Attachment J

Liquids Unloading

Gordon Reid Smith

Independent Consultant
Gordon Smith Review 

Oil & Natural Gas Sector Liquids Unloading Processes

EPA Office of Air Quality Planning and Standards White Paper

“Oil & Natural Gas Sector Liquids Unloading Processes”

Review Prepared By: Gordon Reid Smith; 

Submitted: June 16, 2014

Table of Contents

Executive Summary................................................................................................................. 1

A. Introduction....................................................................................................................... 2

B. Charge Questions ............................................................................................................. 5

Charge Question 1 ........................................................................................................... 5

a. GHGRP Data - 2012 emission year: ..................................................................... 7

b. API/ANGA 2012 Survey Data: ......................................................................... 9

c. U.S. Inventory of Greenhouse Gas Sources and Sinks - 2014: .......................... 10

d. UT Emission Measurement Study:.................................................................. 10

e. ICF/EDF Report: ................................................................................................. 11

Charge Question 2 ......................................................................................................... 11

Charge Question 3 ......................................................................................................... 13

Charge Question 4 ......................................................................................................... 14

a. Available Liquids Unloading Emissions Mitigation Techniques....................... 14

b. Section 3.1”Liquid Removal Technologies” ................................................... 15

c. Costs .................................................................................................................... 19

d. Section 3.1.1 Plunger Lifts: ............................................................................. 19

e. Table 3.1 Plunger Lift Review Comments: ........................................................ 20

f. Section 3.1.1 - Plunger Lift Narrative Review Comments:................................ 21

g. Section 3.1.1 - Artificial Lift Systems:............................................................ 22

h. Section 3.1.1 - Velocity Tubing:...................................................................... 23

i. Section 3.1.1 - Foaming Agents:........................................................................... 24

Charge Question 5 ......................................................................................................... 25

Charge Question 6 ......................................................................................................... 25

Charge Question 7 ......................................................................................................... 26

Charge Question 8 ......................................................................................................... 27

Charge Question 9 ......................................................................................................... 28

Charge Question 10 ....................................................................................................... 28

Charge Question 11 ....................................................................................................... 29

Charge Question 12 ....................................................................................................... 30

Charge Question 13 ....................................................................................................... 31

Charge Question 14 ....................................................................................................... 31

C. Conclusion........................................................................................................................32
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Oil & Natural Gas Sector Liquids Unloading Processes

Executive Summary

EPA’s draft White Paper, “Oil & Natural Gas Sector Liquids Unloading Processes” 

(White Paper) is not the complete high quality technical resource document

contemplated and is not suitable to inform EPA’s deliberations regarding emissions due 

to venting of wells to assist liquids unloading. EPA’s intent is most clearly expressed in 

the paper’s preface:

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.

Instead of a useful and insightful compilation and analysis of available information 

regarding venting of wells to assist liquid unloading, the paper appears to be a simply a 

summary of the information sources referenced. There are misunderstandings and 

incorrect/inaccurate statements scattered throughout the White Paper. The summaries of 

the underlying sources are incomplete and information is incorrectly mischaracterized in 

some instances. Additional information sources, such as the vast amount of industry 

technical literature regarding management of well bore liquids, are not included in the 

scope of the White Paper sources. No discussion regarding the limitations of the 

underlying sources is presented in the White Paper and there is no critical analysis of the 

accuracy or validity of the underlying sources or the information summarized from them 

in the White Paper. The logic and underpinning evidence leading to the conclusions and 

assertions made in the White Paper is not clearly presented. 

To better focus the White paper, a clearly stated goal and criteria for achieving the goal 

would be useful. Having a goal and criteria would also enable evaluation of whether the 

White Paper adequately meets the criteria. More clarity of focus on venting of wells to 

aid liquid unloading, which is the source of emissions, rather than wellbore liquid 

loading in general would improve the White Paper. Understanding the reasons and 

causes for using well venting to aid in liquid unloading is the key to understanding and 

evaluating potential approaches to reduce well venting and emissions. In order too 

adequately evaluate options to reduce venting of wells and the emissions that result, EPA 

needs to understand the reasons that wells are vented, alternatives to venting that will 

still provide for well-bore liquid loading management, and the envelope of conditions 

where these alternatives are feasible. Unfortunately this does not appear to be the focus 

of the White Paper and adequate information is not provided.

Notwithstanding the complexity of well-bore fluid dynamics, if this white paper is 

intended to be a definitive document intended to inform EPA’s understanding and 

evaluation of potential options to reduce emissions from venting of wells for liquids 
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unloading it needs significant improvement in content, organization, and data sources to 

be useful. 

Following are highlights of several key review comments discussed in more detail later 

in this document:

 Based on deeper analysis of the GHGRP data, the majority of the emissions from 

venting for liquid unloading occur from a small number of operators and a small 

subset of wells. Of 1991 non-zero datasets reported at the “subbasin” level, 10 

(less than 0.5%) datasets account for more than 50% of the emissions reported. 

This skewed distribution is consistent with the API/ANGA Survey Report data

and strongly suggests that a program targeted at these instances is more 

appropriate than an industry wide regulatory approach.

 Further illustrating the niche issue of venting for liquid unloading, the 2012 

GHGRP data shows only about 13.5% of U.S. gas wells vented for liquids 

unloading. Given the fact that most U.S. gas are low producers and likely subject 

to liquids loading this indicates that managing well-bore liquids without venting 

is significantly more common than venting. 

 The White Paper’s assertion that plunger lift systems are an effective emission 

control technology is not supported by the data. The data shows wells with 

plunger lifts have a higher frequency of engaging in venting, a higher number of 

vents/well/year, and account for a disproportionate percentage of well venting 

emissions. Despite plunger equipped wells being less than 40% of the wells in 

the API/ANGA survey they account for about 70% of the emissions.

 The use of advanced formation energy management (smart automation) to aid 

liquid unloading while minimizing venting, for wells with plunger lift and wells 

without, is not adequately described.

 The control technology discussions and costs in the White Paper appear to be 

solely based on lessons learned documents from the Natural Gas Star Program. 

These lessons learned documents were developed to foster technology transfer, 

which they are adequate to do, but have never been subjected to the level of 

critical expert review necessary if they are to be used as foundational technical 

information sources. Although not a focus of this review, a partial review of 

these documents identified multiple misunderstandings and errors in them which 

suggests they need critical review as well. 

A. Introduction

The description of liquids loading of well-bores in the introduction is not correct. The 

errors indicate a fundamental misunderstanding of well-bore liquid-loading, the 

techniques and tools that are used to manage liquids loading, and the role that venting 

has in liquid unloading. In addition, there are several misunderstandings, 
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incorrect/erroneous statements and use of terms that do not have any meaning in the 

context of liquid loading of well-bores.

Liquid loading of well-bores occurs when the gas velocity up the well-bore is not 

sufficient for the gas to transport liquids up the well-bore. When a vertical liquid column 

builds up in the well-bore, the hydrostatic weight of the column puts back-pressure on 

the producing formation and can reduce the production rate to the point where the well 

can quit flowing. The volume of flow up a well-bore is a function of the formation 

deliverability (inflow rate), the flowing formation pressure near the well-bore, and the 

cumulative resistance to flow expressed as pressure drop. The cumulative resistance to 

flow is the sum of the fluid column in the well-bore’s hydrostatic pressure, the flowing 

friction up the production tubing/casing, surface equipment pressure-loss/back-pressure, 

and the pressure of the collection line that a well is flowing into. As the cumulative 

resistance to flow approaches the flowing formation pressure the rate of production will 

decrease and if the cumulative resistance equals or exceeds the formation pressure, the 

formation will cease flowing reservoir fluids into the well-bore. As wells deplete the 

formation pressure near the well-bore and the inflow-rate decreases which decreases the 

volume flow rate of reservoir fluids and consequently the velocity of flow up the wellbore. Wells and reservoirs follow a continuum of flow regimes in their economic life as 

the reservoir depletes, production goes down, well-bore (tubing) velocity goes down, and 

liquid loading begins to occur in the well-bore. 

The statement that:

“the accumulation of liquids in the well can occur when the bottom well 

pressure approaches reservoir shut-in pressure” 

is not correct and the use of the term “reservoir shut-in pressure” does not have a 

meaning in this context. “Reservoir shut-in pressure” is more appropriately referred to 

as “average reservoir pressure” which is defined as the volumetric average fluid pressure 

within the reservoir across the areal extent of the reservoir boundaries. It is misleading 

to call the build-up pressure at a well during a shut-in “reservoir shut-in pressure”. 

Techniques and tools that operators use to manage liquid loading that rely on formation 

energy focus on reducing resistance to flow, raising the pressure in the near-wellbore

formation, or increasing the velocity of flow. Lowering surface pressure with 

compression, well-site debottlenecking, or lowering gathering system pressure reduces 

surface resistance to flow. Reducing flowing fluid friction through materials choices can 

assist in reducing flowing friction resistance to flow. Hydrostatic resistance is affected 

by surfactant/soap injection or running plungers to try to reduce the work that is done by 

the gas in lifting liquids (surfactant/soap) or make it more efficient (plungers). Nearwellbore formation pressure can be impacted by stopping flow to allow reservoir fluids 

to resupply depleted fluids and pressure near the well bore. Flow velocity can be 
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increased, for a given flow rate, by installation of smaller diameter “velocity” production 

strings in the well-bore although there is a practical limit to smaller diameters where 

flowing friction overcomes the effect of a smaller diameter flow path. Venting of wells 

to atmosphere is used to lower the resistance to flow by removing the collection 

system and most surface equipment backpressure. A combination of techniques may 

be used concurrently, such as velocity strings and surfactant/soap injection, dependent on 

the well and formation characteristics. 

Once the formation pressure and inflow rate reaches the stage where the reservoir’s 

energy and flow is not sufficient to lift liquids then energy will need to be added to the 

well, which is commonly termed “artificial lift” but more properly termed “mechanical 

deliquification” of gas wells. Added-energy deliquification methods include downhole 

pumps (e.g., sucker-rod pumps, progressing cavity pumps, or electric submersible 

pumps) or gas lift which involves injection of higher pressure gas down the casing/tubing 

annulus and into the flow stream to increase the energy/velocity available for the gas to 

do work lifting the liquids. Each lift type has its specific purpose with respect to liquid 

rate potential, solids handling capabilities, installation/maintenance cost, reservoir 

drawdown potential, etc. Once a mechanical deliquification technique is installed on a 

well, any perceived value of venting is eliminated and venting will not occur. When the 

expected production from a well cannot support the investment required to enable 

deliquification, it will reach the end of its economic life and be abandoned. 

The choice of what technique to employ is based on well-by-well and reservoir-byreservoir analysis and is one of the primary jobs of production engineering teams. For a 

typical well, as it moves through the depletion continuum, a series of techniques will be 

employed. The decision on technology selection requires a thorough understanding of 

the reservoir, conditions that a reservoir is flowing into, the reservoir’s sensitivity to 

backpressure, the volumes and pressures that the deliquification technology must handle, 

and costs/benefits of applying the technology. 

The discussion of venting (also termed “blowing down”) a well and the role of plunger 

lifts is partially incorrect and incomplete. The following are provided to clarify this 

section. 

1. Venting may be either manual or automated and also relies on reservoir energy.

2. Venting may or may not be done in conjunction with shut-in periods to build 

reservoir energy. 

3. Plunger lifts rely on the reservoir energy. Venting to remove flow-line pressure 

and surface pressure drop to create lift is common while running plungers.

4. Plungers do improve the efficiency of a gas stream to perform liquid removal by 

providing a physical barrier between the formation energy and the liquid column

but do not necessarily minimize or eliminate venting.
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5. Minimizing venting, with or without a plunger, hinges on understanding the 

reservoir energy, flow resistance, and available technologies and techniques (such 

as shut-in periods to build near well-bore energy) to provide adequate flow rate

(non-plunger) or adequate pressure differential (plungers) to lift liquids without 

venting. Wells with plunger lifts have more variables that can be manipulated to 

accomplish these goals, but are not inherently able to provide smaller vented 

volumes.

6. Swabbing is a remedial treatment with a rig or wire-line unit that is used only 

when a well will not respond to other techniques to remove the liquids from the 

well-bore and restore flow. It is not commonly used to manage liquid loading on 

a frequent basis, and volumes vented during swabbing operations may be 

markedly higher than individual venting events. 

B. Charge Questions

Charge Question 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)?

The “Introduction” section and Section 2.0 of the white paper incorrectly represents the 

data sources and information summarized as “studies”. Only one of the information 

sources summarized, the UT Phase 1 study, is an actual emission study. The other data 

sources summarized (i.e., the National Inventory, the GHGRP data, the API/ANGA 

report, and the ICF/EDF report;) are inventory estimates and/or reports rather than basic 

measurement studies and should be discussed and characterized as such. These same 

sections also incorrectly state that some information sources summarized include 

information regarding mitigation techniques. What some of these information sources 

do include is information regarding well-bore configuration, specifically information 

regarding the number or percentage of wells that have plunger lift systems. As discussed 

later, plunger lift systems are not an emissions “mitigation technique” by any definition 

of the term. 

Section 2.0 of the paper would benefit from inclusion of a table showing the different 

estimates of emissions attributed to venting of wells to aid liquids unloading at the 

beginning of the section. A table similar to Table 1 following would be useful.
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Table 1

Well Venting for Liquid Unloading Methane Emission Estimates

Name Methane 

MT's

Total # 

of 

Venting 

Wells

# Venting 

With 

Plunger 

Lift

# Venting 

Without 

Plunger 

Lift

MT's per

year per

Venting 

Well

MT's per 

Venting 

Well per 

year with 

Plunger

MT's per 

Venting 

Well per 

year w/o 

Plunger

Greenhouse Gas 

Reporting 

Program - 2012

276,378 58,663 32,448 26,215 4.711 6.158 2.959

U.S. Inventory of 

Greenhouse Gas 

Sources and 

Sinks - 2013 

(2011 Emission 

Year)

258,667 60,810 23,503 37,307 4.254 4.618 4.024

API/ANGA 

Report - 2011 

data

319,664 65,669 36,806 28,863 4.868 5.207 4.584

UT/EDF Phase 1 

Study 162,619 35,828 4.539 not measured 4.539

ICF/EDF Report 277,307 75,399 44,286 31,113 3.678 4.430 2.607

Note: With the exception of the UT/EDF Phase 1 Study this table is U.S. Totals

Note 2: The UT/EDF Phase 1 results should be viewed with an abundance of caution. Only 9 well venting 

instances, all without plunger lift, were measured which is much too small of a population to extrapolate to 

a national or even sub-national level. The UT paper authors clearly state: “Because the characteristics of 

the unloading events sampled in this work are highly variable, and because the number of events sampled 

is small, extrapolating the results to larger populations should be done with caution.” Also, the 

supplemental information for this study indicates that venting may have been triggered on at least some of 

the wells measured solely to enable measurement. If this is correct, the wells were not liquid loaded, the 

flow volumes and dynamics would be very different from a liquid loaded well, flow would likely exceed 

normal production flow of the well, and flow would not be representative of an actual venting to assist 

unloading. 

Note 3: The different data sources/studies used different methane concentrations to arrive at methane 

emission estimates. See the individual studies for information on methane content that was used. 
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Oil & Natural Gas Sector Liquids Unloading Processes

a. GHGRP Data - 2012 emission year: 

The GHGRP data is likely the most complete and data rich source of available 

information regarding the number of wells venting to aid liquids unloading, the number 

of plunger lift systems installed in wells, the frequency of venting, and estimated 

emissions. The GHGRP discussion in the White Paper does not include or indicate the 

significant amount of information available, the granularity of information available 

(down to the county/formation-type combination and below), or an adequate analysis of 

the available data. 

Liquid unloading is reported into the GHGRP at the sub-basin category (county & 

formation type) level for methods 2 and 3. For method 1, reports are made at the level of 

unique combinations of sub-basin category (county & formation type); pressure group 

(5), and tubing diameter group (3). Rather than the 251 basin level reports the white 

paper notes, there are 1,993 separate data sets available at the granularity described. 

Estimates for GHGRP reporting of emissions from venting to aid liquid unloading are 

based on engineering calculations (Methods 2 & 3) or representative well vent 

measurement and extrapolation to other venting wells in the same grouping combination 

(Method 1). 

Data available for the 2012 emission year, for methods 2 and 3 include 

1) Count of wells vented to the atmosphere for liquids unloading. 

2) Count of plunger lifts. 

3) Cumulative number of unloadings vented to the atmosphere (Deferred in 

the 2012 data).

4) Average internal casing diameter or tubing diameter, for all wells, where 

applicable. 

5) Annual CO2 and CH4 emissions, expressed in metric tons CO2e for each. 

Data available for method 1 includes 

1) Count of wells vented to the atmosphere for liquids unloading. 

2) Count of plunger lifts. 

3) Whether the selected representative well in each group had a plunger lift 

(yes/no). 

4) Cumulative number of vents to the atmosphere for liquids unloading. 

5) Average flow rate of the measured well venting in cubic feet per hour. 

6) Internal casing diameter or internal tubing diameter in inches, where 

applicable, 

7) Well depth of each well, selected to represent emissions in that tubing size 

and pressure combination. 
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8) Casing pressure, of each well selected to represent emissions in that tubing 

size group and pressure group combination that does not have a plunger 

lift. 

9) Tubing pressure, of each well selected to represent emissions in a tubing 

size group and pressure group combination that has a plunger lift.

10)Annual CO2 and CH4 emissions, expressed in metric tons CO2e for each 

gas. 

As this illustrates, the GHGRP data includes a large amount of information that can be 

analyzed to help understand well venting to aid in liquids unloading. 

Additional information will be available in data reported in 2015, including items shown 

as deferred above. However, caution needs to be taken when using this data to perform

enough QA/QC to identify and exclude obviously incorrect data. For example, some 

data sets report emissions that are dominated by CO2 (some 100% CO2) which is not 

likely and the number of plunger lifts reported by some reporters under method 3 is 

extremely large in some instances which indicates these reporters did not correctly 

interpret the data field.

A basic analysis of the reported data indicates that 

 10 of the 1993 data sets (0.5%) reported at the granular level account for just 

over 50% of the CH4 emissions reported for venting to aid in liquids unloading 

during 2012 with the top 72 (3.6%) accounting for just over 75%. The chart 

directly below illustrates this data set level. 

 At the facility (basin) & reporter level (251 non-zero data sets) the top 1 (0.4%) 

accounted for about 37% of the total reported emissions, the top 3 (1.2%) 

0

5000

10000

15000

20000

25000

30000

35000

40000

0 200 400 600 800 1000 1200 1400 1600 1800 2000

MT's CH4 per Data Set

Data Sets

MT's CH4 Emissions - Venting for Liquids 

Unloading - 2012
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accounted for over 50% of the total CH4 reported, and the top 20 (7.9%) 

accounted for over 75%. 

 At the parent company level (99 total), the top 2 account for over 50% of the 

reported CH4 emissions and the top 11 account for over 75% of the reported 

CH4 emissions.

As this analysis shows the reported emissions are dominated by a small sub-set of the 

data sets reported which implies a targeted intervention effort for emission reduction is 

more appropriate than a broader regulatory effort. The top reporting companies are very 

aware that their operations have been unfavorably illuminated in the GHGRP and are

making significant efforts to alter operations so that they will not be singled out in future 

reports. This is likely a positive outcome of the transparency provided by the GHGRP

data.

Limitations of the GHGRP data: The data regarding liquids unloading in the GHGRP 

provides only partial coverage of the industry due to the 25,000 metric tonne CO2e 

reporting threshold. EPA has estimated the extent of coverage at 85%. Reported data 

indicated ‘Best Available Monitoring Methods” (BAMM) was used for some parameters 

in some data sets. 

b. API/ANGA 2012 Survey Data: 

Some of the conclusions that the white paper attributes to the API/ANGA survey report 

are not actually made in the report by the survey report authors. The white paper states: 

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.
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These may be correct conclusions made by the White Paper authors based on their 

interpretation of the API/ANGA report information but are not conclusions contained in 

the report. If the conclusions of the White Paper authors they should be identified as 

such. However, there was no information provided in the API/ANGA report referenced 

that would provide the information necessary to reach either of the last two bulleted 

conclusions. The White Paper authors should provide the source of the conclusions 

attributed to the API/ANGA report and correctly attribute them.

The API/ANGA report also reported the percentage of wells with artificial lift 

(mechanical deliquification) installed (7,329 of 54,660 - 13.4%) which is relevant as 

these wells have no potential for venting to help unload liquids. This information is not 

noted in the White Paper. 

c. U.S. Inventory of Greenhouse Gas Sources and Sinks - 2014: 

The White Paper discussion of the 2014 U.S. Inventory of Greenhouse Gas Sources and 

Sinks (NEI) is somewhat incomplete in that it does not discuss the limitations of the 

inventory estimate for liquid unloading or the difference in the ratio of wells venting for 

liquid unloading with and with/out plunger lifts from the other information sources. As 

Table 1 above shows, the ratio of venting wells with plunger lift and those without 

plunger lift in the NEI is opposite the ratio in the API/ANGA survey report, the GHGRP 

data, and the ICF/EDF report. This is likely due to the decimation of the API/ANGA 

data into NEMS regions, which yields smaller data sets for each NEMS region, with 

subsequent analysis at the NEMS region level to estimate activity data and emission 

factors. It is likely that the different ratio is an artifact of analysis of smaller data sets at 

the NEMS region level and hence not representative of the national well population. 

d. UT Emission Measurement Study: 

The White Paper discussion of this study’s measurement of liquid unloading events does 

not appropriately stress the limitations of the study. Since only 9 well-venting instances 

were measured and none had plunger lift installed the unlikely representativeness of 

these 9 measured events should be stressed. Although the White Paper does mention the 

author’s cautions regarding the representativeness of the measured venting events and 

extrapolation to a larger population, these cautions should be stressed. As the UT paper 

authors clearly state: “Because the characteristics of the unloading events sampled in 

this work are highly variable, and because the number of events sampled is small, 

extrapolating the results to larger populations should be done with caution.”

Additionally, the UT study report noted that: “In this work, sampling was performed for 

unloadings in which an operator manually bypasses the well’s separator. Unlike 

automated plunger lift methods, these manual unloading events could be scheduled, 

allowing the study team adequate time to install measurement equipment.” This implies 
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that wells may have initiated venting solely to enable measurement and hence may not 

have been “liquid loaded”. If correct, the measured flow during the venting would likely 

be different (likely higher) than flow from the same well if the well-bore was liquid 

loaded. 

e. ICF/EDF Report: 

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

Oil and Natural Gas Industries (ICF International, 2014)

The White Paper representation that the ICF/EDF report based the 2011 estimate of the 

number of wells venting with and without plunger lifts and estimated emissions on the 

2013 NEI is not consistent with the ICF/EDF report. As the following excerpts from the 

ICF/EDF report clearly notes, the GHGRP data for 2011 and 2012 (presumably 

averaged) was used to establish the “activity count” and “emission factor” for the 

baseline liquid unloading: 

“Data reported to subpart W for 2011 and 2012 was used to develop new 

activity and emission factors for wells with liquids unloading. From the subpart 

W data analysis, the number of wells venting with plunger lifts was reported to 

be 37,643 and the number of wells venting without plunger lifts was reported to 

be 26,451. It was assumed that subpart W covers 85% of reporters, so the 

number of venting wells was increased to 44,286 and 31,113, respectively.” 

“The emission factors were also updated using the data reported to subpart W 

for 2011 and 2012. The total emissions for each venting well type (plunger lift 

versus non‐plunger lift) were divided by the total number of reporting wells in 

order to obtain the new emission factors. From this analysis, 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.”

Also, the White Paper should clearly note that the ICF/EDF baseline estimates for 

venting of wells for liquid unloading does not represent any “new” information and is 

simply an analysis and “gross-up” of the GHGRP data. 

Charge Question 2

Is there further information available on VOC or methane emissions from the 

various liquids unloading practices and technologies described in this paper?

API provided supplemental material and analysis from the 2012 report “Characterizing 

Pivotal Sources of Methane Emissions from Natural Gas Production: Summary and 

Analysis of API and ANGA Survey Responses (API and ANGA, 2012)” to the EPA 

National Inventory team. This information provided additional detail, analysis, and 

derivation of emission factors for both plunger and non-plunger equipped wells. The 
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following table shows a summary of the information furnished that was not reviewed or 

included in this report.

Calculated national # wells w/plunger lift that vent for unloading 36,806 Wells

Calculated national # wells w/o plunger lift that vent for unloading 28,863 Wells

Calculated # vents for wells w/plunger lift 344 vents/venting well-yr

Calculated # vents for wells w/o plunger lift 33 vents/venting well-yr

Emission Factor per vent

Calculated EF: gas emissions per unloading vent for wells w/plunger 

lift 1,005 scf gas/unloading vent

Calculated EF: gas emissions per unloading vent for wells w/o 

plunger lift 9,336 scf gas/unloading vent

Emission Factor per well

Calculated EF: gas emissions per well for venting wells w/plunger 

lift 345,343 scf gas/venting well-yr

Calculated EF: gas emissions per well for venting wells w/o plunger 

lift 304,048 scf gas/venting well-yr

In the GHGRP data for 2012, it is important to note that the total number of wells using a 

venting technique to assist in unloading liquids was 65,669 wells. If there are 504,000 

gas wells then this number is 13% of the total. An administrative or regulatory action 

should be focused at this small subset of the wells rather than being a broad-brush 

approach to burden the entire population of gas wells with restrictions that are 

unnecessary.

Additional information providing background on well-bore liquids loading, techniques 

and tools used to manage liquid loading, and the role of venting to aid liquids unloading 

can be found in the Subpart OOOO docket. The information in the Subpart OOOO 

docket should be accessed and characterized in the White Paper. A massive amount of 

information regarding well-bore liquids loading, management of well-bore liquids, and 

deliquification technologies and techniques is available in the oil and gas industry 

technical literature. A good place to start accessing this information is Gas Well 

Deliquification portion of the “Artificial Lift R&D Council (ALRDC)” website at 

http://www.alrdc.com. 
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Limited information regarding emissions from well venting to aid liquids unloading and 

the reductions achieved by actions/projects to reduce venting are available in the Natural 

Gas Star archives of Technology Transfer Workshops and Annual Implementation 

Workshops which can be found at the EPA’s Natural Gas Star website 

http://www.epa.gov/gasstar/workshops. For example, several updates to the BP “Smart 

Automation” well unloading management, referenced in the white paper, have been 

presented with the latest in February of 2014. 

Charge Question 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?

EPA’s understanding is somewhat correct in that older wells do have a greater tendency 

to develop liquid loading problems due to decreased production rate - not pressure. The 

physical model that describes how free-flowing wells (including wells venting without 

plungers) is a “drag model” that describes the physical action of high-velocity gas flow 

dragging liquid packets at the no-flow boundary between the liquid and the gas. In this 

model, pressure is a secondary effect and the action of the gas on the liquid is dominated 

by the gas velocity. A more correct understanding would be that lower production rate 

wells have a greater susceptibility to liquid loading due to decreased velocity - which 

often occurs in older wells as production rate declines. However, liquid loading issues 

can and do occur in newer wells with inadequate velocity to lift the amount of liquids 

produced by the well. Absent a plunger-lift barrier between the well-bore liquid load and 

the formation, the formation pressure is not the relevant characteristic leading to liquid 

loading.

Whether a well is hydraulically fractured or completed with other stimulation technique 

has nothing to do with when it might experience problematic liquids loading. Whether a 

well is vertical or horizontal is also not relevant to when a well may experience

problematic liquid loading. One could speculate that to the extent that hydraulically 

fracturing a well or drilling a horizontal section increases the production rate from a well 

then such wells would have fewer tendencies to experience problematic liquid loading 

until later in their life-cycle but this is not universally correct. For example:
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 A well making 3 MMSCF/day may begin experiencing liquids loading in certain

high liquids production situations—these liquid loading problems will normally 

be addressed by adding a mechanical pump, not plungers or venting. 

 A well making 50 MSCF/day experiencing liquids loading will typically be 

evaluated for lower cost deliquification methods like adding a plunger or putting 

the well on intermittent (shut-in) or vent cycles. Onset of liquids-loading is a 

function of a very wide range of physical parameters and appropriate responses 

require evaluation of all of those parameters.

Charge Question 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?

Prior to discussion of individual technologies, techniques, and practices to manage wellbore liquids and venting to aid deliquification, the White Paper should acknowledge the 

complexity of the issues. Dealing with liquids-loading issues is a very complex mix of 

engineering and economics applied to an individual well. The appropriate approach to 

managing well-bore liquids in an individual well is likely to change as the well 

progresses through its life-cycle. Attempting to describe the applicability of individual 

techniques to the wide range of U.S. gas wells is not appropriate and runs the risk of 

severely constraining innovation. Well deliquification is a fundamental challenge for 

continued production from the majority of US gas wells and the proportion is expected to 

grow with new growth concentrated in non-traditional gas reservoirs such as shales, coalbeds, and tight-gas sands which are also susceptible to liquid loading. Managing 

wellbore liquids loading is a primary focus for production engineers and operations 

teams. A very large amount of industry focus, research, and attention is applied to gaswell deliquification with innovation and research continually underway. Research and 

work regarding managing well-bore liquids aims to both optimize and improve existing 

techniques along with developing entirely new types of systems. The flexibility to pilot 

some of these ideas/developments must be preserved – even if they ultimately do not 

succeed. 

a. Available Liquids Unloading Emissions Mitigation Techniques

The introductory paragraphs in this section of the White Paper illustrate misconceptions 

in the understanding of liquid loading of wells, venting to aid in unloading liquids, and 

approaches to minimize venting.

As previously noted above, the statement that 
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As the bottom well pressure approaches reservoir shut-in pressure, gas flow 

slows and liquids accumulate at the bottom of the tubing. 

is not correct. “Reservoir shut-in pressure” has no meaning in relation to liquid loading 

of well-bores. What is important is the flow rate into the well-bore and the flow velocity 

up the tubing in the well. 

The introduction of the term “blowdown” as an analogue to venting of wells to aid in 

liquid unloading is simply unnecessary and may be confusing to some readers. In the 

subsequent discussion, the White Paper discusses “blowdown” as a stand-alone approach 

to unloading well-bore liquids. While this may be correct in some instances, venting of 

wells to aid in unloading well-bore liquids is common in conjunction with some other 

approaches discussed - such as plunger lifts. 

The statement that: 

These technologies can reduce the need for liquids unloading operations or 

result in the capture of gas from liquids unloading operations. 

is incorrect in its understanding. What the technologies subsequently discussed can do 

is reduce the need for or practice of venting to aid in unloading liquids - unloading of 

well-bore liquids still must be accomplished. Also, dependent on the technique applied, 

gas not vented may be retained in the reservoir or produced - it is not “captured from 

liquid unloading operations.” 

b. Section 3.1”Liquid Removal Technologies” 

This section of the White Paper has several errors, misunderstandings, and omissions. 

There is no discussion of the limitations of the Natural Gas STAR program documents 

and partner presentations. The White Paper should be very clear that the Natural Gas 

STAR Lessons Learned documents are not peer reviewed, generally represent a 

compilation of information furnished by Natural Gas Star partners and studies 

commissioned by EPA, are generally compiled and written by an EPA contractor, and 

have not been rigorously reviewed by industry or other experts in the subject matter. 

Partner presentations are similar in that they have not been rigorously reviewed and 

typically describe an individual project or application of a technology or technique rather 

than a broad application. For technology and practice sharing the level of review and 

scrutiny was appropriate and the Lessons Learned, Partner Reported Opportunities, and 

Partner Presentation documents are useful and valuable. However, extrapolating these 

Natural Gas Star documents to the broad US population of wells and compiling the 

information to inform public policy, as the White Paper attempts, demands a higher level 
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of review and validation of the underlying information - which is lacking in the White 

Paper.

Some of the actions listed in the White Paper that the Natural Gas Star program reports 

are taken when liquids unloading occur are not correct. For instance:

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

venting the well to the atmosphere (well blowdown),

This statement is not correct. Wells may be vented without a shut-in cycle. A shut-in 

cycle can temporarily increase bottom-hole pressure near the well-bore and, more 

importantly, well inflow and production rate which will increase flow velocity when the 

well is flowed - either to production or atmosphere. Wells are often shut-in, a technique 

known as intermitting, either manually or more commonly via automation to temporarily 

increase well inflow and production rate and enable liquid lifting while producing into a 

collection system.

Swabbing the well to remove accumulated fluids,

The White Paper presents swabbing as a technique commonly used to manage well-bore 

liquid loading. In practice, swabbing is a remedial treatment with a rig or wire-line unit 

that is used only when a well will not respond to other techniques to remove the liquids 

from the well-bore and restore flow. It is expensive and hence not commonly used to 

manage liquid loading on a frequent basis.

The White Paper does not discuss “intermitting” as a technique to manage liquid loading 

of well-bores and potentially reduce venting. Intermitting is a technique where 

producing periods are interspersed with shut-in periods to allow the reservoir to “refill” 

the area around the well-bore that has been partially depleted during the producing 

period. The shut-in periods enable temporarily higher production rates and can enable 

velocities sufficient to lift liquids while producing rather than venting. 

The discussion of “smart automation” techniques, either coupled with plunger lifts or on 

wells without plunger lifts, in the White Paper is incomplete. The key to managing wellbore liquid loading while minimizing venting is understanding, managing, and using

reservoir energy not installing or running plunger lift systems or other techniques to aid 

well-bore liquid management. One approach to smart automation systems (but not the 

only possible approach) works by optimizing the management of individual well flowing 

and shut-in times to enable unloading of well-bore liquids without venting. This 

approach is applicable to both wells with plunger lifts and wells without plunger lifts

although wells with plunger lifts have more variables for the system to manipulate. The 

basic concept is: “The reservoir does not quit working when a well is shut-in”. 

Producing a well creates a zone of lower pressure and lower inflow capacity near the 
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well-bore. During shut-in, when the well is not flowing, the reservoir will continue to 

flow into the depleted zone and partially replenish the reservoir. When a well starts 

flowing after a shut-in period it will temporarily have higher inflow (production) rate

(often termed flush production) and higher pressure available. The higher production 

rate may provide adequate velocity to lift liquids while producing in the absence of a 

plunger lift and the higher pressure may provide adequate energy to lift a plunger and its 

load while producing without the need for venting. Although the potential benefits of 

such an approach are briefly discussed in the White Paper, much more emphasis and 

discussion should be devoted to this subject. 

The BP “smart automation” project discussed in the documents referenced in the White 

Paper (British Petroleum (BP) 2006; U.S. EPA 2006a; and U.S. EPA 2011) provides an 

excellent case study example of the application of understanding and optimizing 

reservoir energy management to sharply minimize venting associated with liquid 

unloading. However, the BP project is somewhat mischaracterized in both U.S. EPA 

2006a and U.S. EPA 2011 as a project to install plunger lift systems in conjunction with 

“smart automation”. The actual nature and success of the project was to optimize the 

frequency and duration of shut-in times on individual wells and plunger cycle timing on 

wells with plungers through the use of automation that learned the performance of each 

well and then optimized the cycle parameters for that well – i.e. “smart automation”. 

This was and is a project about managing reservoir energy not about installing or running 

plunger lift systems. About half of the wells which were venting were plunger equipped 

and about half were not plunger equipped. Both plunger equipped and non-plunger wells 

were previously vented in order to generate the flow or pressure differential necessary to 

lift liquids. Also, the references to this project in the White Paper are incomplete. 

Updates regarding this project were presented at the 2007 Natural Gas Star Annual 

Implementation Workshop and several times since with the latest at the Denver, CO and 

Park City, UT Technology Transfer workshops in 2014. 

Splitting the techniques used to manage liquid loading into “primary” and “remedial” 

technologies in the White Paper is not useful from the standpoint of improving 

understanding regarding minimizing venting to assist deliquification. A more 

appropriate approach would be to split the technologies into those that rely on reservoir 

energy for unloading liquids and those that add energy to the well-bore to unload liquids. 

Plunger lift, velocity tubing, intermitting, soap/surfactant injection, and reducing surface 

pressure via de-bottlenecking or compression all rely on reservoir energy. Down-hole 

pumps, of various types, and gas-lift add energy to the reservoir fluids. Conceptualizing 

technologies/techniques in this manner enables consideration of approaches to minimize 

venting at each stage of a wells life-cycle and in conjunction with each 

technology/technique used. 
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Wells and reservoirs follow a continuum of flow regimes in their economic life as the 

reservoir depletes, production goes down, well-bore (tubing) velocity goes down, and 

liquid loading begins to occur in the well-bore. In the early stage of a well’s life many 

(but by no means all) wells can flow freely and with sufficient velocity to avoid liquid 

loading problems. As the reservoir energy depletes and the production-rate declines, a 

well will reach the stage where liquid-loading begins to be a problem and one of a 

portfolio of technologies or techniques will be used to help lift liquids using the 

reservoir’s energy. As a well continues to produce and the reservoir energy declines 

further, a well will reach the stage where the reservoir’s energy is not sufficient to lift 

liquids and mechanical lift energy, in the form of pumps, gas lift, etc., will have to be 

added to continue producing. When the expected production from a well cannot support 

the investment required to enable deliquification, it will reach the end of its economic 

life and be abandoned. 

The following figure shows a generalized well life-cycle curve with these different stages 

of a wells life illustrated. 

To address this normal well/reservoir depletion and assist liquid lift a number of 

techniques are used – dependent on the well configuration, reservoir properties, well 

depth, and surface equipment and collection system. The choice of what technique to 

employ is based on well-by-well and reservoir-by-reservoir analysis and is one of the 

primary jobs of production engineering teams. For a typical well, as it moves through 
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the depletion continuum, a series of techniques will be employed. The decision on 

technology-selection requires a thorough understanding of the conditions that a reservoir 

is flowing into, the reservoir’s sensitivity to backpressure and the volumes and pressures 

that the deliquification technology must handle, and costs/benefits of applying the 

technology. Operators must have the flexibility to choose the most appropriate and cost 

effective approach for each individual well/reservoir/age/production combination and the 

regulatory certainty to underpin continued investment. Minimizing venting associated 

with liquid unloading is part of this ongoing evaluation. 

c. Costs

Stating generic costs/cost-ranges and/or economics for any of the technologies or 

techniques discussed is fraught with difficulty and error. Costs and economics are as 

variable as the wells and reservoirs they are applied to and any problems or difficulties 

encountered. If problems or difficulties are encountered when installing equipment 

(plungers, profile nipples for a plunger bumper spring, velocity tubing, or soap injection 

mandrels) in a well, costs will escalate dramatically. Certainly such costs are germane to 

the discussion since it is a possible outcome of any decision to work on a well. There is 

simply no way to state generically where most wells are within their performance

lifecycle, how they will respond to a technique/technology, or what the costs and 

economics of application will be. One well may be economic at 20 MSCF/day while 

another might be plugged when the rate reaches 150 MSCF/day. The difference is a 

complex mixture of reservoir performance, market-price differentials, level of 

capitalization, and operating costs. These variations are what drive evaluation of 

individual wells for the appropriate selection and application of technologies/techniques 

to manage liquid loading or a decision to plug a well that can no longer support the costs 

of deliquification. Retaining the flexibility to make individual well-appropriate 

technology-decisions is fundamental to the continued economic production of a great 

many gas wells in the U.S. 

d. Section 3.1.1 Plunger Lifts: 

The assertion in the White Paper that installation of plunger lift systems is an emission 

(venting) control technique is not correct, not supported by the emission data, and not 

underpinned by a logical or technical analysis in the White Paper. Plunger lifts are a 

valuable, effective and commonly used methodology/tool to assist in managing well-bore 

liquid loading. Plunger lifts do increase the efficiency of liquids removal from wells by 

the reservoir energy and hence do help maintain or increase production. However, the 

efficacy of plunger lifts in reducing venting of wells deliquification and emissions is 

completely dependent on how they are operated. As the API/ANGA survey report, the 

GHGRP data, the U.S. Emission Inventory, and the ICF/EDF report reanalysis of the 

GHGRP data shows, venting wells with plungers have higher emissions per well than 
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venting wells without plunger lifts. Despite the API/ANGA survey report estimate that 

only about 36% of U.S. gas wells are equipped with plunger lifts (of which only a subset 

vent), venting of wells with plunger lifts constitute the majority of venting wells and 

emissions. Wells with plunger lift systems comprised ~55% of the more than 58,000 

wells reported as venting for liquids unloading into the GHGRP for 2012. From an 

emission perspective, wells with plunger lift systems accounted for about 72% of the 

GHGRP reported emissions from well venting for liquids unloading. The GHGRP 

reported data is broadly equivalent to that reported from the API/ANGA survey. With 

the API/ANGA survey outcome of about 36% of the well population being equipped 

with plunger lift systems yet responsible for over 50% of the venting wells and 70% of 

the emissions, the efficacy of plunger lift systems as an emission control measure is 

clearly not supported by the data. However, with advanced well liquids unloading 

management (management of reservoir energy), large reductions in the frequency of well 

venting and thereby emissions resulting from liquids unloading, from both plunger and 

non-plunger equipped wells, can likely be made. 

e. Table 3.1 Plunger Lift Review Comments:

 The statement in the Applicability column that 

“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).” 

is incorrect. By definition, plunger lift systems are dependent on reservoir energy, 

specifically downhole pressure, to lift the plunger and the water/fluid load in the wellbore. Adequate differential pressure must exist between the reservoir pressure and the 

sum of liquid column hydrostatic pressure, flowing friction pressure loss, surface 

equipment pressure loss, and collection system back-pressure in order for a plunger to 

return to surface with the liquid load. Adequate differential pressure may be generated 

by using shut-in cycles to increase downhole pressure or by using venting cycles to 

remove surface and collection system back-pressure. The key to minimizing venting 

associated with plunger operation lies in how you achieve adequate differential pressure 

to enable a plunger to lift into the producing system rather than venting to atmosphere. 

 Cost ranges: The cost ranges in Table 3.1 appear to be copied directly from the 

underlying documents cited and do not appear to be updated to current dollars. This 

significant oversight should be corrected in the White Paper. Also, the costs and 

economics extracted from the underlying documents were predominantly based on 

Gas Star partner reports and likely reflected installations of plunger lifts that had 

already been determined to be appropriate for the individual wells where they were 

installed based on a well-by-well evaluation by the companies making the 
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installations. The resultant cost and economic profile would likely be very different 

than installations done on a basis different than well-by-well evaluation. 

 The statement in the “Efficacy and Prevalence” column of the Table 3.1 plunger lift 

section that “The EPA has learned plunger lift systems rely on manual, onsite 

adjustments.” is not uniformly or even mostly accurate. A large percentage of 

plunger lift installations are controlled with automated plunger control systems rather 

than manually operated. Increasingly, these systems incorporate the capability to 

identify problems and make immediate adjustments. Techniques with telemetry, 

electronic data collection, and troubleshooting software continue to improve plungerlift performance and ease of use. A cursory review of plunger vendor websites show 

that most/all offer advanced plunge control systems that optimize plunger efficiency. 

Several links to examples are: 

http://www.weatherford.com/Products/Production/PlungerLift/

http://www.pcslift.com/plungerlift/plunger_products.html

http://www.pcslift.com/PDFs/PCSFerguson_PLMgr.pdf

 Information regarding the prevalence of plunger lifts is missing from Table 3.1. As 

the API/ANGA survey report noted, about 36% of the U.S. gas wells are equipped 

with plunger lifts. 

f. Section 3.1.1 - Plunger Lift Narrative Review Comments:

The introductory paragraph of this section is incomplete and somewhat misleading. 

“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.”

As discussed above, the key to minimizing venting of wells equipped with plunger lifts is 

how the differential pressure necessary to lift a plunger and its load is achieved. If this is 

accomplished through vent cycles then venting emissions are likely to be high for a well 

equipped with a plunger. Conversely, if this is accomplished by using shut-in cycles to 

manage the reservoir pressure build-up then venting emissions are likely to be much 

lower. Using a plunger control system (“smart automation”) that optimizes the operation 

of the plunger on an individual well to achieve maximum unloading/production and 

minimum venting/emissions is likely to reduce venting/emissions to just instances where 

overloading occurs due to system malfunctions or high reservoir liquid/water production 

surges. Differences in approach to operation of plunger lift equipped wells are mostly 
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due to differences in the approach/philosophy that operators take to managing reservoir 

energy and somewhat due to differences in reservoir characteristics. 

The description of a plunger lift system should clearly note that this is an example only 

and that other configurations are common. Also, the White Paper should describe the 

broad range of plunger types and configurations available along with noting the 

significant amount of ongoing development and research devoted to improving plunger 

lifts and their operation. For example, continuous-run flow-through plungers are 

available that have a higher liquid volume lift capacity and are appropriate for some 

wells. Also recently available are flexible plungers designed for use in wells with quite 

high deviation from vertical - which is becoming more common with multi-well pad 

development. Additionally, Figure 3-1 page 21 shows a “gas lift valve” on the bottom of 

the tubing. This valve is not part of the required bottom-hole assembly for plunger 

operation. 

As discussed above in the Table 3.1 comments, the costs and economics of plunger lift 

installations appear to be extracted directly from the underlying documents referenced, 

are not updated to current dollars, and are predominantly based on costs and benefits 

reported by Natural Gas Star partners that have been compiled by an EPA contractor in 

the underlying documents. These costs are seriously outdated and need to be updated 

using an escalator for oil and gas equipment and labor which has been higher than the 

consumer price index (CPI) since 2000. It is strongly suggested that EPA engage 

industry operators and plunger lift suppliers in a survey to gather updated costs. 

The White Paper summary of the ICF/EDF report fails to highlight that the 95% 

reduction in venting, that drives the economics of plunger lift installation summarized, is 

based on a simply asserted reduction that is not underpinned by any analysis in the 

ICF/EDF report. The White Paper does not analyze or validate this assertion. The

ICF/EDF capital and operating cost assumptions summarized in the White Paper have 

similar issues. 

g. Section 3.1.1 - Artificial Lift Systems: 

The discussion of artificial lift systems in both Table 3.1 and the White Paper narrative 

omits several technologies/techniques and pump types used in mechanical deliquification 

(artificial lift).

There is no mention of gas lift, which involves injection of higher pressure gas down the 

casing-to-tubing annulus in order to increase the flow up the tubing thereby increasing 

the velocity and capacity to lift liquids. Gas lift typically requires additional 

compression and piping at the surface which requires either electricity to drive 

compressors or engines to drive compressors – all of which add emissions, complexity, 

reliability concerns, and operating costs. Also, gas lift is limited to those reservoir/well 
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combinations where the gas injected down the well will flow up the well-bore and not 

simply dissipate into the formation. 

The discussion of pumps focus solely on beam pumps (also termed rod pumps, beam lift

pumps, and pumpjacks in the White Paper) and omits progressing cavity pumps and 

electric submersible pumps. Although not as prevalent as beam pumps, these pump 

types are used for deliquification of gas wells. Also, omitted from the White Paper is 

any discussion of linear pumps, both coupled with a rod pump (replacing the walking 

beam), and in downhole applications. Considerable development and research is being 

applied to pump technology and linear pumps are one fairly recent outcome with 

ongoing improvement expected. 

The reference to “downhole separator pumps” in Table 3.1 is not recognized as a 

technology that exists. If a valid technology, the White Paper should provide a detailed 

description of this technology and the nature and extent of its use. 

The costs shown for artificial lift installations have the same problems as costs shown for 

other technologies/techniques. They appear to have been extracted directly from the 

underlying sources referenced, have not been updated to current dollars and appear to be 

based on limited reports by Natural Gas Star partners in the underlying documents. 

Also, costs are very well-specific, company specific, and technology specific. 

Generalizing these costs is not appropriate.

Omitted from Table 3.1 is information from the API/ANGA survey report that 13.4% of 

the wells reported in the survey have some form of mechanical deliquification (artificial 

lift) installed. This is important and should be included. The statement in Table 3.1 that 

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

is incorrect. 

h. Section 3.1.1 - Velocity Tubing: 

The discussion of velocity tubing in Table 3.1 and the narrative omits any discussion of 

the trade-off between increased potential velocity with a smaller x-section of flow and 

increased flowing friction inherent in smaller diameter tubing which inhibits flow and 

hence velocity. In practice this trade-off limits the practical minimum diameter of 

velocity strings to about 1 - 1.5 inches. Although a review of the underlying documents 

referenced by the White Paper is beyond the scope of these comments, the statement in 

U.S. EPA 2011 that “Coiled tubing may also be used, allowing for easier installation 

and the application of a greater range of tubing diameters as small as 0.25 inches.” is 

incorrect and needs to be corrected. 

The excerpt from U.S. EPA 2011 in Table 3.1 that notes 
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“Seamed coiled tubing may provide better lift due to elimination of turbulence 

in the flow stream (U.S. EPA, 2011). 

is based on an unsupported assertion in U.S. EPA 2011 that makes reference to 

unidentified “studies” reaching this conclusion. This reference should be removed from 

the White Paper unless substantiated and attributed. 

The range of flow rates or life-cycle stages where velocity tubing may be applied in both 

Table 3.1 and the narrative discussion are simply not correct. Any tubing string placed 

within the production casing can be thought of as a “velocity string”. The well operator 

is using velocity (at the price of increased friction drop) to keep the gas flow above some 

“critical value” that is required to allow the gas to reliably lift the liquid. It is correct that 

smaller diameter tubing strings are used to increase velocity and the ability of gas to lift 

the liquid. However, the range of production rates and water loading where smaller 

diameter tubing may be a benefit is considerably broader than represented in the White 

Paper. Candidate wells and the appropriate tubing diameter are selected based on a 

modeled calculation of “critical velocity” based on the physics of fluid flow and flowing 

friction. That critical velocity value is not 1000 ft/min (16.67 ft/sec), as stated in the 

White Paper, except in the rarest of coincidences. 

The cost and economic data presented in the White Paper appear to have been extracted 

directly from the underlying documents referenced, are not updated to current dollars and 

should be revised. Also, similar to other costs and benefits noted in the White Paper, 

they appear to be based on self-selected reports from Natural Gas Star partners on 

successful installations of velocity strings and are not likely to reflect the 

performance/benefits of installation of velocity strings where their application is not 

based on well-by-well evaluation and selection. 

The statement in Table 3.1 that velocity strings are “Considered to be a no emission 

solution.” is incorrect. It is not uncommon for wells with smaller diameter velocity 

tubing strings to be vented to aid in liquid unloading. The GHGRP well venting data

using Method 1 (which represents a small portion of total reports) for 2011 and 2012 

contain multiple data sets where the tubing size selection is <1” although this selection is 

not always consistent with the average tubing size shown. 

i. Section 3.1.1 - Foaming Agents:

The discussion of soap/surfactant use in Table 3.1 is not consistent with the discussion 

in the narrative and is not correct. The Table 3.1 discussion focus on injection of 

soap/surfactants omits instances where wells are configured to gravity feed surfactants 

along with instances where “soap sticks” are simply “dropped” down the casing-tubing 

annulus. The discussion of how a soap/water solution generates foaming is an 

oversimplification of the physics involved which are dependent on turbulence for foam 
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generation. In general, the successful use of surfactants is more than the low-tech 

solution implied by the table. 

The Table 3.1 representation of foaming agents as a “no emission solution” is not 

correct. It is not uncommon for venting to be used in conjunction with soap/surfactant 

use to unload liquids. 

The cost and economic data presented in the White Paper appear to have been extracted 

directly from the underlying documents referenced, are not updated to current dollars and 

should be revised. Also, similar to other costs and benefits noted in the White Paper, 

they appear to be based on self-selected reports from Natural Gas Star partners on 

successful use of soap/surfactants and are not likely to reflect the performance/benefits of 

soap/surfactants where their application is not based on well-by-well evaluation and 

selection. 

Charge Question 5

Please provide any data or information you are aware of regarding the 

prevalence of these technologies in the field.

Data regarding the prevalence of plunger lift installations is presented in the API/ANGA 

survey report where 36% of the wells reported (21,500 of 59,648 wells) having plunger 

lifts installed. Projecting this to a national population for 2010 the API/ANGA report 

estimated about 174,743 wells with plunger lift in 2010. 

Data regarding the prevalence of mechanical deliquification (artificial lift) is presented in 

the API/ ANGA survey report where 13.4% of the wells reported (7,993 wells) having 

some form of mechanical deliquification installed. Projecting this to a national 

population for 2010 the API/ANGA result implies about 68,000 wells with mechanical 

deliquification installed in 2010.

Charge Question 6

In general, please comment on the ability of plunger lift systems to perform 

liquids unloading 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?

Plungers operate by providing a mechanical barrier between the liquid column in a wellbore and the reservoir gas/energy that is used to lift the plunger and liquid load to the 

surface. Plungers depend on adequate differential pressure to lift liquids and do increase 
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the efficiency of using reservoir energy vs. depending on velocity to drag liquids. A 

plunger’s ability to rise is defined by six physical parameters:

 Weight of the plunger 

 Mechanical friction of the plunger against the tubing walls

 Fluid friction against the tubing walls 

 Weight of the liquid being lifted

 Surface equipment pressure drop and collection system/surface backpressure

 Formation/reservoir pressure available for lift

The first three parameters have a reasonably consistent and predictable magnitude. The 

fourth parameter is quite variable. If the total liquid weight increases, the balance 

between bottom-hole pressure and flowing tubing-head pressure can fall to zero and lose 

the driving force for the system. At that point operators may remove surface restrictions 

and gathering-system pressure from the equation by venting the well to re-establish the 

necessary differential pressure to run the system. Other operators may rely on shut-in 

periods to build pressure in the near well formation. Other operators may install wellsite compression to allow the use of mechanical horsepower to remove surface 

backpressure from the process. 

With advanced reservoir-energy management and optimized well-liquids unloading 

management, large reductions in the frequency of well venting and thereby emissions 

resulting from liquids unloading, from both plunger and non-plunger equipped wells, can 

likely be made. However, the need to vent will still occur. Even with advanced plunger 

lift systems and advanced control systems for plunger lift equipped wells, there will be 

instances where venting a well to atmosphere is necessary to gain the differential 

pressure necessary to bring a plunger to surface. This is generally due to periods of 

greater than normal water loading (height of water column) in the well bore which can be 

caused by natural variation in reservoir flow or system failures/malfunctions.

As the emission data sources uniformly show, venting of wells equipped with plunger 

lifts accounts for more emissions overall and on a per-venting-well basis than emissions 

from venting of wells not equipped with plunger lifts. The counterfactual interpretation 

of the data, which the ICF/EDF paper does, is purely conjecture and should be noted as 

such. 

Charge Question 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.
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The representation in this question that the BP presentation referenced claims 100% 

liquid removal (presumably of the column of liquid in the well-bore above the plunger) 

is not correct. The BP presentation made no representations regarding the percent of 

liquid (again presumably the column of liquid in the well-bore above the plunger) 

removal by a plunger. 

In practice, plunger lifts are designed with clearance between the plunger and the tubing 

walls to enable gravity free-fall down a well and minimize plunger friction during travel 

to the surface. Due to this clearance, some gas leaks upwards past a plunger and some 

liquid “slips” past the plunger or plates out against the tubing wall and subsequently falls 

back into the well. The amount of liquid that “slips” or plates out against the tubing 

walls and subsequently falls back into the well is variable and depends on several factors. 

Charge Question 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?

There is likely no instance where installation of a plunger lift system during initial well 

construction would be beneficial. Many wells will never be a candidate for plunger lift 

use and installation of a plunger lift system would simply be a complete waste of money. 

Most wells that eventually do experience liquids loading and are candidates for plunger 

lifts will not reach that point until after many years of free-flowing production. Installing 

a plunger lift system at initial well construction would unnecessarily decrease capital 

efficiency. Practically, in the time that a well is free-flowing, it is likely that the well 

may be worked on 3-5 times, each time it is worked on all of the plunger equipment 

would be removed to facilitate pulling the tubing. After sitting in a well for many years, 

it would be rare for components like profile nipples, bumper springs, and lubricators to 

be in a condition that would allow their re-installation so putting this equipment on new 

wells assures that it will be discarded long before it could ever be put in service. It is 

also unlikely that a plunger lift system installed at initial well construction would be 

functional if and when it was called on to operate after many years of sitting in a well. 

For high flowing wellhead pressure wells, such as the Marcellus Shale, lubricators for 

plungers are not available with pressure ratings high enough for application. For high 

production rate wells, the tubing sizes are larger to accommodate the flow. Tubing 

plungers for 4.5 inch tubing, which is common in high rate wells, are not available - nor 

are they needed due to the high flow rates and velocities. Additionally, the plunger 

equipment in a well can fail and cause problems that would require additional 

expenditures to correct. 
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Installing a plunger lift system at the time of initial well construction would also “lockin” technology at the time of installation. Given the tremendous amount of research, 

development and focus being applied to deliquification of gas wells and the amount of 

progress being made this is not advisable. 

The concept of installing a plunger lift system at initial well construction indicates a lack 

of understanding of wells, well life-cycle, liquid loading, and efficient use of resources. 

Charge Question 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?

To the extent that advanced (smart) automation of well operation and liquid loading 

management improves the management of reservoir energy, such use is likely to sharply 

reduce, but not eliminate, the need for venting to aid liquid unloading. This can be 

beneficial for both wells equipped with plunger lifts and wells without plungers installed.

However, these systems are expensive, require customization to the area and reservoir 

where they are being deployed, and require highly skilled personnel to maintain, 

calibrate, and operate. As the BP “smart automation” project, referenced in the White 

Paper, shows these types of installations can be difficult and may take years of concerted 

effort to achieve the desired outcomes. They are not a “silver bullet” answer to reduce 

venting for liquid unloading but are another valuable tool to be used as appropriate. 

Charge Question 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?

This question indicates a misunderstanding of venting to aid liquid unloading, which is 

the activity that results in emissions, and the elimination of any benefit of venting when 

artificial lift is installed. As discussed above, mechanical deliquification (artificial lift) is 

the addition of energy, in the form of a pump or gas lift, to a well-bore to enable liquid 

removal. It is employed when the reservoir energy in a well is not sufficient to use other, 

techniques to aid in liquid removal. Once applied, venting a well provides no benefit and 

will not occur. However, installation of pumps or gas lift is expensive and the expected 

production of many marginal wells will not support the investment necessary. 
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Pumps in gas well deliquification applications struggle to cope with the typically low 

liquid volumes, variable liquid volumes, and damage caused by cavitation and “gaslocking” of the pumps. Many techniques and approaches are employed in an attempt to 

deal with this problem with varying degrees of success. Ongoing research and 

development of gas well deliquification specific approaches and products is making 

progress on these problems. 

Although gas lift is applied to gas well deliquification, it is far less effective on gas wells 

than when applied to oil wells due to water having little ability to absorb natural gas 

which serves lighten the specific gravity of the mixed fluid in a well bore. Gas lift 

typically requires additional compression and piping at the surface which requires either 

electricity or engines to drive compressors – all of which add emissions, complexity, 

reliability concerns, and operating costs. Also, gas lift is limited to those reservoir/well 

combinations where the gas injected down the well will flow up the well-bore and not 

simply dissipate into the formation. 

Beam pumps require a surface power unit and continuous rods from the surface to the 

bottom-hole plunger pump. While more forgiving of low liquid production volumes than 

submersible pumps or progressing cavity pumps, beam pumps are not very optimum for 

deviated well-bores such as those on multi-well pads (done to reduce surface 

disturbance). In a deviated well-bore, the rods will tend to rub against the tubing/casing 

and cause wear and failure of either the rods and/or the tubing/casing. Unless electricity 

is available, the surface power unit must be a gas fired reciprocating engine which adds 

significant emissions, complexity, reliability concerns, and operating costs. 

It is important to understand the distinction between applying a mechanical 

deliquification technology to a gas well to remove liquids from interfering with gas 

production and artificial lift in the classic sense of lifting a commercial product, typically 

oil, to the surface. The economics and economic drivers are entirely different between 

the two. When the expected production from a gas well cannot support the investment 

required to enable deliquification, it will reach the end of its economic life and be 

abandoned. Requiring the installation of mechanical deliquification technology 

(artificial lift) would cause many marginal U.S. gas wells to be abandoned. This would 

likely disproportionately impact smaller producers since they typically have portfolios of 

smaller more marginal wells. 

There are no “standard criteria” that apply across reservoirs, wells, and companies. 

Charge Question 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 
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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?

This reviewer is not aware of any instances where flares or other combustion devices are 

used during liquids unloading operations - including wells with H2S. In 2012, 58,663 

discrete wells were reported into the GHGRP as vented for liquids unloading. Grossing 

this up, using EPA’s estimate of 85% coverage under Subpart W, yields just over 69,000 

individual wells vented to unload liquids in 2012. Flaring of gas during liquids 

unloading would necessitate separation of the liquids from the well stream in a separator 

or flare knock-out drum. Backpressure, sufficient to unload liquids from the separator to 

a storage tank, would need to be held against the well/separator which would directly 

reduce the differential pressure gained by routing to atmosphere and perhaps inhibit 

unloading. Due to the potential flow rate and Btu demand, flares would need to be 

dedicated to liquids unloading and be moderate size (~20 MMBtu/hr) rated. Liquids 

unloading flares would need either continuous pilots (for infrequent use) or electronic 

igniters - perhaps powered by solar. Also, well-sites would need to be “re-piped” to 

route from the separator to the dedicated well unloading flare. Besides the technical 

difficulties dealing with the intermittent and surging flow characteristic of venting for 

liquids unloading, the changing velocities during an unloading and the problems of 

ensuring ignition for a sporadically used flare, the cost would be prohibitive. 

Multiplying the estimated total installed cost of $100k per flare times the number of 

wells vented for liquid unloading in 2012, the cost would easily be billions of dollars. 

There are much more cost effective methodologies to reduce liquids unloading without 

the emissions and visual impact associated with flaring. 

Charge Question 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?

It is very unlikely that portable flare equipment, which tends to be more expensive on a 

unit basis than stationary flares, would be feasible for use with respect to venting for 

liquids unloading. Moving a flare to a location, hooking it up to a vent line, testing the 

integrity of the system, and then ensuring a pilot light each time a well was to be vented 

would take considerable time and cost. Given the sheer number of wells that vent for 

liquids unloading, about 69,000 in 2012 based on the GHGRP data, coupled with the 

number of venting instances, 4,524,802 venting events for Method 1 reported into the 
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Oil & Natural Gas Sector Liquids Unloading Processes

GHGRP plus the yet to be reported instances for Methods 2 & 3, the costs and logistics

to use this approach would far outweigh any benefits. 

Charge Question 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?

The disparity between reports into the GHGRP, discussed above, indicate that how a 

company or operation handles liquid unloading and specifically the philosophy regarding 

management of reservoir energy with respect to well-bore liquid management has a very 

large effect on use of venting as part of well-bore liquid management.

Some operators choose to put production packers, between the tubing exterior and 

production casing interior, above the productive formation. These packers limit 

deliquification options to vent cycles or velocity strings since they preclude plungers, 

mechanical pumping, or the use of soap/surfactants.

At this time, deliquification of horizontal wells is a work in progress with considerable 

research ongoing to develop or improve technologies. When the flow rates decline to the 

point that there is inadequate velocity in the wellbore tubulars to allow the gas to lift the 

liquid there are examples of horizontal wells being placed on vent cycles simply because 

there is not an alternative option.

Charge Question 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.

Other than the Phase 2 UT/EDF study mentioned, no studies of liquids unloading are 

known to be currently underway. However, data reported into the GHGRP in March of 

2015 for the 2014 emission year will include additional information related to venting 

(previously deferred) that will provide significantly better understanding of venting for 

liquid unloading. Pending changes to Subpart W of the GHGRP will require reporting of 
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additional data parameters in 2016 for the 2015 emission year, which will also aid in 

understanding of venting for liquid unloading. 

C. Conclusion

As the GHGRP and API/ANGA data illustrate, venting for liquids unloading is a 

problem mostly driven by a relatively small number of operators and a relatively small 

subset of wells. This strongly suggests that a targeted intervention is appropriate to 

address this issue. 

Since the frequent use of venting is restricted to a small number of operators and the

GHGRP data makes this information public, operators that represent the majority of 

venting events are actively working to reduce/eliminate venting in their operations to 

avoid the public exposure in future reports. This alone is likely to significantly reduce 

the frequency of venting to aid liquids unloading and hence emissions. The assertion in 

the White Paper that installation of plunger lift systems is an emission (venting) control 

technique is not correct, not supported by the emission data, and not underpinned by a 

logical or technical analysis in the White Paper. It is absolutely true that plunger lifts are 

a valuable, effective and commonly used methodology/tool to assist in managing wellbore liquid loading. Plunger lifts do increase the efficiency of liquids removal from 

wells by the reservoir energy and hence do help maintain or increase production. 

However, the efficacy of plunger lifts in reducing venting of wells and emissions is 

completely dependent on how they are operated. As the API/ANGA survey report, the 

GHGRP data, the U.S. Emission Inventory, and the ICF/EDF report shows: venting 

wells with plungers have higher emissions per well than venting wells without plunger 

lifts. From an emission perspective, wells with plunger lift systems accounted for about 

72% of the GHGRP reported emissions from well venting for liquids unloading. The 

general efficacy of plunger lift systems as an emission control measure is clearly not 

supported by the data. However, with advanced well liquids unloading management 

(i.e. management of reservoir energy), large reductions in the frequency of well venting 

and thereby emissions resulting from liquids unloading, from both plunger and nonplunger equipped wells, can likely be made.