methods and calculation methodologies published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, report the most recent reported emissions data with emissions adjusted based on the operating time for the facilityDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 118 of 206 Formatted: Font: 8 pt

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### relative to operating time in the previous reporting period. (ii) [Reserved] (3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to report emission from the facility sources. (4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle shall use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS) to report emissions. (t) Volumetric emissions . Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section , with actual pressure and temperature determined by engineering estimate based on best available data unless otherwise specified. (1) Calculate natural gas volumetric emissions at standard conditions by converting using actual natural gas Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 119 of 206 Formatted: Font: 8 pt

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### emission temperature and pressure of natural gas emissions to standard temperature and pressure , of natural gas using and Equation W-33 of this section. 

#     s a a s n a n s 

### P T P T E E 

### * 67

. 459 * 67

. 459 *

,

, 

###  

 (Eq. W-33)

Where:

E s,n 

### = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. E a,n 

### = Natural gas volumetric emissions at actual conditions in cubic feet. T s 

### = Temperature at standard conditions ( o 

### F). T a 

### = Temperature at actual emission conditions ( o 

### F). P s 

### = Absolute pressure at standard conditions (psia). P a 

### = Absolute pressure at actual conditions (psia).

(2) Calculate GHG volumetric emissions at standard conditions by converting using actual GHG emissions temperature and pressure , and of GHG emissions to standard temperature and pressure using Equation W-34 of this section.

(Eq. W-34)

Where:    
s a a s i a i s P T P T E E * 67

. 459 * 67

. 459 *

,

,  
 Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 120 of 206 Formatted: Font: 8 pt

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### E s,i 

### = GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. E a,i 

### = GHG i volumetric emissions at actual conditions in cubic feet. T s 

### = Temperature at standard conditions ( o 

### F). T a 

### = Temperature at actual emission conditions ( o 

### F). P s 

### = Absolute pressure at standard conditions (psia). P a 

### = Absolute pressure at actual conditions (psia).

(u) GHG volumetric emissions

. Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section , determined by engineering estimate based on best available data unless otherwise specified. with mole fraction of GHGs in the natural gas determined by engineering estimate based on best available data unless otherwise specified. (1) Estimate CH 4 

### and CO 2 

### emissions from natural gas emissions using Equation W-35 of this section.

(Eq. W-35)

Where:

E s,i 

### = GHG i (either CH 4 

### or CO 2 

### ) volumetric emissions at standard conditions in cubic feet. E s,n 

### = Natural gas volumetric emissions at standard conditions in cubic feet. i n s i s 

### M E E *

, , 

###  Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 121 of 206 Formatted: Font: 8 pt

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### M i 

### = Mole fraction of GHG i in the natural gas.

(2) For Equation W-35 of this section, the mole fraction, M i 

### , shall be the annual average mole fraction for each sub-basin category or facility, as specified in paragraphs (u)(2)(i) through (vii) of this section. (i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities. If you have a continuous gas composition analyzer for produced natural gas, you must use an annual average of these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you
must use an annual average your most recent gas composition based on available sample analysis of the field sub-basin categories
. (ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 122 of 206 Formatted: Font: 8 pt

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### solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in §98.234(b). (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for onshore natural gas transmission compression facilities. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (iv) GHG mole fraction in natural gas stored in underground natural gas storage facilities. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (v) GHG mole fraction in natural gas stored in LNG storage facilities. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (vi) GHG mole fraction in natural gas stored in LNG import and export facilities. For export facilities that Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 123 of 206 Formatted: Font: 8 pt

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### receive gas from transmission pipelines, you may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (v) GHG mass emissions . Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions by converting the GHG volumetric emissions at standard conditions into mass emissions using Equation W-36 of this section.

(Eq. W-36) Where:

Mass s,i 

### = GHG i (either CH 4 

### , or CO 2 

### , or N 2 

### O ) mass emissions at standard conditions in metric tons CO 2 

### e. E s,i 

### = GHG i (either CH 4 

### , or CO 2 

### , or N 2 

### O ) volumetric emissions at standard conditions, in cubic feet. = Density of GHG i. Use 0. 0520 0538 kg/ft 3 

### for CO 2 

### and N 2 

### O, and 0. 0190 0196 kg/ft 3 

### for CH 4 

### at 68°F and 14.7 psia or 0.0530 kg/ft 3 

### for CO 2 

### and N 2 

### O, and 0.0193 kg/ft 3 

### for CH 4 

### at 60°F and 14.7 psia . 3

, , 

### 10 * * *  

###  GWP

E Mass i i s i s 

### 

i 

## 
i  Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 124 of 206 Formatted: Font: 8 pt

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### GWP = Global warming potential, 1 for CO 2, 

### 21 for CH 4 

### , and 310 for N 2 

### O.

(w) EOR injection pump blowdown . Calculate CO 2 

### pump blowdown emissions as follows: (1) Calculate the total volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves. (2) Retain logs of the number of blowdowns per calendar year. (3) Calculate the total annual venting emissions using Equation W-37 of this section:

3

, 

### 10 * * * *  

###  i c v i c 

### GHG R V N Mass 

### (Eq. W-37)

Where:

Mass c,i 

### = Annual EOR injection gas venting emissions in metric tons at critical conditions “c” from blowdowns. N = Number of blowdowns for the equipment in the calendar year. V v 

### = Total volume in cubic feet of blowdown equipment chambers (including pipelines, manifolds and vessels) between isolation valves. R c 

### = Density of critical phase EOR injection gas in kg/ft 3 

### . You may use an appropriate standard method published by a consensus-based standardsDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 125 of 206 Formatted: Font: 8 pt

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### organization if such a method exists or you may use an industry standard practice to determine density of super critical EOR injection gas. GHG i 

### = Mass fraction of GHG i 

### in critical phase injection gas. 1 × 10 -3 

### = Conversion factor from kilograms to metric tons. (x) EOR hydrocarbon liquids dissolved CO 2 

### . Calculate dissolved CO 2 

### in hydrocarbon liquids produced through EOR operations as follows: (1) Determine the amount of CO 2 

### retained in hydrocarbon liquids after flashing in tankage at STP conditions. Annual samples must be taken according to methods set forth in §98.234(b) to determine retention of
CO 2 

### in hydrocarbon liquids immediately downstream of the storage tank. Use the annual analysis for the calendar
year. (2) Estimate emissions using Equation W-38 of this section.

Mass s,CO2 

### = S hl 

### * V hl 

### (Eq. W-38)

Where:

Mass s,CO2 

### = Annual CO 2 

### emissions from CO 2 

### retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 126 of 206 Formatted: Font: 8 pt

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### S hl 

### = Amount of CO 2 

### retained in hydrocarbon liquids in metric tons per barrel, under standard conditions. V hl 

### = Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year.

(y) [Reserved] (z) Onshore petroleum and natural gas production and natural gas distribution combustion emissions. Calculate
CO 2 

### CH 4 

### , and N 2 

### O combustion-related emissions from stationary or portable equipment , except as specified in paragraph (z)(3) of this section, as follows: (1) If the fuel combusted in the stationary or portable equipment is listed in Table C-1 of subpart C of this part, or is a blend of containing one or more fuels listed in Table C-1, use the Tier 1 methodology described in subpart C of this part (Gen eral Stationary Fuel Combustion Sources) calculate emissions according to (z)(1)(i) . If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation methodology described in (z)(1)(i) and you may used the then the natural gas emission factor provided for Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 127 of 206 Formatted: Font: 8 pt

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### natural gas as and high heat values listed in Table s C-1
. and C

- 2 of this part may be used. If the fuel is natural gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to (z)(2). If the fuel is field gas, process vent gas, or blend containing field gas or process vent gas, calculate emissions according to (z)(2). (i) For fuels listed in Table C-1 or a blend containing one more fuels listed in Table C-1, calculate CO2, CH4, and N2O emissions according to any Tier listed in subpart C of this part. You must follow all applicable calculation requirements for that tier listed in 98.33, any monitoring or QA/QC requirements listed for that tier in 98.34, any missing data procedures specified in 98.35, and any recordkeeping requirements specified in 98.37. (ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural gas and petroleum production facilities and at natural gas distribution facilities will be reported according to the requirements specified in 98.236(c)(19) and not according to the reporting requirements specified in subpart C of this part. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 128 of 206 Formatted: Font: 8 pt

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### (2) For fuel combustion units that combust field gas or process vent gas, or any a blend of containing field gas or process vent gas , or natural gas that is not of pipeline quality or that has a high heat value of less than 950 Btu per standard cubic feet, and fuels listed in Table C

- 1 of subpart C of this part, calculate combustion emissions as
follows: (i) If you have a continuous flow meter on the combustion unit, you must use the measured flow volumes to calculate the total flow of gas to the uni t. If you do not have a permanent flow meter on the combustion unit, you may install a permanent flow meter on the combustion unit, or use company records or engineering calculations based on best available data on heat duty or horsepower to estimate
volu metric unit gas flow. You may use company records to determine the volume of fuel combusted in the unit during the reporting year. (ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 129 of 206 Formatted: Font: 8 pt

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### gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in paragraph (u)(2)(i) of this section. (iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39 of this section. 

#   

#    j j j a CO a CO a 

### R Y V Y V E * * * * 2 2 , 

###  

### (Eq. W-39 A )

4 4 , 

### * ) 1 ( * CH a CH a 

### Y V E    

### (Eq. W-39B)
Where:

E a,CO2 

### = Contribution of annual emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions. E a,CH4 

### = Contribution of annual CH 4 

### emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.  = Combustion efficiency for portable and stationary equipment determined based on engineering estimation. V a 

### = Volume of gas sent to combustion unit in cubic feet, during the year. Y j 

### = Concentration of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to combustion unit
. Y CH4 

### = Concentration of methane constituent in gas sent to combustion unit. Y CO2 

### = Concentration of CO 2 

### constituent in gas sent to combustion unit. Field Code ChangedDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 130 of 206 Formatted: Font: 8 pt

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#   EF HHV Fuel O N      3 2 

### 10 1 

### R j 

### = Number of carbon atoms in the gas hydrocarbon constituent j ; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus) in gas sent to combustion unit
.

( 3 ) External fuel combustion sources with a rated heat capacity equal to or less than 5 mm B tu/hr do not need to report combustion emissions. You must report the type and number of each external fuel combustion unit. ( iv 4 ) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. ( v 5 ) Calculate both combustion-related CH 4 

### and CO 2 

### mass emissions from volumetric CH 4 

### and CO 2 

### emissions using calculation in paragraph (v) of this section.
( vi 6 ) Calculate N 2 

### O mass emissions using Equation W-40 of this section. (Eq. W

- 40 ) 

#   EFxGWP xFuelxHHVx x O N 3

2 

### 10 1  

### (Eq. W-40)

Where:

N 2 

### O = Annual N 2 

### O emissions from the combustion of a particular type of fuel (metric tons). Fuel = Mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV). Field Code ChangedDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 131 of 206 Formatted: Font: 8 pt

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### HHV = For the high heat value for field gas or process vent gas, use 1.235 x 10 -3 

### mmBtu/scf for HHV. High heat value of the fuel from paragraphs (z) (8) (i) , (z) (8) (ii) or (z)(8)(iii) of this section (units must be consistent with Fuel)
. EF = Use 1.0 × 10 -4 

### kg N 2 

### O/mmBtu. 1 × 10 -3 

### = Conversion factor from kilograms to metric tons. GWP = Global warming potential, as listed in Table A-1 of subpart A of this part.

(i) For fuels listed in Table C

- 1 of subpart C of this part , use the provided default HHV in the table. (ii) For field gas or process vent gas , use 1.235 × 10 - 3 

### mm B tu/scf for HHV. (iii) For fuels not listed in Table C

- 1 of subpart C of this part and not field gas or process vent gas, you must use the methodology set forth in the Tier 2 methodology described in subpart C of this part to determine HHV. (3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in §98.231(a). You must report the type and number of each external fuel combustion unit.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 132 of 206 Formatted: Font: 8 pt

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### §98.234 Monitoring and QA/QC requirements **.** The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250. (a) You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and through-valve leakage from all source types listed in §98.233(k), (o), (p) and (q) that occur during a calendar year, except as provided in paragraph (a)(4) of this section. (1) Optical gas imaging instrument . Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, §60.18 (i)(1) of the Alternative work practice for monitoring equipment leaks , §60.18(i)(1)(i); §60.18(i)(2)(i)(A) and (B) except that the monitoring frequency is annually using the detection sensitivity level of 60 grams per hour in Table 1 to Subpart A to Part 60- Detection Sensitivity Levels; §60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and (iv), and (v); §60.18(i)(3) and (4)(i) and (v) Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 133 of 206 Formatted: Font: 8 pt

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### The daily instrument check and distances, excluding any video records. and (2) of the Alternative work practice for monitoring equipment leaks. Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer’s operating parameters. An optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. (2) Method 21 . Use the equipment leak detection methods in 40 CFR part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected. Inaccessible emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart. Owners or operators must use alternative leak detection devices as described in paragraph(a)(1) or (a)(2) of this section to monitor inaccessible equipment leaks or vented emissions. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 134 of 206 Formatted: Font: 8 pt

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### (3) Infrared laser beam illuminated instrument . Use an infrared laser beam illuminated instrument for equipment leak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer’s operating parameters. (4) [Reserved]Optical gas imaging instrume nt . An optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. (5) Acoustic leak detection device . Use the acoustic leak detection device to detect through-valve leakage. When using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrumentmanufacturer’s calculation methods to quantify the throughvalve leak. When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 135 of 206 Formatted: Font: 8 pt

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### leak is detected. In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer’s operating parameters. . Acoustic stethoscope type devices designed todetect through valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate can be used to identify non-leakers with subsequent measurement required to calculate the rate if through-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour or greater is measured. (b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in §98.233 according to the procedures in §98.3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 136 of 206 Formatted: Font: 8 pt

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### Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (c) Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures such that it is safe to handle and can capture all the emissions, and below the maximum temperature specified by the vent bag manufacturer such that the bag is safe to handle. , The bag must be of sufficient size that and the entire emissions volume can be encompassed for measurement. (1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation time. (2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t). Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 137 of 206 Formatted: Font: 8 pt

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### (4) Estimate CH 4 

### and CO 2 

### volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v). (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methodologies relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the

source. (2) If the high volume sampler, along with all attachments available from the manufacturer, is not able tocapture all the emissions from the source then use antistatic wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer’s manual. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t). Estimate CH 4 

### and CO 2 

### volumetric and mass emissions fromDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 138 of 206 Formatted: Font: 8 pt

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### volumetric natural gas emissions using the calculations in §98.233(u) and (v). (4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH 4 

### by using calibrated gas samples and by following manufacturer’s instructions for calibration. (e) Peng Robinson Equation of State means the equation of state defined by Equation W-41 of this section:

2 2 

### 2 b bV V a b V RT p

m m m 

###   

   

### (Eq. W-41) Where: p = Absolute pressure. R = Universal gas constant. T = Absolute temperature. V m 

### = Molar volume.

a = c c 

### p T

R 2

2 

### 45724

. 0

b = c c 

### p RT 

### 7780

. 0

α = 

#   2 2 

### 1 26992

. 0 54226

. 1 37464

. 0 1                

   

c 

### T T  



### Where:DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 139 of 206 Formatted: Font: 8 pt

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### ω = Acentric factor of the species. T c 

### = Critical temperature. P c 

### = Critical pressure.

(f) Special reporting provisions (1) Best available monitoring methods. EPA will allow owners or operators to use best available monitoring methods for parameters in §98.233 Calculating GHG Emissions as specified in paragraphs (f)(2), (f)(3), and (f)(4) of this section. If the reporter anticipates the potential need for best available monitoring for sources for which they need to petition EPA and the situation is unresolved at the time of the deadline, reporters should submit written notice of this potential situation to EPA by the specified deadline for requests to be considered. EPA reserves the right to review petitions after the deadline but will only consider and approve late petitions which demonstrate extreme or unusual circumstances. The Administrator reserves to right to request further information in regard to all petition requests. The owner or operator must use the calculation methodologies and equations in §98.233 Calculating GHG Emissions. BestDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 140 of 206 Formatted: Font: 8 pt

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### available monitoring methods means any of the following methods specified in paragraph (f)(1) of this section: (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records.(2) Best available monitoring methods for wellrelated emissions . During January 1, 2011 through June 30 December 31 , 2011, owners or and operators may use best available monitoring methods for any well-related data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart , and only where required measurements cannot be duplicated due to technical limitations after June 30, 2011 . These well-related

sources are: (i) Gas well venting during well completions and workovers with hydraulic fracturing as specified in §98.233(g). (ii) Well testing venting and flaring as specified in §98.233(l). Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 141 of 206 Formatted: Font: 8 pt

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### (3) Best available monitoring methods for specified activity data . During January 1, 2011 through June 30 December 31 , 2011, owners or and operators may use best available monitoring methods for activity data as listed below that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart , specifically for events that generate data that can be collected only between January 1, 2011 and June 30, 2011 and cannot be duplicated after June 30, 2011 . These

sources are: (i) Cumulative hours of venting, days, or times of operation in §98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r). (ii) Number of blowdowns, completions, workovers, or other events in §98.233(f), (g), (h), (i), and (w). (iii) Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs §98.233(d), (e), (j), (k), (l), (m), (n), (x), (y), and (z). (4) Best available monitoring methods for leak detection and measurement
. The owner or operator may request use of best available monitoring methods
between During January 1, 2011 through and December 31, 2011 , Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 142 of 206 Formatted: Font: 8 pt

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### for sources requ iring leak detection and/or
measurement owners or operators may used best available monitoring methods for sources requiring leak detection and/or measurement . These sources include: (i) Reciprocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in §98.232 (d)(1), (e)(1), (f)(1), (g)(1), and (h)(1). (ii) Centrifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2). (iii) Acid gas removal vent stacks in onshore petroleum and natural gas production and onshore natural gas processing as specified in §98.232(c)(17) and (d)(6). (iv) Equipment leak emissions from valves, connectors, open ended lines, pressure relief valves, block valves, control valves, compressor blowdown valves, orificeDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 143 of 206 Formatted: Font: 8 pt

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### meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other equipment leaks in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, and natural gas distribution as specified in §98.232 (d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). (v) Condensate (oil and/or water) storage tanks in onshore natural gas transmission compression as specified in §98.232(e)(3). (5) Requests for the use of best available monitoring methods . The owner or operator may submit a request to the Administrator to use one or more best available monitoring
methods. (i) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30 December 31 , 2011 for the sources specified in paragraph (f)(2) of this section. (ii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30 December 31 , 2011 for the sources specified in paragraph (f)(3) of this section. Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 144 of 206 Formatted: Font: 8 pt

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### (iii) Owners or operators must s ubmit a request and receive approval No request or approval by the Administrator
to is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(4) of this section. (iv) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources not listed in paragraph (f)(2), (f)(3), and (f)(4) of this section. (A) Timing of request . The request to use best available monitoring methods for paragraph (f)(4) of this section must be submitted to EPA no later than April 30, 2011. (B) Content of request . Requests must contain the following information for sources listed in paragraph (f)(4) of this section: (1 ) A list of specific source types and specific equipment, monitoring instrumentation, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed or monitoring service will be supplied. Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 145 of 206 Formatted: Font: 8 pt

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### (2 ) Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the instrumentation or monitoring service is needed. (3 ) Documentation which demonstrates that the owner or operator made all reasonable efforts to obtain the information, services or equipment necessary to comply with subpart W reporting requirements, including evidence of specific service or equipment providers contacted and why services or information could not be obtained during 2011. (4 ) A description of the specific actions the facility will take to obtain and/or install the equipment or obtain the monitoring service as soon as reasonably feasible and the expected date by which the equipment will be obtained and operating or service will be provided. (C) Approval criteria . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it does not own the required monitoring equipment, and it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment or to obtain leak detection or measurement services in order to meet the requirements of this subpart for 2011.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 146 of 206 Formatted: Font: 8 pt

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### (iv) EPA does not anticipate a need to approve the use of best available monitoring methods for sources not listed in paragraphs(f)(2), (f)(3), and (f)(4) of this section; however, EPA will review such requests if submitted in accordance with paragraph (f)(5)(iv)(A)-(C) of this section. (A) Timing of request . The request to use best available monitoring methods for sources not listed in paragraphs (f)(2), (f)(3), and (f)(4) of this section must be submitted to EPA no later than April 30, 2011. (B) Content of request . Requests must contain the following information: (1 ) A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods. (2 ) A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 147 of 206 Formatted: Font: 8 pt

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### (3 ) A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all subpart W reporting requirements. (C) Approval criteria . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to meet the requirements of this subpart for 2011. (6) Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in paragraph (f)(2 ) of this section
. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in paragraph (f)(2) of this section beyond June 30, 2011. [Reserved] (i) Timing of request . The extension request must be submitted to EPA no later than April 30, 2011. (ii) Content of request . Requests must contain the following information: (A) A list of specific source types and specific equipment, monitoring instrumentation, contract Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 148 of 206 Formatted: Font: 8 pt

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### modifications, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed, monitoring service will be supplied, or contracts will be modified. (B) Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the instrumentation, contract modification, or monitoring service is needed. (C) A description and applicable correspondence outlining the diligent efforts of the owner or operator in obtaining the needed equipment or service and why they could not be obtained and installed in a period of time enabling completion of applicable requirements of this subpart within the 2011 calendar year. (D) If the reason for the extension is that the owner or operator cannot collect data from a service provider or relevant organization in order for the owner or operator to meet requirements of this subpart for the 2011 calendar year, the owner or operator must demonstrate a good faith effort that it is not possible to obtain the necessary information, service or hardware which may include providing correspondence from specific service providers orDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 149 of 206 Formatted: Font: 8 pt

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### other relevant entities to the owner or operator, whereby the service provider states that it is unable to provide the necessary data or services requested by the owner or operator that would enable the owner or operator to comply with subpart W reporting requirements by June 30, 2011. (E) A description of the specific actions the owner or operator will take to comply with monitoring requirements in 2012 and beyond. (iii) Approval criteria . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to obtain the data necessary to meet the requirements of this subpart for the sources specified in paragraph (f)(2) of this section by June 30, 2011. (7) Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in paragraph (f)(3 ) of this section
. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in paragraph (f)(3) of this section beyond June 30, 2011. [Reserved] Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 150 of 206 Formatted: Font: 8 pt

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### (i) Timing of request . The extension request must be submitted to EPA no later than April 30, 2011. (ii) Content of request . Requests must contain the following information: (A) A list of specific source types for which data collection could not be implemented. (B) Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the data collection could not be implemented. (C) A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies for which data collection could not be implemented in the 2011 calendar year. (iii) Approval criteria . To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to implement the data collection for the sources described in paragraph (f)(3) of this section for the methods required in this subpart by June, 30, 2011.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 151 of 206 Formatted: Font: 8 pt

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### (8) Requests for extension of the use of best available monitoring methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and other sources in this subpart
. The owner or operator must first provide the Administrator an initial electronic notification of intent to submit an extension request for EPA does not anticipate a need for approving the use of best available methods beyond December 31, 2011 for unique or , except in extreme unusual circumstances which include data collection methods that do not meet safety regulations, a requirement being technically infeasible, or counter to other local, State, or Federal regulations. The owner or operator must follow-up this initial notification with an extension request containing the information specified in 98.234(f)(8)(ii). Facilities that submit both a timely notice of intent and extension request consistent with 98.234(f)(8)(ii) can automatically use BAMM through June 30, 2012, for the specific parameters identified in their notification of intent and BAMM request regardless of whether the BAMM request is ultimately approved. Facilities that submit a notice of intent but do Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 152 of 206 Formatted: Font: 8 pt

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### not follow up with a BAMM request by March 30, 2012 cannot automatically use BAMM after December 31, 2011. circumstances, which include safety, a requirement being technically infeasible or counter to other local, State, or Federal regulations. (i) Timing of request
. The initial electronic notice of intent to request BAMM must be submitted by December 31, 2011. The completed extension request must be submitted to the Administrator no later than March 30, 2012. The request to use best available monitoring methods for p aragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and sources not listed in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section must be submitted to EPA no
later than September 30, 2011. (ii) Content of request . Requests must contain the following information: (A) A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods. (B) A description of the unique or unusual circumstances, such as data collection methods that do not meet safety regulations, technical infeasibility, or Formatted: Highlight Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

Formatted: Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 153 of 206 Formatted: Font: 8 pt

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### specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies. (C) A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all of this subpart W reporting requirements. (iii) Approval criteria

. To obtain approval to use BAMM after June 30, 2012, the owner or operator must demonstrate to the Administrator’s satisfaction that the owner or operator faces unique or unusual circumstances such as data collection methods that do not meet safety regulations, technical infeasibility, or legal issues rendering them unable to meet the requirements of this subpart. A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods. (iv) A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner Formatted: Highlight
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Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 154 of 206 Formatted: Font: 8 pt

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### or operator is requesting use of best available monitoring methodologies. (v) A detailed explanation and su pporting documentation of how and when the owner or operator will receive the services or equipment to comply with all of this subpart W reporting requirements. (C) Approval criteria . To obtain approval, the owner or operator must demonstrate to the Adm inistrator’s satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to meet the requirements of this subpart.

§98.235 Procedures for estimating missing data. A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required. If data are lost or an error occurs during annual emissions estimation or measurements, you 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 developed Formatted: Highlight Formatted: Font: 12 pt, Highlight

Formatted: Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 155 of 206 Formatted: Font: 8 pt

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### and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year’s emissions estimation. Where missing data procedures are used 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, (for example flow meters), or for missing temperature or pressure data that are required under §98.236, the 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. §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. (a) Report annual emissions separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section
. in metric tons CO 2 

### e per year at standard conditions. For each segment, report emissions from each source type §98.232(a) in the aggregate, unless Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 156 of 206 Formatted: Font: 8 pt

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### specified otherwise. For example, an onshore natural gas production operati on with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number. (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. Report each source in the aggregate for pipelines and for Metering and Regulating (M&R) stations. (b) For o O ffshore petroleum and natural gas production , report emissions of CH 4 

### , CO 2 

### , and N 2 

### O as applicable to the source type (in metric tons CO 2 

### e per year at standard conditions) individually for all the emissions source types listed in the most recent BOEMRE study. is not required to report activity data and emissions for each aggregated source under §98.236 (c). Reporting requirements for offshore petroleum and natural gas production is set Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 157 of 206 Formatted: Font: 8 pt

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### forth by BOE MRE in compliance with 30 CFR 250.302 through 304. (c) Report the information listed in this paragraph for each applicable source type. If a facility operates under more than one industry segment, each piece of equipment should be reported under its 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 the gas. Both the vented and flared emissions will be reported under the respective source type and not under the flare source type. For each aggregated source, unless otherwise specified, report activity data and emissions (in metric tons CO 2 

### e per year at standard condition s) for each aggregated source type as follows: (1) For natural gas pneumatic devices (refer to Equation W-1 of §98.233), report the following: (i) Actual count and estimated count separately of natural gas pneumatic high bleed devices as applicable. (ii) Actual count and estimated count separately of natural gas pneumatic low bleed devices as applicable. Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 158 of 206 Formatted: Font: 8 pt

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### (iii) Actual count and estimated count separately of natural gas pneumatic intermittent bleed devices as applicable. (iv) Report annual CO 2 

### and CH 4 

### emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, for each of the following pieces of equipment: high bleed pneumatic devices; intermittent bleed pneumatic devices; low bleed pneumatic devices. Report emissions collectively. (2) For natural gas driven pneumatic pumps (refer to Equation W-2 of §98.233), report the following, (i) Count of natural gas driven pneumatic pumps. (ii) Report annual CO 2 

### and CH 4 

### emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, for all natural gas driven pneumatic pumps combined. Report emissions collectively. (3) For each acid gas removal unit (refer to Equation W-3 and Equation W-4 of §98.233), report the following: (i) Total throughput off 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. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 159 of 206 Formatted: Font: 8 pt

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### (ii) For Calculation Methodology 1 and Calculation Methodology 2 of §98.233(d), annual average fraction of CO 2 

### content in the vent from the acid gas removal unit (refer to §98.233(d)(6)). (iii) For Calculation Methodology 3 of §98.233(d), annual average volume fraction of CO 2 

### content of natural gas into and out of the acid gas removal unit (refer to §98.233(d)(7) and (d)(8)). (iv) Report the annual quantity of CO 2 

### , expressed in metric tons CO 2 

### e, that was recovered from the AGR unit and transferred outside the facility. Report emissions from the AGR unit recovered and transferred outside the facility. (v) Report annual CO 2 

### emissions for the AGR unit, expressed in metric tons CO 2 

### e. Report emissions individually. (vi) A unique name or ID number for the AGR unit. (vii) An indication of which calculation methodology was used for the AGR. (4) For dehydrators, report the following: (i) For each Glycol dehydrator with a throughput greater than or equal to 0.4 MMscfd (refer to §98.233(e)(1)), report the following: Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 160 of 206 Formatted: Font: 8 pt

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### (A) Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data. (B) Glycol dehydrator absorbent circulation pump type. (C) Whether stripper gas is used in glycol dehydrator. (D) Whether a flash tank separator is used in glycol dehydrator. (E) Type of absorbent. (F) Total time the glycol dehydrator is operating in hours. (G) Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas. (H) Concentration of CH 4 

### and CO 2 

### in wet natural gas. (I) What vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). (J) For each glycol dehydrator, report annual CO 2 

### and
CH 4 

### emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 

### e for each
gas. Report vent and flared emissions individually. Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 161 of 206 Formatted: Font: 8 pt

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### (K) For each glycol dehydrator, report annual CO 2 

### , CH 4 

### , and N 2 

### O emissions that resulted from flaring process gas from the dehydrator, expressed in metric tons CO 2 

### e for each gas. (L) A unique name or ID number for the glycol dehydrator. (ii) For all glycol dehydrators with a throughput less than 0.4 MMscfd (refer to §98.233, Equation W-5 of §98.233), report the following: (A) Count of glycol dehydrators. (B) Whether any Which vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). (C) Report annual CO 2 

### and CH 4 

### emissions at the facility level that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 

### e for each gas, combined for all glycol dehydrators with a throughput of less than 0.4 MMscfd. Report vent emissions collectively. (D) Report annual CO 2 

### , CH 4 

### , and N 2 

### O emissions at the facility level that resulted from the flaring of process gas, expressed in metric tons CO 2 

### e for each gas, combined for all glycol dehydrators with a throughput of less than 0.4 MMscfd. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 162 of 206 Formatted: Font: 8 pt

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### (iii) For absorbent desiccant dehydrators (refer to Equation W-6 of §98.233), report the following: (A) Count of desiccant dehydrators. (B) Report annual CO 2 

### and CH 4 

### emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, for all absorbent desiccant dehydrators combined. Report emissions collectively. (5) For well venting for liquids unloading (refer to Equations W-7, W-8 and W-9 of §98.233), report the following by field each well tubing diameter grouping and pressure grouping within each sub-basin category : (i) Count of wells vented to the atmosphere for liquids unloading. (ii) Count of plunger lifts. (iii) Cumulative number of unloadings vented to the atmosphere. (iv) Average flow rate of the measured well venting in cubic feet per hour (refer to §98.233(f)(1)(i)(A)). (v) Average casing diameter in inches. (vi) Report annual CO 2 

### and CH 4 

### emissions, expressed in metric tons CO 2 

### e for each gas, for each tubing diameter and Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 163 of 206 Formatted: Font: 8 pt

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### pressure grouping within each sub-basin category. Report emissions collectiv ely. (vii) When using Calculation Methodology 1, casing diameter, depth and pressure of each well selected to represent emissions in that tubing size and pressure combination (refer to Equation W-7 of §98.233). (6) For well completions and workovers, report the following for each field sub-basin category : (i) For gas well completions and workovers with hydraulic fracturing by sub-basin and well type (horizontal or vertical) combination (refer to Equation W-10 of §98.233): (A) Total count of completions in calendar year. (B) Average flow rate of the measured well completion venting in cubic feet per hour (refer to Equation W-12 of §98.233 ) (g)(1)(i) or (g)(1)(ii)). (C) Total count of workovers in calendar year. (D) Average flow rate of the measured well workover venting in cubic feet per hour (refer to Equation W-12 of §98.233 ). (g)(1)(i) or (g)(1)(ii)). (E) Total number of days of gas venting to the atmosphere during backflow for completion. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 164 of 206 Formatted: Font: 8 pt

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### (F) Total number of days of gas venting to the atmosphere during backflow for workovers. (G) Report number of completions and number of workovers employing reduced emissions completions and engineering estimate based on best available data of the amount of gas recovered to sales. (H) Annual CO 2 

### and CH 4 

### emissions that resulted from venting gas directly to the atmosphere, expressed in metric
tons CO 2 

### e for each gas. Report vent emissions collectively. Report flared emissions collectively. (I) Annual CO 2 

### , CH 4 

### , and N 2 

### O emissions that resulted form flares, expressed in metric tons CO 2 

### e for each gas. (ii) For gas well completions and workovers without hydraulic fracturing (refer to Equation W-13 of §98.233): (A) Total count of completions in calendar year. (B) Total count of workovers in calendar year that flare gas or vent gas to the atmosphere
. (C) Total number of days of gas venting to the atmosphere during backflow for completion. (D) Annual CO 2 

### and CH 4 

### emissions that resulted from venting gas directly to the atmosphere, expressed in metric Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 165 of 206 Formatted: Font: 8 pt

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### tons CO 2 

### e for each gas. Report vent emissions collectively. Report flared emissions collectively. (E) Annual CO 2 

### , CH 4 

### , and N 2 

### O emissions that resulted from flares, expressed in metric tons CO 2 

### e for each gas. (7) For each blowdown vent stack (refer to Equation W-14 of §98.233), report the following: (i) Total number of blowdowns per unique volume equipment type in calendar year. (ii) Annual CO 2 

### and CH 4 

### emissions, expressed in metric
tons CO 2 

### e for each gas, for each unique volume type, at each blowdown stack. Report emissions collectively per equipment type. (iii) A unique name or ID number for the blowdown
vent stack. (8) For gas emitted from produced oil sent to atmospheric tanks: (i) For wellhead gas-liquid separator with oil throughput greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of §98.233(j), report the following by field sub-basin category, unless otherwise specified : Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 166 of 206 Formatted: Font: 8 pt

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### (A) Number of wellhead separators sending oil to atmospheric tanks. (B) Estimated average separator temperature, in degrees Fahrenheit, and estimated average pressure, in psig. (C) Estimated average sales oil stabilized API gravity, in degrees. (D) Count of hydrocarbon tanks at well pads. (E) Best estimate of count of stock tanks not at well pads receiving your oil. (F) Total volume of oil from all wellhead separators sent to tank(s) in barrels per year. (G) Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at well pads. (H) Best estimate of count of stock tanks assumed to have emissions control measures not at well pads, receiving your oil. (I) Range of concentrations of flash gas, CH 4 

### and CO 2 

### . (J) Annual CO 2 

### and CH 4 

### emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 

### e for each gas, for each wellhead gas-liquid separator using Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 167 of 206 Formatted: Font: 8 pt

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### Calculation Methodology 1 or 2 of §98.233(j). Report emissions individually for Calculation Methodology 1 and 2 of §98.233(j). (K) Annual CO 2 

### and CH 4 

### gas quantities that were recovered, expressed in metric tons CO 2 

### e for each gas, for each wellhead gas-liquid separator using Calculation Methodology 1 or 2 of §98.233(j). (L) Annual CO 2, 

### CH 4, 

### and N 2 

### O emissions that resulted from flaring gas, expressed in metric tons CO 2 

### e for each gas, for each wellhead gas-liquid separator using Calculation Methodology 1 or 2 of §98.233(j). (M) A unique name or ID number for each wellhead gas liquid separator. (ii) For wells with oil production greater than or equal to 10 barrels per day, using Calculation Methodology 3 and 4 of §98.233(j), report the following by field subbasin category : (A) Total volume of sales oil from all wells in barrels per year. (B) Total number of wells sending oil directly to tanks. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 168 of 206 Formatted: Font: 8 pt

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### (C) Total number of wells sending oil to separators off the well pads. (D) Sales oil API gravity range for wells in (c)(8)(ii) (B) and (c)(8)(ii) (C) of this section, in degrees. (E) Count of hydrocarbon tanks on wellpads (F) Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors. (G) Annual CO 2 

### and CH 4 

### emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 

### e for each gas, at the sub-basin level for Calculation Methodology 3 or 4 of §98.233(j). Report emissions collectively for Calculation Methodology 3 and 4 of §98.233(j). (iii) For wellhead gas-liquid separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of §98.233(j) Equation W-15 of §98.233 ) , report the following: (A) Number of wellhead separators. (B) Number of wells without wellhead separators. Formatted: Font: 12 pt, Highlight
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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 169 of 206 Formatted: Font: 8 pt

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### (C) Total volume of oil production in barrels per
year. (D) Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors. (E) Count of hydrocarbon tanks on well pads. (F) Annual CO 2 

### and CH 4 

### emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 

### e for each gas, at the sub-basin level for Calculation Methodology 5 of §98.233(j). Report CO 2 

### and CH 4 

### emissions collectively. (G) Annual CO 2 

### and CH 4 

### gas quantities that were recovered, expressed in metric tons CO 2 

### e for each gas, at the sub-basin level for Calculation Methodology 5 of §98.233(j). (H) Annual CO 2, 

### CH 4, 

### and N 2 

### O emissions that resulted from flaring gas, expressed in metric tons CO 2 

### e for each gas, at the sub-basin level for Calculation Methodology 5 of §98.233(j). (iv) If wellhead separator dump valve is functioning improperly during the calendar year (refer to Equation W-16 of §98.233), report the following: Formatted: Font: 12 pt, Highlight

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Formatted: Do not check spelling or grammar, Not Superscript/ SubscriptDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 170 of 206 Formatted: Font: 8 pt

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### (A) Count of wellhead separators that dump valve factor is applied. (B) Annual CO 2 

### and CH 4 

### emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 

### e for each gas, at the sub-basin level for improperly functioning dump valves. (9) For transmission tank emissions identified using optical gas imaging instrument per §98.234(a) (refer to §98.233(k)), or acoustic leak detection of scrubber dump valves report the following for each tank: (i) For each transmission storage tank, report annual
CO 2 

### and CH 4 

### emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 

### e for each gas. Report emissions individually. (ii) For each transmission storage tank, report annual CO 2 

### , CH 4 

### , and N 2 

### O emissions that resulted from flaring process gas from the transmission storage tank, expressed in metric tons CO 2 

### e for each gas. [Reserved] (iii) A unique name or ID number for the transmission storage tank. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 171 of 206 Formatted: Font: 8 pt

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### (10) For well testing venting and flaring (refer to Equation W-17 of §98.233), report the following for each basin : (i) Number of wells tested per basin in calendar
year. (ii) Average gas to oil ratio for each basin. (iii) Average number of days the well is tested in a basin. (iv) Report annual CO 2 

### and CH 4 

### emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, emissions from well testing venting. Report emissions of the venting gas collectively. (v) Report annual CO 2, 

### CH 4, 

### and N 2 

### O emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, emissions from well testing flaring. (11) For associated natural gas venting (refer to Equation W-18 of §98.233), report the following for each basin: (i) Number of wells venting or flaring associated natural gas in a calendar year. (ii) Average gas to oil ratio for each basin. Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 172 of 206 Formatted: Font: 8 pt

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### (iii) Report annual CO 2 

### and CH 4 

### emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, emissions from associated natural gas venting. Report emissions of the flaring gas collectively. (iv) Report annual CO 2, 

### CH 4, 

### and N 2 

### O emissions at the facility level, expressed in metric tons CO 2 

### e for each gas, emissions from associated natural gas flaring. (12) For flare stacks (refer to Equation W-19, W-20, and W-21 of §98.233), report the following for each flare: (i) Whether flare has a continuous flow monitor. (ii) Volume of gas sent to flare in cubic feet per
year. (iii) Percent of gas sent to un-lit flare determined by engineering estimate and process knowledge based on best available data and operating records. (iv) Whether flare has a continuous gas analyzer. (v) Flare combustion efficiency. (vi) Report uncombusted CH 4 

### emissions, in metric tons
CO 2 

### e (refer to Equation W-19 of §98.233). Report uncombusted and combusted CO 2 

### and CH 4 

### emissions separately. (vii) Report uncombusted CO 2 

### emissions, in metric tons
CO 2 

### e (refer to Equation W-20 of §98.233). Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 173 of 206 Formatted: Font: 8 pt

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### (viii) Report combusted CO 2 

### emissions, in metric tons
CO 2 

### e (refer to Equation W-21 of §98.233). (ix) Report N 2 

### O emissions, in metric tons CO 2 

### e. (x) A unique name or ID number for the flare stack. (xi) In the case that a CEMS is used to measure CO 2 

### emissions for the flare stack, indicate that a CEMS was used in the annual report and report the combusted CO 2 

### and uncombusted CO 2 

### as a combined number. (13) For each centrifugal compressor: (i) For compressors with wet seals in operational mode (refer to Equations W-22 through W-24 of §98.233), report the following for each degassing vent: (A) Number of wet seals connected to the degassing
vent. (B) Fraction of vent gas recovered for fuel or sales or flared. (C) Annual throughput in million scf, use an engineering calculation based on best available data. (D) Type of meters used for making measurements. (E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to Equation W-24 of §98.233). Formatted: Font: 12 pt, Highlight Formatted: Highlight Formatted: Font: 12 pt, Highlight Formatted: Highlight Formatted: Font: 12 pt, Highlight Formatted: Highlight Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 174 of 206 Formatted: Font: 8 pt

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### (F) Total time the compressor is operating in hours. (G) Report seal oil degassing vent emissions for compressors measured (refer to Equation W-22 of §98.233) and for compressors not measured (refer to Equation W-23 and Equation W-24 of §98.233). (ii) For wet and dry seal centrifugal compressors in operating mode, (refer to Equations W-22 through W-24 of §98.233), report the following: (A) Total time in hours the compressor is in operating mode. (B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to Equation W-24 of §98.233). (C) Report blowdown vent emissions when in operating mode (refer to Equation W-23 and Equation W-24 of §98.233). (iii) For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations W-22 through W-24 of §98.233), report the following: (A) Total time in hours the compressor is in shutdown, depressurized mode. (B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W-24 of §98.233).DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 175 of 206 Formatted: Font: 8 pt

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### (C) Report the isolation valve leakage emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-23 and Equation W-24 of §98.233). (iv) Report total annual compressor emissions from all modes of operation (refer to Equation W-24 of §98.233). (v) For centrifugal compressors in onshore petroleum and natural gas production (refer to Equation W-25 of §98.233), report the following: (A) Count of compressors. (B) Report emissions (refer to Equation W-25 of §98.233) collectively. (14) For reciprocating compressors: (i) For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following: (A) Annual throughput in million scf, use an engineering calculation based on best available data. (B) Total time in hours the reciprocating compressor is in operating mode. (C) Report rod packing emissions for compressors measured (refer to Equation W-26 of §98.233) and forDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 176 of 206 Formatted: Font: 8 pt

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### compressors not measured (refer to Equation W-27 and Equation W-28 of §98.233). (ii) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode (refer to Equations W-26 through W-28 of §98.233), report the following: (A) Total time in hours the compressor is in standby, pressurized mode. (B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to §98.233, Equation W-28). (C) Report blowdown vent emissions when in operating and standby pressurized modes (refer to Equation W-27 and Equation W-28 of §98.233). (iii) For reciprocating compressors in not operating, depressurized mode (refer to Equations W-26 through W-28 of §98.233), report the following: (A) Total time the compressor is in not operating, depressurized mode. (B) Reporter emission factor for isolation valve emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-28 of §98.233).DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 177 of 206 Formatted: Font: 8 pt

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### (C) Report the isolation valve leakage emissions in not operating, depressurized mode. (iv) Report total annual compressor emissions from allmodes of operation (refer to Equation W-27 and Equation W28 of §98.233). (v) For reciprocating compressors in onshorepetroleum and natural gas production (refer to Equation W29 of §98.233), report the following: (A) Count of compressors. (B) Report emissions collectively. (15) For each equipment leak sources that uses emission factors for estimating emissions (refer to §98.233(q) and (r). (i) For equipment leaks found in each leak survey (refer to **§** 98.233(q)), report the following: (A) Total count of leaks found in each complete survey listed by date of survey and each type of leak source for which there is a leaker emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this subpart. (B) For onshore natural gas processing, range of concentrations of CH 4 

### and CO 2 

### (refer to Equation W-30 of Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 178 of 206 Formatted: Font: 8 pt

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### §98.233). Concentration of CH 4 

### and CO 2 

### as described in Equation W

- 30 of §98.233. (C) Report Annual CO 2 

### and CH 4 

### and CO 2 

### emissions , in metric tons CO 2 

### e for each gas (refer to Equation W-30 of §98.233) collectively by equipment type. (ii) For equipment leaks calculated using population counts and factors (refer to **§** 98.233(r)), report the following: (A) For source categories §98.230 (a)(3), (a)(4), (a)(5), (a)(6), and (a)(7), and (a)(8), total count for each type of leak source in Tables W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a population emission factor, listed by major heading and component type. (B) For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major equipment in Table W-1B and Table W-1C of this subpart, by field sub-basin category
. (C) Report CH 4 

### and CO 2 

### Annual CO 2 

### and CH 4 

### emissions , in metric tons CO 2 

### e for each gas (refer to Equation W-31 of §98.233) collectively by equipment type. Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 179 of 206 Formatted: Font: 8 pt

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### (16) For local distribution companies, report the following: (i) Number of above grade T-D transfer stations Number of custody transfer gate stations
. (ii) Number of below grade T-D transfer stations. Number of non

- custody transfer gate st ations. (iii) Number of above grade metering-regulating stations (this count will include above grade T-D transfer stations). Custody transfer gate station meter run leak factor (refer to Equation W

- 32 of §98.233). (iv) Number of below grade metering-regulating stations (this count will include below grade T-D transfer stations). Number of below grade M&R stations with inlet pressure greater than 300 psig. (v) Number of below grade M&R stations with inlet pressure between 100 and 300 psig. [Reserved] (vi) Above grade metering-regulating station leak factor (refer to Equation W-32 of §98.233). Number of below grate M&R stations with inlet pressure less than 100 psig. (vii) Number of miles of unprotected steel distribution mains. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 180 of 206 Formatted: Font: 8 pt

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### (viii) Number of miles of protected steel distribution mains. (ix) Number of miles of plastic distribution mains. (x) Number of miles of cast iron distribution mains. (xi) Number of unprotected steel distribution services. (xii) Number of protected steel distribution services. (xiii) Number of plastic distribution services. (xiv) Number of copper distribution services. (xv) Annual CO 2 

### and CH 4 

### emissions, in metric tons CO 2 

### e for each gas, from all above grade T-D transfer stations combined. Total emissions from each natural gas distribut ion facility. (xvi) Annual CO 2 

### and CH 4 

### emissions, in metric tons
CO 2 

### e for each gas, from all below grade T-D transfer stations combined. (xvii) Annual CO 2 

### and CH 4 

### emissions, in metric tons
CO 2 

### e for each gas, from all above grade metering-regulating stations (including T-D transfer stations) combined. (xviii) Annual CO 2 

### and CH 4 

### emissions, in metric tons
CO 2 

### e for each gas, from all below grade metering-regulating stations (including T-D transfer stations) combined. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 181 of 206 Formatted: Font: 8 pt

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### (xix) Annual CO 2 

### and CH 4 

### emissions, in metric tons
CO 2 

### e for each gas, from all distribution mains combined. (xx) Annual CO 2 

### and CH 4 

### emissions, in metric tons CO 2 

### e for each gas, from all distribution services combined.

(17) For each EOR injection pump blowdown (refer to Equation W-37 of §98.233), report the following: (i) Pump capacity, in barrels per day. (ii) Volume of critical phase gas between isolation
valves. (iii) Number of blowdowns per year. (iv) Critical phase EOR injection gas density. (v) For each EOR pump, report annual CO 2 

### and CH 4 

### emissions, expressed in metric tons CO 2 

### e for each gas. Report emissions collectively. (vi) A unique name or ID for the EOR pump. (18) For EOR hydrocarbon liquids dissolved CO 2 

### for each field sub-basin category (refer to Equation W-38 of §98.233), report the following: (i) Volume of crude oil produced in barrels per year. (ii) Amount of CO 2 

### retained in hydrocarbon liquids in metric tons per barrel, under standard conditions. Formatted: Font: 12 pt, Highlight Formatted: Highlight Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 182 of 206 Formatted: Font: 8 pt

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### (iii) Report annual CO 2 

### emissions at the sub-basin level, expressed in metric tons CO 2 

### e. Report emissions individually. (19) For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the following: (i) Cumulative number of external fuel combustion units with a rated heat capacity equal to or less than 5 mmBtu/hr, by type of unit. (ii) Cumulative number of external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit. (iii) Report annual CO 2 

### , CH 4 

### , and N 2 

### O emissions at from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons CO 2 

### e for each gas, by type of unit. Cumulative emissions from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit. (iv) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel type. Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 183 of 206 Formatted: Font: 8 pt

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### (v) Cumulative number of all internal combustion units, by type of unit. (vi) Report annual CO 2 

### , CH 4 

### , and N 2 

### O emissions from internal combustion units, expressed in metric tons CO 2 

### e for each gas, by type of unit. Cumulative emissions from internal combustion units, by type of unit. (vii) Cumulative volume of fuel combusted in internal combustion units, by fuel type. (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 average API gravity, average gas to oil ratio,and average low pressure separator pressure for each subbasin category.

§98.237 Records that must be retained **.** Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011. In addition to the information required by §98.3(g), you must retain the following
records: Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 184 of 206 Formatted: Font: 8 pt

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### (a) Dates on which measurements were conducted. (b) Results of all emissions detected and
measurements. (c) Calibration reports for detection and measurement instruments used. (d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. (e) The records required under §98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart. §98.238 Definitions. Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Acid gas means hydrogen sulfide (H 2 

### S) and/or carbon dioxide (CO 2 

### ) contaminants that are separated from sour natural gas by an acid gas removal unit. Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 185 of 206 Formatted: Font: 8 pt

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### natural gas using liquid or solid absorbents or membrane separators. Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare. Associated with a single well-pad means associated with the hydrocarbon stream as produced from one or more wells located on that single well-pad. The association ends where the stream from a single well-pad is combined with streams from one or more additional single well-pads, where the point of combination is located off that single well-pad. This does not include storage and condensate tanks that are located downstream of the point of combination. Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by reference, see §98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Formatted: Font: 12 pt, Highlight

Comment [A2]: R agan’s Comment: Do we really want to limit this to single well pads? See previous comment about upstream comingling. Response: We have included coverage from comingling through the “associated” term. Formatted: Highlight Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 186 of 206 Formatted: Font: 8 pt

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### Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see §98.7). Component means each metal to metal joint or seal of non-welded connection separated by a compression gasket, screwed thread (with or without thread sealing compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere. Compressor means any machine for raising the pressure of a natural gas or CO 2 

### by drawing in low pressure natural gas or CO 2 

### and discharging significantly higher pressure natural gas or CO 2 

### . Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions. Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 C.F.R. § 192.3. Engineering estimation , for purposes of subpart W, means an estimate of emissions based on engineering Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 187 of 206 Formatted: Font: 8 pt

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### principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions. Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil. Equipment leak means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening. Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources. External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heaters, industrial boilers, and commercial and domestic combustion units.DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 188 of 206 Formatted: Font: 8 pt

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### Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering-regulating stations , metering stations, and regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system. Facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements 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 §98.238. 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 Formatted: Font: 12 pt, Highlight Formatted: Font: 12 pt, Underline, Highlight Formatted: Font: 12 pt, Highlight

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the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 189 of 206 Formatted: Font: 8 pt

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### that the person or entity owns or operates in the basin would be considered one facility. Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. The gas may or may not be metered, but always does not pass through a city gate station. In some cases a nearby LDC may handle the billing of the gas to the customer(s). Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see §98.7). Flare, for the purposes of subpart W, means a combustion device, whether at ground level or elevated, that uses an open or closed flame to combust waste gases without energy recovery. Flare stack emissions means CO 2 

### and N 2 

### O from partial combustion of hydrocarbon gas sent to a flare plus CH 4 

### emissions resulting from the incomplete combustion of hydrocarbon gas in flares. Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 190 of 206 Formatted: Font: 8 pt

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### Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip. Forced extraction of natural gas liquids means removal of ethane or higher carbon number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include in and of itself; natural gas dehydration, or the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient temperatures, or the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, or portable dewpoint suppression skids.

Gas well means a well completed for production of natural gas (including condensate) from one or more gas zones or reservoirs. Such wells contain no completions for the production of crude oil. Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 191 of 206 Formatted: Font: 8 pt

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### Horizontal well means a well bore that has a planned deviation from primarily vertical to a primarily horizontal inclination or declination tracking in parallel with and through the target formation.

Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an internal combustion engine the expansion of the high-temperature and –pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines. Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric
pressure. LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps. Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 192 of 206 Formatted: Font: 8 pt

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### Metering-regulating station means a station that meters the flowrate, regulates the pressure, or both, of natural gas in a natural gas distribution facility. This does not include customer meters, customer regulators, or farm taps. Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.

Oil well means a well completed for the production of crude oil from at least one oil zone or reservoir. Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued **,** which operates an onshore petroleum and/or natural gas production facility (as described in §98.230(a)(2). Where petroleum and natural gas wells operate without a Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 193 of 206 Formatted: Font: 8 pt

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### drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator. Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank. Pressure groupings are defined as follows: less than or equal to 25 psig; greater than 25 psig and less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and greater than 200 psig. Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits. Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere. Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere. Formatted: Font: 12 pt, Highlight

Formatted: Do not check spelling or grammarDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 194 of 206 Formatted: Font: 8 pt

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### Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases. Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline. Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase. Sub-basin category, for onshore natural gas production, means a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following four formation types as designated by 18 C.F.R. 270.305: Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 195 of 206 Formatted: Font: 8 pt

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### conventional with >0.1 millidarci permeability, and unconventional with ≤ 0.1 millidarci permeability. Unconventional formation types are either shale, coal seam, or other tight reservoir rock. Wells producing from more than one unconventional formation type shall be classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. Unconventional wells producing in two or more formation types of “shale and coal seam”, “shale and other tight”, or “shale, coal seam, and other tight”; are considered shale. In addition, unconventional wells producing in “coal seam and other tight" formations are considered coal. Transmission-distribution (TD) transfer station means a meter-regulating station where a local distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a distribution pipeline. Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 196 of 206 Formatted: Font: 8 pt

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### section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994) . means hig h pressure cross country pipeline transporting saleable quality natural gas from production or natural gas processing to natural gas distribution pressure let

- down, metering, regulating stations where the natural gas is typically odorized before delivery t o
customers. Tubing diameter groupings are defined as follows: less than or equal to 1 inch; greater than 1 inch and less than 2 inch; and greater than or equal to 2 inch. Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size. Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate. Vented emissions means intentional or designed releases of CH 4 

### or CO 2 

### containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, Formatted: Font: 12 pt, Highlight

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Formatted: Do not check spelling or grammarDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 197 of 206 Formatted: Font: 8 pt

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### and direct venting of gas used to power equipment (such as pneumatic devices). Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one or more intentional deviations to enter one or more subsurface targets that are off-set horizontally from the surface location, intercepting the targets either vertically or at an angle. Well testing venting and flaring means venting and/or flaring of natural gas at the time the production rate of a well is determined (i.e., the well testing) through a choke (an orifice restriction). If well testing is conducted immediately after well completion or workover, then it is considered part of well completion or workover.

**TABLE W-1A OF SUBPART W** – **DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION**  **Onshore petroleum and natural gas production Emission Factor**  **(scf/hour/component) Eastern U.S.**  **Population Emission Factors - All Components, Gas Service**  **1** Valve 0.027 Connector 0.004 Open-ended Line 0.062 Pressure Relief Valve 0.041 Low Continuous Bleed Pneumatic Device Vents 2 1.80 Formatted: Font: 12 pt, Highlight

Formatted: Font: 12 pt, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 198 of 206 Formatted: Font: 8 pt

Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Tab stops: 2.66", Left High Continuous Bleed Pneumatic Device Vents 2 48.1 Intermittent Bleed Pneumatic Device Vents 2 17.4 Pneumatic Pumps 3 13.3 **Population Emission Factors - All Components, Light Crude Service**  **4** Valve 0 .04 Flange 0.002 Connector 0.005 Open-ended Line 0.04 Pump 0.01 Other 5 0.23 **Population Emission Factors - All Components, Heavy Crude Service**  **6** Valve 0.0004 Flange 0.0007 Connector (other) 0.0002 Open-ended Line 0.004 Other 5 0.002 **Western U.S. Population Emission Factors - All Components,**  **Gas Service 1**  Valve 0.123 Connector 0.017 Open-ended Line 0.032 Pressure Relief Valve 0.196 Low Continuous Bleed Pneumatic Device Vents 2 1.80 High Continuous Bleed Pneumatic Device Vents 2 48.1 Intermittent Bleed Pneumatic Device Vents 2 17.4 Pneumatic Pumps 3 13.3 **Population Emission Factors - All Components, Light Crude Service**  **4** Valve 0.04 Flange 0.002 Connector (other) 0.005 Open-ended Line 0.04 Pump 0.01 Other 5 0.23 **Population Emission Factors - All Components, Heavy Crude Service**  **6** Valve 0.0004 Flange 0.0007 Connector (other) 0.0002 Open-ended Line 0.004DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 199 of 206 Formatted: Font: 8 pt

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### TABLE W-1B OF SUBPART W – **DEFAULT AVERAGE COMPONENT COUNTS FOR MAJOR ONSHORE NATURAL GAS PRODUCTION EQUIPMENT**  **Major Equipment Valves**  **Connectors Open-ended**  **Lines Pressure**  **relief valves**  **Eastern U.S.** Wellheads 8 38 0.5 0 Separators 1 6 0 0 meters/piping 12 45 0 0 Compressors 12 57 0 0 In-line heaters 14 65 2 1 Dehydrators 24 90 2 2 **Western U.S.** Wellheads 11 36 1 0 Separators 34 106 6 2 meters/piping 14 51 1 1 Compressors 73 179 3 4 In-line heaters 14 65 2 1 Dehydrators 24 90 2 2



### Table W-1C of Subpart W of Part 98 Default Average **Component Counts For Major Crude Oil Production Equipment Major Equipment**  **Valves Flanges**  **Connecto rs**  **O pen**  **** **ended Lines**  **Other Components**  Eastern U.S. Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater-treater 8 12 20 0 0 Header 5 10 4 0 0 Western U.S. Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater-treater 8 12 20 0 0 Other 5 0.002 1 For multi-phase flow that includes gas, use the gas service emissions factors 2 Emission Factor is in units of "scf/hour/device" 3 Emission Factor is in units of "scf/hour/pump" 4 Hydrocarbon liquids greater than or equal to 20  ̊ API are considered "light crude" 5 ”Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.
6 Hydrocarbon liquids less than 20  ̊ API are considered "heavy crude"DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 200 of 206 Formatted: Font: 8 pt

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### Header 5 10 4 0 0



### Table W-1D of Subpart W of Part 98 Designation Of Eastern **And Western U.S. Eastern U.S. Western U.S.**  Connecticut Alabama Delaware Alaska Florida Arizona Georgia Arkansas Illinois California Indiana Colorado Kentucky Hawaii Maine Idaho Maryland Iowa Massachusetts Kansas Michigan Louisiana New Hampshire Minnesota New Jersey Mississippi New York Missouri North Carolina Montana Ohio Nebraska Pennsylvania Nevada Rhode Island New Mexico South Carolina North Dakota Tennessee Oklahoma Vermont Oregon Virginia South Dakota West Virginia Texas Wisconsin Utah Washington Wyoming



### TABLE W-2 OF SUBPART W – **DEFAULT TOTAL HYDROCARBON EMISSION FACTORS FOR ONSHORE NATURAL GAS PROCESSING**  **Onshore natural gas processing Emission Factor**  **(scf/hour/component)**DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 201 of 206 Formatted: Font: 8 pt

Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Tab stops: 2.66", Left **Leaker Emission Factors - Compressor Components, Gas Service** Valve 1 15.07 Connector 5.68 Open-Ended Line 17.54 Pressure Relief Valve 40.27 Meter 19.63 **Leaker Emission Factors – Non-Compressor Components, Gas Service** Valve 6.52 Connector 5.80 Open-Ended Line 11.44 Pressure Relief Valve 2.04 Meter 2.98 1 Valves include control valves, block valves and regulator valves.



### TABLE W-3 OF SUBPART W – **DEFAULT TOTAL HYDROCARBON EMISSION FACTORS FOR ONSHORE NATURAL GAS TRANSMISSION COMPRESSION**  **Onshore natural gas transmission compression**  **Emission Factor (scf/hour/component)**  **Leaker Emission Factors - Compressor Components, Gas Service** Valve 1 1 5.07 Connector 5.68 Open-Ended Line 17.54 Pressure Relief Valve 40.27 Meter 19.63 **Leaker Emission Factors – Non-Compressor Components, Gas Service** Valve 1 6.52 Connector 5.80 Open-Ended Line 11.44 Pressure Relief Valve 2.04 Meter 2.98 **Population Emission Factors – Gas Service** Low Continuous Bleed Pneumatic Device Vents 2 1. 79 41 High Continuous Bleed Pneumatic Device Vents 2 20 18
. 1 8 Intermittent Bleed Pneumatic Device Vents 2 20 18
. 1 8 1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of "scf/hour/device"DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 202 of 206 Formatted: Font: 8 pt

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### TABLE W-4 OF SUBPART W – **DEFAULT TOTAL HYDROCARBON EMISSION FACTORS FOR UNDERGROUND NATURAL GAS STORAGE** 
**Underground natural gas storage Emission Factor**  **(scf/hour/componen t)**  **Leaker Emission Factors - Storage Station, Gas Service** Valve 1 1 5.07 Connector 5 .68 Open-Ended Line 1 7.54 Pressure Relief Valve 4 0.27 Meter 19.63 **Population Emission Factors - Storage Wellheads, Gas Service** Connector 0 .01 Valve 0.10 Pressure Relief Valve 0.17 Open-ended Line 0.03 **Population Emission Factors - Other Components, Gas Service** Low Continuous Bleed Pneumatic Device Vents 2 1. 79 41 High Continuous Bleed Pneumatic Device Vents 2 20 18
. 1 8 Intermittent Bleed Pneumatic Device Vents 2 20 18
. 1 8 1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of "scf/hour/device"



### TABLE W-5 OF SUBPART W – **DEFAULT METHANE EMISSION FACTORS FOR LIQUEFIED NATURAL GAS (LNG) STORAGE** 
**LNG Storage Emission Factor**  **(scf/hour/compone nt)**  **Leaker Emission Factors - LNG Storage Components, LNG Service** Valve 1.21 Pump Seal 4.06 Connector 0.35 Other 1 1.80 **Population Emission Factors - LNG Storage Compressor, Gas Service** Vapor Recovery Compressor 2 4.23 1 "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves. 2

E m i s s iDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 203 of 206 Formatted: Font: 8 pt

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F a c t o r i s i n

u n i t s

o f

" s c f / h o u r / c o m p r e s s o r "DRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 204 of 206 Formatted: Font: 8 pt

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### TABLE W-6 OF SUBPART W – **DEFAULT METHANE EMISSION FACTORS FOR LNG IMPORT AND EXPORT EQUIPMENT**  **LNG import and export equipment Emission Factor**  **(scf/hour/componen t)**  **Leaker Emission Factors - LNG Terminals Components, LNG Service** Valve 1.21 Pump Seal 4.06 Connector 0.35 Other 1 1.80 **Population Emission Factors - LNG Terminals Compressor, Gas Service** Vapor Recovery Compressor 2 4.23 1 "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves. 2

E m i s s i o n
F a c t o r i s i n

u n i t s

o f

" s cDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 205 of 206 Formatted: Font: 8 pt

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### TABLE W-7 OF SUBPART W – **DEFAULT METHANE EMISSION FACTORS FOR NATURAL GAS DISTRIBUTION**  **Natural gas distribution Emission Factor**  **(scf/hour/component) Leaker Emission Factors -**  **Above Grade M&R at City Gate Transmission**  **distribution Transfer Station**  **s 1**  **Components, Gas Service** Connector 1.72 Block Valve 0.566 Control Valve 9.48 Pressure Relief Valve 0.274 Orifice Meter 0.215 Regulator 0.784 Open-ended Line 26.533 **Population Emission Factors - Below Grade M etering-Regulating station**  **&R 1**  **2 Components, Gas Service**  **2 3**  Below Grade M&R Station, Inlet Pressure > 300 psig 1.32 Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20 Below Grade M&R Station, Inlet Pressure < 100 psig 0.10 **Population Emission Factors - Distribution Mains, Gas Service 3**  **4** Unprotected Steel 12.77 Protected Steel 0.36 Plastic 1.15 Formatted: Check spelling and grammar, Highlight Formatted: Check spelling and grammar, Highlight

Formatted: Check spelling and grammar, Highlight Formatted: Check spelling and grammar, Highlight

Formatted: Check spelling and grammar, HighlightDRAFT -- This draft only contains redline/strikeout text. 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. The purpose of this redline is to facilitate public review of the 2011 Technical Revisions to

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule." Page 206 of 206 Formatted: Font: 8 pt

Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Font: 8 pt Formatted: Tab stops: 2.66", Left **Natural gas distribution Emission Factor**  **(scf/hour/component)** Cast Iron 27.67 **Population Emission Factors - Distribution Services, Gas Service**  **5 Service**  **4** Unprotected Steel 0.19 Protected Steel 0.02 Plastic 0.001 Copper 0.03 1 City gate stations at custody transfer and excluding customer meters 1 2 Excluding customer meters 2 3 Emission Factor is in units of "scf/hour/station" 3 4 Emission Factor is in units of "scf/hour/mile" 4 5 Emission Factor is in units of “scf/hour/number of services” Formatted: Check spelling and grammar, HighlightPage 60: [1] Formatted Author 

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