## Attachment J

Liquids Unloading

Gordon Reid Smith Independent ConsultantGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes
EPA Office of Air Quality Planning and Standards White Paper
“Oil & Natural Gas Sector Liquids Unloading Processes”
Review Prepared By: Gordon Reid Smith;
Submitted: June 16, 2014



## Table of Contents Executive Summary

................................ ................................ ................................ ................. 1 A. Introduction

................................ ................................ ................................ ....................... 2 B. Charge Questions

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

................................ ................................ ................................ ........... 5

a. GHGRP Data

- 2012 emission year:

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

................................ ................................ ......... 9

c. U.S. Inventory of G reenhouse Gas Sources and Sinks

- 2014:

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

................................ ................................ .. 10

e. ICF/EDF Report:

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

................................ ................................ ................................ ......... 11 Charge Question 3

................................ ................................ ................................ ......... 13 Charge Question 4

................................ ................................ ................................ ......... 14

a. Available Liquids Unloading Emissions Mitigation Techniques

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

................................ ................... 15

c. Costs

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

................................ ................................ ............. 19

e. Table 3.1 Plunger Lift Review Comments:

................................ ........................ 20 f. Section 3.1.1

- Plunger Lift Narrative Review Comments:

................................ 21
g. Section 3.1.1

- Artificial Lift Systems:

................................ ............................ 22 h. Secti on 3.1.1

- Velocity Tubing:

................................ ................................ ...... 23 i. Section 3.1.1

- Foaming Agents :

................................ ................................ ........... 24 Charge Question 5

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

................................ ................................ ................................ ......... 25 Charge Question 7

................................ ................................ ................................ ......... 26 Charge Question 8

................................ ................................ ................................ ......... 27 Charge Question 9

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

................................ ................................ ................................ ....... 28 Charge Question 11

................................ ................................ ................................ ....... 29 Charge Question 12

................................ ................................ ................................ ....... 30 Charge Question 13

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

................................ ................................ ................................ ....... 31 C. Conclusion

................................ ................................ ................................ ........................ 32Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes



### Executive Summary

EPA’s draft White Paper , “ Oil & Natural Gas Sector Liquids Unloading Processes ” (White Paper) is not the complete hig h quality technical resource document contemplated and is not suitable to inform EPA’s deliberations regarding emissions due to venting of wells to assist liquids unloading. EPA’s intent is most clearly expressed in the paper’s preface: The EPA will use these technical documents to solidify our understanding of these potentially significant sources, which will allow us to fully evaluate the range of options for cost

- effectively cutting VOC and methane waste and emissions.

Instead of a useful and insightful compilation and analysis of availabl e information regarding venting of wells to assist liquid unloading, the paper appears to be a simply a summary of the information sources referenced. There are misunderstandings and incorrect/inaccurate statements scattered throughout the White Paper. T he summaries of the underlying sources are incomplete and information is incorrectly mischaracterized in some instances . Additional information sources, such as the vast amount of industry technical literature regarding management of well bore liquids, ar e 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 inform ation summarized from them in the White Paper. The logic and underpinning evidence leading to the conclusions and assertions made in the White Paper is not clearly presented.
To better focus the White paper, a clearly stated goal and criteria for achiev ing the goal would be useful. Having a goal and criteria would also enable evaluation of whether the White Paper adequately meets the criteria. More clarity of focus on venting of wells to aid liquid unloading, which is the source of emissions, rather th an wellbore liquid loading in general would improve the White Paper. Understanding the reasons and causes for using well venting to aid in liquid unloading is the key to understanding and evaluating potential approaches to reduce well venting and emissions

. In order to o adequately evaluate options to reduce venting of wells and the emissions that result, EPA needs to understand the reasons that wells are vented, alternatives to venting that will still provide for well

- bore liquid loading management, and th e envelope of conditions where these alternatives are feasible. Unfortunately this does not appear to be the focus of the White Paper and adequate information is not provided.
Notwithstanding th e complexity of well

- bore fluid dynamics , if this white paper is intended to be a definitive document intended to inform EPA’s understanding and evaluation of potential options to reduce emissions from venting of wells for liquidsGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

unloading it needs significant improvement in content, organization, and data sources to be useful.
Following are h ighlights of several key review comments discussed in more detail later in this document :

 Based on deeper analysis of the GHGRP data, the majority of the emissions from venting for liquid unloading occur from a small number of operators and a small subset of wells . Of 1991 non

- zero datasets reported at the “subbasin” level, 10 (less than 0.5%) datasets account for more than 50% of the emissions reported. This skewed distribution is consistent with the API/ANGA Survey Report data and s trongly suggests that a program targeted at these instances is more appropriate than a n industry wide regulatory approach.

 Further illustrating the niche issue of venting for liquid unloading, the 2012 GHGRP data shows only about 13.5% of U.S. g as wells vented for liquids unloading

. Given the fact that most U.S. gas are low producers and likely subject to liquids loading this indicates that managing well

- bore liquids without venting is significantly more common than venting.

 The White Paper’s assertion that plunger lift systems are an effective emission control technology is not supported by the data . The data shows wells with plunger lifts have a higher frequency of engaging in venting, a higher number of vents/well/year, and account for a di sproportionate 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 Natur al 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 technic al information sources. Although not a focus of this review, a partial review of these documents identified multiple misunderstandings and errors in them which suggests they need critical review as well

.


### A. Introduction The description of liquids loading of well

- bores in the introduction is not correct . The errors indicate a fundamental misunderstanding of well

- bore liquid

- loading
, the techniques and tools that are used to manage liquids loading , and the role that venting has in liquid unloading. In addition, there are several misunderstandings
,Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

incorrect/erroneous statements and use of terms that do not have any meaning in the context of liquid loading of well

- bores.
Liquid loading of well

- bores occurs when the gas velocity up the well

- bore is not sufficient for the gas to transport liquids up the well

- bore. When a vertical liquid column builds up in the well

- bore, the hydrostatic weight of the column puts back

- pressure on the producing formation and can reduce the productio n 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 press ure 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 lin e that a well is flowing into. A s 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 reser voirs follow a continuum of flow regimes in their economic life as the reservoir depletes, production goes down, well

- bore (tubing) velocity goes down, and liquid loading begins to occur in the well

- bore.

The statement that :

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

- in pressure”

is not correct and the use of the term “ reservoir shut

- in pressure ” does not have a meaning in this context. “ Reservoir shut

- in pressure ” is more appropriately referred to as “average reservoir pressure” which is defined as the volumetric average fluid pressure within the reservoir across the areal extent of the reservoir boundaries. It is misleading to call the build

- up pressure at a well during a shut

- in “reservoir shut

- in pressure”.
Techniques and tools that operators use to manage liquid loading that rely on formation
energy focus on reducing resistance to flow
, raising the pressure in the near

- wellbore formation, or increasing th e velocity of flow . Lowering surface pressure with compression, well

- site debottlenecking, or lowering gathering system pressure reduces surface resistance to flow . Reducing flowing fluid friction through materials choices can assist in reducing flowing friction resistance to flow . Hydrostatic resistance is affected by surfactant/soap injection or running plungers to try to reduce the work that is done by the gas in lifting liquids (surfactant/soap) or make it more efficie nt (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. F low velocity can beGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

increased, for a given flow rate
, by installation of smaller diame ter “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 format ion 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 deliquific ation ” of gas wells

. Added

- energy deliquification methods include downhole pumps (e.g., sucker

- rod pumps, progressing cavity pumps, or electric submersible pumps) or gas lift which involves injection of higher pressure gas down the casing/tubing annulus a nd 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, res ervoir 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

reser voir analysis and is one of the primary jobs of production engineering teams. For a typical well, as it moves through the depletion continuum, a series of techniques will be employed. The decision on technology selection requires a thorough understanding of the reservoir, conditions that a reservoir is flowing into, the reservoir’s sensitivity to backpressure, the volumes and pressures that the deliquification technology must handle, and costs/benefits of applying the technology.

The discussion of venti ng ( also termed “ blowing down ” ) a well and the role of plunger lifts is partially incorrect and incomplete

. The following are provided to clarify this section.

1. Venting may be either manual or automated and also relies on reservoir energy. 2. Venting may or may not be done in conjunction with shut

- in periods to build reservoir energy. 3. Plunger lifts rely on the reservoir energy

. V enting to remove flow

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

. 4. Plun gers do improve the efficiency of a gas stream to perform liquid removal by providing a physical barrier between the formation energy and the liquid column but do not necessarily minimize or eliminate venting.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

5. Minimizing venting, with or without a plunger, hinges on understanding the reservoir energy , flow resistance, and available technologies and techniques (such as shut

- in periods to build near well

- bore energy) to provide adequate flow rate (non

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

. Wells with plunger lifts have more variables that can be manipulated to accomplish these goals , but are not inherently able to provide smaller vented volumes

. 6. Swabbing is a remedial treatment with a rig or wire

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

- bore and restore flow . It is not commonly used to manage liquid loading on a frequent basis , and volumes vented during swabbing operations may be markedly higher than individual venting events.



### B. Charge Questions
Charge Question 1
Please comment on the national estimates of methane emissions and methane emission factors for liquids unloading presented in this paper. Please comment on regional va riability 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 th e white paper incorrectly represents the data sources and information summarized as “studies”. O nly 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 Invent ory, the GHGRP data, the API/ANGA report, and the ICF/EDF report; ) are inventory estimates and/or reports rather than basic measurement studies and should be discussed and characterized as such . These same sections also incorrectly state that some informa tion sources summarized include information regarding mitigation techniques

. What some of these information sources do include is information regarding well

- bore configuration, specifically information regarding the number or percentage of wells that have plunger lift systems. As discussed later, plunger lift systems are not a n 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 attri buted to venting of wells to aid liquids unloading at the beginning of the section . A table similar to Table 1 following would be useful.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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. T he UT paper authors clearly state: “Because the characteristics of the unloading events sampled in this work are highly variable, and because the number of events sampled is small, extrapolating the results to larger populations should be done with caution. ” Also, the supplemental information for this study indicates that venting may have been triggered on at least some of the wells measured solely to enable measurement. If this is correct, the wells were not liquid loaded, the flow volumes and dynamics wo uld 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.

Not e 3: The different data sources/studies used different meth ane concentrations to arrive at methane emission estimates. See the individual studies for information on methane content that was used.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

a. GHGRP Data

- 2012 emission year:
The GHGRP data is likely the most complete and data rich source of available information regarding the number of wells venting to aid liquids unloading, the number of plunger lift systems installed in wells, the frequency of venting, and estimated emissions . The GHGRP discussion in the W hite P aper does not include or indicate the significant amount of information available, the granularity of information available (down to the county/formation

- type combination and below )
, or a n adequate analysis of the available data.
Liquid unloading is reported into the GHGRP at the sub

- basin c ategory (county & formation type) level for methods 2 and 3. For method 1, reports are made at the level of unique combinations of sub

- basin category (county & formation type); pressure group (5), and tubing diameter group (3). Rather than the 251 basin level reports the white paper notes, there are 1,993 separate data sets available at the granularity described. Estimates for GHGRP reporting of emissions from venting to aid liquid unloading are based on engineering calculations (Methods 2 & 3) or repres entative 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) C ount of plunger lifts. 3) Cumulative number of unloadings vented to the atmosphere ( Deferred in the 2012 data ). 4) A verage internal casing diameter or tubing diameter , for all wells, where applicable. 5) Annual CO2 and CH4 emissions, expressed in metric tons CO2 e for each.

Data available for method 1 includes

1) Count of wells vented to the atmosphere for liquids unloading. 2) Count of plunger lifts. 3) Whether the selected representative well in each group had a plunger lift (yes/no). 4) Cumulative number of vents to the atmosphere for liquids unloading

. 5) Average flow rate of the measured well venting in cubic feet per hour. 6) Internal casing diameter or internal tubing diameter in inches, where applicable, 7) Well depth of each well, selected to represent emissions in th at tubing size and pressure combination.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 emissio ns 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 t o 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 p erform enough QA/QC to identify and exclude obviously incorrect data. For example, some data sets report emissions that are dominated by CO2 (some 100% CO2) which is not likely and the number of plunger lifts reported by some reporters under method 3 is extremely large in some instances which indicates these reporters did not correctly interpret the data field.
A basic analysis of the reported data indicates that

 10 of the 1993 data sets (0.5%) reported at the granular level account for just over 50% of the C H4 emissions report ed for venting to aid in liquids unloading during 2012 with the top 72 (3.6%) accounting for just over 75%

. The chart directly below illustrates this data set level.

 At the facility (basin) & reporter level (251 non

- zero data sets) the top 1 (0.4%)

ac counted for about 37% of the total reported emissions, the top 3 (1.2%)Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

accounted for over 50% of the total CH4 reported, and the top 20 (7.9%) accounted for over 75%.

 At the parent company level (99 total), the top 2 account for over 50% of the reported CH4 emissions and the top 11 account for over 75% of the reported CH4 emissions.
As this analysis shows the reported emissions are dominated by a small sub

- set of the data sets reported which implies a targeted intervention effort for emission reduction is more appropriate than a broader regulatory effort. The top reporting companies are very aware that their operations have been unfavorably illuminated in the GHGRP and are making significant efforts to alter operations so t hat they will not be singled out in future reports . This is likely a positive outcome of the transparency provided by the GHGRP data.

Limitations of the GHGRP data: The data regarding liquids unloading in the GHGRP provides only partial coverage of the industry due to the 25,000 metric tonne CO2e reporting threshold. EPA has estimated the extent of coverage at 85%. Reported data indicated ‘Best Available Monitoring Methods” (BAMM) was used for some parameters in some data sets.

b. API/ANGA 2012 Survey Data:

Some of the conclusions that the white paper attributes to the API/ANGA survey report are not actually made in the report by the survey report authors. The white paper states:
The authors of the study made the following conclusions:

 The 2012 GHG Inventory emissions estimates for liquids unloading were overestimated by orders of magnitude. The API/ANGA Survey data indicated a lower percentage of gas wells that vent for liquids unloading and a shorter vent duration.

 The emissions from liquids unloa ding 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 f or 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.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

These may be correct conclusions made by the Wh ite P aper authors based on their interpretation of the API/ANGA report information but are not conclusions contained in the report. If the conclusions of the White Paper authors they should be identified as such. However, there was no information provided in the API/ANGA report referenced that would provide the information necessary to reach either of the last two bulleted conclusions. T he White Paper authors should provide the source of the conclusions attribut ed to the API/ANGA report and correctly attribute them

. The API/ANGA report also reported the percentage of wells with artificial lift ( mechanical deliquification ) installed (7,329 of 54,660

- 13. 4 %) which is relevant as these wells have no potential for venting to help unload liquids. This information is not noted in the White Paper.

c. U.S. Inventory of Greenhouse Gas Sources and Sinks

- 201 4 :
The White Paper discussion of the 2014 U.S. Inventory of Greenhouse Gas Sources and Sinks ( NEI ) is some what 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 represent ativeness 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 impliesGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

that wells may have initiated venting solely to e nable 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” an d “emission factor” for the baseline liquid unloading:
“Data reported to subpart W for 2011 and 2012 was used to develop new activity and emission factors for wells with liquids unloading. From the subpart W data analysis, the number of wells venting with plunger lifts was reported to be 37,643 and the number of wells venting without plunger lifts was reported to be 26,451. It was assumed that subpart W covers 85% of reporters, so the number of venting wells was increased to 44,286 and 31,113, respectively .” “The emission factors were also updated using the data reported to subpart W for 2011 and 2012. The total emissions for each venting well type (plunger lift

versus non ‐

plunger lift) were divided by the total number of reporting wells in order to obtain the new emission factors. From this analysis, the calculated emission factors were 277,000 scf/venting well for wells with plunger lifts and 163,000 scf/venting well for wells without plunger lifts.”
Also, the White Paper should clearly note that the ICF/E DF 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 o f 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. TheGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 nat ional # wells w/o plunger lift that vent for unloading 28,863 Wells

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

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

- yr

Emission Factor per vent

Calculated EF: gas emissions per unloading vent for wells w/plunger lift 1,005 scf gas/unloading vent

Calculated EF : gas emissions per unloading vent for wells w/o plunger lift 9,336 scf gas/unloading vent

Emission Factor per well

Calculated EF: gas emissions per well for venting wells w/plunger lift 345,343 scf gas/venting well

- yr

Calculated EF : gas emissions per well for venting wells w/o plunger lift 304,048 scf gas/venting well

- yr

In the GHGRP data for 2012, i t is important to note that the total number of wells using a venting technique to assist in unloading liquids was 65,669 wells. If there are 504,000 gas wells then this number is 13% of the total. An administrative or regulatory action should be focused at this small subset of the wells rather than being a broad

- brush approach to burden the entire population of gas wells with restrictions that are
unnecessary.

Additional information providing background on well

- bore liquids loading, techniques and tools used to manage liquid loading, and the role of venting to aid liquids unloading can be found in the Subpart OOOO docket. The information in the Subpart O OOO 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 Deliquificati on portion of the “Artificial Lift R&D Council (ALRDC)” website at http://www.alrdc.com

.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

Limited information regarding emissions from well venting to aid liquids unloading and the reductions achieved by actions/proj ect s to reduce venting are available in the Natural Gas Star archives of Technology Transfer Workshops and Annual Implementation Workshops which can be found at the EPA’s Natural Gas Star website http://www.epa.gov/gasstar/workshops . For example, several updates to the BP “Smart Automation” well unloading management, referenced in the white paper, have been presented with the latest in February of 2014.


### Charge Question 3

Please comment on the types of wells that have the highest tendency to develop liquids loading. It is the EPA’s understanding that liquids loading becomes more likely as wells age and well pressure declines. Is this only a problem for wells further down their decline curve or can wells develop liquids loading problems relatively quickly under certain situations? Are certain wells (or wells in certain basins) more prone to developing liquids loading problems, such as hydraulically fractured wells versus conventional wells or hor izontal 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

- flow ing 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 effe ct 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 wel ls 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. Whet her a well is vertical or horizontal is also not relevant to when a well may experience problematic liquid loading . One could speculate that to the extent that hydraulically fracturing a well or drilling a horizontal section increases the production rate from a well th en such wells would have fewer tendencies to experience problematic liquid loading until later in their life

- cycle but this is not universally correct

. For example:Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

 A well making 3 MMSCF/day may begin experiencing liquid s 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 o f 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. T he appropriate approach to managing well

- bore liquids in an individual well is likely to change as the well progresses through its life

- cycle. Attempting to describe the applicability of individual techniques to the wide range of U.S. gas wells is not appropriate and runs the risk of

sever e ly constraining i nnovation. 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 tigh t

- gas sands which are also susceptible to liquid loading. Managing wellbore liquids loading is a primary focus for production engineers and operations teams. A very large amount of industry focus, research, and attention is applied to gas

well deliquific ation 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 the se ideas/developments must be preserved

– even if they ultimately do not succeed.

a. Available Liquids Unloading Emissions Mitigation Techniques
The introductory paragraphs in this section of the White Paper illustrate misconceptions in the understanding of liquid loading of wells
, venting to aid in unloading liquids , and approaches to minimize venting

. As previously noted above, the statement thatGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

As the bottom well pressure approaches reservoir shut

- in pressure, gas flow slows and liquids accumulate at the bottom of the tubing.

is not correct. “Reservoir shut

- in pressure” has no meaning in relation to liquid loading of well

- bores. What is import ant is the flow rate into the well

- bore and the flow velocity up the tubing in the well.
The introduction of the term “blowdown” as an analogue to venting of wells to aid in liquid unloading is simply unnecessary and may be confusing to some readers. In the subsequent discussion, the White Paper discusses “blowdown” as a stand

- alone approach to unloading well

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

- bore liquids is common in conjunction with so me 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. W hat 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 retai ned 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 li mitations 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 Na tural 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 th e level of review and scrutiny was appropriate and the Lessons Le arned, 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 Wh ite Paper attempts , demands a higher levelGordon Smith Review

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of review and validation of the underlying information

- which is lacking in the White Paper.

Some of the actions listed in the White Paper that the Natural Gas Star program reports are taken when liquids unloadi ng occur are not correct. For instance:

S hutting 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. W ells are often shut

- in
, a technique known as intermitting, either manually or more commonly via automation to temporarily increase well inflow and production rate and enable liquid lifting while producing into a collection system.
Swabbing the well to remove accumulated fluids,
The White Paper presents swabbing as a technique commonly used to manage well

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

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

- bore and restore flow. It is expensive and hence n ot commonly used to manage liquid loading on a frequent basis.
The White Paper does not discuss “intermitting” as a technique to manage liquid loading of well

- bores and potentially reduce venting. Intermitting is a technique where producing periods are interspersed with shut

- in periods to allow the reservoir to “refill” the area around the well

- bore that has been partially depleted during the producing period. The shut

- in periods e nable 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 manageme nt

. One approach to s mart automation systems (but not the only possible approach) work s 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 bot h 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 theGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 a bsence 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 mo re 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 exa mple of the application of understanding and optimizing reservoir energy management to sharply minimize venting associated with liquid unloading. However, the BP project is somewhat mischaracterized in both U.S. EPA 2006a and U.S. EPA 2011 as a project to install plunger lift systems in conjunction with “smart automation”. The actual nature and success of the project was to optimize the frequency and duration of shut

- in times on individual wells and plunger cycle timing on wells with plungers through the use of automation that learned the performance of each well and then optimized the cycle parameters for that well

– i.e. “smart automation”. This was and is a project about managing reservoir energy not about installing or running plunger lift systems. A bout 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 assis t 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, so ap/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 m anner enables consideration of approaches to minimize venting at each stage of a wells life

- cycle and in conjunction with each technology/technique used

.Gordon Smith Review

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Wells and reservoirs follow a continuum of flow regimes in their economic life as the reservoir de pletes, 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 loa ding 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

rese rvoir’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 hav e 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 li fe

- cycle curve with these different stages of a wells life illustrated.

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

– dependent on the well configuration, reservoir properties, well depth, and surface equipment and collection system. The choice of what technique to employ is ba sed 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 throughGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

the depletion continuum, a series of techniques will be employed. The decision on technology

- s election 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
tec hnology. 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 associ ated with liquid unloading is part of this ongoing evaluation.

c. Costs
Stating generic costs/cost

- ranges and/or economics for any of the technologies or techniques discussed is fraught with difficulty and error. Costs and economics are as variable as the wells and reservoirs they are applied to and any problems or difficulties encountered

. If problems or difficulties are encountered when installing equipment (plungers, profile nipples for a plunger bumper spring, velocity tubing, or soap injection mandrel s) in a well, costs will escalate dramatically. Certainly such costs are germane to the discussion since it is a possible outcome of any decision to work on a well. There is simply no way to state generically where most wells are within their performance lifecycle , how they will respond to a technique/technology, or what the costs and economics of application will be . One well may be economic at 20 MSCF/day while another might be plugged when the rate reaches 150 MSCF/day. The difference is a complex m ixture of reservoir performance, market

- price differentials, level of capitalization, and operating costs. These variations are what drive evaluation of individual wells for the appropriate selection and application of technologies/techniques to manage li quid 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 w ells in the U.S.

d. Section 3.1.1 Plunger Lift s :

The assertion in the White Paper that installation of plunger lift systems is an emission (venting) control technique is n ot correct , not supported by the emission data , and not underpinned by a logical or t echnical analysis in the White Paper

. P lunger 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 comple tely 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 thanGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

venting wells w ithout 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 emissio ns. 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 reporte d 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 ye t 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 res ervoir 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 depend ent 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 fri ction 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 pressu re or by using venting cycles to remove surface and collection system back

- pressure. The key to minimizing venting associated with plunger operation lies in how you achieve adequate differential pressure to enable a plunger to lift into the producing syst em 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 Wh ite 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 theGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

installations. The resultant cost and economic profile would likely be very different than installations done on a basis different than well

- by

- well evaluation

.

 The statement in the “Efficacy and Prevalence” column of the Table 3.1 plunger lift section that “The EPA has learned plunger lift systems rely on manual, onsite adjustments.” is not uniformly or even mostly accurate. A large percentage of plunger lif

t 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 col lection, 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/plung erlift/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 p lunger 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 w ells 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. Conversel y, if this is accomplished by using shut

- in cycles to manage the reservoir pressure build

- up then venting emissions are likely to be much lower. Using a plunger control system ( “smart automation” ) that optimizes the operation of the plunger on an individu al well to achieve maximum unloading/production and minimum venting/emissions is likely to reduce venting/emissions to just instances where overloading occurs due to system malfunctions or high reservoir liquid/water production surges. Differences in appr oach to operation of plunger lift equipped wells are mostlyGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 syst em 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 developme nt 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 flexibl e plungers designed for use in wells with quite high deviation from vertical

- which is becoming more common with multi

- well pad development. Additionally, Figure 3

- 1 page 21 shows a “gas lift valve” on the bottom of the tubing. This valve is not part of the required bottom

- hole assembly for plunger operation.
As discussed above in the Table 3.1 comments, the costs and economics of plunger lift installations appear to be extracted directly from the underlying documents referenced, are not updated to cur rent 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 fo r 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. T he 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 bot h Table 3.1 and the White Paper narrative omits several technologies/ techniques and pump types used in mechanical deliquification (artificial lift).
There is no mention of gas lift, which involves injection of higher pressure gas down the casing

- to

- tubing annulus in order to increase the flow up the tubing thereby increasing the velocity and capacity to lift liquids. Gas lift typically requires additional compression and piping at the surface which requires either electricity to drive compressors or engine s to drive compressors

– all of which add emissions, complexity, reliability concerns, and operating costs. Also, gas lift is limited to those reservoir/wellGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

combinations where the gas injected down the well will flow up the well

- bore and not simply dissi pate 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, o mitted from the White Paper is any discussion of linear pumps, both coupled with a rod pump (replacing the walking beam), and in downhole applications. Considerable development an d 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 , t he White Paper should provide a detailed description of this technology and the nature and extent of its use.
The costs shown for artificial lift installations have the same problems as costs shown for other technologies/techniques. They appear to have been extracted directly from the underlying sources referenced
, have not been updated to current dollars and appear to be based on limited reports by Natural Gas Star partners in the underlying documents. Also, costs are very well

- specific, company s pecific, and technology specific. Generalizing the se 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 li ft) installed. This is important and should be included. The statement in Table 3.1 that “The EPA does not have information on the prevalence of this technology in the field.” is incorrect.

h. Section 3.1.1

- Velocity Tubing:
The discussion of velocity tubing in Table 3.1 and the narrative omits any discussion of the trade

- off between increased potential velocity with a smaller x

- section of flow and increased flowing friction inherent in smaller diameter tubing which inhibits flow and hence velocity. I n 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 notesGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

“S eamed coiled tubing may provide better lift due to elimination of turbulence in the flow stream (U.S. EPA, 2011).
is based on an unsupported assertion in U.S. EPA 2011 that makes reference to unidentified “studies” reaching this conclusion. This referenc e should be removed from the White Paper unless substa ntiated and attributed

. The range of flow rates or life

- cycle stages where velocity tubing may be applied in both Table 3.1 and the narrative discussion are simply not correct. Any tubing string plac ed 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 b roader 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 no t 1000 ft/min (16.67 ft/sec) , as stated in the White Paper, except in the rarest of coincidences.
The cost and economic data presented in the White Paper appear to have been extracted directly from the underlying documents referenced
, are not updated to current dollars and should be revised . Also, similar to other costs and benefits noted in the White Paper, they appear to be based on self

- selected reports from Natural Gas Star partners on successful installations of velocity strings and are not likely t o 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 incor rect. 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 da ta 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 surfac tants 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 foamGordon Smith Review

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g eneration. 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 co njunction 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 plunge r 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 wi th plunger lift in 2010.
Data regarding the prevalence of mechanical deliquification (artificial lift) is presented in the API/ ANGA survey report where 13.4% of the wells reported ( 7,993 wells ) having some form of mechanical deliquification installed. Projecting this to a national population for 2010 the API/ANGA result implies about 68,000 wells with mechanical deliquification installed in 2010.


### Charge Question 6
In general, please comment on the ability of plunger lift systems to perform liquids unloa ding 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. Plunge rs depend on adequate differential pressure to lift liquids and do increaseGordon Smith Review

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the efficiency of using reservoir energy vs. depending on velocity to drag liquids. A plunger’s ability to rise is defined by six physical parameters:

 Weight of the plunger

 Mecha nical 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 l ose 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 r ely on shut

- in periods to build pressure in the near well formation

. Other operators may install well

site compression to allow the use of mechanical horsepower to remove surface backpressure from the process.

W ith advanced reservoir

- energy management and optimized well

- liquids unloading management, large reductions in the frequency of well venting and thereby emissions resulting from liquids unloading, from both plunger and non

- plunger equipped wells, can likely be made. However, the need to vent will still occur. Even with advanced plunger lift systems and advanced control systems for plunger lift equipped wells, there will be instances where venting a well to atmosphere is necessary to gain the differential pressure necessary to bri ng 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 sourc es uniformly show, venting of wells equipped with plunger lifts accounts for more emissions overall and on a per

- venting

- well basis than emissions from venting of wells not equipped with plunger lifts. The counterfactual interpretation of the data, which the ICF/EDF paper does , is purely conjecture and should be noted as such.


### Charge Question 7
Based on anecdotal experience provided by industry and vendors, the blowdown of a well removes about 15% of the liquid, while a plunger lift removes up to 100% (BP, 2006). Please discuss the efficacy of plunger lifts at removing liquids from wells and the conditions that may limit the efficacy.Gordon Smith Review

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The representation in this question that the BP presentation referenced claims 100% liquid removal (presumably of the c olumn 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 l iquid “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 s everal 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 i nitial 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 wou ld 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 fac ilitate pulling the tubing. After sitting in a well for many years, i t 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 as sures 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 Shal e, 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.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 a dvisable.

T he 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 opera tion and liquid loading management improves the management of reservoir energy, such use is likely to sharply reduce, but not eliminate, the need for venting to aid liquid unloading . This can be beneficial for both wells equipped with plunger lifts and we lls 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” pro ject, 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 v aluable 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 feasi ble, 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.Gordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 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 s urface to the bottom

- hole plunger pump. While more forgiving of low liquid production volumes than submersible pumps or progressing cavity pumps, beam pumps are not very optimum for deviated well

- bores such as those on multi

- well pads (done to reduce surface disturbance). In a deviated well

- bore, the rods will tend to rub against the tubing/casing and cause wear and failure of either the rods and/o r 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 econom ic 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 m echanical 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 H 2 S concentration combustion devices/flares are used during liquids unloading
ope rations to control vented emissions as a safety precaution. However, theGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

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 use d?

This reviewer is not aware of any instances where flares or other combustion devices are used during liquids unloading operations

- including wells with H2S

. In 2012, 58,663 discrete wells were reported into the GHGRP as vented for liquids unloading. Grossing this up, using EPA’s estimate of 85% coverage under Subpart W, yields just over 69,000 individual wells vented to unload liquids in 2012. Flaring of gas during liquids unloading would necessitate separation of the liquids from the well stream i n 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 u se) or electronic igniters

- perhaps powered by solar

. Also, well

- sites would need to be “re

- piped” to route from the separator to the dedicated well unloading flare. Besides the technical difficulties dealing with the intermittent and surging flow chara cteristic 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 t imes the number of wells vented for liquid unloading in 2012, the cost would easily be billions of dollars. There are much more cost effective methodologies to reduce liquids unloading without the emissions and visual impact associated with flaring.


### Charge Question 12
Given that liquids unloading may only be required intermittently at many wells, is the use of a mobile combustion device/flare feasible and potentially less costly than a permanent combustion device/flare?
It is very unlikely that portable flare equipment, which tends to be more expensive on a unit basis than stationary flares, would be feasible for use with respect to venting for liquids unloading. Moving a flare to a location, hooking it up to a vent line, testing the integrity of the system, and then ensuring a pilot light each time a well was to be vented would take considerable time and cost. Given the sheer number of wells that vent for liqui ds 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 theGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

GHGRP plus the yet to be reported instances for Methods 2 & 3, the costs and logistics
to use this approach would far outweigh any benefits.


### Charge Questi o n 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 t he GHGRP, discussed above, indicate that how a company or operation handles liquid unloading and specifically the philosophy regarding management of reservoir energy with respect to well

- bore liquid management has a very large effect on use of venting as p art of well

- bore liquid management.
Some operators cho o se to put production packers , between the tubing exterior and production casing interior, above the productive formation. These packers limit deliquification options to vent cycles or velocity strings since they preclude plungers, mechanical pumping, or the use of soap/surfactants.

At this time , deliquification of horizontal wells is a work in progress with considerable research ongoing to develop or improve technologies

. W hen the flow rates decline t o the point that there is inadequate velocity in the wellbore tubulars to allow the gas to lift the liquid the re are examples of horizontal wells being placed on vent cycles simply because there is not an alternative option.


### Charge Question 14

Are there on going 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 s tage 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 ofGordon Smith Review

Oil & Natural Gas Sector L iquids Unloading Processes

additional data parameters in 2016 for the 2015 emission year, whic h will also aid in understanding of venting for liquid unloading.



### C. Conclusion As the GHGRP and API/ANGA data illustrate, v enting 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 i ntervention 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 i nformation public
, operators that represe nt 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 hen ce do help maintain or increase production.
However, the efficacy of plunger lifts in reducing venting of wells and emissions is completely dependent on how they are operated. As the API/ANGA survey report, the GHGRP data, the U.S. Emission Inventory, a nd 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 we ll venting for liquids unloading. T he 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 redu ctions 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.