Benzene Fenceline Monitoring – Where Should You Be by Now?

If you are responsible for environmental compliance at a petroleum refinery, you are well aware of U.S. EPA’s requirements to install and operate a network of passive benzene fenceline monitors.  The requirements originate from finalized amendments to 40 CFR Part 63, Subpart CC (National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries).  For existing affected sources, the first official sampling event must begin on or before January 30, 2018 (Table 11 of Subpart CC).  Since the compliance date is approximately one year away, you may be wondering if your program is far enough along and where others are in the process.  Here are several key observations.

Petroleum refineries are at various stages in developing and implementing their benzene fenceline monitoring program.  Although no official survey has been conducted, if one were to be conducted, the following three categories of responses are probably very close to reality:

1. There is plenty of time; I have not done anything yet.
2. My petroleum refinery has completed a trial program and operation of the passive samplers will continue through the compliance date.
3. Items 1 and 2 do not apply to me, my petroleum refinery is somewhere in between.

While you are taking a moment to assess where your facility stands; it might be helpful to share some considerations and where you should be in the process.

Selecting Shelter and Sorbent Tube Suppliers

This market has some variability in what is being offered.  There is always the do-it-yourself piecemeal approach, which may work for many facilities.  There are also some nice turnkey solutions offering a continual supply of sorbent tubes, pre-arranged analytical laboratory relationships, and streamlined pre-paid shipping arrangements.  This all comes in a nice kit to simplify the sample handling and analysis processes.  Affected petroleum refineries even have the option to outsource the sample deployment and collection process.  The shelters (to protect the sorbent tubes) can be custom made with PVC piping and other supplies from a local hardware store.  Regardless of the custom made or pre-fabricated approach, be sure the shelter is sized properly to protect the sorbent tube from the elements.  It also must not interfere with the sampling interface, so that representative samples can be obtained.  Most importantly, the sorbent tube retaining mechanism must be designed to securely hold during high wind and precipitation events.

Defining Sampler Locations

The number of sampling locations is site-specific as it depends on the size and shape of the facility and the location of emissions units relative to the petroleum refinery boundary.  Method 325A (Volatile Organic Compounds from Fugitive and Area Sources) in Appendix A to 40 CFR Part 63, has 2 procedures for determining sampling locations (i.e., angular or linear).  Both procedures prescribe how to site sampling locations at a facility and become increasingly complex if the petroleum refinery property parcel is irregularly shaped.  There are criteria for siting the monitor locations including a minimum number and a separating distance.  Designing the placement of monitors can be akin to a jigsaw puzzle or a game of chess.  For example, you may even find that once you pencil in the placement of 10 monitors, it is the 11th monitor that does not meet all criteria and then it is back to the drawing board.  It could also mean that the placement of additional monitors is required due to the location of emissions units near the property boundary.  There is some strategy required to place the samplers advantageously and it is not always straightforward.  The iterative process of placing samplers is where mapping software and some expertise is helpful in designing a successful monitoring program.

Managing Sampling Data

A petroleum refinery with 25 samplers will conduct bi-weekly sampling events which equates to 650 concentration data points annually.  While this may seem like a manageable dataset, keep in mind that the sampling duration (start/end times), location, etc. must also be maintained.  The raw data must be reduced to determine the “delta C” for the sampling period and then must be rolled into a 12-month rolling average to demonstrate compliance with the action level specified by the rule.  There are software packages to help track results and some even offer handy trending by location.  These are “nice to have”  features once the monitoring program is running and multiple data points have been generated to provide a visual of both elevated and low impact sampling locations.  At the very least, a successful program will need a well thought-out spreadsheet or database that simplifies the burden of managing data by considering ease of importing, usability of viewing/filtering, archiving ability, etc.

Next Generation Compliance

Passive sampling has been deemed a cost-effective technique to measure concentrations of benzene in ambient air.  The problem with passive monitoring techniques is that they lack real-time feedback because they provide time-integrated concentration data (e.g., over a two week period).  While wind speed and direction data are collected as part of the monitoring program, the data are not directly factored into concentration measurements.

U.S. EPA is developing more sophisticated tools to complement passive samplers and bridge this gap.  An example is the SPod, which is a solar powered mobile monitoring sensor that can be placed to provide real-time fenceline data.  This might be deployed in areas where elevated fencline concentration is indicated by passive samplers.  SPod can be used as a tool to locate contributing sources of fugitive emissions.  Since the technology is in the development phase, it is difficult to say with certainty if and how it may be adapted for use in the future.  More information can be found here: https://www.epa.gov/sciencematters/fenceline-monitoring

While SPod is under development, the U.S. EPA initiative provides insight as to level of sophistication and the expectation of regulators and the public to increase access to information for transparency and accountability of the regulated community.

Technology advancements allow for increasing rates of data generation.  Is more data really better or would you prefer a smaller data set of high quality information?  Is it important that data quality objectives be considered in designing and implementing a successful monitoring program?  Given the 40 CFR Part 63 Subpart CC compliance deadline, a petroleum refinery that has not yet embarked on a pilot program should strongly consider implementing one now.  In designing a pilot program consideration will need to be given to the duration of the pilot program and how the generated data will be handled, as both will impact the cost of the study.  The data and experience will provide an opportunity to evaluate the ambient benzene concentrations around the petroleum refinery, investigate questionable data, and become familiar with the monitoring routine ahead of the compliance date.

Contact me at 610-933-5246 x121 or nleone@all4inc.com to discuss technical information regarding installation and operation of a benzene fenceline monitoring program.

TCEQ Reporting Season is Almost Upon Us: Are You Ready to Prepare your Facility Emissions Inventory?

As the 2016 calendar year winds down to a close, it’s time to start thinking about and planning for the submission of your facility’s Emissions Inventory (EI) to the Texas Commission on Environmental Quality (TCEQ).  As you may be aware, an EI submission is due on March 31 of the calendar year immediately after the reporting year.  This EI blog, forecasted in my November 8, 2016 blog, will highlight general information about an EI, new additions to EI reporting over the past year, and other information that may be helpful when preparing your EI. 

What is an Emissions Inventory?  Let’s Review the Basics

Before we dive into the details of an EI, let’s first review the basics.  Federal and state law requires the State of Texas to develop annual EIs to meet state implementation plan (SIP) requirements.  To create a state-wide EI, TCEQ requires facilities that satisfy the criteria outlined in 30 TAC §101.10(a) to submit an EI that consists of actual emissions of volatile organic compounds (VOC), nitrogen oxides (NO_X), carbon monoxide (CO), sulfur dioxide (SO₂), lead (Pb), particulate matter with an aerodynamic diameter less than or equal to 10 microns (PM₁₀), particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (PM_2.5), emissions of all hazardous air pollutant (HAPs), or other contaminant requested by TCEQ.

Using the collected facility EIs, TCEQ is able to then gather state-wide emissions data to supply information to the United States Environmental Protection Agency (U.S. EPA), to plan pollution control programs, and to analyze emissions trends, to name a few.  In order to facilitate the collection of this emissions data, TCEQ has developed the State of Texas Environmental Electronic Reporting System (STEERS) Air Emissions Inventory Reporting (AEIR) with two reporting options: the Web-EI system with the Emission Inventory Questionnaire (EIQ) and the text file upload system.  Facilities that meet the requirements of 30 TAC §101.10(a) are required to submit their emissions data using the STEERS online platform.  For first time submissions of any criteria pollutant or HAP that have not been identified in a previous inventory, an initial emissions inventory (IEI) is required.  If a facility has previously submitted an EI and that facility continues to meet the requirements of 30 TAC §101.109(a), an annual emissions inventory update (AEIU) is required.  Just remember, beginning with the 2015 reporting year, the online STEERS-AEIR is the required reporting method for all EIs.  Caution: In case you have not heard, paper copies are no longer accepted by TCEQ.  Another important topic to keep in mind this reporting season is to make sure your facility demonstrates consistency across all platforms of reporting.  For example, make sure your toxic release inventory (TRI) emissions matches what you are reporting to TCEQ on your EI.  If your TRI emissions do not match what you reported to the state, you can expect a call from your regulator.

Getting Started for Your Online Submission

If you are new to submitting an EI online, the following steps must be taken to ensure that TCEQ receives the required information by March 31.

1. Set up a STEERS account and select your appropriate reference number (RN).
   1. Before starting an IEI, contact the State of Texas Air Reporting System (STARS) to make sure necessary data for EI processing is complete.  This can be done by calling the EI Helpline for assistance at (512) 239 – 1773.
2. Assign a person with a “signature authority” that will be the responsible official for the STEERS submissions.
3. Select the data entry method that you will be using (i.e., EIQ entry, or file upload).
4. Attach supporting documentation to your STEERS submission.
5. Submit data from STEERS.

What is TCEQ Looking for in a Complete EI?

Before data is to be submitted in STEERS, be sure to understand what information TCEQ is looking for to determine a complete EI.  The items below identify the information TCEQ is expecting:

1. A complete and updated EI.
2. A signed certification statement.
3. Sample calculations representative of current processes.
   • Be sure to include calculations that show determination of actual annual emissions.
   • Provide enough data so that the determinations can be reproduced.
   • Do not just include generic sample calculations.
4. If stack test data is being used to quantify emissions, provide a summary of the test results.
5. If a continuous emissions monitoring system (CEMS) is being used to determine emissions, provide a summary of the most recent relative accuracy test audit (RATA).
6. Material throughput forms; and
7. Fugitive data forms (if applicable).

Remember, confidential information is not to be submitted through STEERS; rather confidential information is to be submitted in hard copy, or submitted on a burned CD or DVD.

What has Changed Since Last Year?

Effective July 28, 2016, specific clarifications and changes were made to 30 TAC §101.10.  Some changes include the shortening of the applicable distance for off shore facilities, and the change of the EI reporting threshold for Pb to align with the U.S. EPA Annual Emissions Reporting Rule.  Another change includes the addition of a requirement for a facility that is obliged to submit an EI and that has had no emissions events during the reporting period.  These facilities are now required to include a certifying statement that describes the fact that no emissions events have taken place during the reporting period.  A more detailed summary of the changes can be found here.  Be sure to scan over the changes to ensure they do not impact the submission of your EI.  

Extra, Extra: TCEQ is Holding an EI Workshop in Late January

Save the date: on Wednesday, January 25, 2017, TCEQ will be hosting its annual EI Workshop in Austin, TX.  Registration for the event can be found here.  During this workshop, TCEQ will focus on providing a step-by-step tutorial on submitting an EI using the EIQ entry method and providing guidance on the Web-EI file uploading process (e.g., file specifications, troubleshooting, etc.).  ALL4 plans to be in attendance so please be on the lookout for one of our smiling faces if you happen to join this workshop.

Does the upcoming March 31, 2017 EI reporting deadline have you feeling stressed?  Don’t fret. ALL4 has been staying well-informed on EIs and is available to assist in any EI-related matter you may have.  From the preparation of a facility EI, to providing technical review/quality assurance (QA) on an EI, from administratively updating an EI, to submitting an EI through STEERS, ALL4 has you covered.  Feel free to reach out to me at fdougherty@all4inc.com if you have any additional questions or require support in completing your EI.

U.S. EPA Finalizes Leak Detection Methodology Revisions to Subpart W of the GHG Reporting Rule

Back in March 2016, Megan wrote an article about the proposed alignment between the oil and gas industry leak requirements under 40 CFR Part 98 Subpart W – Mandatory Greenhouse Gas (GHG) Reporting for Petroleum and Natural Gas Systems (Subpart W) and 40 CFR Part 60 Subpart OOOOa – Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (Subpart OOOOa).  The goal of the proposed amendments was to incorporate certain Subpart OOOOa leak detection requirements into Subpart W.  On November 30, 2016, U.S. EPA published a final version of those revisions to the Federal Register.  Read on to find out what the final rule changes entail.

Who Is Impacted By These Changes?

The Subpart W revisions affect companies required to quantify and report leak emissions under Subpart W and, in particular, those companies with well sites and compressor stations subject to fugitive emissions monitoring requirement under Subpart OOOOa.

When Is It Changing?

The Subpart W revisions are effective January 1, 2017.  Therefore, Subpart W leak surveys and emissions calculations for calendar year 2017 must be conducted in accordance with the new requirements.

What Is Changing?

The final revisions to Subpart W are generally consistent with the revisions proposed in early 2016.  Four main aspects of Subpart W are being revised relating to leak provisions:

1. Equipment Leak Calculation Methodologies
   For well sites and compressor stations required to conduct fugitive emissions monitoring under Subpart OOOOa, companies will now be required to use a GHG emissions calculation methodology that is based on subpart OOOOa leak monitoring methods.  Although new calculation methodology and equipment leak survey requirements are being added to Subpart W, the new requirements can also be met by counting the number of components with fugitive emissions identified during Subpart OOOOa leak surveys.For sources not subject to Subpart OOOOa well site or compressor station fugitive emissions standards, the Subpart W requirements are largely unchanged:
   • If facilities are currently required to conduct equipment leak surveys under Subpart W for these sources, they will remain subject to this requirement under the revised rules and may now use any monitoring method specified in 40 CFR §98.234(a), including two new methods added to 40 CFR §§98.234(a)(6) or (7).  However, if facilities elect to use either of the two new methods, all components regulated under Subpart OOOOa must be surveyed for these facilities.
   • If facilities are currently required to estimate GHG leak emissions based on component population counts, facilities may continue to use this methodology or, optionally, may elect to estimate emissions based on leak surveys.
   • Finally, in the proposed rule, U.S. EPA considered requiring that facilities in the Onshore Natural Gas Processing industry segment also use Subpart OOOOa leak surveys for Subpart W reporting.  However, in the preamble to the final rule, U.S. EPA indicated that they are delaying finalizing this requirement while completing their review of comments received on this aspect of the proposed amendments.
2. Subpart W Leak Monitoring Methods
   The Subpart W revisions add two new leak monitoring methods: 1) optical gas imaging (OGI) as specified in Subpart OOOOa; and 2) the use of Method 21 as in Subpart OOOOa, which assumes a lower leak definition of 500 ppmv.  The addition of these two methods allows facilities to directly use the results from Subpart OOOOa leak surveys in Subpart W GHG reporting.  Facilities that are not required, and do not elect, to use the two new methods can continue using the existing leak monitoring methods in 40 CFR §98.234(a), including using a Method 21 leak definition of 10,000 ppmv.
3. Regulated Component Types
   Not all components included in the Subpart OOOOa definition of fugitive emissions were regulated under the leak provisions of the previous version of Subpart W.  In the revisions to Subpart W, U.S. EPA is aligning the Subpart W leak components with the Subpart OOOOa definition of fugitive emissions with certain exceptions where Subpart OOOOa components are regulated under another Subpart W source type (e.g., certain compressor vents, thief hatches and other openings on storage tanks).
4. Leaker Emissions Factors
   Subpart W emissions calculations for leaking components are based on emissions factors applied to the number of leaks identified for each component type during leak surveys.  As discussed above, the revisions to Subpart W increase the number of components that may be subject to leak survey requirements.  Therefore, U.S. EPA is adding new leak emissions factors so that emissions can be estimated for the new regulated components.
5. Reporting Requirements
   U.S. EPA is revising Subpart W reporting requirements to include leak survey information for those facilities that will be newly-required to use Subpart OOOOa methods or survey data for GHG emissions reporting purposes or that elect to do so voluntarily.  In addition, U.S. EPA is also requiring reporting of additional information for facilities that utilize the new leak monitoring methods added to Subpart W.

ALL4 has extensive experience assisting oil and gas clients with GHG emissions calculations and reporting, and can help you navigate the new rule requirements.

Draft MERP Guidance Has Arrived

MERP…no I’m not referring to the word used to indicate an awkward conversation or making a sound you may hear from the likes of Kermit the Frog. I’m referring to Modeled Emission Rates for Precursors – MERPs.  On December 2, 2016, U.S. EPA published highly anticipated (at least in the air quality dispersion modeling world) guidance for the development of MERPs as part of a Tier 1 demonstration for ozone and PM_2.5 Prevention of Significant Deterioration (PSD) permitting. Sounds a little scary, right? Don’t worry, we’re here to help.

What the heck is a MERP?

In the preamble of the soon to be finalized Appendix W, U.S. EPA made mention to a new fine particulate (PM_2.5) and ozone precursor tool known as MERPs. MERPs were originally planned to be generally applicable thresholds to determine if a permitting project would contribute significantly to the PM_2.5 and/or ozone National Ambient Air Quality Standards (NAAQS).  After a review of the available data, U.S. EPA determined that variations in source location and source characteristics make generally applicable MERPs a bad idea.  So with this shift in U.S. EPA thinking, a new formula for calculating a MERP on a case-by-case basis was developed: 

I know what you’re probably thinking – “Cool, now I have a million more questions.” Let’s break it down.

• MERPs: Units are evaluated in tons per year (tpy).
• Critical Air Quality Threshold: The critical air quality threshold will be determined by each permitting authority and will be used to indicate that a value above this threshold number will contribute to a violation of the appropriate NAAQS.  For ozone, the critical air quality threshold is provided in units of either parts per million (ppm) or parts per billion (pbb).  For PM_2.5, the critical air quality threshold is provided in units of micrograms per cubic meter (µg/m³).
• Modeled Emission Rate from Source: The emissions rate of precursor emissions for ozone or PM_2.5 of the source you are evaluating as part of the PSD permitting analysis.  This is evaluated in tpy.
• Modeled Air Quality Impact from Source:  The result of the air dispersion modeling analysis for the source that you are evaluating as part of the PSD permitting analysis.  This is evaluated in the same units as the critical air quality threshold.

And I have to use a MERP when?

We can make this short. A facility is required to evaluate a MERP when an emissions analysis determines that emissions increases from a proposed project will exceed the PSD significance thresholds for ozone precursors (i.e., 40 tpy increases for either VOC and NO_X) and/or PM_2.5 (i.e., 10 tpy) and its precursors (i.e., 40 tpy increases for either SO₂ and NO_X).  

Ok – So what are my MERP’ing options?

Now that we have an explanation for what a MERP actually is and why you potentially may need one, let’s take a look at what a facility’s options are for developing a MERP. The way we view it, you have three potential paths to take:

1.      Demonstrate Equivalency with a Source Provided in Appendix A of the MERP Guidance

As part of the guidance provided, U.S. EPA conducted PM_2.5 and ozone photochemical analyses of a large dataset of hypothetical sources, which varied in the following characteristics:

• Areas of the country (i.e., north, south, east, west, central),
• Release height (i.e., high, low), and
• Emissions rates of PM_2.5 and ozone precursors (i.e., 500 tpy, 1000 tpy, 3000 tpy).

Facilities have the option to demonstrate that the source at their facility that they are evaluating under PSD is equivalent to one of the sources included in Appendix A of the MERP Guidance.  This equivalency will be based upon the characteristics listed above.  If a facility can demonstrate equivalency, the MERP can be developed using the values in Appendix A.  This would mean no air quality modeling, a shorter time frame for agency review and less resistance in the development of the MERP.

2.      Conduct Photochemical Modeling

If a facility cannot make the argument that their source is equivalent to one of the sources included in Appendix A, the facility will be required to conduct its own single source apportionment or brute force photochemical modeling analysis.  This approach will increase the resources and timing needed to develop the MERP.  However, once the analysis is completed, it can be used again in future PSD permitting applications, as required.

3.      Follow State Provided Guidance

If a facility is located in a state that is very active in the modeling realm, there is a possibility that the state agency may:

• Elect to deem U.S. EPA’s analysis as representative for the state’s sources;
• Expand on U.S. EPA’s analysis to provide additional sources for facilities to demonstrate equivalence to; or
• Develop its own state-specific photochemical modeling analysis.

We have a feeling that not many states will elect to go with any of the provided guidance scenarios listed, which would limit your options for determining a MERP to demonstrating equivalency with Appendix A of the MERP Guidance or conducting photochemical modeling.

Whatever your facility decides to do, keep in mind that addressing MERPs qualitatively or quantitatively requires a higher level of technical understanding of atmospheric chemistry and air quality modeling than what both you and the state agencies have had to consider before.  Fortunately, ALL4 has experienced staff who can explain in easy to understand terms what the MERP guidance means to you and how you should consider the options for conducting photochemical modeling.    First step in developing those skills? Reading this blog. Second step? Providing comments to U.S. EPA on the draft guidance by February 3, 2017. If you would like additional information regarding the guidance, or help with commenting, please reach out to me at mbarber@all4inc.com. Make sure to stay tuned to ALL4’s blog – something tells me this is only the beginning of exciting modeling changes (HINT HINT final Appendix W updates).

U.S. EPA Finalizes Reconsiderations to the Area Source Boiler MACT Rule

On September 14, 2016, the U.S. Environmental Protection Agency (U.S. EPA) took final action on the five issues raised by petitioners in their petitions for reconsideration of 40 CFR Part 63, Subpart JJJJJJ – National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources [commonly referred to as the Area Source Boiler Maximum Achievable Control Technology (MACT) rule].  U.S. EPA first announced the notice of reconsideration on January 21, 2015.

Similar to U.S. EPA’s response to petitioner’s issues raised relative to 40 CFR Part 63, Subpart DDDDD (the Major Source Boiler MACT rule), U.S. EPA removed the affirmative defense provisions from the Area Source Boiler MACT rule, citing the April 2014 Natural Resources Defense Council (NRDC) vs. U.S. EPA court ruling.  In addition, there were a number of technical corrections and other minor clarifications made to the rule.

This post provides a summary of the final U.S. EPA decisions on the five issues up for reconsideration that we outlined in our previous blog post.

Definitions of “Startup” and “Shutdown”

Consistent with U.S. EPA’s actions relative to the Major Source Boiler MACT rule, U.S. EPA finalized an alternate definition of “startup” to more clearly define when startup ends.  Specifically, the alternate definition states that startup ends four hours after the boiler supplies “useful thermal energy” (i.e., steam or hot water that meets the minimum operating parameters required for use) or produces electricity.  As we described in our previous blog, facilities that rely on this alternate definition will need to implement additional recordkeeping procedures for demonstrating compliance with the 4-hour extended startup period.  U.S. EPA also amended the definition of “shutdown” to incorporate the term “useful thermal energy” to more clearly define when shutdown begins.  These amended definitions are meant to better define when a boiler achieves steady-state operating conditions.

Particulate Matter (PM) Standard Exemptions for Oil-Fired Boilers

If you operate an oil-fired boiler, rated at 10 million British thermal units per hour (MMBtu/hr) or greater, that fires low-sulfur oil (i.e., less than 0.5% sulfur by weight), your boiler was previously exempt from the PM emissions limit.  However, beginning three years from the publication of these final revisions (i.e., September 14, 2019), your boiler now becomes subject to the applicable PM emissions limit in Table 1 of the Area Source Boiler MACT rule.  PM performance testing to demonstrate compliance is due 180 days after the emissions limit becomes effective (i.e., by March 12, 2020).

With this action, U.S. EPA has replaced the low-sulfur oil exemption with an exemption for oil-fired boilers that combust ultra-low-sulfur oil [i.e., less than or equal to 15 parts per million (ppm) sulfur].  In consideration of the comments received to the proposed revisions and review of available data, U.S. EPA concluded that boilers combusting oil containing 15 ppm of sulfur or less would not emit PM in excess of the potentially applicable PM emissions standards.  Therefore, if you operate an oil-fired boiler, rated at 10 MMBtu/hr or greater, that fires ultra-low-sulfur oil, you are exempt from having to meet a PM emissions limit and from having to conduct PM performance testing on the boiler.  However, if you start burning a new fuel type besides ultra-low-sulfur liquid fuel or gaseous fuels, a new performance test is required within 60 days.

Limited-Use Boiler Subcategory

Objections were raised by petitioners to the limited-use boiler subcategory (for boilers with a Federally-enforceable annual capacity of no more than 10%) in the original rule.  Boilers meeting these criteria were only subject to 5-year boiler tune-up requirements and were not subject to any additional emissions limitations or work practice standards.  U.S. EPA, in consideration of the comments received by petitioners, disagreed with the objections raised to the limited-use subcategory.  Due to the unpredictable operation of these boilers, U.S. EPA maintains that it is infeasible to conduct emissions testing and more frequent tune-ups would be difficult to schedule.  Therefore, U.S. EPA did not amend any of the existing requirements for limited-use boilers that were finalized in the February 2013 amendments to the Area Source Boiler MACT rule.

PM Performance Testing Requirements for Certain Boilers

U.S. EPA now requires PM performance testing every five years if, during your initial performance test, PM emissions from the boiler were less than or equal to half of the applicable PM emissions limit.  Previously, U.S. EPA did not require retesting of a boiler if the initial demonstration was below this threshold.  If you have already demonstrated that your PM emissions are less than half of the applicable limit, you have five years from the publication of these final revisions to conduct the next performance test (i.e., by September 14, 2021).  However, if you start burning a new fuel type in between 5-year tests a new performance test is required within 60 days, unless that new fuel is ultra-low-sulfur liquid fuel or gaseous fuels (because new or reconstructed boilers that combust only ultra-low-sulfur liquid fuel are not subject to the PM emissions limit and gas-fired boilers are exempt from the Area Source Boiler MACT rule).  This action does not change your PM performance testing obligations if the initial performance test results in PM emissions greater than half of the applicable PM emissions limit (i.e., you still must conduct testing every three years).

Fuel Sampling Requirements for Coal-Fired Boilers

U.S. EPA is requiring additional fuel sampling for mercury (Hg) based on the initial compliance demonstration for coal-fired boilers.  If the initial sampling demonstrates that Hg in the fuel mixture is less than or equal to half of the applicable Hg emissions limit, further fuel sampling is now required every 12 months thereafter.  Previously, U.S. EPA did not require retesting of a fuel mixture if the initial sampling was below the threshold.  If you have already demonstrated that Hg levels in your fuel mixture are less than half of the applicable limit, you have 12 months from the publication of these finalized reconsiderations to conduct the next round of fuel sampling (i.e., by September 14, 2017).  Additional fuel sampling is required before burning any new fuel type.  This revision does not change the quarterly fuel sampling obligations if the initial sampling results are greater than half of the applicable Hg emissions limit.

If you have questions about how these reconsiderations will affect you, please reach out to me at (610) 933-5246, extension 155, or at cchinofsky@all4inc.com.

U.S. EPA Proposed 2015 Ozone NAAQS Implementation Rule

On November 2, 2016, the United States Environmental Protection Agency (U.S. EPA) proposed an implementation of the 2015 National Ambient Air Quality Standard (NAAQS) for ozone (2015 ozone NAAQS) with requirements that would apply to states with nonattainment areas and states in the ozone transport region (OTR).  The proposed rule, which was subsequently published in the Federal Register (FR) on November 17, 2016, largely resembles the implementation rule promulgated for the 2008 ozone NAAQS and establishes the framework for U.S. EPA, state, tribes, and local air quality agencies for planning to achieve the 2015 ozone standards¹. The three key features of the proposed rule which might impact you are as follows:

Nonattainment Area Classification

The proposed rule establishes the new nonattainment area classification thresholds for designation purposes.  The rule also sets the deadlines for areas to attain the 2015 ozone NAAQS.  The new classification thresholds and number of nonattainment areas potentially subject to each classification (based on 2013-2015 ambient air monitoring data) are as follows:

Based on this new proposed classification, there will be a total of 47 areas classified as marginal nonattainment areas with a potential 3-year attainment date (i.e. attainment by year 2020).

Nonattainment NSR Offset Requirements

Pursuant to 40 CFR Part 51.165 and 40 CFR Part 51 Appendix S, air agencies can issue a permit to a new or modified major stationary source located in an ozone nonattainment area provided that the nonattainment New Source Review (NNSR) emissions offset requirements are met.  Specifically, when NNSR air permitting occurs in ozone non-attainment areas, project-related emissions increase of volatile organic compounds (VOC) and nitrogen oxides (NO_X) must be offset.  IPT regulates how these VOC and NO_X emissions (i.e., ozone precursors) are offset and how offsets of one precursor pollutant can be substituted for another precursor pollutant (i.e., inter-precursor trading – IPT).   However, as part of the proposed rule, U.S. EPA plans to revise the NNSR offset requirements by requiring technical justification for the use of IPT to meet the NNSR offset requirements.  This update to the previously finalized rule is as a result of a petition for reconsideration filed by a coalition of environmental and health advocate groups.

The U.S. EPA is proposing that state, local, and tribal air agencies demonstrate that the use of IPT provides equivalent or greater air quality benefits for ozone concentration reductions in the ozone nonattainment areas as part of the implementation plan submitted by the respective agency.  U.S. EPA is proposing to allow the respective agencies to apply IPT provisions on a case-by-case basis when permitting NNSR projects.  Accordingly, each permit applicant for a NNSR project who wishes to use ozone IPT to satisfy the NNSR emissions offset requirement would be required to calculate how much one ozone precursor (e.g., VOC) would need to be offset by the other ozone precursor (NO_X) in order to be equivalent.  The development of this IPT ratio would require the permit applicant to perform photochemical modeling or other technical demonstrations.  U.S. EPA included a Technical Guidance Document (TGD) on demonstration of IPT for ozone to assist stakeholders.  The TGD is available in the docket for this proposed ozone implementation rule.  ALL4 can assist you in reviewing the TGD, analyze the impact of on your potential NNSR project, and can also support you in drafting comments on the regulations.  Detailed discussion on the TGD and its implementation will be discussed in a separate blog.

Revoking the 2008 Ozone NAAQS

Last but not least, the proposed rule provides two options for revoking the 2008 ozone NAAQS as follows:

Option 1 will revoke the 2008 NAAQS in all areas one year after the 2015 ozone NAAQS designations are finalized.  Considering that the U.S. EPA is required to finalize the 2015 designations by October 2017 which will go into effect by December 2017 (60 days after publishing in FR), the 2008 NAAQS can be revoked as early as December 2018.  This option, however, will require that the air quality agencies establish anti-backsliding measures if the areas were classified as nonattainment for both the 2008 and 2015 NAAQS.

Option 2 will revoke the 2008 NAAQS only in the areas that will be designated as attainment for the 2008 NAAQS one year after the effective date of the designations for each area for the 2015 ozone NAAQS.  That is, only the areas designated as attaining the 2015 ozone NAAQS by December 2018 will be allowed to revoke the 2008 NAAQS by December 2018, but not any earlier.  For the rest of the areas, the 2008 NAAQS will continue to apply until the area can be re-designated as attainment for the 2015 ozone NAAQS.

The finalization of this proposed rule is anticipated to have impact on our clients not only because State Implementation Plans (SIPs) will be changed but also because the NNSR permitting process will be affected.  The comments on this proposed implementation rule are due to U.S. EPA by January 17, 2017.  Stay tuned for my next blog on the Technical Guidance Document on the development of IPT ratios.

TCEQ’s RAP: Committing to Streamline Air Permitting, How Fitting

As promised in my November 8, 2016 blog, let’s discuss the much anticipated implementation of the newest Texas Commission on Environmental Quality (TCEQ) permitting program: Readily Available Permit, otherwise known as RAP.  To start our discussion, let’s travel back in time to the 73^rd Texas Legislature – Senate Bill (SB) 248 Section 2303.054.  This SB required TCEQ to streamline, to the greatest extent possible, the consideration of air permitting applications.  To demonstrate compliance with this legislation, TCEQ has been in action to create innovative ways to streamline the air permitting process.  That brings us to TCEQ’s latest effort to make the air permitting process more efficient: RAP.  Before we dive into the details, please note that TCEQ presented on the RAP program at their annual Advanced Air Permitting Seminar held in early October 2016.  The official slide deck used for the presentation can be found here.

Why RAP: A More Efficient Way of Permitting! Clap, Clap, Clap!

The RAP program is intended to streamline the air permitting process.  The nuts and bolts of a RAP require an applicant to file all technical information associated with a project up-front in an application.  Having the project information presented up-front, in turn will eliminate the back-and-forth communication, which occurs between TCEQ and the permittee when TCEQ needs additional project information.  By eliminating this additional time-consuming communication step, TCEQ intends to increase the efficiency for the permitting of specific projects (see below for specifics).  Therefore, once the up-front project information has been received from the permittee, TCEQ can issue a draft permit and decision for publication.  For ALL4, adjusting to the RAP program will be business as usual.  ALL4 already implements the philosophy of providing the information an agency requires up-front in its air permit applications.

What is a RAP?

TCEQ is currently developing a RAP for minor sources only.  In the future TCEQ may expand the program to be used for more complicated Prevention of Significant Deterioration (PSD)/Nonattainment New Source Review (NNSR) permitting; but for now, a RAP will only be used for minor sources.  For select minor sources, TCEQ will prepare a template air permit with specific conditions intended for specific source categories.  Once TCEQ reviews and approves all of the up-front information provided by the permittee, TCEQ will issue a permit with pre-approved permit conditions that cannot be customized.  Because this permit would be categorized as “readily available,” the air permitting process would not only reduce the amount of time needed for TCEQ to write and review a site-specific permit, it would also reduce the amount of time needed for the applicant to prepare project information since TCEQ is essentially identifying all of the key informational needs upfront.

From an air permitting perspective, a RAP will be subject to the same procedural requirements as case-by-case permits; therefore, the public notice requirements (e.g., sign posting, notice of receipt and intent [NORI], notice of application and preliminary decision [NAPD], etc.) will be required, along with health effects evaluations, and a best available control technology (BACT) analysis.  As required in case-by-case permits, a RAP will also be required to be in compliance with state and Federal air quality rules (e.g., State Implementation Plans [SIP], Standards of Performance for New Stationary Sources [NSPS], National Emission Standards for Hazardous Air Pollutants [NESHAP]).  TCEQ is in the process of developing an official toolkit to further help streamline the RAP air permitting process and facilitate the air permit application process for permittees.  Stay tuned for a blog discussing this toolkit.  

Is there a Limitation to this Permitting Creation?

It is to be understood that because a RAP will contain pre-approved conditions, the air permit will not be able to be customized.  Also, in order for a RAP to be approved, a source must meet all existing requirements specified in that RAP.  Currently the RAP program is being developed for a limited number of sources, which include simple-cycle combustion turbines, fuel marketing terminals, and certain surface coating operations.  TCEQ may expand this list in the future, but for now, the list only includes the aforementioned source categories.

When Will RAPs be Available?

While there is no set or published schedule, it is anticipated that the RAP program will be available for some sources in early 2017.  ALL4 will be keeping an eye on the development of this program and will assess its feasibility to support our clients.  As usual, we will keep you updated on the topic.  Feel free to reach out to me at fdougherty@all4inc.com, if you have any questions.

A New Take on Air Dispersion Modeling: Re-Entrainment Evaluations

Facilities are typically introduced to the world of air dispersion modeling when they are required to demonstrate that a proposed project will not exceed regulatory thresholds, such as maximum allowable air toxics screening levels or the National Ambient Air Quality Standards (NAAQS).  However, over the past year, ALL4 has been using air dispersion modeling for another purpose: re-entrainment evaluations.  Re-entrainment is an atmospheric event that occurs when suspended particles or compounds that are exhausted in a plume are carried back into a plume of air (you may recognize the term if you have a background in cloud physics or chemistry).  In our projects, we have been interested in understanding how emissions of nitrogen oxides (NO_X) from emergency generators, boilers, and/or combined heat and power (CHP) units, for example, can get re-entrained into a building through the fresh air intake system.  We utilize air dispersion modeling to predict the concentration of pollutants of concern at these air intakes and compare the predicted concentrations with the NAAQS and published health guidelines, like those from the Occupational Safety and Health Administration (OSHA) or American Conference of Governmental Industrial Hygienists (ACGIH).  While the NAAQS were developed for ambient air external to buildings, they are concentrations deemed to be acceptable to human and environmental health and therefore can be used as another threshold, in addition to the health guidelines, to which ALL4 can compare re-entrainment modeling results.

So what prompts this kind of evaluation?  A re-entrainment evaluation is not required under any Federal or state air quality regulation; it is instead a consideration during the design phase of a capital project or in response to comments about odor in an existing facility.  To date, our experience has revolved around healthcare facilities and the following capital projects, but this evaluation can apply practically anywhere:

• The construction of a brand new facility.
• The addition of a new wing or patient tower to an existing facility.
• The replacement of existing equipment at a facility.
• The addition of new equipment at a facility.

While it is important to understand the potential for re-entrainment in any industry, the distinction about healthcare facilities, such as hospitals, is that the same people (e.g., patients, doctors) may occupy them 24-hours per day and for extended periods of time.  In addition, patients make up a sensitive population in a concentrated area.  The re-entrainment evaluation aims to identify whether there is a potential to expose this population to products of combustion and other contaminants through re-entrainment.  The results of the re-entrainment evaluation can shape design choices, such as equipment type, location, and/or stack parameters, if the results of the modeling are unfavorable.  Thus, it is important to set up an accurate model and complete the evaluation during the design phase of a project.

To evaluate the potential for re-entrainment, ALL4 uses the American Meteorological Society/Environmental Protection Agency Regulatory Model (AERMOD).  The re-entrainment modeling is completed similar to a NAAQS analysis, such that the model requires 5-years of representative meteorological data, equipment stack parameters and location, building information, and receptors.  The meteorological data can be downloaded from the National Weather Service, but must be processed prior to use.  The stack parameters include height, diameter, exhaust temperature, exhaust velocity, and of course, emissions rates for the pollutants of concern.  Building information is extremely important since we need to represent building downwash as accurately as possible.  This includes building layouts, dimensions, and heights, including the heights of varying tiers.  The receptors are the specific fresh air intake locations, so that AERMOD can predict the concentrations at those points of entry into the facility.

Since these evaluations usually involve only a small number of receptors and a handful of sources, the run time of the model is fast.  The intricacies of this type of air dispersion modeling occur in the data gathering and model set up.  For example, the model should be set up for both “worst case” and “normal” operating scenarios of the modeled sources to reflect situations like routine testing and power outages.  Therefore, the model must be run several times for a re-entrainment evaluation to vary the number of units operating, fuel type, and system loads.  Hence, it is important to identify all contributing sources of emissions and how they operate.  We have even modeled a helipad, by estimating emissions from an idling helicopter.

As for the actual emissions and report, so far we have modeled carbon monoxide (CO), NO_X, and surrogates for volatile organic compounds (VOC), like formaldehyde, to compare the predicted concentrations at the air intake receptors with the published health guidelines.  This type of evaluation involves post processing of the results of the air dispersion modeling to compare with the guidelines, and finally a presentation of values, comparisons, and corresponding operating scenarios in the final report.

Re-entrainment evaluations are a new spin on typical air dispersion modeling, focusing on the potential for exposure to emissions that could be pulled back into a building through the fresh air intake system, as opposed to assessing off-site impacts.  If you are at a facility and have concerns about re-entrainment, or at an engineering firm responsible for the design of a facility, such as a hospital, consider enlisting ALL4 to perform a re-entrainment evaluation.  The evaluation could identify potential problems in time to make adjustments and demonstrate your due diligence.  Sometimes the potential for an exposure issue can be avoided by raising a stack height a few feet or turning a generator around.  Seems like a small price to pay to protect human health – I know our clients have appreciated the peace of mind!  Give me (610.933.5246 x129, aessner@all4inc.com) or Sharon Sadler (x503, ssadler@all4inc.com) a call if you are interested in learning more!