Additionally, the Application is woefully inadequate, sloppy and indeed, even illegible at parts. Since the Mingo TransGas project would be a

Transcription

1 West Virginia Department of Environmental Protection Division of Air Quality th St, SE Charleston, WV April 21, 2009 Re: TransGas Development Systems, LLC Application for a Regulation 13 Construction Permit in Mingo County, West Virginia as a Minor Source of Pollutants In December 2008, TransGas Development Systems, LLC submitted a Regulation 13 Permit Application to West Virginia Department of Environmental Protection to construct a Coal to Gasoline plant in Mingo County, West Virginia ( Project or Facility ). This Application claims that the proposed new Facility is a minor source under the Clean Air Act s New Source Review Program (NSR) as it emits less than 100 ton/yr of regulated pollutants, less than 10 ton/yr of a single hazardous air pollutant (HAP), and less than 25 ton/yr of total HAPs. Thus, the Application completely ignores NSR and HAP requirements. 42 U.S.C & 7502 (NSR); 50 C.F.R , 45 CSR 14 & 19; 42 USC 7412 (HAPs); 40 C.F.R. parts 60 & 63; 45 CSR 34. Review of the Application reveals that this facility is in fact a major source for purposes of NSR for at least particulate matter (PM), volatile organic compounds (VOCs), carbon monoxide (CO), and a major source of HAPs. 1 We urge the Department to reject the Application and request that the Applicant submit a complete Prevention of Significant Deterioration (PSD) and Maximum Available Control Technology (MACT) Application for HAP control for the reasons set out below. Additionally, the Application is woefully inadequate, sloppy and indeed, even illegible at parts. Since the Mingo TransGas project would be a 1 The Division should note that all other recent similar source projects have submitted major source applications. For example, the Medicine Bow Fuel & Power LLC (MBFP) Coal to Liquids Proposal in Wyoming, a similar source that will produce 18,500 gallons of gasoline/day using a methanol to gas process. Although the Club does not endorse the Medicine Bow proposal or permit, the applicant admits it will be a major source of all PSD-regulated pollutants as well as a major source of HAPs. (Application will be ed as an attachment because of its large size). See also Southeast Idaho Energy s coal to fertilizer project at ; Kentucky NewGas proposal (Application will be ed because of its large size); Illinois Power Holdings Application (Application will be ed because of its large size). 85 Second Street, Second Floor, San Francisco, CA Tel: (415) Fax: (415)

2 massive new source of air pollution for West Virginia, full public disclosure and review of the environmental impacts of this proposal are crucial. Sierra Club previously sent a letter, dated February 11, 2009, urging that redacted portions of the Application be disclosed. The Club applauds the Division for responding in a timely fashion to the Application s faults in this regard. Review of the Application to verify minor source status demonstrates that disclosure of this redacted information is crucial for public review. As detailed throughout this letter, both emission limits as well as all process descriptions must be made public in order to assure meaningful public review of the project s classification as a minor source. The public must be able to participate in this crucial decision that would essentially allow the TransGas plant to ignore state and federal regulations that are designed to protect air quality. I write on behalf of the West Virginia Chapter of the Sierra Club, whose members total approximately 2,000. The Sierra Club is a national nonprofit organization of approximately 1.3 million members and supporters dedicated to exploring, enjoying, and protecting the wild places of the earth; to practicing and promoting the responsible use of the earth s ecosystems and resources; to educating and enlisting humanity to protect and restore the quality of the natural and human environment; and to using all lawful means to carry out these objectives. I. EMISSIONS CALCULATIONS IN THE APPLICATION ARE WRONG BECAUSE NUMEROUS EMISSION SOURCES ARE COMPLETELY OMITTED,, IMPROPER ASSUMPTIONS ARE USED, AND CALCULATIONS ARE INCONSISTENT The emission inventory is variously included in Attachment J, Emission Points Data Summary Sheet, and Attachment N, Supporting Emissions Calculations. It consists of two parts: (1) process emissions estimated by UHDE, the design engineer, and (2) fugitive and other supporting emissions estimated in the Application by Potesta & Associates, Inc., who prepared the Application. The process emissions are redacted, as we explained in our previous letter, so important information for verifying minor source status is absent. Additionally, these two sets of calculations are often inconsistent with each other and are incomplete. The omitted sources are as follows: Emergency releases from Flare C2 and G (only pilot emissions were included. See Ap., p. J7); Fugitive CO emissions; 2

3 Fugitive H2S emissions; Fugitive methanol emissions; Vent emissions; CO emissions from cooling tower (from leaks in heat exchangers); Loading rack disconnect spills. In addition to omitted sources of pollutants, the Application used incorrect assumptions to calculate fugitive and other supporting emissions that further underestimate these emissions. First, the Application uses unsupported and unrealistically high control efficiencies for fugitive dust sources. It assumes, for example, an 85% control efficiency for haul road emissions without any support whatsoever. Our expert s experience is that 50% control efficiency is difficult to achieve. The Application also failed to consider collection efficiency of the gasoline loading vapor recovery system. Second, the Application uses an equation for stockpile wind erosion that has been eliminated from AP-42 as it is inaccurate. Finally, the emission calculations contained in Attachment J differ in material ways from those in Attachment N and summarized in Attachment P. The attached Excel spreadsheet, Exhibit 1, summarizes the emissions from Attachment N (Tab Attach N) and Attachment J (Tab Attach J). Tab Attach J highlights in pink discrepancies between the two versions of the emission inventory. If the version of the emissions contained in Attachment J is used, total PM emissions are 134 ton/yr, which exceeds the major source threshold of 100 ton/yr for PM, triggering NSR review. However, one does not have to rely on this one discrepancy to conclude this is a major source, as explained below for individual pollutants. II. THE FACILITY IS A MAJOR SOURCE The Application assumes the source is a minor source because the calculated emissions for all regulated pollutants are less than the major source threshold of 100 ton/yr, based on total emissions as summarized in Table 1 from Attachment P, the proposed Public Notice summary of emissions: 3

4 Table 1 Total Emissions Estimated In Application Pollutant Ton/yr NOx 50 SOx 84 CO 90 VOC PM PM HAPS Methanol 6.85 Source: Ap., Attach. P. The engineering firm, UHDE, calculated emissions for stacks and flares from the main processing units (coal preparation, PDQ, CO2 purification, AGR, MTG, flares and boilers), but excluded large sources of pollutants, including fugitive emissions (stockpiles, crushers, transfer points, haul roads, fugitive components) and certain other supporting facilities (e.g., cooling tower, loading rack). The Application supplements UHDE s calculations with emission estimates for transfer points, crushers, haul roads, stockpiles, tanks, fugitive components, and loading racks. We can only comment on errors and omissions in the Potesta emission estimates, which are not redacted. However, due to the lack of publicly available information on process descriptions and supporting calculations, we cannot comment on the UHDE emission estimates. We urge the Division to scrutinize the information it has from the Applicant, and request that this information be made publicly available so that the public has a meaningful opportunity to participate in the classification of this major new source of air pollution. II.A Particulate Matter (PM) Emissions Exceed 100 TPY Total PM emissions estimated in the Application are ton/yr, just 4.24 ton/yr shy of the 100 ton/yr major source threshold. Clearly, any minor change in assumptions would put this Project over the major source threshold, requiring PSD review. In fact, if the emissions reported in Attachment J are used instead of those in Attachment N, the total PM emissions are 134 ton/yr, exceeding the major source threshold. However, other necessary corrections to the proffered fugitive calculations would put this facility over the major source threshold. 4

5 The particulate matter (PM) emissions accounted for in the Application and our revisions of more accurate estimates are summarized below in Table 2. Table 2 Particulate Matter Emissions (ton/yr) EMISSIONS SOURCE APPLICATION OUR REVISED ESTIMATE UHDE Process Emissions Transfer Points Crushers Stockpiles Haul Roads Cooling Tower TOTAL Source: Ap., Attach. N First, the haul road emissions amount to ton/yr. These emissions were calculated from uncontrolled emissions of ton/yr, assuming 85% control efficiency using WT/WC. The abbreviation WT/WC is not defined (Ap., p. L8), but presumably refers to at least water truck. Our expert s experience is that it is very difficult to achieve more than 50% fugitive dust control for paved haul roads. We did not find the information required for dust control measures, set out in Attachment L at L1 to L2, in the Application. The proposed level of control would require at least paving of the haul road shoulders to prevent dust entrainment, speed limit control, covered truck beds, truck washing, daily road sweeping, and daily or more frequent application of chemical dust suppressants. Recordkeeping and reporting would be required to assure these stringent measures are implemented. The Application does not even hint at these types of measures. If the control efficiency achieved in practice were only 80%, instead of the proffered 85%, PM emissions from haul roads would increase from ton/yr to ton/yr, or an increase of 4.81 ton/yr. The total PM emissions would increase from ton/yr to ton/yr. This increase is thus enough to exceed the major source threshold for PM. Further confusing matters, Attachment L at L100 reports a 70% control efficiency for the haul roads. Regardless, actual emissions could be much higher, ton/yr, if the control efficiency were only 50%, a more typical and realistic value. Second, PM emissions from wind erosion of the coal and limestone stockpiles were estimated to be ton/yr. These emissions were calculated from an equation in the May 1983 edition of AP-42 that has been 5

6 superseded. Ap., p. N5. The cited Section , Aggregate Handling & Storage Piles, from Supplement 14 of AP-42, 2 is superseded by Section of the current, November 2006 edition of AP-42, which has the same caption. However, the equation used to estimate wind erosion emissions from storage piles has been deleted, presumably because it was inaccurate. Wind erosion emissions from storage piles are now covered by AP-42, Section The Application does not contain sufficient information to estimate wind erosion emissions using this section of AP-42. However, AP-42 offers an alternative for active coal storage piles, Section 11.9, Table This section of AP-42 reports a wind erosion and maintenance emission factor of 0.72u lb/acre-hour where u is the wind speed in miles per hour. The Application assumes a wind speed for the site of 7 mph. Thus, coal storage pile emissions would be 5.04 lb/ac-hr. The coal stockpile area is 4.5 acres. Thus, PM emissions from the coal stockpile would be ton/yr. 3 These PM emissions alone nearly exceed the 100 ton/yr significance threshold. When combined with PM emissions from other sources, total facility emissions would be at least ton/yr, assuming no other changes in PM emissions, e.g., as discussed supra for haul roads. The Application makes other assumptions that underestimate fugitive PM emissions that we can identify but do not have adequate information to quantify. A haul road silt loading of 8 g/m 2 is significantly lower than a default of 10 ug/m 2 that is used in many states. The assumed 80-90% control of dust at drop points is unrealistically optimistic. A mean on-site wind speed of 7 mph is based on the state-wide average but should be based on local conditions. We encourage the Division to reject the PM emissions as calculated and require a more realistic and better documented analysis, including proof that all claimed control efficiencies can be met day in and day out on a long-term basis. Correcting this analysis is critical because the claimed potential to emit PM is a mere 4.24 ton/yr shy of the major source significance threshold. II.B Volatile Organic Compound ( VOC ) Emissions Exceed 100 TPY Total VOC emissions estimated in the Application are ton/yr. However, the Application dramatically underestimates the emissions from the loading rack. When this underestimation is corrected, VOC emissions are 360 ton/yr, exceeding the major source threshold of 100 ton/yr. The VOC emissions in the Application and our revisions of more accurate estimates are summarized below in Table 3. 2 Supplement No. 14 for Compilation of Air Pollutant Emission Factors, Third Edition, May 1983, 3 Coal stockpile wind erosion and maintenance emissions: (0.72)(7)(4.5 ac)(8760 hr/hr)/2000 lb/ton = ton/yr. 6

7 Table 3 VOC Emissions (ton/yr) EMISSION APPLICATION OUR REVISED ESTIMATE SOURCE Coal Prep Vent Mill Methanol Fugitives 6.60 Methanol Tank Gasoline Fugitives Gasoline Tanks Loading Racks TOTAL Source: Ap., Attach. N. The Application calculates VOC emissions from loading gasoline into trucks and rail cars using AP-42, Chapter 5.2. It then assumes that 99% of the loading vapors would be controlled by a vapor recovery system. Ap., p. N17. EPA clearly states in AP-42 that this control efficiency is too high. Control efficiencies for the recovery units range from 90 to over 99 percent, depending on both the nature of the vapors and the type of control equipment used. However, not all of the displaced vapors reach the control device, because of leakage from both the tank truck and collection system. The collection efficiency should be assumed to be 99.2 percent for tanker trucks passing the MACT-level annual leak test (). A collection efficiency of 98.7 percent (a 1.3 percent leakage rate) should be assumed for trucks passing the NSPS-level annual test (). A collection efficiency of 70 percent should be assumed for trucks not passing one of these annual leak tests AP-42, Chapter 5.2, p (footnotes omitted). The Application is silent as to leak tests. Absent a specific requirement that tankers (train or truck) servicing the site meet a specific leak rate, a 70% control efficiency should be used in the emission calculations. The vapor recovery system itself may be able to reduce 99% of the VOCs that reach it, but 100% of VOC emissions from loading losses will not reach this system, but rather leak out and spill onto the ground or be emitted as vapors. Using a 70% collection efficiency and 99% vapor recovery control efficiency increases controlled VOC emissions from truck loading from 7

8 11.72 ton/yr to ton/yr. 4 Thus, the VOC emissions from gasoline loading alone are large enough to exceed the major source threshold, requiring NSR review for the entire facility, absent a permit limit controlling the tanker leak rate. There are new source performance standards (NSPS) covering tanker truck loading operations at 40 CFR 60 subpart XX. Attachment D of the TransGas Application includes a list of NSPS sections the facility may be subject to, and the tanker truck NSPS section is not listed. If the NSPS applies to the TransGas facility, the Application should include the section, and the requirement must be included in the final permit. The gasoline loading VOC emissions are otherwise underestimated. First, in AP-42, EPA clearly states that the formula used in the gasoline loading calculations has a probable error rate of +/- 30%. AP-42, p Potential to emit must be based on the maximum emissions. Thus, the emission calculations should account for the 30% error rate by assuming that the emission factor is 30% higher than the factor resulting from the AP-42 equation. Second, the Application completely ignores VOC emissions from evaporation of disconnect spillages from the two loading racks. Third, the Application does not count VOC fugitives (6.60 ton/yr) from the methanol system. These fugitives, which are methanol, a VOC, should be counted as VOC emissions. The emissions listed at Ap., p. N16 are not included in the totals at page N1, totals for advertisement, as also summarized in Attachment P. Finally, fugitive component leak emissions are incomplete and unsupported. The Application reports fugitive component leaks for two sources: vapor sources in the methanol system (Ap., p. N16) and gasoline fugitives. Ap., p. N17. No other fugitive emissions are reported, even though the process flow diagrams show they are present. First, fugitive component leaks are reported for the methanol system. The methanol system is not defined nor its battery limits identified on a process flow diagram. Presumably, the methanol system is the Methanol Synthesis process flow diagram in Attachment E. This diagram does not show the fugitive components, except two compressors. The VOC emissions from fugitive components in this system (6.598 ton/yr) were calculated for the application by multiplying the number of each component (valves, pressure relief valves, connectors, compressor seals) by an emission factor in kilogram per hour per source (kg/hr/source). Ap., p. N16. The Application does not disclose the source of these emission factors, which differ from those used for gasoline emissions on p. N17. The Application should be updated to include a 4 Loading Rack VOC emissions assuming 90% collection efficiency, based on calculations in Ap., p. N17: ( ton/yr)(0.3) + ( ton/yr)(0.7)(0.01) = ton/yr. 8

9 process & instrumentation diagram for the methanol system and support for the VOC emission factors. Second, fugitive component leaks are reported for the gasoline system, based on the EPA report, Protocol for Equipment Leak Emission Estimates, Table 2-2. Ap., p. N17. The Application does not contain a process flow diagram for the gasoline system that lays out its battery limits, process flows, and identifies fugitive components. Thus, it is not possible for the public to evaluate the accuracy of the emission estimates. Again, we urge the Division to carefully evaluate the information it possesses, and continue to take steps to make this information publicly available. Third, the facility will include Pressure Swing Absorption (PSA) units, which would typically contain deaerator and steam vents which are known to be significant sources of VOC emissions and are regulated in some air districts. 5 None are shows on the process flow diagram in the Application. The Division should confirm that no steam or deaerator vents will be used in the PSA system. Finally, the Methanol Synthesis unit contains one steam vent to atmosphere (MUG-SVA) and three steam vents to flare (MUG-SVF1, MUG- SVF2, MUG-SVF3, MUG-SVF4). Ap., Attach. Ff, 331 Methanol Synthesis. The emission inventory does not include any VOC or methanol emissions from vents to atmosphere nor any flaring emissions for the vents to flare, thus underestimating not only VOC emissions, but also CO, NOx, and methanol emissions. II.C Carbon Monoxide ( CO ) Emissions Exceed 100 TPY The CO emissions accounted for in the Application and our revised estimates of more accurate figures are summarized below in Table 4. 5 South Coast Air Quality Management District, Report on Emission Limits for Rule Emissions from Hydrogen Plant Process Vents, May 17,

10 Table 4 CO Emissions (ton/yr) EMISSION SOURCE APPLICATION PLICATION OUR REVISED ESTIMATE Coal Prep Vent Blower Coal Prep Dust Bunker PDQ Lock Hopper Filter PDQ Flare CO2 Purification AGR Flare MTG Stack Gas MTG Waste Gas MTG Tail Gas Flare Startup Steam Boiler Flare Fugitive Emissions >12.45 Steam Vents + Steam Vents to Flare + Cooling Tower TOTAL > The total CO emissions, 90 ton/yr, are just 10 ton/yr shy of the major source threshold of 100 ton/yr. The UHDE emissions summarized in Table 4 do not include fugitive emissions. Ap., Attach N, Mass Balance + Emission Calculation, no page number. The Application did not estimate fugitive emissions of CO, as it did for VOCs and PM/PM10 fugitives. Fugitive emissions of CO would be significant enough to exceed the major source threshold as explained below. The syngas from the Gasifiers, CO Shift Unit, and PSA is a mixture of CO and hydrogen. Carbon monoxide, a PSD-regulated pollutant, would be emitted from all fugitive components valves, pressure release valves, pumps, compressors, sampling lines, and connectors in these systems. The PSA system, for example, includes 30 valves, all of which would emit CO. Ap., Attach F, 335 PSA System. The Application failed to estimate these emissions, nor does it contain the information required to estimate them -- component counts and emission factors that reflect the composition of the gas stream processed by each components. Again, this is information that must be made available for public review. 10

11 However, an estimate can be made of CO fugitive emissions from the PSA system, based on the number of valves shown on the process flow diagram and the leak rate/screening correlations from the EPA report relied on by the Applicant. Assuming a CO concentration of 100,000 ppm, the resulting emission factor is kg CO/hr-valve. 6 The resulting CO emissions from these 30 valves would be ton/yr. These emissions plus those estimated by UHDE from process units is sufficient to exceed the major source significance threshold of 100 ton/yr. CO emission would be released from other sources, including fugitive components in the Gasifiers and CO Shift Unit. Further, these units contain steam vents that are vented to atmosphere or to flares. The CO Shift Unit contains one steam vent to atmosphere (COS-SVA1) and two steam vents to flare. Ap., Attach. F, 233 CO Shift. The CO2/H2S Removal Unit contains two steam vents to atmosphere (CHR-SVA1, CHR-SVF5) and four steam vents to flare. Ap., Attach F, 235 CO2/H2S Removal. The vent gases and flared gases would contain CO. Finally, the Facility contains a cooling tower with a circulating water flow rate of 18,490,000 gallons per hour. Ap., p. N16. The cooled water is used in heat exchangers throughout the Facility to cool hot process streams. Leaks in these heat exchangers result in process fluids contained on the hot side of the exchangers leaking into the cooling water. Contaminants in the leaked process fluids are released to atmosphere in the cooling tower. This is a well known emission source in petroleum refineries. AP-42 contains an emission factor for these leaks, 0.7 lb/mmgal of hydrocarbons. AP-42, Table The process fluids at the facility will contain high concentrations of CO, rather than hydrocarbons. Assuming the same emission factor, CO emissions from heat exchanger leaks alone would be about 57 ton/yr. 7 II.D Methanol A facility is a major source for HAPs if the emissions of any single HAP equal or exceed 10 ton/yr or if total HAP emissions equal or exceed 25 ton/yr. The Application estimated that the facility would emit 6.85 ton/yr of methanol from the methanol storage tank. Ap., p. N1 (summary) and N16 (methanol tank). However, the Application also estimated VOC emissions of ton/yr from fugitive components in the Methanol System. Ap., p. N16. These VOC emissions would be predominately methanol. Absent a demonstration to the contrary, they should be added to the methanol tank 6 EPA, Protocol for Equipment Leak Emission Estimates, November 1995, Table 2-9, valve equation: emission factor = (1.87x10-6 )(100,000 ppm) = kg/hr-valve. Total CO emissions: (0.043 kg/hrvalve)(30 valves)( lb/kg)(8760 hr/yr)/2000 lb/ton = ton/yr. 7 Cooling tower CO leaks: (0.7 lb/mmgal)(18.49 MMgal/hr)(8760 hr/yr)/2000 lb/ton = ton/yr. 11

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