American Oil and Gas Reporter - May 2016 - 55

SpecialReport: Compression & Production Optimization

Subpart W Rules Present Challenges
By Thomas S. Seguljic,
John P. Martin
and Gary J. Stiegel Jr.
CLIFTON PARK, N.Y.-Greenhouse
gas regulatory actions targeting oil and
gas operations have led to complicated
data collection and confusing emissions
calculation requirements. These evolving
GHG regulations present a compliance
challenge for operators, particularly in
light of increasing public and regulatory
scrutiny. However, operators of petroleum
and natural gas systems can avoid reporting
pitfalls by implementing management
systems that ensure compliance.
GHG regulation started with the 2007
Supreme Court ruling that granted the
U.S. Environmental Protection Agency
the authority to regulate GHGs as pollutants under the Clean Air Act. This led to
EPA creating the Greenhouse Gas Reporting Program, which now targets 41
sources.
With its determination that the oil and
gas industry is the second-leading emitter
of GHGs, the EPA has issued a landslide
of reporting requirements targeting oil
and gas. Most of these are found in 40
CFR 98, Subpart W, which came into
effect for reporting year 2011.
In 2014, the White House issued its
Methane Climate Action Plan-Strategy to
Cut Methane Emissions, which mapped
the administration's efforts to improve the
measurement of GHG emissions and to
reduce oil and gas methane emissions by
40-45 percent by 2025 from the base-line
year of 2012. The plan directed the EPA
to study additional ways to reduce methane
emissions from the oil and gas sector, and
if necessary, develop additional regulations
by the end of 2016. After this policy directive, EPA adopted major Subpart W
rule revisions in 2015, and then released a
2016 proposed revision package.
As originally promulgated, 40 CFR 98,
Subpart W, defined eight segments of the
petroleum and natural gas system that must
monitor and report GHG emissions:
* Offshore oil and gas production;
* Onshore oil and gas production;
* Onshore gas processing;
* Onshore gas transmission compression;
* Underground gas storage;
* Liquefied natural gas storage;
* LNG import and export equipment;

and
* Natural gas distribution facilities
owned or operated by local distribution
companies.
Two additional reporting segments
were added to the list in 2015:
* Onshore oil and gas gathering and
boosting; and
* Onshore gas transmission pipelines.
Unique And Expansive
For the oil and gas industry, the key
factor that makes the application of Subpart
W so unique and expansive is its definition
of a "facility." The regulation does not apply
a traditional definition, as in the physical
boundaries of contiguous or adjacent property.
Instead, Subpart W's definition of facility
depends on the industry segment.
For example, under the natural gas
distribution segment, a facility is a local
distribution company as regulated by a
state public utility commission; whereas
the onshore production segment defines
a facility as all emission sources on well
pads, or associated with well pads, that
are under common ownership or control
and are located in a single hydrocarbon
basin as defined by the American Association of Petroleum Geologists.
For example, most Marcellus production
is in the Appalachian Basin Eastern Overthrust area (AAPG Basin 160-A), while
most Bakken production is in the Williston
Basin (AAPG Basin 395). As such, a
single facility as defined by the onshore
production segment could consist of hundreds, if not thousands, of individual wells!
To comply with Subpart W, thousands
of datasets must be collected, including
equipment lists and production/operational
information. Once collected, emissions
must be quantified with engineering calculations based on actual facility or field
data, and using leak detection and "leaker"
factors. Based on this analysis, emissions
from the facility must be reported to the
EPA if carbon dioxide-equivalent emissions are greater than or equal to 25,000
metric tons a year.
The EPA also amended reporting obligations to improve completeness, accuracy, transparency, and the agency's ability
to analyze emissions and understand
emission trends. For example, starting in
reporting year 2017 (calendar year 2016),
operators also must report GHG emissions
from gathering and boosting facilities,

and from hydraulic fracturing completions
and workovers of oil wells.
Reporting Pitfalls
The reporting requirements sound
straightforward, but the reality is that operators have their work cut out for them.
They will need to do their homework to
determine which operations are subject to
reporting, which segment they are subject
to (e.g., onshore production, or gathering
and boosting), and whether any equipment
is excluded. With the 2015 revision of
Subpart W, most upstream operators will
report in either the onshore production, or
gathering and boosting segments. This is
where things start getting complicated.
In regard to workovers, if applicable
to the onshore production segment, starting
in reporting year 2016, operators must
calculate workover emissions from oil
wells using the ratio of the gas flowback
rate to the production flow rate collected
from each well or representative parameters. If representative information is used,
then the operator must subdivide the basin
into a unique combination of wells within
the boundaries of an individual county
and subsurface completion in one or more
of the following formation types: oil,
high-permeability gas, shale gas, coal
seam, or other tight gas reservoir rock.
If wells produce from more than one
formation type, then the well is classified
into only one category, based on the formation type that contributes most to production, as determined by the reporter's
engineering knowledge.
Evaluating which equipment is subject
to reporting under the gathering and
boosting segment is a relatively simple
task. For example, gathering pipelines
are excluded if they have a gas-to-oil
ratio less than 300 cubic feet per barrel,
or they operate under a vacuum. Since
gathering and boosting facilities are
defined by AAPG basins, operators need
to aggregate all equipment by basin, determine each basin's emissions, and compare each basin's emissions to the GHG
threshold. A GHG emissions report must
be filed for each basin that exceeds the
GHG reporting threshold.
Within a basin, operators must further
categorize their well locations as either single- or multiple-well pads. This exercise is
required since the onshore production segment, as defined, includes all equipment on
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