Electronic Reporting for Stack Testing and the Dangerous Assumption “It Won’t Take THAT Long”

With fall and the fourth quarter here, it is important to ensure that you have met your ongoing stack testing compliance requirements.  In completing the requisite stack tests, you have only fulfilled the first step towards facility compliance.  It is also important that you understand how to interpret your collected data and how it needs to be reported in order to proceed.  ALL4 continues to assist clients with electronic reporting obligations and has identified the top two reasons why you shouldn’t assume that electronic reporting “won’t take that long.”

1. The Rabbit Hole: It seems like it should be very easy to compile a stack test report for submittal using U.S. EPA’s Electronic Reporting Tool (ERT) and Compliance and Emissions Data Reporting Interface (CEDRI).  However, there are more steps involved than you had originally thought.  You will discover when preparing a stack test report via the ERT that a lot more information is required than just the stack test results.  Completing all of the appropriate tabs and preparing the necessary attachments can turn what you thought would be a “quick” stack test data submission exercise into more of a burdensome process.”  This process can be further complicated if some of the data from the stack test report is not consistent with the ERT calculated results, and you need to analyze the data to find the discrepancies between them.
2. The Never Ending Treasure Hunt: It is reasonable to assume that you would transcribe information provided in your stack test report directly into ERT, and then upload the ERT file into CEDRI for submission.  Unfortunately, sometimes finding the correct information to include in the report can turn into quite a headache.  Gathering the appropriate stack testing information and deciphering how to use the information to fulfill each requirement of the submission package can be challenging.  Making sure you have all of the information needed to accurately complete your submission package with the essential supporting data and attachments is often the most time consuming part of the submission process.  My suggestion before you begin the ERT data entry process is to make sure you understand the information required by the system and that you have identified the required data in the stack testing information before proceeding.  A little bit of preparation will make the process less troublesome.

Electronic reporting in general and using the various U.S. EPA reporting tools and procedures can be a daunting experience if you have never been through the process. ALL4 continues to help our clients with electronic reporting and in turn, avoiding looking like the proverbial you know what.

If you have any questions about the specific reporting requirements or how to complete these electronic reports, please contact Kayla Turney at kturney@all4inc.com or (610) 933-5246 x143. We’d be happy to help. Or check out our ERT/CEDRI blog post for additional information.

Preparing for the First GHG Report Under the Revised Subpart W Provisions

As we talked about in our December 2015 blog post, U.S. EPA finalized amendments to the 40 CFR Part 98 Mandatory Greenhouse Gas (GHG) Reporting Rule on October 22, 2015, which affected facilities in the Petroleum and Natural Gas Systems industry which are regulated under Subpart W of the rule.  The amendments have expanded the scope of Subpart W in a number of ways:

• Two new regulated industry segments were added: Onshore Petroleum and Natural Gas Gathering and Boosting; and Onshore Natural Gas Transmission Pipelines.
• Reporting of emissions from oil well completions and workovers with hydraulic fracturing is now required for Subpart W Onshore Petroleum and Natural Gas Production segment.
• Onshore Petroleum and Natural Gas Production facilities are required to report well identification numbers associated with certain source types.

The amendments have been in effect since January 1, 2016 and the first report under the revised rule is due in March 2017 for emissions occurring during calendar year 2016.  With the end of the calendar year fast approaching, here are some questions you should be asking yourself:

1. Do I have a compliant GHG monitoring plan in place?
   The Mandatory GHG Reporting Rule requires that regulated facilities maintain written GHG monitoring plans detailing how the data needed for emissions estimates and annual reports will be collected and quality-assured.  With two new segments added to the rule, GHG monitoring plans must be in place for newly-regulated facilities in those segments.  In addition, existing GHG monitoring plans may need to be updated to address the new oil well completion and workover source type and the new requirement to report well identification numbers for facilities in the onshore production segment.
2. Have I conducted an applicability analysis?
   The U.S. EPA has made a downloadable emissions screening utility available for the new gathering and boosting segment here (run the applicability tool for calendar year 2016 and select the  Onshore Petroleum and Natural Gas Gathering and Boosting segment to access the utility’s download page).  However, in our experience with a similar tool developed by U.S. EPA for the onshore production segment, emissions estimates generated by these tools are useful only for a first level evaluation.  With the exception of facilities with very low screening emissions estimates, we recommend either a hybrid approach, using both the tool and external calculations where the tool is believed to be inaccurately estimating emissions, or “full-blown” emissions estimates conducted in accordance with Subpart W requirements.
3. Do I have complete equipment inventories?
   Up-to-date equipment inventories are key to accurate emissions estimates and reporting under Subpart W of the GHG Mandatory Reporting Rule.  New equipment inventories or updates to existing inventories may be needed to collect information on previously-exempt gathering and boosting facilities or in situations where existing inventories do not provide sufficient information to determine if equipment falls under the production segment or gathering and boosting segment.
4. Have I collected data for emissions estimates and reporting?
   U.S. EPA is allowing reporters to use Best Available Monitoring Methods (BAMM) for calendar year 2016 for facilities or sources that are newly-subject to reporting requirements under the rule revisions. Using the BAMM provisions essentially means using engineering estimates and alternative compliance methods in lieu of complying with rule requirements. We have found that over-reliance on BAMM can create reporting challenges:
   • Estimating emissions under the BAMM provisions can be challenging if no actual, real-world data have been collected as a basis for those estimates.  This is particularly important for sporadic emissions events such as blowdowns and non-routine flaring, for which there may be limited opportunities to gather real data.
   • It is always in your best interest to estimate emissions as accurately as possible.  If emissions for newly-regulated gathering and boosting facilities are overestimated due to lack of real data, you may find yourself required to report for the next three or five calendar years under the continued reporting provisions of the rule when your actual emissions may have been under the reporting threshold to begin with.

ALL4 has extensive experience assisting oil and gas clients with GHG emissions calculations and reporting, and can help you navigate the new rule requirements.  If you have any questions, contact JP Kleinle at (610) 933-5246 extension 120 or jkleinle@all4inc.com

What’s Being Reconsidered in the Refinery Sector Rule?

On October 5, 2016, U.S. EPA announced reconsideration of issues raised in petitions submitted for sections of the Refinery Sector Rule (RSR) [i.e., 40 CFR Part 60, Subparts J and Ja and 40 CFR Part 63, Subparts CC (Refinery MACT 1) and UUU (Refinery MACT 2)].  The proposed reconsideration focuses on five main areas of the RSR:

1. Pressure Relief Device (PRD) work practice standards
2. Delayed Coker water overflow alternative provision
3. Emergency flaring work practice standards
4. Fenceline monitoring provision regarding reduction in frequency of monitoring at sampling stations with consistently low benzene concentrations
5. Assessment of risk from the refinery source categories after Implementation of the PRD and emergency flaring work practice standards

U.S. EPA is also proposing amendments to the RSR to clarify a compliance issue and to correct referencing errors.  This article includes a brief history of the RSR, addresses how the reconsiderations came about, and reviews the five main areas of the reconsideration, including what U.S. EPA is seeking comment on, as well as a summary of additional technical considerations.

Let’s Rewind…

For those needing a quick refresher, the RSR was published on December 1, 2015 and became effective on February 1, 2016. U.S. EPA received numerous petitions for reconsideration.

On January 19, 2016, the American Petroleum Institute (API) and the American Fuel and Petrochemical Manufacturers (AFPM) requested an administrative reconsideration and on February 9, 2016, U.S. EPA issued a proposal which was later finalized on July 13, 2016 and addressed items that API and AFPM covered in the original petition (see Meghan Barber’s blog for details).

On February 1, 2016, a petition from Earthjustice, submitted on behalf of a group of NGOs comprised of Air Alliance Houston, California Communities Against Toxics, Clean Air Council, Coalition for a Safe Environment, Del Amo Action Committee, Environmental Integrity Project, Sierra Club, Texas Environmental Justice Advocacy Services and Utah Physicians for a Healthy Environment, was filed. Supplemental joint petitions from API and AFPM were also filed.  On June 16, 2016, letters were sent to petitioners granting reconsideration of the petitioners’ claims as they relate to aspects of the final rule where the public was not afforded an opportunity for notice and comment.  U.S. EPA’s October 5, 2016 proposed reconsideration addresses these petitions.  Upon official publication in the Federal Register, a 45 day comment period will begin.

The Heart of the Matter

Let’s get to the five issues that U.S. EPA has addressed in the proposed reconsideration and break them down a bit.  What are the main issues?  What is U.S. EPA seeking comment on?

1. PRDs– In the final RSR, U.S. EPA established a four-part work practice standard in place of the ‘prohibition on release to the atmosphere’ based on what was achieved by the best performers, as denoted by the two California rules.  The first part of the work practice standard requires PRDs to be monitored using a system capable of notifying an operator of a pressure release, while also recording the time and duration of each pressure release.  The second part of the work practice standard establishes preventative measures for each affected PRD to prevent direct release of HAP to the atmosphere as a result of pressure release events.  The third part requires a root cause analysis be performed to determine the cause of a PRD release event.  The final part of the work practice standard requires a corrective analysis to be conducted and implemented, for any other event other than a force majeure event.  A refinery has 45 days to complete a root cause analysis and implement any corrective actions after the release event.U.S. EPA is seeking comments on the work practice standard for PRDs as provided in 40 CFR §63.648(j)(3) and (5) through (7), including the number and type of release/event allowances; the type of PRDs covered by the work practice standard; and the definition of “force majeure event” in 40 CFR §63.641. Comments are also being sought on the recordkeeping and reporting requirements associated with the work practice standard in 40 CFR §63.655(g)(10)(iii) and (i)(11).
2. Delayed Coking Units (DCUs) –  In the final RSR, U.S. EPA included a new alternative requirement for DCUs with water overflow design to hard-pipe the overflow drain water to the receiving tank via a submerged fill pipe (pipe below the existing liquid level) whenever the overflow water temperature exceeds 220 °F.  U.S. EPA is requesting comments on the alternative work practice standard for delayed coking units employing a water overflow design provided in 40 CFR §63.657(e).
3. Emergency Flaring – In the final RSR, a work practice standard was established for when a flare exceeds its smokeless capacity.  The work practice standard requires for a flare to have a continuously-lit pilot flame and meet combustion zone operating limits (e.g., heat content in the combustion zone) at all times, and also meet the monitoring, recordkeeping, and reporting requirements.  The work practice standard also requires for the development of a flare management plan to identify the flare system smokeless capacity and flare components, waste gas streams that are flared, monitoring systems and their locations, procedures that will be followed to limit discharges to the flare that cause the flare to exceed its smokeless capacity, and prevention measures implemented for PRDs that discharge to the flare header.  The work practice standard requires for a root cause analysis to be conducted and corrective action to be taken for any flaring event that exceeds the flare’s smokeless capacity and that also exceeds the flare tip velocity and/or visible emissions limit.  A refinery has 45 days to complete a root cause analysis and implement any corrective actions after the release event.U.S. EPA is seeking comments on the above smokeless capacity work practice standard in 40 CFR §63.670(o), including requirements to maintain records of prevention measures in 40 CFR §63.670(o)(1)(ii)(B) and (iv); the requirement to establish a single smokeless design capacity in 40 CFR §63.670(o)(1)(iii)(B); the number and type of releases/events that constitute a violation; the phrase “…and the flare vent gas flow rate is less than the smokeless design capacity of the flare” in 40 CFR §63.670(c) and (d)”; and other provisions in 40 CFR §63.670(o)(3) through (7). Additionally comments are being requested on the recordkeeping and reporting requirements associated with these work practice standards in 40 CFR §63.655(g)(11)(iv) and (i)(9)(x) through (xii).U.S. EPA has determined that 40 CFR §63.670(o)(1)(ii)(B) contains an incorrect reference to pressure relief devices for which preventative measures must be implemented. The correct reference is 40 CFR §63.648(j)(3)(ii) not 40 CFR §63.648(j)(5) and as such U.S. EPA is proposing to correct the reference.  U.S. EPA is seeking comment on the updated reference found in 40 CFR §63.670(o)(1)(ii)(B).
4. Benzene Fenceline Monitoring – In the final RSR, U.S. EPA provided provisions that were not proposed that would allow for reduced benzene fenceline monitoring frequency (after 2 years of continual monitoring) at monitoring locations with consistently low fenceline concentrations. U.S. EPA is requesting comment on allowing refineries to reduce the frequency of fenceline monitoring at monitoring sites that consistently record benzene concentrations below 0.9 micrograms per cubic meter (µg/m3), as provided in 40 CFR §63.658(e)(3).
5. Risk Assessment – As part of the development of the rule, U.S EPA performed a residual risk review for the Petroleum Refinery source categories including assessments of chronic and acute inhalation risk, as well as multipathway and environmental risk, to inform U.S. EPA’s decisions regarding ample margin of safety of risk. The study concluded that the cancer risk to the individual most exposed (maximum individual risk or “MIR”) based on allowable HAP emissions is no greater than approximately 100–in-1 million, which is the presumptive limit of acceptability, and that the MIR based on actual HAP emissions is no greater than approximately 60-in-1 million but may actually be closer to 40-in-1 million.

In the final Refinery MACT 1 rule, U.S. EPA established work practice standards for PRD releases and emergency flaring events, which under the proposed RSR would not have been allowed. As a result of not considering these non-routine emissions during the risk assessment for the proposed RSR, U.S. EPA performed a screening assessment of risk associated with these emissions for the final RSR.  The analysis showed that these HAP emissions could increase the MIR based on actual emissions by as much as 2-in-1 million, which results in essentially the same level of risk as was estimated at proposed RSR.

Based on the risk analysis performed for the proposed RSR and the screening assessment that considered the additional non-routine flare and PRD emissions allowed under the final RSR, U.S. EPA determined that the risk posed after implementation is acceptable.  U.S. EPA is seeking comments on the screening analysis and the conclusions reached based on the screening analysis in conjunction with the risk analysis performed for the proposed RSR.

Technical Clarifications

U.S. EPA is proposing to amend provisions related to how to address overlapping requirements for equipment leaks that are contained in Refinery MACT 1 and in the Refinery Equipment Leak NSPS (40 CFR Part 60, Subpart GGGa).  The Refinery MACT 1 currently states that equipment leaks that are subject to the provisions in found in the Refinery Equipment Leak NSPS are only required to comply with the requirements in Refinery Equipment Leak NSPS. Certain provisions of the Refinery MACT 1 detail a work practice standard for the management of releases from PRD.  The proposed revisions would equipment leaks subject to the Refinery Equipment Leak NSPS, must comply with the NSPS provisions, with the exception of PRDs in organic HAP service.  These PRDs will be required to comply with the Refinery MACT 1 requirements found at 40 §63.648(j). U.S. EPA is seeking comments on the proposed language.

Additionally, U.S. EPA is amending the introductory text in 40 CFR §63.648(j) to reference Refinery Equipment Leaks NSPS at 40 CFR §60.482-4a and amending paragraphs (j)(2)(i) through (iii) of Refinery MACT 1 to correct the existing reference to 40 CFR §60.485(b), which should refer to 40 CFR §60.485(c) and 40 CFR §60.485a(c).

Additional information is available in the proposed reconsideration.  Have specific questions?  Reach out to ALL4’s Kristin Gordon or Meghan Barber. Going to the AFPM Environmental Conference in mid-October?  See Kristin, Meghan, Eric Swisher and/or Kayla Turney with the RSR questions.

As the seasons change, so will your Performance Test Methods (Potentially)!

As the season changes from summer to fall, so will most of your performance test methods and performance specifications.  U.S. EPA issued a final rule on August 30, 2016 to make technical and editorial corrections and updates to testing provisions.  The revisions are intended to improve the quality of data and provide flexibility in the use of approved alternative procedures.  The rule is effective as of October 31, 2016, which is can be viewed here.

Noteworthy changes include, but are not limited to:

• Method 202: Among other corrections, U.S. EPA added a section to require calibration of the field balance used to weigh impingers and to require a multipoint calibration of the analytical balance.
• 40 CFR Part 60, Subpart A (General Provisions): §60.8(f) will be revised to require reporting of specific emissions test data in test reports.
  • Current language:

Unless otherwise specified in the applicable subpart, each performance test shall consist of three separate runs using the applicable test method. Each run shall be conducted for the time and under the conditions specified in the applicable standard. For the purpose of determining compliance with an applicable standard, the arithmetic means of results of the three runs shall apply. In the event that a sample is accidentally lost or conditions occur in which one of the three runs must be discontinued because of forced shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological conditions, or other circumstances, beyond the owner or operator’s control, compliance may, upon the Administrator’s approval, be determined using the arithmetic mean of the results of the two other runs.

• • Language as proposed:

Unless otherwise specified in the applicable subpart, each performance test shall consist of three separate runs using the applicable test method.

(1)….

(2) Contents of report (electronic or paper submitted copy). Unless otherwise specified in a relevant standard or test method, or as otherwise approved by the Administrator in writing, results of a performance test shall include general identification information for the facility including a mailing address, the actual address, the owner or operator or responsible official (where they are applicable) or an appropriate representative and an email address for this person, and the appropriate Federal Registry System (FRS) number for the facility; the purpose of the test including the regulation requiring the test, the pollutant being measured, the units of the standard or the pollutant emissions units, and any process parameter component; a brief process description; a complete unit description, including a description of feed streams and control devices, the appropriate source classification code (SCC), and the latitude and longitude of the emission point being tested, and the permitted maximum process rate (where applicable); sampling site description; description of sampling and analysis procedures and any modifications to standard procedures; quality assurance procedures; record of operating conditions, including operating parameters for which limits are being set, during the test; record of preparation of standards; record of calibrations; raw data sheets for field sampling; raw data sheets for field and laboratory analyses; chain-of-custody documentation; explanation of laboratory data qualifiers; example calculations of all applicable stack gas parameters, emission rates, percent reduction rates, and analytical results, as applicable; identification information for the company conducting the performance test including a contact person and his/her email address; and any other information required by the test method, a relevant standard, or the Administrator.

• • U.S. EPA has proposed to add specific test report requirements in lieu of the generalized approach in the current language.  It should be noted that most of the information that will now be required in the proposed §60.8(f) revision is already included in most test reports.  However, now with “Next Gen” compliance and increased transparency, the information will be available to a much wider audience and will possibly include the contact information for the environmental manager.
• Performance Specification (PS) 1 of Appendix B of Part 60:  PS1 will be revised to not limit the location of a continuous opacity monitoring system (COMS) to a point at least four duct diameters downstream and two duct diameters upstream from a control device or flow disturbance.
• PS2 of Appendix B of Part 60: The definition of span will be revised to include the sentence, “For spans less than 500 ppm, the span value may either be rounded upward to the next highest multiple of 10 ppm, or to the next highest multiple of 100 ppm such that the equivalent emissions concentration is not less than 30 percent of the selected span value.”
• PS3 of Appendix B of Part 60: PS3 will be revised to clarify how to calculate relative accuracy.
• Procedure 2 of Appendix F of Part 60: Equations 2-2 and 2-3 in Section 12.0 will be revised to correctly define the denominator when calculating calibration drift.  Equation 2-4 will be revised to correctly define the denominator when calculating accuracy.

The above mentioned corrections and/or revisions are definitely not all inclusive.  U.S. EPA plans to make several revisions in addition to the ones listed above.  As the fall season begins, grab a piece of pumpkin pie and review what revisions may affect your facility’s test program.  If you would prefer to just enjoy your pumpkin pie, give us a call and let us review the changes specific to your test program for you. At a minimum, you will want to share these revisions with your stack test company to make sure they are aware for any testing performed after the October 31^st effective date.  If you have any questions, feel free to contact me at (334) 855-3382 or sbowden@all4inc.com.

The OOOOa Initial Compliance Period Began! Time is Running Out.

The New Source Performance Standards (NSPS) at 40 CFR Subpart OOOOa (Subpart OOOOa) became effective on August 2, 2016.  This means that owners and operators with affected sources must be in compliance with the Subpart OOOOa standards starting August 2, 2016 or upon a startup that occurs after August 2, 2016.

Don’t be fooled into thinking that the 2017 initial reporting deadline provides shelter or time for figuring things out.  For many, the compliance date is a thing of the past, and time is running out on your ability to demonstrate compliance.  For example, the 2017 initial compliance report will require you to demonstrate compliance with notification and recordkeeping activities that should be taking place now.

I ask you to take a minute to evaluate and answer the questions below as if your Subpart OOOOa report is due tomorrow:

• Have you completed a thorough applicability analysis for OOOOa?
• Do you have a comprehensive understand of the notification, recordkeeping, and reporting requirements for your facilities?
• Are you generating the required notifications and records that will be needed to demonstrate compliance?
• Are you thoroughly documenting technically infeasibility issues with regard to flaring versus recovering gas during completion activities?
• What’s your strategy for complying with the new fugitive emissions monitoring and repair requirements?

I can go on and on with more questions but, I trust you get my drift.

Every cloud has a silver lining, right?  Well I have two for you.

1. There is a phase in period that extends the compliance deadline to November 30, 2016 for certain reduced emission completion (REC) requirements for non-delineation and non-wildcat wells.
2. Initial fugitive emissions monitoring surveys for affected well sites and compressor stations must be conducted by June 3, 2017.

These types of junctures make me think of the lyrics “It has to start somewhere.  It has to start sometime.  What better place than here, what better time than now?” from the song Guerilla Radio.  So what are you waiting for?  I made getting started now easy for your by providing a few action items below.

Capitalizing on the reduced emission completion (REC) Phase In Period

1. Read, reread, and develop a comprehensive understanding of the REC requirements for non-delineation and non-wildcat wells at 40 CFR §60.5375a(a)(1) through (4)
2. Give special attention to the four options for managing recovered gas during the separation flowback stage provided at 40 CFR §60.5375a(a)(1)(ii)
   • Route into a gas flow line or collection system
   • Re-inject into the well or another well
   • Use as an onsite fuel source
   • Use for another useful purpose that a purchased fuel or raw material would serve
3. Remember that “flaring” is acceptable only in cases where the above options are deemed technically infeasible.  You will be required to record the reasons for the claim of technical infeasibility with respect to all four options [40 CFR §60.5420a(c)(1)(iii)(A)].
4. Knowing there will come a time when you need to flare (probably a holiday or vacation), prepare a robust and comprehensive WRITTEN document now that provides the basis for the likely technical infeasibility.  Yu can fine tune the document later.
5. Ensure today that your completion combustion device is equipped with a reliable continuous pilot flame and place a copy of the documentation to substantiate this claim in the operating records.
6. Update your daily well logs today to accommodate the records required for the four REC options, flaring, and venting. 

Thoughts about Method 21 Fugitive Emissions Monitoring

For those of you considering or planning to utilize Method 21 (Determination of Volatile Organic Compound Leaks) to comply with the fugitive emissions monitoring survey requirements, I urge you to act on the following suggestions today:

1. Develop a working knowledge of the requirements of Method 21.  Use my link above to locate and print yourself a copy.
2. Be sure your leak detection equipment meets all of the requirements of Section 6.0 and is capable of being calibrated in accordance with Section 7.0. 
3. If you don’t already have one, develop your emissions monitoring plan in accordance with the requirements of 40 CFR §60.5397a(b), incorporating the techniques described in Section 8.0 of Method 21.

My ALL4 colleagues and I have been enjoying helping folks, like yourself, prepare for OOOOa compliance.  We are proud of our ability to “become our client” in our approach to managing and executing projects.  If you find yourself stuck or bogged down with other matters, help is only a phone call or email away.  My contact information is (610) 933-5246, extension 120 or jkleinle@all4inc.com.