Oil & Gas Meet Greenhouse Gas

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Implications of the proposed federal greenhouse gas mandatory reporting rule on the Oil & Gas Industry.

Transcript of Oil & Gas Meet Greenhouse Gas

Oil & Gas Meet Greenhouse Gas

Oil & Gas Meet Greenhouse GasAndrew D. Shroads, QEPRegional DirectorS. Cohen & AssociatesP.O. Box 1276 Westerville, OH 43086) (614) 887-7227 8 [email protected]

1Greenhouse Gas Timeline - I1863John Tyndall lectures about Earths atmosphere exhibiting a greenhouse effect1896Svante Arrhenius develops theory relating carbon dioxide (CO2) concentration to temperature changes1958Dr. Charles Keeling begins measuring atmospheric CO21990International Panel for Climate Change Report: Emissions from humans are substantially increasing greenhouse gas concentration and warming the Earth

22Greenhouse Gas Timeline - II1997Kyoto Protocol ratified legally binding commitments to reduce GHG emissions2005Kyoto Protocol takes effect (blame Russia)2007Bulletin of Atomic Scientists moves Doomsday clock to 11:55 PM, due to global warming2009Environmental Protection Agency (EPA) proposes greenhouse gas regulationsMarch 31, 2011First GHG emissions report (C.Y. 2010) due to EPA

33What are Greenhouse Gases?4Gases that absorb thermal infrared radiation (heat), making the Earth about 59 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)

4Greenhouse Gas PotencyReport 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 = 1CH4 GWP = 21N2O GWP = 310

CO2e = (CO21)+(CH421)+(N2O310)

Example: GHG & GWP6My 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)

6Federal Greenhouse Gas Reporting RulePart 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 injectionN.G. Distribution (LDC)Onshore ProductionLiquiefied N.G. StorageOffshore ProductionOnshore N.G. Processing

Natural Gas Transmission, Compression and Underground StorageLNG Import & Export Facilities7LDC ConfusionBoth Subpart W (proposed) and Subpart NN regulate GHG emissions from LDCSubpart 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 - LDCSubpart 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 reportOn 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 - ISubpart 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)Valves, (including pressure safety), and connectorsOpen-ended linesNatural gas driven pneumatic devicesBelow grade vaults (regulator stations)Buried pipelines

Subpart W: LDC - IIFor above ground meter regulators; andGate station fugitive emissions from connectors, block valves, control valves, pressure relief valves, orifice meters, other meters, regulators, and open ended linesConduct 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 - IIIFor below ground meter regulators and vault fugitives;Pipeline main fugitives; andService line fugitivesLines 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 - IVSubpart 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 calculationThese facilities should already have to report their combustion emissions under Subpart C, as 460 MMCF/year is equal to 25,000 metric tons CO2eEquation:EPA Factor (Gas In - Gas Otherwise Counted)

GHG Reporting Applicability Producers ISubpart W would be applicable to any facility with total GHG emissions 25,000 MT CO2e/yearFacility is defined at the basin-levelEPA proposes to use the Association of Petroleum Geologists (AAPG) three-digit Geological Province Code to define each basinAll equipment owned, rented, or leased by the same entity on all well pads within each basinThe 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 IIGHG 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; andPortable non-self-propelled equipmentAll equipment is included, even if rented or leased

Subpart W: Onshore Production - IEach operation must estimate emissions from well drilling operations, device venting, fugitive emissions, vent stacks, tanks, and dissolved CO2 in liquidsEmissions are estimated using a combination of:leak detection (using optical imaging equipment),direct analytical measurements,engineering calculations,emissions factors, andemissions simulation software (E&P Tank & GlyCalc)

Subpart W: Onshore Production - IIEPA 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 - IIIEmissions SourceCalculationNatural Gas Penumatic High Bleed Device VentingEngineering EstimateNatural Gas Penumatic Low Bleed Device VentingComponent CountNatural gas driven pneumatic pump ventingEngineering EstimateAcid gas removal (AGR) vent stacksEngineering EstimateDehydrator vent stacksEngineering Estimate (GlyCal software)Well venting for liquids unloadingsEngineering Estimate or Direct MeasurementGas well venting during unconventional well completions and workoversEngineering Estimate or Direct MeasurementGas well venting during conventional well completions and workoversEngineering Estimate or Direct MeasurementOnshore production and processing storage tanksEngineering Estimate (E&P Tank software)Well testing venting and flaringEngineering EstimateAssociated gas venting and flaringEngineering EstimateCentrifugal compressor wet seal degassing ventsDirect MeasurementReciprocating compressor rod packing ventingDirect MeasurementLeak detection and leaker emission factorsLeak DetectionPopulation count and emission factorsLeak Detection or Component CountEOR injection pump blowdownLeak Detection or Component CountHydrocarbon liquids dissolvedLeak Detection or Component CountProduced water dissolved CO2Leak Detection or Component CountPortable equipment combustion emissionsEngineering Estimate or Direct MeasurementSubpart W: Onshore Production - IVRecords are required for every emissions sourcePopulation countsNumber of blowdowns, well completions, conventional and unconventional well workoversAnalysis of oil / gas producedOil / gas production informationEquipment used for data anaylsisDates measurements obtainedResults of all emissions detected and measurementsCalibration reports for measuring equipmentInputs / outputs of calculations or simulationsMissing data requires new analysis or calculation

Subpart W: Portable EquipmentGHG emissions from portable equipment are used to determine applicability and estimate GHG emissionsCombustion 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 yearIncludes: drilling rigs, dehydrators, compressors, electrical generators, steam boilers, and heatersGHG emissions from combustion are calculated using 40 CFR, Part 98, Subpart A

Subpart W: Additional ProposalsSubpart 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 thresholdIt 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 linesUSGS definition would make it more difficult to map surface operations to a specific basin

Subpart C: Stationary Fuel Combustion - I22Applicability: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

22Subpart C: Stationary Fuel Combustion - II23GHG 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-12. 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

23Subpart C: Stationary Fuel Combustion - III24Using 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 GasPetroleum Products:Fuel Oil, Kerosene, LPG, GasolineCannot use if fuel heating value is analyzedUsing 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

24Subpart C: Stationary Fuel Combustion - IV25Fuel Analysis (Tier 2):Periodic fuel analyses for fuels listed in 98.34(a)Natural Gas Semiannual analysesCoal & Fuel Oil One from each deliveryLiquid & Gas (not Fuel Oil or Natural Gas) Once per calendar quarterSolid (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

25Subpart C: Stationary Fuel Combustion - V26Additional 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.

26Example Fuel Burning27

Subpart RR: CO2 Injection & SequestrationProposed 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 ReportDetermine GHG emissions for each applicable subpart:Subpart C stationary fuel combustionSubpart P hydrogen productionSubpart W production or LDC (proposed)Total GHG emissions 25,000 MT, submit a GHG report

For LDC, applicability is also determined as a supplierSubpart NN all LDC are applicableU.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 Exemptions30Research & 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.

30Resource: EPA GHG Applicability Tool31

www.epa.gov/climatechange/emissions/GHG-calculatorSelect 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-118831Discontinuing ReportingEmissions 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.3232Submitting the ReportThe 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 soonWill include the reporting requirements for each Subparthttp://www.epa.gov/climatechange/emissions/e-ggrt_faq.html

Signing the Report - I34Designated Representative (DR): an individual having responsibility for the overall operation of the facilityPlant manager;Superintendent;Operator of a well or a well field;Position of equivalent responsibility; orPosition 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

34Signing the Report - IICertificate 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.

3535Signing the Report - III36Agent: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

36Recordkeeping RequirementsThe following records are required:Every unit for which GHG emissions were calculatedData used in GHG calculations, required in a SubpartCopies of the annual GHG reports submittedAny missing data computationsWritten GHG monitoring planCertification results and maintenance records for instruments required in a SubpartAny additional records required in a SubpartAll records must be maintained onsite and readily accessible for three years.

3737GHG Monitoring PlanEach facility must develop a written GHG Monitoring Plan (GHGMP) that details the following procedures:Positions responsible for collecting GHG dataProcesses / methods for collecting GHG dataProcedures used for quality assurance, maintenance, and repair of monitoring systems and equipmentDelegation 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.38

38GHG and Title V PermitsGHG 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 productionDoes not include portable sourcesFacility has to be contiguous, not basin-levelOwnership / partnership issuesWhat are the potential GHG emissions from drilling?Questions?



Sheet153.7759MMBTU/hour38.909MMBTU/hour45.0078MMBTU/hour41.3405MMBTU/hour100,000scf/year102452106.76258993gallons/year2836462.79136691gallons/year2605343.74100719gallons/year2605.343741007253.02kg CO2/mmBTU73.1kg CO2/mmBTU70.83kg CO2/mmBTU70.83kg CO2/mmBTU1.03E-03mmBTU/scf0.139mmBTU/gallon0.124mmBTU/gallon0.135mmBTU/gallon5.45E+00CO22.49E+04CO22.49E+04CO22.49E+04CO29.00E-04kg CH4/mmBTU3.00E-03kg CH4/mmBTU3.00E-03kg CH4/mmBTU3.00E-03kg CH4/mmBTU1.03E-03mmBTU/scf1.39E-01mmBTU/gallon1.24E-01mmBTU/gallon1.35E-01mmBTU/gallon9.24E-05CH41.02E+00CH41.06E+00CH41.06E+00CH421CH4 GWP21CH4 GWP21CH4 GWP21CH4 GWP1.94E-03CO2e (CH4)2.15E+01CO2e (CH4)2.22E+01CO2e (CH4)2.22E+01CO2e (CH4)1.00E-04kg N2O/mmBTU6.00E-04kg N2O/mmBTU6.00E-04kg N2O/mmBTU6.00E-04kg N2O/mmBTU1.03E-03mmBTU/scf1.39E-01mmBTU/gallon1.24E-01mmBTU/gallon1.35E-01mmBTU/gallon1.03E-05N2O2.05E-01N2O2.11E-01N2O2.11E-01N2O310N2O GWP310N2O GWP310N2O GWP310N2O GWP3.18E-03CO2e (N2O)6.34E+01CO2e (N2O)6.54E+01CO2e (N2O)6.54E+01CO2e (N2O)5.45E+00Total CO2e2.50E+04Total CO2e2.50E+04Total CO2e2.50E+04Total CO2e5.4512,015.686.011MMBTU/hour1027MMBTU/MMCF0.0009737098MMCF/hour

Sheet2GHGGWP121310HFE-263fb211HFE-12514,900PFC-146,500PFC c-C3F617,34023,900