\72\ or routing the gas to a combustor (often done as part of the
storage vessel control system). As with the BSER for wet seal
centrifugal compressors discussed earlier in this section, the emission
reduction potential for this option is estimated at 95 percent based on
the efficiencies of the capture system and the combustion device. No
further control options were identified from our white paper process or
information review.
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    \71\ U.S. EPA, 2011b.
    \72\ Subpart OOOOa defines ``route to a process'' to mean that
``the emissions are conveyed via a closed vent system to any
enclosed portion of a process where the emissions are predominantly
recycled and/or consumed in the same manner as a material that
fulfills the same function in the process and/or transformed by
chemical reaction into materials that are not regulated materials
and/or incorporated into a product; and/or recovered.''
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    Instrument air systems and electric pumps require a reliable,
constant supply of electrical power. Because of their remote locations,
well sites, gathering and boosting stations and potentially
transmission stations and storage facilities may not necessarily have a
constant, reliable electrical power supply. Therefore, we do not
believe the use of instrument air systems and electric pumps are
feasible at all facilities in the production and transmission and
storage segments. However, we take comment on is the availability of a
constant, reliable source of electrical power at facilities throughout
the oil and natural gas source category.
    Natural gas processing plants are known to have a constant and
reliable source of electrical power. Therefore, instrument air systems
are technically feasible at natural gas processing plants. Because
pumps powered by instrument air systems release no natural gas, the
methane and VOC emissions are reduced by 100 percent under this control
option.
    For natural gas processing plants, the potential emission reduction
for the instrument air option is 3.46 tpy of methane and 0.96 tpy of
VOC for each diaphragm pump, and 0.38 tpy of methane and 0.11 tpy of
VOC for each piston pump replaced.
    While solar pumps can be installed in certain situations, these
pumps are not technically feasible in all situations for which piston
pumps and diaphragm pumps are needed. Specifically, weather

conditions in certain areas can limit the effectiveness of solar pumps
and the capacity of solar pumps is also limited, so they cannot be used
in all situations where larger pumps are needed. Therefore, solar pumps
are not universally feasible control option for the production and
transmission and storage segments.
    As a result, we further analyzed the remaining potential control
option for the production and transmission and storage segments, which
is routing of natural gas-driven pump emissions to a process (e.g.,
used as fuel for a combustion source) or control device. Assuming that
emissions are routed through a closed vent system to a control device
or process, we believe these control options achieve a 95 percent
reduction in emissions of methane and VOC.
    Based on a 95 percent reduction, we estimate the reduction in
emissions in the production segment to be 0.36 tpy methane and 0.10 tpy
VOC per piston pump and 3.29 tpy of methane and 0.91 tpy of VOC per
diaphragm pump. In the transmission and storage segment, we estimate
the reduction in emissions to be 0.36 tpy of methane and 0.01 tpy VOC
per piston pump and 3.29 tpy of methane and 0.09 tpy of VOC per
diaphragm pump.
    For purposes of this action, we have identified in section VIII.A
two approaches for evaluating whether the cost of a multipollutant
control, such as routing emissions to a combustion device, is
reasonable. As explained in that section, we believe that both
approaches are appropriate for assessing the reasonableness of the
multipollutant controls considered in this action. Therefore, we find
the cost of control to be reasonable as long as it is such under either
of these two approaches.
    Under the single pollutant approach, we assign all costs to the
reduction of one pollutant and zero to all other pollutants
simultaneously reduced. For this approach, we would find the cost of
control reasonable if it is reasonable for reducing one pollutant
alone. In the evaluation below, we assign all the costs to methane
reduction alone and then to VOC reduction alone. For installing a new
control device in the production segment we estimate the cost of
control for reducing methane emissions using a combustion device to be
$60,602 per ton for piston pumps and $6,656 per ton for diaphragm
pumps. The cost of control for reducing VOC emissions for the
production segment is $218,017 per ton for piston pumps and $23,944 for
diaphragm pumps. For both the transmission and storage segment we
estimate the cost of control for reducing methane emissions using a new
combustion device to be $60,602 per ton for piston pumps and $6,656 per
ton for diaphragm pumps. The cost of control for reducing VOC emissions
for both the transmission and storage segment is $2,187,805 per ton for
piston pumps and $240,279 for diaphragm pumps. We do not consider these
cost to be reasonable.
    Under the multipollutant approach we attributed half the cost to
the methane reduction and half to the VOC reduction. For the production
segment, we estimate the cost of reducing methane emissions using a new
combustion device for piston pumps to be $30,301 per ton and the cost
of reducing VOC emissions to be $109,009 per ton. For diaphragm pumps,
the cost of reducing methane emissions is $3,328 per ton and the cost
of reducing VOC emissions is $11,972 per ton. For both the transmission
and storage segment, we estimate the cost of reducing methane emissions
for piston pumps to be $30,301 per ton and the cost of reducing VOC
emissions to be $1,093,903 per ton. For diaphragm pumps, the cost of
reducing methane emissions is $3,328 per ton and the cost of reducing
VOC emissions is $120,140 per ton. We also do not consider these cost
to be reasonable.
    While the use of a new combustion device is not cost-effective, the
costs appear reasonable when using an existing combustion control
device that is already on site. For routing the emissions in the
production segment to an existing combustion control device, under the
single pollutant approach, if we assign all costs to reducing methane
emissions and zero to VOC reduction, the cost is $789 per ton of
methane reduced for piston pumps and $87 per ton of methane reduced for
diaphragm pumps.\73\ If we assign all costs to VOC reduction and zero
to methane reduction, the cost of reducing VOC emissions using an
existing combustion control device in the production segment is $2,840
for piston pumps and $312 for diaphragm pumps. For both the
transmission and storage segment, if we assign all costs to methane
reduction and zero to VOC reduction, the cost of reducing methane
emissions is $789 per ton for piston pumps and $87 per ton for
diaphragm pumps.\74\ If we assign all costs to VOC reduction and zero
to methane reduction, the cost of reducing VOC emissions in the
transmission and storage segment is $28,501 for piston pumps and $3,130
for diaphragm pumps. As shown above, under the single pollutant
approach (i.e., all costs are assigned to one pollutant and zero to the
other), the costs are reasonable regardless of which pollutant bears
all the costs, except for the piston pump at the transmission and
storage segment if all costs are assigned to VOC. In that case, while
the cost is high if it is all assigned to VOC reduction, the cost is
reasonable when assigned to methane reduction.
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    \73\ This is well below the amount we find reasonable for
reducing fugitive methane emissions at well site (see Section
VIII.G.1 below).
    \74\ This is well below the amount we find reasonable for
reducing fugitive methane emissions at well site (see Section
VIII.G.1 below).
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    We also evaluated the cost of control for routing emissions to an
existing control device under the multipollutant approach. For the
production segment, we estimate the cost of reducing methane emissions
for piston pumps to be $395 per ton and the cost of reducing VOC
emissions to be $1,420 per ton. For diaphragm pumps, the cost of
reducing methane emissions is $43 per ton and the cost of reducing VOC
emissions is $156 per ton. For both the transmission and storage
segment, we estimate the cost of reducing methane emissions for piston
pumps to be $395 per ton and the cost of reducing VOC emissions to be
$14,250 per ton. For diaphragm pumps, the cost of reducing methane
emissions is $43 per ton and the cost of reducing VOC emissions is
$1,565 per ton. With respect to piston pumps at transmission and
storage segments, we note that the control is cost-effective under the
single pollutant approach.
    We further evaluated the cost of control for routing the emissions
to a process by installing a new VRU or utilizing an existing VRU and
found these costs to be similar to the costs presented above for new
and existing combustion devices, respectively. We determined that the
cost of control for routing to a process is similar to the costs
presented above for an existing combustion device (see the TSD for this
action for details of this analysis).
    The option of routing emissions to a control device would result in
secondary impacts from combustion. However, we did not identify any
nonair quality or energy impacts associated with this option.
    For natural gas processing plants, we evaluated instrument air
systems based on a 100 percent emissions reduction potential resulting
in a natural gas emission rate of zero standard cubic feet per hour. We
estimated the potential reduction in emissions to be 0.38 tpy of
methane and 0.11 tpy of VOCs per piston pump and 3.46 tpy of methane
and 0.96 tpy of VOC per diaphragm pump.
    Because instrument air systems are known to be used at natural gas

processing plants, we evaluated this option based on the incremental
additional cost of routing the natural gas-driven pumps to an existing
instrument air system, assuming all natural gas processing plants
currently use instrument air systems. We determined that the
incremental cost would be the cost of aligning the capacity of the
existing instrument air system to that needed after the addition of the
pumps. We determined that the facility would likely either replace an
existing compressor or add a compressor to address any needed
additional capacity. Because we do not have data on the number and
distribution of types of natural gas-driven pumps at a typical natural
gas processing plant, we developed several model plant scenarios. We
varied the size of the plant (i.e., the total number of natural gas-
driven pumps) from small, consisting of 4 natural gas-driven pumps per
plant to large, consisting of 100 natural gas-driven pumps per plant.
We also, within the size of the plant, varied the distribution of the
type of pumps using three distribution scenarios (i.e., 50 percent
diaphragm and 50 percent piston, 25 percent diaphragm and 75 percent
piston, and 75 percent diaphragm and 25 percent piston). For each model
plant, we evaluated the cost of an appropriately sized compressor based
on the required additional capacity needed by number and types of
pumps. Details of this analysis are included in the TSD for this
action.
    Under the single pollutant approach, which assigns all costs to the
reduction of one pollutant and zero to all other pollutants, the cost
of control for the model plants ranges from $374 to $2,185 per ton of
methane reduced when assigning all costs to alone to methane reduction,
and ranges from $1,344 to $7,861 per ton of VOC reduced when assigning
all the costs alone to VOC reduction.
    Under the multipollutant approach, we assigned half the cost of
control to the methane reduction and half the cost to the VOC
reduction. The cost of control under the second approach for the model
plants ranges from $187 to $1,093 per ton of methane reduced and $672
and $3,930 per ton of VOC reduced. We find the control to be cost-
effective under either approach.
    We also identified in section VIII.A two additional approaches,
based on new capital expenditures and annual revenues, for evaluating
whether the costs are reasonable. For the capital expenditure analysis,
we used the capital expenditures for 2012 for NAICS 2111, 213111 and
213112 as reported in the U.S. Census data, which we believe are
representative of the production segment. The total capital cost for
complying with the proposed standards for pneumatic pumps is 0.02
percent of the total capital expenditures, which is well below the
percentage capital increase that courts have previously upheld as
reasonable as discussed in Section VIII. A.. For the total revenue
analysis, we used the revenues for 2012 for NAICS 211111, 211112 and
213112, which we believe are representative of the production segment.
The total annualized costs for complying with the proposed standards is
0.001 percent of the total revenues, which is also very low.
    For all types of affected facilities in the production segment, the
total capital costs for complying with the proposed standards is 0.16
percent of the capital expenditures, and the total annualized costs for
complying with the proposed standards is 0.13 percent of the total
revenues, which is also very low.
    In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven piston and diaphragm pumps in
the production and transmission and storage segments to be the same,
which is to route the emissions to an existing control device or route
the emissions to a process. As discussed above, this option results in
a 95 percent reduction of emissions for both methane and VOC.
    We find that the BSER for reducing methane and VOC emissions from
natural gas-driven piston and diaphragm pumps at gas processing plants
is to use an instrument air system in place of natural gas to drive the
pumps. This option results in a 100 percent reduction of emissions for
both methane and VOC.
    We are, therefore, proposing to require 95 percent methane and VOC
control from all natural gas-driven pneumatic pumps in the production
and transmission and storage segments. For gas processing plants, we
are proposing to require 100 percent methane and VOC control from all
pneumatic pumps.
    As discussed above in this section, solar-powered, electrically-
powered and air-driven pumps cannot be employed in all applications.
However, we encourage operators to use other than natural gas-driven
pneumatic pumps where their use is technically feasible. To incentivize
the use of such alternatives, we propose that ``pneumatic pump affected
facility'' be defined in Sec.  60.5365(h) to include only natural gas-
driven pumps. As a result, pumps which are driven by means other than
natural gas would not be affected facilities subject to the pneumatic
pump provisions of the proposed NSPS.
    Public and peer review comments on the white paper noted that, in
addition to piston injection pumps and diaphragm pumps, gas assist
glycol dehydrator pumps are used to pump lean glycol through glycol
dehydrator systems. The glycol dehydrator pumps tend to be more complex
because they ``scavenge'' energy from the high pressure (rich) glycol
flowing from the contactor to the regenerator to provide the bulk of
the energy needed to pump the lean glycol into the contactor. These
types of pumps are used continuously when the glycol dehydrator is in
use. Emissions from gas assist pumps are a function of the lean glycol
circulation rate, the pressure of the contactor, and the model of the
pump. Commenters of the white paper indicate that the emissions profile
of all three types of pumps are very different. Commenters note that
data for the EPA/GRI report for gas assisted glycol pumps is calculated
based on two assumptions of process conditions, water removal, and
information from the pump manufacturer which result in significant
limitations for the calculated emission factor derived in the report.
Furthermore, commenters discuss the NEI have activity factors and
emissions separated from the glycol process emissions for gas assist
lean glycol pumps, however commenters believe that it is not clear
whether the estimate is valid.\75\ Our understanding is that emissions
from glycol dehydrator pumps are not separately quantified because
these emissions are released from the same stack as the rest of the
emissions from the dehydrator system, which are regulated under the
NESHAP at 40 CFR part 63 HH and HHH. It is also our understanding from
commenters that replacing the natural gas in gas-assisted lean glycol
pumps with instrument air is not feasible and would create significant
safety concerns. Commenters state that the only option for these types
of pumps are to replace them with electric motor driven pumps however,
solar and battery systems large enough to power these types of pumps
are not feasible. The EPA is requesting comment and additional
information on the level of uncontrolled emissions from these pumps,
how these pumps are vented through the dehydrator system, and the
amount and characteristics of VOC and methane emissions from
uncontrolled glycol dehydrators.
---------------------------------------------------------------------------

    \75\ June 13, 2014, API comments on EPA's white paper on oil and
natural gas sector pneumatic devices.

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F. Proposed Standards for Well Completions

    For the 2012 NSPS and this action, we have identified two
subcategories of hydraulically fractured wells: (1) Non-exploratory and
non-delineation wells, also known as development wells; and (2)
exploratory (also known as wildcat wells) and delineation wells. An
exploratory well is the first well drilled to determine the presence of
a producing reservoir and the well's commercial viability. A
delineation well is a well drilled to determine the boundary of a field
or producing reservoir. In the 2012 NSPS analysis, we determined that
the emissions profile for subcategory 2 wells is the same as
subcategory 1 wells as described above. In our review of white paper
comments and other information for this action, we found no information
that would indicate this conclusion is not still valid.
1. Proposed Standards for Hydraulically Fractured Non-Wildcat and Non-
Delineation Wells (Subcategory 1 Wells)
    In the 2012 NSPS, we established VOC standards for subcategory 1
hydraulically fractured gas well completions and recompletions in the
oil and natural gas source category. In this action, we are proposing
VOC standards for subcategory 1 oil well completions and recompletions
and methane standards for all subcategory 1 well completions and
recompletions in the oil and natural gas source category. Based on the
analysis below, the proposed VOC and methane standards are the same as
the gas well completion standards currently in the NSPS.
    As explained in the 2012 NSPS, well completions with hydraulic
fracturing are a significant source of VOC and methane emissions, which
occur when natural gas and non-methane hydrocarbons are vented to the
atmosphere during flowback of a hydraulically fractured well. Flowback
emissions are short-term in nature and occur over a period of several
days following fracturing or refracturing of a well. Well completions
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. Hydraulic fracturing is one technique for
improving oil or gas production where the reservoir rock is fractured
with very high pressure fluid, typically water emulsion with a proppant
(generally sand) that ``props open'' the fractures after fluid pressure
is reduced. Emissions are a result of the flowback of the fracture
fluids and reservoir gas at high volume and velocity necessary to lift
excess proppant and fluids to the surface. This multi-phase mixture is
often directed to a surface impoundment or to vented tanks (``frac
tanks''), where methane and VOC vapors escape to the atmosphere during
the collection of water, sand and hydrocarbon liquids. For oil wells,
as the fracture fluids are depleted, the flowback eventually contains
more volume of crude oil from the formation.
    Wells that are fractured generally have greater amounts of VOC and
methane emissions than conventional wells because of the extended
length of the flowback period required to purge the well of the fluids
and sand that are associated with the fracturing operation. Along with
the fluids and sand from the fracturing operation, the flowback period
may also result in emissions of methane and VOC that would not occur in
large quantities at wells that are not fractured.
    There are a variety of factors that will determine the length of
the flowback period and actual volume of emissions from a well
completion such as the number of zones, depth, pressure of the
reservoir, gas composition, etc. This variability means there will be
variability in the emissions from well completions.
    For the 2012 NSPS, we estimated that the emissions from an
uncontrolled gas well completion were 155.5 ton of methane and 22.7
tons of VOC per completion event. We also evaluated oil well
completions emissions for the 2012 NSPS; however, based on that
evaluation, we found oil well completion emissions to be very low and,
therefore, no standard was set for oil well completions.
    For this action, we reviewed new emissions studies and information
for oil well completions, as described in the 2014 white paper titled
``Oil and Natural Gas Sector Hydraulically Fractured Oil Well
Completions and Associated Gas during Ongoing Production.'' \76\ While
there was a wide variation in the results of these studies and
analyses, even in the lowest estimates the potential methane and VOC
emissions from hydraulically fractured oil well completions were
significant. This conclusion is consistent with the Federal
Implementation Plan (FIP) for the Fort Berthold Indian Reservation
(FBIR) (78 FR 17836), in which the EPA found that the emissions from
oil well completions are significant. One difference identified in our
review of comments from the 2014 white paper process was that the
average duration of an oil well completion is on the lower end of the
duration identified in our 2012 analysis, or 3 days. Therefore, for
this action, based on our review of these estimates and the
methodologies used and in consideration of these comments, we estimate
the potential emissions from hydraulically fractured oil well
completions to be 9.72 tons methane and 8.14 tons VOC per 3-day
completion event. These estimates are explained in detail in the 2012
TSD and the TSD for this action which are both available in the docket.
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    \76\ Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415completions.pdf.
---------------------------------------------------------------------------

    For the 2012 NSPS, we evaluated three options for reducing methane
and VOC emissions from hydraulically fractured well completions: RECs,
combustion (e.g., flaring), and the combination of REC with combustion.
For this action, we reviewed public and peer comments on the white
paper as well as state (i.e., Colorado \77\ and Wyoming \78\) and other
federal regulations (i.e., FBIR FIP). We found that the available
control techniques for reducing methane and VOC emissions from well
completion are the same, and they were the same as the control options
we previously identified for controlling VOC emissions: use of a REC,
combustion, and the combination of REC with combustion. We did not find
any other available control options from our white paper process or
information review.
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    \77\ Colorado Oil and Gas Conservation Commission (COGCC) 805
Series Rules (805.b.(3)A) at: http://cogcc.state.co.us/ and the
Colorado Code of Regulations at: http://www.sos.state.co.us/CCR/Welcome.do.
    \78\ WY BACT permitting guidance available at http://deq.state.wy.us/aqd/Oil%20and%20Gas/September%202013%20FINAL_Oil%20and%20Gas%20Revision_UGRB.pdf.
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    RECs are performed by separating the flowback water, sand,
hydrocarbon condensate and natural gas to reduce the portion of natural
gas and VOC vented to the atmosphere, while maximizing recovery of
salable natural gas and condensate and routing the salable gas to a
sales line and routing the recovered condensate to a completion or
storage vessel for collection. Equipment required to conduct RECs may
include tankage (e.g., ``frac tanks''), special gas-liquid-sand
separator traps and gas dehydration.
    Control by combustion is achieved through the use of a completion
combustion device. Based on our review, we believe that traditional
combustion control devices, (i.e., flares

or enclosed combustion control devices), are infeasible for use on
completion emissions because the flowback following hydraulic
fracturing consists of liquids, gases and sand in a high-volume,
multiphase slug flow.
    We evaluated RECs, completion combustion devices and the
combination of RECs with completion combustion devices in order to
determine the BSER for subcategory 1 wells. See the 2012 TSD and the
TSD for this action, available in the docket, for further details on
this evaluation. Our evaluation indicates that REC alone provides for a
90 percent control of emissions where gas emitted from the well is of
suitable quality to be routed to a gathering line. However, in some
cases, the initial gas produced from the well does not meet quality
specifications for entering gathering lines, and as a result, the gas
must be either vented or combusted. Due to the potential for gas to be
emitted, even during the use of a REC, we determined that the use of a
REC alone, would not be the BSER for control of emissions from well
completions. Our evaluation of REC combined with a completion
combustion device indicated that this option resulted in a 95 percent
control of both methane and VOC emissions. We believe this option
maximizes gas recovery and minimizes venting to the atmosphere.
    Under the last option, combustion, we determined that a completion
combustion device would achieve a 95 percent reduction in both methane
and VOC emissions. However, we determined that combustion alone would
not represent the BSER for well completions because, although the
emissions reduction would be equal to the REC and completion combustion
device combination (i.e., 95 percent control), the opportunity to
realize gas recovery would be minimized and the generation of secondary
combustion-related emissions would be increased.
    Based on the 95 percent emission reduction of a REC combined with a
combustion device, in the 2012 NSPS, the emission reductions for a
hydraulically fractured gas well completion event were estimated to be
147.4 tons of methane per completion.\79\ In this analysis, we estimate
the emission reductions for a hydraulically fractured oil well
completion event to be 9.23 tons of methane and 7.73 tons of VOC per
completion based on a 3-day completion event.
---------------------------------------------------------------------------

    \79\ Emissions of VOC from hydraulically fractured subcategory 1
gas wells are subject to the current NSPS and are not included in
this action.
---------------------------------------------------------------------------

    Equipment costs associated with RECs will vary from well to well.
Costs of performing REC are projected to be between $700 and $6,500 per
day, varying based on if key pieces of equipment are readily available
on site or temporarily brought on site. Based on the 2012 NSPS
evaluation, the average cost of a REC combined with completion
combustion device for a 7-day completion event was $33,327. Under our
evaluation in this action, we estimate the cost for a REC combined with
a completion combustion device for a 3-day completion event to be
$17,183. However, in both cases, there are savings associated with the
use of RECs because the gas recovered can be incorporated into the
production stream and sold. With the consideration of gas savings, the
cost of a REC combined with a completion combustion device for a 7-day
completions event for a gas well was estimated to have a net savings.
With the consideration of gas savings, the cost of a REC combined with
a completion combustion device for a 3-day completions event for an oil
well was estimated to be $13,586.
    We determined that the completion combustion device option for well
completions also reduces both methane and VOC emissions by 95 percent.
Therefore, the emissions reductions would be the same as those cited
above for the REC combined with a completion combustion device. The
annual cost for a completion combustion device alone was estimated be
$3,523 for the 2012 NSPS for gas wells and $3,723 under this action for
oil wells.
    For purposes of this action, we have identified in section VIII.A
two approaches (single pollutant approach and multipollutant approach)
for evaluating whether the cost of a multipollutant control is
reasonable. As explained in that section, we believe that both
approaches are appropriate for assessing the reasonableness of the
multipollutant controls considered in this action. Therefore, we find
the cost of control to be reasonable as long as it is such under either
of these two approaches.
    Under the single pollutant approach, we assign all costs to the
reduction of one pollutant and zero to all other pollutants
simultaneously reduced. For this approach, we would find the cost of
control reasonable if it is reasonable for reducing one pollutant
alone. As shown in the evaluation below, which assigns all the costs to
methane reduction alone, and based on an average cost of $33,327 per
completion event for a gas well,\80\ a REC combined with a completion
combustion device, would cost $226 per ton of methane reduced per gas
well completion without cost savings.\81\ As noted above, this option
maximizes gas recovery and minimizes venting to the atmosphere. Thus,
when the value of the natural gas recovered (approximately 1,609 Mcf of
natural gas) is considered, there is a net savings realized for this
option for a subcategory 1 gas well completion or recompletion. We find
these costs to be reasonable for the amount of methane reduction it can
achieve. Also, because all the costs have been attributed to methane
reduction, the cost of the simultaneous VOC reduction is zero and
therefore reasonable. Based on the $17,183 annual cost of a REC
combined with a completion combustion device for a 3-day completion
event for an oil well completion, with the cost attributed only to
methane and zero cost attributed to VOC, the cost of control would be
$1,861 per ton of methane reduced per oil well completion without
considering cost savings attributable to recovery of natural gas. As
noted above, this option maximizes gas recovery and minimizes venting
to the atmosphere. Thus, when the value of the natural gas recovered
(approximately 999 Mcf of natural gas) is considered, the cost of
control would be $1,471 per ton of methane reduced. Under this
approach, the cost of control with all cost attributed to VOC would be
$2,222 per ton of VOC reduced without considering natural gas savings
and $1,757 with savings realized from natural gas recovery. Although
the cost of control for a 3-day completion event at an oil well is
higher than the cost at a gas well, we believe that the emissions
reductions collectively are significant to justify the cost.
Furthermore, we believe that the industry can bear the cost and
survive.
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    \80\ As was determined for the 2012 NSPS.
    \81\ In 2012 we already found that the cost of this control to
be reasonable for reducing VOC emissions from subcategory 1 gas well
completions and recompletions. We are not reopening that decision in
this action. Therefore, this cost finding is relevant only to
methane reduction from subcategory 1 hydraulically fractured gas
well completions.
---------------------------------------------------------------------------

    Under the multipollutant approach, we assign 50 percent of the cost
to methane and 50 percent to VOC. The cost of a REC with completion
combustion for a gas well under this approach would be $930 per ton of
methane and $1,111 per ton of VOC reduced without considering natural
gas savings. With consideration of natural gas savings, the cost of
control is $736 per ton of methane and $879 per ton of VOC reduced.
Based on this

formulation, the costs for pollutant reduction are half of the
estimated costs under the single pollutant approach above and therefore
we believe these costs are not excessive for the same reasons discussed
above.
    Under the single pollutant approach, based on the $3,723 annual
cost of a completion combustion device alone, with the cost attributed
only to methane and zero attributed to VOC, the cost of control would
be $403 per ton of methane reduced per oil well completion. Under this
approach, the cost of control with cost attributed to VOC would be $481
per ton of VOC reduced. Under the multipollutant approach, we assign 50
percent of the cost to methane and 50 percent to VOC. The cost of
control under this approach would be $202 per ton of methane and $241
per ton of VOC reduced. We think that these costs are reasonable.
    See the TSD, available in the docket for this action, for a
detailed description of the cost of control analysis.
    We believe that the cost for both options, a REC combined with
combustion and combustion alone, are reasonable, given the emission
reduction that would be achieved. However, given that the reductions in
emissions are equal between the two control options, the REC combined
with combustion option provides a better environmental benefit with the
recovery of natural gas and reduced secondary combustion-related
emissions. Aside from the potential hazards (in some cases) associated
with combustion devices, we did not identify any nonair environmental
impacts, health or energy impacts associated with REC combined with
combustion, therefore these impacts were not analyzed.
    The use of a completion combustion device with this option would
produce secondary impacts in the form of combustion-related emissions.
We estimate that, for subcategory 1 oil wells completed using a
combination of REC and combustion for the year 2020, the combustion
control-related emissions would be approximately 26 tons of total
hydrocarbons, 69 tons of carbon monoxide, 24,846 tons of carbon
dioxide, and 13 tons of nitrogen oxides.\82\ This is based on the
assumption that 5 percent of the flowback gas is combusted for
subcategory 1 oil wells (controlled with a REC combined with a
completion combustion device).
---------------------------------------------------------------------------

    \82\ Because the current NSPS requires control of gas well
completions using this option, we do not include the secondary
emissions for control of methane from gas well completions.
---------------------------------------------------------------------------

    We estimate that this option of control for subcategory 1 oil well
completions, for the projected year 2020, will result in estimated
emission reductions of 127,478 tons of methane and 106,750 tons of VOC.
Thus, we believe that the benefit of the methane and VOC reductions far
outweigh the secondary impacts of combustion emissions formation during
use of the completion combustion operation. Further, should only
combustion be considered for all oil well completions, including the
subcategory 1 wells, the secondary impacts would be far greater than
those shown above. Secondary impacts of combustion alone are presented
in the discussion of subcategory 2 wells below in this section.
    We also identified in section VIII.A two additional approaches,
based on new capital expenditures and annual revenues, for evaluating
whether the costs are reasonable. For the capital expenditure analysis,
we used the capital expenditures for 2012 for NAICS 2111, 213111 and
213112 as reported in the U.S. Census data, which we believe are
representative of the production segment. The total capital costs for
complying with the proposed standards for subcategory 1 wells is 0.081
percent of the total capital expenditures, which is well below the
percentage capital increase that courts have previously upheld as
reasonable as discussed in Section VIII.A.. For the total revenue
analysis, we used the revenues for 2012 for NAICS 211111, 211112 and
213112, which we believe are representative of the production segment.
The total annualized costs for complying with the proposed standards is
0.033 percent of the total revenues, which is also very low.
    For all types of affected facilities in the production segment, the
total capital costs for complying with the proposed standards is 0.16
percent of the total capital expenditures, and the total annualized
costs for complying with the proposed standards is 0.13 percent of the
total revenues, which is also very low.
    For the reasons stated above, we determine the BSER for subcategory
1 (developmental wells) is the combination of REC and the use of a
completion combustion device. We considered setting a numerical
performance standard; however, we determined that it is not feasible to
prescribe or enforce a numerical performance standard in this case
because the gas can be discharged at multiple locations along with
water and sand in a multiphase slug flow during the flowback process
and, therefore, may not always be emitted at the same specific location
in the process or through one conveyance designed and constructed to
emit or capture such pollutant. Therefore, pursuant to section
111(h)(2) of the CAA, we are proposing an operational standard for
subcategory 1 wells that would require a combination of gas capture and
recovery and completion combustion devices to minimize venting of gas
and condensate vapors to the atmosphere, with provisions for venting in
lieu of combustion for situations in which combustion would present
safety hazards or for periods when the flowback gas is noncombustible.
    For the purposes of these standards we have separated the flowback
period into two stages, the ``initial flowback stage'' and the
``separation flowback stage.'' The initial flowback stage begins with
the first flowback from the well following hydraulic fracturing or
refracturing and is characterized by high volumetric flow water,
containing sand, fracturing fluids and debris from the formation with
very little gas being brought to the surface, usually in multiphase
slug flow. Due to the high volume of the flowback and the small amounts
of gas in the initial flowback, operation of a separator may be
initially technically infeasible, and there may not be sufficient gas
for combustion. During these conditions, the emissions cannot be
controlled from the flowback. During this stage, liquids are collected
and routed to completion vessels.
    For the reasons explained above, during the initial flowback stage,
we propose that the flowback be routed to a storage vessel or to a well
completion vessel that can be a frac tank, a lined pit or any other
vessel. The purpose of this requirement is to avoid having operators
route the flowback to an unlined pit or onto the ground. During the
initial flowback stage, there is no requirement for controlling
emissions from the vessel, and any gas in the flowback during this
stage may be vented. However, the operator must route the flowback to a
separator unless it is technically infeasible for a separator to
function. Conditions that could prevent proper operation of the
separator include insufficient gas concentration, low pressure gas, and
multiphase slug flow containing solids that could clog the separator.
We stress that operators have the responsibility to direct the flowback
to a separator as soon as conditions allow a separator to function and
in accordance with the General Provision requirements to operate the
affected facility in a manner consistent with good air pollution
control practices for minimizing emissions.
    The second stage is defined as the ``separation flowback stage.''
The point at which the separator can function

marks the beginning of the separation flowback stage. This stage is
characterized by the separator operating with a gaseous phase and one
or more liquid phases in the separator. The end of the separation
flowback stage marks the end of the flowback period and is defined as
the point at which the well is shut in and the flowback equipment is
permanently disconnected from the well, or the startup of production.
The end of the separation flowback stage (i.e., the end of flowback) is
characterized by certain indicators. Permanent disconnection of the
temporary equipment used during flowback can be an indicator of
flowback having ended. For example, during flowback, skid-mounted choke
manifolds are used to limit flowback and assist in directing the flow.
Temporary lines laid on the ground from the wellhead to the choke
manifold and to the flowback separators and frac tanks are connected
with ``hammer unions'' which are pipe unions that are designed for ease
of making temporary connections and are characterized by ``ears'' that
allow the joint to be made up quickly by striking with a hammer. After
flowback has subsided and the well has cleaned up sufficiently, the
well is temporarily shut in to disconnect the temporary flowback
equipment. We believe that when the operator permanently disconnects
choke manifolds, temporary separators, sand traps and other equipment
connected with temporary lines and hammer unions, it is a reliable
indicator that flowback has ended and the well is ready for production.
At that point, we believe that operators will remove these temporary
equipment used during flowback to avoid incurring unnecessary charges
for additional days the equipment remains onsite. The well could start
production immediately or it could remain shut in until permanent
equipment is installed.
    During the separation flowback stage, the operator must route all
salable quality natural gas from the separator to a gas flow line or
collection system, re-inject the gas into the well or another well, use
the gas as an on-site fuel source or use the gas for another useful
purpose that a purchased fuel or raw material would serve. If, during
the separation flowback stage, it is technically infeasible to route
the recovered gas to a flow line or collection system, re-inject the
gas or use the gas as fuel or for other useful purpose, the recovered
gas must be combusted. No direct venting of recovered gas is allowed
during the separation flowback stage except when combustion creates a
fire or safety hazard or can damage tundra, permafrost or waterways.
With regard to infeasibility of collecting the salable quality gas, we
believe that owners and operators plan their operations to extract a
target product and evaluate whether the appropriate infrastructure
access is available to ensure their product has a viable path to market
before completing a well. However, there may be cases in which, for
reason(s) not within an operator's control, the well is completed and
flowback occurs without a suitable flow line available. We are aware
that this situation may be more common for wells that are primarily
drilled to produce oil. In those instances, Sec.  60.5375(a)(3)
requires the combustion of the gas unless combustion poses an unsafe
condition as described above. During the separation flowback stage, all
liquids from the separator must be directed to a storage vessel or to a
well completion vessel, routed to a collection system or be re-injected
into the well or another well.
    The proposed operational standard would be accompanied by
requirements for 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.
2. Proposed Standards for Hydraulically Fractured Exploratory and
Delineation Wells (Subcategory 2 Wells)
    In the 2012 NSPS, we established VOC standards for subcategory 2
hydraulically fractured exploratory and delineation gas well
completions. In this action, we are proposing VOC standards for the
hydraulically fractured exploratory and delineation oil well
completions and we are also proposing methane standards for all
hydraulically fractured exploratory and delineation well completions in
the oil and natural gas source category. Based on the analysis below,
the proposed VOC and methane standards described above are the same as
the current standards for hydraulically fractured exploratory and
delineation gas well completion standards currently in the NSPS.
    As noted above, for the 2012 NSPS analysis, we determined that the
emissions profile for subcategory 2 wells is the same as subcategory 1
wells as described above. In our review of white paper comment and
other information for this action, we found no information that would
indicated this conclusion is not still valid. Specifically, we
determined the emissions from a hydraulically fractured oil well were
9.72 tons of methane and 8.14 tons of VOC per 3-day completion
event.\83\
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    \83\ Emissions of VOC from hydraulically fractured subcategory 2
gas wells are subject to the current NSPS and are not included in
this action.
---------------------------------------------------------------------------

    In our analysis for the 2012 NSPS, we determined that a REC is not
an option for subcategory 2 wells because there is no infrastructure in
place to get the recovered gas to market or further processing.
Typically, these types of wells generally are not in proximity to
existing gathering lines at the time the well is completed. Therefore,
for these wells, the only potential control option identified (both
under the 2012 NSPS and under this action) is combustion of gases using
a completion combustion device, as described above. Also as explained
above, because of the high-volume, multiphase slug flow nature of the
flowback gas, water and sand, control by a traditional flare or other
control devices, such as vapor recovery units, is infeasible, since
these devices would be overcome by the erratic high-volume flow of
liquids, which leaves combustion as the only available control system
for subcategory 2 wells. As also discussed above, combustion can
present a fire hazard or other undesirable impacts in some situations.
In our review of white paper comment and other information for this
action, we found no information that would indicate this conclusion is
not still valid.
    Based on the 95 percent emission reduction of a completion
combustion device, the emission reductions for a subcategory 2
hydraulically fractured gas well completion or recompletion are
estimated to be 147.4 tons of methane per completion event.\84\ The
emission reductions for a subcategory 2 hydraulically fractured oil
well completion or recompletion event are estimated to be around 9.23
tons of methane and 7.73 tons of VOC per 3-day completion.
---------------------------------------------------------------------------

    \84\ Emissions of VOC from hydraulically fractured subcategory 2
gas wells are subject to the current NSPS and are not included in
this action.
---------------------------------------------------------------------------

    As noted above, for purposes of this action, we have identified in
section VIII.A two approaches (single pollutant and multipollutant
approaches) for evaluating whether the cost of a multipollutant control
is reasonable. As explained in that section, we believe that both
approaches are appropriate for assessing the reasonableness of the
multipollutant controls considered in this action. Therefore, we find
the cost of control to be reasonable as long as it is such under either
of these two approaches.
    Under the single pollutant approach, we assign all costs to the
reduction of

one pollutant and zero to all other pollutants simultaneously reduced.
For this approach, we would find the cost of control reasonable if it
is reasonable for reducing one pollutant alone. As shown in the
evaluation below, which assigns all the costs to methane reduction
alone, based on an average annual cost of $3,723 per completion, the
cost of control for a completion combustion device is estimated to be
$24 per ton of methane for subcategory 2 gas well completion event. We
find these costs to be reasonable for the amount of methane reduction
it can achieve. Also, because all the costs have been attributed to
methane reduction, the cost of the simultaneous VOC reduction is zero
and therefore reasonable.\85\ We estimate the cost of control for
subcategory 2 oil wells to be $403 per ton of methane and $481 per ton
of VOC per oil well completion. We consider these costs to be
reasonable considering the level of emissions reductions.
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    \85\ In 2012 we already found that the cost of this control to
be reasonable for reducing VOC emissions from hydraulically
fractured subcategory 2 gas well completions. We are not reopening
that decision in this action. Therefore, this cost finding is
relevant only to methane from hydraulically fractured subcategory 2
gas well completions.
---------------------------------------------------------------------------

    We also evaluated the cost of this control under the multipollutant
approach. Under this approach, the costs would be allocated based on
the estimated percentage reduction expected for each pollutant. Because
completion combustion devices reduces both methane and VOC by 95
percent, we attributed 50 percent of the costs to methane reduction and
50 percent of the cost to VOC reduction. The costs for methane
reduction would be half of the estimated costs under the first approach
above, for both gas and oil wells, which we have found to be
reasonable. See the TSD, available in the docket for this action, for a
detailed description of the cost of control analysis.
    Aside from the potential hazards associated with use of a
completion combustion device in some cases, we did not identify any
nonair environmental impacts, health or energy impacts associated with
completion combustion devices, therefore no analysis was completed.
However, completion combustion devices would produce combustion-related
air pollutants. For 870 subcategory 2 oil well completion\86\ for the
projected year 2020, we estimated that 66 tons of total hydrocarbons,
175 tons of carbon monoxide, 62,628 tons of carbon dioxide, 32 tons of
nitrogen oxides and 1 ton of particulate matter would be produced as
secondary emissions. This is based on the assumption that 95 percent of
flowback gas is combusted by the combustion device. This control option
is estimated to reduce emissions for the projected year 2020 by 135,516
tons of methane and 113,481 tons of VOC. Thus, we believe that the
benefit of the methane and VOC reduction far outweighs the secondary
impact of combustion-related pollutants as a result of completion
combustion control.
---------------------------------------------------------------------------

    \86\ Because subcategory 2 hydraulically fractured gas well
completions are subject to the current NSPS, we do not consider
secondary impacts for the destruction of methane under this action.
---------------------------------------------------------------------------

    We also identified in section VIII.A two additional approaches,
based on new capital expenditures and annual revenues, for evaluating
whether the costs are reasonable. For the capital expenditure analysis,
we used the capital expenditures for 2012 for NAICS 2111, 213111 and
213112 as reported in the U.S. Census data, which we believe are
representative of the production segment. The total capital cost for
complying with the proposed standards for subcategory 2 wells is 0.002
percent of the capital expenditures, which is well below the percentage
capital increase that courts have previously upheld as reasonable as
discussed in Section VIII.A.. For the total revenue analysis, we used
the revenues for 2012 for NAICS 211111, 211112 and 213112, which we
believe are representative of the production segment. The total
annualized cost for complying with the proposed standards is 0.001
percent of the total revenues, which is also very low.
    For all types of affected facilities in the production segment, the
total capital costs for complying with the proposed standards is 0.16
percent of the total capital expenditures, and the total annualized
costs for complying with the proposed standards is 0.13 percent of the
total revenues, which is also very low.
    In light of the above, we propose to determine that the BSER for
subcategory 2 wells would be use of a completion combustion device. As
we explained above, the gas is discharged at multiple locations during
flowback and is mixed with water and sand in multiphase slug flow and
therefore we determined that it is not feasible to set a numerical
performance standard.
    Pursuant to CAA section 111(h)(2), we are proposing an operational
standard for subcategory 2 well completions that would require
minimization of venting of gas and hydrocarbon vapors during the
completion operation through the use of a completion combustion device,
with provisions for venting in lieu of combustion for situations in
which combustion would present safety hazards or for periods when the
flowback gas is noncombustible. The owners and operators of these wells
also have a general duty to safely maximize resource recovery and
minimize releases to the atmosphere during flowback and subsequent
recovery.
    As with subcategory 1 wells, for the purposes of these standards we
have separated the flowback period into two stages, the ``initial
flowback stage'' and the ``separation flowback stage.'' During the
initial flowback stage, the requirements for the subcategory 2 wells
would be the same as the subcategory 1 wells. The flowback must be
routed to a storage vessel or to a well completion vessel that can be a
frac tank, a lined pit or any other vessel. During the initial flowback
stage, there is no requirement for controlling emissions from the
vessel, and any gas in the flowback during this stage may be vented.
    During the separation flowback stage, the operator must route all
salable quality gas from the separator to a gas flow line or collection
system, combust the gas, re-inject the gas into the well or another
well, use the gas as an on-site fuel source or use the gas for another
useful purpose that a purchased fuel or raw material would serve. No
direct venting of recovered gas is allowed during the separation
flowback stage except when combustion creates a fire or safety hazard
or can damage tundra, permafrost or waterways. During the separation
flowback stage, all liquids from the separator must be directed to a
storage vessel or to a well completion vessel, routed to a collection
system or re-injected into the well or another well.
    Consistent with requirements for subcategory 1 wells, owners or
operators of subcategory 2 wells would be required to document
completions and provide justification for periods when gas was vented
in lieu of combustion.
    We estimate that these control options for these sources would
reduce the total emissions from all hydraulically fractured and
refractured oil well completions for the projected year 2020 by 135,516
tons of methane and 113,481 tons of VOC. Thus, we believe that the
benefit of the methane and VOC reductions far outweigh the secondary
impact of combustion emissions formation during use of the completion
combustion operation.
    Several public and peer reviewer comments on the white paper noted
that these technologies are currently in regular use by industry to
control oil well completion and recompletion

emissions.\87\ In addition, these control technologies are the same as
those required in the 2012 NSPS to control completion emissions from
hydraulically fractured gas well completions.
---------------------------------------------------------------------------

    \87\ The EPA received six peer review comments and several
submissions of technical information and data on this paper,
available for review at http://www.epa.gov/airquality/oilandgas/whitepapers.html.
---------------------------------------------------------------------------

    The EPA is aware that oil wells cannot perform a REC if there is
not sufficient well pressure or gas content during the well completion
to operate the surface equipment required for a REC. In the 2012 NSPS
the EPA did not require low pressure gas wells to perform REC, but
operators were required to control those well completions using
combustion.\88\ We solicit comment on the types of oil wells that will
not be capable of performing a REC or combusting completion emissions
due to technical considerations such as low pressure or low gas
content, or other physical characteristics such as location, well
depth, length of hydraulic fracturing, or drilling direction (e.g.,
horizontal, vertical, directional).\89\ Additionally, we solicit
comment on all aspects of our proposal to regulate methane and VOC
emissions from hydraulically fractured oil well completions.
---------------------------------------------------------------------------

    \88\ Following publication of the 2012 NSPS, EPA received a
joint petition for administrative reconsideration of the rule. The
petitioners questioned the technical merits of the low pressure well
definition and asserted that the public had not had an opportunity
to comment on the definition. EPA re-proposed the definition of
''low pressure gas well,'' on March 23, 2015 (80 FR 15180), and took
comment on IPAA's alternative definition. EPA has finalized this
definition in a separate action.
    \89\ Many of these data are available in the DrillingInfo
database. More information is available at: http://info.drillinginfo.com.
---------------------------------------------------------------------------

    As shown in the analyses presented above, the BSER for
hydraulically fractured oil wells is the same as that for gas wells.
Accordingly, we are proposing to apply the current requirements for
hydraulically fractured gas well completions to hydraulically fractured
oil well completions. It is logical that the BSER analyses would result
in the same BSER determinations for hydraulically fractured gas and oil
wells, because the available options for controlling emissions and
their current use in the field are the same. Several public and peer
reviewer comments on the white paper noted that the control
technologies used for controlling emissions from hydraulically
fractured oil well completions are the same as those used for
completions of hydraulically fractured gas wells. The commenters
further noted that in many cases it is difficult to distinguish gas
wells from oil wells, because many wells produce both gas and oil.
Consistent standards for completions of hydraulically fractured gas
wells and completions of hydraulically fractured oil wells will remove
the need for operators to distinguish a gas well completion from an oil
well completion for the purposes of complying with subpart OOOO. This
change will improve the implementation of the standards by providing
greater certainty as to which well completions must comply with the
standards.
    We are requesting comment on excluding low production wells (i.e.,
those with an average daily production of 15 barrel equivalents or
less) \90\ from the standards for well completions. It is our
understanding that low production wells have inherently low emissions
from well completions and many are owned and operated by small
businesses. We are concerned about the burden of the well completion
requirement on small businesses, in particular where there is little
emission reduction to be achieved. We recognize that identification of
these wells prior to completion events is difficult. We believe that
drilling of a low production well may be unintentional and may be
infrequent, but production may nevertheless proceed due to economic
reasons. We solicit comment and information on emissions associated
with low production wells, characteristics of these wells and
supporting information that would help owners/operators and enforcement
personnel identify these wells prior to completion. In addition, we
understand that a daily average of 15 barrel equivalents is
representative of low production wells for some purposes, we solicit
comment on the appropriateness of this threshold for applying the
standards for well completions.
---------------------------------------------------------------------------

    \90\ For the purposes of this discussion, we define `low
production well' as a well with an average daily production of 15
barrel equivalents or less. This reflects the definition of a
stripper well property in IRC 613A(c)(6)(E).
---------------------------------------------------------------------------

    Further, we are proposing that wells with a gas-to-oil ratio (GOR)
of less than 300 scf of gas per barrel of oil produced would not be
affected facilities subject to the well completion provisions of the
NSPS.\91\ We solicit comment on whether a GOR of 300 is the appropriate
applicability threshold, and if the GOR of nearby wells would be a
reliable indicator in determining the GOR of a new or modified well.
The reason for the proposed threshold GOR of 300 is that separators
typically do not operate at a GOR less than 300, which is based on
industry experience rather than a vetted technical specification for
separator performance. Though, in theory, any amount of free gas could
be separated from the liquid, the reality is that this is not practical
given the design and operating parameters of separation units operating
in the field.
---------------------------------------------------------------------------

    \91\ On February 24, 2015, API submitted a comment to EPA
stating that oil wells with GOR values less than 300 do not have
sufficient gas to operate a separator. http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2014-0831-0137.
---------------------------------------------------------------------------

    We believe that having no threshold may create a significant burden
for operators to control emissions for these wells with just a trace of
gas. EIA data show that the number of ``oil only'' wells drilled from
2007-2012 was less than 20 percent.\92\ The potential emission
characteristic of oils with a GOR of 300 is relevant when deciding
whether this is a reasonable threshold. Primarily, the concern is
volatility. The threshold must be low enough that the oil produced is
considered non-volatile. Non-volatile ``black oils'' (oil likely to not
have gases or light hydrocarbons associated with it) are generally
defined as having GOR values in the range of 200 to 900.\93\ Therefore,
oil wells with GORs less than 300 are at the lower end of this range,
and will not likely have enough gas associated that it can be
separated. Therefore, the EPA is proposing that the NSPS requirements
for well completions do not apply to completions wells with hydraulic
fracturing that have a GOR of less than 300 scf/barrel.
---------------------------------------------------------------------------

    \92\ http://www.eia.gov/todayinenergy/detail.cfm?id=13571#.
    \93\ http://petrowiki.org/Oil_fluid_characteristics.
---------------------------------------------------------------------------

    We are soliciting comment on whether the well completion provisions
of the proposed rule can be implemented on the effective date of the
rule in the event of potential shortage of REC equipment and, if not,
how a phase in could be structured. We believe that there will be a
sufficient supply of REC equipment available by the time the NSPS
becomes effective. However, we request comment on whether sufficient
supply of this equipment and personnel to operate it will be available
to accommodate the increased number of RECs by the effective date of
the NSPS. We also request specific estimates of how much time would be
required to get enough equipment in operation to accommodate the full
number of RECs performed annually. In the event that public comments
indicate that available equipment would likely be insufficient to
accommodate the increase in number of REC performed, we are considering
phasing in requirements for well completions in the final rule. Such a
phased in approach could be structured

to provide for control of the highest emitting wells first, with other
wells being included at a later date. We solicit comment on whether GOR
of the well and production level of the well should be bases for the
phasing of requirements for RECs. We also solicit suggestions for other
ways to address a potential short-term REC equipment shortage that may
hinder operators' compliance with the proposed NSPS. Additionally, we
solicit comment on what an appropriate threshold should be for low
production wells.
    Finally, we solicit comment on criteria that could help clarify
availability of gathering lines. Availability of a gathering line is
one consideration affecting feasibility of recovery of natural gas
during completion of hydraulically fractured wells. There are several
factors that can affect availability of a gathering line including, but
not limited to, the capacity of an existing gathering line to accept
additional throughput, the ability of owners and operators to obtain
rights of way to cross properties, and the distance from the well to an
existing gathering line. We are aware that some states require
collection of gas if a gathering line is present within a specific
distance from the well. For example, Montana allows gas from wells to
be flared only in cases where the well is farther than one-half mile
from a gas pipeline.\94\ We solicit comment on whether distance from a
gathering line is a valid criterion on which to base requirements for
gas recovery and, if so, what would an appropriate distance for such a
threshold. In addition, we solicit comment on any other factors that
could be specified in the NSPS for requiring recovery of gas from well
completions.
---------------------------------------------------------------------------

    \94\ Administrative Rules of Montana (ARM) Title 17 Chapter 8
Air Quality Subchapter 16--Emission Control Requirements for Oil and
Gas Well Facilities Operating Prior to Issuance of a Montana Air
Quality Permit. Emission Control Requirements, 17.8.1603 Available
at: http://www.deq.mt.gov/dir/legal/Chapters/Ch08-toc.mcpx.
---------------------------------------------------------------------------

3. Use of a Separator During Flowback
    For subcategory 1, subcategory 2 and low pressure gas wells, the
current NSPS at Sec.  60.5375(a) and (f) requires routing of flowback
to a separator unless it is technically infeasible for a separator to
function. The NSPS also provides in Sec.  60.5375(f) that subcategory 2
and low pressure wells are required to control emissions through
combustion using a completion combustion device (which can include a
pit flare) rather than being required to perform a REC. It was our
understanding that a separator could be used at some point during the
flowback period of every well completion. Recent information indicates
that some wells, because of certain characteristics of the reservoir,
do not need to employ a separator. In those cases, we understand that
operators direct the flowback to a pit and can combust gas contained in
the flowback as it emerges from the pipe. At some point, after the well
has flowed sufficiently to clean up the wellbore and the gas is of
salable quality, production begins or the well is temporarily shut in.
As a result of this new information, our initial understanding may not
apply.
    We solicit comment on (1) the role of the separator in well
completions and whether a separator can be employed for every well
completion; and (2) the appropriate relationship of the separator in
the context of our requirements that cover a very broad spectrum of
wells. We solicit further information that would help inform our
consideration of this issue as we seek to ensure we have adequately
established appropriate requirements for all well completions subject
to the NSPS.

G. Proposed Standards for Fugitive Emissions From Well Sites and
Compressor Stations

    In April 2014, the EPA published the white paper titled ``Oil and
Natural Gas Sector Leaks'' \95\ which summarized the EPA's current
understanding of fugitive emissions of methane and VOC at onshore oil
and natural gas production, processing, and transmission and storage
facilities. The white paper also outlined our understanding of the
mitigation techniques (practices and technology) available to reduce
these emissions along with the cost and effectiveness of these
practices and technologies.
---------------------------------------------------------------------------

    \95\ Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks.pdf.
---------------------------------------------------------------------------

    The detection of fugitive emissions from oil and natural gas well
sites and compressor stations, which are comprised of compressors at
natural gas transmission, storage, gathering and boosting stations, can
be determined using several technologies. Historically, fugitive
emissions were detected using sensory monitoring (e.g., visual,
olfactory or sound) or EPA Method 21 to determine if a leak exceeded a
set threshold (e.g., the leak concentration was greater than the leak
definition for the component). As described in the white paper, we
found that many fugitive emission surveys are now conducted using OGI
in the oil and natural gas source category, a technology that provides
a visible image of gas emissions or leaks to the atmosphere. The OGI
instrument works by using spectral wavelength filtering and an array of
infrared detectors to visualize the infrared absorption of hydrocarbons
and other gaseous compounds. As the gas absorbs radiant energy at the
same waveband that the filter transmits to the detector, the gas and
motion of the gas is imaged. The OGI instrument can be used for
monitoring a large array of components at a facility and is an
effective means of detecting fugitive emissions when the technology is
used appropriately.
    Several studies in the white paper estimated that OGI can monitor
1,875-2,100 components per hour. In comparison, the average screening
rate using a Method 21 instrument (e.g., organic vapor analyzer, flame
ionization detector, flow measurement devices) is roughly 700
components per day. However, the EPA's recent work with OGI instruments
suggests these studies underestimate the amount of time necessary to
thoroughly monitor components for fugitive emissions using OGI
instruments. Even though the amount of time may be underestimated, we
believe the use of OGI can reduce the amount of time necessary to
conduct fugitive emissions monitoring since multiple fugitive emissions
components can be surveyed simultaneously, thus reducing the cost of
identifying fugitive emissions in upstream oil and natural gas
facilities when compared to using a handheld TVA or OVA, which requires
a manual screening of each fugitive emissions component.
1. Fugitive Emissions From Well Sites
    Fugitive emissions may occur for many reasons at well sites such as
when connection points are not fitted properly, thief hatches are not
properly weighted or sealed or when seals and gaskets start to
deteriorate. Changes in pressure or mechanical stresses can also cause
fugitive emissions. Potential sources of fugitive emissions, fugitive
emissions components, include agitator seals, connectors, pump
diaphragms, flanges, instruments, meters, open-ended lines, pressure
relief devices, pump seals, valves or open thief hatches or holes in
storage vessels, pressure vessels, separators, heaters and meters. For
purposes of this proposed rule, fugitive emissions do not include
venting emissions from devices that vent as part of normal operations,
such as gas-driven pneumatic controllers or gas-driven pneumatic pumps.
    Based on our review of the public and peer review comments on the
white paper and the Colorado and Wyoming state rules, we believe that
there are two options for reducing methane and VOC fugitive emissions
at well sites: (1) A

fugitive emissions monitoring program based on individual component
monitoring using EPA Method 21 for detection combined with repairs, or
(2) a fugitive emissions monitoring program based on the use of OGI
detection combined with repairs. Several public and peer reviewer
comments on the white paper noted that these technologies are currently
used by industry to reduce fugitive emissions from the production
segment in the oil and natural gas industry.
    Each of these control options are evaluated below based on varying
the frequency of conducting the survey and fugitive emissions repair
threshold (e.g., the specified concentration when using Method 21 or
visible identification of methane or VOC when an OGI instrument is
used). For our analysis, we considered quarterly, semiannual and annual
survey frequency. For Method 21 monitoring and repair, we considered
10,000 ppm, 2,500 ppm and 500 ppm fugitive repair thresholds. The leak
definition concentrations for other NSPS referencing Method 21 range
from 500-10,000 ppm. Therefore, we selected 500 ppm, 2,500 ppm and
10,000 ppm. For OGI, we considered visible emissions as the fugitive
repair threshold (i.e., emissions that can be seen using OGI
instrumentation). EPA's recent work with OGI indicates that fugitive
emissions at a concentration of 10,000 ppm are generally detectable
using OGI instrumentation provided that the right operating conditions
(e.g., wind speed and background temperature) are present. Work is
ongoing to determine the lowest concentration that can be reliably
detected using OGI.\96\
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    \96\ Draft Technical Support Document Appendices, Optical Gas
Imaging Protocol (40 CFR part 60, Appendix K), August 11, 2015.
---------------------------------------------------------------------------

    In order to estimate fugitive methane and VOC emissions from well
sites, we used fugitive emissions component counts from the GRI/EPA
report \97\ for natural gas production well sites, and fugitive
emissions component counts from the GHG inventory and API for oil
production well sites. The types of production equipment located at
natural gas production well pads include: Gas wellheads, separators,
meters/piping, heaters, and dehydrators. The types of oil well
production equipment include: Oil well heads, separators, headers and
heater/treaters. The types of fugitive emissions components that are
associated with both oil and natural gas wells include but are not
limited to: Valves, connectors, open-ended lines and valves (OEL), and
pressure relief device (PRD). Fugitive emissions component counts for
each piece of equipment in the gas production segment were calculated
using the average fugitive emissions component counts in the Eastern
U.S. and the Western U.S. from the EPA/GRI report. These data were used
to develop a natural gas well site model plant. Fugitive emissions
components counts for these equipment types in the oil production
segment were obtained from an American Petroleum Institute (API)
workbook.\98 \These data were used to develop an oil production well
site model plant.
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    \97\ Gas Research Institute/U.S. Environmental Protection
Agency, Research and Development, Methane Emission Factors from the
Natural Gas Industry, Volume 8, Equipment Leaks, June 1996 (EPA-600/
R-96-080h).
    \98\ API Workbook 4638, 1996.
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    Since we have emission factors for only a subset of the components
which are possible sources for fugitive emissions, our emission
estimates are believed to be lower than the emissions profile for the
entire set of fugitive emissions components that would typically be
found at a well site.
    The fugitive emission factors from AP-42,\99\ which provided a
single source of total organic compounds (TOC) emission factors that
include non-VOCs, such as methane and ethane, were used to estimate
emissions and evaluate the cost of control of a fugitive emissions
program for oil and natural gas production well sites. Using the AP-42
factors, the methane and VOC fugitive emissions from a natural gas well
site are estimated to be 4.5 tpy and 1.3 tpy, respectively. For an oil
production well site, the estimated fugitive methane and VOC emissions
are 1.1 tpy and 0.3 tpy, respectively. The calculation of these
emission estimates are explained in detail in the background TSD for
this proposal available in the docket.
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    \99\ U.S. Environmental Protection Agency, Protocol for
Equipment Leak Emission Estimates, Table 2-4, November 1995 (EPA-
453/R-95-017).
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    Information in the white paper related to the potential emission
reductions from the implementation of an OGI monitoring program varied
from 40 to 99 percent. The causes for this range in reduction
efficiency were the frequency of monitoring surveys performed and
different assumptions made by the study authors. According to the
calculations, which are based on uncontrolled emission factors for well
pads contained within the EPA Oil and Natural Gas Sector Technical
Support Document (2011), the Colorado Air Quality Control Commission,
Initial Economic Impact Analysis for Proposed Revisions to Regulation
Number 7 (5 CCR 1001-9) and the FINAL ECONOMIC IMPACT ANALYSIS For
Industry's Proposed Revisions to Colorado Air Quality Control
Commission Regulation Number 3, 6, and 7 (5 CCR 1001-9) (January 30,
2014), a quarterly monitoring program in combination with a repair
program can reasonably be expected to reduce fugitive methane and VOC
emissions at well sites by 80 percent. Although information in the
white paper indicated emission reductions as high as 99 percent may be
achievable with OGI, we do not believe such levels can be consistently
achieved for all of types of components that may be subject to a
fugitive emissions monitoring program. Therefore, using engineering
judgement and experience obtained through our existing programs for
finding and repairing leaking components, we selected 80 percent as an
emission reduction level that can reasonably be expected to be achieved
with a quarterly monitoring program. Due to the increased amount of
time between each monitoring survey and subsequent repair, we believe
that the level of emissions reduction achieved by less frequent
monitoring surveys will be reduced from this level. Therefore, we
assigned an emission reduction of 60 percent to semiannual monitoring
survey and repair frequency and 40 percent to annual frequency,
consistent with the reduction levels used by the Colorado Air Quality
Control Commission in their initial and final economic impacts
analyses. We solicit comment on the appropriateness of the percentage
of emission reduction level that can be reasonably expected to be
achieved with quarterly, semiannual, and annual monitoring program
frequencies.
    For Method 21, we estimated emissions reductions using The EPA
Equipment Leaks Protocol document, which provides emissions factor data
based on leak definition and monitoring frequencies primarily for the
Synthetic Organic Chemical Manufacturing Industry (SOCMI) and Petroleum
Refining Industry along with the emissions rates contained within the
Technology Review for Equipment Leaks document.\100\ We used these data
along with the monitoring frequency (e.g., annual, semiannual, and
quarterly) at fugitive repair thresholds at 500, 2,500 and 10,000 ppm
to determine uncontrolled emissions. Using this information we
calculated an expected

emissions reduction percentage for each of the combinations of
monitoring frequency and repair threshold.
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    \100\ Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI
International, Analysis of Emission Reduction Techniques for
Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180.
---------------------------------------------------------------------------

    We also looked at the costs of a monitoring and repair program
under various monitoring frequencies and repair thresholds (for Method
21), including the cost of OGI monitoring survey, repair, monitoring
plan development, and the cost-effectiveness of the various
options.\101\ For purposes of this action, we have identified in
section VIII.A two approaches (single and multipollutant approaches)
for evaluating the cost-effectiveness of a multipollutant control, such
as the fugitive emissions monitoring and repair programs identified
above for reducing both methane and VOC emissions. As explained in that
section, we believe that both the single and multipollutant approaches
are appropriate for assessing the reasonableness of the multipollutant
controls considered in this action. Therefore, we find the cost of
control to be warranted as long as it is such under either of these two
approaches.
---------------------------------------------------------------------------

    \101\ See pages 68-69 of the TSD.
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    Under the first approach (single pollutant approach), we assign all
costs to the reduction of one pollutant and zero to all other
pollutants simultaneously reduced. Under the second approach
(multipollutant approach), we allocate the annualized cost across the
pollutant reductions addressed by the control option in proportion to
the relative percentage reduction of each pollutant controlled. In the
multipollutant approach, since methane and VOC emissions are controlled
proportionally equal, half the cost is apportioned to the methane
emission reductions and half the cost is apportioned to the VOC
emission reductions. In this evaluation, we evaluated both approaches
across the range of identified monitoring survey options: OGI
monitoring and repair performed quarterly, semiannually and annually;
and Method 21 performed quarterly, semiannually and annually, with a
fugitive emissions repair threshold of 500, 2,500 and 10,000 ppm at
each frequency. The calculation of the costs, emission reductions, and
cost of control for each option are explained in detail in the TSD. As
shown in the TSD, while the costs for repairing components that are
found to have fugitive emissions during a fugitive monitoring survey
remain the same, the annual repair costs will differ based on
monitoring frequency.
    As shown in our TSD, both OGI and Method 21 monitoring survey
methodologies costs generally increase with increasing monitoring
frequency (i.e., quarterly monitoring has a higher cost of control than
annual monitoring). For EPA Method 21 specifically, the cost also
increases with decreasing fugitive emissions repair threshold (i.e.,
500 ppm results in a higher cost of control than 10,000 ppm). However,
as shown in the TSD, the cost of control based on the OGI methodology
for annual, semiannual, and quarterly monitoring frequencies for a
model well site are estimated to be more cost-effective than Method 21
for those same monitoring frequencies.\102\ We therefore focus our BSER
analysis based on the use of OGI.
---------------------------------------------------------------------------

    \102\ See the 2015 TSD for full comparison.
---------------------------------------------------------------------------

    For the reasons stated below, we find that the control cost based
on quarterly monitoring using OGI may not be cost-effective based on
the information available. As shown in the TSD, under the single
pollutant approach, if all costs are assigned to methane and zero to
VOC reduction, the cost is $3,753 per ton of methane reduced, and
$3,521 per ton if savings of the natural gas recovered is taken into
account. If all costs are assigned to VOC and zero to methane
reduction, the cost is $13,502 per ton of VOC reduced, and $12,668 per
ton if savings of the natural gas recovered is taken into account.
Under the multipollutant approach, the cost of control for VOC based on
quarterly monitoring is $6,751 per ton, and $6,334 per ton of VOC
reduced if savings are considered. In a previous NSPS rulemaking [72 FR
64864 (November 16, 2007)], we had concluded that a VOC control option
was not cost-effective at a cost of $5,700 per ton. In light of the
above, we find that the cost of monitoring/repair based on quarterly
monitoring at well sites using OGI is not cost-effective for reducing
VOC and methane emissions under either approach. Having found the
control cost using OGI based on quarterly monitoring not to be cost-
effective, we now evaluate the control cost based on annual and semi-
annual monitoring using OGI. As shown in the TSD, the costs between
annual and semi-annual monitoring are comparable. Because semi-annual
monitoring achieves greater emissions reduction, we focus our analysis
on the cost based on semi-annual monitoring.
    While the cost appears high under the single pollutant approach, we
find the costs to be reasonable under the multipollutant approach for
the following reasons. As shown in the TSD, for VOC reduction, the cost
is $4,979 per ton; when savings of the natural gas recovered are taken
into account, the cost is reduced to $4,562 per ton. For methane
reduction, the control cost is $1,384 per ton; when cost savings of the
natural gas recovered is taken into account, the cost is reduced to
$1,268 per ton. As explained above, we believe that we have
underestimated the emissions from these well sites; therefore, we
believe the use of OGI is more cost-effective than the amount presented
here. Furthermore, while being used to survey fugitive components at a
well site, the OGI may potentially help an owner and operator detect
and repair other sources of visible emissions not covered by the NSPS.
One example would be an intermittently acting pneumatic controller that
is stuck open. The OGI could help the owner and operator detect and
address and reduce such inadvertent emissions, resulting in more cost
saving from more natural gas recovered.
    We also identified in section VIII.A two additional approaches,
based on new capital expenditures and annual revenues, for evaluating
whether the costs are reasonable. For monitoring and repair of fugitive
emissions at well sites, we believe that the total revenue analysis is
more appropriate than the capital expenditure analysis and therefore we
did not perform the capital expenditure analysis. For the total revenue
analysis, we used the revenues for 2012 for NAICS 211111, 211112 and
213112, which we believe are representative of the production segment.
The total annualized costs for complying with the proposed standards is
0.085 percent of the total revenues, which is very low.
    For all types of affected facilities in the production, the total
annualized costs for complying with the proposed standards is 0.13
percent of the total revenues, which is also very low.
    For the reasons stated above, we find the cost of monitoring and
repairing fugitive emissions at well sites based on semi-annual
monitoring using OGI to be reasonable. To ensure that no fugitive
emissions remain, a resurvey of the repaired components is necessary.
We expect that most of the repair and resurveys are conducted at the
same time as the initial monitoring survey while OGI personnel are
still on-site. However, there may be some components that cannot not be
repaired right away and in some instances not until after the initial
OGI personnel are no longer on site. In that event, resurvey with OGI
would require rehiring OGI personnel, which would make the resurvey not
cost effective. On the other hand, as shown in TSD, the cost of
conducting resurvey using Method 21 is $2 per component, which is
reasonable.

    We did not find any nonair quality health and environmental
impacts, or energy requirements associated with the use of OGI or
Method 21 for monitoring, repairing and resurvey fugitive components at
well sites. Based on the above analysis, we believe that the BSER for
reducing fugitive methane and VOC emissions at well sites is a
monitoring and repair standard based on semi-annual monitoring using
OGI and resurvey using Method 21.
    As mentioned above, OGI monitoring requires trained OGI personnel
and OGI instruments. Many owners and operators, in particular small
businesses, may not own OGI instruments or have staff who are trained
and qualified to use such instruments; some may not have the capital to
acquire the OGI instrument or provide training to their staff. While
our cost analysis takes into account that owners and operators may need
to hire contractors to perform the monitoring survey using OGI, we do
not have information on the number of available contractors and OGI
instruments. In light of our estimated 20,000 active wells in 2012 and
that the number will increase annually, we are concerned that some
owners and operators, in particular small businesses, may have
difficulty securing the requisite OGI contractors and/or OGI
instrumentation to perform monitoring surveys on a semi-annual basis.
Larger companies, due to the economic clout they have by offering the
contractors more work due to the higher number of wells they own, may
preferentially retain the services of a large portion of the available
contractors. This may result in small businesses experiencing a longer
wait time to obtain contractor services. In light of the potential
concern above, we are co-proposing monitoring survey on an annual basis
at the same time soliciting comment and supporting information on the
availability of trained OGI contractors and OGI instrumentation to help
us evaluate whether owners and operators would have difficulty
acquiring the necessary equipment and personnel to perform a semi-
annual monitoring and, if so, whether annual monitoring would alleviate
such problems.
    Recognizing that additional data may be available, such as
emissions from super emitters that may have higher emission factors
than those considered in this analysis, we are also taking comment on
requiring monitoring survey on a quarterly basis.
    CAA section 111(h)(1) states that the Administrator may promulgate
a work practice standard or other requirements, which reflects the best
technological system of continuous emission reduction when it is not
feasible to enforce an emission standard. CAA section 111(h)(2) defines
the phrase ``not feasible to prescribe or enforce an emission
standard'' as follows:

[A]ny situation in which the Administrator determines that (A) a
hazardous air 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 and economic
limitations.

    The work practice standards for fugitive emissions from well sites
are consistent with CAA section 111(h)(1)(A), because no conveyance to
capture fugitive emissions exist for fugitive emissions components at a
well site. In addition, OGI does not measure the extent the fugitive
emissions from fugitive emissions components. For the reasons stated
above, pursuant to CAA section 111(h)(1)(b), we are proposing work
practice standards for fugitive emissions from the collection of
fugitive emission components at well sites.
    The proposed work practice standards include details for
development of a fugitive emissions monitoring plan, repair
requirements and recordkeeping and reporting requirements. The fugitive
emissions monitoring plan includes operating parameters to ensure
consistent and effective operation for OGI such as procedures for
determining the maximum viewing distance and wind speed during
monitoring. The proposed standards would require a source of fugitive
emissions to be repaired or replaced as soon as practicable, but no
later than 15 calendar days after detection of the fugitive emissions.
We have historically allowed 15 days for repair/resurvey in LDAR
programs, which appears to be sufficient time. Further, in light of the
number of components at a well site and the number that would need to
be repaired, we believe that 15 days is also sufficient for conducting
the required repairs under the proposed fugitive emission
standards.\103\ That said, we are also soliciting comment on whether 15
days is an appropriate amount of time for repair of sources of fugitive
emissions at well sites.\104\
---------------------------------------------------------------------------

    \103\ In our TSD we estimate the number of fugitive emissions
components to be around 700 and of those components we estimate that
about 1 percent would need to be repaired.
    \104\ This timelines is consistent with the timeline originally
established in 1983 under 40 CFR part 60 subpart VV.
---------------------------------------------------------------------------

    Many recent studies have shown a skewed distribution for emissions
related to leaks, where a majority of emissions come from a minority of
sources.\105\ Commenters on the white papers agreed that emissions from
equipment leaks exhibit a skewed distribution, and pointed to other
examples of data sets in which the majority of fugitive methane and VOC
emissions come from a minority of components (e.g., gross emitters).
Based on this information, we solicit comment on whether the fugitive
emissions monitoring program should be limited to ``gross emitters.''
---------------------------------------------------------------------------

    \105\
---------------------------------------------------------------------------

    We believe that a properly maintained facility would likely detect
very little to no fugitive emissions at each monitoring survey, while a
poorly maintained facility would continue to detect fugitive emissions.
As shown in our TSD, we estimate the number of fugitive emission
components at a well site to be around 700. We believe that a facility
with proper operation would likely find one to three percent of
components to have fugitive emissions. To encourage proper maintenance,
we are proposing that the owner or operator may go to annual monitoring
if the initial two consecutive semiannual monitoring surveys show that
less than one percent of the collection of fugitive emissions
components at the well site has fugitive emissions. For the same
reason, we are proposing that the owner or operator conduct quarterly
monitoring if the initial two semi-annual monitoring surveys show that
more than three percent of the collection of fugitive emissions
components at the well site has fugitive emissions. We believe the
first year to be the tune-up year to allow owners and operators the
opportunity to refine the requirements of their monitoring/repair plan.
After that initial year, the required monitoring frequency would be
annual if a monitoring survey shows less than one percent of components
to have fugitive emissions; semi-annual if one to three percent of
total components have fugitive emissions; and quarterly if over three
percent of total components have fugitive emissions. We solicit comment
on this approach, including the percentage used to adjust the
monitoring frequency. We also solicit comment on the appropriateness of
performance based monitoring frequencies. We also solicit comment on
the appropriateness of triggering different monitoring frequencies
based on the percentage of components with fugitive emissions. Under
the proposed standards, the affected facility would be

defined as the collection of fugitive emissions components at a well
site. To clarify which components are subject to the fugitive emissions
monitoring provisions, we propose to add a definition to Sec.  60.5430
---------------------------------------------------------------------------
for ``fugitive emissions component'' as follows:

    Fugitive emissions component means any component that has the
potential to emit fugitive emissions of methane or VOC at a well
site or compressor station site, including but not limited to
valves, connectors, pressure relief devices, open-ended lines,
access doors, flanges, closed vent systems, thief hatches or other
openings on a storage vessels, agitator seals, distance pieces,
crankcase vents, blowdown vents, pump seals or diaphragms,
compressors, separators, pressure vessels, dehydrators, heaters,
instruments, and meters. Devices that vent as part of normal
operations, such as a natural gas-driven pneumatic controllers or
natural gas-driven pumps, are not fugitive emissions components,
insofar as the natural gas discharged from the device's vent is not
considered a fugitive emission. Emissions originating from other
than the vent, such as the seals around the bellows of a diaphragm
pump would be considered fugitive emissions.

Thus, all fugitive emissions components at the affected facility would
be monitored for fugitive emissions of methane and VOC.
    For the reasons stated in section VII.G.1, for purposes of the
proposed standards for fugitive emissions at well sites, modification
of a well site is defined as when a new well is drilled or a well at
the well site (where collection of fugitive emissions components are
located) is hydraulically fractured or refractured. As explained in
that section, other than these events, we are not aware of any other
physical change to a well site that would result in an increase in
emissions from the collection of fugitive components at such well site.
To clarify and ease implementation, we propose to define
``modification'' to include only these two events for purposes of the
fugitive emissions provisions at well sites.
    In the 2012 NSPS, we provided that completion requirements do not
apply to refracturing of an existing well that is completed responsibly
(i.e. green completions). Building on the 2012 NSPS, the EPA intends to
continue to encourage corporate-wide voluntary efforts to achieve
emission reductions through responsible, transparent and verifiable
actions that would obviate the need to meet obligations associated with
NSPS applicability, as well as avoid creating disruption for operators
following advanced responsible corporate practices. It has come to our
attention that some owners and operators may already have in place, and
are implementing, corporate-wide fugitive emissions monitoring and
repair programs at their well sites that are equivalent to, or more
stringent than our proposed standards. Such corporate efforts present
the potential to further the development of LDAR technologies. To
encourage companies to continue such good corporate policies and
encourage advancement in the technology and practices, we solicit
comment on criteria we can use to determine whether and under what
conditions well sites operating under corporate fugitive monitoring
programs can be deemed to be meeting the equivalent of the NSPS
standards for well site fugitive emissions such that we can define
those regimes as constituting alternative methods of compliance or
otherwise provide appropriate regulatory streamlining. We also solicit
comment on how to address enforceability of such alternative approaches
(i.e., how to assure that these well sites are achieving, and will
continue to achieve, equal or better emission reduction than our
proposed standards). We recognize that meeting an NSPS performance
level should not, standing alone, be a basis for a source not becoming
an affected facility.
    For the reasons stated above, we are also soliciting comments on
criteria we can use to determine whether and under what conditions all
new or modified well sites operating under corporate fugitive
monitoring programs can be deemed to be meeting the equivalent of the
NSPS standards for well sites fugitive emissions such that we can
define those regimes as constituting alternative methods of compliance
or otherwise provide appropriate regulatory streamlining. We also
solicit comment on how to address enforceability of such alternative
approaches (i.e., how to assure that these well sites are achieving,
and will continue to achieve, equal or better emission reduction than
our proposed standards).
    We are requesting comment on whether the fugitive emissions
requirements should apply to all fugitive emissions components at
modified well sites or just to those components that are connected to
the fractured, refractured or added well. For some modified well sites,
the fractured or refractured or added well may only be connected to a
subset of the fugitive emissions components on site. We are soliciting
comment on whether the fugitive emission requirements should only apply
to that subset. However, we are aware that the added complexity of
distinguishing covered and non-covered sources may create difficulty in
implementing these requirements. However, we note that it may be
advantageous to the operator from an operational perspective to monitor
all the components at a well site since the monitoring equipment is
already onsite.
    As explained above, Method 21 is not as cost-effective as OGI for
monitoring. That said, there may be reasons why and owner and operator
may prefer to use Method 21 over OGI. While we are confident with the
ability of Method 21 to detect fugitive emissions and therefore
consider it a viable alternative to OGI, we solicit comment on the
appropriate fugitive emissions repair threshold for Method 21
monitoring surveys. As mentioned above, EPA's recent work with OGI
indicates that fugitive emissions at a concentration of 10,000 ppm is
generally detectable using OGI instrumentation provided that the right
operating conditions (e.g., wind speed and background temperature) are
present. Work is ongoing to determine the lowest concentration that can
be reliably detected using OGI As mentioned above, we believe that OGI.
In light of the above, we solicit comment on whether the fugitive
emissions repair threshold for Method 21 monitoring surveys should be
set at 10,000 ppm or whether a different threshold is more appropriate
(including information to support such threshold).
    While we did not identify OGI as the BSER for resurvey because of
the potential cost associated with rehiring OGI personnel, there is no
such additional cost for those who either own the OGI instrument or can
perform repair/resurvey at the same time. Therefore, the proposed rule
would allow the use either OGI or Method 21 for resurvey. When Method
21 is used to resurvey components, we are proposing that the component
is repaired if the Method 21 instrument indicates a concentration less
than 500 ppm above background. This has been historically used in other
LDAR programs as an indicator of no detectable emissions.
    The proposed standards would require that operators begin
monitoring fugitive emissions components at a well site within 30 days
of the initial startup of the first well completion for a new well or
within 30 days of well site modification. We are proposing a 30 day
period to allow owners and operators the opportunity to secure
qualified contractors and equipment necessary for the initial
monitoring survey. We are requesting comment on whether 30 days is an
appropriate amount of time to

begin conducting fugitive emissions monitoring.
    We received new information indicating that some companies could
experience logistical challenges with the availability of OGI
instrumentation and qualified OGI technicians and operators to perform
monitoring surveys and in some instances repairs. We solicit comment on
both the availability of OGI instruments and the availability of
qualified OGI technicians and operators to perform surveys and repairs.
    We are proposing to exclude low production well sites (i.e., a low
production site is defined by the average combined oil and natural gas
production for the wells at the site being less than 15 barrels of oil
equivalent (boe) per day averaged over the first 30 days of production)
\106\ from the standards for fugitives emissions from well sites. We
believe the lower production associated with these wells would
generally result in lower fugitive emissions. It is our understanding
that fugitive emissions at low production well sites are inherently low
and that such well sites are mostly owned and operated by small
businesses. We are concerned about the burden of the fugitive emission
requirement on small businesses, in particular where there is little
emission reduction to be achieved. To more fully evaluate the
exclusion, we solicit comment on the air emissions associated with low
production wells, and the relationship between production and fugitive
emissions. Specifically, we solicit comment on the relationship between
production and fugitive emissions over time. While we have learned that
a daily average of 15 barrel per day is representative of low
production wells, we solicit comment on the appropriateness of this
threshold for applying the standards for fugitive emission at well
sites. Further, we solicit comment on whether EPA should include low
production well sites for fugitive emissions and if these types of well
sites are not excluded, should they have a less frequent monitoring
requirement.
---------------------------------------------------------------------------

    \106\ For the purposes of this discussion, we define `low
production well' as a well with an average daily production of 15
barrel equivalents or less. This reflects the definition of a
stripper well property in IRC 613A(c)(6)(E).
---------------------------------------------------------------------------

    We are also requesting comment on whether there are well sites that
have inherently low fugitive emissions, even when a new well is drilled
or a well site is fractured or refractured and, if so, descriptions of
such type(s) of well sites. The proposed standards are not intended to
cover well sites with no fugitive emissions of methane or VOC. We are
aware that some sites may have inherently low fugitive emissions due to
the characteristics of the site, such as the gas to oil ratio of the
wells or the specific types of equipment located on the well site. We
solicit comment on these characteristics and data that would
demonstrate that these sites have low methane and VOC fugitive
emissions.
    We are requesting comment on whether there are other fugitive
emission detection technologies for fugitive emissions monitoring,
since this is a field of emerging technology and major advances are
expected in the near future. We are aware of several types of
technologies that may be appropriate for fugitive emissions monitoring
such as Geospatial Measurement of Air Pollutants using OTM-33
approaches (e.g., Picarro Surveyor), passive sorbent tubes using EPA
Methods 325A and B, active sensors, gas cloud imaging (e.g., Rebellion
photonics), and Airborne Differential Absorption Lidar (DIAL).
Therefore, we are specifically requesting comments on details related
to these and other technologies such as the detection capability; an
equivalent fugitive emission repair threshold to what is required in
the proposed rule for OGI; the frequency at which the fugitive
emissions monitoring surveys should be performed and how this frequency
ensures appropriate levels of fugitive emissions detection; whether the
technology can be used as a stand-alone technique or whether it must be
used in conjunction with a less frequent (and how frequent) OGI
monitoring survey; the type of restrictions necessary for optimal use;
and the information that is important for inclusion in a monitoring
plan for these technologies.
2. Fugitive Emissions From Compressor Stations
    Fugitive emissions at compressor stations in the oil and natural
gas source category may occur for many reasons (e.g., when connection
points are not fitted properly, or when seals and gaskets start to
deteriorate). Changes in pressure and mechanical stresses can also
cause fugitive emissions. Potential sources of fugitive emissions
include agitator seals, distance pieces, crank case vents, blowdown
vents, connectors, pump seals or diaphragms, flanges, instruments,
meters, open-ended lines, pressure relief devices, valves, open thief
hatches or holes in storage vessels, and similar items on glycol
dehydrators (e.g., pumps, valves, and pressure relief devices).
Equipment that vents as part of normal operations, such as gas driven
pneumatic controllers, gas driven pneumatic pumps or the normal
operation of blowdown vents are not considered to be sources of
fugitive emissions.
    Based on our review of the public and peer review comments on the
white paper and the Colorado and Wyoming state rules, we believe that
there are two options for reducing methane and VOC fugitive emissions
at compressor stations: (1) A fugitive emissions monitoring program
based on individual component monitoring using EPA Method 21 for
detection combined with repairs, or (2) a fugitive emissions monitoring
program based on the use of OGI detection combined with repairs.
Several public and peer reviewer comments on the white paper noted that
these technologies are currently used by industry to reduce fugitive
emissions from the production segment in the oil and natural gas
industry.
    Each of these control options are evaluated below based on varying
the frequency of conducting the monitoring survey and fugitive
emissions repair threshold (e.g., the specified concentration when
using Method 21 or visible identification of methane or VOC when an OGI
instrument is used). For our analysis, we considered quarterly,
semiannual and annual monitoring frequencies. For Method 21, we
considered 10,000 ppm, 2,500 ppm and 500 ppm fugitive repair
thresholds. The leak definitions for other NSPS referencing Method 21
range from 500-10,000 ppm. Therefore, we selected 500 ppm, 2,500 ppm
and 10,000 ppm. For OGI, we considered visible emissions as the
fugitive repair threshold (i.e., emissions that can be seen using OGI).
EPA's recent work with OGI indicate that fugitive emissions at a
concentration of 10,000 ppm are generally detectable using OGI
instrumentation, provided that the right operating conditions (e.g.,
wind speed and background temperature) are present. Work is ongoing to
determine the lowest concentration that can be reliably detected using
OGI.\107\
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    \107\ Draft Technical Support Document Appendices, Optical Gas
Imaging Protocol (40 CFR part 60, Appendix K), August 11, 2015.
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    In order to estimate fugitive emissions from compressor stations,
we used component counts from the GRI/EPA report \108\ for each of the
compressor station segments. Fugitive emission factors from AP-42 \109\
were used to estimate emissions from gathering and boosting stations in
the production

segment and emission factors from the GRI/EPA report were used to
estimate fugitive emission from transmission and storage compressor
stations and evaluate the cost of control for these segments.
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    \108\ Gas Research Institute/U.S. Environmental Protection
Agency, Research and Development, Methane Emission Factors from the
Natural Gas Industry, Volume 8, Equipment Leaks, June 1996 (EPA-600/
R-96-080h).
    \109\ Environmental Protection Agency, Protocol for Equipment
Leak Emission Estimates, Table 2-4, November 1995 (EPA-453/R-95-
017).
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    Since we have emission factors for only a subset of the components
which are possible sources for fugitive emissions, our emission
estimates are believed to be lower than the emissions profile for the
entire set of components that would typically be found at a compressor
station.
    The fugitive emission factors from AP-42,\110\ which provided a
single source of TOC emission factors that include non-VOCs, such as
methane and ethane, were used to estimate emissions and evaluate the
cost of control of a fugitive emissions program for compressor
stations. Using the GRI/EPA and AP-42 data, fugitive emissions from
gathering and boosting stations were estimated to be 35.1 tpy of
methane and 9.8 tpy of VOC. Fugitive emissions from natural gas
transmission stations were estimated to be 62.4 tpy of methane and 1.7
tpy of VOC. Fugitive emissions from natural gas storage facilities were
estimated to be 164.4 tpy of methane and 4.6 tpy of VOC. The
calculation of these emission estimates are explained in detail in the
TSD available in the docket.
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    \110\ U.S. Environmental Protection Agency, Protocol for
Equipment Leak Emission Estimates, Table 2-4, November 1995 (EPA-
453/R-95-017).
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    Information in the white paper related to the potential emission
reductions from the implementation of an OGI monitoring program varied
from 40 to 99 percent. The causes for this range in reduction
efficiency were the frequency of monitoring surveys performed and
different assumptions made by the study authors. According to the
calculations, which are based on uncontrolled emission factors for well
pads contained within the EPA Oil and Natural Gas Sector Technical
Support Document (2011), the Colorado Air Quality Control Commission,
Initial Economic Impact Analysis for Proposed Revisions to Regulation
Number 7 (5 CCR 1001-9) and the FINAL ECONOMIC IMPACT ANALYSIS For
Industry's Proposed Revisions to Colorado Air Quality Control
Commission Regulation Number 3, 6, and 7 (5 CCR 1001-9) (January 30,
2014), a -quarterly monitoring program in combination with a repair
program can reasonably be expected to reduce fugitive methane and VOC
emissions at well sites by 80 percent. Although information in the
white paper indicated emission reductions as high as 99 percent may be
achievable with OGI, we do not believe such levels can be consistently
achieved for all of types of components that may be subject to a
fugitive emissions monitoring program. Therefore, using engineering
judgement and experience obtained through our existing programs for
finding and repairing leaking components, we selected 80 percent as an
emission reduction level that can reasonably be expected to be achieved
with a quarterly monitoring program. Due to the increased amount of
time between each monitoring survey and subsequent repair, we believe
that the level of emissions reduction achieved by less frequent
monitoring surveys will be reduced from this level. Therefore, we
assigned an emission reduction of 60 percent to semiannual monitoring
survey and repair frequency and 40 percent to annual frequency,
consistent with the reduction levels used by the Colorado Air Quality
Control Commission in their initial and final economic impacts
analyses. We solicit comment on the appropriateness of the percentage
of emission reduction level that can be reasonably expected to be
achieved with quarterly, semiannual, and annual monitoring program
frequencies.
    For Method 21, we estimated emissions reductions using The EPA
Equipment Leaks Protocol document, which provides emissions factor data
based on leak definition and monitoring frequencies primarily for the
Synthetic Organic Chemical Manufacturing Industry (SOCMI) and Petroleum
Refining Industry along with the emissions rates contained within the
Technology Review for Equipment Leaks document.\111\ We used these data
along with the monitoring frequency (e.g., annual, semiannual, and
quarterly) at fugitive repair thresholds at 500, 2,500 and 10,000 ppm
to determine uncontrolled emissions. Using this information we
calculated an expected emissions reduction percentage for each of the
combinations of monitoring frequency and repair threshold which range
from.
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    \111\ Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI
International, Analysis of Emission Reduction Techniques for
Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180
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    We also looked at the costs of a monitoring and repair program
under various monitoring frequencies and repair thresholds (for Method
21), including the cost of OGI monitoring survey, repair, monitoring
plan development, and the cost-effectiveness of the various
options.\112\ For purposes of this action, we have identified in
section VIII.A two approaches (single pollutant and multipollutant
approaches) for evaluating whether the cost of a multipollutant
control, such as the fugitive emissions monitoring and repair programs
identified above, is reasonable. As explained in that section, we
believe that both approaches are appropriate for assessing the
reasonableness of the multipollutant controls considered in this
action. Therefore, we find the cost of control to be reasonable as long
as it is such under either of these two approaches.
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    \112\ See pages 68-69 of the TSD.
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    Under the first approach (single pollutant approach), we assign all
costs to the reduction of one pollutant and zero to all other
pollutants simultaneously reduced. Under the second approach
(multipollutant approach), we apportion the annualized cost across the
pollutant reductions addressed by the control option in proportion to
the relative percentage reduction of each pollutant controlled. In the
multipollutant approach, since methane and VOC are controlled equally,
half the cost is apportioned to the methane emission reductions and
half the cost is apportioned to the VOC emission reductions. In this
evaluation, we evaluated both approaches across the range of identified
monitoring survey options: OGI monitoring and repair performed
quarterly, semiannually and annually; and Method 21 monitoring
performed quarterly, semiannually and annually, with a fugitive
emissions repair threshold of 500, 2,500 and 10,000 ppm at each
frequency. The calculation of the costs, emission reductions, and cost
of control for each option are explained in detail in the TSD. As shown
in the TSD, while the costs for repairing components that are found to
have fugitive emissions during a fugitive monitoring survey remain the
same, the annual repair costs will differ based on monitoring
frequency.
    As shown in our TSD, both OGI and Method 21 monitoring survey
methodologies costs generally increase with increasing monitoring
frequency (i.e., quarterly monitoring has a higher cost of control than
annual monitoring). For EPA Method 21 specifically, the cost also
increases with decreasing fugitive emissions repair threshold (i.e.,
500 ppm results in a higher cost of control than 10,000 ppm). However,
as shown in the TSD, the cost of control based on the OGI methodology
for annual, semiannual, and quarterly monitoring frequencies are
estimated to be more cost-effective than Method 21 for those same
monitoring

frequencies.\113\ We therefore focus our BSER analysis based on the use
of OGI.
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    \113\ See the 2015 TSD for full comparison.
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    As shown in the TSD, the costs are comparable for all three
monitoring frequencies using OGI. For the reasons explained below, we
find the monitoring/repair program using OGI at compressor stations to
be cost-effective for all three monitoring frequencies. Under the
single pollutant approach, if we assign all control costs to VOC and
zero to methane reduction, the costs range from $3,110 to $4,273 per
ton of VOC reduced ($2,338 to $3,502 with gas saving) and zero for
methane, which indicate that the control is cost-effective. Even if we
assign all of the costs to methane and zero to VOC reduction, the
costs, which range from $686 to $930 per ton of methane reduced ($471
to $715 per ton with gas savings), are well below our cost-
effectiveness estimates for the semi-annual monitoring and repair
option for reducing fugitive emissions at compressor stations, which we
find to be reasonable for the reasons stated above. Under the
multipollutant approach, the costs for VOC reduction range from $1,555
to $2,136 ($1,169 to $1,751 with gas saving). The costs for methane
reduction range from $343 to $465 per ton ($236 to $358 per ton with
gas savings). Again these cost estimates for methane reductions are
well below our estimates for the monitoring/repair program at
compressor stations using OGI based on semiannual monitoring, which we
find to be reasonable for the reasons stated above. Further, as
previously explained, we believe the emission reduction values used in
these calculations underestimate the actual emission reductions that
would be achieved by a fugitives monitoring and repair program, so
these cost of control values likely represent a high end cost
assumption. Therefore, we believe the use of OGI is more cost-effective
than the amounts presented here. The calculation of the costs, emission
reductions, and cost of control calculations for each option are
explained in detail in the TSD for this action available in the docket.
    While the costs are comparable for all three monitoring frequencies
using OGI, for the reasons stated below, we have concerns with the
potential compliance burdens, in particular on small businesses,
associated with quarterly monitoring, and we believe that semi-annual
monitoring could achieve meaningful reduction without such potential
issues.
    Further practical aspects we considered for the methodology of each
monitoring survey include the likeliness that many owners and operators
will hire a contractor to conduct the monitoring survey due to the cost
of the specialized equipment needed to perform the monitoring survey
and the training necessary to properly operate the OGI equipment. We
also believe that small businesses are most likely to hire such
contractors because they are less likely to have excess capital to
purchase monitoring equipment and train operators. We are concerned
that the limited supply of qualified contractors to perform monitoring
surveys may lead to disadvantages for small businesses. Larger
businesses, due to the economic clout they have by offering the
contractors more work due to the higher number of compressor stations
they own, may preferentially retain the services of a large portion of
the available contractors. This may result in small businesses
experiencing a longer wait time to obtain contractor services.
    Specifically for conducting OGI monitoring surveys, we believe that
many operators will hire OGI contractors to conduct the OGI surveys.
The proposed fugitive emissions monitoring plan requires that operators
verify the capability of OGI instrumentation, determine viewing
distance, and determine the maximum wind speed. Additionally, there are
specific requirements for conducting the survey such as how to operate
OGI in adverse monitoring conditions or how to deal with interferences
such as steam. Each corporate-wide plan will need to include these
requirements and will require OGI contractors and operators to be
trained to meet these requirement. The monitoring plan requirements
will also cause the surveys to take more time, thus affecting the
availability of OGI equipment and contractors. Therefore, if we specify
quarterly monitoring surveys, we are concerned that the available
supply of qualified contractors and OGI instruments may not be
sufficient for small businesses to obtain timely monitoring surveys.