OK… This is a long one. In the Refinery Sector Rule, EPA established an interesting parameter they named the “Net Heating Value Dilution Parameter” or NHVdil. It is measured in Btu/ft2. What? We are all familiar with the net heating value of gases which, volumetrically, are measured in Btu/ft3. That makes sense. But what exactly is Btu/ft2? There seems to be a lot of confusion about this parameter. So I thought I would try to clear things up by answering two questions… Where did it come from? and Does it really matter? First of all, let’s clarify that only flares using what EPA calls “perimeter assist air” need to be concerned about NHVdil. What is perimeter assist air? Well… EPA’s assist air naming conventions are somewhat non-intuitive and confusing (and will be the subject of an upcoming blog post) but it’s a safe assumption that any air-assisted flare is affected and must maintain an NHVdil greater than 22 Btu/ft2 [40 CFR 63.670(f)]. This is in addition to the 270 Btu/ft3combustion zone net heating value (NHVcz) limit [40 CFR 63.670(e)] that applies to all flares. In the case of air flares though, NHVcz = NHVvg (Vent Gas Net Heating Value). I know, it’s confusing. The other flavor of assist air defined by EPA is called pre-mix air. For the purpose of this discussion I am completely ignoring pre-mix air. It is rarely found on flares and just needlessly complicates the discussion. Why did EPA establish an additional limit for air-assisted flares? Isn’t the NHVcz limit adequate for air flares? As It turns out, NHVcz works perfectly well for air flares – except for nine data points collected in 1985. More on this in a moment. Prior to the promulgation of the Refinery Sector Rule, the informal parameter for air flares was the stoichiometric ratio (SR). The results of the 2010 TCEQ air flare tests (70 data points) indicated that at an SR less than about 10, the flare had good combustion efficiency. And that makes sense. If the SR gets too high (too much excess air) eventually the flame is cooled and diluted to the point where combustion begins to decline. However, when you look at the nine data points EPA collected on air flares in 1985, the SR doesn’t seem to work. There are some charts further down that will show this. IMPORTANT FACT TO KNOW ABOUT THE AIR FLARE IN THE 1985 EPA TEST… It had a 1.5-inch effective diameter. Barely more than a soda straw with a flame on top. Size Does Matter... When It Comes to Flares We know that other effects seen on tiny flarelets don’t scale up to industrial sized flares. Wind effects for example. Several Canadian studies on tiny flarelets in a wind tunnel, some no bigger than a few millimeters in diameter, indicated that wind can cause a condition on flares known as “wake dominated flow” resulting in a combustion efficiency decline. In response to these test results, EPA considered a wind-based parameter in the Refinery Sector Rule proposal. Some early flare consent decrees incorporate a parameter called the “Momentum Flux Ratio” to address this. However, no evidence of a wind effect impacting combustion efficiency has ever been measured on a full-size flare. Fortunately, this concept was abandoned by EPA in the final rule. So is there a similar “scale up” issue impacting the 1985 air flare data? Hold that thought. EPA concluded, and not without some logic, that flare diameter is a factor in assisted flare performance. They reasoned that on flares with small effective diameters, the assist-air will mix with the vent gas more rapidly than on larger diameter flares and potentially cause premature cooling and dilution which will affect combustion efficiency. Therefore, they concluded, flare diameter needs to be considered. Why not for steam-assisted flares? I don’t know. Stop asking hard questions. EPAs NHVdil Approach To address this perceived issue, EPA came up with the NHVdil approach. You can look up the actual equation in the Refinery Sector Rule but I’m going to give you the simplified version. Here’s how you get a parameter in units of Btu/square foot. Step 1: Determine the vent gas fraction. That is, what volume fraction of the total material exiting the flare, vent gas and assist-gas, is vent gas. So… In the unusual case where you are adding both steam and air, you would add the steam volume to the denominator as well. This is a unitless value. By EPA’s definition, vent gas includes supplemental gas, purge gas, and sweep gas. Step 2: Multiply the vent gas fraction by the flare effective diameter. This product is what EPA calls the dilution factor (DF). It is in units of feet. Since the vent gas fraction will always be less than or equal 1, this product will always be less than or equal to the effective diameter. As the vent gas fraction and effective diameter increase, so does DF. But a larger dilution factor actually means LESS dilution… confusing. The DF is more like a "un-dilution factor." Step 3: Multiply the DF by NHVvg to get NHVdil. Since DF is in units of feet and NHVvg is in units of Btu/cubic foot, the feet cancels one of the foots (I think that makes sense) and you are left with the somewhat improbable unit for NHVdil of Btu/square foot. Another way to look at it is... So does this NHVdil parameter actually work? Do we need a separate parameter for air flares? The chart below compares three air flare parameters – NHVdil, NHVcz, and stoichiometric ratio – and how each relates to flare combustion efficiency. The data are taken from the 2010 TCEQ flare test (70 points), EPA’s 1985 flare study (9 points), and more recent tests on air flare combustion efficiency (77 points). The EPA data points are shown as circles. The NHVcz data are calculated using assist air flow rate in place of the steam flow rate required in the EPA NHVcz equation. Figure 1 Figure 1 shows all the data but it is not particularly informative since everything on the first two graphs is squished to the left. It does show the EPA 1985 data as outliers in both the NHVcz and stoich ratio graphs. Let’s zoom in for a closer look. Figure 2 Figure 2 shows a zoomed in view including EPA’s “good combustion” line of 96.5% combustion efficiency (in red) and some parameter limits (in blue). Look very closely at the NHVdil and NHVcz graphs.The two graphs are identical (ignoring scale). The two parameters are completely interchangeable for all air flare data. This makes sense since NHVdil and NHVcz are both just scaled versions of NHVvg. NHVdil is just NHVvg scaled by vent gas to total gas ratio and diameter while NHVcz is just NHVvg scaled by assist gas to vent gas ratio. The effect of the diameter in the NHVdil equation is just to squash the data more as flare diameter decreases. What about the stoich ratio? This works very well for all the air flare data except... the 1985 EPA data. The EPA data shows good combustion only at sub-stoichiometric levels -- 0.10, 0.23, and 0.45. Anything higher and combustion efficiency rapidly drops off. Does this make sense? I don't know. Maybe some combustion savvy readers can weigh in on that one. So the bottom line on NHVdil? It certainly makes sure that all those people operating 1- and 2-inch flares are effectively brought into the regulatory fold. My belief… from a practical standpoint, we could have gone with either NHVcz or the stoich ratio and it wouldn’t have made any real difference. Here is a final question… Why are air flares required to meet BOTH NHVdil and NHVcz limits? The data shows that as long as NHVdil > 22 Btu/ft2, the flare is good. Requiring the flare also meet the 270 Btu/scf limit in many cases can be a significant penalty for air flare owners. But that is a question for another blog… If you, Loyal Reader, have any flare-related questions, or any other air-quality questions for that matter, let us know. We love answering reader questions.
Danny Landry is a pioneering entrepreneur in the field of drone (or UAV) use for industrial inspection and air quality monitoring. In this episode of Hot Air, I talk with Danny about various UAV applications in air quality monitoring, optical gas imaging, confined space inspections, 3-D plant modeling, and related topics. I met Danny when he worked with us on an innovative project using a drone as one end of an open path monitoring system to measure stack emissions. Danny did an amazing job implementing the aerial logistics of our vision for using this innovative technology developed by CleanAir. The video below shows some scenes from that project. There is music so be prepared... In addition to the open path project, Danny and I discuss the use of UAVs for confined space entry monitoring and inspection, using sophisticated photogrammetric software to develop 3-D models of plants, and other aspects of UAV use for monitoring and inspection. Check out some photos of Danny and his drones below. Also links to two videos on 3-D plant modeling and aerial photography. You can reach Danny at firstname.lastname@example.org or visit the website at www.pitinc.com. Listen and subscribe to Hot Air on iTunes, Google Play, Spotify, or anywhere you get your podcasts. Search for "Hot Air" or use one of the links below. Listen on the web: http://cleanair.libsyn.com Listen on iTunes: https://itunes.apple.com/us/podcast/hot-air-by-clean-air/id1413894085?mt=2 Listen on Spotify: https://open.spotify.com/show/24gUGGOvpygt3ayjAJtdbU?si=sbKPuLaVQFayMGPG50sEEQ Listen on Google Play: https://play.google.com/music/listen#/ps/Ivy2hniljmxncjhtj72jblrgcua Listen on Stitcher: https://www.stitcher.com/podcast/scott-evans/hot-air-by-clean-air?refid=stpr Video Links: 3-D Plant Modeling Aerial photography Discussing Strategy for Open Path Monitoring Project 3-D Plant Model Rendered from Drone Photographs Confined Space Entry Drone Preparing for Inspection Thermal Imaging Drone in Flight with Retroreflector Confined Space Inspection Photo Discussing Confined Space Inspection Flight Plan Ground Control
In these inaugural episodes of CleanAir's podcast series Hot Air, I sit down with Jim Guenthoer to talk about the elements necessary for a successful stack test. Jim brings his 40+ years of stack testing experience to the table and provides lots of practical advice and anecdotes for both those who use stack testing services and those who provide them. Part 1 covers pre-test activities, Part 2 deals with the testing itself, and Part 3 addresses post-test activities. Our discussion is available as both an audio podcast and a video presentation. During the audio podcast, there are occasional references to the slides but not to the extent that it makes it difficult to follow without the slides. A link to download a copy of Jim's slides is provided below. The audio podcast can be heard on iTunes, Spotify, Stitcher, or Google Play or is available via a web link. All links are provided below. Subscribe to the podcast to receive new episodes of interest to anyone involved with air quality issues. Enjoy! The Successful Stack Test: Part 1: Pre-Test Why We Test Selecting the Test Contractor The Test Plan Choosing a Test Method Safety Site Access Site Support The Successful Stack Test: Part 2: The Test Equipment Mobilization and Setup Sampling and Data Collection Sample Recovery Wrapping Up Activities The Successful Stack Test: Part 3: Post-Test Sample Analysis and Laboratories Test Report Considerations Concluding Thoughts You can listen and subscribe to Hot Air on iTunes, Google Play, Spotify, or anywhere you get your podcasts. The Successful Stack Test Listen on the web: http://cleanair.libsyn.com Listen on iTunes: https://itunes.apple.com/us/podcast/hot-air-by-clean-air/id1413894085?mt=2 Listen on Spotify: https://open.spotify.com/show/24gUGGOvpygt3ayjAJtdbU?si=sbKPuLaVQFayMGPG50sEEQ Listen on Google Play: https://play.google.com/music/listen#/ps/Ivy2hniljmxncjhtj72jblrgcua Listen on Stitcher: https://www.stitcher.com/podcast/scott-evans/hot-air-by-clean-air?refid=stpr Watch the Video Slide Presentation: https://vimeo.com/album/5444815 Link to a copy of Jim's slides: https://cdn2.hubspot.net/hubfs/3331037/Guenthoer%20P6.pdf
US EPA’s flare velocity limits were originally issued in 1986. Since then, they have found their way into flare regulations around the world. They were developed following a series of EPA sponsored tests conducted in the 1980’s that examined how various flare operating parameters, including velocity, affect flare performance. The limits were established using only one or two data points from a limited data set. Surprisingly, there is no evidence in the 1980’s data that high velocity in any way degrades flare performance. So how did we end up limiting flare velocity to, in most cases, 60 feet per second? What impact has this had on flare design and emissions? CleanAir has prepared a short white paper that describes the history of these limits. It also reviews the new flare data that has been collected over the past 10 years. The new data reinforces the 1980’s data showing no flare performance degradation at higher velocities. In fact, flare combustion is improved at higher velocities. It’s time for EPA to consider either scrapping flare velocity limits entirely, or at least significantly modifying them. Given the recent issues permitting multi-point ground flares which require high velocity to properly function, a change in regulation is needed and would be welcomed by flare vendors and users alike. Hit the button below to receive your copy of the CleanAir white paper on flare velocity.
Infrared cameras are typically perceived as tools for hydrocarbon detection. However, with the proper equipment, they can be used for a variety of chemical detection projects. CleanAir helped a whipped cream manufacturer who experienced significant releases of nitrous oxide (N2O) in their production process. The leaks created a hazardous work environment and frequent production shutdowns. They employed a manually intensive leak detection method using a soapy mixture to identify the source of the leak. Benefits Of FLIR Cameras CleanAir supplied an Optical Gas Imaging (OGI) solution using a FLIR camera with interchangeable band-pass filters. As opposed to the manual soap approach. Unlike the well-known FLIR GasFind cameras that have fixed filters for specific compounds. The FLIR SC8313 camera can be fitted with filters for a wide range of compounds – both hydrocarbon and non-hydrocarbon. This camera provides rapid frame-rate and high definition images. Thus, enabling low detection limits for small leak detection. Drawbacks Of FLIR Cameras Flexibility and high resolution come at a price, though. One of the disadvantages of the camera is that it is fairly large and not as portable as the GasFind cameras. It is designed to be used in a fixed position in a laboratory or other workspace. For this application, CleanAir designed a custom mobility solution allowing the camera to move from a stationary position in a lab out onto the production floor and be deployed as a mobile leak detector. This custom OGI system allowed the identification and repair of many N2O leaks across the production line. Short-term fixes were then put in place to either decrease or eliminate the leaks. Periodic inspections are still being conducted until longer-term solutions are implemented.
The Trump EPA's new Affordable Clean Energy (ACE) rule proposal announced today aims to replace the Obama EPA's Clean Power Plan (CPP) for limiting CO2 emissions from coal-fired power plants. The new proposal finds that the Best System of Emission Reduction (BSER) for such plants is Heat Rate Improvements (HRI) -- that is, to have each affected plant figure out how to generate more electricity with less fuel. This approach is in stark contrast with CPP which contained a complex "building block" approach to BSER. But aside from the controversy that will inevitably surround the less stringent CO2 reductions required, there are also proposed changes to EPA's New Source Review (NSR) permitting program that may stir up just as much hoopla. NSR is one of EPA's bedrock programs that has been around almost as long as EPA itself. The NSR program requires sources to undergo a pretty expensive, time-consuming, rigorous (some would say "onerous") review to determine whether constructing a new facility or modifying an existing facility would result in the "significant increase" of a regulated pollutant. If there is a significant increase, the plant would then be subject to potentially much more stringent (i.e., costly) requirements. Needless to say, most plants avoid NSR entanglement like the plague. The current NSR approach to determining whether there is a significant increase is incredibly complex and detailed but in broad strokes goes something like this... Step 1: Is there a physical or operational change? If yes, go to Step 2. If no, end. Step 2: Is there an ANNUAL increase in actual emissions greater than the EPA significance threshold? If yes, go to Step 3. If no, end. Step 3: Is there a significant increase in NET ANNUAL emissions? If yes, our condolences... you are subject to NSR rules. If no, congrats, you are not subject to major source NSR (maybe minor though). The key takeaway here is that a significant increase in emissions is determined on an annual basis. That creates a potential problem from the power plant's perspective. How? At the present time, there is no system in place to store the power produced by power plants. So the output of all the power plants on the electrical grid must be continually adjusted based on the electrical demand. This process is called dispatching. The more efficiently a plant operates, the more likely it is to be dispatched at a higher output or for longer periods of time. Therefore, if a plant improves its efficiency through a heat rate improvement project under ACE (a good thing), it will likely be operating at higher loads over a longer period of time. This may trigger NSR applicability (a not-so-good thing). This may happen even though the plant's pollutant emission concentrations remain unchanged or even are reduced. It's simply a matter of ANNUAL operating time. Yes, the efficient plant is generating electricity in place of a less efficient plant, but that offset is not recognized by the NSR approach. Now I'm not going to get into a debate about NSR stringency here and whether that's a good thing or a bad thing. I'm simply stating that from a power plant's perspective, NSR can be viewed as inhibiting potential efficiency increases. And the ACE proposal is all about power plant efficiency. To address this issue, the ACE proposal changes the NSR significant increase procedure for coal-fired plants from three steps to four... Step 1: Same as now Step 2: Is there an increase in HOURLY emissions? If yes, go to Step 3. If no, end. Step 3: Same as Step 2 now Step 4: Same as Step 3 now EPA is proposing several alternatives to how this hourly test would be calculated. The overall idea is to limit exposure to NSR applicability when initiating projects to improve plant efficiency. This could be considered in the same light as EPA current NSR exemption for pollution control projects. In any case, the proposed change is not mandatory but simply an option that may be adopted by states in their State Implementation Plans to meet ACE requirements. I'm looking forward to the debate on this one...
1. Hydrogen Chloride (HCl) is an acid gas classified as a Hazardous Air Pollutant (HAP), and is identified as harmful to the environment and human health. HCl is highly corrosive and can damage metal structures over time. It is also highly water soluble (known as Hydrochloric Acid in solution) and will affect the chemistry and ecology of bodies of water or certain types of soils. 2.Hydrogen Chloride regulation. The U.S. EPA regulates HCl across several industries, including fossil-fueled power plants, refineries, cement kilns, pharmaceutical manufacturers, and steel manufacturers. Within the U.S., HCl emissions must be measured, estimated, or calculated, and periodically reported to regulatory agencies. If an affected source measures HCl directly, then the source owner must use a specified sampling methodology dictated by the regulation affecting the source. 3. US EPA Method 26. Originally promulgated in 1991, this test method extracts a sample from the stack or duct at a constant rate and passes the sample through a filter to remove particulate. After the filter, reagent-filled impingers capture chloride ions as the sample is bubbled through the sampling train. Since the method does not measure HCl directly, but rather the captured chloride ions, other chlorine compounds have the potential to generate a positive bias, if present. The chloride ion concentration is measured via ion chromatography. 4. US EPA Method 26A. Originally promulgated in 1994, this method employs the same underlying principles as Method 26 while conforming to most Method 5 specifications for sampling particulates. Specifically, Method 26A isokinetically extracts a sample from the stack or duct and passes it through a Method 5 filter to remove particulate. The impingers capture chloride ions just as in Method 26; however, to account for higher flow rates and higher sample moisture levels, the impingers hold larger volumes than in Method 26. The EPA created this method to address possible sampling biases in “wet” stacks, or stacks that are at or near the moisture saturation point and where entrained water droplets containing HCl may be present. 5. US EPA Method 320. Method 320 is a spectrographic method. Unlike the “wet” Methods 26 and 26A, this method measures the HCl in the gas phase without first absorbing it into a liquid reagent. A sample is extracted from the stack or duct at a constant rate and passed through an FTIR sample cell. The FTIR scans the volume of gas in the cell and measures HCl (as well as other compounds) in near real-time. American Society for Testing and Materials (ASTM) D6348 12e1 is an FTIR method like Method 320 that may also be used when FTIR is approved for use at a source. These methods directly measure HCl, not chloride ions and so are less susceptible to some biases. 6. Which method should be used for compliance? The Mercury and Air Toxics Standards (MATS) Rule lowered the HCl emissions limits for all existing power generating units, while giving sources different options for complying with the new limits. Certain sources may use sulfur dioxide (SO2) as a surrogate for HCl, certain low emitting sources (LEE) may be exempt from monitoring HCl, and other sources may choose to comply with a permanent HCl CEMS. For sources not qualifying for or opting not to use these compliance options, Methods 26, 26A, and 320 are the HCl measurement methods to be used for quarterly stack testing compliance demonstration. For sources with a wet stack, Method 26A must be used. For sources with a dry stack, Method 26 or Method 320 can also be used. Non-power generating units historically restricted methodology to Methods 26 and 26A for HCl compliance; however, FTIR has been approved for some sources in some states. 7. What about measurements that are not for compliance? Recently, source owners have installed dry sorbent injection (DSI) and other emission control devices to comply with lower HCl limits. During the performance guarantee for newly installed control devices, as well as subsequent tuning or diagnostic testing, source owners choose the measurement methodology that they believe best helps them meet their test program goals and quality objectives. There are no regulations that specify measurement methodology when the testing is not for compliance purposes. 8. Entrained water biases in Method 26. Method 26 uses small filters, small impingers, and extracts samples at a slow, constant rate. When sampling a wet stack, this method will not representatively sample entrained water droplets. Typically, the low flow rate and small sampling train makes it likely that smaller entrained water droplets and gas molecules will be overrepresented in the sampling train, while larger entrained water droplets will be underrepresented in the sampling train. This means that the HCl concentration will typically be biased low when Method 26 is used in the presence of entrained water droplets. 9. Chlorine biases. Chloride salts and elemental chlorine exist in the flue gas and cause molecular interactions to occur in the bulk flow. Conditions found in typical flue gases drive conversion of most chlorine content to gaseous HCl. However, any residual chlorine in the bulk flow could also convert to HCl in the sampling system if the sampling system is not carefully constructed and operated. This transport issue can be a problem with all of the methods referenced above. 10. Keep it hot, rinse a lot. Chloride ions deposit on the surfaces of unheated and chilled portions of the sampling train (the impingers), so the post-run collection and rinse methodology for wet methods becomes very important. Sample system temperature has a direct effect on the degree of chloride deposition. Sample system temperature must be kept as hot as possible during sampling at all points. Any cold spots, even small ones, can introduce a significant bias to the measurement. Also, laboratory studies show that a large volume of rinse water and thorough wetting of all surfaces of sampling equipment is necessary to fully remove all collected chloride. The important of thorough rinsing cannot be overstated – research shows that recovery and rinsing bias is tester-specific. Like the wet methods, Method 320 also requires transport of the sample from the source to the instrument. Adequate and consistent heating of the gas sample along the entire transport path is critical in achieving good performance with this method. M26 and M26A specify a temperature range of 248-273 °F, while M320 does not specify temperature. Temperatures must not exceed 400°F if Teflon components are used since Teflon is unstable above this temperature. 11. What are some alternatives? There have been mixed results with in-stack measurements using FTIR as well as tunable diode laser (TDL) technology. These approaches eliminate sample transport biases entirely, but are more amenable to long-term measurements and CEMS applications rather than short-term compliance tests. More recently, EPA has considered the use of sorbent traps (OTM-40) for HCl as Alternate Test Method 129 (ALT-129), which can eliminate some of the transport concerns. Overall, HCl is a difficult compound to quantify, not because of a lack of analytical techniques that can measure HCl, but because of the complications of sample transport. CleanAir conducted a study, for the Electric Power Research Institute (EPRI) comparing wet methods to FTIR for halide measurements. Also, in the special case of a supersaturated stack, CleanAir performed diagnostic testing to help troubleshoot HCl issues with an isokinetic FTIR. If you have any questions concerning HCl measurement, we can help you with research, data, and testing.
The U.S. EPA recently “upgraded” Other Test Method 40 (OTM-40) to an approved alternative method (ALT-129) for coal-fired Electric Generating Units (EGUs) subject to 40 CFR Part 63 Subpart UUUUU, otherwise known as the Mercury and Air Toxics Standards or MATS. The change from OTM to ALT means the method can now be used by coal-fired EGUs without pre-approval . The method is the same, just the broad approval is new. The approval does come with some restrictions, however. The method may only be used without pre-approval by coal-fired EGUs and only those with low moisture flue gas at temperatures above 212 °F. The flue gas can contain no entrained droplets. Under these conditions, field testing shows OTM-40 performs similarly to Method 26A (M26A, one of the traditional HCl Reference Methods) but could potentially be biased high. A simpler sample train setup, lack of harmful chemical reagents, and quicker sample recovery may contribute to lower testing costs for affected facilities compared to Method 26 or 26A. OTM-40 uses HCl sorbent traps and the same equipment and procedures as Method 30B (M30B, mercury sorbent trap method). The sample gas flows through paired sorbent tubes which capture HCl as chloride. Sample recovery and analysis typically consist of a water extraction followed by ion chromatography. Like M30B, method performance is evaluated for each test using NIST-traceable spiking in one of the traps. This paired-sample design helps validate test results and assess method precision which is difficult to accomplish with the traditional test methods. While M26 uses a set of glass impingers filled with reagent to collect HCl outside of the stack, OTM-40 traps capture the HCl sample in-situ. This difference eliminates potential low bias resulting from insufficient heating of the sampling system, since the sample is collected in the traps before the sample gas is transported through the rest of the sampling equipment. However, this approach is susceptible to the same potential high bias as M26 from the presence of elemental chlorine (Cl2) or other chlorinated compounds in the flue gas. Unlike M26 or M26A, the trap method could also have a high bias if there are any chloride compounds contained in the particulate matter collected on the glass wool plug at the front of the trap. The trap method requires that the glass wool be included in the sample analyses, whereas the particulate filters in the conventional methods are not required to be analyzed. As mentioned above, OTM-40 is currently only approved for coal-fired EGUs with dry stacks. Stacks with wet scrubbers still require isokinetic sampling and nozzles for representative sampling of possible entrained water droplets. OTM-40 does not sample in this fashion. Also, the method has only been validated on coal-fired utility stacks; therefore, OTM-40 has not been approved for other sources although it may still be used with pre-approval. Click here for the approval letter, and here for the full method description.
EPA’s long-suffering Mercury and Air Toxics Standards (MATS) rule regulates emissions of mercury and other air toxics from coal-fired power plants. The rule has its origins 28 years ago with the passage of the Clean Air Act of 1990. The Act required that EPA submit a Utility Air Toxics Study to Congress to determine whether it was “appropriate and necessary” to regulate power plants under the air toxics provisions of the Clean Air Act. And the saga begins... Note: Red dates indicate key events Bush 1 EPA November 15, 1990 - President George H.W. Bush signs the Clean Air Act Amendments of 1990 into law. The statute includes the provision that requires EPA submit a Utility Air Toxics Study to Congress to determine whether it is “appropriate and necessary” to regulate power plants under the Section 112 air toxics provisions of the Act. This is due November 15, 1993. The Act also requires EPA to issue a Mercury Study Report addressing the broader question of the impact of mercury emissions from many sources. Clinton EPA November 15, 1993 - Nothing to report… October 1994 - EPA enters into a settlement agreement to issue the study by November 15, 1995. November 15, 1995 - Nothing to report... December 1997 - EPA issues the Mercury Study Report to Congress. This is not the Utility Air Toxics Study but is a massive 8-volume report on mercury emissions and their effects from a wide range of sources. It is a snapshot of EPA’s current understanding of mercury and its environmental impact. February 1998 - The Utility Air Toxic Study is issued! Note that this is not the determination of “appropriate and necessary” but just the data upon which that determination will be made. That determination is pushed into the future. One of the major conclusions from the study was that mercury from coal-fired utilities was the HAP of greatest public health concern and that there was a plausible link that mercury from electric utilities was adding to the existing environmental burden. December 20, 2000 - During the Clinton-Bush transition period, the Clinton EPA issues a determination that based on the results of the Utility Air Toxic report, regulating electric utilities under Section 112 of the Clean Air Act is appropriate and necessary. This was the trigger for EPA to begin rule development. Bush 2 EPA January 30, 2004 - The Bush EPA issues proposed mercury regulations - the Clean Air Mercury Rule (CAMR). Much of the proposal preamble is an apology for having to issue the regulations. The Bush EPA blames the necessity of the rule (correctly) on the appropriate and necessary determination issued by the Clinton EPA. The proposal spells out two approaches to regulating mercury — 1) Applying Maximum Achievable Control Technology (MACT) and 2) Developing a market-based “cap and trade” program. BUT… In an interesting twist, EPA also proposes revising the appropriate and necessary determination to regulate mercury emissions from power plants under Section 111 (New Source Performance Standards) of the Clean Air Act as opposed to Section 112 (air toxics). The MACT approach requires “delisting” power plants from the list of sources regulated under Section 112. Needless to say, this is a controversial proposal for three reasons. First, of course, it is a modification of the Clinton EPA determination and is done without conducting additional research to support the decision. Second, a cap and trade program for air toxics had not been previously considered for any rule. And third, regulating an air toxic (mercury) under Section 111 allows for potentially less stringent control. March 16, 2004- EPA issues a supplement to the January proposal that provides further details on the cap and trade program. December 1, 2004- EPA issues a Notice of Data Availability summarizing the modeling analyses EPA is using to support the upcoming rule. February 3, 2005- EPA’s Office of Inspector General (OIG) issues a report finding (among other things) that EPA did not follow prescribed guidelines in determining MACT reductions for the rule and that their analysis as to whether MACT or cap and trade provide the best cost/benefit ratio was flawed. OIG recommends re-analysis of the MACT data. March 29, 2005 -EPA finds that it IS NOT appropriate and necessary to regulate power plants under Section 112 despite it’s earlier finding that it IS appropriate and necessary. It concluded that the Utility Air Toxics Study over-estimated mercury emissions becasue it did not take into account mecury reduction caused by other requirements of the Clean Air Air. EPA delists electic utilities from the Section 112 air toxics list setting the stage for regulating these units under Section 111. Law firms rejoice. Litigation ensues. May 18, 2005- EPA promulgates CAMR using the cap and trade approach under Section 111. There is no indication in the final rule that EPA followed the recommendations of the OIG report. Even more litigation ensues. February 8, 2008- In New Jersey v EPA, the D.C. Circuit finds that EPA’s delisting rule violated the Clean Air Act and vacates the rule. This means that mercury emissions from power plants must remain listed under Section 112. Since the Clean Air Act does not permit Section 112 listed sources to be regulated under Section 111 as required by CAMR, the court finds that CAMR must also be vacated. The rule is dead. Long live the rule. EPA requests a review by the Supreme Court. Obama EPA February 6, 2009- The Obama EPA asks the Supreme Court to dismiss the request for review filed by the Bush EPA. December 24, 2009- EPA approves an Information Collection Request (ICR) requiring all coal- and oil-fired power plants to submit operating and emissions data for use in crafting a new rule. Merry Christmas for stack testers. March 16, 2011- EPA proposes its replacement for CAMR. This is the MATS rule. The proposed rule would establish standards for both existing and future power plants following a traditional MACT approach under Section 112. February 16, 2012- EPA promulgates the MATS rule. Litigation ensues. July 20, 2012- EPA grants Petition for Reconsideration focusing on measurement issues related to mercury and how EPA established the new source standards for particulate matter and hydrochloric acid, as well as startup and shutdown provisions. November 16, 2012- EPA issues a proposal to update requirements for new plants based on the Reconsideration. The proposal includes 1) Revised NSPS standards, 2) Requirements applicable during startups and shutdowns, 3) Changes in some monitoring requirements and definitions. March 28, 2013- EPA promulgates the final rule for the update to new plant standards. Startup and shutdown provisions are not addressed pending further public comment. June 25, 2013- Re-opening of public comment on startups and shutdowns November 7, 2014- EPA issues a direct final rule (and parallel proposal in case of adverse comment) on MATS e-reporting. EPA has developed two systems for submitting electronic data to the agency - 1) The Emissions Collection and Monitoring Plan System (ECMPS) developed by the Clean Air Markets division of EPA and 2) The Compliance and Emissions Data Reporting Interface (CEDRI) developed by the Office of Air Quality Planning and Standards (OAQPS) and home of the much-maligned Electronic Reporting Tool (ERT). The MATS rule requires that affected sources report data to BOTH systems depending on the type of data. Several commenters suggested this was inefficient particularly since most sources affected under MATS have already been reporting to ECMPS for many years. EPA agrees in this rule and pledges to consolidate reporting in ECMPS. To allow time for the transition, EPA amends MATS so that the CEDRI data can be submitted to ECMPS as a pdf attachment. EPA also sets a deadline of April 16, 2017 for this transition to ECMPS to be complete. If it is not, affected sources will be required to submit data collected after this data through CEDRI (via ERT). November 7, 2014- EPA finalizes update of startup shutdowns provisions based on the Reconsideration. The rule revision affects both existing and new units and includes work standard practices during startup and shutdown periods and adjustments to monitoring and testing during these periods. December 19, 2014- EPA proposes technical corrections for MATS. A variety of small changes to various parts of the rule focusing on 1) Resolution of conflicts between the preamble and regulatory text, 2) Corrections made in response to comments that were inadvertently not made, and 3) clarification of language in the regulatory text. One significant proposal is to remove the affirmative defense to civil penalties caused by malfunctions and replace it with “enforcement discretion.” This is in response to NRDC v.EPA in which the DC Court of Appeals struck down the affirmative defense in the Portland Cement rule. March 9, 2015- EPA promulgates final e-reporting rule given comments from November 7 proposal. In this rule, EPA states that, as part of a Phase 2 transition, they "plan to develop another rulemaking that requires affected source owners or operators to submit the data elements required in the rule in a structured XML format using the ECMPS Client Tool." April 21, 2015- EPA denies all outstanding Petitions for Reconsideration except for startup/shutdown petitions signaling that they have finalized their approach to the MATS rule. June 29, 2015- In the landmark Michigan v EPA decision (also see here), the Supreme Court remands (but does not vacate) the rule to EPA for failing to conduct a cost/benefit analysis (CBA) at the start of the rule-making process. This decision, along with Entergy v Riverkeeper (also see here), is seen by many as removing EPA’s discretion regarding when to perform some type of CBA if the statute is not clear or is silent on the matter. Justice Scalia writing for the majority states that EPA "must consider cost — including, most importantly, cost of compliance — before deciding whether regulation is appropriate and necessary.” It is important to note that the remand did not halt implementation of the rule. Therefore, all regulatory deadlines remained in place as EPA reconsidered the cost of the rule. At this point, it is estimated that 70% of the affected units have already installed the control equipment necessary to comply with the standard. November 20, 2015- Supplemental Cost Analysis to support appropriate and necessary determination. This, of course, is EPA’s response to the Michigan v EPA decision. This analysis only presents the data. It does not address whether the data continues to support EPA’s earlier finding that it is appropriate and necessary to regulate power plant under Section 112. March 17, 2016- EPA issues final technical corrections including removal of the affirmative defense for malfunctions. April 14, 2016- EPA issues its revised appropriate and necessary determination based on the November 20 Supplemental Cost Analysis required by the Supreme Court in Michigan v EPA. They find that even after reconsidering costs, it is still appropriate and necessary to regulate power plants under Section 112. Litigation ensues. August 8, 2016- EPA denies Petitions for Reconsideration of startup/shutdown rule revisions. August 23, 2016- EPA proposes to extend the e-reporting deadline to July 1, 2018. The transition to ECMPS is not going as quickly as EPA would like so they propose to extend the “return to CEDRI” deadline. Trump EPA April 6, 2017 - EPA finalizes rule to extend e-reporting deadline to July 1, 2018 April 27, 2017- At the request of the Trump EPA, DC Court of Appeals suspends MATS litigation resulting from the April 14, 2017 appropriate and necessary determination to allow EPA to evaluate the situation. EPA is required to file progress reports with the court every 90 days. MATS continues in effect with essentially all affected units having either installed the necessary control equipment to comply or shut down units that were not cost-effective to upgrade. September 10, 2017- President Trump nominates William Wehrum as EPA Assistant Administrator for Air and Radiation. Wehrum, who previously served in the Bush EPA as Assistant Administrator, was one of the chief architects of the legal strategy for the CAMR rule. April 19, 2018- Administrator Wehrum, speaking at an American Bar Association conference in Orlando states, "Under the law, there are good reasons why the [MATS] standard shouldn't exist because it's not appropriate and necessary. But on the other hand, we cannot turn a blind eye toward the practical, the implications of the possibility of rescinding the rule and the uncertainty that that would cause within the regulated community.” He stated further, "We're still thinking about it. We haven't quite figured out what we're going to do.” June 26, 2018- Another extension to the e-reporting deadline, this time until July 1, 2020. It’s taking even longer than EPA anticipated to modify ECMPS to accept MATS data. So what lies in the future for MATS? Given that all of the plants subject to the rule have already made the investment in pollution control to comply with MATS or have shut down non-compliant units, maybe whatever happens at this point is moot. As of this writing, litigation is still suspended and EPA is still weighing options. The next couple of years will tell. It is too early to tell whether the newly appointed interim Administrator, Andrew Wheeler, will attempt to change the course of MATS. But the real decision maker here is Bill Wehrum. And he’s still scratching his head.
Particulate is defined by the method used to measure it. Unlike chemically distinct emissions like carbon monoxide or nitrogen oxide, “particulate” can be composed of many different distinct compounds. Some of these compounds may be volatile and may be “particulate” at lower temperatures but gaseous at higher temperatures. US EPA Method 5. This test method isokinetically extracts a sample from the stack or duct and passes that sample through a filter. The sample probe and filter are heated to 248 °F. Any particulate captured on the filter is (logically) referred to as “filterable particulate” or FPM; that is, any material not gaseous at that temperature is captured. There are variants of Method 5 (for example, 5B and 5F) that use other temperatures for sample collection. US EPA Method 202. The gaseous material sampled with Method 5 passes through the filter and a temperature-controlled condenser followed by two, initially dry, impingers – essentially big test tubes. As the gas is cooled, water and other compounds (both organic and inorganic) condense out. Any material collected in these impingers (minus the water) is referred to as “condensable particulate” or CPM. The logic used for this method is that any condensed material would also condense and form particulate when the gases exit the stack and are cooled in the ambient air. More on this assumption in a moment... Method 202 Bias Issues. Unfortunately, there are often other compounds present in the sample gas that may react when placed together in a large, wet impinger. Two compounds commonly found in some gas streams are ammonia (NH3) and sulfur dioxide (SO2). Left on their own in the stack, these two gases will not normally combine even upon exiting the stack. However, when mixed together in an impinger with even a small amount of water, the two gases combine to form ammonium salts – a particulate. The formation of ammonium salts is an artifact of Method 202 sampling and does not occur with gas exiting the stack. Therefore, Method 202, can be biased high for gases streams containing these two compounds -- the method creates “false particulate.” A Synergistic Effect. NH3is highly water soluble. During a test, as NH3is dissolved in the impinger water, the pH of the water is raised. The higher pH enhances the collection of SO2. -- in effect, a little caustic scrubber is created. The higher the pH, the more efficiently SO2is scrubbed. The more NH3and SO2are captured, the higher the Method 202 bias. Some may say that when Method 202 was modified a few years back, it fixed the bias problem. Unfortunately, there is ample evidence that while the bias issues are better than they were with the old method, they are still with us. The addition of the “dry” impingers and CPM filter in the new method helped but did not completely solve the bias problem. What to Do? For facilities where highly biased CPM results are an issue, here is an approach that can work. For Method 202 analysis, results are split into organic and inorganic fractions. It is the inorganic fraction that typically is biased. It is where the ammonium salts are found. So the solution? Use only the organic fraction. But wait, I hear you say. What about any other inorganic condensable compounds that may be legitimately considered particulates? We can’t just throw away all the inorganics, can we? Controlled Condensation. In any gas stream that contains SO2, particularly those with catalysts to control NOx, there will be some SO3/H2SO4– sulfuric acid. At temperatures well above ambient, sulfuric acid will form a mist which is legitimately considered a particulate. At Method 5 collection temperatures (248 °F) Much of this mist will be captured on the filter, but some of it will make it through the filter and condense in the impingers. For many gas streams containing SO2, SO3will be the only significant contributor to CPM. This SO3must be accounted for since it is a legit particulate. The answer is to do a test that is specific to sulfuric acid mist… controlled condensation (CCM). Why Controlled Condensation? The CCM method is designed to condense SO3/H2SO4while minimizing water condensation. Method 202 condenses both water and acid gas simultaneously leading to the chemical interactions described above. While CCM does not completely eliminate the potential for the formation of false particulate, it performs much better than M202 in this regard. An unbiased CPM measurement. So a less biased measurement of CPM can be obtained by using the results of the CCM test in place of the Method 202 inorganic fraction. The total CPM would then be: CPM = Method 202 organic fraction + CCM results Both tests should be conducted either simultaneously or as close as possible in time. In order to use this approach, regulatory authority permission must typically be granted. CleanAir has a white paper available on this issue with more detailed information, data, and a case study. If you are interested in this approach to unbiased CPM measurement, we can support you with research, data, and testing. Let us know if we can help.
There are many reasons to conduct a gas turbine performance test, including determining compliance with acceptance guarantees, establishing benchmarks for performance monitoring and power purchase agreements, and determining performance parameter corrections. Regardless of the reason, these test results need to be both reliable and defendable in order to make sound decisions. CleanAir recently gave a presentation on gas turbine performance testing at the Western Turbine Users conference (WTUI). The presentation included information on gas turbine performance testing preparation, execution, instrumentation, correction methodology, and test uncertainty analysis. Gas turbine performance test results are typically corrected to a reference condition for comparison to guarantees or for comparison to previous test results as part of a performance monitoring plan. The presentation begins with the recommended preparations and provides a high level overview of the basic test measurements and the common corrections that are applied to test results in order to calculate corrected gas turbine performance. A pre-test uncertainty analysis is often completed to identify the most important test measurements that influence corrected gas turbine performance, which helps in the selection of appropriate test instrumentation. A post-test uncertainty analysis calculates the uncertainty of the corrected gas turbine performance based on the actual test conditions. The presentation concludes with a comparison of the corrected gas turbine performance uncertainty using typical station instrumentation versus typical precision test instrumentation. If you are in need of reliable, defensible performance data for internal benchmark testing, contractual acceptance, or even for dispatching, this presentation should help you feel more confident you are getting the best data possible. If you would like a copy of the full presentation, please click here. Generating Reliable Gas Turbine Performance Data
EPA today published their response to Alternative Means of Emission Limitation (AMEL) requests from four refineries and a chemical plant. These are: ExxonMobil (Baytown), Marathon (GBR and Garyville), Chalmette (Chalmette), and the chemical plant is LACC (Lake Charles). Each of these facilities operates flares designed to work at exit velocities greater than those allowed under current EPA rules at 40 CFR 60.18 and 63.11. These facilities conducted extensive testing to determine that under the operating conditions specified in the AMEL request, the flares achieved VOC and HAP reductions as good as or better than what is required under the various standards that apply to them. Under a framework established by EPA and published in the Federal Register on April 21, 2016, sources operating pressure assisted multi-point ground flares (MPGFs), may request an AMEL for exemption from the exit velocity requirements. The CleanAir Flare Team has developed several of these AMELs for our refinery and chemical clients and also collected the data used to support them.
Performance Specification 11 (PS-11) establishes the initial installation and performance procedures required for evaluating the acceptability of a particulate matter (PM) continuous emission monitoring system (CEMS). Multiple industries utilize PM CEMS and are influenced by applicable EPA regulations; such as the Portland Cement MACT, Industrial Boiler MACT, and Utility MACT. Evaluation of the performance of a PM CEMS over an extended period of time, or to identify specific calibration techniques and procedures to assess their performance is covered under Procedure 2 of Appendix F—Quality Assurance Requirements for Particulate Matter Continuous Emission Monitoring Systems Used at Stationary Sources. In all there are hundreds of pages (and a few spreadsheets too!) that must be reviewed to become familiar with PS-11 and PM CEMS requirements. Newly installed PM CEMs operations will bring about a multitude of difficult questions. Correlation curves and coefficients, RRA, RCA, ACA, SVA, precision, bias, stratification, regression analysis, what does it all mean? Do they apply to my current test program? How do I operate to perform the tests at three different PM concentration or loading levels? Should I perform EPA Method 5, 5B or MATS 5? Do I need to worry about condensable particulate matter (CPM)? How does PS-11 influence my future PM Relative Accuracy Test Audits (RATAS)? What is the method detection limit (MDL) of the stack test? How do I know good reference method (RM) test data from bad? Can the tester perform overlapping (staggered) test runs to obtain data points more quickly? Should I conduct paired, otherwise known as collocated, reference method test runs? CleanAir has done the hard work for you and summarized the important information you need to know in CleanAir “Layperson’s Guide to PS-11”.
CleanAir is now accredited to ISO 17025, the international standard for competence of testing laboratories. This is in addition to two other accreditations we hold: ASTM D7036 (Standard Practice for Competence of Air Emission Testing Bodies) and the NELAC FSMO standard for Field Activities. In order to obtain these accreditations, CleanAir underwent rigorous third party quality audits both in our offices and in the field. These credentials provide assurance to our clients that CleanAir’s quality system and practices meet stringent US and international quality standards. Scope of Accreditation For more detailed information and for copies of our accreditation certificates, please see our Accreditation page.
This is Part 2 of my blog post on EPA's proposed amendments to the Refinery Sector Rule (RSR). Part 1 covered changes to Subpart CC (MACT 1). Part 2 covers changes to Subpart UUU (MACT 2) and Subpart Ja. On Monday, March 19, 2018, US EPA issued proposed amendments to the Refinery Sector Rule (RSR). These amendments are based on three petitions of reconsideration filed with the agency -- two of these were joint submissions by the American Petroleum Institute (API) and the American Fuel and Petrochemical Manufacturers (AFPM) and the third from Earthjustice filed on behalf of several environmental groups. See EPA Docket EPA-HQ-OAR-2010-0682 for source documents. The proposed changes to Subpart UUU are listed below. Changes to Subpart CC were previously posted. FCCU Provisions 1. Remove restriction in Section 63.1573(a) in complying with the alternative PM standard in Section 63.1564(a)(5)(ii). Currently, the use of the alternative is restricted to occasions when “the unit does not introduce any other gas streams into the catalyst regenerator vent.” 2. Amend Section 63.1565(a)(5)(ii) and Table 10 to allow for the use of a wet O2 measurement for demonstrating compliance with the standard so long as it is used directly with no correction for moisture content. Other Corrections 1. CPMS monitoring and data collection... Amend the language in Refinery MACT 2 in Section 63.1572(d)(1) so that the language is the same as that in Refinery MACT 1 in Section 63.671(a)(4). 2. Amend the recordkeeping requirement in Section 63.1576(a)(2)(i) to apply only when facilities elect to comply with the alternative startup and shutdown standards. 3. Amend Section 63.1574(a)(3) to clarify that the results of performance tests conducted to demonstrate initial compliance are to be reported by the date the NOCS report is due (150 days from the compliance date) whether the results are reported using CEDRI or in hard copy as part of the NOCS report and to clarify the information to be included in the NOCS if the test results are submitted through CEDRI. 4. The results of periodic performance tests and the one-time hydrogen cyanide (HCN) test required by Section 63.1571(a)(5) and (6) must be reported with the semi-annual compliance reports as specified in Section 63.1575(f) instead of within 60 days of completing the performance evaluation. 5. Streamline reporting of the results of performance evaluations for continuous monitoring systems (as provided in entry 2 to Table 43) to align with the semi-annual compliance reports as specified in Section 63.1575(f), rather than requiring a separate report submittal. 6. Add the phrase “Unless otherwise specified by this subpart” to Section 63.1575(k)(1) and (2) to indicate that any performance tests or performance evaluations required to be reported in a NOCS report or a semi-annual compliance report are not subject to the 60-day deadline specified in these paragraphs. 7. We are also proposing to add Section 63.1575(l) to address extensions to electronic reporting deadlines. 8. Revise selected entries in Table 44 to clarify several sections of the General Provisions that the reporting can be written or electronic, the timing of these reports is specified in Subpart UUU, and the Subpart UUU provisions supersede the General Provisions. Clarifications and Technical Corrections to NSPS Ja 1. Amend the language in Section 60.105a(b)(2)(ii) which does not currently include Methods 3A and 3B (and the alternative ANSI/ASME method for EPA Method 3B) and mistakenly cites Appendix A-3 rather than Appendix A-2, to make it consistent with the other similar requirements in NSPS subpart Ja.
On Monday, March 19, 2018, US EPA issued proposed amendments to the Refinery Sector Rule (RSR). These amendments are based on three petitions of reconsideration filed with the agency -- two of these were joint submissions by the American Petroleum Institute (API) and the American Fuel and Petrochemical Manufacturers (AFPM) and the third from Earthjustice filed on behalf of several environmental groups. The proposed changes to Subpart CC (Refinery MACT 1) are listed below. Changes to Subpart UUU (Refinery MACT 2) and Subpart Ja will be posted in a follow-up blog. Definitions 1. Changing the definition of Flare Purge Gas to clarify that purge could be interpreted to include gases introduced to the flare for safety reasons other than to prevent oxygen infiltration. 2. Changing the definition of Flare Supplemental Gas to exclude added steam or air and include only gas that increases the heating value of the flare gas. Also, the definition clarifies that natural gas is not the only option for flare supplemental gas. 3. Adding a definition of Pressure Relief Device and revising the definition of Relief Valve and consistently using the term "pressure relief device" throughout the rule. 4. Revising the definition of Reference Control Technology for Storage Vessels to be consistent with the storage vessel rule requirements at 40 CFR 63.660. Miscellaneous Process Vent Provisions 1. Add language to 40 CFR 63.643(c) to explicitly state that maintenance vents need not be identified in the NOCS report. 2. Amend 40 CFR 63.643(c)(1)(iv) to read (new text highlighted in bold): “If the maintenance vent is associated with equipment containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers) and a pure hydrogen supply is not available at the equipment at the time of the startup, shutdown, maintenance, or inspection activity, the LEL of the vapor in the equipment must be less than 20 percent, except for one event per year not to exceed 35 percent.” 3. Amend 40 CFR 63.643(c)(1) to read: “Prior to venting to the atmosphere, process liquids are removed from the equipment as much as practical and the equipment is depressured to a control device meeting requirements in paragraphs (a)(1) or (2) of this section, a fuel gas system, or back to the process until one of the following conditions, as applicable, is met.” 4. Blind installation for maintenance... Require depressuring the equipment to 2 pounds (lb) per square inch gauge (psig) or less prior to equipment opening and maintaining the pressure of the equipment where purge gas enters the equipment at or below 2 psig during the blind flange installation. The low allowable pressure limit will reduce the amount of process gas that will be released during the initial equipment opening and ongoing 2-psig pressure requirement will limit the rate of purge gas use. Together, these requirements will limit the emissions during blind flange installation and will result in comparable emissions allowed under the existing maintenance vent provisions. 5. Documentation of each release from maintenance vents which serve equipment containing less than 72 lbs of VOC is not necessary, as long as there is a demonstration that the event is compliant with the requirement that the equipment contains less than 72 lbs of VOC. Revise 40 CFR 63.643(c)(1) to require a record demonstrating that the total quantity of VOC in the equipment based on the type, size, and contents is less than 72 lbs of VOC at the time of the maintenance vent opening. 6. Amend 40 CFR 63.644(c) to make clear that open-ended valves or lines that are capped and plugged sufficiently to meet the standards in NSPS subpart VV at 40 CFR 60.482-6(a)(2), (b) and (c), are exempt from the bypass monitoring in 40 CFR 63.644 (c). Pressure Relief Device Provisions 1. Add the phrase -- “affected pressure relief device”-- to 40 CFR 63.648(j)(3)(v) to clarify that the requirements in (j)(3)(v) also apply only to releases from PRDs that are in organic HAP service. 2. Revise 40 CFR 63.648(j)(3)(ii)(A) to make clear that independent, non-duplicative systems count as separate redundant prevention measures. 3. Amend the reporting requirements at 40 CFR 63.655(g)(10) and the recordkeeping requirements at 40 CFR 63.655(i)(11) to retain the requirements to report and keep records of each release to the atmosphere through the pilot vent that exceeds 72 lbs/day of VOC, including the duration of the pressure release through the pilot vent and the estimate of the mass quantity of each organic HAP release. Delayed Coking Unit Decoking Operation Provisions 1. Clarify provisions in 40 CFR 63.657(e) that the water overflow requirements in 40 CFR 63.657(e) are only applicable if the primary pressure or temperature limits in 40 CFR 63.657(a) were not met prior to overflowing any water. However, if water overflow is used before the primary pressure or temperature limits in 40 CFR 63.657(a) are met, then the owner or operator must use “controlled” water overflow until the applicable temperature limit is achieved. 2. Add provisions to 40 CFR 63.657(e) requiring the use of a separator or disengaging device operated in a manner to prevent entrainment of gases from the coke drum vessel to the overflow water storage tank. Gases from the separator must be routed to a closed vent blowdown system or otherwise controlled following the requirements for a Group 1 miscellaneous process vent. Fenceline Monitoring Provisions 1. Proposing an alternative to the additional monitor siting requirement for pumps, valves, connectors, sampling connections, and open-ended lines sources that are actively monitored monthly using audio, visual, or olfactory means and quarterly using Method 21 or the AWP. 2. Clarify that if a root cause analysis was performed and corrective action measures were implemented prior to the exceedance of the annual average Δc action level, then these documented actions can be used to fulfill the root cause analysis and corrective action requirements in 40 CFR 63.658(g) and recordkeeping in 40 CFR 63.655(i)(8)(viii). 3. Revise reporting requirements so that quarterly reports are to cover calendar year quarters (i.e., Quarter 1 is from January 1 through March 31; Quarter 2 is from April 1 through June 30; Quarter 3 is from July 1 through September 30; and Quarter 4 is from October 1 through December 31) rather than being directly tied to the date compliance monitoring began. 4. Modify reporting requirements associated with collecting and analyzing QA/QC samples. First, require only one field blank per sampling period rather than two. Second, decrease the number of duplicate samples that must be collected each sample period. Instead of requiring a duplicate sample for every 10 monitoring locations, facilities with 19 or fewer monitoring locations are only required to collect one duplicate sample per sampling period and facilities with 20 or more sampling locations only be required to collect two duplicate samples per sampling period. 5. Require that duplicate samples be averaged together to determine the sampling location’s benzene concentration for the purposes of calculating Δc. 6. Revise the Table 6 entry for 40 CFR 63.7(f) to indicate that 40 CFR 63.7(f) applies except that alternatives directly specified in 40 CFR part 63, subpart CC do not require additional notification to the Administrator or the approval of the Administrator. Also, editorial revisions to the fenceline monitoring section; these proposed revisions are included in Table 2 in section III.A.7 of the preamble. Flare Control Device Provisions 1. Allow owners or operators of flares whose only assist air is from perimeter assist air entrained in lower and upper steam at the flare tip and with a flare tip diameter of 9 inches or greater to comply only with the NHVcz operating limit. Steam-assisted flares with perimeter assist air and an effective tip diameter of less than 9 inches would remain subject to the requirement to account for the amount of assist air intentionally entrained within the calculation of NHVdil. 2. Add provisions to specify that owners or operators of these smaller diameter steam-assisted flares use the steam flow rate and the maximum design air-to-steam ratio of the steam tube’s air entrainment system for determining the flow rate of this assist air. Using the maximum design ratio will tend to over-estimate the assist air flow rate, which is conservative with respect to ensuring compliance with the NHVdil operating limit. 3. Include specific provisions for continuously monitoring fan speed or power and using fan curves for determining assist air flow rates. 4. Clarify that the initial 2-hour visible emissions demonstration should be conducted the first time regulated materials are routed to the flare. 5. Clarify at 40 CFR 63.670(h)(1) to provide that the daily 5-minute observations must only be conducted on days the flare receives regulated material and that the additional visible emissions monitoring is specific to cases when visible emissions are observed while regulated material is routed to the flare. 6. Clarify, at 40 CFR 63.670(o)(1)(iii)(B), that the owner or operator must establish the smokeless capacity of the flare in a 15-minute block average and at 40 CFR 63.670(o)(3)(i) that the exceedance of the smokeless capacity of the flare is based on a 15-minute block average. 7. Correct an error in the units for the cumulative volumetric flow used in the flare tip velocity equation in 40 CFR 63.670(k)(3). 8. Clarify that certification of compliance for these flare vent gas flow meter accuracy requirements can be made based on the typical range of flare gas compositions expected for a given flare. Electronic Reporting and Other Corrections 1. Revise the introductory text in 40 CFR 63.660 to clarify that owners or operators of affected Group 1 storage vessels storing liquids with a maximum true vapor pressure less than 76.6 kilopascals (11.0 psi) can comply with either the requirements in 40 CFR part 63, subpart WW or SS and that owners or operators storing liquids with a maximum true vapor pressure greater than or equal to 76.6 kilopascals (11.0 psi) must comply with the requirements in 40 CFR part 63, subpart SS. 2. Clarify that the additional compliance time at 40 CFR 63.1063(a)(2)(ix) (Subpart WW) applies to the implementation of controls in 40 CFR 63.660(b) (Subpart CC). 3. Amend paragraphs 40 CFR 63.655(f) and 40 CFR 63.655(f)(6) to expressly provide that sources having a compliance date on or after February 1, 2016, may submit the NOCS in the periodic report rather than as a separate submission. 4. Clarify at 40 CFR 63.660(e) that the initial inspection requirements that applied with initial filling of the storage vessels are not required again simply because the source transitions from the requirements in 40 CFR 63.646 to 40 CFR 63.660. 5. Revise 40 CFR 63.655(f)(1)(i)(B)(3) and (C)(2), (f)(1)(iii), (f)(2), and (f)(4) to clarify that when the results of performance tests [or performance evaluations] are to be reported in the NOCS, the results are due by the date the NOCS report is due (report is due 150 days from the compliance date) whether the results are reported using the Compliance and Emissions Data Reporting Interface (CEDRI) or in hard copy as part of the NOCS report. If the source submits the test results using CEDRI, we are also proposing to specify that the source need not resubmit those results in the NOCS, but may instead submit specified information identifying that a performance test [or performance evaluation] was conducted and the unit(s) and pollutant(s) that were tested. 6. Add the phrase “Unless otherwise specified by this subpart” to 40 CFR 63.655(h)(9)(i) and (ii) to make clear that test results associated with a NOCS report are not due within 60 days of completing the performance test or performance evaluation. 7. Amend several references in Table 6–General Provisions Applicability to Subpart CC that discuss reporting requirements for performance tests or performance evaluations to recognize that performance test results may be written or electronic. 8. Revise the ERT Web site to clarify that electronic reporting is not required where the ERT does not support the test method for the pollutant of interest. This has implications where a particulate test and HCN test are conducted coincidentally. In this case, the PM test (supported by ERT) would be submitted through ERT while the HCN test (not supported by ERT) would be submitted in hard copy. 9. Revise 40 CFR 63.655(h)(10) to address the situation where an extension may be warranted due to a force majeure event, which is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents them from complying with the requirement to submit a report electronically as required by the rule. 10. Revise 40 CFR 63.655(i)(5) to include the subparagraphs (as previously codified in subparagraph (i)(4)) that were inadvertently not included in the published CFR. 11. Move the paragraphs at 40 CFR 63.655(h)(5)(iii) to 40 CFR 63.655(i)(3)(ii)(C).