Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW Washington, DC 20005

- 4070 USA Telephone: 202

- 682

- 8 319 Fax: 202

- 682

- 8031 Email: ToddM@api.org www.api.org

June 13 , 2014

Mr. Chris Frantz US EPA 109 T.W. Alexander Drive Mail Code: #143

- 05 Research Triangle Park, NC 27709

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

Processes

Dear Mr. Frantz :

The American Petroleum Institute (API) appreciates the opportunity to provide feedback on EPA’s White Papers on Methane and Volatile Organic Compound (VOC) Emissions in the Oil and Natural Gas Sector. On April 15, 2014, EPA released, for external peer review, white papers that focus on technical issues covering emissions and mitigation techniques targeting methane and VOCs from five separate emission sources. As noted in the Obama Ad ministration’s Strategy to Reduce Methane Emissions, EPA will use the papers, along with the input from the peer reviewers and the public, to determine how to best pursue additional reductions from these sources. As described below, API does not believe ad ditional methane controls should be required at this time.

API represents over 590 oil and natural gas companies, leaders of a technology

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

. economy, and, since 2000, has invested nearly $2 trillion in U.S. capital projects to advance all forms of energy, including alternatives. Many of our members will be directly impacted by any policy decisions that may arise from this effort regardless of whether it informs either regulatory action by the federal government or states

.

API provide d technical feedback and expertise throughout the de velopment of the New Source Performance Standard (NSPS) Subpart OOOO rule

. Each source addressed by the white papers w as considered for regulation during th e development of the NSPS and EPA, ultimately, chose not to regulate them

. While our understanding of emissions from oil and gas production continues to evolve, the fundamental merits of requiring additional regulatory control of these sources is un changed

. A s such
, API continues to believe that no addition al regulation of oil and gas produ ction sources is

necess ary prior to the full implementation of the NSPS OOOO rule and a subsequent evaluation of
emissions

.Page 2

Considering the potential for significant impact on our members that may arise from any policy decision stemming from the white papers
, API has developed significant technical comments (see attached) to address a number of technical inaccuracies about the sources and the conclusions that have been drawn. Barring significant revision, API believes that the current white papers are simply insuff icient to inform sound policy decisions and that simply posting comments on the current version will not result in an informed process . As such , API recommends the EPA take the following steps:

 R evise the white papers to correct any fundamental flaws or i naccuracies that were identified in response to peer review and stakeholder comment (e.g., improved source description s , improved understanding of emission quantification , misconceptions about emission mitigation options )

 Develop a response to comments doc ument that clearly identify the changes the EPA makes to the revised white papers and explains the Agency’s rationale for those changes

 Identify emission studies in progress that will better inform EPA’s understanding of these source emissions and await th e pending study reports

In recent years, there have been significant swings in the national emission estimates from oil and gas production sources, including those covered by the white papers, which indicate a necessity to continue collecting data to impr ove our understanding. Much of this learning will come from improved reporting under Subpart W of EPA’s Greenhouse Gas Reporting Program as well as current studies and others planned in the coming years, which involve taking direct measurements of the sour ces. EPA and industry would both be well served by allowing these studies to inform policy.

Again, we appreciate the work by EPA to initiate these white papers and the opportunity to provide feedback on this effort. API and its members are dedicated to working with EPA to improve our collective understanding of these emissions and providing the technical operator experience that’s needed to do so. Recognizing the potential for these white papers to inform not only EPA but other government agency policy d ecisions, w e request the opportunity to provide additional feedback to the Agency in response to any of our comments in advance. Furthermore, we again offer our experience and expertise as EPA moves into the policy evaluation phase of this effort.

Sincerely, /s/
Matthew Todd

Cc: Peter Tsirigotis, EPA David Cozzie, EPA

Bruce Moore , EPA

# Comments on

Oil & Natural Gas Sector Liquids Unloading Processes

by EPA Office of Air Quality Planning and Standards

June, 2014

Prepared by

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

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014



## Table of Contents
Executive Summary

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

................................ ................................ ................................ ................................ ..... 2 B. Charge Ques tions

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

................................ ................................ ................................ ....................... 4

a. GHGRP Data

- 2012 emission year:

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

................................ ................................ ............................... 7

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

- 2014:

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

................................ ................................ ....................... 8

e. ICF/EDF Report:

................................ ................................ ................................ ..................... 8 Charge Question 2

................................ ................................ ................................ ....................... 9 Charge Quest ion 3

................................ ................................ ................................ ..................... 10 Charge Question 4

................................ ................................ ................................ ..................... 11

a. AVAILABLE LIQUIDS UNLOADING EMISSIONS MITIGATION TECHNIQUES

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

................................ ................................ ....... 12

c. Costs

................................ ................................ ................................ ................................ ..... 15 d. Section 3.1.1 Plu nger Lifts:

................................ ................................ ................................ . 16

e. Table 3.1 Plunger Lift Review Comments:

................................ ................................ ......... 16 f. Section 3.1.1

- Plunger Lift Narrative Review Comments:

................................ ............... 17
g. Section 3.1.1

- Artificial Lift Systems:

................................ ................................ ................. 18 h. Section 3.1.1

- Velocity Tubing:

................................ ................................ .......................... 19
i. Section 3.1.1

- Foaming Agents :

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

................................ ................................ ................................ ..................... 20 Charge Question 6

................................ ................................ ................................ ..................... 21 Charge Que stion 7

................................ ................................ ................................ ..................... 21 Charge Question 8

................................ ................................ ................................ ..................... 22 Charge Question 9

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

................................ ................................ ................................ ................... 23 Charge Question 11

................................ ................................ ................................ ................... 24 Charge Question 12

................................ ................................ ................................ ................... 25 Charge Que stion 13

................................ ................................ ................................ ................... 25 Charge Question 14

................................ ................................ ................................ ................... 26 C. Conclusion

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

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014



## Executive Summary The U.S. Environmental Protection Agency (EPA) has developed a draft document titled Oil and Natural Gas Sector Liquids Unloading Processes (referred to as “the White Paper”) to, as stated in the Preface, seek input and solidify its understanding of the methane and volatile organic compounds (VOCs) emissions from leaks in this industry sector. The American Petroleum Institute (API) hereby sub mits its input and comments in this document.
The White Paper does not meet the goal of being a high quality technical document intended as a resource to inform EPA’s deliberations regarding emissions due to venting of wells to assist liquids unloading. Ra ther than a robust compilation and analysis of available information regarding venting of wells to assist liquid unloading, the White P aper appears to be a summary of the information sources referenced. In some instances, the summaries of the underlying s ources are incomplete and information is incorrectly mischaracterized. There are misunderstandings and incorrect/inaccurate

statements scatter ed throughout the White Paper and a dditional information sources, such as the vast amount of industry technical l iterature regarding management of well bore liquids, are not included in the scope of the White Paper sources. No discussion regarding the limitations of the underlying sources is presented in the White Paper and there is no critical analysis of the accur acy or validity of the underlying sources or the information summarized from them in the White Paper. The logic and underpinning evidence leading to the conclusions and assertions made in the White Paper is not clearly presented.
More clarity of focus on venting of wells to aid liquid unloading, which is the source of emissions, rather than wellbore liquid loading in general would improve the White Paper. Understanding the reasons and causes for using well venting to aid in liquid unloading is the key to u nderstanding and evaluating potential approaches to reduce well venting and emissions. Managing the use of venting to affect liquids unloading should be the predominant focus of the white paper. To adequately evaluate options to reduce venting of wells a nd the emissions that result, it is necessary to understand the reasons that wells are vented, alternatives to venting that will still provide for well

- bore liquid loading management, and the envelope of conditions where these alternatives are feasible. T his does not appear to be the focus of the White Paper and adequate information is not provided.

W ell

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

u ses to manage well

- bore liquids are complex . Not withstanding this complexity, the W hite P aper needs significant improvement in content, organization, and data sources to be useful if is intended to inform EPA’s understanding and evaluation of potential options to reduce emissions from venting of wells f or liquids unloading.
Following the public announcement that a white paper was being drafted on emissions associated with liquids unloading, API submitted early feedback (March 2014) to EPA and those comments are attached for further consideration.
Highl ights of key review comments discussed in more detail later in this document follow:

• Based on deeper analysis of the GHGRP data, emissions from venting for liquid unloading are mostly driven by a relatively small number of operators and a relatively sm all subset of wells with less than 0.5% (10 of 1991) of the datasets at the “subbasin” level accounting for more than 50% of theAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

2 emissions. This skewed distribution is consistent with the API/ANGA Survey Report data. This strongly suggests that a targete d type intervention is more appropriate than a broadly applicable regulatory approach.

• Further illustrating the niche issue of venting for liquid unloading, the GHGRP data shows only about 13.5% of U.S. gas wells vented for liquids unloading in 2012. Gi ven the fact that most U.S. gas wells are low producers and likely subject to liquids loading this indicates that managing well

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

• The White Paper’s assertion that plunger lift system s are an effective emission control technology is not supported by the data that shows wells with plunger lifts have a higher frequency of engaging in venting, a higher number of vents/venting

- well/year, and account for a disproportionate percentage of wel l 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 min imizing venting, for wells with plunger lift and wells without, is not adequately described.

• The control technology discussions and costs in the White Paper appear to be solely based on lessons learned documents from the Natural Gas Star Program. Thes e lessons learned documents were developed to foster technology transfer, which they are adequate to do, but have never been subjected to the level of critical expert review necessary if they are to be used as foundational technical info rmation sources.



## A. Introduction

The description of liquids loading of well

- bores is incorrect which indicates a fundamental misunderstanding of well

- bore liquid

- loading
, the techniques and tools that are used to manage liquids loading , and the role that venting has in liquid unloading. Additionally, there are several misunderstandings
, incorrect/erroneous statements and use of terms that do not have any meaning in the context of liquid loading of well

- bores.
Liquid loading of well

- bores occurs when the gas velocit y up the well

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

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

- bore, the weight of the column puts back

- pressure on the producing formation and can reduce production rate to the point where the well can quit flowing. The volume of flow up a well

- bore is a function of the formation deliverability (inflow rate), the flowing formation pressure near the well

- bore , and the cumulative resistance to flow expressed as pressure drop . The cumulative resistance to flow is the sum of the fluid column in the well

- bore’s hydrostatic pressure, the flowing friction up the production tubing/casing, surface equipment pressure

- loss/back

- pressure, and the pressure of the collection line that a well is flowing into. 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 exceed s 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 conseque ntly the velocity of flow up the well

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

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

3 production goes down, well

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

- bore.

The statement that : “the accumulation of liquids in the well can occur when the bottom well pressure approaches reservoir shut

- in pressure”
is not correct and is rendered somewhat meaningless by the use of the term “ reservoir shut

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

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

- up pressure at a well during a shut

- in “reservoir pressure”.
Techniques and tools that operators use to manage liquid loading that rely on formation energy focus on reducing resistance to flo w or by raising the pressure in the near

- wellbore. Lowering surface pressure with compression, wellsite debottlenecking, or lowering gathering system pressure reduces surface resistance to flow . Reducing flowing fluid friction through materials choices c an assist in reducing flowing friction resistance to flow . Hydrostatic resistance is affected by surfactant/soap injection or running plungers to try to reduce the work that is done by the gas in lifting liquids (surfactant/soap) or make it more efficient (plungers)

. Near

- wellbore formation pressure can be impacted by stopping flow to allow reservoir fluids to resupply depleted fluids and pressure near the well bore. F low velocity can be increased, for a given flow rate
, by installation of smaller diameter “velocity” production strings in the well

- bore although there is a practical limit to smaller diameters where flowing friction overcomes the effect of a smaller diameter flow path. Venting of wells to atmosphere is used to lower the resistance to flow by removing the collection system and most surface equipment backpressure. A combination of techniques may be used concurrently, such as velocity strings and surfactant/soap injection, dependent on the well and formation c haracteristics.
Once the formation pressure and inflow rate reaches the stage where the reservoir’s energy and flow is not sufficient to lift liquids then energy will need to be added to the well
, which is commonly termed “ artificial lift ” but more prope rly termed “ mechanical deliquification ” of gas wells

. Added

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

- rod pumps, progressing cavity
pumps, or electric submersible pumps) or gas lift which involves injection of higher pressure gas down the casing/tubing annulus and into the flow stream to increase the energy /velocity available for the gas to do work lifting the liquids. Each lift type has its specific purpose with respect to liquid rate potential, solids handling capabilities, i nstallation/maintenance cost, reservoir drawdown potential,

etc. Once a mechanical deliquification technique is installed on a well
, any perceived value of venting
is eliminated and venting will not occur

. When the expected production from a well cannot support the investment required to enable deliquification, it will reach the end of its economic life and be abandoned.
The choice of what technique to employ is based on well

- by

- well and reservoir

- by

- 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.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

4 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 the process.

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

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

. V enting to reduce flow resistance and create lift is

common while running plungers

. 4. Plungers do improve the efficiency of a gas st ream to perform liquid removal by providing a physical barrier between the formation energy and the liquid column (reducing liquid drag effects) but do not necessarily minimize or eliminate venting.
5. Minimizing venting, with or without a plunger, hinges on understanding the reservoir energy
, flow resistance, and available technologies and techniques (such as shut

- in periods to build near well

- bore energy) to provide adequate flow rate to lift liquids without venting. Wells with plunger lifts have more variables that can be manipulated to accomplish this goal , but are not inherently able to provide smaller vented volumes

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

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

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



## B. Charge Questions

Charge Question 1

Please comment on the national estimates of methane emissions and methane emission factors for liquids unloading presented in this paper. Please comment on regional variability and the factors that inf luence regional differences in VOC and methane emissions from liquids unloading. What factors influence frequency and duration of liquids unloading (e.g., regional geology)?

The “Introduction” section and Section 2.0 of the white paper incorrectly represen ts 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 Inventory, the GHGRP data, the API/ANGA report, and the ICF/EDF report; ) are inventory estimates and/or reports rather than basic measurement studies and should be discussed and characterized as such . These same sections also state that some information sources summarized include information regarding mitigation techniques which is not correct. What some of these information sources do include is information regarding well

- bore configuration, specifically information regarding the number or percentage of wells that have plunger lift systems. As discussed later, plunger lift systems are not 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 attributed to venting of wells to aid liquids unloading at the beginning of the section

.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

5 Table 1
Well Venting for Liquid Unloading Methane Emission Estimates

Name Methane

MT's Total #

of Venting Wells # Venting

With Plunger Lift # Venting

Without Plunger Lift MT's per

year per Venting Well MT's per

Venting Well per
year with Plunger MT's per

Venting Well per
year w/o Plunger

Greenhouse Gas Reporting Program

- 2012 276,378 58,663 32,448 26,215 4.711 6.158 2.959

U.S. Inventory of Greenhouse Gas Sources and Sinks

- 2013 (2011 Emission Year) 258,667 60,810 23,503 37,307 4.254 4.618 4.024

API/ANGA Report

- 2011 data 319,664 65,669 36,806 28,863 4.868 5.207 4.584

UT/EDF Phase 1 Study 162,619 35,828 4.539 not measured 4.539

ICF/EDF Report 277,307 75,399 44,286 31,113 3.678 4.430 2.607
Note: With the exception of the UT/EDF Phase 1 Study this table is U.S. Totals
Note 2: The UT/EDF Phase 1 results should be viewed with an abundance of caution. Only 9 well venting instances, all without plunger lift, were measured which is much too small of a population to extrapolate to a national or even sub

- national level. Als o, the supplemental information for this study indicates that venting may have been triggered on at least some of the wells measured solely to enable measurement. If this is correct, the wells were not liquid loaded, the flow volumes and dynamics would be very different from a liquid loaded well, flow would likely exceed normal productio n 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 methane concentrations to arrive at methane emission estimates. See the individual studies fo r information on methane content that was used.

a. GHGRP Data

- 2012 emission year:

The GHGRP data is likely the most complete and data rich source of available information regarding the number of wells venting to aid liquids unloading, the number of plunger lift systems installed in wells, the frequency of venting, and estimated emissions. The GHGRP discussion in the white paper does not include or indicate the significant amount of information available, the granularity of information available (dow n to the county/formation

type combination and below )
, or even a cursory analysis of the emission data.
Liquid unloading is reported into the GHGRP at the sub

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

- basin category (county & formation type); pressure group (5), and tubing diameter group (3). Rather than the 251 basin level reports the white paper notes, there areAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

6 1,993 separate data sets available at the granularity described. Estimates for GHGRP reporting of emissions from venting to aid liquid unloading are based on engineering calculations (Methods 2 & 3) or representative well vent measurement and extrapolation to other venting wells in the same grou ping combination (Method 1).
Data available for the 2012 emission year, for methods 2 and 3 include

1) Count of wells vented to the atmosphere for liquids unloading. 2) Count of plunger lifts. 3) Cumulative number of unloadings vented to the atmosphere ( Deferred in the 2012 data ). 4) A verage internal casing diameter or tubing diameter , for all wells, where applicable. 5) Annual CO2 and CH4 emissions, expressed in metric tons CO2e for each.

Data available for method 1 includes

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

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

. 8) Casing pressure, of each well selected to represent emissions in that tubing size group and pressure group combination that does not have a plunger lift. 9) Tubing pressure, of each well selected to represent emissions in a tubing size group and pressure group combination that has a plunger lift. 10) Annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas.
As this illustrates, the GHGRP data includes a large amount of information that can be analyzed to help understand well venting to aid i n 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 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 reported for venting to aid in liquids unloading during 2012 with the top 72 (3.6%) accounting for just over 75%

.

 At the facility (basin) & reporter level (25 1 non

- zero data sets) the top 1 (0.4%) accounted for about 37% of the total reported emissions, the top 3 (1.2%) accountedAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

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

 At the parent company level (99 total)
, the top 2 account for over 50% of the reported CH4 emissions and the top 11 account for over 75% of the reported CH4
emissions.

As this analysis shows the reported em issions are dominated by a small sub

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

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

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

b. API/ANGA 2012 Survey Data:

Some of the conclusions that the white paper attributes to the API/ANGA survey report are not actually made i n 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 d ata indicated a lower percentage of gas wells that vent for liquids unloading and a shorter vent duration.

 The emissions from liquids unloading are not specific to only conventional wells, but can be for any well depending on several technical and geologic al aspects of the well.

 Although most wells do not require liquids unloading until later in the well’s productive lifetime, the timeframe for initiating liquids unloading operations varies significantly and can be early in the well’s productive life span.

 Most of the emissions from liquids unloading operations are produced by less than 10% of the venting well population.
These may be conclusions made by the white paper authors based on their interpretation of the API/ANGA report information and if so should be identified as such. However, there was no information provided in the API/ANGA report referenced that would provide the information necessary to reach either of the last two bulleted conclusions. Unless the white paper authors can provide the source of the conclusions attributed to the API/ANGA report and correctly attribute them, they should be removed.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

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

- 13. 4 %) whic h is relevant as these wells have no potential for venting to help unload liquids.

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 somewhat incomplete in that it does not discuss the limitations of the inventory estimate for liquid unloading or the difference in the ratio of wells venting for liquid unloading with and with/out plunger lifts from the other information sources. As Table 1 above shows, the ratio of venting wells with plunger lift and those without plunger lift in the NEI is opposite the ratio in the API/ANGA survey report, the GHGRP data, and the ICF/EDF report. This is likely due to the decimation of the API/ANGA d ata 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 repr esentativeness of the measured venting events and extrapolation to a larger population, these cautions should be stressed. As the UT paper authors clearly state: “Because the characteristics of the unloading events sampled in this work are highly variable
, and because the number of events sampled is small, extrapolating the results to larger populations should be done with caution.”
Additionally, the UT study report noted that: “In this work, sampling was performed for unloadings in which an operator manually bypasses the well’s separator. Unlike automated plunger lift methods, these manual unloading events could be scheduled, allowing the study team adequate time to install measurement equipment.” This implies that wells may have initiated venting so lely to enable measurement and hence may not have been “liquid loaded”. If correct, the measured flow during the venting would likely be different (likely higher) than flow from the same well if the well

- bore was liquid loaded.

e. ICF/EDF Report:

Economi c 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 witho ut plunger lifts and estimated emissions on the 2013 NEI is not consistent with the ICF/EDF report. As the following excerpts from the ICF/EDF report clearly notes, the GHGRP data for 2011 and 2012 (presumably averaged) was used to establish the “activity count” and “emission factor” for the baseline liquid unloading: “Data reported toAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

9 subpart W for 2011 and 2012 was used to develop new activity and emission factors for wells with liquids unloading. From the subpart W data analysis, the number of wells ven ting 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, res pectively.” “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 t o obtain the new emission factors. From this analysis, the calculated emission factors were 277,000 scf/venting well for wells with plunger lifts and 163,000 scf/venting well for wells without plunger lifts.”
Also, the White Paper should clearly note that the ICF/EDF baseline estimates for venting of wells for liquid unloading does not represent any “new” information and is simply an analysis and “gross

- up” of the GHGRP data.


## Charge Question 2

Is there further information available on VOC or methane emissions from the various liquids unloading practices and technologies described in this paper?

API provided supplemental material and analysis from the 2012 report “Characterizing Pivotal
Sources 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. The following table shows a summary of the information furnished that was not reviewed or included in this report.
Calculated national # wells w/plunger lift that vent for unloading 36,806 Wells

Calculated 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

yrAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

10 It is important to note that the total number of wells using a venting technique to assist in unloading liquids was 65,669 wells. If there are 504,000 gas wells then this number is 13% of the total. Any administrative or regulatory action should be focus ed 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 tool s 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 informatio n 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 Deliquifica tion portion of the “Artificial Lift R&D Council (ALRDC)” website at http://www.alrdc.com

. Limited information regarding emissions from well venting to aid liquids unloading and the reductions achieved by actions/project s to reduce venting are available in the Natural Gas Star archives of Technology Transfer Workshops and Annual Implementation Workshops can be found at the EPA’s Natural Gas Star website h ttp://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 c an 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 hori zontal wells versus vertical wells?
EPA’s understanding is somewhat correct in that older wells do have a greater tendency to develop liquid loading problems due to decreased production rate

- not pressure. The physical model that describes how free

- flowing wells (including wells venting without plungers) is a “drag model” that describes the physical action of high

- velocity gas flow dragging liquid packets at the no

- flow boundary between the liquid and the gas. In this model, pressure is a secondary effect and the action of the gas on the liquid is dominated by the gas velocity. A more correct understanding would be that lower production rate wells have a greater susceptibility to liquid loading due to dec reased velocity

- which often occurs in older wells as production rate declines. However, liquid loading issues can and do occur in newer wells with inadequate velocity to lift the amount of liquids produced by the well. Absent a plunger

- lift barrier bet ween 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 mi ght experience problematic liquids loading. Whether a well is vertical or horizontal is also not relevant to when a well may experience problematic liquidAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

11 loading . One could speculate that to the extent that hydraulically fracturing a well or drilling a horizontal section raises the production rate from a well th en such wells would have fewer tendencies to experience problematic liquid loading until later in their life

- cycle. For example:

 A well making 3 MMSCF/day may begin experiencing liquids loading in certain high liquids production situations

— these liquid loading problems will normally be addressed by adding a mechanical pump, not plungers or venting.

 A well making 50 MSCF/day experiencing liquids loading will typically be evaluated for lower cost deliquification methods like adding a plunger or putting the well on
intermittent (shut

- in) or vent cycles. Onset of liquids

- loading is a function of a very wide range of physical parameters and appropriate responses require evaluation of all of those pa rameters.


## 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 tech nologies. How does the well’s life cycle affect the applicability of these technologies?

Prior to discussion of individual technologies, techniques, and practices to manage well

- bore liquids and venting to aid deliquification
, the White Paper should acknowledge the complexity of the issues. Dealing with liquids

- loading issues is a very complex mix of engineering and economics applied to an individual well. The appropriate approach to managing well

- bore liquids in an individua l well will likely change as the well progresses through its life

- cycle. Attempting to describe the applicability of individual techniques to the wide range of U.S. gas wells is not an appropriate approach and runs the risk of sever e ly constraining innova tion. Well deliquification is a fundamental challenge for continued production from the majority of US gas wells and the proportion is expected to grow with new growth concentrated in non

- traditional gas reservoirs such as shales, coal

- beds, and tight

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

- well deliquification with innovation and research continually underway. Research and work regarding managing well

- bore liquids aims to both optimize and improve existing techniques along with developing entirely new types of systems. The flexibility to pilot some of these ideas/d evelopments must be preserved

– even if they ultimately do not succeed.

a. AVAILABLE LIQUIDS UNLOADING EMISSIONS MITIGATION TECHNIQUES

The introductory paragraphs in this section of the White Paper illustrates misconceptions in the understanding of liquid loading of wells
, venting to aid in unloading liquids , and approaches to minimize venting

.
As previously noted above, the statement that
As the bottom well pressure approaches reservoir shut

- in pressure, gas flow slows and liquids accumulate at the bottom of the tubing.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

12 is not correct. “Reservoir shut

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

bores. What is important is the flow rate into the well

- bore and the flow velocity up the tubing in the well.

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

- alone approach to unloading well

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

- bore liquids is common in conjunction with some other approaches discussed

- such as plunger lifts.

The statement that:

These technol ogies can reduce the need for liquids unloading operations or result in the capture of gas from liquids unloading operations.

is incorrect in its understanding. What the technologies subsequently discussed can do is reduce the need for or practice of ve nting to aid in unloading liquids

- unloading of well

- bore liquids still must be accomplished. Also, dependent on the technique applied, gas not vented may be retained in the reservoir or produced

- it is not “captured from liquid unloading operations.”

b. Section 3.1”Liquid Removal Technologies”

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

There is no discussion of the limitations of the Natural Gas STAR program documents and partner presentations. The White P aper should be very clear that the Natural Gas STAR Lessons Learned documents are not peer reviewed, generally represent a compilation of information furnished by Natural Gas Star partners and studies commissioned by EPA, are generally compiled and written by an EPA contractor, and have not been rigorously reviewed by industry or other experts in the subject matter. Partner presentations are similar in that they have not been rigorously reviewed and typically describe an individual project or application o f 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 Learned, Partner Reported Opportunities, and Partner Presentation documents are useful and valuable. However, extrapolating these Natural Gas Star documents to the broad US population of wells and compiling the information to inform public policy , as the White Paper purports to do, demands a higher level of review and validation of the underlying information

- which is lacking in the White Paper.

Some of the actions listed in the White Paper th at the Natural Gas Star program reports are taken when liquids unloading 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, eitherAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

13 manually or more commonly via automation to temporarily increase well inflow and production rate and enable liquid lifting while producing into a col lection 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 r educe 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 en able 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 t he 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 managemen t

. 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 both wells with plunger lifts and wells without plunger lifts although wells with plunger lifts have more variables for the system to manipulate . The basic concept is: “The reservoir does not quit working when a well is shut

- in”. Producing a well creates a zone of lower pressure and lower inflow capacity near the well

- bore. During shut

- in, when the well is not flowing, the reservoir will continue to flow into the depleted zone and partially replenish the reservoir. When a well starts flowing after a shut

- i n period it will temporarily have higher inflow (production) rate (often termed flush production) and higher pressure available. The higher production rate may provide adequate velocity to lift liquids while producing in the absence of a plunger lift and the higher pressure may provide adequate energy to lift a plunger and its load while producing without the need for venting

. Although the potential benefits of such an approach are briefly discussed in the White Paper
, much more emphasis and discussion should be devoted to this subject.

The BP “smart automation” project discussed in the documents referenced in the White Paper ( British Petroleum (BP) 2006; U.S. EPA 2006a; and U.S. EPA 2011) provides an excellent case s tudy example of the application of understanding and optimizing reservoir energy management to sharply minimize venting associated with liquid unloading. However, the BP project is somewhat mischaracterized in both U.S. EPA 2006a and U.S. EPA 2011 as a pr oject 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 thro ugh the use of automation that learned the performance ofAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

14 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
sys tems. About half of the wells which were venting were plunger equipped and about half were not plunger equipped. Both plunger equipped and non

- plunger wells were previously vented in order to generate the flow or pressure differential necessary to lift l iquids. 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 C ity, UT Technology Transfer workshops in 2014.

Splitting the techniques used to manage liquid loading into “primary” and “remedial” technologies in the White Paper is not useful from the standpoint of improving understanding regarding minimizing venting to assist deliquification. A more appropriate approach would be to split the technologies into those that rely on reservoir energy for unloading liquids and those that add energy to the well

- bore to unload liquids. Plunger lift, velocity tubing, intermit ting, soap/surfactant injection, and reducing surface pressure via de

- bottlenecking or compression all rely on reservoir energy. Down

- hole pumps, of various types, and gas

- lift add energy to the
reservoir fluids

. Conceptualizing technologies/techniques i n this manner enables consideration of approaches to minimize venting at each stage of a wells life

- cycle and in conjunction with each technology/technique used

. Wells and reservoirs follow a continuum of flow regimes in their economic life as the rese rvoir depletes, production goes down, well

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

- bore. In the early stage of a well’s life many (but by no means all) wells can flow freely and with sufficient velocity to avoid li quid loading problems. As the reservoir energy depletes and the production

- rate declines, a well will reach the stage where liquid

- loading begins to be a problem and one of a portfolio of technologies or techniques will be used to help lift liquids using the reservoir’s energy. As a well continues to produce and the reservoir energy declines further, a well will reach the stage where the reservoir’s energy is not sufficient to lift liquids and mechanical lift energy, in the form of pumps, gas lift, etc., will have to be added to continue producing. When the expected production from a well cannot support the investment required to enable deliquification, it will reach the end of its economic life and be abandoned.

The following figure shows a generalized well life

- cycle curve with these different stages of a wells life illustrated.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

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

– dependent on the well conf iguration, reservoir properties, well depth, and surface equipment and collection system. The choice of what technique to employ is based on well

- by

well and reservoir

- by

- reservoir analysis and is one of the primary jobs of production engineering

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

- selection requires a thorough understanding of the conditions that a reservoir is flowing into, the reservoir’s sensitivit y to backpressure and the volumes and pressures that the deliquification technology must handle, and costs/benefits of applying the technology. Operators must have the flexibility to choose the most appropriate and cost effective approach for each individ ual well/reservoir/age/production combination and the regulatory certainty to underpin continued investment. Minimizing venting associated with liquid unloading is part of this ongoing evaluation.

c. Costs

Stating generic costs/cost

- ranges and/or economics for any of the technologies or techniques discussed is fraught with difficulty and error. Costs and economics are as variable as the wells and reservoirs they are applied to and any problems or difficulties encountered . There are documented cases where installing a plunger in a well has cost several hundreds of thousands of dollars when other problems were encountered upon pulling the tubing to set a profile nipple for a bumper spring. Certainly such costs are germane to the discussion since it is a pos sible outcome of any decision to work on a well. There is simply no way to state generically where most wells are within their performance lifecycle , how they will respond to a technique/technology, or what the costs and economics of application will be

. One well may be economic at 20 MSCF/day while another might be plugged when the rate reaches 150 MSCF/day. The difference is a complex mixture of reservoir performance, market

- price differentials, level of capitalization, and operatingAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

16 costs. These var iations are what drive evaluation of individual wells for the appropriate selection and application of technologies/techniques to manage liquid loading or a decision to plug a well that can no longer support the costs of deliquification. Retaining the fle xibility to make individual well

- appropriate technology

- decisions is fundamental to the continued economic production of a great many gas wells in the U.S.

d. Section 3.1.1 Plunger 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 technical analysis in the White Paper

. P lunger lifts are a valuable , effective an d 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 pl unger lifts in reducing venting of wells deliquification and emissions is completely dependent on how they are operated. As the API/ANGA survey report, the GHGRP data, the U.S. Emission Inventory, and the ICF/EDF report reanalysis of the GHGRP data shows, venting wells with plungers have higher emissions per well than venting wells without plunger lifts. Despite the API/ANGA survey report estimate that only about 36% of U.S. gas wells are equipped with plunger lifts (of which only a subset vent) , venting of wells with plunger lifts constitute the majority of venting wells and emissions. Wells with plunger lift systems comprised ~55% of the more than 58,000 wells reported as venting for liquids unloading into the GHGRP for 2012. From an emission perspecti ve, wells with plunger lift systems accounted for about 72% of the GHGRP reported emissions from well venting for liquids unloading. The GHGRP reported data is broadly equivalent to that reported from the API/ANGA survey. With the API/ANGA survey outcome of about 36% of the well population being equipped with plunger lift systems yet responsible for over 50% of the venting wells and 70% of the emissions, the efficacy of plunger lift systems as an emission control measure is clearly not supported by the da ta . However, with advanced well liquids unloading management (management of reservoir energy), large reductions in the frequency of well venting and thereby emissions resulting from liquids unloading, from both plunger and non

- plunger equipped wells,

can likely be made.

e. Table 3.1 Plunger Lift Review Comments:

 The statement in the Applicability column that
“Candidate wells for plunger lift systems generally do not have adequate downhole pressure for the well to flow freely into a gas gathering system”(U.S. EPA, 2006b).”

is incorrect. By definition, plunger lift systems are dependent on reservoir energy, sp ecifically downhole pressure, to lift the plunger and the water/fluid load in the well

- bore. Adequate differential pressure must exist between the reservoir pressure and the sum of liquid column hydrostatic pressure, flowing friction pressure loss, surfac e equipment pressure loss, and collection system back

- pressure in order for a plunger to return to surface with the liquid load. Adequate differential pressure may be generated by using shut

- in cycles to increase downhole pressure or by using venting cycl es to remove surface and collection system back

pressure. The key to minimizing venting associated with plunger operation lies in how youAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

17 achieve adequate differential pressure to enable a plunger to lift into the producing system rather than venting to a tmosphere.

 Cost ranges: The cost ranges in Table 3.1 appear to be copied directly from the underlying documents cited and do not appear to be updated to current dollars. This significant oversight should be corrected in the White Paper. Also, the costs and economics extracted from the underlying documents were predominantly based on Gas Star partner reports and likely reflected installations of plunger lifts that had already been determined to be appropriate for the individual wells where they were inst alled based on a well

- by

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

- by

well evaluation.

 The statement in the “E fficacy and Prevalence” column of the Table 3.1 plunger lift section that “The EPA has learned plunger lift systems rely on manual, onsite adjustments.” is not uniformly or even mostly accurate. A large percentage of plunger lift installations are control led with automated plunger control systems rather than manually operated. Increasingly, these systems incorporate the capability to identify problems and make immediate adjustments. Techniques with telemetry, electronic data collection, and troubleshootin g software continue to improve plunger

- lift performance and ease of use. A cursory review of plunger vendor websites show that most/all offer advanced plunge control systems that optimize plunger efficiency. Several links to examples are:
http://www.weatherford.com/Products/Production/PlungerLift/ http://www.pcslift.com/plungerlift/plunger_produc ts.html http://www.pcslift.com/PDFs/PCSFerguson_PLMgr.pdf

 Information regarding the prevalence of plunger lifts is missing from Table 3.1. As the API/ANGA survey report noted, about 36% of the U.S. gas wells are equipped with plunger lifts.

f. Section 3.1.1

- Plunger Lift Narrative Review Comments:

The introductory paragraph of this section is incomplete and somewhat misleading.
“Based on our assessment of the data, a plunger lift system fo r 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. Ther e may be potential for improved production and emissions reduction when paired with a smart well automation that optimizes production and reduces product losses to the atmosphere.”

As discussed above, the key to minimizing venting of wells equipped with pl unger lifts is how the differential pressure necessary to lift a plunger and its load is achieved. If this is accomplished through vent cycles then venting emissions are likely to be high for a well equipped with a plunger. Conversely, if this is accompl ished by using shut

- in cycles to manage the reservoir pressure build

- up then venting emissions are likely to be much lower. Using a plunger control system, “smart automation”, system that optimizes the operation of the plunger on an individual well to ach ieve maximum unloading/production and minimum venting/emissions is likely toAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

18 reduce venting/emissions to just instances where overloading occurs due to system malfunctions or high reservoir liquid/water production surges. Differences in approach to operat ion of plunger lift equipped wells are mostly due to differences in the approach/philosophy that operators take to managing reservoir energy and somewhat due to differences in reservoir characteristics.

The description of a plunger lift system should clearly note that this is an example only and that other configurations are common. Also, the White Paper should describe the broad range of plunger types and configurations available along with noting the s ignificant amount of ongoing development and research devoted to improving plunger lifts and their operation. For example,
continuous

- run flow

- through plungers are available that have a higher liquid volume lift capacity and are appropriate for some wells . Also recently available are flexible plungers designed for use in wells with quite high deviation from vertical

- which is becoming more common with multi

- well pad development. Additionally, Figure 3

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

As discussed above in the Table 3.1 comments, the costs and economics of plunger lift installations appear to be extracted directly from the underlying documen ts referenced, are not updated to current dollars, and are predominantly based on costs and benefits reported by Natural Gas Star partners that have been compiled by an EPA contractor in the underlying documents. These costs are seriously outdated and nee d to be updated using an escalator for oil and gas equipment and labor which has been higher than the consumer price index (CPI) since 2000. It is strongly suggested that EPA engage industry operators and plunger lift suppliers in a survey to gather updat ed 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 ana lysis in the ICF/EDF report. The White Paper does not analyze or validate this assertion. The ICF/EDF capital and operating cost assumptions summarized in the White Paper have similar issues.

g. Section 3.1.1

- Artificial Lift Systems:

The discussion of artificial lift systems in both Table 3.1 and the White Paper narrative omits several technologies/ techniques and pump types used in mechanical deliquification (artificial lift).
There is no mention of gas lift, which involves injection of higher pressure gas down the casing

- to

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

– all of which add emissions, complexity, reliability concerns, and operating costs. Also, gas lift is limited to those reservoir/well combinations where the gas injected down the well will flow up the well

bore and not simply dissipate into the formation.
The discussion of pumps focus solely on beam pumps (also termed rod pumps, beam lift pumps, and pumpjacks in the White Paper) and omits progressing cavity pumps and electric submersible
pumps . Al though 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. ConsiderableAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

19 development and research is being applied to pump technology and linear pumps are one fair ly

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 a nd the nature and extent of its use.
The costs shown for artificial lift installations have the same problems as costs shown for other technologies/techniques. They appear to have been extracted directly from the underlying sources referenced and have not been updated to current dollars and appear to be based on limited reports by Natural Gas Star partners in the underlying documents. Also, c osts are very well

- specific, company specific, and technology specific. Generalizing the se costs is not
approp riate. Omitted from Table 3.1 is information from the API/ANGA survey report that 13.4% of the wells reported in the survey have some form of mechanical deliquification (artificial lift) installed. This is important and should be included. The statement in Table 3.1 that “The EPA does not have information on the prevalence of this technology in the field.” is incorrect.

h. Section 3.1.1

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

off between increased potential velocity with a smaller x

- section of flow and increased flowing friction inherent in smaller diameter tubing which inhibits flow and hence velocity. In practice this trade

- off limits the practical minimum diameter of veloci ty strings to about 1

- 1.5 inches

. Although a review of the underlying documents referenced by the White Paper is beyond the scope of these comments, the statement in U.S. EPA 2011 that “Coiled tubing may also be used, allowing for easier installation and the application of a greater range of tubing diameters as small as 0.25 inches.” is incorrect and needs to be corrected.
The excerpt from U.S. EPA 2011 in Table 3.1 that notes “Seamed coiled tubing may provide better lift due to elimination of turbul ence in the flow stream (U.S. EPA, 2011). is based on an unsupported assertion in U.S. EPA 2011 that makes vague reference to unidentified “studies” reaching this conclusion. This reference should be removed from the White Paper unless substa ntiated.

Th e range of flow rates or life

- cycle stages where velocity tubing may be applied in both Table 3.1 and the narrative discussion are simply not correct. Any tubing string placed within the production casing can be thought of as a “velocity string”. The wel l operator is using velocity (at the price of increased friction drop) to keep the gas flow above some “critical value” that is required to allow the gas to reliably lift the liquid. It is correct that smaller diameter tubing strings are used to increase velocity and the ability of gas to lift the liquid. However, the range of production rates and water loading where smaller diameter tubing may be a benefit is considerably broader than represented in the White Paper. Candidate wells and the appropriate

t ubing diameter are selected based on a modeled calculation of “critical velocity” based on the physics of fluid flow and flowing friction. That critical velocity value is not 1000 ft/min (16.67 ft/sec) , as stated in the White Paper, except in the rarest o f 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 beAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

20 revised . Also, similar to other costs and benefits noted in the White Paper, they appear to be based on self

- selected reports from Natural Gas Star partners on successful installations of velocity strings and are not likely to reflect the performance/benefits of installation of velocity strings where their application is not based on well

- by

- well evaluation and selection

. The statement in Table 3.1 that velocity strings are “Considered to be a no emission solution.” is incorrect. It is not uncommon for wells with smaller diameter velocity tubing strings to be vented to aid in liquid unloading. The GHGRP well venting data using Method 1 (which represents a small portion of total reports) for 2011 and 2012 contain multiple data sets where the tubing size selection is <1” although this selection is not always consistent with the average tubing size shown

.
i. Section 3.1.1

- Foaming Agents : The discussion of soap/surfactant use in Table 3.1 is not consistent with the discussion in the narrative and is not correct. The Table 3.1 discussion focus on injection of soap/surfactants omits instances where wells are configured to gr avity feed surfactants along with instances where “soap sticks” are simply “dropped” down the casing

- tubing annulus. The discussion of how a soap/water solution generates foaming is an oversimplification of the physics involved which are dependent on turb ulence for foam generation. In general, the successful use of surfactants is more than the low

- tech solution implied by the table.
The Table 3.1 representation of foaming agents as a “no emission solution” is not correct. It is not uncommon for venting to be used in conjunction with soap/surfactant use to unload liquids.
The cost and economic data presented in the White Paper appear to have been extracted directly from the underlying documents referenced
, are not updated to current dollars and should be revised . Also, similar to other costs and benefits noted in the White Paper, they appear to be based on self

- selected reports from Natural Gas Star partners on successful use of soap/surfactants and are not likely to reflect the performance/benefits of soap/surfactants where their application is not based on well

- by

- well evaluation and selection.


## Charge Question 5

Please provide any data or information you are aware of regarding the prevalence of these technologies in the field.
Data regarding the pre valence of plunger lift installations is presented in the API/ANGA survey report where 36% of the wells reported (21,500 of 59,648 wells) having plunger lifts installed

. Projecting this to a national population for 2010 the API/ANGA report estimated about 174,743 wells with plunger lift in 2010.
Data regarding the prevalence of mechanical deliquification (artificial lift) is presented in the API/ ANGA survey report where 13.4% of the wells reported ( 7,993 wells ) having some form of mechanical deliquifica tion installed. Projecting this to a national population for 2010 the API/ANGA result implies about 68,000 wells with mechanical deliquification installed in 2010.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

21 

## Charge Question 6

In general, please comment on the ability of plunger lift systems to perf orm liquids unloading without any air emissions. Are there situations where plunger lifts have to vent to the atmosphere? Are these instances only due to operator error and malfunction or are there operational situations where it is necessary in order for the plunger lift to effectively remove the liquid buildup from the well tubing?
Plungers operate by providing a mechanical barrier between the liquid column in a well

- bore and the reservoir gas/energy that is used to lift the plunger and liquid load to the surface. Plungers depend on adequate differential pressure to lift liquids and do increase the efficiency of using reservoir energy vs. depending on velocity to drag liquids. A plunger’s ability to rise is defined by six physical parameters :

 Weight of the plunger

 Mechanical friction of the plunger against the tubing walls

 Fluid friction against the tubing wal ls

 Weight of the liquid being lifted

 Surface equipment pressure drop and collection system/surface backpressure

 Formation/reservoir pressure available for lift
The first three parameters have a reasonably consistent and predictable magnitude. The fourth parameter is quite variable. If the total liquid weight increases, the balance between bottom

- hole pressure and flowing tubing

- head pressure can fall to zero and lose the driving force for the system. At that point operators may remove surface restrictio ns and gathering

- system pressure from the equation by venting the well to re

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

- in periods to build pressure in the near well reservoir. Other operators may in stall well

- site compression to allow the use of mechanical horsepower to remove the 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 both plunger lift equipped wells, there will be instances where venting a well to atmosphere is necessary to gain the differential pressure necessary to bring a plunger to surface. This is generally due to periods of greater than normal water loading (height of water column) in the well bore which can be caused by natural variation in reservoir flow or system failures/malfunctions.

As the emission data sources uniformly show, venting of wells equipped with plunger lifts accounts for more emissions overall and on a per

- venting

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


## Charge Question 7

Based o n anecdotal experience provided by industry and vendors, the blowdown of a well removes about 15% of the liquid, while a plunger lift removes up to 100% (BP,API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

22 2006). Please discuss the efficacy of plunger lifts at removing liquids from wells and the conditi ons that may limit the efficacy.

The representation in this question that the BP presentation referenced claims 100% liquid removal (presumably of the column of liquid in the well

- bore above the plunger) is not correct. The BP presentation made no representations regarding the percent of liquid (again presumably the column of liquid in the well

- bore above the plunger) removal by a plunger.

In practice, plunger lifts are designed with clearance between the plunger and the tubing walls to enable gravity free

- fall down a well and minimize plunger friction during travel to the surface. Due to this clearance, some gas leaks upwards past a plunger and some liquid “slips” past the plunger or plates out against the tubing wall and subsequently falls back into the well. The amount of liquid tha t “slips” or plates out against the tubing walls and subsequently falls back into the well is variable and depends on several factors.


## Charge Question 8

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

ion versus later in the well’s life. Are there cost savings associated with installing the plunger lift system during initial well construction?

There is likely no instance where installation of a plunger lift system during initial well construction would be beneficial. Many wells will never be a candidate for plunger lift use and installation of a plunger lift system would simply be a complete waste of money. Most wells that eventually do experience liquids loading and are candidates for plunger lifts wi ll 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 t hat the well may be worked on 3

- 5 times, each time it is worked on all of the plunger equipment would be removed to facilitate pulling the tubing. After sitting in a well for many years, 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 assures that it will be discarded long before it could ever be put in service. It is also unlikely that a plunger lift system installed at initial well construction would be functional if and when it was called on to operate after many years of sitting in a well. For high flowing wellhead pressure wells, such as the Marcellus Shale, lubricators for plungers are not available with
pressure r atings high enough for application. For high production rate wells, the tubing sizes are larger to accommodate the flow. Tubing plungers for 4.5 inch tubing, which is common in high rate wells, are not available

- nor are they needed due to the high flow rates and velocities. Additionally, the plunger equipment in a well can fail and cause problems that would require additional expenditures to correct.

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

- in” techno logy at the time of installation. Given the tremendous amount of research, development and focus being applied to deliquification of gas wells and the amount of progress being made this is not advisable.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

23 T he concept of installing a plunger lift system a t 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 o f a plunger lift system. Do these technologies, in combination with customized control software, improve performance and reduce emissions?

To the extent that advanced (smart) automation of well operation and liquid loading management improves the management of reservoir energy, such use is likely to reduce, but not eliminate, the need for venting to aid liquid unloading . This can be beneficial for both wells equipped with plunger lifts and wells without plungers installed.

However, these systems a re expensive, require customization to the area and reservoir where they are being deployed, and require highly skilled personnel to maintain, calibrate, and operate. As the BP “smart automation” project, referenced in the White Paper, shows these types o f installations can be difficult and may take years of concerted effort to achieve the desired outcomes. They are not a “silver bullet” answer to reduce venting for liquid unloading but are another valuable tool to be used as appropriate.


## Charge Q uestion 10

Please comment on the feasibility of the use of artificial lift systems during liquids unloading operations. Please be specific to the types of wells where artificial lift systems are feasible, as well as what situations or well characteristics discourage the use of artificial lift systems. Are there standard criteria that apply?

This question indicates a misunderstanding of venting to aid liquid unloading , which is the activity that results in emissions, and the elimination of any benefit of ven ting when artificial lift is installed. As discussed above, mechanical deliquification (artificial lift) is the addition of energy, in the form of a pump or gas lift, to a well

- bore to enable liquid removal. It is employed when the reservoir energy in a well is not sufficient to use other, techniques to aid in liquid removal. Once applied, venting a well provides no benefit and will not occur. However, installation of pumps or gas lift is expensive and the expected production of many marginal wells will not support the investment necessary.

Pumps in gas well deliquification applications struggle to cope with the typically low liquid volumes, variable liquid volumes, and damage caused by cavitation and “gas

- locking” of the pumps. Many techniques and ap proaches 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 appli ed 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 r equires additionalAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

24 compression and piping at the surface which requires either electricity or engines to drive
compressors – all of which add emissions, complexity, reliability concerns, and operating costs. Also, gas lift is limited to those reservoir/we ll combinations where the gas injected down the well will flow up the well

- bore and not simply dissipate into the formation.

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

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

- bores such as those on multi

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

- bore, the rods will tend to rub against the tubing/casing and cause wear and failure of either the rods and/or the tubing/casing. Unless electricity is available, the surface power unit must be a gas fired reciprocating engine which adds significant emissions, complexi ty, reliability concerns, and operating costs.

It is important to understand the distinction between applying a mechanical deliquification technology to a gas well to remove liquids from interfering with gas production and artificial lift in the classic sense of lifting a commercial product, typically oil, to the surface. The economics and economic drivers are entirely different between the two. When the expected production from a gas well cannot support the investment required to enable deliquification , it will reach the end of its economic life and be abandoned. Requiring the installation of mechanical deliquification technology (artificial lift) would cause many marginal U.S. gas wells to be abandoned. This would likely disproportionately impact sma ller 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 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 liqui ds unloading operations to reduce VOC or methane emissions. Please comment on the feasibility of the use of combustion devices/flares during liquids unloading operations. Please be specific to the types of wells where combustion devices/flares are feasible . Are there operational or technical situations where combustion devices/flares could not be used?
API is not aware of any instances where flares or other combustion devices are used during liquids unloading operations

. In 2012, 58,663 discrete wells wer e 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 n ecessitate separation of the liquids from the well stream in a separator or flare knock

- out drum. Backpressure, sufficient to unload liquids from the separator to a storage tank, would need to be held against the well/separator which would directly reduce the differential pressure gained by routing to atmosphere and perhaps inhibit unloading. Due to the potential flow rate and Btu demand, flares would need to be dedicated to liquids unloading and be moderate sizeAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

25 (~20 MMBtu/hr) rated. Liquids unloading f lares would need either continuous pilots (for infrequent use) or electronic igniters powered by solar in most instances. Also, well

- sites would need to be “re

- piped” to route from the separator to the dedicated well unloading flare. Besides the technica l difficulties dealing with the intermittent and surging flow characteristic of venting for liquids unloading, the changing velocities during an unloading and the problems of ensuring ignition for a sporadically used flare, the cost would be prohibitive. Multiplying the estimated total installed cost of $100k per flare times the number of wells vented for liquid unloading in 2012, the cost would easily be billions of dollars. There are much more cost effective methodologies to reduce liquids unloading wit hout the emissions and visual impact associated with flaring.

Combustors on H 2 S wells are truly a special case. Hydrogen sulfide presents an acute safety risk both to employees and to the general public. Understanding and designing for that risk is part of the economic evaluation made prior to producing the well. Combustors on these wells regularly require electricity to drive blowers to ensure that the combustion process is stoichiometric and unburned process gas is prevented to the maximum extent possible. Igniters/pilots that are robust and redundant technologies are provided. In short these devices are very expensive to acquire and operate. Requirements for this technology on sweet

- gas wells would make the vent/plug decision much easier and many wells with considerable recoverable gas in place would be abandoned rather than installing flare/combustion technology.


## Charge Question 12

Given that liquids unloading may only be required intermittently at many wells, is the use of a mobil e 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 w ith respect to venting for liquids unloading. Moving a flare to a location, hooking it up to a vent line, testing the integrity of the system, and then ensuring a pilot light each time a well was to be vented would take considerable time and cost. Given the sheer number of wells that vent for liquids unloading, about 69,000 in 2012 based on the GHGRP data, coupled with the number of venting instances, 4,524,802 venting events for Method 1 reported into the GHGRP plus the yet to be reported instances for M ethods 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 certai n wells?
The disparity between reports into the GHGRP, discussed above, indicate that how a company or operation handles liquid unloading and specifically the philosophy regarding management ofAPI Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

26 reservoir energy with respect to well

- bore liquid management h as a very large effect on use of venting as part of well

- bore liquid management.

Some operators cho o se to put production packers above the productive formation. These packers limit deliquification options to vent cycles or velocity strings since they prec lude 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 to 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 option.


## Charge Question 14

Are there ongoing or planned studies that will substantially improve the current understanding of VOC and methane emissions from liquids unloading events and available options for increased product recovery and emissions reductions? The EPA is aware of an additional stage of the Allen et al. study to be completed in partnership with the EDF and other partners that will directly meter the emissions from liquids unloading events. However, the EPA is not aware of any other ongoing or planned studies addressing this source of emissions.

Other tha n the Phase 2 UT/EDF study mentioned, no studies of liquids unloading are known to be currently underway. However, data reported into the GHGRP in March of 2015 for the 2014 emission year will include additional information related to venting (previously deferred) that will provide significantly better understanding of venting for liquid unloading. Pending changes to Subpart W of the GHGRP will require reporting of additional data parameters in 2016 for the 2015 emission year, which will also aid in under standing 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 represent the majority of venting events are actively working to reduce/eliminate venting in their operations to avoid the public exposure in future reports

. This alone is likely to significantly reduce the frequency of venting to aid liquids unloading and hence emissi ons. 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 i s absolutely true that plunger lifts are a valuable, effective and commonly used methodology/tool to assist in managing well

- bore liquid loading. Plunger lifts do increase the efficiency of liquids removal from wells by the reservoir energy and hence do h elp maintain or increase production.API Comments on Submitted to EPA

Oil & Natural Gas Sector Liquids Unloading Processes June 1 3 , 2014

27 However, the efficacy of plunger lifts in reducing venting of wells and emissions is completely dependent on how they are operated. As the API/ANGA survey report, the GHGRP data, the U.S. Emission Inventory, and the ICF/EDF report shows: venting wells with plungers have higher emissions per well than venting wells without plunger lifts. From an emission perspective, wells with plunger lift systems accounted for about 72% of the GHGRP reported emissions from well

vent ing 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 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.

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1 

## Liquids Unloading

Well

- bore Deliquification ( Liquids Unloading) Background

W ell

- venting to unload liquids can be a significant source of hydrocarbon pollutant emissions and there are technologies and techniques in use and available to significantly reduce, but not eliminate, venting of wells to assist in deliquification. Deliquification of gas wells is a highly complex and technical subject with many approaches and technologies in use and venting of wells is one technique , often used in combination with other techniques that depend on reservoir pressure

- such as plunger lifts, used to assist unloading

. Well deliquification is a fundamental challenge for continued production from the majority of US gas wells and the proportion is expected to grow with new growth concentrated in non

- traditional gas reservoirs such as shales, coal

- beds, and tight

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

- well deliquification with innova tion and research continually underway. For example, the 12 th


### Annual Gas Well Deliquification Workshop was held in February 2014 in Denver, Colorado was attended by over 500 representatives of dozens of upstream producers . This workshop series, along wit h a portfolio of other venues dedicated to well deliquification and artificial lift, is organized by the Artificial Lift Research and Development Council (ALRDC), and the Southwestern Petroleum Short Course (SWPSC). This research and work is both optimizi ng and improving existing techniques along with developing entirely new types of systems

. T he flexibility to pilot some of these ideas/developments must be preserved

– even if they ultimately do not succeed.
Liquid loading of well

- bores occurs when the gas production

- rate (velocity) up the well

- bore is not sufficient to carry liquids up the well

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

- bore, the weight of the column puts back

- pressure on the producing formation and the production rate declines to the point where the well can quit flowing. According to the Energy Information Administration’s 2009 “Distribution of Wells by Production Rate Bracket” some 338,056 (73%) wells out of a total gas well inventory of 461,388 gas wells produce 90 mcf of gas (15 BOE) or less per day ( http://www.eia.doe.gov/pub/oil_gas/petrosystem/us_table.html 

### ) . These low rate wells are either impaired by liquids accumul ation or are using some deliquification method to produce.
Wells and reservoirs follow a continuum of flow regimes in their economic life as the reservoir depletes, production goes down, well

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

- bore. In the early stage of a well’s life many (but by no means all)

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### wells can flow freely and with sufficient velocity to avoid liquid loading problems. As the reservoir energy depletes and the production

- rate declines, a well will reach the stage where liquid

- loading begins to be a problem and one of a portfolio of technologies or techniques will be used to help lift liquids using the reservoir ’ s energy. As a well continues to produce and the reservoir energy declines further, a well will reach the stage where the reservoir ’ s energy is not suf ficient to lift liquids and artificial lift energy, in the form of pumps, gas lift, etc., will have to be added to continue producing. When the expected production from a well cannot support the investment required to enable deliquification, it will reach the end of its economic life and be abandoned.
The following figure shows a generalized well life

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

To combat this normal well/reservoir depletion and assist liquid lift a number o f techniques are used

– dependent on the well configuration, reservoir properties, well depth, and surface equipment and collection system. MCF/day



## Time

Deliquification Progression Example

Conventional Well

CBM Well Most wells Freeflow above this line

Velocity strings, plungers, surfactant injection, and surface pressure management are often effective below this line

Energy addition required below this line

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### Techniques that rely on the reservoir energy are:

 The tubing in a well may be changed to smaller diameter “velocity strings” which provide for higher velocity at any given flow rate and provide higher liquid lift capabilities. There is a decreasing benefit from smaller diameter velocity strings due to flowing friction buildup in smaller diameter tubing.

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

 Wells may be put on a shut

- in cycle to allow pressure/energy build

- up of the reservoir near the well bore which equals higher production rates/velocity (temporary) and better liquids lifting.

 A p lunger lift may be installed in a well. This is generally coupled with a shut

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

 Venting a well may be used in conjunction with any of these techniques to create additional differential pressure /energy and aid unloading of liquids.

Techniques where energy is added to the well:

 Mechanical pumps are selected when rate of liquid a ccumulation is too high for plungers to operate or reservoir pressure is too low for plungers to operate without excessive shut

- in time to build up reservoir pressure

.

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

- casing

a nnulus.

 Compression which lowers the surface pressure creating more differential for flow and increasing velocity by lowering pressure.

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

The choice of what technique to employ is b ased on well

- by

- well and reservoir

- by

- reservoir analysis and is one of the primary jobs of the production engineering teams. For a typical well, as it moves through the depletion continuum, a series of techniques will be employed. The decision on technol ogy

- selection requires a thorough understanding of the conditions that a reservoir is flowing into, the reservoir’s sensitivity to backpressure and the volumes and pressures that the deliquification technology must handle, and costs/benefits of applying th e technology. Operators must have the flexibility to choose the most appropriate and cost effective approach for each individual well/reservoir/age/production combination and the regulatory certainty to underpin continued investment.

An excellent overvi ew of this subject is Gas Well Deliquification, Second Edition, by Dr. James F. Lea, Dr. Henry V. Nickens, and Mr. Mike R. Wells (Gulf Publishing, 2008, ISBN 978

- 0

- 7506.8280

- 0). This 588 page book does a good job of explaining the basis for choosing among the various technolog ies, but it does not presume a one

- size

- fits

- all solution

.

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### Well Venting to A id L iquids U nloading
The production rate of a well, consequent velocity up the well

- bore, and
, hence , the ability to lift liquids is mostly a function of the differential pressure between the reservoir and the flow

line/collection system and the reservoir’s sensitivity to backpressure. In order to flow, the total reservoir pressure must be greater than the t otal resistance to flow. This resistance is comprised of fluid friction and fluid interference across the reservoir; the flowing friction up the well

- bore; the weight of the vertical fluid column in the well

- bore; surface equipment and piping pressure los ses; and the collection system/flow

- line back

- pressure. Opening a well

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

pressure

- loss and the back pressure from the collection line and increases differential pressure to increase flow rates and velocities, which may enable the well to lift the liquid from the well

bore (unload the well). Venting of wells has been a common practice in low rate gas well deliquification for decades and is not restricted to wells without deliquification assist technologies, such as plunger lifts, in place. As the API/ANGA report and the GHGRP data show
, venting of wells to aid liquids unloading occurs in both plunger equipped wells and non

- plunger equipped wells with plunger equip ped wells having higher reported emissions overall.

Minimizing Venting to Assist Liquids Unloading
As discussed above, there are various reservoir

- driven techniques operators use in wells experiencing liquids loading to assist in deliquification
, which also helps reduc e the need for venting . Each of these may be the best solution for a particular portion of the life of a reservoir

. It is a misconception that plunger

- lift systems are th e single emission control action for wells where venting for liquids unloading occurs. This misconception is further exacerbated by a lack of understanding, even among those purport ing plunger lift systems as the solution to liquids unloading
, of liquids loading or plunger lift systems and their appropriate use s , limitations, and efficacy. Plungers work by providing a mechanical barrier between a small volume of water and the gas that is used to transport it up the well

- bor e

. The mechanical barrier isolates the gas from the liquids, prevents gas from moving up through the liquids hence making better use of the gas energy, and helps prevent liquids from falling ba ck into the well

bore. If the gas could flow faster, then that mechanical barrier would not be necessary or helpful. Plunger capacity is limited by well depth, differential between reservoir pressure/surface pressure
, and the gas/liquid ratio that the we ll produces. Even plunger lifted wells reach a point where they lack the reservoir pressure to run a plunger against backpressure with adequate frequency to lift the liquid present . At that point the operator has the choice of replacing the plunger with a lift method that adds energy to the system or

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### plugging the well. Operators analyze these wells and have to make the decision to spend capital and operating expense on a pu mp versus drilling a new well

. It also appears that EPA holds some misunderstanding of plunger lift. Although plungers are among the most common tools used in middle stage deliquification, there is a misconception that plungers eliminate the need to vent to atmosphere. In many cases, wells are vented to atmosphere to generate the differential pressure necessary to lift the plunger and liquid column up the well

- bore. While t his can be controlled and minimized , it cannot be eliminated.

 One primary stud y /project that is often highlight ed from the Natural Gas Star program is the BP “smart automation” well bore venting control system in the San Juan basin. What is generally misunderst ood ( or simply not acknowled ged ) is that about half of the wells which were venting (around 4.2 BCF of gas per year) were plunger equipped and were vented in order to generate the energy necessary to lift the plunger and liquid column. The fundamental nature of this project has also been mischaracterized as a project to install plunger lift systems to mitigate venting. The actual nature and success of the project was to optimize the shut

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

– i.e. “smart automation”. This was and is a project about managing reservoir energy not about installing or running plunger lift systems. The basic concept is: “The reservoir does not quit working when a well is shut

- in”.

o The fact that it t ook about 6 years to fully develop the system and achieve 90% + venting reduction is also often ignored. It is technically and operationally very difficult.

 Plungers are not universally applicable to well

- bores. For example , unless remedial action is tak en, a plunger can’t be used in a well

- bore with changing tubing sizes, defects or buildups of scale or in coil tubing which has an “internal upset” weld seam. Plungers can only be run where the inside of the well

- bore is reasonably smooth an d in reasonably good condition. They also do not work well in highly deviated directional (S

- shaped

– typical for multi

- well pads) or horizontal well

- bores.

 Although casing plungers are available for wells without tubing, they have had significant reliabi lity problems and it is also difficult to control the velocity up the well

- bore to avoid high velocities which have blown the top off of well

- heads resulting in uncontrolled release of significant quantities of gas.

 Once a well/reservoir declines sufficien tly, plungers will no longer work and energy must be added to the well

- bore or the well abandoned. This is an economics decision.

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### Studies and Data Sources

 API believes the only recent data/studies with a broad data set are the API/ANGA survey results and report and the GHGRP reported data.

 Care needs to be taken in use of the GHGRP data. For example, one company in one basin (one reporter/facility combination) accounts for about 37% of the industry wide methane emissions from liquids unloading. Any b road national “emission factor” should either exclude this data set or weight it according to the number of wells producing and/or venting.

 The UT/EDF study measured emissions from about 9 liquid unloading events but all were shale wells and hence do n ot represent the cross section of well/reservoir types. In addition, the supplemental information indicated that the researchers “triggered” an unloading event in some instances to enable measurement. If correct, the flow profile would not be equivalent to a well with a liquids column in the well

- bore which inhibited flow and triggered venting to the atmosphere.

 Phase 2 of the UT/EDF study is purported to include measurement of a larger number of liquid unloading events from a cross section of well/reserv oir types. The phase 2 report is expected to be published later in 2014.

 The annual U.S. Inventory of Greenhouse Gas Sources and Sinks estimate of emissions from liquids unloading also needs to be used with an abundance of caution. The radical variation in the estimated methane from liquids unloading; from 185.57 Gg in 2008 up to 4,554.42 Gg in 2009 ( ~2,354 % increase) and then down to 249 Gg in 2011 ( 98% decrease ) amply illustrates the uncertainty of the Inventory as a data source.

 The Natural Gas Star presentations and documents need to be fully understood, including the limitations of conditions, physical and operational, to their applicability

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

pa rtner reported opportunities have been characterized incorrectly in some of the documentation

– such as the BP project discussed above.

Options for M itigating V enting for L iquids U nloading

Options dependent on reservoir energy

 Automated control of s hut

- in cycles and plunger runs (where equipped) to optimize building of formation/reservoir energy

– used with both plunger and non

- plunger wells. This w ill only work where a radial pressure gradient from low to higher exists in the reservoir as distance from the wellbore increases

– which is typical for tight sands, shales, and some other formation types

. The automation algorithms m ust be customized for each area

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

sam e.

 A combination of flow measurement on the tubing and valve control on the tubing/casing annulus to allow the use of the tubing flow to manage liquid production while allowing well capacity in excess of the amount required for unloading to be produced up the tubing/casing annulus.

 Install plunger lifts along with appropriate control system. Plungers depend on formation/reservoir energy to lift liquids and cannot operate when energy declines beyond that necessary to lift liquids. Using automated control of shut

- in cycles (above) will extend the period where plunger lift systems are effective without regular venting to assist plunger
recovery.

o Even with advanced plunger lift systems and control systems there will be instances where venting a well to atmosphere is necessary to gain the differential pressure necessary to bring a plunger to surface. This is generally due to periods of greater than normal water loading (height of water column) in the well bore which can be caused by natural variation in reservoir flow, or system failures/malfunctions.

 Velocity (smaller diameter) tubing strings to increase velocity and liquid lift. How ever, there is a trade

- off between tubing diameter and flowing friction back

- pressure. As tubing diameter decreases, flowing friction increases which decreases differential pressure and hence flow rate/velocity. At small tubing diameters
, the flowing fri ction decreases velocity more than the restricted flow area increases velocity. Velocity strings depend on formation/reservoir pressure to lift liquids.

 Soap /surfactant sticks or injection. These work by increasing the surface area/weight ratio of water hence increasing the ability of a certain velocity to lift liquids. Soap sticks and
soap /surfactant injection are generally considered a stop

- gap solution to liquids loading because balancing the amount of soap, the ability to activate the soap load, and the ability to deal with the formation damage that soap can cause generally shortens the effective period that this technique is adequate. Wells producing a high proportion of condensate or oil do not foam adequately and there is a potential to form emuls ions which may prevent flow or need additional surface treatment. When using batch/soap sticks, th e well will be shut

- in to enable pressure build

- up and chemical mixing . Then the well may be blown down

t o start flow again. This m ay reduce the overall blow

- downs but will not eliminate the m. Continuous injection needs to get th e amount of chemical just right; t oo much = less production and foam on surface ; t oo little = less production. A limitation of any surfactant is the chemical make

- up of the liqui d that must be lifted. Some wells load with water, others may load with condensed hydrocarbon liquids (condensate). The surfactant must be compatible with the liquids in the well, and condensate is more difficult to treat. As

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### mentioned with other techni ques, there is no “one size fits all” solution . Different foaming agents can have different effectiveness and the efficacy for an individual well will vary.

Options that add energy

 The economic life of a gas well is often defined by the ability to econo mically support installing deliquification methods. If a well cannot economically support the cos t to add energy to a well for lifting liquids
, it will be plugged and abandoned.

 Install additional surface compression to lower back

- pressure against the well.

 Typical approaches to mechanical deliquification are a submersible pump, a beam pump (nodding donkey), and gas lift.

o Submersible pumps are better suited to oil wells with high liquid volumes and they struggle with the low amount of liquids in a d epleted gas well. If sufficient liquids are not produced and a “pump

- off” controller does not work (common)
, they will burn out. Submersible pumps require a fairly high

- voltage (440 V) electricity source at each well which is not common. Electrical cabl e must be run to the bottom

- hole pump location to power the pump.

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

- hole plunger pump. While more forgiving of low liquid production volumes th an submersible pump s, 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 rod s and/or the tubing/casing. Unless electricity is available
, the surface power unit must be a gas fired reciprocating engine which adds significant emissions, complexity, reliability concerns, and operating costs.

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

- to

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

– all of which add emissions, complexity, reliability concerns, and operating costs. Also, gas lift is limited to those reservoir/well combinations where the ga s injected down the well will flow up the well

- bore and not simply dissipate into the formation.

o For further information regarding gas well liquids loading, gas well liquids unloading, and artificial lift please see the Artificial Lift R&D Council web

- si te at http://www.alrdc.com/production/

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### EPA Questions and Responses

EPA Questions: What is the f easibility of the use of flares during liquids unloading operations? Are there operational or technical situations where flares could not be used?

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

. In 2012, 58,663 discrete wells were rep orted 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 necess itate separation of the liquids from the well stream in a separator or flare knock

- out drum. Backpressure sufficient to unload liquids from the separator to a storage tank would need to be held against the well/separator which would directly reduce the di fferential 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

w ould need either continuous pilots (for infrequent use) or electronic igniters powered by solar in most instances. Also, well

- sites would need to be “re

- piped” to route from the separator to the dedicated well unloading flare. Besides the technical diffi culties dealing with the intermittent and surging flow characteristic of venting for liquids unloading , the changing velocities during an unloading and the problems of ensuring ignition for a sporadically used flare , the cost would be prohibitive. Multiplying the estimated total install ed cost of $100k per flare times the number of wells vented for liquid unloading in 2012 , the cost would easily be billions of dollars. There are much more cost effective methodologies to reduce liquids unloadi ng without the emissions and visual impact associated with flaring.

EPA Question: What is the f easibility of the use of artificial lift systems during liquids unloading operations ?

This question indicates a somewhat fundamental misunderstanding of well liquids management. Artificial Lift, generally considered to be downhole pumps or gas

- lift, eliminates the need to unload liquids due to the energy added directly to the well

- bore. A pump or gas

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

– but only if the expected production can support the additional capital and operating expense. Requiring early application of “artificial lift” would shorten the economic life of many margina l wells. This would tend to differentially impact small operators due to their tendency to hold portfolios of marginal wells.

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

Wells with sufficient flow and velocity do not have liquids loading problems and there is no reason to even consider using a plunger lift system. Installing a plunger lift system in a well that does not have liquid loading problems is a waste of money. W hen a well does encounter liquids loading problems and a plunger lift is judged to be the best option, there are some limitations on when plunger lifts can be run in a well. Plunger lifts cannot be run in wells with variable tubing sizes, defects or scale build

- up in the tubing, or in wells with coil

- tubing that has an internally

- upset weld seam. They can only be run in wells with reasonably smooth tubing. Plungers do not work well in highly deviated directional (S

- shaped

– typical for multi

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

- bore. For wells without tubing, casing plungers are available but have had significant reliability problems and have experienced difficulties controlling the velocit y up the well

- bore to avoid high velocities which have blown the top off of well

- heads resulting in the uncontrolled release of significant quantities of gas. Once a well/reservoir declines sufficiently, plungers will no longer work and energy must be add ed to the well

- bore or the well abandoned. Again, t his is an economics decision.

EPA Questions: Are there situations where plunger lifts have to vent to the atmosphere? Are these instances only due to operator error and malfunction or are there operational situations where venting is necessary in order for the plunger lift to effectively remove the liquid buildup from the well tubing?

Wells with plunger lift systems comprised ~55% of the more than 58,000 wells reported as venting for liquids unlo ading into the GHGRP for 2012 . From an emission perspective, wells with plunger lift systems accounted for about 72 % of the emissions from well venting for liquids unloading. T he GHGRP reported data is broadly equivalent to that reported from the API/ANG A
survey

. With the API/ANGA survey outcome of about 36% of the well population being equipped with plunger lift systems yet responsible for over 50% of the venting wells and 70% of the emissions
, the efficacy of plunger lift systems as an emission control measure is clearly not supported by the data . Although
, with advanced well liquids unloading management
, large reductions in the frequency of well venting and thereby emissions resulting from liquids unloading , from both plunger and non

- plunger equipped wells, can likely be made . However , the need to vent will still occur. Even with advanced plunger lift systems and advanced control systems for both plunger lift and non

- plunger lift equipped wells, there will be instances whe re venting a well to atmosphere is necessary to gain the differential pressure necessary to bring a plunger to surface. This is generally due to periods of greater than normal water loading

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### (height of water column) in the well bore which can be caused by natural variation in reservoir flow or system failures/malfunctions.

EPA Question: It is EPA’s understanding that liquids loading becomes more likely as wells age due to declining well pressure.

See well lifecycle discussion in the background section above.

EPA Question: Is liquids loading only a problem for older wells or can wells develop liquids loading problems relatively quickly in certain situations?

Liquid loading is a function of the gas flow

- rate from a well and the amount of water/liquid it produces which is somewhat independent of age . O lder wells do tend to be lower producers due to being located in fields/reservoirs that have been produced for a long period and are partially depleted. However, no t all old wells have liquid loading problems and not all new wells are immune from liquid loading problems.

EPA Question: Are certain wells more prone to developing liquids loading problems such as hydraulically fractured wells versus conventional well s?

The tendency of a well to have liquid loading problems is caused by a combination of lower gas flow rate and liquids production. Whether a well has been hydraulically fractured or not is
im material. Because hydraulic fracturing tends to increase production, hydraulic fractured wells should tend to have fewer liquids loading problems than an equivalent non

- fractured well. Due to their production profile, some coal bed wells tend to have liq uids loading problems early in their life.
ICF/EDF Mitigation Paper Commentary

– Liquids Loading

The ICF paper recommends plunger lift systems as the sole technology to reduce venting for liquids unloading and the consequent emissions. Although other tech niques of managing well

bore liquids were briefly discussed, only installation of plunger lift systems was analyzed. Throughout the paper , the authors make a series of unsupported assertions and assumptions to arrive at their recommendation. Additionally , there are several instances where the author s ’ statements clearly indicate a limited understanding of liquids loading or the techniques used to manage liquids loading in wells. Some examples:

 Plunger lifts are devices that fit into the well bore and use the gas pressure to bring liquids to the surface more efficiently while controlling and limiting the amount of venting (Figure 3 7).

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### o The assertion that plunge r lift systems control and limit th e amount of venting is not supported by the facts that plunger equipped wells account for the majority of both venting wells and emissions from venting for liquids unloading. Although a properly managed plunger lift system will help manage liquids unloadi ng in a well
, the impact on emissions will be dependent on the well and reservoir conditions along with how the plunger lift is setup based on these conditions

.

 If there is insufficient pressure to direct the gas to the sales line and the gas must be vented, the emissions can still be reduced by 90% compared to uncontrolled venting. ... Plunger lifts are a relatively low cost option and can be implemented in a relatively simple manual control method or more complex automated installations. ... Gas STAR Partners report reductions of venting emissions of 90% for plunger lifts that do not go to the sales line.

o Th e statement that simply installing a plunger lift in a well will reduce emissions by
90% appears to be anecdotal as the authors do not provide any source or reference for the information despite providing the source/reference for some of the other information in the report. The author s ’ implication that this level of emission reduction can be achieved absent appropriate management of the reservoir energy is simply unfounded.

 While it seems counterintuitive that wells with plunger lifts that vent would be emitting more than those without plunger lifts, ICF interprets this information to indicate that most of the wells with the largest venting emissions have already installed plunger lifts while most of the remaining wells are venting infrequently or venting small volumes that do not justify the cost of i nstalling plunger lifts.

o This “interpretation” by the authors is completely baseless and not correct. Plunger lift systems are installed in wells to assist with management of liquids loading and enable production

- not to reduce emissions. The intent of plunger lift systems is to maintain production
, not avoidance of emissions or recovery of emissions. This shows the authors ’ lack of understanding of liquids loading, management of liquids loading, and the industry’s reasons for management of liquids load ing.

 Approaches to plunger lift operation range from ad hoc manual operation, to fixed mechanical timers, to programmable “fuzzy logic” automated controllers. Specific data on the potential reductions from optimized plunger lift operation is not availa ble but it is clear from industry experience that an integrated program of training, technology, and automation can improve the performance of plunger lifts for both productivity and emission reductions.

o This statement by the authors ignores the BP “smart automation” project
, discussed above
, which is focused on the impact (>90% reduction) that optimized management of formation energy on a well

- by

- well basis can have on emissions
,

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### presented at Natural Gas Star conferences numerous times, and well known to at least one of the ICF authors. At worst, this indicates the authors bias to select information and make assertions that supports a desired outcome and not include information and data that conflicts with their pre

- determined goal. At best, it indicates a very cavalier approach to the complex subject of liquids loading which is central to keeping many of the US gas wells producing and which is the focus of ongoing and substanti al industry effort and research.

It is not clear what population of venting wells ICF used in their analysis of the economics of installing plunger lift systems. In the body of the report
, the authors note about 127,000 wells vented for liquids unloa ding reported into the GHGRP for 2012. In appendix B
, the authors note 69,054 wells reported into the GHGRP as the average for 2011 and 2012. The latter number agrees with API’s analysis of the GHGRP data for liquids unloading which shows 69,525 and
58
, 633 wells vented for liquids unloading in 2011 and 2012
, respectively.
Overall, the ICF/EDF report recommendation of a single technology, plunger lift systems, as a solution to reducing liquids unloading emissions widely misses the mark. Wh ile significant reductions in emissions from venting wells for unloading liquids, in both plunger equipped and

non

- plunger equipped wells, are possible using cost

- effective techniques
, recommending a single approach is not appropriate. An integrated approach, choosing between all of the tools available, in a manner appropriate for the well and reservoir

– after engineering analysis, and including management of reservoir energy will be necessary to achieve significant reductions.

Recommended Charge Questions for Peer Reviewers

1. Do the data sources and studies that the paper relies upon appear credible and complete? 2. Was sufficient QA/QC conducted with regard to the data sources and studies that the paper relies on to determine their applicability and validity? 3. Are the conclusions reached by the authors supported by the information and data that was relied upon? 4. Are assertions made in the paper supported by the underlying facts and data? 5. Are assumptions made in the paper clearly noted? Do these assumptions seem valid and balanced? 6. Does th e paper reflect an understanding of the complexity of liquids loading in gas wells and the technologies and techniques used by industry at appropriate points in a well’s life

- cycle to manage liquids loading? 7. Does the paper reflect an understanding of the fundamental nature of liquid loading management to the continued ability to produce the majority of the onshore US gas wells?

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### 8. Does the paper adequately discuss the constraints for use of plunger lift systems and the fact that venting of wells equipped w ith plunger lift systems accounts for greater emissions in the GHGRP data and the API/ANGA report? 9. Does the paper present a realistic evaluation of actual emission reduction potential from regulation of venting for liquids unloading?