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# MEMORANDUM

DATE: August 15, 2015

SUBJECT: Summary of Estimated Methane Emi ssions, Reductions and Cost 40 CFR 60 Subpart OOOO

FROM: Veronica Hanzel, EC/R Incorporated

TO: Charlene Spells, EPA/OAQPS/SPPD

The 40 CFR part 60, subpart OOOO new source performance standards (NSPS) for the oil and natural gas sector were promulgated in 2012 to reduce volatile organic compound (VOC) emissions from gas well completions, equipment leaks, compressors and pneumatic controllers at natural gas processing plants, compressors at gath ering and boosting stations and storage vessels. We anticipate reductions in methane and hazardou s air pollutants (HAP) emissions as well as natural gas savings as a co-benefit of the 2012 NSPS standards. During the development of the proposed (in 2011) and final sta ndards (in 2012) and the recons ideration of storage vessel provisions in 2013, these estimated emissions reducti ons and natural gas savi ngs were previously provided in various support documents. For ease of review, this memorandum briefly summarizes control technology di scussion and the estimated reductions of methane and HAP emissions and the natural gas savings antici pated from implementation of the 2012 NSPS for these affected facilities. In addition, we pres ent the corresponding reduc tion in carbon dioxide equivalents (CO 2 

# e) based on estimated methane reductions. The supporting documents from which we have compiled emissions information for these

affected facilities are as follows:

 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. B ackground Technical Suppo rt Document for the Final New Source performance Standards, dated July 2011. 1 

# This document will be

referred to here as the 2011 TSD.

 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. Background Supplementa l Technical Support

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## U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution. Background Technical Support Document for Proposed Standards. July 2011. EPA-453/R-11002.

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# Document for the Final New Source pe rformance Standards, dated April 2012. 2 

# This

document will be referred to here as the 2012 TSD.

 Memorandum, Heather Brown, EC/R titled "C omposition of Natural Gas for use in the Oil and Natural Gas Sector Rulemaking", dated July 28, 2011. This document will be referred here as the 2011 Natural Gas Composition Analysis. 3



# Estimation of Methane and HAP Emissions A potential benefit of VOC emissions reducti ons for the affected facilities under the

NSPS is the reduction of methane and HAP as a re sult of reduction of the emission of natural gas that contains methane and HAP. As such, wh en conducting the analysis for VOC emissions reductions for the development of the 2012 NSPS, we also calculated methane and HAP emissions reductions. The general method for es timating VOC emissions for the NSPS analysis was to estimate methane emissions by applying a ratio of methane in natural gas (segment specific) emitted by a source, and convert that to VOC or HAP based on weight percent ratios

that were determined in the 2011 Natural Gas Co mposition Analysis for the oil and natural gas sector. Our natural gas composition analysis determ ined a weight percent of methane in natural gas to be 65.7 percent for the production segm ent and 86.2 percent in the transmission and storage segment. Natural gas composition was determined to be different for gas well completions compared to other aspects of produ ction. We determined, for well completions, the average natural gas composition (volume percent) of methane in natural gas to be 83.081 percent for gas wells and 46.73 percent for oil wells. Because natural gas composition was determined to vary among industry segments and among the various affected facilities, different ratios were used accordingly. Table 1 summarizes the weight pe rcent ratios used for the various affected facilities in the various segments.

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## U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution. Background Supplemental Technical Support Document for Proposed Standards . April 2012. Docket ID EPA-HQ-OAR-2010-0505-4550.

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## Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. "Composition of Natural Gas for use in the Oil and Natural gas Sector Rulemaking". July 2011. Docket ID EPA-HQ-OAR-2010-0505-0084.

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# Table 1. Ratios Used in Estimating Emi ssions for the Oil and Natural Gas Sector

Segment Affected Facility Ratio VOC/Methane HAP/Methane Production HF Gas Well Completions a 

## 0.146 0.0106 Production Equipment Leaks - Processing b 

## 0.278 0.0105

Transmission b 

## Equipment Leaks Pneumatic Pumps Pneumatic Controllers Reciprocating Compressors 0.0277 0.000822

Storage b 

## Equipment Leaks Pneumatic Pumps Pneumatic Controllers Reciprocating Compressors Centrifugal Compressor 0.0277 0.000822

a. From Table 9 of the 2011 Natural Gas Composition Analysis. b. From Table 6 of the 2011 Natural Gas Composition Analysis.



# We determined the natural gas emissions from the various types of sources evaluated for

the NSPS based on different studies and data avai lable at the time of the development of the NSPS. Our estimation of methane, VOC and HAP emissions for each of the affected facility types under the 2012 NSPS were conduc ted as described below.

Hydraulically Fractured Natu ral Gas Well Completions The basic approach for estimation of emissions from hydraulically fractured natural gas well completions was to approximate natural gas emissions from representative gas well completions and then estimate methane, VOC and HAP using a representative gas composition

ratios as described in the 2011 Natural Gas Com position Analysis. We determined for the final rule, as described in the 2012 TSD, that the emission factor for a gas well completion was 9,000 Mcf of natural gas per completion and that na tural gas is 83.081 percen t methane by volume. Based on the volume percent of methane to natural gas from the 2011 Natural Gas Composition Analysis and the conversion from volume methane to weight methane of 0.0208 tons of methane per Mcf of methane, we es timated the methane emissions for hydraulically fractured gas wells in the 2012 NSPS final ru le. We then used the gas composition ratios

described in Table 1 above to calculate the VOC and HAP emissions. Table 2 summarizes the emissions, emission reductions, gas savings, capita l cost (in 2008 dollars), and methane cost of control for natural gas well completions as cal culated for the 2012 NSPS and based on a 7-day completion event.

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# Equipment Leaks from Natural Gas Processing Plants For equipment leaks from natural gas processi ng plants, the baseline emissions used for the analysis were the NSPS standards under 40 CFR Part 60, subpart KKK. Based on a model plant analysis, as described in Table 8-6 of the 2011 TSD, we dete rmined baseline emissions of methane to be 51.4 tons per year (tpy) per plant and the HAP emissions to be 0.539 tpy per plant. Based on our 2011 NSPS analysis of level of control achieved by LDAR programs, the

incremental additional emissions reductions above the subpart KKK (subpart VV level of control) afforded by a subpart VVa program or an LDAR program based on the monthly monitoring of components using optical gas im aging (OGI) combined annual Method 21 were

calculated. The reductions were estimated to be th e same for both of these control options which were 48.5 tons per year of methane and 0.508 tons per year of HAP per plant.

Table 3 summarizes the results of the cost an alysis with respect to these control options.

Compressors in the Production and Processing Segments

The 2012 NSPS included emission standards for compressors at natural gas processing plants and in the production segm ent between the well head and natural gas processing plants (not including compressors located at the wellhe ad). The baseline emissions for the NSPS were

calculated based on methane emission factors fro m "Methane Emissions from the Natural Gas Industry: Volume 8 - Equipment Leaks" Table 4- 8. The emission factors used are summarized in

Table 6-2 of the 2011 TSD. Using an average number of cylinders per co mpressor and a percent pressurized factor,

we determined the baseline emissions from r eciprocating compressors in the production segment (i.e., gathering and boosting stations) to be 12.3 tpy of methane and 0.129 tpy of HAP, and 23.3 tpy of methane and 0.244 tpy of HAP at natural gas processing plants. The emission factors used for centrifugal compressors were for wet seal and dry seal compressors. The estimated emissions from wet seal centrifugal compressors in the processing segment were determined to be 228 tpy of methane and 0.736 tpy of HAP. The estimated emissions from dry seal centrifugal compressors in the processing segment were determined to be 28.6 tpy of methane and 0.0926 tpy of HAP. Thes e emission rates are summarized in table 6-3

of the 2011 TSD. For reciprocating compressors, only one cont rol method was evaluated; replacement of rod packing. The estimated emission reduction from replacing rod packing were 6.84 tpy of

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# methane and 0.0717 tpy of HAP. This was based on a formula that considered the gas composition of the segments, the current emission factors for reciprocating compressors as stated above and an assumed 11.5 cubic feet per hour pe r cylinder emission rate for a compressor with newly installed rod packing. For centrifugal compressors at natural gas processing plants we estimated potential reductions for 95 percent control using a capture system combin ed with either a combustion device or rerouting of captured gas in a proce ss. This resulted in emi ssion reductions of 216 tpy of methane and 0.699 tpy of HAP per unit. Table 4 below summarizes the cost analysis of the control options for methane as was conducted for the NSPS.

Pneumatic Controllers in Production and Processing Segments For pneumatic controllers in production a nd at natural gas processing plants, we

calculated the estimated methane and HAP emissi ons based on the emission rates for high-bleed

and low bleed controllers. The cont roller is considered to be high- bleed when the emission are in excess of 6 standard cubic feet pe r hour (scfh), while low bleed de vices bleed at a rate less than or equal to 6 scfh. For the 2012 NSPS, for the pr oduction segment, we used the best available emissions estimates from pneumatic devices that are presented in Table W-1A and W-1B of the Greenhouse Gas Mandatory Reporting Rule for Petroleum and Natural Gas Systems (Subpart W). For the processing segment we used the repr esentative emissions from a bleed-device from Volume 12 of the EPA/GRI report. We used the methane emission rates from these sources and then applied the natural gas composition ratios to estimate HAP emissions. For natural gas and oil production the emission rates were estimate d to be 6.91 tpy methane and 0.073 tpy HAP for a high bleed controller and 0.26 tpy methane and 0.003 tpy of HAP fo r a low-bleed controller. For the natural gas processing segment, the emissions were estimated to be 1 tpy of methane and 0.01 tpy of HAP for both a high bleed device and a low-bleed device. The control technology options evaluated for pneumatic cont rollers in the production segment was replacement of high-bleed controller s with low-bleed controllers. For natural gas processing, we assumed that all high-bleed cont rollers had already been replaced by non-gas

driven controllers. We estimated that the em ission reduction from replacing a high-bleed pneumatic controller with a low-bleed controlle r to be 6.65 tpy of methane and 0.07 tpy of HAP in the production segment. We used the incremen tal cost of a high-bleed device over a low-bleed device of $165 to estimate cost of control for the production segment.

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# Because we estimated that the high-bleed devi ces were already replaced with instrument air systems (non-gas driven) the rule required ze ro emissions from these sources. We estimated the cost of several size instrument air systems to evaluate cost of control for these sources at natural gas processing plants. The cost evaluation of these systems is discussed in detail in

section 5.4.2.3 of the 2011 TSD. Table 5 below summa rizes the results of the cost of control analysis for pneumatic controllers for the 2012 NSPS.7Table 2. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Hydraulically FracturedNatural Gas Well CompletionsEmissions Per Unit(tons/completionevent)aControlMethodNatural GasSavedb(Mcf/completionevent)Emission Reductions(tons/completionevent)cCapitalCostd($2008)Total Cost($/completionevent)dMethane Cost ofControld($/ton)MethaneHAPMethaneHAPwithoutsavingswith gassavingsewithoutsavingswith gassavingse155.53 1.649 REC 8,100 139.97 1.48 29,713 $29,713netsavings$191netsavings155.53 1.649 Combustion NA 147.75 1.57 3,523 $3,523 NA $23 NA155.53 1.649REC withCombustion8,100 147.75 1.57 $33,237 $33,237 $837 $191 $12a. Based on 9,000 Mcf natural gas emissions per 7-day completion event (from the final 2012 TSD Section 1.5) and 83.081 percentmethane in natural gasfrom gas wells, and 0.0208 tons of methane per Mcf, and 0.0106 HAP to methane ratio for gas wells.b. Based on gas savings of ninety percent for a REC. Calculated from savings per unit based on $4 per Mcf of natural gas. Gas saved for centrifugalcompressors only applies to control routing to a process.c. Based on 90 percent control for REC and 95 percent control for combustion and REC combined with combustion.d. From tables 4-5, 4-6 and 4-8 of the 2011 TSD.e. Savings based on natural gas saved for a REC at $4 per Mcf. No savings is attributed to combustion.8Table 3. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Equipment Leaks at Natural GasProcessing PlantsEmissions Per Unit(tpy)aControl MethodNaturalGasSavedb(Mcf/yr)EmissionReductions(tpy)cCapitalCostd($2008)Annual CostMethane Cost ofControld($/ton)($2008)dMethaneHAPMethaneHAPwithoutsavingswith gassavingsewithoutsavingswith gassavingse51.4 0.539Subpart VVaLDAR2,819 48.5 0.508 7,522 $45,160 $33,915 $931 $69951.4 0.539OGI/Method 21Monitoring2819 48.5 0.508 92,522 $87,059 $75,813 $1,795 $1,563a. Based on model plant described in Table 8-6 of the 2011 TSD.b. Estimated gas savings for model plant described in Table 8-6 of the 2011 TSD.c. Based on a control effectiveness of 93.6% for valves, 95.9% for connectors, 100% for open-ended lines and 100% for pressurerelieve devices.d. From tables 8-13 and 8-18 of the 2011 TSD.e. Savings based on $4 per Mcf of natural gas saved.9Table 4. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for CompressorsCompressorType/Oil and GasSegmentEmissions PerUnit(tons/year)aControlMethodNaturalGasSavedbper unit(Mcf/yr)EmissionReductions(tons/compressoryear)cCapitalCostd($2008)cAnnual Cost perCompressor($/compressoryear)dMethane Cost ofControld($/ton)MethaneHAPMethaneHAPwithoutsavingswith gassavingsewithoutsavingswith gassavingseReciprocatingGathering &Boosting12.3 0.129Replace RodPacking397 6.84 0.072 $5,346 $1,669 $83 $244 $12Processing 23.3 0.244Replace RodPacking1079 18.6 0.195 $4,050 $1,413NetSavings$76NetSavingsCentrifugal (wet seal)Processing 228 0.736Route toCombustiondevice orprocess12,527 216 0.699 $67,918 $103,371 $53,264 $478 $247a. From Table 6-3 of the 2011 TSD.b. Calculated from savings per unit based on $4 per Mcf of natural gas. Gas saved for centrifugal compressors only applies to control routing to a processc. From Table 6-6 of the 2011 TSD for reciprocating compressors and Table 6-10 of the 2011 TSD for centrifugal compressorsd From table 6-7 of the 2011 TSD for reciprocating compressors and Table 6-12 of the 2011 TSD for centrifugal compressors.e. Savings for centrifugal compressors only applies when routing emissions to a process. There is no savings for routing to a combustion device.10Table 5. Summary of Subpart OOOO Analysis of Emissions, Reductions and Costs for Pneumatic ControllersCompressorType/Oil and GasSegmentEmissions PerUnit(tons/year)aControlMethodNaturalGasSavedbper unit(Mcf/yr)EmissionReductions(tons/compressoryear)cCapitalCostd($2008)cAnnual Cost perCompressor($/compressoryear)dMethane Cost ofControld($/ton)MethaneHAPMethaneHAPwithoutsavingswith gassavingswithoutsavingswith gassavingsNatural GasProcessing1 0.01InstrumentAir- ZeroEmissionRate871 225 2 16,972 11,090 7,606 738 506Oil andNatural GasProduction6.91 0.073Emissionthreshold -6 scfh)386 6.65 0.07 165 23 -1,519 4netsavingsa. From table 5-2 of the 2011 TSD .b. Value of recovered product assumes natural gas processing is82.8 percent methane by volume. A natural gas price of $4 per Mcf was assumed.c. From Table 5-6 of the 2011 TSD for production segment. For the natural gas processing segment, the reductions are based on asmall system size, 15 tpyreduction per loop and 15 control loops (See table 5-11 of the 2011 TSD).d. From Tables 5-10 and 5-11 of the 2011 TSD.