S‐1

Measurements of Methane Emissions at Natural Gas Production Sites 

in the United States 

Supporting Information 

David T. Allen1*, Vincent M. Torres1, James Thomas1, David Sullivan1, Matthew Harrison2, Al 

Hendler2, Scott C. Herndon3, Charles E. Kolb3, Matthew Fraser4, A. Daniel Hill5, Brian K. 

Lamb6, Jennifer Miskimins7, Robert F. Sawyer8, and John H. Seinfeld9 

1

Center for Energy and Environmental 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 Manning Road, Billerica, MA 01821 

4

School of Sustainable Engineering and the Built 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 Engineering, Washington State University, PO 

Box 642910, Washington State University, Pullman WA 99164 

7

Department of Petroleum Engineering, Colorado School of Mines, 1600 Arapahoe 

Street, Golden, CO 80401 

8

Department of Mechanical Engineering, Mail Code 1740, University of California, 

Berkeley, CA 94720-1740 

9

Department of Chemical Engineering, California 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, methane 

   
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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: Gas Well Liquids Unloading..............page S-34

S4 Downwind Mobile Sampling of Natural 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 standard units of standard cubic feet (scf). 

One scf of methane contains 19.2 g methane. 
S‐3

S1 Direct Source Measurements: Well Completion Flowbacks 

S1.1 Methods 

Methane emissions were measured directly, at the point of release. Data for 27 well 

completion events are reported. Section S4 describes measurements of methane concentrations 

that were made downwind of 6 of the completion events; these downwind measurements were 

used to confirm that all of the major emission sources were being measured. 

The sources of well-site methane emissions 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 work). There are several stages in the flowback 

process that utilize the equipment shown in Figure S1-1. In the first stage (Step 1 in Figure S1-

1), reservoir gases mixed with water, sand and fracturing liquid flow from the high pressure well 

head, through a choke, to either an open top tank or an enclosed tank with open vents. In either 

case, the tank gases are vented to the atmosphere. Figure S1-2 shows examples of open-top 

tanks, used in Step 1. To measure emissions from 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 wavelengths to visualize hydrocarbon plumes, was 

used to check for leakage around the seal. The gases were vented through a plenum that had exit 

stacks of two diameters. The smaller diameter stack was used during periods of low flow and the 

larger stack was used during periods of high flow. Switching between the stacks was done with 

pneumatic controllers operated remotely. Gas velocity in the stack was measured using a pitot 

tube in the center of the stack. Total volumetric 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 stack to an estimated average velocity in the stack.1

 

Gas samples for composition analysis were drawn from the temporary stack, through tubing to a 

sampling port 10-20 meters from the tank. Gas samples were drawn into evacuated tedlar bags 

for subsequent analysis using gas 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 configuration 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 flowback tank hatches, and the flare
S‐5

Figure S1-2. Open top tank used in Step 1 of flowback using the equipment configuration 

shown in Figure S1-1. Upper Left: line leading from well to tank; upper right: temporary plastic 

cover installed and clamped to edge of tank, with 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 place 
S‐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 ranged 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). Separator 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 streams) 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 enclosed, with hatches allowing venting to the 

atmosphere. As shown in Figure S1-3, temporary 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 the separator was routed, through 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 determine the flow of flared methane. 

A combustion efficiency of 98% was assumed, based on standard EPA emission factors2,3. 

 The period of flowback to the separator and enclosed flowback tank lasted from a few 

hours to more than a week, depending on the characteristics of the well. After 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 1 
S‐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 configurations 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 flare, and in still other cases the gas from the 

separator was routed exclusively to sales. The categorizations shown in Table S1-1 are 

distinguished by the type of surface equipment used, rather than the fate of the streams from 

particular pieces of surface equipment. Thus, Table 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 different emissions. However, there are common 
S‐9

elements in the completions which are similar across multiple configurations. These elements 

include: 

1. Flow of a mixture of sand, water, gas and fracturing 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 either vented or sent to a combustion device 

3. Flow of pressurized water, with dissolved methane, from a separator to a tank where gas 

flashes from the liquid and is either vented or sent to a combustion device 

4. Flow of gas, including methane, from a separator 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 sand 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 anticipated 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 necessary 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 emissions will be lower than potential emissions. In 

contrast, for Configuration 4, a configuration that will not be permissible under recent EPA New 

Source Performance Standards (NSPS) (Subpart OOOO regulations), there are no emission 

controls, so potential emissions and 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 liquids and gases from the well and 

ending at the point at which the completion contractor’s report stated that it ended. Often this 

end point was when gases were routed to sales or to a centralized gas processing facility, 

however, the end point was not uniformly defined. For example, some completion flowbacks 

were routed from the well to a temporary separator, and the operator defined the end of the 

completion as the point at which flow was routed 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 estimates are provided in Tables S1-2 through S1-5. 

 Methane emissions over an entire completion flowback event, summed over all emission 

sources for each event (e.g., tank vents, uncombusted methane from flares), ranged from a few 

thousand scf to more than 800,000 scf, with an average 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 the well was sent immediately, at the start of the 

completion, to a separator, and all of the gases from 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 emission 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 completions. 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 completion 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 methane from the flare dominated the total 

methane emissions from the completion event (Gulf Coast Completions 1-4– see Table S1-3). 

For flowbacks using flares, it was assumed that 98% of the methane fed to the flare was 
S‐11

combusted and 2% of the methane fed to the flare remains un-combusted and escaped into the 

atmosphere2,3. Figure S1-4 shows an example of the methane flow to the flare at a completion, 

which had the surface equipment configuration shown in Figure S1-1. In this completion (Gulf 

Coast Completion 1), a total of 5,000,000 scf of methane (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 gases 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 from the flare (estimated at 100,000 scf) dominate 

total methane emissions during this completion event. 

Figure S1-4. Flow of gas from well completion separators 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 flowback tank. The flow from the separator to the flowback tank is not 

constant. The flow varies as the separator periodically builds hydrocarbon 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 completion
S‐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 occurred 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 can cause the concentration of methane in the vent 

gas to vary. For example, methane concentration in the stack of the flowback tank will vary 

based on the oil and water level in the flowback tank, since the methane flashing from the 

separator discharge is diluted by the existing air in the vapor space of the flowback tank and 

dilution changes as vapor space changes. These liquid levels change, depending on the schedule 

minutes

minutes
S‐13

for emptying tanks of their liquids. In addition, oil and water composition can vary over the 

course of a flowback, changing the methane solubility. Because of these and other factors, 

detailed temporal analysis of the methane emissions 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 determined 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 interpolated methane concentrations, two sensitivity 

analyses were performed. In one sensitivity analysis, 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 for 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. For 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 measurement until the end of the completion. For the 

estimate on the higher bound on concentration, the methane concentration at the start of the 

completion was assumed to be equal to the initial concentration measurement and it was assumed 

that the final gas composition persisted from the 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 based on physical arguments. The size 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, rather 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 approximately 20% of the total emission estimates.
S‐14

Table S1-2. Methane emissions (scf) from Appalachian well completions: results from 5 sampling 

(Dark shading indicates that data were not used in determining average emission factorsa) 

Emission Source 

(duration of completion flowback event, hr) 

1 

Company 

AP-A 

2 

Company 

AP-B 

3 

Company 

AP-B 

4 

Company 

AP-C 

Configuration 

1* 

(62.5 hr) 

Configuration 

3*** 

(37.8 hr) 

Configuration 

3*** 

(12.5 hr) 

Configuratio

1** 

(339.2 hr) 

Flowback to open top tank; gases vented 12,700 ± 

10,000 scf 

6,700 ± 800 

scf 

Not applicable 1,105,000 

320,000 sc

Atmospheric Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaControlled (combusted) Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaAtmospheric Vent from Tank handling liquid water stream from Completion Separator 

Included in the 

flowback to 

open tank 

Included in the 

flowback to 

open tank 

63,500 ± 6,000 

scf 

Included in 

flowback t

open tank 

Controlled (combusted) Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable Not applicable Not applicaGas from overhead of completion separator, sent to flare (assumed 2.0% of methane is uncombusted in flare) 

16,000 scf 1,000 scf 44,000 scfb Not applica

Total (based on temporary stack cross sectional area 

x centerline velocity) 29,000 scf 7,700 scf 108,000 1,105,000 s

Total (based on temporary stack cross sectional area x 

centerline velocity x 0.8 ) 26,000 ± 8,000 scf 6,400 ± 700 scf 95,000± 5,000 scf 880,000 ± 300,000 sc

aBecause of partial data loss, there is significant uncertainty, difficult to quantify, in the results from this completion; the data from this completi

averages or in regional and national extrapolations 

bIncludes 4,000 scf from flare and 40,000 scf from venting of separator; 

*Configuration 1 (from Table S1-1): Initial flowback went to an open-top tank. After the initial period, the flow was sent to a separator. Gas fro

Liquids from the separator were sent to flowback tanks that were vented ** Configuration 1 (from Table S1-1): Initial flowback went to an open-top tank. After the initial period, the flow was sent to a separator. Gas 

sales. 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 a vented flowback t
S‐15

Table S1-3. Methane emissions (scf) from Gulf Coast well completions: results from 7 sampling 

Emission Source 

(duration of completion flowback event, hr) 

1 

Company 

GC-A 

2 

Company 

GC-A 

3 

Company 

GC-B 

4 

Company 

GC-B 

Configuration 

1* 

(74.9 hr) 

Configuration 

1* 

(74.9 hr) 

Configuration 

2** 

(28.0 hr) 

Configuratio

2** 

(27.9 hr) 

Flowback to open top tank; gases vented 1300 ± 180 scf 500 ± 400 scf 40,000 ± 

30,000 scf 

13,000 ± 

10,000 scf 

Atmospheric Vent from Tank handling liquid HC stream from Completion Separator 3700 ± 550 scf 4800 ± 900 scf Not applicable Not applicaControlled (combusted) Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable 14,000 scf 20,000 scAtmospheric Vent from Tank handling liquid water stream from Completion Separator 600 ± 120 scf 200 ± 100 scf 60,000 scf 60,000 scControlled (combusted) Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable Not applicable Not applicaGas from overhead of completion separator, sent to flare (assumed 2.0% of methane is uncombusted in flare) 

100,000 scf 85,000 scf 150,000 scf 90,000 sc

Total (based on temporary stack cross sectional area 

x centerline velocity) 106,000 scf 91,000 scf 264,000 scf 180,000 sc

Total (based on temporary stack cross sectional area x 

centerline velocity x 0.8 ) 105,000 ± 600 scf 90,000 ± 800 scf 260,000 ± 30,000 scf 180,000 ± 8,

scf 

*Configuration 1(from Table S1-1): Initial flowback went to an open-top tank. After the initial period, flow was sent to a high pressure separatoseparator was sent to a flare; water from the high pressure separator was sent to a vented flowback tank. Hydrocarbon liquids from the high prespressure separator. Gas from the low pressure separator was sent to a flare; hydrocarbon liquids from the low pressure separator were sent to a v**Configuration 2 (from Table S1-1): Initial flowback went to an open-top tank. After the initial period, the flow was sent to a separator. Gas fflare 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‐16

Table S1-3 (continued). Methane emissions (scf) from Gulf Coast well completions: results from 7 sam

(Dark shading indicates that data were not used in determining average emission factorsa) 

Emission Source 

(duration of completion flowback event, hr) 

6a

Company 

GC-A 

7a

Company 

GC-A 

Configuration 

2**  

( 164 hr) 

Configuration 

2** 

(108 hr) 

Flowback to open top tank; gases vented 1,000 scf 1,000 scf Atmospheric Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicableControlled (combusted) Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicableAtmospheric Vent from Tank handling liquid water stream from Completion Separator 3,000 3,000 Controlled (combusted) Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicableGas from overhead of completion separator, sent to flare (assumed 2.0% of methane is uncombusted in flare) 

243,000 scf 86,000 scf 

Total (based on temporary stack cross sectional area 

x centerline velocity) 247,000 scf 90,000 scf 

Total (based on temporary stack cross sectional area x 

centerline velocity x 0.8 ) 247,000 scf 90,000 scf 

aBecause of partial data loss, there is significant uncertainty, difficult to quantify, in the results from this completion; the data from this completi

averages or in regional and national extrapolations **Configuration 2 (from Table S1-1): Initial flowback went to an open-top tank. After the initial period, the flow was sent to a separator. Gas fflare. Hydrocarbon liquids from the separator were sent to a flowback tanks that was vented to a combustion device. 
S‐17

Table S1-4. Methane emissions (scf) from Mid-Continent well completions: results from 5 samplin

Emission Source 

(duration of completion flowback event, hr) 

1 

Company 

MC-A 

2 

Company 

MC-A 

3 

Company 

MC-B 

4 

Company 

MC-B 

Configuration 

4  

(144.7 hr) 

Configuration 

4** ** 

(147.2 hr) 

Configuration 

3*** 

(138.0 hr) 

Configuratio

3*** 

(138.0 hr) 

Flowback to open top tank; gases vented 250,000 ± 

32,000 scf 

34,000 ± 5,000 

scf 

Not applicable Not applicab

Atmospheric Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaControlled (combusted) Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaAtmospheric Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable 3,400 scf 3,000 scf Controlled (combusted) Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable Not applicable Not applicaGas from overhead of completion separator, sent to flare (assumed 2.0% of methane is uncombusted in flare) 

Not applicable Not applicable Not applicable Not applica

Total (based on temporary stack cross sectional area 

x centerline velocity)

250,000 scf 34,000 scf 3,400 scf 3,000 scf 

Total (based on temporary stack cross sectional area x 

centerline velocity x 0.8 ) 200,000 ± 30,000 scf 27,000 ± 4,000 scf 2,700 scf 2,400 scf 

***Configuration 3 (from Table S1-1): Flowback to a separator; gas from the separator to sales; liquid from the separator to a vented flowback t Configuration 4 (from Table S1-1): Flowback went to a vented tank. 
S‐18

Table S1-5. Methane emissions (scf) from Rocky Mountain well completions: results from 10 samp

Emission Source 

(duration of completion flowback event, hr) 

1 

Company 

RM-A 

2 

Company 

RM-A 

3 

Company 

RM-B 

4 

Company 

RM-B 

Configuration 

4** ** 

(30.2 hr) 

Configuration 

4  

(30.1 hr) 

Configuration 

4** ** 

(44.5 hr) 

Configuratio

4  

(34.3 hr) 

Flowback to open top tank; gases vented 30,000 ± 

10,000 scf 

16,400 ± 3,000 

scf 

13,000 ± 7,000 

scf 

37,000 ± 

10,000 scf 

Atmospheric Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaControlled (combusted) Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaAtmospheric Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable Not applicable Not applicaControlled (combusted) Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable Not applicable Not applicaGas from overhead of completion separator, sent to flare (assumed 2.0% of methane is uncombusted in flare) 

Not applicable Not applicable Not applicable Not applica

Total (based on temporary stack cross sectional area 

x centerline velocity) 30,000 scf 16,400 scf 13,000 scf 37,000 scf 

Total (based on temporary stack cross sectional area x 

centerline velocity x 0.8 ) 24,000 ± 8,000 scf 13,000 ± 2,000 scf 10,400 ± 6,000 scf 30,000 ± 8,0

scf 

** **Configuration 4 (from Table S1-1): Flowback went to a vented tank. 
S‐19

Table S1-5 (continued). Rocky Mountain methane emissions (scf) from well completions: results from 10 

Emission Source 

(duration of completion flowback event, hr) 

6 

Company 

RM-B 

7 

Company 

RM-C 

8 

Company 

RM-C 

9 

Company 

RM-C 

Configuration 

4**** 

(23.7 hr) 

Configuration 

1* 

(4.8 hr) 

Configuration 

1* 

(15.1 hr) 

Configuratio

1* 

(20.5 hr) 

Flowback to open top tank; gases vented 42,000 ± 4,000 

scf 

40 scf 6,000 ± 2,000 

scf 

50,000 ± 5,0

scf 

Atmospheric Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaControlled (combusted) Vent from Tank handling liquid HC stream from Completion Separator Not applicable Not applicable Not applicable Not applicaAtmospheric Vent from Tank handling liquid water stream from Completion Separator Not applicable Included in the flowback to 

open tank 

Included in the 

flowback to 

open tank 

Included in 

flowback t

open tank 

Controlled (combusted) Vent from Tank handling liquid water stream from Completion Separator Not applicable Not applicable Not applicable Not applicaGas from overhead of completion separator, sent to flare (assumed 2.0% of methane is uncombusted in flare) 

Not applicable 440 scf 9,000 scf 4,300 scf 

Total (based on temporary stack cross sectional area 

x centerline velocity) 42,000 scf 500 scf 15,000 scf 54,000 scf 

Total (based on temporary stack cross sectional area x 

centerline velocity x 0.8 ) 34,000 ± 3,000 scf 500 scf 12,000 ± 2,000 scf 44,000 ± 4,0

scf 

*Configuration 1 (from Table S1-1): Initial flowback went to an open-top tank. After the initial period, the flow was sent to a separator. Gas fror 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 completion flowback events. Of these, 24 will be 

used to establish emission averages. The three completion 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 completion 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 averages. 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 completions involved no initial flow to an open top tank. Flowback went 

directly to a temporary separator; gas from the separator went to sales, and liquids from the 

separator went to a vented flowback tank (Configuration 3). The study team made several days 

of measurements, but the arrival of a hurricane necessitated removing the temporary stacks. The 

flowbacks continued throughout the hurricane. The study team used the completion reports to 

extrapolate data that had already been collected on the vent from the flowback tank. Because the 

study team was able to develop an extrapolation based on emission behavior that had already 

been directly measured for several days, the data were included. 

Additional data for each of the 27 completions are provided in Table S1-6. Table S1-6 

includes potential emissions for 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 events 

 
S‐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 

(106

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 summation 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-7 

 
S‐22

The data reported in Tables S1-2 to S1-6 are the first extensive measurements reported to 

date on methane emissions from well completion flowbacks. 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 completions with hydraulic fracturing 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 reduced their potential emission estimates due to 

assumed reductions from regulatory and voluntary controls. In the national inventory, EPA 

combines reductions associated with well completion flowbacks and workovers with hydraulic 

fracturing. In order to allow a comparison between the emissions reported in this work and an 

average emission per completion flowback in the national inventory, the same percentage 

reduction to potential emissions was applied to workovers and completion flowbacks. 

Specifically, since potential emissions for completion flowbacks (63.6 billion scf) and workovers 

with hydraulic fracturing (13.8 billion scf) totaled 77.4 billion scf, and since total reductions 

were 36 billion scf, the percentage reduction applied to potential emissions 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 completion 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% relative 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 account for approximately 80% of the reduction in 

emissions relative to the EPA inventory. Finally, the wells with uncontrolled releases had much 

lower than average potential to emit. Of the 9 wells 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 national inventory. This accounts for the remainder of the emissions 

difference. 

S1.3 Uncertainty Estimates 

Confidence limits for the completion flowback emissions were estimated using two 

complementary approaches. As noted earlier in this section, uncertainties associated with 

composition and flow measurements were estimated and combined into an overall measurement 

uncertainty. For the completion flowbacks, this resulted in uncertainty bounds that were in the 

range of 20% of emissions. A complementary bootstrapping method6

 was employed to develop 
S‐23

an estimate of the combined sampling and measurement uncertainties. In the bootstrapping 

procedure, the original data set of 24 flowbacks was recreated by making 24 random event 

selections, with replacement, 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 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% percentiles of the means in the 1000 re-sampled 

datasets. The combined measurement and sampling 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 the 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 pneumatically powered equipment, such as 

pumps and controllers, leaks from piping and equipment 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 was on measuring emissions from pneumatic pumps and 

controllers and measuring leaks from equipment, pipes, flanges and fittings. These sources were 

chosen for measurement because they are currently estimated to contribute over 20 bcf of the 

EPA national inventory from natural gas production.4

 Figure S2-1 shows a representative well 

site configuration with potential emission sources identified. 

Figure S2-1. Gas Well Production Site

The equipment present on individual well sites 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 separator 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 leaks 
S‐25

some sites but not others. Some sites had solar powered devices (e.g., chemical injection pumps) 

or combustion control devices that reduced or eliminated emissions 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 Shale 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. Similarly, while 78% of the sites 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 equipment leak measurements included leaks from 

wellhead equipment, piping, flanges, fittings, valves, separators, dehydrators, and non-exhaust 

emissions from compressors. Since the equipment count is expected to scale with the number of 

wells, emissions from equipment leaks are reported per well. Emissions for tanks were not 

examined because access to the multiple potential leak 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 controllers, 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 emission factors are used in 

the extrapolation of the data reported here to regional and national estimates, 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, valves 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 camera8 to 

identify potential leak sources. Scanning with an infrared camera is an approved alternative 

work practice (40CFR60.18) used in identifying leaking equipment. In the alternative work 

practice, the threshold for detecting a leak, consistent with the practices used by the study team, 

is 30 g/hr (0.026 scf/m). The threshold for detection 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 natural gas production, transmission, storage, and 

processing facilities. The Hi-Flow instrument has 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 operator’s hands free for climbing ladders or otherwise accessing 

locations. The instrument comes with attachments for enclosing leaking devices and is controlled 

by a handheld unit consisting of an LCD and a 4-key control pad, which is attached to the main 

unit via a 6 foot coiled cord. 

A component’s leak rate is measured by sampling at a high flow rate so as to capture all 

the gas leaking from the component along with a certain amount of surrounding air. By 

accurately measuring the flow rate of the sampling stream and the natural gas concentration 

within that stream, the gas leak rate can be calculated (see Equation below). The instrument 
S‐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 through a flexible 1.5 inch I.D. hose. Various 

attachments connected to the end of the sampling 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 CO2 and 

water. A thermal conductivity sensor is then used to determine CO2 concentration. A second 

identical combustibles sensor channel measures the 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 measured, the instrument will encounter additional 

hydrocarbons (typically ethane, propane, butane and higher alkanes). To account for the effect 

of these species on the measurements, gas composition data were collected for each natural gas 

production site that was visited. Typically this gas analysis was 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 area. 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 and 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 pumps and pneumatic controllers were measured 

with the Hi-Flow Sampler. All operating pneumatic 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 solar powered and non-operating pneumatic pumps were 

only sampled if leaks were detected using the infrared camera. 

Because many of the devices sampled had intermittent flows (e.g., pneumatic pumps and 

controllers), a variety of methane 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 sampled from the controllers associated with the 

wells that were sampled. This approach of random 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 the data for the controllers were treated as one 

dataset. 

Data analysis methods and 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 sample set. There are hundreds of thousands of 

natural gas production wells in the United States, and 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, using a method referred to as bootstrapping.6

 

In the bootstrapping procedure, a data set was 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 replacement, 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 here 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 pumps, pneumatic controllers and equipment leaks. 
S‐29

S2.2 Results and Discussion 

Pneumatic Chemical Injection Pumps 

Pneumatic Chemical Injection Pumps use the pressure from on-site natural gas to drive 

pumps that inject anti-corrosion and other liquids into the produced gas stream. Table S2-2 

reports emission rates, by region, and a national average, for Chemical Injection Pumps. 

Not all wells had active Chemical Injection Pumps. For example, no operating Chemical 

Injection Pumps were encountered at active production 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 had 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 that point in the well life). 

Table S2-2 reports both “whole gas” emission 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 emission factors are expressed 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 variability in the mean of the data set (as described in Section 

S2.1), rather than an instrumental uncertainty in a single measurement 
S‐30

 The average values of emissions per pump for Chemical Injection Pumps reported here 

are similar to the emission factor suggested by EPA3 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 reductions are applied to potential 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. Emissions per pump from the Gulf Coast are 

statistically different (higher) than emissions from pumps in the Midcontinent region. The 

difference in average values is roughly 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 emissions. 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 emissions. 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 these 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 possibilities, that have not yet been investigated, but that 

may be pursued in follow-up work, include pump design or local regulatory requirements. 

Pneumatic Controllers 

Pneumatic Controllers use the pressure from on-site natural gas to drive devices that 

actuate valves controlling flow from units such as separators to units such as tanks. Table S2-3 

reports emission rates, by region and a national 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 included in the total; no high bleed controllers were 

reported by companies providing controller type information 

**Uncertainty characterizes the variability in the mean of the data set (as described in Section 

S2.1), rather than an instrumental uncertainty in a single measurement 
S‐31

 The average values of emissions per device for Pneumatic Controllers reported here are 

comparable to the values suggested by EPA3

 for use in estimating methane emissions (1.39, 37.3 

and 13.5 scf whole gas per device per hour for low bleed, high bleed and intermittent bleed 

controllers vs. 11.2 reported here for a mix of intermittent and low bleed controllers). No high 

bleed controllers were reported by the companies that provided controller type information. At a 

total of 55 sites, site operators reported only intermittent 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 confounding factor, can be used to establish separate emission factors 

for intermittent and low-bleed devices. These 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 assuming 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 density of 20.3 g/scf, as measured in this work) for low bleed 

controllers. For intermittent and low bleed controllers, the measured emission factors are 29% 

and 270% higher than the EPA emission factors (expressed in units of scf whole gas per hour), 

respectively. 

There is significant geographical variability in the emissions rate from pneumatic 

controllers between production regions. Emissions per controller from the Gulf Coast are 

highest and are statistically different than emissions from controllers 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 emissions 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 (Colorado Air Regulation XVIII.C.1; XVIII.C.2; technical 

feasibility criterion under review as this is being written). However, observed differences in 

emission rates between intermittent and low bleed devices (roughly a factor of 3) are not 

sufficient to explain all of the 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 devices, the volume of oil produced was not a good 

predictor of emissions. Well head and separator pressure were also not good predictors of 

emissions. The definition of low-bleed controllers may be issue, however. All low bleed 

devices are required to have emissions below 6 scf/hr (0.1 scf/m), but there is not currently a 

clear definition of which specific controller designs should be classified 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, separators, wellheads, and connectors located on 

site are reported in Table S2-4. The data are reported as emissions normalized by the number of 

wells on each site. Out of the 150 sites visited, 146 had wells on the sites. The remaining 4 

sites, all in the Gulf Coast region, had separators and other equipment on site, but no wells. 

Some companies operating in the Gulf Coast region 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 sites were excluded in the data averaging. The 

equipment at the four sites with no wells was estimated 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 variability in the number of wells and the 

type of equipment located on well sites makes averaging emissions per site a less useful way to 

represent equipment leak data than average emissions from leaks per well (leaks at a site divided 

by the number of wells at the site). Further, the number and type of equipment that could be 

potential leak sources generally 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 the data set (using a bootstrapping 

method as described in Section 2.3), rather than an instrumental uncertainty in a single 

measurement 
S‐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), calculated by dividing the potential emissions in 

these categories in the EPA national 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 lift 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 would 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 gathering compressors for the 

wells that were sampled. A second factor confounding comparisons with the national inventory 

is that the EPA calculates net emissions in the national inventory by subtracting reductions from 

potential emissions. The equipment leak reductions are reported as an aggregate reduction that 

also includes reductions associated with blowdowns, 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 emissions for these categories, the emissions in the 

national inventory (not including compressors) are 9 billion scf (172 Gg, 0.04 scf/m per well). 

These estimated net emissions from equipment leaks 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 composition and flow measurements were estimated 

as approximately 10% of emissions. A complementary bootstrapping method6

 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 these 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 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 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 emission 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 stack installed on top of the tank 

vent on the blowdown site tanks. Figure S3-1 shows a temporary stack in use. Grounded metal 

or metal lined tubing was used to prevent static discharge. Flow rate through the temporary 

stack was measured continuously, near the centerline of the temporary stack, using 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 stacks 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 the stack centerline. The factor of 0.8 was used 

to convert the centerline velocity in the stack to an estimated average velocity in the stack, 

accounting for the change in velocity profile 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 fraction 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 combination 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 the 
S‐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 emissions that occur because of the blowdown 

but that are not released during the period when the tank is actively venting through the thief 

hatch. 

Uncertainty in these measurement methods is estimated at 10% of the measured 

emissions and this estimate is dominated by the 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 section, these measurement uncertainties are small compared to the 

combined sampling and measurement uncertainty. 

S3.2 Results and Discussion 

Emissions were measured for a total of 9 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-1c were performed on three different wells at a 

single well site and unloading events 2a-c were also performed at three different wells at a single 

well site, in a different production region than Events 1a-c. 

The unloadings were heterogeneous in their characteristics. Methane emissions ranged 

from less than 1,000 scf to 191,000 scf. Some unloadings lasted two hours (or more) and had 

relatively uninterrupted flow (Events 1a-b). Other unloadings were as short as 10-15 minutes 

(e.g, Events 2b and 3) with uninterrupted flow and 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 leads 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 recognizes that average emissions are often used 

to establish an annual emission estimate for unloading 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 emissions 
S‐36

per well per year for unloading without plunger lifts in EPA’s national inventory (7,734 million 

scf for unloadings without plunger lifts for 35,828 wells with this type of unloading4

) and an 

estimate of 240,000 scf methane based on a survey 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 measurements 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 

blowdownc

(hr) 

Volume 

of well 

bore 

(ft3) 

Well 

shut-in 

pressure 

(psia) 

Normal 

production 

rate for 

well 

(scf/hr) 

Events 

per 

year 

for 

wellg

1a 

(GC) 

248,500a

(199,000)b

96% 191,000 2.77d

 10,906 300 374,000 7 

1b 

(GC) 

208,100a

(166,000)b

96% 159,000 1.904d

 10,906 300 374,000 1 

1c 

(GC) 

85,800a

(68,600)b

96% 65,900 0.63d 10,906 300 374,000 1 

2a 

(RM) 

1,810a

(1,450)b

92.9% 1,350 0.75e

 1,875 527 295,000 2 

2b 

(RM) 

1,770a

(1,420)b

92.9% 1,320 0.2d 1,876 642 169,000 4 

2c 

(RM) 

1,270a

(1,020)b

92.9% 950 1.25e 1,900 1116 304,000 2 

3 

(AP) 

14,550a

(11,600)b

97.4% 11,300 0.25d 1,404 890 208,000 12 

4 

(GC) 

5670a

(4540)b

84.4% 3,800 1.1f

 1,977 1500 25,000 12 

5 

(GC) 

121,200a

(97,000)b

81.4% 79,000 1.25d 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 sectional area * centerline velocity 

b

based on temporary stack cross sectional 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 continuous 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 sampling 

 
S‐38

Table S3-2. Emissions estimates per well per year for manual well unloading 

Event Regiona 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 sectional area * centerline 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 characteristics 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, API/ANGA report an average of 32.57 events per well per year, 

higher than the average of 5.9 in this work. The 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/ANGA12) is 304,000 scf of 

gas or 240,000 scf methane per well per year, assuming 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 significant differences between 

the two populations. One major difference is the frequency of unloading. The wells in the 

API/ANGA survey have an average of 32.57 unloadings per year, while in this work the average 

is 5.9. This means that the average per event, 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 here. The API/ANGA dataset contains more 

wells that unload with high frequency, 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, rather 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 without plunger lifts in the 

GHGRP3 assumes that the volume in the entire length of the pressurized well is vented to the 

atmosphere. This is assumed to occur during the first hour of the blowdown, 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 than one hour, the emissions are 

assumed to be equal to the volume in the pressurized well. The equation (W-8) provided by EPA 

is: 

Where: 

Es,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 for 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). 

CDp = Casing internal diameter for each well, p, in inches. 

WDp = 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. 

SPp = For each well, p, shut-in pressure or surface 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 tubing pressure of each well, p, in the subbasin, in pounds per square inch absolute (psia); in this work the product of 

0.37×10−3

* CDp* WDp* SPp is obtained by multiplying the well volume (in ft3, 

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

by 14.7 

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

. 

SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per 

hour; for this work these data are reported in Table S3-1. 

HRp,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 blowdown casing volume at shut-in pressure. 
S‐40

Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or equal to 1.0 

then Zp,q is equal to 1. 

Data for all of the input variables for EPA 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 results of applying this estimation method to the 9 

well unloadings (without plunger lift) sampled in this work. 

Table S3-3. Comparison of measured and estimated 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 248,500a

(199,000)b

884,600 6,192,600 222,600 662,000 

1b 208,100a

(166,000)b

559,200 559,200 222,600 336,600 

1c 85,800a

(68,600)b

222,600 222,600 222,600 0 

2a 1,810a

(1,450)b

67,200 134,400 67,200 0 

2b 1,770a

(1,420)b

81,900 327,600 81,900 0 

2c 1,270a

(1,020)b

144,200 288,400 144,200 0 

3 14,550a

(11,600)b

85,000 1,020,000 85,000 0 

4 5670a

(4540)b

204,200 2,450,200 201,700 2,500 

5 121,200a

(97,000)b

199,200 2,390,000 195,000 4,200 

Avg. 76,500a

(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). Further, the detailed temporal patterns of gas flow observed in this 
S‐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, employing EPA emission estimation methods, for 

the 9 unloadings reported here (270,000 scf methane), is roughly five times the measured 

average per event of 57,000 scf. If the estimated emissions are calculated by well (multiplying 

the emissions per event by the events per year for the well), the average is 1,500,000 scf 

methane, six times the average in the API/ANGA survey. 

 All of these averaging methods 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 

differences between estimates and measurements, and to better characterize the population of 

wells with unloading emissions. 

Finally, it is also clear from the data that properly accounting for unloading emissions 

will be important in reconciling emission inventories with regional ambient measurements. 

Average methane emission rates for a single unloading 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 for 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 approximately 1 scf/m per well) or from completions (typically tens of 

scf/m per event). At these emission rates, a single unloading event could, during the very short 

period that it is occurring, result in emissions that are the equivalent of just a few wells in routine 

production to the equivalent of up to several thousand wells in routine production. This indicates 

that reconciliation between instantaneous ambient measurements and emission inventories will 

need to very carefully represent 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, uncertainties associated with composition and flow 

measurements were estimated as approximately 10% of emissions. A complementary 

bootstrapping method6

 was employed to develop an estimate of the combined sampling and 

measurement uncertainties. In the bootstrapping procedure, the original data set of 9 unloadings 

was recreated by making 9 random event selections, with replacement, 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 95% confidence interval for the emission estimate of 

57,000 scf is 17,000-100,000 scf, where the bounds represent 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 procedure leads to a much larger uncertainty range 

than would be estimated from the uncertainty associated with the measurement alone. Therefore 
S‐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 measurements of the total methane emissions from 

natural gas production sites. The resulting emissions 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 not directly measured using the methods employed 

in this study, such as emissions that 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 species were emitted at a controlled rate, on site, at 

locations as close as possible to methane releases. The tracer species and methane were 

measured at downwind locations (100 m to more than 1 km). Upwind concentrations were 

measured, as required, if downwind mobile sampling indicated that concentrations did not return 

to baseline values outside of detected plumes. If it is assumed that the tracer disperses in a 

manner equivalent to the methane, the ratio of the 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 tracer release rate and the ratio of the methane 

concentration to the tracer concentration detected sufficiently far downwind, as shown in 

Equation S4-1. 

Methane emission rate = Tracer emission rate * (downwind – upwind concentration of methane) 

/ (downwind – upwind concentration of tracer) (Eqn. S4-1) 

Prior work has demonstrated that the “tracer flux ratio” quantification approach can 

accurately quantify the total emissions from emissions from industrial sites13 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 area 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 tracer 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 site. The method also requires accessibility of 

downwind locations for sampling. For this work, since measurements were done using a mobile 

van, a downwind road network was required. Because of these constraints, downwind sampling 

was only performed at a subset of the sites. The exact fraction of sites that are amenable to this 
S‐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 equipped with commercial and research grade 

instrumentation designed to operate while in motion. The majority of the instruments on board 

are in-situ sampling instruments used to characterize the composition of the sampled air. Other 

instruments include wind speed and direction, vehicle position and orientation using the global 

positioning system (GPS), atmospheric pressure and temperature. Examples of the application of 

this type of mobile laboratory to atmospheric 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 standard 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 the 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 lag times, 5-9 seconds, but 

retained the rapid time response in the instrument itself. Reported time series data from the 

instruments with a longer lag time were consequently time shifted 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 spent 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 inlet lag as well as define instrument zero. The 

flow rate of the zero of calibration gas was set to induce less than a 0.2% pressure change at the 

first instrument in the manifold and still “overflow” 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 turbulently 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 direction 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 WM30 rotary vane anemometer and an AirMar 

LB150 sonic anemometer. The LB150 device also employs an internal GPS to correct for the 

motion of the vehicle to report a true wind. Atmospheric pressure was logged using a calibrated 

1000 Torr MKS pressure transducer and temperature was measured. A Vacuubrand MD4 

diaphragm pump was used to draw sample through the CO2 Licor instrument and to other 

diagnostic equipment. It was also used to induce small draws on the lines used for periodic zero 

and calibration. A Varian Triscroll 600 was used to draw 9 slpm through the tunable infrared 

differential absorption spectrometers in series. 

The primary analytical composition measurements in this work were performed using 

tunable infrared laser differential absorption spectroscopy (TILDAS). The primary external 

tracer in this work was nitrous oxide (N2O) and was measured using absorption lines at 2199.737 

cm-1. The auxiliary external tracer in this work was acetylene (C2H2) and was measured using an 

absorption line at 1342.349 cm-1. Methane (CH4) was measured using the minor (13C) 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 N2O, 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 during the tracer release campaign 

Measurement Rate Instrument 

Methane (CH4) 1 s Quantum Cascade Laser Sys. (1294 cm-1) 

Carbon Monoxide (CO) 1 s Quantum Cascade Laser System (2230 cm-1) 

Acetylene/Ethyne (C2H2) 1 s Quantum Cascade Laser System (1342 cm-1) 

Nitrous Oxide (N2O) 1 s Quantum Cascade Laser System (2200 cm-1) 

Carbon Dioxide (CO2) 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 MKS 1179 A Mass Flow Controllers (SN’s 001347521, 

001773651, 020003843). The MKS 1179 A Mass Flow Controller operates on the principle that 

by monitoring the temperature flux of a gas and using a known specific heat constant for that gas 

one can monitor the mass flow rate. The MKS 247 unit acts as a processor for the MFCs; its data 

output is logged on to the release stand computer. The mass flow controllers are calibrated and 

checked throughout each campaign to ensure accuracy. Once the release gas has been regulated 

by the mass flow controller it passes through a series of emergency shut off valves then to 

release. 
S‐46

 The tracer release base unit was deployed with 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 speed, wind direction, temperature, pressure, GPS 

location, solar intensity, and relative 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 distilled 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 (in this work, methane) undergo 

equivalent atmospheric dispersion prior to downwind sampling. The observed downwind 

concentration ratio of the two tracers can be compared to the known ratios of mass emission rates 

to provide a characterization of measurement uncertainty. 

S4.2.3 Data analysis 

 Typical data generated in tracer flux measurements are shown 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 tracer release points for N2O and acetylene are shown. The N2O release 

point was located adjacent to an on-site compressor. The acetylene release point was located 

adjacent to a tank battery. The mobile van made measurements of methane, acetylene and N2O 

along a road north of the production sites. The path of the van is shown as a series of dots, with 

the size and color of the dots indicating the magnitude of the methane concentration. Measured 

concentration distributions are shown for N2O, acetylene and methane. 
S‐47

Figure S4-1. Summary of data collected during downwind 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 van path (shown as dots), and concentration 

distributions of tracers and methane along the transect path (upper right). 

 The analysis of the concentration distributions is summarized in Figure S4-2 and S4-3. A 

first observation from the concentration distributions is that the acetylene and N2O concentration 

profiles are different, based on locations of the tracer release sites. Also shown in Figure S4-2 is 

a hypothetical distribution of acetylene that would be anticipated, if the releases were co-located. 

The differences in the acetylene and N2O 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 tracers were used to estimate plume capture (as 

described below). 
S‐48

Figure S4-2. Acetylene, N2O and methane concentration profiles (background corrected) along 

the path traversed by the measurement van (horizontal axis is local measurement time). Also 

shown is a hypothetical distribution 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 N2O tracer. 

Methane emission rate = N2O tracer emission rate * (downwind – upwind concentration of 

methane) / (downwind – upwind concentration of N2O tracer) (Eqn. S4-2) 

Figure S4-3 shows multiple instances of the instantaneous methane concentration and the N2O 

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 N2O release rate gives an estimated 

methane release rate of 1.26 g CH4 per second. 
S‐49

Figure S4-3. Comparison of the instantaneous methane concentration (measurement – 

background) associated with the N2O tracer shown in Figure S4-1, and the N2O tracer 

concentration (measurement – background) at the same 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 comparing the concentration ratios of acetylene to 

N2O, observed second by second, in the plume, to the known ratio of the emission rates of the 

two tracers. Figure S4-4 shows 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 second by second observations in the plume. The average of the 

methane to N2O concentration ratios, observed second by second in the plume, indicated by the 

slope of the line in Figure S4-4b, was consistent throughout the plume, and was used in Equation 

S4-2, along with the known N2O tracer emission rate, to calculate methane emissions. The 

average of the acetylene to N2O concentration ratios, observed second by second in the plume, 

indicated by the slope of the line in Figure S4-4c, 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 plume (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 concentrations in the plumes at all sites are compared 

to the known ratios of tracer releases at all sites, the distribution is normally distributed with a 

standard deviation of 15%. The ratio shows a positive 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 sensitive to the meteorological conditions, topography 

and downwind access, and so is likely not generalizable beyond the work reported here. 
S‐51

 

Figure S4-4 a.) Methane, acetylene and N2O plumes observed downwind of a production site; 

tracers were co-located; b.) the average ratio of methane to N2O in the plume, determined using 

second by second observations of methane and N2O is indicated by the slope of the line; this 

ratio was used in Equation S4-2, with the known release rate for N2O, to estimate methane 

emissions; c.) the average ratio of acetylene to N2O in the plume determined using second by 

second observations of acetylene and N2O in the plume is indicated by the slope of the line; the 

0.8% error indicates the difference between the ratios of the observed concentrations in the 

plume and the ratios of the tracer 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 presented in two sections: (i) emissions fluxes 

from well completion activities, and (ii) emission fluxes from natural gas production sites. 

Emission fluxes from well completion flowback activities 

 Measurements were made downwind of 6 well completion flowbacks. Five of the six 

flowbacks were of the type reported as Configuration 4 in Table S1-1 – flowbacks in which the 

entire flow was sent to a vented tank. There are several reasons for a focus on these types of 

completions. First, these types of completions have the greatest uncertainty in their emissions. 

Other types of completions, involving separators, have well completion reports that typically 

include gas volumes, oil volumes and water volumes released by the separators. Reasonably 

accurate engineering methods can be used to estimate the emissions arising from these separator 

flows when they reach the tanks. In contrast, engineering estimates of emissions associated with 

flow directly from a well head have a high degree of uncertainty and the direct source 

measurements made in this work provide data that cannot be routinely estimated. An additional 

reason for focusing on this category of completions is that the completion involves a single 

emission point. This reduces the uncertainty in the emission estimates based on the tracer release 

method. 

 Comparisons of the direct source measurements and the emission estimates based on the 

dual tracer method, for the 5 flowbacks that utilized Configuration 4, are provided in Table S4-2 

and Table S4-3. Table S4-2 reports comparisons for Rocky Mountain completions 3, 4 and 5, 

which occurred sequentially. Table S4-3 reports comparisons for Midcontinent completions 1 

and 2, which occurred concurrently. Since the 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 made. In general, downwind measurements 

are reported for periods when the van was consistently (but not necessarily continuously) in the 

plume. During these periods, the ratio of methane to tracer concentration 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 rate 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 calculation method, non-zero direct source emission 

estimates were calculated by summing all emissions 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-zero 
S‐53

emissions might be expected, since plume spreading downwind would cause the van to record 

shorter zero emission periods than the direct source measurements. 

Table S4-2. Direct source methane emission measurements 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 concurrently 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 report; after the venting period ended, the gas was sent from the 
S‐54

separator to a flare where the gas was combusted. Flow rates to the flare were reported hourly in 

the completion report, so hourly emission estimates were made for the flare, based on methane 

flow to the flare and an assumed combustion efficiency 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 measurements 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. Flaring 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 measurements and emission estimates based on 

downwind tracer measurements is generally within a factor of 2. Because 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 completion flowbacks are roughly 97% below the most 

recent national estimates and that emissions from completion flowbacks without methane control 

or recovery equipment, observed in this work, are well below the average potential emissions in 

current national inventories4

. Even if emissions based on the direct source measurements were 
S‐55

doubled, projected national emissions from completion flowbacks would still be 95% less than 

current estimates.4

 

 One exception to the general agreement, within 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 likely due to the temporal resolution of the 

composition measurements in the direct source method. In this completion, during this time 

period, methane concentrations were dropping rapidly. The direct source emission estimate is 

based on gas composition measurements at the 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 rapid drop to lower emissions for most of the 

measurement period. If the direct source measurements are based on the gas composition at the 

end of the period, rather than a linear interpolation, the ratio of the direct source measurements to 

the tracer measurements would be similar to other ratios in Table S4-2. 

 It should also be noted that the downwind dual tracer measurements for completion 

flowback AP-3 provide some evidence of flare combustion efficiencies. At approximately 

10:45, methane that had been vented from the separator was routed to the flare. The downwind 

emission estimate dropped in less than a few minutes from 325 scf/m to 9.1 scf/m. If it is 

assumed that the emissions from the flowback tank 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 measured downwind are less than the emissions 

directly measured from the flowback tank vent, suggesting the flare emissions are near zero 

(100% combustion efficiency). Even if it is assumed that the downwind measurements are only 

detecting methane emissions from the flare, combustion efficiencies would be estimated as at 

least 97.2% ((1-(9.1/325))*100). These are preliminary observations, and given the uncertainties 

in the direct source and dual tracer measurements, do not support the use of a new emission 

factor for flares. Nevertheless, the data are supportive of the assumption of 98% combustion 

efficiency used throughout this work. 

 
S‐56

Emission fluxes from natural 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, and 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 atmospheric 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 (condensate) tanks are not vented directly to the atmosphere, but 

instead are sent to a combustor. The combustor 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 

pumpsa

Fugitivesa

 Compressorsb Tanksb 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 averages 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 agreement 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, that for some sites, the total on site measurements 

are dominated by tanks and these are estimated, rather than calculated emissions. Most of the 

Rocky Mountain sites had combustors on the vents to the hydrocarbon tanks, resulting in much 

lower tanks emissions, but the extent of agreement 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 owner reports that tank vents are not sent to a 

combustor. If a combustor were in place, or if the separator did not send liquid to the tank while 
S‐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 difficult to account for, is that 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 entire downwind sampling period. 

 Overall, the downwind measurements do not suggest 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 applied 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 term used to scale up the emissions is called the 

activity factor (AF), and is the count or population of the source or event at the scale of interest, 

such as regionally or nationally. This can be shown as: 

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

Where: 

EFi = 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 drawn from EPA’s 2011 national emission inventory4

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) 446,745a

a

Estimate from U.S. Department of Energy, Energy Information Administration is 513,000 on-shore gas wells23

No uncertainty bounds are reported for activity factors in the EPA national inventory, and 

therefore no uncertainty bounds are reported in Table 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 calculation scenarios can provide a rough characterization of the 

uncertainties associated with applying these counts to estimating national emissions. 

Specifically, for well completions and equipment leaks, regional activity counts can be 

multiplied by regionally averaged emission factors or national activity counts can be multiplied 

by nationally averaged emission factors. For pneumatic devices, emissions averaged by device 

type (e.g., low bleed and intermittent pneumatic controllers) 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 national averaging can also be performed. These calculation scenarios 

are reported in Section S5.3. 

 
S‐61

S5.3 Emission Factors and National Emission Estimates 

Table S5-2 provides central estimates of national emission rates, by source category, based 

on the activity factors reported in Table S5-1. 

Table S5-2. Central estimates of National Emission 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 

CH4 (Gg) 

New Gas Well 

Completion 

Flowbacks 115,000a

 scf CH4/ event 8077 events/yr 

EPA 2011 

Inventory 

0.93 bcf/yr 

(18 Gg) 

Gas Well Liquids 

Unloadings (nonplunger) 48,000-

300,000b

scf CH4/ 

well/yr 35,828 

Wells that 

unload 

EPA 2011 

Inventory 

1.3-10.7 bcf/yr 

(25- 205 Gg) 

Pneumatic 

Devices 67,400c

scfy CH4

/device 447,379 devices 

EPA 2011 

Inventory 

30.2 bcf/yrd

(580 Gg) 

Chemical 

Injection Pumps 101,000 

scfy CH4

/device 35,013 devices 

EPA 2011 

Inventory 

3.5 bcf/yr 

(68 Gg) 

Equipment Leaks 33,900 

scfy CH4 

/well 446,745 gas wells 

EPA 2011 

Inventory 

15.1e

 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. EPA4, 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/ANGA12 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. EPA4 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. EPA4

, 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 estimating 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 the regional estimates (0.73 bcf; 90,000 scf/event, 

8077 events). Regionally averaged emission estimates were used as the central estimate in 

this work because there were differences in the emission factors observed by region and 

because the frequency of U.S. well completion activity (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 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 36% higher than the regional estimates (41.1 bcf; 92,000 scf/device, 447,379 

devices). Regionally averaged emission estimates 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 aggregated by device type, with national emissions estimated by 

multiplying the numbers of devices by the emission factor per device. This approach was not 

used in this work because the EPA national inventory4

 does not report device counts by type, 

and because when device counts by type are reported, 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 that 
S‐63

is identical (to two significant figures) to the regional estimates (15.1 bcf; 33,900 scf/well, 

446,745 wells). 

Measurements made on liquids unloading and workovers, collected as part of this work, were not 

used to develop national emission estimates. 

Workovers For workovers, four events, all done without 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 national inventory, these data were not used to 

estimate emissions for workovers (without hydraulic fracturing) at a national scale. 

Workovers with hydraulic fracturing are a more significant source of estimated emissions, 

accounting for approximately 10% of emissions in the EPA national inventory.4

 The 

emissions associated with flowback from workovers 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 for workovers with hydraulic fracturing 

comparable to the emission factor for completion flowbacks may be appropriate. If the 

emission factor for workovers with hydraulic fracturing 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 reduced by 97%, compared to the current estimate 

in the national emission inventory. This assumption 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 national emission estimate is in reasonable agreement with the EPA 

inventory4

 and the API/ANGA estimate.12 In contrast, another estimate of unloading 

emissions, based on the per event emissions observed 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 lower estimate of unloading emissions could be 

suggested based on national event counts, emission 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 differences 
S‐64

between estimates and measurements, and to better characterize 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 factors, 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 average 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 national average emission factor 

measurement was ±19% 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 (±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 pneumatic controllers (±14% around the midpoint) and 

that the emission factor measurements are independent of the activity data, leads to a net 

uncertainty of ±46% around the midpoint. The overall range for the estimate is 1.8-5.2 bcf with 

a nationally weighted central 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 range of values derived from national and regional estimates (±1% 

around the midpoint) and that the emission factor measurements are independent of the activity 
S‐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 weighted central estimate of 15.1bcf. 

S5.5 Comparisons with National Emission Inventory

The national emission estimates, based on the measurements made in this work, can be compared 

to emissions reported in the EPA’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 reductions and reductions required by regulations. 

All regulatory reductions and some voluntary reductions are assigned 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, combined. In cases such as this, allocation of 

combined reductions was assumed to be proportional to the potential emissions. Specifically, 

since the potential emissions for completion flowbacks 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 scf). This percentage reduction was applied 

uniformly for all of the aggregated source categories. In situations where a source had both 

regulatory and voluntary reductions (e.g., dehydrator vents and condensate tanks), potential 

emissions were first reduced by reductions required 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. This 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 methane per year); source categories labeled in 

gray had aggregated voluntary emission reductions (see text) 

EPA GHG Inventory Activity 

Potential 

Emissions 

(Gg)a

Emission 

Reductions 

(Gg)a

Net 

Emissions 

(Gg) 

Completions with Hydraulic Fracturing 1221b 567b 654 

Refractures (Workovers with hydraulic fracturing) 266b 124b 143 

Pneumatic Device Vents 1,134 779 355 

Chemical Injection Pumps 64 30c 34 

Equipment leaks: Gas Wells without HF 24 11c

172d

Equipment leaks: Gas Wells with HF 28 13c

Equipment leaks: Separators 107 50c

Equipment leaks: Meters/Piping 102 48c

Equipment leaks: Heaters 33 15c

Equipment leaks: Dehydrators 31 15c

Workovers without HF 0.6 0.3c 0.3 

Liquids Unloading (without plunger lifts) 149 0 149 

Liquids Unloading (with plunger lifts) 108 0 108 

Kimray Pumps 365 180 

930e

Condensate Tanks without Controls 261 167c

Condensate Tanks with Controls 52 0 

Gas Engines 276 49 

Dehydrators Vents 114 73c

Small Reciprocating Compressors 68 

Large Reciprocating Compressors 15 35 

Large Reciprocating Stations 1 

Pipeline Leaks 170 80c

Completions without Hydraulic Fracturing 0 0 

Well Drilling 0.8 0.4c

Vessel Blowdowns 0.7 0.3c

Pipeline Blowdowns 3 1c

Compressor Blowdowns 3 1c

Compressor Starts 6 3c

Pressure Relief Valves 0.7 0.3c

Mishaps 2 1c

Emissions from Coalbed Methane and Offshore Production 

Powder River Coal Bed Methane Produced Water 46 21c

Black Warrior Coal Bed Methane Produced Water 13 6c

Offshore Platforms 266 125c

Deepwater Platforms 23 11c

TOTAL 4,949 2,405 2,545 a

Potential emissions data are from U.S. GHG Inventory 13 Annex 3, Table A-134. Emission reductions data are from Tables A132 and A-133.4

b

EPA reports aggregated emission reductions for completions and workovers with hydraulic fracturing. This work divides these 

emission reductions between completions and workovers proportional to their potential 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 proportional 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 small 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 compressors (68 Gg of potential 

emissions minus 29 Gg of reductions assigned to small compressors out of 35 Gg of reductions assigned to all compressors
S‐67

S6 Site Selection and Representativeness 

Methane emissions were measured directly at 190 natural gas production sites in the Gulf 

Coast, Midcontinent, Rocky Mountain and Appalachian 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 the 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 methane 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 efforts, 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 provided sites in each of the regions. 

While the data presented in this report represents one of the most extensive datasets 

available on methane emissions from current natural 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 sampling targets in each area 

 
S‐68

Table S6-1. Sources of CH4 Emissions from Natural Gas Well Sites*, †, § 

(measurements were made for sources shaded light gray; dark gray shading indicates limited measurements) 

* Study scope is limited to CH4 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 sources and other miscellaneous sources: 

flaring, compressor engine exhaust, drill rig engines, 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 CH4 (65%) from the natural gas production stage (onshore and 

offshore).4

 

Activity or Source 

Included in 

Current 

Work? 

Rationale for Inclusion/Exclusion 

Pre-production 

Construction of Well 

site N 

No emissions from the natural gas formation occur during this process. 

Surface construction equipment combustion 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 gas 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 not 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 facilities 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 shaded 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

Appalachian 
S‐70

The nine companies that participated in this study included mid-size and large 

companies. While there are thousands of oil and gas companies in the U.S., and small 

companies were not part of the participants, the 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 National 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 Alaska 

 
S‐71

Regional sampling was done to account for differences in practices that may occur due to 

field or state differences, or practices that may vary even within a company across the U.S. The 

Study Team sampled in four geographical regions (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 company, 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 (Controllers), fugitive leaks, number of geographically 

distinct sites, and number of wells, and production 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 79 
S‐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 provided 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 companies 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 companies 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 different companies. 

The selection of specific sites was randomized to the extent possible. 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 the total number of well completions, nationwide in 

2011, for all the participating companies combined, averaged roughly 10 per day. That meant 

that in any given production region, 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 and tear down by the study team required a day 
S‐73

before and a day after the completion. Unloading, 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 sampling were selected based on proximity to 

completion sampling. Typically, a list of candidate 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 Coast sites, where the study team, based in Austin, 

Texas, could make day trips to production sites. For these sites, the study team randomly 

selected from hundreds of potential sites provided 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 occurring. 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 performed only at a subset of sites. This subset 

was selected based on the expectation of stable, moderate winds at the sites and the availability 

of a dense road network that would allow the van access to downwind sampling points. Based 

on these criteria, the downwind sampling team was tasked to mirror the sampling efforts of the 

direct source measurement team to the extent 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 changes to the U.S. gas production system during the measurement 

effort. The system of wells and oil and gas operations 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 Organic Compound (VOC) controls, in the forms of 

new regulations for National Emission Standards for Hazardous Air Pollutants (NESHAP) and 

New Source Performance Standards (NSPS Part OOOO) that went into effect in 2012 and would 

potentially affect new sources in 2012. The regulations 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 study, 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‐74

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