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4.0 WELL COMPLETIONS AND RECOMPLETIONS

In the oil and natural gas sector, well completions and recompletions contain multi-phase 

processes with various sources of emissions. One specific emission source during completion 

and recompletion activities is the venting of natural gas to the atmosphere during flowback. 

Flowback emissions are short-term in nature and occur as a specific event during completion of a 

new well or during recompletion activities that involve re-drilling or re-fracturing an existing 

well. This chapter describes completions and recompletions, and provides estimates for 

representative wells in addition to nationwide emissions. Control techniques employed to reduce 

emissions from flowback gas venting during completions and recompletions are presented, along 

with costs, emission reductions, and secondary impacts. Finally, this chapter discusses 

considerations in developing regulatory alternatives for reducing flowback emissions during 

completions and recompletions.

4.1 Process Description

4.1.1 Oil and Gas Well Completions

All oil and natural gas wells must be “completed” after initial drilling in preparation for 

production. Oil and natural gas completion activities not only will vary across formations, but 

can vary between wells in the same formation. Over time, completion and recompletion activities 

may change due to the evolution of well characteristics and technology advancement. 

Conventional gas reservoirs have well defined formations with high resource allocation in 

permeable and porous formations, and wells in conventional gas reservoirs have generally not 

required stimulation during production. Unconventional gas reservoirs are more dispersed and 

found in lower concentrations and may require stimulation to extract gas.1

Well completion activities include multiple steps after the well bore hole has reached the 

target depth. These steps include inserting and cementing-in well casing, perforating the casing 

at one or more producing horizons, and often hydraulically fracturing one or more zones in the 

reservoir to stimulate production. Surface components, including wellheads, pumps, dehydrators, 

separators, tanks, and gathering lines are installed as necessary for production to begin. The 

flowback stage of a well completion is highly variable but typically lasts between 3 and 10 days 

for the average well.2
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Developmental wells are drilled within known boundaries of a proven oil or gas field, 

and are located near existing well sites where well parameters are already recorded and necessary 

surface equipment is in place. When drilling occurs in areas of new or unknown potential, well 

parameters such as gas composition, flow rate, and temperature from the formation need to be 

ascertained before surface facilities required for production can be adequately sized and brought 

on site. In this instance, exploratory (also referred to as “wildcat”) wells and field boundary 

delineation wells typically either vent or combust the flowback gas. 

One completion step for improving gas production is to fracture the reservoir rock with 

very high pressure fluid, typically a water emulsion with a proppant (generally sand) that “props 

open” the fractures after fluid pressure is reduced. Natural gas emissions are a result of the 

backflow of the fracture fluids and reservoir gas at high velocity necessary to clean and lift 

excess proppant to the surface. Natural gas from the completion backflow escapes to the 

atmosphere during the reclamation of water, sand, and hydrocarbon liquids during the collection 

of the multi-phase mixture directed to a surface impoundment. As the fracture fluids are 

depleted, the backflow eventually contains a higher volume of natural gas from the formation. 

Due to the additional equipment and resources involved and the nature of the backflow of the 

fracture fluids, completions involving hydraulic fracturing have higher costs and vent 

substantially more natural gas than completions not involving hydraulic fracturing.

Hydraulic fracturing can and does occur in some conventional reservoirs, but it is much 

more common in “tight” formations. Therefore, this analysis assumes hydraulic fracturing is 

performed in tight sand, shale, or coalbed methane formations. This analysis defines tight sand as 

sandstones or carbonates with an in situ permeability (flow rate capability) to gas of less than 0.1 

millidarcy.a

“Energized fractures” are a relatively new type of completion method that injects an inert 

gas, such as carbon dioxide or nitrogen, before the fracture fluid and proppant. Thus, during 

initial flowback, the gas stream will first contain a high proportion of the injected gas, which will 

gradually decrease overtime. 

 

a A darcy (or darcy unit) and millidarcies (mD) are units of permeability Converted to SI units, 1 darcy is equivalent 

to 9.869233×10−13 m2 or 0.9869233 (μm)2. This conversion is usually approximated as 1 (μm)2.
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4.1.2 Oil and Gas Well Recompletions

Many times wells will need supplementary maintenance, referred to as recompletions 

(these are sometimes also referred to as workovers). Recompletions are remedial operations 

required to maintain production or minimize the decline in production. Examples of the variety 

of recompletion activities include completion of a new producing zone, re-fracture of a 

previously fractured zone, removal of paraffin buildup, replacing rod breaks or tubing tears in the 

wellbore, and addressing a malfunctioning downhole pump. During a recompletion, portable 

equipment is conveyed back to the well site temporarily and some recompletions require the use 

of a service rig. As with well completions, recompletions are highly specialized activities, 

requiring special equipment, and are usually performed by well service contractors specializing 

in well maintenance. Any flowback event during a recompletion, such as after a hydraulic 

fracture, will result in emissions to the atmosphere unless the flowback gas is captured. 

When hydraulic re-fracturing is performed, the emissions are essentially the same as new 

well completions involving hydraulic fracture, except that surface gas collection equipment will 

already be present at the wellhead after the initial fracture. The backflow velocity during refracturing will typically be too high for the normal wellhead equipment (separator, dehydrator, 

lease meter), while the production separator is not typically designed for separating sand. 

Backflow emissions are not a direct result of produced water. Backflow emissions are a 

result of free gas being produced by the well during well cleanup event, when the well also 

happens to be producing liquids (mostly water) and sand. The high rate backflow, with 

intermittent slugs of water and sand along with free gas, is typically directed to an impoundment 

or vessels until the well is fully cleaned up, where the free gas vents to the atmosphere while the 

water and sand remain in the impoundment or vessels. Therefore, nearly all of the backflow 

emissions originate from the recompletion process but are vented as the backflow enters the 

impoundment or vessels. Minimal amounts of emissions are caused by the fluid (mostly water) 

held in the impoundment or vessels since very little gas is dissolved in the fluid when it enters 

the impoundment or vessels.
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4.2. Emission Data and Emissions Factors

4.2.1 Summary of Major Studies and Emission Factors

Given the potential for significant emissions from completions and recompletions, there 

have been numerous recent studies conducted to estimate these emissions. In the evaluation of 

the emissions and emission reduction options for completions and recompletions, many of these 

studies were consulted. Table 4-1 presents a list of the studies consulted along with an indication 

of the type of information contained in the study.

4.2.2 Representative Completion and Recompletion Emissions

As previously mentioned, one specific emission source during completion and 

recompletion activities is the venting of natural gas to the atmosphere during flowback. 

Flowback emissions are short-term in nature and occur as a specific event during completion of a 

new well or during recompletion activities that involve re-drilling or re-fracturing of an existing 

well. For this analysis, well completion and recompletion emissions are estimated as the venting 

of emissions from the well during the initial phases of well preparation or during recompletion 

maintenance and/or re-fracturing of an existing well.

As previously stated, this analysis assumes wells completed/recompleted with hydraulic 

fracturing are found in tight sand, shale, or coal bed methane formations. A majority of the 

available emissions data for recompletions is for vertically drilled wells. It is projected that in the 

future, a majority of completions and recompletions will predominantly be performed on 

horizontal wells. However, there is not enough history of horizontally drilled wells to make a 

reasonable estimation of the difference in emissions from recompletions of horizontal versus 

vertical wells. Therefore, for this analysis, no distinction was made between vertical and 

horizontal wells. 

. As shown in Table 4-1, methane emissions from oil and natural gas operations have 

been measured, analyzed and reported in studies spanning the past few decades. The basic 

approach for this analysis was to approximate methane emissions from representative oil and gas 

completions and recompletions and then estimate volatile organic compounds (VOC) and 

hazardous air pollutants (HAP) using a representative gas composition.3The specific gas 

composition ratios used were 0.278 pounds (lb) VOC per lb methane (lb VOC/lb methane) and 

0.0105 lb HAP/lb methane. 
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Table 4-1. Major Studies Reviewed for Consideration of Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity

Factor(s)

Emission 

Figures

Control 

Information

Greenhouse Gas Mandatory Reporting Rule 

and Technical Supporting Documents 4 EPA 2010 Nationwide X

Inventory of Greenhouse Gas Emissions and 

Sinks: 1990-2008 27,5 EPA 2010 Nationwide X

Methane Emissions from the Natural Gas 

Industry6, 7, 8, 9

Gas Research Institute 

/US Environmental 

Protection Agency

1996 Nationwide X X

Methane Emissions from the US Petroleum 

Industry (Draft) 10 EPA 1996 Nationwide X

Methane Emissions from the US Petroleum 

Industry 11 EPA 1999 Nationwide X

Oil and Gas Emission Inventories for Western 

States 12

Western Regional Air 

Partnership 2005 Regional X X

Recommendations for Improvements to the 

Central States Regional Air Partnership's Oil 

and Gas Emission Inventories 13

Central States Regional 

Air Partnership 2008 Regional X X

Oil and Gas Producing Industry in Your 

State14

Independent Petroleum 

Association of America 2009 Nationwide

Emissions from Natural Gas Production in the 

Barnett Shale and Opportunities for Costeffective Improvements 15

Environmental Defense 

Fund 2009 Regional X X

Emissions from Oil and Natural Gas 

Production Facilities 16

Texas Commission for 

Environmental Quality 2007 Regional X X

Availability, Economics and Production of 

North American Unconventional Natural Gas 

Supplies 1

Interstate Natural Gas 

Association of America 2008 Nationwide

Petroleum and Natural Gas Statistical Data17 U.S. Energy Information 

Administration

2007-

2009 Nationwide
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Table 4-1. Major Studies Reviewed for Consideration of Emissions and Activity Data

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Report Name Affiliation Year of 

Report

Activity

Factor(s)

Emission 

Figures

Control 

Information

Preferred and Alternative Methods for 

Estimating Air Emissions from Oil and Gas 

Field Production and Processing Operations 18

EPA 1999 X X

Supplemental Generic Environmental Impact 

Statement on the Oil, Gas and Solution 

Mining Regulatory Program 19

New York State 

Department of 

Environmental 

Conservation

2009 Regional X X

Natural Gas STAR Program 20, 21, 22, 23, 24, 25, 26

EPA 2000-

2010

Nationwide/

Regional X X
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The EPA’s analysis to estimate methane emissions conducted in support of the 

Greenhouse Gas Mandatory Reporting Rule (Subpart W), which was published in the Federal 

Register on November 30, 2010 (75 FR 74458), was the foundation for methane emission 

estimates from natural gas completions with hydraulic fracturing and recompletions with 

hydraulic fracturing. Methane emissions from oil well completions, oil well recompletions, 

natural gas completions without hydraulic fracturing, and natural gas recompletions without 

hydraulic fracturing were derived directly from the EPA’s Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2008 (Inventory).27 A summary of emissions for a representative 

model well completion or recompletion is found in Table 4-2. 

4.3 Nationwide Emissions from New Sources

4.3.1 Overview of Approach

The first step in this analysis is to estimate nationwide emissions in absence of the 

proposed rulemaking, referred to as the baseline emissions estimate. In order to develop the 

baseline emissions estimate, the number of completions and recompletions performed in a 

typical year was calculated and then multiplied by the expected uncontrolled emissions per well 

completion listed in Table 4-2. In addition, to ensure no emission reduction credit was attributed 

to sources already controlled under State regulations, it was necessary to account for the number 

of completions/recompletion already subject to State regulations as detailed below.

4.3.2 Number of Completions and Recompletions

The number of new well completions was estimated using the National Energy Modeling 

System (NEMS). NEMS is a model of U.S. energy economy developed and maintained by the 

Energy Information Administration (EIA). NEMS is used to produce the Annual Energy 

Outlook, a reference publication that provides detailed forecasts of the energy economy from the 

current year to 2035. EIA is legally required to make the NEMS source code available and fully 

documented for the public. The source code and accompanying documentation is released 

annually when a new Annual Energy Outlook is produced. Because of the availability of NEMS, 

numerous agencies, national laboratories, research institutes, and academic and private-sector 

researchers have used NEMS to analyze a variety of issues. NEMS models the dynamics of

energy markets and their interactions with the broader U.S. economy. The system projects the 

production of energy resources such as oil, natural gas, coal, and renewable fuels, the conversion
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Table 4-2. Uncontrolled Emissions Estimates from Oil and Natural Gas Well 

Completions and Recompletions 

Well Completion Category

Emissions

(tons/event)

Methane* VOC** HAP‡

Natural Gas Well Completion without 

Hydraulic Fracturing 0.76 0.21 0.01

Natural Gas Well Completion with 

Hydraulic Fracturing 158 44 1.66

Oil Well Completions 0.015 0.004 0.0002

Natural Gas Well Recompletions without 

Hydraulic Fracturing 0.05 0.01 0.0005

Natural Gas Well Recompletions with 

Hydraulic Fracturing 158 44 1.66

Oil Well Recompletions 0.002 0.001 0.00002

*Reference 4, Appendix B., pgs 84-89. 

**Assumes 0.278 lb VOC /lb methane. 

‡Assumes 0.0105 lb HAP/lb methane.
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of resources through processes such as refining and electricity generation, and the quantity and 

prices for final consumption across sectors and regions. 

New well completion estimates are based on predictions from the NEMS Oil and Gas 

Supply Model, drawing upon the same assumptions and model used in the Annual Energy 

Outlook 2011 Reference Case. New well completions estimates were based on total successful 

wells drilled in 2015 (the year of analysis for regulatory impacts) for the following well 

categories: natural gas completions without hydraulic fracturing, natural gas recompletions 

without hydraulic fracturing, natural gas recompletions with hydraulic fracturing, oil well 

completions, and oil well recompletions. Successful wells are assumed to be equivalent to 

completed wells. Meanwhile, it was assumed that new dry wells would be abandoned and shut in 

and would not be completed. Therefore estimates of the number of dry wells were not included 

in the activity projections or impacts discussion for exploratory and developmental wells.

Completion estimates are based on successful developmental and exploratory wells for each 

category defined in NEMS that includes oil completions, conventional gas completions and 

unconventional gas completions. The NEMS database defines unconventional reservoirs as those 

in shale, tight sand, and coalbed methane formations and distinguishes those from wells drilled in 

conventional reservoirs. Since hydraulic fracturing is most common in unconventional 

formations, this analysis assumes new successful natural gas wells in shale, tight sand, and 

coalbed methane formations are completed with hydraulic fracturing. New successful natural gas 

wells in conventional formations are assumed to not be completed with hydraulic fracturing.

Natural gas recompletions without hydraulic fracturing and oil well recompletions were 

based on 2005 NEMS data and based on assumptions found in Subpart W’s Technical 

Supporting Document (TSD)4that wells undergo completion every ten years. In other words, 10 

percent of the total wells classified as being completed in 2005would perform a recompletion in 

2015.

The number of natural gas recompletions with hydraulic fracturing (also referred to as a 

re-fracture) was approximated using the same 10 year assumption and applied to well count data 

found in the HPDI®database.bThe HPDI database is a database of oil and natural gas well 

information maintained by a private organization that includes information including the 

 

b HPDI, LLC is a private organization specializing in oil and gas data and statistical analysis. The HPDI database is 

focused on historical oil and gas production data and drilling permit data. 
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location, formation type, shut-in pressure, production rates and condensate recovery rates for 

U.S. oil and natural gas wells.c Because HPDI is a comprehensive resource for historical well 

data, it was assumed these data would provide a strong foundation to estimate the expected 

number of recompletions of currently existing wells in lieu of the well forecast predicted by the 

NEMS model. The number of well completions and recompletions for each well source category 

is listed in Table 4-3. 

4.3.3 Level of Controlled Sources in Absence of Federal Regulation

As stated previously, to determine the impact of a regulation, it is first necessary to 

determine the current level of emissions from the sources being evaluated, or baseline emissions. 

To more accurately estimate baseline emissions for this analysis, and to ensure no emission 

reduction credit was attributed for sources already being controlled, it was necessary to evaluate

the number of completions/recompletions already subject to regulation. Therefore, the number of 

completions and recompletions already being controlled in the absence of federal regulation was 

estimated based on the existing State regulations that require control measures for completions 

and recompletions. In order to determine the number of completions and recompletions that are 

already controlled under State regulations, EIA historical well count data was analyzed to 

determine the number of new wells undergoing completion and recompletion in the States 

identified as having existing controls.d Colorado (CO) and Wyoming (WY) were the only States 

identified as requiring controls on completions prior to NSPS review.

In 2008, the state of Wyoming’s Air Quality Division (WAQD) required operators in the 

Jonah-Pinedale Area to complete wells without flaring or venting where the following criteria are 

met:(1) the flowback gas meets sales line specifications and (2) the pressure of the reservoir is 

high enough to enable REC. If the above criteria are not met, then the produced gas is to be 

flared. The WAQD requires that, “emissions of VOC and HAP associated with the flaring and 

venting of hydrocarbon fluids (liquids and gas) associated with well completion and recompletion activities shall be eliminated to the extent practicable by routing the recovered 

liquids into storage tanks and routing the recovered gas into a gas sales line or collection 

 

c

For the State of Pennsylvania, the most recent drilling information available from HPDI was for 2003. Due to the 

growth of oil and gas operations occurring in the Marcellus region in Pennsylvania, this information would not 

accurately represent the size of the industry in Pennsylvania for 2006 through 2008. Therefore, information from the 

Pennsylvania’s Department of Environmental Protection was used to estimate well completion activities for this 

region. Well data from remaining states were based on available information from HPDI. From 

<http://www.marcellusreporting.state.pa.us/OGREReports/Modules/DataExports/DataExports.aspx

d

See EIA’s The Number of Producing Wells, http://www.eia.gov/dnav/ng/ng_prod_wells_s1_a.htm
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Table 4-3: Estimated Number of Total Oil and 

Natural Gas Completions and Recompletions for a Typical Year

Well Completion Category

Estimated Number 

of Total 

Completions and 

Recompletions*

Estimated 

Number of 

Controlled 

Completions and 

Recompletions

Estimated 

Number of 

Uncontrolled 

Completions and 

Recompletions*

Natural Gas Well Completions without 

Hydraulic Fracturing* 7,694 7,694

Exploratory Natural Gas Well Completions 

with Hydraulic Fracturing** 446 446

Developmental Natural Gas Well 

Completions with Hydraulic Fracturing** 10,957 1,644 9,313

Oil Well Completions‡ 12,193 12,193

Natural Gas Well Recompletions without 

Hydraulic Fracturing 10,817 10,817

Natural Gas Well Recompletions with 

Hydraulic Fracturing‡‡ 14,177 2,127 12,050

Oil Well Recompletions‡

10,666 10,666

*Natural gas completions and recompletions without hydraulic fracturing are assumed to be 

uncontrolled at baseline.

**Fifteen percent of natural gas well completions with hydraulic fracturing are assumed as 

controlled at baseline. 

‡Oil well completions and recompletions are assumed to be uncontrolled at baseline.

‡‡Fifteen percent of natural gas well recompletions with hydraulic fracturing are assumed to be 

controlled at baseline. 
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system.” In 2010, the WAQD changed this regulation to cover the entire state, which affects the 

potential reductions that a NSPS rule could achieve in future years.28 Similar to WY, in 2007 the 

Colorado Oil and Gas Conservation Commission (COOGCC) requires REC for oil and natural 

gas wells where specific criteria is met based on pressure, formation productivity, and wellbore 

conditions.29 Historical data from EIA were used to evaluate the number of wells completed 

with hydraulic fracturing because NEMS does not project new wells at the State-level; NEMS 

projects new wells at a regional level. While neither of these States required completion controls 

until after 2007, it was assumed for this analysis that the ratio of wells in CO and WY to the total 

number of wells in the U.S. represent the percentage of controlled wells for well completions. 

The ratio of wells in WY to the number of total nationwide wells was assumed to represent the 

percentage of controlled well recompletions as it was the only State identified as having 

regulations directly regulated to recompletions. 

For the purpose of determine the control percentage of fractured wells, it was necessary 

to determine the percentage of wells, on average, that are completed with hydraulic fracturing in 

each State. Since the historical EIA data does not distinguish producing wells by reservoir type, 

the percentage of wells completed with hydraulic fracturing in each State was determined by 

applying the percentage of well completions with hydraulic fracturing compared to total well 

completions as estimated in section 4.3.2. In 2015, it is estimated that there are 11,403 

hydraulically fractured natural gas well completions out of a total 19,097 total natural gas well 

completions, which represents approximately 60 percent of new well completions. Therefore, it 

was assumed that 60 percent of new producing wells perform completions and recompletions 

with hydraulic fracturing in each State.

To estimate the number of completions controlled in absence of federal regulation, a 

three year average between 2006 and 2008 was used to estimate the average number of new 

wells drilled in each State to account for the variability of drilling activity in each State from 

year to year. The 60 percent hydraulic fracturing qualifier determined above was applied to the 

data because this analysis assumes only wells completed with hydraulic fracturing are controlled 

in absence of federal regulation. 

The EIA data lists all existing producing wells in each State by year. To estimate the 

number of new well completions, one year-end (e.g., 2007) well population was subtracted from 

the following year-end (e.g., 2008) well population to establish how many new wells were 
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completed for the latter year (e.g. number of producing wells in 2008 – number of producing 

wells in 2007 = number of new well completions in 2008). Using the EIA producing well data, it 

was estimated that there were approixmately10,926 well completions with hydraulic fracturing 

on average between 2006 and 2008.eThis estimate does not account for the number of producing 

wells that may have been shut-in during the year and replaced with new wells and should be 

considered conservative. Based on this analysis, WY accounted for 1,047 fractured natural gas 

completions, or 9.5 percent of new wells, on average, in the U.S. CO accounted for 605 fractured 

gas well completions, or 5.5 percent of new well completions, on average, in the US. Therefore, 

15 percent of well completions with hydraulic fracturing in the U.S. were determined to be 

controlled in the absence of federal regulation. 

The percentage of controlled recompletions with hydraulic fracturing was estimated 

based on new producing wells in 2005 that were completed with hydraulic fracturing. This 

methodology was chosen to be consistent with the methodologies used to determine the number 

of new well completions and recompletions for 2015 (as described in Section 4.3.2) and follows 

the same assumption that wells are recompleted every ten years (i.e. wells completed with 

hydraulic fracturing in 2005 will recomplete with hydraulic fracturing in 2015). To estimate the 

number of controlled recompletions, a similar methodology was applied, however, CO does not 

regulate recompletions, therefore, only the percent of recompletions in WY was estimated. In 

2005, it is estimated that WY accounted for 2,094 new well completions with hydraulic 

fracturing out of 13,672 total hydraulically fractured natural gas wells in the US. Therefore is it 

assumed, 15 percent of the natural gas well population that is recompleted with hydraulic 

fracturing in 2015 is assumed to be controlled. This methodology does not account for the 

percentage of the existing well population in WY that may also recomplete in 2015 and should 

be considered a conservative estimate.

Completions and recompletions that are performed without hydraulic fracturing, in 

addition to oil well completions and recompletions were assumed to not be subject to State 

regulations and therefore, were assumed to not be regulated at baseline. Baseline emissions for 

the controlled completions and recompletions covered by regulations (as estimated above) are 

assumed to be reduced by 95 percent from the use of both REC and combustion devices that may 

 

e Any State that was estimated to have a negative number of producing wells was estimated as having zero 

completions. 
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be used separately or in tandem, depending on the individual State regulation.

f

The final activity 

factors for uncontrolled completions and uncontrolled recompletions are also listed in Table 4-3.

4.3.4 Emission Estimates

Using the estimated emissions, number of uncontrolled and controlled wells at baseline,

described above, nationwide emission estimates for oil and gas well completions and 

recompletions in a typical year were calculated and are summarized in Table 4-4. All values have 

been independently rounded to the nearest ton for estimation purposes. As the table indicates, 

hydraulic fracturing significantly increases the magnitude of emissions. Completions and 

recompletions without hydraulic fracturing have lower emissions, while oil completions and 

recompletions have even lower emissions in comparison.

4.4 Control Techniques

4.4.1 Potential Control Techniques

Two techniques were considered that have been proven to reduce emissions from well

completions and recompletions: REC and completion combustion. One of these techniques, 

REC, is an approach that not only reduces emissions but delivers natural gas product to the sales

meter that would typically be vented. The second technique, completion combustion, destroys 

the organic compounds. Both of these techniques are discussed in the following sections, along 

with estimates of the impacts of their application for a representative well. Nationwide impacts 

of chosen regulatory options are discussed in section 4.5.

4.4.2 Reduced Emission Completions and Recompletions

4.4.2.1 Description

Reduced emission completions, also referred to as “green” or “flareless” completions, use 

specially designed equipment at the well site to capture and treat gas so it can be directed to the 

sales line. This process prevents some natural gas from venting and results in additional 

economic benefit from the sale of captured gas and, if present, gas condensate. Additional 

equipment required to conduct a REC may include additional tankage, special gas-liquid-sand 

separator traps, and a gas dehydrator.30 In many cases, portable equipment used for RECs 

operate in tandem with the permanent equipment that will remain after well drilling is 

 

f

Percentage of controls by flares versus REC were not determined, so therefore, the count of controlled wells with 

REC versus controlled wells with flares was not determined and no secondary baseline emission impacts were 

calculated.
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Table 4-4. Nationwide Baseline Emissions from Uncontrolled Oil and Gas Well Completions and Recompletions

Well Completion Category

Uncontrolled 

Methane 

Emissions 

per event

(tpy)

Number of 

Uncontrolled 

Wells*

Baseline Nationwide Emissions 

(tons/year)‡

Methane VOC** HAP***

Natural Gas Well Completions without 

Hydraulic Fracturing 0.763 7,694 5,870 1,632 61.63

Exploratory Natural Gas Well Completions 

with Hydraulic Fracturing 158.32 446 70,612 19,630 741

Developmental Natural Gas Well Completions 

with Hydraulic Fracturing 158.32 9,313 1,474,528 409,919 15,483

Oil Well Completions 0.015 12,193 186 51.72 1.95

Natural Gas Well Recompletions without 

Hydraulic Fracturing 0.051 10,817 553 154 5.80

Natural Gas Well Recompletions with 

Hydraulic Fracturing 158.32 12,050 1,907,785 530,364 20,031

Oil Well Recompletions 0.002 10,666 21.31 5.93 0.22

±Minor discrepancies may be due to rounding. 

*The number of controlled and uncontrolled wells estimated based on State regulations. 

**Based on the assumption that VOC content is 0.278 pounds VOC per pound methane. This estimate accounts for 5 percent 

of emissions assumed as vented even when controlled. Does not account for secondary emissions from portion of gas that is 

directed to a combustion device.

*** Based on the assumption that HAP content is 0.0105 pounds HAP per pound methane. This estimate accounts for 

5 percent of emissions assumed as vented even when controlled. Does not account for secondary emissions from portion of gas 

that is directed to a combustion device.

‡ Baseline emissions include emissions from uncontrolled wells plus five percent of emissions from controlled sources. The 

Baseline emission reductions listed in the Regulatory Impacts (Table 4-9) represents only emission reductions from 

uncontrolled sources.
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completed.31 In other instances, permanent equipment is designed (e.g. oversized) to specifically 

accommodate initial flowback. Some limitations exist for performing RECs since technical 

barriers fluctuate from well to well. Three main limitations include the following for RECs:

Proximity of pipelines. For exploratory wells, no nearby sales line may exist. The 

lack of a nearby sales line incurs higher capital outlay risk for exploration and 

production companies and/or pipeline companies constructing lines in exploratory 

fields. The State of Wyoming has set a precedent by stating proximity to gathering 

lines for wells is not a sufficient excuse to avoid RECs unless they are deemed 

exploratory, or the first well drilled in an area that has never had oil and gas well 

production prior to that drilling instance (i.e., a wildcat well).

32 In instances where 

formations are stacked vertically and horizontal drilling could take place, it may be 

possible that existing surface REC equipment may be located near an exploratory 

well, which would allow for a REC.

Pressure of produced gas. During each stage of the completion/recompletion process, 

the pressure of flowback fluids may not be sufficient to overcome the sales line 

backpressure. This pressure is dependent on the specific sales line pressure and can be 

highly variable. In this case, combustion of flowback gas is one option, either for the 

duration of the flowback or until a point during flowback when the pressure increases 

to flow to the sales line. Another control option is compressor applications. One 

application is gas lift which is accomplished by withdrawing gas from the sales line, 

boosting its pressure, and routing it down the well casing to push the fracture fluids 

up the tubing. The increased pressure facilitates flow into the separator and then the 

sales line where the lift gas becomes part of the normal flowback that can be 

recovered during an REC. Another potential compressor application is to boost 

pressure of the flowback gas after it exits the separator. This technique is 

experimental because of the difficulty operating a compressor on widely fluctuating 

flowback rate.

Inert gas concentration. If the concentration of inert gas, such as nitrogen or carbon 

dioxide, in the flowback gas exceeds sales line concentration limits, venting or 

combustion of the flowback may be necessary for the duration of flowback or until 

the gas energy content increases to allow flow to the sales line. Further, since the 

energy content of the flowback gas may not be high enough to sustain a flame due to 

the presence of the inert gases, combustion of the flowback stream would require a 

continuous ignition source with its own separate fuel supply. 

4.4.2.2. Effectiveness

RECs are an effective emissions reduction method for only natural gas completions and 

recompletions performed with hydraulic fracturing based on the estimated flowback emissions 

described in Section 4.2. The emissions reductions vary according to reservoir characteristics and 

other parameters including length of completion, number of fractured zones, pressure, gas 

composition, and fracturing technology/technique. Based on several experiences presented at 
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Natural Gas STAR technology transfer workshops, this analysis assumes 90 percent of flowback 

gas can be recovered during a REC.33 Any amount of gas that cannot be recovered can be 

directed to a completion combustion device in order to achieve a minimum 95 percent reduction 

in emissions. 

4.4.2.3 Cost Impacts

All completions incur some costs to a company. Performing a REC will add to these 

costs. Equipment costs associated with RECs vary from well to well. High production rates may 

require larger equipment to perform the REC and will increase costs. If permanent equipment, 

such as a glycol dehydrator, is already installed or is planned to be in place at the well site as 

normal operations, costs may be reduced as this equipment can be used or resized rather than 

installing a portable dehydrator for temporary use during the completion. Some operators 

normally install equipment used in RECs, such as sand traps and three-phase separators, further 

reducing incremental REC costs. 

Costs of performing a REC are projected to be between $700 and $6,500 per day, with 

representative well completion flowback lasting 3 to 10 days.2 This cost range is the incremental 

cost of performing a REC over a traditional completion, where typically the gas is vented or 

combusted because there is an absence of REC equipment. Since RECs involve techniques and 

technologies that are new and continually evolving, and these cost estimates are based on the 

state of the industry in 2006 (adjusted to 2008 US dollars).

g Cost data used in this analysis are 

qualified below:

$700 per day (equivalent to $806 per day in 2008 dollars) represents completion and 

recompletion costs where key pieces of equipment, such as a dehydrator or three 

phase separator, are already found on site and are of suitable design and capacity for 

use during flowback. 

$6,500 per day (equivalent to $7,486 in 2008 dollars) represents situations where key 

pieces of equipment, such as a dehydrator or three-phase separator, are temporarily 

brought on site and then relocated after the completion. 

Costs were assessed based on an average of the above data (for costs and number of days 

per completion), resulting in an average incremental cost for a REC of $4,146 per day (2008 

dollars) for an average of 7 days per completion. This results in an overall incremental cost of 

$29,022 for a REC versus an uncontrolled completion. An additional $691 (2008 dollars) was 

 

g The Chemical Engineering Cost Index was used to convert dollar years. For REC, the 2008 value equals 575.4 and 

the 2006 value equals 499.6.
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included to account for transportation and placement of equipment, bringing total incremental 

costs estimated at $29,713. Reduced emission completions are considered one-time events per 

well; therefore annual costs were conservatively assumed to be the same as capital costs. 

Dividing by the expected emission reductions, cost-effectiveness for VOC is $707 per ton, with a 

methane co-benefit of $198 per ton. Table 4-5 provides a summary of REC cost-effectiveness. 

Monetary savings associated with additional gas captured to the sales line was also estimated 

based on a natural gas price of $4.00hper thousand cubic feet (Mcf).

34

 It was assumed that all 

gas captured would be included as sales gas. Therefore, assuming that 90 percent of the gas is 

captured and sold, this equates to a total recovery of 8,258 Mcf of natural gas per completion or 

recompletion with hydraulic fracturing. The estimated value of the recovered natural gas for a 

representative natural gas well with hydraulic fracturing is approximately $33,030. In addition 

we estimate an average of 34 barrels of condensate is recovered per completion or 

recompletion.35 Assuming a condensate value of $70 per bbl, this result is an income due to 

condensate sales around $2,380.2 When considering these savings from REC, for a completion 

or recompletion with hydraulic fracturing, there is a net savings on the order of $5,697 per 

completion.

4.4.2.4 Secondary Impacts

A REC is a pollution prevention technique that is used to recover natural gas that would 

otherwise be emitted. No secondary emissions (e.g., nitrogen oxides, particulate matter, etc.) 

would be generated, no wastes should be created, no wastewater generated, and no electricity 

needed. Therefore, there are no secondary impacts expected due to REC.

4.4.3 Completion Combustion Devices

4.4.3.1 Description 

Completion combustion is a high-temperature oxidation process used to burn combustible 

components, mostly hydrocarbons, found in waste streams.36 Completion combustion devices 

are used to control VOC in many industrial settings, since the completion combustion device can 

normally handle fluctuations in concentration, flow rate, heating value, and inert species 

content.37 

 

h The average market price for natural gas in 2010 was approximately $4.16 per Mcf. This is much less compared to 

the average price in 2008 of $7.96 per Mcf. Due to the volatility in the price, a conservative savings of $4.00 per 

Mcf estimate was projected for the analysis in order to not overstate savings. The value of natural gas condensate 

recovered during the REC would also be significant depending on the gas composition. This value was not 

incorporated into the monetary savings in order to not overstate savings. 
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Table 4-5. Reduced Emission Completion and Recompletion Emission Reductions

and Cost Impacts Summary

Well Completion 

Category

Emission Reduction Per 

Completion/Recompletion

(tons/year)‡±

Total Cost Per 

Completion/

Recompletion* 

($/event)

VOC Cost 

Effectiveness 

($/ton)**

Methane Cost 

Effectiveness 

($/ton)

VOC Methane HAP without 

savings

with 

savings

without 

savings

with 

savings

Natural Gas 

Completions and 

Recompletions

with Hydraulic 

Fracturing

39.5 142 1.58 29,713 752 net 

savings 209 net savings

±Minor discrepancies may be due to rounding.

±±This represents a ninety percent reduction from baseline for the average well. 

*Total cost for reduced emission completion is expressed in terms of incremental cost versus a 

completion that vents emissions. This is based on an average incremental cost of $4,146 per day 

for an average length of completion flowback lasting 7 days and an additional $691 for 

transportation and set up. 

**Cost effectiveness has been rounded to the nearest dollar. 
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Completion combustion devices commonly found on drilling sites are rather crude and 

portable, often installed horizontally due to the liquids that accompany the flowback gas. These 

flares can be as simple as a pipe with a basic ignition mechanism and discharge over a pit near 

the wellhead. However, the flow directed to a completion combustion device may or may not be 

combustible depending on the inert gas composition of flowback gas, which would require a 

continuous ignition source. Sometimes referred to as pit flares, these types of combustion 

devices do not employ an actual control device, and are not capable of being tested or monitored 

for efficiency. They do provide a means of minimizing vented gas and is preferable to venting. 

For the purpose of this analysis, the term completion combustion device represents all types of 

combustion devices including pit flares.

4.4.3.2 Effectiveness

The efficiency of completion combustion devices, or exploration and production flares, 

can be expected to achieve 95 percent, on average, over the duration of the completion or 

recompletion. If the energy content of natural gas is low, then the combustion mechanism can be 

extinguished by the flowback gas. Therefore, it is more reliable to install an igniter fueled by a 

consistent and continuous ignition source. This scenario would be especially true for energized 

fractures where the initial flowback concentration will be extremely high in inert gases. This 

analysis assumes use of a continuous ignition source with an independent external fuel supply is 

assumed to achieve an average of 95 percent control over the entire flowback period.

Additionally, because of the nature of the flowback (i.e., with periods of water, condensate, and 

gas in slug flow), conveying the entire portion of this stream to a flare or other control device is 

not always feasible. Because of the exposed flame, open pit flaring can present a fire hazard or 

other undesirable impacts in some situations (e.g., dry, windy conditions, proximity to 

residences, etc.). As a result, we are aware that owners and operators may not be able to flare 

unrecoverable gas safely in every case. 

Federal regulations require industrial flares meet a combustion efficiency of 98 percent or 

higher as outlined in 40 CFR 60.18. This statute does not apply to completion combustion 

devices. Concerns have been raised on applicability of 40 CFR 60.18 within the oil and gas 

industry including for the production segment.38, 39, 40 The design and nature of completion 

combustion devices must handle multiphase flow and stream compositions that vary during the 

flowback period. Thus, the applicability criterion that specifies conditions for flares used in 
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highly industrial settings may not be appropriate for flares typically used to control emissions 

from well completions and recompletions.

4.4.3.3 Cost Impacts

An analysis depicting the cost for wells including completion combustion devices was 

conducted for the Petroleum Services Association of Canada (PSAC) 41 in 2009 by N.L. Fisher 

Supervision and Engineering, Ltd.iThe data corresponds to 34 gas wells for various types of 

formations, including coal bed methane and shale. Multiple completion methods were also 

examined in the study including hydraulic and energized fracturing. Using the cost data points 

from these natural gas well completions, an average completion combustion device cost is 

approximately $3,523 (2008 dollars).j As with the REC, because completion combustion devices 

are purchased for these one-time events, annual costs were conservatively assumed to be equal to 

the capital costs.

It is assumed that the cost of a continuous ignition source is included in the combustion 

completion device cost estimations. It is understood that multiple completions and recompletions

can be controlled with the same completion combustion device, not only for the lifetime of the 

combustion device but within the same yearly time period. However, to be conservative, costs 

were estimated as the total cost of the completion combustion device itself, which corresponds to 

the assumption that only one device will control one completion per year. The cost impacts of 

using a completion combustion device to reduce emissions from representative 

completions/recompletions are provided in Table 4-6. Completion combustion devices have a 

cost-effectiveness of $84 per ton VOC and a co-benefit of $23 per ton methane for completions 

and recompletions with hydraulic fracturing. 

4.4.3.4 Secondary Impacts

Noise and heat are the two primary undesirable outcomes of completion combustion 

device operation. In addition, combustion and partial combustion of many pollutants also create 

 

i

It is important to note that outliers were excluded from the average cost calculation. Some outliers estimated the 

cost of production flares to be as low as $0 and as high as $56,000. It is expected that these values are not 

representative of typical flare costs and were removed from the data set. All cost data found in the PSAC study were 

aggregated values of the cost of production flares and other equipment such as tanks. It is possible the inclusion of 

the other equipment is not only responsible for the outliers, but also provides a conservatively high estimate for 

completion flares. 

j The Chemical Engineering Cost Index was used to convert dollar years. For the combustion device the 2009 value 

equals 521.9. The 2009 average value for the combustion device is $3,195.
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secondary pollutants including nitrogen oxides, carbon monoxide, sulfur oxides, carbon dioxide, 

and smoke/particulates. The degree of combustion depends on the rate and extent of fuel mixing 

with air and the temperature maintained by the flame. Most hydrocarbons with carbon-tohydrogen ratios greater than 0.33 are likely to smoke.36 Due to the high methane content of the 

gas stream routed to the completion combustion device, it suggests that there should not be 

smoke except in specific circumstances (e.g., energized fractures). The stream to be combusted 

may also contain liquids and solids that will also affect the potential for smoke. Soot can 

typically be eliminated by adding steam. Based on current industry trends in the design of 

completion combustion devices and in the decentralized nature of completions, virtually no 

completion combustion devices include steam assistance.36

Reliable data for emission factors from flare operations during natural gas well 

completions are limited. Guidelines published in AP-42 for flare operations are based on tests 

from a mixture containing 80 percent propylene and 20 percent propane.36 These emissions 

factors, however, are the best indication for secondary pollutants from flare operations currently 

available. These secondary emission factors are provided are provided in Table 4-7. Nationwide 

impacts of combustion devices are further discussed in Section 4.5.

4.5 Regulatory Options

The REC pollution prevention approach would not result in emissions of CO, NOx, and 

PM from the combustion of the completion gases in the flare, and would therefore be the 

preferred option. As discussed above, REC is only an option for reducing emissions from gas 

well completions/workovers with hydraulic fracturing. Taking this into consideration, the 

following regulatory alternatives were evaluated:

Regulatory Option 1: Require completion combustion devices for conventional natural 

gas well completions and recompletions;

Regulatory Option 2: Require completion combustion devices for oil well completions 

and recompletions;

Regulatory Option 3: Require combustion devices for all completions and recompletions;

Regulatory Option 4: Require REC for all completions and recompletions of 

hydraulically fractured wells;
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Table 4-6. Emission Reduction and Cost-effectiveness Summary 

for Completion Combustion Devices

Well Completion 

Category

Emission Reduction Per 

Completion/Recompletions

(tons/year)*

Total Cost 

of 

Combustion 

Device

($)

VOC Cost 

Effectiveness

($/ton)

Methane Cost 

Effectiveness

($/ton)

VOC Methane HAP

Natural Gas Well 

Completions without 

Hydraulic Fracturing

0.202 0.725 0.01

3,523

17,485 4,861

Natural Gas Well 

Completions with 

Hydraulic Fracturing

42 150 1.66 84 23

Oil Well Completions 0.004 0.014 0.0002 874,270 243,047

Natural Gas Well 

Recompletions without 

Hydraulic Fracturing

0.0135 0.049 0.001 261,141 72,597

Natural Gas Well 

Recompletions with 

Hydraulic Fracturing

42 150 1.66 84 23

Oil Well Recompletions 0.001 0.002 0.00002 6,675,417 1,855,766

± Minor discrepancies may be due to rounding.

** Costs are stated in 2008 dollars.
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Table 4-7. Emission Factors from Flare Operations from AP-42 Guidelines Table 13.4-1

*

Pollutant Emission Factor

(lb/106 Btu)

Total Hydrocarbon** 0.14

Carbon Monoxide 0.37

Nitrogen Oxides 0.068

Particular Matter‡0-274

Carbon Dioxide‡‡ 60 

*Based on combustion efficiency of 98 percent.

**Measured as methane equivalent.

‡Soot in concentration values: nonsmoking flares, 0 micrograms per liter (μg/L); lightly 

smoking flares, 40 μg/L; average smoking flares, 177 μg/L; and heavily smoking flares, 

274 μg/L.

‡‡Carbon dioxide is measured in kg CO2/MMBtu and is derived from the carbon dioxide 

emission factor obtained from 40 CFR Part 98, subpart Y, Equation Y-2. 
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Regulatory Option 5: Require REC and combustion operational standards for natural gas 

well completions with hydraulic fracturing, with the exception of exploratory, and 

delineation wells; 

Regulatory Option 6: Require combustion operational standards for exploratory and 

delineation wells; and 

Regulatory Option 7: Require REC and combustion operational standards for all natural 

gas well recompletions with hydraulic fracturing.

The following sections discuss these regulatory options.

4.5.1 Evaluation of Regulatory Options

The first two regulatory options (completion combustion devices for conventional natural 

gas well completions and recompletions and completion combustion devices for oil well 

completions and recompletions) were evaluated first. As shown in Table 4-6, the cost 

effectiveness associated with controlling conventional natural gas and oil well completions and 

recompletions ranges from $17,615/ton VOC to over $3.5 million/ton VOC. Therefore, 

Regulatory Options 1 and 2 were rejected due to the high cost effectiveness.

The next regulatory option, to require completion combustion devices for all completions 

and recompletions, was considered. Under Regulatory Option 3, all of the natural gas emitted 

from the well during flowback would be destroyed. Not only would this regulatory option result 

in the destruction of a natural resource with no recovery of salable gas, it also would result in an 

increase in emissions of secondary pollutants (e.g., nitrogen oxides, carbon monoxide, etc.). 

Therefore, this Regulatory Option 3 was also rejected.

The fourth regulatory option was to require RECs for all completions and recompletions 

of hydraulically fractured wells. As stated previously, RECs are not feasible for all well 

completions, such as exploratory wells, due to their distance from sales lines, etc. Further, RECs 

are also not technically feasible for each well at all times during completion and recompletion 

activities due to the variability of the pressure of produced gas and/or inert gas concentrations. 

Therefore, Regulatory Option 4 was rejected.

The fifth regulatory option was to require an operational standard consisting of a 

combination of REC and combustion for natural gas well completions with hydraulic fracturing. 

As discussed for Regulatory Option 4, RECs are not feasible for every well at all times during 
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completion or recompletion activities due to variability of produced gas pressure and/or inert gas 

concentrations. In order to allow for wellhead owners and operators to continue to reduce 

emissions when RECs are not feasible due to well characteristics (e.g, wellhead pressure or inert 

gas concentrations), Regulatory Option 5 also allows for the use of a completion combustion 

device in combination with RECs.

Under Regulatory Option 5, a numerical limit was considered, but was rejected in favor 

of an operational standard. Under section 111(h)(2) of the CAA, EPA can set an operational 

standard which represents the best system of continuous emission reduction, provided the 

following criteria are met: 

“(A) a pollutant or pollutants cannot be emitted through a conveyance designed and 

constructed to emit or capture such pollutant, or that any requirement for, or use of, such 

a conveyance would be inconsistent with any Federal, State, or local law, or 

(B) the application of measurement methodology to a particular class of sources is not 

practicable due to technological or economic limitations.”

As discussed in section 4.4.3, emissions from a completion combustion device cannot be 

measured or monitored to determine efficiency making an operational standard appropriate. 

Therefore, an operational standard under this regulatory option consists of a combination of REC 

and a completion combustion device to minimize the venting of natural gas and condensate 

vapors to the atmosphere, but allows venting in lieu of combustion for situations in which 

combustion would present safety hazards, other concerns, or for periods when the flowback gas 

is noncombustible due to high concentrations of inert gases. Sources would also be required, 

under this regulatory option, to maintain documentation of the overall duration of the completion 

event, duration of recovery using REC, duration of combustion, duration of venting, and specific 

reasons for venting in lieu of combustion. It was also evaluated whether Regulatory Option 5 

should apply to all well completions, including exploratory and delineation wells. 

As discussed previously, one of the technical limitations of RECs is that they are not 

feasible for use at some wells due to their proximity to pipelines. Section 111(b)(2) of the CAA 

allows EPA to “...distinguish among classes, types, and sizes within categories of new sources 

for the purpose of establishing....” performance standards. Due to their distance from sales lines, 

and the relatively unknown characteristics of the formation, completion activities occurring at 

exploratory or delineation wells were considered to be a different “type” of activity than the 

types of completion activities occurring at all other gas wells. Therefore, two subcategories of 
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completions were identified: Subcategory 1 wells are all natural gas wells completed with 

hydraulic fracturing that do not fit the definition of exploratory or delineation wells. Subcategory 

2 wells are natural gas wells that meet the following definitions of exploratory or delineation

wells:

Exploratory wells are wells outside known fields or the first well drilled in an oil or gas 

field where no other oil and gas production exists or 

Delineation wells means a well drilled in order to determine the boundary of a field or 

producing reservoir.

Based on this subcategorization, Regulatory Option 5 would apply to the Subcategory 1 wells 

and a sixth regulatory option was developed for Subcategory 2 wells.

Regulatory Option 6 requires an operational standard for combustion for the Subcategory 

2 wells. As described above, REC is not an option for exploratory and delineation wells due to 

their distance from sales lines. As with the Regulatory Option 5, a numerical limitation is not 

feasible. Therefore, this regulatory option requires an operational standard where emissions are 

minimized using a completion combustion device during completion activities at Subcategory 2 

wells, with an allowance for venting in situations where combustion presents safety hazards or 

other concerns or for periods when the flowback gas is noncombustible due to high 

concentrations of inert gases. Consistent with Regulatory Option 5, records would be required to 

document the overall duration of the completion event, the duration of combustion, the duration 

of venting, and specific reasons for venting in lieu of combustion.

The final regulatory option was considered for recompletions. Regulatory Option 7 

requires an operational standard for a combination of RECs and a completion combustion device 

for all recompletions with hydraulic fracturing performed on new and existing natural gas wells. 

Regulatory Option 7 has the same requirements as Regulatory Option 5. Subcategorization 

similar to Regulatory Option 5 was not necessary for recompletions because it was assumed that 

RECs would be technically feasible for recompletions at all types of wells since they occur at 

wells that are producing and thus proximity to a sales line is not an issue. While evaluating this 

regulatory option, it was considered whether or not recompletions at existing wells should be 

considered modifications and subject to standards.

The affected facility under the New Source Performance Standards (NSPS) is considered 

to be the wellhead. Therefore, a new well drilled after the proposal date of the NSPS would be 
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subject to emission control requirements. Likewise, wells drilled prior to the proposal date of the 

NSPS would not be subject to emission control requirements unless they underwent a 

modification after the proposal date. Under section 111(a) of the Clean Air Act, the term 

“modification” means 

“any physical change in, or change in the method of operation of, a stationary source 

which increases the amount of any air pollutant emitted by such source or which results 

in the emission of any air pollutant not previously emitted.” 

The wellhead is defined as the piping, casing, tubing, and connected valves protruding above the 

earth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line connects 

to a wellhead valve. In order to fracture an existing well during recompletion, the well would be 

re-perforated, causing physical change to the wellbore and casing and therefore a physical 

change to the wellhead, the affected facility. Additionally, much of the emissions data on which 

this analysis is based demonstrates that hydraulic fracturing results in an increase in emissions. 

Thus, recompletions using hydraulic fracturing result in an increase in emissions from the 

existing well producing operations. Based on this understanding of the work performed in order 

to recomplete the well, it was determined that a recompletion would be considered a 

modification under CAA section 111(a) and thus, would constitute a new wellhead affected 

facility subject to NSPS. Therefore, Regulatory Option 7 applies to recompletions using 

hydraulic fracturing at new and existing wells.

In summary, Regulatory Options 1, 2, 3, and 4 were determined to be unreasonable due 

to cost considerations, other impacts or technical feasibility and thereby rejected. Regulatory 

Options 5, 6, and 7 were determined to be applicable to natural gas wells and were evaluated 

further.

4.5.3 Nationwide Impacts of Regulatory Options

This section provides an analysis of the primary environmental impacts (i.e., emission 

reductions), cost impacts and secondary environmental impacts related to Regulatory Options 5, 

6, and 7 which were selected as viable options for setting standards for completions and 

recompletions.

4.5.3.1 Primary Environmental Impacts of Regulatory Options

Regulatory Options 5, 6, and 7 were selected as options for setting standards for 

completions and regulatory options as follows:
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Regulatory Option 5: Operational standard for completions with hydraulic 

fracturing for Subcategory 1 wells (i.e., wells which do not meet the definition of

exploratory or delineation wells), which requires a combination of RECs and 

completion combustion devices with an allowance for venting during specified 

situations.

Regulatory Option 6: An operational standard for completions with hydraulic 

fracturing for exploratory and delineation wells (i.e., Subcategory 2 wells) which 

requires completion combustion devices with an allowance for venting during 

specified situations.

Regulatory Option 7: An operational standard equivalent to Regulatory Option 5 

which applies to recompletions with hydraulic fracturing at new and existing 

wells.

The number of completions and recompletions that would be subject to the regulatory 

options listed above was presented in Table 4-3. It was estimated that there would be 9,313 

uncontrolled developmental natural gas well completions with hydraulic fracturing subject to 

Regulatory Option 5. Regulatory Option 6 would apply to 446 uncontrolled exploratory natural 

gas well completions with hydraulic fracturing, and 12,050 uncontrolled recompletions at 

existing wells would be subject to Regulatory Option 7.k

Table 4-8 presents the nationwide emission reduction estimates for each regulatory 

option. It was estimated that RECs in combination with the combustion of gas unsuitable for 

entering the gathering line, can achieve an overall 95 percent VOC reduction over the duration of 

the completion operation. The 95 percent recovery was estimated based on 90 percent of 

flowback being captured to the sales line and assuming an additional 5 percent of the remaining 

flowback would be sent to the combustion device. Nationwide emission reductions were 

estimated by applying this 95 percent VOC reduction to the uncontrolled baseline emissions 

presented in Table 4-4.

4.5.3.2 Cost Impacts

Cost impacts of the individual control techniques (RECs and completion combustion 

devices) were presented in section 4.4. For Regulatory Option 6, the costs for completion 

combustion devices presented in Table 4-6 for would apply to Subcategory 2 completions. The 

cost per completion event was estimated to be $3,523. Applied to the 446 estimated 

 

k The number of uncontrolled recompletions at new wells is not included in this analysis. Based on the assumption 

that wells are recompleted once every 10 years, any new wells that are drilled after the date of proposal of the 

standard would not likely be recompleted until after the year 2015, which is the date of this analysis. Therefore, 

impacts were not estimated for recompletion of new wells, which will be subject to the standards.
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Table 4-8. Nationwide Emission and Cost Analysis of Regulatory Option

Minor discrepancies may be due to rounding.

* Number of sources in each well completion category that are uncontrolled at baseline as presented in Table 4-3.

** Costs per event for Regulatory Options 5 and 7 are calculated by adding the costs for REC and completion combustion device presented in Tables 4-5 and 4-

6, respectively. Cost per event for Regulatory Option 6 is presented for completion combustion devices in Table 4-6

†Nationwide emission reductions calculated by applying the 95% emission reduction efficiency to the uncontrolled nationwide baseline emissions in Table 4-4.

Well Completion 

Category

Number 

of 

Sources 

subject to 

NSPS*

Capital 

Cost Per 

Completion 

Event ($)**

Nationwide Emission 

Reductions (tpy)†

VOC Cost 

Effectiveness 

($/ton)

Methane Cost 

Effectiveness 

($/ton)

Total Nationwide Costs

(million $/year)

VOC Methane HAP without 

savings

with 

savings

without 

savings

with 

savings

Capital 

Cost

Annual

without 

savings

Annual 

with 

savings

Regulatory Option 5 (operational standard for REC and combustion)

Subcategory 1:

Natural gas 

Completions with 

Hydraulic Fracturing

9,313 33,237 388,398 1,400,802 14,708 797 net 

savings 221 net savings 309.5 309.5 (20.24)

Regulatory Option 6 (operational standard for combustion)

Subcategory 2:

Natural gas 

Completions with 

Hydraulic Fracturing

446 3,523 18,649 67,081 704 84 84 23 23 1.57 1.57 1.57

Regulatory Option 7 (operational standard for REC and combustion)

Natural Gas Well 

Recompletions with 

Hydraulic Fracturing

12,050 33,237 502,520 1,812,396 19,030 797 net 

savings 221 net savings 400.5 400.5 (26.18)
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Subcategory 2 completions, the nationwide costs were estimated to be $1.57 million. Completion 

combustion devices are assumed to achieve an overall 95 percent combustion efficiency.

Since the operational standards for Regulatory Options 5 and 7 include both REC and 

completion combustion devices, an additional cost impact analysis was performed to analyze the 

nationwide cost impacts of these regulatory options. The total incremental cost of the operational 

standard for Subcategory 1 completions and for recompletions is estimated at around $33,237, 

which includes the costs in Table 4-5 for the REC equipment and transportation and the costs in 

Table 4-6 for the completion combustion device. Applying the cost for the combined REC and 

completion combustion device to the estimated 9,313 Subcategory 1 completions, the total 

nationwide cost was estimated to be $309.5 million, with a net annual savings estimated around 

$20 million when natural gas savings are considered. A cost of $400.5 million was estimated for 

recompletions, with an overall savings of around $26 million when natural gas savings are 

considered. The VOC cost effectiveness for Regulatory Options 5 and 7 was estimated at around 

$797 per ton, with a methane co-benefit of $221 per ton. 

4.5.3.3 Secondary Impacts

Regulatory Options 5, 6 and 7 all require some amount of combustion; therefore the 

estimated nationwide secondary impacts are a direct result of combusting all or partial flowback 

emissions. Although, it is understood the volume of gas captured, combusted and vented may 

vary significantly depending on well characteristics and flowback composition, for the purpose 

of estimating secondary impacts for Regulatory Options 5 and 7, it was assumed that ninety 

percent of flowback is captured and an additional five percent of the remaining gas is combusted. 

For both Subcategory 1 natural gas well completions with hydraulic fracturing and for natural 

gas well recompletions with hydraulic fracturing, it is assumed around 459 Mcf of natural gas is 

combusted on a per well basis. For Regulatory Option 6, Subcategory 2 natural gas completions 

with hydraulic fracturing, it is assumed that 95 percent (8,716 Mcf) of flowback emissions are 

consumed by the combustion device. Tons of pollutant per completion event was estimated 

assuming 1,089.3 Btu/scf saturated gross heating value of the "raw" natural gas and applying the 

AP-42 emissions factors listed in Table 4-7. Table 4-9 summarizes the estimated secondary 

emissions of the selected regulatory options. 
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Table 4-9 Nationwide Secondary Impacts of Selected Regulatory Options

Pollutant

Regulatory Options 5* Regulatory Option 6‡ Regulatory Options 7*

Subcategory 1 Well 

Completions with Hydraulic 

Fracturing

Subcategory 2 Wells 

Completions with 

Hydraulic Fracturing

Well Recompletions with 

Hydraulic Fracturing

tons per 

event**

Nationwide 

Annual 

Secondary 

Emissions 

(tons/year)

tons per 

event**

Nationwide 

Annual 

Secondary 

Emissions 

(tons/year)

tons per

event**

Nationwide 

Annual 

Secondary 

Emissions 

(tons/year)

Total 

Hydrocarbons 0.03 326 0.66 296 0.03 422

Carbon Monoxide 0.09 861 1.76 783 0.09 1,114

Nitrogen Oxides 0.02 158 0.32 144 0.02 205

Particulate Matter 0.00000002 0.0002 0.011 5 0.00000002 0.0003

Carbon Dioxide 33.06 307,863 628 280,128 33.06 398,341

*The operational standard (Regulatory Options 5 and 7) combines REC and combustion is assumed to capture 90 percent of flowback 

gas. Five percent of the remaining flowback is assumed to be consumed in the combustion device. Therefore, it is estimated 459 Mcf 

is sent to the combustion device per completion event. We estimate there are 9,313 Subcategory 1 wells and 12,050 recompletions. 

**Based on a1,089.3 Btu/scf saturated gross heating value of the "raw" natural gas.

‡Assumes 8,716 Mcf of natural gas is sent to the combustion unit per completion. We estimate 446 exploratory wells fall into this 

category. 
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4.6 References

1. ICF Consulting. Availability, Economics, and Production Potential of North American 

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3. Memorandum from Brown, H., EC/R Incorporated to B. Moore, U.S. Environmental 

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for the U.S. Environmental Protection Agency. 1999. 
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12. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western 

States. Prepared for Western Governors’ Association. December 27, 2005. 

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Wells: Reduced Emission Completions. Natural Gas STAR. Producers Technology 
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Transfer Workshop. Farmington, NM. 2008. 

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28 State of Wyoming Department of Environmental Quality, Air Quality Division. Well

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29 Colorado Oil and Gas Conservation Commission. 2 CCR-404-1. http://oilgas.state.co.us/RuleMaking/FinalDraftRules/COGCCFinalDraftRules_110708.pdf

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33 Memorandum to Bruce Moore from [NAME]. [Title]. ICF Consulting. July 2011.

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38. Memorandum to Bruce Moore from Denise Grubert. American Petroleum Institute 

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