Oil and Gas Emission Inventoriesfor the Western StatesJames RussellAlison PollackGreg YarwoodENVIRON International CorporationToday’s Presentation•Background•2002 Inventory Methodology•2018 Inventory Methodology•Oil and Gas Controls•Additional ProjectsAdditionalProjectsOil and GasControls2018 InventoryMethodology2002 InventoryMethodology**Background**•Evaluate existing inventories•Develop consistent oil and gasinventory methodology•Update the baseline (2002) inventory•Project emissions for future year(2018) inventoryProject GoalsPrevious Inventory Coverage, Point•Facilities extracted:– Compressor stations– Gas plants– Storage tanks– Other smaller sourcesdepending uponinventory thresholds•Inventory thresholdsfrom 1 tpy to 100 tpy•IrregularitiesWell locations were not obtained for California as CARB provided countylevel emissions estimatesAdditionalProjectsOil and GasControls2018 InventoryMethodology2002 InventoryMethodology**Background**Previous Inventory Coverage, Area•Covered– California and Wyoming– Colorado and Alaska point sourceinventories include most sources•Not covered– New Mexico, Montana, Utah, etc...– Sources such as drill rigs and pumpengines are not included in the existing2002 inventoriesAdditionalProjectsOil and GasControls2018 InventoryMethodology2002 InventoryMethodology**Background**Base Year (2002) Inventory Procedure•Adopt point source emissions from existingstate inventories•Estimate area source emissions for:– Important NOx sources•Drill rig engines•Natural gas compressor engines•CBM pump engines– Minor NOx and VOC wellhead processes•Incorporate emission controls•Reconcile point and area inventoriesAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundDrill Rig EnginesData Collection•Drilling companies contacted•Oil and gas commission data– Well depth– Spud date – date drilling begins– Completion date – date wellpreparation is finalized•WYDEQ survey of drillingemissions in Jonah-Pinedale– 13.5 tons NOx/well– 3.3 tons SO2/wellAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundDrill Rig EnginesEmissions CalculationEFA= EFJx ( DA/ DJ) x ( TA/ TJ)where:EFA= The emission factor for another formationEFJ= The Jonah-Pinedale emission factorDA= The average depth of wells drilled in another areaDj = The average depth of wells drilled in Jonah-PinedaleTA= The duration of drilling in another areaTj= The duration of drilling in Jonah-PinedaleE = EF x Wwhere:E = The 2002 emission for a given formationEF = The formation specific emission factorW = The number of wells drilled in the formation in 2002.1. Adjust emission factor based on the characteristics of aformation2. Estimate emissions using formation-specific emission factorsAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundNatural Gas Compressor EnginesData Collection•Compressor operatorscontacted•Oil and gas commission data•Existing inventories– Colorado 2002 point sourceinventory (2004)– New Mexico Oil and GasAssociation inventory (2003)– BLM environmental impactstatements– 2002 East Texas inventory (2005)AdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundNatural Gas Compressor EnginesEmissions Calculation•Emission factor: 2.3x10-5 tons NOx/MCF,derived from NMOGA inventory•Activity data: Gas production obtained fromoil and gas commissionsEmission CalculationE = P x EFWhere:E = 2002 NOx emissionP = 2002 gas production (MCF)EF = Emission factor, 2.3x10-5tons NOx / MCFAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundCBM Pump EnginesData Collection•Wyoming Generatordatabases•Field power supply•Pertinent oil and gascommission data– Well depth– Water producedAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundCBM Pump Engines1:Estimate Engine Activity•First estimate usedscaling of WY activity•Improved estimate usesengineering calculationsand water production•Assumptions– Pump operation– Well designgPzHHgPzLP2222222111 

# ν

γ

ν

γ++=−+++LPHdH+=gVDLfHL22×=17.185.185.1)318.1(RCLVHHL××=550/ 

# γ××=QHPPGPEPP 

# ε

ε//=1. Energy in System2. Calculate Frictional Lossesor3. Calculate Pump Power4. Calculate EnginePowerModified BernoulliDarcy-WeisbachHazen-Williams equationAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundCBM Pump Engines2:Estimate Engine Emissions∑∗+∗∗=wIwAwHAHAEFE)*1.0(Where:E = 2002 county NOx emissionEF = Emission factor, see table below (g/hp-hr)Aw= Engine power for pumping at county well w (hp)HA= Hours of pumping (4,380 hr)HI= Hours of idling (4,380 hr)WY DEQ6.1 g/hp-hr*WyomingNONROAD 200412 g/hp-hrColorado & New MexicoSourceEngine EFStates*Natural gas engines in Wyoming are controlledAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundMinor NOx & VOC Wellhead ProcessesData Collection•WYDEQ emission factors– Glycol dehydrators– Completions, flaring & venting– Heaters– Tanks– Pneumatic devices•State control requirements•Alternative local emission factors•Oil and gas commission production dataAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundMinor NOx & VOC Wellhead ProcessesEmissions Calculations•Divided productionbetween oil wells and gaswells based on OGC data•Estimated emissions at oilwells by combiningproduction with WYDEQoil well emission factors*•Estimated emissions atgas wells by combiningproduction with WYDEQgas well emission factors*Calculation of Wellhead Emissions for Individual WellsGas WellE = SUMi(Pgx EFg,i) + SUMj(Pc x EFc,j) + SUM(EFw)Where:E = The 2002 emissionPg= 2002 gas productionEFg,i= Emission factor for gas process iPc= 2002 condensate productionEFc,j= Emission factor for condensate process jEFw= Per well emission factorOil WellE = SUMi(Pox EFg,i) + SUM(EFw)Where:E = The 2002 emissionPo= 2002 oil productionEFo,i= Emission factor for oil process iEFw= Per well emission factor*If provided, alternate local factors were usedAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundPoint vs. Area ReconciliationAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** BackgroundCreated scaling factor based on NM pointinventory and gas productionPTE 100 TPYSouth Dakota& UtahGathered additional data from states to includesources with a PTE between 25 and 100 TPYPTE 100 TPYNorth Dakota& OregonNo reconciliation required.PTE 25 TPYOther StatesRemoved compressor, condensate tank anddehydrator emissions from area source inventory2 TPY actualemissionsColoradoNo compressor engines include in State’sinventory => no reconciliation required5 TPYNevadaSmaller equipment grouped in large facilitiesPTE 100 TPYAlaskaReconciliationInventoryThresholdsStates2002 Oil and Gas EmissionsWRAP Total 36,550215,662103,792374,71593,371468,087PointSourceTotal TotalAreaSourceTotalOil Wells Gas WellsCondensateTanksWRAP Total 54,82821,53642,8003,141130,376181,191311,566TotalCompressorEnginesDrillRigs WellheadCBMPumpEnginesPointSourceTotalAreaSourceTotalArea Point Total Area Point Total Total PercentWRAP Total 130,376181,191311,56614,479181,191195,670115,89759%WRAP Oil and Gas InventoryOil and Gas in PreviousInventoryChange in Oil andGas EmissionsVOC Emissions (tpy)NOx Emissions (tpy)Change in 2002 Oil and Gas NOx EmissionsAdditionalProjectsOil and GasControls2018 InventoryMethodology**2002 Inventory Methodology** Background•Grow county and tribal level emissionsbased on estimated growth in oil and gasproduction•Sources of data– Local, Bureau of Land Management– Regional, Energy Information Administration•Adjust for post-2002 on-the-books controls•Special casesFuture Year (2018) Inventory ProcedureAdditionalProjectsOil and GasControls**2018 Inventory Methodology** 2002 InventoryMethodologyBackgroundResource Management Areas()0202WWWWGPf−+=where:G = the 2002 to 2018 growth factorW02= the wells (oil/gas/CBM) active in 2002Wf= the wells (oil/gas/CBM) forecast to beadded by 2018WP= the wells (oil/gas/CBM) estimated to beplugged and abandoned by 2018AdditionalProjectsOil and GasControls**2018 Inventory Methodology** 2002 InventoryMethodologyBackgroundResulting Areas of GrowthAdditionalProjectsOil and GasControls**2018 Inventory Methodology** 2002 InventoryMethodologyBackground2018 Oil and Gas EmissionsVOC Emissions (tpy)NOx Emissions (tpy)Change in NOx Emissions, 2002 to 2018Change in VOC Emissions, 2002 to 2018WRAP Total 166,00927,08284,9321,348279,370126,536405,907CBM PumpEnginesArea SourceTotalPoint SourceTotal TotalCompressorEngines Drill Rigs WellheadWRAP Total 43,248648,762194,895886,904100,811987,715Area SourceTotalPoint SourceTotal TotalOil Wells Gas WellsCondensateTanksWRAP Total 203% 26% 98% -57% 114% -30% 30%CBM PumpEnginesArea SourceTotalPoint SourceTotal TotalCompressorEngines Drill Rigs WellheadWRAP Total 18% 201% 88% 137% 8% 111%Point SourceTotal TotalArea SourceTotalOil Wells Gas WellsCondensateTanksAdditionalProjectsOil and GasControls**2018 Inventory Methodology** 2002 InventoryMethodologyBackgroundControls Included in WRAP InventoryFederal emissionstandardsDrill rigsAll statescontrol with flare or vaporrecovery (50 – 90% effective)Completion:Flaring & VentingColorado*control with 90% efficiencyGlycol DehydratorsColorado*Montana,North Dakota,Wyomingcontrol with 98% efficiencyusing combustion, vaporrecovery, etc...Condensate TanksMontana, Utahuse line powerFederal emissionstandardsWyomingemission limits on gasengines of 1-2 g/bhp-hrPump EnginesFederal emissionstandards, Colorado*Wyoming,Utahemission limits of 1-2 g/bhp-hrCompressorsPost 20022002ControlProcess*Will apply only in nonattainment areasAdditionalProjects**Oil and Gas Controls** 2018 InventoryMethodology2002 InventoryMethodologyBackground•Controls under development– Montana, proposed 25 tpy site cap– Utah, reporting and control requirements– Wyoming considering drill rig requirements•EPA Natural Gas Star Program– Industry developed strategies to control emissionsfrom many oil and gas processes– http://www.epa.gov/gasstar/index.htm•Northeast Texas compressor control demonstrationAdditional Control InformationAdditionalProjects**Oil and Gas Controls** 2018 InventoryMethodology2002 InventoryMethodologyBackgroundCompressor Engine Control OptionSystem DesignControl SystemPower SupplyAdditionalProjects**Oil and Gas Controls** 2018 InventoryMethodology2002 InventoryMethodologyBackgroundCompressor Engine Control OptionCost Effectiveness•Annual emission reduction = 12.3 tons NOx•Annualized costs = $2,250•$2,250 / 12.3 tons NOx =$183 / ton NOx*96%0.513.37002497%0.412.77555896%96%97%NOx Control Efficiency0.513.0742360.50.3After(g NOx/hp-hr)12.411.6Before(g NOx/hp-hr)7238670640EngineEmissions Reductions Achieved*Assumes 3% discount rateand five year project lifeAdditionalProjects**Oil and Gas Controls** 2018 InventoryMethodology2002 InventoryMethodologyBackground•Northwest New Mexico area sourceinventory– Cover additional processes– Obtain improved activity data and emissionfactors– Estimate SO2 emissions from additional sources•Upcoming four corners PSD incrementanalysis expected to establish historicalinventoriesAdditional Projects**Additional Projects** Oil and GasControls2018 InventoryMethodology2002 InventoryMethodologyBackground•WRAP oil and gas inventory documentation:http://www.wrapair.org/forums/ssjf/documents/eictts/oilgas.html•WRAP emissions database: http://www.wrapedms.org•Contacts: jrussell@environcorp.com orapollack@environcorp.comAdditional InformationAdditionalProjectsOil and GasControls2018 InventoryMethodology2002 InventoryMethodologyBackground