S

‐ 1 

### Measurements of Methane Emissions at Natural Gas Production Sites
in the United States
Supporting Information

David T. Allen 1* , Vincent M. Torres 1 , James Thomas 1 , David Sullivan 1 , Matthew Harrison 2 , Al Hendler 2 , Scott C. Herndon 3 , Charles E. Kolb 3 , Matthew Fraser 4 , A. Daniel Hill 5 , Brian K. Lamb 6 , Jennifer Miskimins 7 , Robert F. Sawyer 8 , and John H. Seinfeld 9

1 Center for Energy and Environm ental Resources, University of Texas at Austin, 10100 Burnet Road, Building 133, M.S. R7100, Austin, TX 78758

2 URS Corporation, 9400 Amberglen Boulevard, Austin, TX 78729

3 Aerodyne Research, Inc., 45 Ma nning Road, Billerica, MA 01821

4 School of Sustainable Engineering and the Bu ilt Environment, Arizona State University PO Box 875306, Tempe, AZ 85287

5 Department of Petroleum Engineering, Texas A&M University, 3116 TAMU, College Station, TX, 77843-3116

6 Department of Civil & Environmental Engi neering, Washington State University, PO Box 642910, Washington State Un iversity, Pullman WA 99164

7 Department of Petroleum Engineering, Co lorado School of Mines, 1600 Arapahoe Street, Golden, CO 80401

8 Department of Mechanical Engineering, Ma il Code 1740, University of California, Berkeley, CA 94720-1740

9 Department of Chemical Engineering, Calif ornia Institute of Technology, M/C 210-41, Pasadena, CA 91125 *Corresponding author: email: allen@che.utexas.edu ; tel.: 512-475-7842

Keywords: Natural gas, greenhouse gas emissions, methaneS

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### Table of Contents

S1 Direct Source Measurements: Well Completion Flowbacks..............page S-3

S2 Direct Source Measurements: Wells in Routine Production..............page S-24

S3 Direct Source Measurements: Ga s Well Liquids Unloading..............page S-34

S4 Downwind Mobile Sampling of Natu ral Gas Production Sites..........page S-43

S5 Nationally Scaled Emissions Estimates.................................................page S-59

S6 Site Selection and Representativeness...................................................page S-67

References...............................................................................................page S-74

This Supporting Information uses industry stan dard units of standard cubic feet (scf). One scf of methane cont ains 19.2 g methane.S

‐ 3 S1 Direct Source Measurements: Well Completion Flowbacks

S1.1 Methods Methane emissions were measur ed directly, at the point of release. Data for 27 well completion events are reported. Section S4 desc ribes measurements of methane concentrations that were made downwind of 6 of the comple tion events; these downwind measurements were used to confirm that all of the major emission sources were being measured. The sources of well-site methane emi ssions during a completion depend on the equipment used in the completion. In this work, the surface configurations will be classified into five categories, each with different types of surface configurations. Figure S1-1 shows a simplified flow diagram for one type of surface equipment configuration used during completion flowback (labeled as Configuration 1 in this wo rk). There are several stages in the flowback process that utilize the equipmen t shown in Figure S1-1. In the first stage (Step 1 in Figure S1- 1), reservoir gases mixed with water, sand and fract uring liquid flow from the high pressure well head, through a choke, to either an open top tank or an enclosed ta nk with open vents. In either case, the tank gases are vented to the atmos phere. Figure S1-2 shows examples of open-top tanks, used in Step 1. To measure emissions fr om open-top tanks, a temporary plastic cover was placed over the open-top tank, secured by clamping to the edge of the tank. A hand-held infrared camera, designed with filters and banded wave lengths to visualize hydrocarbon plumes, was used to check for leakage around the seal. The ga ses were vented through a plenum that had exit stacks of two diameters. The smaller diameter st ack was used during periods of low flow and the larger stack was used during pe riods of high flow. Switching be tween the stacks was done with pneumatic controllers operated remotely. Gas ve locity in the stack was measured using a pitot tube in the center of the stack. Total volum etric flow was calculated by multiplying the stack cross-sectional area by 80% of the gas velocity at the stack centerline. The factor of 0.8 was used to convert the centerline velocity in the stac k to an estimated average velocity in the stack. 1 Gas samples for composition analysis were draw n from the temporary stack, through tubing to a sampling port 10-20 meters from the tank. Gas samp les were drawn into evacuated tedlar bags for subsequent analysis using ga s chromatography. If an enclosed (vented) tank was used, then no plastic cover was used and a temporary stack was placed over the tank hatch. Gas velocities and compositions were measured using the same methods as used for the open top tanks.S

‐ 4 Figure S1-1. Flowback surface equipment configurati on including an open top tank and oil and water flowback tanks, venting to atmosphere; in this configuration, emissions occur from the open top tank, the water and hydrocarbon fl owback tank hatches, and the flareS

‐ 5 Figure S1-2. Open top tank used in Step 1 of flow back using the equipment configuration shown in Figure S1-1. Upper Le ft: line leading from well to ta nk; upper right: temporary plastic cover installed and clamped to edge of tank, w ith exhaust stacks on ground adjacent to tank; lower: Conceptual diagram of sampling system.

Two temporary stacks with

different diameters and gas sampling lines

Clamps holding temporary cover in placeS

‐ 6 The initial step of the completion flowback to the open-top or vented tank lasted until sufficient volumes and concentrations of natural gas were present, allowing the completion to proceed to the next step. This initial period ra nged from an hour to multiple days. In some completions, Step 2 of the completion consisted of flow to a separator (sometimes with a sand trap between well and separator). Separato r pressures ranged, over the completion events sampled in this work, from less than 100 to more than 1000 psi. Gas and liquid streams (sometimes separate water and hydrocarbon liquid st reams) flow from the separator. The water and hydrocarbon streams were fed to water and hydrocarbon flowback tanks, shown in Figure S1-3. The flowback tanks were generally encl osed, with hatches allo wing venting to the atmosphere. As shown in Figure S1-3, temporar y stacks, similar to those used in Step 1, recorded the volumes of gas exiting the flowback tanks. Tubing was used to draw gas samples to a remote sampling port, where again the samples were drawn into evacuated tedlar bags for subsequent gas analysis. The gas stream from th e separator was routed, th rough a flow meter, to a flare, or sometimes to sales. If the gas was sent to a flare, the flow rate and gas composition analysis, reported by the operator of the site, were used to determin e the flow of flared methane. A combustion efficiency of 98% was assume d, based on standard EPA emission factors 2,3

.
The period of flowback to the separator a nd enclosed flowback tank lasted from a few hours to more than a week, depending on the character istics of the well. Af ter this phase of the completion, gas was routed to sales lines and the well entered production.S

‐ 7 Figure S1-3. Oil and water flowback tanks. Upper and middle: Hatches in the tanks allowed gases to vent to the atmosphere; temporary stacks were installed on the hatches to measure gas flow. Samples for gas composition analyses were drawn from the stack, through tubing, to a remote sampling port.

Lower: Conceptual diagram of sampling system.

Vapor communication between tanks connected by a liquid line was minimal since the fluid in the active tank was above the truck loading line and not at the tank bottom Stack on open top tank only operational during Step 1S

‐ 8 The completion flowback configuration shown in Figure S1-1 was one of multiple surface equipment configurations encountered by the Study Team over the course of the study. The flowback configurations, and the frequency with which they were observed, are summarized in Table S1-1. Not all of the surface configurat ions in each of the 5 categories were exactly identical. For example, in some configurations, gas from a separator was routed to a flare; in other cases the gas was routed to sales and the fl are, and in still other cases the gas from the separator was routed exclusivel y to sales. The categorizatio ns shown in Table S1-1 are distinguished by the type of surface equipment use d, rather than the fate of the streams from particular pieces of surface equipment. Thus, Ta ble S1-1 is a summary, rather than a complete inventory of surface configurations.

Table S1-1. Surface equipment configurations for completions

Configuration Number Description of surface equipment and completion process Frequency of configuration in completions sampled in this work (%)

1 Initial flow from the well to an open or vented tank , with gases vented to the atmosphere; after this initial phase flow is routed to

a separator or multiple (high and low pressure) separators. Water and hydrocarbon liquids are sent to water and oil flowback tanks that vent to the atmosphere; gas from the separator is metered and sent to a flare or sales. (See Figure S1-1) 9 (33%)

2 Initial flow from the well to an open or vented tank , with gases vented to the atmosphere; after this initial phase flow is routed to

a separator or multiple (high and low pressure) separators. Water is sent from the separator to a vented flowback tank. The vented gases may be released or metered and sent to a flare. Hydrocarbon liquids are sent from the separator to a sealed flowback tank, and the vented gases are sent to a combustor

. 4 (15%)

3 Flow directly from the well to a separator or multiple separators, with no initial flowback to an open tank; gases from the separator either to sales or flare; liquids from the separator to a flowback tank 5 (18%)

4 Flow from the well to an open or vented tank , with gases vented to the atmosphere, for the entire duration of the completion 9 (33%)

5 Other* 0 (0%)

*The other category is included to facilitate comparisons with national data on equipment configurations used in completion flowbacks

These multiple equipment configurations reflect the wide range of production characteristics of wells and can be expected to lead to di fferent emissions. However, there are commonS

‐ 9 elements in the completions which are similar across multiple configurations. These elements include:

1. Flow of a mixture of sand, water, gas and fr acturing liquid from the well to an open tank, where the gas is vented. 2. Flow of pressurized hydrocarbon liquid, with dissolved methane, from a separator to a tank where gas flashes from the liquid and is ei ther vented or sent to a combustion device 3. Flow of pressurized water, with dissolved me thane, from a separator to a tank where gas flashes from the liquid and is either ve nted or sent to a combustion device 4. Flow of gas, including methane, from a separa tor to a sales line or to a flare which is designed to destroy 98+% of the combustible gases

In addition, during some of the completions there were other small venting events. In completions that used sand filter vessels, the sa nd filter was occasionally blown down to a vented or open top tank to discharge the collected sand. These small emission events were not possible to directly measure. In cases where it was anti cipated that emissions from these sources could be significant, estimates of these quantities were added to the completion emissions.

The focus in the completion flowback emissions reported here is on actual emissions, however, in order to understand the differences in emissions between the different surface equipment categories, it will be ne cessary to distinguish between potential and actual emissions. The concept of potential emissions, as opposed to actual emissions, is used by the US EPA in its national emission inventory. 4 In this work, the potential emissions from a completion flowback will include the emissions that would occur if all of the methane flowing from the well during the completion flowback was emitted to the atmosphere. Configurations 1, 2 and 3 all involve some level of emission control, so actual emi ssions will be lower than potential emissions. In contrast, for Configuration 4, a configuration th at will not be permissible under recent EPA New Source Performance Standards (NSPS) (Subpart OOOO regulations), there are no emission controls, so potential emissions a nd actual emissions are equal.

Section S1.2 reports total methane emission data for each completion sampled in this work, and methane emissions for each of the elements that was in place for the sampled completions.S

‐ 10 S1.2 Results and Discussion

A total of 27 completion flowback events were sampled. Completion flowback events were defined as beginning with the initiation of the flow of li quids and gases from the well and ending at the point at which the co mpletion contractor’s report stated that it ended. Often this end point was when gases were routed to sale s or to a centralized gas processing facility, however, the end point was not uniformly define d. For example, some completion flowbacks were routed from the well to a temporary separa tor, and the operator defined the end of the completion as the point at which flow was rout ed to a permanent, rather than temporary separator, even though the gases from the temporary separator went to sales. In other cases, the end of completion flowback was the point at which flow ended to temporary flowback equipment. In all cases for this study, the end of the completion flowback was at the termination time stated in the completion contractor’s report.

Of the 27 completions sampled in this work, five were in the Appalachian region, seven in the Gulf Coast region, five in the Mid- Continent region, and ten in the Rocky Mountain region. Summaries of the methane emission estimate s are provided in Tables S1-2 through S1-5.

Methane emissions over an entire completi on flowback event, summed over all emission sources for each event (e.g., tank vents, uncombus ted methane from flares), ranged from a few thousand scf to more than 800,000 scf, with an av erage value of 90,000 scf. The durations of the completions ranged from 5 to 339 hours (2 weeks). The completions with the lowest emissions were those where the flowback from th e well was sent immediately, at the start of the completion, to a separator, and all of the gases fr om the separator were sent to sales. The only emissions were from methane dissolved in liquids (mostly water) sent from the separator to a vented flowback tank. The completion with the highest total emissions, 880,000 scf, was the longest completion (339 hours) and also was a completion in which the initial flowback from the well went directly into a vented tank, and where that initial flow was very high in methane. Some of the other relatively high emissi on events (~200,000 to 300,000 scf methane) were completions with large amounts of flared gas (up to 7 million scf of methane sent to the flare). Another completion with emissions in excess of 200,000 scf of methane was one in which all gases, for the entire event, were vented to the atmosphere. This type of venting for the entire duration of the completion was observed in 9 comp letions. However, the 9 completions of this type showed a wide range of emissions (200,000 scf methane for one completion (Midcontinent Completion 1) and 27,000 scf methane for another co mpletion of this type for an adjacent well completed during the same time period (Midcontinent Completion 2 – see Table S1-4)).

Many of the completions sampled in this study either sent gases directly to sales and/or used a flare on-site to combust gases vented from separators. In some cases where a flare was present, the assumed volume of uncombusted me thane from the flare dominated the total methane emissions from the completion event (G ulf Coast Completions 1-4– see Table S1-3). For flowbacks using flares, it was assumed that 98% of the methane fed to the flare wasS

‐ 11 combusted and 2% of the methane fed to the flare remains un-combusted and escaped into the atmosphere 2,3 . Figure S1-4 shows an example of the me thane flow to the flare at a completion, which had the surface equipment configuration show n in Figure S1-1. In this completion (Gulf Coast Completion 1), a total of 5,000,000 scf of meth ane (6.4 million scf of total gas) was fed to the flare during the multi-day completion. Flow to the flare begins, after hour 4, when the transition is made from flow to the open top tank (Step 1) to flow to the separator. Flow to the flare ends when the completion ends and gase s are routed to sales. If the 5,000,000 scf of methane (6,400,000 scf of gas) fed to the flare (counted as a potential emission in this completion) is combusted at 98% efficiency, methane emissions from the flare will be 100,000 scf. In this completion, all other methane emissions during the completion event totaled 5,000 scf methane. The assumed methane emissions fr om the flare (estimated at 100,000 scf) dominate total methane emissions during this completion event.

Figure S1-4 . Flow of gas from well completion separa tors to a flare (Gulf Coast Completion 1)

Another source of methane emissions in many completions was methane that flowed from a separator, dissolved in hydrocarbon phase or aqueous phase liquids, which subsequently flashed in an oil or water flowb ack tank. The flow from the separa tor to the flowback tank is not constant. The flow varies as the separator pe riodically builds hydrocarb on liquid level to a set point, then discharges the liquid to the flowback tank. This results in the type of periodic flow shown in Figures S1-5 and S1-6. 0 1000 2000 3000 4000 5000 6000 7000

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 Cumulative flow of
gas, thousands of scf

Hours since start of completionS

‐ 12 Figure S1-5. Methane venting through temporary stack in an oil flowback tank in Gulf Coast Completion 1. Two hours of data are shown. Approximately 40 separator discharge events occurred during this period (20 per hour).

Figure S1-6. Methane venting through temporary stack in a water flowback tank for Gulf Coast Completion 1. Six hours of data are shown; 24 discharge events occurre d during this period (4 per hour).

The percentage of methane in the gases vented from flowback tanks in separator discharge events such as those shown in Figures S1-5 and S1-6 varied over the course of the flowback. There are a number of factors that ca n cause the concentration of methane in the vent gas to vary. For example, methane concentratio n in the stack of the flowback tank will vary based on the oil and water level in the flowb ack tank, since the methane flashing from the separator discharge is diluted by the existing ai r in the vapor space of the flowback tank and dilution changes as vapor space changes. Thes e liquid levels change, depending on the schedule minutes

minutesS

‐ 13 for emptying tanks of their liquids. In additi on, oil and water composition can vary over the course of a flowback, changing the methane sol ubility. Because of these and other factors, detailed temporal analysis of the methane em issions from the flowbacks was not performed; instead, time integrated analyses were done.

Volumetric flow of vent gas was recorded each minute. For each one-minute record of volumetric flow, a percentage of methane was de termined using linear interpolation between the most recent composition measurement before and the most recent composition measurement after the flow measurement. Compositions were measured approximately hourly during initial phases of completion flowbacks; as completions extended into multiple days and flows became steady, composition measurements were made every 4-8 hours. To assess the magnitude of the uncertainty associated with using linearly inte rpolated methane concentrations, two sensitivity analyses were performed. In one sensitivity an alysis, the methane concentration for each minute of flow data was assumed to be the lower of the most recent composition measurement before and the most recent composition measurement after the flow measurement. In a second sensitivity analysis, the methane concentration fo r each minute of flow data was assumed to be the higher of the most recent composition measurement before and the most recent composition measurement after the flow measurement. Fo r the estimate of the lower bound on emissions, it was assumed that the methane percentage in the gas at the start of the completion was equal to half of the detection limit (0.18% , equal to half of the smallest concentration recorded in the chromatographic analyses (0.36%) during the entire study) and it was assumed that the final gas composition persisted from the time of the measur ement until the end of the completion. For the estimate on the higher bound on con centration, the methane concentr ation at the start of the completion was assumed to be equal to the init ial concentration measurement and it was assumed that the final gas composition persisted from th e time of the measurement until the end of the completion. These two sensitivity analyses provide a quantification of the uncertainty associated with using discrete, rather than continuous methane analyses. Methane concentrations are not expected to change rapidly base d on physical arguments. The si ze of the vapor space in a half full flowback tank is more than 1000 scf, so each separator discharge event only displaces a few percent of available vapor space.

The uncertainty ranges reported in Tables S1-2 to S1-5 are a combination of the uncertainty bounds based on using intermittent, rath er than continuous composition analyses, and an estimated 10% uncertainty bound for the flow through the temporary stacks. 5 In arriving at an overall uncertainty estimate, it is assumed that the uncertainties in composition measurements and flow are independent. Not included in the uncertainty estimates for the measurements are uncertainties in combustion efficiencies in flares and combustors (assumed to be 98% 2 ) and uncertainties in the flow measurements of gas flows to sales or flares. The total quantified measurement uncertainties are approximat ely 20% of the total emission estimates.S‐14Table S1-2.Methane emissions (scf) from Appalachian well completions: results from 5 sampling events(Dark shading indicates that data were not used in determining average emission factorsa)Emission Source(duration of completion flowback event, hr)1CompanyAP-A2CompanyAP-B3CompanyAP-B4CompanyAP-C5aCompanyAP-CConfiguration1*(62.5 hr)Configuration3***(37.8 hr)Configuration3***(12.5 hr)Configuration1**(339.2 hr)Configuration1**(228 hr)Flowback to open top tank; gases vented12,700 ±10,000 scf6,700 ± 800scfNot applicable 1,105,000 ±320,000 scf240,000 ±122,000 scfAtmospheric Vent from Tank handling liquid HCstream from Completion SeparatorNot applicable Not applicableNot applicable Not applicableNot applicableControlled (combusted) Vent from Tank handlingliquid HC stream from Completion SeparatorNot applicable Not applicableNot applicable Not applicableNot applicableAtmospheric Vent from Tank handling liquidwater stream from Completion SeparatorIncluded in theflowback toopen tankIncluded in theflowback toopen tank63,500 ± 6,000scfIncluded in theflowback toopen tankIncluded in theflowback toopen tankControlled (combusted) Vent from Tank handlingliquid water stream from Completion SeparatorNot applicable Not applicableNot applicable Not applicableNot applicableGas from overhead of completion separator, sentto flare (assumed 2.0% of methane isuncombusted in flare)16,000 scf 1,000 scf 44,000 scfbNot applicableNot applicableTotal(based on temporary stack cross sectional areax centerline velocity)29,000 scf 7,700 scf 108,000 1,105,000 scf240,000 scfTotal(based on temporary stack cross sectional area xcenterline velocity x 0.8 )26,000 ± 8,000scf6,400 ± 700 scf 95,000± 5,000scf880,000 ±300,000 scf190,000 ±100,000 scfaBecause of partial data loss, there is significant uncertainty, difficultto quantify, in the resultsfrom this completion; thedata from this completion were not used in calculatingaverages or in regional and national extrapolationsbIncludes 4,000 scf from flare and 40,000 scf from venting of separator;*Configuration 1 (from Table S1-1): Initial flowback went to anopen-top tank. After the initial period, the flow was sent toa separator. Gas from the separator was sent to a flare.Liquids from the separator were sent to flowback tanks that were vented** Configuration 1 (from Table S1-1): Initial flowback went to anopen-top tank. After the initial period, the flow was sent to a separator. Gas from the separator was sent tosales. Liquids from the separator were sent to flowback tanks that were vented***Configuration 3 (from Table S1-1): Flowback to a separator; gas from the separator to sales; liquid from the separator to avented flowback tankS‐15Table S1-3.Methane emissions (scf) from Gulf Coast well completions: results from 7 sampling eventsEmission Source(duration of completion flowback event, hr)1CompanyGC-A2CompanyGC-A3CompanyGC-B4CompanyGC-B5CompanyGC-CConfiguration1*(74.9 hr)Configuration1*(74.9 hr)Configuration2**(28.0 hr)Configuration2**(27.9 hr)Configuration4****(13.8 hr)Flowback to open top tank; gases vented1300 ± 180 scf 500 ± 400 scf 40,000 ±30,000 scf13,000 ±10,000 scf21,600 ±12,000 scfAtmospheric Vent from Tank handling liquid HCstream from Completion Separator3700 ± 550 scf 4800 ± 900 scf Not applicable Not applicable Not applicableControlled (combusted) Vent from Tank handlingliquid HC stream from Completion SeparatorNot applicable Not applicable 14,000 scf 20,000 scf Not applicableAtmospheric Vent from Tank handling liquidwater stream from Completion Separator600 ± 120 scf 200 ± 100 scf 60,000 scf 60,000 scf Not applicableControlled (combusted) Vent from Tank handlingliquid water stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableGas from overhead of completion separator, sentto flare (assumed 2.0% of methane isuncombusted in flare)100,000 scf 85,000 scf 150,000 scf 90,000 scf Not applicableTotal(based on temporary stack cross sectional areax centerline velocity)106,000 scf 91,000 scf 264,000 scf 180,000 scf 21,600 scfTotal(based on temporary stack cross sectional area xcenterline velocity x 0.8 )105,000 ± 600scf90,000 ± 800scf260,000 ±30,000 scf180,000 ± 8,000scf17,300 ± 10,000scf*Configuration 1(from Table S1-1): Initial flowback went to anopen-top tank. After the initial period, flow was sent to a high pressure separator. Gas from the high pressureseparator was sent to a flare; water from the high pressure separator was sent to a vented flowback tank. Hydrocarbon liquidsfrom the high pressure separator were sent to a lowpressure separator. Gas from the low pressure separator was sent to a flare; hydrocarbon liquids from the low pressure separator were sent to a vented flowback tank**Configuration 2 (from Table S1-1): Initial flowback went to anopen-top tank. After the initial period, the flow was sent toa separator. Gas from the separator was sent to aflare or to sales. Hydrocarbon liquids from the separator were sent to a flowback tanks that was vented to a combustion device. Configuration 4 (from Table S1-1): Flowback went to a vented tank.S‐16Table S1-3 (continued).Methane emissions (scf) from Gulf Coast well completions: results from 7 sampling events(Dark shading indicates that data were not used in determining average emission factorsa)Emission Source(duration of completion flowback event, hr)6aCompanyGC-A7aCompanyGC-AConfiguration2** ( 164 hr)Configuration2**(108 hr)Flowback to open top tank; gases vented1,000 scf1,000 scfAtmospheric Vent from Tank handling liquid HCstream from Completion SeparatorNot applicableNot applicableControlled (combusted) Vent from Tank handlingliquid HC stream from Completion SeparatorNot applicableNot applicableAtmospheric Vent from Tank handling liquidwater stream from Completion Separator3,0003,000Controlled (combusted) Vent from Tank handlingliquid water stream from Completion SeparatorNot applicableNot applicableGas from overhead of completion separator, sentto flare (assumed 2.0% of methane isuncombusted in flare)243,000 scf86,000 scfTotal(based on temporary stack cross sectional areax centerline velocity)247,000 scf90,000 scfTotal(based on temporary stack cross sectional area xcenterline velocity x 0.8 )247,000 scf90,000 scfaBecause of partial data loss, there is significant uncertainty, difficultto quantify, in the resultsfrom this completion; thedata from this completion were not used in calculatingaverages or in regional and national extrapolations**Configuration 2 (from Table S1-1): Initial flowback went to anopen-top tank. After the initial period, the flow was sent toa separator. Gas from the separator was sent to aflare. Hydrocarbon liquids from the separator were sent to a flowback tanks that was vented to a combustion device.S‐17Table S1-4.Methane emissions (scf) from Mid-Continentwell completions: results from 5 sampling eventsEmission Source(duration of completion flowback event, hr)1CompanyMC-A2CompanyMC-A3CompanyMC-B4CompanyMC-B5CompanyMC-BConfiguration4 (144.7 hr)Configuration4** **(147.2 hr)Configuration3***(138.0 hr)Configuration3***(138.0 hr)Configuration3***(138.0 hr)Flowback to open top tank; gases vented250,000 ±32,000 scf34,000 ± 5,000scfNot applicable Not applicable Not applicableAtmospheric Vent from Tank handling liquid HCstream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableControlled (combusted) Vent from Tank handlingliquid HC stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableAtmospheric Vent from Tank handling liquidwater stream from Completion SeparatorNot applicable Not applicable 3,400 scf 3,000 scf 3,400 scfControlled (combusted) Vent from Tank handlingliquid water stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableGas from overhead of completion separator, sentto flare (assumed 2.0% of methane isuncombusted in flare)Not applicable Not applicable Not applicable Not applicable Not applicableTotal(based on temporary stack cross sectional areax centerline velocity)250,000 scf 34,000 scf 3,400 scf 3,000 scf 2,600 scfTotal(based on temporary stack cross sectional area xcenterline velocity x 0.8 )200,000 ±30,000 scf27,000 ± 4,000scf2,700 scf 2,400 scf 2,100 scf***Configuration 3 (from Table S1-1): Flowback to a separator; gas from the separator to sales; liquid from the separator to avented flowback tank Configuration 4 (from Table S1-1): Flowback went to a vented tank.S‐18Table S1-5.Methane emissions (scf) from Rocky Mountainwell completions: results from 10 sampling eventsEmission Source(duration of completion flowback event, hr)1CompanyRM-A2CompanyRM-A3CompanyRM-B4CompanyRM-B5CompanyRM-BConfiguration4** **(30.2 hr)Configuration4 (30.1 hr)Configuration4** **(44.5 hr)Configuration4 (34.3 hr)Configuration4** **(68.4 hr)Flowback to open top tank; gases vented30,000 ±10,000 scf16,400 ± 3,000scf13,000 ± 7,000scf37,000 ±10,000 scf49,000 ±30,000 scfAtmospheric Vent from Tank handling liquid HCstream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableControlled (combusted) Vent from Tank handlingliquid HC stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableAtmospheric Vent from Tank handling liquidwater stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableControlled (combusted) Vent from Tank handlingliquid water stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableGas from overhead of completion separator, sentto flare (assumed 2.0% of methane isuncombusted in flare)Not applicable Not applicable Not applicable Not applicable Not applicableTotal(based on temporary stack cross sectional areax centerline velocity)30,000 scf 16,400 scf 13,000 scf 37,000 scf 49,000 scfTotal(based on temporary stack cross sectional area xcenterline velocity x 0.8 )24,000 ± 8,000scf13,000 ± 2,000scf10,400 ± 6,000scf30,000 ± 8,000scf39,000 ± 30,000scf Configuration 4 (from Table S1-1): Flowback went to a vented tank.S‐19Table S1-5 (continued).Rocky Mountain methane emissions (scf) from well completions: results from 10 sampling eventsEmission Source(duration of completion flowback event, hr)6CompanyRM-B7CompanyRM-C8CompanyRM-C9CompanyRM-C10CompanyRM-CConfiguration4** **(23.7 hr)Configuration1*(4.8 hr)Configuration1*(15.1 hr)Configuration1*(20.5 hr)Configuration1*(34.1 hr)Flowback to open top tank; gases vented42,000 ± 4,000scf40 scf 6,000 ± 2,000scf50,000 ± 5,000scf39,000 ±11,000 scfAtmospheric Vent from Tank handling liquid HCstream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableControlled (combusted) Vent from Tank handlingliquid HC stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableAtmospheric Vent from Tank handling liquidwater stream from Completion SeparatorNot applicable Included in theflowback toopen tankIncluded in theflowback toopen tankIncluded in theflowback toopen tankIncluded in theflowback toopen tankControlled (combusted) Vent from Tank handlingliquid water stream from Completion SeparatorNot applicable Not applicable Not applicable Not applicable Not applicableGas from overhead of completion separator, sentto flare (assumed 2.0% of methane isuncombusted in flare)Not applicable 440 scf 9,000 scf 4,300 scf 6,500 scfTotal(based on temporary stack cross sectional areax centerline velocity)42,000 scf 500 scf 15,000 scf 54,000 scf 45,500 scfTotal(based on temporary stack cross sectional area xcenterline velocity x 0.8 )34,000 ± 3,000scf500 scf 12,000 ± 2,000scf44,000 ± 4,000scf37,700 ± 9,000scf*Configuration 1 (from Table S1-1): Initial flowback went to anopen-top tank. After the initial period, the flow was sent toa separator. Gas from the separator was sent to a flareor to sales. Water and hydrocarbon liquids from the separator were sent to flowback tanks that were vented****Configuration 4 (from Table S1-1): Flowback went to a vented tank.S

‐ 20 Tables S1-2 to S1-5 provide data on 27 comple tion flowback events. Of these, 24 will be used to establish emission averages. The three co mpletion flowbacks that were not considered in establishing averages (AP-5, GC-6 and GC-7) all had initial flowbacks into open top tanks, with gases vented to the atmosphere. In these comp letion flowbacks, the study team was unable to collect complete emission data for the initial flow to the open tank. Existing methods for estimating emissions during these initial flows do not provide reliable estimates, therefore, these completion flowbacks are not included in aver ages. Completion flowbacks MC-3, MC-4 and MC-5 also had some missing data, but in this case the completion flowbacks were included in the averaging. These comp letions involved no initi al flow to an open t op tank. Flowback went directly to a temporary separator; gas from the separator went to sales, and liquids from the separator went to a vented flow back tank (Configuration 3). Th e study team made several days of measurements, but the arrival of a hurricane necessitated removing the temporary stacks. The flowbacks continued throughout the hurricane. Th e study team used the completion reports to extrapolate data that had alrea dy been collected on the vent from the flowback tank. Because the study team was able to develop an extrapolati on based on emission behavior that had already been directly measured for several da ys, the data were included. Additional data for each of the 27 completions are provided in Table S1-6. Table S1-6 includes potential emissions fo r each of the completions, and compares net to potential emissions. The concept of potential, as opposed to net emissions is used by the US EPA in its national emission inventory. 4 In this work, the potential emissions from a completion flowback include the emissions that would occur if all of the methane flowing from the well during the completion flowback was emitted to the atmosphere. Configurations 1, 2 and 3 all involve some level of emission control, so measured emissions will be lower than potential emissions. In contrast, for Configuration 4, there are no emission controls so potential emissions and measured emissions are equal. The average fraction of emissions controlled was 98.6%, where:

Fraction of emissions controlled = 1- ( Ʃ measured emissions / Ʃ potential emissions) with the summation taken over 24 of the 27 emission eventsS

‐ 21 Table S1-6. Potential and actual methane emissions for completion flowbacks Completion

flowback Configuration (see Table S1- 1) Potential emissions (scf methane) Measured emissions (scf methane) Measured/ potential Initial production (10 6 scf/day) a AP-1 1 788,000 26,000 0.03 <0.01 AP-2 3 57,000 6,400 0.11 6.0 AP-3 3 390,000 95,000 0.24 6.8 AP-4 1 54,000,000 880,000 0.02 2.2 AP-5 1 48,000,000 190,000 0.004 7.5 GC-1 1 5,000,000 105,000 0.02 3.0 GC-2 1 4,250,000 90,000 0.02 2.7 GC-3 2 21,500,000 260,000 0.01 1.3 GC-4 2 13,000,000 180,000 0.01 0.8 GC-5 4 17,300 17,300 1 5.4 GC-6 2 12,200,000 247,000 0.02 6.1 GC-7 2 4,320,000 90,000 0.02 1.5 MC-1 4 200,000 200,000 1 1.3 MC-2 4 27,000 27,000 1 1.3 MC-3 3 20,500,000 2,700 0.0001 3.2 MC-4 3 17,500,000 2,400 0.0001 3.9 MC-5 3 18,700,000 2,100 0.0001 3.8 RM-1 4 24,000 24,000 1 Not avail. RM-2 4 13,000 13,000 1 Not avail. RM-3 4 10,400 10,400 1 0.3 RM-4 4 30,000 30,000 1 0.3 RM-5 4 39,000 39,000 1 0.4 RM-6 4 34,000 34,000 1 0.1 RM-7 1 22,000 500 0.02 3.2 RM-8 1 440,000 12,000 0.03 3.2 RM-9 1 254,000 44,000 0.17 1.7 RM-10 1 358,000 37,700 0.11 3.2 Average 6,500,000** 90,000** 0.014*

a Average daily gas production for first 30 days after completion
*1- Ʃ measured emissions/ Ʃ potential emissions, with the su mmation taken over 24 of the 27 emission events, excluding AP-5, GC-6 and GC-7 **Average taken over 24 of the 27 emission events, excluding AP-5, GC-6 and GC-7S

‐ 22 The data reported in Tables S1-2 to S1-6 ar e the first extensive measurements reported to date on methane emissions from well completion fl owbacks. However, national inventories of methane emissions have been performed . 4 In the most recent EPA national greenhouse gas emission inventory, 4 a total of 8077 well comple tions with hydraulic frac turing are estimated to result in 63.6 billion scf of methane emissions for an average of 7.87 million scf of potential methane emissions per event. EPA then redu ced their potential emission estimates due to assumed reductions from regulatory and voluntar y controls. In the national inventory, EPA combines reductions associated with well comp letion flowbacks and workovers with hydraulic fracturing. In order to allow a comparison betwee n the emissions reported in this work and an average emission per completion flowback in th e national inventory, the same percentage reduction to potential emissions was applied to workovers and completion flowbacks. Specifically, since potential emissions for comple tion flowbacks (63.6 billion scf) and workovers with hydraulic fracturing (13.8 billion scf) totale d 77.4 billion scf, and since total reductions were 36 billion scf, the percentage reduction ap plied to potential emi ssions for both completion flowbacks and workovers with hydraulic fracturing was 46.4%. This leads to an estimate of 34 billion scf of net methane emissions for co mpletion flowbacks and 7.4 billion scf of net emissions for workovers with hydraulic fracturing. The average net completion flowback emissions, per event is 4.2 million scf of methane. In this work, the average emission per completion flowback is 0.09 million scf per event, a reduction of 98% rela tive to the 4.2 million scf average for actual emissions in the EPA national inventory.

This large difference between the net emissions measured in this work and the net emissions estimated in the national inventory is due to several factors. First, the average potential emissions for completion flowbacks, measured in this work, are 20% lower than estimated by EPA. Second, 67% of the wells sent methane to sales or control devices. Third, for those wells with methane capture or control, 99% of the potential emissions were captured or controlled. Combined, these three factors acc ount for approximately 80% of the reduction in emissions relative to the EPA i nventory. Finally, the wells with uncontrolled rele ases had much lower than average potential to emit. Of the 9 we lls in this work that had uncontrolled venting of methane, the average potential to emit was 43,000 scf (0.83 Mg), which is 0.55% of the average potential to emit in the nationa l inventory. This accounts for the remainder of the emissions difference.

S1.3 Uncertainty Estimates Confidence limits for the completion flowb ack emissions were estimated using two complementary approaches. As noted earlier in this section, uncertainties associated with composition and flow measurements were estimate d and combined into an overall measurement uncertainty. For the completion flowbacks, this re sulted in uncertainty bo unds that were in the range of 20% of emissions. A complementary bootstrapping method 6 was employed to developS

‐ 23 an estimate of the combined sampling and m easurement uncertainties. In the bootstrapping procedure, the original data set of 24 fl owbacks was recreated by making 24 random event selections, with replacement, from the data set. A total of 1000 of thes e re-sampled data sets were created and the mean value of the emissions for each re-sampled data set was determined. The 95% confidence interval for the emission estimate of 90,000 scf is 35,000-173,000 scf, where the bounds represent the 2.5% and 97.5% per centiles of the means in the 1000 re-sampled datasets. The combined measurement and samp ling uncertainty estimate from the bootstrapping procedure leads to a much larger uncertainty range than would be estimated from the uncertainty associated with the measurement alone. Therefore the overall uncertainty in the completion flowback emission estimate is reported as th e uncertainty determined from the bootstrapping method.S

‐ 24 S2 Direct Source Measurements: Wells in Routine Production

S2.1 Methods Source types Emission sources on production sites include pn eumatically powered equipment, such as pumps and controllers, leaks from piping and e quipment and flashing of methane from storage tanks. In addition, some sites may have equipment such as compressors that may have methane in their exhaust. The focus in this work wa s on measuring emissions fr om pneumatic pumps and controllers and measur ing leaks from equipment, pipes, fla nges and fittings. These sources were chosen for measurement because they are curren tly estimated to contribute over 20 bcf of the EPA national inventory fr om natural gas production. 4 Figure S2-1 shows a representative well site configuration with potent ial emission sources identified.

Figure S2-1. Gas Well Production Site

The equipment present on individual well si tes can be highly variable. Sites could contain one or multiple wells. Some sites isolate wells from separators and their controllers and in these cases, a site may have no wells. At sites with multiple wells, the wells might each have their own separator and tank system, or separa tor and tank systems servicing multiple wells might be in place. Additional equipment such as dehydrators and compressors were present on Pneumatic controllers

used to control flow Pneumatically powered pumps may inject corrosion inhibitors or other chemicals Equipment, valves, flanges and fittings

may have leaksS

‐ 25 some sites but not others. Some sites had sola r powered devices (e.g., chemical injection pumps) or combustion control devices th at reduced or eliminated emi ssions even if the equipment associated with production was the same.
This heterogeneity in the configuration of well sites has been documented in other studies. For example, in a study by the City of Fort Worth, 7 which reports on emissions from 375 well sites in the Barnett Shal e production region (sites were randomly selected from the well sites that were within the City of Fort Worth) , 30% of the sites had one well, 63% had between 2 and 6 wells, and one site had 13 wells. Similarl y, while 78% of the site s had between 1 and 4 tanks, 16% had more than 4 tanks, and one site had 20 tanks. The potential sources of fugitive emissions, such as valves and flanges, varied by an order of magnitude or more between sites. Ten percent of the sites had less than 62 valves, but 10% had more than 446 valves. Ten percent of the sites had 390 or less connectors (such as flanges), but 10% had more than 3571.
Because of the heterogeneity of individual well sites, this study will not focus on average emissions per site. Instead, the data analysis reported here will be on individual equipment types and emissions per well. Specifically, emissions for chemical injection pumps and pneumatic controllers will be reported per device. The eq uipment leak measurements included leaks from wellhead equipment, piping, flanges, fittings, va lves, separators, dehydrators, and non-exhaust emissions from compressors. Since the equipment c ount is expected to scal e with the number of wells, emissions from equipment leaks are repor ted per well. Emissions for tanks were not examined because access to the multiple potential l eak sites on tanks would have required a lift at each site, severely limiting the number of sites that could have been visited. Measurements from exhaust gases (e.g., from compressor exhaust) were also not included.
For the pneumatic pumps and pneumatic contro llers, emissions are reported as regional and national averages per device. Equipment leak emissions at a site are divided by the number of wells at a site to arrive at emissions per well. Emissions per well at each site were averaged on both a regional and national basis. These per device and per well emissi on factors are used in the extrapolation of the data reported here to regional and national estima tes, as described in Section S5.
Table S2-1 summarizes the measurements made for each source type.S

‐ 26 Table S2-1. Summary of equipment and sites sampled

Equipment type Numbers of devices sampled in each production region Total Appalachian Gulf Coast Midcontinent Rocky Mtn.

Chemical Injection Pump 0 21 41 0 62

Pneumatic Devices 133 106 51 15 305

Equipment leaks* 100 69 50 59 278

Number of distinct sites 47 58 26 19 150

Number of wells 168 157 85 79 489

*Includes leaks from wellhead equipment, piping, flanges, fittings, valv es and separators; does not include flashing from tanks or engine exhaust gases

Measurement methods The initial step in the measurements was to scan the site using an infrared camera 8 to identify potential leak sources. Scanning with an infrared camera is an approved alternative work practice (40CFR60.18) used in identifying l eaking equipment. In the alternative work practice, the threshold for detec ting a leak, consistent with the practices used by the study team, is 30 g/hr (0.026 scf/m). The threshold for de tection of a leak with an infrared camera can depend, however, on operator interpretation of visual images and site specific parameters such as the background in the image of the potentially leaking component. Once the site was scanned with the infrared camera, all identified leaks were measured with a Hi-Flow Sampler. 9 The Hi-Flow Sampler is a portable, intrinsically safe, battery-powered instrument designed to determine the rate of gas leakage around various pipe fittings, valve packings, and compressor seals found in natura l gas production, transmission, storage, and processing facilities. The Hi-Flow instrument ha s been used for several decades in measuring emissions of methane in natural gas production. 5,10,11 The instrument is packaged inside a backpack, thus leaving the ope rator’s hands free for climbing ladders or otherwise accessing locations. The instrument comes with attachments for enclosing leaking devi ces and is controlled by a handheld unit consisting of an LCD and a 4-ke y control pad, which is attached to the main unit via a 6 foot coiled cord. A component’s leak rate is measured by sampli ng at a high flow rate so as to capture all the gas leaking from the component along w ith a certain amount of surrounding air. By accurately measuring the flow ra te of the sampling stream and the natural gas concentration within that stream, the gas leak rate can be calculated (see Equation below). The instrumentS

‐ 27 automatically compensates for the different specific gravity values of air and natural gas, thus assuring accurate flow rate calculations.

Leak = Flow * (Gas sample – Gas background) * 10 –2

Where: Leak = Rate of gas leakage from source (cfm) Flow = Sample flow rate (cfm) Gas sample = Concentration of gas from leak source (volume %) Gas Background = Background gas concentration (volume %)

The gas sample is drawn into the main unit th rough a flexible 1.5 inch I.D. hose. Various attachments connected to the end of the sampli ng hose provide the means of capturing all the gas that is leaking from the component under test. The main unit consists of an intrinsically safe , high-flow blower that pulls air, at up to 10 scf/m, from around the component being tested through a flexible hose and into a gas manifold located inside the unit. The sample is first passed through a restrictor where the measured pressure differential is used to calculate the sample’s actual flow rate. Next, a portion of the sample is drawn from the manifold and directed to a combustibles sensor that measures the sample’s methane concentration in the range of 0.05 to 100% gas by volume. The combustibles sensor consists of a catalytic oxidizer, designed to convert all sampled hydrocarbons to CO 2 and water. A thermal conductivity sensor is then used to determine CO 2 concentration. A second identical combustibles sensor channel measures th e background methane level within the vicinity of the leaking component. The instrument was calibrated using samples consisting of pure methane in ambient air. However, when natural gas emissions are measur ed, the instrument will encounter additional hydrocarbons (typically ethane, propane, butane a nd higher alkanes). To account for the effect of these species on the measurements, gas compos ition data were collected for each natural gas production site that was visited. Typically this gas analysis wa s provided by the site owner. Based on the gas composition, provided for each site in the study data set, the percentage of carbon accounted for by methane, in the sample stream, was determined. This percentage, multiplied by the total gas flow rate reported by the instrument, was the methane flow. The final element in the sampling system is a blower that exhausts the gas sample back into the atmosphere away from the sampling ar ea. The measured flow rate and the measured methane levels (both leak and background levels) are used to calculate the leak rate of the component being tested, with all measured a nd calculated values being displayed on the handheld control unit. Once the equipment leak emissions, detected by the infrared camera were quantified, emissions from pneumatic chemical injection pu mps and pneumatic controllers were measured with the Hi-Flow Sampler. All operating pneuma tic Chemical Injection Pumps were sampled.S

‐ 28 Some sites had solar powered electrical pumps, which did not emit methane in normal operation as pneumatic pumps do. Other sites had pneumatic pumps installed but not in operation. Still other sites did not have pumps. Both sola r powered and non-operating pneumatic pumps were only sampled if leaks were detect ed using the infrared camera. Because many of the devices sampled had intermittent flows (e.g., pneumatic pumps and controllers), a variety of meth ane concentrations were encountered by the Hi-Flow measurement system as the operation cycle for a pump or controller was sampled. Because of this intermittency in flow, determining the detection limit for the measurement system is not simple. It can be quantified based on the smallest non-zero emission rate measured. In this work, the smallest non-zero emission rate measured by the Hi-Flow system was 0.00048 scf/m and therefore the detection limit will be assumed to be less than or equal to that value. Measurements were made on a total of 305 pneumatic controllers, representing an estimated 41% of the controllers, randomly samp led from the controllers associated with the wells that were sampled. This approach of ra ndom sampling was adopted after the first sites had already been visited. For the first sites, only pneumatic controllers that were observed to be actively emitting methane were sampled. Statistical analysis of the data collected using the two approaches showed no systematic difference so th e data for the controllers were treated as one dataset.

Data analysis methods a nd uncertainty reporting Average methane emission rates, by equipment type, will be the primary method of data reporting in this section. The uncertainty in these average emission estimates is dominated by the uncertainty in the representativeness in the sa mple set. There are hu ndreds of thousands of natural gas production wells in the United States, a nd the number of sites sampled in this work, while large in comparison to other emission data sets , is small relative to the total number of sites available. Therefore, the uncertainties reported in this section will characterize the expected uncertainty in the emission means, usi ng a method referred to as bootstrapping. 6 In the bootstrapping procedure, a data set wa s re-sampled at random (with replacement). For example, for Chemical Injection Pumps, the original data set of 62 pumps was recreated by making 62 random pump selections, with replacemen t, from the data set. A total of 1000 of these re-sampled data sets were created and the mean value of the emissions for each re-sampled data set was determined. The bounds reported he re represent the 2.5% and 97.5% percentiles of the means in the 1000 re-sampled datasets. This bootstrapping procedure was used to establish uncertainty estimates for chemical injection pump s, pneumatic controllers and equipment leaks.S

‐ 29 S2.2 Results and Discussion Pneumatic Chemical Injection Pumps Pneumatic Chemical Injection Pumps use the pr essure from on-site natural gas to drive pumps that inject anti-corrosion and other liquids into the pro duced gas stream. Table S2-2 reports emission rates, by region, and a nationa l average, for Chemical Injection Pumps. Not all wells had active Chemical Injection Pumps. For example, no operating Chemical Injection Pumps were encounter ed at active produc tion sites in the Appalachian or Rocky Mountain regions. When Chemical Injection Pumps were present, some were solar powered (no routine methane emissions), and some wells ha d pneumatic injection pumps that had been installed but were not in operation (e.g., because the liquids, such as anti-corrosion additives, were not required by the well at th at point in the well life). Table S2-2 reports both “whole gas” emissi on rates, and methane emission rates. The methane emissions rate is based on the Hi-Flow Sampler measurement. Whole gas (natural gas) emissions are reported here since emissi on factors are expresse d in US EPA emission factors as whole gas emissions per device.

Table S2-2. Emissions from Chemical Injection Pumps Emissions per Pneumatic Chemical Injection Pump* Appalachian Gulf Coast Midcontinent Rocky Mtn. Total Number sampled 21 41 62 Emissions rate (scf methane/min/device) ** 0.476 ± 0.200 0.047 ± 0.013 0.192 ± 0.085 Emissions rate (scf whole gas/min/device, based on site specific gas composition) ** 0.506 ± 0.209 0.050 ± 0.014 0.204 ± 0.089

*Solar powered pumps, and pneumatic pumps that were present but not in operation are not included in the total **Uncertainty characterizes the va riability in the mean of the da ta set (as described in Section S2.1), rather than an instrumental uncertainty in a single measurementS

‐ 30 The average values of emissions per pump for Chemical Injection Pumps reported here are similar to the emissi on factor suggested by EPA 3 for use in estimating methane emissions (13.3 scf whole gas per pump per hour vs. 12.2 (9 % lower) reported here). As described in Section S5, however, if estimated emission reducti ons are applied to poten tial emissions, the net EPA estimate will be less per pump than the values reported here. There is significant geographical variability in the emissions rate from Chemical Injection Pumps between production regions. Em issions per pump from the Gulf Coast are statistically different (higher) than emissions from pumps in the Midcontinent region. The difference in average values is r oughly an order of magnitude. A number of hypotheses were examined to attempt to explain the differences in emissions. Volume of liquid pumped was not a good predictor of emi ssions. Well head and separator pressure were considered since the pumps must overcome these pressures to drive liquid flow. These variables also were not good predictors of emi ssions. Company specific practices were also considered. While roughly 90% of the samples came from two companies, one from each region (see Section S6), a total of 6 companies provided data, 3 in the Gulf Coast and 3 in the Midcontinent, and for all of thes e companies the same regional differences (Gulf Coast emissions > Midcontinent) were observed. Mean values of emissions, by company, were similar in each of the regions. Other possibilitie s, that have not yet been investigated, but that may be pursued in follow-up work, include pum p design or local regul atory requirements.

Pneumatic Controllers Pneumatic Controllers use the pressure from on-site natural gas to drive devices that actuate valves contro lling flow from units such as separators to units such as tanks. Table S2-3 reports emission rates, by region and a natio nal average, for Pneumatic Controllers.

Table S2-3. Emissions from Pneumatic Controllers Emissions per Pneumatic Controller* Appalachian Gulf Coast Midcontinent Rocky Mtn. Total Number sampled 133 106 51 15 305 Emissions rate (scf methane/min/device) ** 0.126 ± 0.043 0.268 ± 0.068 0.157 ± 0.083 0.015 ± 0.016 0.175 ± 0.034 Emissions rate (scf whole gas/min/device, based on site specific gas composition) ** 0.130 ± 0.044 0.289 ± 0.071 0.172 ± 0.086 0.021 ± 0.022 0.187 ± 0.036

*Intermittent and low bleed controllers are includ ed in the total; no high bleed controllers were reported by companies providing co ntroller type information **Uncertainty characterizes the va riability in the mean of the da ta set (as described in Section S2.1), rather than an instrumental uncertainty in a single measurementS

‐ 31 The average values of emissions per device for Pneumatic Controllers reported here are comparable to the values suggested by EPA 3 for use in estimating methane emissions (1.39, 37.3 and 13.5 scf whole gas per device per hour for lo w bleed, high bleed and intermittent bleed controllers vs. 11.2 reported here for a mix of in termittent and low bleed controllers). No high bleed controllers were reported by the companies that provided cont roller type information. At a total of 55 sites, site operators reported only interm ittent controllers and at 24 sites, site operators reported only low bleed controllers . These sites, where potential mis-identification of controller type is less likely to be a c onfounding factor, can be used to es tablish separate emission factors for intermittent and low-bleed devices. Th ese emission factors are 0.290±0.120 scf natural gas per device per minute (17.4 scf/h, 5.9±2.4 g scf/m a ssuming a natural gas density of 20.3 g/scf, as measured in this work) for intermittent controllers and 0.085±0.049 scf/m (5.1 scf/h, 1.7±1.0 g scf/m assuming a natural gas dens ity of 20.3 g/scf, as measured in this work) for low bleed controllers. For intermittent and low bleed cont rollers, the measured emission factors are 29% and 270% higher than the EPA emi ssion factors (expressed in units of scf whole gas per hour), respectively. There is significant geographical variability in the emissions rate from pneumatic controllers between prod uction regions. Emissions per c ontroller from the Gulf Coast are highest and are statistically di fferent than emissions from c ontrollers in Rocky Mountain and Appalachian regions. The Rocky Mountains have the lowest emissions. The difference in average values is more than a factor of ten between Rocky Mountain and Gulf Coast regions. Some of the regional differences in emi ssions may be explained by differences in practices for utilizing low bleed and intermittent controllers. For example, new controllers installed after February 1, 2009 in regions in Colorado that do not meet ozone standards, where most of the Rocky Mountain controllers were sampled, are required to be low bleed (or equivalent) where technically feasible (Colorad o Air Regulation XVIII.C.1; XVIII.C.2; technical feasibility criterion under re view as this is being written). However, observed differences in emission rates between intermittent and low bl eed devices (roughly a fa ctor of 3) are not sufficient to explain all of th e regional differences. A number of additional hypotheses were examined to attempt to explain the differences in emissions. For datasets consisting entirely of intermittent or entirely of low-bleed devi ces, the volume of oil produced was not a good predictor of emissions. Well h ead and separator pressure were also not good predictors of emissions. The definition of low-bleed contro llers may be issue, however. All low bleed devices are required to have emi ssions below 6 scf/hr (0.1 scf/m), but there is not currently a clear definition of which specific controller de signs should be classifi ed as low bleed and reporting practices among companies can vary. Other possibilities for explaining the low-bleed emission rates observed in this work, that have not yet been investigated, but that may be pursued in follow-up work, include operating practices for the use of the controllers.S

‐ 32 Emissions from equipment leaks Emissions from leaks in piping, valves, sepa rators, wellheads, and connectors located on site are reported in Table S2-4. The data are reported as emi ssions normalized by the number of wells on each site. Out of the 150 sites visite d, 146 had wells on the sites. The remaining 4 sites, all in the Gulf Coast region, had separa tors and other equipmen t on site, but no wells. Some companies operating in the Gulf Coast regi on isolate wells from separators and aggregate separators for multiple wells on a single site. Because these sites did not include all of the equipment associated with natural gas production , and because the wells associated with the separators were not sampled, these four site s were excluded in the data averaging. The equipment at the four sites with no wells was estim ated to be associated with 11 off-site wells, making a well count of 478 for 146 sites. The average emissions per well for these four sites (assuming one well per separator located at the site) were all less than the average per well emissions reported for the Gulf Coast. Emissions are reported per well because the va riability in the number of wells and the type of equipment located on well sites makes aver aging emissions per site a less useful way to represent equipment leak data than average emissi ons from leaks per well (leaks at a site divided by the number of wells at the site). Further, th e number and type of equipment that could be potential leak sources gene rally scales with the number of wells.

Table S2-4. Emissions from equipment leaks Emissions per Well* Appalachian Gulf Coast Midcontinent Rocky Mtn. Total

Number of sites with wells visited (number of sites with leaks detected) 47 (30) 54 (31) 26 (19) 19 (17) 146 (97)

Emissions rate (scf methane/min/well) ** 0.098 ± 0.059 scf/m/well 0.052 ± 0.030 scf/m/well 0.046 ± 0.024 scf/m/well 0.035 ± 0.026 scf/m/well 0.064 ± 0.023 scf/m/well Emissions rate (scf whole gas/min/well, based on site specific gas composition) ** 0.100 ± 0.060 scf/m/well 0.058 ± 0.033 scf/m/well 0.055 ± 0.034 scf/m/well 0.047 ± 0.034 scf/m/well 0.070 ± 0.024 scf/m/well

*All leaks detected with the FLIR camera, not including pneumatic pumps and controllers are included in the total **Uncertainty characterizes the variability in the mean of th e data set (using a bootstrapping method as described in Section 2.3), rather th an an instrumental uncertainty in a single
measurementS

‐ 33 The average values of equipment leak emissions per well reported here are similar to the average values of potential emissions per well for gas wells, separators, heaters, piping and dehydrator leaks (0.072 scf methane/min/well), calc ulated by dividing the pot ential emissions in these categories in the EPA nationa l inventory by the number of wells. 4 Two issues confound this comparison, however. First, measurements made in this work included non-exhaust emissions from compressors that were located on well sites. These compressors can perform a variety of functions, including lif t and compression for delivery into sales lines. The national inventory groups fugitive emissions from all of these types of compressors into a category for gathering compressors (3.5 billion scf/year; 0.015 scf/m per well). It w ould be appropriate to include some of these emissions in the comparisons to the measurements made in this work, but not all of the emissions, since this work did not collect data on all gath ering compressors for the wells that were sampled. A second factor c onfounding comparisons with the national inventory is that the EPA calculates net emissions in the national inventory by subt racting reductions from potential emissions. The equipment leak reductio ns are reported as an aggregate reduction that also includes reductions associated with blowdow ns, pressure relief valves, some coal-bed methane categories and other source categories (see Section S5). If these reductions are assumed to be the same percentage of potential emissi ons for these categories, the emissions in the national inventory (not including compressors) ar e 9 billion scf (172 Gg, 0.04 scf/m per well). These estimated net emissions from equipment l eaks are roughly half to two-thirds (depending on how compressors are included) of the emissions measured in this work.

S2.3 Uncertainty Estimates Confidence limits for the emissions were estimated using two complementary approaches. Uncertainties associated with co mposition and flow measurements were estimated as approximately 10% of emissions. A complementary bootstrapping method 6 was employed to develop an estimate of the combined sampling and measurement uncertainties. In the bootstrapping procedure, the original data set of was recreated by making random event selections, with replacement, from the data set. A total of 1000 of thes e re-sampled data sets were created and the mean value of the emissions for each re-sampled data set was determined. The 95% confidence interval for the emi ssion estimate represents the 2.5% and 97.5% percentiles of the means in the 1000 re-sampled datasets. The combined measurement and sampling uncertainty estimate from the bootst rapping procedure leads to a much larger uncertainty range than would be estimated from the uncertainty associated with the measurement alone. Therefore the overall uncertainty in the em ission estimate is reported as the uncertainty determined from the bootstrapping method.S

‐ 34 

### S3 Direct Source Measurements: Gas Well Liquids Unloading

S3.1 Methods

The method used to measure emissions from manual liquid unloading of a gas well, by well blowdown, is similar to the method used to measure emissions from flowback tanks, described in Section S1. Flow is directed through a portable st ack installed on top of the tank vent on the blowdown site tanks. Figure S3-1 sh ows a temporary stack in use. Grounded metal or metal lined tubing was used to prevent static discharge. Flow ra te through the temporary stack was measured continuously, ne ar the centerline of th e temporary stack, usi ng a pitot tube.

Figure S3-1. Temporary Stack on Blowdown Site Tank Hatches

Where there were multiple tanks manifolded together, either all of the blowdown was routed to a single tank with a temporary stack, or temporary st acks were placed on all of the tanks that were vented. Total volumetric flow was calculated by multiplying the cross-sectional area of each stack by 80% of the gas velocity at th e stack centerline. The factor of 0.8 was used to convert the centerline velocity in the stack to an estimat ed average velocity in the stack, accounting for the change in velocity prof ile from friction near the stack walls. 1 Since the gas vented is the produced natural gas, the methane fraction of the vented gas will be assumed to be equal to the methane fr action in the normally produced gas. This was presumed to be a more accurate indicator of total emissions than measurements of the gas composition made through the temporary stack. The gas exiting through the temporary stack during the blowdown period is a co mbination of the blowdown gas and the gas initially in the tank (typically much lower in methane than the site’s produced gas). At the end of theS

‐ 35 blowdown, the tank will contain more methane, from the blowdown, than was in the tank at the start of the blowdown. This methane, which is associated with the blowdown event, will eventually be released as part of normal tank operations. Multiplying vented gas volume by production gas methane fraction captures these em issions that occur because of the blowdown but that are not released duri ng the period when the tank is ac tively venting through the thief hatch. Uncertainty in these measurement methods is estimated at 10% of the measured emissions and this estimate is dominated by th e assumed uncertainty in the flow (10%). Variability in the gas composition from the well is expected to be much less than 10%. As described later in this secti on, these measurement un certainties are sma ll compared to the combined sampling and meas urement uncertainty.

S3.2 Results and Discussion Emissions were measured for a total of9 gas well liquid unloading events for nonplunger lift wells. Measurements were made in the Appalachian, Gulf Coast, and Rocky Mountain production regions. No data were taken in the Midcontinent region because there were no unloadings at the visited fields during the measurement campaign. Data are presented in Tables S3-1 and S3-2. Unloading events 1a-1 c were performed on three different wells at a single well site and unload ing events 2a-c were also performed at three different wells at a single well site, in a different produc tion region than Events 1a-c. The unloadings were heterogeneous in their ch aracteristics. Methane emissions ranged from less than 1,000 scf to 191,000 scf. Some un loadings lasted two hours (or more) and had relatively uninterrupted flow (Eve nts 1a-b). Other unloadings we re as short as 10-15 minutes (e.g, Events 2b and 3) with uninterrupted flow a nd still others had intermittent flow for short periods and periods of no flow for much of the unloading period (e.g., Events 2a, 2c). The data from the unloading events can be averaged in multiple ways. One method for averaging the emissions is to consider emissions per event. Total emissions for the nine events are summed and divided by the number of events (9 events). This lead s to an average of 57,000 scf of methane per event and a median value of 5,000 to 11,000 scf. Bootstrapping methods (see Section S1) established 95% confidence bounds of 17,000-105,000 scf. The emissions from four of the 9 events contribute over 95% of the total emissions, so if this sample is representative, there is a population of high emitting events and a population of low emitting events. A second method for analyzing the data recogni zes that average emissions are often used to establish an annual emission estimate for unloa ding for individual wells. An annual emission estimate will multiply the emissions per event by a frequency (events per year) of the events. These calculations are reported in Table S3-2. For the nine wells for which data were available, this average was 300,000 scf per well per year (95% confidence limit of 100,000-620,000 scf). This per well average of unloading emissions is comparable to the 215,000 scf average emissionsS

‐ 36 per well per year for unloading without plunger li fts in EPA’s national inventory (7,734 million scf for unloadings without plunger lifts fo r 35,828 wells with this type of unloading 4 ) and an estimate of 240,000 scf methane based on a surv ey conducted by the American Petroleum Institute and America’s Natural Gas Alliance. 12 Again, however, the data are skewed with three very low emitting wells in the Rocky Mountain region, and much higher emissions per well in the Gulf Coast and Appalacian regions.S

‐ 37 Table S3-1. Emissions and well data for meas urements of manual well unloading Event (Region) Volume vented, scf

Raw and (corrected) Methane in produced
gas (vol %) Methane emitted

per event (scf) b Duration of blowdown c (hr) Volume of well

bore (ft 3 ) Well shut-in
pressure

(psia) Normal production

rate for

well (scf/hr) Events
per year for well g 1a (GC) 248,500 a (199,000) b 96% 191,000 2.77 d 10,906 300 374,000 7

1b (GC) 208,100 a (166,000) b 96% 159,000 1.904 d 10,906 300 374,000 1

1c (GC) 85,800 a (68,600) b 96% 65,900 0.63 d 10,906 300 374,000 1

2a (RM) 1,810 a (1,450) b 92.9% 1,350 0.75 e 1,875 527 295,000 2

2b (RM) 1,770 a (1,420) b 92.9% 1,320 0.2 d 1,876 642 169,000 4

2c (RM) 1,270 a (1,020) b 92.9% 950 1.25 e 1,900 1116 304,000 2

3 (AP) 14,550 a (11,600) b 97.4% 11,300 0.25 d 1,404 890 208,000 12

4 (GC) 5670 a (4540) b 84.4% 3,800 1.1 f 1,977 1500 25,000 12

5 (GC) 121,200 a (97,000) b 81.4% 79,000 1.25 d 1,977 1450 16,700 12

Avg. 76,500 (61,200) 93% 57,000 1.0 4,900 780 240,000 5.9

a based on temporary stack cross sect ional area * centerline velocity b based on temporary stack cross sectiona l area * centerline velocity * 0.8

c measured based on the time of first appearance of gas flow in temporary stack to end of gas flow in temporary stack d Once gas flow began, flow was conti nuous until the end of the unloading

e An initial burst of flow for ~5 minutes, flowed by a period of no flow, followed by a burst of flow for ~5-15 minutes
f Flow for 1 hour 5 minutes with 4 bursts of flow of up to 15 minutes, periods of no flow of up to 35 minutes.

g Reported by companies that provided the wells for samplingS

‐ 38 Table S3-2. Emissions estimates per well per year for manual well unloading Event Region a Methane emitted per
event (scf) b Events per year for well Emissions per year for well (scf)

1a GC 191,000 7 1,337,000 1b GC 159,000 1 159,000 1c GC 65,900 1 65,900 2a RM 1,350 2 2,700 2b RM 1,320 4 5,280 2c RM 950 2 1,900 3 AP 11,300 12 136,000 4 GC 3,800 12 45,600 5 GC 79,000 12 948,000 Avg. 57,000 5.9 300,000

a GC: Gulf Coast; RM: Rocky Mountain; NE: Northeast b based on temporary stack cross secti onal area * centerlin e velocity * 0.8

Since the number of events sampled is very small relative to the total number of wells and unloading events (35,828 wells with unloading events without plunger lifts in the 2013 EPA national inventory), the characteri stics of the wells sampled in this work should be compared to wider populations. One source of data is a survey reported by the American Petroleum Institute and America’s Natural Gas Alliance. 12 In this survey, over 20 companies provided unloading data on 40,000-60,000 wells (with the number in the sample depending on the type of emission event). Based on these survey data, API/ANGA estimate national totals of 28,863 wells without plunger lift that vent for unloading and 36,806 wells with plunger lift that vent for unloading. For the non-plunger lift wells, AP I/ANGA report an average of 32.57 events per well per year, higher than the average of 5.9 in this work. Th e average duration is 1.90 hours, which is roughly double the average time of 1.0 hr for the unloadings sampled in this work. The average release for wells without plunger lift (based on data in Appendix C of API/ANGA 12 ) is 304,000 scf of gas or 240,000 scf methane per well per year, as suming that gas is 78.8% methane. This is consistent with the data reported in this work (300,000 scf methane per well per year), however, while the per well annual emission rates for the 9 wells sampled in this work are consistent with the per well annual emissions in the API/ANGA data, there are si gnificant differences between the two populations. One major difference is th e frequency of unloading. The wells in the API/ANGA survey have an average of 32.57 unloadings per year, while in th is work the average is 5.9. This means that the average per even t, accounting for the different frequency of unloading of individual wells, is 9300 scf gas (7350 scf methane) in the API/ANGA survey and 57,000 scf methane in the observations reported he re. The API/ANGA dataset contains more wells that unload with high freque ncy, but lower emissions per event, than the data reported here.S

‐ 39 Another difference between the API/ANGA survey reports and the data reported here is that the API/ANGA dataset relies on estimated, ra ther than measured emissions. The emissions were estimated using the method suggested for unloading events in EPA’s Greenhouse Gas Reporting Program (GHGRP). 3 Methodology 2 for unloading w ithout plunger lifts in the
GHGRP 3 assumes that the volume in the entire lengt h of the pressurized well is vented to the atmosphere. This is assumed to occur during the first hour of the bl owdown, if the blowdown lasts more than one hour, and any gas flow beyond 1 hour is assumed to occur at the normal well gas flow rate production rate. If the blowdown lasts for less th an one hour, the emissions are assumed to be equal to the volume in the pressu rized well. The equation (W-8) provided by EPA is:

Where:
E s,n = Annual natural gas emissions at standard conditions, in cubic feet/year; this work assumes one event and reports the results per event

W = Total number of wells with well venting fo r liquids unloading for each sub-basin = 1 in this work.

0.37×10 − 3 = {3.14 ( π )/4}/{14.7*144} (psia converted to pounds per square feet). CD p = Casing internal diameter for each well, p, in inches. WD p = Well depth from either the top of the well or the lowest packer to the bottom of the well, for each well, p, in feet. SP p = For each well, p, shut-in pressure or su rface pressure for wells with tubing production or casing pressure for each well with no packers in pounds per square inch absolute (psia); or casing-to-tubing pressure ratio of one well with no packer from the same sub-basin multiplied by the tubi ng pressure of each well, p, in the subbasin, in pounds per square inch absolu te (psia); in this work the product of 0.37×10 − 3 * CD p * WD p * SP p is obtained by multiplying the well volume (in ft 3

, from Table S3-1), by the shut-in pressure (in psia, from Table S3-1) and dividing by 14.7

V p = Number of unloading events per year per well, p; assumed equal to 1 in this work

. SFR p = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour; for this work these data ar e reported in Table S3-1.

HR p,q = Hours that each well, p, was left open to the atmosphere during each unloading event, q; for this work these data are reported in Table S3-1.

1.0 = Hours for average well to blowdo wn casing volume at shut-in pressure.S

‐ 40 Z p,q = If HR p,q is less than 1.0 then Z p,q is equal to 0. If HR p,q is greater than or equal to 1.0 then Z p,q is equal to 1.

Data for all of the input variables for EP A equation W-8 (above) were collected from each study participant on the wells where direct measurements were made and are reported in Tables S3-2 and S3-3. Table S3-3 reports the re sults of applying this estimation method to the 9 well unloadings (without plunger lift) sampled in this work.

Table S3-3. Comparison of measured and estimate d gas volumes emitted during well blowdown

Event number Measured Volume vented

(scf) Total Emission Estimate per event based on Equation W-8 (scf) Total Emission Estimate per well per year based on Equation W-8 and

events/yr (Table 4-2) (scf) Emissions based on well bore volume from Equation
W-8 (scf) Emissions, after hour 1, based on production rate (scf)

1a 248,500 a (199,000) b 884,600 6,192,600 222,600 662,000

1b 208,100 a (166,000) b 559,200 559,200 222,600 336,600

1c 85,800 a (68,600) b 222,600 222,600 222,600 0

2a 1,810 a (1,450) b 67,200 134,400 67,200 0

2b 1,770 a (1,420) b 81,900 327,600 81,900 0

2c 1,270 a (1,020) b 144,200 288,400 144,200 0

3 14,550 a (11,600) b 85,000 1,020,000 85,000 0

4 5670 a (4540) b 204,200 2,450,200 201,700 2,500

5 121,200 a (97,000) b 199,200 2,390,000 195,000 4,200

Avg. 76,500 a (61,200) b 270,000 1,500,000 159,000 111,000

a based on temporary stack cross sectional area * centerline velocity
b based on temporary stack cross sectional area * centerline velocity * 0.8

In general, a simplified model assuming that the entire volume of the pressurized well is emitted during an unloading appears to work in some cases (e.g., Events 1a and 1b), but not in others (e.g., Events 2a-c). Furt her, the detailed temporal patterns of gas flow observed in thisS

‐ 41 work do not support the concept of a transition in the mechanism of flow after a one hour time period. Overall, the average emission estimate, em ploying EPA emission estimation methods, for the 9 unloadings reported here (270,000 scf meth ane), is roughly five times the measured average per event of 57,000 scf. If the estimate d emissions are calculated by well (multiplying the emissions per event by th e events per year for the we ll), the average is 1,500,000 scf methane, six times the average in the API/ANGA survey. All of these averag ing methods assume a single scalar value represents a wide range of unloadings; the data presented in th is work and in the API/ANGA survey suggest that refined emission estimation methods, taking into accoun t well and unloading characteristics, will be required. Additional measurements of unloading emissions are needed, both to resolve the differences between estimates and measurements , and to better characterize the population of wells with unloading emissions. Finally, it is also clear fro m the data that properly acc ounting for unloading emissions will be important in reconciling emission inventories with regional ambient measurements. Average methane emission rates for a single unl oading ranged from roughly a hundred grams per minute (5 scf/m) to in excess of 30,000 grams per minute (1500 scf/m), with a mean value of approximately 10,000 g/min (500 scf/m). Values fo r specific unloadings can be calculated from the data in Table S3-1. The unloading emission rates are much larger than emission rates for production sites (typically approxima tely 1 scf/m per well) or from completions (typically tens of scf/m per event). At these emission rates, a si ngle unloading event could, during the very short period that it is occurring, result in emissions that are the equivale nt of just a few wells in routine production to the equivalent of up to several thou sand wells in routine production. This indicates that reconciliation between instantaneous ambi ent measurements and emission inventories will need to very carefully re present the emissions from unloadings.

S3.3 Uncertainty Estimates Confidence limits for the unloading emissions were estimated using two complementary approaches. As noted earlier in this section, un certainties associated with composition and flow measurements were estimated as approxima tely 10% of emissions. A complementary bootstrapping method 6 was employed to develop an estimate of the combined sampling and measurement uncertainties. In th e bootstrapping procedure, the or iginal data set of 9 unloadings was recreated by making 9 random event selections, w ith replacement, from the data set. A total of 1000 of these re-sampled data sets were create d and the mean value of the emissions for each re-sampled data set was determined. The 95% confidence interval for the emission estimate of 57,000 scf is 17,000-100,000 scf, where the bounds repr esent the 2.5% and 97.5% percentiles of the means in the 1000 re-sampled datasets. The combined measurement and sampling uncertainty estimate from the bootstrapping procedur e leads to a much larger uncertainty range than would be estimated from the uncertainty as sociated with the measurement alone. ThereforeS

‐ 42 the overall uncertainty in the unloading emission estimate is reported as the uncertainty determined from the bootstrapping method.S

‐ 43 S4 Downwind Tracer Ratio Measurements at Natural Gas Production Sites

S4.1 Measurement Description and Objective The overall goal of the sampling downwind of natural gas production sites was to perform instantaneous and time integrated measur ements of the total methane emissions from natural gas production sites. The resulting emissi ons measurements represent a site aggregated emission estimate and complement on-site measurements of emissions from multiple emission sources. The objective of these downwind measurements is to determine whether the direct source measurements are capturing all significant sources of emissions, and to assess the magnitude of emissions of methane that were no t directly measured using the methods employed in this study, such as emissions th at are part of the exhaust gas of devices such as flares.

The measurements employed tracer release methodologies to quantify the total methane emission rate coming from a site. Tracer specie s were emitted at a controlled rate, on site, at locations as close as possible to methane re leases. The tracer species and methane were measured at downwind locations (100 m to mo re than 1 km). Upwind concentrations were measured, as required, if downwind mobile sampling indicated that concentr ations did not return to baseline values outside of det ected plumes. If it is assumed that the tracer disperses in a manner equivalent to the methane, the ratio of th e far field concentrations of the tracer gas and the sample gas will be the same as the ratios of their emission rates. Thus, the unknown methane emission rate is obtained from the well-known tra cer release rate and the ratio of the methane concentration to the tracer c oncentration detected sufficien tly far downwind, as shown in Equation S4-1.

Methane emission rate = Tracer emission rate * (downwind – upwind concen tration of methane) / (downwind – upwind concentration of tracer) (Eqn. S4-1)

Prior work has demonstrated that the “tra cer flux ratio” quantification approach can accurately quantify the total emissions from emissions from industrial sites 13 and landfills. 14,15
Prior research has also shown the tracer flux ratio method to be useful at quantifying the sum of small emission rates stemming from a large ar ea where individual measurements would be challenging. 16-19 The primary assumption underlying the use of the tracer flux ratio approach is the assumption of equivalent dispersion of the tr acer and methane. Therefore, in addition to reporting methane emissions estimated using this technique, a series of experiments were conducted to assess the accuracy of the equivalent dispersion assumptions.

Application of this method depends on winds that will form a well-developed plume, detectable at ground level, downwind of the s ite. The method also re quires accessibility of downwind locations for sampling. For this work, since measurements were done using a mobile van, a downwind road network was required. Becau se of these constraints, downwind sampling was only performed at a subset of the sites. The exact fraction of sites that are amenable to thisS

‐ 44 type of sampling will depend on meteorological conditions, which may vary by season, as well as topographic conditions.

S4.2 Methods

S4.2.1 Mobile Laboratory The mobile laboratory is a 25’ long truck e quipped with commercial and research grade instrumentation designed to opera te while in motion. The majori ty of the instruments on board are in-situ sampling instruments used to character ize the composition of the sampled air. Other instruments include wind speed and direction, ve hicle position and orientation using the global positioning system (GPS), atmospheric pressure and temperature. Examples of the application of this type of mobile laboratory to atmosphe ric measurements are described by Kolb et al. 20 and Herndon et al. 21,22

. Inlet description Through an inlet system at the front of the vehicle, ~ 15 stan dard liters per minute (slpm) of ambient sample are continuously drawn from a common inlet to various instruments that subsample in parallel and series (depending on th e needs of the specific instrument). Generally, each of the instruments has a response time of less than 1 s. The lag time from sample passage into the inlet and measurement by the instrument varied for each instrument. For compounds of interest in this work, the lag time was only ~ 1 s because of an 18 fold pressure drop induced just after the sample line had been brought into the truck. The additional measurements that were not associated with the primary or auxiliary tracer or methane had longer la g times, 5-9 seconds, but retained the rapid time response in the instrument itself. Repor ted time series data from the instruments with a longer lag tim e were consequently time shif ted to a common inferred inlet time without averaging. The timescale of the plume encounters in the atmosphere were 15 seconds to a minute or longer. Since the time sp ent in the instrument was typically less than 1 second, the nominal timeshift to common inlet time does not introduce bias when interpreting the concomitant increases in various species.

The inlet system also had an “overblow” line attached where gas from the truck interior could be added within 6 cm of the inlet tip (or the atmosphere). The line was used to trigger periodic zero gas, used to time the respective in let lag as well as define instrument zero. The flow rate of the zero of calibra tion gas was set to induce less than a 0.2% pressure change at the first instrument in the manifold and still “overf low” the inlet. Thus, the instrumentation was operated in the same mode between calibration and sample. The overblow line was also drawn with a minor flow (90 sccm) at its interior terminus in order to prevent the contents of the line from slowly diffusing or turbul ently burping into the sample.S

‐ 45 Instrument overview The mobile lab heading and position were determined using a Hemisphere V110 GPS Compass operated at 1 Hz. Wind speed and dir ection were measured several ways. Fixed portable rotary vane anemometers were deployed at the release site. On the mobile lab, the apparent wind was measured using a Vaisala WM 30 rotary vane anemometer and an AirMar LB150 sonic anemometer. The LB150 device also em ploys an internal GPS to correct for the motion of the vehicle to report a true wind. Atmospheric pressu re was logged using a calibrated 1000 Torr MKS pressure transducer and temp erature was measured. A Vacuubrand MD4 diaphragm pump was used to draw sample through the CO 2 Licor instrument and to other diagnostic equipment. It was also used to indu ce small draws on the lines used for periodic zero and calibration. A Varian Triscr oll 600 was used to draw 9 slpm through the tunable infrared differential absorption spectrometers in series.

The primary analytical composition measuremen ts in this work were performed using tunable infrared laser differen tial absorption spectroscopy (TIL DAS). The primary external tracer in this work was nitrous oxide (N 2 O) and was measured using absorption lines at 2199.737

cm -1 . The auxiliary external tracer in this work was acetylene (C 2 H 2 ) and was measured using an absorption line at 1342.349 cm -1 . Methane (CH 4 ) was measured using the minor ( 13 C) and major carbon isotope absorption lines at 1294.196 and 1294.379 cm -1 . In the same continuous wave quantum cascade laser modulation cycle as N 2 O, an absorption line of carbon monoxide (CO) was also included. A summary of the analytical instrumentation is provided in Table S4-1.

Table S4-1. Measurements deployed dur ing the tracer release campaign

Measurement Rate Instrument

Methane (CH 4 ) 1 s Quantum Cascade Laser Sys. (1294 cm -1 ) Carbon Monoxide (CO) 1 s Quantum Cascade Laser System (2230 cm -1 ) Acetylene/Ethyne (C 2 H 2 ) 1 s Quantum Cascade Laser System (1342 cm -1 ) Nitrous Oxide (N 2 O) 1 s Quantum Cascade Laser System (2200 cm -1 ) Carbon Dioxide (CO 2 ) 1 s Licor or QCL

S4.2.2 Tracer Release Stand Description The flow of tracer gas is regulated and monitored using an MKS 247 4-Channel Controller (SN 01000079) coupled with MK S 1179 A Mass Flow Controllers (SN’s 001347521, 001773651, 020003843). The MKS 1179 A Mass Flow Contro ller operates on the principle that by monitoring the temperature flux of a gas and usi ng a known specific heat constant for that gas one can monitor the mass flow rate. The MKS 247 un it acts as a processor for the MFCs; its data output is logged on to the release stand comput er. The mass flow contro llers are calibrated and checked throughout each campaign to ensure accuracy. Once the re lease gas has been regulated by the mass flow controller it passes through a se ries of emergency shut off valves then to release.S

‐ 46 The tracer release base unit was deployed w ith two Porta-Met Meteorological stations to collect information about the release environment. The Porta-Met is a relatively compact, tripod mounted unit that is able to measure wind sp eed, wind direction, temper ature, pressure, GPS location, solar intensity, and relativ e humidity. Units were placed at positions appropriate to the site scale wind transport. Wireless RS 232 radios fed data to the on-site tracer release stand. After periodic archiving of the data, the tracer release stand di stilled and bundled the results for a radio transmission to the Mobile Laboratory. The transmission was done using a pair of Freewave RS 232 wireless transmitters.

Two tracers were employed in this work. The primary use of the dual tracers in this work was to assess the accuracy of the fundamental assumption in the tracer flux ratio method, that the tracer compound and the species of interest for quantification (i n this work, methane) undergo equivalent atmospheric dispersion prior to downwind sampling. The observed downwind concentration ratio of the two tracers can be co mpared to the known ratio s of mass emission rates to provide a characterization of measurement uncertainty.

S4.2.3 Data analysis Typical data generated in tr acer flux measurements are s hown in Figure S4-1. An aerial image of a natural gas production site is shown; winds out of the southeast are shown as blue lines on the image. The tr acer release points for N 2 O and acetylene are shown. The N 2 O release point was located adjacent to an on-site compressor. The acety lene release point was located adjacent to a tank battery. The mobile van ma de measurements of methane, acetylene and N 2 O along a road north of the production s ites. The path of the van is s hown as a series of dots, with the size and color of the dots i ndicating the magnitude of the me thane concentration. Measured concentration distributions are shown for N 2 O, acetylene and methane.S

‐ 47 Figure S4-1. Summary of data collected during dow nwind sampling at a natural gas production site. Shown are a satellite image of the site, wind direction at multiple points in time (from the southeast, shown in blue as two lines, indicating variations in wind direction), downwind methane measurements along the measurement va n path (shown as dots), and concentration distributions of tracers and methane along the transect path (upper right).

The analysis of the concentration distributi ons is summarized in Figure S4-2 and S4-3. A first observation from the concentration di stributions is that the acetylene and N 2 O concentration profiles are different, based on locati ons of the tracer release sites. Also shown in Figure S4-2 is a hypothetical distribution of acetylene that would be an ticipated, if the releas es were co-located. The differences in the acetylene and N 2 O concentration distributions can, in principle, be used to estimate separately emissions from the compressor and tank battery. In this work, however, only total site measurements are reported and the dual tr acers were used to estimate plume capture (as described below).S

‐ 48 Figure S4-2. Acetylene, N 2 O and methane concentration prof iles (background corrected) along the path traversed by the measur ement van (horizontal axis is local measurement time). Also shown is a hypothetical distributi on of acetylene (dashed blue line) that would be anticipated, if the releases were co-located.

The total methane release rate for the site is based on the N 2 O tracer.

Methane emission rate = N 2 O tracer emission rate * (downw ind – upwind concentration of methane) / (downwind – upwind concentration of N 2 O tracer) (Eqn. S4-2)

Figure S4-3 shows multiple instances of the in stantaneous methane concentration and the N 2 O tracer concentration at the same time. The average ratio of the instantaneous concentrations (4.4:1, derived from the slope of the line) and the known N 2 O release rate gives an estimated methane release rate of 1.26 g CH 4 per second.S

‐ 49 Figure S4-3. Comparison of the instantaneous me thane concentration (measurement – background) associated with the N 2 O tracer shown in Figure S4-1, and the N 2 O tracer concentration (measurement – background) at the sa me time. The slope of the line shown in the Figure equals the ratio of the emission rate of methane to emission rate of tracer.

The degree of plume capture is assessed by compar ing the concentration ra tios of acetylene to
N 2 O, observed second by second, in the plume, to the known ratio of the emission rates of the two tracers. Figure S4-4 show s this comparison for a typical production site where the tracer releases were co-located. For this site, the concentration for the two tracers and methane were very highly correlated in sec ond by second observations in the plume. The average of the methane to N 2 O concentration ratios, observed second by second in the plume, indicated by the slope of the line in Figure S4- 4b, was consistent throughout the pl ume, and was used in Equation S4-2, along with the known N 2 O tracer emission rate, to calc ulate methane emissions. The average of the acetylene to N 2 O concentration ratios, observed second by second in the plume, indicated by the slope of the line in Figure S4-4 c, was compared to the known ratio of emission rates for the two tracers. This calculation tested the assumption of equivalent dispersion of the two plumes. The 0.8% error reported in Figure S4 -4c indicates the difference between the ratio of the observed tracer concentrations in the pl ume (determined from the slope of the line shown in Figure S4-4c) and the ratios of the tracer release rates for this site, divided by the ratio of the tracer releases.S

‐ 50 When the observed ratios of tracer concentratio ns in the plumes at all sites are compared to the known ratios of tracer releas es at all sites, the distributi on is normally distributed with a standard deviation of 15%. The ratio shows a pos itive bias of 4%. Overall, this leads to an empirical uncertainty estimate of 20% for the dual tracer measurements performed in this work. This uncertainty would be expected to be sens itive to the meteorolog ical conditions, topography and downwind access, and so is likely not ge neralizable beyond the work reported here.S

‐ 51 Figure S4-4 a.) Methane, acetylene and N 2 O plumes observed downwind of a production site; tracers were co-located; b.) the average ratio of methane to N 2 O in the plume, determined using second by second observations of methane and N 2 O is indicated by the slope of the line; this ratio was used in Equation S4-2, with the known release rate for N 2 O, to estimate methane emissions; c.) the average ratio of acetylene to N 2 O in the plume determined using second by second observations of acetylene and N 2 O in the plume is indicated by the slope of the line; the 0.8% error indicates the differen ce between the ratios of the obs erved concentrations in the plume and the ratios of the tra cer release rates for this site. 0.8% error a.)

b.) c.)S

‐ 52 S4.3 Results and Discussion The results from the downwind sampling are pr esented in two sections : (i) emissions fluxes from well completion activities, and (ii) emissi on fluxes from natural gas production sites.

Emission fluxes from well co mpletion flowback activities Measurements were made downwind of 6 we ll completion flowbacks. Five of the six flowbacks were of the type repor ted as Configuration 4 in Table S1-1 – flowbacks in which the entire flow was sent to a vent ed tank. There are several reas ons for a focus on these types of completions. First, these types of completions ha ve the greatest uncertainty in their emissions. Other types of completions, invol ving separators, have well comp letion reports that typically include gas volumes, oil volumes and water volum es released by the separators. Reasonably accurate engineering methods can be used to esti mate the emissions arising from these separator flows when they reach the tanks. In contrast, en gineering estimates of emissions associated with flow directly from a well head have a high de gree of uncertainty and the direct source measurements made in this work provide data th at cannot be routinely estimated. An additional reason for focusing on this category of completio ns is that the completion involves a single emission point. This reduces the uncertainty in the emission estimat es based on the tracer release method.

Comparisons of the direct source measurem ents and the emission estimates based on the dual tracer method, for the 5 flowbacks that utili zed Configuration 4, are provided in Table S4-2 and Table S4-3. Table S4-2 reports comparis ons for Rocky Mountain completions 3, 4 and 5, which occurred sequentially. Table S4-3 repor ts comparisons for Midcontinent completions 1 and 2, which occurred concurrently. Since th e downwind van is only able to sample when meteorological conditions set up a plume measurable downwind, the results are presented in time windows when the downwind measurements were ma de. In general, downwind measurements are reported for periods when the van was consiste ntly (but not necessarily continuously) in the plume. During these periods, th e ratio of methane to tracer c oncentration in the plume was plotted, and the average of the slope of was determined. The slope is multiplied by the known release rate for the tracer to yield an emission ra te for methane. No attempt was made to estimate transport times since typically the measurement interval was long compared to the transport times.

Tables S4-2 and S4-3 compare dual tracer emission estimates to direct source measurements in two ways. In one calcula tion method, non-zero dir ect source emission estimates were calculated by summing all emi ssions for the measurement period, then dividing by the time period during the van measurements when emissions were non-zero. In addition, Tables S4-2 and S4-3 report the average total direct source emissions over the measurement period divided by the total measurement time. The downwind measurement is expected to be between these two values, since plume capture was not complete for the sampling period. In addition, a low bias in the downwind measurements , when compared to direct source, non-zeroS

‐ 53 emissions might be expected, since plume spr eading downwind would cause the van to record shorter zero emission periods than the direct source measurements.

Table S4-2. Direct source methane emission measurem ents for Rocky Mountain Completions 3, 4 and 5 and methane emission estimates based on downwind measurements.

Completion Measurement van start and stop times, expressed as time from start of completion Tracer emission estimate (scf/m) Direct source emission
measurement (scf/m) Direct
source to

trace emission estimate

ratio (1.0=match) Start End Averaged

over Entire period Averaged

over nonzero emissions RM-3 33 hr 42 min 34 hr 35 min 9.8±1.5 1.4 12.6 0.14-1.3 RM-3 34 hr 44 min 45 hr 26 min* 19.7±3 4.6 24 0.23-1.2 RM-4 27 hr 18 min 29 hr 25 min 37.1±5.6 30.4 32.5 0.82-0.87 RM-4 30 hr 37 min 33 hr 59 min 7.4±1.1 10.2 20.0 1.3-2.7 RM-5 40 hr 18 min 44 hr 44 min 4.4±0.7 19.3 42.6 4.3-9.6 *time period extends a few minutes past the end of the completion

Table S4-3. Direct source methane emission measurements for combined Midcontinent Completions 1 and 2 (emissions occurred concurre ntly on the same site) and methane emission estimates based on downwind measurements. Completion Measurement van start and stop times, expressed as time from start of completion (both started at same time) Tracer emission estimate (scf/m) Direct source emission
measurement (scf/m) Direct
source to

trace emission estimate

ratio Start End Averaged

over Entire period Averaged

over nonzero emissions MC-1 +

MC-2 3 hr 58 min 7 hr 34 min 10.7±1.6 2.4 10.9 0.22-1.0

MC-1 +

MC-2 90 hr 51 min 93 hr 31 min 12.1±1.8 13.6 28.8 1.1-2.3

The sixth completion flowback for which downwind measurement were made (AP-3 in Table S1-2) was selected because of the presence of a flare. Flow from the well was routed to a separator; liquids from the separator went to a vented tank, where methane would flash. This flow was measured and is reported in Table S4-4 in the column labeled vented flowback tank emissions. Gas from the separator initially went to sales, then was vented for a period reported as 75 minutes in the completion re port; after the venti ng period ended, the gas was sent from theS

‐ 54 separator to a flare where the ga s was combusted. Flow rates to the flare were reported hourly in the completion report, so hourly emission estimate s were made for the flare, based on methane flow to the flare and an assumed combustion e fficiency of 98%. Each of the three flows (flowback tank vent, separator vent and flare emissions) are reported in Table S4-4. The temporal resolution of the direct source measuremen ts is set by the separator vent and flare flow information in the completion report, which is in hourly blocks. The 75 minute vent from the separator began 30 minutes into the 9-10AM block on the day of the flowback and ended at 10:45 in the 10-11AM block. Flarin g began at 10:45. Table S4-4 compares emissions estimated based on the dual tracer downwind measurement method to the sum of the direct source

measurements.

Table S4-4. Direct source methane emission measurements for Appalachian Completion Flowback 3 (emissions from multiple sources ) and methane emission estimates based on downwind measurements.

Time Direct emission measurements (scf) Dual tracer
measurement (scf per min) Direct/Dual
tracer Vented flowback tank Separator
vent Flare Total Direct
measurements (scf per min) 8:30- 9:00 717 0 0 24 128 0.19

9:00- 9:30 2800 0 0 92 290 0.32

9:30- 10:00 2800 15,600 0 612 421 1.45

10:00- 10:30 4400 10,200 0 558 390 1.07

10:30- 11:00 5700 7,400 150* 390 366 1.07

Total emitted 50,300 scf 47,900 scf 1.05

* Flow rates to the flare were reported hourly ; emission estimates were made for the flare emissions, based on methane flow to the flare and an assumed combustion efficiency of 98%

Agreement between direct source emission m easurements and emission estimates based on downwind tracer measurements is generally within a factor of 2. Becau se of the challenges associated with comparing intermittent direct source measurements with plume measurements taken up to a kilometer or more downwind, more precise comparisons are not justified using the methods employed in this work. Nevertheless, the comparison of direct source measurements of completions, with an independent downwind measurement, provides strong support for the conclusion that methane emissions from comple tion flowbacks are roughly 97% below the most recent national estimates and that emissions fr om completion flowbacks without methane control or recovery equipment, observed in this work, are well below the average potential emissions in current national inventories 4 . Even if emissions based on the direct source measurements wereS

‐ 55 doubled, projected national emissions from comp letion flowbacks would s till be 95% less than current estimates. 4

One exception to the general agreement, w ithin a factor of two, between the downwind measurements and the direct source measurements is Rocky Mountain Completion 5. For this completion, the downwind dual tracer measurements indicate a much lower emission rate than the direct source measurements, but this is li kely due to the temporal resolution of the composition measurements in th e direct source method. In th is completion, during this time period, methane concentrations were dropping rapi dly. The direct source emission estimate is based on gas composition measurements at th e beginning and end of the sampling period and the direct source emissions are based on a linear extrapolation of the concentration. The van records high emission rates initially, then a ra pid drop to lower emissions for most of the measurement period. If the direct source measur ements are based on the gas composition at the end of the period, rather than a linear interpolati on, the ratio of the direct source measurements to the tracer measurements would be simila r to other ratios in Table S4-2.

It should also be noted that the downw ind dual tracer measurements for completion flowback AP-3 provide some evidence of flar e combustion efficiencies . At approximately 10:45, methane that had been vented from the sepa rator was routed to the flare. The downwind emission estimate dropped in less than a few minut es from 325 scf/m to 9.1 scf/m. If it is assumed that the emissions from the flowback ta nk vent that had mixed downwind with the flare emissions were typical of the flowback tank emissions during the 30 minute period from 10:30- 11:00 (5700 scf/30 minutes) the total emissions m easured downwind are less than the emissions directly measured from the flowback tank vent , suggesting the flare em issions are near zero (100% combustion efficiency). Even if it is a ssumed that the downwind measurements are only detecting methane emissions from the flare, com bustion efficiencies would be estimated as at least 97.2% ((1-(9.1/325))*100). Thes e are preliminary observations, and given the uncertainties in the direct source and dual tracer measurem ents, do not support the use of a new emission factor for flares. Neverthele ss, the data are supportive of the assumption of 98% combustion efficiency used throughout this work.S

‐ 56 Emission fluxes from natur al gas production sites Measurements were made downwind of a total of 20 production sites. Results are summarized in Table S4-5. Table S4-5 lists the number of wells per site, the emissions from various pieces of equipment on each site, the total emissions from the site based on direct source measurements and emission estimation methods, a nd the total site emissions based on downwind

measurements.

Note that emissions from the exhaust of compressors and emissions from tanks are estimated using standard emission estimation methods, rather than measurements. The emissions from compressors are small, relative to total emissions, however, the emissions from tanks are relatively large for many sites. These tank emissions are due to methane dissolved in hydrocarbon liquid and water at separator conditions, which subsequently flashes when the liquids are sent to atmo spheric pressure tanks. The amount of methane dissolved in the liquids is calculated based on a solubility estimate, which depends on the composition of the gas, the API gravity of the oil, and the separator pressure. In some regions (e.g., the Rocky Mountains), gases vented from hydrocarbon liquid (cond ensate) tanks are not vented directly to the atmosphere, but instead are sent to a combustor. The com bustor was assumed to have a 98% combustion efficiency.S

‐ 57 Table S4-5. Comparison of direct source and downwind emission estimates for production sites.

Site (# of wells on

site) Emissions from on site measurements or estimation (scf/m) Tracer emission estimate (scf/m) Direct

source to tracer emission estimate Pneumatic

Controls and
pumps a Fugitives a Compressors b Tanks b Total

MC-1 (2) 1.41 0.23 2.23E-04 0.25 1.89 2.32 0.815 MC-2 (1) 0.97 0.01 5.91E-05 0.01 0.99 2.00 0.495 MC-3 (3) 1.09 0.29 5.25E-04 0.25 1.63 2.95 0.552 MC-4 (2) 0.61 0.33 7.60E-06 1.38 2.31 3.36 0.687 MC-5 (2) 1.41 0.34 2.31E-04 0.11 1.85 4.16 0.445 RM-1 (8) 0.19 0.02 0 0.01 0.22 0.584 0.368 RM-2 (8) 0.05 0.10 0 4.28 4.43 1.70 2.60 RM-3 (1) 0.05 0.09 0 0.00 0.13 0.442 0.303 RM-4 (7) 0.11 0.00 0 0.00 0.11 0.839 0.137 RM-5 (2) 0.06 0.03 0 0.01 0.09 0.240 0.392 RM-6 (6) 0.42 0.31 0 0.01 0.74 0.421 1.75 RM-7 (1) 0.19 0.07 0 0.02 0.27 0.368 0.736 RM-8 (1) 0.04 0.23 0 0.02 0.29 1.08 0.266 RM-9 (4) 0.00 0.02 0 0.36 0.38 0.864 0.436 RM-10 (6) 0.03 0.01 0 2.82 2.86 0.080 35.7

AP-1 (6) 0.13 0.01 0 0.29 0.43 * * AP-2 (6) 0.61 0.45 0 0.22 1.28 0.270 4.74 AP-3 (6) 0.14 2.82 0 1.80 4.75 4.12 1.15 AP-4 (5) 0.03 0.57 0 0.76 1.36 0.709 1.92 AP-5 (6) 0.02 0.27 0 0.10 0.39 0.288 1.37

a Based on direct source measurements or av erages of direct source measurements

b Based on emission estimation methods *No plume captured downwind

If site RM-10 is excluded, the average of the ratio of direct source measurements to tracer measurements is 1.1, suggesting reasonable ag reement between the dual tracer emission estimates and the direct source measurements and emission estimates (for those sources not measured). It is important to note, however, th at for some sites, the total on site measurements are dominated by tanks and these are estimated, rath er than calculated em issions. Most of the Rocky Mountain sites had combustors on the vent s to the hydrocarbon tanks , resulting in much lower tanks emissions, but the extent of agreem ent between on-site emission measurements and estimates and emissions estimated based on downwind measurements is still dependent on calculations rather than measurements, in this case the control efficiency assumed for the combustor. For example, for RM-10, the site ow ner reports that tank ve nts are not sent to a combustor. If a combustor were in place, or if the separator did not send liquid to the tank whileS

‐ 58 the measurements were being made, the ratio of on-site to tracer based measurements would be similar to the other Rocky Mountain sites.

Another factor that is likely small, but diffi cult to account for, is th at the on-site direct source measurements altered the methane emitted from the sites, since the HiFlow analyzer combusted methane as it was making measurements. This bias is believed to be small because the Hi-Flow instrument only analyzed one source at a time and because the instrument was not operated continuously for the enti re downwind sampling period.

Overall, the downwind measurements do not su ggest any reason to expect that there are large systemic biases or errors in the direct source measurements.S

‐ 59 S5 Nationally Scaled Emissions Estimates

S5.1 Methods
The method used to scale up an emission measurement from a limited set of samples to a larger regional or national total is to multiply the average result of the emission measurement times the number of times that emission occurs in the larger scale. Often the emission measurement is thought of as an “emission factor” or EF, and is a pplied to a particular source in some discreet increment (such as an emission per event, an emission per device, and emission per component, or emission per location). The te rm used to scale up the emissions is called the activity factor (AF), and is the c ount or population of the source or event at the scale of interest, such as regionally or nationally. This can be shown as:

EF i * AF i = ER i (Equation S5-1)

Where:

EF i = Emission Factor for region i

AF i = Activity Factor for region i

ER I = resulting Emission Rate total for region i
This can be done at any scale. It may be done regionally, if that is the primary differentiator, then the regions can be summed to produce a national total. Alternately, it may be done nationally in a single calculation.S

‐ 60 S5.2 Activity data
Activity factors used in this work are dr awn from EPA’s 2011 nati onal emission inventory 4
and are shown in Table S5-1.

Table S5-1. National Activity Factors from EPA Inventory

Year 2011 AF’s National Count for 2011 Count of new gas well completion events 8077 with hydraulic fracturing Count of gas well unloading events performed Not reported as events, EPA does report 35,828 non-plunger wells that unload Count of applicable gas well workovers 11,663 workovers without hydraulic fracturing 13,445 total workovers Count of gas powered pneumatic controllers 447,379 Count of injection pumps 35,013 Count of gas wells (not including associated gas wells) 446,745 a

a Estimate from U.S. Department of Energy, Energy Information Administration is 513,000 on-shore gas wells 23
No uncertainty bounds are reported for activit y factors in the EPA national inventory, and therefore no uncertainty bounds are reported in Tabl e S5-1. It is beyond the scope of this work to perform a detailed analysis of the uncertainty in the activity factor counts reported in Table S5-1, however, a variety of cal culation scenarios can provide a rough characterization of the uncertainties associated with applying thes e counts to estimati ng national emissions. Specifically, for well completions and equipm ent leaks, regional activity counts can be multiplied by regionally averaged emission factor s or national activity counts can be multiplied by nationally averaged emission factors. For pne umatic devices, emissions averaged by device type (e.g., low bleed and intermittent pneumatic c ontrollers) can be multiplied by activity counts by device type, or total equipment counts can be multiplied emission factors averaged over all device types. Regional or nationa l averaging can also be perfor med. These calculation scenarios are reported in Section S5.3.S

‐ 61 S5.3 Emission Factors and Na tional Emission Estimates

Table S5-2 provides central estimates of nati onal emission rates, by source category, based on the activity factors repor ted in Table S5-1.

Table S5-2. Central estimates of National Em ission Rates by Source Categories Central estimates of National Emission Rates by Source Categories

Source Category Emission Factor (based on

measurements in this work) EF Units Activity Factor AF Units AF Source National Emissions Billion scf/yr

CH 4 (Gg) New Gas Well Completion Flowbacks 115,000 a scf CH 4 / event 8077 events/yr EPA 2011 Inventory 0.93 bcf/yr (18 Gg) Gas Well LiquidsUnloadings (nonplunger) 48,000- 300,000 b scf CH 4 / well/yr 35,828 Wells that unload EPA 2011 Inventory 1.3-10.7 bcf/yr (25- 205 Gg) Pneumatic Devices 67,400 c scfy CH 4 /device 447,379 devices EPA 2011 Inventory 30.2 bcf/yr d (580 Gg)
Chemical Injection Pumps 101,000 scfy CH 4 /device 35,013 devices EPA 2011 Inventory 3.5 bcf/yr (68 Gg)

Equipment Leaks 33,900 scfy CH 4 /well 446,745 gas wells EPA 2011 Inventory 15.1 e bcf/yr (291 Gg)

a Regional averages for the completion flowbacks were calculated (252,000 Appalachia; 130,000 Gulf Coast; 47,000 Midcontinent, 24,000 Rocky Mountain) and multiplied by the fraction of completion events per region (U.S. EPA 4 , 0.19 Appalachia; 0.36 Gulf Coast; 0.20 Midcontinent, 0.17 Rocky Mountain; 0.08 West Coast and Southwest) to arrive at a regionally weighted emission; for West Coast and Southwest regions, the national average emission factor (90,000) was used.
b An emission factor based on the limited measurements reported in this work is 300,000 scf per well per year; an emission factor based on the emissions reported by API/ANGA 12 and multiplied by a ratio of measured to estimated emissions found in this work is 48,000 scf per well per year

c U.S. EPA 4 reports 447,379 pneumatic devices but does not report an activity factor by device type; the emission factor used here is based on an average value of the samples taken in this work.
d Using regional emission factors of 0.126 (Appalachia), 0.268 (Gulf Coast), 0.157 (Midcontinent) and 0.015 (Rocky Mountain) scf methane/min/device, multiplied by the number of devices per region (74,136 Appalachia; 53,049 Gulf Coast; 140,041 Midcontinent; 122,878 Rocky Mountain; 57,275 West Coast and Southwest) results in a regionally weighted emission factor of 67,400 scf methane/device/yr and a national estimate of 30.2 billion scf/yr; for West Coast and Southwest regions, the national average emission factor (92,000) was used.

e Regional averages for the equipment leaks per well were calculated (0.098 Appalachia; 0.058 Gulf Coast; 0.046 Midcontinent, 0.035 Rocky Mountain) and multiplied by the fraction of wells per region (U.S. EPA 4 , 0.34 Appalachia; 0.17 Gulf Coast; 0.20 Midcontinent, 0.19 Rocky Mountain; 0. 10 West Coast and Southwest) to arrive at a regionally weighted emission; for West Coast and Southwest regions, the national average emission factor was used.S

‐ 62 Alternative scenarios for esti mating national emissions were considered for each source
category.
Completion flowbacks Estimates of national emissions for completion flowbacks can be based on either regional average activity counts , as reported in Table S5-2, or on national activity counts and a national average emission factor. The national averaging leads to an
emission estimate that is 23% lower than th e regional estimates (0.73 bcf; 90,000 scf/event, 8077 events). Regionally averaged emission esti mates were used as the central estimate in
this work because there were differences in the emission factor s observed by region and because the frequency of U.S. well completion ac tivity (highest number of completions in the Gulf Coast) did not match the distribution well completions sampled in establishing emission factors (highest number of events sampled in the Rocky Mountains).

Pneumatic devices Estimates of national emissions for pneumatic controllers can be based on either regional average activity counts, as re ported in Table S5-2, or on national activity counts and a national average emission factor. The national averaging leads to an emission estimate that is 36% higher than the regi onal estimates (41.1 bcf; 92,000 scf/device, 447,379 devices). Regionally averaged emission estimate s were used as the central estimate in this
work because there were differences in the emission factors observed by region. Pneumatic
controllers could also be a ggregated by device type, with national emissions estimated by multiplying the numbers of devices by the emissi on factor per device. This approach was not used in this work because the EPA national inventory 4 does not report devi ce counts by type, and because when device counts by type are re ported, some high bleed devices are typically part of the count; no high bleed devices were reported by the companies that provided controller type information in this work.

Pneumatic pumps Estimates of national emissions for pneumatic pumps can be based on either regional average activity counts, or on national activity counts and a national average emission factor, as reported in Table S5-2. Nationally averaged emission estimated were used as the central estimate in this work, even though there were differences in the emission factors observed by region, because of the limited number of regions in which pneumatic pumps were sampled in this work. An estimate of the uncertainty introduced by using a national averaging will be assumed to be comparable to the difference between regional and national averaging for pneumatic controllers (36%).
Equipment leaks Estimates of national emissions for equipment leaks can be based on either regional average activity counts, as reported in Table S5-2, or on national activity counts and a national average emission factor. The national averaging leads to an emission estimate thatS

‐ 63 is identical (to two si gnificant figures) to the regional estimates (15.1 bcf; 33,900 scf/well, 446,745 wells).
Measurements made on liquids unloading and workove rs, collected as part of this work, were not used to develop national emission estimates.

Workovers For workovers, four events, all done w ithout hydraulic fracturing, were sampled. Since the data set was very small and since workovers without hydraulic fracturing represent
less than 0.1% of total emissions in the EPA na tional inventory, these data were not used to estimate emissions for workovers (without hydr aulic fracturing) at a national scale. Workovers with hydraulic fracturing are a more significant source of estimated emissions, accounting for approximately 10% of emi ssions in the EPA national inventory. 4 The
emissions associated with flowback from wo rkovers with hydraulic fracturing may be expected to have emissions comparable to completion flowbacks, and in the EPA national inventory, completion flowbacks and workovers with hydraulic fracturing are sometimes grouped together. 4 Therefore, an emission factor fo r workovers with hydraulic fracturing comparable to the emission factor for comple tion flowbacks may be appropriate. If the emission factor for workovers with hydraulic fr acturing were assumed to be the same as the emissions factor for completion flowbacks that is based on the measurements presented in this work, total workover emissions would be redu ced by 97%, compared to the current estimate in the national emission inventory. This assumpti on is not made in this work since no direct
measurements of workovers with hydraulic fracturing were made.
Liquid unloadings Only well unloadings without plunger lifts were measured in this work. If the per well annual emissions from unloadings without plunger lifts, determined in this work (300,000 scf/well), are multiplied by the national counts of wells with unloadings without plunger lift, the nationa l emission estimate is in reason able agreement with the EPA inventory 4 and the API/ANGA estimate. 12 In contrast, another estimate of unloading emissions, based on the per event emissions obser ved in this work and a count of unloading events from the API/ANGA survey, 12 would lead to a national estimate 5 times the estimate based on unloading emissions per well. A lowe r estimate of unloading emissions could be suggested based on national event counts, emi ssion estimates, and the finding that emission
estimation methods over-estimate observations made in this work by a factor of 5. All of these methods, however, assume a single scalar value represents a wide range of unloadings; the data presented in this work and in the API/ANGA survey suggest that refined emission estimation methods, taking into account well and unloading characteristics, will be required. Additional measurements of unloading emissions are needed, both to resolve the differencesS

‐ 64 between estimates and measurem ents, and to better characteri ze the population of wells with unloading emissions.

S5.4 Central estimates and overall assessment of uncertainties in national emission
estimates
Uncertainties in national emission estimates calculated in this section are a combination
of the uncertainties associated with emission f actors, activity factors and the methods used to combine activity and emission factors. For each source category for which national emissions were estimated, combined uncertainty ranges were estimated.
Well completions: The 95% confidence bound on national av erage emission factor measurement was 35,000-173,000 scf/event (±66% around the midpoint). Assuming that the uncertainty due to activity data can be roughly characterized as the range of values derived from national and regional estimates (±12% around the midpoint) and that the emission factor measurements are independent of the activity data , leads to a net uncertainty of ±67% around the midpoint. The overall range for the estimate is 0.28-1.4 bcf with a regionally weighted central estimate of 0.93
bcf.

Pneumatic controllers The 95% confidence bound on nati onal average emission factor
measurement was ±19% around the midpoint. Assuming that th e uncertainty due to activity data can be roughly characterized as the range of values deri ved from national and regional estimates (±14% around the midpoint) and that the emission factor measurements are independent of the activity data , leads to a net uncertainty of ±23% around the midpoint. The overall range for the estimate is 27-43 bcf with a regionally weighted central estimate of 30.2
bcf.

Pneumatic pumps The 95% confidence bound on national average emission factor measurement was ±44% around the midpoint. Assuming that the uncertainty due to activity data can be roughly characterized as the same as for pneum atic controllers (±14% around the midpoint) and
that the emission factor measurements are inde pendent of the activity data, leads to a net uncertainty of ±46% around the midpoint. The over all range for the estima te is 1.8-5.2 bcf with a nationally weighted cent ral estimate of 3.5 bcf.
Equipment leaks The 95% confidence bound on national average emission factor measurement was ±36% around the midpoint. Assuming that the uncertainty due to activity data can be roughly characterized as the rang e of values derived from national and regional estimates (±1% around the midpoint) and that the em ission factor measurements ar e independent of the activityS

‐ 65 data, leads to a net uncertainty of ±36% around the midpoint. The overall range for the estimate is 9.7-20.7 bcf with a regionally weig hted central estimate of 15.1bcf.

S5.5 Comparisons with National Emission Inventory

The national emission estimates, based on the measur ements made in this work, can be compared to emissions reported in the EP A’s national emission inventory. 4 In assembling the national emission inventory, EPA first estimates potential emissions for source categories, then reduces the potential emissions by estimated voluntary reduc tions and reductions re quired by regulations. All regulatory reductions and some voluntary reductions are a ssigned to specific sources, however, some voluntary reductions are aggregated by source category. For example, the EPA estimates a total of 36 billion scf (691 Gg) of emission reductions for well completion flowbacks and workovers with hydraulic fracturing, combin ed. In cases such as this, allocation of combined reductions was assumed to be proportiona l to the potential emissions. Specifically, since the potential emissions for completion flow backs and workovers with hydraulic fracturing were 63.6 and 13.8 billion scf, respectively (1221 and 266 Gg), the reductions were 46% of the combined potential emissions (77.4 billion sc f). This percentage reduction was applied uniformly for all of the aggreg ated source categories. In s ituations where a source had both regulatory and voluntary reducti ons (e.g., dehydrator vents and condensate tanks), potential emissions were first reduced by reductions requi red by regulations, then the voluntary reductions were apportioned based on the remaining emissions. Table S5-3 reports potential emissions and the reductions applied for each source category. Th is Table uses units of Gg methane, the units in which the national inventory is reported, to facilitate comparison with the national inventory.S

‐ 66 Table S5-3 National emission inventory emission estimates by source category (potential emissions, reductions and net emissions in Gg me thane per year); source categories labeled in gray had aggregated voluntary em ission reductions (see text)

EPA GHG Inventory Activity Potential Emissions (Gg) a Emission Reductions (Gg) a Net Emissions (Gg) Completions with Hydraulic Fracturing 1221 b 567 b 654 Refractures (Workovers with hydraulic fracturing) 266 b 124 b 143 Pneumatic Device Vents 1,134 779 355 Chemical Injection Pumps 64 30 c 34 Equipment leaks: Gas Wells without HF 24 11 c

172 d

Equipment leaks: Gas Wells with HF 28 13 c Equipment leaks: Separators 107 50 c Equipment leaks: Meters/Piping 102 48 c Equipment leaks: Heaters 33 15 c Equipment leaks: Dehydrators 31 15 c Workovers without HF 0.6 0.3 c 0.3 Liquids Unloading (without plunger lifts) 149 0 149

Liquids Unloading (with plunger lifts) 108 0 108 Kimray Pumps 365 180

930 e Condensate Tanks without Controls 261 167 c

Condensate Tanks with Controls 52 0 Gas Engines 276 49 Dehydrators Vents 114 73 c Small Reciprocating Compressors 68 35 Large Reciprocating Compressors 15

Large Reciprocating Stations 1 Pipeline Leaks 170 80 c Completions without Hydraulic Fracturing 0 0 Well Drilling 0.8 0.4 c Vessel Blowdowns 0.7 0.3 c Pipeline Blowdowns 3 1 c Compressor Blowdowns 3 1 c Compressor Starts 6 3 c Pressure Relief Valves 0.7 0.3 c Mishaps 2 1 c Emissions from Coalbed Methane and Offshore Production Powder River Coal Bed Methane Produced Water 46 21 c Black Warrior Coal Bed Methane Produced Water 13 6 c Offshore Platforms 266 125 c Deepwater Platforms 23 11 c TOTAL 4,949 2,405 2,545

a Potential emissions data are from U.S. GHG Inventory 13 Annex 3, Table A-134. Emi ssion reductions data are from Tables A132 and A-133. 4

b EPA reports aggregated emission reductions for completions and workovers with hy draulic fracturing. This work divides these emission reductions between comple tions and workovers proportional to their potenti al emissions.

c EPA reports 551 Gg of aggregated emission reductions for the 23 activities shaded in the table. This work divides these emission reductions among the activities pr oportional to their potential emissions.
d Table 2 in the main text reports 172-211 Gg; the 211 Gg includes an additional 39 Gg due to small compressors (68 Gg of potential emissions minus 29 Gg of reductions assigned to smal l compressors out of 35 Gg of reductions assigned to all
compressors

e Table 2 in the main text reports 891-930 Gg; the 891 Gg does not include 39 Gg due to small comp ressors (68 Gg of potential emissions minus 29 Gg of reductions assi gned to small compressors out of 35 Gg of reductions assigned to all compressorsS

‐ 67 S6 Site Selection and Representativeness

Methane emissions were measured directly at 190 natural ga s production sites in the Gulf Coast, Midcontinent, Rocky Mountain and A ppalachian production regions of the United
States. The sites included 150 production sites associated with 489 wells (146 sites had wells directly on the site that were examined in this work; 4 sites were fed by 11 off-site wells, the equipment on these 4 sites was examined but not th e off-site wells; see p. S-32). In addition to the 150 production sites, 27 well completion flowbacks, 9 well unloadings, and 4 well workovers were sampled; the sites were operated by 9 different companies. The types of sources that were targeted for measurement account for approximately two-thirds of methan e emissions from all onshore and offshore natural gas production, as estimated in the 2011 national greenhouse gas emission inventory. 4 A summary of the scope of the study, along with a rationale for the
inclusion or exclusion of sources for direct measurement effort s, is provided in Table S6-1. Sampling was conducted at sites throughout the United States (see Figure S6-1). Table S6-2 lists the number of sampling sites in each region. Of the nine companies that provided sites for sampling, at least three companies pr ovided sites in each of the regions.
While the data presented in this report repr esents one of the most extensive datasets
available on methane emissions from current natu ral gas production activities, the sites sampled still represent a small fraction of the total number of sites nationwide. Representative sampling was believed to be achieved by:

 Selecting a large number of participant companies

 Selecting a range of geographic areas to sample

 Setting minimum number of sa mpling targets in each areaS

‐ 68 Table S6-1. Sources of CH 4 Emissions from Natural Gas Well Sites *, †, § (measurements were made for sources shaded light gray ; dark gray shading indicat es limited measurements)

* Study scope is limited to CH 4 emissions from well sites and any off-site equipment up to the point of comingling of multiple well streams (in which case the centralized separation facility is included). Emissions from gas processing plants, transmission pipelines, gas storage, and local distribution systems are beyond the scope of the study. †Other sources excluded from direct measurements include all combustion so urces and other miscellaneous sources: flaring, compressor engine exhaust, drill rig engi nes, trucks, well abandonment, upsets and others. Upwind/Downwind measurements inform an assessment of total emissions from excluded sources.
§ Covered sources account for 85 bcf of 133 bcf CH 4 (65%) from the natural gas production stage (onshore and offshore). 4 Activity or Source Included in Current Work? Rationale for Inclusion/ExclusionPre-production Construction of Well site N No emissions from the natural gas formation occur during this process. Surface construction equipment combus tion emissions were not part of the measurement target.

Well Drilling N While emissions from the gas formation are possible during drilling fluid circulation, they are considered to be small and not included (except for combustion) by the EPA in the GHG Reporting Program

Hydraulic Fracturing N Liquids are going into the formation during this process, and at extremely high pressures. No ga s releases are expected. Surface trucking and pumping equipment combustion emissions were not part of the measurement target. Well Completion (Flowback) Y 34 bcf in the 2011 EPA national emission inventory of methane emissions from natural gas production Well Testing N Considered to be a minor source, and rarely involving venting.Routine Production Pneumatic Devices Y 18.5 bcf in the 2011 EPA national emission inventory of methane emissions from natural gas production
Pneumatic Pumps Y 1.8 bcf in the 2011 EPA national emission inventory of methane emissions from natural gas production

Condensate Tanks Partial Emissions from these tanks, while a potentially large source, are considered well defined and known, with working models and equations of state. Therefore these were no t a primary study target, but were measured in some opportunistic cases. Produced Water Tanks Partial

Dehydrator Vents N These complex sources were considered relatively well defined and modeled. Surface Equipment (Leaks) Y ~ 10 bcf in the 2011 EPA national emission inventory of methane emissions from for equipment sampled in this work Surface Equipment (Leaks from Compressors) Partial The scope of the study excluded central facilities (mimicking the GHG Reporting Program), compressor fac ilities were not targeted. Some on well sites were measured. Amine Units (Gas sweetening) N These complex sources were considered a small national contributor and also well defined and modeled.Maintenance Well liquids unloading Y 13.4 bcf in the 2011 EPA national emission inventory of methane emissions from natural gas production

Well workovers Y 7.5 bcf in the 2011 EPA national emission inventory of methane emissions from natural gas production

Blowdowns N This intermittent source of equipment depressuring for maintenance is manually calculated and not a measurable event. It was not a target of this study.S

‐ 69 Figure S6-1. Methane emissions were measured at well-sites in the Appalachian, Midcontinent, Gulf Coast, and Rocky Mountains Regions. Regions shad ed in blue indicate American Association of Petroleum Geologists (AAPG) 24 basins where sampling was done.

Table S6-2. Distribution of sampling locations, by region

Region Production Sites Unloadings Workovers Completion
Flowbacks Gulf Coast 58 (157 wells) 5 0 7 Midcontinent 26 (85 wells) 0 1 5 Rocky Mountain 19 (79 wells) 3 3 10 Appalachian 47 (168 wells) 1 0 5 Total 150 (489 wells) 9 4 27 

### Rocky Mountain

Midcontinent

Gulf Coast AppalachianS

‐ 70 The nine companies that participated in this study included mid-size and large companies. While there are thousands of o il and gas companies in the U.S., and small companies were not part of the participants, th e participants do represent a sizable sample of overall U.S. production and well count, as shown in Tables S6-3 and S6-4. Participants account for almost 12% of all U.S. gas wells, account for 16% of gross gas production, and almost half of the new well completions. Representativeness cannot be completely assured, however, since companies volunteered, and were not randomly selected.

Table S6-3. Participant Portion of National Gas Wells

Region (from Fig 2-3) Participant Company Total Gas Wells, 2011 DOE EIA Gas Wells, Onshore, L48, 2011 Percentage of Gas Wells operated by our

participants Appalachian 8,739 202,788 4.30% Midcontinent 18,117 125,295 14.5% Gulf Coast 9,941 81,247 12.2% Rocky Mountain 23,805 103,643 23.0% Total 60,602 513,000 11.8%

Table S6-4. Participant Portion of Na tional Gross Gas Production

Region (from Fig 2-3) Participant Co. Total Gas Production (million scf), 2011 DOE EIA Gas Production, Gross (million scf) 2011* Percentage of Production operated by our participants Appalachian 282,798 2,357,792 12.0% Midcontinent 893,010 7,125,555 12.5% Gulf Coast 1,271,450 7,498,590 17.0% Rocky Mountain 1,379,408 6,262,666 22.0% Total 3,826,667 23,264,162 (15,577,188) (gas well prod + shale gas prod) 16.4%

*Excludes U.S. offshore and AlaskaS

‐ 71 Regional sampling was done to account for differe nces in practices that may occur due to
field or state differences , or practices that may vary even w ithin a company across the U.S. The Study Team sampled in four geographical region s (Appalachian, Gulf Coast, Midcontinent and Rocky Mountain), and with multiple companies in each region. All nine of the sponsoring companies provided sampling sites during the Study. The details of the distribution of samples in the data set, for production sites, by compa ny, region and equipment type is provided in Table
S6-5.

Table S6-5 – Distribution of samples in study dataset: Counts, per company, of Chemical Injection Pumps, Pneumatic Devices (Controller s), fugitive leaks, number of geographically distinct sites, and number of wells, and producti on sites and wells. Each of the 9 companies providing sites and is assigned a randomly chosen letter identifier. Data are reported for the aggregated study data set and by region.
Host Company Number count D F H L N Q R S W total Chemical Injection Pump 0 1 0 1 1 0 17 39 3 62 Pneumatic Devices 12 33 32 15 33 32 60 26 62 305 Other Fugitives 3 27 16 32 9 45 88 19 39 278 Number of distinct sites 6 11 10 14 16 13 45 12 23 150 Number of wells 10 27 33 88 54 49 106 49 73 489

Appalachian Region Host Company Number count D F H L N Q R S W total Chemical Injection Pump Pneumatic Devices 12 32 28 32 29 133 Other Fugitives 3 16 4 45 32 100 Number of distinct sites 6 10 10 13 8 47 Number of wells 10 33 36 49 40 168

Rocky Mountain Host Company Number count D F H L N Q R S W total Chemical Injection Pump Pneumatic Devices 4 11 15 Other Fugitives 10 49 59 Number of distinct sites 4 15 19 Number of wells 25 54 79S

‐ 72 Gulf Coast Host Company Number count D F H L N Q R S W total Chemical Injection Pump 1 17 3 21 Pneumatic Devices 13 11 49 33 106 Other Fugitives 1 22 39 7 69 Number of distinct sites 3 10 30 15 58 Number of wells 9 63 52 33 157

Midcontinent Host Company Number count D F H L N Q R S W total Chemical Injection Pump 1 1 39 41 Pneumatic Devices 20 5 26 51 Other Fugitives 26 5 19 50 Number of distinct sites 8 6 12 26 Number of wells 18 18 49 85

For completions, seven of the nine companies pr ovided sampling sites. For the remaining two companies, attempts were made to schedule completion sampling, however, it was not possible to identify completions that the study team could sample, due to scheduling of the completions and the study team’s other sampling commitments. In each of the Appalachian, Gulf Coast and Rocky Mountain regions, three different comp anies provided completion events. These companies are identified as AP-A to AP-C, GC-A to GC-C and RM-A to RM-C in this report. In the Midcontinent region, two different companie s provided completion events. These companies are identified as MC-A and MC-B in this report. Note that company A in one region is not necessarily the same as company A in another region.
For liquid unloadings, 5 events were sampled in the Gulf Coast, 3 in the Rocky Mountains and 1 in the Appalachian region. These events were provided by 4 diffe rent companies.
The selection of specific sites wa s randomized to the extent possi ble. For completions, the study team provided time windows when the measurement team would be available in certain regions and host companies identified completions that would begin as soon as possible after the study team arrived. In most cases this scheduling completely determined which sites would be sampled. To illustrate this, consider that th e total number of well completions, nationwide in 2011, for all the participating companies combin ed, averaged roughly 10 per day. That meant that in any given production regi on, on any particular day, just one or two new completions, for all of the companies combined, was likely to be starting.
The time commitment associated with sampling completions was extensive. Completions lasted up to two weeks; sampling equipment set up an d tear down by the study team required a dayS

‐ 73 before and a day after the completion. Unlo ading, workover and production site sampling was much shorter in duration, typically a few hours to a half day. Consequently, sites selected for unloading, workover and production site sampli ng were selected based on proximity to completion sampling. Typically, a list of candida te sites was provided by the host company. If the list was too long to be entirely sampled in the allotted time, the study team selected sites based on an ability to sample as many sites as possible in the time available.
One exception to this pattern was for Gulf Coas t sites, where the study team, based in Austin, Texas, could make day trips to production site s. For these sites, the study team randomly selected from hundreds of potential sites provide d by host companies. A second exception was for unloadings. These events were difficult to schedule since they were often done, by site operators, immediately as needed. This often did not allow the study team to travel to the site and set up equipment prior to the unloading occurri ng. Therefore, special efforts were made to identify and sample unloadings that could be scheduled. Unloadings numbered 1a-1c and 2a-2c
were selected in this manner.
The downwind sampling described in S4 was performe d only at a subset of sites. This subset was selected based on the expecta tion of stable, moderate winds at the sites and the availability
of a dense road network that would allow th e van access to downwind sampling points. Based on these criteria, the downwind sampling team was tasked to mirror the sa mpling efforts of the
direct source measurement team to the exte nt possible given road networks downwind of sampling sites and the prevailing meteorology on the day sampling was done. Sampling was done in the Appalachian, Midcontinent and the Rocky Mountain regions.
A final potential bias is cha nges to the U.S. gas production system during the measurement effort. The system of wells and oil and gas ope rations continued to grow during the test period, but the technology was considered fairly constant during the test period. The study participants were aware that the EPA’s new Volatile Orga nic Compound (VOC) controls, in the forms of new regulations for National Emission Standard s for Hazardous Air Pollutants (NESHAP) and
New Source Performance Standard s (NSPS Part OOOO) that went into effect in 2012 and would potentially affect new sources in 2012. The regul ations require controls on certain VOC sources
that also result in control of methane. Since most of these controls will affect tank vents and dehydrators, which were not sampled by this stud y, the effect was considered minimal. The regulations do require minimization of high-bleed rate pneumatics on new facilities, and this may have had an effect on the study pneumatic measurements.S

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