Texas Commission on Environmental Quality Flare Task Force Stakeholder Group Member List
Mark Allen BASF Eddie Alrayes Trinity Jed Anderson Attorney Lindley Anderson TCEQ Matt Baker TCEQ James Barron RMT Inc Charles Bates Enbridge Manuel Bautista TCEQ Ellen Belk EPA Region 6 Judy Bigon ExxonMobil Doug Boutros Lubrizol David Bower TCEQ David Brymer TCEQ Kevin Cauble TCEQ Cynthia Causey Solutia Inc. Andrea B. Cavalier Du Pont, La Porte Plant Miranda Cheathem Waid Environmental Brian Christian TCEQ Laura Clark TCEQ Bharat Contractor Invista Tyrah Cooksey Eagle Rock Energy Zak Covar TCEQ Elena Craft EDF Bruce Davis DuPont Stephen Davis TCEQ Kathleen Decker TCEQ Russell DiRaimo Stark Joe Doby TCEQ Tim Doty TCEQ Robert Ehlers Valero Energy Katie Ellet SI Group Ed Fiesinger Zephyr Enviromental Corp Ashley Forbes TCEQ Jim Franklin John Zink Jason Frederick Total Petrochemicals USA David Furry LSI Chock Ganapathy INEOS David Greer TCEQ Joseph Halverson Trinity Steven R. Hansen Shell Jason Harris TCEQ
LAST UPDATED APRIL 13, 2009 Wesley Heefner EPCO Inc. Minor Hibbs TCEQ Susana Hildebrand TCEQ Chris Horton TCEQ Daniel Hoyt City of Houston Dan Hunter Conoco Phillips Amy Hurd Golden Specialty Teresa Hurley TCEQ Jason Johns DOW Lindsey Jones TCEQ Marvin Jones TCEQ Steven Kilpatrick TCEQ Darin Kinnard DCP Midstream Joe Layden Lyondell Heather Lehrmann Waste Management Kim Lesniak Shell Bob Levy Industry Professionals for Clean Air Stan Lewis Kuraray America David Manis TCEQ Brandt Mannchen Houston Sierra Club Jess McAngus Spirit Env Vince Meiller TCEQ Scott Mgebroff TCEQ John Minter TCEQ Les Montgomery RPS JDC Bob Morris Western Refining James Murray Exxon Mobil Danielle Nesvacil TCEQ Jennifer Nunez DuPont William Obrien Chemetall Foste Corp Emmanuel Oladoyin Seadrift Coke LP Dave Oldaker RMT Inc Karen Olson Zephyr Environmental Corporation Luis Pedraza CP Chem. Theresa Pella TCEQ Leila Pezeshki Lubrizol Tim Prince Prince Environmental Steve Ramsey Environ Lucy Randel Industry Professionals for Clean Air Carol Ransom TCEQ Chuck Rivette Waste Management Ken Rozacky TCEQ Les Rucker Valero Ron Ryan EPCO Jeff Saitas
LAST UPDATED APRIL 13, 2009 David Schanbacher TCEQ Trey Scofield DCP Midstream Keith Sheedy TCEQ Beth Seaton TCEQ David Seifert Goodyear James Smith ERM Johnny Spell DOW Christopher Sterling Bigler LP Salal Tahiri TCEQ Marise Textor Texas Petrochemicals David Thorley Waste Management Roger Tygant Shell Matt VanVleck Harris County Dana Poppa Vermillion TCEQ Ashley K. Wadick TCEQ Don Weaver TCEQ Gwen Weddington Prazair Cynthia Williams TCEQ Linda Williams URS Paulette Wolfson City of Houston Carl Young EPA Region 6
LAST UPDATED APRIL 13, 2009 Flare Task Force Stakeholder Group
March 30 and April 2, 2009
TCEQ Flare Task Force Flare Task Force • March 30 and April 2, 2009 • Page 1 March 30 and April 2, 2009 Overview
• Flare Task Force – Goals, timeline, participation
• Texas Flares – Background information, flare regulations
• Flare Issues Under Evaluation – Flare performance – Flare monitoring – Alternatives to flaring routine emissions
• Informal Comments
• Questions and Discussion
Flare Task Force • March 30 and April 2, 2009 • Page 2 Flare Task Force
Flare Task Force • March 30 and April 2, 2009 • Page 3 Goals
• Comprehensive evaluation of all aspects of flares – How flares factor into state air quality issues with respect to air toxics and ozone – The understanding of flare use and efficiency – The adequacy of state regulation of flares
• Develop staff report with options, considerations, and recommendations – Improving state air quality – Improving our understanding and regulation of flares
• Anticipate submitting the final staff report to the Executive Director in Fall 2009
Flare Task Force • March 30 and April 2, 2009 • Page 4 TCEQ Participants
• Office of the Executive Director – Small Business and Environmental Assistance Division – Special Counsel to the Executive Director • Chief Engineer’s Office – Air Quality Division – Toxicology Division • Office of Permitting and Registration – Air Permits Division • Office of Compliance and Enforcement – Field Operations Division – Monitoring Operations Division – Enforcement Division • Office of Legal Services – Environmental Law Division – Litigation Division
Flare Task Force • March 30 and April 2, 2009 • Page 5 Stakeholder Involvement
• Flare Task Force Stakeholder Group is open participation
• Encourage open dialogue and information sharing
• Informal written comments accepted until May 1, 2009 – Communicate your expertise and unique perspective – Provide scientific data and concrete solutions to problems – Details at the end of the presentation
• Anticipate additional stakeholder meetings this spring/summer
Flare Task Force • March 30 and April 2, 2009 • Page 6 Texas Flares
Flare Task Force • March 30 and April 2, 2009 • Page 7 Number of Flares in Texas
Flares Reported in the 2006 TCEQ Emissions Inventory
Statewide 1132
Houston-Galveston-Brazoria 521
Beaumont-Port Arthur 118
Flare Task Force • March 30 and April 2, 2009 • Page 8 Flare Service Types
Service Type Reported in 2006 HGB BPA TCEQ Emissions Inventory
Routine 110 12
Upset/Maintenance 63 15
Both 280 65
Not Specified 68 26
Flare Task Force • March 30 and April 2, 2009 • Page 9 Flare Task Force • March 30 and April 2, 2009 • Page 10 Flare Task Force • March 30 and April 2, 2009 • Page 11 Flare Task Force • March 30 and April 2, 2009 • Page 12 State Regulations
• 30 TAC Chapter 106 – Permits by Rule – Permit by rule §106.492 for flares – Sources that meet these requirements are authorized by rule
• 30 TAC Chapter 116 – Permits for New/Modified Sources – Requires case-by-case permit review for new/modified flares – Required to meet BACT: compliance with 40 CFR §60.18 – Hydrocarbon destruction and removal efficiency is assumed to be 98% or 99% when the flare meets 40 CFR §60.18 requirements – Pollution control project standard permit
• 30 TAC Chapter 111 – Visible Emissions – Visible emissions from non-emergency process flares limited to no more than 5 minutes in any 2-hour period
Flare Task Force • March 30 and April 2, 2009 • Page 13 State Regulations
• 30 TAC Chapter 115 – Volatile Organic Compounds – Control requirements for VOC emissions in nonattainment and near nonattainment areas – Compliance with 40 CFR §60.18 for flares used to control affected waste gas streams
• 30 TAC Chapter 115, Subchapter H – HRVOC – Control requirements for HRVOC vent gas streams in HGB area – Harris County sources subject to the HECT program – Continuous monitoring of flow rate, net heating value, and gas stream composition – Destruction efficiency is assumed to be 98-99% when the flare meets the requirements in 40 CFR §60.18 – Destruction efficiency is assumed to be 93% when the flare does not meets the requirements in 40 CFR §60.18
Flare Task Force • March 30 and April 2, 2009 • Page 14 Federal Regulations
• 40 CFR §60.18 and §63.11 contain requirements for the operation and monitoring of affected flares
• Rule requirements – Limit visible emissions – Flame present at all times – Maximum flare tip exit velocity – Net heating value content – Operate using good engineering practices
• If flare meets requirements of §60.18 or §63.11 the destruction efficiency is assumed to be 98%
Flare Task Force • March 30 and April 2, 2009 • Page 15 Flare Issues Under Evaluation:
Flare Performance
Flare Task Force • March 30 and April 2, 2009 • Page 16 Summary of Issues Identified
• Examine how flare performance might be impacted by – Meteorology – Flare waste gas stream flow rate – Flare waste gas stream composition – Physical design characteristics and maintenance – Assist flow rates
• Evaluate existing flare combustion efficiency and destruction efficiency estimates used to calculate emissions – Practical and technical basis for determining the destruction and removal efficiency (DRE) estimates – Potential research
Flare Task Force • March 30 and April 2, 2009 • Page 17 Flare Performance Impacts
• Meteorological Conditions – Wind – Ambient temperature – Humidity – Other conditions?
• Potential Performance Impacts – High winds can cause flame separation and result in increased emissions – University of Alberta study found crosswinds greater than 5 miles per hour reduced combustion efficiency (CE) – Meteorological conditions are not accounted for in DRE assumptions
Flare Task Force • March 30 and April 2, 2009 • Page 18 Flare Performance Impacts
• Flare Waste Gas Stream Flow Rate – Flares used for both emergency service and routine waste gas disposal often operate with a high turndown ratio – Turndown ratio is the total design capacity compared to the actual flare waste gas stream flow rate – Survey of HRVOC flares found that flare waste gas flow rates are typically less than 1% of the design capacity – No minimum exit velocity requirements for flare waste gas streams
• Potential Performance Impacts – DRE estimates may not be accurate when the flare is operating with a high turndown ratio
Flare Task Force • March 30 and April 2, 2009 • Page 19 Flare Performance Impacts
• Flare Waste Gas Stream Composition – Flare waste gas stream composition can be highly variable
• Potential Performance Impacts – DRE estimates are based on EPA research that primarily tested waste gas streams containing simple hydrocarbons – DRE estimates may not be accurate for waste gas streams with more complex VOC
Flare Task Force • March 30 and April 2, 2009 • Page 20 Flare Performance Impacts
• Physical Design Characteristics and Maintenance – Flare tip design, maintenance, and replacement schedule – Pilot condition
• Potential Performance Impacts – Damaged flare tip or pilots can reduce DRE – Could the design and maintenance of other flare system components impact performance?
Flare Task Force • March 30 and April 2, 2009 • Page 21 Flare Performance Impacts
• Improper Flare Air- or Steam-Assist Operation – Flares are often designed to minimize visible emissions and noise to comply with applicable regulations – Air- or steam-assist used for smokeless operation – Assist gas to waste gas ratio and assist gas flow rate are not typically monitored
• Potential Performance Impacts – VOC contaminated steam-assist can reduce DRE – Severe over-assist can extinguish the flame – Excess assist gas to waste gas ratios can potentially reduce combustion efficiency due to cooling the combustion zone – One TCEQ study noted ratio of assist gas to waste gas is highly variable, ranging from 2 to more than 50
Flare Task Force • March 30 and April 2, 2009 • Page 22 Flare Performance Impacts
Flare Task Force • March 30 and April 2, 2009 • Page 23 Flare Performance Impacts
Flare Task Force • March 30 and April 2, 2009 • Page 24 Comparison of Flare Performance
Flare Task Force • March 30 and April 2, 2009 • Page 25 Bottom Line
• TexAQS II research indicates VOC concentrations in the HGB area are consistent with higher VOC emissions than reported in the TCEQ Point Source Emissions Inventory
• Small differences between the assumed DRE and the actual DRE can result in big differences between the actual and the reported emissions
• For example – If DRE is 99% then the estimated VOC emissions are 2 tpy – If DRE is 98% then the estimated VOC emissions doubles to 4 tpy – The 1% decrease in DRE results in a 100% increase in emissions
Flare Task Force • March 30 and April 2, 2009 • Page 26 Assessing Flare Efficiency
• DRE estimates are based on EPA studies (1980s) – DRE is assumed to be 98% or 99% if flare meets 40 CFR §60.18
• Recent field studies using Differential Absorption Lidar (DIAL) indicate DRE for flares warrants further evaluation
• Emission measurement problems identified by EPA (1983) include: – Effects of high temperatures and radiant heat on test equipment – Effects of wind and intrinsic turbulence on the flame – Undefined dilution of flare emission plumes with ambient air – Lack of suitable sampling locations
Flare Task Force • March 30 and April 2, 2009 • Page 27 Upcoming TCEQ Research
• Measure flare emissions in a controlled environment – Direct measurement techniques and remote sensing technologies
• Assess flare DRE and CE during various operating conditions – 40 CFR §60.18 specifications – Flare gas flow rate (turndown ratio) – Assist flow rate – Limited hydrocarbon mixtures in waste gas stream – Mechanical condition
• Compare to traditional material balance emissions determinations
• Determine the hydrocarbon species in flare plumes currently visualized by passive IR cameras using remote sensing spectrometer
Flare Task Force • March 30 and April 2, 2009 • Page 28 Remote Sensing Technology
Differential Absorption Lidar (DIAL)
• Can measure emissions remotely
• Vertical scans enable plume mapping and flux calculation Wind vector • Combine integrated concentrations with simple wind field to determine emissions flux
Flare Task Force • March 30 and April 2, 2009 • Page 29 Flare Issues Under Evaluation:
Flare Monitoring
Flare Task Force • March 30 and April 2, 2009 • Page 30 Summary of Issues Identified
• Determine the necessity of monitoring flare operating parameters to ensure flare DRE and CE
• Examine the adequacy of existing monitoring requirements to ensure the proper operation of flares – Flare gas flow rate – Air-assist or steam-assist flow rate – Flare gas composition – Flare gas net heating value – Other monitoring approaches
• Evaluate special considerations associated with monitoring flares used in various types of service
Flare Task Force • March 30 and April 2, 2009 • Page 31 Flare Monitoring
• Monitoring Flare Gas Flow Rate
• Goals – Determine the amount of material being sent to the flare – Maintain exit velocity below the limit in 40 CFR §60.18 – For assisted flares, determine the assist gas to waste gas ratio
• Techniques – Most common monitoring technology – ultrasonic flow meters – Examples of others: pressure differential, optical sensors, etc.
• Frequency – Flow sensors are typically instantaneous but data averaging and recordkeeping is typically done in block periods – What block averaging time is sufficient?
Flare Task Force • March 30 and April 2, 2009 • Page 32 Flare Monitoring
• Monitoring Flare Air- or Steam-Assist Flow Rate
• Goals – Determine assist gas to waste gas ratio – Help ensure better flare performance by maintaining appropriate assist gas to waste gas ratio
• Techniques – Mass flow or volumetric flow necessary to achieve goal – Flow indicators or valve position monitors not adequate
• Frequency – Flow sensors are typically instantaneous – What block averaging time is sufficient?
Flare Task Force • March 30 and April 2, 2009 • Page 33 Flare Monitoring
• Monitoring Flare Gas Composition
• Goals – Determine the composition of waste gas stream sent to the flare
• Techniques – Total VOC analyzer – Online analyzers for speciation (e.g., gas chromatograph)
• Frequency – Total VOC analyzers can operate near instantaneous – Online speciation cycle typically once every 5-7 minutes depending on the level of speciation – What block averaging time is sufficient?
Flare Task Force • March 30 and April 2, 2009 • Page 34 Flare Monitoring
• Monitoring Flare Gas Net Heating Value
• Goal – Maintain the minimum net heating value for proper operation
• Techniques – Online calorimeter – Online speciation to calculate net heating value – Alternative: Continuously maintain assist fuel gas sufficient to maintain minimum net heating value while assuming zero net heating value from waste gas
• Frequency – Some are near instantaneous and some are periodic – What block averaging time is sufficient?
Flare Task Force • March 30 and April 2, 2009 • Page 35 Flare Monitoring
• Options and Considerations
• What other monitoring options or approaches are available to help ensure proper flare operation?
• Considerations for special categories of flares or unique situations – Extreme service
Metal alkyls
Liquid burning flares
Others – Limited use / portable flares – Others
Flare Task Force • March 30 and April 2, 2009 • Page 36 Flare Issues Under Evaluation:
Alternatives to Flaring Routine Emissions
Flare Task Force • March 30 and April 2, 2009 • Page 37 Summary of Issues Identified
• Best Management Practices – Strategies to minimize routine flaring – Implementation options
• Alternative Control Devices – Flare gas recovery systems – Vapor combustors, thermal oxidizers – Staged flares
• Additional Alternatives – Re-evaluate flaring as BACT for routine emissions – Revise the flare PBR – Revise the pollution control standard permit for flares – Revise the Chapter 111 rules for visible emissions
Flare Task Force • March 30 and April 2, 2009 • Page 38 Best Management Practices
• Strategies to Minimize Routine Flaring – Flare minimization plans are required by some California districts – Root cause analysis – Operational or procedural changes – Other BMP to reduce flaring routine emissions?
• Implementation Options – Incentives to encourage the use of BMP – Voluntary measures – Implement strategies similar to those in California – Create other regulatory requirements for BMP – Agreed orders – Other alternative strategies?
Flare Task Force • March 30 and April 2, 2009 • Page 39 Alternative Control Devices
• Flare Gas Recovery Systems – Process gasses are collected, compressed, and reused – Can be added to existing flare systems without compromising the safety
• Advantages – Reduced emissions, including NOx – Reduced purchase gas requirements and/or increased product – Extended flare-tip life – Reduced steam consumption
• Disadvantages – Inability to handle high volumes – Siting constraints – Upfront capital investment
Flare Task Force • March 30 and April 2, 2009 • Page 40 Alternative Control Devices
• Vapor Combustors, Thermal Oxidizers – Enclosed combustion chamber devices
• Advantages – Monitoring and compliance testing – Reliability of destruction efficiency – Reduced emissions – Reduced fuel costs – Less noise, hidden flame, lower radiation
• Disadvantages – Increased NOx emissions – Inability to handle high volumes – Siting constraints – Cost
Flare Task Force • March 30 and April 2, 2009 • Page 41 Alternative Control Devices
• Staged Flare Systems – In staged flare systems or flares in series, one flare handles routine gas volumes and a larger flare handles emergencies
• Advantages – Separates low flows from high flows – Can be added to existing flare systems without compromising the safety function of the flare system
• Disadvantages – Siting constraints – Cost
Flare Task Force • March 30 and April 2, 2009 • Page 42 Additional Alternatives
• Evaluate BACT – Limit the use of flares as Tier 1 BACT for routine emissions – Consider operational parameters during BACT evaluation – Cost of changing existing control devices
• Revise Flare PBR – Limit scope – Improve monitoring requirements – Require flares to meet specific operating parameters (40 CFR §60.18)
• Revise Pollution Control Standard Permit – Limit scope with regard to changes to flares
• Consider Revising Visible Emissions Limits – Do the requirements encourage flare design and/or operation in a way that decreases destruction efficiency?
Flare Task Force • March 30 and April 2, 2009 • Page 43 Informal Comments
Flare Task Force • March 30 and April 2, 2009 • Page 44 Informal Comments
• Requesting informal comments on: – Issues currently identified for evaluation – Additional issues for evaluation – Specific research or control strategy concepts – Data from existing research studies – Technical and economic feasibility – Implementation options
• When submitting comments: – Provide as much detail and technical information as possible – Provide a copy, web link, or citation for any specific documents referenced (e.g., a research study, state rule, etc.) – Explain the economic information on a dollar per ton basis – Clearly identify any confidential information
Flare Task Force • March 30 and April 2, 2009 • Page 45 Informal Comments
• Please submit comments by May 1, 2009
• Electronic comments are preferable, and may be submitted via e-mail to [email protected] – All electronic comments should reference “Flare Task Force Stakeholder Group” in the subject line
• Mail comments to Lindley Anderson, TCEQ Air Quality Division, MC-206, P.O. Box 13087, Austin, TX 78711- 3087
• Fax comments to (512) 239-5687
Flare Task Force • March 30 and April 2, 2009 • Page 46 Questions and Discussion
Flare Task Force • March 30 and April 2, 2009 • Page 47
Buell Consulting Services, LLC 2005 Pembroke Bay Drive League City, TX 77573
Phone: 832.202.4211 Fax: 281.715.4220
May 7, 2009
RE: Flare Task Force Stakeholder Group
Mr. Anderson,
In development of the new SIP rules and the effort to collect additional data related to flare performance, the following information is provided. The comments contained, here in, provide additional details regarding consideration of the use of pressure-assisted flare technology, as well as practical experience utilizing thermal oxidizers.
Pressure-assisted Flares As currently written, 30 TAC 115 Subchapter H, Division 1 allows the use of flares to control subject vent streams; however the flare type is restricted to steam-assisted, air-assisted, or non-assisted flares by referencing the requirements of 40 CFR §60.18(c)(2)-(6) & (d). 40 CFR §60.18 was originally developed around non-assisted, air-assisted, and steam-assisted flare technologies and did not specifically address pressure-assisted flares.
Pressure-assisted flares utilize the waste gas pressure to create a condition where air is drawn into contact with the gas and mixed to achieve smokeless combustion. This results in high exit velocities greater than 400 ft/sec. Pressure-assisted flares operate at sonic exit velocities at the tip, typically Mach 1.0 or greater.
More information about pressure-assisted flares can be found as follows: http://www.epa.gov/ttn/catc/dir1/fflare.pdf http://www.johnzink.com/products/flares/pdfs/flar_hydra.pdf
Pressure-assisted flares can be utilized for both routine process operations and maintenance activities. One of my clients desires to use a pressure-assisted flare to control HRVOC- containing streams under 30 TAC §115.725 (i). The issue is that HRVOC hourly average mass emission rates cannot be accurately calculated per 30 TAC §115.725(g)(2)(E) because the flare tip velocity exceeds the maximum allowable velocity in 40 CFR §60.18. At the lower DRE (93%), HRVOC emissions will be over-reported and the 1200 lb/hr site cap in 30 TAC 115.722 will be exceeded.
The Dow Chemical Company (Dow) also operates facilities in the HGA that utilize the pressure-assisted flare technology. Dow approached TCEQ about the use of these flares to comply with the current HRVOC requirements. In order to review the request, TCEQ required additional data. Dow contracted John Zink to develop a test protocol to demonstrate that the destruction efficiency of pressure-assisted flares is equal to or better than other flare types, even though the exit velocity is higher. The test program was executed at John Zink’s test facility located in Tulsa, Oklahoma.
Page 1 of 3
Dow in conjunction with John Zink presented the attached paper on the results of the pressure-assisted flare emissions testing conducted at the John Zink facility to simulate the Dow application. The testing conducted actually captured the inlet flare gas and the flue gas, so that the DRE could be demonstrated. The testing concluded that combustion stability is a major factor in flare burner performance and pressure-assisted flares have the capability to perform at performance level’s comparable to steam-assisted and air-assisted flares.
Since several facilities in the HGA and BPA could potentially utilize pressure-assisted flares, it would be prudent in development of the new SIP rules and the review of the effectiveness of 40 CFR §60.18 to include language in the state rules to address the use of these flares for compliance. I do not have access to the test results from Dow; however, it was noted in the attached paper that both TCEQ and EPA witnessed the testing and assisted in the development of the test plan and protocol. Presumptively, TCEQ is currently in receipt of this testing.
Thermal Oxidizers When utilizing thermal oxidizers to comply with HRVOC, the compliance demonstration for routine operation falls into 30 TAC §115.725(a), which requires that the thermal oxidizer be tested and an appropriate operating parameter be selected during the testing and subsequently tracked to demonstrate compliance. Vendor data and/or process knowledge is allowed for the estimation of MSS activities and emission events in the use of thermal oxidizers (or other control devices besides flares) under 30 TAC §115.725(a)(3); however, this does not apply to routine operations. There is no option to utilize vendor data or process knowledge for routine operations that are limited in scope, similar to the various compliance options offered for flares in 30 TAC §115.725(e) – (k). Is it possible that options for alternates to testing (rather than monitoring, as was done for flares) could be developed for various limited duration routine operating scenarios (such as limited use < 720 hours/year, marine loading, pipeline maintenance, etc.) for thermal oxidizers and other control devices? What I was hoping could be addressed is adding options for using alternate control devices (like thermal oxidizers or vapor combustors) where costly performance testing would not be required in some limited routine operations and vendor guarantees and engineering calculations could be substituted for the testing. This would provide more compliance flexibility and perhaps entice more industry personnel to employ the use of this alternate control.
When controlled in a flare, VOCs with 3 carbons or less are destroyed by 99%. Conversely, all hydrocarbons controlled in a thermal oxidizer are destroyed by 99.99%. In effect, the thermal oxidizers are 100 times more efficient in removing HRVOC (with less than 3 carbon atoms) than a flare. This comes at price, though, since incinerators (thermal oxidizers) with a maximum rated capacity greater than 40 MMBtu/hr are subject to 30 TAC 117 and the NOx Cap and Trade Program. 30 TAC §117.303(a)(4)(A) specifies that incinerators (thermal oxidizers) with a maximum rated capacity less than 40 MMBtu/hr are exempt from the NOx Cap and Trade Program. Flares, regardless of size, are also currently exempt. The NOx emission factors for flares are between 0.0485 - 0.0680 lb NOx/MMBtu. The vendor guaranteed NOx rate for a thermal oxidizer is typically 0.15 lb NOx/MMBtu. To control a thermal oxidizer with a capacity larger than 40 MMBTU/hr to the 30 TAC 117 limit would require the installation of additional control, typically Selective Catalytic Reduction (SCR), and the introduction of new emission hazards, NH3. To avoid this issue, the thermal oxidizer must be sized below 40 MMBtu/hr; however, this is not sufficient to control the
Page 2 of 3 entire flare load at most operating facilities. Therefore, use of the flare to control both routine and emergency conditions is still necessary. If TCEQ’s objective is to utilize a thermal oxidizer as a primary replacement for flares, this issue needs to be addressed such that the thermal oxidizer can be sized to handle the entire flare load during normal operating conditions (which will most likely be in excess of 40 MMBTU/hr). What is the trade off between lower HRVOC emissions and higher NOx formation? Is it possible that this can somehow be addressed with the current cap and trade programs for NOx and HRVOC such that equivalent HRVOC credits can be utilized to offset increases in NOx emissions?
Additionally, another issue that arises with the use of a thermal oxidizer is testing. Typical NSR boiler plate language for a thermal oxidizer mandates testing to demonstrate 99.99% DRE. The detection limits of the current EPA Reference Methods make this task very difficult. Measuring the flow rate of the inlet using Method 1-4 is not typically an issue nor is measuring the composition of the inlet stream using Method. However, because the thermal oxidizers have such high destruction efficiencies, Method 18 cannot be used to accurately measure the composition of the outlet. When Method 18 is used, many of the components in the outlet stream are well below the detection limits of the respective component. Using the detection limit or even one half the detection limit to calculate the DRE often results in not being able to mathematically prove 99.99%. Instead, Method 18 is limited to verify that the probability of the unit’s DRE is approaching 99.99% (example DRE > 99.78%), but cannot confirm 99.99%. TCEQ should consider altering the standard NSR boiler plate language to allow more flexibility in demonstration of compliance by perhaps allowing a comparable ppm stack outlet concentration comparable to the 99.99% DRE that can be tested utilizing Method 25A. This is similar to the approach allowed in most federal rules and would make compliance demonstration achievable.
I hope that this information will assist you in the development of the new rule language. If you have any questions or concerns, please feel free to contact me at 832-202-4211. I appreciate you providing the opportunity for feedback.
Thank you,
Trisha Froemming, PE
Attachments - John Zink Study - Pressure Assisted Flares.pdf
Page 3 of 3
Attachments
TexasTexas TechnologyTechnology ConferenceConference “Flare“Flare SystemSystem EmissionsEmissions Control”Control”
Combustion Efficiency of Flares
Accepted by EPA for combustion efficiency of 98% plus Federal Regulatory Requirements For Achieving 98% CE Are Defined In 40 CFR 60.18 Summary of 40 CFR 60.18 Requirements
• Proven Constant Flare Pilot • 200 btu/scf Minimum LHV for non- assisted Flares • 300 btu/scf Minimum LHV for Steam or Air Assisted Flares • Exit Velocity Limitation per Formula for Non Startup, Shutdown, or Malfunction Operating Flare Cases Basis of Flare 98% CE
• EPA / CMA Joint Testing Program in 1982 (propylene / nitrogen / ng mixtures) • EPA / EER Testing Program in 1984 to 1986 (h2s / propane / nitrogen mixtures) • EPA / Dupont testing Program in 1997 (hydrogen influence) EPA / CMA Testing Types of Flares Tested
Wind Non-Assisted Pilot Shield Burner
Ignition Inlet
Pilot Gas Inlet Velocity Seal types of Flares Tested
Steam Injector Pilot Burner
Wind Steam Assisted Shield
Ignition Inlet
Center Steam
Pilot Gas Inlet Steam Velocity Inlet Seal Types of Flares Tested
Air Assisted EPA / CMA Test Equipment
• Nominal 8 Inch Steam Assisted Flare Tip • Nominal 4 Inch Air Assisted Flare Tip • Two (2) Nominal 300,000 Btu/Hr Pilots per Tip • No Center Steam Injection • 7.5 HP Air Blower CMA Test Summary Average Qualified CE For Different Flare Types:
• Non-Assisted Flare from CMA Testing: 99.6% • Steam Assisted Flare from CMA Testing: 99.7% • Air Assisted Flare from CMA Testing: 99.6% EPA / CMA Test Conclusions CMA Test of Sonic Flare
• Test # 81 • Sonic Velocity Flare Tip • Propylene Gas • 99.8% Combustion Efficiency EPA / EER Flare Testing Basic EPA / EER Testing Goals
• Expand on Results From Previous Flare Testing • Include For Additional Gas Types • Analyze Commercial Flare Tips • Improve on Test Methodology • Develop Screening Facility EER Flare Screening Facility Flare Screening Facility Test Results EPA / EER Testing Key Observations Common Results for All Testing Programs
• CE impacted by lower heating value of mixture being flared • Flare tip must have constant pilot • CE always high for stable flames • CE for low heating value gases impacted by exit velocity • 98% Plus CE Achievable for Flares Key Factors in Maintaining Flare Efficiency
• Maintain Proper Mechanical Condition of Flare Tip • Maintain Proper Mechanical Condition of Flare Pilots • Ensure Proper LHV of Gases Flared • Ensure Proper Steam or Air Control Mechanical Condition Impact of Steam injection
• Steam to HC Ratios of 3.5 to 1 or Less Had 98% Plus CE • Steam to HC Ratio of 5.8 to 1 Had 82% CE • Steam to HC Ratio of 6.7 to 1 had 69% CE Steam Control Methods
• Flare Gas Flow Measurement and Ratio Control • Optical Analysis of Flare Flame with output to Steam Controller • Manual Adjustment of Steam Flow for Smokeless Flame • Radiant Temperature Measurement for Steam Control Flare Gas Flow Measurement Options
• Ultrasonic Insertion Type • Thermal Mass Flow Insertion Type • Orifice Plate • V-cone Orifice Device • Annubar Device • Vortex Meter • Turbine Meter Optical Flame Analysis
• Grade Mounted Unit • Measures Infrared Energy from Carbon Particles • Controls Steam Injection to Set Point • Can Be Affected by Fog, Snow, Rain, Etc. Steam Flow Control Valve Sizing Steam Flow Control Valve Sizing Steam Assisted Flares
• Proper Steam Control is Critical to CE • Significant Reduction in CE when Oversteamed Examples of Oversteamed Flares Air Assisted Flares
• Air Control is Critical to CE • Reduction in CE is Similar to Steam Flare for Over Aeration Typical Flare Pilots
Older Style Modern Unit • 250,000 Btu/hr Plus • 75,000 Btu/hr or • High Stability Less • Flame front • High Stability generator or Electric • Flame front ignition generator or Electric • 1 or 2 ignition Thermocouple • 1 or 2 • Retractable Thermocouple Thermocouple • Retractable Thermocouple Stable, Sonic Flare
• 99% Plus Combustion Efficiency Stable, Air Assisted Flare
• 99% Plus Combustion Efficiency Stable, Smoking Flare
• 99% plus combustion efficiency Stable, Smokeless Steam Assisted Flare • 99% Plus Combustion Efficiency Unstable, Sonic Flare • 70% Or Less Combustion Efficiency Oversteamed Flare
• 70% Or Less Combustion Efficiency Unburned HC Emissions
• Continuous Smaller Flows Impact Total Yearly Emissions • Emergency or Infrequent Relief’s Have Smaller Impact on Yearly Totals Tons per Year UHC vs. Flare Tip Size
140 120 100
80 Proper Steam Oversteam 60 40
20
0 Summary
• Elevated Flares can Achieve 99.5% Plus CE When Properly Sized, Maintained and Operated • Unburned HC Emissions can be Significant from Improper Operation
Environmental Integrity Project 1303 San Antonio Street, Suite 200 Austin, Texas 78701 512-637-9477 (phone) 512-584-8019(facsimile)
May 8, 2009
Via Electronic Submission: [email protected] Lindley Anderson MC-206 Air Quality Division, Chief Engineer's Office Texas Commission on Environmental Quality P.O. Box 13087 Austin, Texas 78711-3087
Re: Flare Task Force Stakeholder Group Public Comments
Dear Ms. Anderson:
On behalf of the Environmental Integrity Project (EIP), I appreciate the opportunity to submit these comments to the Flare Task Force Stakeholder Group. In addition, I request to be added as a member to the Flare Task Force Stakeholder Group and would like to be notified of any additional Stakeholder Group meetings. Due to the ongoing and serious public health consequences that result from the underreporting of flaring emissions, EIP supports the agency’s goals to improve its understanding and regulation of flares.
Attached to this comment letter, please find the Data Quality Act Petition (Petition), submitted to the U.S. EPA by the City of Houston which sets out in detail (technical and legal) the need for revisions to the way that emission estimates are currently calculated at refineries and chemical manufacturing plants. An April 7, 2009 response from EPA headquarters is also attached. TCEQ’s effort to undertake a “comprehensive evaluation of all aspects of flares” is an important step towards achieving more accurate measurements and more appropriate permit limits in the refinery and chemical manufacturing plant sectors. While the attached documentation addresses multiple systemic flaws resulting from of the use of inaccurate emission factors at refineries and chemical manufacturing plants, much of the documentation specifically addresses flares and information relevant to the goals of the Flare Task Force Stakeholder Group.
As TCEQ continues with its evaluation, EIP urges the agency to pay particular attention to significant known problems with estimating emissions based on current emission factors. These factors are used as a basis to calculate emissions from flares in the permitting process addressed by rules at 30 Tex. Admin. Code § 106.492 and 30 Tex. Admin. Code Chapters 115 and 116. When assumptions that underestimate emissions from flaring have been incorporated into individual permits, the state implementation plan (SIP) then also suffers from invalid assumptions.
Two examples of significant problems with TCEQ’s use of current emission factors are that (1) the factors incorporate an erroneous assumption that equipment is new and operating under normal conditions and (2) emission factors do not account for environmental variables that significantly impact emissions. With regard to the assumption about operating conditions, EPA studies conducted in the 1980s used to develop the emission factors specifically “excluded abnormal flaring conditions which might represent large hydrocarbon releases during process upsets, start-ups and shutdowns.”1 This is significant because the VOC emissions released from flares at refineries and chemical plants during a single SSM event may actually exceed the permitted annual average emissions. With regard to environmental variables, it is known that flares become less efficient and destroy less VOCs, as wind speeds increase.2 Yet, the emission factors for industrial flares were developed based on the assumption that 98- 99% of VOCs sent to the flare are destroyed.3 Specifically, it has been shown that the ability of flares to destroy VOCs (i.e. the destruction efficiency) decreases rapidly as wind speed increases from one to six meters per second.4 A study published in the Journal of the Air and Waste Management Association (JAWMA) found that “[a]s wind speeds increased beyond six meters per second, combustion efficiencies tended to level off at values between 10 and 15%.5 The study further noted that “[t]heoretical considerations and observational evidence suggest that flare combustion efficiency typically may be at ~70% at low wind speeds (U ≤ 3.5 m/s). They should be even less at higher wind speeds.”6
These are just two examples set out in the attached Petition. To the extent that staff has not already reviewed the Petition, EIP urges the staff to carefully review the City of
1 See Robert E. Levy et al., Indus. Prof. for Clean Air, Reducing Emissions from Plate Flares (No. 61) 10 (Apr. 24, 2006) and pp. 11-12 of the attached Petition.
2 EPA, VOC Fugitive Losses, at viii (noting that “the emission factor for flare estimation is based on a flare operating in still air conditions).
3 Douglas M. Leahey et al., Theoretical and Observational Assessment of Flare Efficiency, 51 J. Air & Waste Mgmt. 1610, 1611 (2001).
4 Leahy et al., supra note 77, at 1611.
5 Id.
6 Id. at 1615. Houston’s Data Quality Act Petition, its exhibits A – E and the April 7, 2009 response from EPA.
Sincerely,
/s/ Layla Mansuri Attorney, Environmental Integrity Project
Enclosures
Attachments
This page intentionally left blank. ~jED STqT ENVIRONMENTAL PROTECTION AGENCY a UNITED STATES WASHINGTON, D.C. 20460 y ~\l/gig ( C 02 ~ ~~~rqG PRO'1t!:S APR 7 2009 OFFICE OF AIR AND RADIATION
The Honorable Bill White Mayor of Houston Office of the Mayor 901 Bagby, 3rd Floor Post Office Box 1562 Houston, Texas 77251-1562
Dear Mayor White : for Correction (RFC 08003) Thank you for your letter of July 9, 2008, filing a Request Information Quality Guidelines (EPA IQG) . In under the Environmental Protection Agency's 22, 2009, you cite concerns about the that letter and your subsequent letter dated January refineries and chemical plants. You objectivity and utility of the emission factors pertaining to to revise the emission factors subject request that EPA: (1) immediately establish firm deadlines data from direct observation and to your petition, based upon reliable, accurate and unbiased emission inventories; (2) require the use other accurate measurements, in order to create valid plants of cost-effective remote sensing annually by large refineries and chemical manufacturing verify emissions; and (3) require technologies and installation of fenceline monitoring to to document emissions reductions refineries and chemical plants undergoing modification installing pollution control through the use of direct measurement if they wish to avoid concerns about the accuracy of equipment required under the Clean Air Act. We share your stakeholders to improve emission emissions estimates and hope to work with you and other inventories at refineries and chemical plants. a number of initiatives As you are aware and as outlined in your request, we have (including fenceline monitoring) and designed to advance the use of remote sensing technologies chemical plants. In addition, as a better characterize emissions from petroleum refineries and are planning to undertake a number of direct result of the concerns outlined in your request, we additional initiatives.
Ongoing and Planned Initiatives measurement and analysis of 1) A grant was awarded in July 2008 to the City of Houston for
Objectivity, Utility, and Integrity of Information ' Guidelines for Ensuring and Maximizing the Quality, 2002 (67 FR 63657) . Disseminated by the Environmental Protection Agency, EPA, InfoQualityGuidelines.adf http //www.epa :;ov/quality/informationguidelines/documents/EPA
Internet Address (URL) e http://www.epa.gov Process Chlorine Free Recycled Paper Recycled/Recyclable 0 Printed with Vegetable Oil Based Inks on 100% Postconsumer, volatile organic compound (VOC) and air toxics emissions in the Houston Ship Channel area using DIAL (Differential Absorption LIDAR (Light Detection and Ranging)) technology. This grant demonstrates EPA's support for additional data which Houston area stakeholders can consider in making decisions to achieve improved local air quality. Additionally, the data collected will help our understanding of these emissions nationwide. We look forward to working with you in this effort to prioritize sources for assessment, to ensure the sources are well characterized during the assessment, and to understand the results of the effort. Finally, upon completion of this study (estimated to be in 2010), we will evaluate how best to incorporate these results into future projects and ultimately into future emission estimation guidance.
2) Prior to receipt of your Request for Correction, we had begun the development of a protocol handbook (with detailed examples and case studies of previous projects) that would include all essential aspects of undertaking a project using remote-sensing technologies for emissions measurements including data quality objectives, quality assurance plans, validation/verification, and data interpretation. Your request confirms the importance of developing this type of handbook and we are committed to issuing a draft by the end of 2010. Further information on this initiative can be obtained by contacting Dennis Mikel at (919) 541-5511 .
3) Subsequent to the completion of the DIAL remote sensing study that was conducted at the BP Amoco facility in Texas City, Texas, we began evaluating the emission estimates from the test data that was collected during that study. In addition, we will also evaluate data from any future remote sensing studies. We believe these data are the appropriate data to review as we improve emissions estimation methods rather than examining past remote sensing data studies conducted at foreign petroleum refineries, where the refining practices may or may not reflect the practices of domestic refineries and the emission sources were not well characterized. We intend to provide a draft analysis of the BP Amoco data to the public for review within the next 6 months. We plan to accomplish this by following the same established procedures that we follow for soliciting public comments on draft emissions factors. Specifically, we will post the draft analysis to our emissions factors web site (http ://www.epa.gov/ttn/chief/efpac/abefpac.html) and notify individuals of the opportunity to comment through our CHIEF Listserv service. Further information on this initiative can be obtained by contacting Brenda Shine at (919)541-3608.
4) In direct response to your requests, in January 2009, we began the development of a comprehensive protocol for the estimation of VOC and air toxics emissions from petroleum refineries and chemical plants. This protocol will address all emissions sources and will include startup, shutdown, and malfunction events. In developing the protocol, we will review existing emission factors, including, but not limited to tanks, flares, and cooling towers, and to refine or revise the emission factors as necessary. We plan to make a draft of this protocol available for public review by following the same established procedures that were explained in item number 3 above. In the future, we plan to use data derived from this protocol to: a) evaluate risks to exposed populations; b) conduct comparisons to existing emissions estimates (e.g., TRI) for specific facilities; and c) better characterize the cost effectiveness of controls. In addition, we will develop additional factors and methodologies for additional emission sources including delayed cokers. This protocol will improve the consistency, transparency and accuracy of future emission estimates for these facilities . Further information on this initiative can be obtained by contacting Brenda Shine at (919) 541-3608.
5) As part of our corrective action strategy to the 2006 EPA Office of Inspector General Report,2 we have already developed tools such as the Electronic Reporting Tool (ERT) to assist in improving the quality of our emissions factors . In addition, we will continue our efforts to develop a self-sustaining emissions factors program that produces high quality emission factors, quantifies the uncertainty of emissions factors, ensures the appropriate use of emissions factors, considers stakeholder input appropriately, and improves emissions quantification through the use of better tools and knowledge of uncertainty. More information on the ERT can be obtained by visiting http ://www.epa.gov/ttn/chief/ert/ert_tool .html, and more information on our efforts to redesign our emissions factor program can be obtained by contacting Bob Schell at (919) 541-4116.
Background
I believe our rationale for undertaking the initiatives outlined above is best explained by first providing some background information on the purpose and intended use of AP-42 emissions factors. These factors are designed to be representative values relating the quantity of a pollutant released to the atmosphere under normal operating conditions with an activity associated with the release of that pollutant. By their nature, these factors are indicative of situations that have broad applicability and, as such, were originally intended as a tool for use in developing national, regional, state, and local emissions inventories . The idea of developing emission factors to account for site-specific conditions such as upsets, start-ups and shutdowns is counter to the definition of an emissions factor. We do not believe that updating emissions factors to account for such site-specific events is the solution for improving emissions estimates at refineries and chemical plants . We believe the issue is larger than just the quality and coverage of specific emission factors and speaks to the need for a comprehensive protocol for developing emission inventories. The protocol will combine emissions factors (to account for emissions during periods of normal routine operations) with other engineering calculations (to account for emissions during non-routine conditions) to allow for the estimation of facility-wide emissions during any stages of operation at a facility. Ultimately, we believe the lack of such a protocol can lead to omission of emission sources, improper characterization of process data and subsequent emissions data, and inconsistent reporting from one facility to the next.
To illustrate our point, consider some of the more common emission sources at petrochemical and petroleum refining facilities, such as storage tanks and flares. While AP-42 emission estimation equations exist for calculating working and standing losses from tanks, the estimates resulting from these equations depend on whether the user has accurately characterized the material stored in the tanks, the conditions of the fittings and seals, and the ambient conditions surrounding the tanks. If these site-specific conditions are not properly characterized,
2 EPA Can Improve Emissions Factors Development and Management, U .S. EPA Office of Inspector General, Report No. 2006-P-00017, March 22, 2006 . http://www.epa.gov/oig/reports/2006/20060322-2006-P-00017 .pdf the resulting emissions estimates will not be representative. Further, if short term inputs resulting in short-term emission rates are then extrapolated to long term or annual emissions without consideration of variability in operations or other conditions, resulting long term emissions will not be representative . Even if we undertake a study to improve the emissions equations, the inputs to these equations will always be site specific and will always affect the quality and accuracy of the emissions estimates. Similarly, a VOC destruction efficiency of 98 percent is often used for flares. While this efficiency may not be achieved in practice under all conditions (and this is an area where newer, state-of-the-art measurement techniques can inform this debate), other factors, such as flow and concentration and variability over time, are just as important to the emission estimate for a flare. Developing better flare emission factors will not address these site-specific variables that are crucial to the overall estimates.
Therefore, in addition to improving specific emission factors for selected processes (e.g., emissions from delayed cokers), we believe that a more comprehensive approach to addressing how facility-wide emissions estimates are conducted is needed to improve the overall accuracy of future emission estimates. This approach, or protocol, would provide a consistent method for selecting and applying emission factors, where available and appropriate, but also would provide guidance on the use of other emission estimation methodologies that do not rely on emission factors. It would address, among other things, minimum data quality objectives for process inputs, coverage of emissions sources, calculation of non-routine events such as startups, shutdowns and malfunctions, and inclusion of other information that would inform the estimates such as temporal variability in processing operations .
We are committed to developing such a protocol for petroleum refineries and petrochemical plants. As part of this effort, we would also review specific emission factors and initiate work to refine, revise and develop additional factors and methodologies for emission sources, including but not limited to tanks, flares, delayed cokers, and cooling towers. This effort could include the use of optical remote sensing techniques to quantify emission sources as well as startup, shutdown, and malfunction events that have been difficult to quantify. It will also include a critical review of available remote sensing data, conclusions drawn from the assessment, and an assessment/prioritization of sources for further study. Finally, we will also attempt to validate any protocol with actual measurement data. We plan to work with you and other stakeholders to undertake this project.
Finally, as noted in item number 5 above, we have embarked upon an effort to redesign our current emissions factor program for both criteria and air toxics pollutants to (1) make the development of emissions factors more self supporting and open to fuller participation by external organizations; (2) increase the use of electronic means to standardize the development process, quantify the quality components, and streamline all aspects of emissions factors development and use; (3) make the emissions factors uncertainties and emissions quantification methodologies more transparent to users; and (4) provide direction on the proper application of emissions factors consistent with non-inventory program goals including clearer guidance and direction on use of more direct quantification tools (e .g., emissions monitoring) in lieu of emissions factors. We believe this effort will provide the foundation that will result in high quality emissions factors based on a significant amount of data for many industrial sectors, including the petroleum refining and chemical industry sectors. We believe that the efforts we have initiated, especially the development of an emissions protocol document, will allow for more accurate estimation of emissions from these types of facilities. Although we have not provided firm deadlines for revising the emission factors for petroleum refineries and chemical plants, this letter provides a status update and a timeline for the completion of key tasks for each initiative. With respect to your request to require large refineries and chemical manufacturing plants to change their current procedures, federal agencies can not add additional requirements without a formal rulemaking. Before considering this option, EPA would like to evaluate the data from the initiatives outlined in this letter to determine the most effective way to enhance the estimation of emissions from large refineries and *chemical manufacturing plants. In closing, we look forward to working with you to further address this important issue, including establishing milestones and priorities for the development of solutions to these important emissions estimation issues.
If you are dissatisfied with this response, you may submit a Request for Reconsideration (RFR). The EPA requests that any such RFR be submitted within 90 days of the date of EPA's response. If you choose to submit a RFR, please send a written request to the EPA Information Quality Guidelines Processing Staff via mail (Information Quality Guidelines Processing Staff, Mail Code 2811R-, U.S . EPA, 1200 Pennsylvania Avenue, NW, Washington, DC 20460); electronic mail ([email protected]); or fax [(202) 565-2441] . If you submit a RFR, please reference the request number assigned to the original Request for Correction (RFC #08003). Additional information about how to submit an RFR is listed on the EPA Information Quality Guidelines website at httn://www.epa. ov/ uality/informationjauidelines/ .
Again, thank you for your letter. If you have additional questions, or require further information on the IQG process, please contact Reggie Cheatham at (202) 564-7713 .
Sincerely,
Elizabeth CWig Acting Assistant Administrator
This page intentionally left blank. Reducing Emissions From Plant Flares
Paper #61 – Revised April 24, 2006
Prepared by Robert E. Levy, Lucy Randel, Meg Healy and Don Weaver
Industry Professionals for Clean Air, 3911 Arnold St., Houston, TX 77005
ABSTRACT
Regulation of emissions from plant flares in Texas is based on flare efficiency studies conducted by the US Environmental Protection Agency (EPA) in the early 1980’s, which concluded that flare combustion efficiencies of 98 or 99 percent are achieved when critical operating variables are controlled appropriately. However, recent studies suggest that, even when well-controlled, flares may operate with efficiencies appreciably lower than 98 percent due to crosswinds and other factors. Lower than assumed flare combustion efficiencies, particularly during emission events, could account for a significant portion of previously unrecognized emissions from refineries and chemical plants and help to explain Houston’s high ozone levels. This paper discusses the state of the art in understanding flare emissions and examines the specific shortcomings of the current Texas flare regulations, including new regulations on highly reactive volatile organic compounds (HRVOCs). In addition, it considers steps that could mitigate flare emissions, and finally provides a list of recommendations for industry and regulators. Recommendations include expanding research on factors affecting flare combustion efficiency; improving monitoring and reporting of flare operating parameters, such as steam assist and flare gas mass ratios; minimizing the volume of waste gases routed to elevated, unenclosed flares; and encouraging the use of flare gas recovery systems or wind-protected ground flares and thermal oxidizers.
INTRODUCTION
Houston is classified by the EPA as being in "severe" nonattainment of the one-hour ozone standard and in "moderate" nonattainment of the eight-hour standard. The Texas Commission on Environmental Quality (TCEQ) has recognized a link between episodic emissions of the type associated with flaring and sudden exceedances of the one-hour ozone standard by enacting a new short-term limit on highly-reactive volatile organic compound (VOC) emissions. Ozone and smog result from the reaction of VOCs with nitrous oxides in sunlight. Significant quantities of VOCs are released from elevated flares, which burn waste hydrocarbons primarily during emergencies and upset conditions.
1
In a 2000 annual summary of emissions, the TCEQ estimated that flares were responsible for 12 percent of total emissions of volatile hydrocarbons in the Houston-Gulf Coast area, based on an assumed 98 or 99 percent flare combustion efficiency.1 However, flare burning efficiencies are not readily measured. Rather, VOC destruction efficiencies of 98 or 99 percent are assumed by the TCEQ2,3 and industry, based on experimental studies completed by the EPA in the early 1980’s.
In 1986, EPA used the data from these studies to codify the requirements for flares under the New Source Performance Standards (NSPS) in 40 CFR 60.18. The NSPS rule specifies limits of critical flare operating variables that must be controlled to obtain 98 percent or higher combustion efficiency. These critical operating variables include heat content of the flare fuel mixture, the ratio of fuel gas to assist gas (air or steam) and burner tip velocity. In 1994, similar control device requirements were added to the National Emissions Standards for Air Pollutants (NESHAP) in 40 CFR 63.11. Other than the addition of a provision for hydrogen fueled flares in 1998,4 the requirements have remained essentially unchanged for 20 years.
The TCEQ has not required reporting of operating data, except weight of total hydrocarbon burned and "engineering estimates" of stream composition. With inadequate operating data, 98 to 99 percent combustion efficiency cannot be realistically assumed. Another operating variable, crosswind velocity, was not addressed in the EPA studies, and more recent experimental work suggests crosswinds reduce flare combustion efficiency. Although some independent research has recently been initiated by the International Flare Consortium5, neither EPA nor TCEQ has undertaken significant large- scale experimental work since the early 1980’s.
In this paper, we review the literature evaluating effects of operating parameters on flare efficiency, as well as recent approaches in both industry and government to quantify and reduce hydrocarbon emissions from flares. The authors believe serious attention to these issues with enforceable goals is imperative if the Houston-Galveston area (HGA) is to reduce its “smog day count.” Recycling of waste gases, rather than flaring, must be seriously considered and flares should be reserved for essential use during unavoidable emergency events.
The authors represent Industry Professionals for Clean Air (IPCA), whose members have been affiliated with the petroleum or petrochemical and are concerned about the air pollution in the Houston-Galveston region. Based on our experience and research, we believe elevated flares present the most significant problems for controlling emissions of VOCs and toxic air pollutants in our region. Our purpose is to make realistic recommendations for reducing flare emissions that will encourage industry and the regulators to take action.
2 EMISSIONS FROM PLANT FLARES
The Texas Commission on Environmental Quality (TCEQ) uses high destruction efficiencies, based on combustion efficiencies established in the early 1980’s by the EPA to establish regulatory requirements, calculate permit limits, monitor compliance, enforce control requirements and plan for attainment of air quality standards. The TCEQ presumes that flares destroy 99% of ethylene and propylene, and 98% of other VOCs, except for certain compounds with less than 3 carbons, as long as continuous monitoring data for the flare inlet demonstrates compliance with the EPA’s minimum heating value and maximum exit velocity requirements specified in 40 CFR 60.18.6 Findings from the EPA 1983 Flare Study generally reflect use of high-efficiency flares burning simple chemicals at natural gas processing plants under optimal operating parameters and wind speeds less than five miles per hour. 7 The TCEQ’s approach, therefore, makes no allowance for real world operating variables. Specifically, it is based on the unrealistic assumptions that:
• plants are consistently operated according to the parameters necessary to optimize flare destruction efficiency; • crosswinds have minimal effect on combustion efficiency; and • flares perpetually operate at high destruction efficiency.
In the following discussion we will examine these assumptions and develop suggestions for adoption of more realistic ones.
Because flares are designed and used for control of emission spikes, the hourly emission rate permitted8 and experienced by a flare is likely to be the highest of any unit at a facility, even assuming a 98% to 99% VOC destruction efficiency. If realistic efficiencies were applied, then the emission rates would be dramatically higher and might account for much of the discrepancy between measured and model-predicted air pollution in the Houston region.
Determine More Realistic Flare Destruction Efficiencies
Operating Parameters
As stated earlier, EPA work in the 1980’s established the basis for current federal and Texas flare regulations. 40 CFR 60.18 and corresponding state regulations require that flares operate:
• “with a flame present at all times”,9 and • “with no visible emissions …, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours.”10
The waste stream routed to the flare either burns on its own or, if it has low heating value (less than 300 Btu/scf), with the assistance of a high-energy (more than 1000 Btu/scf) fuel gas, like natural gas or propane, to facilitate complete combustion.11 Typically, operators use fuel gas, or some other purge gas, to keep slow flowing emissions moving
3 toward the flare.12 With or without additional fuel, the combustion of many waste streams produces smoke – i.e., visible emissions.13 For smokeless combustion, operators typically inject steam or air to “achieve more complete combustion.”14 The injection of steam or air (assist gas) “at the flare tip [also] increases the mixing of waste gas with air, as well as the residence time of the waste gas constituents into the flame zone, thereby increasing combustion efficiency.”15
Operators must maintain a delicate, but essential, balance between smokeless and oversteamed emissions. Studies in the 1980s “demonstrated that assist gas to waste gas mass ratios between 0.4 and 4 were effective in reducing soot while ratios between 0.2 and 0.6 achieved the highest hydrocarbon destruction efficiency.”16 Too much assist gas (over steaming or over aerating) “may … reduce the overall combustion efficiency by cooling the flame to below optimum temperatures for destruction of some waste gas constituents, and in severe cases may even snuff the flame, thus significantly reducing combustion efficiency and significantly increasing flare exhaust gas emissions.”17 The EPA 1983 Flare Study noted: “Combustion efficiencies were observed to decline under conditions of excessive steam (steam quenching) and high exit velocities of low Btu gases.”18 Thus, EPA regulations establish parameters for heat content and exit velocity.19
The EPA 1983 Flare Study also demonstrated that separation of the flame from the burner tip results in a serious drop in burning efficiency.20 This flame separation has been observed during emergency flaring events under high winds and during addition of excess steam. The reported loss of efficiency occurs because, under these conditions, some of the gases do not remain in the combustion zone long enough for complete conversion to carbon oxides. Some of the gases have the opportunity to partially or totally bypass the combustion zone, with the result that unburned VOCs are emitted to the atmosphere.
In addition, the TCEQ learned from a contractor’s evaluation of flare gas flow rate and composition measurement methodologies that although “data on destruction efficiency versus assist gas ratio obtained under controlled conditions would suggest that poor assist gas control might negatively impact destruction efficiencies, there are little or no data available on the impact of assist gas ratio control on destruction efficiency of operating flares.”21 Thus, “the effect of assist gas to waste gas ratio on flare combustion efficiency, as well as destruction efficiency, requires further investigation.”22 Based on a review of some 50 refinery and petrochemical plant flares, and discussions with petrochemical plant operators, the TCEQ learned that the assist gas injection rate for 90% of the flares is controlled manually “by the operator based on [visual] flare observations (either directly or on a video monitor).”23 Nevertheless, neither the EPA’s nor the TCEQ’s regulations adequately address the critical role that steam content plays in flare combustion, and apparently neither agency is actively investigating steam content control for flares in the Gulf Coast region.
Furthermore, because the EPA 1983 Flare Study focused on simple hydrocarbons, subsequent analyses may not take into account the possibility that while the original compound may be destroyed, large hydrocarbons could simply be broken down into smaller hydrocarbons and other compounds, some of which may be toxic as well.
4 An independent group, the International Flare Consortium, has initiated research focused on exactly these issues in their project: "The effect of flare gas flow & composition; steam assist & flare gas mass ratio; wind & flare gas momentum flux ratio; and wind turbulence structure on the combustion efficiency of flare flames focusing on speciated emissions of the highly reactive volatile organic compounds (ethylene, propylene, butadiene) and the class archetypal hazardous air pollutant carcinogens (formaldehyde, benzene, benzo(a)pyrene)."24
Upsets present even more of an operations problem. An evaluation of emission events in the Houston-Galveston area between January 31 and December 31, 2003 “shows that HRVOC events and possibly VOC emissions events have the potential to contribute significantly to ozone formation in HGA.”25 A 2002 TCEQ toxicological evaluation of VOC monitoring data collected downwind of three Harris County plants noted that “exposure to recurrent elevated short-term levels of 1,3-butadiene may increase the risk of reproductive and developmental effects.”26
Consider this specific example in which a large chemical complex reported 304 tons of VOC emissions due to upsets and 622 tons of VOC emissions total for the year 2000. The applicable permit allowed only 124 tons of VOC emissions. Among other emission events in 2000, this company reported an upset, shutdown and startup from July 17, 2000 through August 18, 2000. As part of the response to this upset, the plant operator “maximized steam flow to the flares to optimize combustion and minimize smoke.”27
As noted above, too much steam can reduce combustion efficiency by cooling the flame. A TCEQ study determined that an “assist gas to waste gas mass ratio between 0.2 and 0.6 achieved the highest hydrocarbon destruction efficiency.”28 The company cited above reported that “[t]he hydrocarbon stream being flared during the July upset most likely required a steam to hydrocarbon ratio of 0.7.” We do not have enough information to accurately calculate the destruction efficiency of this company’s flare during the July 2000 upset, but experience suggests it is likely that the heat content was too low and the exit velocity too high for the efficiency to be 98+%, as assumed in most of the Upset/Maintenance Notification Forms filed regarding the incident.
The TCEQ’s new regulations regarding flares that burn HRVOCs assign 93% destruction efficiency to flares not meeting the EPA’s standards for minimum heat content and maximum exit velocity based on continuous monitoring.29 During the above-cited July 2000 upset, if a flare destruction efficiency of 93% is assumed, rather than 98%, the 304 tons of VOC emissions would become 1064 tons of VOC emissions. This represents 1.7 times the 622 tons of total VOC emissions reported at this plant during the entire year 2000. Moreover, reductions in residence time during startup and shutdown operations,
5 when flares operate at high rates for extended periods, may reduce combustion efficiency substantially below the 93% provided for in the new regulations.
Crosswinds
The TCEQ’s assumed flare destruction efficiencies of 98+% also do not take into account routine, yet less than ideal, weather conditions, such as crosswinds. An open flame, in the absence of a crosswind, assumes a symmetrical shape of maximum volume having an equilibrium flame temperature dependent upon operating conditions. Crosswinds distort the flame, reducing flame volume and flame temperature. High combustion efficiency requires that the combustible material be present in the high temperature region of the flame for a significant period. Crosswinds in excess of 5 miles per hour, however, may significantly degrade combustion efficiency because they shorten the residence time of the combustible material in the flame.
The EPA 1983 Flare Study only conducted tests on flares at wind speeds up to 5 miles per hour because flame instability made it impossible to obtain proper samples at higher wind speeds.30 Consequently, there is a significant gap in the EPA field data, but lab- scale data suggests potentially significant reduction in combustion efficiency at high wind speeds.31,32
Ongoing studies by the Engineering Department of the University of Alberta and the Alberta Resource Council also demonstrate the need to consider the effects of crosswinds on flares. The University of Alberta studies not only confirm findings in the EPA 1983 Flare Study regarding flame separation, they also conclusively demonstrate that crosswinds can have a serious deleterious effect on the combustion efficiency of an open flame.
Since significant crosswinds are usually present along the Texas Gulf Coast,33 these wind effects must be accounted for. Yet, the TCEQ inappropriately dismissed the findings from the University of Alberta research when they reviewed the data in 2001 and 2002. We requested internal documents from the TCEQ relating to this review and found that the TCEQ dismissed the entire body of research from the University of Alberta based primarily on the TCEQ Staff’s review of only one 2001 study.34 In analyzing this study, the TCEQ Staff concluded:
• questionable simplifying assumptions were made in the development of a mathematical model from the experimental work on a pilot-scale facility; and
6 • poor flare destruction efficiency results obtained with field studies of a simple oil field flare could not be extrapolated to more sophisticated plant flares “with engineered burners and good liquid knockout systems.” 35
The University of Alberta researchers did not directly investigate commercial plant flares with engineered flare tips, but the basic findings of this study indicate that crosswinds affect combustion efficiency under a variety of circumstances. Thus, while we agree with TCEQ’s specific critiques, it is inappropriate for them to exclude the basic research by the University of Alberta on the basis that results of a field study of an oil field flare could not be directly applied to Gulf Coast flares because of design differences.
Baylor University collected some samples in canisters during flyovers it conducted in 2001 for TCEQ, but apparently there has been no follow-up to this work. We have found no documentation indicating that the EPA or the TCEQ subsequently considered the effects of crosswinds on flares in policies or guidelines related to flares.
In the TCEQ Emissions Inventory Guidelines, in the technical supplement on flares revised in 2004, TCEQ does acknowledge the potential for unstable flames in developing the 93% destruction efficiency to be used when 40 CFR 60.18 requirements are not met36. Nonetheless, neither the EPA nor the TCEQ routinely consider the critical variable of wind speed in permit reviews, compliance investigations or emission reduction planning. The entire question of crosswind impact on flare combustion efficiency appears to have disappeared from their deliberations, without explanation, for more than two decades.
Research being undertaken by the International Flare Consortium37 is intended to directly address the issue of crosswind effects on industrial flares and needs to be followed closely by the EPA and TCEQ.
Performance Testing
The absence of further study or testing by the regulatory authorities is particularly perplexing, since the TCEQ and the EPA acknowledge problems with accurately estimating air emissions generally, and from flares in particular. The TCEQ “has determined that [VOC] emissions may be underestimated in air shed emission inventories.”38 These deficiencies are important because emission inventories are the foundation for effectively controlling air pollution.39 And, since flare emissions represent a significant portion of an industrial plant’s ozone-forming emissions,40 undercounting of flare emissions could represent a significant portion of underestimated emission inventories.
Flare emissions, however, are much more difficult to measure than those of other pollution control devices. According to the EPA 1983 Flare Study, “Flare emission measurement problems include: the effects of high temperatures and radiant heat on test equipment, the meandering and irregular nature of flare flames due to external winds and intrinsic turbulence, the undefined dilution of flare emission plume with ambient air, and the lack of suitable sampling locations due to flare and/or flare heights, especially during process upsets when safety problems would predominate.”41 In addition, the EPA 1983
7 Flare Study specifically “excluded abnormal flaring conditions which might represent large hydrocarbon releases during process upsets, start-ups and shutdowns.”41
This, however, does not justify excusing the monitoring of flare emissions. Without proper monitoring it is impossible to know whether flares are performing as expected. The TCEQ expects “that emissions from flares would be better estimated if they were based on waste gas flow rate and composition measurements. … The overall objective of the [TCEQ] studies on flare emissions is to obtain performance specifications that ensure quality assured sampling, testing, monitoring, measurement and monitoring systems for waste gas flow rate, waste gas composition, and assist gas flow rate.”42 Modern insertion meters can measure mass flow within +1%, and continuous composition analyzers are readily available. However, measuring flows within an uncertainty of + 5% to 10% “in flare systems with highly variable compositions or where the meter cannot be located in a section of pipe with a representative flow profile will be a challenge.”43
Accordingly, the TCEQ now requires that operators of flares that burn HRVOCs – 1,3- butadiene, butenes, ethylene and propylene – continuously monitor compliance with “maximum tip velocity and minimum heat content requirements to ensure proper combustion by the flare.”44 These new regulations do not adequately reduce flare emissions, however, because:
• In setting the appropriate assist gas flow rates and aggregate flow velocity, it is important to know the composition of the flow. The TCEQ, however, does not require continuous composition monitoring. • Most operators control assist gas injections manually, based on the visual evaluation of the flame’s smokiness by the operator. Thus, depending on the skill and attention of the operator, significant fluctuations in heating value and exit velocities can occur over the course of an hour, such that substantial short-term fluctuations in heating value could offset each other. One study notes that the ratio of assist gas to waste gas with manual control varied from about 2 to more than 50.45 In this way, oversteaming can significantly reduce combustion efficiency without violating the minimum heat value requirement for the one-hour average. • Although most flares are designed to be most efficient at the high volumes experienced during non-routine operations, many are routinely used for disposal of low-flow emissions. • The TCEQ presumes that “because many of these flares are also used for non- HRVOC streams, the regulations will result in better combustion of other VOC streams as well. This improved combustion will reduce emissions of less-reactive VOCs.”46 The TCEQ, however, did not make the continuous monitoring requirement applicable to waste gas streams of other VOCs. So there is no quality control on flares that burn only other VOCs and air toxics, which could represent a significant volume of VOC emissions in the Houston-Galveston area. • The results of industry monitoring are not readily accessible to the public. Although the San Francisco Bay Area has far fewer industrial flares emitting much lower volumes of pollutants, the Bay Area Air Quality Management District (BAAQMD) in California requires all refinery operators with elevated flares to submit monthly reports of daily quantities (and species) of releases during the
8 period reported.47 The BAAQMD posts these reports, complete with graphs illustrating daily spikes in emissions, on its website.48 • Historically, TCEQ enforcement of monitoring requirements, if any, generally comprised only minor recordkeeping violations. • The monitoring requirements on many flares with the potential for substantial emissions are significantly weaker. Generally, these relaxed regulations require only a combination of calorimeter, engineering calculations and process knowledge for monitoring flares used for abatement of emissions from loading operations, maintenance, startup and shutdown activities, emergencies, temporary service, liquid or dual phase streams, and metal alkyl production processes.49
In addition, the type of continuous monitoring required by the TCEQ may not be adequate. Flow measurement devices typically “calculate volumetric flow by sensing a velocity in the pipe and multiplying that velocity by the cross sectional area of the pipe in which the velocity is being sensed.”50 The accuracy of these measurements, however, is based on assumptions that:
• velocity is uniform across the cross section; and • the gas is of a known composition.
Thus, frequent changes in the waste gas composition could significantly marginalize the quality of flare performance assessments.
Although safety concerns may preclude direct monitoring of emissions, parametric monitoring and remote sensing techniques do exist which would provide data more indicative of actual flare performance and emissions. For example, Open Path Fourier Transformation Infrared (FTIR) technology “can identify, measure, and speciate over 100 compounds” from a distance of more than 100 meters.51 FTIR is particularly suited for VOC identification and quantification because VOCs present strong absorption spectra in the infrared region.52
In the near term, the TCEQ could follow the lead of California regulators in requiring more extensive reporting of flare operations and emissions as a means to identify priorities in reducing flare emissions and motivating operators to undertake emission reduction projects sooner rather than later. Even before the BAAQMD issued its Flare Monitoring Rule, its staff reported that flaring dropped dramatically because of increased industry attention to flaring and flare monitoring.53
Similar observations were made in Southern California. Their monitoring rule, Rule 1118 – Emissions from Refinery Flares, was promulgated by South Coast Air Quality Management District (SCAQMD) in 1998 and amended in November 2005. During the period from 2000 to 2003, SOx emissions were reduced from 2633 tons to 735 tons with only a fraction attributed to new equipment and the rest to expanded use of “ best management practices.”54
These same data showed 79% of emissions were from unknown causes or nonrecordable events. In response SCAQMD amended Rule 1118 to require a “Specific Cause
9 Analysis” of significant flaring events as defined by 1118 (c)(D), or an analysis of the relative cause of “any other flare events where more than 5,000 standard cubic feet of vent gas are combusted. (Rule 1118 (c)(E)). The revised rule also incorporates other provisions to further reduce flaring emissions, such as mitigation fees and flare management plans (1118 (d)).
Require Alternatives to Elevated Flares
For more consistent reductions in flare emissions over the long term, the TCEQ could require alternatives to elevated flares. It is common practice for industry to use elevated flares for routine destruction of vent gases or off-spec hydrocarbons, not just for emergency or short-term releases. Most flares are built for non-routine events, such as upsets, startup and shutdown, so they are not designed for optimal efficiency at low temperatures and low flow rates.55 Consequently, routine flaring may result in unnecessary emissions of HRVOCs, VOCs and toxic materials.
The TCEQ appropriately requires that many vent and relief valve emissions be controlled, rather than vented to the atmosphere. Ideally, these routine emissions should be recovered in a flare gas recovery system,56 which recycles the valuable components of the waste stream, using an elevated flare only as a backup system.
Where gas recovery is impractical, we believe TCEQ should require operators to install high efficiency combustion devices to handle all predictable demand. Enclosed ground flares, incinerators and thermal oxidizers are acceptable alternatives because they can consistently achieve high combustion efficiencies as a result of the enclosed firebox, longer residence times at high temperature and negligible wind effects.
But high-efficiency combustion devices themselves need further attention from the TCEQ as well. Like owners of motorized vehicles, operators should be required to demonstrate the emission control performance of each device on an annual basis. After the TCEQ gains experience with the results of such testing, the frequency for specific classes of equipment, or particular companies, could be adjusted to ensure that testing occurs at appropriate intervals.
While avoiding flaring of routine vent gases is important, minimizing episodic emissions may be even more critical in reducing emissions of combustion byproducts, carbon monoxide (CO), carbon dioxide (CO2) and nitrogen oxides (NOx). As demonstrated by the example cited earlier, emissions from a single episodic event can exceed annual average emissions. In reviewing emission events occurring during 2003, the University of Texas’ Center for Energy and Environmental Resources found that the Houston Galveston Area averaged more than one emission event per week: “Over an 11-month period there are 58 times (affecting 395 hours) when ethylene event emissions exceed the 2000 annual average of 586 lbs/hr and 7 times (affecting 44 hours) when event emissions exceed 5 times the annual average.”57 Unlike in the rest of Texas, and the rest of the United States, emissions in Houston “change all the time,” and “[p]oor air quality [is] due mostly to days with both ozone conducive meteorology and high emissions.”58 Hence
10 preventing unnecessary releases may provide the greatest decrease in overall VOC emissions while also reducing emission of combustion byproducts, CO, CO2, and NOx.
In an effort to reduce such variable emissions, EPA Region 6, the Texas Natural Resources Conservation Commission (TNRCC, predecessor to the TCEQ), the Louisiana Department of Environmental Quality, and 13 petrochemical facilities in Louisiana and Texas, participated in the Episodic Release Reduction Initiative. In 1999 and 2000, the Initiative participants evaluated “the causes of releases to the air associated with startups/shutdowns, equipment failures, and process upsets.”59
In the Technical Exchange on Startup/Shutdown practices, petrochemical facilities shared case studies and examples of methods used to reduce flaring. Participants noted that changes to procedures and training as well as design improvements could be used to reduce emissions.60 Key findings on ways to reduce emissions include:
• using flare gas recovery systems for routine venting and planned shutdowns; • improving training of operators, better documentation of procedures highlighting environmental impacts, and allowing additional time for startup and shutdown; and • reducing flaring among ethylene producers by recycling off-spec streams to furnace feed, augmenting the plant’s steam capacity, and using a ground flare to handle off-spec and startup loads.
Since that time, individual facilities in Texas have implemented site-specific programs to reduce flaring. In 2001, the Dow Chemical Plant in Freeport, TX initiated a flare minimization project at the Light Hydrocarbons plant. Before project implementation, nearly all off-spec hydrocarbons at the unit, which includes an ethane/propane cracking process, were flared. By optimizing equipment and procedures related to plant start-up, shutdown, upsets and plant trips, including improving overall plant reliability, the plant had an “89% reduction in overall upset flaring – using a two year running average.” Further, from 2001 to the end of 2003, the plant achieved documented savings of $2.5 million.61
Also in Texas, Shell Chemicals developed a “parking mode” to reduce feed rates during upset conditions in order to minimize flaring at its two ethylene units in Deer Park. Implementation resulted in a 50% reduction in flaring between 2002 and 2003.62
In the San Francisco Bay Area, flare minimization projects and studies such as these are now required of refineries regulated by BAAQMD under Regulation 12, Rule 12: “Flares at Petroleum Refineries”, adopted July 20, 2005. This rule builds on their 2003 rule, Regulation 12, Rule 11: “Flare Monitoring at Petroleum Refineries”. Flare minimization plans submitted under Rule 12 must be approved by the Air District and “must include:
• Detailed information about equipment and operating practices related to flares, • Steps the refinery has taken and will take to minimize the frequency and duration of flaring, and
11 • A schedule of implementation of all feasible flare prevention measures.”63
TCEQ should consider implementing regulations similar to BAAQMD Rule 12 that would encourage other facilities in Texas to follow the examples of Dow and Shell cited above.
More extensive testing and reporting by plant operators on the operating parameters and performance of flares and other waste gas combustion devices also would help the TCEQ enforce existing regulations and identify priorities for reducing the use of elevated flare stacks as emission control devices.
CONCLUSION AND RECOMMENDATIONS
We conclude that the TCEQ must take action to determine more realistic flare destruction efficiencies, minimize the volume of emissions routed to elevated, unenclosed flares, and encourage the use of flare gas recovery systems, or wind-protected ground flares and thermal oxidizers. Specific recommendations are as follows:
1. Enforce existing requirements for flare operations rigorously and consistently.
2. Expand and accelerate TCEQ, EPA and others’ research on the factors affecting combustion efficiency of flares, alternatives to flares and flare monitoring technologies.
3. Revise TCEQ policies and guidelines for estimating flare emissions. At a minimum, the effects of steam and crosswinds should be factored into emission estimates for rulemaking, permitting, enforcement, reporting and planning activities. These effects must be based on best available data rather than assumed values.
4. Conduct a rulemaking proceeding for regulations requiring more extensive monitoring and reporting of flare emissions. At a minimum, operators should be required to report daily emissions each month, and the TCEQ should post these reports on its website.
5. Develop a strategy to increase the use of flare gas recovery systems or, where impractical, use of more effective destruction technologies, such as enclosed ground flares or thermal oxidizers, rather than elevated flare stacks, as emission control devices.
6. Use elevated flare stacks only for release of combustibles in emergencies, for safety reasons, or as necessary during planned startups or shutdowns of equipment.
12 7. Divert uncontrolled emissions from vents and relief valves to vapor recovery systems and other alternatives to flares, with flares serving only as a backup system. The TCEQ should set a goal for eliminating uncontrolled, authorized VOC emissions by a specified date, and systematically review its regulations and permitting policies to identify steps towards that goal.
8. Test high efficiency combustion devices, such as enclosed ground flares and thermal oxidizers, regularly to demonstrate emission control performance.
REFERENCES
1. Gabriel Cantu, TCEQ, 2000 Houston - Galveston Speciated Point Source Modeling Inventory, October 2003, Slide 17. 2. TCEQ publication RG-109 (Draft) Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers, October 2000, pp.19, 35. 3. TCEQ,“Technical Justification For 99% Flare Efficiency,” attached as Appendix L to Revisions to the SIP for the Control of Ozone Air Pollution, HGB Ozone Nonattainment Area (HGB 2004 SIP Revisions), October 2004. 4. Federal Register May 4, 1998, pp. 24436-24437, Standards of Performance for New Stationary Sources: General Provisions; National Emission Standards for Hazardous Air Pollutants for Source Categories: General Provisions 5. James Seebold, Peter Gogolek, John Pohl, & Robert Schwartz, “Practical Implications of Prior Research on Today's Outstanding Flare Emissions: Questions and a Research Program to Answer Them”, Presented at AFRC-JFRC 2004 Joint International Combustion Symposium, Environmental Control of Combustion Processes: Innovative Technology for the 21st Century, October 10 – 13, 2004, Maui, HI. 6. TCEQ, RG-109, pg. 19. 7. Flare Efficiency Study, EPA-600/2-83/052,. USEPA, Cincinnati, OH July 1983 (EPA 1983 Flare Study) Table 1.Flare Efficiency Test Results, p. 4. 8. URS Corp., Extraction of Allowable VOC Release Levels From TCEQ permits, prepared for Houston Advanced Research Center Texas Environmental Research Consortium, April 15, 2004. 9. 40 CFR §60.18(c)(2). 10. 40 CFR §60.18(c)(1). 11. TCEQ Work Assignment 5 Draft Flare Gas Flow Gas Rate and Composition Measurement, Methodologies Evaluation Document, prepared by Shell Global Solutions (US), Inc., p. 5-1. (Measurement Methodologies Evaluation). 12. Measurement Methodologies Evaluation, p. 1-6. 13. John F. Straitz, III, “Clearing the Air About Flare Systems,” Chemical Engineering, September 1996, reprint, p. 5. 14. Straitz, p. 5. 15. Measurement Methodologies Evaluation, p. 5-1. 16. Measurement Methodologies Evaluation, p. 5-5. 17. Measurement Methodologies Evaluation, p. 5-2. 18. EPA 1983 Flare Study, p. ii.
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19. 40 CFR §60.18(c)(3) and (4). 20. EPA 1983 Flare Study, Table 1, p. 4. 21. Measurement Methodologies Evaluation, p. 5-6. 22. Measurement Methodologies Evaluation, p. 5-2. 23. Measurement Methodologies Evaluation, p. 5-3. 24. Seebold, et al. 25. Cynthia Folsom Murphy and David T. Allen, “Event Emissions in the Houston Galveston Area” (HGA), January 14, 2004 (Event Emissions in HGA), p. A-31, available at www.harc.edu/harc/Projects/AirQuality/Projects/Status/H13.aspx. 26. Joseph T. Haney, Jr., and Laura Carlisle, Toxicology & Risk Assessment, Office of Permitting, Remediation & Registration, TNRCC Interoffice memorandum to Dan Thompson, Director, Region 12, Houston, July 31, 2002, p. 3. 27. Reference omitted to protect the company. 28. Measurement Methodologies Evaluation, p. 5-5. 29. 30 TAC §115.725(d)(7). 30. EPA 1983 Flare Study, p. 19. 31. M.R. Johnson, O. Zastavniuk, J.D. Dale and L.W. Kostiuk, “The Combustion Efficiency of Jet Diffusion Flames in Cross-flow,” presented at the Joint Meeting of the United States Sections – The Combustion Institute, Washington, D.C., March 15- 17, 1999. 32. Matthew R. Johnson, Adrian J. Majeski, David J. Wilson and Larry W. Kostiuk, “The Combustion Efficiency of a Propane Jet Diffusion Flame in Cross Flow,” presented at the Fall meeting of the Western State Section of the Combustion Institute, Washington, October 26-27, 1998 (Paper #98F-38). 33. Houston’s average annual wind speed is 7.9 miles per hour and Galveston’s is 11.0 miles per hour. See the University of Utah Department of Meteorology’s Utah and National Climate Data at http://www.met.utah.edu/jhorel/html/wx/climate/windavg.html. 34. Douglas M. Leahey, Katherine Preston and Mel Strosher, Theoretical and Observational Assessment of Flare Efficiencies, 51 J. Air & Waste Mgmt., 1610, 1611 (2001) 35. Karen Olson, Email to Terry Blodgett, et al., February 27, 2002, 11:31 AM (Olson Feb. 27 Email) (from TCEQ Response to Open Records Request, March 29, 2005 (Mar. 29 Response). 36. TCEQ publication RG-360, 2005 Emissions Inventory Guidelines, Technical Supplement 4; Flares, January 2006, p. A-46. 37. International Flare Consortium web site: URL http://home.earthlink.net/~international-flare-consortium/index.html. Accessed March 2006. 38. Measurement Methodologies Evaluation, p. E-1. 39. TCEQ Science Synthesis Committee, “Accelerated Science Evaluation of Ozone Formation in the Houston-Galveston Area,” November 13, 2002, p. 4. An analysis of scientific data on ozone formation in the Houston-Galveston area as part of the TCEQ’s Texas Air Quality Study in the summer of 2000.
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40. Cantu, TCEQ, 2003, Slide 17. 41. EPA 1983 Flare Study, p. 1. 42. Measurement Methodologies Evaluation, p. E-1. 43. Measurement Methodologies Evaluation, p. 6-1 to 6-2. 44. HGB 2004 SIP Revisions §1.6.2.1 Collateral VOC Reductions. 45. Measurement Methodologies Evaluation, p. 5-4. 46. HGB 2004 SIP Revisions §1.6.2.1 Collateral VOC Reductions. 47. Bay Area Air Quality District Regulation 12-11-401. 48. URL http://www.baaqmd.gov/enf/flares. 49. 30 TAC §115.725(e)-(k). 50. Measurement Methodologies Evaluation, p. 2-1. 51. Survey and Demonstration of Monitoring Technology for Houston Industrial Emissions (Project H31.2004) ENVIRON International Corporation. Prepared for Houston Advanced Research Center, January 12, 2005, pp. 3-12 to 3-13 (Monitoring Technology for Houston). 52. Monitoring Technology for Houston, p. 3-16. 53. BAAQMD Staff Report, Regulation 12, Rule 11, p. 31-32. 54. SCAQMD Summary Evaluation Report on Emissions from Flaring Operations at Refineries, Version 1, September 3, 2004. 55. Matthew R. Johnson, et al. (University of Alberta), “The Combustion Efficiency of a Propane Jet Diffusion Flame in Cross Flow,” presented at the Fall Meeting of the Western States Section of the Combustion Institute, Washington, October 26-27, 1998, p. 11. 56. P.W. Fisher and D. Brennan, “Minimize Flaring with Flare Gas Recovery,” Hydrocarbon Processing, June, 2002, p. 83. 57. Event Emissions in HGA, p. A-21. 58. Harvey Jeffries, et al. Stochastic Emissions Inventories for Houston Point Sources, Concepts and Examples, presentation to TCEQ, October 2000, Slide 2, available at URL http://www.airchem.sph.unc.edu/Research/Projects/Texas/MCCG/ (emphasis in original). 59. The Episodic Release Reduction Initiative, July 5, 2001 (ERRI), p. 1, URL http://www.epa.gov/earth1r6/6en/a/erri07-5fin.pdf. 60. ERRI, Appendix F, pp.32-36. 61. Steven Krietenstein, “Flare Minimization Strategy During Plant Upsets: Freeport” presented at 2005 AIChE Spring National Meeting, 17th Annual Ethylene Producers’ Conference, Session TA009 – Ethylene Plant Operations, Atlanta, GA, April 12, 2005. 62. Nicholas Genty and Bryce Kagay, “Development of a Parking Mode at Shell Chemical’s Deer Park Plant Olefin Unit OP-III, presented at 2005 AIChE Spring National Meeting, 17th Annual Ethylene Producers’ Conference, Session TA009 – Ethylene Plant Operations, Atlanta, GA, April 12, 2005. 63. BAAQMD Press Release July 20, 2005, “Air District Board Adopts Refinery Flare Rule”.
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KEY WORDS flare, combustion, emissions, combustion efficiency, destruction efficiency, air pollution, crosswinds, ozone, ozone-forming emissions, HRVOC, VOC, elevated flare, ground flare, thermal oxidizer, flare minimization, flare gas recovery, refinery, petrochemical, TCEQ, BAAQMD, University of Alberta. Alberta Resource Council, Houston- Galveston, Gulf Coast, FTIR, International Flare Consortium
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FINAL REPORT
A Review of Experiences Using DIAL Technology to Quantify Atmospheric Emissions at Petroleum Facilities
PREPARED FOR
Environment Canada Pollution Data Division Science and Risk Assessment Directorate Science and Technology Branch 351 St. Joseph Blvd., 9th Floor Gatineau, QC K1A 0H3
Contact: Roy McArthur
Telephone: (819) 953-9967 Facsimile: (819) 934-4158 E-mail: [email protected]
PREPARED BY
Clearstone Engineering Ltd. 700, 900-6 Avenue S.W. Calgary, Alberta, T2P 3K2 Canada
Contact: David Picard Telephone: 1 (403) 215-2730 Facsimile: 1 (403) 266-8871 E-mail: [email protected] Website: www.clearstone.ca
September 6, 2006 Final Report
EXECUTIVE SUMMARY
This report presents the results on a technical literature review of Canadian and international experiences regarding the application of differential absorption lidar (DIAL) for the measurement of emissions from petroleum facilities.
Preliminary results from fugitive emission measurements undertaken as part of a DIAL demonstration project at a petroleum refinery in Western Canada indicate that these emissions may be significantly greater than the values estimated using currently established inventory methods. Similarly, DIAL measurement studies conducted during 2003 and 2004 in the upstream oil and gas sector (i.e., by Alberta Research Council and Sectrasyne Ltd., working with CAPP and PTAC) indicated that the emission estimates derived using currently established methods may significantly under estimate volatile organic compound (VOC) emissions. The fugitive emissions from two of the gas plants surveyed were 4 to 8 times the mass emissions estimated based on installed equipment and standard industry emission factors, the current NPRI reporting method. Process flares typically were the source of 10 to 15% of the methane emissions from these sites. These were the first DIAL measurements of this type conducted in North America.
Furthermore, U.S. EPA Inspector General recently published a report stating that current methods of estimation based on emission factors are not accurate and lead to significant underreporting1.
In an attempt to facilitate the analysis of the implication of this recent information, Environment Canada (EC) commissioned this literature review to provide a background document covering the following topics:
1. The European Commission IPPC Bureau’s Integrated Pollution Prevention and Control (IPPC) Reference Document on Best Available Techniques on Emissions from Storage (draft January 2005 available) and elucidate on recommendations and limitation for the use of DIAL to update emission factors and monitor emissions. 2. The DIAL study results for the Canadian upstream oil and gas sector and for the Western Canada petroleum refinery. 3. The European experience with DIAL (e.g. history and rationale of DIAL development, legal requirements to use DIAL, scope and frequency of such measurements for industrial facilities, uncertainty of DIAL measurements, measurement protocols and data quality assurance and control, facility level measurement results). 4. The current U.S. opinion and/or conclusions on the potential for application of the DIAL technology and other assessments that indicate significant underreporting of emissions by industrial facilities (e.g. magnitude, reasons for underreporting, emission sources affected by underreporting). 5. Any outstanding technical issues that must be resolved. 6. Potential impact of all of this information on the Canadian VOC emission estimates.
1 Source: US. EPA. 2006. EPA Can Improve Emissions Factors Development and Management. Report. No. 2006- P-00017. Prepared by US EPA Office of Inspector General, March 22, 2006. .pp 37. i Final Report
TABLE OF CONTENTS Section Page 1.0 INTRODUCTION...... 1 2.0 AN OVERVIEW OF THE DIAL TECHNOLOGY...... 2 2.1 BASIC METHOD ...... 2 2.2 EMISSION QUANTIFICATION PROCEDURES ...... 3 2.3 FACTORS INFLUENCING DETECTION LIMITS AND ACCURACY ...... 3 2.3.1 Distance From Source ...... 4 2.3.2 Spatial Resolution...... 4 2.3.3 Interferences from Other Compounds...... 4 2.3.4 Optical Noise ...... 5 2.3.5 Aerosol or Particulate Distribution...... 5 2.3.6 Interference from Nearby Sources...... 5 2.3.7 Data Averaging...... 6 2.3.8 Extrapolation of Results...... 6 2.4 APPLICATIONS...... 7 2.5 MANUFACTURERS ...... 7 2.6 ADVANTAGES, DISADVANTAGES AND LIMITIATION...... 8 3.0 EXPERIENCES WITH DIAL ...... 10 3.1 BELGIUM...... 10 3.2 CANADA...... 10 3.3 CZECH REPUBLIC ...... 11 3.4 EUROPEAN COMMISSION...... 12 3.5 GERMANY ...... 13 3.6 SWEDEN ...... 13 3.7 THE EUROPEAN UNION NETWORK FOR THE IMPLEMENTATION AND ENFORCEMENT OF ENVIRONMENT LAW (IMPEL)...... 14 3.8 UNITED KINGDOM...... 15 3.9 UNITED STATES...... 16 4.0 CONCLUSIONS AND RECOMMENDATIONS ...... 18 4.1 CONCLUSIONS ...... 18 4.2 RECOMMENDATIONS ...... 19 5.0 REFERENCES CITED ...... 20
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LIST OF ACRYNOMS
DIAL – Differential Absorption LIDAR DOAS - Differential Optical Absorption Spectroscopy FTIR - Fourier Transform Infrared Spectroscopy IMPEL - European Network for Implementation and Enforcement of Environmental Law (An informal Network of the environmental authorities of member States) IR - Infrared LASER - Light Amplification by Stimulated Emission of Radiation LIDAR – Light Detection and Ranging. NPRI - National Pollutant Release Inventory OP - Open Path PI - Path Integrating RADAR - Radio Detection And Ranging ROMT - Remote Optical Sensing Techniques ROSE - Remote Optical Sensing Evaluation SODAR - Sonic Detection and Ranging TDLAS - Tunable Diode Laser Absorption Spectroscopy UV - Ultraviolet VDI - Verein Deutscher Ingenieure (The Association of German Engineers) VOC - Volatile Organic Compound
iii Final Report
1.0 INTRODUCTION
This study presents a general overview of DIAL and the experiences in Canada and internationally in its application for detection and quantification of atmospheric emissions at petroleum refineries and other facilities or sources.
Section 2 delineates the DIAL method, discusses some of the factors that influence the method’s detection limits and accuracy, lists its potential applications, highlights key advantages and disadvantages, and lists some of the manufacturer’s of DIAL systems.
Section 3 discusses the experiences and findings of different researchers, in Canada and internationally, applying the DIAL technology. Relevant standards, guidelines, best practices and regulatory requirements are noted. The conclusions and recommendations of this report are presented in Section 4 and all references that have been cited are listed in Section 5.
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2.0 AN OVERVIEW OF THE DIAL TECHNOLOGY
2.1 Basic Method
Differential absorption LIDAR (DIAL) is an open-path optical sensing technique used for the remote measurement of trace gases in the atmosphere. It offers the unique ability to rapidly map pollutant concentrations in both two and three dimensions using a single instrument (i.e., laser sounding). A volume of several cubic kilometres surrounding the instrument location can be mapped, and a target plume cross-section can be mapped in minutes. Moreover, DIAL allows emissions to be monitored where physical access is difficult or hazardous, including high elevation plumes, and there is negligible disturbance of the plume by the measurement. DIAL is often used as a research tool to obtain detailed and fast-repeating measurements of important plume quantities, such as plume spread, plume meandering, instant concentration profiles and cross-sections.
DIAL systems are available as a truck mounted mobile laboratory, and have also been installed in aircraft.
DIAL can measure simultaneously in the infrared (IR), visible and ultra-violet (UV) spectral regions and provide real-time data for any gaseous species with characteristic absorption in these spectral regions including: SO2 , NO2 , NO, Ozone, Benzene, Toluene, Xylene and higher aromatics, Alkanes, Alkynes, petroleum and diesel vapours, Hg, HCl, N2O, HF and H2S. Other uses include the measurement of ambient concentrations of aerosols and opacity measurements.
DIAL is an important advance on the more conventional optical line monitoring systems such as differential optical absorption spectroscopy (DOAS) and fourier transform IR (FTIR) spectroscopy in which a retro-reflector, which must be re-positioned after each measurement, is used to return the laser beam to the detector. In these conventional systems an average concentration of the species to be measured is obtained and range resolution is not possible, which is a significant limitation. DIAL also uses a coherent light source to measure not just contents of a direct path or line, but full 3D volumetric data. The downside is that the pulse has to be strong and the receiver large to cover the typical target ranges of several kilometers.
DIAL relies on back-scattered laser light using a general method known as light detection and ranging (LIDAR). LIDAR is like RADAR but instead of microwaves it uses light in the infrared (IR), visible and ultraviolet (UV) ranges. A pulsed laser beam is sent out into the atmosphere and small proportions of the light are backscattered by particles along the beam path to a sensitive detector (or optical telescope). The dust particles and aerosols present in the atmosphere serve as reflectors. The laser light is in short pulses and time resolution of the backscattered light (along with the speed of light) gives range resolution.
DIAL relies on the unique "fingerprint" absorption spectrum of each molecule and measurements are usually made on a single compound at a time. The particle backscatter light is measured for two wavelengths where the target absorbs strongly and weakly, respectively. The selection of more than two wavelengths is a mathematical necessity for simultaneous measurement of multiple species or for resolving interference effects between a target compound and a background gas such as water vapour or carbon dioxide (Weibring et al, 2004). This is especially
2 Final Report true in the mid IR region, where many hydrocarbon compounds have overlapping spectral features.
The concentration of the target substance is determined based on the size of the differential return signal at different distances along the laser beam path. The time history of the return signals provides the range from the transmitter/receiver.
The strength of the signal received by the DIAL system depends on the distribution both of the target gas and of aerosol. These vary depending upon the nature of the source being investigated.
The ability to range resolve DIAL to measure the concentration of gaseous species is determined by both hardware and data processing considerations (Warren, 1989). The latter must perform a number of functions, including signal averaging, transmit energy normalization, plus shape deconvolution (if needed), path-integrated concentration estimation by the familiar log-ratio DIAL algorithm, and, finally, numerical differentiation to produce the concentration estimate and its uncertainty as a function of range. Because raw concentration estimates are intrinsically noisy, the algorithm chosen to perform the differentiation is of critical importance. This is particularly true in a dynamic environment, where only limited pulse averaging can be performed prior to the estimation, either because a large volume must be monitored quickly or because the concentration of the target species changes rapidly.
2.2 Emission Quantification Procedures
The mass emissions of a target substance from a process or fugitive source of interest may be determined by making a series of DIAL scans vertically at a right angle to the wind to locate a the plume and obtain the concentration profile across the plume cross-section, while at the same time measuring local meteorological conditions. Normally wind speed and direction measurements are taken with equipment located on the ground. Some researchers (e.g., Weibring, 1998) have developed a remote sensing technique (wind videography) and combined it with DIAL measurements.
The compiled concentration and wind speed data are combined to produce a mass emission profile for a whole site; for instance, for fugitive emissions from an oil refinery. A representative “upwind” or “clean-air” flux from the recorded downwind data is then subtracted from the results to determine the final emissions rate. If there are no potential sources upwind of the plant being surveyed, it is sufficient to subtract a single clean-air column to allow for system offsets. Otherwise, a further correction can be applied by subtracting a measured upwind flux. In this case, care is needed to ensure that only the relevant portion of the upwind mass flow rate is subtracted.
2.3 Factors Influencing Detection Limits and Accuracy
DIAL is capable of measuring gas concentrations of a few ppm per metre. Thus, the minimum detection limit is several ppm for spacial mapping at a resolution of 1 m. At a coarser resolution of 100 m, the minimum detection limit is on the order of a few tens of ppb.
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A typical DIAL measurement has an accuracy better than 10 percent and <5 mg/m3·m. However, the accuracy is very much determined by the weather conditions and other atmospheric parameters. The determination of emission rates using DIAL is less accurate since uncertainties in wind profiles and source variability are also introduced. For example, Egeback et al (1984) report uncertainties of 30 percent in their results due mainly to uncertainties in the wind velocity determinations.
The following sections delineate some of the key factors that influence DIAL detection limits and the accuracy of emission rate determinations, namely:
• Distance form the source. • Spatial resolution applied. • Interference from other compounds. • Optical noise. • Aerosol or particulate distribution. • Interference from nearby sources. • Data averaging. • Extrapolation of results.
2.3.1 Distance From Source
The plume is usually measured sufficiently far downwind that mixing within it is fairly uniform and recirculation and other wake effects have died away. However, a compromise must be made between accuracy, which improves with distance from the source, and sensitivity which decreases with distance from the source. Walmsley and O’Connor (1998) report that: depending on the compromise, and conditions at the time, the uncertainty in the emission rate measurement may vary from 20 percent or better associated with controlled release experiments in un-congested conditions to a factor of four associated with the use of oversimplified wind data in congested areas. For large emissions (i.e., tens of kg/h and above) it is normally possible to make measurements at the accurate end of this range by measuring at a large distance from the source. For smaller emissions, where measurements must be made relatively close to the source, the achievable accuracy is often less favourable.
2.3.2 Spatial Resolution
The final accuracy of a measurement depends greatly on the number of measurement lines. Walmsley and O’Connor (1998) recommend operating with a 10 m resolution; it is usually best to avoid 2.5 m to reduce noise and 30 m or 100 m because of the poor localization of gas and the inability to recover quickly from disturbances. The latter is important because disturbances due to steam leaks or hard-target returns from pipes, cables, etc. are often unavoidable and recovery takes more than three times the spatial resolution. The extended response to disturbances has usually prevented good quality measurements at 30 or 100 m in plant areas.
2.3.3 Interferences from Other Compounds
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There are significant overlaps in the absorption spectra of the different hydrocarbons that may be detected by DIAL, as well as interference effects from water vapour (Weibring et al., 2004). Such interferences or cross-sensitivities may compromise the accuracy of the measurement results when making measurements on unknown mixtures such as the cocktail of fugitive hydrocarbons from a refinery. Walmsley and O’Connor (1998) have dealt with this by making measurements using the butane absorption coefficient and then correcting the results using the species ratios measured by absorption tubes and gas chromatography together with the absorption coefficients in the DIAL system’s spectral database. For a typical refinery mixture the correction factor for total alkanes relative to a simple as-butane interpolation has been determined to be about ±5 percent.
2.3.4 Optical Noise
The accuracy is greater for a nighttime recording in an atmospherically stable area. At the other extreme, measurements are not at all possible if the visibility is dramatically limited by fog or rain. Increasing the laser pulse power improves the accuracy somewhat and allows the measurement range to be increased.
For a given concentration of gas, the detectable range reportedly improves by more than 50 percent during the night due to the reduction in background optical noise.
2.3.5 Aerosol or Particulate Distribution
The signal received from a DIAL system depends on the distribution both of the target gas and of aerosol. For simplification purposes, it is often assumed that a uniform distribution of ambient aerosol exists. With variable aerosol concentrations resulting in variable backscatter, DIAL will tend to overestimate peak concentrations in the plume (Bennett, 1998).
According to Walmsley and O’Connor (1998), fluctuations in the backscatter coefficients are often the main noise source. These fluctuations are most likely to occur around process units and water treatment areas where steam condensation can produce strong local increases in backscatter well beyond the boundaries of visible steam plumes. Significant local increases in backscatter have also been observed in association with dust from active work areas or roads or squally showers of rain or particularly snow. Conversely, heat inputs from fin-fan coolers or furnaces have sometimes been found to eliminate most of the backscatter, presumably by evaporation of atmospheric aerosols.
Ansmann (1985) reports that great care must be taken in the analysis of H2O DIAL measurements when layers with high aerosol concentration, clouds or strong temperature inversion exist.
2.3.6 Interference from Nearby Sources
Clearly, the more congested an area and the more nearby sources there are, the more difficult it is isolate the emission contributions for a particular source within a facility. This is true for any remote sensing technique.
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For DIAL measurements, the noise on both the clean-air line and the individual measurement lines is an important factor. Since the clean line is subtracted from every measurement line, optimal accuracy is obtained by spending as much measurement time establishing the single clean-air column as is spent in total on all the measurement columns from which it is subtracted (Walmsley and O’Connor, 1998).
2.3.7 Data Averaging
A difficulty with the DIAL technique arises from its sensitivity to noise in the received signals. A DIAL system estimates gas concentrations from subtle variations between shots and as a function of range. DIAL typically requires the averaging of many shots to obtain an acceptable signal to noise ratio. Depending on the desired sensitivity and the range, this may lead to temporal and spatial resolutions of tens of seconds and 50 to 100 m (Bennett, 1998).
The amount of gas can be underestimated when measuring large fluctuating gas concentrations, because of the bias introduced by averaging the raw signals before deriving concentrations. Under practical conditions; however, the degree of underestimation is likely to be small.
2.3.8 Extrapolation of Results
An extrapolation from the measurement results is needed to determine annual emissions. This requirement is not unique to DIAL measurements. Any measurements that are costly or labour-intensive, either to operate equipment or in subsequent analysis, are usually only deployed for short-term measurements, and these are then usually only made during the day. Dry conditions are preferred for some equipment, and most remote sensing techniques require a minimum wind speed to guarantee a well defined plume downwind. All of these factors mean a simple extrapolation on a time basis is subject to considerable uncertainty.
While it is desirable for the measurement to be as accurate as possible (within practicable limits), there is little point in making a highly accurate measurement over a short period, if there are much larger uncertainties regarding the extrapolation to cover all the unmeasured periods (Richardson and Phillips, 2001). These uncertainties arise primarily due to operational factors (change in working practice, changes in equipment, changes in feedstock), and due to the weather (effects of temperature, rain, frost, snow, calm days, and high winds).
According to Richardson and Phillips (2001) there is a tendency to compile inventories without regard for the uncertainty in the estimates, and to set targets for improvement as if it were a simple accounting exercise. Interestingly, their work shows that the nature of uncertainties skews estimates towards under-estimation. The result is that improved methods of estimation often result in higher emission estimates which are unwelcome to all parties involved, especially when money has been invested to meet reduction targets.
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2.4 Applications
The primary applications of DIAL and DIAL in combination with wind profiling (e.g., using SODAR) include the following:
• The monitoring and charting of diffuse and source emissions in industrial areas. • Mapping of hidden sources and estimation of their contribution to the total air pollution over a given area. • Studies of the spreading of gas from a source and its effects on air quality in surrounding areas are also important. • The estimation of fluxes of fugitive emissions. • Detection of plumes and monitoring of their propagation. • Monitoring of pollutant dispersion and distribution above a complex relief and during smog episodes. • Study of the creation and propagation of ozone smog. • Acquisition of the input, calibration and verification data for air pollution modeling. • Remote measurements into inaccessible, hazardous or elevated areas. • Wide area surveys of ambient air quality. • Measurement of total industrial site emissions. • Boundary fence monitoring. • Identification and quantification of leaks, storage losses, and other fugitive and engineered sources of emissions. • Plume tracking and source identification from complex industrial plants. • Environmental impact assessments. • Validation of emission estimates or modeling techniques.
The need for such measurements to control emissions from an industrial area is evident. DIAL is also one of a variety of tools that can be used to screen for significant cost-effective emission control opportunities at facilities, and has, in some cases, resulted in significant savings due to avoid product losses. The technique might also be of use to study the transport of pollutants across the borders. Not least, DIAL is a remote measuring technique for research on air pollution problems.
Fredriksson et al (1979) have used the LIDAR in several studies of particle emissions from industrial smoke stacks. Measurements of relative particle distributions are easy to perform using elastically backscattered light and neglecting weak effects of beam attenuation. If absolute particle loads in stack effluents are to be measured, the LIDAR system should be pointed to the plume as close as possible to the mouth of the stack as possible. This approach avoids both influences due to wind and due to condensing water droplets. Because of the complexity of the Mie scattering theory and the lack of detailed information on particle characteristics, it is normally necessary to provide an in-stack calibration.
2.5 Manufacturers
A few companies, such as ORCA Photonics Systems Inc. (www.orcaphoton.com), Lockheed Martin Coherent Technologies Inc. (http://www.lockheedmartin.com), Optech Inc.
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(www.optech.ca) (a Canadian company), and Elight Laser Systems GmbH (www.elight.de) produce commercial LIDAR systems for aerosol, turbulence, and other measurements. Although experiencing some success, LIDAR systems are not high-volume systems due to their significant cost.
Q-Peak (www.qpeak.com) has been developing frequency-agile laser systems and other components for defense-related LIDAR and DIAL systems.
Additionally, there are companies, including some of those listed above, and others such as Spectrasyne Ltd. (http://www.spectrasyne.ltd.uk/) and the UK’s National Physics Laboratory (NPL) (http://www.npl.co.uk/), that offer commercial DIAL services.
2.6 Advantages, Disadvantages and Limitiation
The key advantages of DIAL are as follows:
• True remote sensing up to 1 kilometre or more. • Can target specific chemicals, as well as be used in a more "open" mode much like a point source organic vapor analyzer. In the open mode a chemical family such as alkanes is measured by picking a band that is common to many and interpreting the results as an "average." • Rapid scanning and two- and three-dimensional mapping of emissions in near real time allowing emissions and their atmospheric dispersion to be tracked over time. • Able to measure the emissions from very elevated sources and very complex sources. • Able to detect hidden sources and emission hot spots. With traditional fenceline monitoring techniques it is possible that a toxic release plume could pass around, over, or below the monitors without being fully detected.
The main disadvantages or constraints are as follows:
• Significant expense for instrument costs and staff (e.g., the price is approximately $15K+ per day and it normally takes about two weeks to complete a survey of mid to large sized sites). • Large size and weight (truck mounted mobile laboratory). • It requires experts to run the system and interpret the data. • Considerable data processing. • Susceptible to interferences. • Requires good downwind access. • Constrained by meteorological conditions which could result in standby charges if these conditions are not appropriate at the time of the survey (all remote monitoring methods have this same limitation). • While DIAL can provide quantification of total emissions, its ability to identify hidden sources and emission hot spots is more of a coarse screening capability due to its inability to access congested areas or go inside buildings. For example, knowing that a large process building or a congested area of a plant contributes a significant amount of emissions is not the same as knowing exactly which source or sources in these areas are causing the emissions and need to be controlled. Qualitative methods such as handheld IR cameras and traditional leak survey methods offer a more practicable and affordable approach for pinpointing
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emission control opportunities in these situations; but lack the ability to quantify the emissions (e.g., as may be needed to justify control expenditures). • Not suitable for continuous monitoring. • The process of reviewing data to assure it meets quality assurance standards can be burdensome. • While DIAL’s ability to both identify and quantify emissions has many useful benefits compared to purely qualitative detection methods; this comes at a financial cost. At the operations and maintenance level, the quantification of emissions is only necessary where the practicability or need for emissions control is in question. For example, most facilities would prefer to simply repair any detected leaks rather than go to the added cost of quantifying the leak rate before making the repairs.
Because of the unique information that is expected to be acquired by the DIAL system, the question of its accuracy and compatibility with air quality monitoring reference methods is of great importance (Keder et al., 2004).
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3.0 EXPERIENCES WITH DIAL
The general experience reported in the literature from the application of DIAL technology to quantify atmospheric emissions at petroleum refineries has been that, despite some limitations, DIAL is able to accurately quantify the amount of VOC emissions occurring at the time of measurement. The results have shown that potentially significant unaccounted for contributions may occur at some facilities. DIAL has proven effective in quantifying hidden or missed sources as well as sources and controls with deteriorated performance. Fugitive equipment leaks and evaporation losses from product storage, loading and unloading are typically determined to be the major sources of VOC emissions at petroleum facilities.
Recognition that current policies and targets governing the management of VOC emissions are being understated by inventorying and environmental reporting initiatives is driving increasing emphasis on measurement and improved estimation of these emissions. For example, data from the Texas Air Quality Study (TexAQS) 2000 suggest that the VOC emissions inventory for Texas is low by a factor of 3 to 10 (D. Allent – University of Texas). Tropospheric ozone reduction strategies, in particular, require good VOC emissions data.
With a few exceptions, DIAL systems have been seen largely as a research tool and less as a regular monitoring technique due to their significant costs. While DIAL is but one of a variety of techniques that may be used to develop quantitative measurements of VOC emissions from fugitive and process sources at petroleum refineries, it remains one of the most powerful options available. Increasing demand will only improve its affordability.
The following sections summarize some of the specific experiences with the use of DIAL in the different countries in which it has been applied.
3.1 Belgium
In the late 1990’s all refineries in Flanders, Belgium reported emissions of 13,000 tonnes per year. A DIAL analysis on 2 refineries (about 10 percent of throughput of the total), found emissions of 16,000 tonnes per year.
3.2 Canada
The most recent DIAL work done in Canada was conducted by Spectrasyne in cooperation with Alberta Research Council. This work involved the measurement of fugitive emissions from several gas processing plants in Alberta during 2003 and 2004 (Chambers, 2003; Chambers, 2004), and from a petroleum refinery in 2005 (Chambers and Strosher, 2006).
The basic objective of these studies was to use the DIAL method to measure the mass emissions of methane, C hydrocarbons and benzene, apportion the measured fugitive emissions to various 2+ areas of the plants, and compare the DIAL measured rate of fugitive emissions with the emission rates calculated using estimation methods.
At the refinery, measurements of SO2 from a tail gas incinerator and NO emissions from a gas turbine power plant where also performed and compared to the corresponding measurements
10 Final Report performed using the DIAL system with differences of only -11 and +1 percent respectively. However, no verification measurements were performed on fugitive sources; consequently, it is not clear that the DIAL’s performance would be as good on these more difficult sources. Ideally, such checks on fugitive emission sources should involve the quantification, by DIAL, of know releases of tracer gas in realistic fugitive emission scenarios.
The DIAL survey at the refinery was performed over a period of ten survey days. The results were extrapolated, with some assumptions, to develop estimates of total annual emissions of C2+ hydrocarbons and were compared to VOC estimates reported by the facility to Environment Canada’s National Pollutant Release Inventory (NPRI). The authors noted that VOCs exclude ethane but felt that C2+ was still a reasonable proxy for VOCs. There were no significant upsets in the plant operation or hydrocarbon spills during the survey.
The extrapolated DIAL measurement results indicated that the value of product lost due to storage tank and process plant fugitive emissions was 15 fold greater than that determined by the emissions estimation procedures. While this finding is consistent with the general finding noted by other researchers that emission inventory methods tend to understate actual emissions due to a common assumption of no deteriorated performance of sources and emission controls, it is not a completely fair comparison. Most emission estimation methods, such as the use of emission factors, have a statistical basis and are recognized as having large uncertainties when applied to relatively small numbers of sources or used to estimate instantaneous emissions. Still, the observed differences are noteworthy.
3.3 Czech Republic
An extensive field measurement campaign was performed by Keder et al (2004) in the Czech Republic in the summer of 2001 in which ozone was measured by DIAL, aircraft and ground monitoring stations simultaneously. Good agreement was obtained between the DIAL results and an analyzer located near the ground. However, the comparison with the other results was less favourable. Accordingly, Keder et al recommended that a substantial effort should be focused on the explanation of causes of discrepancies between the concentration measurement results from DIAL and the results from the other analyzers.
The application of combined DIAL/SODAR techniques was demonstrated in the following cases:
• Mapping of hidden sources and estimation of their contribution to the total air pollution over a given area. • Monitoring of distribution and propagation of atmospheric pollution emitted from line sources. • Detection of plumes and monitoring of their propagation. • Monitoring of pollutant dispersion and distribution above a complex relief and during smog episodes. • Study of the creation and propagation of ozone smog. • Acquisition of the input, calibration and verification data for air pollution modeling.
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3.4 European Commission
In 2004 the European Commission funded a project entitled Remote Optical Sensing Evaluation (ROSE) aimed at developing an improved understanding of the factors affecting the validity of measurements made using remote optical sensing techniques (ROMTs). The project took place as part of the Fifth Framework scheme and brought together eleven organizations from all over Europe, and representing a wide range of expertise. The lead member of the consortium was Sira Ltd from the UK.
The project began with a field measurement campaign conducted under genuine measurement conditions at locations across Europe using a variety of open-path techniques including DIAL. The team then moved on to a series of controlled tests, both laboratory-based and using a specially-constructed test facility, the design of which was based on the experience gained during the field test campaigns.
The experiences of the consortium members both inside and outside the project were presented in two public documents (Sira Ltd, 2004a,b): (1) Recommendations for Best Practice in the Use of Open-Path Instrumentation and (2) Recommendations for Performance Standards for Open- Path Instrumentation.
While much of the information presented in these two documents pertained to optical techniques other than DIAL, the following two relevant points were made:
• Experimental work during the field trials could be constrained by security and access issues to the detriment of the ideal operation of the ROMTs. The instruments might be capable of higher level performance, lower detection limits or greater sensitivity if it was possible to set up equipment in the best locations and at optimum path lengths for the trials. This is an important consideration for ROMT use.
• DIAL validation is difficult as there are no other measurement techniques which can measure, range resolved concentrations along a line, 2D concentration profiles or mass emissions. In most cases correlations have been with only one facet of the DIAL capability, e.g. concentration measured along a path with sorption tubes compared with a single line range resolved DIAL concentration measurement.
In July of 2006 the Eurpoean Commission published a reference document on best available techniques for the monitoring and control of emissions from storage tanks. The document noted that atmospheric emissions from storage tanks and loading/unloading operations (e.g., at refineries and oil terminals) are normally determined by calculation methodologies published by API, US EPA and CEFIC/EVCM (European Council of Vinyl Manufacturers). At sites where significant VOC emissions are to be expected, it was stated that BAT includes calculating the VOC emissions regularly. Because of uncertainties in the models it was suggested that storage losses at these facilities may occasionally need to be monitored to quantify the emissions and to give basic data for refining the calculation methods. It was further suggested that this could be done using DIAL techniques, but the necessity and frequency of emission monitoring should to be decided on a case-by-case basis. Notwithstanding this, no consensus could be achieved on how to monitor VOC emissions and how to validate calculation results. DIAL is used commonly in Sweden for monitoring emissions from tanks storing hydrocarbon products at refineries and oil terminals, but there is not enough information on the use of DIAL at other sites and in
12 Final Report other countries. Accordingly, it was recommended that more information be collected on the monitoring of VOC emissions from storage tanks.
3.5 Germany
Germany is the only European country that currently has any formal standards pertaining to the application of DIAL. These and other related standards are listed below:
• VDI 4202 Part 1 Minimum requirements for suitability tests of automated ambient air quality measuring systems - Point-related measurement methods of gaseous and particulate pollutants. • VDI 4202 Part 2 (2004) Minimum requirements for suitability tests of ambient air quality measuring systems - Optical remote sensing systems for the measurement of gaseous pollutants. • VDI 4203 Part 4 Control planning for automatic measurement equipment proving procedures for remote optical measurement equipment for measurement of gaseous emissions. • VDI 4210 Part 1 (1999) Remote sensing. Atmospheric measurements with LIDAR. Measuring gaseous air pollution with DAS LIDAR. • VDI 4280 Part 1 (1996) Planning of ambient air quality measurements: General rules.
Copies of the above standards could not be obtained for examination within the time available for this literature review; however, according to Sira Ltd (2004a), VDI 4210 covers the principles of the LIDAR method, characterization of performance, a little about the design, planning and execution of measurements, calibration, and evaluation of both data and system performance. Appendix B of the standard gives a variety of examples of the use of DAS-LIDAR (also known as DIAL-LIDAR) in various applications.
VDI 4280 covers what you must know in advance about the measurements you are going to make and the capabilities of the personnel involved. There is comprehensive coverage of the factors which must be considered, and the catalogue of questions in Appendix A makes a good checklist for anyone contemplating a measurement campaign of this kind.
3.6 Sweden
Sweden has the most experience using DIAL to measure refinery emissions. A Swedish national mobile LIDAR system was developed in 1979 at the Chalmers University. The construction was based on the results and experiences from research and previous LIDAR systems. Work has also been done in Sweden by several mobile LIDAR systems constructed by other research groups (i.e., The Stanford Research Institute, the research institute of ENEL in Italy, and the National Physical Laboratory in England).
Sweden has required remote sensing at refineries since the late 1980’s. Initially they also tried differential optical absorption spectroscopy (DOAS) and other single-beam techniques, but by 1995/6 all refineries were required to use DIAL. DIAL measurements are currently performed every 2 to 3 years. Table 1 summarizes some of the available DIAL measurement results for petroleum refineries in Sweden.
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Notes Table 1. A summary of DIAL measurement results at petroleum refineries in Sweden. Company Location Contractor Year Estimated % Annual Emitted/Rated Emissions1 Capacity (t/y) AB Nynas Gothenburg Spectrasyne 1999 82.5 0.129 AB Nynas Gothenburg Spectrasyne 1995 120 0.188 Preem Gothenburg Spectrasyne 1999 268 0.050 OK (Preem) Gothenburg Spectrasyne 1995 274 0.051 OK (Preem) Gothenburg Spectrasyne 1992 317.4 0.059 BP (Preem) Gothenburg BP 1989 840 0.155 Research BP (Preem) Gothenburg BP 1988 990 0.183 Research Shell Gothenburg Shell 1999 157 0.0380 Global Solutions Shell Gothenburg Shell 1996 167 0.040 Global Solutions Scanraff Brofjorden- Spectrasyne 1999 503 0.049392548 Lysekil Scanraff Brofjorden- Spectrasyne 1995 332 0.030999619 Lysekil Scanraff Brofjorden- Spectrasyne 1992 691 0.0677672 Lysekil S11 Source: Barrefors, G. (2003) and a PowerPoint presentation by A. Cuclis and D. Byun from the University of Houston. 1 Based on extrapolations from DIAL measurements.
3.7 The European Union Network for the Implementation and Enforcement of Environment Law (IMPEL)
In 2000, IMPEL, the environmental inspectors network for the European Union (EU) commissioned a project to review diffuse VOC emissions estimation methods and measures in the EU and to propose guidelines to improve the monitoring, licensing and inspection of industrial activities.
The project focused on the VOC emissions of diffuse sources of large process installations (primarily refineries and petro-chemical plants), and considered both fugitive emissions (leakage from equipment) and emissions from storage tanks, loading and unloading facilities. Emissions resulting from the use of solvents and from petrol filling stations were excluded as they were already regulated by existing directives.
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At the time it was determined that specific standards for process equipment with respect to diffuse VOC emissions did not exist; although, a few general guidance documents such as the German TA-Luft & VDI-3479/3790 and the British ETBPP documents existed.
The study made a number of general recommendations regarding emission targets, control requirements, emissions monitoring and reporting and non-compliance actions. It was further recommended that the IMPEL set up an EU-wide information exchange programme on the licensing and enforcement practice in relation to diffuse VOC emissions. Such a programme could include a bench marking on subjects like estimation methods and measures.
It was also suggested that supporting activities may be considered by the authorities, such as:
• organizing an information and training programme in regions where the subject is relatively new (targeting both companies and licensing & enforcing bodies), • establishing national guidelines, • performing an eco-audits of the industrial plants, • establishing a helpdesk to assist both companies and licensing and enforcing bodies .
While the study examined the merits of DIAL and other measurement technologies, it did not present any specific recommendations on a preferred method.
3.8 United Kingdom
There have been three mobile DIAL systems in the UK. Spectrasyne, a private company formed by a management buyout from British Petroleum operates the only commercially available DIAL system in the UK. Much of their work is described throughout this report.
For many years (beginning in 1995) Shell Research operated a one-third share of an infrared DIAL system along with SESL (Siemens Environmental Systems Ltd.) and BG (Walmsley and O’Connor, 1998; Richardson and Phillips, 2001). That system was built by SESL and NPL (the UK National Physics Laboratory) using technology developed by NPL. It could measure concentrations well below 1 ppm at ranges up to 1 km. Shell used the system to measure the emissions of methane, ethane, and heavier alkanes from a range of their petroleum industry sites; both as a research tool and in locations where DIAL is preferred by the regulators (e.g. at oil refineries and the harbour in Gothenburg, Sweden). However, it is understood that Shell, along with SESL, have since discontinued their involvement in this technology due to the limited market and regulatory demand.
Some of the work and noteworthy findings published by Shell regarding DIAL and its application at petroleum facilities are as follows:
• Walmsley and O’Connor (1998) recommended that future tests with more comprehensive sets of anemometry (e.g., SODAR) be conducted to define the errors incurred by the use of relatively limited wind data sets. • The National Physical Laboratory (NPL), the European oil company’s organization for environment, health, and safety (CONCAWE), and Shell, all performed studies of emissions from storage tanks using the DIAL technique (Richardson and Phillips, 2001;
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CONCAWE, 1995). One of the major conclusions from that work was that the API models for estimating annual VOC emissions from storage tanks are appropriate for tanks in first class condition, but do not allow for the increased emissions from tanks in poor condition. According to Richards and Phillips (2001), it was rather like assuming emissions from private cars could be based on the assumption that they were all brand new and running to specification. The few worst tanks account for a major proportion of the emissions. On a broader scale, Richards and Phillips also note that improved estimation and the discovery of overlooked sources can result in upward revision of the emission estimates, and they go on to state that this is both awkward to explain to the public at large, and hides the real improvements that will normally have taken place. • Shell’s study of floating roof storage tanks also showed that the emission flux varied with the position of the roof in the tank. This behavior was also noted by CONCAWE (1995). The greatest flux occurred when the tank was full and the roof was high relative to the walls of the tank. When the tank was half full, a recirculation air pattern formed within the tank that tended to keep the hydrocarbon escape rate down. O'Conner et al (1998) concluded that the model being used to predict fugitive emission flux from tank farms might underestimate the actual amount escaping. In another project conducted by Shell, the DIAL system was used to monitor the emissions from numerous tank facilities located at a port. The DIAL was able to image the emissions from these facilities and provided overall flux estimates. The study identified a small number of tanks that were responsible for a majority of the emissions. • Richardson and Phillips (2001) report, based on their experiences in locating and quantifying emission sources at petrochemical plants, that conventional open-path measurement techniques give large coverage at a more modest cost than DIAL, and are more readily shipped around the world. They suggest using upwind/dowind monitoring combined with dispersion modeling to back-calculate the source strength. However, they go on to point out that the difficulty with such methods for source location and emission rate estimation is in measuring or modeling the vertical extent of the plume, especially for process plants where there may be a large heat input leading to complicated heat island effects, and especially under low wind conditions. The actual accuracy of the emission estimate will depend on a variety of factors including the reliability of the dispersion modelling, the quality of the measurements performed, the detection limits achieved, the representativeness of the compiled data, meteorological conditions, background noise and interferences. Accordingly, the true accuracy is never really known unless appropriate confirmation measurements are performed which may be difficult and costly to do on large, complex sources.
3.9 United States
Most of the work in the US with LIDAR has been done for, or by, the US Department of Defense. However, Active Imaging Solutions of ITT Industries Space Systems Division has developed a commercial airborne DIAL system for detection and measurement of fugitive emissions at oil and gas facilities (Brake, 2005). This system provides 2-dimension concentration profiles of the emissions from a facility when looking down on the facility from an aerial position, but does not provide quantification of emission rates. Demonstrations have been conducted on tank batteries and a gathering pipeline segment being repaired with gas release
16 Final Report rates as low as 0.6 m3 per minute being readily detected. It is claimed that the system can survey up to 1600 km of pipeline per day and can operate day or night.
Additionally, US EPA (2006) recently developed a protocol for characterizing gaseous emissions from non-point pollutant sources. The protocol is specific to the use of open-path, Path- Integrated Optical Remote Sensing (PI-ORS) systems in multiple beam configurations to directly identify “hot spots” and measure emission fluxes. PI-ORS systems include scanning open-path FTIR, UV-DOAS, TDLAS, and PI-DIAL, The choice of PI-ORS system to be used for the collection of measurement data (and subsequent calculation of PIC) is left to the discretion of the user. Basic user knowledge of a PI-ORS system and the ability to obtain quality path-integrated concentration (PIC) data is assumed.
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4.0 CONCLUSIONS AND RECOMMENDATIONS
The conclusions and recommendations of this study are presented in the following subsections:
4.1 Conclusions
The DIAL technology is unique in its ability to rapidly develop near real-time two- and three- dimensional mapping of the atmospheric emissions plume from point, line and complex area or volume sources. Subject to proper quality control/quality assurance (QA/QC) measures, suitable meteorological conditions and downwind access, DIAL can provide quite accurate quantification of emission rates and provide coarse screening for hidden sources and emission hot spots. Moreover, it is an invaluable research tool for developing an improved understanding of fugitive and other complex emission sources, and of the atmospheric dispersion of these emissions.
Its significant cost is the primary reason DIAL has not seen widespread use as a frequent monitoring technology for use at industrial facilities. Even in Sweden where refineries are required to conduct regular DIAL surveys, these surveys are only conducted for typically a two week period once every two to three years. Still, as the technology gains increasing acceptance and demand, costs are likely to decrease making it a more practicable choice.
The validity of taking snapshot emission measurement results from a DIAL survey and extrapolating them to determine annual emissions is a potential issue that requires careful consideration of the characteristics of the sources being considered and the operating conditions at the time. However, there are really no low-cost approaches that can be used to accurately quantify total VOC emissions from a single facility or process area except for point sources with continuous emission monitoring systems in place. Traditional inventory estimation methods remain the most practical means of developing emission estimates for regional or national issues. Although, the current literature indicates that these inventory methods may often introduce a significant negative bias due to inadequate consideration of the deteriorated performance of emission sources and controls with time. Furthermore, indications are that the unaccounted for emissions from such effects are not normally distributed. Rather, they are characterized by more of a skewed distribution where only a few sources in each category are contributing most of the unaccounted emissions at a facility, and only a few facilities are contributing most of the unaccounted for emissions by the industry.
A quantitative measurement approach is really the only option for developing an accurate assessment of an individual facility’s total VOC emissions, identifying the primary sources of these emissions and potential emission reduction opportunities (e.g., to address local air emission issues). DIAL is one of various measurement options that could be considered, each having its own advantages and disadvantages. The best option should be determined on a case-by-case basis giving consideration to the accuracy of the emission estimates needed to facilitate sound decisions in the final environmental analysis to be performed. The uncertainty contributions of all elements of the analysis should be considered, not just those of the emission estimates, and a practicable approach taken in managing these uncertainties.
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4.2 Recommendations
Clear guidelines should be established that set out specific accuracy targets for the various emission reporting requirements imposed on industry. These targets should be science-based values that consider potential local, regional and national environmental decision-making needs, and reflect a practicable approach to managing the uncertainty in the final environmental analyses to be preformed using the emissions data. These targets may be different for different pollutants. Alternatively, approved technologies or estimation methods should be identified, which, when applied in accordance with good practice, may be deemed to comply with such objectives. At a minimum, current VOC inventorying methods, guidelines and emission factors should be reviewed to identify opportunities for improvements.
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5.0 REFERENCES CITED
Ansmann, A. 1985. Errors in Ground-Based Water-Vapor DIAL Measurements Due to Doppler- Broadened Rayleigh Backscattering. Applied Optics. v 24, n 21. November 1985. pp. 3476- 3480(5).
Barrefors, G. 2003. Fugitive VOC-emissions Measured at Oil Refineries in the Province of Vastra Gotaland in South West Sweden (Development and Results 1986 to 2001). A report commissioned by The Count Administration of Vastra Gotaland, Sweden. .pp 30.
Bennett, M. 1998. The Effect of Plume Intermittnecy Upon Differential Absorption LIDAR Measurements. Atmospheric Environment. v 32, n 15. pp. 2423-2427.
Brake, D. 2005. Detection and Measurement of Fugitive Emissions Using Differential Absorption Lidar (DIAL). A presentation made by Active Imaging Solutions of ITT Industries Space Systems Division at the EPA Gas STAR Program – Annual Implementation Workshop, 25 October 2005.
Chambers, A.K. 2003. Well Test Flare Plume Monitoring Phase II: DIAL Testing in Alberta. ARC Contract Report No. CEM 7454-2003, December, 2003. (available at www.ptac.org/env/dl/envp0402fr.pdf ).
Chambers, A.K. 2004. Optical Measurement Technology for Fugitive Emissions from Upstream Oil and Gas Facilities. ARC Contract Report No. CEM – P004.03, December, 2004. (available at www.ptac.org/env/dl/envp0403.pdf ).
Chambers, A.K., and M. Strosher. 2006. Refinery Demonstration of Optical Technologies for Measurement of Fugitive Emissions and for Leak Detection. A report prepared by Alberta Research Council for Environment Canada. .pp 43.
CONCAWE. 1995. VOC Emissions from External Floating Roof Tanks: Comparison of Remote Measurements by Laser with Calculation Methods. Prepared for the CONCAWE Air Quality Management Group, based on work performed by the Special Task Force on DIAL measurement of gasoline tanks (AQ/STF-44). Report No. 95/52. .pp 70. (www.concawe.org/1/MAJDFIPABLJPHMMLHJHILPDIVEVC7191P3PDBK9DW3GK9DW3 571KM/CEnet/docs/DLS/Rpt_95-52-2004-01744-01-E.pdf)
Egeback, A., K.A. Fredriksson, and H.M. Hertz. 1984. DIAL Techniques for the Control of Sulfur Dioxide Emissions. Applied Optics. v 23, n 5. March 1984. pp. 722-729(8).
European Commission. 2006. Reference Document on Best Available Techniques on Emissions from Storage. A report on an information exchange carried out under Article 16(2) of Council Directive 96/61/EC (IPPC Directive). .pp 432. (http://www.jrc.es/pub/english.cgi/d1254315/)
Fredriksson, K., B. Galle, K. Nystroem, and S. Svanberg. 1979. LIDAR System Applied in Atmospheric Pollution Monitoring. Applied Optics. v 18, n 17. September 1979. pp. 2998- 3003(6).
20 Final Report
IMPEL. 2000. Diffuse VOC Emissions: Emission Estimation Methods, Emission Reduction Measures and Licensing and Enforcement Practice. A report prepared by Tebodin assisted by Schelde Leak Repairs Specam and Cowi. Brussles. .pp 124.
Keder, J., M. Strizik, P. Berger, A. Cerny, P. Engst, and I. Nemcova. 2004. Remote Sensing Detection of Atmospheric Pollutants by Differential Absorption LIDAR 510M/SODAR PA2 Mobile System. Meteorology and Atmospheric Physics. v 85, n 1-3. January 2004. pp. 155- 164(10).
Lamb, B., J.B. McManus, J.H. Shorter, C.E. Kolb, B. Mosher, R.C. Harriss, E. Allwine, D. Blaha, T. Howard, A. Guenther, R.A. Lott, R. Siverson, H. Westberg, and P. Zimmerman. 1994. Measurement of Methane Emissions from Natural Gas Systems Using Atmospheric Tracer Methods. Presented at the 1994 International Workshop on Environmental and Economic Impacts of Natural Gas Losses, March 22-24, 1996, Prague, Czech Republic. pp. 26.
Minnich, T.R., R.J. Krocks, P.J. Solinski, D.E. Pescatore, and M.R. Leo. 1991. Determination of Site-Specific Vertical Dispersion Coefficients In Support of Air Monitoring at Lipari Landfill. A paper presented at the 1991 AWMA/EPA International Symposium on the Measurement of Toxic and Related Air Pollutants, Durham, NC, May 1991. .pp 8.
O’Connor, S., H. Walmsley, and H. Pasley. 1998. Differential absorption LIDAR (DIAL) measurements of the mechanisms of volatile organic compound loss from external floating roofed tanks. EUROPTO Conference on Spectroscopic Atmospheric Environmental Monitoring Techniques, Barcelona, Spain, SPIE Vol. 3493. [abstract]
Piccot, S.D., S.S. Masemore, W. Lewis-Bevan, E.S. Ringier, and B.D. Harris. 1996. Field Assessment of a New Method for Estimating Emission Rates from Volume Sources Using Open- Path FTIR Spectroscopy. J. Air & Waste Manage. Assoc. v46 .pp 159-171.
Richardson, S.A., and V.R. Phillips. 2001. A Comparison of Petrochemical and Agricultural Approaches to Emission Inventorisation and Uncertainties. Report No. OG.01.47049R . A report prepared by Shell Global Solutions. Chester, England. OG.01.47049R
Sira Ltd. 2004a. Recommendations for Best Practice in the Use of Open-path Instrumentation - A Review of Best Practice Based on the Project: Remote Optical Sensing Evaluation (ROSE) August 2001-July 2004. A report prepared for the European Commission by the ROSE Consortium. Contract No. G6RD-CT2000-00434. .pp 131.
Sira Ltd. 2004b. Recommendations for Performance Standards for Open-path Instrumentation – Recommendations Generated Based on the Project: Remote Optical Sensing Evaluation (ROSE) August 2001-July 2004. A report prepared for the European Commission by the ROSE Consortium. Contract No. G6RD-CT2000-00434. .pp 174.
US Environmental Protection Agency. 2006. Final ORS Protocol: Optical Remote Sensing for Emission Characterization from Non-Point Sources. .pp 44. (www.epa.gov/ttn/emc/prelim/otm10.pdf).
21 Final Report
Walmsley, H.L. and S.J. O’Connor. 1998. The Accuracy and Sensitivity of Infrared Differential Absorption LIDAR Measurements of Hydrocarbon Emissions from Process Units. Pure Appl. Opt. v 7. pp. 907-925(19).
Warren, R.E. 1989. Concentration Estimation From Differential Absorption LIDAR Using Nonstationary Wiener Filtering. Applied Optics. v 28, n 23. December 1989. pp. 5047-5051(5).
Weibring, P., C. Abrahamsson, M. Sjoholm, J.N. Smith, H. Edner and S. Svanberg. 2004. Multi- component Chemical Analysis of Gas Mixtures Using a Continuously Tuneable LIDAR System. Applied Physics B. v 79, n 4. September 2004. pp. 525-530(6).
Weibring, P., M. Andersson, H. Edner, and S. Svanberg. 1998 Combination of lidar and Plume Velocity Measurements for Remote Sensing of Industrial Emissions. Department of Physics, Lund Institute of Technology, Sweden, SPIE vol. 3104, 0277-786X/97
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This page intentionally left blank. VOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCVOCV measured atOilRefineries in theProvinceofVästraGötalandSouthWest Sweden Fugitive VOC-emissions commissioned byTheCountyAdministrationofVästraGötaland development andresults1986–2001 - a successstory County Administration Report 2003:56 Fugitive VOC-emissions measured at Oil Refineries in the Province of Västra Götaland in South West Sweden - a success story
development and results 1986 – 2001 commissioned by The County Administration of Västra Götaland
County Administration Report 2003:56 PRODUCTION | THE COUNTY ADMINISTRATION OF VÄSTRA GÖTALAND TEXT | LENNART FRISCH, AGENDA ENVIRO AB LAYOUT | CILLA ODENMAN PUBLICATION | 2003:56 ISSN | 1403-168X PRINT | GÖTEBORGS LÄNSTRYCKERI AB PREFACE This report describes the environmental trends that have been on the agenda of the Swedish oil refineries in recent years, specifically focusing on emissions of Volatile Or ganic Compounds (VOC). In the case of oil refineries this is more or less also synony mous with hydrocarbons and in most cases VOC is synonymous with NMVOC (Non methane VOC). If methane is included this is clearly stated in the report. The issue of VOC-emissions has been high on the agenda for the Swedish oil refi neries since the mid 1980’s, when the first major discussions started on how to carry out measurements at the sites. Later the issue also has been raised for, among others, oil harbours and other main tank storage areas. The total crude oil throughput of the Swedish oil refi ning sites is about 20 million ton per year. Today we have more than 15 years of measurement experience with the laser based DIAL-system (Differential Absorption Lidar). The system has been shown to be a very powerful tool in the measurement, as well in the combat, of the true VOC-emission. Other systems have also been tested (DOAS, HAWK) but have been shown to be non- reliable in performance. This report is written by Lennart Frisch, MD at the environmental consulting bureau Agenda Enviro AB, and is commissioned by the County Administration of Västra Götaland (former the Provincial Government of Göteborg and Bohus) and the Swedish Environmental Protection Agency. The Author is fully responsible for the content in the report.
Gunnar Barrefors, Department of environmental protection County administration of Västra Götalands län
About the author: Lennart Frisch, MSc. and certified environmental lead auditor according to ISO 19 011, is the managing director of the environmental consultancy bureau Agenda Enviro AB, www.agendaenviro.se
Between 1981 – 1986 he was process engineer and head of computer systems at the Shell Refinery in Göteborg, later environmental officer at the regional autho rities of the Province of Göteborg and Bohus, and since 1996 an environmental consultant for mainly industrial clients but also for the Swedish environmental ministry, the Swedish EPA as well as regional and local environmental authori ties. He has amongst others been Swedish representative at the EU-commission network IMPEL (Implementation and enforcement of environmental law) and the Article 19 committee of EMAS at the EU-commission. He has been a multi- annual member of the Swedish EPA advisory board on implementation and en forcement of environmental law and of the Swedish EPA scientifi c committee on air quality and emissions to air. CONTENTS
1. SHORT HISTORICAL BACKGROUND 7
2. SHORT-CUT INFORMATION ON THE SITES FOR OFFICIAL DIAL-MEASUREMENTS 9 2.1 Preem Raffinaderi AB, Göteborg 9 2.1 Skandinaviska Raffinaderi AB, Scanraff, Lysekil 9 2.3 Shell Raffinaderi AB, Göteborg 9 2.4 Nynäs AB, Göteborg 10 2.5 Nynäs AB, Nynäshamn 10 2.6 Gothenburg Port, Oil Harbour, Göteborg 10
3. INITIAL MEASUREMENTS 12
4. MEASURES UNDERTAKEN TO REDUCE EMISSIONS 14 4.1 Preem Raffinaderi AB, Göteborg 14 4.2 Skandinaviska Raffinaderi AB, Scanraff, Lysekil 15 4.3 Nynäs AB, Göteborg 17
5. DESIGNING A MEASUREMENT SURVEY 18 5.1 VOC’s to be included 18 5.2 Meteorological measurements 20 5.3 Measurement strategy 20
6. MEASUREMENT RESULTS 25 6.1 State of the art methodology 25 6.2 Presented data 26 6.3 Preem Raffinaderi AB, Göteborg 28 6.4 Skandinaviska Raffinaderi AB, Scanraff, Lysekil 28 SHORT HISTORICAL BACKGROUND
1. SHORT HISTORICAL BACKGROUND
In Sweden there are three fuel producing oil refineries. On top of that there are also oil refi ning facilities for other products like bitumen and lube oil. Out of the total of five oil refineries in Sweden four lie in the Province of Västra Götaland and out of these, three are situated in the town of Göteborg (Gothenburg), the Capital of the Province and the second biggest town of Sweden. The fourth refi nery in the province - with the highest capacity - is situated in the municipality of Lysekil some 100 km north of Göteborg. The fifth oil refinery is mainly producing lube oil and is situated in Nynäshamn, some 100 km south of Stockholm. Crude oil and the products received when processing it are also handled at a number of Oil Harbours along the Swedish coast. The largest facilities for this are the Gothenburg Port and the oil harbour at the Scanraff oil refi nery in Lysekil. The fi rst refinery in the area, the Koppartrans refinery, later bought by Shell, was on stream in 1953. Originally this plant was planned and designed for China, but with the changing political realities at that time, the facilities were redirected to Sweden and Göteborg. Prior to that the Nynäs oil refinery in Nynäshamn had already opened in 1928, at that time also being a fuel producing refinery. The second Nynäs-refi nery, was opened in Göteborg in 1956 aiming at a production of mainly bitumen. In the mid 1960’s the Shell refinery was revamped doubling its capacity and in 1967 BP got its own refinery on stream (later sold to OK Petroleum and later renamed Preem). Until the beginning of the 1970’s there were no refineries in the province having other than low skimming facilities. In 1972 Shell installed a thermal cracker unit and 1975 the Scanraff facilities in Lysekil came on stream with about the same production outline as the Shell refinery, but with significant higher capacity (7 Mton/a). In 1984 the Scanraff refinery was extended with a catalytic cracker unit. Scanraff is also today within the Preem Group. At the beginning of the 1970’s there were plans for major extensions of the Shell and BP refineries (up to 13 and 15 Mton/a respectively). These plans were however subsequently turned down because of the energy crisis in 1973/74 as well as the startup of Scanraff. There were also plans for a second refinery, “Statsraff” close to Scanraff. These plans were also never fulfi lled. Environmental issues were not really on the refinery agenda in the beginning, alt hough equipment for the removal and recovery of sulphur in process streams - such as Claus-units - were installed all over during the 1960’s and 1970’s. The function of these units in the BP and Shell case though left some doubt, leaving BP to slaughter the old Claus-units, installing a new (smaller) one in the early 1980’s and Shell revamping its units also in the 1980’s. The turning time in environmental thinking at the refineries came during the second half of the 1980’s with some court cases on sulphur emissions. This lead to a subsequent change of policy at the oil refineries towards an environmental image. After substantially reducing overall emissions in the late 1980’s advanced facilities for sulphur removal - tail gas treating units - were installed at both the Shell and Scanraff refi neries in 1993/4 and soon after that also at Preem. Scanraff also reduced the use of oil as internal fuel early on so that the entire refinery - with the exception of the FCC-unit using coke – was normally fi red on gas only.
7 SHORT HISTORICAL BACKGROUND
In the beginning of the 1990’s low NOx-burners were introduced at the refi neries, starting with some mixed experience. Clearly though that introduction, as well as the increased knowledge in the control rooms of the impact of firing conditions to the creation of NOx-emissions, also reduced NOx -emissions substantially although it has been difficult to describe exactly how much as historically NOx never was measured. Later also SCR-units, beginning with the FCC at Scanraff, were installed, today also being used for boilers at the Shell and Preem refi neries. Emissions of volatile organic compounds (VOC) historically were only roughly calcu lated either as a figure based on throughput, or on the number of certain process-units in the plant multiplied by certain theoretical emission data. Historically emissions from storage facilities, such as tanks were only very rarely thought of being of any magnitude to count with. Because of hard pressure from the Provincial Government in the second half of the 1980’s sophisticated measurement devices were taken out of the laboratories to be used for fi eld measurements. Measured – true – VOC-emissions showed to be substantially higher than what could be thought of based on the old calculations, especially for the storage facilities. Based on the first measurements with the laser technique in 1988 and 1989, later measurements in 1992, 1995, 1996 and 1999 have shown tremendous reductions of VOC-emissions during these years. The reduced emissions clearly follow fruit-bearing actions taken by the companies to reduce emissions. Starting in 1996, VOC-measurements with the DIAL-technique were also carried out in the oil harbour of the Göteborg Port, giving the same principal results as at the oil refineries. In 1999 also the first DIAL-measurement was carried out at the Nynäs hamn oil refining site of Nynäs, also here giving the same principal results as the early measurements at the other oil refi neries some 5-15 years earlier. The only emissions not in accordance with the diminishing trend are the emissions of carbon dioxide. As a basic rule, further refining of the crude oil needs more energy than if no such refinement took place. This was already the case for the deeper conversion introduced by the Shell refinery in the early 1970’s and with the introduction of the FCC at Scanraff in 1984 and of course with an increased production in itself. In recent years CO2-emissions have increased further based on the demand from society on the oil refineries to produce new, less environmentally disturbing products. This of course is a contradictory situation, which politically has been shown not to be all too easy to handle.
8 SHORT-CUT INFORMATION ON THE SITES FOR OFFICIAL DIAL-MEASUREMENTS
2. SHORT-CUT INFORMATION ON THE SITES FOR OFFICIAL DIAL-MEASUREMENTS
Below the main features are described for the different refi neries as well as for the Oil harbour at the Göteborg Port.
2.1 Preem Raffinaderi AB, Göteborg Being a BP Refinery until 1991, since its start on stream in 1966, the refi nery has had a low-skimming profile until the mid 1990’s. In 1994 an isomerization unit was set on stream as the first new major process change since the startup. In 1996 facilities for the desulphurization of gasoil as well as for the production of “Environmental diesel“ were installed. At the same time new big tail-gas treating units for process-sulphur came on stream. The licensed throughput is 6 Mton/a although a practical limit could be assumed at somewhat more than 5 Mton/a. The normal annual throughput has been around 4 Mton/a, with the exception of some years in the beginning of the 1980’s, when then throughput dropped below 3 Mton/a as a result of a major fi re. The number of people employed is about 250. The refinery is situated in the muni cipality of Göteborg on the Hising Island. Measurements with DIAL (Spectrasyne) have been executed in 1988, 1989, 1992, 1995/96 and 1999.
2.2 Skandinaviska Raffinaderi AB, Scanraff, Lysekil This refinery was planned in the 1960’s and got its licensing in the early 1970’s. In the early years the licensed throughput was 7 Mton/a. After a period having the limit on 8.3 Mton/a it is now set at 10 Mton/a. In 1984 the refinery was extended with a FCC unit, originally with a licensed capacity of 1.3 Mton/a. In 1992 this was raised to 1.5 Mton/a, with 1.75 Mton/a from 1995 and onwards. The owners have differed throughout the years, now being owned by Preem, the same owner as for the Preem refi nery. The refinery is situated in the municipality of Lysekil, without any other industry of its size in the neighborhood and being the industrial facility of highest importance in the area. The refi nery employs some 550 people. Measurements with DIAL (Spectrasyne) have been executed in 1992, 1995 and 1999.
2.3 Shell Raffinaderi AB, Göteborg The equipment for the refinery was originally built in the USA with destination for mainland China just after the 2nd World War. Due to the political changes in China at that time an alternative destination was thought of. Starting under the name of Kop partrans with a shared ownership by two Swedish companies, Kopparberg and Trans atlantic a small fuel producing refinery with two minor crude oil units was set up in the 1950’s. The maximum capacity at this time was about 2 Mton/a.
9 SHORT-CUT INFORMATION ON THE SITES FOR OFFICIAL DIAL-MEASUREMENTS
After being bought by Shell, new facilities were installed in the mid 1960’s more than doubling the throughput. Licensed throughput is 5 Mton/a, but the practical maximum could be set at around 4 Mton/a. The refinery is situated in the municipality of Göteborg on the Hising Island. The number of people employed is a little less than 200. Measurements with DIAL (Shell Research) have been executed in 1996 and 1999.
2.4 Nynäs AB, Göteborg Nynäs AB is a refinery in Göteborg (Gothenburg) situated at the Hising Island produ cing mainly bitumen and related products. The licensed throughput is 450 000 ton/a. The facilities were built in 1956 and subsequently put on stream in 1957 slowly in creasing the throughput from some 100 - 200 kton/a in the early years to around 400 kton in recent years. On a monthly basis the throughput is about 50 kton, but as the plant normally has a winter shut down the possible level of some 600 000 ton/a is ne ver reached at the present situation. As the winter shut down is based on the needs of the domestic market, changes could though be brought about in the future if the mar ket picture is being altered. The Nynäs refinery is normally referred to as the “small bitumen plant“ in the Pro vince as the facilities for the fuel producing refi neries are much bigger. The number of people employed is about 50 at the refi nery. Measurements with DIAL (Spectrasyne) have been executed in 1995 and 1999.
2.5 Nynäs AB, Nynäshamn The refinery is situated in Nynäshamn some 100 km south of Stockholm and has the longest history of the Swedish refi neries. The refinery was started in 1928 and was a fuel producing refinery until 1983. At that time Nynäs, as a company, left the Swe dish fuel market and the refinery was revamped in order to produce bitumen products and naphtenic special oils including lube oils using a very heavy crude oil. The license for the refi nery is limited to 1,8 Mton of crude oil intake, and the refi nery is equipped with, amongst others, one vacuum distillation and three hydrations units, the latter be ing one hydrofi nisher and two hydrotreaters. The desulphurization capacity has been increased during the last years and new equip ment has been installed for the removal of sulphur. The refi nery uses external fuel. Measurements with DIAL (Spectrasyne) have been executed in 1999.
2.6 Gothenburg Port, Oil Harbour, Göteborg The Gothenburg Port has a long history dating back to the time when Göteborg was founded in the 17th century. Since about 1850 the Gothenburg Port has held the posi tion of being the largest Swedish – as well as Nordic – port, now being about number 10 in Europe. Annually some 34 Mton of goods is handled in the port of which the Oil harbour is handling close to 20 Mton of crude oil and oil products.
10 SHORT-CUT INFORMATION ON THE SITES FOR OFFICIAL DIAL-MEASUREMENTS
The Oil harbour is situated on the northern shore of the Göta Älv river and thus nowadays lies more or less as a part of the Göteborg city, although a bit west of the centre. Within the oil harbour site also a number of handling and distribution compa nies have their facilities including tank storage and off-loading of products to trucks and railway. Measurements with DIAL (Spectrasyne and Shell Research) have been executed in 1996 and 1999 respectively.
11 INITIAL MEASUREMENTS
3. INITIAL MEASUREMENTS
In the early and mid 1980’s the problem with the – at that time – unknown real emis sions of Volatile Organic Compounds (VOC) from the oil refineries, lead to a number of discussions between representatives from the environmental enforcing authority, the Provincial Government of Göteborg and Bohus, and representatives from the re fi neries. The discussions finally lead to a decision on January 19th 1988 by the Provincial government, that one of the oil refineries had to start doing measurements. The oil refinery chosen, at that time the BP refinery in Göteborg (nowadays Preem Raffi naderi AB) , was considered to have the best location for a first trial of measurements. The reason for this was that the refinery at the time was a simple low-skimming facility, with the geographical positioning of the process area and the tank farms well separated. Also the infringement of emissions from other sources in the area could easily be taken care of as the distance to other emitting sources – also taking in account the prevailing wind direction – was considered to be more than suffi cient. The decision was coupled with a fine of SEK 2 million – at the time some USD 300 000 - in case measurements and reporting were not carried out as decided by the authorities. By coincidence BP at the time had already developed an in-house laser based DIAL- system (Differential Absorption Lidar) which had already been used inside of the BP group under the fl ag of BP Research. The first measurements were carried out at the BP refinery (later Preem) in May 1988, in June 1989 and also in February 1992, before it was considered that it was without any doubt possible and feasible to use the system in an appropriate way to determine the true VOC-emissions also for the other Swedish oil refi neries. At the time of the initial measurements at the BP refinery, theoretical (API- and Radian-based) calculations had been used to get some rough idea of the VOC emission level. The emissions calculated showed that some 700 ton VOC/a could be estimated to be emitted. This was virtually turned upside down when the figures of the real emis sions – based on the DIAL-measurements – were released during the autumn of 1988. The emission level at the refinery turned out to be about 10 000 tons/a instead, and in this figure the product tank farm was not included. With that included (it was fi rst measured in the measurements in 1989), the real emission level in 1988 for the BP refinery could be estimated at some 14 000 tons/a, ie. 20 times higher than what the calculations showed. The presentation of the measured figures to the public – in Sweden all these data are open to the public domain – resulted in a heated discussion in the papers and in subsequent meetings between the representatives of the environmental authorities of the Province and the management of the then BP refinery. These discussions resulted in a number of decisions, which showed to be of great value in the coming combat of the VOC-emissions, namely: • the management of the BP Refi nery confirmed that the measured values, although high, were reliable • the management of the BP Refi nery confirmed that they felt obliged to undertake actions in order to reduce emissions. As a matter of fact the measurements showed amongst others one single leak corresponding to some 4 000 ton VOC/a in itself. This leak was subsequently tightened up by the end of the measurements
12 INITIAL MEASUREMENTS
• the management of the BP Refi nery declared that they were willing to undertake a new measurement in about one years time in order to both confirm the results of the undertaken measurements and to receive a proof of the impact due to measures planned to be undertaken in the meantime before that measurement.
With this declaration by the BP Refinery a good basis, between the environmental authorities at the Provincial Government and the refinery itself, was laid for a mutual cooperation climate on these issues. It was agreed that the coming measurements should also consider the possible impact of such ambient factors as wind speed and outdoor temperature as well as the impact of a shining sun. The results that were achieved showed that the impact of wind speed for some installations could be other than negligible, namely the tank storage area, but that a knowledge of normal average wind speed could be of good value in assuming normal average emisisons. Outdoor temperature as well as the impact of the sun rays on the other hand was shown to be of a negligible impact, this being specifi cally – and amongst others – proved by the measurements at the now Preem refi nery during one of the coldest February-periods in 1992.
13 MEASURES UNDERTAKEN TO REDUCE EMISSIONS
4. MEASURES UNDERTAKEN TO REDUCE EMISSIONS
Information on the current situation on implemented measures has been gathered for the two main fuel producing oil refineries and for the small bitumen-producing plant. Generally it can be noted that the different actions started with a major implementa tion phase as a result of the 1988 measurement results, which – as noted above - were staggering high. On top of what is presented here it is also obvious that the refineries now pay much more attention to problems of VOC’s and to the emissions of these pollutants compa red to the situation only a decade ago. Today it is a normal part of life in the crude oil processing to think of solutions to keep down the VOC emissions, especially in case new facilities are designed, constructed and taken on stream. The following measures to reduce emissions could specifi cally be noted:
4.1 Preem Raffinaderi AB, Göteborg 4.1.1 Tanks and other storage • For oil pumps the sumps are covered and the trays tilted. At the place of the crude oil tanks the clear water pumps are vented directly to air. • Inner fl oating roofs are equipped with primary seals (4 tanks) • Blanket gas is used for three different tanks containing naphta and equipped with fixed copula roofs. In recent years the blanket gas has been changed from hydro gen-rich reformer off gas to nitrogen. • Secondary seals on the outer fl oating roofs of the crude oil tanks. • All product tanks with outer floating roofs have been equipped with a secondary sealing (excl. tanks with kerosene) as well as with equipment to reduce evaporation around the piping for level control. • External fixed cupola roofs with internal floating roof equipped with primary and secondary seal on gasoline components, gasoline and slops tanks. The cupola roofs also play a role to avoid rain water entering the tanks. •Drainage of tanks being better surveyed during operations. The drainage is led from the crude oil tanks to other tanks, ie. led back to a sludge tank and not directly to the WWT. • A new type of roof drainage system is installed on the crude oil tanks. The size of the drainage devices have been decreased, allowing also a decrease of the area where VOC is exposed to the atmosphere. • Changed roof drainage systems on all other tanks to abolish old piping which was due to leak VOC. • Caverns are kept with a low filling degree and designed with a common gas phase to keep the pressure low and thereby diminishing the risk of evaporating or ven ting VOC’s at all fi lling levels.
4.1.2 Process area • Piston rod seals have been exchanged for products of the latest technique, mainly related to the material of the seal on the piston compressors.
14 MEASURES UNDERTAKEN TO REDUCE EMISSIONS
• All control valves on the refinery re equipped with live-loading packing. All valves for manual operation on the new parts of the process area are from 1996/97 also equipped with live loading packing as well as also some other valves which – due to other reasons - have been up for exchange in recent years. All valves in service with light hydrocarbons are equipped with live-loading packing. • Safety relief valves are led to the fl are due to basic design by the plant in 1967. • Pumps: In 1994 the first LPG-pump was equipped with magnetic drive. Now all LPG-pumps have been equipped with tandem seals (not pressurized). Pumps wor
king with a magnetic drive amongst others are being used in service where H2S is present in more than negligible concentration levels. • All flanges serving light hydrocarbon streams are equipped with expanding grap hite seals. • For new process equipment the number of fl anges are reduced by design. • Flanges to purge or drain ends are either equipped with caps, blinded or plugged. • Streams of product samples sent to on-line instruments to control specifi cations are returned to the processes are led to the fl are. • Most of the sampling stream to places for manual caught analyses are returned to the process or to the fl are. • A fl ue gas compressor installed in 2002. • In line mixing of products is the general means of establishing fi nal products. • A leak detection and repair programme has been in full implementation for about 10 years.
4.1.3 Waste water treatment • A settling tank of 10 000 m3 has been installed before the WWT to reduce the hy drocarbon content to the API also enabling an uncovering of the API. Measure ment tests will be undertaken to see if the uncovering is a possible option or not. • The well to gather incoming water to the WWT is covered. • The PPI-separator is kept covered by water, by which no further coverage is neces sary.
4.2 Skandinaviska Raffinaderi AB, Scanraff, Lysekil 4.2.1 Tanks and other storage • A balancing line in between tanks in light hydrocarbon service to improve pressure balancing and to reduce the risk of venting through safety relief valves. • Secondary seals are being used on all tanks with floating roofs which are in service for products with a higher evaporating pressure than kerosene, in total 14 storage tanks. • A new liquefied secondary seal installed on one of the crude oil tanks, following very high measured emissions by the DIAL trial in 1999. • Vent gas from caverns is led to the fl are instead of to the atmosphere.
15 MEASURES UNDERTAKEN TO REDUCE EMISSIONS
4.2.2 Process area • For four centrifugal compressors the vent gas is led to the fuel gas/fl ue gas system. • For 13 piston compressors the leakage from the piston rod is led to the fuel gas/ fl ue gas system. • All pumps used for hydrocarbons with a density below 0,65 (at 200°C) are revam ped and have new axis seals of tandem type. • About 250 control valves in service with naphta and lighter hydrocarbons are equipped with improved packing material (graphite) which in some cases also is combined with a system based on springs. • Valves run manually are all equipped with a new type of glandered packing (grap hite rings in combination with a plait of carbon fi bre) • For fl anges a spiraled graphite packing is used. • Streams for on-line samples to GC’s are led to the fl ue gas system. • Streams for samples of LPG are equipped in such way that purge gas is led either back to the fl are or returned back to the product. • A leak detection and repair programme has been in full implementation for about 10 years.
4.2.3 Waste water treatment A number of changes have in recent years been undertaken on the WWT in order to both reduce the amount of oil led to the plant and to reduce the amount of open space where oil can evaporate. This has been done by the following actions: • Settling tanks with inner floating roofs prior to the waste water treatment to reduce the oil led to the WWT. • Installing skimmers in a pre treatment basin to the API-separators system. • Removal of oil at different underground culvert systems leading to the WWT. • The waste water stemming from the product quay is led to the settling tanks ins tead of directly to the WWT. • Total coverage of the API-separators.
4.2.3.1 Actions in 2002 During 2002 the WWT was rebuilt to enable the refi nery to fulfil new emission limits set out in the license for the plant, specifically concerning the amount of suspended material and nitrogen in the effluent water. These changes were also used in order to improve the balance of the emissions to air at the WWT. Existing API-separators and flotation units were exchanged for new flotation units. The basin for pumping of was te water to the settling tanks, as well as to the fl otation units, was completely covered and the gas recovered sucked off and led to the biological cleaning stage of the WWT. Also the biological cleaning stage was renewed. Existing equipment for supplying air were replaced with systems entering the air to the bottom of the basin. The new system for the cleaning of nitrogen in the water also should lead to a situation where the air supply is turned off from time to time in both of the basins where the air is supplied. This is presumed to also reduce the VOC-emission to air.
16 MEASURES UNDERTAKEN TO REDUCE EMISSIONS
4.3 Nynäs AB, Göteborg The refinery has in the late 1990’s, after some staggering measurement results on the VOC-emissions in 1995, been introducing a complete system for vapour recovery for nearly all tanks on the refi nery. The system is also continuously extended. As the initial measurements were carried out in 1995 there were not any major emis sions expected from the site, as nearly only heavy products were being produced and fed through the system. On the contrary very high emission levels were encountered o due to the raised temperature in the bitumen tanks, held at around some 200 C. This was contrary to all the old techniques for calculating emissions, where emissions from storing such heavy products by these calculation methods as a definition were set to zero. The measurements proved this completely wrong. In the mid 1990’s the refi nery subsequently decided to introduce a complete system for vapour recovery at the tanks of the refinery. The system is divided in two parts, one where all tanks with non-oxidized products are put together, and one where the oxidized products are taken care of. There is also a connection in between the both systems to level the pressure out. The system uses nitrogen as blanket gas. By later measurements it has been shown that the carried out actions substantially have decreased the emissions and on top of that an improved reliability in the proces sing has been achieved as the tanks, mainly those with oxidized products, now do not get choked at all, allowing for far fewer shut-downs of tanks and for far fewer cleaning operations than before. Roughly the reduction in emissions from the tanks being put together in the vapour recovery system was reduced by half from 1995 until 1999, due to the system described above.
17 DESIGNING A MEASUREMENT SURVEY
5. DESIGNING A MEASUREMENT SURVEY
Measurements of fugitive VOC emissions need both sufficient time to be carried out, and to be sufficient in area coverage. They also need to take into account variations in the meteorological circumstances during the measurement survey as well as its relation to the meteorological normal conditions. It will not be possible to defend continuous measurements on the site by DIAL or any – if so – equivalent measurement technique at today’s cost. The costs for such an exercise will be too high. On the other hand too short measurement periods will not give sufficient data, and will make the data received doubtable in both accuracy and relevance. The methods for a good survey, in that the aim is to really sort out and defi ne the real emission levels, vary from site to site depending on differences in both localisation and possible interference from other sources, topography and meteorology as well as fluctuations in the normal running of the facilities at the site. Never the less, below are proposed some basic rules to run a successful measurement exercise, based on the Swedish experience.
VOC’s to be included 5.1 Define at an early stage which VOC’s are to be included! For a petrochemical plant it might sometimes be possible to distinguish this to a few and well defi ned number of specified VOC’s due to the production of well distinguished hydrocarbons. This does on the other hand not mean that in case of an ethylene-cracker you only can go for et hylene. You need also to measure ethane, propane, propylene, butane and aromatics and maybe also some other well defi ned VOC’s to get the major part of the emission. For oil refineries on a general basis there is a vast spread on which VOC’s really are emitted. This means that a measurement should be covering the widest scope possible. With current existing equipment it is possible to measure alkanes and alkenes in the
span C2 – C22. In case a too narrow span is used the figures measured will be too low
compared to the real situation. As normally the share above C15 is low, it is suffi cient
to measure C2 – C15. Aromatics should also be included and it is possible to measure at least up to some
C10 – C11 with today’s techniques. On a GC that would correspond to about C15 when talking about the retention times of the straight hydrocarbons. The normal way is to use the DIAL-equipment for measuring one typical aromatic substance, normally toluene or benzene, and the other aromatics present are measured by sorption tube equipment in order to get a sufficiently proper value on their presence related to that aromatic substance measured directly by the DIAL.
Other VOC’s to be taken care of are the cyclic ones with a cycle less than C6, which could be included in the alkanes/alkenes-measurement set, although at a maximum they look to account for some 5-7% of the total, which on the other hand cannot be said to be negligible. In case certain interest is lying within the field of methane as a green-house gas, this could of course also be measured by the DIAL, and should be done so in case it cannot be defi ned as a less important parameter for the plant. When describing emission fi gures it should however preferably be done separately for methane as the environmental impact of dif
18 DESIGNING A MEASUREMENT SURVEY
ferent types of VOC vary quite substantially. A proposed division would be the following:
SUBSTANCES MEASURED (KG/H) ANNUALIZED (TON/A) REMARKS
Alkanes C2 – C8
Alkanes C9 – C15 Σ Alkanes
Alkenes C2 – C8
Alkenes C9 – C15 Σ Alkenes
Aromatics Benzene Aromatics Toluene
Aromatics C8 – C11 Σ Aromatics
Cyclic hydrocarbons Σ NMVOC
Methane
Σ VOC
This division should preferably be done for – primarily – the site as a whole but also for each of the main subsections defined for the site, normally at least the crude oil tank storage, the process area, the waste water treatment plant and the product tank storage. The DIAL-system gives by its measurements in the normal operation mode, at a refinery or the like, levels of a sum of those VOC’s that are detected for a certain wavelength. To get a picture of which VOC’s are present it means that the DIAL has to be added to tube sorption measurements or other methods to get the full picture and the distribution. For this it is very important that the equipment used is able to detect all VOC’s fully in the whole of the above described span, i.e. not only up to a level of
C8 – C10 when talking about straight hydrocarbons, but up to about C15 instead, and subsequently also such a range for aromatics. Below the measurement strategy is described mainly in terms of the use of the DIAL – or another equivalent system – as this gives the basic variation in emissions on a mass flux basis. To get the real figures in mass flux it is nearly equally important that the sorption tubes – or equivalent equipment – are used more or less in parallel to get the full picture. Without this, or in case a too narrow range is used for the VOC’s, the received data will not give the full picture.
19 DESIGNING A MEASUREMENT SURVEY
5.2 Meteorological measurements The meteorology, as wind speed and direction, should be continuously measured at at least three heights during the whole time of each measurement activity. Normally the levels should be something like 5-8 m, around 10 m and 15 – 25 m above ground le vel, to get an accurate picture of the wind profi le. Continuous reliable information about the wind profile is necessary for getting an accurate measurement of the emissions from the facilities and continuous data on the wind direction is also basic information for defining the plume during the measurement as a whole, as it is the fl ux perpendicular to the plane that counts. Another basic requirement for the measurement of the meteorological conditions is that the free air wind is given and that the met stations are placed in the scan plane so that the effect of possible partial wind shadows are accounted for.
5.3 Measurement strategy 5.3.1 The whole site The running of an oil refinery, or the like, in itself contains a lot of parameters which in different ways can be varied and thus differently affect the operations and thereby also the emission levels. This is true for both the storage areas and the process area, although the general influence of day-to-day variations for the storage area, on a gene ral level, is definitely greater than for the process area in the case where we do not talk of sudden leaks in the process or shut-down operations. To receive reliable data, measurements therefore have to be undertaken in such a way that variations in normal operations are taken care of and, as much as possible, also are included in and analyzed during the measurement campaign. This means that surveys need to be undertaken over such a length of time that variations can be taken care of, and under such operative conditions within the site so that it during the mea surements is possible to gather all necessary and relevant data for the later analyses and determination of emission mass flux levels. This has to be emphasized even more when measuring the tank storage area and the different off-loading operations. It is always recommended that, initially, an overall measurement of the whole site is carried out. This is also possible to undertake if the site is not all to big in size (up to some 1,2 * 1,2 km). In case the site is very large it is still of importance to get an initial overall picture of the emissions situation. This then has to be done by splitting the area up in sections with sizes which are possible to cover by the measurement device. Each initial overall measurement should not be less than half a day, preferably one whole day. The time to be spent is also depending on the number of repeat visits aimed for and is of course also wind direction dependant. When the wind curtails the initial measurements, this could also be made up for later by the following measurements during the total measurement survey.
5.3.2 Division into Sub-sections Having a broad picture of the overall emissions situation the next step is to focus on the defined sub-sections of the main area. For an oil refinery this would generally mean
20 DESIGNING A MEASUREMENT SURVEY
a division in at least the following areas: • the storage facilities for raw material (crude oil etc.) • the process area • the waste water treatment area • the product storage and • other specific areas which might be of certain interest or by other means large emit ters like ship, truck or railway loading
For other types of sites non-relevant parts of these could of course be omitted, i.e. for an oil harbour the “process area” generally is a non existent part. The geographical and topographical parameters of course also have a general impact on this choice and generally there is no problem in a further division into sub-sections other than what is indicated above. Typically it could on top of this also be of interest to study just one or a few storage tanks or parts of the process area, mainly perhaps where there are new installations or parts of the plant which are suspected to have higher emissions than others. See also below chapter 5.3.3. In case the geographical area for the site is small (in relative terms) the number of specific sub-sections could be reduced, but then only when taking into account that the possibilities for interpreting the results are not hampered. Measurement quantity is a tricky issue. As a general rule you can never have too much data but this has to be balanced against economics. The idea is to get suffi cient data to cover the day to day or hour to hour normal operations and peaks. Overlaid on this will be the more abnormal peaks due to a whole range of accidental or maintenance activities etc. It is rare that you don’t detect one or two of these ‘abnormals’ during the course of a survey, which however is positive as they anyway have to be taken care of in a correct manner to address a real annual emission level. An exclusion is debatable because, although the specific incident may be very unusual, there is infi nite potential for other unusual incidents. Something unusual will be happening with a relative high frequency at complex sites, and it needs to be recognized that unusual incidents will add to the emission total of “normal operations”. As a guideline for a survey, a minimum of two to three days should be devoted to each sub-section. This time should be split up into at least four separate visits of 3 - 4 hours each at random choice of time during the total survey, but in conjunction with situations when the right conditions for measuring are met. Where a sub-section is very large it may be necessary to sub-divide it into even smaller parts with consequently less time spent at each spot. If several sub-divisions are necessary then the total time devoted to the whole main area preferably should be proportionately increased. Specifying the number of scans to be carried out, i.e. single shot measurement of about 10 – 15 minutes, is often counter productive because scans can be shortened and coarsened, so a measurement time utilization is better to specify. This should consist of the system utilization time per day or for the whole survey. What is required is the actual measurement time of the system excluding between-scan setting and relocation time, although provision needs to be made for these. A good system should give over 4 hours a day of integrated measurement time, which is then also the basis for the timings described in this report.
21 DESIGNING A MEASUREMENT SURVEY
As the emissions performance of the different sub-sections at an oil refi nery are dif fering quite substantially the following advice would be given based on which type of sub-section we are focusing at:
6.3.2.1 Tank storage Especially in case of outer floating roofs, emissions are expected to vary with wind speed and liquid level in the tanks. This proposes specific measurement activities to cover the impact of these parameters. Measurements should be carried out in such a way that they in the analyzing can be split up in different single and/or groups of tanks in order to enable a reception of data which can be used to implement measures to re duce emissions. Typically one division is normally for crude oil tanks and product tanks respectively. Here it is very important to point out that the old traditional calculation methods more or less say that emissions are virtually zero for products heavier than kerosene. This is a huge mistake in these calculation methods, as the real measurements will show substantial emissions and this especially if such products are heated up above normal ambient temperature. Another mistake by the old calculations is the misinterpreting of the huge influence individual variations in between tanks, due to construction, history and maintenance, although they at a fi rst glance look very similar. The individual conditions of a tank, especially when looking at the larger tanks with outer floating roofs, has a sometimes tremendous impact on the real emissions. Some times emissions can be about fifty times higher or more compared to what is predicted by the old calculation methods, even if the liquid used is of kerosene type and lighter. Each measurement activity should be divided up into a sufficient number of scans so that enough information is gathered to enable an annualization as well as to have a good picture of the individual tanks with the highest emissions as well as a general picture of the variability of emissions due to wind speed and the filling height of the tanks. The latter especially is important for tanks with outer fl oating roofs.
5.3.2.2 Process area Emissions do nearly not at all vary with meteorological conditions, but could be va rying due to sudden leaks, changes in leak pattern and – in some cases – throughput as well as due to major changes in operational conditions. The relatively constant ex pected processing conditions could indicate that in some cases – when equal emission levels are measured from one time to another – the number of measurements to cover this subsection during the survey could be reduced to as low as two measurements of the above indicated length if the sub-divisions is not too large. Measurements need on the other hand normally to be divided up into different parts of a site as the processing at many sites geographically is split up into different and well divided sub-divisions. If so, for each of these further sub-sections measurements have to be carried out as specified above. In a normal situation we talk of some two to three sub-sections.
5.3.2.3 Waste water treatment plant Measurements of VOC-emissions from the WWT should be carried out in an analogy with those done for the tank storage. The variation of emissions with wind speed nor
22 DESIGNING A MEASUREMENT SURVEY
mally is far less compared to that of storage tanks. In the case where the WWT con sists of a large open surface, emissions to air will normally both be high (“cleaning the water by letting the pollutants evaporate to air”) and to some extent also affected by meteorological conditions. If settling tanks and other – intermediate storage facilities – are used in combination with the traditional WWT, their emissions should be mea sured separately. The content of hydrocarbons in the effl uent water and the mix of different types of hydrocarbons – and thereby also the corresponding mix in the emissions to air - will vary more than what is the case for the other areas. This indicates that the use of mea surement device facilities to speciate the hydrocarbons need to be frequently used for the WWT plant.
5.3.2.4 Other facilities Measurements around loading facilities should be carried out in such a way as to making it possible to arrive at some statistical sound level when looking at the nor mal operation, the working hours and other general performance parameters for the trucks as well as the railcar or ships being used. It is expected that there will be good possibilities to arrive at such measurement data when talking of trucks, as such opera tions are quite frequent, and railcars where they are frequently used. The aim has to be to arrive at typical emission levels for the specific operations and then sum that up to annual values depending on the number of such operations which are carried out as a whole, also taking into account typical daily start-up and shut-down situations. Typically loading operations to truck often to a high degree take place outside of normal operation hours – quite frequently during early morning hours – which means that measurements need to cover this period also in an appropriate way.
5.3.3 Dividing sub-sections When having a good picture of a certain sub-section, or even prior to that, it is re commended to also focus measurements on different already detected or expected hot spots. These could be defi ned due to many reasons of which some could be: • Newly constructed plant at the site • Plants with old equipment • Plants where certain measures have been carried out to reduce emissions • Plants where the strategy to reduce emissions would differ from other parts at a site • Specifi c tank operations (such as major tanks with outer fl oating roofs) • Parts of a sub-section or sub-division where specifically high emissions are expected or already have been initially measured
The latter is quite often due to “surprising” bad operations, typically in facilities like splitters, distillation towers or due to poor maintenance of storage tanks. For each of these single spots, irrespective of its size, there should be counted up to 2-3 hours of effective measurements in order to get accurate data. In case spots with very high emissions are detected - and which are possible to tighten within short notice
23 DESIGNING AV MEASUREMENT SURVEY
- this should of course be done. The measurements however still have to be included in the reporting to show the actual measures that have been undertaken on the plant in order to display the real situation.
5.3.4 Conclusions As described above the amount of time and the necessity to, for a single site, split me asurements up is different from site to site. Still it is possible, based on the experience at the Swedish refineries, to foresee what an average measurement survey would look like in time and methodology when following the guidelines described in the chapters above. It has also to be noted that the risk of arriving at disputable data due to not working according to the points outlined above cannot be ruled out as there always tend to be a discussion about the final contents, possibly leading to the need for new repeated measurements, thus making the whole story more expensive than it had been if it had been done in the right way from the beginning. Good planning and contact with the measuring team by personnel at the site therefore is an essential part of any survey. As noted above a measurement day at the site should normally mean at least 4 hours of real collecting of data, which means concentration and meteorological data, the rest of the time allowing for accurate placing of the measurement devices (normally in a truck), tuning of instruments and adhering to the right wind directions. Data should also be analyzed daily, to in the best way configure the measurements for the coming days. Summing up the time needed for a measurement survey would thus – as a rule of thumb – look like the following number of days at the site for a measurement team: • Measurement of the whole site: 2 days • Subsections: - Crude Oil Tank storage: 2-3 day - Process Area: 2-6 days (for 1-3 sub-sections) - Waste water treatment: 2-3 days - Product Tank Storage: 2-3 days - Loading operations etc.: 2-3 days • Other certain hot spots: 2-4 days
This makes out a total of 14 – 24 days which for small sites could be reduced to about one third, but for large sites even more time could be needed. Preliminary reporting should already be made by the measurement team to the site at the end of the survey, but there should of course also be daily discussions with the responsible personnel at the site on the ongoing findings and the proposed coming measurements. A final written report should normally be presented within one month from the last day of measurements.
24 MEASUREMENT RESULTS
6. MEASUREMENT RESULTS
As mentioned above DIAL measurements have been undertaken at 6 different Swedish sites since 1988. There have been 15 measurement surveys using two different systems, the Spectrasyne system with 12 surveys and Shell Research with the remaining three. Out of the 15 measurements, 10 are on fuel producing oil refineries, three on bitumen/ lube oil producing oil refi neries and two on an oil harbour. The easiest way to present the measurement results of all these surveys in a report like this would be to – for each single measurement survey – just present the data that were reported at the time of each measurement. As the systems and the methodology have been continuously improved throughout the years, this would however not give a really fair description of the results when comparing them with each other. The presentation of, and the abilities to assess, the achieved measured data has
been continuously improved. Initially only hydrocarbons in the range of C3 – C8 were measured as well as one of the aromatics, normally toluene or benzene. The aromatics- content has been shown to vary quite substantially with different areas of the refi neries and there has also turned out to be a non-negligible content of hydrocarbons in the
volatile part being heavier than C8, which was the initial upper limit of chain length to
be measured. Now up to C22 is measured. On the light side in recent years C2 is now
also included, initially only reaching down to C3. To make a true presentation of the real emission values the information of the old measurement surveys has to be processed together with the once recorded and presen ted figures to arrive at comparable and even – with today’s knowledge - more exact data and to assess trends. It would be of very limited value, with current knowledge of what is being emitted and with the improved techniques of recording met data and tube sorption analyses, to go back to old methods for measurement and reporting. The methods for displaying results in this report are thus discussed below.
6.1 State of the art methodology
Today techniques exist to measure NMVOC’s from C2 up to about C22 in the non-aro
matic range. Hydrocarbons in the heavy range above C15 only make out a small por tion of the emission and could thus be exempted as they can be diffi cult to analyze.
Aromatics are possible to measure up to the same retention times as straight C15. It is therefore no reason for not measuring these, as aromatics of this size seem far from negligible for the total mass fl ux. For storage facilities it is also important that wind measurements are correct, and that it is possible to normalize emissions to air from the tank storage facilities to what is defined as the normal meteorological situation, mainly talking in terms of wind speed. There is an impact of wind-speed on the emission levels at the storage facilities. Spe cifi cally this impact is high when the wind-speed is very high and the impact has been shown to also have a slight exponential profile. On the other hand, very high wind speed is normally not the predominant situation but the impact of such situations should at least be addressed, in case there temporarily is a high windspeed when measuring. At the initial Swedish measurements, data was not specifically related to any normalized wind speed, but emphasis has been put on the issue in recent years establishing wind- normalized emission data. Normalization should then be done to a situation typical to
25 MEASUREMENT RESULTS
the specific spot within a site where measurements are carried out, which means that for one refinery site there could be different average wind speed levels depending on the place of measurement. The means of reducing this possible impact is of course by, during one measurement period, doing a number of repeated measurements at each of the different measurement spots. By experience the wind normalization at tanks could as a rule of thumb mean up to about +- 10-20% of the measured emission level, but of course less in comparison with the total measured emissions for the site as a whole. As the DIAL-measuring system works in a real life situation, i.e. measuring the VOC which are passing through the measurement-plane, there are of course also emitted VOC’s that do not get across that plane (the lower the wind, the higher the degree), which means that the DIAL-measured emissions always can be expected to be on the low side due to this. Trials carried out to get a better understanding of this phenomenon show that the maximum “lost” emission due to this normally would be about 10% of the real emission. In the figures below this “loss” is not taken into account, but is here anyway mentioned as it indicates that emission-levels in fact could be even higher than what is being measured and presented below.
6.2 Presented data The data presented below consists of both comparable data for a number of years at those sites where the highest number of measurements have been carried out, the Pre- em and Scanraff refineries, as well as data showing typical changes in emission levels due to variations in the conditions of some of the equipment at the Scanraff refi nery. All presented figures are exclusive of methane, as methane has a completely different environmental impact than does the other VOC’s – although they also within themselves show big differences in environmental impact – as methane is more of a green house gas than anything else. A rough guess is however that methane could add some 10-20% on top of the total emission as a rough approximation, and then of course varying with site, equipment, service and with time. Some specific measurements have also been carried out on the Swedish refineries to indicate typical levels of methane emissions for crude oil tanks and the waste water treatment. Methane in these exercises have amounted to 12-33% of the total NMVOC-emissions for the crude oil storage and being as high as 50-80% of the NMVOC-emissions from the WWT. Measurements on the Swedish sites have been carried out with two different systems, the Spectrasyne (former BP Research) system which can measure both in the infrared (alkanes etc.) and the ultraviolet (aromatics) and the Shell Research system which only can measure in the infrared (alkanes etc.). Combined with these systems meteorological measurements have been carried out as well as tube sorption measurements. The range of hydrocarbons covered vary with the system used. Generally it could be noted that emissions of VOC’s could be expected
up to at least the C15-level (pentadecane). The Spectrasyne measurements have been carried out to meet this requirement, whereas Shell Research only reaches the level of
some C8– C10. Spectrasyne, in contrary to Shell Research, also includes C2 in the total and has also made some spot measurements on methane, although this is not included in
26 MEASUREMENT RESULTS
normal VOC-fi gure, i.e. VOC-figures should in this report be looked at as NMVOC if nothing else is stated. The conclusion is that it already from the beginning are different results to be expec ted from the two systems as the measurements are not done in an equivalent way. It is quite obvious that the Shell Research measurement device will record too low values compared to the real life situation as hydrocarbons heavier than C8-C10 are not detec ted, and also not C2. As the Shell Research DIAL does not include the ultraviolet it does not measure aromatics either which also makes the presented figures a bit more doubtable. Being aware of this, it does seem to be possible to in some way interpret the Shell Research measurements, although it will not be possible to in an accurate way say how much too low the presented figures are compared to the true total emissions as C2 and hydrocarbons above C8/C10 are left out and no aromatics are measured with the Shell Research DIAL. As noted above however in contrary though the Spectrasyne measurements fulfi l the needed requirements. Presenting single measurement surveys at a site only gives a rough indication of the emissions level at the site – still however much more reliable than any theoretical calculation – and is therefore not the best way of describing the emissions situation as the level of emissions may vary from time to time due to the condition of the site, both when talking about the tanks (i.e. conditions of seals and tanks as a whole) and the process area (sudden leaks etc.). A better way of describing the emissions situation is to describe it for those sites where at least three measurement surveys have been carried out and where the measurement results can be compared with each other. The measurements should then preferably also be compared bearing in mind the current state of the art of measurements, which means that DIAL-measurements for aromatics, and hydrocarbons in the range of C2
– C15 also should be taken into account. To make this possible the choice in this report has been to present the data of measurement surveys for the Preem and Scanraff refineries during the period of 1992 – 1999, bearing in mind the current state of the art of the measurements. This means that the older and historically reported measured data is, where it has been shown to be needed, recalculated to the current standards to be comparable and to show trends. Data for the tank storage area has also been normalized to the wind speed on average being accurate for the area of the specifi c refinery. For Scanraff data is also presented for a few practical situations, showing the impact and value of real life emissions and the uselessness of old calculated data. In the tables data are transferred from measured kg/h to tons/a by presuming an average of 8 600 hours/a of emissions a year. By this periods of maintenance and shut downs are taken into account. Of course minor individual differences do exist, but their impact can anyway be assumed to be below the total level of accuracy of the presented fi gures.
27 MEASUREMENT RESULTS
6.3 Preem Raffinaderi AB, Göteborg
AREA 1988 1989 1992 1995 1999 kg/h tons/a kg/h tons/a kg/h tons/a kg/h tons/a kg/h tons/a Crude Oil Tanks (Wind Normalized) 410 3500 350 3000 180 1590 90 790 80 700 Process Area 1640 14100 530 4600 115 1000 130 1150 170 1490 Waste Water Treatment 56 480 55 470 9 80 17 140 37 320 Product Tanks (Wind Normalized) 750 6400 750 6400 310 2700 270 2330 170 1470 Total 2860 24500 1680 14500 620 5360 510 4410 460 3980
Note: In 1988 emissions from Product Tanks were not measured, as the emissions were presumed to be low. As to make figures comparable, figures for these emissions have 1989 have been put in the table to also represent 1988.
6.4 Skandinaviska Raffinaderi AB, Scanraff, Lysekil
AREA 1992 1995 1999 kg/h tons/a kg/h tons/a kg/h tons/a South Tanks incl Crude 310 2700 90 770 350 3020 oil (Wind normalised) Process Area 380 3270 260 2270 230 2000 Waste Water Treatment 160 1350 80 690 55 480 Main Tanks (Wind 660 5660 320 2760 430 3670 Normalized) Total 1500 12900 760 6500 1060 9160
6.4.1 Example of tank storage conditions – tanks At the 1995 measurement survey all storage with outer floating roofs tanks with outer floating roofs had recently been A set of comparative measurements and anal equipped with secondary seals and thus main yses have been undertaken at a sertain set of tenance work had been done quite close before tanks at the Scanraff refinery. The results are the measurements, so emissions were measured shown below in a table. As a background to to be very low. the table the following should be noted: At the In 1999 the emissions from the gasoline as well Scanraff refinery in 1992 high levels of emis as the gasoline component tanks (with outer fl oa sions were recorded from tanks with Vacuum ting roofs) had increased due to presumed poor gasoil, because light hydrocarbons had slipped performance of the seals introduced. High emis to the tank with the product, i.e. due to poor sions were experienced from the crude oil tanks. upstream operation. High emissions from cru The inspection that followed due to the high de oil tank Tk-1401 were recorded due to high recorded measurement results proved a number liquid level being kept in the tank. In 1992 only of leakages along the roof sealing of the crude oil two gasoline component tanks were equipped tanks. Major maintenance works were carried out with secondary seals. on two of the crude oil tanks and on the third the
28 MEASUREMENT RESULTS
seals were changed to new ones. Unfortunately however no follow-up measurements were carried out to see the results of the latter installation. Below the measured emissions at the tanks are presented as comparison-fi gures with the results related as factors compared to the old rigid calculation methods, ie. the true emission value is presented as a factor compared to what emission level is accounted for when only relying on calculations. In the table measured data from 1992 and 1995 is in this case not compensated to the 1999 state of the art knowledge, but it anyway quite clearly shows the dependence of good maintenance work and the need for fre quent control on emission levels. Recalculating all data to 1999 standards would even clearer have shown the trends and the value of measured emission data compared to only calculated data, the latter not varying at all from time to time.
TANKS WITH OUTER FLOATING ROOFS DIAL MEASUREMENT (YEAR) 1992 1995 1999 (factor) (factor) (factor) Gasoline tanks 2,7 2,0 2,4 Gasoline component tanks 1,9 1,7 2,2 Crude oil tanks (Tk-1401 and Tk-1402) 26 2,6 13 Crude oil tank (Tk-1406) ----- 1,1 52
6.4.2 Rearranging the waste water treatment unit Also for the waste water treatment unit a follow-up study has been carried out for the Scanraff the existing refi nery. In 1992 at Scanraff settling tanks were used for ballast water only and they were also equipped with fi xed roofs only. The API- separator was only partially covered. At the 1995 measurement survey one of the settling tanks was equipped with an inner floating roof and was also put into a somewhat different service, being used as a settlingtank for both ballast and all other waste water produced at the site. In 1999 both settling tanks were used for all waste water produced at the site and had also become equipped with inner floating roofs. The API-separators were now completely covered.
29 kg/h 1992 1995 1999 45
40
35
30
25
20
15
10
5
0 Wast water treatment Settling tanks
In the table data from 1992 and 1995 is not compensated to 1999 state of the art conditions, but anyway quite clearly show the dependence of good maintenance work and need for frequent control on emission levels. Recalculating all data to 1999 standards would have shown the decreased emissions even more clearly.
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Comments Regarding Flare Task Force Stakeholder Group Meeting of 30 March 2009
Several of our members attended the Flare Task Force Stakeholder Group Meeting on 30 March 2009 in Houston. We are encouraged to see that TCEQ is undertaking a comprehensive evaluation of flares. As we have discussed with you in the past, we feel strongly that flares are a major contributor to unreported emissions, particularly in the Houston–Galveston–Brazoria area. Most of our earlier comments are still applicable and we have therefore included a copy of the 2006 IPCA paper, Reducing Emissions from Plant Flares. We urge the agency to make the most of this evaluation and use it as an opportunity to enact meaningful regulations and agency policies that will minimize flare emissions in our region.
A few areas that we would like to highlight in these comments are:
• Flare monitoring • Experimental assessment of efficiencies • Flare minimization
Flare Monitoring
Assist Gas Monitoring
IPCA has long called for better monitoring of flares to ensure that they are operated under conditions that maximize destruction efficiency. For example, we have highlighted EPA data available since the 1980’s that show that excess steam reduces destruction efficiencies. TCEQ’s DIAL and infrared field studies, as did earlier EPA lab studies, detected more unburned hydrocarbons in plumes from flares with excessive steam ratios. Several years ago Shell Global Solutions prepared for the agency TCEQ Work Assignment 5, Flare Gas Flow Rate and Composition Measurement Methodologies Evaluation. The report concluded: “the effect of assist gas to waste gas ratio on flare combustion efficiency, as well as destruction efficiency, requires further investigation. Over aerating or over steaming of the flare flame has the potential to significantly reduce combustion efficiency.” (Stakeholder Resource 6, page 5-2). For some reason this report, written circa 2004, never progressed past the draft form and the calls for further investigation are only recently starting to get attention.
We urge TCEQ to act expeditiously to use the new corroborating data from field studies presented at the stakeholder meeting and any future studies as a basis for specific, enforceable requirements for appropriate steam and assist gas ratios, backed with clearly defined monitoring and reporting provisions. According to Work Assignment 5, as of just a few years go, approximately 90% of the 50 flares investigated in the study were using manual steam control based on visual observations. This is a far cry from state of the art or best available control technology and we cannot accept long delays before implementation of better controls.
Assist Gas Control
Steam control can be accomplished in a number of ways as discussed in the TCEQ Work Assignment 5 and by ZEECO in a 2007 presentation Flare System Emission Controls at the Texas Technology Conference: texasiof.ces.utexas.edu/texasshowcase/pdfs/presentations/b2/ssmith.pdf Commercial vendors have control systems designed specifically to control smoke with minimum steam addition. Minimizing steam has the added benefit of reducing energy costs, which would thereby reduce the effective cost of the new controls. Infrared technology is an important component of many of these controls. For example, Williamson Corporation uses infrared technology to monitor the flame in a flare control system: http://www.instrumentation.co.za/news.aspx?pklNewsId=26272&pklCategoryID=69 as does Powertrol: http://www.powertrol.com/flaremon.htm The E2Technology Quasar uses infrared technology to monitor the flare gas, pilot and smoke: http://www.mikroninfrared.com/literature/pm-sm.pdf.
Other companies, such as the Sniffers NV, provide services to identify and detect fugitive losses from flare systems as well as equipment leaks into flare systems. http://www.the-sniffers.be/flare/monitoring.htm
The technology for flare monitoring and control is well developed and commercially available. Its use should be part of the Texas strategy to reduce emissions.
Experimental Assessment of Efficiencies
The potential for crosswinds to decrease flare efficiencies, even in industrial flares, was mentioned in your presentation. Flame separation at high wind speeds was also detected in corroborating studies by researchers from University of Alberta as well as early EPA lab tests.
We urge TCEQ to conduct or support experimental programs that further define this risk. A group called the International Flare Consortium purported to undertake this task, but results they may have to date, if any, are available only to their industrial sponsors and withheld from the public. Secretive research with publishing of only results favorable to industry will not clean our air. This question must be answered with definitive experimental programs in the public domain.
One experimental approach would be to use the existing experimental flare installation that TCEQ has employed before (John Zink Co.) combined with a suitable variable speed blower at the burner level. A sampling system installed opposite the blower could be held in place on the crane used to install the blower. This allows simple positioning and moving of the sampling device as required to map the plume.
Plume mapping of existing flares could also be investigated to better quantify emissions. Consider this rather simple and inexpensive approach. First, select flares where the prevailing breezes carry the plumes over the fence line. Second, sample the plume from private or government property, using tethered weather balloons. Attach the other end of the tether to a deep-sea fishing rig, so that the balloon can be positioned anywhere in the plume by the ground operator. The plume can then be mapped using a simple hydrocarbon concentration indicator-recorder, with readout at ground level. Problem plumes can be analyzed more completely by taking samples for subsequent analysis, again using the tethered balloon.
Flare Minimization
No matter what the efficiency, the best way to reduce emissions is to eliminate routine flaring and minimize start-up, shutdown and malfunction flaring. Elimination of flaring eliminates the hydrocarbon and sulfur emissions as well as the combustion by-products, which include NOx, SO2, some remaining VOCs and CO and CO2, a greenhouse gas.
Flare Minimization Plans
Flare minimization plans are required for refineries in the Los Angeles and San Francisco Bay areas according to BAAQMD Regulation 12 Rule 12 and SCAQMD Rule 1118. TCEQ has expressed concern that such an approach would be difficult to manage in Texas because of the large number of flares. However, each flare does not have its own plan; a facility has a plan that includes all the flares under that facility registration. Therefore, a tiered approach requiring full flare minimization plans for only the largest facilities, would be an option that is less burdensome to the agency and smaller facilities. Many of the larger Texas facilities have already created flare minimization plans for their refineries in California and some have also created internal plans for facilities in Texas. In addition, Shell Oil, Deer Park, as part of its recent consent decree (fact sheet attached), must create and implement a plant-wide flare minimization plan in accordance with California’s toughest-in-the-nation guidelines. Another approach would use emissions targets as a basis for determining when a flare minimization plan is needed. For example, SCAQMD Rule 1118 requires flare minimization plans for facilities that exceed performance targets for emission of sulfur dioxide per million barrels of crude oil processed. These targets progressively decrease from 1.5 tons SO2 per MM BBL in 2006 to 0.5 tons in 2012. Local targets might focus on ozone precursors and HAPs. This approach adds the incentive that facilities able to meet emission targets would be exempt from the bureaucratic requirement of preparing and submitting a plan for others to review.
Flare Minimization Work Practices
Other components of the Shell consent decree that are applicable to many flare operators are the upgrading of steam supply systems and flare mapping. The Episodic Release Reduction Initiative (ERRI) study, conducted by EPA Region 6, TNRCC and industry in 1999 and 2000, identified an unreliable steam supply system as a frequent contributor to upsets that led to flaring. Particularly if plants are not required to define their own means for flare minimization, TCEQ should consider requiring certain levels of redundancy in steam supply as a requirement for the largest flare sources. Perhaps industry could be given a choice between creating a flare minimization plan or following some predefined minimization techniques most often used in other locales. These might include, among others: • upgrading steam supply, • installing or upgrading flare gas recovery systems, • monitoring equipment and valves connected to flare headers for leaks, and • flare mapping--the creation and maintenance of complete and accurate maps of all connections and flows to a facility’s flares.
In sum, TCEQ can tailor flare minimization requirements to the specifics of the Texas Gulf Coast so that local issues can be addressed in a manageable way. The critical point is that flare minimization must be addressed!
Respectfully submitted by
Lucy Randel Research Director Industry Professionals for Clean Air
Matthew S. Tejada, Ph.D. Executive Director Galveston Houston Association for Smog Prevention
Elena Craft, M.S., Ph.D. Air Quality Specialist Environmental Defense Fund
Attachments Reducing Emissions From Plant Flares
Paper #61 – Revised April 24, 2006
Prepared by Robert E. Levy, Lucy Randel, Meg Healy and Don Weaver
Industry Professionals for Clean Air, 3911 Arnold St., Houston, TX 77005
ABSTRACT
Regulation of emissions from plant flares in Texas is based on flare efficiency studies conducted by the US Environmental Protection Agency (EPA) in the early 1980’s, which concluded that flare combustion efficiencies of 98 or 99 percent are achieved when critical operating variables are controlled appropriately. However, recent studies suggest that, even when well-controlled, flares may operate with efficiencies appreciably lower than 98 percent due to crosswinds and other factors. Lower than assumed flare combustion efficiencies, particularly during emission events, could account for a significant portion of previously unrecognized emissions from refineries and chemical plants and help to explain Houston’s high ozone levels. This paper discusses the state of the art in understanding flare emissions and examines the specific shortcomings of the current Texas flare regulations, including new regulations on highly reactive volatile organic compounds (HRVOCs). In addition, it considers steps that could mitigate flare emissions, and finally provides a list of recommendations for industry and regulators. Recommendations include expanding research on factors affecting flare combustion efficiency; improving monitoring and reporting of flare operating parameters, such as steam assist and flare gas mass ratios; minimizing the volume of waste gases routed to elevated, unenclosed flares; and encouraging the use of flare gas recovery systems or wind-protected ground flares and thermal oxidizers.
INTRODUCTION
Houston is classified by the EPA as being in "severe" nonattainment of the one-hour ozone standard and in "moderate" nonattainment of the eight-hour standard. The Texas Commission on Environmental Quality (TCEQ) has recognized a link between episodic emissions of the type associated with flaring and sudden exceedances of the one-hour ozone standard by enacting a new short-term limit on highly-reactive volatile organic compound (VOC) emissions. Ozone and smog result from the reaction of VOCs with nitrous oxides in sunlight. Significant quantities of VOCs are released from elevated flares, which burn waste hydrocarbons primarily during emergencies and upset conditions.
1
In a 2000 annual summary of emissions, the TCEQ estimated that flares were responsible for 12 percent of total emissions of volatile hydrocarbons in the Houston-Gulf Coast area, based on an assumed 98 or 99 percent flare combustion efficiency.1 However, flare burning efficiencies are not readily measured. Rather, VOC destruction efficiencies of 98 or 99 percent are assumed by the TCEQ2,3 and industry, based on experimental studies completed by the EPA in the early 1980’s.
In 1986, EPA used the data from these studies to codify the requirements for flares under the New Source Performance Standards (NSPS) in 40 CFR 60.18. The NSPS rule specifies limits of critical flare operating variables that must be controlled to obtain 98 percent or higher combustion efficiency. These critical operating variables include heat content of the flare fuel mixture, the ratio of fuel gas to assist gas (air or steam) and burner tip velocity. In 1994, similar control device requirements were added to the National Emissions Standards for Air Pollutants (NESHAP) in 40 CFR 63.11. Other than the addition of a provision for hydrogen fueled flares in 1998,4 the requirements have remained essentially unchanged for 20 years.
The TCEQ has not required reporting of operating data, except weight of total hydrocarbon burned and "engineering estimates" of stream composition. With inadequate operating data, 98 to 99 percent combustion efficiency cannot be realistically assumed. Another operating variable, crosswind velocity, was not addressed in the EPA studies, and more recent experimental work suggests crosswinds reduce flare combustion efficiency. Although some independent research has recently been initiated by the International Flare Consortium5, neither EPA nor TCEQ has undertaken significant large- scale experimental work since the early 1980’s.
In this paper, we review the literature evaluating effects of operating parameters on flare efficiency, as well as recent approaches in both industry and government to quantify and reduce hydrocarbon emissions from flares. The authors believe serious attention to these issues with enforceable goals is imperative if the Houston-Galveston area (HGA) is to reduce its “smog day count.” Recycling of waste gases, rather than flaring, must be seriously considered and flares should be reserved for essential use during unavoidable emergency events.
The authors represent Industry Professionals for Clean Air (IPCA), whose members have been affiliated with the petroleum or petrochemical and are concerned about the air pollution in the Houston-Galveston region. Based on our experience and research, we believe elevated flares present the most significant problems for controlling emissions of VOCs and toxic air pollutants in our region. Our purpose is to make realistic recommendations for reducing flare emissions that will encourage industry and the regulators to take action.
2 EMISSIONS FROM PLANT FLARES
The Texas Commission on Environmental Quality (TCEQ) uses high destruction efficiencies, based on combustion efficiencies established in the early 1980’s by the EPA to establish regulatory requirements, calculate permit limits, monitor compliance, enforce control requirements and plan for attainment of air quality standards. The TCEQ presumes that flares destroy 99% of ethylene and propylene, and 98% of other VOCs, except for certain compounds with less than 3 carbons, as long as continuous monitoring data for the flare inlet demonstrates compliance with the EPA’s minimum heating value and maximum exit velocity requirements specified in 40 CFR 60.18.6 Findings from the EPA 1983 Flare Study generally reflect use of high-efficiency flares burning simple chemicals at natural gas processing plants under optimal operating parameters and wind speeds less than five miles per hour. 7 The TCEQ’s approach, therefore, makes no allowance for real world operating variables. Specifically, it is based on the unrealistic assumptions that:
• plants are consistently operated according to the parameters necessary to optimize flare destruction efficiency; • crosswinds have minimal effect on combustion efficiency; and • flares perpetually operate at high destruction efficiency.
In the following discussion we will examine these assumptions and develop suggestions for adoption of more realistic ones.
Because flares are designed and used for control of emission spikes, the hourly emission rate permitted8 and experienced by a flare is likely to be the highest of any unit at a facility, even assuming a 98% to 99% VOC destruction efficiency. If realistic efficiencies were applied, then the emission rates would be dramatically higher and might account for much of the discrepancy between measured and model-predicted air pollution in the Houston region.
Determine More Realistic Flare Destruction Efficiencies
Operating Parameters
As stated earlier, EPA work in the 1980’s established the basis for current federal and Texas flare regulations. 40 CFR 60.18 and corresponding state regulations require that flares operate:
• “with a flame present at all times”,9 and • “with no visible emissions …, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours.”10
The waste stream routed to the flare either burns on its own or, if it has low heating value (less than 300 Btu/scf), with the assistance of a high-energy (more than 1000 Btu/scf) fuel gas, like natural gas or propane, to facilitate complete combustion.11 Typically, operators use fuel gas, or some other purge gas, to keep slow flowing emissions moving
3 toward the flare.12 With or without additional fuel, the combustion of many waste streams produces smoke – i.e., visible emissions.13 For smokeless combustion, operators typically inject steam or air to “achieve more complete combustion.”14 The injection of steam or air (assist gas) “at the flare tip [also] increases the mixing of waste gas with air, as well as the residence time of the waste gas constituents into the flame zone, thereby increasing combustion efficiency.”15
Operators must maintain a delicate, but essential, balance between smokeless and oversteamed emissions. Studies in the 1980s “demonstrated that assist gas to waste gas mass ratios between 0.4 and 4 were effective in reducing soot while ratios between 0.2 and 0.6 achieved the highest hydrocarbon destruction efficiency.”16 Too much assist gas (over steaming or over aerating) “may … reduce the overall combustion efficiency by cooling the flame to below optimum temperatures for destruction of some waste gas constituents, and in severe cases may even snuff the flame, thus significantly reducing combustion efficiency and significantly increasing flare exhaust gas emissions.”17 The EPA 1983 Flare Study noted: “Combustion efficiencies were observed to decline under conditions of excessive steam (steam quenching) and high exit velocities of low Btu gases.”18 Thus, EPA regulations establish parameters for heat content and exit velocity.19
The EPA 1983 Flare Study also demonstrated that separation of the flame from the burner tip results in a serious drop in burning efficiency.20 This flame separation has been observed during emergency flaring events under high winds and during addition of excess steam. The reported loss of efficiency occurs because, under these conditions, some of the gases do not remain in the combustion zone long enough for complete conversion to carbon oxides. Some of the gases have the opportunity to partially or totally bypass the combustion zone, with the result that unburned VOCs are emitted to the atmosphere.
In addition, the TCEQ learned from a contractor’s evaluation of flare gas flow rate and composition measurement methodologies that although “data on destruction efficiency versus assist gas ratio obtained under controlled conditions would suggest that poor assist gas control might negatively impact destruction efficiencies, there are little or no data available on the impact of assist gas ratio control on destruction efficiency of operating flares.”21 Thus, “the effect of assist gas to waste gas ratio on flare combustion efficiency, as well as destruction efficiency, requires further investigation.”22 Based on a review of some 50 refinery and petrochemical plant flares, and discussions with petrochemical plant operators, the TCEQ learned that the assist gas injection rate for 90% of the flares is controlled manually “by the operator based on [visual] flare observations (either directly or on a video monitor).”23 Nevertheless, neither the EPA’s nor the TCEQ’s regulations adequately address the critical role that steam content plays in flare combustion, and apparently neither agency is actively investigating steam content control for flares in the Gulf Coast region.
Furthermore, because the EPA 1983 Flare Study focused on simple hydrocarbons, subsequent analyses may not take into account the possibility that while the original compound may be destroyed, large hydrocarbons could simply be broken down into smaller hydrocarbons and other compounds, some of which may be toxic as well.
4 An independent group, the International Flare Consortium, has initiated research focused on exactly these issues in their project: "The effect of flare gas flow & composition; steam assist & flare gas mass ratio; wind & flare gas momentum flux ratio; and wind turbulence structure on the combustion efficiency of flare flames focusing on speciated emissions of the highly reactive volatile organic compounds (ethylene, propylene, butadiene) and the class archetypal hazardous air pollutant carcinogens (formaldehyde, benzene, benzo(a)pyrene)."24
Upsets present even more of an operations problem. An evaluation of emission events in the Houston-Galveston area between January 31 and December 31, 2003 “shows that HRVOC events and possibly VOC emissions events have the potential to contribute significantly to ozone formation in HGA.”25 A 2002 TCEQ toxicological evaluation of VOC monitoring data collected downwind of three Harris County plants noted that “exposure to recurrent elevated short-term levels of 1,3-butadiene may increase the risk of reproductive and developmental effects.”26
Consider this specific example in which a large chemical complex reported 304 tons of VOC emissions due to upsets and 622 tons of VOC emissions total for the year 2000. The applicable permit allowed only 124 tons of VOC emissions. Among other emission events in 2000, this company reported an upset, shutdown and startup from July 17, 2000 through August 18, 2000. As part of the response to this upset, the plant operator “maximized steam flow to the flares to optimize combustion and minimize smoke.”27
As noted above, too much steam can reduce combustion efficiency by cooling the flame. A TCEQ study determined that an “assist gas to waste gas mass ratio between 0.2 and 0.6 achieved the highest hydrocarbon destruction efficiency.”28 The company cited above reported that “[t]he hydrocarbon stream being flared during the July upset most likely required a steam to hydrocarbon ratio of 0.7.” We do not have enough information to accurately calculate the destruction efficiency of this company’s flare during the July 2000 upset, but experience suggests it is likely that the heat content was too low and the exit velocity too high for the efficiency to be 98+%, as assumed in most of the Upset/Maintenance Notification Forms filed regarding the incident.
The TCEQ’s new regulations regarding flares that burn HRVOCs assign 93% destruction efficiency to flares not meeting the EPA’s standards for minimum heat content and maximum exit velocity based on continuous monitoring.29 During the above-cited July 2000 upset, if a flare destruction efficiency of 93% is assumed, rather than 98%, the 304 tons of VOC emissions would become 1064 tons of VOC emissions. This represents 1.7 times the 622 tons of total VOC emissions reported at this plant during the entire year 2000. Moreover, reductions in residence time during startup and shutdown operations,
5 when flares operate at high rates for extended periods, may reduce combustion efficiency substantially below the 93% provided for in the new regulations.
Crosswinds
The TCEQ’s assumed flare destruction efficiencies of 98+% also do not take into account routine, yet less than ideal, weather conditions, such as crosswinds. An open flame, in the absence of a crosswind, assumes a symmetrical shape of maximum volume having an equilibrium flame temperature dependent upon operating conditions. Crosswinds distort the flame, reducing flame volume and flame temperature. High combustion efficiency requires that the combustible material be present in the high temperature region of the flame for a significant period. Crosswinds in excess of 5 miles per hour, however, may significantly degrade combustion efficiency because they shorten the residence time of the combustible material in the flame.
The EPA 1983 Flare Study only conducted tests on flares at wind speeds up to 5 miles per hour because flame instability made it impossible to obtain proper samples at higher wind speeds.30 Consequently, there is a significant gap in the EPA field data, but lab- scale data suggests potentially significant reduction in combustion efficiency at high wind speeds.31,32
Ongoing studies by the Engineering Department of the University of Alberta and the Alberta Resource Council also demonstrate the need to consider the effects of crosswinds on flares. The University of Alberta studies not only confirm findings in the EPA 1983 Flare Study regarding flame separation, they also conclusively demonstrate that crosswinds can have a serious deleterious effect on the combustion efficiency of an open flame.
Since significant crosswinds are usually present along the Texas Gulf Coast,33 these wind effects must be accounted for. Yet, the TCEQ inappropriately dismissed the findings from the University of Alberta research when they reviewed the data in 2001 and 2002. We requested internal documents from the TCEQ relating to this review and found that the TCEQ dismissed the entire body of research from the University of Alberta based primarily on the TCEQ Staff’s review of only one 2001 study.34 In analyzing this study, the TCEQ Staff concluded:
• questionable simplifying assumptions were made in the development of a mathematical model from the experimental work on a pilot-scale facility; and
6 • poor flare destruction efficiency results obtained with field studies of a simple oil field flare could not be extrapolated to more sophisticated plant flares “with engineered burners and good liquid knockout systems.” 35
The University of Alberta researchers did not directly investigate commercial plant flares with engineered flare tips, but the basic findings of this study indicate that crosswinds affect combustion efficiency under a variety of circumstances. Thus, while we agree with TCEQ’s specific critiques, it is inappropriate for them to exclude the basic research by the University of Alberta on the basis that results of a field study of an oil field flare could not be directly applied to Gulf Coast flares because of design differences.
Baylor University collected some samples in canisters during flyovers it conducted in 2001 for TCEQ, but apparently there has been no follow-up to this work. We have found no documentation indicating that the EPA or the TCEQ subsequently considered the effects of crosswinds on flares in policies or guidelines related to flares.
In the TCEQ Emissions Inventory Guidelines, in the technical supplement on flares revised in 2004, TCEQ does acknowledge the potential for unstable flames in developing the 93% destruction efficiency to be used when 40 CFR 60.18 requirements are not met36. Nonetheless, neither the EPA nor the TCEQ routinely consider the critical variable of wind speed in permit reviews, compliance investigations or emission reduction planning. The entire question of crosswind impact on flare combustion efficiency appears to have disappeared from their deliberations, without explanation, for more than two decades.
Research being undertaken by the International Flare Consortium37 is intended to directly address the issue of crosswind effects on industrial flares and needs to be followed closely by the EPA and TCEQ.
Performance Testing
The absence of further study or testing by the regulatory authorities is particularly perplexing, since the TCEQ and the EPA acknowledge problems with accurately estimating air emissions generally, and from flares in particular. The TCEQ “has determined that [VOC] emissions may be underestimated in air shed emission inventories.”38 These deficiencies are important because emission inventories are the foundation for effectively controlling air pollution.39 And, since flare emissions represent a significant portion of an industrial plant’s ozone-forming emissions,40 undercounting of flare emissions could represent a significant portion of underestimated emission inventories.
Flare emissions, however, are much more difficult to measure than those of other pollution control devices. According to the EPA 1983 Flare Study, “Flare emission measurement problems include: the effects of high temperatures and radiant heat on test equipment, the meandering and irregular nature of flare flames due to external winds and intrinsic turbulence, the undefined dilution of flare emission plume with ambient air, and the lack of suitable sampling locations due to flare and/or flare heights, especially during process upsets when safety problems would predominate.”41 In addition, the EPA 1983
7 Flare Study specifically “excluded abnormal flaring conditions which might represent large hydrocarbon releases during process upsets, start-ups and shutdowns.”41
This, however, does not justify excusing the monitoring of flare emissions. Without proper monitoring it is impossible to know whether flares are performing as expected. The TCEQ expects “that emissions from flares would be better estimated if they were based on waste gas flow rate and composition measurements. … The overall objective of the [TCEQ] studies on flare emissions is to obtain performance specifications that ensure quality assured sampling, testing, monitoring, measurement and monitoring systems for waste gas flow rate, waste gas composition, and assist gas flow rate.”42 Modern insertion meters can measure mass flow within +1%, and continuous composition analyzers are readily available. However, measuring flows within an uncertainty of + 5% to 10% “in flare systems with highly variable compositions or where the meter cannot be located in a section of pipe with a representative flow profile will be a challenge.”43
Accordingly, the TCEQ now requires that operators of flares that burn HRVOCs – 1,3- butadiene, butenes, ethylene and propylene – continuously monitor compliance with “maximum tip velocity and minimum heat content requirements to ensure proper combustion by the flare.”44 These new regulations do not adequately reduce flare emissions, however, because:
• In setting the appropriate assist gas flow rates and aggregate flow velocity, it is important to know the composition of the flow. The TCEQ, however, does not require continuous composition monitoring. • Most operators control assist gas injections manually, based on the visual evaluation of the flame’s smokiness by the operator. Thus, depending on the skill and attention of the operator, significant fluctuations in heating value and exit velocities can occur over the course of an hour, such that substantial short-term fluctuations in heating value could offset each other. One study notes that the ratio of assist gas to waste gas with manual control varied from about 2 to more than 50.45 In this way, oversteaming can significantly reduce combustion efficiency without violating the minimum heat value requirement for the one-hour average. • Although most flares are designed to be most efficient at the high volumes experienced during non-routine operations, many are routinely used for disposal of low-flow emissions. • The TCEQ presumes that “because many of these flares are also used for non- HRVOC streams, the regulations will result in better combustion of other VOC streams as well. This improved combustion will reduce emissions of less-reactive VOCs.”46 The TCEQ, however, did not make the continuous monitoring requirement applicable to waste gas streams of other VOCs. So there is no quality control on flares that burn only other VOCs and air toxics, which could represent a significant volume of VOC emissions in the Houston-Galveston area. • The results of industry monitoring are not readily accessible to the public. Although the San Francisco Bay Area has far fewer industrial flares emitting much lower volumes of pollutants, the Bay Area Air Quality Management District (BAAQMD) in California requires all refinery operators with elevated flares to submit monthly reports of daily quantities (and species) of releases during the
8 period reported.47 The BAAQMD posts these reports, complete with graphs illustrating daily spikes in emissions, on its website.48 • Historically, TCEQ enforcement of monitoring requirements, if any, generally comprised only minor recordkeeping violations. • The monitoring requirements on many flares with the potential for substantial emissions are significantly weaker. Generally, these relaxed regulations require only a combination of calorimeter, engineering calculations and process knowledge for monitoring flares used for abatement of emissions from loading operations, maintenance, startup and shutdown activities, emergencies, temporary service, liquid or dual phase streams, and metal alkyl production processes.49
In addition, the type of continuous monitoring required by the TCEQ may not be adequate. Flow measurement devices typically “calculate volumetric flow by sensing a velocity in the pipe and multiplying that velocity by the cross sectional area of the pipe in which the velocity is being sensed.”50 The accuracy of these measurements, however, is based on assumptions that:
• velocity is uniform across the cross section; and • the gas is of a known composition.
Thus, frequent changes in the waste gas composition could significantly marginalize the quality of flare performance assessments.
Although safety concerns may preclude direct monitoring of emissions, parametric monitoring and remote sensing techniques do exist which would provide data more indicative of actual flare performance and emissions. For example, Open Path Fourier Transformation Infrared (FTIR) technology “can identify, measure, and speciate over 100 compounds” from a distance of more than 100 meters.51 FTIR is particularly suited for VOC identification and quantification because VOCs present strong absorption spectra in the infrared region.52
In the near term, the TCEQ could follow the lead of California regulators in requiring more extensive reporting of flare operations and emissions as a means to identify priorities in reducing flare emissions and motivating operators to undertake emission reduction projects sooner rather than later. Even before the BAAQMD issued its Flare Monitoring Rule, its staff reported that flaring dropped dramatically because of increased industry attention to flaring and flare monitoring.53
Similar observations were made in Southern California. Their monitoring rule, Rule 1118 – Emissions from Refinery Flares, was promulgated by South Coast Air Quality Management District (SCAQMD) in 1998 and amended in November 2005. During the period from 2000 to 2003, SOx emissions were reduced from 2633 tons to 735 tons with only a fraction attributed to new equipment and the rest to expanded use of “ best management practices.”54
These same data showed 79% of emissions were from unknown causes or nonrecordable events. In response SCAQMD amended Rule 1118 to require a “Specific Cause
9 Analysis” of significant flaring events as defined by 1118 (c)(D), or an analysis of the relative cause of “any other flare events where more than 5,000 standard cubic feet of vent gas are combusted. (Rule 1118 (c)(E)). The revised rule also incorporates other provisions to further reduce flaring emissions, such as mitigation fees and flare management plans (1118 (d)).
Require Alternatives to Elevated Flares
For more consistent reductions in flare emissions over the long term, the TCEQ could require alternatives to elevated flares. It is common practice for industry to use elevated flares for routine destruction of vent gases or off-spec hydrocarbons, not just for emergency or short-term releases. Most flares are built for non-routine events, such as upsets, startup and shutdown, so they are not designed for optimal efficiency at low temperatures and low flow rates.55 Consequently, routine flaring may result in unnecessary emissions of HRVOCs, VOCs and toxic materials.
The TCEQ appropriately requires that many vent and relief valve emissions be controlled, rather than vented to the atmosphere. Ideally, these routine emissions should be recovered in a flare gas recovery system,56 which recycles the valuable components of the waste stream, using an elevated flare only as a backup system.
Where gas recovery is impractical, we believe TCEQ should require operators to install high efficiency combustion devices to handle all predictable demand. Enclosed ground flares, incinerators and thermal oxidizers are acceptable alternatives because they can consistently achieve high combustion efficiencies as a result of the enclosed firebox, longer residence times at high temperature and negligible wind effects.
But high-efficiency combustion devices themselves need further attention from the TCEQ as well. Like owners of motorized vehicles, operators should be required to demonstrate the emission control performance of each device on an annual basis. After the TCEQ gains experience with the results of such testing, the frequency for specific classes of equipment, or particular companies, could be adjusted to ensure that testing occurs at appropriate intervals.
While avoiding flaring of routine vent gases is important, minimizing episodic emissions may be even more critical in reducing emissions of combustion byproducts, carbon monoxide (CO), carbon dioxide (CO2) and nitrogen oxides (NOx). As demonstrated by the example cited earlier, emissions from a single episodic event can exceed annual average emissions. In reviewing emission events occurring during 2003, the University of Texas’ Center for Energy and Environmental Resources found that the Houston Galveston Area averaged more than one emission event per week: “Over an 11-month period there are 58 times (affecting 395 hours) when ethylene event emissions exceed the 2000 annual average of 586 lbs/hr and 7 times (affecting 44 hours) when event emissions exceed 5 times the annual average.”57 Unlike in the rest of Texas, and the rest of the United States, emissions in Houston “change all the time,” and “[p]oor air quality [is] due mostly to days with both ozone conducive meteorology and high emissions.”58 Hence
10 preventing unnecessary releases may provide the greatest decrease in overall VOC emissions while also reducing emission of combustion byproducts, CO, CO2, and NOx.
In an effort to reduce such variable emissions, EPA Region 6, the Texas Natural Resources Conservation Commission (TNRCC, predecessor to the TCEQ), the Louisiana Department of Environmental Quality, and 13 petrochemical facilities in Louisiana and Texas, participated in the Episodic Release Reduction Initiative. In 1999 and 2000, the Initiative participants evaluated “the causes of releases to the air associated with startups/shutdowns, equipment failures, and process upsets.”59
In the Technical Exchange on Startup/Shutdown practices, petrochemical facilities shared case studies and examples of methods used to reduce flaring. Participants noted that changes to procedures and training as well as design improvements could be used to reduce emissions.60 Key findings on ways to reduce emissions include:
• using flare gas recovery systems for routine venting and planned shutdowns; • improving training of operators, better documentation of procedures highlighting environmental impacts, and allowing additional time for startup and shutdown; and • reducing flaring among ethylene producers by recycling off-spec streams to furnace feed, augmenting the plant’s steam capacity, and using a ground flare to handle off-spec and startup loads.
Since that time, individual facilities in Texas have implemented site-specific programs to reduce flaring. In 2001, the Dow Chemical Plant in Freeport, TX initiated a flare minimization project at the Light Hydrocarbons plant. Before project implementation, nearly all off-spec hydrocarbons at the unit, which includes an ethane/propane cracking process, were flared. By optimizing equipment and procedures related to plant start-up, shutdown, upsets and plant trips, including improving overall plant reliability, the plant had an “89% reduction in overall upset flaring – using a two year running average.” Further, from 2001 to the end of 2003, the plant achieved documented savings of $2.5 million.61
Also in Texas, Shell Chemicals developed a “parking mode” to reduce feed rates during upset conditions in order to minimize flaring at its two ethylene units in Deer Park. Implementation resulted in a 50% reduction in flaring between 2002 and 2003.62
In the San Francisco Bay Area, flare minimization projects and studies such as these are now required of refineries regulated by BAAQMD under Regulation 12, Rule 12: “Flares at Petroleum Refineries”, adopted July 20, 2005. This rule builds on their 2003 rule, Regulation 12, Rule 11: “Flare Monitoring at Petroleum Refineries”. Flare minimization plans submitted under Rule 12 must be approved by the Air District and “must include:
• Detailed information about equipment and operating practices related to flares, • Steps the refinery has taken and will take to minimize the frequency and duration of flaring, and
11 • A schedule of implementation of all feasible flare prevention measures.”63
TCEQ should consider implementing regulations similar to BAAQMD Rule 12 that would encourage other facilities in Texas to follow the examples of Dow and Shell cited above.
More extensive testing and reporting by plant operators on the operating parameters and performance of flares and other waste gas combustion devices also would help the TCEQ enforce existing regulations and identify priorities for reducing the use of elevated flare stacks as emission control devices.
CONCLUSION AND RECOMMENDATIONS
We conclude that the TCEQ must take action to determine more realistic flare destruction efficiencies, minimize the volume of emissions routed to elevated, unenclosed flares, and encourage the use of flare gas recovery systems, or wind-protected ground flares and thermal oxidizers. Specific recommendations are as follows:
1. Enforce existing requirements for flare operations rigorously and consistently.
2. Expand and accelerate TCEQ, EPA and others’ research on the factors affecting combustion efficiency of flares, alternatives to flares and flare monitoring technologies.
3. Revise TCEQ policies and guidelines for estimating flare emissions. At a minimum, the effects of steam and crosswinds should be factored into emission estimates for rulemaking, permitting, enforcement, reporting and planning activities. These effects must be based on best available data rather than assumed values.
4. Conduct a rulemaking proceeding for regulations requiring more extensive monitoring and reporting of flare emissions. At a minimum, operators should be required to report daily emissions each month, and the TCEQ should post these reports on its website.
5. Develop a strategy to increase the use of flare gas recovery systems or, where impractical, use of more effective destruction technologies, such as enclosed ground flares or thermal oxidizers, rather than elevated flare stacks, as emission control devices.
6. Use elevated flare stacks only for release of combustibles in emergencies, for safety reasons, or as necessary during planned startups or shutdowns of equipment.
12 7. Divert uncontrolled emissions from vents and relief valves to vapor recovery systems and other alternatives to flares, with flares serving only as a backup system. The TCEQ should set a goal for eliminating uncontrolled, authorized VOC emissions by a specified date, and systematically review its regulations and permitting policies to identify steps towards that goal.
8. Test high efficiency combustion devices, such as enclosed ground flares and thermal oxidizers, regularly to demonstrate emission control performance.
REFERENCES
1. Gabriel Cantu, TCEQ, 2000 Houston - Galveston Speciated Point Source Modeling Inventory, October 2003, Slide 17. 2. TCEQ publication RG-109 (Draft) Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers, October 2000, pp.19, 35. 3. TCEQ,“Technical Justification For 99% Flare Efficiency,” attached as Appendix L to Revisions to the SIP for the Control of Ozone Air Pollution, HGB Ozone Nonattainment Area (HGB 2004 SIP Revisions), October 2004. 4. Federal Register May 4, 1998, pp. 24436-24437, Standards of Performance for New Stationary Sources: General Provisions; National Emission Standards for Hazardous Air Pollutants for Source Categories: General Provisions 5. James Seebold, Peter Gogolek, John Pohl, & Robert Schwartz, “Practical Implications of Prior Research on Today's Outstanding Flare Emissions: Questions and a Research Program to Answer Them”, Presented at AFRC-JFRC 2004 Joint International Combustion Symposium, Environmental Control of Combustion Processes: Innovative Technology for the 21st Century, October 10 – 13, 2004, Maui, HI. 6. TCEQ, RG-109, pg. 19. 7. Flare Efficiency Study, EPA-600/2-83/052,. USEPA, Cincinnati, OH July 1983 (EPA 1983 Flare Study) Table 1.Flare Efficiency Test Results, p. 4. 8. URS Corp., Extraction of Allowable VOC Release Levels From TCEQ permits, prepared for Houston Advanced Research Center Texas Environmental Research Consortium, April 15, 2004. 9. 40 CFR §60.18(c)(2). 10. 40 CFR §60.18(c)(1). 11. TCEQ Work Assignment 5 Draft Flare Gas Flow Gas Rate and Composition Measurement, Methodologies Evaluation Document, prepared by Shell Global Solutions (US), Inc., p. 5-1. (Measurement Methodologies Evaluation). 12. Measurement Methodologies Evaluation, p. 1-6. 13. John F. Straitz, III, “Clearing the Air About Flare Systems,” Chemical Engineering, September 1996, reprint, p. 5. 14. Straitz, p. 5. 15. Measurement Methodologies Evaluation, p. 5-1. 16. Measurement Methodologies Evaluation, p. 5-5. 17. Measurement Methodologies Evaluation, p. 5-2. 18. EPA 1983 Flare Study, p. ii.
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19. 40 CFR §60.18(c)(3) and (4). 20. EPA 1983 Flare Study, Table 1, p. 4. 21. Measurement Methodologies Evaluation, p. 5-6. 22. Measurement Methodologies Evaluation, p. 5-2. 23. Measurement Methodologies Evaluation, p. 5-3. 24. Seebold, et al. 25. Cynthia Folsom Murphy and David T. Allen, “Event Emissions in the Houston Galveston Area” (HGA), January 14, 2004 (Event Emissions in HGA), p. A-31, available at www.harc.edu/harc/Projects/AirQuality/Projects/Status/H13.aspx. 26. Joseph T. Haney, Jr., and Laura Carlisle, Toxicology & Risk Assessment, Office of Permitting, Remediation & Registration, TNRCC Interoffice memorandum to Dan Thompson, Director, Region 12, Houston, July 31, 2002, p. 3. 27. Reference omitted to protect the company. 28. Measurement Methodologies Evaluation, p. 5-5. 29. 30 TAC §115.725(d)(7). 30. EPA 1983 Flare Study, p. 19. 31. M.R. Johnson, O. Zastavniuk, J.D. Dale and L.W. Kostiuk, “The Combustion Efficiency of Jet Diffusion Flames in Cross-flow,” presented at the Joint Meeting of the United States Sections – The Combustion Institute, Washington, D.C., March 15- 17, 1999. 32. Matthew R. Johnson, Adrian J. Majeski, David J. Wilson and Larry W. Kostiuk, “The Combustion Efficiency of a Propane Jet Diffusion Flame in Cross Flow,” presented at the Fall meeting of the Western State Section of the Combustion Institute, Washington, October 26-27, 1998 (Paper #98F-38). 33. Houston’s average annual wind speed is 7.9 miles per hour and Galveston’s is 11.0 miles per hour. See the University of Utah Department of Meteorology’s Utah and National Climate Data at http://www.met.utah.edu/jhorel/html/wx/climate/windavg.html. 34. Douglas M. Leahey, Katherine Preston and Mel Strosher, Theoretical and Observational Assessment of Flare Efficiencies, 51 J. Air & Waste Mgmt., 1610, 1611 (2001) 35. Karen Olson, Email to Terry Blodgett, et al., February 27, 2002, 11:31 AM (Olson Feb. 27 Email) (from TCEQ Response to Open Records Request, March 29, 2005 (Mar. 29 Response). 36. TCEQ publication RG-360, 2005 Emissions Inventory Guidelines, Technical Supplement 4; Flares, January 2006, p. A-46. 37. International Flare Consortium web site: URL http://home.earthlink.net/~international-flare-consortium/index.html. Accessed March 2006. 38. Measurement Methodologies Evaluation, p. E-1. 39. TCEQ Science Synthesis Committee, “Accelerated Science Evaluation of Ozone Formation in the Houston-Galveston Area,” November 13, 2002, p. 4. An analysis of scientific data on ozone formation in the Houston-Galveston area as part of the TCEQ’s Texas Air Quality Study in the summer of 2000.
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40. Cantu, TCEQ, 2003, Slide 17. 41. EPA 1983 Flare Study, p. 1. 42. Measurement Methodologies Evaluation, p. E-1. 43. Measurement Methodologies Evaluation, p. 6-1 to 6-2. 44. HGB 2004 SIP Revisions §1.6.2.1 Collateral VOC Reductions. 45. Measurement Methodologies Evaluation, p. 5-4. 46. HGB 2004 SIP Revisions §1.6.2.1 Collateral VOC Reductions. 47. Bay Area Air Quality District Regulation 12-11-401. 48. URL http://www.baaqmd.gov/enf/flares. 49. 30 TAC §115.725(e)-(k). 50. Measurement Methodologies Evaluation, p. 2-1. 51. Survey and Demonstration of Monitoring Technology for Houston Industrial Emissions (Project H31.2004) ENVIRON International Corporation. Prepared for Houston Advanced Research Center, January 12, 2005, pp. 3-12 to 3-13 (Monitoring Technology for Houston). 52. Monitoring Technology for Houston, p. 3-16. 53. BAAQMD Staff Report, Regulation 12, Rule 11, p. 31-32. 54. SCAQMD Summary Evaluation Report on Emissions from Flaring Operations at Refineries, Version 1, September 3, 2004. 55. Matthew R. Johnson, et al. (University of Alberta), “The Combustion Efficiency of a Propane Jet Diffusion Flame in Cross Flow,” presented at the Fall Meeting of the Western States Section of the Combustion Institute, Washington, October 26-27, 1998, p. 11. 56. P.W. Fisher and D. Brennan, “Minimize Flaring with Flare Gas Recovery,” Hydrocarbon Processing, June, 2002, p. 83. 57. Event Emissions in HGA, p. A-21. 58. Harvey Jeffries, et al. Stochastic Emissions Inventories for Houston Point Sources, Concepts and Examples, presentation to TCEQ, October 2000, Slide 2, available at URL http://www.airchem.sph.unc.edu/Research/Projects/Texas/MCCG/ (emphasis in original). 59. The Episodic Release Reduction Initiative, July 5, 2001 (ERRI), p. 1, URL http://www.epa.gov/earth1r6/6en/a/erri07-5fin.pdf. 60. ERRI, Appendix F, pp.32-36. 61. Steven Krietenstein, “Flare Minimization Strategy During Plant Upsets: Freeport” presented at 2005 AIChE Spring National Meeting, 17th Annual Ethylene Producers’ Conference, Session TA009 – Ethylene Plant Operations, Atlanta, GA, April 12, 2005. 62. Nicholas Genty and Bryce Kagay, “Development of a Parking Mode at Shell Chemical’s Deer Park Plant Olefin Unit OP-III, presented at 2005 AIChE Spring National Meeting, 17th Annual Ethylene Producers’ Conference, Session TA009 – Ethylene Plant Operations, Atlanta, GA, April 12, 2005. 63. BAAQMD Press Release July 20, 2005, “Air District Board Adopts Refinery Flare Rule”.
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KEY WORDS flare, combustion, emissions, combustion efficiency, destruction efficiency, air pollution, crosswinds, ozone, ozone-forming emissions, HRVOC, VOC, elevated flare, ground flare, thermal oxidizer, flare minimization, flare gas recovery, refinery, petrochemical, TCEQ, BAAQMD, University of Alberta. Alberta Resource Council, Houston- Galveston, Gulf Coast, FTIR, International Flare Consortium
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This page intentionally left blank. FACT SHEET
PROPOSED SETTLEMENT AGREEMENT BETWEEN ENVIRONMENT TEXAS, SIERRA CLUB AND SHELL OIL COMPANY
Since 2003, Shell Oil Company’s oil refinery and chemical plant in Deer Park, Texas, have emitted approximately five million pounds of air pollutants during hundreds of so- called “upsets” or “emission events” – equipment breakdowns, malfunctions, and other non-routine occurrences. Environment Texas and Sierra Club sued Shell in January 2008 for approximately a thousand separate violations of the federal Clean Air Act since 2003 related to these emission events. The Texas Commission on Environmental Quality has issued fines and violation notices to Shell, but failed to solve the problem.
This settlement has been agreed upon by the parties and filed in court, but requires the approval of U.S. District Judge David Hittner before it can take effect.
HIGHLIGHTS OF PROPOSED SETTLEMENT AGREEMENT
Reduction Of Upset Emissions
• Within three years, Shell must reduce its emissions from upset events by nearly three-quarter of a million pounds per year compared to its current performance, reducing its emissions by approximately 60% in year one, 75% in year two, and more than 80% in year three. • Failure to meet these annual emission caps – for total pollutants and for individual chemicals – will subject Shell to automatic monetary penalties for each pound of pollutants above the caps. • Shell will face enhanced monetary penalties for each pound of excess benzene and 1,3-butadiene emissions, and for large exceedances of the overall caps.
This unique approach to upset events – a “hard cap” on emissions, regardless of cause – creates a powerful incentive for Shell to prevent upsets and minimize pollution releases.
Physical And Operational Upgrades to Further Reduce Emissions
• Olefins Unit Ground Flare: This flare handles an enormous load of emissions and likely operates at combustion efficiency levels far below EPA requirements. Shell must upgrade the flare and operate it at 98% efficiency – which could reduce emissions of VOCs by hundreds or thousands of tons per year.
• Coker Unit: Shell must make several major upgrades to the wet gas compressor at the refinery’s Coker Unit, which has been responsible for significant emission events.
• Flare Minimization Plan: Shell must create and implement a plant-wide flare minimization plan in accordance with California’s toughest-in-the-nation guidelines.
• Tank Emissions: Shell must implement new emission controls on tanks within three years, rather than the ten years allowed by new EPA regulations for hazardous air pollutants.
• Hurricane Preparedness: Shell must implement and continuously update a facility- wide plan to minimize emissions during plant-wide emergency shutdowns.
• Steam Supply: Shell must make further upgrades to its steam supply system if steam supply failures continue to cause pollution releases.
Enhanced Monitoring of Emissions
• Infrared Scanning for Leak Detection: Shell must conduct real-time infrared scanning, focusing on the pollutants of greatest concern (such as benzene) in the areas of the plant most likely to generate unmonitored emissions (such as tanks).
• Flare Mapping: Shell must, for the first time, create and continuously update complete and accurate maps of all connections and flows to its flares.
• Emission Event Tracking and Prevention System: Shell must implement a facility- wide system to track and prevent upset events and “near-miss” events that could have resulted in unauthorized emissions.
The cost of all upgrades and monitoring may be in the tens of millions of dollars.
Civil Penalty and Local Environmental Projects
Shell must pay a civil penalty of $5.8 million for its past violations. Plaintiffs believe this is the largest environmental citizen suit penalty in Texas history and nationally one of the largest ever against a single facility.
The entire penalty payment will be used to fund local environmental, health and education projects:
• $3,600,000 to the Houston-Galveston Area Council for disbursal to local school districts to retrofit or replace polluting diesel school buses with cleaner or alternative-fueled models, with priority given to projects in eastern Harris County. • $2,000,000 to the Houston Advanced Research Center to fund the East Harris County Solar Energy Pilot Program, a project to install and test commercially available solar energy systems on public buildings. • $200,000 to the Galveston-Houston Association for Smog Prevention (GHASP) and Mothers for Clean Air to fund the Ozone Theater Project, an award-winning interactive program to educate elementary- and middle-school students in Harris County about air pollution.
BACKGROUND: AIR POLLUTION FROM “EMISSION EVENTS” AT SHELL DEER PARK
AIR POLLUTANTS EMITTED DURING SHELL’S EMISSION EVENTS (1) (in pounds)
POLLUTANT 2003 2004 2005 2006 2007 2008 Total
SO2 501,840 742,378 329,876 95,187 519,562 194,196 2,383,039
VOCs (2) 63,625 325,208 380,449 116,471 421,172 172,466 1,479,391 Carbon monoxide 12,236 143,714 266,116 49,660 205,850 173,171 850,747
NOx (3) 11,299 20,780 85,036 5,978 132,969 24,025 280,087
Benzene 28,674 1,620 44,470 13,077 3,752 6,114 97,707
1,3-Butadiene 180 34,475 22,497 2,725 3,283 3,472 66,632 Hydrogen sulfide 4,848 11,266 3,807 982 6,639 2,028 29,570
TOTAL 593,848 1,243,346 1,065,284 268,278 1,286,192 575,472 5,032,420
(1) Emission data is calculated from Shell’s own emission event reports to TCEQ; only emissions that violated a permit limit (even if not all of the amount emitted was above the limit) are included here. (2) VOC totals include benzene and butadiene. (3) NOx includes NO2, NO and nitric oxide.
SHELL’S UPSET EMISSIONS AND AIR QUALITY IN HARRIS COUNTY
Air quality in Harris County is consistently ranked as among the worst in the nation, particularly for ground-level ozone, or smog. On more than 50 separate occasions beginning in 2003, Shell Deer Park emitted nitrogen oxides (NOx) and/or volatile organic compounds (VOCs) – both of which contribute to the formation of ground-level ozone – during upset events that occurred within 24 hours of an ozone exceedance day in the Houston Ozone Non-Attainment Area.
Air toxics are also of great concern. Certain VOCs emitted during upset events at Shell Deer Park are hazardous air pollutants, and some – such as benzene and 1,3- butadiene – are carcinogens.
Shell has also emitted illegal levels of sulfur dioxide (SO2), which can cause respiratory problems and acid rain; carbon monoxide (CO), which also contributes to ozone formation; and hydrogen sulfide (H2S), which smells like rotten eggs and can irritate the eyes, nose and throat.
April 1, 2009
Ms. Lindley Anderson Air Quality Division, MC-206 Texas Commission on Environmental Quality P.O. Box 13087 Austin, Texas 78711-3087
Dear Ms. Anderson,
Enclosed are the comments of the Houston Regional Group and Lone Star Chapter of the Sierra Club (Sierra Club) regarding the Flare Task Force Stakeholder Group Meeting that was held in Houston, Texas on March 30, 2009.
The Sierra Club supports TCEQ’s efforts to determine whether flares should be regulated further to reduce air emissions. It has long been a Sierra Club contention that flares are greater sources of air emissions than reported and need additional regulation. The Sierra Club has the following comments about flares:
1) The Sierra Club strongly encourages the TCEQ to not prejudge whether a flare recovery and minimization plan should be required for all flares or a certain segment of the flare population. The Sierra Club does not believe because there are a great number of flares that this fact should keep TCEQ from requiring such a plan.
As we stated at the March 30, 2009 public meeting, TCEQ can prepare a rule in a manner that requires staggered submittal of flare recovery and minimization plans so the work load is acceptable. Since the Houston-Galveston-Brazoria Ozone Non-Attainment Area is so badly out-of-compliance no obvious source of ozone precursors should be taken off the table simply because there are many such sources. In fact the large number of sources argues for regulation because emission reductions could be potentially large.
While it is good to have industry agree voluntarily with a regulation that TCEQ wants to implement regarding a flare recovery and minimization plan industry’s approval should not be allowed to delay any needed regulation of flares via these plans. The Sierra Club’s experience is that industry will delay and fight regulations and that TCEQ must take a firm stance and implement regulations. It is the public’s health is at risk and protection of the public’s health must take precedence over industry’s liking for a particular regulation or plan. After all people get sick and die from air pollution the longer that we allow industry to delay needed air pollution reductions.
2) The Sierra Club urges TCEQ to pay particular attention to the trade-off between any increase in visible emissions versus the reduction of volatile organic compound (VOC) emissions when considering flare controls and operation. The Houston area is almost in non-attainment for particulate matter and any allowance for more particulate matter from flares (visible emissions) could cause particulate matter non-attainment problems for our area and health problems for our citizens.
3) The Sierra Club supports the use of infrared cameras and DIAL (differential absorption Lidar) as monitoring methods that can be used for compliance and enforcement and emissions inventory purposes. The best monitoring of flares, both by a company and by the TCEQ, should be required so that excess air emissions can be discovered and eliminated or reduced.
4) The Sierra Club is particularly interested in alternatives to flares. While actual emergencies may call for a flare, routine use of other flares as control devices, in our view, is fraught with problems because TCEQ cannot easily tell if the destruction efficiency of 98-99% is actually being achieved. Without some type of real time monitoring that can conclusively show such destruction efficiency success and due to the large amount of air emissions produced with less efficient destruction efficiencies it makes sense to eliminate routine flaring of waste products as either best available control technology, lowest achievable emissions rate, or best management practices. As much as possible chemicals sent to a flare should be recovered and recycled back into the process. This reduces air emissions, increases product efficiency, and saves money.
5) The Sierra Club urges TCEQ to ensure that all flares for oil/gas fields have been included in its flare population. The Sierra Club has seem a number of these flares out in-the-field and we are concerned that they are isolated sources and if not operated properly can become area sources of VOC that are not easily noticed or considered for enforcement and compliance work.
6) Because so many things affect proper flare operation, including crosswinds, high winds, variable gas stream composition, BTU value of the gas stream, excessive assist gas, improper air or steam assist, appropriate maintenance, high turndown ratios, etc., if flares are to be used then specific requirements for their use may be needed. If such requirements are too onerous in a particular application then perhaps a flare should not be allowed in that instance.
7) The Sierra Club supports research and testing of flares to gain additional information but does not want such actions to overtly delay additional regulation of flares.
8) Finally, any information collected about flares, during monitoring, testing, or research should be made available to the public. After all the public’s health is threatened by air pollution and the public has a right to know where and what emissions, that could harm them, are emitted.
The Sierra Club appreciates this opportunity to comment. Thank you.
Sincerely,
Brandt Mannchen Air Quality Issue Char Lone Star Chapter of the Sierra Club Chair, Air Quality Committee Houston Regional Group of the Sierra Club 5431 Carew Houston, Texas 77096 713-664-5962 [email protected]
May 8, 2009
Ms. Lindley Anderson MC 206 Air Quality Division Chief Engineer’s Office Texas Commission on Environmental Quality PO Box 13087 Austin, Texas 78711-3087
RE: Flare Taskforce: Informal Comment Submittal
Dear Ms. Anderson:
Texas Chemical Council (TCC) and Texas Oil and Gas Association (TXOGA) appreciate the opportunity to provide comments on issues raised by the agency’s industrial flare task force. Our organizations are working together to prepare more detailed comments which will be available to the agency in the near future.
TCC is a statewide trade association representing 77 chemical manufacturers with more than 200 Texas facilities. The Texas chemical industry has invested more than $50 billion in physical assets in the state and pays over $1 billion annually in state and local taxes. TCC’s members provide approximately 70,000 jobs and over 400,000 indirect jobs to Texans across the state. TCC member companies manufacture products that improve the quality of life for all Americans. Chemical products are the state’s largest export with over $30 billion each year.
TXOGA, the largest and oldest oil and gas association in Texas, represents 4,000 members of the oil and gas industry. The membership of TXOGA produces in excess of 90 percent of Texas’ crude oil and natural gas, operates some 95 percent of the state’s refining capacity, and is responsible for a vast majority of the state’s pipeline mileage. The oil and gas industry employs 189,000 Texans, providing payroll and benefits of over $22 billion in the most recent data. In addition, large associated capital investments by the oil and gas industry generate significant secondary economic benefits for Texas.
The work of the agency’s flare task force is of significant interest to our membership. We respectfully request your careful and thoughtful consideration of our suggestions. If you have any questions on these informal comments, please contact:
For TCC: Mike McMullen at (512) 646-6404 or Susan Moore at (832) 474 4118. For TXOGA: Deb Hastings at (512) 478 6631 or James Murray at (281) 834 0154.
Sincerely,
Mike McMullen, TCC Deb Hastings, TXOGA
1
An Overview of Texas Chemical Council’s (TCC) and Texas Oil & Gas Association’s (TXOGA) Pending Detailed Comments on Industrial Flares
Background
There are over 1000 flares in Texas according to Texas Commission on Environmental Quality. Many of these flares are used at industrial facilities to combust flammable, toxic, or corrosive vapors to less objectionable compounds. (API 521 paragraph 6.4.1). Flares are first and foremost safety devices designed to protect people and equipment. Such use of flares should not be discouraged through regulation. Typical flow to flare systems include: emergency (pressure relief flows and emergency depressurization), episodic (venting required for maintenance or regeneration and de-inventorying for shutdown and/or startup operations), and continuous flows (sweep gas through flare system piping, process venting of analyzer flows, gas seals, certain types of pressure control, and PRV leakage).
At its Flare Task Force Stakeholder Group meetings on March 30 and April 2, 2009, the Texas Commission on Environmental Quality expressed a strong interest in additional review of industrial flares for a number of reasons including:
1. A belief that flare emissions account for 60% of the highly reactive volatile organic compounds (HRVOC) reported in the Houston Galveston Brazoria special air emission inventory. 2. Flare emissions depend heavily on a flare’s destruction efficiency which may vary depending on flame stability, operating conditions, flare tip size and design, the specific compounds being combusted, and gas composition. 3. Recent agency initiatives including the 2007 DIAL study in Texas City and use of the gas imaging infrared (IR) camera to conduct fence-line flare monitoring raised additional questions that might be addressed with further study.
The agency indicated tentative topics for evaluation include flare performance, flare monitoring issues, and alternative emission control; Texas Chemical Council (TCC) and Texas Oil and Gas Association (TXOGA) are pleased to offer a summary of our pending, detailed comments on these topics.
Section 1: Flare Performance
Issue:
Flare performance may be impacted by many variables including meteorology, waste gas stream flow rate and composition, operational practices dealing with steam, air and natural gas assist rates, and flare tip design. These numerous variables all play a role in ensuring adequate flare performance.
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Discussion:
TCC and TXOGA believe most flares operate efficiently. The main indicator of efficient performance is a stable flare flame.
The challenge for the regulated community and for the agency is to establish a clear understanding of proper flare operation and design. This would include understanding flare efficiency from at least two aspects--1) Destruction Rate Efficiency (DRE), which measures the efficiency of the chemical destruction of the original combustible components in the flow to the flares and 2) Flare Combustion Efficiency (FCE), which measures the efficiency in completing combustion of the original combustible components in the flow to the flares. The difference between DRE and FCE is that in DRE the chemical destruction of the original components in the flow to the flares will measure whether a given component (e.g., ethylene) is completely destroyed. This destruction may, however, be accomplished by producing intermediate combustion products. In FCE, the measurement is only whether the given component (e.g., ethylene) is completely converted to CO2 and H2O.
Flare efficiency may be adversely affected by crosswinds, according to some studies in the scientific literature. Many of the studies are on small flares (< 12 inches) in wind tunnels. These types of tests are not broadly applicable to general flaring conditions in petrochemical plants where scale-up to actual conditions is difficult, if not impossible. In addition, some studies suggest that certain compositions are less affected by crosswinds. However, available data are not sufficiently comprehensive to make these conclusions for actual operating flares.
Some compounds and mixtures can be flared at higher velocities than others. If pressure assist is available, most gases can be flared at sonic velocities with no steam or air assist needed. For specific compounds and mixtures, flare designers have enough experience to design for the appropriate exit velocity range for a given mixture and flare tip design.
Tests have established that stable flare flames can be achieved resulting in efficient performance over a wide range of steam-to-fuel ratios. Steam assist rates needed for efficient performance have a wide range of effectiveness depending on the flare tip design and size, flare gas composition, available steam pressure, and steam addition system variations. Tests suggest that steam-to-fuel ratios above the smoke point and below the snuffing point result in efficient operation. A similar variation in air rates for an air assisted flare is possible. Strict adherence or control to a tight steam-to-fuel ratio is not needed as long as operation above the “smoke point” and below the “snuff point” for a specific flare system is maintained. This operating range is most times wider than the vendor recommended range for ideal operation.
Path Forward:
Given the large number of variables that can impact flare performance and the uniqueness of each site’s equipment, a case-by-case methodology is needed to assess flare efficiency. The scale up of smaller flare test work to full scale operating flares is a problem yet to be resolved.
3 TCC encourages the development of a method that is capable of determining the operating window or envelope for efficient operation. It should be sensitive enough to (1) identify performance at low flows and at low and high steam-to-fuel ratios and (2) determine if crosswinds result in inefficient performance while, at the same time, understanding if mitigating measures are successful in maintaining efficient operation. Ideally the technique would utilize a remote sensing tool that could establish the operating window of efficient flare performance for any specific flare installation. We envision use of this device as analogous to a compliance test that is done on a periodic, rather than continuous basis. Furthermore, the effects of composition and flare tip design relative to the effects of crosswinds on flare performance may warrant additional study.
Section 2: Flare Monitoring
Issue
The agency indicated in recent stakeholder meetings a desire to better understand the adequacy of existing monitoring requirements (in particular, flare gas flow rates, net heating value, and other parameters) and whether or not existing steam/air assist flares are adequately monitored and “maintained within manufacturer’s design ranges”.
Discussion
Flares are used for emergency, episodic, and continuous flows as described in the background section of this summary. The flow and composition of the stream to a flare can be highly variable, especially if the flare handles both routine and non-routine releases. In addition, flare flow and composition can vary considerably if streams are collected from multiple units and sent to the same flare. When a flare handles routine process flows as well as emergency relief flows, the flow rate may vary from a few hundred pounds per hour to several hundred thousand pounds per hour, and the flare stream could be a chemical mixture of only a relatively small number or compounds or one of potentially a hundred or more compounds. The wide range in both the flow and the potential chemical composition leads to inherent flare monitoring challenges. Based on industries’ experience in the HRVOC monitoring program, identifying a flow meter that can accurately measure the flow over such a potentially broad range of VOCs is difficult at best. A flow meter with a very broad range has a higher degree of accuracy at one end of the spectrum when compared to the other end of the spectrum. To accurately measure flare flow, this technical challenge must be overcome in a reliable and cost-effective manner. Analyzing the flare stream composition also presents technical challenges. The time required for a Gas Chromatograph (GC) analysis increases as the number of chemical components in the stream increases. For example, the PAMS GC that TCEQ and industry use at certain ambient air monitoring sites analyze for 55 compounds and generate one data point per hour. The GC used for the HRVOC monitoring is configured to identify five compounds and is capable of generating the required data point every 15 minutes. The need for complete compositional data should be weighed against the objectives of the monitoring program because the complexity of the analysis increases dramatically with increasing requirements for additional component review. Consideration should be given to the merits of measuring other stream characteristics to
4 provide similar flare efficiency information. For example, direct measurement of heat content can provide data to support determination of the flare’s operating efficiency.
Path Forward:
The wide range in both the flow and the potential chemical composition leads to inherent flare monitoring challenges. To accurately measure flare flow over a wide range, improvements in existing flow measurement technologies are necessary. This technical challenge must be overcome in a reliable and cost-effective manner. Additional studies on analyzers, flow instruments, or computer software could lead to improvements in technologies for flow measurement. Continuous gas composition analysis of complex chemical mixtures is neither cost- effective nor efficient. Consideration should be given to the merits of measuring other stream characteristics to provide similar flare efficiency information. For example, direct measurement of heat content can provide data to support determination of the flare’s operating efficiency. Steam assist and air assist rates needed for efficient performance have a wide range of effectiveness that is influenced by flare tip design and size, flare gas composition, and other site-specific system variations. Any regulatory schemes that might be deemed necessary should provide the flexibility to achieve program goals in a manner best suited for each operation. For example, some air assist flares may stage the air flow with multiple flow settings using a multiple air fan speed control, variable frequency fan speed control or multi-fans, louvers, etc. Other plants, for example, may not have high pressure utility air systems available for this service. Additional work is needed to better define proper flare operation considering the complexity of this issue prior to moving-forward with additional regulatory monitoring proposals. After completion of such work, the level of detail needed in crafting such language should consider both the variability of flow and composition and the number of data points required to ensure a cost-effective monitoring program. If rulemaking is deemed necessary, it should follow closely existing requirements in 30 TAC 115.725.
Section 3: Alternatives to Flaring
A. Alternative Control Devices
Issue
The agency indicates a desire to evaluate alternative control devices.
Discussion
The majority of the present flare installations utilize an open flame concept. Flares come in various configurations, from ground or fenced flares, elevated flares, marine and boom flares, pit flares, flares utilizing assisting media, etc. The use of a particular design is dictated by specific disposal requirements for each installation as well as site specific conditions. Very rarely is the decision on use of a particular type of flare based on cost considerations only.
5 Three types of alternative control devices might be evaluated as an alternative to flares. These include:
Installation of flare gas recovery systems Utilization of vapor combustors/thermal combustors Utilization of staged flares
Each of these devices has advantages and disadvantages which are discussed in more detail in the following table.
Control Device Advantage Disadvantage
Flare Gas Recovery -Reduces the overall emissions, -Could be utilized only if suitable including NOx user of recovered gas is found. -Reduces purchased gas -Recovery gas may not be suitable requirements for facility and/or due its nature, such as: low BTU recovered gas could increase content, high content of inert product volumes from facility. gases, corrosive, toxic, high -Extends flare tip life and flare composition variation, presence reliability and availability rates of contaminants, etc. -Reduces the assisting media -Unable to handle high volumes requirements, such as assisting -Siting constraints gas, steam and power for air -High upfront capital investment assisting flare. -Increases complexity of the -Reduces the impact to the installation requiring provisions community by decreasing the for a safe transition from gas effects of radiation, smoke, noise, recovery mode to emergency and flame visibility. flaring and back -Purge gas to a stand-by emergency flare must be used to prevent air egress into flare stack
Vapor Combustor/Thermal -Achieves the highest possible DRE -Increased NOx emissions if one Oxidizer and provides reliable destruction of available NOx control efficiency regardless of the gas technologies is not implemented. composition or weather conditions -Inability to handle high volume -Superior monitoring and compliance testing ability of flare gas due to combustor size -Reduction in overall emissions limitations. -Reduced fuel cost by employing the -Increased complexity of waste heat recovery installation when employed in -Less noise, hidden flame, and lower combination with large open radiation flame flare. -Eliminate need for use of assisting -Siting constraints. media -Cost of system. -Eliminate CO emissions from combustion process and incoming -High maintenance and operating flare gas by effective control of costs. combustor temperature. -Post combustion flue gas treatment with use of scrubbers further reduces overall emission rates (acid components, particulates, etc.) -NOx emissions can be reduced by employing Low NOx technologies such a use of Low NOx burners, Ammonia or Urea injection (NSCR) into the combustion chamber or utilizing flue gas treatment via use of SCR. -Better reliability and availability than in open flame flares.
6
Staged Flares -Separates low flow from high -Siting constraints. flow. -More complex controls. -Allows each flare to be designed -More costly and difficult and operated at the optimum maintenance due to limited access combustion conditions resulting to flares or flare stages. in higher destruction efficiency -Cost of system. and lower overall emissions. -Can be added to existing flare systems, conditional to space availability, without compromising the safety function of the flare system. -If the system is based on use of ground flare then use of assisting media would not be required. -Increases the flare system reliability and availability.
Path Forward:
No one particular control device is best suited for all petrochemical applications. Flexibility to evaluate site specific conditions should be considered. Flare minimization efforts should go hand-in-hand with evaluations of alternative devices.
It is doubtful that flares can be eliminated entirely. The potential for very large, emergency releases will continue to play a decisive factor in the use of emergency flares as essential safety devices into the future.
B. Flare Minimization Plans
Issue
The agency hopes to evaluate the benefit and possible options for flare minimization plans.
Discussion
Many petrochemical plants already have flare minimization plans in place as a best management practice. A typical plan might include:
A discussion of planned and unplanned flaring events Procedures to minimize hydrocarbon flaring including, for example, mechanical reliability programs and/or event management programs Procedures to minimize emissions during planned shutdown (depressure) of process units or equipment Procedures to minimize emissions during startup (pressurization) of process units or equipment
Development of such a plan might benefit a plant by providing a review of flaring causes and a subsequent analysis of potential measures to reduce emissions from planned events.
7 Path Forward
Consider incentives to encourage sites to develop a flare minimization plan as a best practice. Allow any flare emission reductions achieved by implementing best management practices or other similar programs to generate emission credits that can be traded or otherwise used by the site.
C. Other alternative strategies
Issue:
The agency might consider additional research to develop alternative strategies that may result in emission reductions from flares
Discussion:
The agency might support efforts to improve design and test methods including consideration for the following:
Improvements of the existing technologies for flow measurement. This could include analyzers, flow instruments, and computer software.
IR Camera and DIAL side-by-side study to review flare destruction efficiencies building on the Texas Commission on Environmental Quality’s remote sensing work performed in 2003.
Flare tip design to achieve better mixing, higher destruction rates, minimize use of assisting media, reduce flame radiation rates, and flare noise.
Improved reliability of the flare pilot and flare tip
Improved pilot and flare tip flame detection systems.
Path Forward:
Seek grants to conduct additional research in these areas.
8
consulting ♦ training ♦ data systems
May 5, 2009
Lindley Anderson MC 206, Air Quality Division Chief Engineer's Office Texas Commission on Environmental Quality P.O. Box 13087 Austin, Texas 78711-3087
RE: Comments to TCEQ Flare Task Force
Dear Ms. Anderson:
On behalf of Western Refining, I am submitting these comments concerning the TCEQ’s Flare Task Force efforts to evaluate flare usage, efficiency and impact on Texas air quality. We appreciate the opportunity to provide these initial comments. We look forward to continuing to work with the TCEQ in this evaluation of flare usage and any potential changes in state regulation or air permitting requirements related to flares.
Our general comment is that the Flare Task Force goals presented at the stakeholders meeting are very broad and the proposed timeline is exceptionally accelerated. We recommend that TCEQ take a prioritized and step-wise approach to their flare evaluation and that adequate time be allocated to assure a thorough and comprehensive analysis is performed. TCEQ should focus their efforts on those issues and areas that can be expected to provide the most environmental benefit. It is especially important that TCEQ recognize that if a plant has a flare gas recovery system which recovers most, but not necessarily all routine flare waste gas, the potential issues and impact to the environment associated with emissions from those flares are already minimized.
Attached are more detailed comments in response to your request at the March 30 and April 2, 2009 Flare Task Force stakeholder group meetings. Western Refining (Western) would be happy to follow up with more specific details, if desired by the TCEQ Flare Task Force. Please note that Western has provided summaries of data for the El Paso Refinery north flare. The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis.
Please let us know what additional detailed information you would like to see. We would be happy to meet with you to discuss additional information that might be helpful. Western also invites you to come and see our flare systems and flare gas recovery systems at their El Paso refinery. Western has previously and continues to offer the TCEQ an opportunity to bring the FLIR camera to assess our flares performance under various operating conditions.
2600 Via Fortuna, Suite 450 ♦ Austin, Texas 78746 ♦ PH 512.329.5544 ♦ FAX 512.329.8253
www.ZephyrEnv.com ♦ www.HazMatAcademy.com
Ms. Lindley Anderson May 5, 2009 Page 1 of 6
Attachment Flare Task Force Stakeholder Group Comments
Concerning the TCEQ Flare Task Force (FTF) goals as described in the stakeholder meeting:
1) Our general comment is that the FTF goals and timeline presented at the stakeholders meetings are very broad and the proposed timeline is exceptionally accelerated. We suggest that TCEQ take a prioritized and step-wise approach to their flare evaluation and that adequate time be allocated to assure the completion of a thorough and comprehensive analysis. This will assure that any staff recommendations are based on a scientifically thorough analysis which clearly demonstrates that implementation of recommendations can be expected to provide a measurable environmental benefit.
2) The current schedule provides for staff recommendations to be made before the proposed flare research is completed. We recommend that flare research be completed and reported to the stakeholder group for comments before staff recommendations are developed.
3) Any recommendations related to limiting flare usage needs to take into account that: a. EPA and TCEQ have encouraged reliance on flares for both routine and emergency vents for decades. b. Even with a flare gas recovery system, flaring of routine vents cannot be expected to be completed eliminated. c. Any recommendations for limiting the use of flaring through broadly applicable prohibitions on flaring of routine emissions in permitting or regulations needs to be carefully evaluated to determine if this is a necessary step to address identified environmental objectives. d. Flare systems are large and complex. They have grown over time into extensive arrays of large diameter piping as a result of state and federal permits and federal regulations which have required venting to flares. The design of these systems are highly complex (with the need to balance flows, pressures, and handle widely varying flows) which will require detailed analysis before making any modifications in order to assure continued safe operation and compliance with federal process safety management requirements. e. Certain flares, which burn gas streams consisting of a significant amount of hydrogen (>50%), have recently been addressed by EPA and should not be a priority for the FTF.
4) We agree with comments provided by TCC and TXOGA. We understand that TXOGA has provided the attached presentation to TCEQ. The TXOGA presentation provides a very good overview of the need for flaring, the complexity of the issues, and the wide variety of flare system types that are in service. It also provides a good description of common refinery maintenance practices. Because of the need for flaring and the complexity and variety of situations, we recommend that TCEQ take a prioritized and step-wise approach to their flare evaluation to assure that a thorough and comprehensive analysis is used to identify any potential flare issues, and to develop and evaluate the impact of any associated proposed staff recommendations. It is especially important that TCEQ recognize that if a plant has a flare gas recovery system which recovers most, but not necessarily all routine
Ms. Lindley Anderson May 5, 2009 Page 2 of 6
flare waste gas, the potential issues and impact to the environment associated with emissions from those flares are already minimized.
5) Any policy or regulatory decisions (based on scientific data gathered by the FTF which may indicate that, for some specific operating scenarios, destruction efficiencies may be different than has been historically expected) should take into account that, for years, EPA and TCEQ have encourage reliance on flares for both routine and emergency vents. The TCEQ and EPA have specified that the destruction efficiency that can be claimed for those operations. As part of this flare effort TCEQ needs to work diligently with the stakeholders and EPA to assure that no un-intended retrospective state or federal reviews or related potential past, current or near future compliance questions are extrapolated from the FTF research.
6) The FTF priorities should take into account the existing flare gas recovery systems that are already in place in many facilities. For example, Western Refining has a flare gas recovery system on both their main flare headers (north and south main flares). When flare gas recovery systems are in place much, but not all, of the potential routine vent flaring is minimized. This is demonstrated by Figure 1, for the north main flare, which shows that the approximate percent of Western Refining total 2008 flaring time and emissions related to routine venting is less than 3% of total flare time and emissions. At 98% efficiency this routine flaring corresponds to less than 0.5 tons per year of VOC as compared to the refinery total VOC emission cap of 930 tpy. So, even if on occasion the efficiency was not quite 98% the emissions associated with this reduced efficiency are insignificant relative to the overall permit cap.
7) The FTF priorities should take into account the existing best management practices (BMP) that are already in place in many facilities. In their last turnaround, as part of their BMP, Western Refining performed a maintenance, repair and inspection of the entire North flare collection and recovery system. Western would be happy to provide additional information about this BMP activity if the FTF is interested.
8) Concerning the question of how flares impact Texas ozone air quality and the associated adequacy of state regulation:
a. Has any dispersion modeling been performed as a sensitivity study on whether flare usage has a potential predictable or measurable affect on ozone strategies or watch areas in the state? If so, this should be presented to the flare stakeholder group for review and comment. If not perhaps this would be a valuable analysis to perform early in the Task Force work to begin to answer this question. We would be happy to work with the FTF to develop a reasonable range of operating scenarios for this sensitivity analysis. We believe this analysis needs to be done for each unique geographical area of the state that TCEQ identifies as a priority for study. b. For the El Paso area, Western Refining offers the following qualitative data from 2008 for its North main flare in El Paso. Please note that the short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Also, note that during Western’s flexible permit application review the flare routine emissions were modeled along with other cap contributions and predicted impacts were shown to be
Ms. Lindley Anderson May 5, 2009 Page 3 of 6
acceptable. We believe this data shows that the potential emissions from routine venting to these flares should not be considered a priority in the TCEQ FTF study because they are relatively small emission sources and because of the minimal air quality impact. i. Figure 1, presented in item 6 above, shows that total routine flare emissions for 2008 compared to Turnaround and off-spec propane flaring. ii. Figure 2 shows the total 2006 EIQ Western flare VOC emission compared to the latest 2006 EIQ total VOC for the state of Texas. Note that the 2006 EIQ is the most recent complete EIQ available from the TCEQ. However the flare data divided between the different operating categories (turnaround, off-spec propane, and routine venting) is from 2008. So, for purposes of this analysis, the proportion of flaring between the three categories is assumed to be the same in 2006 as it is in 2008. iii. Figure 3 shows total 2006 EIQ Western flare VOC emission (based on the proportions of turnaround, off-spec propane and routine venting from 2008 data) compared to the latest 2006 EIQ total VOC for El Paso County. iv. Figure 4 shows total 2006 EIQ Western flare VOC emission (based on the proportions of turnaround, off-spec propane and routine venting from 2008 data) compared to the total reported 2006 VOC emission inventory for Western Refining. v. Figure 5 shows the estimated ambient air impact from the worst case routine flaring event (from 2008 data) estimated based on ratioing flare modeling results that were previously performed in January 2008 for the TCEQ regional office. This figure shows that the estimated ambient impact from routine venting can be expected to be consistently below 1% of the TCEQ published ESL.
9) Concerning the proposed FTF research:
a. Current available information does not provide an adequate basis for concluding that flare performance is less than what has been historically established. We applaud the TCEQ interest in performing research concerning the effect of operating scenarios, gas composition and flare system design on flare performance. However, we caution against broad conclusions and regulatory positions being extrapolated based on a narrow set of data that may be developed in this research.
b. As TCEQ acknowledges in their presentation there are many variables that can affect flare performance , including flare design (specific tip design, assist gas design and pilot systems), flare system design, waste gas characteristics (flow rate and composition) and meteorological conditions. In order to develop scientifically reliable conclusions on the effect of any one of these variables on destruction efficiency, the proposed research must comprehensively evaluate each variable and sufficient data must be obtained to develop statistically sound conclusions. We encourage the TCEQ FTF to include extensive stakeholder involvement in development of the test plan to assure that any data gathered addresses the variable of highest concern and will provide the most benefit in informing policy and regulatory decision makers.
c. We suggest that TCEQ take a tiered approach to focus the research on those flare related variables of highest concern. We encourage TCEQ to take this approach in conjunction with active stakeholder involvement.
Ms. Lindley Anderson May 5, 2009 Page 4 of 6
TCEQ had begun the first step to this approach which is to assemble the information currently available and has placed it on their website. However, we encourage the TCEQ to further evaluate what specific operating conditions or variables are addressed by each study to evaluate the reliability of each study and determine if it is a valid for regulatory decisions. Based on this evaluation, TCEQ will be able to identify the data gaps for the needed research. Then those variables that can be expected to have the most impact on flare performance should be prioritized for research and should be thoroughly tested in a well-designed, thoroughly sampled and well controlled testing process
For example, concerning evaluation of existing information, from the TCEQ presentation and website, it appears that the TCEQ is relying upon very limited information. In addition, the information needed for the first step does not appear to be included in the website. We request that TCEQ make that information available. • Hawk camera images and 2007 flare DIAL study: What were the specific operating conditions (flow rate, composition, tip velocity, assist gas ratio, etc) • It is not clear what report is being relied that TCEQ says found that at wind speeds higher that 5 MPH there will be reduced flare destruction efficiency. Again we encourage TCEQ to identify clearly what information is being relied upon so that information can be evaluated in its context. For example, there have been papers published which rely on simplified theoretical models compared to actual operation for flares that may not have had adequate liquid knockout or an engineered flare tip. These type of papers should not be relied upon by the TCEQ as credible information to base regulatory or policy decisions. Again we encourage TCEQ to thoroughly test hypotheses before implementing regulatory decisions. Certainly an engineered flare system with adequate liquid knockout and an engineered flare tip design to account for winds should be expect to perform better than a flare without those features. • Again, TCEQ presentation indicates that HRVOC flare survey found that flare waste gas flow rates are typically less than 1% of the design capacity. It would be helpful if the TCEQ website included that survey results for stakeholder review.
10) Concerning questions related to flare performance that FTF identified to be addressed:
a. The effect of high turndown ratio (low tip velocity) on flare performance should be expected to depend significantly on the flare system design of the flare tip, piloting and assist gas. We recommend that TCEQ work very closely with flare manufacturers concerning the limitations of flare tips depending on these design criteria and include these variables as part of the testing matrix for the TCEQ research.
b. Flare Waste Gas Stream Composition - We understand that TCEQ believes that flare composition can be highly variable and therefore greatly affect expected destruction efficiency. Western Refining 2008 composition data, summarized in Figure 6 shows the average, high and low concentration for each component of the refinery flare gas.
Ms. Lindley Anderson May 5, 2009 Page 5 of 6
In addition, Figure 7 a chart BTU value showing that even with variation in the composition the Btu value always is maintained well above the required BTU/SCF. Therefore, we believe that this data shows that the composition variability is not, in all cases, as significant as TCEQ may believe.
c. TCEQ expressed concerns about the difference in the compounds being routed to the flares and the compounds tested in EPA research. Please note, per the charts provided in item 10)b. above that Western Refining the highest concentration materials in their flare gas are consistently light hydrocarbons and hydrogen (all of which are compounds that EPA has tested and demonstrated 98+% destruction efficiency).
d. TCEQ expressed concern about the potential effect of out-of-range Flare Air-Assist or Steam-Assist ratios on flare performance. i. In its research, TCEQ needs to evaluate the range of acceptable assist ratio that minimizes visible emissions and does not affect destruction efficiency. This ratio may be different depending on the compound. ii. Before TCEQ considers requiring some type of assist ratio control, TCEQ needs to determine what is available and its limitations. TCEQ indicates that valve position monitors are not adequate; however, TCEQ should reconsider that this may be adequate depending on assist ratio tolerances which assure destruction efficiency and the accuracy of valve position flow estimates. iii. Please note that, while one TCEQ study noted ratio of assist gas to waste gas as highly variable, ranging from 2 to more than 50, there is no information on the waste gas flow rates during those periods of high assist ratio so there is no information to conclude if there is actual waste gas being routed to the flare at that time. TCEQ should not conclude from that study that all flares run at those assist ratios.
11) Concerning Flare Monitoring Questions:
a. TCEQ should recognize that the flare monitoring necessary to assure good destruction efficiency and minimal impact on the air quality will not be the same for all flares depending on the potential and significance of emissions and potential air quality impacts from those flares. Certainly, flare systems that have flare gas recovery require much less rigorous monitoring to assure consistent operation of the flare since the recovery system dampens out significant swings in flows.
b. Western Refining has flare gas recovery systems, flare gas flow rate measurements and takes weekly samples for composition. Western Refining would be happy to provide more information on these systems if it would be helpful to the TCEQ Flare Task Force.
12) Concerning Alternatives to Flaring Routine Emissions:
a. Certainly, if a flare system includes flare gas recovery, BMP for maintenance, and appropriate monitoring, TCEQ should be satisfied with flares for regulatory
Ms. Lindley Anderson May 5, 2009 Page 6 of 6
compliance and BACT. Therefore, alternatives in this situation should not be an issue.
b. TCEQ needs to keep in mind that cost of developing separate waste gas collection system and alternative control devices require significant cost and engineering to assure pressure balance and safety. These alternatives should only be considered on a case by case basis for very specific application in grass roots plants not for retrofit in existing flare systems.
13) Concerning Strategies to Minimize Routine Flaring:
a. There are many strategies for minimizing routine flaring. Certainly, TCEQ should consider a flare gas recovery system, which recovers most but not all routine vents, and implemented BMP as an acceptable flare minimization strategy and no further regulatory requirements are necessary.
b. It is important to remember that for existing flare gas recovery systems there may be additional limitations because of the type of compressors, and the design of the system.
c. When considering new systems, TCEQ should acknowledge that there are many situations when flares are appropriate and would be expected to provide the required efficiency. Therefore any consideration of changes to permitting requirements needs to be carefully evaluated and discussed thoroughly with the stakeholders before proposal.
Figure 1 - Summary of Western Refining Flaring Minutes
3%
13%
Turnaround Flaring
Off-Spec Propane Flaring
Routine Flaring
% is estimated based on flare time
84%
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 2 ‐ State Wide Flare VOC Emissions 2006 With Flaring Categories
Flares Other Than Western Refining 1% 98.87% 1.13% Western Turnaround Flaring Western Off‐Spec Propane Flaring Western Routine Flaring
0.10% 0.03%
Flare categorization (turnaround, off‐spec propane, and routine) is estimated based on 2008 data (84% 13%, and 3% of total flaring respectively.) Distribution of emissions for 2006 is assumed similar.
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 3 ‐ El Paso County VOC Emissions (2006) Compared to Western Refining Flares
El Paso County Other Than Western Refining Flares 6% 1% Western Turnaround Flaring 1.2% Western Off‐Spec Propane Flaring 92.8% Western Routine Flaring
0.2%
Flare categorization (turnaround, off‐spec propane, and routine) is estimated based on 2008 data (84% 13%, and 3% of total flaring respectively.) Distribution of emissions for 2006 is assumed similar.
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 4 ‐ Western Refining VOC Emissions 2006 and Flare Contribution
0.4% 2% 9%
Western Refining Sources Other Than Flares Turnaround Flaring Off‐Spec Propane Flaring Routine Flaring
89%
Flare categorization (turnaround, off‐spec propane, and routine) is estimated based on 2008 data (84% 13%, and 3% of total flaring respectively.) Distribution of emissions for 2006 is assumed similar.
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 5: Estimated Ambient Impact of Routine Flaring as % of ESL based on worst case emission rate and composition
JANUARY ANALYSIS 0.0018
0.0016 ESL 0.0014 of
% 0.0012
0.0010
0.0008
0.0006
0.0004
0.0002
0.0000
FEBRUARY ANALYSIS 0.0002
0.0002 ESL
0.0002 of
% 0.0001
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 5: Estimated Ambient Impact of Routine Flaring as % of ESL based on worst case emission rate and composition
MARCH ANALYSIS 0.00004
0.00003 ESL of
% 0.00003
0.00002
0.00002
0.00001
0.00001
0.00000
APRIL ANALYSIS 0.000003
ESL 0.000002 of
%
0.000002
0.000001
0.000001
0.000000
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 5: Estimated Ambient Impact of Routine Flaring as % of ESL based on worst case emission rate and composition
JUNE ANALYSIS 0.0002
0.0002 ESL
0.0002 of
% 0.0001
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
JULY ANALYSIS 0.0002
0.0002 ESL
0.0002 of
% 0.0001
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 5: Estimated Ambient Impact of Routine Flaring as % of ESL based on worst case emission rate and composition
AUGUST ANALYSIS 0.0000001
0.0000001 ESL of
% 0.0000001
0.0000001
0.0000001
0.0000000
0.0000000
0.0000000
SEPTEMBER ANALYSIS 0.000003
0.000003 ESL of
% 0.000002
0.000002
0.000001
0.000001
0.000000
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 5: Estimated Ambient Impact of Routine Flaring as % of ESL based on worst case emission rate and composition
OCTOBER ANALYSIS 0.00004
0.00003 ESL of
% 0.00003
0.00002
0.00002
0.00001
0.00001
0.00000
NOVEMBER ANALYSIS 0.0018
0.0016 ESL 0.0014 of
% 0.0012
0.0010
0.0008
0.0006
0.0004
0.0002
0.0000
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 5: Estimated Ambient Impact of Routine Flaring as % of ESL based on worst case emission rate and composition
DECEMBER ANALYSIS 0.0002
0.0002 ESL
0.0002 of
% 0.0001
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 6 ‐ Western Refining North Flare Gas Analysis 60.00
50.00
40.00
30.00
20.00
1010.00 00
0.00
12 month average
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis. Figure 7 ‐ Western Refining 2008 North Flare Calculated Net Heating Value of Flare Gas(Btu/SCF) 1800
1600
1400
1200
1000
800 Net Heating Value (Btu/SCF) 600
400
200
0
The short timeframe for comments did not allow extremely detailed quality assurance for the data analysis, so please accept these summaries as a qualitative and representative analysis.