The Tangled Web
If you are in the upstream or midstream oil and gas industry segment, building a comprehensive environmental compliance program that covers all of the applicable regulatory requirements is, to say the least, daunting. If you have even one affected facility, you are probably well aware of how many environmental rules cover your various assets. When you multiply these requirements by several (or dozens or even hundreds of) affected facilities, successful navigation and execution of the plethora of work practice requirements, notification and reporting deadlines, and other miscellaneous obligations becomes an overwhelming prospect. The latest challenge adding to the complexity and confusion surrounding air quality compliance in particular is leak detection and repair (LDAR). While gas processing plants have plenty of historical experience in navigating the burdens of the LDAR world, upstream and midstream oil and gas operators are facing an entirely new regulatory domain. These facilities may be subject to overlapping LDAR requirements under New Source Performance Standards (NSPS), Greenhouse Gas (GHG) Mandatory Reporting Rule (MRR), state-specific programs, and/or facility-specific permit requirements. However, the challenging regulatory complexities and practical hurdles that come with implementing an LDAR program can be overcome with careful planning. This article highlights some of the main considerations and provides insight on various critical lessons learned.
What is LDAR?
In a basic sense, leak detection and repair is exactly what the name suggests: finding facility components that are leaking and fixing them. The U.S. Environmental Protection Agency (EPA) has a long history of regulating industries (such as petroleum refining and chemical manufacturing), and more specifically, the components within those industries that have the potential to leak pollutants to the atmosphere.
Sounds simple enough. But, what needs to be monitored? How often do you need to monitor? What do you monitor with? How is a leak defined? When is the repair required to be made? All of these are valid and critical questions, and the answers can vary depending on the underlying requirement(s) of the requisite LDAR program. On the most basic level, LDAR is simply finding and fixing leaks. However, not every source that emits pollutants is necessarily a leak, and not every leak is easy to identify. While one LDAR program might cover flanges, connectors, and valves, another program might also include pneumatic controllers or pressure relief valves. Depending on the detailed requirements of the underlying program in question, the gas emitted from those types of sources may or may not be considered a leak. Thus, a firm understanding of the detailed applicable requirements is imperative to avoid costly mistakes and to ensure a comprehensive compliance program is in place. The following sections offer some practical tips for achieving these lofty goals.
How Do You Find a Leak That You Cannot See?
The standard historical approach to LDAR typically involved the use of a simple hand-held instrument such as a flame ionization detector (FID) or a photoionization detector (PID). These tools were used to monitor leaks under regulatory programs that relied on EPA's Method 21, a practice of "sniffing" individual components that is generally considered time-consuming and tedious, and complicated by burdensome recordkeeping requirements.
Today's modern approach to LDAR capitalizes on technological advancements, typically using optical gas imaging (OGI) cameras as the primary monitoring tool. These cameras actually visualize the gas stream (which is often invisible to the naked eye) and make it appear as "smoke" on a screen. One distinct advantage of this technology is the ability to monitor (survey) multiple components at a time. An experienced team of surveyors properly utilizing Method 21 can survey up to a few hundred components in a day, whereas a single OGI surveyor with some basic training can effectively survey several thousand components in the same timeframe. This makes OGI the clear winner in terms of overall efficiency; however, it is important to note that OGI cameras are currently primarily used in a qualitative manner, whereas an FID can measure the actual concentration of a leak. The current OGI cameras on the market do not quantify the gas emitted, although add-on quantitative technologies are becoming available.
Of course, state-of-the-art technology comes with a cost and in this case, the price tag is pretty high. Whereas a good quality FID might cost approximately $10k, a new OGI camera will run upwards of $85k. FLIR® and Opgal® are the two main players in the OGI game, with both companies supplying EPA-recognized cameras that can be used to demonstrate compliance with federal LDAR rules. The FLIR® GF320® and Opgal® EyeCGas® devices are the most widely used cameras in the industry, although several competitors are currently trying to break into the market with less expensive offerings.
Implementing an LDAR program is no small undertaking. While some companies may voluntarily choose to conduct some type of leak survey and repair program as a best practice, most will find it difficult to justify the time and expense without a regulatory driver. Enter onto the scene, EPA's New Source Performance Standards (NSPS) Subpart OOOOa. This subpart regulates a wide variety of emissions sources in the oil and gas industry, from the wellhead through gathering systems, to transmission compression sites. New facilities and "modified" facilities become subject to prescriptive LDAR requirements under the rule.
One key differentiator of Subpart OOOOa, as compared to other "traditional" LDAR rules, is its significantly more comprehensive coverage. Under the rule, virtually any source at the facility that has the potential to emit methane or VOC is considered a "fugitive emissions component." For all practical purposes, that means just about anything with a gas or liquid in it (e.g., facility gas lines, instrumentation connectors, produced water lines, etc.) is subject to LDAR. There are a few possible exceptions, however, such as storage tank thief hatches. Thief hatches may be exempt from the NSPS fugitive requirements if they meet specified criteria, or they may be subject to monthly audio-visual-olfactory checks (AVOs) under the storage tank requirements. Agency inspectors have been known to arrive on site with OGI cameras in hand and are almost certain to survey thief hatches during their inspection. So, it may be prudent to include these components in your OGI surveys regardless of the applicability determination. This is just one example of the key regulatory considerations that go into a well thought-out LDAR program.
State-specific (or in some cases, permit-specific) LDAR requirements can add another layer of complexity to a facility's LDAR program. An increasing number of states are adopting LDAR requirements specifically targeted at the oil and gas industry sector. These requirements may be straightforward but more stringent than NSPS Subpart OOOO/OOOOa requirements (e.g., they require more frequent monitoring), or they may be completely different in terms of applicability, leak definition, repair timelines, etc. For example, the Ohio Environmental Protection Agency's GP12 permit for well pads requires OGI surveys on a quarterly basis, whereas Subpart OOOOa requires semi-annual monitoring. The Pennsylvania Department of Environmental Protection's state exemption criteria for well sites require leaks to be repaired in 15 days, while Subpart OOOOa requires repairs in 30 days. These are just two examples where state and federal LDAR requirements are similar, but not identical. A strategically developed, comprehensive LDAR program can ensure that all applicable requirements are met, without having to manage separate, potentially redundant programs.
Reporting of emissions from fugitive sources is yet another complication in the tangled web of LDAR requirements. Oil and gas facilities that emit more than 25,000 tons per year of carbon dioxide equivalent (CO2e) emissions are subject to reporting under 40 CFR 98 Subpart W of EPA's MRR for GHGs. The requirements for monitoring of leaks and the corresponding calculation of emissions from those leaks under Subpart W vary based on not only the industry segment, but also the component type. In general, facilities subject to NSPS Subpart OOOOa monitoring requirements are required to use those monitoring results to calculate and report GHG emissions under Subpart W. For sources not subject to NSPS Subpart OOOOa, however, you may have the option of using monitoring data or published emissions factors (again, variable by segment and component type). Finally, some states also require reporting of annual emissions data from oil and gas facility fugitive leaks, which may include VOC and GHG pollutant emissions. This requires careful consideration of the calculation methods and emission factors that will be used in order to align the emissions data that are reported to EPA and state agencies, much of which also becomes publicly available.
At the heart of every successful LDAR program is a carefully crafted monitoring plan. Although the level of detail and complexity of these plans will vary depending on their scope (one facility or many) and purpose (e.g., state requirements vs. NSPS Subpart OOOOa), each should clearly spell out how you comply with the underlying LDAR rule(s). The plan content can vary from simple rule regurgitation (not usually recommended) to a practical guidebook that any surveyor can implement. The monitoring plan should outline the procedures for surveying components, tracking and repairing leaks, and documenting the actions taken. An effective plan is a roadmap that is easily followed and is based on serious and thoughtful planning.
For example, the plan should consider components that may be difficult or unsafe to monitor, and should document the criteria used to make that determination. Potential safety hazards, such as surveying inside small enclosures with known gas vents (e.g., Gas Processing Units), should be taken into account. While some OGI cameras are labeled or considered "intrinsically safe," they are designated as either unclassified or Class I Division 2 electrical devices under Occupational Health and Safety Administration (OSHA) standards (there are currently no cameras meeting OSHA's Class I Division 1 designation). It may be possible to survey components using OGI without entering a restricted area, or it may be feasible to use EPA Method 21 as an alternative. These are considerations that should be addressed in an effective monitoring plan.
Surveyors and Their Qualifications
Do your camera operators know the difference between a gas leak and surface convection? Are they familiar enough with your facility operations to know when a pneumatic actuator is a vent rather than a leak? Do they know how to determine the survey parameters that allow them to comply with your LDAR plan under Subpart OOOOa? Do they have the tools necessary to complete a full day of surveying (e.g., a power inverter for in-vehicle charging)? Most importantly, can they complete a general survey safely and in accordance with your requirements?
These are just a few basic, but critical, questions that should be answered. Whether the surveys are performed by in-house staff or contractors, ensuring that your surveyors are performing complete, accurate, and compliant surveys will provide peace of mind, minimize compliance risk, and also save money from unnecessary repairs, follow up surveys, or simple inefficiencies.
Agency and Non-governmental Organization Interest
The oil and gas industry in general, and fugitive leaks in particular, are a central focus for both regulatory agencies as well as environmental non-governmental organizations (ENGOs). OGI cameras are more widely available and are now used as a tool by state and federal agency personnel for conducting spot checks on a variety of emissions sources. The camera may not measure exactly how much gas is being vented or leaked, but it can give an immediate snapshot of a facility's general compliance status. OGI cameras were a key tool used by the agency in the case of the Noble Energy Consent Decree,1 where almost 100 tank batteries were inspected over a two-month period. These tools provide a relatively quick and easy way for an agency to evaluate compliance without having to enter the facility property.
Apart from the agencies, ENGOs such as Earthworks and others have purchased OGI cameras to "expose" the pollution being generated by oil and gas facilities. A prime example of this is the Oil and Gas Threat Map,2 which is an interactive map showing the locations of oil and gas facilities across the county. In addition to the locations, the map includes actual videos taken with a FLIR® GF320® camera at some of the facilities. Of particular concern is that these videos provide no context, so that to the average citizen or untrained eye, they appear to show copious amounts of gas being vented. To the trained OGI surveyor with an understanding of environmental regulations, the videos actually show simple combustion emissions (mostly CO2 and water) and/or what is likely permitted venting from regulated sources, rather than leaks or malfunctions.
Strategies for Compliance
With the many complex facets of LDAR program management, the single most important step facilities can take is careful and comprehensive planning. This is most effective when it involves a cross-functional team of environmental and safety staff, operations and maintenance personnel, and LDAR surveyors. Clear and concise communication of monitoring requirements and leak repair deadlines can help avoid deviations and potential violations and monetary penalties. For operators with multiple facilities with differing LDAR requirements, compliance strategies such as aligning all sites to the most stringent monitoring frequency and repair schedule may be desirable. Alternatively, if operators elect to minimize cost by managing different programs on a site-by-site basis, communication will be an especially critical component of compliance, as the facilities may operate quite independently and with different staff. Coordination of monitoring logistics (equipment rental or purchase and periodic calibration), training of personnel, and management of data are other aspects of LDAR program development that require careful consideration.
Are you stuck in the tangled web of LDAR requirements? A wide array of tasks are required for comprehensive LDAR program management, including developing monitoring plans, conducting surveys, auditing compliance, performing emission calculations, and preparing reports. Selection and implementation of various software applications or environmental management information systems (EMIS) may also be considered to support compliance.
To learn more about how Trinity can help you with your LDAR program and other environmental compliance needs, please contact Christi Wilson in Trinity's Pittsburgh Office at (724) 935-2611.