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- 1 4.0 WELL COMPLETIONS AND RECOMPLETION S

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 t he 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 re duce 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 flo wback 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 activit ies 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

a t 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a well completion is highly variable but typically lasts between 3 and 10 days for the average well. 2INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE 7.5.2011

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- 2 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 ne ed 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 th e 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 e missions 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

. N atural gas from the completion backflow escapes to the atmosphere during the reclamati on of water, sand, and hydrocarbon liquids during the collection
of the multi

- phase mixture directe d 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, c ompletions 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 analysi s 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 dioxid e 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 wil l 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.INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE 7.5.2011

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- 3 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 a re 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 re

fracturing 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 wi th 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 or iginate 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 w hen it enters the impoundment or vessels.INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE 7.5.2011

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- 4 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 st udies 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 indicat ion of the type of info rmation contained in the study

. 4.2.2 Representative Completion and Recompletion Emissions As previously mentioned, o ne 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 r ecompletion 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 dur ing 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
avail able 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, met hane 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. 3 The 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 4

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 Industry 6 , 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 E missions 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 State 14 Independent Petroleum Association of America 2009 Nationwide
Emissions from Natural Gas Production in the Barnett Shale and Opportunities for Cost

effective 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 Data 17 U.S. Energy Information Administration 2007

-

2009 NationwideTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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Table 4

- 1. Major Studies Reviewed for Consideration of Emissions and Activity Data

4

- 6 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 XTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 7 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 o il well completion s, oil well recompletion s, 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 n ationwide emissions in absence of the proposed rulemaking, referred to as the baseline emissions estimate. In order to develop the
baseline e missions 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, t o ensure no emission reduction credi t 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 w as 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 ref

erence publication that provides detailed forecasts of the energy economy from the current year to 2035. EIA is legally required to make the NEMS s ource 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. N EMS 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 conversionTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 8

Table 4

- 2. Uncontrolled Emissions E stimates 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 9 of resources through processes such as refining and electricity generation, and the quantity and prices for final consumption across sectors and regions

. New w ell 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 equivale nt 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 explorator y 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
, th is analysis assumes new successful natural gas wells in shale, tight sand
, and
coalbed methane formations are completed with hydraulic fractur ing . New successful natural gas
wells in conventional formations are assumed to not be completed with hydraulic fr actur ing

. 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) 4 that wells undergo completion every ten years. In other words, 10 percent of the total wells classified as being completed in 2005 would 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. b The HPDI database is a database of oil and natural gas well
informat ion 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 10 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 hi storical 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 forecas t predicted by the
NEMS model. The number of well completions and recompletions for each we ll 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 e missions from the sources being evaluated, or baseline emissions

. T o 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

. The refore, 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 unde rgoing 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 e nable 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 re

co mpletion 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 HPD I was for 2003. Due to the growth of oil and gas operations occurring in the Marcellus region in Pennsylvania, this infor mation would not accurately represent the size of the industry in Penns ylvania for 2006 through 2008. Therefore, information from the Pennsylvania’s Department of Environmental Protection was used to estimate well completi on activities for this region. Wel l 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.htmTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 11

Table 4

- 3: Estimated Number of Total Oil and Natural Gas Completions and Recompletion s 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 uncontrol led at baseline. ‡‡Fifteen percent of natural gas well recompletions with hydraulic fracturing are assumed to be controlled at baseline.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 12 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 well bore
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 controll ed wells for well completions.
The ratio of wells in WY to th e 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 produ cing wells by reservoir type,

t he 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 1 9,097 total natural gas well completions
, which represents approximately 60 percent of new well completions

. Therefore, it
was assumed tha t 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 wereTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 13 completed for the latter year (e.g. number of producing wells in 2008

– number of producing wells in 2007 = number of new well completio ns in 2008) . Using the EIA producing well data
, it was estimated that there were approixmately 10,926 well completions with hydraulic fracturing on average b etween 2006 and 2008. e This estimate does not account for the number of producing wells that may hav e been shut

- in during the year and replaced with new wells and should be
considered conservative. Based on this analysis, W Y accounted for 1,047 fractured natural gas completions, or 9.5 percent of new wells , on average, in the U.S. C O 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 f ederal r egulation

. 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 num ber of new well completions and recompletions for 2015 ( as described in Section 4.3.2 ) and fo llows the same assumption that wells are rec ompleted every ten years (i.e. w ells completed with hydraulic fracturing in 2005 will recomplete with hydraulic fractur ing 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 w ith hydraulic fracturing out of 13,672 total hydraulical ly fractured natural gas wells in the US

. Therefore is it assumed, 15 percent of the natural gas well population that is recomplete d with hydraulic
f racturing 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 complet ions and recompletions covered by regulations (as estimated above) are assumed to be reduce d 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 14 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, n ationwide 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 fractu ring 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 d elivers 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 impac ts 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 “gre en” 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 ve nting 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 n o secondary baseline emission impacts were calculated.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 15

Table 4

- 4 . Nationwi de Baseline Emissions from Uncontrolled Oil and Gas Well Completions and Recompletion s

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 70,61 2 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 t he Regulatory Impacts (Table 4

- 9 ) represents only emission reductions from uncontrolled sources

.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 16 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 l imitations 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 c onstructing lines in exploratory fields

. The S tate 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 n ever 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 l ine. 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 frac ture fluids up the tubing. The incr eased 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 i t 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 ma y 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 reductio n method for only natural gas completions and recompletion s performed with hydraulic fracturing based on the estimated flowback emissions
described in Section 4.2

. The emissions r eductions 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 atTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 17 Natural Gas STAR technology transfer workshops , this analysis assumes 90 percent of flowbac k 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 dehydr ator, 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 operator s 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 l asting 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 continua lly 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 18 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 wer e conservatively assumed to be the same as capital costs

. Dividing by the expected emission reductions, co st

- effectiveness for VOC is $707 per ton, w ith 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 $4.00 h per thousand cubic feet (Mcf)

. 34 It was assumed that all gas captured would be included as sales gas

. Therefore, assuming that 90 p ercent 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 hydrau lic 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 ord er 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 generate d, no wastes should be created, no wastewater generated, and no electricity
needed

. Therefore, there are no secondary imp acts 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 t he 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 savi ngs.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 19 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 av erage incremental cost of $4,146 per day for an average length of completion flowb ack lasting 7 days and an additional $691 for transportation and set up.
** Cost effectiveness has been rounded to the nearest dollar.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 20 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 discharg e 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 represent s all types of combustion devices including pit flares

. 4.4.3.2 Effectiveness The efficiency of completion combustion devices, or exploration and production flare s, 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 l ow, 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, b ecause 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 eve ry 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 criter ion that specifies conditions for flares used inTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 21 highly industrial settings may not be appropriate for flares typically used to control emissions from well completions and recompletion s. 4.4.3.3 Cost Impacts An analysis depicting the cost for wells includi ng completion combustion devices was conducted for the Petroleum Services Association of Canada (PSAC) 41 in 2009 by N.L. Fisher Supervision and Engineering, Ltd. i The data corresponds to 34 gas wells for various types of formations, including coal bed meth ane 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 i s 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 sa me yearly time period

. However, to be conservative, c osts 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

. C ompletion combustion devices have a

cost

- effectiveness of $84 per ton VOC and a co

- benefit of $23 per ton methane for completions

a nd 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 repres entative 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 valu e for the combustion device is $3,195.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 22 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 hydroc arbons with carbon

- to

hydrogen ratios greater than 0.33 are likely to smoke. 36 Due to the high methane content of the gas stream routed to the c ompletion 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 typ ically 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 b ased 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 Tab le 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, NO x , and PM from the combustion of the completion gases in the flare, a nd 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 ev aluated :

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: Requir e c ombustion devices for all completions and recompletions; Regulatory Option 4: Require REC for all completions and recompletions of hydraulically fractured wells ;TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 23

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 0.20 2 0.72 5 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 0.01 35 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

.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 24 Table 4

- 7 . Emission Factors from Flare Operations from AP

- 42 Guidelines Table 13.4

- 1 *

Pollutant Emission Factor (lb/10 6 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

.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 25 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 wel l 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. T herefore, Regulatory Options 1 and 2 were rejected due to the high cost effectiveness. The next regulatory option, to re quire completion c ombustion devices for all completions
and recompletions, was considered. Under Regulatory Option 3, all of the natura l 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 re quire REC s 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 o f 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 completi ons with hydraulic fracturing. As discussed for Regulatory Option 4, RECs are not feasible for every well at all times duringTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 26 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
devi ce 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 con tinuous 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 conveya nce 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, emission s 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 consist s of a combination of REC
and a completion comb ustion 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 t he overall duration of the completion event, duration of recovery using REC, duration of combustion, durat ion 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 lim itations of RECs is that they are not feasible for use at some well s 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 establish ing....” 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 ofTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 27 completions were identified: Subcategory 1 wells are all natural gas wells completed with hydraulic fracturing that do not fit the definition of explorato ry or delineation wells

. Subcategory
2 wells are natural gas wells that meet the following definition s 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 describe d 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 em issions are minimized using a completion combustion device during completion activities at S ubcategory 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 n oncombustible 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 REC s 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 technicall y 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 sh ould 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 beTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 28 subject to emis sion 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 ter m “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 emitt ed.”
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 existin g 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 recomple tions 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 sec ondary 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:TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 29

Regulatory Option 5 : O perational 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 REC s 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 appl ies 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 abo ve was presented in Table 4

- 3. It was estimated that there would be 9,313

uncont rolled developmental natural gas well completions with hydraulic fracturing s ubject to Regulatory Option 5. Regulatory Option 6 would apply to 446 uncontrolled exploratory natural gas well completions with hydraulic fracturing, and 12,050 uncontrolled reco mpletions at existing wells would be s ubject to Regulatory Option 7. k
Table 4

- 8 presents the nationwide emission reduction estimat es 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 o f 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 completio ns

. The cost per completion event was estimated to be $3,523

. Ap p lied 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 propo sal 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 30 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 pr esented 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 compl etion combustion devices in Table 4

- 6 †Nationwide emission reductions calculated by applying the 95% emission reduction efficiency to the uncontrolled nationwide b aseline 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 Effect iveness ($/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) Subc ategory 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) Subc ategory 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 )TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 31 Subcategory 2 completions, the nationwide c osts 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, a n 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,

w hich 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 comp letions, 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 arou nd $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 c ombusted. 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 32 Table 4

- 9 Nationwide Secondary Impacts of Selected Regulatory Options

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

Subc ategory 1 Well Completions with Hydraulic Fracturing Subc ategory 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 flowba ck gas. Five percent of the remaining flowback is assumed to be consumed in the combustion device. Therefore, it is estimated 45 9 M cf is sent to the combustion device per completion event. We estimate there are 9,313 Subcategory 1 wells and 12,050 recompletio ns. **Based on a 1,089.3 Btu/scf saturated gross heating value of the "raw" natural gas

. ‡Assumes 8,716 Mcf of natural gas is se nt to the combustion unit per completion. We estimate 446 exploratory wells fall into this category.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 33 4.6 References

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