Home

10_PetroRefine

1. If you have a Fluid Catalytic Cracking Unit FCCU the GHG emissions quantification method you will use is based on the calculation of hourly coke burn rate in the catalyst regeneration unit Here are the steps involved 1 Coke burn rate is calculated on an hourly basis using the methodology specified by the U S EPA in 40 CFR Part 63 National Emission Standards for Hazardous Air Pollutants Petroleum Refineries Coke burn rate input parameters are derived from FCCU control room instrumentation See the first equation in 95113 b A for specifics You should use the equation for the calculation of Q the volumetric flow rate of exhaust gas before entering the emission control system which is provided in this section Calculation of Q is also based on 40 CFR Part 63 guidelines 2 You will then calculate a daily average coke burn rate expressed in kg day 3 Next you need to determine the carbon fraction in the coke burned That is what fraction of the coke contained on spent catalyst is carbon As an example if based on analysis of FCCU catalyst withdrawn from an appropriate sampling location you determine that 95 percent of the mass on the spent catalyst is carbon carbon content would be expressed as CF 0 95 Assuring Carbon Fraction Accuracy Note that the regulation does not specify a frequency or methodology for the determination of the variable carbon fraction As FCCU CO emissions may represent a significant fraction of you
2. Organic Liquid Storage Tanks This report contains a detailed description of the types of storage tanks perimeter seals and deck fittings It is available here www epa gov ttn chief ap42 ch07 bgdocs b07s01 pdf Another resource is the Santa Barbara County Air Pollution Control District Rule 325 Crude Oil Production and Separation found at www arb ca gov DRDB SB CURHTML R325 PDF Read the Installation Instructions file first and then install TANKS 4 09D on your computer You will need to uninstall previous versions of TANKS If you have previous databases you can import them into TANKS 4 09D See sections 3 4 Using a Previous Database and 6 0 Database Utilities of the Users Manual for instructions 10 18 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 5 3 2 Establishing your Chemical Databases The first step in the set up procedure of the TANKS model should be to establish chemical databases for the types of hydrocarbons for which you will be calculating VOC emissions crude oil asphalt distillates and naphtha 1 Crude Oil the model contains one Chemical Database for crude oil with an RVP of 5 Use this database for your crude oil storage tanks 2 Distillate oils in this case you also use the default database contained in the TANKS model 3 Naphtha TANKS contains a data base for jet naphtha use this database 4 Asphalt in the case of a
3. XCC ZFo t i 1 For all leaking components where the component screening value is above zero and below the limit set by your local air district above which correlation equations may not be used for VOC calculation either 9 999 or 999 999 ppmv use the equation found in section 95113 c 4 A 3 b 10 27 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Table 10 5 4b Fugitive Equipment VOC Emissions Leaking Components SV gt 0 and less than upper bound for use of correlation equation Required Data Units Value Data Source 0 correlation equation unitless column three Table 14 coefficient for component i regulation Appendix A SV component screening ppmv operator determined value for component n Bi correlation equation unitless column three Table 14 exponent for component type regulation Appendix A i t time from last screening time hours operator determined If your local air district has set a screening value limit of 9 999 ppmv for the use of correlation equations SV gt 9 999 ppmv is considered pegged you will use the equation found in section 95113 c 4 A c to calculate VOC emissions 6 n E yoce 2 Xlo SVE t l n a Table 10 5 4c Fugitive Equipment VOC Emissions Pegged Components SV gt 9 999 ppmv Required Data Units Value Data Source CC number of i components number
4. 2008 CO MMBtu is then calculated using the equation found in section 95125 e 3 The operator should ensure that a representative sample is drawn for carbon analysis the HHV analyzer is properly installed in an appropriate location the carbon content analysis accurately characterizes the fuel and sampling is performed under conditions representative of prevailing operational parameters 2 Calculate CO emissions Once you have determined a daily CO EF for your RFG system daily CO emissions are calculated using the daily average RFG HHV derived from the on line continuous HHV analyzer Use of a daily average HHV is designed to integrate daily variations in RFG heating value and indirectly carbon content This calculation is accomplished using the formula found in section 95125 e 4 _ RFG CO emissions for all RFG systems are then summed to calculate facility RFG CO emissions Exception for Small Refineries Refiners that qualify as small refiners under California statutes may calculate CO emissions from refinery fuel gas combustion on a weekly basis rather than daily See Title 13 California Code of Regulations Section 22609 a 32 to determine whether your facility is small 10 1 3 Calculating Natural Gas and Associated Gas CO Combustion Emissions section 95125 c or d There are several steps required to calculate stationary combustion CO emissions from natural gas and associated gas 1 Determin
5. 25 kg CH4 kg COD and MCF from Table 12 10 15 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Table 10 5 1 1 Fugitive Emissions from Wastewater Treatment Methane Required Data Units Value Data Source Q Volume of wastewater m yr operator measured treated CODgave average of quarterly kg m operator measured COD S COD removed in sludge kg COD yr operator measured B methane generation 0 25 kg CH kg COD supplied capacity MCF methane conversion unit less operator determined from factor Table 12 regulation Appendix A Conversion factor kg to 0 001 supplied metric tonnes CH Q COD S B MCF 0 001 10 5 1 2 Wastewater Nitrous Oxide emissions Calculation of nitrous oxide emissions requires that the operator measure the nitrogen content of effluent on a quarterly basis If you have more than one autonomous wastewater treatment facility you must determine N20 emissions from each facility Samples should be collected at a location representative of wastewater entering the facility immediately prior to treatment Again the regulation does not specify a method of analysis and staff suggests that you consult with a reference text or contract laboratory ARB staff suggests that you consult the EPA Clean Water Act Analytical Methods documentation for references e g Method 351 2 concerning the determination of to
6. Btu gases and flexigas Pressure swing absorption off gas vapor recovery gases and asphalt tank headspace gases are examples of low Btu gases If you have questions as to whether a process gas that you generate might fall into this category ARB encourages you to discuss the issue with staff Flexigas is formed when hydrocarbons are thermally cracked in a flexicoker to produce coke products Usually low Btu gases are either used as a supplemental fuel that is mixed with a fuel of higher Btu content and combusted as part of a fuel mixture or destroyed in a flare or other destruction device such as a thermal oxidizer Other than inclusion in CEMS estimates low Btu gas stationary combustion CO emissions are determined depending upon their use 10 1 6 1 Combustion of low Btu gases as a fuel If you are mixing a low Btu gas to supplement another fuel consult sections 95125 f 1 A and C If you are mixing a low Btu gas with refinery fuel gas the more stringent RFG requirements apply to the resulting mixture If you mix a low Btu gas with natural gas the HHV of the resulting mixture determines which emissions calculation method you should use just as is the case with natural gas If the HHV of the natural gas low Btu gas mixture falls in the 975 1100 Btu range then you should determine mixture HHV monthly use the appropriate default CO emission factor from Table 4 of regulation Appendix A and calculate emissions using the formula in sectio
7. If ARB approves your source test plan you will conduct source testing annually during a period of typical and representative operating conditions and under the supervision of ARB or local AQMD APCD personnel For all sour gas streams that you do not source test you should use the default value of 20 percent In the case where you do conduct source testing CO emissions for the source tested sour gas stream should be summed with CO emissions from all non source tested streams and total CO emissions related to sulfur recovery reported Table 10 4 4 Sulfur Recovery Units CO Process Emissions Required Data Units Value Data Source FR volumetric flow of acid metric tonnes yr operator measured gas to SRU MW co2 44 kg kg mole supplied MVC molar volume choose MVC for 20 C or 60 F supplied conversion MF molecular of CO in sour default MF 20 or supplied or operator source gas operator source test test derived 0 001 CF kg to metric tonnes supplied CO FR MWeo MVC MF 0 001 10 5 Reporting Fugitive Emissions The reporting regulation requires that the operator report four categories of fugitive emissions methane and nitrous oxide from wastewater treatment methane from oil water separators methane from storage tanks and methane from fugitive equipment Each of these is discussed below 10 5 1 Reporting Wastewater Treatment Fugitive Emissions Both methane and nitrous oxide may be emitted du
8. an assumed destruction efficiency of 98 percent are used in the first equation found in section 95113 b 4 A to calculate annual methane emissions These same inputs are used to calculate CO combustion emissions using the second equation in section 95113 b 4 A In this case a conversion factor 2 743 is used to convert from CH to CQ Table 10 4 3a Asphalt Blowing Operations CO Process Emissions Required Data Units Value Data Source Ma mass of asphalt blown 10 bbl yr operator measured EF methane emissions 2 555 scf CH 10 bbl supplied MWcu4 methane molecular 16 04 kg kg mole supplied weight MVC molar volume choose MVC for 20 C or 60 F supplied conversion DE methane destruction 98 expressed as 0 98 supplied efficiency CF kg to metric tonnes 0 001 supplied CH M EF MW MVC 1 DE 0 001 Table 10 4 3b Asphalt Blowing Operations CH Process Emissions Required Data Units Value Data Source M mass of asphalt blown 10 bbl yr operator measured EF methane emissions 2 555 scf CH4 10 bbl supplied MWcu4 methane molecular 16 04 kg kg mole supplied weight MVC molar volume choose MVC for 20 C or 60 F supplied conversion DE methane destruction 98 expressed as 0 98 supplied efficiency CF CH to CO2 2 743 supplied CF kg to metric tonnes 0 001 supplied CO M EF MWoy MVC DE 2 743 0 001 10 4 4 Reporting Sulfur Re
9. and these are discussed below At most refineries emissions must be determined daily for each RFG system In cases where multiple RFG systems are mixed and homogenized prior to combustion it may be more appropriate to determine the carbon content of the mixture rather than each system individually The most important consideration is to ensure that the carbon content of all RFG combusted is accurately quantified There are three general procedural approaches for calculating CO emissions resulting from the combustion of refinery fuel gas 10 1 2 1 CEMS section 95125 g The operator may use a CEMS to quantify CO emissions from one or more refinery fuel gas systems Refer to section 95125 g of the regulation and section 13 7 of this guidance documentation for specifics concerning CEMS installation operation and emissions calculation 10 2 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 1 2 2 Carbon content testing_using on line instrumentation or discrete sample laboratory analysis section 95125 d 3 A The operator may use on line instrumentation e g a gas chromatograph to determine fuel gas carbon content An important consideration in evaluating any on line compositional analysis method is that the instrumentation and analytical methodology used provide a complete characterization of all major species present in the refinery fuel gas system In practic
10. destruction Use the formula found in section 95113 d 2 A The method assumes a carbon fraction of 0 6 for the NMHC species You should use the flaring destruction efficiency specified by your local air district 10 29 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Table 10 6 1a Flaring Emissions CO and CH Using NMHC and CH4 Required Data Units Value Data Source CFymuc NMHC carbon fraction unitless CFymyc 0 6 supplied NMHC flare NMHC emissions kg day operator determined as per air district reporting requirements CH flare emissions kg day operator determined as per air district reporting requirements FE flare destruction percent specified by local air district efficiency CF methane to carbon 2 743 supplied dioxide CF kg to metric tonnes 0 001 supplied CF carbon to carbon dioxide 3 664 supplied 365 CO gt CF yc NMHC FE 100 FE 3 664 CH FE 100 FE 2 743 0 001 1 If you are subject to SCAQMD Rule 1118 Control of Emissions from Refinery Flares you should calculate ROG as specified in Attachment B of Rule 1118 and report flare CO emissions as shown in section 95113 d 2 B This document is available at the following link www aqmd gov rules reg reg11 r1118 pdf The method assumes an ROG carbon fraction of 0 6 and you should use the flare destruction efficiency
11. in situations where the HHV of the fuel in question is measured 10 1 7 3 Default fuel HHV and emissions factors In the case where the fuel HHV is not measured you may use default HHV and EF values Default HHV and EF values for CH and N20 are found in Table 4 of regulation 10 7 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Appendix A For refinery fuel gas use the values listed for still gas Use the equation found in section 95125 b 3 10 1 8 Calculating CH and N20 combustion emissions from Derived Gases The emission factors for derived gases found in Table 6 of regulation Appendix A are applicable for species such flexigas PSA off gas and low Btu gases in general 10 2 Fuel and Feedstock Consumption The operator is required to report both fuel and feedstock consumption as directed in section 95113 a 3 You should report in the units indicated the consumption of all fuels combusted at the facility and all feedstocks involved in processes that are used to calculate GHG emissions In addition section 95103 a 2 requires you to report fuel consumption for each process unit or group of units where fuel use is separately metered 10 3 Reporting Hydrogen Production Plant Emissions Refer to Chapter 11 of this document for guidance on reporting emissions from hydrogen production facilities Hydrogen plants associated with petroleum refinerie
12. 3 3 Tank Contents Tab Entries Tank Contents Chemical Category Single or Multi Chemical Name of Liquid component Liquid Crude oil Crude oil single Crude oil RVP 5 Asphalt Petroleum Distillates single Asphalt Distillate oil Petroleum Distillates single Distillate Fuel oil no 2 Naphtha Petroleum Distillates single Jet Naphtha JP4 Monthly Calculations Tab Click both the Fill Mixture Names with First Mixture Name and Distribute Throughput buttons This will populate the monthly contents fields with the contents name and distribute the annual throughput of the storage tank equally across the twelve months of the year 10 5 3 4 Generating VOC Emissions Run Report After you have established a Chemical Database for asphalt if you have asphalt storage tanks at your facility and your storage tank database you are ready to generate VOC emission reports From the tool bar choose Report and then Annual and Brief from the pull down menus You may also select Summary or Detail if you would like to examine the generated data in more detail this depth of the report which you select will not affect the results You will then see the following Screen where you will choose the storage tanks for which you generate emission reports Select tanks in the left column by clicking on them click on the Select button in the center column and the selected tank will appear in the right column 10 25 Refineries Califor
13. 5 f refers you to section 95125 d 3 A or 95125 e 10 1 5 Options for Calculating CO Combustion Emissions from Other Fuels section 95125 a c or d The methods described in sections 95125 a c and d of the regulation are applied to the more common fuels where composition heating value carbon content and thus CO combustion emissions are well characterized and exhibit little variability In addition to CEMS discussed above the regulation provides three alternatives for determining CO stationary combustion emissions for these fuels 10 1 5 1 Default CO emission factor and default heat content section 95125 a Find the fuel in Table 4 of regulation Appendix A Use the default HHV and CO emission factor values for the fuel along with fuel consumption data mass or volume year to calculate stationary combustion emissions for this fuel 10 1 5 2 Measured HHV and default CO2 emission factors section 95125 c You may also choose to use measured rather than a default value HHV with a default CO emission factor If you choose to determine fuel HHV you must comply with the requirements of section 95125 c and related sections dealing with parameters such as sampling frequency and analysis methods 10 1 5 3 Measured carbon content section 95125 d Finally you may choose to measure fuel carbon content and calculate fuel stationary combustion emissions using the appropriate solid liquid or gaseous fuel formula and A
14. California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 CHAPTER 10 PETROLEUM REFINERIES Guidance for Regulation Section 95113 As listed in section 95113 a of the regulation the emissions data report for a petroleum refinery must include the following information as applicable 1 Stationary combustion CO emissions by fuel type 2 Stationary combustion CH and N20 emissions by fuel type 3 Consumption data for fuels and feedstocks 4 Hydrogen production plant emissions of CO2 CH4 and N20 5 Specified process emissions 6 Specified fugitive emissions 7 Flaring emissions 8 Emissions from electricity generating units 9 Emissions from co generation facilities 10 Indirect energy purchases Calculation methods for each of these reporting requirements are discussed in this chapter Note that in addition to referring to the common methodologies section of the regulation section 95125 you will find general guidance on applicable methods in Chapter 13 of this document Information specific to refineries is included here 10 1 Stationary Combustion Emissions As indicated by the regulation s general requirements section 95103 a 2 the operator needs to calculate and report emissions for each GHG separately for each fuel type used except where a CEMS is deployed discussed below Thus in compiling and reporting stationary combustion emissions you will be effectively populati
15. STM method found in section 95125 d ARB staff recommends you choose an 10 5 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 analytical method that provides data for 295 percent of the carbon in the fuel For all fuels other than refinery fuel gas carbon content should be measured monthly Careful consideration of default values In practice when should you determine fuel HHV and or carbon content rather than use default values If you have concerns or questions concerning the accuracy of default values it would be appropriate to investigate in more detail which approach is suitable to ensure an accurate accounting As an example if you are using headspace gas as a fuel or feedstock and are presently measuring only bulk liquid composition you should examine the appropriateness of this approach How closely does the liquid analysis approximate the composition of the actual fuel or feedstock and is the measured HHV significantly different from the default value In this case analysis of both phases should answer the question When you are presented with alternative approaches choose the method that ensures the integrity of your emissions report not the simply the easiest or least expensive 10 1 6 Calculating CO Combustion Emissions from Low Btu Gases section 95113 a 1 E Section 95113 a 1 E details stationary combustion CO emission calculations for low
16. and N20 emissions resulting from fuel combustion represent a small fraction of fuel combustion related GHG emissions While CH and N20 emissions are strongly dependent on combustion technology calculation methods are fuel specific and based on fuel HHV You should choose the most appropriate of the following three methods for calculating CH and N O stationary combustion emissions 10 1 7 1 Source Testing section 95125 b 4 The operator may elect to conduct source testing to determine fuel and combustion specific emissions factors EFs for CH4 and or N20 The source test plan you use must be approved by ARB and repeated at least annually under the supervision of ARB or the local air district EFs should be expressed in terms of grams of CH or Emission factors derived from source testing grams of N20 per MMBtu Additionally are specific to fuel and combustion the HHV of the fuel in question should be technology If you conduct source testing on measured at the time of the source test a steam boiler combusting refinery fuel gas Use the measured fuel HHV rather than a for example the derived CH and N20 EFs default value and the methodology should be used only when calculating CH and specified in section 95125 b 2 Source bord E as similar boilers combusting testing is addressed in more detail in Appendix B of this guidance document 10 1 7 2 Measured HHV and a default emission factor Use the method found in section 95125 b 2
17. characterize your treatment facility as well maintained with no significant methane emissions and use a MCF value of zero you would not be required to report emissions Once you have evaluated your treatment and chosen an appropriate MCF value to determine wastewater related emissions you will need to know the volume of wastewater that is discharged annually to your treatment facilities To calculate methane emissions you will also need to determine the chemical oxidation demand COD kg m of the wastewater and any of any sludge that is removed from the treatment facility You should sample and measure wastewater COD on a quarterly basis Choose an appropriate sampling location where a representative sample of incoming wastewater composition can be collected and sample when situations are representative of normal operational conditions The regulation does not specify a specific method for the determination of wastewater COD The determination of COD is a common practice ARBstaff suggests you consult a recognized reference source such as Standard Methods for Examination of Water and Wastewater 20 edition Available at http www standardmethods org If you have more than one wastewater treatment facility you will need to determine the COD of wastewater entering each system The following variables are then used to calculate methane emissions annual wastewater volume treated average COD sludge COD removed methane generation capacity 0
18. covery Unit Process Emissions Numerous refining processes e g distillation hydrodesulfurization and catalytic cracking generate products that require sulfur removal and thus are directed to a sulfur recovery plant These process streams also contain entrained hydrocarbons that are typically oxidized during the sulfur removal process and subsequently emitted as 10 13 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 CO2 This section of the regulation section 95113 b 5 is designed to account for these emissions To calculate CO emissions from a sulfur recovery plant you need to know the volume of gas treated annually at your plant Depending upon the pumping configuration of your sulfur recovery plant this may require measurement of multiple input stream flows Make sure that you account for all sour gas streams entering the plant A default molecular fraction of CO in the sour gas treated of 20 percent expressed as 0 20 may be used to then calculate CO emissions as shown in section 95113 b 5 A If you believe that this default value may overestimate or underestimate CO emissions you may submit a request to ARB to conduct source testing for one or more of the sour gas streams entering your sulfur plant For example if you have one sour gas stream that has a low carbon content you may submit a source test plan for that gas stream to ARB for review
19. e the operator should ensure good quality data is gathered on 295 percent of the mass of hydrocarbons present in each RFG system where on line instrumentation is used ARB staff recommends that instrumentation be operated maintained and calibrated according to original equipment manufacturer OEM specifications and located appropriately in order to obtain a representative sample of the RFG system in question For each RFG system where on line instrumentation is used the operator must determine carbon content and fuel molecular weight at least once every eight hours that RFG from the system is combusted Measurements should be taken at approximately the same relative period beginning middle or end during each 8 hour period or at times during each 8 hour window appropriate to provide for representative sampling For each analysis the operator will also need to calculate refinery fuel gas molecular weight kg fuel kg mole using the data from the on line instrumentation To calculate daily CO emissions the current day carbon content values kg C kg fuel should be averaged to calculate daily average carbon content Similarly the fuel molecular weight determinations should be averaged These daily average carbon content and fuel molecular values are then applied to the equation found in section 95125 d 3 A along with the amount of RFG combusted to calculate daily CO emissions Daily emissions are then summed to calculate annual emission
20. e fuel HHV The operator needs to know the HHV of the natural gas or associated gas in order to determine which method to use to calculate CO stationary emissions from these two fuels HHV may be measured either by the facility operator or by the fuel supplier HHV may be determined by using the ASTM methods listed in section 95125 c 1 B or by using on line instrumentation 2 Converting low heat value LHV to HHV If you currently have installed an on line analyzer that measures only LHV you will need to convert LHV to HHV using the approach shown in section 95125 c 1 C where HHV LHV x CF If the fuel in question is natural gas you should use a conversion factor CF of 1 11 If the fuel is a mixture containing refinery fuel gas simply derive a weekly average fuel system specific CF where CF HHV LHV The weekly HHV may be derived from either from the daily HHV calculated as part of the daily carbon content determination or from on line instrumentation 3 Next you will choose a CO emission calculation method based on fuel HHV value If the HHV of your natural gas associated gas or mixture is gt 975 Btu scf but lt 1100 Btu scf you should determine HHV on a monthly basis The monthly HHV value is then used with an EF kg CO MMBtu to calculate fuel CO emissions section 95125 c 1 _ The applicable EF value can be found in Table 4 of regulation Appendix A Choose the EF which corresponds to the correct 10 4 Refineries Cali
21. ection of the refining reporting section of the regulation section 95113 addresses the destruction of hydrocarbons streams including but not limited to coker flue gas vapor recovery gases casing PSA off gas and process vent gases These gases may be destroyed in an incinerator or thermal destruction device or combusted as a supplemental fuel in heaters boilers etc If you use a CO boiler to dispose of hazardous waste these emissions should be reported here You should report the resultant CO emissions using the method in section 95113 d 3 if these emissions are not reported elsewhere such as part of your flaring or stationary combustion emissions In this case you will need to analyze these gas streams on a quarterly basis determining both carbon content and molecular weight You will also need to determine the volume of each gas stream with an accuracy of at least 7 5 percent You should choose analytical methods that provide an accurate measurement of the carbon content of these gas streams Your choice of analytical methods should be based on the characteristics of the individual gas streams and may be different for different gas streams CO emissions should be calculated for all gas streams destroyed Table 10 6 2 Emissions from other Control Devices Required Data Units Value Data Source GV volume of gas A scf year operator determined destroyed CC carbon content of gas A kg C kg fuel annual average
22. ed periodically not specify an analytical during the working lifetime of the catalyst methodology or measurement frequency Again staff recommends that you choose an appropriate method and sampling frequency to ensure that you accurately characterize emissions from this source The required variables and equation are found immediately below regenerated catalyst As is the 10 10 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Table 10 4 1 2a Periodic Catalyst Regeneration CO Process Emissions Required Data Units Value Data Source n number of days of unitless operator determined operation CRR mass of catalyst kg regeneration cycle operator determined regenerated CF spent Weight fraction carbon on spent catalyst unitless operator determined CF regen Weight fraction carbon on regenerated catalyst unitless default 0 operator determined Conversion factor carbon to 3 664 supplied carbon dioxide Conversion factor kg to 0 001 supplied metric tonnes n CO X CRR CF pen CFregen 3 664 0 001 1 b Reporting Continuous Catalyst Regeneration Process Emissions If you regenerate catalyst continually in an operation other than an FCCU you should use the method found in section 95113 b 2 B As is the case with periodic catalyst regeneration discussed above you need to determine carb
23. fornia Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 HHV range of the natural gas or associated gas you combusted during the month in question 4 If the HHV of your fuel is either less than 975 Btu scf or greater than 1100 Btu scf either you or your fuel supplier must determine fuel carbon content a minimum of once per month CO emissions are then calculated using the formula found in section 95125 d 3 10 1 4 Calculating CO combustion emissions from Fuel Mixtures section 95125 f There are two critical requirements that must be met to ensure valid emissions estimation whenever two or more fuels are mixed prior to combustion First the amount of each fuel combusted must be determined accurately Secondly the fuel combusted must be adequately characterized Thus you must determine the appropriate fuel characteristics HHV and or carbon content of either the fuel mixture or every individual fuel contained in the mixture The operator may choose to use a CEMS to determine fuel mixture CO emissions in which case fuel characterization is not required The operator will still need to measure consumption for each fuel however If the operator mixes refinery fuel gas with natural gas or another fuel prior to combustion the resulting fuel mixture is subject to the more stringent refinery fuel gas requirements concerning sampling frequency and emissions determination In this case section 9512
24. g cause changes in internal liquid and vapor volumes Ambient winds can also cause tank breathing emissions as they pass the tank exterior Flashing losses occur when liquid introduced into a tank changes pressure and volatiles contained in the liquid flash off Fugitive tank emissions will be determined using the U S EPA TANKS model This model calculates working and breathing VOC emissions Model generated VOC outputs will converted to methane emissions using a default conversion factor of 0 6 CH 0 6 VOC Alternatively you may use the results of storage tank headspace analysis to 1 Note that this program was developed by the American Petroleum Institute API API retains the copyright and has granted permission for the nonexclusive noncommercial distribution of this material to governmental and regulatory agencies TANKS is available for public use but cannot be sold without written permission from API the U S EPA Midwest Research Institute and The Pechan Avanti Group 10 17 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 determine a tank specific conversion factor but it is suggested that you consult ARB staff prior to using this option The TANKS model is used to calculate VOC emissions from above ground storage tanks containing crude oil asphalt naphtha and distillate oils If any of these storage tanks are equipped with vapor recovery tec
25. gas service components This includes all components carrying natural gas refinery fuel gas and low Btu gases All components should be identified as one the following six classification types value pump seal connector flange open ended pipe and other For guidance you should consult and use the Component Identification and Counting Methodology found in the following CAPCOA 1999 document California Implementation Guidelines for Estimating Mass Emissions of Fugitive Hydrocarbon Leaks at Petroleum Facilities CAPCOA and CARB 1999 www arb ca gov fugitive fugitive htm 10 26 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 All gas service components should be screened using a monitoring instrument capable of detecting methane Screenings should be conducted at the frequency interval required by your local air district Specific screening procedures and instrument calibration requirements can be found in EPA Reference Method 21 published in 40 CFR 60 Appendix A EPA Method 21 www epa gov ttn emc promgate m 21 pdf First identify and screen your gas service components Component screening values will be used to calculate methane emissions The CAPCOA document referenced above provides several methods by which VOC emissions may be calculated using component screening values You will use Method 3 the Correlation Equation Method with modifications as required by the
26. hnology vapors are actively collected and emissions are accounted for elsewhere e g flare GHG or refinery fuel gas system reporting to avoid double counting you should not report them here There are several steps required to generate an emission report for your storage tanks Install TANKS on a suitable computer Set up a chemical database for crude oil asphalt naphtha and distillate components Establish your storage tank database Generate emissions reports for each storage tank Sum storage tank VOC emissions Convert VOC emissions to methane emissions using the default factor 0 6 N oO or BR W 10 5 3 1 Installing TANKS TANKS is a window based program available at no cost from the US EPA at the following location The model can be downloaded from www epa gov ttn chief software tanks index html Consult the system requirements link to ensure that the computer on which you plan to install TANKS meets the minimum requirements operating system RAM hard disk space A user s manual is available at the following web page User s manual www epa gov ttn chief software tanks tanks409b tank4man pdf While the user manual is 1999 vintage it remains a very useful document A list of Frequent Asked Questions FAQ can be found here FAQ www epa gov ttn chief faq tanksfaq html 1 Another EPA document you may find very helpful is the September 2006 report entitled Emission Factor Documentation for AP 42 Section 7 1
27. ions Required Data Units Value Data Source n number of days of unitless Operator determined operation CR daily average coke burn kg day operator measured rate CF carbon fraction in coke unitless operator determined burned conversion factor carbon to 3 664 supplied carbon dioxide Conversion factor kg to metric 0 001 supplied tonnes 10 4 1 2 Calculating Other Catalyst Regeneration Process Emissions section 95113 b 2 Methods for GHG emissions determination for alternate catalyst regeneration processes are presented in section 95113 b 2 of the regulation and summarized below a Periodic Catalyst Regeneration Process Emissions If you regenerate catalyst periodically you should refer to the methodology found in section 95113 b 2 A You will determine CO emissions occurring during each regeneration cycle and sum to calculate annual emissions In this case you will need to know the mass of catalyst regenerated during each regeneration cycle You will also need to determine the weight fraction of carbon on The regulation allows you to use a default both the spent catalyst prior to value of zero for the weight fraction of regeneration and on the carbon on your regenerated catalyst Keep in mind that using this default value may result in an overestimation of your CO case with FCCU catalyst ee dth ff ds th tion the regulation does emissions and thus sta recommen s that reSenerTa this variable be measur
28. n 95125 c If the HHV of the mixture is above or below this range you must measure the carbon content of the mixture monthly and use the formula in section 95125 d 3 to calculate CO2 emissions 10 6 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 1 6 2 Destruction of low Btu gas in a flare or other destruction device section 95113 d The operator should choose the appropriate emissions calculation method based on the disposition of the low gas stream Choose the applicable option below a Your Low Btu gas is sent to a flare or flares and you report these flare emissions to your local AQMD APCD In this case refer to section 95113 d 2 Choose the method you use based on your Air District reporting requirements For a more detailed discussion see the Flare Control Device section 95113 d discussion below b Your Low Btu gas is destroyed in a destruction device such as a thermal oxidizer and emissions are not reported to the local AQMD APCD In this case refer to section 95113 d 3 You must determine carbon content and molecular weight of the low Btu gas quarterly and compute an annual average You must also determine the volume of low Btu gas destroyed annually 7 5 percent and use the equation in section 95113 d 3 to calculate annual CO combustion emissions 10 1 7 Calculating Stationary Combustion CH and N20 emissions section 95125 b CH
29. n at the bottom left of this database to display a blank Chemical Database sheet Fill in this sheet as shown below 10 20 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Chemical Name X CAS Number 8052 42 4 X Category Petroleum Distillates Liq Mol Weight 1000 Liquid Density Ib gal 60F 3 0925 Vapor Molecular Weight 105 Vapor Pressure Information fill in one or more options completely Option 1 Enter Vapor Pressure psia for each temperature 40F 0 80F 0 0 50F 0 90F 60F 0 100F 0 TOF 0 Option 2 Constants for Antoine s Equation using C E amp 2xX CT VET 7 Option 3 Constants for Antoine s Equation using K A 75350 06 B 9 00346 Option 4 Reid Vapor Pressure psia Distillates Crude Oil 0 ASTM Slope Distillates Only 0 Add New Delete Save Close Help When you have entered all the data for the Asphalt Chemical Database Save this file You are now ready to establish your storage tank data base 10 5 3 3 Establishing your storage tank data base The next step in working with TANKS is to enter descriptive information concerning the storage tank or tanks for which you will be modeling VOC emissions If you are creating a new tank file make sure that the Create New Tank Record button is selected highlight the type of tank and click the OK button Make sure that yo
30. ndition Breather Vent Settings Vacuum Setting psig 0 03 Pressure Setting psig 0 03 Copy Run Report Save Internal Floating Roof Tank Identification i Physical Characteristics Site Selection Tank Contents Monthly Calculations Physical Characteristics 1 Tank Characteristics Rim Seal System o Primary Seal 0 00 Secondary Seal z 0 00 Net Throughput gal yr 0 00 Deck Characteristics 7 Deck Type 0 Deck Fitting Category 7 Effective Column Diameter 0 v Internal Shell Condtion v External Shell Color Shade v External Shell Condition Diameter ft Tank Volume gal Turnovers per year Self Supporting Roof Humber of Columns Roof Color Shade Roof Paint Condition Copy Run Report Save 10 23 Refineries California Air Resources Board External Floating Roof Tank Identification Physical Characteristics Tank Characteristics Roof Characteristics Diameter ft 0 Roof Type x Tank Volume gal 0 00 Roof Fitting Category z Turnovers per year 0 00 Net Throughput galiyr f 0 00 Tank Construction and Rim Seal System aa i Ef Paint Color Shade idaidand asad Paint Condition ee View Add Fittings Close Help Domed External Floating Roof Tank Identification i Site Selection Tank Contents Monthly Calculations Physical Characteristics Tank Characteristic
31. neration and cogeneration sectors to requirements and is described in Chapter caleulate GHG emission frorn these 8 of this document while section 95112 sources See Chapters 8 and 9 provides the cogeneration system requirements and is covered in Chapter 9 Refer to those sections of the regulation and the associated guidance chapters for more information If your electricity generating activities are not large enough to trigger these additional reporting requirements include these emissions in your facility GHG report as additional stationary sources with emissions calculated specific to fuel type like your other sources The regulation also includes definitions for cogeneration facility cogeneration system generating facility generating unit and electricity generating facility which may be helpful in evaluating whether these types of activities or units are at the facility 10 8 Reporting Indirect Energy Usage If you purchase and consume electricity from a retail provider or a facility that you do not own or operate you need to report the amount of electricity usage and identify the provider Similarly if you purchase and consume steam heat and or cooling from a facility you do not own or operate you need to report this thermal energy use and identify the provider The methodologies are found in Chapter 13 10 32 Refineries
32. ng a matrix that looks something like the one below The fuels you combust may be different than those shown in the Table below of course Table 10 1 Stationary Combustion GHG Emissions Fuel co CH N2O Refinery fuel gas Natural Gas Associated Gas Diesel Fuel Residual Fuel Propane CNG Gasoline Kerosene Naphtha CEMS fuel mixtures n a n a The purpose of this chapter is to provide guidance on the requirements of section 95113 of the mandatory GHG reporting regulation As described more specifically in Chapter 1 of this document this guidance does not add to substitute for or amend the regulatory requirements as written in these or other sections of the regulation Subchapter 10 Article 2 sections 95100 to 95133 title 17 California Code of Regulations 10 1 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 1 1 Reporting Stationary Combustion CO emissions Using CEMS In most cases CO emissions from stationary combustion will be calculated using methods that are based on the type of fuel combusted The one exception is when a Continuous Emission Monitoring System CEMS is used to measure CO emissions CEMS may be used to measure and report stationary combustion emissions from single or multiple combustion sources New CEMS must be installed and operated according to the requireme
33. nia Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Choose Tank s For Report Asphalt Tank Big Asphalt Test Tank 1 FakeTank 1 Select All gt gt FakeTank 2 _ Select al gt Heated HT 1 Heated VFRT 1 lt Remove lt lt Remove All Asphalt Test Tank 1 FakeTank 2 Heated VFRT 1 ID Asphalt Test Tank 1 City Bakersfield State California Company Fake Oil Tank Type Vertical Fixed Roof Tank Run Report Close Help When you have chosen all the storage tanks for which you want to generate emissions reports click Run Report The output of the report is then used to calculate methane emissions Use the Total VOC emissions TANKS output expressed in lbs VOC to calculate methane emissions Multiply this number by either the default conversion factor of 0 6 or the tank specific conversion factor derived from tank headspace analysis to calculate annual methane emissions Finally convert from pounds of methane to metric tonnes methane and report this value You should frequently back up your TANKS data bases to ensure that all your data entry work is protected from unforeseen computer problems such as a hard disk failure 10 5 4 Reporting Equipment Fugitive Emission Methane Equipment fugitive methane emissions methods are based upon your local AQMD APCD Leak Detection and Repair LDAR procedures You will need to extend your LDAR monitoring to all
34. nts of 40 CFR Part 75 except that the ARB regulation does not trigger a reporting requirement to the U S EPA CQ concentrations rather than O2 and flue gas flow measurements should be used to determine hourly CO mass emissions for any new CEMS system per section 95125 g 7 Operators must also measure and report fuel consumption that results in GHG emissions When you use a CEMS to determine GHG emissions resulting from the combustion of a fossil fuel mixture it will not be possible to separately report CO emissions for each fuel contained in the mixture The CEMS data are instead used to report CO emissions from combustion of the mixture See the guidance for section 95125 g found in section 13 7 of this document for additional direction on CEMS 10 1 2 Options for Calculating and Reporting Refinery Fuel Gas CO Combustion Emissions For most California refineries refinery fuel gas RFG represents a significant fraction of the fuel that is combusted during refining processes There also may be significant compositional variation among multiple fuel gas systems within a refinery It is essential that fuel characteristics affecting GHG emissions be accurately determined The reporting regulation is designed to provide high resolution data to quantify CO emission from this very important source Several quantification approaches are available to provide operators with flexibility in exactly how to quantify refinery fuel gas emissions
35. of quarterly determinations operator determined MW molecular weight of gas A kg kg mole annual average of quarterly determinations operator determined MVC molar volume choose MVC for 20 C or 60 F supplied conversion CF carbon to carbon dioxide 3 664 supplied CF kg to metric tonnes 0 001 supplied CO GV CC MW 1 MVC 3 664 0 001 10 31 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 7 Reporting Requirements for Electricity Generation and Cogeneration If electricity generation or cogeneration occurs at your facility within the same contiguous boundary and under your operational control emissions from these activities must be included in your emissions data report If the electricity generating or cogeneration facility has a nameplate generating capacity of 1 MW or more and its CO emissions from electricity generating activities trigger the separate reporting Do you have electricity generation or a threshold of 2 500 metric tonnes the cogeneration system on site report must comply with the requirements of regulation sections If your system is at least 1 MW and 95111 and 95112 as applicable emitted at least 2 500 MT CO from electricity generation refer to the Regulation section 95111 includes the 8 methods provided for the electricity electricity generating facility reporting i f ge
36. on fraction on both spent and regenerated catalyst Choose an appropriate sampling location analytical methodology and sampling frequency You will also need to determine the average catalyst regeneration rate and the time the regenerator was operational These variables shown in the Table below are entered into the equation found in section 95113 b 2 B to calculate annual CO emissions Table 10 4 1 2b Continuous Catalyst Regeneration CO Process Emissions Required Data Units Value Data Source CCirc average catalyst tonnes hr Operator determined regeneration rate CF spent Weight fraction unitless operator determined carbon on spent catalyst CF regen Weight fraction carbon on regenerated catalyst unitless default 0 operator determined H hours regenerator hours year operator determined operated annually Conversion factor carbon to 3 664 supplied carbon dioxide CO CC CF cent CFregen H 3 664 10 11 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 4 2 Calculating Process Vent Emissions If facility equipment continuously or periodically discharges a gas stream to the atmosphere directly or after being routed to a control device and you do not report these process vent emissions elsewhere in your GHG report e g flare or other control device emissions refinery fuel gas combustion etc
37. operator determined where SV gt 9 999 ppmv PFip 10 VOC emission factor kg VOC hour column four Table 14 for component type i pegged regulation Appendix A over 9 999 ppmv t time since last screening hours operator determined 6 E Vocp 10 XCC PF p0 t i t If your local air district has set a screening value limit of 99 999 ppmv for the use of correlation equations SV gt 99 999 ppmv is considered pegged you will use the equation found in section 95113 c 4 A d to calculate VOC emissions Table 10 5 4d Fugitive Equipment VOC Emissions Pegged Components SV gt 99 999 ppmv Required Data Units Value Data Source CC number of i components number operator determined where SV gt 99 999 ppmv PFip 100 VOC emission factor kg VOC hour column five Table 14 for component type i pegged regulation Appendix A over 99 999 ppmv t time since last screening hours operator determined 10 28 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 6 E Vocr 100 gt CC PFip joo t After you have calculated VOC emissions for all your zero components leaking components and pegged components sum the three to obtain your fugitive equipment VOC emissions The sum total of VOC emissions is then multiplied by CF a VOC to CH conversion factor and a kg to metric tonnes conversion factor 0 001 to calculate total methane emi
38. procedures that your local AQMD APCD has put in place You will calculate VOC emissions for three categories of components based on the component screening value 1 Zero components where the screening value corrected for background is indistinguishable from zero 2 Leaking components components with screening values greater than zero but less than the screening value limit above which the local AQMD APCD does not allow the use of correlation equations for the calculation of VOC emissions This upper bound screening value is either 9 999 ppmv or 99 999 ppmv 3 Pegged components with SVs above the upper SV correlation equation limit Each of these three calculation methods is discussed in more detail below For each of the six Component Types you will find a Default Zero Factor ZFi9 in kg hr in Table 14 of regulation Appendix A VOC emissions for all zero components are then calculated and summed using the equation found in section 95113 c 4 A 3 a Table 10 5 4a Fugitive Equipment VOC Emissions Zero Components Required Data Units Value Data Source CC number of i components number operator determined where SV 0 ZFio zero VOC emission kg VOC hour column two Table 14 factor for component i regulation Appendix A t time from last screening time hours Operator determined i component type where 1 valve 2 pump seal 3 others 4 connector 5 flange and 6 open ended line 6 Evoc o
39. r refinery GHG emissions you will want to ensure that the methodology you use to determine your spent and regenerated catalyst carbon fraction is accurate ARB staff recommends that you also examine the temporal variability of carbon fraction and choose an analysis frequency that is appropriate Some of the issues you should consider at what rate does the carbon fraction on spent and regenerated catalyst change are the changes linear are there periodic operational changes e g addition of new catalyst that may result in step changes in carbon fraction values what changes in operating conditions should trigger carbon fraction determination It is recommended that you develop a sound methodology and retain all data and experimental procedure documentation Some up front sampling and or data analysis will ensure that your FCCU CO emissions are reported accurately minimize lab and personnel costs and facilitate verification Material balance based determinations of these variables may be appropriate but this approach should be well documented and supported Calculate CO emissions from your FCCU using the equation found in section 95113 b 1 C and shown below See Table 10 4 1 1 for a description of the required variables CO CR CF 3 664 0 001 1 10 9 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Table 10 4 1 1 FCCU CO Process Emiss
40. ring the treatment of refinery wastewater Microbial production of methane occurs under anoxic conditions and a small fraction of nitrous oxide an intermediate product in the nitrification denitrification cycle is emitted to the atmosphere 10 14 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 5 1 1 Wastewater Methane Emissions Before you sample your wastewater streams the operator should consult Table 12 in Appendix A of the regulation Based on the specifics of wastewater treatment and discharge at your facility first two columns of Table 12 you will need to select a methane correction factor MCF which is simply the fraction of waste that is treated anaerobically at the facility in question The Table contains default MCF values both for untreated discharge and six general aerobic and anaerobic treatment situations Note that methane recovery for anaerobic treatment is not considered here Therefore if have an enclosed anaerobic treatment facility where methane is captured and not emitted to the atmosphere you would not be required to report methane emissions here There are only two characterization categories provided for aerobic treatment facilities a well managed system where small amounts of methane may be emitted and an overloaded and not well managed system A range of MCF values is listed for these two treatment conditions 0 0 4 If you choose to
41. s Roof Characteristics Diameter ft 0 Roof Type 7 Tank Volume gal 0 00 Roof Fitting Category 7 Turnovers per year 0 00 Het Throughput galiyr 0 00 Tank Construction and Rim Seal System Internal Shell Condition o Tank Comer Do Paint Color Shade o Y Og Ermar om Paint Condition o CU Rey SREE View Add Fittings Copy Run Report Save Close Help Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Section 4 0 of the User s Guide Entering Tank Data steps through the data entry process for each of the tank types Note that in the case of a VFRT where the tank is heated when you enter data on the Tank Contents tab you are required to enter the Average Maximum and Minimum Liquid Surface Temperature and the Bulk Liquid Temperature 10 24 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Site Selection Tab Use the pull down menu on the Nearest Major City Tab to choose the location most appropriate for your storage tank Note that major metropolitan areas such as San Francisco and Los Angeles list two locations suffixed with AP airport or C O City of Tank Contents Tab Use this Tab to designate the contents of each of the storage tanks Use the following selection to set up storage tank contents files for storage tanks containing crude oil distillate asphalt and naphtha Table 10 5
42. s from each RFG system 10 1 2 3 System specific CO emission factor section 95125 e This third approach requires you to use an on line high heat value HHV analyzer HHV data and a daily carbon content determination are used to derive a daily refinery fuel system specific CO emission factor This emission factor is then used with a daily average RFG system HHV value from the on line analyzer to calculate CO emissions 1 Calculate a RFG system specific daily emissions factor You need to determine the carbon content and HHV for the RFG system in order to calculate a CO emission factor To do this once per day determine the carbon content kg C kg fuel molecular weight kg fuel kg mole and the HHV Btu scf of the RFG system Carbon content and fuel molecular weight are measured by drawing a representative RFG sample and performing a carbon analysis Carbon content and molecular weight may also be determined using an on line instrument High heating value is determined either using data from the carbon analysis or from an on line HHV analyzer When using data from an on line HHV analyzer the operator uses either the hourly average HHV value coinciding with the hour in which the carbon content determination is made or the hour in which the sample was collected for analysis A daily emission factor metric tonnes 10 3 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December
43. s may be owned and operated by the refinery or by another entity contracted to provide hydrogen for the refinery Reporting responsibility rests on the entity with operational control of the hydrogen plant as discussed in Chapter 2 10 4 Refinery Process Emissions At most refineries the major source of process emissions of GHGs is catalyst regeneration Process emissions also are generated from process vents asphalt blowing and sulfur recovery Using CEMS Just as the processes that generate GHGs in a refinery differ methods to calculate GHG emissions are process specific However use of a CO CEMS to measure process GHG emissions is an option As is the case with CEMS used with stationary combustion emissions process CEMS must be installed and operated according to requirements found in 40 CFR Part 75 This does not mean you are required to report CEMS CO emissions to U S EPA 10 4 1 Calculating CO Emissions from Catalyst Regeneration Refinery catalyst may be regenerated in a number of different manners The operator should choose the most appropriate method in section 95113 b 1 and 2 described below based on the manner in which catalyst is regenerated Table 10 2 summarizes the needed information 10 8 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 10 4 1 1 Reporting Fluid Catalytic Cracking Unit FCCU process CO emissions section 95113 b 1
44. specified by your local air district Table 10 6 1b Flaring Emissions CO and CH using ROG Required Data Units Value Data Source CFrog ROG carbon fraction unitless CFraog 0 6 supplied ROG flare ROG emissions kg day operator determined as per air district reporting requirements FE flare destruction percent specified by local air district efficiency CF kg to metric tonnes 0 001 supplied CF carbon to carbon dioxide 3 664 supplied 365 CO gt CFaog ROG FE 100 FE 3 664 0 001 1 Finally if you are not currently required to report flaring emissions to your local air district you will use a simplified calculation method based on refinery feed through put The only variable you will need to supply is refinery through put in m year 10 30 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 Table 10 6 1c Flaring Emissions CO using refinery through put Required Data Units Value Data Source RFT refinery through put m year operator determined EFymuc NMHC emission factor 0 002 kg NMHC m supplied CFymuc NMHC to carbon unitless 0 6 supplied conversion factor CF carbon to CO 3 664 supplied CF kg to metric tonnes 0 001 supplied CO RFT EF unio CFyic 3 664 0 001 10 6 2 Reporting Emissions from Destruction Devices Other than Flares This last s
45. sphalt products will need to establish a Chemical Database for this petrochemical To establish a chemical database for asphalt storage tanks Run TANKS You will first see a screen containing the USEPA Emissions Factor and Inventory Group logo click in this box or wait approximately five seconds and the screen will advance and display the TANKS Model Notice Box describing the model origin and distribution restrictions Click OK to advance to the following screen 10 19 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 File Data Report Backup Help eee HERT VERT IFRT EFRT DEFRT _Edit Welcome to TANKS 4 0 9d Horizontal Tank Vertical Fixed Roof Tank Internal Floating Roof Tank External Floating Roof Tank Asphalt Tank Big Asphalt Test Tank 1 FakeTank 1 FakeTank 2 Heated HT 1 Close the Welcome screen by clicking the cancel option Next click the Data button on the top menu bar choose Chemical from the drop down menu and then move the cursor to the right to select Edit Database See the panel below S TANKS 4 0 9d File ES Report Backup Help D Tanks gt D ey Wass Chemical P Edit Database Meteorological gt Import Fittings Export Print Rim Seals b Deck Seams gt Speciation Profiles gt 4 03 Update TANKS will display an established Chemical Database sheet acetaldehyde Click the Add New butto
46. ssion factors for gravity DAF and IAF oil water separators when they are either covered or uncovered and not connected to a destruction device In these cases you will report methane emissions using the method in this section You need to know the volume of water annually treated by the separator The volume of treated water is used along with the appropriate oil water separator EF from Table 13 to calculate methane emissions A conversion factor of 0 6 is used to convert from nonmethane hydrocarbons to methane Table 10 5 2 Fugitive Emissions from Oil water Separators Methane Required Data Units Value Data Source EF sep NMHC emission factor kg NMHC m operator determined from Table 13 regulation Appendix A Vwater Volume of water m year operator measured treated annually CF mc NMHC to CH unit less 0 6 supplied conversion factor Conversion factor kg to 0 001 supplied metric tonnes CH EF cop Vwater CFynic 0 001 water 10 5 3 Reporting Storage Tanks Fugitive Emissions There are three types of emissions from hydrocarbon storage tanks working losses breathing losses and flashing losses Working losses occur as a result of the filling and emptying processes Internal headspace gas is expelled and external air is pulled into a storage tank as product enters and exits the tank Breathing losses as a result of changes in environmental parameters such as solar and thermal heating and coolin
47. ssions CH JE osa E vocac eer OF E Vocp 100 J Criss 0 001 1 In most cases you should be able to determine a system specific VOC to methane conversion factor CF based on determinations of gas composition and methane content from fuel analysis In cases where fuel analysis data is available use the mass CH mass fuel ratio to calculate a system specific CF In cases where representative data is not available you should use a default CF value of 0 6 10 6 Reporting Emissions from Flares and Other Control Devices section 95113 d Regulatory methods for the calculation of flaring emissions are based on the reporting requirements of your local air district You should make sure that stationary combustion emissions of CO2 CH4 and N20 are reported for all flare pilot and purge gas consumed in the flaring process Consult the previous discussion of stationary combustion emissions for details 10 6 1 Reporting Flare Emissions Next based on local air district reporting requirements the operator will report emissions resulting from the flaring of hydrocarbons routed to your flares If you are required to report flaring CH and NMHC emissions to your local air district e g BAAQMD Regulation 12 Rule 11 you will report CO and CH flaring emissions as shown in section 95113 d 2 First calculate CO emissions resulting from the combustion of both NMHC species and methane contained in hydrocarbon streams routed to flares for
48. tal nitrogen in wastewater This documentation can be found at the following link www epa gov waterscience methods Table 10 5 1 2 Fugitive Emissions from Wastewater Treatment Nitrous Oxide Required Data Units Value Data Source Q Volume of wastewater treated m yr operator measured N in effluent kg N m annual operator measured quarterly average N20 emission factor 0 005 kg N O N kg N supplied CF kg N20 N to kg N20 1 571 supplied CF kg to metric tonnes 0 001 supplied NO Q Noave EF yoo 1 571 0 001 10 5 2 Reporting Oil Water Separator Fugitive Emissions Fugitive methane emissions from oil water separators must also be calculated if you have these devices at your facility and emissions are not diverted to a destruction device You should first consult Table 13 in regulation Appendix A Here you will see that for three types of oil water separators gravity dissolved air flotation DAF and induced air flotation IAF the methane emission factor is zero when these devices are 10 16 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 connected to a functioning destruction device If this is the case at your facility you are not required to report GHG emissions here The destruction of low Btu gases such as those recovered from an oil water separator are covered in section 95113 d 3 Table 13 does provide methane emi
49. u have selected the correct tank type from the five tank type options list Horizontal Fixed Roof Tank HFRT Vertical Fixed Roof Tank VFRT Internal Floating Roof Tank IFRT External Floating Roof Tank EFRT Domed External Floating Roof Tank DEFRT 10 21 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 You will then see the following window Vertical Fixed Roof Tank Identification Physical Characteristics Site Selection Tank Contents Monthly Calculations Identification Ho Description State City Company Optional Copy Run Report Save Close Help Across the top of this screen you will see five tabs Identification Physical Characteristics Site Selection Tank Contents and Monthly Calculations Step through the first three tabs to determine what information you will need to enter These first three tabs and data requirements for each are discussed briefly below Consult the User s Guide for a more detailed discussion Identification Tab The Identification Tab is the same for all types of storage tanks Identification Tab enter data for each of the five fields on this page Identification No give each tank a unique ID name This will be the name that TANKS assigns to this Tank Record Thus it must be unique and you should maintain a master list to aid in identification when you edit each tank profile and generate
50. upplied Ey gt VR F MW MVC VT 0 001 1 10 4 3 Calculating Asphalt Production Emissions If you conduct asphalt blowing operations at your facility you are required to report CO and CH emissions that result from control measures The assumption is that emissions from asphalt blowing operations are directed to a destruction device such as a flare or incinerator for control It is important not to double count these emissions If asphalt plant blowing emissions are sent to a flare and you report emissions from this flare to your local AQMD APCD you will report GHG emissions using the methodology in regulation section 95113 d as discussed in section 10 6 1 of this chapter They would not be calculated using the following methodology 10 12 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 If you control asphalt blowing emissions using a destruction device such as an incinerator you should use the methodology found in section 95113 b 4 You will calculate CH emissions resulting from the incomplete combustion of asphalt blowing emissions as well as combustion destruction related CO2 emissions In both cases you need to know the mass of asphalt blown 10 bbl year annually To calculate CH emissions from the mass of asphalt blown annually an emission factor volume of methane released per thousand barrels of blown asphalt of 2 555 scf CH4 10 bbl and
51. you must report CO2 CH and N20 emissions from process vents It is important to avoid double counting of process vent emissions Additionally if you transfer a process vent stream to a third party facility for processing the responsibility for reporting resulting emissions is also transferred to that third party facility To quantify process vent emissions you need to measure the vent release rate and duration of venting to determine the volume of gas emitted You must also measure the molar fraction of each GHG CO CH4 and N20 in the vent gas stream Especially in the case of hydrogen plant process vent emissions measurement of flow rate and gas composition is difficult at best ARB staff recommends that you consult AQMD APCD regulations for additional guidance For example South Coast Air Quality Management District Rule 1189 Emissions from Hydrogen Plant Process Vents provides valuable direction for sampling and analyzing these process vent streams Table 10 4 2 Process Vent Emissions CO CH and N O Required Data Units Value Data Source VR vent rate scf unit time operator measured Fx molar fraction of X in vent gas stream X CO CH or N20 MW molecular weight of X kg kg mole supplied MVC molar volume choose MVC for 20 C or 60 F supplied conversion VT time duration of venting time operator determined n number of ventings number operator determined CF kg to metric tonnes 0 001 s
52. your emissions report Description enter a brief description of each tank This will provide you with additional information to aid in tank identification State select California from the pull down menu accessed by clicking on the down arrow City select the nearest city to the location of the tank Note that for both Los Angeles and San Francisco there are two choices denoted by the suffixes AP and C O AP is airport and C O is City Of 10 22 Refineries California Air Resources Board Instructional Guidance for Mandatory GHG Emissions Reporting December 2008 If you wish to review or edit an existing storage tank record select Open an Existing Tank Record highlighting the tank record you wish to edit and clicking OK Physical Characteristics Tab The data you will enter differs depending upon the type of storage tank record that you are establishing Below are screen shots for the Physical Characteristics data requirements for each of the five tank types Vertical Fixed Roof Tank Identificatio Site Selection Tank Contents Monthly Calculations Roof Characteristics Color Shade Condition a Maximum Liquid Height ft Type Dimensions Shell Height ft Shell Diameter ft Average Liquid Height ft Height ft 0 00 0 00 Het Throughput gal yr 0 00 Is Tank Heated Ho X Working Volume gal Turnovers per Year Shell Characteristics Shell Color Shade Shell Co

10_PetroRefine

Contents

Download Pdf Manuals

Related Search

Related Contents