Oil & Gas Meet Greenhouse Gas

Andrew D. Shroads, QEPRegional DirectorS. Cohen & AssociatesP.O. Box 1276 • Westerville, OH 43086) (614) 887-7227 • 8 ashroads@scainc.com

Greenhouse Gas Timeline - I

1863John Tyndall lectures about Earth’s atmosphere exhibiting a “greenhouse effect”

1896Svante Arrhenius develops theory relating carbon dioxide (CO2) concentration to temperature changes

1958Dr. Charles Keeling begins measuring atmospheric CO2

1990International Panel for Climate Change Report: Emissions from humans are substantially increasing greenhouse gas concentration and warming the Earth

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Greenhouse Gas Timeline - II

1997Kyoto Protocol ratified – legally binding commitments to reduce GHG emissions

2005Kyoto Protocol takes effect (blame Russia)

2007Bulletin of Atomic Scientists moves Doomsday clock to 11:55 PM, due to global warming

2009Environmental Protection Agency (EPA) proposes greenhouse gas regulations

March 31, 2011First GHG emissions report (C.Y. 2010) due to EPA

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What are Greenhouse Gases?

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Gases that absorb thermal infrared radiation (heat), making the Earth about 59º F warmer than without the gasesThere are several greenhouse gases (GHGs); 6 are regulated by this rule:1. Carbon Dioxide (CO2)2. Methane (CH4)3. Nitrous Oxide (N2O)4. Perfluorocabons (PFC)5. Hydrofluorocarbons (HFC)6. Sulfur Hexafluoride (SF6)

Greenhouse Gas Potency

Report emissions of carbon dioxide (CO2), nitrous dioxide (N2O) and methane (CH4) and total emissions in carbon dioxide equivalents (CO2e)

CO2e is the GHG multiplied by its global warming potential (GWP) CO2 GWP = 1 CH4 GWP = 21 N2O GWP = 310

CO2e = (CO2×1)+(CH4×21)+(N2O×310)

1 21 310 11

14,900

6,500

17,340

23,900

CO

2

CH

4

N2O

HF

E-2

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2

HF

E-1

25

PF

C-1

4

PF

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SF

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GW

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Example: GHG & GWP

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My home burns 100,000 cf/year N.G., emitting:12,001.12 lbs. CO2

0.20 lbs. CH4

0.02 lbs. N2O From 40 CFR 98, Tables A-1, C-1, C-2

To calculate the total CO2e emissions, multiply each pollutant by its GWP (CO2 = 1, CH4 = 21, and N2O = 310).

12,001.12 lbs. CO2 × 1 = 12,001 lbs.

0.20 lbs. CH4 × 21 = 4 lbs.

0.02 lbs. N2O × 310 = 6 lbs.

Total CO2e 12,011 lbs. (6 U.S. short tons)

Federal Greenhouse Gas Reporting Rule

Part of the Consolidated Appropriations Act (budget bill)Title 40 Code of Federal Regulations (40 CFR), Part 98Subpart NN: Effective January 1, 2010 for Natural Gas Local Distribution Companies (LDC)Subpart W (proposed): Petroleum & Natural Gas Systems, including:

Subpart RR (proposed): CO2 injection

• N.G. Distribution (LDC)• Onshore Production• Liquiefied N.G. Storage• Offshore Production• Onshore N.G. Processing

• Natural Gas Transmission, Compression and Underground Storage

• LNG Import & Export Facilities

LDC Confusion

Both Subpart W (proposed) and Subpart NN regulate GHG emissions from LDC

Subpart W (operations) would regulate the fugitive emissions (leaks) of natural gas from the equipment delivering the gasSubpart NN (supplier) regulates GHG emissions from combustion of all natural gas delivered by the LDC

Thus, some emissions are double-counted, unless EPA changes Subpart W when it is finalized.

GHG Reporting Applicability - LDC

Subpart W: Total GHG emissions ≥25,000 MT CO2e/year from: Facility (Gas Distribution Equipment after “City Gate”) Any stationary fuel combustion sources (heaters) or

other categories in §98.2(a)(2) (H2 production)

Subpart NN: All LDC must report On August 11, 2010, EPA proposed modifying this

requirement to only LDC supplying >460 MMCF/year of natural gas, as 460 MMCF/year of natural gas is equal to 25,000 metric tons of CO2e

Subpart W: LDC - I

Subpart W regulates operations distributing natural gasEach LDC must estimate the natural gas lost by the equipment in the distribution system after the “city gate” station (end of high pressure transmission line) Above ground gate stations (metering and regulating

stations)o Valves, (including pressure safety), and connectorso Open-ended lineso Natural gas driven pneumatic devices

Below grade vaults (regulator stations) Buried pipelines

Subpart W: LDC - II

1. For above ground meter regulators; and2. Gate station fugitive emissions from connectors, block

valves, control valves, pressure relief valves, orifice meters, other meters, regulators, and open ended lines

Conduct an annual leak detection with an optical gas imaging instrument on any line with a gas content >10% CH4, plus CO2 (by weight)

If a leak is detected, estimate emissions from all leaking equipment using EPA emissions factors in Subpart W for leaking equipment and the hours the equipment was used during the year

Subpart W: LDC - III

1. For below ground meter regulators and vault fugitives;2. Pipeline main fugitives; and3. Service line fugitives

Lines with a gas content >10% CH4, plus CO2 (by weight) must be reported;

Leak detection not required; EPA emissions factors are provided in Subpart W; Emissions are estimated using a “population count”

equation:

Source Count × EPA Factor × Hours in Operation

Subpart NN: LDC - IV

Subpart NN regulates the LDC as a natural gas supplierEmissions are estimated assuming all natural gas delivered is combusted, stored, or re-distributedTo reduce double-counting, end-users receiving 460,000,000 standard cubic feet/year (460 MMCF/yr) are removed from calculation These facilities should already have to

report their combustion emissions under Subpart C, as 460 MMCF/year is equal to 25,000 metric tons CO2e

Equation:EPA Factor ×(Gas In - Gas Otherwise Counted)

GHG Reporting Applicability – Producers I

Subpart W would be applicable to any facility with total GHG emissions ≥25,000 MT CO2e/year

Facility is defined at the “basin-level” EPA proposes to use the Association of Petroleum

Geologists (AAPG) three-digit Geological Province Code to define each basin

All equipment owned, rented, or leased by the same entity on all well pads within each basin

The company required to report GHG emissions is the “operating entity” listed on state well drilling or operating permit for the wellsFor jointly managed facilities, one entity must be chosen

GHG Reporting Applicability – Producers II

GHG emissions are estimated from any equipment used in drilling the well, storing gas or petroleum, gathering product from multiple wells, and enhanced oil recovery (EOR) operations, including: Compressors; Generators; Storage facilities; Piping; and Portable non-self-propelled equipmentAll equipment is included, even if rented or leased

Subpart W: Onshore Production - I

Each operation must estimate emissions from well drilling operations, device venting, fugitive emissions, vent stacks, tanks, and dissolved CO2 in liquids

Emissions are estimated using a combination of: leak detection (using optical imaging equipment), direct analytical measurements, engineering calculations, emissions factors, and emissions simulation software (E&P Tank & GlyCalc)

Subpart W: Onshore Production - II

EPA tested GHG from four production cases at well padsRange of GHG emissions from a single well pad: 370 metric tons CO2e – production at an associated

gas and oil well (no drilling) with minimal equipment and a vapor recovery unit (67 wells = 25,000 MT)

5,000 metric tons CO2e – Unconventional well drilling and operation starting in the beginning of the year with higher emitting practices (5 wells = 25,000 MT)

Due to the large number of potential emissions sources, well pad emissions will be extremely variableCould use a “worst-case scenario” to determine when GHG emissions reporting is required

Subpart W: Onshore Production - III

Emissions Source Calculation

Natural Gas Penumatic High Bleed Device Venting Engineering Estimate

Natural Gas Penumatic Low Bleed Device Venting Component Count

Natural gas driven pneumatic pump venting Engineering Estimate

Acid gas removal (AGR) vent stacks Engineering Estimate

Dehydrator vent stacks Engineering Estimate (GlyCal software)

Well venting for liquids unloadings Engineering Estimate or Direct Measurement

Gas well venting during unconventional well completions and workovers Engineering Estimate or Direct Measurement

Gas well venting during conventional well completions and workovers Engineering Estimate or Direct Measurement

Onshore production and processing storage tanks Engineering Estimate (E&P Tank software)

Well testing venting and flaring Engineering Estimate

Associated gas venting and flaring Engineering Estimate

Centrifugal compressor wet seal degassing vents Direct Measurement

Reciprocating compressor rod packing venting Direct Measurement

Leak detection and leaker emission factors Leak Detection

Population count and emission factors Leak Detection or Component Count

EOR injection pump blowdown Leak Detection or Component Count

Hydrocarbon liquids dissolved Leak Detection or Component Count

Produced water dissolved CO2 Leak Detection or Component Count

Portable equipment combustion emissions Engineering Estimate or Direct Measurement

Subpart W: Onshore Production - IV

Records are required for every emissions source Population counts Number of blowdowns, well completions, conventional

and unconventional well workovers Analysis of oil / gas produced Oil / gas production information Equipment used for data anaylsis Dates measurements obtained Results of all emissions detected and measurements Calibration reports for measuring equipment Inputs / outputs of calculations or simulationsMissing data requires new analysis or calculation

Subpart W: Portable Equipment

GHG emissions from portable equipment are used to determine applicability and estimate GHG emissions Combustion emissions from portable equipment that

cannot move on roadways under its own power and drive train and stationed at a wellhead for more than 30 days in a reporting year

Includes: drilling rigs, dehydrators, compressors, electrical generators, steam boilers, and heaters

GHG emissions from combustion are calculated using 40 CFR, Part 98, Subpart A

Subpart W: Additional Proposals

Subpart W is only a proposed rule; EPA is considering field-level reporting, (as defined in Energy Information Administration Oil and Gas Field Code Master) Field-level reporting would allow more wells to fall

below the reporting threshold It is unlikely that EPA would overrule basin-level

reporting, as it would collect less dataEPA is also considering using the U.S. Geologic Survey (USGS) definition for basin, which is based purely on the geology of the hydrocarbon basin, ignoring county lines USGS definition would make it more difficult to map

surface operations to a specific basin

Subpart C: Stationary Fuel Combustion - I

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Applicability:All stationary units that combust fuels (e.g. boilers, engines, process heaters, incinerators)Does not include: Portable sources, (unless required by Subpart W) Emergency generators, (emergency use only) Flares, (unless required by Subpart W) Hazardous waste combustion

(unless another fuel is used)EPA website has an emissions calculator for Subpart C

Subpart C: Stationary Fuel Combustion - II

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GHG to report: CO2, CH4, and N2O Calculation Methods (Tiers):

1. Fuel Usage × Default Heat Factor × GHG FactorDefault heat factor – average heating value per amount of fuel, (e.g. MMBTU/CF); Table C-1

2. Fuel Usage × Measured Heat Factor × GHG FactorMeasured heat factor - heating value per amount

of fuel3. Fuel Usage × Fuel Carbon Content × 44(CO2)/12(C)

Measured carbon content - percent of carbon in fuel4. Continuous Emissions Monitoring System (CEMS)

Measured carbon emissions rate exiting stack

Subpart C: Stationary Fuel Combustion - III

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Using Calculation Method Tier 1Unit Maximum Rated Heat Capacity ≤250 MMBTU/hourFuel used is listed in Table C-1: Gases:

Natural Gas, Blast Furnace Gas, Coke Oven Gas Petroleum Products:

Fuel Oil, Kerosene, LPG, GasolineCannot use if fuel heating value is analyzed

Using Calculation Method Tier 2Unit Maximum Rated Heat Capacity ≤250 MMBTU/hr or >250 MMBTU/hr, if firing natural gas or distillate fuel oilFuel used is listed in Table C-1

Subpart C: Stationary Fuel Combustion - IV

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Fuel Analysis (Tier 2):Periodic fuel analyses for fuels listed in §98.34(a) Natural Gas – Semiannual analyses Coal & Fuel Oil – One from each delivery Liquid & Gas (not Fuel Oil or Natural Gas) – Once per

calendar quarter Solid (not Coal) – Weekly samples analyzed monthlyFrom an Ohio EPA air permit: For each shipment of oil received for burning in this emissions unit, the permittee shall collect … a representative grab sample of oil and maintain records of the … analyses for sulfur content and heat content…

Subpart C: Stationary Fuel Combustion - V

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Additional Fuel Analysis Requirements:Fuel sampling is only required if the unit operates within the time period for fuel analysis (e.g. calendar quarter)For blended fuels, either use a weighted heating value, based on the proportions of fuels within the blend or have a representative blended fuel sample analyzedOil or gas flow meters (Tier 3) must be calibratedFuel billing meters (if provided by a separate owner) can be used in lieu of oil or gas flow metersFor missing analysis data, use the average of the before and after values.

Example – Fuel Burning

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Subpart RR: CO2 Injection & Sequestration

Proposed subpart applies to any well in which CO2 is injected into the subsurface, including wells for geologic sequestration (GS) or for any other purposeIf doing CO2 injection for any other purpose than GS, not subject to other parts of Part 98GS is long-term storage of CO2

So You Have To Report

Determine GHG emissions for each applicable subpart: Subpart C – stationary fuel combustion Subpart P – hydrogen production Subpart W – production or LDC (proposed)Total GHG emissions ≥25,000 MT, submit a GHG report

For LDC, applicability is also determined as a supplier Subpart NN – all LDC are applicable U.S. EPA has proposed a 460 MMCF/year exemption

For CO2 injection, report CO2 injected if otherwise required to report under the GHG rule (≥25,000 MT)

Reporting Exemptions

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Research & development activities: Activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale.

Resource: EPA GHG Applicability Tool

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www.epa.gov/climatechange/emissions/GHG-calculator

Select source categories from the list, calculate annual CO2e emissions, and the results will detail rule applicability and the appropriate subparts. EPA GHG hotline: 877-GHG-1188

Discontinuing Reporting

Emissions must be reported each year, even if emissions are reduced below 25,000 MT CO2e; however, there are three possible methods whereby a facility can reduce emissions and cease reporting (Subpart RR not applicable):1. Emissions are less than 25,000 MT CO2e for five consecutive years;2. Emissions are less than 15,000 MT CO2e for three

consecutive years; or3. ALL applicable GHG-emitting processes cease to operate; not applicable to municipal solid waste landfills.

Instead of a final report, a cessation notification is submitted.

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Submitting the Report

The GHG emissions report will be submitted through a website setup by EPAThe website is called the electronic Greenhouse Gas Reporting Tool (e-GGRT)Currently unavailablee-GGRT registration will be online “soon”Will include the reporting requirements for each Subpart

http://www.epa.gov/climatechange/emissions/e-ggrt_faq.html

Signing the Report - I

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Designated Representative (DR): an individual having responsibility for the overall operation of the facility

Plant manager; Superintendent; Operator of a well or a well field; Position of equivalent responsibility; or Position having overall responsibility for environmental

matters for the company. If subject to 40 CFR 75, must be same individual.

Can delegate alternate designated representative (ADR)

DR and ADR may be with different companies

Signing the Report - II

Certificate of Representation:Submitted by the DR and ADR to EPA at least 60 days prior to a GHG due date (January 30, 2011);Separate from the GHG Report;Lists the owners or operators for the facility;Form will be a printout from e-GGRT;Certifies that the DR and ADR have a written “document of agreement” with the owners or operators of the facility;DR and ADR actions are binding upon the facility owners and operators.

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Signing the Report - III

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Agent:The DR or ADR can further delegate to an agent;An agent submits the report on behalf of the DR or ADR;Agent can be someone within or outside the organization, (e.g. contractors, other partners)Agent is given authorization to EPA by DR or ADR;Agent is delegated through e-GGRT

Recordkeeping Requirements

The following records are required: Every unit for which GHG emissions were calculated Data used in GHG calculations, required in a Subpart Copies of the annual GHG reports submitted Any missing data computations Written GHG monitoring plan Certification results and maintenance records for

instruments required in a Subpart Any additional records required in a SubpartAll records must be maintained onsite and readily accessible for three years.

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GHG Monitoring Plan

Each facility must develop a written GHG Monitoring Plan (GHGMP) that details the following procedures:1. Positions responsible for collecting GHG data2. Processes / methods for collecting GHG data3. Procedures used for quality assurance, maintenance,

and repair of monitoring systems and equipment4. Delegation Agreement and Certificate of Representation

The GHGMP can reference existing documents, provided that the requirements are easily identified.

EPA can request a copy of the GHGMP or review the GHGMP during an audit.

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GHG and Title V Permits

GHG is now a pollutant in Title V operating permitsEmissions trigger is 100,000 tpy of actual or potential GHG emissionsSites not triggering GHG reporting rule would not trigger Title V permit (25,000 MT = 27,000 U.S. tons)Title V was not written for oil & gas production Does not include portable sources “Facility” has to be contiguous, not “basin-level” Ownership / partnership issues What are the potential GHG emissions from drilling?

Questions?