# Oil and Natural Gas S ector Pneumatic

Devices

R e p o r t f o r O il and N atural G as Sector Pneumatic Devices

R e v i e w P a n e l April 2014

P r e p a r e d by
U

. S. E PA O f

f i c e o f A i r Q u a l i t y P l a nn i ng a n d S t a n d a r ds ( O A Q PS)

T h i s i n f or m a ti on i s d

i s t r i b u t e d so l e l y f or t h e p u rpose of pr e - d

i ss e m i n a ti on p ee r r

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y g u i d e li ne s. I t h as n ot b ee n f

or m a ll y d i ss e m i n a t e d by E P A . It do e s n ot r

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s h o u l d n ot be c o n s t

r u e d t o r e pr e s en t a n y A g enc y d e t e r m i n a ti on or po li cy .iiiii



### Tabl e of Contents

PREFACE

................................ ................................ ................................ ................................ ....... 1

1.0 INTRODUCTION

................................ ................................ ................................ ................. 2

1.1 Definition of the Source

................................ ................................ ................................ .... 2

1.1.1 Pneumatic Controlle rs

................................ ................................ ................................ .... 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. Oi l 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

................................ ......................... 28iv

2.2.1 Methane Emissions from the Natural Gas Industry (GRI/EPA, 1996c) (GRI/EPA, 1996e) 28

2.2.1.1 M

ethane 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 Technique s

............................... 36

3.1.1 Zero Bleed Pneumatic Controllers

................................ ................................ ............... 41

3.1.2 Low Bleed Pneumatic Controllers

................................ ................................ ............... 41

3.1.3 Instrumen t 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

................................ ................................ ................................ ............ 57v

5.0 CHARGE QUESTIONS FOR REVIEWERS

................................ ................................ ..... 57

6.0 REFERENCES

................................ ................................ ................................ .................... 581



### PREFACE

On March 28, 2014 the Obama Administration released a key eleme nt 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 e fforts 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
A gency is seeking input from i ndependent 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.html2



### 1.0 INTRODUCTION

The oil and natu ral 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 50 4,000 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 futur e 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 techn iques 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 p aper is natural gas

- driven pneumatic controllers and natural gas

driven pneumatic pumps

. Such p neumatic contro llers and pumps are widespread in the oil and natural gas industry and emit natural gas , which contains methane and VOC s

. In some applications, p neumatic controllers and pumps used in this industry ma y be driven by gases other than natural gas and, therefo re, do not emit methane or VOC s

.

1

. 1 .1 Pneumatic Controllers

For the purposes of this white paper, a p neumatic controller means an automated instrument used for maintaining a process condition such as liquid level, pressure, pressure difference and temper ature. 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 p neumatic controllers come in a variety of designs for a variety of uses. For the purposes o f this w hite p aper, 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 set

point to adjust gas pressure in the valve actuator. For the purposes o f this paper,

c ontinuous 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 scf h.

 Intermittent pneumatic controller means a pneumatic controller that vents non

continuously. These natural gas

- driven pneumatic controller s do not have a continuous bleed, but are actuated using pressurized natural gas.

 Z ero bleed pneumatic controller m eans a pneumatic controller that does not bleed natural gas to the atmosphere. Th ese natural gas

- driven pneumatic controller s are self

- contained devices that release gas to a downstream pipeline instead of to the atmosphere

.4

1.1. 2 Pneumatic Pumps

Pneum atic 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, 1996 d )

. The supply gas for these pumps can be compressed air, but most often these pumps use natural gas from the production stream (GRI/EPA, 1996 e )

.

1.2 Background

1 .2.1 Pneumatic Controllers

Pne umatic 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 us e 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 co ntinuously 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 r ates 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 thro ttle the gas flow; and (3) zero bleed controllers , which are self

- contained devices that release gas to a downstream pipeline instead of to the at mosphere (EPA, 2011a)

.

As noted above, i ntermittent controllers are devices that only emit gas during actuation and do not have a continuous bleed rate. T hus, t he actual amount of emissions from an intermittent controller is dependent on the amount of natu ral gas vented per actuation and how often it is actuated. Continuous bleed controllers also vent an additional volume of gas during5

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 fu nctionally 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 pres sure 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 p ower 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 VOC s , but may have secondary impacts related to generation of
requ ired 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, 1996 d ). These pumps have two major components , a driver side and a mot ive 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 . T he motive side of the pump d elivers 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/E PA, 1996 d ).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 sm all 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, su rfactants, oxygen scavengers and hydrogen sulfide scavengers (GRI/EPA, 1996 d ). These chemical s are normally injected using pneumatic pumps at the wellhead, and into gathering lines or at production separation facilities (GRI/EPA, 1996 d ). Pneumatic pumps , c ommonly 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, 1996 e ).

1.3 Purp ose of the White Paper

This w hite p aper 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 miti gation techniques . Section 4 summarizes the EPA’s understand ing 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 p neumatic 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 contro llers 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 t he studies relevant to pneumatic controllers , and Section 2.2 discusses the studies7

relevant to pneumatic pumps

. T hese 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, 1996 c ) 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

- 20 1 2 ( U

. S

. EPA , 201 4 ) EPA 201 4 Nationwide/ Regional X X

Greenhouse Gas Reporting Program ( U

. S

. EPA , 2013) EPA 2013 Basin X X

Measurements of M ethane E missions from N atural G as P roduction S ites 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 P ollutant E missions from the D evelopment, P roduction, and P rocessing of Marcellus Shale N atural G as (Roy et al

. , 2014) Carnegie Mellon University 2014 Regional (Marcellus S hale) 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 an d discusses pertinent studies and data sources that estimate emissions from pneumatic controller s

.8

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

This report ’s main objective was to quantify annual methane emissions from pneumatic controllers from the natural gas production , processing, transmission, and distribution sector s

. The methane emissions were determined by developing average annual emissions factors for the various types of pneumatic controllers used in each of the natura l gas se gments

. The annual emission factors were then extrapolated to a national estimate using activity factors for each of the natural gas se gment s

.

Production

The data used to develop emission factors for pneumatic controllers in the natural gas product ion sector were obtained from a study performed by the Canadian Petroleum Association (CPA) 1 , manufacturers’ data, measured emission rates 2 , data collected from site visits, and literature data for methane composition.

The CPA study consisted of methane a nd 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 p er 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, 1996 c ).

1 Picard, D.J., B.D. Ross, and D.W.H. Koon, A D etailed Inventory of CH 4 and VOC Emissions f

rom Upstream Oil and Gas Operations in Alberta . Canadian Petroleum Association, Calgary, Alberta, 1992. 2 Controller survey data provided by Te nneco 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 w ere 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 report ed maximum value (GRI/EPA, 1996c ).

The measured emissions data 4 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

. F or ste ady operating conditions , one data point was measured for 15

- 20 minutes

. F or 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 rate s for continuous bleed controllers were determined to be 872 scfd/device for onshore and offshore production sites and 1,363 scfd/device for transmission station s.

The measured emission data 5 also 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 b leed 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 w as determined to be 511 scfd/device.

Site visit data w ere 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

coun ts 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 type s of
gas

- operated pneumatic controllers : continuous bleed controllers and two types of intermittent bleed controll ers used to operate isolation valves 6 ( 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 dat a , 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 Systems 7 , 8 and the count of the isolation valves at four sites. Using th ese data,

6 Isolation valves at transmission stations are very large and are most oft en 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 Va ne, 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 devic e (scfy/device). For turbine

- operated isolation valves, the natural gas emissions were estimated using information provided by Limi torque Corporation 9 and 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 transmi ssion 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 use d
compre ssed air to operate the majority of pneumatic controllers at the plant s . Only one of the plants use d natural gas

- powered continuous bleed controllers , and five had natural gas

- driven pneumatic controllers for the isolation valves on the main pipeline emerg ency 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 controller s 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 P ersonal 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 Activ ity 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

cont rollers 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 produc tion, 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 emis sion 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 fro m 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 , 1996 c ). The activity factor for high bleed pneumatic controllers was determined to be 157,581 and assumes that tank batteries with heater treaters have fo ur 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 , 1996 c ).

The low bleed pneumatic controller methane emission factor was estimated to be 10 % of the high bleed methane emission factor or 3 5 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, 1996 c ) , 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

- 201 2 ( U

. S

. EPA , 201 4 )

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 wit h 1990.

The U.S. submits the GHG I nventory 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 thr ough 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 201 4 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 I nventory, 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 201 2 Nationwide Emissions from Pneumatic Controllers

Industry Segment Potential CH 4 Emissions ( MT ) CH 4

Emission Reducti ons ( MT ) Net CH 4

Emissions ( MT ) Natural gas and petroleum production a 1, 6 4 2,6 22 873,100 769,5 22 Natural gas processing 1,9 23 b b Natural gas transmission and storage 263, 561 14, 078 249, 483

a In the GHG Inventory, all Natural Gas STAR reductions for pne umatic 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 I nventory 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 non

zero.
The GHG Inventory data estimates that pneumatic controller emissions are 1 3 % of overall methane emissions from the oil and natural gas secto r s

. 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 201 4 G HG Inventory ’s estimates of 2012 methane emissions from pneumatic controllers in the natural gas and petroleum production industry segment. The table15

presents the population of pneumatic controllers , methane emission factors, potential methane emissions , a nd the estimated national total of pneumatic controllers and potential methane emissions

. The natural gas production data are broken down by the E nergy I nformation A gency’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 201 2 National and Regional Methane Emissions from Pneumatic

Co ntrollers in the Natural Gas and Petroleum Production Segment

NEMS Region Population of P neumatic Controllers a CH 4 Potential

E mission F actor ( scfd/device ) a CH 4 E missions (MT) Potential Emissions

- Natural Gas Systems North East 77,261 373 202,696
Midconti nent 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 38 6 145,057
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 43 5,103 Combined Natural Gas and Petroleum Systems
Total 892,403 1,6 4 2,622 Voluntary Emission Reductions

- Natural Gas and Petroleum 873,100 Net Emissions

- Natural Gas and Petroleum b 76 9,522

a 1996 GRI/EPA re port , extrapolated using r atios 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 likel y 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. F or the natural gas production segment, pneumatic controllers were estimated each year by applying a regional factor for the numbe r 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 fact or 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 petr oleum 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 regio n

- 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 co ntrollers

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 the se 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 o n 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 vo luntary 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 before17

being incorporated into the GHG Inv entory. F uture 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 201 4 GHG Inventory’s estimates of 201 2 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 CH 4 Potential

Emission Factor (scfy/plant) b C H 4 Potential

E missions ( MT ) CH 4 Emission

Reductions ( MT ) Net CH 4

Emissions ( MT )
606 gas plants a 164,721 1,92 3 c c

a Oil and Gas Journal , with available 201 2 activity data

. b 1996 GRI/EPA report

. c Although voluntary Natural Gas STAR emission reductions a re 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 1 996 GRI/EPA report. This potential emission factor is expressed in terms of standard cubic feet per year per processing plant (scfy/plant)

. T he associated activity factor is the number of U.S. gas plants, which comes from the Oil and Gas Journal

.

The GHG I nventory does not report emissions reductions specific to pneumatic

contr ollers 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 201 4 GHG Inventory’s es timates of 201 2 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) CH 4 Potential

Emission Factor (scfy/device) CH 4

Potential Emissions (MT) CH 4

Emission Reductions (MT) Net CH 4

Emissions (MT)
Transmission 70,827 162,197 a 221,257 Storage 13,542 162,197 a 42,304
Total 84 ,369 263,561

- 14,078 b 249, 483

a 1996 GRI/EPA report

. b V oluntary 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 poten tial 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

. T he 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.

T he 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 segm ent

.

2. 1

. 4 Greenhouse Gas Reporting P rogram ( 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 GHG s and products that would emit GHGs if released or combusted.19

When reviewing this data and comparing it to other dat a 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 CO 2 equivalent ( MT CO 2 e ) or more. Facilities use uniform methods prescribed by the EPA to calculate GHG emissions, such as direc t 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 reg ulations at 40 CFR part 98, subpart W. T he 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 ga s tr ansmission 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 CO 2 . In the natural gas transmission and storage segments, default gas composition factors are used. Subpart W emission factors for pneumatic controller s are located at 40 CFR Part 98, s ubpart 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 d ocument 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 facilities 11 in each o f 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 Emis sions 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 tho se 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, Mi dcontinent, 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 natur al 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 so urces 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 o wner. 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 S tudy

Methane Emissions per Pneumatic Controller Appalachian Gulf Coast Midcontinent Rocky Mtn. Total
Nu m ber sampled a 133 106 51 15 305
E m issions rate (scf methane / m i n/device) b 0.126 ± 0.043 0.268 ± 0.068 0.157 ± 0.083 0.015 ± 0.016 0.175 ± 0.034

E m issions rate (scf whole gas/ m i n/device, based on site

- specific gas co m position ) b 0.130 ± 0.044 0.289 ± 0.071 0.172 ± 0.086 0.021 ± 0.022 0.187 ± 0.036

a Inter m i tte n t and low bleed controllers a r e in c l u ded in the t o tal; no high bleed co n t r o ll e rs were reported by

co m panies providing controller type info r m ation b Uncertai n ty characterizes the va ri a bility in the m ean of the d a ta s e t, rather than an instru m ental uncer tainty in a single m e a sure m ent
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 emis sions 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 th at 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 Ro cky Mountain and Appalachian regions. The difference in average values is more than a factor of 1022

between Rocky Mountain and Gulf Coast regions. The study provided the following discussion of these differences:

Some of the regional differences in emission s 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 con trollers 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 consist ing 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 c an 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 (4 47,379) 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 com pleted 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 bellow s 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 (m 3/ 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 rate s 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 t emperature differences.” The report notes that metering a device can affect the operation of the device when hooked up due to back pressure , adding that i t is possible that certain controllers did n o t 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 i ndividual models of pneumatic controllers, t he study generated emission factor s for “generic high bleed controller s ” 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 sev eral 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 Fa ctors 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 Pressure c Generic High Bleed Controller 0.2605 9.199 0.0012
Generic High Bleed Intermittent Controller 0.2476 8.744 0.0012

a “ Bleed rate ” d efined 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 Pr a sino 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 (R 2 values) for these supply pressure coefficie nts 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 Atmosph eric 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 curre nt 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 fr om 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 b e on the order of 10 tons/day in 2009

.
This study developed these emissi ons 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 Emission s f rom 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 factor s for pneumatic control lers associated with each natural gas well , which were drawn primarily from a 2008 ENVIRON report. 13 Table 2

- 11 shows these assumptions.

13 Bar

- I lan, Amnon et al., ENVIRON International Corporation. Recommendations for Improvement to the CENRAP States’ Oil and Gas Emissions Inventories . Prepared for the Central States Reg ional Air Partnership. November 13, 2008. This report also includes emission f actors for positioners (15.2 scfh) and transducers26

Table 2

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

Associated with Each Natural Gas Well

T ype 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 no t 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 pneumat ic 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 E missions 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 201 3 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 emis sions, 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 pneum a tic controllers per gathering/boosting station that were not accounted for in the 201 3 GHG Inventory. The study also used emission fact ors 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 anal yzed, 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 calc ulate 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 continuous ly 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 contr ollers : 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 an28

increase of 41% (26 Bcf or 4 91 ,000 MT ) in methane emissions in comparison to the 201 3 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 co

control benefits from the replacement of these pneumatic controllers are presented in S ect ion 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

sec tion and only the information relevant to pneumatic pumps is discussed.

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

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

/EPA reports ; chemical injection pumps (GRI/EPA, 1996 d ) and gas

- assisted glycol
pumps (GRI/EPA, 1996 f

). 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, 1996 c )

Th is report estimates emissions from two types of pumps that the oil and nat ural 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 injection29

pumps: a study by the CPA 14 , data collected from site visits, literature data for me thane composition, and data from pump manufacturers.

The CPA study provided natural gas emissi ons 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 (s cfd/pump) with an average of 334 scfd/pu mp.

Data from site visits included: the total number of chemical injection pumps for a particular site, number of chemical injection pump s 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

c omposition of 78 .8 % (GRI/EPA, 1996 d ).

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 CH 4 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 M easurement s 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%

Manufacturer s ’ data and the CPA data w ere used to determine the volume of gas released per pump stroke. Thi s 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 calcul ated 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 av erage 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 t o be 446 scfd/pump and the emission factor for piston pumps was calculated to be 48.9 scfd/pump

.

T he percentage of piston and diaphragm pumps and their respective emission factors were then used to calculate an average emission factor for chemical injecti on 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, 1996 a ) . 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

– G as
- Assisted Glycol Pumps (GRI/EPA, 1996 e )

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 s tream 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, 199 6 e ).

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 operatin g 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 treate d 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 f raction 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 final32

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

- press ure. 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 us ed. 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 fra ction 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 processin g 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 dehydrato r s with gas

- assisted pum ps. 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 nationa l 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 S inks : 1990

- 201 2 ( U

. S

. EPA , 2014 )

Table 2

- 1 3 summarizes the 2014 GHG Inventory estimates of 2012 national methane emissions from pneumatic pump s in the natural gas production and processing segment s

. (Note: The GHG inventory does not include estimates of em issions from pneumatic pumps in the natural gas transmission and storage segments

. ) The pneumatic pumps described in the GHG
I nventory include: chemical injection pumps and Kimray pumps. T he table includes potential emissions, emission reductions and net e missions. For pneumatic pumps, the emission reductions33

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

- 1 3 . S ummary of GHG Inventory 2012 Nationwide Emissions

from Pneumatic Pumps

Industry Segment Potential CH 4

Emissions ( MT ) CH 4 Emission

Reductions (MT) Net CH 4

Emissions ( MT ) Natural gas production 455,719 2,771 452,948
Petroleum Production 49,973 N/A
Natu ral gas processing 5,011 N/A

The 201 4 GHG Inventory data estimates that pneumati c pump emissions are around 16 % of overall methane emissions from the natural gas production and processing sectors.

Tables 2

- 1 4 and 2

- 1 5 show the 201 4 GHG Inventory ’s estim ates of 201 2 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 e mission 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 factor s for chemical injection pu mps 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 0.0 1 to 0.6 8 ) 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) . F or the processing segment, the activity factor for Kimray pumps is based the total processing plant throughput multiplied by the fraction of na tural gas treated by dehydrators at34

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

- 1 4 . Estimated 2012 National and Regional Methane Emissions from Chemical

Injection Pumps in the Natural Gas Production Segment

NEMS Region Population of Chemical Injection Pumps a CH 4 Potential E mission

Factor ( scfd/device ) a CH 4 Emissions (MT)
Natural Gas Production
North East 795 268 1,499
Midcontinent 15,343 260 28,045 Rocky Mou ntain 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 49,97 3

a 1996 GRI/EPA report, extrapolated using ratios relating other factors for which activity data are available.
Table 2

- 1 5 . Estimated 201 2 National and Regional Methane Emissions from Kimray

Pumps in the Natural Gas Production and Processing Segments

NEM S Region Total Natural Gas using Kimray Pumps a CH 4 Potential E mission Factor ( scfd/

MMscf ) a CH 4 Emissions

(MT)
Natural Gas Production
North East 6,487,241 1,073 134,073
Midcontinent 4,409,271 1,040 88,32 2 Rocky Mountain 3,404,114 975 63,934
South We st 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 Processing35

All Regions 1,463,675 178 5,011
Total Potential Emissions 393,389

a 1 996 GRI/EPA report, extrapolated using ratios relating other factors for which activity data are available. Note: The GHG I nventory did not list any Kimray pumps in the natural gas transmission or distribution sectors.

The basis for the GHG Inventory’s po tential 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 compo sition 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 require s facilities in the onshore petroleum and natural
gas pro duction 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

. F acilities also apply a fa cility

- 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 m ethane 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 pump s to be 0.5917 m 3 /hr36

(approximately 20.9 scfh). For diaphragm

- type pneumatic pumps, the bleed rate was calculated to be 1.0542 m 3 /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 include s an inventory of methane emissions for 2011 using data from the 2013 GHG Inven tory 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 th e 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

- a ssisted glycol pumps) were estimated to be 1 7 Bcf (32 1 ,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 c ontrollers 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 Techni ques

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 lo w bleed or zero bleed37

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

- gas

- driven control ler s, and enhanced maintenance.38 Table 3

- 1. Summary of Alternative Mitigation Techniques for Pneumatic Controllers

Option Descripti on 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 self

contained natural gas

- driven devices that vent to the downstr eam 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 low

pressure control valves, e.g., in gathering, metering a nd 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 infor mation 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 functio nal 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 Natu ral 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 Descripti on Applicability Costs Efficacy and Prevalence Convert to Instrument Air (U

. S

. EPA, 2006c) Compress ed 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
c onversion 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 co ncentration 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 depen dent 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. T here are secondary emissions associated with electrical power gener ation.

The EPA does not have information on the prevalence of this technology in the field.

Mechanical and Solar

Powered 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. Electric

powered valves are only reliable with a constant supply of electric ity (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 t he field.40 Table 3

- 1. Summary of Alternative Mitigation Techniques for Pneumatic Controllers

Option Descripti on 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 controlle r s (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

Th e 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 th e 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 suita ble 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

L ow bleed controllers provide similar functional control as high bleed controlle rs , but have lower continuous bleed emissions. I t 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, 20 11a) . 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, b ut 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 resp onse time is needed, cases where large valves require a high bleed rate to actuate, or a safety isolation valve is involved.

Replacing h igh 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 wher e pneumatic controllers monitor the suction and discharge pressure and actuate a recycle when one or the other is out of the specified target range. Ano ther scenario where fast and precise control is necessary include s transient (non

- steady) situations whe re 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 presen t 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 un acceptable. E mergency valves are often not controlled with bleeding controllers (e.g ., neither low bleed n or 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 E mergency 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 w ill be lost. For this reason, control valves are deliberately selected to either fail open or fail closed, depending on which option is the failsafe.

Cost s

The c osts described in this section a re based on vendor research and information given in the append ices 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 o f 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 Controllers a

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 ga s captured to the s ales 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 th e 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. 17 The average market price for natural gas in 20 10 was approximately $4.16 per M cf

. This is much less compared to the aver age price in 2008 of $7.96 per M cf

. Due to the volatility in the value , a con servative savings of $4.00 per M cf 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 producti on 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 transm ission 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 fo r 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 dev ices 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 instal led. 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

av ailable, 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 eit her an existing electric power supply or have their own power generation system. For smaller facilities and in remote locations, however, a reliable source of45

electric power can be difficult to ensure . In some instances, solar

- powered battery

operated 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 compre ssor 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 orif ices.

 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 shor t 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 pneumati c 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, the se system s 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 o f 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 System47

Cost s

Instrument air conversion requires additional equipment to proper ly 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 p neumatic 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 alter native 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 pneumat ic 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 Cos ts for Various Sized Instrument Air Systems a
Compressor Power Requirements b Flow Rate Control Loops Size of Unit H p 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 w ith 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, includin g installation and labor, of three representative sizes of compressors based on assumptions found in the Natural Gas STAR48

document, “Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air” a re 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 o f levers, hand wheels, springs and flow channels with the most common mechanica l 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 solar

powe red) 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 som e 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 belo w $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 Capital a Annualized

Capital b Labor

Cos t Total

Annual Costs c 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 b e equal to 1.5 times the cost of capital. Equipment costs were derived from the Natural Gas Star Lessons Learned docume nt 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

M anufacturers 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 mor e flow through a larger opening.

 Broken or worn diaphragms, bellows, fittings, and nozzles.

 Corrosives in the gas leading to erosion or corr osion of control loop internals.

 Improper installation.

 Lack of maintenance (maintenance includes replacement of the filter used to remove debris from the supply gas and repla cement of O

- rings and/or seals).

 Lack of calibration of the controller or adjustment of the distance between the flapper and nozzle.

 Foreign materi al lodged in the pilot seat.

 Wear in the seal seat

. Maintenance of pneumatics can correct many of these problems and can be a n effective method for reducing emissio ns. 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

unnece ssary valve positioners can save up to 18 scfh per device ( U

. S

. EPA , 2006a)

.
However, p roper methods of maintaining a device are highly variable , t hus, costs are

v ariable based on labor, time, and fuel required to travel to many remote locations.

3.2 Avai lable Pneumatic Pump Emissions Mitigation Techniques

There are several techniques t hat are currently being used t o reduce emissions from pneumatic pumps . Table 3

- 5 provides a summary of these techniques for reducing emissions51

from pneumatic pumps, which in clude 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 locatio ns. 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 ai r 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 ca n 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 natu ral 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 incrementa l operating costs are estimated to be $100 to $1,000 (U.S. EPA, 2011b). The potential annual52 Table 3

- 5

. Summary of Alternative Mitigation Techniques for Pneumatic Pumps

Option Description Applicability Costs Efficacy and Prevalence Replace natural gas

- a ssisted pump with instrument air pump (U

. S

. EPA, 2011b) Circulation pumps in glycol dehydration

units and chemical injection pumps are retrofitt ed with instrument air to drive the pumps (U

. S

. EPA, 2011b)

. Facilities with excess capacity of instrument air o r 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 fr om 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 2,50 0 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 gas

assisted pump with solar

- charged direct curren t 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 ps ig. 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 p artner s for Natural Gas STAR stated a replacement cost of $2,000 per pump
, i nclud ing 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 gas

assisted pump with electric pump (ICF, 2014) In settings where a constant supply of

electricity is available , natural gas pneumatic pumps can be re placed 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)

. Electrica l 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 elect rical 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

m aximum 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

- po wered 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 i nto 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

T he Natural Gas STAR p rogram reported the cost of replacing pneumatic pumps with solar

- charged electric pumps to be approximately $2,000 per pump ( U

. S

. EPA , 2011b ). The solar55

panels and storage batteries are nearly maintenance free, and the solar panels hav e a life span of

u p 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. EI A, 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 $4.0 0 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 hav e 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

E lectrical 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 controlle rs and pumps and the emissions mitigation techniques . The following are characteristics the Agency believes are important to understanding th e s e source s 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 1 3 % of overall methane emissions from the oil and natural gas sectors.

 Recent emission measurement studi es have resulted in a wide range of methane emission factors for n atural gas

- driven pneumatic controllers

. T he studies all show that emissions can vary depending on sector (e.g., production, transmission, or storage) and the type of
gas

- driven pneumatic co ntroller.

 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 n atural gas

- driven pneumatic controllers , and result in no methane or VOC emissions

.

 Zero bleed, m echanical, 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 i ndustry 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 201 4 GHG Inventory data estimates that pneumatic pump emissions are 1 6 % 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 gas

assisted Kimray pumps. Chemical injecti on 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 whe re electrical power is not available or reliable.

 Where a reliable source of electrical power is available, instrument air systems are an effective replacement for n atural gas

- driven pneumatic pumps

.



### 5.0 CHARGE QUESTIONS FOR REVIEWERS

1. Did this paper approp riately 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 emissi on 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 particul ar activities require high bleed pneumatic controllers and h ow 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 c ontrollers ?

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 th e 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 t he 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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