Attachment H

Liquids Unloading

Jim Bolander

Southwestern Energy
Peer-review of “Report for Oil and Natural Gas Sector Liquid Unloading Processes”, 

April 2014,

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

By Jim Bolander, P.E., Senior Vice President, Southwestern Energy (SWN)

The Report for Oil and Natural Gas Sector Liquid Unloading Processes report (“White Paper”) is 

a compendium of prior measurements and analysis of methane emissions and control 

technologies relating to liquid unloading and artificial lift technology. The stated purpose of the 

white paper is to provide a “summary of the EPA’s understanding of emissions from liquid 

unloading in the oil and natural gas sector, the mitigation techniques available to reduce these 

emissions, the efficacy of these techniques and prevalence of these techniques in the field.” In 

general, the summary developed in the white paper is an accurate reflection of current data. In 

addition to the sources that EPA refers to in the document, there are other technical documents 

that we recommend EPA consult to improve its understanding of the emissions profile and 

techniques.

SWN believes that it is important for EPA to segregate and distinguish actual measurement 

studies from literature surveys and desktop analysis to understand the nature and efficacy of 

liquid unloading practices in operations and their potential for emissions. We recommend that 

EPA consider actual measured data, and more importantly recent measurements to 

develop the most accurate characterization possible of emission factors and policy options. 

There is an important new study underway led by Dr. David Allen with University of Texas to 

further evaluate and characterize methane emissions from liquid unloading events at natural gas 

facilities (Phase II UT study). This Phase II UT study is expected to be published in a peerreviewed journal by mid-summer 2014. We strongly urge EPA to fully analyze this new 

Allen et al. paper in developing its policy recommendations.

1. According to 2009 EIA "Distribution of Wells by Production rate Bracket" -

approximately 73% of gas wells produce less than 90 MCFD. Based on the typical tubing 

configuration in producing wells (2-3/8” and/or 2-7/8” tubing), gas flow rates below 100 MCFD 

result in gas velocities below 1,000 feet per min (fpm), a general “rule of thumb” to remove 

liquids from well bore. These low rate wells are either impaired due to liquid loading or are 

using some type of artificial lift.

Technical Background on Liquid Unloading:

2. Liquid loading is defined/occurs when the gas production rate (velocity) up the well bore 

is insufficient to lift liquids to the surface. The minimum flow rate to lift liquids is based on 

transporting a liquid droplet by maintaining the gas velocity necessary to keep the droplet in 

suspension. The gas velocity in the well bore is affected by the surface operating pressure 

(Flowing Tubing Pressure) and cross-sectional area of the well bore.
3. The Turner equation1 for calculating the minimum gas velocity required to sustain flow is 

based on the following equation (for water):

Vg = 5.34(67 - 0.0031 P)

1/4/(0.0031P)1/2

And

Qc = (3.06*P*Vg*A)/TZ

Vg = Velocity of the gas stream (ft/sec)

P = Flowing tubing pressure (psi)

Qg = Gas flow rate (MMCFD)

A = Cross sectional area of tubing (ft2)

T = Flowing temperature (oR)

Z = Gas compressibility factor

4. Use of the Turner equation can provide an initial determination of the critical flow rate to 

sustain flow and efficient liquid unloading. However, it is limited in that the equation does not 

account for liquid hold-up in the well bore. Liquid hold-up is defined as the fractional part of the 

pipe occupied by liquid due to density differences in the gas and liquid phases. Empirical 

pressure loss models have been developed to more accurately determine the pressure loss within 

the wellbore to determine the flow rate in which liquid hold-up occurs

2

. These models are based 

on the produced fluid phase and flow regime type. Tubing performance curves can be developed 

and used in conjunction with a well’s inflow performance curve to determine expected flow rate 

for each producing scenario and the associated liquid loading rate.

5. Operating conditions of the well play an important factor in liquid loading conditions.

a. The flowing tubing pressure (FTP) affects liquid loading with higher FTP 

increasing the backpressure on the well bore reducing inflow from the well. Also, as indicated by 

the Turner equation below, FTP affects the critical velocity of the well. Higher FTP will cause a 

well to exhibit liquid loading conditions even at a higher flow rates. One method to minimize 

liquid loading is to lower the FTP by installing compression.

b. The flow area (or internal diameter (ID)) of flow string (such as tubing), will also 

affect liquid loading conditions. Larger ID tubing will exhibit liquid loading conditions at a 

higher flow-rate than smaller ID tubing. One method to minimize liquid loading is to install a 

smaller ID tubing such as a coiled tubing velocity string. The reduced ID increases the gas 

velocity from the well and lowers the critical gas rate to lift liquids. One issue in the use of 

velocity strings is the increased friction in the well bore which can limit the minimum drawdown 

on the reservoir.

c. As the well ages, the natural decline of the well will cause the well to drop below 

its critical rate as defined above. However, the above factors can cause the well to exhibit liquid 

loading conditions at any time during the wells life.
1. The current EPA Inventory of US Greenhouse Gas Emissions and Sinks: 1990 - 2012, 

estimates that 60,810 natural gas wells (~13% of total gas well count) have liquid unloading that 

result in methane emissions.

Discussion on Emission Inventory on Unloading Data:

a. 39% of the wells are on plunger lift.

b. 61% of the wells are manually unloaded.

The API/ANGA 2012 Survey Data (API and ANGA, 2012)3 suggests that the percentage of 

plunger lift wells that vent to be as high as 56% which also supports the GHGRP 2012 reported 

emissions from liquid unloading (U.S. EPA 2013) which reported that 55% of the plunger lift 

wells vented during normal operations.

2. The API/ANGA 2012 Survey Data (API and ANGA, 2012) indicated that about 36% of 

the well population being equipped with plunger lift systems are responsible for over 50% of the 

venting and 70% of the emissions. This would indicate that the use of plunger lift for the 

primary emission control technology would be ineffective according to the data.

3. The API/ANGA data set indicates that venting frequency is higher than the current EPA 

assumptions and is also a controlling factor in emissions. EPA assumes a frequency of ~39 vents 

per well per year. The API/ANGA data set indicates that for non-plunger wells the average is 

~33 vents/well/yr and ~343 vents/well/yr for plunger lift wells. The data also indicates that for 

non-plunger wells, 14% of the wells which vent in excess of 50 vents/well/yr have the highest 

emissions and account for 51% of the emissions. The data is similar for plunger lift wells 

indicating that wells that have a venting frequency in excess of 200 vents/well/yr (27% of wells) 

accounts for 84% of the emissions. This data indicates that a small number of wells dominate 

the emissions profile for liquid unloading.

4. In summary, the data presented in the API/ANGA data set indicate that emissions from 

liquid unloading exhibit a “fat tail”. In addition, results from a small sampling of data (nine 

wells) from the Allen et al Phase I UT Study4 determined that 95% of the emissions were from 

four wells. It seems clear that there are a small number of sources responsible for the majority of 

emissions. Instead of adopting a “single solution” approach to controlling liquid unloading, EPA 

should analyze the existing data (API/ ANGA, EPA Subpart W and upcoming Allen – Phase 2) 

to determine if there are trends which can be used to determine producing characteristics for 

evaluation of alternative artificial lift methods.

1. Artificial lift systems to deliquify gas well are designed based on specific well conditions

(mechanical and reservoir). Deliquification methods include the following in order based on cost 

and effectiveness2, 5:

Artificial Lift Selection Summary:

a. Intermittent Flow: used when a well first exhibits signs of liquid loading. A well 

is temporarily shut-in to allow pressure to increase. The well is then cycled on at a high rate to 

unload the well. This method is not effective long-term but is inexpensive.

b. Surfactants (or soap injection): used to foam the liquids to reduce density and 

assist in lifting the liquids. Soap injection is more successful in wells that primarily produce 

water.
c. Velocity Strings: used to increase gas velocity. However, friction build-up will 

limit the effective operating range.

d. Compression: used to reduce flowing operating pressure thus reducing flowing 

bottomhole pressure which increases inflow from the reservoir. This is a means of achieving 

higher well bore velocities. Compression can be used when a well exhibits liquid loading and in 

conjunction with other artificial lift methods.

e. Plungers: used in conjunction with a lower flowing tubing pressure (compression) 

and intermittent flow (shut-in cycle) to lift liquids. The use of plungers reduces gas-liquid 

slippage as the liquid is brought to the surface. Plungers have a wide operating range but require 

a minimum gas-liquid ratio (400 scf/bbl per 1,000' of depth - if well configured without a 

packer). Plungers are most successful in low volume gas wells (30 BLPD) and issues include 

solids (sand production) and deviated wells which affects the plunger’s mechanical ability to 

cycle properly.

f. Gas lift: used to raise gas velocity in the flow string by injecting down the annulus 

and combining with gas from the reservoir to assist in lifting liquids. Issues include available 

high pressure gas for injection and also gas lift will limit the drawdown on the reservoir.

g. Downhole pumps and can include the following types:

i. Hydraulic

ii. Electrical submersible pump (ESP)

iii. Progressive cavity pump

iv. Beam pump (rod pump, pumpjacks)

Options i. thru iii. are primarily used in high liquid volume wells. Beam pumps 

are more successful in lower liquid rate wells. One issue in gas wells is that any system is more 

efficient if the downhole pump can be set below the producing perforations to prevent gaslocking.
2. Artificial lift capital cost and economic criteria are important factors when evaluating 

each method. Each method based on the well’s operating conditions should be evaluated on a 

case by case basis to determine which method is most cost effective. During the life of the 

well, a well may produce under various stages of artificial lift. An economic analysis will not be 

considered in the discussion on liquid unloading. A good source on artificial lift selection and 

economic analysis for each method can be found on the Artificial Lift R&D Council web-site at 

http://www.alrdc.com

Response to Charge Questions for Reviewers:

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

factors for liquids unloading presented in this paper. Please comment on regional 

variability and the factors that influence regional differences in VOC and methane 

emissions from liquids unloading. What factors influence frequency and duration of 

liquids unloading (e.g., regional geology)? 

RESPONSE:

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

liquids unloading practices and technologies described in this paper? 

See discussion above concerning national emissions and emission factors. 

We believe that the paper appropriately summarizes the different studies and data 

sources. While regional differences can be seen in the data, the key factor is the 

producing characteristics for each well (flowing pressure, gas rate and liquid rate). 

Combined with each well’s downhole and surface configuration, these factors determine 

the conditions for liquid loading. Regional influence may be seen based on a similar well 

configuration across a producing basin and also the age and producing characteristics of 

the wells in each basin. However, it is important to note that these similarities can be 

seen across the entire country.

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? 

RESPONSE: As described above in the technical background, liquid unloading occurs 

when the gas velocity is not sufficient to lift liquids. While most cases may be attributed to 

“older” lower gas volume wells, the conditions for liquid loading to occur is a function of gas 

flow rate and liquid rates from the well along with mechanical and pressure constraints. 

Also, the type of well (hydraulically fractured, conventional and unconventional) does not 

determine liquid loading criteria. 
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? 

RESPONSE: The Artificial Lift R&D Council web-site is an excellent source on artificial 

lift selection and economic analysis (http://www.alrdc.com). The selected documents 

below are excellent sources in describing the various technologies, pros/cons of each 

technology and approximate capital cost and economic analysis. It should be noted that 

the cost outlined in the ALRDC should be used as “estimate” only. Actual capital and 

operating cost should be determined based on individual well operating conditions and 

each well’s mechanical configuration.

• Guidelines & Recommended Practices – Selection of Artificial Lift Systems for 

Deliquifying Gas Wells (Sections 2.1, 2.2 and 2.2a)

The “other” artificial lift technologies discussed in the section above do not have any 

direct emissions associated with their operations. However, each technology needs to be 

evaluated based on each well’s operating conditions for optimum performance and cost 

benefit. It should be noted that during the life of well, as it depletes, a series of 

techniques may be utilized to optimize performance.

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

technologies in the field. 

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

unloading 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? 

RESPONSE: The well’s operating conditions (flowing tubing pressure (FTP), gas and 

liquid flow rates, mechanical configuration and average casing pressure at the surface) will 

dictate the operating parameters for each plunger lift well. An early engineering approach to 

the design of plunger lift installation is based on the work of Foss and Gaul6 in the Ventura 

Avenue Field, California. The approach is to estimate the casing pressure required to lift the 

fluid slug before the plunger surfaces and to calculate the minimum gas volume to displace 

the liquid slug to the surface. Gas in excess continues to flow (afterflow) while the plunger is 

held at the surface prior to shut-in and pressure build-up.

Pc = [Ps + Pp + (P1h + P1f)](1 + D/K)

Pc = Average casing pressure required to lift the liquid slug (psi)

Ps = Surface tubing pressure (psi)

Pp = Pressure to lift weight of plunger (psi)

(P1h + P1f) = Pressure to lift liquid head and frictional pressure loss

D = Tubing Depth (ft)

K = Constant for flowing gas friction
Qc = Vt*(Pc/Ps)*(Ts/TaZ)*(1/1000)

Qc = Minimum gas volume required to lift the liquid slug

Vt = Tubing volume (ft3

)

Ps = Pressure base, 14.7 psia

Ts = Temperature base, 520 o

R

Ta = Average wellbore temperature, o

R

Z = gas compressibility factor

Each well must be evaluated using a similar approach as above or other engineered 

approaches. Key factors in evaluating each well is the mechanical configuration (tubing 

size), the flowing tubing pressure and the reservoir pressure. In most cases when plunger lift 

equipment is initially installed, the plunger will be able to cycle against the line pressure of 

the pipeline thus all gas is flowed into sales without any venting/emissions. As the well 

declines, the ability to lift the plunger is reduced as the well flows against the back pressure 

from the surface system. Lowering the surface pressure will improve the plunger efficiency. 

Foss and Gaul developed performance charts which can be used to determine the most 

efficient operating conditions. When wells are vented during plunger operation, the plunger 

will lift fluid to the surface only when the surface tubing pressure is at atmospheric 

conditions (no backpressure). This occurs when the well’s gas flow rate and average casing 

pressure do not meet the criteria as determined in the calculations above. Reducing the 

backpressure to atmospheric conditions will lower the required minimum flow rate and 

average casing pressure to lift the liquid slug. The Foss and Gaul model assumes a fixed rise 

and fall velocity in its analysis. A more robust analysis by Lea7 describes a dynamic model 

of surface rise. However, the Foss and Gaul model is a good approximation to describe the 

energy required for effective plunger operation.

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

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

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

may limit the efficacy. 

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

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

the plunger lift system during initial well construction? 

RESPONSE:

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? 

 New wells typically are able to flow without assistance and do not require 

artificial lift until the flow rate and pressure decline to the point in which liquid loading 

begins to occur. Wells can flow naturally for years thus installing plunger lift equipment 

during the initial completion does not make good economic sense from a time value of 

money perspective. In addition, when a well begins to exhibit liquid loading conditions, each 

well must be evaluated to determine which artificial lift method is required for optimum 

performance and economic benefit.
RESPONSE:

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? 

 “Smart” automation is installed in plunger and non-plunger applications to 

effectively manage a well’s reservoir energy. Automation works by optimizing an individual 

well flowing and shut-in times to optimize liquid unloading and well performance. An 

optimized plunger lift well is a well that is operating at the maximum number of cycles to 

generate the lowest average flowing bottom hole pressure with the available reservoir energy. 

“Smart” automation analyzes time, pressure and plunger velocity to optimize each for 

maximum benefit.

RESPONSE:

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? 

 Please refer to response to Question 4 and the ALRDC web-site for selection 

criteria of artificial lift technologies.

RESPONSE:

The response to Question 6 describes the technical basis for venting operations at 

atmospheric conditions. Flaring during unloading would require flowing the full well stream 

through the separator with sufficient backpressure to separate gas and fluids. The gas would 

then be piped to flare system. The backpressure to operate the separator would negatively 

impact the performance of the plunger lift system as previously described.

 The flowing characteristics during venting operations inhibit the design of 

flare equipment. During the unloading operation, initial gas flow rate and pressure are high 

and decline rapidly over a short time period. Flare design (tip diameter) is based on flow rate 

and design criteria can be found in Radian Corporation / EPA 1995 Report – Chapter 7 on 

Flares8

. In addition, the sporadic nature of liquid unloading venting operations would require 

either a continuous pilot or electronic igniter. The design cost associated with the 

requirements needed for this type of flow would be cost prohibitive.

Flare combustion design for H2S operations requires additional design considerations to 

assure unburned gas is prevented to the maximum extent and design is part of the original 

well evaluation.

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

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

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

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

preclude the use of these technologies at certain wells? 

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

understanding of VOC and methane emissions from liquids unloading events and available 

options for increased product recovery and emissions reductions? The EPA is aware of an 

additional stage of the Allen et al. study to be completed in partnership with the EDF and 

other partners that will directly meter the emissions from liquids unloading events. However, 

the EPA is not aware of any other ongoing or planned studies addressing this source of 

emissions

RESPONSE: The Phase 2 UT/EDF study expected for publication in 2014 will provide 

additional analysis on liquid unloading operations. In addition, continued data gathering 

from the GHGRP will provide information on liquid unloading and emissions from venting 

operations.

1. Turner, R.G., Hubbard, M.G. and Dukler, A.E.: "Analysis of Prediction of Minimum 

Flow Rate for the Continuous Removal of Liquids from Gas Wells", November, 1969, 

JPT, 1475-1482.

References:

2. Lea, J.F. and Tighe, R.E.: SPE 11583, "Gas Well Operation with Liquid Production"

3. Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: 

Summary and Analysis of API and ANGA Survey Responses (API/ANGA 2012)

4. Allen, David, T., et al. 2013. “Measurement of methane emissions at natural gas 

production sites in the United States.” Proceeding of the National Academy of Sciences 

(PNAS). October 29, 2013 

(http://www.pnas.org/content/early/2013/09/10/1304880110.full.pdf+html).

5. "Guidelines & Recommended Practices: Selection of Artificial Lift Systems for 

Deliquifying Gas Wells": http://alrdc.com

6. Foss, D.L. and Gaul, R.B.: Plunger Lift Performance with Operating Experience –

Ventura Avenue Field”, Drilling and Production Practices, API, 1965, 124 – 140.

7. Lea, James F.: SPE 10253, “Dynamic Analysis of Plunger Lift Operations”

8. Chapter 7 FLARES: Diana K. Stone, Susan K. Lynch, Richard F. Pandullo, Radian 

Corporation Research Triangle Park, NC 27709, Office of Air Quality Planning and 

Standards U.S. Environmental Protection Agency, Research Triangle Park, NC 27711, 

December 1995