American Oil and Gas Reporter - October 2015 - 48

rule divides oil and gas well sites into two
categories: subcategory 2 (wildcat and delineation wells), and subcategory 1 (all
other wells). Subcategory 1 wells must
use reduced emission completions (RECs)
and combustion. The proposal does not,
however, require RECs if it is technically
infeasible for a separator to function.
Owners and operators will be required
to control emissions during part of flowback. For subcategory 1 wells, EPA recognizes two distinct stages: "initial flowback" and "separation flowback." The
initial flowback stage starts when flowback
begins and ends when the fluids are
routed to a separator. Any gas in the
initial flowback is not subject to control.
The separation flowback stage begins
when the separator can function. During
this stage, operators may route all saleable
gas to a flowline or collection system,
reinject the gas, use it for on-site fuel, or
put the gas to another useful purpose.
Operators must combust the gas if it is
technically infeasible to route the gas in
this way, or if the gas is not of saleable
quality, unless combustion creates a fire
or safety hazard, or can damage certain
land features or waterways.
Flowback ends when production begins
or when the well is shut in and the flowback
equipment is permanently disconnected.
All flowback liquids must be routed to a
well completion vessel, a storage vessel,
or a collection system. Well completions
performed during a refracturing operation
are not subject to these flowback requirements, if they meet Quad O standards, but
these completions may still be subject to
fugitive emissions requirements.
For subcategory 2 (wildcat and delineation) wells, the proposal would require
using only a completion combustion device. Flowback routing requirements and
the circumstances when a separator must
be used are the same as for subcategory
1. As with Quad O standards, low-pressure
wells are subject to the subcategory 2 requirements.
Operators will be required to document
flowback times, and the total duration of
venting, combustion and flaring during
flowback.
The proposed rule also places a general
duty on operators "to safely maximize resource recovery and minimize releases to
the atmosphere during flowback and subsequent recovery." This vague general duty
creates compliance risks because the proposed rule does not define a suite of measures that qualify as "maximizing" resource
recovery or "minimizing" releases.
Pumps And Compressors
The proposed rules for new sources
would apply as well to pneumatic con-

48 THE AMERICAN OIL & GAS REPORTER

trollers and pneumatic pumps at well
sites, production gathering and boosting
stations, natural gas processing plants,
and natural gas compressor stations used
in transmission and storage. Consistent
with Quad O regulations, EPA is requiring
use of low-bleed controllers (bleed rate
of six cubic feet an hour or less) between
the wellhead and the point where gas
enters the transmission line.
Pneumatic controllers at natural gas
plants would have to achieve zero bleed
rates. These controllers would be driven
by compressed air rather than natural
gas. Certain critical applications are
exempt from these requirements, based
on operational or safety considerations.
The proposed standards apply to natural
gas-driven chemical/methanol pumps and
diaphragm pumps. The requirements for
these devices depend on their location:
zero emissions for pumps at natural gas
processing plants, and 95 percent control
efficiency for pumps at all other sites, if
a control device is already available.
To meet these requirements, EPA suggests routing emissions from the pump to
an existing control device such as is used
to control emissions from storage tanks.
The proposed rules also cover compressors at gathering and boosting stations,
natural gas processing plants, and compressor stations in the transmission and
storage segments. Affected wet-seal centrifugal compressors must achieve 95
percent control efficiency by capturing
and routing emissions to a combustion
control device.
EPA will allow dry-seal systems-
which have substantially lower emissions
than wet seals-and routing emissions to
a process as alternatives to routing to a
combustion device. Operators must replace
reciprocating compressor rod-packing
systems every 26,000 hours of operation
or after 36 months. Alternatively, the operator may route emissions from rod
packing through a closed-vent system
under negative pressure.
Fugitive Emissions Monitoring
Under the proposed rules, operators
must survey "well site" fugitive emissions,
including all ancillary equipment in the
immediate vicinity of the well such as
separators, storage vessels, heaters, dehydrators, or other equipment at the site.
The survey must cover valves, connectors,
open-ended lines, pressure relief devices,
closed-vent systems, and thief hatches
on tanks. Devices that vent as part of
"normal operations"-such as natural gasdriven pneumatic controllers or pumps-
are not fugitive emission components.
Two types of well sites would be exempt from monitoring fugitive emissions:

low production wells (combined oil and
gas production averaged over the first 30
days is less than 15 boe/d), and sites
where additional drilling activities other
than fracturing or refracturing (such as
workovers) are conducted on an existing
well.
The rules would require operators to
use optical gas imaging (OGI) to detect
fugitive emissions. The initial survey must
occur within 30 days after operations begin,
with follow-up surveys every six months.
Operators must repair or replace the sources
of any fugitive emissions "as soon as
practicable, but no later than 15 days"
after the survey. Operators must resurvey
repaired components no later than 15
days after the repairs are completed.
Additionally, companies would be required to develop and implement site
monitoring plans that specify measures
for locating fugitive emission sources
and the detection technology to be used.
The monitoring plan must address instrumentation, procedures for conducting
an OGI survey during adverse monitoring
conditions, operator training, and dealing
with infrared camera interferences such
as steam.
EPA is proposing to adjust the frequency of required monitoring based on
the results of prior fugitive emission surveys. It plans to decrease survey frequency
for sites that find fugitive emissions from
fewer than 1 percent of components
during two consecutive surveys. EPA
proposes to increase survey frequency to
quarterly for sites that find fugitive emissions from 3 percent or more of covered
components during two consecutive surveys.
Monitoring frequency would continue
to increase or decrease, based on the
results of later surveys. EPA is asking
for comments on the monitoring frequency.
The operator must keep one or more
digital photographs of each affected well
site or compressor station for each monitoring survey (a photograph of every
component that is surveyed is not required), as well as a fugitive emissions
monitoring log for each affected facility.
The photographs and logs must be available at the facility or the field office.
EPA also is soliciting comments on
whether these records should be sent
electronically to the permitting agency
as well.
The proposal also requires affected
facilities to file annual reports. EPA acknowledges that this could create duplicative record keeping and reporting
requirements with Subpart W greenhouse
gas reporting regulations, and state and
local rules, and solicits comments on

American Oil and Gas Reporter - October 2015

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