Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

Fax: 202-682-8031

Email: ToddM@api.org

www.api.org

June 13, 2014

Mr. Chris Frantz

US EPA 

109 T.W. Alexander Drive

Mail Code: #143-05

Research Triangle Park, NC 27709

Re: EPA VOC/Methane White Paper on Oil and Natural Gas Sector Liquids Unloading 

Processes

Dear Mr. Frantz:

The American Petroleum Institute (API) appreciates the opportunity to provide feedback on EPA’s White 

Papers on Methane and Volatile Organic Compound (VOC) Emissions in the Oil and Natural Gas Sector.

On April 15, 2014, EPA released, for external peer review, white papers that focus on technical issues 

covering emissions and mitigation techniques targeting methane and VOCs from five separate emission 

sources. As noted in the Obama Administration’s Strategy to Reduce Methane Emissions, EPA will use 

the papers, along with the input from the peer reviewers and the public, to determine how to best 

pursue additional reductions from these sources. As described below, API does not believe additional 

methane controls should be required at this time. 

API represents over 590 oil and natural gas companies, leaders of a technology-driven industry that 

supplies most of America’s energy, supports more than 9.8 million jobs and 8 percent of the U.S. 

economy, and, since 2000, has invested nearly $2 trillion in U.S. capital projects to advance all forms of 

energy, including alternatives. Many of our members will be directly impacted by any policy decisions 

that may arise from this effort regardless of whether it informs either regulatory action by the federal 

government or states.

API provided technical feedback and expertise throughout the development of the New Source 

Performance Standard (NSPS) Subpart OOOO rule. Each source addressed by the white papers was 

considered for regulation during the development of the NSPS and EPA, ultimately, chose not to 

regulate them. While our understanding of emissions from oil and gas production continues to evolve,

the fundamental merits of requiring additional regulatory control of these sources is unchanged. As 

such, API continues to believe that no additional regulation of oil and gas production sources is 

necessary prior to the full implementation of the NSPS OOOO rule and a subsequent evaluation of 

emissions.
Page 2

Considering the potential for significant impact on our members that may arise from any policy decision 

stemming from the white papers, API has developed significant technical comments (see attached) to 

address a number of technical inaccuracies about the sources and the conclusions that have been 

drawn. Barring significant revision, API believes that the current white papers are simply insufficient to 

inform sound policy decisions and that simply posting comments on the current version will not result in 

an informed process. As such, API recommends the EPA take the following steps:

 Revise the white papers to correct any fundamental flaws or inaccuracies that were identified in 

response to peer review and stakeholder comment (e.g., improved source descriptions, 

improved understanding of emission quantification, misconceptions about emission mitigation 

options)

 Develop a response to comments document that clearly identify the changes the EPA makes to 

the revised white papers and explains the Agency’s rationale for those changes

 Identify emission studies in progress that will better inform EPA’s understanding of these source 

emissions and await the pending study reports

In recent years, there have been significant swings in the national emission estimates from oil and gas 

production sources, including those covered by the white papers, which indicate a necessity to continue 

collecting data to improve our understanding. Much of this learning will come from improved reporting 

under Subpart W of EPA’s Greenhouse Gas Reporting Program as well as current studies and others 

planned in the coming years, which involve taking direct measurements of the sources. EPA and industry 

would both be well served by allowing these studies to inform policy. 

Again, we appreciate the work by EPA to initiate these white papers and the opportunity to provide 

feedback on this effort. API and its members are dedicated to working with EPA to improve our 

collective understanding of these emissions and providing the technical operator experience that’s 

needed to do so. Recognizing the potential for these white papers to inform not only EPA but other 

government agency policy decisions, we request the opportunity to provide additional feedback to the 

Agency in response to any of our comments in advance. Furthermore, we again offer our experience and 

expertise as EPA moves into the policy evaluation phase of this effort.

Sincerely,

/s/

Matthew Todd

Cc: Peter Tsirigotis, EPA

David Cozzie, EPA

Bruce Moore, EPA
Comments on

Oil & Natural Gas Sector

Liquids Unloading Processes

by EPA Office of Air Quality Planning and Standards

June, 2014

Prepared by

The American Petroleum Institute (API)
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

Table of Contents

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

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

B. Charge Questions ...........................................................................................................................4

Charge Question 1 .......................................................................................................................4

a. GHGRP Data - 2012 emission year: ......................................................................................5

b. API/ANGA 2012 Survey Data: ...............................................................................................7

c. U.S. Inventory of Greenhouse Gas Sources and Sinks - 2014: ...........................................8

d. UT Emission Measurement Study: .......................................................................................8

e. ICF/EDF Report: .....................................................................................................................8

Charge Question 2 .......................................................................................................................9

Charge Question 3 .....................................................................................................................10

Charge Question 4 .....................................................................................................................11

a. AVAILABLE LIQUIDS UNLOADING EMISSIONS MITIGATION TECHNIQUES ...........................11

b. Section 3.1”Liquid Removal Technologies” .......................................................................12

c. Costs .....................................................................................................................................15

d. Section 3.1.1 Plunger Lifts: .................................................................................................16

e. Table 3.1 Plunger Lift Review Comments:.........................................................................16

f. Section 3.1.1 - Plunger Lift Narrative Review Comments: ...............................................17

g. Section 3.1.1 - Artificial Lift Systems:.................................................................................18

h. Section 3.1.1 - Velocity Tubing: ..........................................................................................19

i. Section 3.1.1 - Foaming Agents:...........................................................................................20

Charge Question 5 .....................................................................................................................20

Charge Question 6 .....................................................................................................................21

Charge Question 7 .....................................................................................................................21

Charge Question 8 .....................................................................................................................22

Charge Question 9 .....................................................................................................................23

Charge Question 10 ...................................................................................................................23

Charge Question 11 ...................................................................................................................24

Charge Question 12 ...................................................................................................................25

Charge Question 13 ...................................................................................................................25

Charge Question 14 ...................................................................................................................26

C. Conclusion..................................................................................................................................... 26
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

Executive Summary

The U.S. Environmental Protection Agency (EPA) has developed a draft document titled Oil and 

Natural Gas Sector Liquids Unloading Processes (referred to as “the White Paper”) to, as stated in 

the Preface, seek input and solidify its understanding of the methane and volatile organic 

compounds (VOCs) emissions from leaks in this industry sector. The American Petroleum Institute 

(API) hereby submits its input and comments in this document.

The White Paper does not meet the goal of being a high quality technical document intended as a 

resource to inform EPA’s deliberations regarding emissions due to venting of wells to assist liquids

unloading. Rather than a robust compilation and analysis of available information regarding venting of 

wells to assist liquid unloading, the White Paper appears to be a summary of the information sources 

referenced. In some instances, the summaries of the underlying sources are incomplete and 

information is incorrectly mischaracterized. There are misunderstandings and incorrect/inaccurate 

statements scattered throughout the White Paper and 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.

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. Managing the use of venting to 

affect liquids unloading should be the predominant focus of the white paper. To adequately evaluate 

options to reduce venting of wells and the emissions that result, it is necessary 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. This does not 

appear to be the focus of the White Paper and adequate information is not provided. 

Well-bore fluid dynamics and the portfolio of techniques, practices, and technologies that the industry 

uses to manage well-bore liquids are complex. Notwithstanding this complexity, the White Paper

needs significant improvement in content, organization, and data sources to be useful if is intended to 

inform EPA’s understanding and evaluation of potential options to reduce emissions from venting of 

wells for liquids unloading. 

Following the public announcement that a white paper was being drafted on emissions associated 

with liquids unloading, API submitted early feedback (March 2014) to EPA and those comments are 

attached for further consideration.

Highlights of key review comments discussed in more detail later in this document follow:

• Based on deeper analysis of the GHGRP data, emissions from venting for liquid unloading are 

mostly driven by a relatively small number of operators and a relatively small subset of wells with less 

than 0.5% (10 of 1991) of the datasets at the “subbasin” level accounting for more than 50% of the 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

2

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

suggests that a targeted type intervention is more appropriate than a broadly applicable regulatory 

approach.

• Further illustrating the niche issue of venting for liquid unloading, the GHGRP data shows only 

about 13.5% of U.S. gas wells vented for liquids unloading in 2012. Given the fact that most U.S. gas 

wells 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 that shows wells with plunger lifts have a higher frequency of 

engaging in venting, a higher number of vents/venting-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. 

A. Introduction

The description of liquids loading of well-bores is incorrect which indicates 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. Additionally, there are several 

misunderstandings, 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 

weight of the column puts back-pressure on the producing formation and can reduce 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 well-bore. Wells 

and reservoirs follow a continuum of flow regimes in their economic life as the reservoir depletes, 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

3

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 is rendered somewhat meaningless by the use of the term “reservoir shut-in 

pressure” which 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 pressure”. 

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

focus on reducing resistance to flow or by raising the pressure in the near-wellbore. Lowering surface 

pressure with compression, wellsite 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). Near-wellbore 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 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. Addedenergy 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-by-reservoir 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. 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

4

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 the process. 

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 reduce flow resistance and 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 (reducing liquid drag 

effects) but do not necessarily minimize or eliminate venting.

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 to lift liquids without venting. Wells 

with plunger lifts have more variables that can be manipulated to accomplish this goal, 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 will generally 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 state that some information sources summarized include information 

regarding mitigation techniques which is not correct. 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. 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

5

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. 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. 

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/formationtype combination and below), or even a cursory analysis of the emission 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 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

6

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 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. 

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 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%. 

 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%) accounted 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

7

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 much 

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 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.

These may be conclusions made by the white paper authors based on their interpretation of 

the API/ANGA report information and if so 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. Unless the white 

paper authors can provide the source of the conclusions attributed to the API/ANGA report

and correctly attribute them, they should be removed. 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

8

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. 

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 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 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

9

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 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 wellyr

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

plunger lift

304,048 scf gas/venting wellyr
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

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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. Any 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. 

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 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 
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loading. One could speculate that to the extent that hydraulically fracturing a well or drilling a 

horizontal section raises the production rate from a well then such wells would have fewer 

tendencies to experience problematic liquid loading until later in their life-cycle. For example:

 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 well-bore 

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 will likely 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 an 

appropriate approach 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, coal-beds, and tight-gas sands which are 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 gas-well 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 illustrates 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 

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

liquids accumulate at the bottom of the tubing. 
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is not correct. “Reservoir shut-in pressure” has no meaning in relation to liquid loading of wellbores. 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 wellbore 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 purports to do, demands a higher level 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 
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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 wellbores 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 well-bore 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 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 
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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. 

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. 
API Comments on Submitted to EPA

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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-bywell and reservoir-by-reservoir 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 

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. There are 

documented cases where installing a plunger in a well has cost several hundreds of thousands of 

dollars when other problems were encountered upon pulling the tubing to set a profile nipple for 

a bumper spring. 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 
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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 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 well-bore. 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 backpressure. The key to minimizing venting associated with plunger operation lies in how you 
API Comments on Submitted to EPA

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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 installations. The resultant cost and economic 

profile would likely be very different than installations done on a basis different than well-bywell 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 plunger-lift 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”, system that optimizes the operation of the plunger on an individual 

well to achieve maximum unloading/production and minimum venting/emissions is likely to 
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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 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 bottomhole 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-totubing 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 combinations where the gas injected down the well will flow up the wellbore 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 
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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 and 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 tradeoff 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 “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 vague reference to unidentified “studies” 

reaching this conclusion. This reference should be removed from the White Paper unless 

substantiated. 

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 
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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 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.
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

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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 well-bore 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 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 reservoir. Other 

operators may install well-site compression to allow the use of mechanical horsepower to remove 

the 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 both 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, 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

22

2006). Please discuss the efficacy of plunger lifts at removing liquids from wells and the 

conditions that may limit the efficacy.

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. 

Installing a plunger lift system at the time of initial well construction would also “lock-in” 

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. 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

23

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 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. 

Pumps in gas well deliquification applications struggle to cope with the typically low liquid 

volumes, variable liquid volumes, and damage caused by cavitation and “gas-locking” 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 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

24

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 bottomhole 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 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?

API is not aware of any instances where flares or other combustion devices are used during liquids 

unloading operations. 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 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

25

(~20 MMBtu/hr) rated. Liquids unloading flares would need either continuous pilots (for infrequent 

use) or electronic igniters powered by solar in most instances. 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. 

Combustors on H2S wells are truly a special case. Hydrogen sulfide presents an acute safety risk 

both to employees and to the general public. Understanding and designing for that risk is part of 

the economic evaluation made prior to producing the well. Combustors on these wells regularly 

require electricity to drive blowers to ensure that the combustion process is stoichiometric and 

unburned process gas is prevented to the maximum extent possible. Igniters/pilots that are robust 

and redundant technologies are provided. In short these devices are very expensive to acquire 

and operate. Requirements for this technology on sweet-gas wells would make the vent/plug 

decision much easier and many wells with considerable recoverable gas in place would be 

abandoned rather than installing flare/combustion technology.

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 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 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

26

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 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 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 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 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. 
API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 13, 2014

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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 non-plunger 

equipped wells, can likely be made. 
API – March 27, 2014

1

Liquids Unloading

Well-bore Deliquification (Liquids Unloading) Background 

Well-venting to unload liquids can be a significant source of hydrocarbon pollutant emissions 

and there are technologies and techniques in use and available to significantly reduce, but not 

eliminate, venting of wells to assist in deliquification. Deliquification of gas wells is a highly 

complex and technical subject with many approaches and technologies in use and venting of 

wells is one technique, often used in combination with other techniques that depend on 

reservoir pressure - such as plunger lifts, used to assist unloading. 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, coal-beds, and tight-gas sands which are 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 gas-well 

deliquification with innovation and research continually underway. For example, the 12th

Annual Gas Well Deliquification Workshop was held in February 2014 in Denver, Colorado was 

attended by over 500 representatives of dozens of upstream producers. This workshop series, 

along with a portfolio of other venues dedicated to well deliquification and artificial lift, is 

organized by the Artificial Lift Research and Development Council (ALRDC), and the 

Southwestern Petroleum Short Course (SWPSC). This research and work is both optimizing and 

improving 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. 

Liquid loading of well-bores occurs when the gas production-rate (velocity) up the well-bore is 

not sufficient to carry liquids up the well-bore. When a vertical liquid column builds up in the 

well-bore, the weight of the column puts back-pressure on the producing formation and the 

production rate declines to the point where the well can quit flowing. According to the Energy 

Information Administration’s 2009 “Distribution of Wells by Production Rate Bracket” some 

338,056 (73%) wells out of a total gas well inventory of 461,388 gas wells produce 90 mcf of gas 

(15 BOE) or less per day (http://www.eia.doe.gov/pub/oil_gas/petrosystem/us_table.html) . These 

low rate wells are either impaired by liquids accumulation or are using some deliquification 

method to produce. 

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) 
API – March 27, 2014

2

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 artificial 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 combat 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. MCF/day

Time

Deliquification Progression Example

Conventional 

Well

CBM 

Well

Most wells Freeflow above this line

Velocity strings, plungers, surfactant

injection, and surface pressure 

management are often effective below 

this line

Energy addition required below this line
API – March 27, 2014

3

Techniques that rely on the reservoir energy are: 

 The tubing in a well may be changed to smaller diameter “velocity strings” which provide 

for higher velocity at any given flow rate and provide higher liquid lift capabilities. There is 

a decreasing benefit from smaller diameter velocity strings due to flowing friction buildup in 

smaller diameter tubing. 

 Soap injection may be used to “foam” the liquids to reduce the unit density and enable 

liquids lifting. 

 Wells may be put on a shut-in cycle to allow pressure/energy build-up of the reservoir near 

the well bore which equals higher production rates/velocity (temporary) and better liquids 

lifting.

 A plunger lift may be installed in a well. This is generally coupled with a shut-in cycle to 

build enough pressure under the plunger to lift it along with the liquid column.

 Venting a well may be used in conjunction with any of these techniques to create additional 

differential pressure/energy and aid unloading of liquids.

Techniques where energy is added to the well:

 Mechanical pumps are selected when rate of liquid accumulation is too high for plungers to 

operate or reservoir pressure is too low for plungers to operate without excessive shut-in 

time to build up reservoir pressure.

 Gas lift which raises tubing velocity to lift liquids by injecting gas down the tubing-casing 

annulus.

 Compression which lowers the surface pressure creating more differential for flow and 

increasing velocity by lowering pressure.

 Combinations of above approaches such as foaming, gas lift, and compression

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 the 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 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. 

An excellent overview of this subject is Gas Well Deliquification, Second Edition, by Dr. James F. 

Lea, Dr. Henry V. Nickens, and Mr. Mike R. Wells (Gulf Publishing, 2008, ISBN 978-0-7506.8280-

0). This 588 page book does a good job of explaining the basis for choosing among the various 

technologies, but it does not presume a one-size-fits-all solution.
API – March 27, 2014

4

Well Venting to Aid Liquids Unloading

The production rate of a well, consequent velocity up the well-bore, and, hence, the ability to 

lift liquids is mostly a function of the differential pressure between the reservoir and the flowline/collection system and the reservoir’s sensitivity to backpressure. In order to flow, the total 

reservoir pressure must be greater than the total resistance to flow. This resistance is 

comprised of fluid friction and fluid interference across the reservoir; the flowing friction up the 

well-bore; the weight of the vertical fluid column in the well-bore; surface equipment and 

piping pressure losses; and the collection system/flow-line back-pressure. Opening a well-bore 

to atmospheric pressure (venting a well) removes the effect of the surface equipment/piping 

pressure-loss and the back pressure from the collection line and increases differential pressure 

to increase flow rates and velocities, which may enable the well to lift the liquid from the wellbore (unload the well). Venting of wells has been a common practice in low rate gas well 

deliquification for decades and is not restricted to wells without deliquification assist 

technologies, such as plunger lifts, in place. As the API/ANGA report and the GHGRP data show,

venting of wells to aid liquids unloading occurs in both plunger equipped wells and non-plunger 

equipped wells with plunger equipped wells having higher reported emissions overall. 

Minimizing Venting to Assist Liquids Unloading

As discussed above, there are various reservoir-driven techniques operators use in wells 

experiencing liquids loading to assist in deliquification, which also helps reduce the need for 

venting. Each of these may be the best solution for a particular portion of the life of a reservoir. 

It is a misconception that plunger-lift systems are the single emission control action for wells 

where venting for liquids unloading occurs. This misconception is further exacerbated by a 

lack of understanding, even among those purporting plunger lift systems as the solution to 

liquids unloading, of liquids loading or plunger lift systems and their appropriate uses, 

limitations, and efficacy. Plungers work by providing a mechanical barrier between a small 

volume of water and the gas that is used to transport it up the well-bore. The mechanical 

barrier isolates the gas from the liquids, prevents gas from moving up through the liquids hence 

making better use of the gas energy, and helps prevent liquids from falling back into the wellbore. If the gas could flow faster, then that mechanical barrier would not be necessary or 

helpful. Plunger capacity is limited by well depth, differential between reservoir 

pressure/surface pressure, and the gas/liquid ratio that the well produces. Even plunger lifted 

wells reach a point where they lack the reservoir pressure to run a plunger against 

backpressure with adequate frequency to lift the liquid present. At that point the operator has 

the choice of replacing the plunger with a lift method that adds energy to the system or 
API – March 27, 2014

5

plugging the well. Operators analyze these wells and have to make the decision to spend 

capital and operating expense on a pump versus drilling a new well. 

It also appears that EPA holds some misunderstanding of plunger lift. Although plungers are 

among the most common tools used in middle stage deliquification, there is a misconception 

that plungers eliminate the need to vent to atmosphere. In many cases, wells are vented to 

atmosphere to generate the differential pressure necessary to lift the plunger and liquid 

column up the well-bore. While this can be controlled and minimized, it cannot be eliminated.

 One primary study/project that is often highlighted from the Natural Gas Star program is 

the BP “smart automation” well bore venting control system in the San Juan basin. What is 

generally misunderstood (or simply not acknowledged) is that about half of the wells which 

were venting (around 4.2 BCF of gas per year) were plunger equipped and were vented in 

order to generate the energy necessary to lift the plunger and liquid column. The 

fundamental nature of this project has also been mischaracterized as a project to install 

plunger lift systems to mitigate venting. The actual nature and success of the project was to 

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

o The fact that it took about 6 years to fully develop the system and 

achieve 90% + venting reduction is also often ignored. It is technically 

and operationally very difficult.

 Plungers are not universally applicable to well-bores. For example, unless remedial action is 

taken, a plunger can’t be used in a well-bore with changing tubing sizes, defects or buildups 

of scale or in coil tubing which has an “internal upset” weld seam. Plungers can only be run 

where the inside of the well-bore is reasonably smooth and in reasonably good condition. 

They also do not work well in highly deviated directional (S-shaped – typical for multi-well 

pads) or horizontal well-bores.

 Although casing plungers are available for wells without tubing, they have had significant 

reliability problems and it is also difficult to control the velocity up the well-bore to avoid 

high velocities which have blown the top off of well-heads resulting in uncontrolled release 

of significant quantities of gas.

 Once a well/reservoir declines sufficiently, plungers will no longer work and energy must be 

added to the well-bore or the well abandoned. This is an economics decision. 
API – March 27, 2014

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Studies and Data Sources

 API believes the only recent data/studies with a broad data set are the API/ANGA survey 

results and report and the GHGRP reported data.

 Care needs to be taken in use of the GHGRP data. For example, one company in one basin 

(one reporter/facility combination) accounts for about 37% of the industry wide methane 

emissions from liquids unloading. Any broad national “emission factor” should either 

exclude this data set or weight it according to the number of wells producing and/or 

venting. 

 The UT/EDF study measured emissions from about 9 liquid unloading events but all were 

shale wells and hence do not represent the cross section of well/reservoir types. In 

addition, the supplemental information indicated that the researchers “triggered” an 

unloading event in some instances to enable measurement. If correct, the flow profile 

would not be equivalent to a well with a liquids column in the well-bore which inhibited 

flow and triggered venting to the atmosphere.

 Phase 2 of the UT/EDF study is purported to include measurement of a larger number of 

liquid unloading events from a cross section of well/reservoir types. The phase 2 report is 

expected to be published later in 2014. 

 The annual U.S. Inventory of Greenhouse Gas Sources and Sinks estimate of emissions from 

liquids unloading also needs to be used with an abundance of caution. The radical variation

in the estimated methane from liquids unloading; from 185.57 Gg in 2008 up to 4,554.42 Gg 

in 2009 (~2,354% increase) and then down to 249 Gg in 2011 (98% decrease) amply 

illustrates the uncertainty of the Inventory as a data source. 

 The Natural Gas Star presentations and documents need to be fully understood, including 

the limitations of conditions, physical and operational, to their applicability – many/most 

are not universally applicable and this is often ignored. Also, many of the Natural Gas Star 

partner reported opportunities have been characterized incorrectly in some of the 

documentation – such as the BP project discussed above. 

Options for Mitigating Venting for Liquids Unloading

Options dependent on reservoir energy

 Automated control of shut-in cycles and plunger runs (where equipped) to optimize building 

of formation/reservoir energy – used with both plunger and non-plunger wells. This will 

only work where a radial pressure gradient from low to higher exists in the reservoir as 

distance from the wellbore increases – which is typical for tight sands, shales, and some 

other formation types. The automation algorithms must be customized for each area
API – March 27, 2014

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(reservoir and well combinations) although the basis code, physics and approach are the 

same.

 A combination of flow measurement on the tubing and valve control on the tubing/casing 

annulus to allow the use of the tubing flow to manage liquid production while allowing well 

capacity in excess of the amount required for unloading to be produced up the 

tubing/casing annulus. 

 Install plunger lifts along with appropriate control system. Plungers depend on 

formation/reservoir energy to lift liquids and cannot operate when energy declines beyond 

that necessary to lift liquids. Using automated control of shut-in cycles (above) will extend 

the period where plunger lift systems are effective without regular venting to assist plunger 

recovery.

o Even with advanced plunger lift systems and control systems 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. 

 Velocity (smaller diameter) tubing strings to increase velocity and liquid lift. However, there 

is a trade-off between tubing diameter and flowing friction back-pressure. As tubing 

diameter decreases, flowing friction increases which decreases differential pressure and 

hence flow rate/velocity. At small tubing diameters, the flowing friction decreases velocity 

more than the restricted flow area increases velocity. Velocity strings depend on 

formation/reservoir pressure to lift liquids.

 Soap/surfactant sticks or injection. These work by increasing the surface area/weight ratio 

of water hence increasing the ability of a certain velocity to lift liquids. Soap sticks and 

soap/surfactant injection are generally considered a stop-gap solution to liquids loading 

because balancing the amount of soap, the ability to activate the soap load, and the ability 

to deal with the formation damage that soap can cause generally shortens the effective 

period that this technique is adequate. Wells producing a high proportion of condensate or 

oil do not foam adequately and there is a potential to form emulsions which may prevent 

flow or need additional surface treatment. When using batch/soap sticks, the well will be 

shut-in to enable pressure build-up and chemical mixing. Then the well may be blown down 

to start flow again. This may reduce the overall blow-downs but will not eliminate them. 

Continuous injection needs to get the amount of chemical just right; too much = less 

production and foam on surface; too little = less production. A limitation of any surfactant 

is the chemical make-up of the liquid that must be lifted. Some wells load with water, 

others may load with condensed hydrocarbon liquids (condensate). The surfactant must be 

compatible with the liquids in the well, and condensate is more difficult to treat. As 
API – March 27, 2014

8

mentioned with other techniques, there is no “one size fits all” solution. Different foaming 

agents can have different effectiveness and the efficacy for an individual well will vary. 

Options that add energy

 The economic life of a gas well is often defined by the ability to economically support 

installing deliquification methods. If a well cannot economically support the cost to add

energy to a well for lifting liquids, it will be plugged and abandoned. 

 Install additional surface compression to lower back-pressure against the well.

 Typical approaches to mechanical deliquification are a submersible pump, a beam pump 

(nodding donkey), and gas lift.

o Submersible pumps are better suited to oil wells with high liquid volumes and they 

struggle with the low amount of liquids in a depleted gas well. If sufficient liquids 

are not produced and a “pump-off” controller does not work (common), they will 

burn out. Submersible pumps require a fairly high-voltage (440 V) electricity source 

at each well which is not common. Electrical cable must be run to the bottom-hole 

pump location to power the pump. 

o 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, 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. 

o Gas lift requires a higher pressure gas supply to “inject” 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 

combinations where the gas injected down the well will flow up the well-bore and 

not simply dissipate into the formation. 

o For further information regarding gas well liquids loading, gas well liquids unloading, 

and artificial lift please see the Artificial Lift R&D Council web-site at 

http://www.alrdc.com/production/
API – March 27, 2014

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EPA Questions and Responses

EPA Questions: What is the feasibility of the use of flares during liquids unloading operations?

Are there operational or technical situations where flares could not be used?

API is not aware of any instances where flares or other combustion devices are used during 

liquids unloading operations. 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 powered by solar 

in most instances. 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. 

EPA Question: What is the feasibility of the use of artificial lift systems during liquids unloading 

operations?

This question indicates a somewhat fundamental misunderstanding of well liquids 

management. Artificial Lift, generally considered to be downhole pumps or gas-lift, eliminates 

the need to unload liquids due to the energy added directly to the well-bore. A pump or gas-lift 

is installed on a well when it can no longer unload liquids using the reservoir’s pressure – but 

only if the expected production can support the additional capital and operating expense. 

Requiring early application of “artificial lift” would shorten the economic life of many marginal 

wells. This would tend to differentially impact small operators due to their tendency to hold 

portfolios of marginal wells. 
API – March 27, 2014

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EPA Question: When is it infeasible to use a plunger lift system?

Wells with sufficient flow and velocity do not have liquids loading problems and there is no 

reason to even consider using a plunger lift system. Installing a plunger lift system in a well that 

does not have liquid loading problems is a waste of money. When a well does encounter 

liquids loading problems and a plunger lift is judged to be the best option, there are some 

limitations on when plunger lifts can be run in a well. Plunger lifts cannot be run in wells with 

variable tubing sizes, defects or scale build-up in the tubing, or in wells with coil-tubing that has 

an internally-upset weld seam. They can only be run in wells with reasonably smooth tubing. 

Plungers do not work well in highly deviated directional (S-shaped – typical for multi-well pads)

wells. In a horizontal well, plungers will only run in the vertical portion of the well-bore. For 

wells without tubing, casing plungers are available but have had significant reliability problems 

and have experienced difficulties controlling the velocity up the well-bore to avoid high 

velocities which have blown the top off of well-heads resulting in the uncontrolled release of 

significant quantities of gas. Once a well/reservoir declines sufficiently, plungers will no longer 

work and energy must be added to the well-bore or the well abandoned. Again, this is an 

economics decision. 

EPA Questions: 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 venting is necessary in order for the plunger lift to effectively remove the liquid buildup 

from the well tubing?

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 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. Although, with advanced 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 both plunger lift and non-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 
API – March 27, 2014

11

(height of water column) in the well bore which can be caused by natural variation in reservoir 

flow or system failures/malfunctions. 

EPA Question: It is EPA’s understanding that liquids loading becomes more likely as wells age 

due to declining well pressure. 

See well lifecycle discussion in the background section above.

EPA Question: Is liquids loading only a problem for older wells or can wells develop liquids 

loading problems relatively quickly in certain situations?

Liquid loading is a function of the gas flow-rate from a well and the amount of water/liquid it 

produces which is somewhat independent of age. Older wells do tend to be lower producers 

due to being located in fields/reservoirs that have been produced for a long period and are 

partially depleted. However, not all old wells have liquid loading problems and not all new 

wells are immune from liquid loading problems. 

EPA Question: Are certain wells more prone to developing liquids loading problems such as 

hydraulically fractured wells versus conventional wells?

The tendency of a well to have liquid loading problems is caused by a combination of lower gas 

flow rate and liquids production. Whether a well has been hydraulically fractured or not is

immaterial. Because hydraulic fracturing tends to increase production, hydraulic fractured 

wells should tend to have fewer liquids loading problems than an equivalent non-fractured 

well. Due to their production profile, some coal bed wells tend to have liquids loading 

problems early in their life.

ICF/EDF Mitigation Paper Commentary – Liquids Loading

The ICF paper recommends plunger lift systems as the sole technology to reduce venting for 

liquids unloading and the consequent emissions. Although other techniques of managing wellbore liquids were briefly discussed, only installation of plunger lift systems was analyzed. 

Throughout the paper, the authors make a series of unsupported assertions and assumptions to 

arrive at their recommendation. Additionally, there are several instances where the authors’

statements clearly indicate a limited understanding of liquids loading or the techniques used to 

manage liquids loading in wells. Some examples: 

 Plunger lifts are devices that fit into the well bore and use the gas pressure to bring liquids to 

the surface more efficiently while controlling and limiting the amount of venting (Figure 3 7).
API – March 27, 2014

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o The assertion that plunger lift systems control and limit the amount of venting is not 

supported by the facts that plunger equipped wells account for the majority of both 

venting wells and emissions from venting for liquids unloading. Although a properly 

managed plunger lift system will help manage liquids unloading in a well, the impact 

on emissions will be dependent on the well and reservoir conditions along with how

the plunger lift is setup based on these conditions. 

 If there is insufficient pressure to direct the gas to the sales line and the gas must be vented, 

the emissions can still be reduced by 90% compared to uncontrolled venting. ... Plunger lifts 

are a relatively low cost option and can be implemented in a relatively simple manual 

control method or more complex automated installations. ... Gas STAR Partners report 

reductions of venting emissions of 90% for plunger lifts that do not go to the sales line. 

o The statement that simply installing a plunger lift in a well will reduce emissions by 

90% appears to be anecdotal as the authors do not provide any source or reference 

for the information despite providing the source/reference for some of the other 

information in the report. The authors’ implication that this level of emission 

reduction can be achieved absent appropriate management of the reservoir energy 

is simply unfounded. 

 While it seems counterintuitive that wells with plunger lifts that vent would be emitting 

more than those without plunger lifts, ICF interprets this information to indicate that most of 

the wells with the largest venting emissions have already installed plunger lifts while most of 

the remaining wells are venting infrequently or venting small volumes that do not justify the 

cost of installing plunger lifts.

o This “interpretation” by the authors is completely baseless and not correct. Plunger 

lift systems are installed in wells to assist with management of liquids loading and 

enable production - not to reduce emissions. The intent of plunger lift systems is to 

maintain production, not avoidance of emissions or recovery of emissions. This 

shows the authors’ lack of understanding of liquids loading, management of liquids 

loading, and the industry’s reasons for management of liquids loading. 

 Approaches to plunger lift operation range from ad hoc manual operation, to fixed 

mechanical timers, to programmable “fuzzy logic” automated controllers. Specific data on 

the potential reductions from optimized plunger lift operation is not available but it is clear 

from industry experience that an integrated program of training, technology, and 

automation can improve the performance of plunger lifts for both productivity and emission 

reductions.

o This statement by the authors ignores the BP “smart automation” project, discussed 

above, which is focused on the impact (>90% reduction) that optimized 

management of formation energy on a well-by-well basis can have on emissions, 
API – March 27, 2014

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presented at Natural Gas Star conferences numerous times, and well known to at 

least one of the ICF authors. At worst, this indicates the authors bias to select 

information and make assertions that supports a desired outcome and not include 

information and data that conflicts with their pre-determined goal. At best, it 

indicates a very cavalier approach to the complex subject of liquids loading which is 

central to keeping many of the US gas wells producing and which is the focus of 

ongoing and substantial industry effort and research. 

It is not clear what population of venting wells ICF used in their analysis of the economics of 

installing plunger lift systems. In the body of the report, the authors note about 127,000 wells 

vented for liquids unloading reported into the GHGRP for 2012. In appendix B, the authors note 

69,054 wells reported into the GHGRP as the average for 2011 and 2012. The latter number 

agrees with API’s analysis of the GHGRP data for liquids unloading which shows 69,525 and 

58,633 wells vented for liquids unloading in 2011 and 2012, respectively. 

Overall, the ICF/EDF report recommendation of a single technology, plunger lift systems, as a 

solution to reducing liquids unloading emissions widely misses the mark. While significant 

reductions in emissions from venting wells for unloading liquids, in both plunger equipped and 

non-plunger equipped wells, are possible using cost-effective techniques, recommending a 

single approach is not appropriate. An integrated approach, choosing between all of the tools 

available, in a manner appropriate for the well and reservoir – after engineering analysis, and 

including management of reservoir energy will be necessary to achieve significant reductions. 

Recommended Charge Questions for Peer Reviewers

1. Do the data sources and studies that the paper relies upon appear credible and 

complete?

2. Was sufficient QA/QC conducted with regard to the data sources and studies that 

the paper relies on to determine their applicability and validity?

3. Are the conclusions reached by the authors supported by the information and data 

that was relied upon?

4. Are assertions made in the paper supported by the underlying facts and data?

5. Are assumptions made in the paper clearly noted? Do these assumptions seem 

valid and balanced?

6. Does the paper reflect an understanding of the complexity of liquids loading in gas 

wells and the technologies and techniques used by industry at appropriate points in 

a well’s life-cycle to manage liquids loading? 

7. Does the paper reflect an understanding of the fundamental nature of liquid loading 

management to the continued ability to produce the majority of the onshore US gas 

wells? 
API – March 27, 2014

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8. Does the paper adequately discuss the constraints for use of plunger lift systems 

and the fact that venting of wells equipped with plunger lift systems accounts for 

greater emissions in the GHGRP data and the API/ANGA report?

9. Does the paper present a realistic evaluation of actual emission reduction potential 

from regulation of venting for liquids unloading?