Oil and Natural Gas Sector 

Liquids Unloading Processes

Report for Oil and Natural Gas Sector

Liquids Unloading Processes

Review Panel

April 2014

Prepared by

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

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

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

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

i

Table of Contents

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

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

2.0 OIL AND NATURAL GAS SECTOR LIQUIDS UNLOADING AVAILABLE 

EMISSIONS DATA AND EMISSIONS ESTIMATES................................................................. 4

2.1 Greenhouse Gas Reporting Program (U.S. EPA, 2013) .................................................. 5

2.2 API/ANGA 2012 Survey Data (API and ANGA, 2012) ................................................. 6

2.3 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014) 8

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

States (Allen et al., 2013)............................................................................................... 10

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

Oil and Natural Gas Industries (ICF International, 2014).............................................. 11

3.0 AVAILABLE LIQUIDS UNLOADING EMISSIONS MITIGATION TECHNIQUES

14

3.1 Liquid Removal Technologies....................................................................................... 14

3.1.1 Primary Techniques................................................................................ 20

3.1.2 Remedial Techniques............................................................................. 23

4.0 SUMMARY ................................................................................................................... 25

5.0 CHARGE QUESTIONS FOR REVIEWERS ............................................................... 26

6.0 REFERENCES............................................................................................................... 28
1

PREFACE

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

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

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

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

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

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

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

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

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

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

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

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

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

The white papers are available at: 

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

1.0 INTRODUCTION

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

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

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

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

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

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

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

hydraulic fracturing).

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

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

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

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

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

In new gas wells, there is generally sufficient reservoir pressure to facilitate the flow of 

water and hydrocarbon liquids to the surface along with produced gas. In mature gas wells, the 

accumulation of liquids in the well can occur when the bottom well pressure approaches 

reservoir shut-in pressure. This accumulation of liquids can impede and sometimes halt gas 

production. When the accumulation of liquid results in the slowing or cessation of gas 

production (i.e., liquids loading), removal of fluids (i.e., liquids unloading) is required in order to 

maintain production. Emissions to the atmosphere during liquids unloading events are a 

potentially significant source of VOC and methane emissions.

Most gas wells will have liquid loading occur at some point during the productive life of 

the well. When this occurs, common courses of action to improve gas flow include (U.S. EPA, 

2011): 

 Shutting in the well to allow bottom hole pressure to increase, then venting the well to the 

atmosphere (well blowdown, or “blowing down the well”), 
3

 Swabbing the well to remove accumulated fluids,

 Installing a plunger lift,

 Installing velocity tubing, and

 Installing an artificial lift system. 

Blowing down the well involves the intentional manual venting of the well to the 

atmosphere to improve gas flow, whereas the use of a plunger lift system uses the well’s own 

energy (gas/pressure) to lift liquids from the tubing by pushing the liquids to the surface by the 

movement of a free-traveling plunger ascending from the bottom of the well to the surface. The 

plunger essentially acts as a piston between liquid and gas. Use of a plunger lift often minimizes 

and sometimes eliminates the need for blowing down the well.

Because of the potential for substantial VOC and methane emissions occurring during 

liquids unloading at natural gas wells, there are an increasing number of studies on emissions 

from natural gas well liquids unloading events. These studies of liquids unloading practices

attempt to quantify emissions on a well specific, regional and national level and often take into 

account the use of available mitigation techniques, such as plunger lifts. This document provides 

a summary of the EPA’s understanding of VOC and methane emissions from natural gas 

production liquids unloading events, available liquids unloading and emission mitigation 

techniques, the relative magnitude of emissions associated with the respective techniques and the 

efficacy and prevalence of those techniques in the field. Section 2 of this document provides our 

understanding of emissions from liquids unloading events, and Section 3 provides our 

understanding of available liquids unloading and emissions mitigation techniques. Section 4

summarizes the EPA’s understanding based on the information presented in Sections 2 and 3, 

and Section 5 presents a list of charge questions for reviewers to assist us with obtaining a more 

comprehensive understanding of liquids unloading VOC and methane emissions and emission 

mitigation techniques for the liquids unloading process.
4

2.0 OIL AND NATURAL GAS SECTOR LIQUIDS UNLOADING 

AVAILABLE EMISSIONS DATA AND EMISSIONS ESTIMATES

Given the potential for significant emissions from liquids unloading, there have been 

several information collection efforts and studies conducted to estimate emissions and available 

emission mitigation techniques. Some of these studies are listed in Table 2-1, along with an 

indication of the type of information contained in the study (i.e., activity level, emissions data, 

mitigation techniques).

Table 2-1. Summary of Major Sources of Liquids Unloading Information

Name Affiliation

Year of 

Report

Activity 

Data

Emissions 

Data

Mitigation 

Techniques

Greenhouse Gas Reporting Program

(U.S. EPA, 2013)

U.S.

Environmental 

Protection 

Agency

2013 Sub-basin X X

Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2012

(2014 GHG Inventory)

(U.S. EPA, 2014)

U.S.

Environmental 

Protection 

Agency

2013 Regional X X

Characterizing Pivotal Sources of 

Methane Emissions from Natural Gas 

Production: Summary and Analysis 

of API and ANGA Survey Responses 

(API and ANGA, 2012)

American 

Petroleum 

Institute 

(API)/America’s 

Natural Gas 

Alliance (ANGA)

2012 Regional X X 

Measurements of Methane Emissions 

at Natural Gas Production Sites in the 

United States (Allen et al., 2013)

Multiple 

Affiliations, 

Academic and 

Private

2013

9 Liquids 

Unloading 

Events

X X

Economic Analysis of Methane 

Emission Reduction Opportunities in 

the U.S. Onshore Oil and Natural 

Gas Industries (ICF International, 

2014)

ICF International 

(Prepared for the 

Environmental 

Defense Fund)

2014 Regional X X

A more-detailed description of the data sources listed in Table 2-1 is presented in the 

following sections, including how the data may be used to estimate national VOC and methane

emissions from liquids unloading events. 
5

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

In October 2013, the EPA released 2012 greenhouse gas (GHG) data for Petroleum and 

Natural Gas Systems1collected under the Greenhouse Gas Reporting Program (GHGRP). The 

GHGRP, which was required by Congress in the FY2008 Consolidated Appropriations Act, 

requires facilities to report data from large emission sources across a range of industry sectors, as 

well as suppliers of certain GHGs and products that would emit GHGs if released or combusted.

When reviewing this data and comparing it to other datasets 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 facility2in the Petroleum and Natural Gas Systems source 

category is required to submit annual reports if total emissions are 25,000 metric tons carbon 

dioxide equivalent (CO2e) or more. Facilities use uniform methods prescribed by the EPA to 

calculate GHG emissions, such as direct measurement, engineering calculations, or emission 

factors derived from direct measurement. In some cases, facilities have a choice of calculation

methods for an emission source.

The liquids unloading source emissions reported under the GHGRP include emissions 

from facilities that have wells that are venting, including those wells that vent during plunger lift 

operation. Liquids unloading techniques that do not involve venting are not reported. The total 

reported methane emissions in 2012 for liquids unloading were approximately 276,378 metric 

tons (MT). Facilities were given the option among three methods for calculating emissions from 

liquids unloading. The first calculation method involved using a representative well sample to 

calculate emissions for both wells with and without plunger lifts. The second and third 

 

1 The implementing regulations of the Petroleum and Natural Gas Systems source category of the GHGRP are 

located at 40 CFR Part 98 Subpart W.

2

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

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

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

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

American Association of Petroleum Geologists). 
6

calculation methods provided engineering equations for wells with plunger lifts and without 

plunger lifts. 

Of the 251 facilities that reported emissions for well venting for liquids unloading, 120

facilities reported using Best Available Monitoring Methods (BAMM) for unique or unusual 

circumstances. Where a facility used BAMM, it was required to follow emission calculations 

specified by the EPA, but was allowed to use alternative methods for determining inputs to 

calculate emissions. These inputs are the values used by facilities to calculate equation outputs or 

results. Table 2-2 shows the activity count and reported emissions for the different calculation 

methods.

Table 2-2. Greenhouse Gas Reporting Program 2012 Reported Emissions from Liquids 

Unloading (U.S. EPA, 2013)

Calculation Method

Number of 

Facilities 

Reportinga

Number of Wells 

Venting During 

Liquids 

Unloading

Number of Wells

Venting that are 

Equipped With 

Plunger Lifts

Reported CH4

Emissions (MT)b

Method 1: Direct 

Measurement of 

Representative Well 

Sample

42 10,024 7,149 112,496

Method 2: Engineering 

Calculation for Wells 

without Plunger Lifts

188 23,536 0 71,593

Method 3: Engineering 

Calculation for Wells 

with Plunger Lifts

132 25,103 25,103 92,289

Total 251 58,663 32,252 276,378

a Total number of facilities is smaller than the sum of facilities from each method because some 

facilities reported under both Method 2 and Method 3.

bThe reported CH4 MT CO2e emissions were converted to CH4 emissions in MT by dividing by a global 

warming potential (GWP) of methane (21). 

2.2 API/ANGA 2012 Survey Data (API and ANGA, 2012)

The API/ANGA 2012 Survey Data includes a dataset from over 20 companies covering 

over 90,000 gas wells, including approximately 59,000 wells that conducted liquids unloading 
7

operations. This study sample population includes representation from most of the geographic 

regions of the country as well as most of the geologic formations currently developed by the 

industry. The study provides estimated methane emissions from liquids unloading for 5,327 

wells that were calculated based on well characteristics such as well bore volume, well pressure, 

venting time, and gas production rate and using 40 CFR part 98, subpart W engineering 

equations. These emissions estimates and the activity data used to calculate the estimates are 

presented in Table 2-3.

Table 2-3. API/ANGA Study Liquids Unloading Emissions Estimates 

(API and ANGA, 2012; pg. 14)

Mid-Level Survey Data

Total number of wells with plunger lift (42,681 in sample) 11,518

Total number of wells without plunger lift (42,681 in sample) 31,163

Number of plunger equipped wells that vent (42,681 in sample) 2,426 (21.1%)

Number of non-plunger equipped wells that vent (i.e., wells 

performing blowdowns)(42,681 in sample)

2,901 (9.3%)

Total annual volume gas vented for venting wells

1,719,843,596 standard cubic feet (scf)

gas/year

Calculated volume vented gas per venting well 322,854 scfy gas/well

Calculated methane volume vented per venting well 254,409 scfy CH4/well

Calculated National Well Data

Calculated national number of wells with plunger lift

that vent for unloading 36,806

Calculated national number of wells without plunger lift

that vent for unloading (i.e., wells performing blowdowns) 28,863

National Emission Calculations

Total gas venting for liquids unloading volume 

(scaled for national wells) 21,201,410,618 scf gas/yr

Total methane venting for liquids unloading 

(scaled for national wells) 16,706,711,567 scf CH4/yr

Total liquid unloading vented methane 

(scaled for national wells) 319,664 MT CH4/yr
8

The authors of the study made the following conclusions:

 The 2012 GHG Inventory emissions estimates for liquids unloading were

overestimated by orders of magnitude. The API/ANGA Survey data indicated a lower 

percentage of gas wells that vent for liquids unloading and a shorter vent duration.

 The emissions from liquids unloading are not specific to only conventional wells, but 

can be for any well depending on several technical and geological aspects of the well. 

 Although most wells do not require liquids unloading until later in the well’s 

productive lifetime, the timeframe for initiating liquids unloading operations varies 

significantly and can be early in the well’s productive life span. 

 Most of the emissions from liquids unloading operations are produced by less than 

10% of the venting well population.

The study does not discuss the characteristics that cause certain wells to have 

significantly higher emissions than other venting wells. The study showed that the majority of 

emissions came from a small percentage of venting wells, and both conventional and 

hydraulically fractured wells can vent during liquids unloading. Additionally, while a large 

percentage of wells equipped with plunger lifts do not vent during liquids unloading events, 

many wells with plunger lifts produce emissions during liquids unloading events. This suggests 

that plunger lifts are capable of unloading liquids from a well without venting, but in many cases 

they are operated in a manner that results in venting. It is not clear to the EPA what the 

conditions are that cause these wells with plunger lifts to be operated in a manner that results in 

significant venting during liquids unloading.

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

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

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

removals by source and by economic sector over a time series, beginning with 1990. The U.S. 

submits the GHG Inventory to the United Nations Framework Convention on Climate Change 

(UNFCCC) as an annual reporting requirement. The GHG Inventory includes estimates of 

methane and carbon dioxide for natural gas systems (production through distribution) and 
9

petroleum systems (production through refining). The 2014 GHG Inventory data (published in 

2014; containing emissions data for 1990-2012) was evaluated for information on liquids 

unloading emissions.

The 2014 GHG Inventory applied calculated National Energy Modeling System (NEMS) 

(U.S. EPA, 2014) region- and unloading technology-specific emission factors to the percentage 

of wells requiring liquids unloading by using the percentages of wells venting for liquids 

unloading with plunger lifts, and wells without plunger lifts in each region based on API/ANGA 

Survey data (see Section 2.1.1.3 for a discussion on this data). 

The 2014 GHG Inventory activity data (number of wells), emissions factors (standard 

cubic feet per year [scfy]/well) and the calculated emissions for liquids unloading are presented 

by NEMS region in Table 2-4. 

Table 2-4. Data and Calculated CH4 Emissions [MT] for the Natural Gas 

Production Sector by NEMS Region (U.S. EPA, 2014, ANNEX 3 Methodological 

Descriptions for Additional Source or Sink Categories)

NEMS

Region Activity

Activity 

Dataa,b

(number of 

wells)

Emission Factor

(scfy)/wellb

Calculated Emissions 

(MT)

North East

Liquids Unloading 

(with plunger lifts)

6,924 268,185 35,764

Liquids Unloading 

(without plunger 

lifts; blowdowns)

17,906 141,646 48,849

Midcontinent

Liquids Unloading 

(with plunger lifts)

2,516 1,140,052 55,245

Liquids Unloading 

(without plunger 

lifts; blowdowns)

4,469 190,179 16,369

Rocky Mountain

Liquids Unloading 

(with plunger lifts)

10,741 119,523 24,726

Liquids Unloading 

(without plunger 

lifts; blowdowns)

1,267 1,998,082 48,758
10

NEMS

Region Activity

Activity 

Dataa,b

(number of 

wells)

Emission Factor

(scfy)/wellb

Calculated Emissions 

(MT)

South West

Liquids Unloading 

(with plunger lifts)

1,379 2,856 76

Liquids Unloading 

(without plunger 

lifts; blowdowns)

8,078 77,899 12,120

West Coast

Liquids Unloading 

(with plunger lifts)

159 317,292 972

Liquids Unloading 

(without plunger 

lifts; blowdowns)

142 279,351 764

Gulf Coast

Liquids Unloading 

(with plunger lifts)

1,784 61,758 2,122

Liquids Unloading 

(without plunger 

lifts; blowdowns)

5,445 265,120 27,803

Total 60,810 273,568

aDI Desktop, 2014.

bAPI/ANGA 2012 Survey Data, Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production 

– Summary and Analysis of API and ANGA Survey Responses (API and ANGA, 2012).

The 2014 GHG Inventory data estimates that liquids unloading emissions in 2012 were 

14% of overall methane emissions from the natural gas production segment.

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

States (Allen et al., 2013)

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

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

emission estimates to the 2011 estimates reported in the EPA’s 2013 GHG Inventory. The 

sources or operations tested included liquids unloading. Under this study, sampling was 

performed for liquids unloading in which an operator manually bypassed the well’s separator. 

These manual unloading events could be scheduled, which allowed time to install measurement 

equipment. 
11

Analysis included nine well unloading events, ranging from 15 minutes to two hours, 

including both continuous flow and intermittent flow events. Some of the wells sampled only 

unloaded liquids once over the current life of the well, where others were unloaded monthly. The 

average emissions per unloading event were 1.1 MT of methane (95% confidence limits of 0.32-

2.0 MT). The study reports that the average emissions per well per year (based on the emissions 

per event for each well multiplied by the frequency of the events per year reported by the well 

operator) was 5.8 MT. The study acknowledges that the sampled population characteristics 

reflected a wide range of emission rates and that when emissions are averaged per event, 

emissions from four of the nine events contribute more than 95% of the total emissions. This 

result is consistent with the API/ANGA 2012 Survey Data and 2012 data reported to the 

GHGRP; all suggest that certain wells produce significantly more emissions during liquids 

unloading events than others. The study also suggests that the length of the liquids unloading 

event and the number of events are crucial factors in a well’s annual emissions from liquids 

unloading.

The authors report that their study supports their belief that the application of the 

API/ANGA 2012 Survey data method used when calculating the 2013 GHG Inventory

overestimates GHG emissions. Although the authors believe that their study provides valuable 

information, they caution that the sampling in their study was insufficient to characterize 

emissions from liquids unloading for all well sites in all basins and recommend that additional 

measurement of unloading events be conducted in order to improve national emissions estimates. 

Because characteristics of the unloading events sampled in the study were highly variable, and 

because the number of events sampled was small, the authors caution the use of the data to 

extrapolate to larger populations.

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

Onshore Oil and Natural Gas Industries (ICF International, 2014)

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

conduct an economic analysis of methane emission reduction opportunities from the oil and 
12

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. Liquids 

unloading is one of the 22 emission sources that is included in the study. 

The study relied on the EPA’s 2013 GHG Inventory for methane emissions data for the 

oil and natural gas sector. This emissions data was revised to include updated information from 

the GHGRP (EPA) 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. The 

projected emissions are not discussed further here, because projected emissions are not a topic 

covered by this white paper.

The study used the GHGRP data for 2011 and 2012 to develop new activity and emission 

factors for wells with liquids unloading. It was assumed that the respondents represented 85% of 

the industry, therefore, the EPA’s 2013 GHG Inventory estimate of the number of venting wells 

with plunger lifts was increased to 44,286 from 37,643, and the estimate of the number of 

venting wells without plunger lifts was increased to 31,113 from 26,451.3The emission factors 

were updated by dividing the total emissions for each venting well type (those equipped with 

plunger lifts and those that were not equipped with a plunger lift) by the total number of 

reporting wells. The calculated emission factors were 277,000 scf/venting well for wells with 

plunger lifts and 163,000 scf/venting well for wells without plunger lifts. Using these updated 

emission factors, ICF estimated a net increase of methane emissions from liquids unloading (as 

compared to the EPA’s 2013 GHG Inventory) by approximately 30% to 17 billion cubic feet 

(Bcf)(approximately 321,012 MT). This represented the study’s baseline methane emissions for 

2011 for liquids unloading.

 

3 The EPA is unaware of how the study authors determined the GHGRP data represented 85% of the industry.
13

Further information included in this study on the use of a plunger lift as a mitigation or 

emission reduction option, methane control costs, and their estimates for the potential for VOC 

emissions co-control benefits from the use of a plunger lift are presented in Section 3.1 of this 

document. 
14

3.0 AVAILABLE LIQUIDS UNLOADING EMISSIONS MITIGATION 

TECHNIQUES

As noted previously, many natural gas wells have sufficient reservoir pressure to flow 

formation fluids (water and hydrocarbon liquids) to the surface along with the produced gas. As 

the bottom well pressure approaches reservoir shut-in pressure, gas flow slows and liquids 

accumulate at the bottom of the tubing. A common approach to temporarily restoring flow is to 

vent the well to the atmosphere (well “blowdown”) which removes liquids but also produces 

emissions.

Several techniques are available that could produce less (compared to blowdown) or no 

emissions from liquids unloading. The following section describes techniques that remove 

liquids from the well by other means than a blowdown and in the process can reduce the amount 

of vented gas and, thus, reduce the VOC and methane emissions. These technologies can reduce 

the need for liquids unloading operations or result in the capture of gas from liquids unloading 

operations. 

3.1 Liquid Removal Technologies

Numerous liquid removal technologies have been evaluated for their emission levels and 

their potential for eliminating or minimizing emissions from liquids unloading. The Natural Gas 

STAR program reports the potential for significant emissions reductions and economic benefits 

from implementing one or more lift options to remove this liquid instead of blowing down the 

well to the atmosphere (U.S. EPA, 2006b and 2011).

As noted in Section 1 of this document, the Natural Gas STAR program reports that when 

liquids loading occurs during the productive life of the well, one or more of the following actions 

are generally taken (U.S. EPA, 2011):

 Shutting in the well to allow the bottom hole pressure to increase, and then venting the 

well to the atmosphere (well blowdown), 

 Swabbing the well to remove accumulated fluids,
15

 Installing velocity tubing,

 Installing a plunger lift system, and 

 Installing an artificial lift system.

In the sections below, the technologies have been divided into “primary” and “remedial” 

technologies. It is the EPA’s understanding that the “primary” technologies are used as more 

permanent solutions to liquids loading problems, while the “remedial” technologies may mitigate 

the problem but do not provide a long term permanent solution. These technologies are 

summarized in Table 3-1.
16

Table 3-1. Liquid Removal Techniques for Liquid Unloading of Natural Gas Wells

Mitigation 

Techniques Description Applicability Costs

Efficacy and 

Prevalence

Primary Techniques

Plunger Lift Systems Plunger lifts use the well’s own 

energy (gas/pressure) to drive a 

piston or plunger that travels the 

length of the tubing in order to push 

accumulated liquids in the tubing to 

the surface (U.S. EPA, 2006b). 

Plunger systems have been 

known to reduce emissions from 

venting and increase well 

production. Specific criteria 

regarding well pressure and 

liquid to gas ratio can affect 

applicability. Candidate wells for 

plunger lift systems generally do 

not have adequate downhole 

pressure for the well to flow 

freely into a gas gathering system

(U.S. EPA, 2006b).

The following 

information is from the 

EPA’s Natural Gas 

STAR Program technical 

documents, however, 

additional cost data may 

be available such as from 

equipment or service 

providers (U.S. EPA, 

2006b and 2011):

 Capital, installation 

and startup cost 

estimates: $1,900-

$7,800 (Note: 

Commenters on the 

ICF study cited a cost 

of $15,000. The study 

escalated the cost to 

$20,000 (ICF 

International, 2014))

 Smart automation 

system: $4,700/well -

$18,000/well 

depending on the 

complexity of the 

system. 

 Additional startup 

costs (e.g., well depth 

survey, miscellaneous 

well clean out 

operations): $700-

$2,600.

API/ANGA Survey 

data show plunger lifts 

can result in zero 

emissions or significant 

emissions depending 

on how they are 

operated.

The EPA has learned 

plunger lift systems 

rely on manual, onsite 

adjustments. When a 

lift becomes 

overloaded, the well 

must be manually 

vented to the 

atmosphere to restart 

the plunger. Optimized 

plunger lift systems 

(e.g., with smart well 

automation) can 

decrease the amount of 

gas vented by up to 

90+% and reduce the 

need for venting due to 

overloading (U.S. 

EPA, 2006b).
17

Mitigation 

Techniques Description Applicability Costs

Efficacy and 

Prevalence

 Annual operating and 

maintenance costs 

(e.g., inspection and 

replacement of 

lubricator and 

plunger): $700-$1,300

 Annual cost savings 

from avoided 

emissions from use of 

an automated system:

$2,400-$10,241.

Artificial lifts (e.g., 

rod pumps, beam lift 

pumps, pumpjacks and 

downhole separator 

pumps)

Artificial lifts require an external 

power source to operate a pump that 

removes the liquid buildup from the 

well tubing (U.S. EPA, 2011).

The devices are typically used 

during the eventual decline in the 

gas reservoir shut-in pressure, 

when there is inadequate 

pressure to use a plunger lift. At 

this point, the only means of 

liquids unloading to keep gas 

flowing is downhole pump 

technology (U.S. EPA, 2011). 

The following 

information is from the 

EPA’s Natural Gas 

STAR Program technical 

documents, however, 

additional cost data may 

be available such as from 

equipment or service 

providers (U.S. EPA, 

2011):

 Capital and 

installation costs

(includes location 

preparation, well clean 

out, artificial lift 

equipment and 

pumping unit): 

$41,000-$62,000/well 

 Average cost of 

pumping unit: 

$17,000-$27,000. 

Artificial lifts can be 

operated in a manner 

that produces no 

emissions (U.S. EPA, 

2011).

The EPA does not have 

information on the 

prevalence of this 

technology in the field.
18

Remedial Techniques

Velocity tubing Velocity tubing is smaller diameter 

production tubing and reduces the 

cross-sectional area of flow, 

increasing the flow velocity and 

achieving liquid removal without 

blowing emissions to the atmosphere. 

Generally, a gas flow velocity of 

1,000 feet per minute (fpm) is 

necessary to remove wellbore liquids

(U.S. EPA, 2011).

 Velocity tubing strings are 

appropriate for low volume 

natural gas wells upon initial 

completion or near the end of 

their productive lives with 

relatively small liquid 

production and higher 

reservoir pressure. Candidate 

wells include marginal gas 

wells producing less than 60 

Mcfd (U.S. EPA, 2011).

 Coil tubing can also be used 

in wells with lower velocity 

gas production (U.S. EPA, 

2011).

The following 

information is from the 

EPA’s Natural Gas STAR 

Program technical 

documents, however, 

additional cost data may 

be available such as from 

equipment or service 

providers (U.S. EPA, 

2011):

 Installation requires a 

well workover rig to 

remove the existing 

production tubing and 

place the smaller 

diameter tubing string 

in the well.

 Capital and 

installation costs 

provided from 

industry include the 

following:

$7,000-$64,000/well

Considered to be a “no 

emissions” solution. 

Low maintenance, 

effective for low 

volumes lifted. Often 

deployed in 

combination with 

foaming agents. 

Seamed coiled tubing 

may provide better lift 

due to elimination of 

turbulence in the flow 

stream (U.S. EPA, 

2011).

The EPA does not have 

information on the 

prevalence of this 

technology in the field.

Foaming agents A foaming agent (soap, surfactants) 

is injected in the casing/tubing 

annulus by a chemical pump on a 

timer basis. The gas bubbling 

through the soap-water solution 

creates gas-water foam which is 

more easily lifted to the surface for 

water removal (U.S. EPA, 2011).

A means of power will be 

required to run the surface 

injection pump. The soap supply 

will also need to be monitored. If 

the well is still unable to unload 

fluid, additional, smaller tubing 

may be needed to help lift the 

fluids. Foaming agents work best 

if the fluid in the well is at least 

50% water. Surfactants are not 

effective for natural gas liquids 

or liquid hydrocarbons. Foaming 

agents and velocity tubing may 

be more effective when used in 

combination (U.S. EPA, 2011).

The following 

information is from the 

EPA’s Natural Gas STAR 

Program technical 

documents, however, 

additional cost data may 

be available such as from 

equipment or service 

providers (U.S. EPA, 

2011):

Foaming agents are low 

cost. No equipment is 

required in shallow wells. 

In deep wells, a surfactant 

Considered to be a “no 

emissions” solution. 

Low volume method 

applied early in 

production decline 

when bottom hole 

pressure still generates 

sufficient velocity to 

lift liquid droplets (U.S. 

EPA, 2011).

The EPA does not have 

information on the 

prevalence of this 

technology in the field.
19

injection system requires 

the installation of surface 

equipment and regular 

monitoring. Pump can be 

powered by solar or AC 

power or actuated by 

movement of another 

piece of equipment. 

 Capital and startup 

costs to install soap 

launchers: $500-

$3,880

 Capital and startup 

costs to install soap 

launchers and velocity 

tubing: $7,500-

$67,880

 Monthly cost of 

foaming agent: 

$500/well or $6,000/yr
20

3.1.1 Primary Techniques

Plunger Lifts

Based on our assessment of the data, a plunger lift system for liquids unloading is capable 

of performing liquids unloading with little or no emissions. The level of emissions depends on how 

the plunger lift system is operated, specifically, whether gas is directed to the sales line or vented to 

the atmosphere. There may be potential for improved production and emissions reduction when 

paired with a smart well automation that optimizes production and reduces product losses to the 

atmosphere. A schematic diagram of a plunger lift is shown in Figure 3-1.

Basic installation costs for plunger lifts were estimated as ranging from $1,900 - $7,800 

based on information gathered from the EPA’s Natural Gas STAR program (see Table 3-1). 

Plunger lift installation costs include installing the piping, valves, controller and power supply on 

the wellhead and setting the downhole plunger bumper assembly, assuming the well tubing is open 

and clear. Lower costs (e.g., $1,900) would result where no other activities are required for 

installation. Higher costs (e.g., $7,800) would be incurred in situations where running a wire-line, 

which is necessary to check for internal blockages within the tubing, and a test run of the plunger is 

conducted from top to bottom (a process also known as broaching) to ensure that the plunger will 

move freely up and down the tubing string (U.S. EPA, 2006b).

Other startup costs in addition to the installation costs can include a well depth survey, 

swabbing to remove well bore fluids, removing mineral scale and cleaning out perforations, fishing 

out debris in the well, and other miscellaneous well clean out operations. Additional startup costs 

were estimated to be $700 - $2,600 (U.S. EPA, 2006b). However, commenters on the ICF study 

cited startup costs of $15,000. The commenters also stated that well treatments and clean outs are 

often required before plunger lifts can be installed. The study escalated the cost to $20,000 per well 

(ICF International, 2014).
21

Figure 3-1. Example Plunger Lift (U.S. EPA, 2006b)

The activities to install the smart automation plunger lift include installing the controller, 

power supply, and host system, in addition to the activities required for the plunger itself. The 

typical cost of automating a plunger lift system is approximately $5,700 - $18,000, depending on 

the complexity of the well. This cost would be in addition to the startup costs of a plunger-only 

system (U.S. EPA, 2011). Installing telemetry units can help to optimize production; however,

automated controllers are not necessarily required for reducing emissions. 

Natural Gas STAR Partners have reported methane emissions reductions and economic 

benefits from implementing plunger lifts as compared to conducting blowdowns, especially those 

equipped with smart automation systems. The reported economic benefits from natural gas savings 
22

and improved well production range from $2,400 - $4,389 per well per year4(U.S. EPA, 2011).

The EPA is not aware of any adverse secondary environmental impacts that would result from the 

installation and operation of plunger lifts in a liquid producing natural gas well, and the use of a 

smart automated plunger lift system has the potential to optimize production and minimize 

emissions over the use of a non-automated plunger lift system.

The ICF study (ICF International, 2014) calculated emission control cost curves ($/Mcf of 

methane reduced) using their 2018 projected methane emission estimates. The primary sources 

used for projecting onshore methane emissions for liquids unloading for 2018 included natural gas 

forecast information from the U.S. EIA’s Annual Energy Outlook (AEO) and 2014 Early Release 

(Lower 48 Natural Gas Production and Supply Prices by Supply Region) and API’s Quarterly Well 

Completions Report. The EIA information was used to project methane emissions by using regional 

gas production information projected in EIA’s 2014 AEO for 2018. The API’s report was used to 

update well counts by EIA AEO regions whereby a ratio of the number of wells in 2018 to wells in 

2011 was used to drive the activity for most of the emission sources involved in gas production. 

The study assumed the application of a plunger lift (assuming 95% control of methane emissions) 

on 30% of the estimated venting wells without plunger lifts. ICF estimated a methane reduction of 

1.6 Bcf (or approximately 30,212 MT) at a cost of $0.74/Mcf methane reduced with the application 

of a plunger lift on these uncontrolled wells. ICF also estimated that VOC emissions would be 

reduced by 9.3 kilotons (or approximately 9,300 MT) at a cost of $125/ton. According to the report, 

liquids unloading can increase production by anywhere from 3 to 300 thousand cubic feet per day 

(Mcf/day) and, without taking credit for the productivity increase, the report estimates that the costeffectiveness breakeven point is about 1,200 Mcf/yr of venting (estimated as a reduction cost of 

$0.05/Mcf reduced). Their analysis assumed capital costs of $20,000 and annual operating costs of 

$2,400.

Artificial Lift Systems

Artificial lift systems (e.g., rod pumps and pumping units) require an external power source 

to operate, such as electric motors or natural gas fueled engines. However, these systems can be 

 

4 Assumes a gas price of $3 per Mcf.
23

installed and effectively remove liquids from the well even after the well pressure has declined to 

the point where a plunger lift system can no longer be operated, thus they are capable of prolonging 

the life of a well. They typically require the use of a well workover rig to install a downhole rod 

pump, rods, and tubing in the well. 

Based on results reported by Natural Gas STAR Partners, the cost of implementing artificial 

lift systems range from $41,000 - $62,000. The reported economic benefits from natural gas 

savings range from $2,919 - $6,120 per well per year5(U.S. EPA, 2011).

Secondary environmental impacts occur due to the emissions from the natural-gas fueled 

engine used to power the lift system, however, these impacts can be reduced by using an electric 

motor instead.

3.1.2 Remedial Techniques

Velocity Tubing

As was described previously, liquids build up in the well tubing as well pressure declines 

and the gas flow velocity is not sufficient to push the liquids out of the well tubing. Velocity tubing 

(smaller diameter production tubing) decreases the cross-sectional area of the conduit through 

which the gas flows and thus increases the velocity of the flow. The Natural Gas STAR Program 

uses 1,000 fpm as a general rule of thumb for the velocity necessary to remove liquids from the 

well (Note: This is a rule of thumb and the actual required velocity will differ based on well 

characteristics). When velocity tubing is installed, it must be a small enough diameter to increase 

the gas flow velocity to 1,000 fpm or to the necessary velocity to remove the liquids from the 

particular well. A well workover rig is required to remove the existing production tubing and 

replace it with the velocity tubing. The EPA experience through the Natural Gas STAR Program 

suggests the wells that are the best candidates for this technology are marginal wells that produce 

less than 60 Mcfd. However, as well pressure continues to decline as the well ages, the installed 

velocity tubing may no longer be sufficient to increase the gas flow velocity to the level necessary 

to remove liquids from the well. At this point, velocity tubing of a smaller diameter or other liquids 

 

5 Estimate does not include value of improved well production. Assumes a gas price of $3 per Mcf.
24

removal technologies may be required to remove liquids from the well tubing.

Based on results reported by Natural Gas STAR Partners, the cost of implementing velocity 

tubing ranges from $7,000 - $64,000. The reported economic benefits from natural gas savings and 

improved well production range from $27,855 - $82,830 per well per year6(U.S. EPA, 2011). The 

EPA is not aware of any adverse secondary environmental impacts that would result from the 

installation and operation of velocity tubing.

Foaming Agents

Foaming agents can help to remove liquids from wells that are accumulating liquids at low 

rates. The foam produced from surfactants can reduce the density of the liquid in the well tubing 

and can also reduce the surface tension of the fluid column, which reduces the gas flow velocity 

necessary for pushing the liquid out of the well tubing. This technology can be used in conjunction 

with velocity tubing. However, foaming agents work best when the majority of the liquid built up 

in the well tubing is water, because they are not effective on natural gas liquids or liquid 

hydrocarbons (U.S. EPA, 2011).

The foaming agent can be delivered into the well as a soap stick or it can be injected into 

the casing-tubing annulus or a capillary tubing string. If the well is deep, then an injection system is 

required that includes foaming agent reservoir, an injection pump, a motor valve with a timer and a 

power source for the pump (e.g., AC power for electric power or gas for pneumatic pumps) (U.S. 

EPA, 2011).

Based on results reported by Natural Gas STAR Partners, the costs of foaming agents range 

from $500 - $9,880. The reported economic benefits from natural gas savings and improved well 

production range from $1,500 - $28,080 per well per year7(U.S. EPA, 2011). 

 

6 Assumes a gas price of $3 per Mcf.

7 Assumes a gas price of $3 per Mcf.
25

For deep wells that require an injection system, secondary environmental impacts occur due 

to the emissions from the power source for the pump. Pneumatic pumps can result in vented gas 

emissions and electric pumps emissions depending on the source of the electric power.

4.0 SUMMARY

The EPA has used the data sources, analyses and studies discussed in this paper to form the 

Agency’s understanding of VOC and methane emissions from liquids unloading and the emissions 

mitigation techniques. The following are characteristics the Agency believes are important to 

understanding this source of VOC and methane emissions:

 A majority of gas wells (conventional and unconventional) must perform liquids unloading 

at some point during the well’s lifetime. As gas wells age and well pressure declines, the 

need for liquids unloading to enhance well performance becomes more likely.

 The 2014 GHG Inventory estimates the 2012 liquids unloading emissions to be 14% of 

natural gas production sector emissions.

 The majority of emissions from liquids unloading events come from a small percentage of 

wells. Some of the characteristics that affect the magnitude of liquids unloading annual 

emissions from a well are the length of time of each event and the frequency of events.

 A wide range of emission rates from blowdowns have been reported from the limited 

available well-level data. In the Allen et. al. study, when emissions are averaged per event, 

emissions from four of the nine events included in the study contribute more than 95% of 

the total emissions. This result is consistent with the API/ANGA 2012 Survey data and 

2012 data reported to the GHGRP; all suggest that certain wells produce more emissions 

during blowdowns than others. Some suggested causes of this variation are the length of the 

blowdown and the number of blowdowns per year, which are affected by underlying 

geologic factors.

 Industry has developed several technologies that effectively remove liquids from wells and 

can result in fewer emissions than blowdowns. Plunger lifts are the most common of those 

technologies.
26

 The emissions reduction efficiency plunger lifts can achieve varies greatly depending on 

how the system is operated. It is not clear to the EPA what the conditions are that lead to 

wells with plunger lifts to be vented during plunger lift operation.

 The two liquids unloading techniques that result in vented emissions that the EPA is aware 

of are plunger lifts when vented to the atmosphere and blowdowns.

5.0 CHARGE QUESTIONS FOR REVIEWERS

1. Please comment on the national estimates of methane emissions and methane emission factors 

for liquids unloading presented in this paper. Please comment on regional variability and the 

factors that influence regional differences in VOC and methane emissions from liquids 

unloading. What factors influence frequency and duration of liquids unloading (e.g., regional 

geology)?

2. Is there further information available on VOC or methane emissions from the various liquids 

unloading practices and technologies described in this paper?

3. Please comment on the types of wells that have the highest tendency to develop liquids loading. 

It is the EPA’s understanding that liquids loading becomes more likely as wells age and well 

pressure declines. Is this only a problem for wells further down their decline curve or can wells 

develop liquids loading problems relatively quickly under certain situations? Are certain wells 

(or wells in certain basins) more prone to developing liquids loading problems, such as 

hydraulically fractured wells versus conventional wells or horizontal wells versus vertical 

wells?

4. Did this paper capture the full range of feasible liquids unloading technologies and their 

associated emissions? Please comment on the costs of these technologies. Please comment on 

the emission reductions achieved by these technologies. How does the well’s life cycle affect 

the applicability of these technologies?

5. Please provide any data or information you are aware of regarding the prevalence of these 

technologies in the field.

6. In general, please comment on the ability of plunger lift systems to perform liquids unloading 
27

without any air emissions. Are there situations where plunger lifts have to vent to the 

atmosphere? Are these instances only due to operator error and malfunction or are there 

operational situations where it is necessary in order for the plunger lift to effectively remove the 

liquid buildup from the well tubing?

7. Based on anecdotal experience provided by industry and vendors, the blowdown of a well 

removes about 15% of the liquid, while a plunger lift removes up to 100% (BP, 2006). Please 

discuss the efficacy of plunger lifts at removing liquids from wells and the conditions that may 

limit the efficacy.

8. Please comment on the pros and cons of installing a plunger lift system during initial well 

construction versus later in the well’s life. Are there cost savings associated with installing the 

plunger lift system during initial well construction?

9. Please comment on the pros and cons of installing a “smart” automation system as part of a 

plunger lift system. Do these technologies, in combination with customized control software, 

improve performance and reduce emissions?

10. Please comment on the feasibility of the use of artificial lift systems during liquids unloading 

operations. Please be specific to the types of wells where artificial lift systems are feasible, as 

well as what situations or well characteristics discourage the use of artificial lift systems. Are 

there standard criteria that apply?

11. The EPA is aware that in areas where the produced gas has a high H2S concentration 

combustion devices/flares are used during liquids unloading operations to control vented 

emissions as a safety precaution. However, the EPA is not aware of any instances where 

combustion devices/flares are used during liquids unloading operations to reduce VOC or 

methane emissions. Please comment on the feasibility of the use of combustion devices/flares 

during liquids unloading operations. Please be specific to the types of wells where combustion 

devices/flares are feasible. Are there operational or technical situations where combustion 

devices/flares could not be used? 

12. Given that liquids unloading may only be required intermittently at many wells, is the use of a 

mobile combustion device/flare feasible and potentially less costly than a permanent 

combustion device/flare?
28

13. Given that there are multiple technologies, including plunger lifts, downhole pumps and 

velocity tubing that are more effective at removing liquids from the well tubing than 

blowdowns, why do owners and operators of wells choose to perform blowdowns instead of 

employing one of these technologies? Are there technical reasons other than cost that preclude 

the use of these technologies at certain wells?

14. Are there ongoing or planned studies that will substantially improve the current understanding 

of VOC and methane emissions from liquids unloading events and available options for 

increased product recovery and emissions reductions? The EPA is aware of an additional stage 

of the Allen et al. study to be completed in partnership with the EDF and other partners that will 

directly meter the emissions from liquids unloading events. However, the EPA is not aware of 

any other ongoing or planned studies addressing this source of emissions.

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