## Attachment H

Liquids Unloading

Jim Bolander

Southweste rn EnergyPeer

- review of “ Report for Oil and Natu ral 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 s tated 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 p revalence 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 recomm end EPA consult to improv e 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 a nd 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 fac tors 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 peer

reviewed 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

. The se 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 in sufficient 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 drop let 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 equation 1 for calculating the minimum gas velocity required to sustain flow is

based on t he following equation (for water):

Vg = 5.34(67

- 0.0031 P ) 1/4 /(0.0031 P ) 1/2

And

Qc = (3.06*P*Vg*A)/T Z

Vg = Velocity of the gas stream (ft/sec) P = Flowing tubing pressure (psi) Qg = Gas flow rate (MMCFD) A = Cross sectional area of tubing (ft 2 ) T = Flowing temperature ( o R)

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 accuratel y 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 pres sure (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 e xhibit 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 loadi ng 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 increase s 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 c urrent 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 well s 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 reporte d 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 v enting 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, t he 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 Study 4 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 an alyze 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

. A rtificial 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 effectiveness 2 , 5 : Artificial Lift Selection Summ ary:

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. Surfactant s (or soap injection) : used to foam the liquids to reduce density and

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

water.c. V elocity S tring s: used to increase gas velocity. However, friction build

- up will

limit the effective operating range

. d. Compression : used to reduce flowing operating pressure t hus reduc ing flowing bottomhole pressure which increase s inflow from the reservoir

. This is a means of achieving higher well bore velocities. Compression can be u sed 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 combin ing with gas from the reservoir to assist in lift ing 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. H ydraulic

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 wel ls is that any system is more efficient if the downhole pump can be set below the producing perforations to prevent gas

locking

.2. Artificial lift capital cost and economic criteria are important factor s 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

c onsidered 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

Respo nse 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 chara cteristics 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 configu ration 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 pr essure 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 emi ssions? 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

tech nology 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 serie s 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 malfunc tion 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 rat es, 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 Gaul 6 in t he 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 t o flow (afterflow) while the plunger is held at the surface prior to shut

- in and pressure build

- up.

P

c = [P

s + P p + (P 1h + P 1f )](1 + D/K)

P

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

P

s = Surface tubing pressure (psi)

P p = Pres sure to lift weight of plunger (psi) (P 1h + P 1f ) = Pressure to lift liquid head and frictional pressure loss D = Tubing Depth (ft) K = Constant for flowing gas frictionQ

c = V t *(P

c /P

s )*(T

s /T

a Z)*(1/1000)

Q

c = Minimum gas volume required to lift the liquid slug

V t = Tubing volume (ft 3 )

P

s = Pressure base, 14.7 psia

T

s = Temperature base, 520 o R

T

a = Average wellbore temperature, o R Z = gas compressibility factor

Each well must be evaluated using a similar approach as above or other engineer ed 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 backpressur e 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 Lea 7 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% o f 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 li ft 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. Pleas e 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 econom ic 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 i nstalled 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 th e 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 H 2 S 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 combust ion 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 Que stion 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 fl owing 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 s ystem 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 flo w rate and design criteria can be found in Radian Corporation / EPA 1995 Report

– Chapter 7 on

Flares 8

. In addition, t he 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 H 2 S 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 unloadi ng 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 add ition, 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 L ift Operations”

8. Chapter 7 FLARES: Diana K. Stone, Susan K. Lynch, Richard F. Pandullo, Radian Corporatio n Research Triangle Park, NC 27709, Office of Air Quality Planning and Standards U.S. Environmental Protection Agency, Research Triangle Park, NC 27711

, December 1995