Greenhouse Gas Permitting – You May Be Doing Too Much

U.S. EPA amended its Prevention of Significant Deterioration (PSD) and Title V regulations on August 19, 2015 in order to formally eliminate the regulatory provisions that were identified as vacated within the April 10, 2015 Coalition Amended Judgment. Specifically, the Tailoring Rule’s Step 2 PSD permitting requirements at 40 CFR §51.166(b)(48)(v) and 40 CFR §52.21(b)(49)(v) as well as the regulations that require U.S. EPA to consider further phasing-in GHG permitting requirements at lower GHG emission thresholds at 40 CFR §52.22, 40 CFR §70.12, and 40 CFR §71.13 were removed from the Code of Federal Regulations.

Pursuant to this action, a facility not yet considered a major source with respect to the PSD program cannot trigger major source status on the basis of GHG emissions alone. And, as was further outlined in the December 19, 2014 “No Action Assurance Memo” issued by the Office of Enforcement and Compliance Assurance (OECA), U.S. EPA is no longer authorized to enforce the terms and conditions of a PSD permit that was historically issued under these terms, or for related GHG terms and conditions that are contained in the source’s Title V permit. Pursuant to an earlier rulemaking finalized on May 7, 2015, applicants may apply to rescind an existing PSD permit if their regulated sources fall under Step 2 of the PSD permitting process on the basis of GHG alone, in which case the No Action Assurance Memo would no longer be applicable to that source once its Step 2 permit is rescinded.

The August 19, 2015 action does not change the applicability of 40 CFR §51.166(j), 40 CFR §51.166(b)(48)(iv), 40 CFR §52.21(j), or 40 CFR §52.21(b)(48)(iv). For sources that trigger PSD based on emissions of pollutants other than GHG (i.e., anyway sources), the PSD Best Available Control Technology (BACT) requirement continues to apply as is outlined in the August 19, 2015 Federal Register Notice.

While these changes bring PSD and Title V regulations closer to the ruling outlined in the Coalition Amended Judgment, U.S. EPA will continue to make changes to their PSD and Title V regulations to fully implement the Coalition Amended Judgment. Future rulemakings are expected to (1) revise additional definitions within the PSD regulations and (2) remove the remaining vacated portions of the Title V regulations which require a stationary source to obtain a Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. Be on the lookout for updates concerning these future rulemakings on ALL4’s website, where you can expect to find the latest in regulatory news related to climate change!

U.S. EPA Proposed Amendments to Subpart OOOO and Proposed a New Subpart OOOOa

The anticipation ended on August 18, 2015 when the U.S. Environmental Protection Agency (EPA) proposed to amend 40 CFR Part 60, Subpart OOOO (Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution) and create a new subpart OOOOa.  Subpart OOOO would be amended to apply to facilities constructed, modified or reconstructed after August 23, 2011 (i.e., the original proposal date of subpart OOOO) and before the proposal date of the new subpart OOOOa.  Subpart OOOOa would apply to facilities constructed, modified or reconstructed after the date the proposal is published in the Federal Register and would include current Volatile Organic Compound (VOC) requirements already provided in subpart OOOO as well as new provisions for methane and VOC across the oil and natural gas source category.

U.S. EPA will receive comment on the proposals for only 60 days after it is published in the Federal Register.  If you haven’t started reviewing the proposals, start now.  The publication is nearly 600 pages long!  ALL4’s E&P Team is here to help you wade through portions of the proposal.  In fact, this blog addresses the low hanging fruit as much of the content comes from U.S. EPA’s Fact Sheet.

Takeaways from the U.S. EPA Fact Sheet

U.S. EPA’s proposal would:

• Require that the oil and natural gas industry also reduce/control methane.
• Require methane and VOC reductions for sources that the 2012 standards did not address (e.g., natural gas capture from hydraulically fractured oil wells).  U.S. EPA published a Table that illustrates the differences in regulated sources between the 2012 standards and the 2015 proposed standards.
• Extend emission reduction requirements further “downstream”, covering equipment at natural gas transmission compressor stations and at gas storage facilities, which was not regulated in the 2012 standards.
• Require leak detection and repair program.
• Limit emissions from new and modified pneumatic pumps.
• Provide guidelines for states to reduce VOC emissions from existing oil and gas sources in certain ozone nonattainment areas and in the Ozone Transport Region.
• Clarify Federal air permitting requirements as they apply to the oil and natural gas industry.

Sources already subject to the 2012 standards for VOC reductions are not expected to have to install additional controls, because the best system of emission reduction (BSER) for methane is the same as for VOC.

We intend to dig into the rule and prepare subsequent blogs on more specific topics that we think oil and gas operators will find helpful.  We invite you to interact with us by posting questions or provide ideas for future blog topics.  In the meantime, we dug a little deeper into the well completion requirements and noted the key observations below:

Key Observations for Source Requirements

U.S. EPA has recognized that lower production well sites would generally result in lower fugitive emissions and such well sites are mostly owned and operated by small businesses.  Due to concerns about the burden of fugitive emission requirements on small businesses, U.S. EPA is proposing to exclusions for low production well sites.  The sections below provide additional information concerning exclusions.

Well Completions

• Wells with a gas-to-oil ratio (GOR) of less than 300 scf of gas per barrel of oil produced would not be affected facilities subject to well completion provisions.
• U.S. EPA has explicitly solicited comment on whether a GOR of 300 is the appropriate applicability threshold.  Be sure to submit your comments to support your views. 

Fugitive Emissions from Well Site & Compressor Stations

• The proposal acknowledges that some well sites consist only of one or more wellhead and have no ancillary equipment.  Thus, the proposal would exclude fugitive emission requirements for well sites that contain only one or more wellhead.
• The proposal would also exclude low producing well sites.  A low producing well site would be defined by the average combined oil and natural gas production less than 15 barrels of oil equivalent (boe) per day averaged over the first 30 days of production.

Liquids Unloading

• Due to insufficient information, the proposal does not include standards for liquids unloading.
• U.S. EPA has explicitly solicited comment on nationally applicable technologies and techniques that can be applied to new gas wells that will reduce methane and VOC emissions from liquids unloading.

We will be discussing the Draft Control Techniques Guidelines for reducing VOC emissions from existing oil and gas sources in certain ozone nonattainment areas and states in the Ozone Transport Region.  We will also be discussing the proposed Source Determination Rule that will determine when multiple pieces of equipment and activities in the oil and gas industry must be deemed a single source.

Stay tuned.

Contact JP Kleinle (610) 933-5246, extension 120 or at jkleinle@all4inc.com to discuss the content of this blog or any other oil and gas related topics.

Five Things to Consider Before the January 31, 2016 Major Source Boiler MACT Compliance Date

You’ve determined whether your boilers or process heaters are subject to emissions limits, and if so, whether your affected sources can meet those limits.  If not, you’ve evaluated options for reducing emissions so that they can meet those limits.  You’ve received approval from your local air permitting authority to make the necessary changes.  Your project is moving along and you’re getting closer and closer to the finish line.  January 31, 2016 is right around the corner now, but there is still much to be done.  Here are five things to consider before the compliance date.

1.  There is still time to receive a 1-year extension to the compliance date.

Is your emissions reduction project taking a little longer than expected?  As long as you are installing air pollution controls or replacing your boilers, you are eligible for a 1-year extension to the January 31, 2016 compliance date.¹  Although it’s not a guarantee, most permitting authorities will grant a valid extension request without question.  To request the extension, submit a written request to your local air permitting authority with your justification for the extension no later than 120 days prior to the January 31, 2016 compliance date (i.e., by October 3, 2015).  Remember, the justification for the extension should be “nonfrivolous” and for purposes of installing air pollution controls or replacing your boilers – it cannot be simply due to rule uncertainty (more on that later).²  Doesn’t January 31, 2017 sound nice?

¹ See 78 FR 7143 and §63.6(i)(4)(i)(A).
² See §63.6(i)(4)(i)(B).

2.  Compliance plans must be in place 60 days prior to conducting your performance test, fuel sampling, and/or performance evaluation(s).

If your boilers or process heaters are subject to emissions limits, you will need to develop at least two types of compliance plans, and potentially more depending on your selected method(s) for demonstrating compliance.  If you will be demonstrating compliance by conducting a performance test, you will need a Performance Test Plan, and if your compliance program requires fuel sampling (either as part of a performance test or if you are using fuel sampling in lieu of performance testing), you will need a Fuel Monitoring Plan.  Ongoing monitoring (e.g., via CEMS, COMS, CPMS¹) will require a performance evaluation and an associated Monitoring Plan.

These plans need to be submitted only upon request (at least 60 days prior to conducting the given compliance demonstration; unless using an alternative analytical method for fuel sampling, in which case it must be submitted for approval).  Therefore, these plans must be prepared and “at the ready” to be submitted sooner than at least 60 days prior to conducting the initial compliance demonstration.

If you will be utilizing emissions averaging or efficiency credits to demonstrate compliance, you will need an Emissions Averaging Plan and an Energy Efficiency Implementation Plan, respectively.  Last but not least, the proposed reconsiderations to the rule contain a requirement to develop a Startup and Shutdown Plan.  Check out our Boiler MACT Compliance Plan Worksheet, and head on over to Susie’s 4 The Record article for more information.

¹ CEMS = Continuous Emissions Monitoring System; COMS = Continuous Opacity Monitoring System; CPMS = Continuous Parametric Monitoring System.

3.  Performance test results must be submitted to U.S. EPA electronically.

Once you’ve conducted your performance test and/or fuel sampling, you will need to use U.S. EPA’s Compliance and Emissions Data Reporting Interface (CEDRI), accessed through their Central Data Exchange (CDX), to submit your results to their WebFIRE database in a file format generated by using their Electronic Reporting Tool (ERT).  Sounds simple enough, right?  We didn’t think so, either.  Results must be submitted within 60 days after the completion of performance tests, so give yourself as much time as possible to complete this step, and contact us for support.  This information just scratches the surface of submitting electronic data to U.S. EPA, so check out Sean’s blog post for more details.  Looking for more on the performance test itself?  Chuck’s head is spinning, too.

4.  The Notification of Compliance Status is due no more than 60 days after all affected sources have demonstrated compliance.

Here is some potentially good news.  Let’s say you have two affected sources with the 1-year extension and three affected sources that do not.  U.S. EPA has confirmed that the Notification of Compliance Status (NOCS) must be submitted no more than 60 days after the completion of the compliance demonstrations for the last affected source, even those with a 1-year extension, based on the following language from the rule (emphasis added):

§63.7545(e) If you are required to conduct an initial compliance demonstration as specified in §63.7530, you must submit a Notification of Compliance Status according to §63.9(h)(2)(ii). For the initial compliance demonstration for each boiler or process heater, you must submit the Notification of Compliance Status, including all performance test results and fuel analyses, before the close of business on the 60th day following the completion of all performance test and/or other initial compliance demonstrations for all boiler or process heaters at the facility according to §63.10(d)(2). The Notification of Compliance Status report must contain all the information specified in paragraphs (e)(1) through (8), as applicable. If you are not required to conduct an initial compliance demonstration as specified in §63.7530(a), the Notification of Compliance Status must only contain the information specified in paragraphs (e)(1) and (8).

Sources without a 1-year extension must still demonstrate compliance by the original applicable deadlines; however, the NOCS for all affected sources need not be submitted until 60 days after the final initial compliance demonstration is complete.

5.  The rule may change right before or even after the compliance date.

As I alluded to earlier, there are still proposed reconsiderations out there for Major Source Boiler MACT (as well as Area Source Boiler MACT and the CISWI¹ rule for that matter).  Due to U.S. EPA’s focus on the Clean Power Plan, we have learned that the proposed reconsiderations may not be finalized until close to, or even after, the January 31, 2016 Major Source compliance date.  The proposed reconsiderations could impact startup and shutdown provisions, excursions when utilizing a particulate matter (PM) CPMS, and the carbon monoxide (CO) emissions limit for certain boilers.  Learn more by reading Mark’s blog post on the subject.

Given the uncertainty around the potential changes, facilities may be forced to prepare for these proposed changes, even though they may not be finalized as proposed.  We’ll keep you posted on updates to the timeline as they are available.

¹ CISWI = Commercial and Industrial Solid Waste Incinerator

These are just five of the many things to consider as we get closer and closer to the Major Source Boiler MACT compliance date.  Have you conducted your energy assessments and initial tune-ups?  Will you be testing before January 31, 2016 or within the allowable 180 days after that date (i.e., by July 29, 2016)?  What else have you learned during your Boiler MACT journey?  Let me know in the comments, and don’t hesitate to give me a call with any questions about the information presented here.

Related content:

• ALL4’s 4 Rules (Boiler MACT) Initiative Page contains lots of resources to help you navigate Boiler MACT.
• Testing soon?  Check out Chuck’s blog post.
• Takeaways from NCASI’s June 2015 Boiler MACT session.

Sulfur Dioxide (SO2) Data Requirements Rule (DRR): The Final Rule

On August 10, 2015, the U.S. Environmental Protection Agency (U.S. EPA) submitted the final version of the DRR (40 CFR Part 51, Subpart BB) for the 2010 one (1)-hour sulfur dioxide (SO₂) National Ambient Air Quality Standards (NAAQS). The final rule looks pretty familiar (if you need a refresher check out Colin and Frank’s articles), but there are a few changes worth noting:

1. Agencies must identify sources in their jurisdictions that have SO₂ emissions greater than 2,000 tons per year (tpy) during the most recent year for which emissions data are available. The rule no longer contains applicability criteria based on other emissions thresholds or populations in a given area.
2. Agencies now have three (3) options to characterize air quality:
   a. Air quality modeling,
   b. Ambient monitoring, or
   c. Establishing enforceable permit limits to keep the source(s) below the
   2000 tpy threshold
3. Agencies must identify the approach to be used for affected sources by July 1, 2016
4. For sources using the modeling approach, a protocol must be provided to U.S. EPA by July 1, 2016, and submit modeling analyses by January 13, 2017
5. For sources using the monitoring approach, monitors must be installed and operational by January 1, 2017
6. For sources electing to take a limit, the limit must be adopted and effective by January 13, 2017

ALL4 currently is assisting several clients with DRR evaluations and would be happy to assist you in evaluating and implementing your compliance approach. Feel free to contact Colin McCall at (678) 460-0324 x206 with questions.

A Review of 1-Hour NO2 NAAQS Air Quality Modeling

During the development of this 4TR article, proposed revisions to Appendix W to 40 CFR Part 51 “ Guideline on Air Quality Models (Guideline) were published in the Federal Register. As a result of revisions which propose to establish Tier 3 nitrogen dioxide (NO₂) atmospheric chemical reaction screening techniques as default methods, applicants will no longer need to gain U.S. EPA approval after the Guideline revisions are finalized. In the meantime, the guidance provided below related to the Tier 3, NO₂ atmospheric chemical reaction screening techniques must be provided for U.S. EPA regional approval for permits issued before the Guideline is finalized. The Guideline is anticipated to be finalized in the spring of 2016.

I’ve been involved in quite a few natural gas combined-cycle power plant projects and it seems like the critical issue is related to showing compliance with the 1-hour NO₂ National Ambient Air Quality Standard (NAAQS) [188 micrograms per cubic meter (μg/m³) or 100 parts per billion (ppb) based on the average (5 years or 1 year depending on whether you using NWS or onsite data) of the 98^th percentile of maximum daily 1-hour concentrations]. This is especially challenging when evaluating start-up related emissions. As natural gas combined-cycle power plants have become more efficient, it has led to the ability to start-up faster to quickly meet energy demand. Even though these units are more fuel efficient than ever, the fact that they can now be started up in less than one hour (usually daily, Monday through Friday) to meet peak energy demand has actually made complying with the 1-hour NO₂ NAAQS more difficult for two (2) reasons:

1. Since these more efficient units start-up in less than one hour, the start-up emissions can’t be averaged across multiple hours and
2. The total number of start-ups that occur in a year.

For these two (2) reasons, State agencies don’t feel that start-up NO₂ emissions meet the definition of an intermittent emissions unit as summarized in U.S. EPA’s March 1, 2011 Memorandum “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO₂ NAAQS and are, therefore, requiring start-up NO₂ emissions to be evaluated as continuously occurring (i.e., the most conservative approach). Because of interpretation, we have had to work through some less conservative options for showing compliance with the 1-hour NO₂ NAAQS for evaluating start-up NO₂ emissions and even for normal operation process sources.

First of all, gone are the days of using the conservative assumption of full conversion of nitric oxide (NO) to NO₂, which is referred to as the Tier I approach. In all of the 1-hour NO₂ modeling that we have completed, a less conservative Tier 2 or Tier 3 approach has been required to demonstrate compliance with the 1-Hour NO₂ NAAQS. The current status of these methods is summarized well in U.S. EPA’s September 30, 2014 Clarification of the Use of AERMOD Dispersion Modeling for Demonstration Compliance with the NO₂ NAAQS memorandum. However, I’ve summarized them below with some things to keep in mind if using either of these options.

• Tier 2 Method multiply Tier 1 results by empirically derived NO₂/NO_Xratios with the national default ratio of 0.8 for hourly NO₂.
• Tier 3 Method detailed screening methods may be used on a case-by-case basis. At this time, the Ozone Limiting Method (OLM) and the Plume Volume Molar Ratio Method (PVMRM) are considered to be appropriate screening techniques.

The Tier 2 ambient ratio method (ARM) is a simple approach that can be used that does not require additional approval beyond your State agency. In addition the current version of AERMOD has an option to automatically perform the ratio. Depending on the magnitude of your 1-hour NO_X emission rate and surrounding terrain, this approach is a viable option for demonstrating compliance with the 1-hour NO₂ NAAQS in certain scenarios. Another more recent Tier 2 method is the Ambient Ratio Method 2 (ARM2), which is based on an evaluation of the ratios of NO₂/NO_X from U.S. EPA’s Air Quality System (AQS) record of air quality data. ARM2 was developed by categorizing all the AQS data into bins of 10 ppb increments for NO_X values less than 200 ppb and into bins of 20 ppb for NO_X in the range of 200-600 ppb. The ARM2 equation is then used to compute NO₂/NO_X ratios based on the total NO_X levels. Since ARM2 is currently classified as a non-default beta option in AERMOD, it is currently treated like a Tier 3 option that requires U.S. EPA regional approval. However, in addition to Tier 3 revisions described above, the Appendix W revisions propose to replace ARM with ARM2 as the Tier 2 option. In any event the following four (4) criteria must be met to justify that ARM2 is appropriate for a particulate project:

1. The Tier 1, total conversion results should be around 150-200 ppb. Total conversion results closer to 200 ppb may be justified if the project site is located in an area of lower background ozone concentrations.
2. If Tier 1 total conversion results are greater than 200 ppb, ARM2 may be appropriate if the project site is located in an area with generally low background NO₂ levels (less than about 20-30 ppb).
3. If Tier 1 total conversion results in greater than 200 ppb, ARM2 may be appropriate if it has been demonstrated that the primary sources (i.e., greater than 95% of modeled NO_X emissions) have an NO₂/NO_X in-stack ratio (ISR) less than 0.2. U.S. EPA preference is for actual testing results to identify sources ISRs.
4. Background ozone concentrations should generally be below 80-90 ppb, with no more than seven (7) hourly concentrations in a year greater than 80-90 ppb. ARM2 is a less conservative option that requires a better understanding of actual ISRs.

The Tier 3 options (OLM and PVMRM) incorporate the atmospheric chemical reaction referred to as titration to convert NO to NO₂ in the presence of ozone. The Tier 3 options also currently require U.S. EPA regional approval (until Appendix W revisions are finalized) for use and source-specific ISR stack test data and representative hourly ozone data for the period corresponding to the meteorological dataset being used for the air quality modeling evaluation. Most ozone ambient monitoring programs only collect data during the ozone season (typically April 1^st through September 30^th). Therefore, in most cases, supplementing ozone data from more distant year-round ozone ambient monitoring stations is required. In cases where representative year-round ozone ambient monitoring stations aren’t available another approach is to extrapolate winter conditions from the shoulder seasons from ozone monitors only operated during the ozone season.

In most cases, Tier 3 represents the least conservative option for 1-hour NO₂ NAAQS air quality modeling. However, because each site has a unique set of specific inputs; it is always recommended to evaluate available methods to determine the most appropriate option for your particulate site. Another recommendation that was included in U.S. EPA’s September 30, 2014 memorandum when using a Tier 3 option is to use a default ISR of 0.2 for any local sources included in a NAAQS air quality modeling evaluation that is greater than four (4) kilometers from the applicant site. This updated default ISR for local sources has made the difference between showing compliance with the 1-hour NO₂ NAAQS and not. Much like ARM2, there is the possibility that the Tier 3 options will be upgraded to default status in the final Appendix W revisions.

In addition to less conservative options for accounting for NO to NO₂ conversion, another important component to a 1-hour NO₂ NAAQS air quality modeling evaluation is the incorporation of representative background NO₂ concentrations. There are currently two (2) options outlined in U.S. EPA guidance memoranda for incorporating 1-hour NO₂ background concentrations. The Tier 1 option is to add the monitoring design value concentration [three (3) year average of the 98^th percentile of daily maximum 1-hour concentrations] to the modeled design concentration. This approach is very conservative and in most cases the Tier 2 option for incorporating background concentrations is required. The Tier 2 approach allows for the incorporation of seasonal and diurnal fluctuations. Specifically, the 3rd highest monitored NO₂ concentration for each hour (1-24) from each day over one (1) season from the last three (3) available years is calculated and the appropriate value is added to the modeled concentration. The most recent version of AERMOD has the ability to incorporate this approach or alternative approaches for varying background monitored concentrations to be added to modeled concentrations.

The last thing to consider when evaluating the 1-hour NO₂ NAAQS is the operating schedule of the source being modeled. This is especially true when evaluating start-up conditions. This approach should be used with caution because there is always the possibility that whatever operating schedule that is incorporated into the model will end up as an operating limit in your permit. However, close attention should be paid to limits already accepted as part of a permit either through emission restrictions or operating hours. In most cases, an operating schedule can be developed for air quality modeling purposes that is more conservative than existing limits but less conservative than assuming 8,760 hours of operation. Since this approach falls into an area with little guidance from U.S. EPA, it is recommended that you work closely with your State agency before proceeding very far down this path.

It should be noted that less conservative approaches for incorporating background concentrations and operating schedules as outlined above can also be utilized for the other 1-hour NAAQS, sulfur dioxide (SO₂), as well as for the fine particulate (PM_2.5) 24-hour and annual NAAQS. However, PM_2.5 comes with a host of other air quality modeling issues that I will save for another 4 The Record.

Since the incorporation of more stringent 1-hour NAAQS (NO₂ and SO₂), it has become necessary to incorporate less conservative modeling options when addressing Prevention of Significant Deterioration (PSD) requirements. Since the most recent version of Appendix W predates the 1-hour NAAQS (Appendix W was last amended in November 2005), U.S. EPA has had to play catch up by releasing guidance memoranda outlining these approaches. Now that proposed revisions have been published with favorable updates to NO₂ modeling techniques, I strongly encourage the regulated community to take this opportunity to provide comments in support of the update of ARM2 as a Tier 2 option and Tier 3 options gaining regulatory default status.

For more information on 1-hour NO₂ NAAQS air quality modeling please Dan Dix at ddix@all4inc.com or 610.933.5246 x118.

Ethylene Production – A Tale of Explosive Growth and Air Quality Compliance

ALL4’s Oil and Gas Sector Initiative was conceived in response to the renewal of the domestic oil and gas industry, associated primarily with the use of hydraulic fracturing (or fracking) and horizontal drilling in shale formations (e.g., Marcellus, Haynesville, Bakken, Eagle Ford) and the impact of greatly expanded oil and gas production on gathering/midstream operations, gas transmission/distribution systems, and domestic oil refining operations. With the United States now the largest producer of natural gas in the world , it is logical that the availability of natural gas liquids (NGL) associated with the processing of all of that natural gas is very high. The extraction of ethane, an NGL, from natural gas creates a feedstock for the production of ethylene (or ethene), which is the world’s highest volume produced chemical and the basis for bottles, toys, clothes, windows, pipes, carpet, tires, and many other products. In the U.S., it currently costs about $300 to make one (1) ton of ethylene, down steeply from $1,000 only a few years ago. According to an analysis by PricewaterhouseCoopers, it currently costs $1,717 to make ethylene in Asia, where plants depend on high-priced oil instead of natural gas, and $455 per ton to make ethylene in Saudi Arabia, using a combination of ethane and butane. Ethylene plants are also being built in Qatar, which, like the U.S., has an abundance of low cost natural gas. The U.S. Energy Information Administration (U.S. EIA) states that current expansion projects at existing facilities will increase U.S. ethylene production by 40% by 2018.

As domestic unconventional oil and gas development continues to expand, the supply of ethane available for ethylene production will continue to increase, and we see from our everyday lives that the demand for ethylene-based products continues to grow. However, ethylene is expensive to transport over long distances. Therefore, the next wave of domestic ethylene production plants will likely be greenfield (new plants) that are integrated with natural gas (and, therefore, ethane) production facilities or located near ethane pipelines to produce ethylene for use in the production of, for example, polyethylene for plastic bags or ethylene glycol for antifreeze. But whether we have an expansion to an existing ethylene production plant, or a Greenfield facility co-located or near to a natural gas production facility, there are air quality regulations and permitting requirements that must be evaluated before a project can proceed. For this article, we are going to briefly review the air quality regulatory history of some of the myriad of regulations that address emissions of hazardous air pollutants (HAPs) from ethylene production plants. We will also discuss some of the types of challenges that facilities may encounter along the way with respect to evolving testing, monitoring, and related compliance requirements.

Air Quality Regulatory History

Emissions of hazardous air pollutants (HAPs) from ethylene production are regulated by the U.S. Environmental Protection Agency (U.S. EPA) under its National Emissions Standards for Hazardous Air Pollutants (NESHAPs) regulations (40 CFR Part 63). In general, NESHAP regulations contain emissions standards based on maximum achievable control technology (MACT), and thus, are often referred to as MACT rules. MACT requirements for ethylene production plants were first promulgated in 2002, as part of U.S. EPA’s Generic MACT (40 CFR Part 63, Subpart YY; Ethylene MACT). A new Part 63 subpart (40 CFR Part 63, Subpart XX) was simultaneously promulgated and that specifies the requirements for ethylene process wastes and heat exchange systems. The Ethylene MACT applies to chemical manufacturing process units (CMPUs) in which ethylene and/or propylene are produced by separation from petroleum refining process streams or by subjecting hydrocarbons (e.g., natural gas and ethane) to high temperatures in the presence of steam and that are located at facilities that are major sources of HAPs. The Ethylene MACT regulates emissions of the following organic HAPs:

• Benzene
• 1,3-Butadiene
• Cumene
• Ethyl benzene
• Hexane
• Naphthalene
• Styrene
• Toluene
• o-, m-, and p-Xylene

The Ethylene MACT overlaps compliance elements from multiple other Part 63 regulations, such as, but not limited to:

• General Provisions (Subpart A)
• Equipment Leaks—Control Level 2 Standards (Subpart UU)
• Storage Vessels (Tanks)—Control Level 2 (Subpart WW)
• Closed Vent Systems, Control Devices, Recovery Devices and Routing to a Fuel Gas System or a Process (Subpart SS)
• Hazardous Organic NESHAP (HON; Subparts F, G and H)
• Refinery MACT I (Subpart CC)
• Benzene Waste Operations (BWON) NESHAP (40 CFR Part 61, Subpart FF)

These collective regulations impose requirements on the following emission sources at ethylene production plants as follows:

• Heat Exchange Systems – the Ethylene MACT requirements are similar to HON; however they may be subject to certain more stringent testing and monitoring requirements under the Ethylene MACT.
• Waste Operations – the Ethylene MACT requires BWON compliance with more widespread control requirements for certain operations.
• Storage Vessels – requirements are based on size and vapor pressure (VP), with the requirements ranging from submerged fill pipes to internal and external floating roofs (IFR and EFR, respectively), or closed vent systems routed to a control device.
• Process Vents – applicability is driven by flowrate and HAP concentration. Control requirements include the reduction of organic HAP to 98% by weight or 20 parts per million by volume via control devices that meet the Subpart SS requirements. Subpart SS has further requirements for flares, absorbers, condensers, carbon adsorbers, boilers, incinerators, process heaters, and closed vent systems, as well as other control devices.
• Transfer Racks – requirements are based on throughput and HAP VP.
• Equipment Leaks – requirements are based on equipment that contains or contacts an organic HAP at specific weight percent concentrations. Subpart UU imposes monitoring requirements for valves, pumps, connectors, agitators, and pressure relief devices. Additional requirements exist for compressors and sampling connection systems.

With this overview of the Ethylene MACT behind us, let’s discuss where this rule is headed.

____________________________________________________________________________________

1http://www.eia.gov/cfapps/ipdbproject/iedindex3.cfm?tid=3&pid=3&aid=1&cid=all,&syid=2009&eyid=2013&unit=BCF
2http://www.technologyreview.com/news/509291/shale-gas-will-fuel-a-us-manufacturing-boom/ (Technology Review)
3http://www.pwc.com/us/en/industrial-products/publications/shale-gas-chemicals-industry-potential.jhtml (PWC)
4http://www.eia.gov/todayinenergy/detail.cfm?id=19771 (U.S. EIA)
5Technology Review.

The Future of the Ethylene MACT

In a previous article, ALL4 described the U.S. EPA’s residual risk and technology review (RTR) process, in which the Clean Air Act (CAA) requires U.S. EPA to review and revise individual NESHAP, as necessary, taking into account developments in practices, processes and control technologies. The RTR process has an eight (8)-year review cycle for each NESHAP. On February 3, 2015, Earthjustice submitted a Notice of Citizen Suit Concerning Clean Air Act Deadlines to U.S. EPA for its failure to implement the RTR process for over 30 NESHAPs, including the Ethylene MACT. In anticipation of the lawsuit, U.S. EPA issued a CAA §114 Information Collection Request (ICR) to Ethylene MACT-affected facilities to support the upcoming technology review. This ICR was followed by another request to facilities to review and update, as necessary, their reporting year 2011 National Emissions Inventory (NEI) data for the risk portion of the review. U.S. EPA collaborated with the American Chemistry Council (ACC) and the American Fuel & Petrochemical Manufacturers (AFPM) to expand the request outside of the original ICR recipients. On March 24, 2015, U.S. EPA proposed an extension to the ICR to solicit additional public comments.

So what is U.S. EPA’s next move? Obtaining source-specific emissions testing data is the next step in the RTR process, most likely through the ICR process. In addition, ALL4 has heard discussions about the potential to develop initial emissions standards for emissions points in the ethylene production source category, such as air emissions from ethane cracking furnaces, including emissions during decoking operations.

Compliance Elements

While we await the proposed amendments to the Ethylene MACT following the RTR process, it provides an opportunity to discuss certain compliance requirements within the rule that are unique, or at the very least, different from the “normal” NESHAP requirements, particularly as it relates to continuous emissions and parametric monitoring. Readers of ALL4’s recent blogs and 4 The Record articles concerning NESHAPs such as Boiler MACT and the Portland Cement MACT have been exposed to discussions on the requirement to prepare site-specific monitoring plans and performance testing plans. The content of the plans required by the Boiler MACT and Portland Cement MACT are specified within the rules themselves, but also include cross-references to Subpart A. As specified in 40 CFR §63.11000(b), the general provisions in Subpart A related to performance testing and monitoring requirements (40 CFR §§63.6, 63.7 and 63.8), respectively, do not apply to sources subject to Subpart YY. This is not to say that an emissions testing program (including performance evaluation procedures for parametric monitoring systems) is not required for review and approval by your state or local air permitting authority. Rather, the provisions of Subpart SS govern the testing and monitoring requirements associated with the closed vent systems and control devices used by Subpart YY-affected sources. Similarly, Subpart A also does not apply to Subpart SS requirements. Subpart SS contains continuous emissions monitor system (CEMS) installation, operation, and maintenance requirements, as well as performance test requirements. The performance test requirements are different than, and include flexibility not present in, the typical Subpart A performance test procedures. Therefore, there is a bit of a learning curve for those new to the Subpart YY community. ALL4 has been working with clients in this area recently, particularly related to the waiver from performance testing requirements perspective, as well as relying on the use of prior performance tests to substitute for initial performance tests.

Contrary to recent revisions to many NESHAP requirements, Subpart YY retains startup, shutdown, and malfunction (SSM) provisions. SSM is very popular in the air quality legal news lately, largely related to the removal of affirmative defense provisions from NESHAPs, as well as the ongoing process for 36 states to remove SSM exemptions from their State Implementation Plans (SIPs). Subpart YY is one (1) of a handful of NESHAPs that specifies SSM and SSM Plan-related requirements, as opposed to making general cross-references to the SSM provisions contained in Subpart A (which, not so coincidentally, are also not incorporated by reference by Subpart YY). Control requirements under Subpart YY do not apply during periods of SSM. Instead, compliance with an SSM Plan is required for process vents, including furnace and decoking vents, as well as closed vent systems and control devices. The purpose of the SSM Plan is to have procedures in place for owners and operators to correct malfunctions as soon as practical to minimize emissions and to reduce the reporting burden associated with periods of SSM. This is akin to the “good old days” when SSM Plans were required by NESHAPs and SSM was more like a four (4) letter word. But what will happen to the SSM provisions following the RTR process? If we look at other source categories regulated by Subpart YY (Acrylic and Modacrylic Fibers Production, Polycarbonate Production, and Amino/Phenolic Resins Production), we see that the October 8, 2014 amendments to those affected sources eliminated the exemptions to emissions limits and standards during periods of SSM to ensure the standards are consistent with the District of Columbia Circuit Court’s vacatur of similar provisions in other rules. It is expected that the updated Ethylene MACT also will include the removal of the SSM provisions.

Last and certainly not least, the ever-present challenge of New Source Review (NSR) permitting will certainly impact ethylene production projects. The most notable challenges are expected to be the air dispersion modeling aspect of NSR, particularly where an ethylene production plant is co-located with an existing facility, or where one (1) will be constructed in an already industrialized area. In addition, in areas that are not attaining compliance with the National Ambient Air Quality Standards or NAAQS (now, or in the immediate future should the expected tightening of NAAQS occur), the NSR process will likely require that emissions increases of nonattainment pollutants and precursors be offset. In many instances, facilities will need to purchase emissions reduction credits, which can be on the order of tens of thousands of dollars per ton in certain areas of the country that will attract ethylene production plants. The explosive growth demands for the industry must be adequately balanced with the efforts and timing associated with NSR-related permitting.

Parting Thoughts

As described in the beginning of this article, construction of new ethylene production plants is expected (and is already occurring) because of the favorable supply and price of domestic ethane. Ethylene production plants are subject to many different NESHAPs (and we did not even discuss New Source Performance Standards) that are not as common as others. ALL4’s Oil and Gas sector initiative has allowed us to stay ahead of the curve to assist clients with this important domestic growth market. With our presence in Texas and Pennsylvania, we are right in the thick of the expanding domestic oil and gas industry, which also means we are ideally located to support the development of ethylene production plants that are anticipated to take place. Furthermore, the complexity of the regulations that apply to ethylene production plants present an on-going challenge to the industry that will not get any easier moving forward.

Please contact the following individuals with questions or comments regarding ethylene production:

The Next Generation of Air Permit Applications in Georgia

On July 30, 2015, I attended a training session at the Georgia Environmental Protection Division (GEPD) offices in Atlanta, Georgia for a hands-on demonstration of its new electronic permit application software system, “Georgia EPD Online System,” or GEOS.  GEOS is a portal to prepare and submit online electronic permit applications for National Pollutant Discharge Elimination System (NPDES) Municipal Wastewater Discharge Permits and Title V Air Quality Permits.  This online system allows information to be submitted to the GEPD in a streamlined manner, and also provides the general public with queried environmental data.  Eventually, the software system will be used for reporting purposes; however, the initial rollout of the system is limited to permit applications.

Within GEOS, members of the regulated community may apply, amend, and renew Title V operating permits, as well as submit compliance reports and monitoring data.  In order to begin this process, a Responsible Official (RO) must create an account and associate their facility.  If a third-party Consultant (like ALL4!) will be preparing forms on the facility’s behalf, the RO must also associate a Preparer.  The Preparer does not have the authority to submit an application, but does have the ability to complete all the applications assigned by the RO.  After the forms are complete, the RO certifies and submits the applications.  The process of creating an RO account and associating facilities and Preparers is outlined below.  GEPD’s step-by-step guide to these steps is provided in the GEOS Responsible Official Account Creation document.

Step 1: Create an Account

1. Select user Type: Responsible Official (RO)
2. Select account type: Title V, NPDES, and/or SIP.  You may have more than one (1) account type associated with your RO account.
3. Associate New Facility: Search and select the facility from the provided list and check the type(s) of application(s) that will be completed.  The options provided for application type will be based on the type(s) of the account(s) created in item two (2) of this list.
4. Select “OK” and push “Next” to continue.
5. Answer all security questions and press “Next”.
6. Enter CAPTCHA and click “Create Account”.
7. Print and sign the Subscriber Agreement and mail the ORIGINAL copy to*:

Georgia Environmental Protection Division
Attn: Information Technology
2 Martin Luther King Jr, Drive SE
Suite 1456
Atlanta, GA 30334

*This process may take a couple of weeks, so it is best to mail the Subscriber Agreement as soon as possible to avoid delays.

Step 2: Add a Consultant to prepare the forms

1. Go to “My Account”
2. Click “Add Consultant” and search for a consultant using his/her email address.**
3. Click “Validate & Associate”.
4. Click “Add Application Authorizations” and enter the requested information.

**The Preparer must first create an account before an RO is able to associate the facility with the Preparer.  A guide to this process can be found here.

Once a Consultant is assigned to prepare the forms, the Preparer may begin entering information into the GEOS system.  Upon completion of the necessary applications, the RO may submit the applications to GEPD online.  GEOS will provide a submission receipt, which the facility should retain for company records.

For more in-depth information regarding the GEOS reporting process, please review the GEOS User Guide for the Regulated Community.  ALL4 already is using this system to prepare Title V operating permit applications so please do not hesitate to contact us with questions about GEOS.

Compliance and Emissions Data Reporting Interface (CEDRI) Review

Do you want to find out the compliance status of a cement plant, a power plant, a refinery, or any another facility subject to New Source Performance Standards (NSPS) or National Emission Standards for Hazardous Air Pollutants (NESHAPs)? Just point and click.

The U.S. Environmental Protection Agency (U.S. EPA) has started to promulgate regulations under 40 CFR Parts 60 (NSPS) and 63 [NESHAPs; also known as a Maximum Achievable Control Technology (MACT)] that now require electronic reporting, or E-Reporting. Facilities will be required to electronically submit test results, monitoring data including continuous emissions monitoring (CEM) data, compliance reports, and/or emissions reports through U.S. EPA’s Compliance and Emissions Data Reporting Interface (CEDRI). CEDRI was created in order to centralize the location where data are reported.

As per U.S. EPA’s CEDRI Overview, CEDRI is located on U.S. EPA’s Central Data Exchange (CDX). CDX is used by U.S. EPA to manage data that are reported. U.S. EPA has prepared a CDX and CEDRI User’s Guide to help users effectively use this reporting system. CEDRI supports three (3) types of reporting submittals: performance test reports [submitted through the Electronic Reporting Tool (ERT)], notification reports, and air emissions reports. Once CEDRI has the required information for a report and it has been reviewed by the submitting party, the report must be signed, submitted, and validated using the CDX Cross-Media Electronic Reporting Regulation (CROMERR) service.

CEDRI users can take on different roles for facility reporting in order to allow for multiple people to work on a report. The three (3) available roles are as follows:

1. Preparer
   Preparers, such as consultants or testing contractors, are permitted to make edits to and assemble reports within the system. Preparers may only access reports which they have prepared or are preparing and may not submit a report in CEDRI.
2. Certifier
   A Certifier has the same type of access as the Preparer, but may also sign and submit reports within the system. Consultants and contractors are unable to be the Certifier of a facility.
3. Delegated Certifier
   Delegated Certifiers are granted authority by a Certifier to sign and submit reports and have the same abilities as a Certifier.

After a report is submitted, it is stored in the CROMERR archive and is immediately available for review by the applicable regulatory authorities. After a review period, the reports will be available for public review through the WebFIRE database.

Currently, U.S. EPA houses templates for reporting information in CEDRI, such as templates for reporting for steam generating units (40 CFR Part 60, Subparts Da, Db, and Dc); reciprocating internal combustion engines (RICE) (40 CFR Part 60, Subparts IIII and JJJJ, and Part 63, Subpart ZZZZ); Boiler MACT (40 CFR Part 63, Subparts DDDDD and JJJJJJ); and Portland cement (PC) MACT (40 CFR Part 63, Subpart LLL).

U.S. EPA continues to develop more E-Reporting rules for NSPS and NESHAPs and more tools to facilitate E-Reporting in general. It is safe to assume that U.S. EPA will continue to move towards E-Reporting as a universal tool to review submittals from various industrial facilities subject to NSPS or NESHAP. This means that the majority of facilities could be affected by the E-Reporting rules and be required to submit information through E-Reporting tools such as CEDRI (i.e., reported data for many facilities could quickly become available for public review and scrutiny).

What does this mean for your data? Can your data meet this scrutiny?