American Oil and Gas Reporter - July 2016 - 101

Clean Air Act Compliance

NSPS OOOOa Brings New Challenges
By Georgette Reeves
AUSTIN, TX.-The finalized Clean
Air Act standards announced by the U.S.
Environmental Protection Agency in May
to cut emissions of methane and volatile
organic compounds from new, modified
and reconstructed oil and gas industry
sources contain a host of new compliance
challenges for operators.
EPA published its New Source Performance Standard OOOOa in the Federal
Register on June 3. This new regulation
builds on and adds to NSPS OOOO (Quad
O), with which many operators have been
grappling since its inception in 2011.
There are two key dates for an NSPS
such as this: the date the rule is proposed
and the date the final rule is published.
EPA usually ties compliance applicability to the date the rule is proposed (in this
case, Sept. 18, 2015), and compliance
deadlines to the date a rule is published
(June 3, 2016).
Some initial NSPS OOOOa annual reports will be due in October 2017. However, the race is on to achieve some compliance requirements as soon as August of
this year, with heavy hitting compliance
deadlines no later than June 2017 for certain sources that were constructed, modified or reconstructed after Sept. 18, 2015.
There are many nuanced differences between the requirements found in Quad O
and those in OOOOa. However, some of
the biggest changes that will impact upstream and midstream operations are:
* Leak detection and repair (LDAR)
requirements for new, modified and reconstructed well sites and compressor stations;
* Expansion of existing reduced emission completion and/or completion combustion requirements for nearly all hydraulically fractured wells (not natural gas
wells only, as was required in Quad O);
* The addition of control requirements for new, modified or reconstructed
pneumatic pumps located at well sites and
gas plants; and
* Professional engineer certification
requirements for closed vent system designs
used to control emissions from storage tanks,
pneumatic pumps, and reciprocating and
centrifugal compressors, as well as P.E. certification if controlling pneumatic pumps is
determined to be "infeasible."
The time frame for demonstrating
compliance with these requirements is aggressive. While some of the requirements
found in OOOOa may reflect practices already in use, it is important to ensure that

future records are kept in accordance
with these rules in order to demonstrate
compliance when annual reports are due.
LDAR Requirements
While there are many impactful aspects
of NSPS OOOOa, one of the steepest learning curves facing the upstream and gathering/boosting segments relates to the
LDAR requirements. There are two distinct
elements to the LDAR requirements:
* LDAR program development
(which includes record keeping and reporting elements), and;
* LDAR survey performance.
Operators are required to use either optical gas imaging (OGI) or "Method 21"
to perform the required surveys. Method
21 is a leak detection program typically
used by chemical, refining and gas processing facilities that determines VOC emissions using a portable monitoring instrument such as an organic vapor analyzer.
Many well sites that have been hydraulically fractured after Sept. 18, 2015,
likely will trigger semiannual LDAR survey and record keeping requirements under the new rule. Any well site that has
been completed after Sept. 18, 2015 (even
if it is not hydraulically fractured), should
be evaluated closely to determine its status under the new LDAR requirements.
Compressor stations that were constructed after Sept. 18, 2015, must conduct
quarterly LDAR surveys. Compressor stations that are modified (i.e., adding compressors or increasing overall compressor
horsepower) after that date also will be subject to quarterly monitoring requirements.
Gathering and boosting compressor stations
as well as natural gas transmission compressor stations are subject to this requirement.
Operators have until June 3, 2017, to
develop the required LDAR monitoring
plans, acquire equipment (or hire contractors), develop record-keeping and datamanagement programs, and conduct the
first survey at each site that is subject to
the rule's LDAR requirements. As the June
2017 compliance deadline approaches,
keep in mind the following guidance:
* For the LDAR requirements found
in NSPS OOOOa, compliance is demonstrated through adequate record keeping
and reporting. Consider dedicating resources upfront to developing an effective
record keeping program. While doing
so, also consider what data management
tools may be needed to store the required
records. There are requirements for photographs and other images, which can take

up considerable electronic space.
* Other industries, including chemical plants, fractionating plants and refineries, have been subject to LDAR requirements for many years. For many upstream and midstream operators, however, this may be the first time to develop and
implement full-scale LDAR programs. It
will be important to carefully document,
test, and update survey procedures in the
form of a LDAR monitoring plan in order
to develop a program that makes sense and
meets the rule requirements.
LDAR Monitoring Plans
The rule requires that operators prepare
a LDAR monitoring plan for each "company defined area." While the rule doesn't specify what a company defined area
is, EPA has indicated it expects a company to define a company defined area as
similar facilities located in a geographically similar or proximate area.
Each LDAR monitoring plan must include the following elements:
* Description of the LDAR method
(OGI or Method 21);
* Frequency for surveys;
* Details of the equipment used to detect leaks (Anyone using OGI must verify that the OGI camera meets the specifications detailed in the rule.);
* Procedures and time frames for
identifying and repairing components,
including those that are unsafe to repair;
* Specific procedures for conducting
surveys, including ensuring adequate thermal background, adverse monitoring condition procedures, training and experience
of the operator conducting the surveys, and
equipment calibration procedures;
* Site maps with defined observation
paths; and
* Additional information required by
Method 21, if Method 21 is used.
While EPA is allowing operators to develop plans for company defined areas,
many operators may find that sites within
similar geographic regions are still highly
variable, which can add to the burden of developing their LDAR monitoring plans.
EPA does not require operators to
submit their LDAR plans initially, however, they must be submitted on request.
While developing the required monitoring plan, consider implementing concurrently a "pilot program" for LDAR surveys. This could give operators the opportunity to implement real-world considerations into their monitoring plans. This will
assist in developing documentation that not
JULY 2016 101

American Oil and Gas Reporter - July 2016

Table of Contents for the Digital Edition of American Oil and Gas Reporter - July 2016