Oil and Natural Gas Sector Pneumatic 

Devices

Report for Oil and Natural Gas Sector Pneumatic Devices

Review Panel 

April 2014

Prepared by

U.S. EPA Office of Air Quality Planning and Standards (OAQPS)

This information is distributed solely for the purpose of pre-dissemination peer review under applicable 

information quality guidelines. It has not been formally disseminated by EPA. It does not represent and

should not be construed to represent any Agency determination or policy.
ii
iii

Table of Contents

PREFACE....................................................................................................................................... 1

1.0 INTRODUCTION ................................................................................................................. 2

1.1 Definition of the Source .................................................................................................... 2

1.1.1 Pneumatic Controllers.................................................................................................... 2

1.1.2 Pneumatic Pumps........................................................................................................... 4

1.2 Background ....................................................................................................................... 4

1.2.1 Pneumatic Controllers.................................................................................................... 4

1.2.2 Pneumatic Pumps........................................................................................................... 5

1.3 Purpose of the White Paper............................................................................................... 6

2.0 AVAILABLE EMISSIONS DATA AND ESTIMATES ................................................. 6

2.1 Discussion of Data Sources for Pneumatic Controllers .................................................... 7

2.1.1 Methane Emissions from the Natural Gas Industry (GRI/EPA, 1996c) ........................ 8

2.1.2 Estimates of Methane Emissions from the U.S. Oil Industry (ICF Consulting, 1999) 12

2.1.3 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)

13

2.1.4 Greenhouse Gas Reporting Program (U.S. EPA, 2013)............................................... 18

2.1.5 Measurements of Methane Emissions at Natural Gas Production Sites in the United 

States (Allen et al., 2013)............................................................................................. 20

2.1.6 Determining Bleed Rates for Pneumatic Devices in British Columbia (Prasino Group 

2013) 23

2.1.7 Air Pollutant Emissions from the Development, Production, and Processing of 

Marcellus Shale Natural Gas (Roy et al., 2014)........................................................... 25

2.1.8 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. 

Onshore Oil and Natural Gas Industries (ICF, 2014)................................................... 26

2.2 Discussion of Data Sources for Pneumatic Pumps ......................................................... 28
iv

2.2.1 Methane Emissions from the Natural Gas Industry (GRI/EPA, 1996c) (GRI/EPA, 

1996e) 28

2.2.1.1 Methane Emissions from the Natural Gas Industry – Chemical 

Injection Pumps (GRI/EPA, 1996c) ............................................................................. 28

2.2.1.2 Methane Emissions from the Natural Gas Industry – Gas-Assisted 

Glycol Pumps (GRI/EPA, 1996e)................................................................................. 31

2.2.2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)

32

2.2.3 Greenhouse Gas Reporting Program (U.S. EPA, 2013)............................................... 35

2.2.4 Determining Bleed Rates for Pneumatic Devices in British Columbia (Prasino Group 

2013) 35

2.2.5 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. 

Onshore Oil and Natural Gas Industries (ICF, 2014)................................................... 36

3.0 AVAILABLE PNEUMATIC DEVICE EMISSIONS MITIGATION TECHNIQUES ..... 36

3.1 Available Pneumatic Controller Emissions Mitigation Techniques ............................... 36

3.1.1 Zero Bleed Pneumatic Controllers............................................................................... 41

3.1.2 Low Bleed Pneumatic Controllers ............................................................................... 41

3.1.3 Instrument Air Systems................................................................................................ 44

3.1.4 Mechanical and Solar-Powered Systems in Place of Bleed Controller........................ 48

3.1.5 Maintenance of Natural Gas-Driven Pneumatic Controllers ....................................... 50

3.2 Available Pneumatic Pump Emissions Mitigation Techniques ...................................... 50

3.2.1 Instrument Air Pump.................................................................................................... 51

3.2.2 Solar Power Pump........................................................................................................ 54

3.2.3 Electric Power Pumps .................................................................................................. 55

4.0 SUMMARY......................................................................................................................... 56

4.1 Pneumatic Controllers..................................................................................................... 56

4.2 Pneumatic Pumps............................................................................................................ 57
v

5.0 CHARGE QUESTIONS FOR REVIEWERS ..................................................................... 57

6.0 REFERENCES .................................................................................................................... 58
1

PREFACE

On March 28, 2014 the Obama Administration released a key element called for in the 

President’s Climate Action Plan: a Strategy to Reduce Methane Emissions. The strategy 

summarizes the sources of methane emissions, commits to new steps to cut emissions of this 

potent greenhouse gas, and outlines the Administration’s efforts to improve the measurement of 

these emissions. The strategy builds on progress to date and takes steps to further cut methane 

emissions from several sectors, including the oil and natural gas sector. 

This technical white paper is one of those steps. The paper, along with four others, 

focuses on potentially significant sources of methane and volatile organic compounds (VOCs) in 

the oil and gas sector, covering emissions and mitigation techniques for both pollutants. The 

Agency is seeking input from independent experts, along with data and technical information 

from the public. The EPA will use these technical documents to solidify our understanding of 

these potentially significant sources, which will allow us to fully evaluate the range of options 

for cost-effectively cutting VOC and methane waste and emissions.

The white papers are available at: 

www.epa.gov/airquality/oilandgas/whitepapers.html
2

1.0 INTRODUCTION

The oil and natural gas exploration and production industry in the U.S. is highly dynamic 

and growing rapidly. Consequently, the number of wells in service and the potential for greater 

emissions from oil and natural gas sources is also growing. There were an estimated 504,000 

producing gas wells in the U.S. in 2011 (U.S. EIA, 2012a), and an estimated 536,000 producing 

oil wells in the U.S. in 2011 (U.S. EIA, 2012b). It is anticipated that the number of gas and oil 

wells will continue to increase substantially in the future because of the continued and expanding 

use of horizontal drilling combined with hydraulic fracturing (referred to here as simply 

hydraulic fracturing). 

Due to the growth of this sector and the potential for increased air emissions, it is 

important that the U.S. Environmental Protection Agency (EPA) obtain a clear and accurate 

understanding of emerging data on emissions and available mitigation techniques. This paper 

presents the Agency’s understanding of emissions and available emissions mitigation techniques

from a potentially significant source of emissions in the oil and natural gas sector.

1.1 Definition of the Source

The focus of this white paper is natural gas-driven pneumatic controllers and natural gasdriven pneumatic pumps. Such pneumatic controllers and pumps are widespread in the oil and 

natural gas industry and emit natural gas, which contains methane and VOCs. In some 

applications, pneumatic controllers and pumps used in this industry may be driven by gases other 

than natural gas and, therefore, do not emit methane or VOCs. 

1.1.1 Pneumatic Controllers

For the purposes of this white paper, a pneumatic controller means an automated 

instrument used for maintaining a process condition such as liquid level, pressure, pressure

difference and temperature. Based on the source of power, two types of pneumatic controllers are 

defined for this paper:
3

 Natural gas-driven pneumatic controller means a pneumatic controller powered by 

pressurized natural gas.

 Non-natural gas-driven pneumatic controller means an instrument that is actuated using 

other sources of power than pressurized natural gas; examples include solar, electric, and 

instrument air.

Natural gas-driven pneumatic controllers come in a variety of designs for a variety of 

uses. For the purposes of this white paper, they are characterized primarily by their emissions 

characteristics:

 Continuous bleed pneumatic controllers are those with a continuous flow of pneumatic 

supply natural gas to the process control device (e.g., level control, temperature control, 

pressure control) where the supply gas pressure is modulated by the process condition, 

and then flows to the valve controller where the signal is compared with the process setpoint to adjust gas pressure in the valve actuator. For the purposes of this paper, 

continuous bleed controllers are further subdivided into two types based on their bleed 

rate:

o Low bleed, having a bleed rate of less than or equal to 6 standard cubic feet per 

hour (scfh).

o High bleed, having a bleed rate of greater than 6 scfh.

 Intermittent pneumatic controller means a pneumatic controller that vents noncontinuously. These natural gas-driven pneumatic controllers do not have a continuous 

bleed, but are actuated using pressurized natural gas.

 Zero bleed pneumatic controller means a pneumatic controller that does not bleed natural 

gas to the atmosphere. These natural gas-driven pneumatic controllers are self-contained 

devices that release gas to a downstream pipeline instead of to the atmosphere.
4

1.1.2 Pneumatic Pumps

Pneumatic pumps are devices that use gas pressure to drive a fluid by raising or reducing 

the pressure of the fluid by means of a positive displacement, a piston or set of rotating 

impellers. Pneumatic pumps are generally used at oil and natural gas production sites where 

electricity is not readily available (GRI/EPA, 1996d). The supply gas for these pumps can be 

compressed air, but most often these pumps use natural gas from the production stream 

(GRI/EPA, 1996e). 

1.2 Background

1.2.1 Pneumatic Controllers

Pneumatic controllers are automated instruments used for maintaining a process 

condition such as liquid level, pressure, pressure differential, and temperature. In many 

situations, across all segments of the oil and gas industry, pneumatic controllers make use of the 

available high-pressure natural gas to operate control of a valve. In these natural gas-driven

pneumatic controllers, natural gas is released with every actuation of the valve, i.e., valve

movement. In some designs, natural gas is also released continuously from the valve control 

pilot. The rate at which the continuous release occurs is referred to as the bleed rate. Bleed rates 

are dependent on the design and operating characteristics of the device. Similar designs will have 

similar steady-state rates when operated under similar conditions. There are three basic designs

of natural gas-driven pneumatic controllers: (1) continuous bleed controllers are used to 

modulate flow, liquid level, or pressure, and gas is vented continuously at a rate that may vary 

over time; (2) intermittent controllers release gas only when they open or close a valve or as they

throttle the gas flow; and (3) zero bleed controllers, which are self-contained devices that release 

gas to a downstream pipeline instead of to the atmosphere (EPA, 2011a).

As noted above, intermittent controllers are devices that only emit gas during actuation 

and do not have a continuous bleed rate. Thus, the actual amount of emissions from an 

intermittent controller is dependent on the amount of natural gas vented per actuation and how 

often it is actuated. Continuous bleed controllers also vent an additional volume of gas during 
5

actuation, in addition to the device’s continuous bleed stream. Thus, actual emissions from a 

continuous bleed device also depend, in part, on the frequency of activation and the amount of 

gas vented during activation. As the name implies, zero bleed controllers are considered to emit 

no natural gas to the atmosphere (EPA, 2011a). 

In general, intermittent controllers serve functionally different purposes than bleed 

controllers and, therefore, cannot replace bleed controllers in most (but not all) applications.

Furthermore, zero bleed controllers are “closed loop” systems that can be used only in 

applications with very low pressure and therefore may not be suitable to replace continuous 

bleed pneumatic controllers in many applications.

Non-natural gas-driven pneumatic controllers can be used in some applications. These 

controllers can be mechanically operated or use sources of power other than pressurized natural 

gas, such as compressed “instrument air.” Instrument air systems are feasible only at oil and 

natural gas locations that have electrical service sufficient to power an air compressor. At sites 

without electrical service sufficient to power an instrument air compressor, mechanical or 

electrically powered pneumatic controllers can be used. Non-natural gas-driven controllers do 

not directly release methane or VOCs, but may have secondary impacts related to generation of 

required electrical power (EPA, 2011a).

1.2.2 Pneumatic Pumps

There are two types of pneumatic pumps that are commonly used in the oil and natural 

gas sector: piston and diaphragm (GRI/EPA, 1996d). These pumps have two major components,

a driver side and a motive side, which operate in the same manner but with different 

reciprocating mechanisms. Pressurized gas provides energy to the driver side of the pump, which 

operates a piston or flexible diaphragm to draw fluid into the pump. The motive side of the pump 

delivers the energy to the fluid being moved in order to discharge the fluid from the pump. The 

natural gas leaving the exhaust port of the pump is either directly discharged into the atmosphere 

or is recovered and used as a fuel gas or stripping gas (GRI/EPA, 1996d).
6

The majority of pneumatic pumps used in oil and natural gas production are used for 

chemical injection or glycol circulation (GRI/EPA, 1996d). Pneumatic pumps used for chemical 

injection are needed in oil and natural gas production to inject small amounts of chemicals to 

limit processing problems and protect equipment. Typical chemicals that are injected into the 

process include: biocides, demulsifiers, clarifiers, corrosion inhibitors, scale inhibitors, hydrate 

inhibitors, paraffin dewaxers, surfactants, oxygen scavengers and hydrogen sulfide scavengers 

(GRI/EPA, 1996d). These chemicals are normally injected using pneumatic pumps at the 

wellhead, and into gathering lines or at production separation facilities (GRI/EPA, 1996d). 

Pneumatic pumps, commonly referred to as “Kimray” pumps, used for glycol circulation recover 

energy from the high-pressure rich glycol/gas mixture leaving the absorber and use that energy to 

pump the low-pressure lean glycol back into the absorber (GRI/EPA, 1996e).

1.3 Purpose of the White Paper

This white paper provides a summary of the EPA’s understanding of the emissions from 

natural gas-driven pneumatic controllers and pumps in the oil and natural gas sector, the 

mitigation techniques available to reduce these emissions, the efficacy of these techniques and 

the prevalence of these techniques in the field. Section 2 of this document provides the EPA’s

understanding of emissions from pneumatic controllers and pumps, and Section 3 provides our 

understanding of available mitigation techniques. Section 4 summarizes the EPA’s 

understanding based on the information presented in Sections 2 and 3, and Section 5 presents a 

list of charge questions for reviewers to assist the EPA with obtaining a more comprehensive 

understanding of pneumatic controller and pump VOC and methane emissions and emission 

mitigation techniques.

2.0 AVAILABLE EMISSIONS DATA AND ESTIMATES

There are a number of studies that have been published that have estimated VOC and 

methane emissions from pneumatic controllers and pneumatic pumps in the oil and natural gas 

sector. These studies have used different methodologies to estimate these emissions including the 

use of equipment counts and emission factors and direct measurement of emissions. Section 2.1 

discusses the studies relevant to pneumatic controllers, and Section 2.2 discusses the studies 
7

relevant to pneumatic pumps. These studies are listed in Table 2-1, along with an indication of 

the type of information contained in the study.

Table 2-1. Summary of Major Sources of Pneumatic Controller and Pump Information

Report Name Affiliation

Year of 

Report

Activity 

Factor

Pneumatic 

Controllers

Pneumatic 

Pumps

Methane Emissions from the 

Natural Gas Industry (GRI/EPA, 

1996c)

Gas 

Research 

Institute / 

EPA

1996 Nationwide X X

Estimates of Methane Emissions 

from the U.S. Oil Industry (ICF 

Consulting, 1999)

EPA 1999 Nationwide X

Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2012

(U.S. EPA, 2014)

EPA 2014

Nationwide/

Regional X X

Greenhouse Gas Reporting 

Program (U.S. EPA, 2013) EPA 2013 Basin X X

Measurements of Methane 

Emissions from Natural Gas 

Production Sites in the United 

States (Allen et al., 2013)

Multiple 

Affiliations, 

Academic 

and Private

2013 Nationwide X

Determining Bleed Rates for 

Pneumatic Devices in British 

Columbia (Prasino, 2013)

The Prasino 

Group 2013 British Columbia X

Air Pollutant Emissions from the 

Development, Production, and 

Processing of Marcellus Shale 

Natural Gas (Roy et al., 2014)

Carnegie 

Mellon 

University

2014

Regional 

(Marcellus 

Shale)

X

Economic Analysis of Methane 

Emission Reduction Opportunities 

in the U.S. Onshore Oil and 

Natural Gas Industries (ICF, 2014)

ICF 

International 2014 Nationwide X X

2.1 Discussion of Data Sources for Pneumatic Controllers

This section presents and discusses pertinent studies and data sources that estimate 

emissions from pneumatic controllers.
8

2.1.1 Methane Emissions from the Natural Gas Industry (GRI/EPA, 1996c)

This report’s main objective was to quantify annual methane emissions from pneumatic

controllers from the natural gas production, processing, transmission, and distribution sectors.

The methane emissions were determined by developing average annual emissions factors for the 

various types of pneumatic controllers used in each of the natural gas segments. The annual 

emission factors were then extrapolated to a national estimate using activity factors for each of 

the natural gas segments.

Production

The data used to develop emission factors for pneumatic controllers in the natural gas 

production sector were obtained from a study performed by the Canadian Petroleum Association 

(CPA)1, manufacturers’ data, measured emission rates2, data collected from site visits, and

literature data for methane composition. 

The CPA study consisted of methane and VOC emission measurements from pneumatic 

controllers in two types of service: 19 in on/off service and 16 in throttling service.

3

The CPA 

study determined the average natural gas emission rate for on/off controllers was 213 standard 

cubic feet per day per device (scfd/device), and the average natural gas emission rate for 

throttling controllers was 94 scfd/device. For throttling controllers, the CPA study did not 

distinguish between the throttling controllers with intermittent bleed rates and throttling 

controllers with continuous bleed rates. In addition, only one throttling controller actuated during 

the emission measurement. Therefore, these measurements are lower in comparison to field 

measurements of similar devices in the U.S. (GRI/EPA, 1996c).

 

1

Picard, D.J., B.D. Ross, and D.W.H. Koon, A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil 

and Gas Operations in Alberta. Canadian Petroleum Association, Calgary, Alberta, 1992.

2

Controller survey data provided by Tenneco Gas Transportation, 1994 and Chevron, 1995.

3

Controllers in on/off service wait until a specific set point is reached before actuating (e.g., a high or low liquid 

level). Controllers in throttling service maintain a desired set point (e.g., pressure).
9

The manufacturers’ data were obtained from four manufacturers of pneumatic controllers 

and were based on laboratory testing of new controllers. The manufacturers’ noted that emissions 

in the field can be higher due to operating condition, age, and wear of the device. The gas 

consumption rates for the manufacturers’ pneumatic controllers ranged from 0 to 2,150 scfd. The 

manufacturers noted that the emissions from these controllers in the field may be higher than the 

reported maximum value (GRI/EPA, 1996c). 

The measured emissions data4 were collected by connecting a flow meter to the supply 

line between the pressure regulator and the controller to measure the gas consumption of the 

controller. The duration of the test depended on the operating conditions. For steady operating 

conditions, one data point was measured for 15-20 minutes. For variable operating conditions,

several one-hour measurements were taken. The data set contained a total of 41 measurements 

from a combination of continuous bleed controllers from offshore and onshore production sites 

and transmission stations. The average gas emissions rates for continuous bleed controllers were 

determined to be 872 scfd/device for onshore and offshore production sites and 1,363 scfd/device 

for transmission stations.

The measured emission data5also provided data for intermittent bleed controllers that

were measured using the same techniques that were used for the continuous bleed pneumatic 

controllers. A total of seven measurements were performed on intermittent bleed controllers

located at onshore natural gas production sites. No measurements were available for intermittent 

bleed controllers in the offshore or transmission segments. The average natural gas emission rate 

for the intermittent pneumatic controllers was determined to be 511 scfd/device.

Site visit data were collected from a total of 22 sites to determine the number of 

pneumatic controllers located at natural gas production sites, and to determine the fraction of 

these controllers that were intermittent or continuous bleed. The study determined that 65% of 

 

4

Controller survey data provided by Tenneco Gas Transportation, 1994 and Chevron, 1995.

5

Controller survey data provided by Tenneco Gas Transportation, 1994 and Chevron, 1995.
10

the pneumatic controllers were intermittent bleed and 35% of the pneumatic controllers were 

continuous bleed.

The measured emission data, the CPA study emissions data, and the pneumatic controller

counts were used to develop a single emission factor for a “generic” pneumatic device. For the 

production segment, the “generic” pneumatic controller emission factor was calculated using:

 323 scfd/device for intermittent bleed controllers,

 654 scfd/device for continuous bleed controllers,

 a methane content of 78.8%, and 

 the ratio of intermittent bleed to continuous bleed controllers at natural gas 

production sites. 

The “generic” emission factor was determined to be 345 scfd/device of methane for a 

pneumatic controller at natural gas production sites.

Transmission

The transmission “generic” emission factor was calculated using data from three types of 

gas-operated pneumatic controllers: continuous bleed controllers and two types of intermittent 

bleed controllers used to operate isolation valves6(isolation valves with turbine operators and 

isolation valves with displacement-type pneumatic/hydraulic operators). The continuous bleed 

emission factor was obtained from the transmission station measured emission data, which was 

determined to be 1,363 scfd/device. The isolation valve with displacement-type 

pneumatic/hydraulic operators emission factor was determined using data provided by Shafer 

Valve Operating Systems7,8and the count of the isolation valves at four sites. Using these data, 

 

6

Isolation valves at transmission stations are very large and are most often actuated either pneumatically or by 

electric motor. Isolation valve pneumatic controllers only discharge gas when they are actuated and are considered 

to be intermittent.

7

Shafer Valve Operating Systems. Gas Consumption Calculation Method for Rotary Vane, Gas/Hydraulic 

Actuators. Technical Bulletin Data, Bulletin GC-00693. June 1993.
11

the average annual emission factor was determined to be 5,627 standard cubic feet per year per 

device (scfy/device). For turbine-operated isolation valves, the natural gas emissions were 

estimated using information provided by Limitorque Corporation9and information from two

transmission sites. This information was used to calculate an emission factor of 67,599

scfy/device. The above emission factors, a methane content of 93.4% and proportions of each of 

these controllers at transmission sites was used to calculate a “generic” emission factor of 

162,197 scfy/device of methane for pneumatic controllers at transmission stations.

Processing

The site visit information from nine natural gas processing plants found that plants used

compressed air to operate the majority of pneumatic controllers at the plants. Only one of the 

plants used natural gas-powered continuous bleed controllers, and five had natural gas-driven 

pneumatic controllers for the isolation valves on the main pipeline emergency shutdown system 

or isolation valves used for maintenance. The same type of pneumatic controllers used in the 

transmission sector are used at natural gas processing sites; therefore, the same emission factors 

were used to calculate a facility pneumatic emission factor. Using the survey data and the 

transmission sector pneumatic controller emission factors, the annual methane emissions were 

determined to be 165 thousand standard cubic feet per facility (Mscfy/facility).

Summary

A summary of the pneumatic controller emission factors, activity factors, and annual 

methane emission rates estimated by this report are provided in Table 2-2 for the natural gas 

production, processing and transmission segments. The total methane emissions from pneumatic 

controllers was estimated to be 45,634 million standard cubic feet per year (MMscfy) or 861,704 

metric tons (MT).

 

8

Shafer Valve Operating Systems. Gas Consumption Calculation Method for Rotary Vane, Gas/Hydraulic 

Actuators. Technical Bulletin Data, Bulletin GC-2-00394. March 1994.

9

Personal correspondence with Belva Short of Limitorque Corporation, Lynchburg, VA, April 5, 1994.
12

Table 2-2 GRI Nationwide Pneumatic Controller Methane Emissions in the United States

(1992 Base Year)

Natural gas 

Segment

Methane 

Emission Factor Activity Factor

Annual 

Methane 

Emission Rate 

(MMscf/yr)

Annual 

Methane 

Emission Rate 

(MT)

Production 125,925 

scfy/device

249,111 

controllers 31,369 592,349

Processing 165,000 

scfy/facility 726 facilities 120 2,262

Transmission 162,197 

scfy/device

87,206 

controllers 14,145 267,093

Total 45,634 861,704

2.1.2 Estimates of Methane Emissions from the U.S. Oil Industry (ICF Consulting, 1999)

ICF Consulting (ICF Consulting, 1999) prepared a report for the EPA that estimated 

methane emissions from crude oil production, transportation and refining, identified potential 

methane mitigation techniques and provided an analysis of the economics of reducing methane 

emissions. The report estimated that 97% of the annual methane emissions occur during crude oil 

production (59.1 billion cubic feet, Bcf or 1,116,000 MT) in 1995. The transportation and 

refining sectors generate 0.3 Bcf (5,700 MT) and 1.3 Bcf (24,500 MT) of the annual methane 

emissions, respectively. The annual methane emissions were estimated using methane emission 

factors and activity factors to calculate the annual methane emissions from the oil industry.

In the production segment, annual vented methane emissions from 13 sources account for 

91% (53.8 Bcf or 1,016,000 MT) of the total 1995 methane emissions from crude oil production. 

Two of these sources: high bleed pneumatic controllers and low bleed pneumatic controllers

account for 37% (19.9 Bcf or 376,000 MT) and 7% (3.7 Bcf or 69,900 MT) of the annual vented 

methane emissions, respectively. 
13

The high bleed pneumatic controller methane emissions were calculated using an 

emission factor of 345 scfd (GRI/EPA, 1996c). The activity factor for high bleed pneumatic 

controllers was determined to be 157,581 and assumes that tank batteries with heater treaters 

have four pneumatic controllers (three level controllers and one pressure controller). Tank 

batteries without heater treaters were assumed to have three pneumatic controllers. In addition, it 

was assumed that 35% of the total pneumatic controllers were high bleed, which is based on the 

percentage of continuous bleed pneumatic controllers determined in the GRI/EPA study 

(GRI/EPA, 1996c).

The low bleed pneumatic controller methane emission factor was estimated to be 10% of 

the high bleed methane emission factor or 35 scfd.

10 The activity factor for low bleed controllers

was calculated to be 292,650 controllers and was determined using the assumption that 65% of 

the total pneumatic controllers are intermittent bleed (GRI/EPA, 1996c), which this report 

assumed to be low bleed pneumatic devices.

No methane emissions from pneumatic controllers were estimated in this report for the 

transportation and refining segments of the oil industry.

2.1.3 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)

The EPA leads the development of the annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks (GHG Inventory). This report tracks total U.S. greenhouse gas (GHG) 

emissions and removals by source and by economic sector over a time series, beginning with 

1990. 

The U.S. submits the GHG Inventory to the United Nations Framework Convention on 

Climate Change (UNFCCC) as an annual reporting requirement. The GHG Inventory includes 

estimates of methane and carbon dioxide for natural gas systems (production through 

distribution) and petroleum systems (production through refining). 

 

10 EPA Natural Gas STAR default value for low bleed pneumatic controllers.
14

Table 2-3 summarizes the 2014 GHG Inventory’s (published in 2014; containing 

emissions data for 1990-2012) estimates of 2012 national methane emissions from pneumatic 

controllers in the natural gas production, processing, transmission and storage segments and the 

petroleum production segment. Where presented in the GHG Inventory, the table includes 

potential emissions (i.e., emissions that would be released in the absence of controls), emission 

reductions and net emissions. For pneumatic controllers, the emission reductions reported to the 

Natural Gas STAR program are deducted from potential emission to calculate net emissions. In 

future years, the GHG Inventory will also account for regulatory reductions impacting emissions 

from pneumatic controllers that result from subpart OOOO.

Table 2-3. Summary of GHG Inventory 2012 Nationwide Emissions from 

Pneumatic Controllers

Industry Segment

Potential 

CH4

Emissions 

(MT)

CH4

Emission 

Reductions

(MT)

Net CH4

Emissions 

(MT)

Natural gas and petroleum productiona1,642,622 873,100 769,522

Natural gas processing 1,923 b b

Natural gas transmission and storage 263,561 14,078 249,483

a

In the GHG Inventory, all Natural Gas STAR reductions for pneumatic devices are removed from the 

natural gas systems estimate. As some of these reductions likely occur in petroleum systems, a 

combined number for production segment pneumatic devices in natural gas and petroleum systems is 

presented here.

b The GHG Inventory does not include a specific emission reduction for pneumatic controllers in the 

natural gas processing sector resulting from the Natural Gas STAR program although it is likely nonzero. 

The GHG Inventory data estimates that pneumatic controller emissions are 13% of 

overall methane emissions from the oil and natural gas sectors. The following sections provide 

greater detail on the estimates given in Table 2-3.

2.1.3.1 Natural gas and petroleum production industry segment

Table 2-4 shows the 2014 GHG Inventory’s estimates of 2012 methane emissions from 

pneumatic controllers in the natural gas and petroleum production industry segment. The table 
15

presents the population of pneumatic controllers, methane emission factors, potential methane 

emissions, and the estimated national total of pneumatic controllers and potential methane 

emissions. The natural gas production data are broken down by the Energy Information 

Agency’s (EIA’s) National Energy Modeling System (NEMS) regions. The table also presents 

the national total of methane emission reductions compiled from Natural Gas STAR reports and 

the resulting estimated national net methane emissions from pneumatic controllers.

Table 2-4. Estimated 2012 National and Regional Methane Emissions from Pneumatic 

Controllers in the Natural Gas and Petroleum Production Segment

NEMS Region

Population of 

Pneumatic 

Controllersa

CH4 Potential 

Emission Factor

(scfd/device)

a

CH4 Emissions

(MT)

Potential Emissions-Natural Gas Systems

North East 77,261 373 202,696

Midcontinent 167,589 362 426,133

Rocky Mountain 122,127 339 291,166

South West 55,095 353 136,534

West Coast 2,098 402 5,933

Gulf Coast 53,436 386 145,057

Total 477,606 1,207,519

Potential Emissions-Petroleum Systems 

High Bleed 145,179 330 336,692

Low Bleed 269,618 52 98,411

Total 414,797 435,103

Combined Natural Gas and Petroleum Systems

Total 892,403 1,642,622

Voluntary Emission Reductions-Natural Gas and Petroleum 873,100

Net Emissions-Natural Gas and Petroleumb769,522

a

1996 GRI/EPA report, extrapolated using ratios relating other factors for which activity data are available.

b

In the GHG Inventory, all Natural Gas STAR reductions for pneumatic devices are removed from the natural gas 

systems estimate. As some of these reductions likely occur in petroleum systems, a combined number for 

production segment pneumatic devices in natural gas and petroleum systems is presented here.
16

Recent national activity data on pneumatic controllers are not available. To calculate 

national emissions for these sources for the GHG Inventory, a set of industry activity data drivers 

was developed and used to update activity data. For the natural gas production segment, 

pneumatic controllers were estimated each year by applying a regional factor for the number of 

pneumatic controllers per well to annual regional data on gas well population. These factors 

ranged from 0.5 to 1.6 pneumatic controllers per well. For the petroleum production segment, 

pneumatic controllers were estimated each year by applying a factor for the number of pneumatic 

controllers per heater/treater (4), and pneumatic controller per battery without a heater/treater (3).

The basis for the GHG Inventory’s potential methane emission factors for pneumatic 

controllers in the natural gas and petroleum production industry segment is the 1996 GRI/EPA 

report. The factor for natural gas systems represents a mix of the average emissions from 

continuous bleed and intermittent natural gas-driven pneumatic controllers in the 1996 GRI/EPA 

report. The region-specific factors are developed using the GRI/EPA factor and regional gas 

composition data. For petroleum systems, it was then assumed that 65% of pneumatic controllers 

in the petroleum production segment are low bleed pneumatic controllers, and 35% of controllers 

are high bleed. The GRI/EPA factors for low and high bleed controllers are applied to these 

populations 

According to the GHG Inventory, the 1996 GRI/EPA report “still represents the best 

available [emissions] data in many cases, [but] using these emission factors alone to represent 

actual emissions without adjusting for emissions controls would in many cases overestimate 

emissions. For this reason, ‘potential emissions’ are calculated using the [1996 GRI/EPA report]

data, and then current data on voluntary and regulatory emission reduction activities are deducted 

to calculate actual emissions.”

In the case of pneumatic controllers in the natural gas production industry segment, the 

GHG Inventory reduces the calculated potential emissions using voluntary emission reductions 

reported by industry partners to the Natural Gas STAR Program. The reductions undergo quality 

assurance and quality control checks to identify errors, inconsistencies, or irregular data before 
17

being incorporated into the GHG Inventory. Future inventories are expected to reflect the subpart 

OOOO requirements for pneumatic controllers as they are implemented.

2.1.3.2 Natural gas processing industry segment

Table 2-5 shows the 2014 GHG Inventory’s estimates of 2012 methane emissions from 

pneumatic controllers in the natural gas processing industry segment.

Table 2-5. Estimated 2012 National Methane Emissions from Pneumatic Controllers in the 

Natural Gas Processing Segment

Activity Factor

CH4 Potential 

Emission Factor

(scfy/plant)b

CH4 Potential 

Emissions (MT)

CH4 Emission 

Reductions

(MT)

Net CH4

Emissions (MT)

606 gas plantsa164,721 1,923

c c

a Oil and Gas Journal, with available 2012 activity data.

b

1996 GRI/EPA report.

c Although voluntary Natural Gas STAR emission reductions are reported for this industry segment in the aggregate, 

no value is given specifically for pneumatic controllers.

The basis for the GHG Inventory’s potential methane emission factors for pneumatic 

controllers in the natural gas processing segment is the 1996 GRI/EPA report. This potential 

emission factor is expressed in terms of standard cubic feet per year per processing plant 

(scfy/plant). The associated activity factor is the number of U.S. gas plants, which comes from 

the Oil and Gas Journal.

The GHG Inventory does not report emissions reductions specific to pneumatic 

controllers in this industry segment and, thus, there is no reported net emissions figure.

2.1.3.3 Natural gas transmission and storage segment

Table 2-6 shows the 2014 GHG Inventory’s estimates of 2012 methane emissions from 

pneumatic controllers in the natural gas transmission and storage industry segment.
18

Table 2-6. Estimated 2012 National Methane Emissions from Pneumatic Controllers in the 

Natural Gas Transmission and Storage Segment

Subsegment

Activity 

Factor (# of 

controllers)

CH4 Potential 

Emission Factor

(scfy/device)

CH4

Potential 

Emissions

(MT)

CH4

Emission 

Reductions

(MT)

Net CH4

Emissions

(MT)

Transmission 70,827 162,197a221,257

Storage 13,542 162,197a42,304

Total 84,369 263,561 -14,078b249,483

a

1996 GRI/EPA report.

b Voluntary Natural Gas STAR emission reductions are reported for all pneumatic controllers in this industry 

segment, not split out by transmission and storage.

The basis for the GHG Inventory’s potential methane emission factors for pneumatic 

controllers in the natural gas transmission and storage segment is the 1996 GRI/EPA report. In 

this case, the potential emission factor is expressed in terms of scfy/device. The associated 

activity factor is the number of pneumatic controllers. For transmission, the number of 

pneumatic controllers is calculated based on transmission pipeline length. For storage, the 

number of pneumatic controllers is calculated based on number of compressor stations in the 

storage segment.

The 2014 GHG Inventory includes voluntary emission reductions reported by industry 

partners to the Natural Gas STAR Program for pneumatic controllers in the natural gas 

transmission and storage industry segment.

2.1.4 Greenhouse Gas Reporting Program (U.S. EPA, 2013)

In October 2013, the EPA released 2012 GHG data for Petroleum and Natural Gas 

Systems collected under the Greenhouse Gas Reporting Program (GHGRP). The GHGRP, which 

was required by Congress in the FY2008 Consolidated Appropriations Act, requires facilities to 

report data from large emission sources across a range of industry sectors, as well as suppliers of 

certain GHGs and products that would emit GHGs if released or combusted. 
19

When reviewing this data and comparing it to other data sets or published literature, it is 

important to understand the GHGRP reporting requirements and the impacts of these 

requirements on the reported data. The GHGRP covers a subset of national emissions from 

Petroleum and Natural Gas Systems; a facility in the Petroleum and Natural Gas Systems source 

category is required to submit annual reports if total emissions are 25,000 MT of CO2 equivalent 

(MT CO2e) or more. Facilities use uniform methods prescribed by the EPA to calculate GHG 

emissions, such as direct measurement, engineering calculations, or emission factors derived 

from direct measurement. In some cases, facilities have a choice of calculation methods for an 

emission source.

The GHGRP addresses petroleum and natural gas systems with implementing regulations 

at 40 CFR part 98, subpart W. The rules define three segments of the oil and natural gas industry 

sector that are required to report GHG emissions from pneumatic controllers: (1) onshore 

petroleum and natural gas production, (2) onshore natural gas transmission compression, and 

(3) underground natural gas storage. Facilities calculate emissions from pneumatic controllers by 

determining the number of each type of controller at the facility and applying emission factors. 

In the petroleum and natural gas production segment, facilities must apply facility-specific gas 

composition factors for methane and CO2. In the natural gas transmission and storage segments, 

default gas composition factors are used. Subpart W emission factors for pneumatic controllers 

are located at 40 CFR Part 98, subpart W, Table W-1A (Onshore Petroleum and Natural Gas 

Production), Table W-3 (Onshore Natural Gas Transmission Compression), and Table W-4 

(Underground Natural Gas Storage). These emission factors are based on the 2009 document 

Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry

published by the American Petroleum Institute (API), which in turn is based on the 1996 

GRI/EPA report. 
20

Table 2-7 shows the number of reporting facilities11 in each of the three industry 

segments, along with reported pneumatic controller methane emissions.

Table 2-7. Facilities and Reported Emissions from Pneumatic Controllers, 2012

Segment

Number of 

Reporting 

Facilities 

Reported Methane 

Emissions (MT)a

Petroleum and NG 

Production 

417 861,224

Transmission 330 7,582

Storage 38 4,493

a The reported methane MT CO2e emissions were converted to methane emissions in MT by dividing 

by a global warming potential (GWP) of methane (21).

2.1.5 Measurements of Methane Emissions at Natural Gas Production Sites in the United States 

(Allen et al., 2013)

A study completed by multiple academic institutions and consulting firms was conducted 

to gather methane emissions data at onshore natural gas sites in the U.S. and compare those 

emission estimates to the 2011 estimates reported in the 2013 GHG Inventory. The sources or 

operations tested included 305 pneumatic controllers located at 150 distinct natural gas 

production sites in four production regions (Appalachian, Gulf Coast, Midcontinent, and Rocky 

Mountain).

Testing was carried out using a Hi-Flow Sampler, which is a portable, 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. To allow the quantity of methane to be separated out from other chemical 

 

11 In general, a “facility” for purposes of the GHGRP means all co-located emission sources that are commonly 

owned or operated. However, the GHGRP has developed a specialized facility definition for onshore production. 

For onshore production, the “facility” includes all emissions associated with wells owned or operated by a single 

company in a specific hydrocarbon-producing basin (as defined by the geologic provinces published by the 

American Association of Petroleum Geologists).
21

species, gas composition data were collected for each natural gas production site, typically

provided by the site owner. The 305 sampled pneumatic controllers represented an estimated 

41% of all the controllers associated with the wells that were sampled. The sampling time for 

each controller was not specified in the study. Table 2-8 shows the emission rates determined by 

the testing.

Table 2-8. Pneumatic Controller Methane Emission Rates Reported in the Allen Study

Methane Emissions per Pneumatic Controller

Appalachian Gulf Coast Midcontinent Rocky Mtn. Total

Number sampleda

133 106 51 15 305

Emissions rate (scf 

methane/min/device)b 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)

b

0.130 ± 0.044 0.289 ± 0.071 0.172 ± 0.086 0.021 ± 0.022 0.187 ± 0.036

a

Intermittent and low bleed controllers are included in the total; no high bleed controllers were reported by 

companies providing controller type information

b Uncertainty characterizes the variability in the mean of the data set, rather than an instrumental uncertainty in a

single measurement

The Allen study reports that the average whole gas emission rate was 11.2 scfh per 

pneumatic controller for the tested population, which consisted of a mix of intermittent and low 

bleed controllers. No high bleed controllers were reported by the companies that provided 

controller type information. The study also reports whole gas emission factors of 5.1 scfh for low 

bleed controllers and 17.4 scfh for intermittent controllers. These emission factors are based on 

measured emissions at the 24 sites where the site operators reported only low bleed controllers 

and the 55 sites reporting only intermittent controllers, where potential misidentification of 

controller type is less likely to be a confounding factor. 

The study notes that 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 the Rocky 

Mountain and Appalachian regions. The difference in average values is more than a factor of 10
22

between Rocky Mountain and Gulf Coast regions. The study provided the following discussion 

of these differences:

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. Wellhead and 

separator pressure were also not good predictors of emissions. The definition of 

low-bleed controllers may be [an] 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.

The study estimated 2011 national methane emissions from pneumatic controllers in the 

natural gas production industry segment at 570,000 MT (with a range of 510,000 – 812,000 MT 

based on the 95% confidence bounds of the emission factor) using the same number of 

controllers (447,379) used in the 2013 GHG Inventory for 2011. This estimate was computed 

using a regionally weighted emission factor of 67,400 scfy methane/device. 
23

2.1.6 Determining Bleed Rates for Pneumatic Devices in British Columbia (Prasino Group 

2013)

A study completed by the Prasino Group was conducted to determine the average bleed 

rate of pneumatic controllers when operating under field conditions in British Columbia (BC). 

Bleed rates were sampled from pneumatic controllers using a positive displacement bellows

meter at upstream oil and gas facilities across a variety of producing fields in the Fort St. John, 

BC and surrounding areas. For this study, bleed rate was defined as “the amount of fuel gas 

released to the atmosphere per hour,” including both continuous bleed (where applicable) and 

emissions during activation. The study centered on high bleed controllers, including both 

continuous bleed and intermittent controllers with emissions greater than 0.17 cubic meters per 

hour (m3/hr) (e.g, > 6 scfh).12 The study aimed to identify the most common high bleed 

pneumatic controllers in the field and test emissions from at least 30 units of each model. In 

identifying controllers to test, the study used a manufacturer-supplied emission rate of 0.119 

m

3

/hr as a cutoff to explore whether some models identified by manufacturers as low bleed 

perform at that level in the field.

Field measurements were carried out with a Calscan Hawk 9000 Vent Gas Meter, which

uses a positive displacement diaphragm meter that detects flow rates down to zero, and can also 

effectively measure any type of vent gas (methane, air, or propane). (A few sampled devices ran 

on air at large sites using compressed air, or propane at sour sites using compressed propane; 

such samples were corrected using a density ratio to equivalent natural gas emissions rates.) This 

device uses “a precision pressure sensor, an external temperature probe, and industry standard 

gas flow measurement algorithms to accurately measure the gas rates and correct for pressure 

and temperature differences.” The report notes that metering a device can affect the operation of 

the device when hooked up due to back pressure, adding that it is possible that certain controllers 

did not produce enough pressure when hooked up to overcome the back pressure, resulting in a 

 

12 This definition of “high bleed” is slightly different than the definition presented in Section 1.1.1 of this paper, 

because “intermittent bleed controllers” are included as “high bleed controllers” if their emissions are above the 

specified threshold. The definition presented in Section 1.1.1 places “intermittent bleed controllers” in their own 

category. 
24

zero reading. The sample time for each controller was 30 minutes, so there was variability in the 

number of actuation events captured for each controller depending on operating conditions.

In addition to emission factors for individual models of pneumatic controllers, the study 

generated emission factors for “generic high bleed controllers” and “generic high bleed 

intermittent controllers.” The study also included a regression analysis of the relationship 

between bleed rate and the pressure of the supply gas routed to the controller. Based on the 

analysis, the study found that the positive relationship between these parameters was strong 

enough to recommend use of a supply pressure coefficient to calculate the bleed rate for several 

controller models and for generic controllers. The generic emission factors and supply pressure 

coefficients are shown in Table 2-9.

Table 2-9. Generic Natural Gas Emission Factors and Supply Pressure Coefficients for 

High Bleed Pneumatic Controllers

Type of Pneumatic Controller

Average Bleed 

Rate (m

3

/hr)

a

Average Bleed 

Rate (scfh)

b

Coefficient Related 

to Supply Pressurec

Generic High Bleed Controller 0.2605 9.199 0.0012

Generic High Bleed Intermittent Controller 0.2476 8.744 0.0012

a

“Bleed rate” defined to include actuation emissions as well as continuous bleed.

b Calculated.

c

Supply pressure apparently in kPa, although not clearly stated in the report.

Based on what it termed a “positive correlation,” the Prasino study recommended the use 

of the supply pressure coefficients above for calculating emission rates for generic high bleed 

controllers and generic high bleed intermittent controllers. It should be noted that the coefficients 

of determination (R2values) for these supply pressure coefficients are 0.41 and 0.35 for high 

bleed and high bleed intermittent controllers, respectively.
25

2.1.7 Air Pollutant Emissions from the Development, Production, and Processing of Marcellus 

Shale Natural Gas (Roy et al., 2014)

A study by the Center for Atmospheric Particle Studies at Carnegie Mellon University

was conducted to develop an emission inventory for the development, production, and 

processing of natural gas in the Marcellus Shale region for 2009 and 2020. (Note: The focus of 

this white paper is current emissions, therefore, the 2020 projections are not discussed further.) 

The inventory includes estimates for emissions of nitrogen oxides, VOC, and particulate matter 

less than 2.5 micrometers in diameter from major activities, including VOC emissions from 

pneumatic controllers associated with “wet” and “dry” gas wells. The study estimated VOC 

emissions from pneumatic controllers associated with Marcellus Shale natural gas wells to be on 

the order of 10 tons/day in 2009.

This study developed these emissions estimates by estimating the number of wet and dry 

wells in the region and establishing per-well emission factors for 2009. The per-well emission 

factors are shown in Table 2-10.

Table 2-10. Per-Well VOC Emissions from Pneumatic Controllers in 2009 (95% confidence 

interval)

Type of Well

VOC Emissions, 2009

(tons/producing well)

Dry Gas 0.5 (0.08 – 0.8)

Wet Gas 3.5 (2.4 – 4.4)

The per-well emission factors were based on assumptions regarding the type, number, 

and emission factors for pneumatic controllers associated with each natural gas well, which were 

drawn primarily from a 2008 ENVIRON report.13 Table 2-11 shows these assumptions.

 

13 Bar-Ilan, Amnon et al., ENVIRON International Corporation. Recommendations for Improvement to the 

CENRAP States’ Oil and Gas Emissions Inventories. Prepared for the Central States Regional Air Partnership. 

November 13, 2008. This report also includes emission factors for positioners (15.2 scfh) and transducers 
26

Table 2-11. Assumed Type, Number, and Emission Factors for Pneumatic Controllers 

Associated with Each Natural Gas Well

Type of Device

Number of 

Controllers Emission Factor (scfh)

a

Liquid Level 

Controller 2 31 (2009)

Pressure Controller 1 17 (2009)

a

2009 emission factors are from the 2008 ENVIRON report.

The emission factors from this study and the ENVIRON report are not comparable to the 

emission factors discussed above because they are provided for different classifications of 

pneumatic controllers. In addition, these emission factors differ from those discussed previously 

in that they are based on bleed rates provided by manufacturers rather than measured emissions.

2.1.8 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore 

Oil and Natural Gas Industries (ICF, 2014)

The Environmental Defense Fund (EDF) commissioned ICF International (ICF) to 

conduct an economic analysis of methane emission reduction opportunities from the oil and 

natural gas industry to identify the most cost-effective approach to reduce methane emissions 

from the industry. The study projects the estimated growth of methane emissions through 2018 

and focuses its analysis on 22 methane emission sources in the oil and natural gas industry 

(referred to as the targeted emission sources). These targeted emission sources represent 80% of 

their projected 2018 methane emissions from onshore oil and gas industry sources. Pneumatic 

devices are several of the 22 emission sources that are included in the study and include: high 

bleed pneumatic controllers, intermittent bleed pneumatic controllers, Kimray pumps, 

intermittent bleed pneumatic controllers – dump valves, and chemical injection pumps. The 

 

(13.6 scfh). The emission factors in the report “were obtained from data gathered as part of the EPA’s Natural Gas 

STAR program.” Examination of Natural Gas STAR program materials clearly shows that these emission factors 

were derived from the manufacturer-supplied natural gas bleed rates for high bleed pneumatic controllers listed in 

Appendix A to Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry. 

The ENVIRON report also includes the number of controllers of each type associated with each gas well, said to 

be drawn from survey data in the CENRAP states. The numbers for liquid level controllers and pressure 

controllers are reflected in Table 2-15; the report found zero positioners and transducers per well.
27

methodology that was used for this analysis is based on the 2013 GHG Inventory and uses data 

from the GHGRP and the University of Texas/EDF gas production measurement study (Allen et 

al., 2013). 

The study relied on the 2013 GHG Inventory for 1990-2011 for methane emissions data 

for the oil and natural gas sector. These emissions data were revised to include updated 

information from the GHG Inventory and the Measurements of Methane Emissions at Natural 

Gas Production Sites in the United States study (Allen et al., 2013). The revised 2011 baseline 

methane emissions estimate was used as the basis for projecting onshore methane emissions to 

2018. (Note: The focus of this white paper is current emissions, therefore, the 2018 projections 

are not discussed further.)

The study used the 2013 GHG Inventory estimates for 2011 to develop new activity and 

emission factors for pneumatic controllers. The count of pneumatic controllers was calculated 

using the well counts and assuming 0.94 pneumatic controllers per well. The study did find that 

there are an additional 8.6 pneumatic controllers per gathering/boosting station that were not 

accounted for in the 2013 GHG Inventory. The study also used emission factors from subpart W,

which reported pneumatic controllers in three categories: low bleed, intermittent bleed and high 

bleed controllers. To break out the number of pneumatic controllers in each of these categories, 

the emission data from subpart W were analyzed, and the study determined that the percentage of 

pneumatic controllers were 10% high bleed, 50% intermittent bleed and 40% low bleed. These 

percentages were applied to the pneumatic controller counts and the respective emission factor 

was used to calculate the emissions from these controllers. Intermittent pneumatic controllers

were further segregated into two categories: dump valves and non-dump valve intermittent 

controllers. The dump valves represent intermittent controllers that do not continuously bleed 

and only emit during actuation. The study estimated that 75% of the total intermittent pneumatic 

controllers were dump valves. Based on the subpart W data and the assumptions above, the study 

used the following emission factors for each of the controllers: 320 Mcf/yr/device for high bleed, 

120 Mcf/yr/device for non-dump intermittent, 20 Mcf/yr/device for dump intermittent and 11 

Mcf/yr/device for low bleed pneumatic controllers. Using these factors, the study estimated an 
28

increase of 41% (26 Bcf or 491,000 MT) in methane emissions in comparison to the 2013 GHG 

Inventory. 

Further information included in this study on the replacement of high bleed and 

intermittent bleed pneumatic controllers with low bleed pneumatic controllers, and the 

replacement of pneumatic pumps with electric pumps as mitigation or emission reduction 

techniques, methane control costs, and their estimates for the potential for VOC emissions cocontrol benefits from the replacement of these pneumatic controllers are presented in Section 3 

of this document.

2.2 Discussion of Data Sources for Pneumatic Pumps

Many of the data sources for pneumatic pumps are the same as those for pneumatic 

controllers, therefore, the overall descriptions of these data sources are not repeated in this 

section and only the information relevant to pneumatic pumps is discussed.

2.2.1 Methane Emissions from the Natural Gas Industry (GRI/EPA, 1996c) (GRI/EPA, 1996e)

The methane emission estimates for pneumatic pumps are separated into two categories

for the GRI/EPA reports; chemical injection pumps (GRI/EPA, 1996d) and gas-assisted glycol 

pumps (GRI/EPA, 1996f). A summary of each of these reports and the methane calculation 

methodologies are provided in the following sections.

2.2.1.1 Methane Emissions from the Natural Gas Industry – Chemical Injection Pumps

(GRI/EPA, 1996c)

This report estimates emissions from two types of pumps that the oil and natural gas 

industry uses for chemical injection into process streams: piston pumps and diaphragm pumps. 

Four sources of information were used to develop an emission factor for chemical injection 
29

pumps: a study by the CPA14, data collected from site visits, literature data for methane 

composition, and data from pump manufacturers.

The CPA study provided natural gas emissions from five diaphragm chemical injection 

pumps using the “bagging” method. This method involves enclosing the pump and measuring the 

flow rate and concentration of the natural gas emissions from the pump. The measurements from 

this study reported natural gas emissions ranging from 254 to 499 standard cubic feet per day per 

pump (scfd/pump) with an average of 334 scfd/pump.

Data from site visits included: the total number of chemical injection pumps for a 

particular site, number of chemical injection pumps used in natural gas production, the energy 

source for the pump (e.g., natural gas, instrument air, electricity), frequency of operation (e.g., 

pumping rate in strokes per minute), number of pumps that are active or idle, pump operation 

schedule, size of the unit (e.g., volume displacement of the motive chamber), manufacturer and 

model number of the pump, and supply gas pressure. Table 2-12 provides a summary of the site 

visit data. The methane emission factor in Table 2-12 was calculated using a methane 

composition of 78.8% (GRI/EPA, 1996d).

Table 2-12. Summary of Chemical Injection Pump Site Visit Data

Chemical Injection 

Pump Data

All Data Natural Gas Industry Data

Piston Pumps

Diaphragm 

Pumps Piston Pumps

Diaphragm 

Pumps

Percent of Total Pumps 49.8 ± 38% 50.2 ± 38% 4.5 ± 678% 95.5 ± 32%

Pump Actuation Rate 

(strokes/min) 26.32 ± 29% 13.64 ± 49% 3.57 ± 42% 14.75 ± 61%

Number of Pump 

Actuation 

Measurements

32 8 15 5

Number of Sites with 7 5 2 4

 

14 Canadian Petroleum Association. A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas 

Operations in Alberta, March 1992.
30

Chemical Injection 

Pump Data

All Data Natural Gas Industry Data

Piston Pumps

Diaphragm 

Pumps Piston Pumps

Diaphragm 

Pumps

Pump Actuation 

Measurements

Percent of Pumps 

Operating 44.6 ± 62% 40.0 ± 52% 77.5 ± 148% 58.0 ± 39%

Number of Sites with 

Pumps Operating 7 10 4 6

Methane Emissions 

Factor (scfd/pump) 248 ± 83% 668 ± 88%

Manufacturers’ data and the CPA data were used to determine the volume of gas released 

per pump stroke. This was done by using the natural gas usage data (amount of natural gas 

required to pump one gallon of liquid), stroke length, and stoke diameter to calculate volume of 

natural gas per pump stoke. For diaphragm pumps, the average natural gas usage was calculated 

to be 0.0719 standard cubic feet per stroke (scf/stroke). The piston pump average natural gas 

usage was calculated to be 0.0037 scf/stroke. These averages were then used to determine the 

emission factor for each of the pump types by multiplying the average frequency (strokes per 

day) by the operating time percentage. Note that the report uses the “all data” frequency and 

operating percentage to calculate the emission factor for each type of pump. The emission factor 

for diaphragm pumps was calculated to be 446 scfd/pump and the emission factor for piston 

pumps was calculated to be 48.9 scfd/pump. 

The percentage of piston and diaphragm pumps and their respective emission factors 

were then used to calculate an average emission factor for chemical injection pumps. The 

average emission factor was determined to be 248 scfd/pump. The 1992 national emissions were 

then calculated using the average chemical injection pump emission factor (248 scfd/pump) and 

the activity factor for chemical injection pumps of 16,971 (GRI/EPA, 1996a). The resulting 1992 

national emissions from chemical injection pumps for the natural gas production segment was 

calculated to be 1,536 MMscf/yr (29,008 MT).
31

2.2.1.2 Methane Emissions from the Natural Gas Industry – Gas-Assisted Glycol Pumps 

(GRI/EPA, 1996e)

For many glycol dehydrators in the natural gas industry, small gas-assisted pumps are 

used to circulate the glycol. These pumps use energy from the high-pressure rich glycol/gas 

mixture leaving the absorber to pump the low-pressure lean glycol back to the absorber. Natural 

gas is entrained in the rich glycol stream feeding the pump and is discharged from the pump at a 

lower pressure to the regenerator. If the glycol unit has a flash tank, most of the natural gas in the 

low-pressure stream can be recovered and used as a fuel or stripping gas. If the natural gas from 

the pump is used as a stripping gas, or if there is no flash tank, all of the pump exhaust gas will 

be vented through the regenerator’s atmospheric vent stack (GRI/EPA, 1996e).

Methane emissions from these gas-assisted pumps were calculated using technical 

information from Kimray, a manufacturer of gas-assisted pumps. No direct measurements of 

pump gas usage were used in the calculations. Kimray reported that the natural gas usage ranges 

from 0.081 actual cubic feet per gallon of glycol pumped (acf/gal) for high-pressure pumps 

( >400 psig) to 0.130 acf/gal for low-pressure pumps (< 400 psig). These values convert to 3.73

standard cubic feet per gallon (scf/gal) at an operating pressure of 800 psig and 83 mole percent 

methane for high-pressure pumps and 2.31 scf/gal at an operating pressure of 300 psig and 83 

mole percent methane for low-pressure pumps. 

The gas usage rates were then converted to an amount of natural gas treated by assuming 

a typical high-pressure dehydrator would remove 53 pounds of water per million cubic feet of 

gas (lbs/MMscf), and a typical low-pressure dehydrator would remove 127 lbs/MMscf. The 

design glycol-to-gas ratio was assumed to be three gallons of glycol per pound of water removed 

and an overcirculation ratio of 2.1 was used to determine the emission factors for the pumps for 

the natural gas production segment. Using these factors and the fraction of dehydrators without 

flash tanks (0.735) and the fraction of dehydrators without combustion vent controls (0.988), the 

emission factor for the gas-assisted pumps in the natural gas production segment were calculated 

to be 904.5 standard cubic feet of methane per million standard cubic feet of natural gas treated 

(scf/MMscf) for high-pressure pumps, and 1342.2 scf/MMscf for low-pressure pumps. The final 
32

emission factor for methane from an average gas-assisted glycol pump was determined assuming 

that 80% of these pumps are high-pressure and 20% are low-pressure. The average emission 

factor was calculated to be 992.0 scf/MMscf and was used to estimate methane emissions from 

the natural gas production segment.

For natural gas processing, the study assumed that only high-pressure gas-assisted glycol 

pumps are used. The emission factor was calculated using the high-pressure pump gas usage 

(3.73 scf/gal), the design glycol-to-gas ratio (3 gal glycol/lb water), the water removal rate for a 

high-pressure system (53 lbs/MMcsf), an overcirculation ratio of 1.0, the fraction of dehydrators 

without flash tanks (0.333) and the fraction of dehydrators without combustion vent controls 

(0.900). These values were used to calculate a methane emission factor of 177.8 scf/MMscf for 

gas-assisted pumps for the natural gas processing segment. The natural gas transmission and 

storage segments do not use gas-assisted glycol pumps.

The 1992 national methane emissions were calculated using data from site surveys to 

determine the natural gas throughput of dehydrators with gas-assisted pumps. The natural gas 

throughput of dehydrators with gas-assisted pumps was estimated to be 11.1 trillion standard 

cubic feet per year (Tscf/yr) for the natural gas production segment and 0.958 Tscf/yr for the 

natural gas processing segment. The 1992 national methane emissions from gas-assisted pumps 

were calculated to be 10,962 MMscf/yr (206,989 MT) for the natural gas production segment 

and 170 MMscf/yr (3,215 MT) for the natural gas processing segment.

2.2.2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)

Table 2-13 summarizes the 2014 GHG Inventory estimates of 2012 national methane 

emissions from pneumatic pumps in the natural gas production and processing segments. (Note: 

The GHG inventory does not include estimates of emissions from pneumatic pumps in the 

natural gas transmission and storage segments.) The pneumatic pumps described in the GHG 

Inventory include: chemical injection pumps and Kimray pumps. The table includes potential 

emissions, emission reductions and net emissions. For pneumatic pumps, the emission reductions 
33

in this report are voluntary reductions through the Natural Gas STAR program. In future years, 

the GHG Inventory will also account for regulatory reductions that result from subpart OOOO.

Table 2-13. Summary of GHG Inventory 2012 Nationwide Emissions 

from Pneumatic Pumps

Industry Segment

Potential CH4

Emissions (MT)

CH4 Emission 

Reductions (MT)

Net CH4

Emissions (MT)

Natural gas production 455,719 2,771 452,948

Petroleum Production 49,973 N/A

Natural gas processing 5,011 N/A

The 2014 GHG Inventory data estimates that pneumatic pump emissions are around 16% 

of overall methane emissions from the natural gas production and processing sectors.

Tables 2-14 and 2-15 show the 2014 GHG Inventory’s estimates of 2012 methane 

emissions from chemical injection pumps and gas-assisted pumps (Kimray pumps) in the natural 

gas and petroleum production and processing industry segments. The tables present population 

of chemical injection and Kimray pumps, methane emission factors and potential methane 

emissions from these devices in each of the EIA’s NEMS regions, and the estimated national 

total of chemical injection pumps, Kimray pumps and potential methane emissions. The activity 

factors for chemical injection pumps are based on the estimated count of chemical injection 

pumps in operation. For the production sector, a regional factor for pumps per well (ranging 

from 0.01 to 0.68) is applied to annual regional well counts to calculate chemical injection 

pumps each year for natural gas, and for petroleum systems it is estimated that around 20% of 

wells have pumps (based on 1996 GRI/EPA) and that 25% of pumps use gas. For the production 

sector, the activity factors for Kimray pumps are based on the total throughput of natural gas 

multiplied by the fraction of dehydrators using gas-driven pumps (0.9 for the production 

segment). For the processing segment, the activity factor for Kimray pumps is based the total 

processing plant throughput multiplied by the fraction of natural gas treated by dehydrators at 
34

gas plants (0.5) and then multiplied by the fraction of dehydrators that use a gas-driven pump 

(0.1 for the processing segment).

Table 2-14. Estimated 2012 National and Regional Methane Emissions from Chemical 

Injection Pumps in the Natural Gas Production Segment

NEMS Region

Population of 

Chemical Injection

Pumpsa

CH4 Potential Emission

Factor (scfd/device)

a

CH4 Emissions 

(MT)

Natural Gas Production

North East 795 268 1,499

Midcontinent 15,343 260 28,045

Rocky Mountain 14,849 244 25,448

South West 2,531 253 4,508

West Coast 1,422 289 2,890

Gulf Coast 2,537 278 4,951

Total Natural Gas 37,477 67,341

Voluntary Emission 

Reductions

-2,771

Net Emissions-Natural Gas 64,570

Petroleum Production 28,702 248 49,973

a

1996 GRI/EPA report, extrapolated using ratios relating other factors for which activity data are available.

Table 2-15. Estimated 2012 National and Regional Methane Emissions from Kimray

Pumps in the Natural Gas Production and Processing Segments

NEMS Region

Total Natural Gas 

using Kimray Pumpsa

CH4 Potential Emission

Factor (scfd/MMscf)

a

CH4 Emissions 

(MT)

Natural Gas Production

North East 6,487,241 1,073 134,073

Midcontinent 4,409,271 1,040 88,322

Rocky Mountain 3,404,114 975 63,934

South West 1,692,957 1,014 33,050

West Coast 85,450 1,157 1,904

Gulf Coast 3,137,482 1,110 67,095

Production Total 19,216,515 388,378

Natural Gas Processing
35

All Regions 1,463,675 178 5,011 

Total Potential Emissions 393,389

a

1996 GRI/EPA report, extrapolated using ratios relating other factors for which activity data are available.

Note: The GHG Inventory did not list any Kimray pumps in the natural gas transmission or distribution sectors.

The basis for the GHG Inventory’s potential methane emission factors for pneumatic 

pumps in the natural gas production and processing segments is the 1996 GRI/EPA report.

The region-specific factors used in the production segment are developed using the 

GRI/EPA factor and regional gas composition data.

2.2.3 Greenhouse Gas Reporting Program (U.S. EPA, 2013)

The GHGRP addresses petroleum and natural gas systems with implementing regulations 

at 40 CFR part 98, subpart W. The rule requires facilities in the onshore petroleum and natural 

gas production segment to report GHG emissions from pneumatic pumps. Facilities calculate 

emissions from pneumatic pumps by determining the number of pneumatic pumps at the facility 

and applying an emission factor of 13.3 scf/hour/pump. Facilities also apply a facility-specific 

gas composition factor for calculating emissions. For 2012, 343 facilities in the onshore 

petroleum and natural gas production industry segment reported emissions from pneumatic 

pumps, with total methane emissions of 135,227 metric tons. 

2.2.4 Determining Bleed Rates for Pneumatic Devices in British Columbia (Prasino Group 

2013)

The study used data from the Canadian Association of Petroleum Producers (2008), 

Pacific Carbon Trust (2011), Cap-Op Energy’s Distributed Energy Efficiency Project Platform 

(DEEPP) database to compile a list of pneumatic pumps. The study notes that the total number of 

pneumatic pumps is unknown and the list only comprises a subset of the total population. In 

total, 184 samples were taken from chemical injection pumps. From the data collected, the study 

determined the average bleed rate for a piston-type pneumatic pumps to be 0.5917 m3/hr 
36

(approximately 20.9 scfh). For diaphragm-type pneumatic pumps, the bleed rate was calculated 

to be 1.0542 m3/hr (approximately 37.2 scfh). 

2.2.5 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore 

Oil and Natural Gas Industries (ICF, 2014)

The analysis developed by ICF includes an inventory of methane emissions for 2011 

using data from the 2013 GHG Inventory and the GHGRP (U.S. EPA, 2013), in addition to data 

from the EIA and GRI. 

For pneumatic chemical injection pumps in the natural gas production segment, the 2011 

ICF inventory updated the count of chemical injection pumps to reflect changes made to the well 

counts and applied the Natural Gas STAR estimated reductions associated with pneumatic 

pumps. These changes resulted in a 2011 methane estimate of 3 Bcf (56,600 MT) from chemical 

injection pumps in the natural production segment. Kimray pumps (gas-assisted glycol pumps)

were estimated to be 17 Bcf (321,000 MT).

3.0 AVAILABLE PNEUMATIC DEVICE EMISSIONS MITIGATION 

TECHNIQUES

The following sections describe the different available emissions mitigations techniques

that the EPA is aware of for pneumatic controllers and pneumatic pumps. The primary sources of 

information for mitigations techniques was the EPA’s Natural Gas STAR Lessons Learned 

documents and the ICF economic analysis (ICF, 2014).

3.1 Available Pneumatic Controller Emissions Mitigation Techniques

Several techniques to reduce emissions from pneumatic controllers have been developed 

over the years. Table 3-1 provides a summary of these techniques for reducing emissions from 

pneumatic controllers including replacing high bleed controllers with low bleed or zero bleed 
37

models, driving controllers with instrument air rather than natural gas, using non-gas-driven 

controllers, and enhanced maintenance.
38

Table 3-1. Summary of Alternative Mitigation Techniques for Pneumatic Controllers

Option Description Applicability Costs Efficacy and Prevalence

Install Zero Bleed 

Controller in Place of 

Continuous Bleed 

Controller (U.S. EPA, 

2011a, GE Energy 

Services, 2012)

Zero bleed controllers are selfcontained natural gas-driven 

devices that vent to the downstream 

pipeline, not the atmosphere. 

Provide the same functional control 

as continuous bleed controllers, 

where applicable (U.S. EPA, 

2011a, GE Energy Services, 2012).

Applicable only for relatively lowpressure control valves, e.g., in 

gathering, metering and regulation 

stations, power plant and industrial 

feed, and city gate stations/distribution 

applications (U.S. EPA, 2011a).

The EPA does not have 

cost information on this 

technology.

100% emission reduction, 

where applicable. 

The EPA does not have 

information on the 

prevalence of this 

technology in the field, 

however, it is the EPA’s 

understanding that 

applicability is limited.

Install Low Bleed 

Controller in Place of 

High Bleed Controller

(U.S. EPA, 2006b)

Low bleed controllers provide the 

same functional control as a high 

bleed devices, while emitting less 

continuous bleed emissions (U.S. 

EPA, 2006b). 

Applicability depends on the function 

of instrumentation for an individual 

device and whether the device is a 

level, pressure, or temperature 

controller. Not recommended for 

control of very large valves that 

require fast and/or precise response to 

process changes. These are found most 

frequently on large compressor 

discharge and bypass pressure 

controllers (U.S. EPA, 2006b).

Based on information 

from Natural Gas STAR

(U.S. EPA, 2006b) and 

supplemental research 

conducted for subpart 

OOOO, low bleed 

devices cost, on average, 

around $165 more than 

high bleed versions. ICF 

report assumed a cost of 

$3,000 per replacement 

based on industry 

comments (ICF, 2014).

Estimated average 

reductions (U.S. EPA, 

2011a): 

Production segment:

6.6 tpy methane 

Transmission:

3.7 tpy methane

The EPA does not have 

information on the 

prevalence of this 

technology in the field.
39

Table 3-1. Summary of Alternative Mitigation Techniques for Pneumatic Controllers

Option Description Applicability Costs Efficacy and Prevalence

Convert to Instrument 

Air (U.S. EPA, 2006c)

Compressed air may be substituted 

for natural gas in pneumatic 

systems without altering any of the 

parts of the pneumatic control. In 

this type of system, atmospheric air 

is compressed, stored in a tank, 

filtered and then dried for 

instrument use. Instrument air 

conversion requires additional 

equipment to properly compress 

and control the pressured air. This 

equipment includes a compressor, 

power source, air dehydrator and 

air storage vessel (U.S. EPA, 

2006c).

Most applicable at facilities where 

there are a high concentration of 

pneumatic control valves and an 

operator present. Because the systems 

are powered by electric compressors, 

they require a constant source of 

electrical power or a backup natural 

gas pneumatic device (U.S. EPA, 

2006c). 

System costs are 

dependent on size of 

compressor, power 

supply needs, labor and 

other equipment (U.S. 

EPA, 2006c). A cost 

analysis is provided in 

Section 3.1.3 below.

100% emission reduction, 

where applicable. There 

are secondary emissions 

associated with electrical 

power generation.

The EPA does not have 

information on the 

prevalence of this 

technology in the field.

Mechanical and SolarPowered Systems in 

Place of Bleed 

Controller (U.S. EPA, 

2006a, U.S. EPA, 

2006b)

Mechanical controls operate using 

a simple design comprised of 

levers, hand wheels, springs and 

flow channels. The most common 

mechanical control device is the 

liquid-level float to the drain valve 

position with mechanical linkages. 

Electricity or small electrical 

motors (including solar-powered) 

have been used to operate valves. 

Solar control systems are driven by 

solar power cells that actuate 

mechanical devices using electric 

power. As such, solar cells require 

some type of backup power or 

storage to ensure reliability (U.S. 

EPA, 2006a).

Application of mechanical controls is 

limited because the control must be 

located in close proximity to the 

process measurement. Mechanical 

systems are also incapable of handling 

larger flow fluctuations. Electricpowered valves are only reliable with a 

constant supply of electricity (U.S. 

EPA, 2006a).

Depending on supply of 

power, costs can range 

from below $1,000 to 

$10,000 for entire 

systems (U.S. EPA, 

2006a).

100% emission reduction, 

where applicable. 

The EPA does not have 

information on the 

prevalence of this 

technology in the field.
40

Table 3-1. Summary of Alternative Mitigation Techniques for Pneumatic Controllers

Option Description Applicability Costs Efficacy and Prevalence

Enhanced Maintenance

(U.S. EPA, 2006a)

Instrumentation in poor condition 

typically bleeds 5 to 10 scfh more 

than representative conditions due 

to worn seals, gaskets, diaphragms; 

nozzle corrosion or wear; or loose 

control tube fittings. This may not 

impact operations but does increase 

emissions. Proper methods of 

maintaining a device are highly 

variable (U.S. EPA, 2006a).

Enhanced maintenance to repair and 

maintain pneumatic controllers

periodically can reduce emissions at 

many controllers (U.S. EPA, 2006a). 

Variable based on labor, 

time, and fuel required 

to travel to many remote 

locations.

Natural gas emission 

reductions of 5 to 10 scfh

(U.S. EPA, 2006a). 

The EPA does not have 

information on the 

prevalence of this practice 

in the field.
41

The mitigation techniques summarized in Table 3-1 are discussed in more detail in the 

following sections.

3.1.1 Zero Bleed Pneumatic Controllers

Zero bleed pneumatic controllers are self-contained, “closed loop” natural gas-driven 

controllers that vent to the downstream pipeline rather than to the atmosphere (U.S. EPA, 

2011a). These closed loop devices are considered to emit no natural gas to the atmosphere. 

However, they can be used only in applications with very low pressure and, therefore, may not 

be suitable to replace continuous bleed pneumatic controllers in many applications. Some 

applications where they may suitable include gathering, metering and regulation stations, power 

plant and industrial feed, and city gate stations/distribution (U.S. EPA, 2011a). To date, the EPA 

has not obtained any information on the cost of zero bleed controllers or their prevalence in the 

field.

3.1.2 Low Bleed Pneumatic Controllers 

Description

Low bleed controllers provide similar functional control as high bleed controllers, but 

have lower continuous bleed emissions. It has been estimated on average that 6.6 tons of 

methane and 1.8 tons of VOC will be reduced annually in the production segment from installing 

a low bleed device in place of a high bleed device (U.S. EPA, 2011a). In the transmission 

segment, the average achievable reductions per device are estimated around 3.7 tons and 0.08 

tons for methane and VOC, respectively (U.S. EPA, 2011a). As defined in this white paper, a

low bleed controller can emit up to 6 scfh, but this is higher than the expected emissions from the 

typical low bleed controllers available on the current market.
42

Applicability

There are certain situations in which replacing and retrofitting are not feasible, such as 

instances where a minimal response time is needed, cases where large valves require a high bleed 

rate to actuate, or a safety isolation valve is involved. 

Replacing high bleed pneumatic with low bleed controllers is infeasible in situations 

where a process condition may require a fast or precise control response so that it does not stray 

too far from the desired set point (U.S. EPA, 2011a). A slower-acting controller could potentially 

result in damage to equipment and/or become a safety issue. An example of this is on a 

compressor where pneumatic controllers monitor the suction and discharge pressure and actuate 

a recycle when one or the other is out of the specified target range. Another scenario where fast 

and precise control is necessary includes transient (non-steady) situations where a gas flow rate 

may fluctuate widely or unpredictably (U.S. EPA, 2011a). In this case, a responsive high bleed 

device may be required to ensure that the gas flow can be controlled in all situations. 

Temperature and level controllers are typically present in control situations that are not prone to 

fluctuate as widely or where the fluctuation can be readily and safely accommodated by the 

equipment. Therefore, such processes may be appropriate for control from a low bleed device, 

which is slower acting and less precise.

Safety concerns can limit the appropriateness of low bleed controllers in specific 

situations where any amount of bleeding is unacceptable. Emergency valves are often not

controlled with bleeding controllers (e.g., neither low bleed nor high bleed), because it may not 

be acceptable to have any amount of bleeding in emergency situations (U.S. EPA, 2011a). 

Pneumatic controllers are designed for process control during normal operations and to keep the 

process in a normal operating state. If an Emergency Shut Down (ESD) or Pressure Relief Valve 

(PRV) actuation occurs,15 the equipment in place for such an event is spring-loaded, or otherwise 

not pneumatically powered. During a safety issue or emergency, it is possible that the pneumatic 

 

15 ESD valves either close or open in an emergency depending on the fail safe configuration. PRVs always open in 

an emergency.
43

gas supply will be lost. For this reason, control valves are deliberately selected to either fail open 

or fail closed, depending on which option is the failsafe.

Costs

The costs described in this section are based on vendor research and information given in 

the appendices of the Natural Gas STAR Lessons Learned document on pneumatic controllers

(U.S. EPA, 2006a). As Table 3-2 indicates, the average cost for a low bleed pneumatic is $2,553, 

while the average cost for a high bleed is $2,338.16 Thus, the incremental cost of installing a low 

bleed device instead of a high bleed device is on the order of $165 per device. (Note: The ICF 

report assumed a cost of $3,000 to replace an existing high bleed pneumatic controller with a low 

bleed pneumatic controller based on industry comments (ICF, 2014).)

Table 3-2. Cost Projections for the Representative Pneumatic Controllersa

Device

Minimum 

cost ($)

Maximum 

cost ($) Average cost ($)

Low Bleed 

Incremental 

Cost

($)

High bleed controller 366 7,000 2,388

$165

Low bleed controller 524 8,852 2,553

a Major pneumatic controllers vendors were surveyed for costs, emission rates and any other pertinent 

information that would give an accurate picture of the present industry.

Monetary savings associated with additional gas captured to the sales line were estimated 

based on a natural gas value of $4.00 per Mcf (U.S. EIA, 2010).

17 The representative low bleed

device is estimated to emit 6.65 tons, or 319 Mcf, (using the conversion factor of 0.0208 tons 

methane per 1 Mcf) of methane less than the average high bleed device per year. Assuming 

production quality gas is 82.8% methane by volume, this equals 385.5 Mcf natural gas recovered 

 

16 Costs are estimated in 2008 U.S. Dollars. 

17The average market price for natural gas in 2010 was approximately $4.16 per Mcf. This is much less compared to 

the average price in 2008 of $7.96 per Mcf. Due to the volatility in the value, a conservative savings of $4.00 per 

Mcf estimate was projected for the analysis in order to not overstate savings. 
44

per year (EC/R, 2011). Therefore, the value of recovered natural gas from one pneumatic 

controller in the production segment equates to approximately $1,500. While the owner of the 

transmission system is generally not the owner of the natural gas, the potentially lost gas still has 

value. The total value of the recovered gas from one pneumatic controller in the transmission 

segment is $1,375 assuming a natural gas value of $4.00 per Mscf and transmission natural gas is 

92.8% methane by volume (EC/R, 2011).

3.1.3 Instrument Air Systems

Description

The major components of an instrument air conversion project include the compressor, 

power source, dehydrator, and volume tank. The following is a description of each component as 

described in the Natural Gas STAR document (U.S. EPA, 2006c), Lessons Learned: Convert 

Gas Pneumatic Controls to Instrument Air:

 Compressors used for instrument air delivery are available in various types and sizes, 

from centrifugal (rotary screw) compressors to reciprocating piston (positive 

displacement) types. The size of the compressor depends on the size of the facility, the 

number of control devices operated by the system and the typical bleed rates of these 

devices. The compressor is usually driven by an electric motor that turns on and off, 

depending on the pressure in the volume tank. For reliability, a full spare compressor is 

normally installed. A minimum amount of electrical service is required to power the 

compressors.

 A critical component of the instrument air control system is the power source required 

to operate the compressor. Because high-pressure natural gas is abundant and readily 

available, gas pneumatic systems can run uninterrupted on a 24-hour, 7-day per week 

schedule. The reliability of an instrument air system, however, depends on the 

reliability of the compressor and electric power supply. Most large natural gas plants 

have either an existing electric power supply or have their own power generation 

system. For smaller facilities and in remote locations, however, a reliable source of 
45

electric power can be difficult to ensure. In some instances, solar-powered batteryoperated air compressors can be effective for remote locations, which reduce both 

methane emissions and energy consumption. Small natural gas powered fuel cells are 

also being developed.

 Dehydrators, or air dryers, are also an integral part of the instrument air compressor 

system. Water vapor present in atmospheric air condenses when the air is pressurized 

and cooled, and can cause a number of problems to these systems, including corrosion 

of the instrument parts and blockage of instrument air piping and controller orifices. 

 The volume tank holds enough air to allow the pneumatic control system to have an 

uninterrupted supply of high-pressure air without having to run the air compressor 

continuously. The volume tank allows a large withdrawal of compressed air for a short 

time, such as for a motor starter, pneumatic pump, or pneumatic tools, without affecting 

the process control functions.

Compressed air may be substituted for natural gas in pneumatic systems without altering 

any of the parts of the pneumatic control. The use of instrument air eliminates natural gas 

emissions from natural gas powered pneumatic controllers. All other parts of a gas pneumatic 

system will operate the same way with instrument air as they do with natural gas. A diagram of a 

natural gas pneumatic controller is presented in Figure 3-1. A diagram of a compressed 

instrument air system is presented in Figure 3-2.

Applicability

The use of instrument air eliminates natural gas emissions from the natural gas-driven 

pneumatic controllers; however, these systems may only be used in locations with access to a 

sufficient and consistent supply of electrical power. Instrument air systems are also usually 

installed at facilities where there is a high concentration of pneumatic control valves and the 

presence of an operator that can ensure the system is properly functioning (U.S. EPA, 2006c). 
46

Figure 3-1 Natural Gas Pneumatic Control System

Figure 3-2. Compressed Instrument Air System
47

Costs

Instrument air conversion requires additional equipment to properly compress and control the 

pressured air. The size of the compressor will depend on the number of control loops present at a 

location. A control loop consists of one pneumatic controller and one control valve. The volume 

of compressed air supply for the pneumatic system is equivalent to the volume of gas used to run 

the existing instrumentation—adjusted for air losses during the drying process. The current 

volume of gas usage can be determined by direct metering if a meter is installed. Otherwise, an 

alternative rule of thumb for sizing instrument air systems is 1 cubic foot per minute (cfm) of 

instrument air for each control loop. As the system is powered by electric compressors, the 

system requires a constant source of electrical power or a backup pneumatic device. Table 3-3

outlines three different sized instrument air systems including the compressor power 

requirements, the flow rate provided from the compressor, and the associated number of control 

loops.

Table 3-3. Compressor Power Requirements and Costs for Various Sized 

Instrument Air Systemsa

Compressor Power Requirementsb Flow Rate Control Loops

Size of Unit Hp kW (cfm) Loops/Compressor

Small 10 13.3 30 15

Medium 30 40 125 63

Large 75 100 350 175

a

Based on rules of thumb stated in the Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic 

Controls to Instrument Air.

b

Power is based on the operation of two compressors operating in parallel (each assumed to be operating at full 

capacity 50% of the year).

The primary costs associated with conversion to instrument air systems are the initial 

capital expenditures for installing compressors and related equipment and the operating costs for 

electrical energy to power the compressor motor. This equipment includes a compressor, a power 

source, a dehydrator and a storage vessel. It is assumed that in either an instrument air solution or 

a natural gas pneumatic solution, gas supply piping, control instruments, and valve actuators of 

the gas pneumatic system are required. The total cost, including installation and labor, of three 

representative sizes of compressors based on assumptions found in the Natural Gas STAR 
48

document, “Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air” are

summarized in Table 3-4.

3.1.4 Mechanical and Solar-Powered Systems in Place of Bleed Controller

Description

Mechanical controls have been widely used in the natural gas and petroleum industry. 

They operate using a combination of levers, hand wheels, springs and flow channels with the 

most common mechanical control device being a liquid-level float to the drain valve position 

with mechanical linkages (U.S. EPA, 2006a). Another device that is increasing in use is 

electronic control instrumentation. Electricity or small electrical motors (including solarpowered) have been used to operate valves and therefore do not bleed natural gas into the 

atmosphere (U.S. EPA, 2006a). Solar control systems are driven by solar power cells that actuate 

mechanical devices using electric power. As such, solar cells require some type of backup power 

or storage to ensure reliability.

Applicability

Application of mechanical controls is limited because the control must be located in close 

proximity to the process measurement. Mechanical systems are also incapable of handling larger

flow fluctuations (U.S. EPA, 2006c). Electric-powered valves are only reliable with a constant 

supply of electricity. These controllers can achieve 100% reduction in emissions where 

applicable.

Costs

Depending on supply of power, costs can range from below $1,000 to $10,000 for entire 

systems (U.S. EPA, 2006a).
49

Table 3-4 Estimated Capital and Annual Costs of Various Sized Representative Instrument Air Systems

Instrument 

Air System 

Size Compressor Tank Air Dryer

Total 

Capitala

Annualized 

Capitalb

Labor 

Cost

Total 

Annual 

Costsc

Annualized Cost 

of Instrument 

Air System

Small $3,772 $754 $2,262 $16,972 $2,416 $1,334 $8,674 $11,090

Medium $18,855 $2,262 $6,787 $73,531 $10,469 $4,333 $26,408 $36,877

Large $33,183 $4,525 $15,083 $135,750 $19,328 $5,999 $61,187 $80,515

a Total Capital includes the cost for two compressors, tank, an air dryer and installation. Installation costs are assumed to be equal to 1.5 times the cost of capital. 

Equipment costs were derived from the Natural Gas Star Lessons Learned document and converted to 2008 dollars from 2006 dollars using the Chemical 

Engineering Cost Index. 

b The annualized cost was estimated using a 7% interest rate and 10-year equipment life. 

c Annual Costs include the cost of electrical power as listed in Table 3-3 and labor. 
50

3.1.5 Maintenance of Natural Gas-Driven Pneumatic Controllers

Manufacturers of pneumatic controllers indicate that emissions in the field can be higher 

than the reported gas consumption due to operating conditions, age, and wear of the device (U.S. 

EPA, 2006a). Examples of circumstances or factors that can contribute to this increase include:

 Nozzle corrosion resulting in more flow through a larger opening.

 Broken or worn diaphragms, bellows, fittings, and nozzles.

 Corrosives in the gas leading to erosion or corrosion of control loop internals.

 Improper installation.

 Lack of maintenance (maintenance includes replacement of the filter used to remove 

debris from the supply gas and replacement of O-rings and/or seals).

 Lack of calibration of the controller or adjustment of the distance between the flapper and 

nozzle.

 Foreign material lodged in the pilot seat.

 Wear in the seal seat.

Maintenance of pneumatics can correct many of these problems and can be an effective 

method for reducing emissions. Cleaning and tuning, in addition to repairing leaking gaskets, 

tubing fittings, and seals, can save 5 to 10 scfh per device. Tuning to operate over a broader 

range of proportional band often reduces bleed rates by as much as 10 scfh. Eliminating 

unnecessary valve positioners can save up to 18 scfh per device (U.S. EPA, 2006a).

However, proper methods of maintaining a device are highly variable, thus, costs are 

variable based on labor, time, and fuel required to travel to many remote locations.

3.2 Available Pneumatic Pump Emissions Mitigation Techniques

There are several techniques that are currently being used to reduce emissions from 

pneumatic pumps. Table 3-5 provides a summary of these techniques for reducing emissions 
51

from pneumatic pumps, which include chemical injection pumps and natural gas-assisted 

recirculation pumps.

3.2.1 Instrument Air Pump

Description

Circulation pumps in glycol dehydration processes and chemical injection pumps are 

often powered by pressurized natural gas at remote locations. As a result, these pumps vent 

natural gas to the atmosphere as part of their normal operation. To mitigate VOC and methane 

emissions, some companies are using instrument air to power these pumps. These companies 

have found that the use of instrument air increased operational efficiency, decreased maintenance 

and decreased costs, while eliminating emissions of methane and VOC (U.S. EPA, 2011b).

Applicability

Converting chemical injection pumps and glycol dehydration circulation pumps to 

instrument air can be applied to natural gas hydration operations across all gas industry sectors 

with excess capacity of its instrument air system. Because the systems are powered by electric 

compressors, they require a constant source of electrical power or a backup natural gas 

pneumatic device (U.S. EPA, 2011b). 

Costs

The total cost to convert a natural gas pneumatic circulation pump to instrument air 

includes the installation of piping and an appropriate control system between the existing 

instrument air system and the glycol pump if the driver is independent of the circulation pump. If 

the driver is separated from the pump by O-rings, then the pump would need to also be replaced. 

The implementation capital costs are estimated to be $1,000 to $10,000, and the incremental 

operating costs are estimated to be $100 to $1,000 (U.S. EPA, 2011b). The potential annual 
52

Table 3-5. Summary of Alternative Mitigation Techniques for Pneumatic Pumps

Option Description Applicability Costs

Efficacy and 

Prevalence

Replace natural 

gas-assisted pump 

with instrument air 

pump (U.S. EPA, 

2011b)

Circulation pumps in glycol dehydration 

units and chemical injection pumps are

retrofitted with instrument air to drive the

pumps (U.S. EPA, 2011b).

Facilities with excess capacity of 

instrument air or facilities that can 

install an air compressor system. 

Because the systems are powered by 

electric compressors, they require a 

constant source of electrical power or a 

backup natural gas pneumatic pump

(U.S. EPA, 2011b). 

The installation of 

the piping from the 

air compressor 

system to the pump 

accounts for the bulk 

of the capital cost 

and typically ranges 

from $100 to $1,000

(U.S. EPA, 2011b).

100% emission 

reduction, where 

applicable. The Natural 

Gas STAR reports 

typical annual methane 

savings to be 2,500 Mcf 

for glycol circulation 

pumps and 183 Mcf for 

chemical injection 

pumps (U.S. EPA, 

2011b). 

The EPA does not have 

information on the 

prevalence of this 

technology in the field.

Replacement of 

natural gasassisted pump with 

solar-charged 

direct current 

pump (U.S. EPA, 

2011b)

In field settings, low volume natural gas 

pneumatic pumps can be replaced with 

solar-charged DC pumps (U.S. EPA, 

2011b). 

Low volume solar-charged pneumatic 

pumps are limited to approximately 5 

gallons per day discharge at 1,000 psig. 

Large volume solar pumps are 

available with maximum output of 38 

to 100 gallons per day at maximum 

injection pressures of 1,200 to 3,000 

psig (U.S. EPA, 2011b).

The reporting 

partners for Natural 

Gas STAR stated a 

replacement cost of 

$2,000 per pump,

including the solar 

panels, storage 

batteries and pump

(U.S. EPA, 2011b).

100% emission 

reduction, where 

applicable. The Natural 

Gas STAR reports 

typical annual methane 

savings to be 182.5 Mcf 

per chemical injection 

pump conversion (U.S. 

EPA, 2011b). 

The EPA does not have 

information on the 

prevalence of this 

technology in the field.
53

Option Description Applicability Costs

Efficacy and 

Prevalence

Replacement of 

natural gasassisted pump with 

electric pump

(ICF, 2014)

In settings where a constant supply of 

electricity is available, natural gas 

pneumatic pumps can be replaced with 

electric pumps (ICF, 2014).

These pumps require a constant source 

of electricity, thus, they are typically 

installed at processing plants or large 

dehydration facilities, which are 

normally equipped with electricity

(U.S. EPA, 2011b).

Electrical pumps are 

estimated to cost 

roughly $10,000 per 

pump and the annual 

electrical usage cost 

was estimated to be 

$2,000 per year. 

(ICF, 2014)

100% emission 

reduction, where 

applicable. 

The annual methane 

reduction from 

replacing pneumatic 

pumps with electrical 

pumps is estimated to 

be 5,000 Mcf (ICF, 

2014).

The EPA does not have 

information on the 

prevalence of this 

technology in the field.
54

natural gas savings are estimated to be 2,500 Mcf (U.S. EPA, 2011b) or $10,000 based on a 

natural gas value of $4.00 per Mcf (U.S. EIA, 2010). For chemical injection pumps, the 

implementation costs are the same, but the potential annual natural gas savings are estimated to 

be 183 Mcf per pump conversion (U.S. EPA, 2011b) or $732 based on a natural gas value of 

$4.00 per Mcf (U.S. EIA, 2010).

3.2.2 Solar Power Pump

Description

Solar power can be used to operate pumps located at remote sites where electricity is not 

available. These solar-powered pumps use electric power captured by solar panels to operate a 

DC-charged pump. Solar injection pumps can handle a range of throughputs and injection 

pressures. Low volume solar-charged DC pumps are limited to approximately 5 gallons per day 

discharge at 1,000 psig (U.S. EPA, 2011b). Large volume solar pumps are available with 

maximum output of 38 to 100 gallons per day at maximum injection pressures of 1,200 to 3,000 

psig (U.S. EPA, 2011b). These pumps eliminate the methane and VOC emissions that would 

have resulted from the use of a pneumatic pump.

Applicability

These solar-powered pumps are generally used to replace low volume natural gas 

pneumatic pumps if sufficient sunlight is available to power the pumps and backup power is not 

required. These low volume pumps are typically used to inject methanol or corrosion inhibiters 

into producing wells and other field equipment. These chemical injection pumps are typically 

sized for 6 to 8 gallons of methanol injection per day. The large volume pumps can be used to 

replace gas-assisted circulation pumps for glycol dehydrators.

Costs

The Natural Gas STAR program reported the cost of replacing pneumatic pumps with 

solar-charged electric pumps to be approximately $2,000 per pump (U.S. EPA, 2011b). The solar 
55

panels and storage batteries are nearly maintenance free, and the solar panels have a life span of 

up to 15 years and the electric motors last approximately 5 years in continuous use (U.S. EPA, 

2011b). The potential annual natural gas savings are estimated to be 2,500 Mcf or $10,000 based 

on a natural gas value of $4.00 per Mcf (U.S. EIA, 2010) for recirculation pumps (U.S. EPA, 

2011b). For chemical injection pumps, the implementation costs are the same, but the potential 

annual natural gas savings are estimated to be 183 Mcf (U.S. EPA, 2011b) or $732 based on a 

natural gas value of $4.00 per Mcf (U.S. EIA, 2010). The ICF report estimates the cost of 

replacing chemical injection pneumatic pumps with solar-powered pumps to be $5,000 per pump 

with a natural gas savings of 180 Mcf per year (ICF, 2014) or $720 based on a natural gas value 

of $4.00 per Mcf (U.S. EIA, 2010).

3.2.3 Electric Power Pumps

Description

Electric power pumps are used to replace natural gas-assisted pneumatic used to 

recirculate glycol in gas dehydrators. These pumps eliminate the methane and VOC emissions 

that would have resulted from the use of a pneumatic pump.

Applicability

These pumps require a constant source of electricity, thus, they are typically installed at 

processing plants or large dehydration facilities, which are normally equipped with electricity.

Costs

Electrical pumps are estimated to cost roughly $10,000 per pump and the annual 

electrical usage cost was estimated to be $2,000 per year (ICF, 2014). The annual methane 

reduction from replacing pneumatic pumps with electrical pumps is estimated to be 5,000 Mcf

(ICF, 2014) or $20,000 based on a natural gas value of $4.00 per Mcf (U.S. EIA, 2010).
56

4.0 SUMMARY

The EPA has used the data sources, analyses and studies discussed in this paper to form 

the Agency’s understanding of emissions from pneumatic controllers and pumps and the 

emissions mitigation techniques. The following are characteristics the Agency believes are 

important to understanding these sources of VOC and methane emissions.

4.1 Pneumatic Controllers

 The majority of recent emissions estimates for pneumatic controllers have focused on 

methane emissions and not VOC emissions.

 The GHG Inventory data estimates that pneumatic controller emissions are 13% of 

overall methane emissions from the oil and natural gas sectors.

 Recent emission measurement studies have resulted in a wide range of methane emission 

factors for natural gas-driven pneumatic controllers. The studies all show that emissions 

can vary depending on sector (e.g., production, transmission, or storage) and the type of 

gas-driven pneumatic controller.

 Natural gas-driven pneumatic controllers are particularly useful in segments of the oil and 

natural gas industry that involve remote locations where electrical power is not available 

or reliable.

 Low bleed gas-driven controllers can replace high bleed gas-driven controllers in many, 

but not all, applications.

 Where a reliable source of electrical power is available, instrument air systems can 

replace natural gas-driven pneumatic controllers, and result in no methane or VOC 

emissions.

 Zero bleed, mechanical, and solar-powered controllers can replace continuous bleed 

controllers in certain applications, but are not broadly applicable to all segments of the oil 

and natural gas industry.
57

4.2 Pneumatic Pumps

 Pneumatic pumps in the oil and natural gas industry are used as chemical injection pumps 

and circulation pumps for glycol dehydrators. Pressure from the natural gas line is used to 

power these pumps and the natural gas is vented to the atmosphere.

 There are several mitigation techniques that can be used to reduce or eliminate emissions 

from pneumatic pumps and they include: instrument air pumps and electric pumps (both 

AC and DC powered).

 The 2014 GHG Inventory data estimates that pneumatic pump emissions are 16% of 

overall methane emissions from the natural gas production and processing sectors. The 

2014 GHG Inventory estimated methane emissions from these sources to be 64,570 MT 

of methane for chemical injection pumps and 393,389 MT of methane for natural gasassisted Kimray pumps. Chemical injection pumps at petroleum systems emitted 49,973 

MT of methane, or around 3% of emissions from petroleum production. 

 Natural gas-driven pneumatic pumps are particularly useful in segments of the oil and 

natural gas industry that involve remote locations where electrical power is not available 

or reliable.

 Where a reliable source of electrical power is available, instrument air systems are an 

effective replacement for natural gas-driven pneumatic pumps.

5.0 CHARGE QUESTIONS FOR REVIEWERS

1. Did this paper appropriately characterize the different studies and data sources that quantify 

emissions from pneumatic controllers and pneumatic pumps in the oil and gas sector?

2. Please discuss explanations for the wide range of emission rates that have been observed in 

direct measurement studies of pneumatic controller emissions (e.g., Allen et al., 2013 and 

Prasino 2013). Are these differences driven purely by the design of the monitored controllers 

or are there operational characteristics, such as supply pressure, that play a crucial role in 

determining emissions?
58

3. Did this paper capture the full range of technologies available to reduce emissions from 

pneumatic controllers and pneumatic pumps oil and gas facilities? 

4. Please comment on the pros and cons of the different emission reduction technologies. Please 

discuss efficacy, cost and feasibility for both new and existing pneumatics.

5. Please comment on the prevalence of the different emission control technologies and the 

different types of pneumatics in the field. What particular activities require high bleed 

pneumatic controllers and how prevalent are they in the field?

6. What are the barriers to installing instrument air systems for converting natural gas-driven 

pneumatic pumps and pneumatic controllers to air-driven pumps and controllers?

7. Are there situations where it may be infeasible to use air driven pumps and controllers in 

place of natural gas-driven pumps and controllers even where it is feasible to install an 

instrument air system?

8. Did this paper correctly characterize the limitations of electric-powered pneumatic 

controllers and pneumatic pumps? Are these electric devices applicable to a broader range of 

the oil and gas sector than this paper suggests?

9. Are there ongoing or planned studies that will substantially improve the current 

understanding of VOC and methane emissions from pneumatic controllers and pneumatic 

pumps and available techniques for increased product recovery and emissions reductions?

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