EPA Greenhouse Gas Mandatory Reporting Rule - OIPA

EPA Greenhouse Gas 

Mandatory Reporting Rule 

Onshore Petroleum & Natural Gas Production

Onshore Petroleum & 

Natural Gas Production

Agenda 

1.Applicability 

2.Source Categories 

3.BAMM Time Line 

4.BAMM Request 

5.Questions 

NYSE: DVN www.devonenergy.com page 3

Disclaimer 

• Devon and its contractors make no 

representations or warranties regarding the 

accuracy or validity of any of the regulatory 

interpretations discussed in this presentation, 

and any reliance on such regulatory 

interpretations will be at your own risk and 

discretion. 


Basin / Facility Map 

• Facility - With respect to onshore petroleum 

and natural gas production: “Facility” means All 

petroleum or natural gas equipment on a well 

pad or associated with a well pad under 

common ownership or control, including leased, 

rented, or contracted activities by an onshore 

petroleum and natural gas production owner or 

operator, that are located in a single 

hydrocarbon basin. 

• Basin - American Association of Petroleum Geologists 

(AAPG) Provinces Code Map 


AAPG Basins 


Asset Classification 

• Sub-basin Categories – Comprised of the formation type within 

county lines. 

Conventional 

Unconventional 

Formation Types 

>0.1 millidarci permeability 

≤ 0.1 millidarci permeability 

• Shale 

• Coal seam 

• Other tight reservoir rock 

On August 19 th , 2011 EPA proposed a sub-basin construct for 

classification of production assets within a basin. Operators will need to classify all 

of their assets into 1 of 4 EPA proposed sub-basins. 


Production Type 

Production Type – Based on production zones. 

OIL WELL 

A well completed for the 

production of crude oil from at 

least 1 oil zone or reservoir 

Light crude (≥ 20° API) 

Heavy crude (< 20° API) 

GAS WELL 

Any well that is 

not completed 

in an oil zone 

or reservoir 

(undefined in 

subparts A or W) 


Applicability Tool 

• EPA Applicability Tool 

• Industry groups and operators have tested the EPA tool and 

determined that it provides wildly inaccurate results and is not 

based on subpart W methodologies 

• Example: Onshore production centrifugal compressor venting 

• EPA Applicability Tool: 2,140 MT CO 2e /yr 

• Subpart W Calculation: 4,892 MT CO 2e /yr 

• Error of 56% 

• Operator Applicability Tools 

• Many operators and contractors have developed their own 

applicability tools to determine applicability for their assets. 

• Devon has assisted the OIPA in the development of an applicability 

tool for its membership. 



General Instructions 

• Color scheme: 

– Green cells are required. User must enter values for applicable source types. 

– Blue cells are optional. Default values are used for these cells if no user data are 

entered. Operator should enter operator-specific data where available. 

– Red cells display emission estimation results and cannot be altered. 

• The tool is intended to be used for the onshore production industry segment 

only. 

• Emission estimation methods are provided for the following source types: 

– Onshore production storage tanks 

– Combustion emissions from natural gas-fired internal combustion engines 

– Acid gas removal (AGR) vents 

– Compressor vents 

– Dehydrator vents 

– Equipment leaks 

– Pneumatic device vents 

– Pneumatic pump vents 



General Instructions (cont’d) 

• Not all potential subpart W source types are included in this tool. Source 

types that are not covered by this tool include, but are not necessarily limited 

to, the following: 

– Well event emissions: 

• Well venting for liquids unloading 

• Venting/flaring during completions and workovers w/ & w/o hydraulic fracturing 

• Well testing venting/flaring 

• Associated gas venting/flaring 

– Flare stack emissions 

– Combustion emissions from non-gas fired equipment (e.g., diesel-fired generators) 

– Combustion emissions from large (> 5 MMBtu/hr) external combustion devices 

– Enhanced oil recovery (EOR) operations (EOR injection pump blowdowns & 

hydrocarbon liquids dissolved CO 2 ) 

• If an operator has any of the omitted source types, actual emissions may be 

significantly greater than those estimated by this tool. 



Gas Composition 

• Enter produced gas CH 4 and CO 2 concentrations representative of your 

operations 

• These compositions are used in several of the source type calculations 

throughout the tool 

• Default values of 85% for CH 4 and 5% for CO 2 should be modified based 

on operator-specific data 



Onshore Production Tanks 

• Estimations based on results of E&P TANK runs for 8 

geographical database cases from the Southwestern U.S. 

• Select the case that is most representative of your 

operations 

• Enter total, basin-wide hydrocarbon liquids (oil/condensate) 

production from all wells 



Combustion Sources 

• Estimates emissions from natural gas-fired internal combustion 

engines 

• Calculations based on modified engine type, size, and fuel 

consumption data for production engines 

– Data source: 

• Burklin, C., Heaney, M. (2006, October 5). Natural Gas Compressor 

Engine Survey for Gas Production and Processing Facilities. Retrieved 

from 

http://www.utexas.edu/research/ceer/GHG/files/ConfCallSupp/H06 

8FinalReport.pdf 

– See applicability tool information tab for detailed information 

about data sources and assumptions 



Combustion Sources (cont’d) 

• Enter total basin-wide number of engines by type (rich burn/lean 

burn) within each size range 

• Estimations use “typical size” and fuel consumption ratings of 

representative models within each type/size range combination 

• See applicability tool information for data source and assumption 

details 



Acid Gas Removal Venting 

• Estimations based on subpart W §98.233(d)(3) Calculation Methodology 3 

• Enter total basin-wide sour gas (inlet stream) volume for all AGR units 

(required) 

• Enter sour gas (inlet stream) CO 2 

concentration (optional) 

– If no sour gas concentration is entered, CO 2 

concentration for produced 

gas from composition tab is used by default 

• Enter sweet gas (outlet stream) CO 2 

concentration (optional) 

– If no sweet gas concentration is entered, zero is used by default 



Compressor and Dehydrator Venting 

• Dehydrator venting estimations based on subpart W §98.233(e)(2) 

Calculation Methodology 2 for glycol dehydrators with annual throughput 

less than 0.4 MMscf/day (146 MMscf/yr) 

– If you operate any production dehys with ≥ 0.4 MMscf/day throughputs, consider 

using a GLYCalc run in lieu of Applicability Tool to estimate CO 2 and CH 4 for 

emissions from these units 

• Compressor venting calculations based on only available subpart W 

methodology for onshore production 

• Enter total basin-wide counts of dehydrators, reciprocating compressors, 

and centrifugal compressors 



Equipment Leaks 

• Estimation based on subpart W §98.233(r)(2)(i) Calculation Methodology 3, which 

uses major equipment counts and composition from Gas Composition tab 

– Light Crude emission factors used for oil production equipment leak estimates 

• Enter total basin-wide counts of gas wells and oil wells 

• Enter total basin-wide counts of major equipment by equipment type 

– Separators and line heaters for gas production sites 

– Separators, heater-treaters, and headers for oil production sites 

• Dehydrator and compressor counts are taken from Compressor and Dehydrator 

Venting section of the tool 

– Compressor and Dehydrator Venting section must be completed first 

– Dehys and compressors assumed to be in gas production service 



Pneumatic Devices & NG-Driven Pneumatic Pumps 

• Estimations based on subpart W §98.233(a) & (b) 

• Subpart W multipliers and emission factors used along with composition 

from Gas Composition tab 

• Enter total basin-wide counts of pneumatic devices by type 

– High bleed (continuous) 

– Low bleed (continuous) 

– Intermittent bleed 

• Enter total basin-wide count of natural gas-driven pneumatic pumps 


Applicability Tool Demonstration 

Please provide your information! 


Onshore Production Source 

Categories 

1. (a) Natural Gas Pneumatic 

Device Venting 

2. (c) Natural Gas-Driven 

Pneumatic Pump Venting 

3. (d) Acid Gas Removal Vents 

4. (e) Dehydrator Vents 

5. (f) Well Venting for Liquids 

Unloading 

6. (g) Gas Well Venting During 

Completions & Workovers With 

Hydraulic Fracturing 

7. (h) Venting During Completions 

& Workovers Without Hydraulic 

Fracturing 

8. (j) Onshore Production Storage 

Tanks 

9. (l) Well Testing, Venting & 

Flaring 

10.(m) Associated Gas Venting & 

Flaring 

11.(n) Flare Stack Emissions 

12.(o) Centrifugal Compressor 

Venting 

13.(p) Reciprocating Compressor 

Venting 

14.(r) Population Count & Emission 

Factors 

15.(x) EOR Hydrocarbon Liquids 

Dissolved CO 2 

16.(z) Onshore Petroleum & Natural 

Gas Production & Natural Gas 

Distribution Combustion 

Emissions 

17.(w) EOR Injection Pump 

Blowdown 


Regulation Disclaimer 

• As operators, engineers and industry experts we 

understand that the rule is often unclear and 

contains errors and inconsistencies. 

• Many industry groups (including OIPA) and 

operators are working with the EPA to address 

issues within the rule. 

• However, the fact of the matter is that the rule is 

final and a reporting deadline has been set. 


98.233(a): Natural Gas Pneumatic 

Device Venting 

Source Category Points of Interest: 

*Device Definitions in Subpart A 

High 

Low 

Intermittent 

Device Classification 

> 6scf/hr 

≤ 6scf/hr 

Snap-acting / Throttling 

•T = Operating hours of each device type (Cumulative) 

•GHG i = Sub-basin representative gas analysis 

•Operators must complete an actual count by the third calendar year of 

reporting (2013). 


98.233(c): Natural Gas-Driven 

Pneumatic Pump Venting 

• Source Category Points of Interest: 

• Count – Operators must have an actual count for the first year of 

reporting. 

• T – Operating hours of each pump (Cumulative) 

• GHG i - Sub-basin representative gas analysis 


98.233(d): Acid Gas 

Removal Vents 


• Methodology 1: CEMS 

• Methodology 2: Vent Meter 

• Methodology 3: Volumetric CO 2 Emission Calculation 

Vol I – Inlet CO 2 content (Requires Quarterly Analysis [FAQ – Avg ]) 

Vol O - Outlet CO 2 content (Requires Quarterly Analysis [FAQ – Avg ]) OR 

(Sales Line Spec) 

• Methodology 4: Standard Simulation Software (AspenTech HYSYS®, API 

4679 AMINECalc) 


98.233(e): Dehydrator Vents 


• Glycol Dehydrator Classification: 

Throughput threshold 0.4 mmscf/day 

0.4 mmscf/day Methodology 1 

0.4 mmscf/day < Methodology 2 

• Methodology 1: Standard Simulation Software 

(AspenTech HYSYS®, API 4679 AMINECalc) 

• Methodology 2: Volumetric GHG Emission Calculation 

Requires contractors to conduct an asset inventory (Count) 

• Desiccant Dehydrators – Refilling Process Emissions 


98.233(f): Well Venting for 

Liquids Unloading 


Well Classification: Two (2) categories: 

Wells without plunger lift 

Wells with plunger lift 

• Methodology 1: Representative Measurement Data (FR in cf/hr) 

• Requires operators to install a flow meter to measure the flow rate. 

• Operators will have to further classify their wells into: 

• Tubing diameter groups & Pressure groupings per sub-basin 

• EPA has proposed 5 pressure groupings 

• Methodology 2 & 3: Individual Well Venting Events 

We anticipate most industry operators to use methodologies 2 & 3. 

Methodology 2 applies to wells without plunger lift assist 

Methodology 3 applies to wells with plunger lift assist 

• Operators will need to track the time duration of each venting event regardless of 

the methodology they elect to use. 

• The majority of data points needed for methodologies 2 & 3 are well characteristics 

(static data points that will not change) 


98.233(g): Gas Well Venting During Completions & 

Workovers With Hydraulic Fracturing 


• “With/Without Fracture” refers to the fracturing process, not the status 

of a well as fractured or unfractured. 

• Operators must specify which processes they are performing on a well 

(Completion or Workover) 

• Operators must specify the well type (horizontal or vertical) to further 

classify wells. 

• Two (2) Methodologies for operators to choose from: 

• Both methodologies calculate representative flow rates (FR) to apply to all 

horizontal/vertical, completion/workover combinations in a gas producing sub-basin. 

• Operators will need to track the number of events (completion or workover) and the time 

duration of each event. 

• Operators also need to track whether the emissions are routed to atmosphere (venting) or 

flare. 

• Methodology 1 uses a flow meter. Methodology 2 is a flow rate calculation. 


98.233(h): Venting During Completions & 

Workovers Without Hydraulic Fracturing 


• “With/Without Fracture” refers to the fracturing process, not the 

status of a well as fractured or unfractured. 

• Operators must determine which processes they are performing on a 

well (Completion or Workover) 

– Operators and Industry groups are working with the EPA to define what processes 

are considered workovers and completions. 

– Operators will need to track the number of events (completions or workovers) and 

the time duration for each event. 

– Operators also need to track whether the emissions are routed to atmosphere 

(venting) or flare. 


98.233(j): Onshore Production 

Storage Tanks 


• Regulation allows for the use of engineering estimates (Default Values) 

• Oil – All hydrocarbon liquids (not including produced water) 

• Methodologies 1 – 4 apply to wells with production ≥ 10 bbl/day 

***The process flow of the production and orientation of the equipment is required 

to choose the proper methodology. 

• Methodologies 1-3 apply to wells with colocated separators or tanks. 

• Methodology 4 applies to wells that are not colocated with separators or 

tanks. 

• Methodology 5 applies to wells with production < 10 bbl/day 

***Operators will still have to conduct an inventory to track all oil/condensate 

production tanks. 


98.233(l) Well Testing, Venting & 

Flaring 


• Many operators don’t plan to report well testing emissions under 

source category (l). They plan to report emissions from well testing, 

venting & flaring under source categories (g) or (h). 

• It is interpreted that these emissions are part of a completion or 

workover process. 

• According to operators, any other well testing will be done through 

test separators and will not create an emission event. 


98.233(m): Associated Gas 

Venting & Flaring 


• Industry members have identified this source category to apply to 

stranded wells only. 

• Stranded well = a well not connected to pipeline infrastructure 

• Industry has interpreted this to not include venting or flaring for 

emergency, maintenance or service interruptions. 

• EPA has not indicated that this source category does not include 

service interruption or emergency events. 


98.233(n): Flare Stack Emissions 

Source Category Points of Interest: 

• Industry has interpreted the EPA’s intent for source category (n) to 

capture all other flaring emissions not accounted for in other 

source categories. 

• EPA has requested feedback from industry on this source category. 

• Regulation allows for the use of engineering estimates based on 

best available data or company records to determine unmeasured 

flow volumes. 

• If CEMs and continuous flow measurement devices are available on 

the flare, they must be used. 

• Instrumentation will need to calibrated per the requirements in 98.234 (b) 

• If flow measurement and CEMS not available we operators are allowed to use 

engineering estimates based on best available data 

• Use manfacturer’s data for flare efficiency. 

• If not available, default is 98% 


98.233(o): Centrifugal 

Compressor Venting 


• Requires operators to have a total count of centrifugal 

compressors in operation each reporting year. 

• Industry has interpreted this to be the number of compressors 

operating on Dec. 31 of the reporting year. 

• Operators will need to conduct an inventory annually or track 

changes throughout the year. 


98.233(p): Reciprocating 

Compressor Venting 


• Requires operators to have a total count of reciprocating 

compressors in operation each reporting year. 

• Industry has interpreted this to be the number of compressors 

operating on Dec. 31 of the reporting year. 

• Operators will need to conduct an inventory annually or track 

changes throughout the year. 


98.233(r): Population Count 

and Emission Factors 


• Asset Classification: 

• Oklahoma is classified in the Western U.S. 

• Assets classified into service (Light/Heavy Crude or Gas) 

• Major equipment or actual component counts 

• Operators have two (2) methodologies to choose from. 

• Methodology 1 – Count major equipment and use EPA component counts and 

emission factors. 

• EPA has designated that each well pad will have 1 meters/piping 

• Methodology 2 – Count each component individually and use EPA emission factors. 

• Tubing systems ≤ ½ inch diameter are exempt from (r) 


98.233(w): EOR Injection Pump 

Blowdown 


• EPA has indicated that pump implies a liquid. CO2 is a gas up to 

1,300 psi. EPA has indicated source category (w) does not apply to 

compressors moving CO2 gas. 

• Industry has identified this as an isolated process, and most operators 

are addressing these events with the operators that manage these 

operations. 

• Data point collection: 

– Calculate volume of pump (engineering or manufacturer information) 

– Track the number of blowdowns in the reporting year. 

– Remaining data points reference gas quality 


98.233(x): EOR Hydrocarbon 

Liquids Dissolved CO2 


• Industry has identified this as an isolated process, and most operators 

are addressing these events with the operators that manage these 

operations. 

• Data point collection: 

– Run analysis on hydrocarbon liquids to determine CO2 concentration. 

– Annual samples must be pulled at STP downstream of the atmospheric tanks 

(post flashing) 

– Total annual hydrocarbon liquid produced from EOR operations 


98.233(z): Onshore Petroleum & Natural 

Gas Distribution Combustion Emissions 


• Applicability 

• External Combustion Sources - < 5 mmbtu are exempt 

– (report a count) 

• Internal Combustion Engines – Two (2) categories 

• Stationary Internal Combustion Engines 

• Portable Internal Combustion Engines 

• Classification 

• Equipment Type 

• Fuel Type 

• Volume of Fuel Consumed 


Best Available Monitoring 

Methods (BAMM) 

• BAMM - 2011 

• Determine Applicability 

• BAMM - Jan. 1 – Dec. 31, 2011 (proposed) 

• Data plan for 2011 

• Event data 

• Asset Inventory 

• Asset Characteristic data 

• 40 CFR Part 98, Subpart W 98.234 (f)(5)(iv) (proposed) 

• Operators can use BAMM for sources not listed in paragraph 

(f)(2), (f)(3), and (f)(4). 


BAMM Timeline (Proposed) 

• 40 CFR Part 98, Subpart W 98.234 (f)(8) 

• Electronic Notice of Intent (e-NOI) 

• e-NOIs submitted to the MRRpetition @ epa.gov 

• e-NOIs must be submitted by Dec. 31, 2011 

• e-NOIs must be submitted in order to submit a extension request 

• BAMM Extension Request 

• Extension requests can be submitted electronically or by mail 

• Extension requests must be submitted by March 30, 2012 

• Extension Requests must contain the information required in 

98.234 (f)(8)(ii) 

• Facilities that submit both an e-NOI and an Extension 

Request will automatically use BAMM through June 30,2012 


BAMM e-NOI 

• Content of e-NOI 

• Identify all facilities for which BAMM is needed. 

• Types of emission sources (source categories) 

• BAMM provision the source falls under. 

• 98.234 (f)(2), (f)(3), (f)(4) or (f)(5) 

• EPA has indicated that a single e-NOI for a company is 

acceptable as long as it identifies all individual facilities 

by name. 


BAMM Extension Request 

• Content of Extension Request 

• A list of source categories containing data parameters 

that BAMM is needed for. 

• A description of the unique or unusual circumstances 

specific to each source. 

• A detailed explanation and supporting documentation 

of when the operator will comply with reporting 

requirements. 

• Industry Position 


Date/Deadline Summary 

• 2011 Reporting deadline 

• Sept. 27, 2012 (proposed) 

• GHG Program (Auto BAMM expiration date) 

• Jan. 1, 2012 

• Operators that determine applicability for Subpart W, will need to have 

systems and programs in place to track operations and events. 

• BAMM deadlines 

• Auto BAMM for Jan 1 – Dec. 31, 2011 

• e-NOI due Dec. 31 

• BAMM Extension Request due March 30, 2012 

• Auto BAMM granted for Jan. 1 – June 30,2012 

• Operators will need to collect data for any data point not included in 

their BAMM Extension Request on January 1, 2012. 


Questions 

Any Questions 


Thank You.

EPA Greenhouse Gas Mandatory Reporting Rule - OIPA

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