SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

FINAL STAFF REPORT FOR

PROPOSED AMENDED RULE 1118

- – CONTROL OF EMISSIONS FROM

REFINERY FLARES

Dated: October 2005

Deputy Executive Officer Planning, Rule Development, and Area Sources Elaine Chang, DrPH

Assistant Deputy Executive Officer Planning, Rule Development, and Area Sources Laki Tisopulos, Ph.D., P.E.

Planning and Rules Manager VOC Rule Development Larry M. Bowen, P.E.

Author: Eugene Teszler AQ Specialist Reviewed by: Ed Muehlbacher, P.E. Program Superviso r Jeri G. Voge Sr. Deputy District Counsel

Contributors Pang Mueller, P.E. Sr. Manager Paul Park Sr. AQ Engineer Abe Udobot AQ Engineer Zach Muepo AQ Inspector Glenn Kasai AQ Engineer Raul Dominguez AQ Chemist Kathy Kasza AQ Chemist Jeff Cox AQ Engineer Sharon Garrett AQ InspectorSOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

GOVERNING BOARD

Chairman: WILLIAM A. BURKE, Ed.D. Speaker of the Assembly Appointee

Vice Chairman: S. ROY WILSON, Ed.D. Supervisor, Fourth District Riverside County Representative

MEMBERS:

MICHAEL D. ANTONOVICH Supervisor, Fifth District Los Angeles County Representative

JANE W. CARNEY Senate Rules Committee Appointee

BEATRICE J. S. LAPISTO-KIRTLEY Mayor Pro Tem, City of Bradbury Cities Representative, Los Angeles County/Eastern R egion

RONALD O. LOVERIDGE Mayor, City of Riverside Cities Representative, Riverside County

GARY OVITT Supervisor, Fourth District San Bernardino County Representative

JAN PERRY Councilmember 

### , 9 th 

### District Cities Representative, Los Angeles County, Western Region

MIGUEL PULIDO Mayor, City of Santa Ana Cities Representative, Orange County

JAMES W. SILVA Supervisor, Second District Orange County Representative

CYNTHIA VERDUGO-PERALTA Governor’s Appointee

DENNIS YATES Mayor, City of Chino Cities Representative, San Bernardino County

EXECUTIVE OFFICER:

BARRY R. WALLERSTEIN, D.Env.TABLE OF CONTENTS

Page

EXECUTIVE SUMMARY ---------------------------------- ------------------------------------------- ES-1

CHAPTER I – BACKGROUND ----------------------------- --------------------------------------------I-1

A. RULE HISTORY ------------------------------------

--------------------------------------- 1-1

B. OTHER CALIFORNIA DISTRICTS FLARE RULES ----------------------------------I-2

C. US EPA REGULATIONS

--------------------------------------------------- ---------------I-3

D. EQUIPMENT AND OPERATION

--------------------------------------------------- -----I-4

E APPLICABLE RULES REVIEW--------------------------

-------------------------------- I-5

F AFFECTED FACILITIES

-------------------------------------------------- ---------------I-6

CHAPTER II – CONTROL TECHNOLOGY -------------------- ---------------------------------- II-1

A. CONTROL OPTIONS

--------------------------------------------------- ------------------II-1

B FLARE MINIMIZATION PLANS

--------------------------------------------------- -----II-1

C. FLARE GAS RECOVERY SYSTEMS----------------------

------------------------------ II-2

CHAPTER III – PROPOSED RULE AMENDMENTS ------------- ---------------------------- III-1

A. DEFINITIONS----------------------------------------

------------------------------------- III-1

B. REQUIREMENTS---------------------------------------

---------------------------------- III-3

C. PERFORMANCE TARGETS--------------------------------

-------------------------- III- 4 5

D. FLARE MINIMIZATION PLAN REQUIREMENTS ---------------

------------------ III-7

E. FLARE MONITORING AND RECORDING PLANS ---------------

--------------- III- 7 8

F. OPERATION MONITORING AND RECORDING -----------------

----------------- III-8

G. RECORDKEEPING REQUIREMENTS -------------------------

------------------- III- 9 10

H. NOTIFICATION AND REPORTING -------------------------

---------------------- III- 9 10

I. TEST METHODS ---------------------------------------

-------------------------------- III-10

J. EXEMPTIONS-----------------------------------------

------------------------------- III- 10 11K. ATTACHMENT A ---------------------------------------

----------------------------- III- 10 11

L. ATTACHMENT B ---------------------------------------

----------------------------- III- 10 11

CHAPTER IV – EMISSION INVENTORY-------------------- ------------------------------------ IV-1

A. CONTRIBUTING SOURCES -------------------------------

---------------------------- IV-1

B. EMISSION INVENTORY ---------------------------------

------------------------------- IV-2

CHAPTER V – EMISSION REDUCTIONS -------------------- -------------------------------------V-1

CHAPTER VI – COST-AND COST EFFECTIVENESS----------- ----------------------------- VI-1

A. COSTS -------------------------------------------

------------------------------------------- VI-1

B. COST-EFFECTIVENESS

--------------------------------------------------- ----------- VI-11

CHAPTER VII – COMPARATIVE ANALYSIS----------------- -------------------------------- VII-1

CHAPTER VIII – DRAFT FINDINGS---------------------- -------------------------------------- VIII-1

CHAPTER IX – COMMENTS AND RESPONSES ---------------- ------------------------------ IX-1

APPENDIX A – REFERENCES ---------------------------- --------------------------------------------A-1

APPENDIX B – CALIFORNIA AIR RESOURCES BOARD RESOLUT ION 86-60 -------B-1E X E C U T I V E S U M M A R YEXECUTIVE SUMMARY FINAL STAFF REPORT

Proposed Amended Rule 1118 ES-1 October 2005 Rule 1118 – Emissions from Refinery Flares was orig inally adopted by the South Coast Air Quality Management District (AQMD) on February 13, 1998, with the purpose of monitoring, recording and reporting data on petroleum refinery flaring and related operations. This represented Step I of Control Measure CMB-07 of the 1997 Air Quality Management Plan (AQMP) that targets emission reductions from refine ry flares, also found in the 2003 AQMP. Pursuant to the AQMD Board’s direction upon the ado ption of the rule, staff analyzed the monitoring data submitted by refineries in the time period from October 1, 1999 through December 31, 2003 and compiled the “Evaluation Repo rt on Emissions from Flaring Operations

at Refineries”.

Staff presented the report at the September 3, 2004 AQMD Board Meeting and concluded that emissions from refinery flares were significant eno ugh to warrant the implementation of controls. The report suggests possible ways of red ucing emissions through the prevention of flaring of excess fuel gas, the elimination of leak s from pressure relief devices and the reduction of emissions during routine flaring. These objecti ves can be achieved by installing flare gas recovery systems and gas treating systems, expandin g current capacities of flare gas recovery and treatment systems already in place, and conduct ing surveys to detect leaking pressure relief devices. The report also recommended improvements in the measurement of flare vent gas flows and the installation of continuous monitoring syste ms to measure the total sulfur gas concentration and the higher heating value of the f lared gas, as well as the standardization of methodologies for flow and emissions calculations a nd for missing data substitution. Following the report presentation, the AQMD Board directed st aff to amend Rule 1118 – Emissions from Refinery Flares, and implement Step II of Control M easure CMB-07. Step II of the control measure aims to reduce emissions of criteria pollut ants from refinery flares by identifying and requiring the most feasible and cost-effective cont rol options available.

The air quality objective for the Proposed Amended Rule (PAR) 1118 is to help AQMD attain state and federal air quality standards by minimizi ng emissions of criteria air contaminants and their precursors from flaring activities at petrole um refineries. The proposed amendment would eliminate the flaring of vent gases except for thos e resulting from emergencies, shutdowns and startups, turnarounds and essential operational nee ds; establish operational requirements of diagnostic practices to minimize flaring.

The proposed amendment establishes refinery specifi c performance targets for flare-related total sulfur emissions, calculated as sulfur dioxide, at 1.5 tons per million barrels of crude

process ed ing capacity in calendar year 2006, 1 ton per million barrels o f crude process ed ing capacity in calendar year 2008, 0.7 tons per million barrel s of crude process ed ing capacity in calendar year 2010, and 0.5 tons per million barrel s of crude process ed ing capacity in calendar year 2012, respectively, based on the 2004 industry -wide throughput processing capacity

. During the rule development process, industry identified a n inequity of using crude throughput versus crude capacity based on a fixed year of 2004 to est ablish annual SO 2 performance targets. In any one year, any refinery could be conducting a shutdo wn or turnaround of a major crude processing unit, which could reduce crude throughpu t for that baseline year reflecting an artificially low baseline throughput for that refin ery. Whereas crude processing capacity more accurately allocates refinery emissions based on no rmal refinery operations. Local refineries are operating at near capacity; therefore, the differen ce in emissions impact and reductions based on throughput or capacity are minimal. Excess flare related total sulfur emissions would b e subject to mitigation fees of $25,000, $50,000 or $100,000 per ton, depending on whether excess emissions are no more than ten percent, greater tha n twenty percent but less than twenty percent,EXECUTIVE SUMMARY FINAL STAFF REPORT

Proposed Amended Rule 1118 ES-2 October 2005 or more than twenty percent, respectively, of the a nnual performance targets. Excess emissions would also trigger the submittal of a flare minimiz ation plan by the refinery and a possible

issuance of a Notice of Sulfur Dioxide Exceedance b y the Executive Officer. Emissions resulting from external power curtailment, natural disasters or acts of war or terrorism will be exempt from being counted towards these limits.

The proposed amendment, in keeping with the recomme ndations from the “Evaluation Report on Emissions from Flaring Operations at Refineries”, w ill also enhance monitoring requirements to improve data reporting accuracy, primarily requirin g the use of higher heating value analyzers and also total sulfur analyzers pending the result of a pilot test feasibility study taking place at one of the refineries. Until the analyzers are ins talled, but no later than July 1, 2007, the sampling frequency of flare events would be increas ed to daily from weekly. In addition, the rule will require the flare gas flow meters to be i nstalled in a representative location or be upgraded with totalizing capability such that only an accurate flow to the flare is registered. The amended rule will also establish uniform missing da ta procedures and calculations for reporting emissions during monitors’ downtime periods.

The amended rule will set new notification requirem ents for flaring events, as well as reporting, which will require quarterly reports to be submitte d in an electronic format certified by the facility official and approved by the Executive Off icer. Each petroleum refinery will submit a detailed technical description of the flare system, including an audit of vent gas recovery capacity, a summary of the flaring emissions reduct ions achieved to date and future planned flare

emission reductions.

The emissions reductions associated with proposed a mendments are estimated to be 1.18 tons per day of SO 2 and 1.44 tons per day overall for all criteria pol lutants, excluding carbon monoxide, from the emissions baseline average (2002-2004) to 2012. The cost-effectiveness is estimated to be between $ 3,922 5,524 and $ 6,926 8,620 per ton of SO 2 reduced. When considering additional reductions in NOx, VOC and PM10, the cost effective ness ranges between $ 3

, 112 4,527 and $ 5 ,6 75 7,063 per ton of pollutant reduced.

The proposed amended Rule 1118 is considered a “pro ject” as defined by the California Environmental Quality Act (CEQA), and the AQMD is t he designated lead agency. Pursuant to CEQA and AQMD Rule 110, the AQMD prepared an enviro nmental assessment (EA) evaluating potential adverse significant impacts associated wi th implementing the proposed amended rule. The EA concluded that implementing PAR 1118 would h ave no significant impacts on the environment. An environmental impact is defined as an impact to the physical conditions that exist within the area which would be affected by th e proposed project.C H A P T E R I

BACKGROUNDCHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-1 October 2005 A. RULE HISTORY

The concept of reducing emissions from petroleum re finery operations was originally formalized in the 1982 Air Quality Management Plan (AQMP) as M easure A15. Measure A15 proposed increasing the use of blowdown and vapor recovery s ystems to reduce emissions from flares. Consideration of adoption in 1985 was postponed to provide additional time to collect background information regarding flaring operations and alternative control options. Measure A15 has been carried over through subsequent AQMPs and in the 2003 AQMP takes the form of

Control Measure CMB-07.

In 1984, the Citizens for a Better Environment (CBE ) petitioned the California Air Resources Board (CARB) to make a determination of the technol ogical feasibility, availability and

economic reasonableness of continuous emission moni tors for refinery flares. CARB granted the CBE request and contracted a study with an engineer ing firm to evaluate the feasibility of continuously monitoring flaring operations at petro leum refineries. The study found that no refinery in California accurately monitored flow ra tes to its flares. Several types of flow meters had been installed on refinery flares, but the inst rumentation could only provide relative flow information because the gas density varies and gas constituent data is necessary to calculate flow accurately. The study concluded that continuous mo nitoring of flare gas flow rates, gas composition and remote monitoring of flare plumes w ere practicable but would require substantial further development before they could b e considered ready to use for accurate and precise measurements on flares at a reasonable cost

. Despite concluding that the aforementioned devices still required substantial development, the study found that devices which constantly monitored the on/off status of refinery flares were not only practicable, but were also ready to use at a r elatively inexpensive cost. In 1986, CARB determined that monitoring devices were technologic ally feasible, available and economically reasonable for limited applications to identify and record continuously the on/off status of refinery flares in order to better quantify flare e missions. This finding was formalized and adopted by CARB as Resolution No. 86-60. CARB also encouraged local air pollution control districts to adopt rules requiring refineries to in stall on/off status monitors and collect flare gas composition data so that a suggested control measur e for the control of emissions from refinery flares could be developed.

In 1987 through 1988, refineries in the South Coast Air Basin participated in a flare study resulting from CARB Resolution No. 86-60. The resu lts of this study met with limited success.

Staff’s review of the available data has determined that the results of the study are insufficient to quantify the emissions from petroleum refineries, e specially in light of the recent refinery modifications to produce clean fuels. In addition, the previous monitoring equipment used in this study was found to be maintenance intensive an d is no longer used by the refineries.

Since 1988, staff has tracked the development of av ailable technology that could accurately monitor gas flare parameters which would result in sufficient data to quantify emissions. Recent advances in technology have resulted in devices tha t can now accurately monitor gas flare parameters. Staff has found that these monitoring devices are currently being used in various industries that use gas flares with favorable resul ts.

In 1993 and 1994, staff required two refineries to conduct flare system studies as a result of frequent complaints of odor from emissions associat ed with their gas flaring operations. Recommendations based on these studies were impleme nted and resulted in a significant

reduction in violations of Rule 402 – Public Nuisan ce. These studies and subsequentCHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-2 October 2005 implementation of recommendations showed that each refinery flare system is complex and unique, but that opportunities do exist to reduce n uisance problems associated with refinery flare
systems.

On February 13, 1998, the AQMD Board adopted Rule 1 118 with the purpose of monitoring, recording and reporting data on refinery and relate d flaring operations. Upon rule adoption, the AQMD Board passed a resolution directing staff to a ) collect and analyze the data submitted by subject refineries to determine if flare emissions are significant, and b) recommend whether

further controls are needed.

After evaluating the data submitted to the AQMD fro m October 1, 1999 through December 31, 2003, staff compiled the “Evaluation Report on Emis sions from Flaring Operations at Refineries”, which was presented to the AQMD Board on September 3, 2004. The report recommended amending Rule 1118, concluding that, al though refineries had made important progress in reducing emissions since Rule 1118 was originally adopted, flare emissions, especially oxides of sulfur (SOx), were still signi ficant enough to warrant further controls. The report suggest various ways to reduce flare emissio ns, such as the elimination of leaks from pressure relief devices, the installation of flare gas recovery systems and gas treating systems. In

addition to focus on minimization of flare emission s, the report emphasized the potential of the amendment to improve the monitoring, reporting and emission calculation methodology in order to increase the accuracy of the data collected.

B. OTHER CALIFORNIA DISTRICTS FLARE RULES

Several other air pollution control districts in Ca lifornia also have flare rules. The Bay Area Air Quality Management District’s (BAAQMD) Rule 12-11, adopted in June 2003, is comparable to AQMD’s current Rule 1118. Rule 12-11 – Flare Monit oring at Petroleum refineries applies to refineries in the San Francisco area. The rule req uires the monitoring and recording of the vent gas and the composition as well as continuously rec ording digital video images of the flare tip for each flare. Refineries are required to submit monthly reports in electronic format, containing daily flows and gas composition and corresponding c alculated emissions of methane, nonmethane hydrocarbons and sulfur compounds resulting from combustion, as well as the archived video pictures of the flares. A complementary rule , Rule 12-12 which seeks to minimize flare emissions through the use of Flare Minimization Pla ns was adopted in June 2005, and is similar in some respects to PAR 1118.

The Santa Barbara Air Pollution Control District (S BAPCD) also regulates flares based upon its own Rule 359 - Flares and Thermal Oxidizers, adopte d on June 28, 1994. This rule applies to oil and gas production, petroleum refineries and relate d sources, natural gas services and transportation sources and wholesale trade in petro leum/petroleum products that operate flares or thermal oxidizers. Rule 359 specifies sulfur conte nt limits, technology-based standards for flares and thermal oxidizers, and emission standards for o xides of nitrogen (NOx) and reactive organic compounds (ROC) and operational limits. The rule a lso incorporates a Flare Minimization Plan, monitoring, recordkeeping, reporting and source tes t requirements for ground flares. However, a review of the staff report for Rule 359 indicates t hat there are no petroleum refinery operations in Santa Barbara similar to the petroleum refinery ope rations in the South Coast Air Basin and that Rule 359 applies to non-refinery petroleum operatio ns such as oil and gas exploration and bulk loading terminals.CHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-3 October 2005 Ventura County Air Pollution Control District (VCAP CD) Rule 54 - Sulfur Compounds is

similar to the SBAPCD Rule 359. While Rule 54 does apply to flares, as in the case with the SBAPCD rule, Rule 54 also applies to non-refinery p etroleum operations and AQMD staff is not aware of any petroleum refinery operations in the j urisdiction of VCAPCD.

C. U.S. EPA REGULATIONS (EPA)

The EPA New Source Performance Standards (NSPS), un der 40CFR 60.18 – General Control Device Requirements, contains provisions for flares that control vent gases from storage tanks built after July 23, 1984, subject to 40CFR 60 Subp art Kb and from piping components that were installed after January 4, 1983, subject to Subpart GGG. The federal regulation requires flares to operate without visible emissions, to maintain a pi lot flame present at all times the flare is in operation and observe certain limits for the net he ating value and exit velocity of the gases being combusted. The regulation also requires monitoring of the flares to ensure that they are operated in compliance with these requirements.

Another NSPS regulation, 40CFR 60 Subpart J – Stand ards of Performance for Petroleum Refineries, covers operation of combustion devices such as flares, that were built or modified after June 11, 1973 under 40CFR 60.104(a). This re gulation limits the concentration of the hydrogen sulfide (H 2 S) in the vent gases routed to flares to 160 ppm, a veraged over three hours. However, vent gases that are combusted due to start up, shutdown, process upset or relief valve leakage are exempt from this requirement.

In 1998, EPA launched a program called “The Petrole um Refinery Initiative” consisting of a series of investigations at refineries under a mult i-faceted compliance approach. One of the refinery activities targeted by the investigation w as excessive flaring of acid gas (gas with high

H 2 S content generated during the oil refining process and from the sour water stripper) that results in large amounts of sulfur dioxide being re leased into the atmosphere. Also investigated was excessive hydrocarbon flaring. EPA’s position, as stated in the Enforcement Alert newsletter of October 2000, is that routine or non- emergency flaring does not constitute good air pollution practice and may be a violation of the Cl ean Air Act. In the newsletter, EPA states that refineries should have adequate capacity to recover and treat sour gases routinely generated in their process without resorting to flaring. Good a ir pollution practices also include investigating the root cause of a flaring incident and taking cor rective actions to prevent recurrence in the future. In the newsletter, EPA states that a prope rly designed, operated and maintained flare gas recovery system is one way to minimize or avoid fla ring.

In an effort to reduce excessive flaring of acid ga s and emissions of SOx and NOx, EPA, to date, has entered into 15 global settlements with petrole um refiners representing more than 65% od domestic refinery capacity. The settlements now co ver 76 refineries and conferences are currently ongoing with 11 more petroleum refiners w ho represent an additional 24 refineries. Refineries effected by the global settlements are s ubject to a consent degree requiring them to prepare and submit plans to minimize hydrocarbon fl aring, conduct root cause analysies of flaring events and implement control options such a s installing flare gas recovery systems, rerouting hydrocarbon streams away from flares or m aking hydrocarbon flares compliant with the provisions of 40CFR 60.104(a). By stipulating to consent decrees with EPA, the refineries agreed to undertake certain remediation and mitigat ion actions, pay fines and provide affirmative relief by completing environmentally beneficial pro jects. These aforementioned requirements ofCHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-4 October 2005 the consent decrees are, in part, the concepts on w hich the proposed amendment to Rule 1118 is

based.

Four refineries within the AQMD’s jurisdiction have entered consent decrees with EPA: Equilon Enterprises, BP West Coast Products, Chevron Produc ts Company and Conoco Phillips. As a result of the settlements, these companies pledged to reduce SOx and other air contaminants emissions to the environment by minimizing acid gas and hydrocarbon flaring and by agreeing to subject their flares to the requirements of 40CFR 6 0.104 for combustion devices.

D. EQUIPMENT AND OPERATION

Flares are combustion devices used extensively in t he petroleum industry to burn and dispose of excess combustible gases that are generated as part of the production processes or during a process upset. Flares are also used as safety devi ces to reduce the potential for fires and explosions due to unburned gaseous hydrocarbon rele ases. Blowdown systems are designed and installed at petroleum refineries to provide for sa fe containment or safe release of liquids and gases that must be disposed of in the refining proc ess. Such systems generally consist of a series of venting manifolds which lead from the process eq uipment to a blowdown recovery system (i.e., storage tank, wastewater system, compressor) and flares.

Flares can be elevated like a stack where the combu stion, or burn-off, takes place at the tip of the

flare and the flames are visible from a distance. They can also be of the ground-flare type where the burners are concentrically located near the gro und level in a shrouded, refractory lined enclosure. Both types of flares are capable of des truction of hydrocarbons and other combustible gases. However, as with any type of combustion equ ipment, they generate air pollutants such as NOx, SOx, carbon monoxide (CO), and particulate mat ter (PM), in addition to the release of reactive organic gases (ROG) which have not been co mpletely combusted. Also, similar to any other combustion device, flares have the potential to generate toxic emissions depending on the type of gases burned and operating parameters.

Flares have a design capacity, usually expressed in pounds per hour, which represents the maximum design flow of a specific composition, temp erature and pressure of vent gas that can be combusted in a particular flare. Due to federal and local regulations, most flares are designed for smokeless operation over a specified flow range , which is achieved by injecting steam or air at the flare tip to increase turbulence and allow a mbient air to better mix with the hydrocarbons. The federal requirement allows refinery flare opera tors to operate a flare with visible emissions for up to five minutes in any two consecutive hour time period. The smokeless capacity of a

flare is defined as the maximum flow to a flare tha t can be burned without smoke and is also expressed in pounds per hour of a specific gas comp osition, temperature and pressure. Typically, flares are operating in a smokeless mann er in a range up to 20 percent of their maximum design flow; at higher flows the size of th e pipe that would be required to provide adequate steam injection at the flare tip becomes a design challenge. Another factor contributing to visible emissions is the nature of the hydrocarb ons being combusted. Paraffins have the least tendency to smoke, whereas unsaturated and aromatic hydrocarbons have a higher tendency to

smoke.

A flare must have the pilot burners on at all times to ensure ignition of the vent gas generated in the process system it serves whenever it is in oper ation. A stream of combustible gas, called purge gas, is continuously flowing into the flare t o prevent air from entering the flare headerCHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-5 October 2005 which can create an unsafe explosive mixture of air and hydrocarbons. Depending on the flare design and size, the amount of purge gas needed to keep the flare safe varies considerably. Although the quantities are relatively small, the b urning of pilot and purge gases represent a

continuous source of emissions.

In a refinery setting, a gas flare may be installed for only one process area or it can be used to serve a number of process units for a wide variety of purposes ranging from controlling a small stream of leaks or vent gas from a piece of equipme nt to the disposal of large quantities of gases during an emergency. Therefore, depending on how a flare is designed and used, in Rule 1118 flares are classified into three distinctive catego ries: clean service, emergency service, and general service.

A clean service flare is used to only burn natural gas, hydrogen, liquefied petroleum gas, or other gases with a fixed composition vented from specific equipment. These gases contain little or no sulfur, and the quality (i.e., heat content and sul fur content) of the gas is usually predictable regardless of the flaring situations. In the basin , there are four clean flares, which are associated with three liquefied propane and butane storage are as and a hydrogen generating plant each.

An emergency service flare is a flare that receives vent gas only during emergencies. The quality and volume of the vent gases vary depending on the source and duration of the emergency release. Nevertheless, an emergency flar e is usually in a standby mode and does not create emissions except for those associated with p ilot and purge gases, and during actual emergencies.

The most common and complicated flare configuration is the general service flare. In addition to the services described above, flares in a refinery are also used to dispose of gases from routine or non-routine operations including purged gas streams , non-emergency releases of excess pressures, venting of storage tanks or wastewater s umps and equipment leaks, startups and shutdowns, turnaround activities, etc.

E. APPLICABLE RULES REVIEW

In addition to Rule 1118, flares are also subject t o general AQMD prohibitory rules, such as Rule 401 – Visible Emissions, Rule 402 – Public Nuisance and Rule 431.1 – Sulfur Content of Gaseous Fuels. Flares built after June 11, 1973, a re subject to 40CFR 60 Subpart J - New Source Performance Standards (NSPS); flares may also be su bject to 40CFR 60.18 – General Control Device Requirements if either vent gases from stora ge tanks subject to 40CFR 60 Subpart Kb or from components subject to 40CFR 60 Subpart GGG are routed to them.

In order to maintain a smokeless operation, flares at refineries are equipped with steam jets (steam assisted) to provide good mixing of the flar e gas with air. Within the smokeless range of operation of a flare, if not enough steam is used d uring a flaring event, smoking may occur due to pockets of incomplete combustion that are formed in the combustion zone. Rule 401 prohibits visible emissions in excess of Ringelmann 1 or 20 p ercent opacity for periods exceeding more than three aggregate minutes within any hour. 40CF R 60.18 requires flares to have no visible emissions except for periods of time up to five min utes during two consecutive hours. The two standards are not identical, since they use differe nt methods to determine visible emissions: Rule

401 uses USEPA Reference Method 9 and 40CFR 60.18 u ses USEPA Reference Method 22.CHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-6 October 2005 If combustion is incomplete, as denoted by visible emissions, odorous materials may be emitted, affecting the area downwind of the flare and potent ially resulting in a public nuisance. Odors

could also be emitted if the heat content of the fl ared gas is very low resulting in the flame temperature not being hot enough to ensure complete destruction of odorous materials. The flare operator should supplement combustion with high BTU content gas to prevent this problem. A

steam- or air-assisted flare should not be used for disposal of gases with less than 300 BTU/scf.

Although flares operate within refineries subject t o Regulation XX - RECLAIM, they are not included in this program and their emissions do not count towards refineries’ RECLAIM SOx

and NOx allocations. The total sulfur content of t he flare pilot gas and the purge gas, which maintain the flare operating continuously, is limit ed to a concentration of 40 ppm calculated as

H 2 S, averaged over a four hour period per Rule 431.1 – Sulfur Content of Gaseous Fuels. Most of the flares in the basin use natural gas for purg e and pilots in order to comply with this requirement. The total sulfur content of the vent gas routed to a flare due to an emergency is exempt from the rule requirements. The federal reg ulation, 40CFR 60 Subpart J, has a limit of 160 ppm H 2 S, averaged over a rolling three hour period, for p urge and pilot gas combusted in a flare, whereas emergency vent gases and relief valv e leakage are exempt from this requirement.

F. AFFECTED FACILITIES

The types of refinery operations subject to this ru le are: petroleum refineries, sulfur recovery plants that recover sulfur compounds from acid gase s and sour water generated by petroleum refineries, and hydrogen production plants that pro duce hydrogen from refinery gas and supply it for petroleum refinery operations. Presently, in t he AQMD, there are seven operating petroleum refineries, one sulfur recovery plant and one hydro gen production plant, with a total of 10 distinct physical locations. The following facilit ies operate 27 flares subject to Rule 1118:

• Air Products (Hydrogen Production Plant)

• BP West Coast Products (Refinery)

• Chevron Products Company (Refinery)

• ConocoPhillips Company (Refinery – Carson Plant)

• ConocoPhillips Company (Refinery – Wilmington Plant )

• Equilon Enterprises, LLC, Shell Oil Products US (Lo s Angeles Refinery)

• Equilon Enterprises, LLC, Shell Oil Products US (Su lfur Recovery Plant)

• ExxonMobil Oil Corporation (Refinery)

• Paramount Petroleum Corporation (Refinery)

• Ultramar Inc. (Refinery)

Table I-1 shows the subject facilities and an inven tory of their flares. Since ConocoPhillips and Equilon Shell Oil submit one quarterly Rule 1118 re port for both their facilities (CarsonCHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-7 October 2005 Plant/Wilmington Plant and L.A. Plant/SRU, respecti vely) the table shows eight reporting

facilities.

Table I -1 Flare Inventory Type of Service Reporting
Facility Number of

Flares Type of flare Clean Emergency/

General

Service

A 4 Elevated 1 3

B 1 Ground Flare 1

C 2 Elevated 2

D 2 Elevated 1 1

E 5 Elevated 5

F 1 Elevated 1

G 6 Elevated 6

H 6 Elevated 1 5

8 Facilities 27 Flares 4 23C H A P T E R II

CONTROL TECHNOLOGYCHAPTER II – CONTROL TECHNOLOGY FINAL STAFF REPORT

Proposed Amended Rule 1118 II-1 October 2005 A. CONTROL OPTIONS

At petroleum refineries, flares have historically b een used to dispose of combustible gases resulting from emergency relief, overpressure, proc ess upsets, startups, shutdowns and other operational and safety reasons to prevent direct re lease of toxic and /or odorous substances to the atmosphere. In recent years, U.S. Occupational Saf ety and Health Administration (OSHA) and U.S. EPA have become more concerned with refinery o peration, resulting in tighter regulations on safety and emissions control and enforcement act ions such as Consent Decrees, as shown before. Furthermore, smoke, noise, glare and odors sometimes associated with refinery operations may, and at times have impacted the surr ounding communities, leading to an increase in the involvement of community and environmental g roups in the regulatory process of controlling refinery flares.

There are two alternatives to control flare emissio ns: post-combustion and pre-combustion controls. Possible post-combustion controls could be selective catalytic reduction (SCR) units, Lo-NOx burners, scrubbers and bag houses. While po st-combustion control technology exists, the unpredictability of the flare operation and the fact that combustion takes place at the tip of an flare 150 to 200 feet above the ground make such co ntrol devices impractical for elevated flares.

Controlling flue gases would be very costly under t hese circumstances and results would not be guaranteed. Therefore, the best way to control and minimize flare emissions is through the use of pre-combustion control, which prevents the forma tion and reduces the amount of vent gases routed to refinery flares, or recover the vent gase s prior to combustion at the flare.

B. FLARE MINIMIZATION PLANS

Refineries can obtain meaningful results in their e ffort to minimize the volume of vent gases routed to the flare by setting up and implementing flare minimization plans. It is possible to achieve significant reductions in the volume of ven t gas generated by process units at refineries. Listed below are several possible alternatives of m inimizing flare emissions that could be incorporated in flare minimization plans:

- Better engineering and equipment design A reevaluation of existing process flow and equipme nt allowing changes in operating parameters such as temperature and pressure setting s may result in reduced volumes of vent gas being generated.

- Diverting or eliminating streams vented to the flar es Certain streams that routinely are directed to the flare may be rerouted and either treated for use as fuel gas or recycled back in the process

.

- Installation of redundant equipment to increase rel iability By installing redundant equipment, in case of a bre akdown, the spare can be put on line, thus avoiding a process upset that results in gas b eing routed to the flare.

- Installation of flow monitors for vent gas generate d at each process unit Installation of flow monitors on process units flar e headers is a useful tool that allows the operator to quickly identify the origin of increase d flare flows and take immediate corrective actions, potentially avoiding a flare ev ent.CHAPTER II – CONTROL TECHNOLOGY FINAL STAFF REPORT

Proposed Amended Rule 1118 II-2 October 2005 - Periodic monitoring maintenance programs of pressur e relief valves that identify leaks to the blowdown system, such as acoustic or thermal su rveys Pressure relief devices may develop leaks in time, due to the corrosive nature of the process, due to chattering or improper reseating. Given the extended periods of time between turnarounds, leaks may result in significan t emissions, even at small rates. By conducting acoustical or thermal surveys of relief devices connected to the flare, the operators can identify and, with detection equipmen t currently available, even quantify the amount of leak-through gas that escapes to the flare. Upon identification of leaking relief devices, the operator can prioritize their m aintenance and repair in order to reduce flare emissions. This program is especially valuab le for those flares that are not equipped with flare gas recovery because these leaks end up being combusted in the flare for extended periods of time until the next scheduled t urnaround.

- Conducting Specific Cause Analysis of significant f laring incidents This investigative procedure is used to identify th e cause of significant flaring events and whether any equipment and/or operational changes ar e needed to prevent future reoccurrences. Once the investigation is completed , corrective measures need to be taken and implemented. It is important to communicate th e findings to all parties involved and

create a mechanism to track corrective actions in o rder to prevent future events. This analytical process enables a facility to shift the focus on preventing flaring events rather than reacting to them.

- Operator training for environmental awareness Making the operators aware of the impact of flare e vents on the environment and teaching them procedures that minimize venting to f lares needs to be part of the facility’s training program and should have full management su pport.

- Optimization of turnaround schedules

Coordination of turnaround schedules for different units can result in reducing flaring activity and minimize emissions associated with the se periodic maintenance activities.

- Developing startup and shutdown procedures that do not use flaring For certain units, it is possible to develop proced ures that avoid flaring during shutdown and startup, such as using reduced loads, recycling feeds, better decontamination procedures, etc. Sometimes more time is necessary for a startup or shutdown, or physical modifications achieve this purpose.

C. FLARE GAS RECOVERY SYSTEMS

An alternative control option to minimizing the vol ume of vent gases routed to flares is to simply prevent the vent gases from being combusted in the flare by recovering them with a flare gas recovery system. In light of increasing environmen tal concerns, this flare gas recovery system control option is becoming popular, especially sinc e there is an economic incentive due to recovery of valuable gas. The system usually consi sts of a set of compressors, a heat exchanger, a phase separator and associated pumps. The vent g as is compressed, cooled and routed to an amine scrubber for removal of sulfur compounds, and subsequently may be used as fuel gas or feed for refinery processes. A flare system genera lly consists of a header or manifold that collects the flare gases from various sources, a kn ockout drum, a liquid seal (usually water)CHAPTER II – CONTROL TECHNOLOGY FINAL STAFF REPORT

Proposed Amended Rule 1118 II-3 October 2005 drum, and the flare itself. A flare gas recovery s ystem unit connection is typically located

between the knockout vessel and the flare water sea l.

The primary control variable of the flare gas recov ery system is the flare system pressure. As vent gases from various process units collect in th e flare header, pressure reaches a predetermined pressure control set point, triggerin g the start up of the recovery compressor. The suction pressure of the compressor is set lower tha n that of the water seal, such that under normal operation, there is not enough pressure in the flar e header to break through the liquid seal and all gas is recovered. During major upsets, if the flow exceeds the compressor capacity, the flare header pressure increases, breaking the liquid seal and the vent gases reach the flare, where they are combusted. Therefore, the safety function of t he flare system is maintained in the event of process upset conditions.

In order to have a high recovery rate, the compress or station should be sized with a capacity two to three times the normal flare flow (Oil and Gas J ournal, December 7, 1992). API Guideline 520 states that the normal flow rate is some averag e flare load or a frequently encountered maximum load and that the recovery system should be designed to operate over a wide range of dynamically changing loads. API 520 goes on to say that often these systems are installed to comply with local regulatory limits and therefore, must be sized to conform to any such limits.C H A P T E R III

PROPOSED RULE AMENDMENTSCHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-1 October 2005 PROPOSED AMENDMENTS

Staff proposes amending Rule 1118 as follows:

- Add, modify or delete definitions.

- Add new operational requirements for flares and est ablish diagnostic practices to minimize flaring.

- Prohibit the flaring of gases other than those resu lting from emergencies, shutdowns, startups, turnarounds and essential operational nee ds and require minimization of such flaring.

- Establish refinery specific performance targets for minimizing flare emissions based on annual crude throughput.

- Require refineries to pay a mitigation fee for exce edances of a refinery specific performance target.

- Require a Flare Minimization Plan and possible issu ance of a Notice of Sulfur Dioxide

Exceedance when flare SOx emissions exceed the faci lity specific target for a given year.

- Add and modify requirements for the Flare Monitorin g and Recording Plan.

- Add and modify requirements for the operation monit oring and recording.

- Modify the recordkeeping requirements.

- Add new notification and reporting requirements.

- Expand and update the test methods.

- Modify and add exemptions.

- Enhance and update monitoring specifications in Att achment A – Flare Monitoring System Requirements.

- Modify and enhance Attachment B – Guidelines for Ca lculating Flare Emissions which include missing data substitution procedures.

A. DEFINITIONS

The following definitions are new:

- Emergency - is defined as a condition that requires immediate attention to restore normal operation, caused by a sudden, infrequent and unavo idable event. An emergency may be caused by equipment breakdown, natural disaster or an act of war or terrorism. If a repetitive flare event from the same equipment is caused by poor maintenance or a flare

event results from careless operation, it will not be deemed an emerge ncy.

- Essential Operational Need – is defined as flare ev ent caused by a specifically listed operational or maintenance related activity where d ue its quality or quantity, the vent gas cannot be reasonably recovered, treated, used or de livered for sale with existing equipment. Examples of Essential Operational needs as determined by the Executive

Officer are:
Temporary fuel gas imbalances caused by inability of a customer to receive sales

gas used for generation of electricity for a state grid or a third party contractualCHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-2 October 2005

gas purchase agreement, or due to sudden shutdown o f a combustion device for reasons other than operator error or poor maintenan ce; Leakage of relief valves due to malfunction; Venting of gas streams that are incompatible with the operation of the flare gas

recovery equipment (e.g., molecular weight outside the design range) or that could pose a safety hazard to the fuel gas system ( e.g., very low or very high BTU content that causes temperature swings in combustio n devices, upsetting the process). Whenever the vent gas has a low BTU cont ent a refinery may use supplemental natural gas or other clean gas that is compliant with Rule 431.1 to ensure high combustion efficiency; Venting of clean gas streams to either a clean se rvice flare or a general service

flare; Intermittent minor venting from sight glasses, co mpressor bottles, sampling

equipment and pumps or compressors casings; Emergency situations when the pressure vessel ope rati o n g pressure rises above

the set point of the pressure relief valve device(s)

.

- Flare Gas Recovery System - is defined as any syste m designed to prevent or minimize the combustion of vent gases in a flare, composed o f, but not limited to, compressors, heat exchangers, pumps, water seal drums, etc.

- Flare Minimization Plan is defined as a document th at meets specific rule requirements in subdivision (e).

- Natural Gas - is defined as a mixture of gaseous hy drocarbons, with at least 80 percent methane (by volume), and of pipeline quality, such as the gas sold or distributed by any utility company regulated by the California Public Utilities Commission.

- Notice Of Sulfur Dioxide Exceedance – is defined as a notice that may be issued by the Executive Officer to a refinery in the event an ann ual performance target is exceeded and remains in its compliance record.

- Pilot - is defined as an auxiliary burner used to i gnite the vent gas routed to a flare.

- Purge Gas - is defined as a continuous gas stream i ntroduced in the flare header, flare stack and /or flare tip for the purpose of maintain ing a positive flow that prevents that prevents the formation of an explosive mixture due to ambient air ingress.

- Sampling Flare Event – this definition replaces Rec ordable Flare Event and applies to

flare events with a flow rate of at least 330 scfm for fifteen consecutive minutes or more, or any other flare event as approved in writing by the Executive Officer upon request from a facility, due to specific operational parame ters of a flare. Sampling flare events

that occur within 15 minutes of each other are cons idered a single event if the facility can

demonstrate to the satisfaction of the Executive Of ficer that the events had a common cause and the release of vent gas originated from t he same process unit.

- Shutdown - is defined as the procedure by which the operation of a process unit or piece of equipment is stopped at the end of a production run or for the purpose of performing maintenance, repair or replacement of equipment.

- Specific Cause Analysis - is defined as an investig ation used to identify the cause of certain flare events with emissions exceeding eithe r 100 pounds of VOC or 500 pounds of sulfur dioxide, or 500,000 standard cubic feet o f flared gas, provide corrective measure(s), and prevent recurrence of a similar eve nt.CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-3 October 2005 - Startup - is defined as the procedure by which a pr ocess unit or piece of equipment achieves operational status. The attainment of nor mal operational status may be substantiated by parameters such as temperature, pr essure, feed rate and also by products meeting quality specifications.

- Turnaround - is defined as a planned activity invol ving shutdown and startup of one or several process units for the purpose of performing periodic maintenance, repair, replacement of equipment, or installation of new eq uipment.

- VOC – is defined as in Rule 102 of AQMD Rules and R egulations.

The following definitions were modified:

- Flare Event - clarifies that an event takes place w hen vent gas is combusted in a flare and ends when the vent gas velocity drops below 0.12 fe et per second, or when no more vent gas is combusted as demonstrated by the water seal monitoring record or other parameters as approved by the Executive Officer in the Flare Monitoring and recording

Plan.

- Flare Monitoring System - was expanded to include, in addition to the flow meter, a continuous higher heating value analyzer and a tota l sulfur analyzer.

- Gas Flare - was shortened by removing “Gas” since t his rule addresses flares used to dispose of gases only.

- Hydrogen Plant - was expanded to include the proces ses used to generate hydrogen.

- Representative Sample - was modified by deleting pa rt of the definition that no longer applies or was moved under monitoring requirements.

- Petroleum Refinery – was expanded, for the purpose of this rule, to clarify that all portions of the petroleum refining operation, inclu ding those at non-contiguous locations operating flares, shall be considered as one petrol eum refinery.

- Sulfur Recovery Plant - was expanded to also includ e sour gases as process feed.

- Vent Gas - was redefined as any gas generated at a refinery that is routed to a flare excluding assisted air or steam injected directly i nto the stack or flare combustion zone via a line separate from the flare header.

The following definition was deleted:

- Recordable Flare Event - was removed due to the new monitoring requirements and was replaced with “sampling flare event”.

B. REQUIREMENTS

Staff has added new requirements for flares, arrang ed by the date they become effective.

The following requirements become effective on Janu ary 1, 2006:

- A flare must have the pilot flames present any time the system it serves is in operation.

- All flares must operate without visible emissions, as determined by US EPA Method 22. The method allows for visible emissions for no long er than five minutes within a two consecutive hour period.CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-4 October 2005 - All pressure relief devices (PRDs) connected direct ly to flares must have an annual inspection using acoustical or thermal surveys in o rder to detect leaks. The requirement applies only to PRDs venting directly to flares (ga ses that are not collected or controlled with flare gas recovery and treatment. The inspect ion has to be conducted within 90 days prior to a scheduled turnaround, if one is schedule d for that calendar year.

- The owner or operator of a flare having a flaring e vent with emissions exceeding either 100 pounds of VOC or 500 pounds of sulfur dioxide, or 500,000 standard cubic feet of vent gas combusted is required to conduct a Specifi c Cause Analysis of the event. Flare

events associated with planned shutdowns, planned startups, and turnarounds are exempt from this requirement since their cause is known an d therefore no investigation is

necessary.

- The owner or operator of a flare has to identify th e cause, where feasible, of any flare event where at least 5,000 standard cubic feet of v ent gas was released to the flare. For some smaller releases, the owner or operator may no t have sufficient data to determine

the cause of the flare event.

The following requirements are effective January September 1, 200 7 6 :

- The owner or operator of a refinery subject to rule shall submit the technical detail of each flare system, including an audit of vent gas r ecovery capacity, an assessment of the flare gas reductions achieved since the adoption of Rule 1118 in 1998 and the planned

future flare emission reductions.

The following requirements are effective January 1, 2007:

- The owner or operator of a refinery subject to this rule shall submit an evaluation of options to reduce flaring during planned events suc h as shutdowns, startups and turnarounds. The evaluation shall include, but is not limited to such options as slowing the depressurization of vessels, storing vent gases , etc.

- Owners or operators have to operate flares such tha t only vent gases resulting from an emergency, shutdown, startup, turnaround or essenti al operational need are combusted and have to minimize flare emissions during these e vents.

- Staff acknowledges that some refineries will instal l gas recovery and treatment system(s) to comply with this requirement, and that the refin eries will need time to connect and operate these systems. In recognition of this need staff proposes to establish a compliance date of no later than January 1, 2009, o r January 1, 2010 if more than two flares are to be controlled, provided that those re finery operators submit an application to construct and operate the control equipment for app roval by the Executive Officer prior to January 1, 2007.

The following requirement is effective on January 1 , 2009:

− Any vent gas combusted in a flare, except for vent gas resulting from an emergency, shutdown, startup, process upset or relief valve le akage, cannot exceed 160 ppm H 2 S concentration, averaged over three hours. Staff be lieves that by January 1, 2009, most refineries will have sufficient vent gas recovery a nd treatment capacity to be able to comply with this requirement during essential opera tional needs, for which this requirement would essentially apply. Refineries needing to install gas recovery and treatment system(s) for more than two flares to com ply with the requirements to limit andCHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-5 October 2005 minimize flaring under paragraph (c)(3), as well as this requirement to limit the H 2 S concentration in the vent gas, will be granted a co mpliance date of January 1, 2010, to be consistent with the requirements of paragraph (c)(3 ), provided that those refinery operators submit an application to construct and op erate the control equipment for approval by the Executive Officer prior to January 1, 2007.

C. PERFORMANCE TARGETS

PAR 1118 prohibits flaring of gases other than thos e resulting from emergencies, shutdowns, startups, turnarounds, and essential operational ne eds. It also sets decreasing flare total sulfur performance targets for the allowed flaring activit ies, calculated and reported as sulfur dioxide (SO 2 ), for subject refineries, based on 2004 throughputs crude processing capacities , with the purpose of capturing emission reductions achieved s ince the rule was adopted and to ensure that

these and future emission reductions are enforceabl e, permanent, real, and verifiable. During the rule development process, industry identified an in equity of using crude throughput versus crude capacity based on a fixed year of 2004 to establish annual SO 2 performance targets. In any one year, any refinery could be conducting a shutdown o r turnaround of a major crude processing unit, which could reduce crude throughput for that baseline year reflecting an artificially low baseline throughput for that refinery. Whereas cru de processing capacity more accurately allocates refinery emissions based on normal refine ry operations. Local refineries are operating at near capacity; therefore, the difference in emis sions impact and reductions based on throughput or capacity are minimal. Total SO 2 reductions will be determined annually for each calendar year. To determine compliance with the SO 2 Performance Targets, the annual emissions will be divided by the 2004 refinery throughput crude processing capacity . The performance targets proposed and the corresponding milestones, starting with year 2006, are as

shown in Table III - 1:

Table III– 1

SO 2 Performance Targets (Tons per million barrels crude process ed ing capacity )

Year 2006 2008 2010 2012

SO 2 Performance Target 1.5 1 0.7 0.5

In the event that a refinery exceeds the specified performance target in any calendar year, it will have to pay a mitigation fee for each ton of sulfur dioxide over the limit based on the following levels of exceedance: $25,000 for each and every to n where the exceedance is up to ten percent over the performance target, $50,000 for each and e very ton where the exceedance is greater than ten percent but no more than twenty percent over th e annual performance target, or $100,000 for each and every ton where the exceedance is greater than twenty percent over the applicable performance target. The mitigation cannot exceed $ 4,000,000 dollars per each petroleum refinery in any one year. Any mitigation fees paid would be used to implement emission reduction projects in the area impacted by the exce ss emissions.

It is expected that refineries will implement the p rocedures and install the equipment necessary to achieve compliance with the annual sulfur dioxid e performance targets. However, since the operation of flares is variable based upon periodic events, some of which may be unforeseeable,CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-6 October 2005 it is possible that a refinery could exceed a perfo rmance target in any one year. The mitigation fee provision offers the refinery an alternative co mpliance option in that circumstance and allows the opportunity for the refinery to take those acti ons necessary to ensure the performance targets are met in future years. For each year an annual p erformance target is exceeded, the Executive Officer may also issue a Notice of Sulfur Dioxide E xceedance that will become part of the petroleum refinery’s compliance record.

In establishing the appropriate monetary amount for the mitigation fees, staff considered two larger petroleum refineries that currently have no or limited controls on their flares. Historical flare sulfur dioxide (SO 2 ) emissions and flare vent gas flows for the two fa cilities for the years 2002, 2003 and 2004 and the three year average are shown in Table III - 2.

Table III – 2

Historical Data

2002 2003 2004 Average

SO 2 (tons/year) 59 76 27 54 Refinery

1 Flow (million cubic feet per year) 804 804 657 755

SO 2 (tons/year) 77 45 19 47 Refinery

2 Flow (million cubic feet per year) 308 324 289 307

As part of their 2004 Emissions Fee Billing (EFB) s ubmittal, .Refinery 1 and Refinery 2 reported processing of approximately 95 and 51, million barr els of crude oil during the 2003-2004 fiscal year, respectively. Table III-3 is a summary of th e permitted annual crude oil throughput (in million barrels of crude oil per year), the 201 0 2 performance target for each petroleum refinery target (in tons SO 2) and the amount of SO 2 exceedance at twenty percent over the 2012 annual

SO 2 performance target of 0.5 tons per million barrels of crude oil.

Table III – 3 Analysis

Facility Annual Crude

Oil Throughput (million barrels) 201 0 2 Annual SO 2

Performance Target (tons) 20% SO 2

Exceedance (tons)

Refinery 1 93 47 10

Refinery 2 50 25 5

To estimate the vent gas flow associated with the 1 0 tons and 5 tons of sulfur dioxide excess emissions, staff will use the ratio of three year a verage of vent gas flow to SO2 emissions. Staff

believes that the total flow and SO2 emissions for any year will average the high and low flows

and SO2 emissions that will be used to determine th e approximate vent gas flow for the sulfur

dioxide excess emissions.

Therefore, the flow associated with the yearly exce edance, in million standard cubic feet per year (mmscfy) and calculated as daily, averaged over 365 days (mmscfd) is:CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-7 October 2005 Refinery 1

Flow 1 = 10 tons * 755 mmscfy / 54 tons = 140 mmscfy = 0.38 mmscfd

Refinery 2 :

Flow 2 = 5 tons * 307 mmscfy / 47 tons = 33 mms cfy = 0.09 mmscfd

To prevent future exceedances, it is assumed that t he two facilities would have to install flare gas recovery and treating systems to control this amoun t of vent gas associated with the SO 2 exceedance. The capacity of the control system sho uld be two to three times the vent gas flow rate; staff has determined the cost of a flare gas recovery and treating system to be $2.17 million per million standard cubic feet per day (mmscfd) of vent gas recovery/treatment (see discussion in Chapter VI).

The cost to install vent gas recovery and treatment to control the incremental amount of sulfur dioxide that caused the exceedance of the annual pe rformance target is:

Refinery 1

Control Cost = 0.38 mmscfd * 2 * $2.17 million p er mmscfd / 10 tons per day

= $164,920 per ton SO 2 reduced

Refinery 2

Control Cost = 0.09 mmscfd * 2 * $2.17 million p er mmscfd / 5 tons per day

= $78,120 per ton SO 2 reduced

The average cost to control the incremental amount of sulfur dioxide that caused the exceedance of the annual performance target is $121,520. As p reviously stated, the operation of flares and resultant emissions are variable based upon periodi c events. Therefore, a mitigation fee of $100,000 per ton of SO 2 for annual exceedances of more than twenty percent of the annual performance target is appropriate. The mitigation fee for exceedances less than twenty percent are less than the cost of vent gas recovery and tre atment and therefore would be considered

reasonable.

D. FLARE MINIMIZATION PLAN REQUIREMENTS

Each refinery that exceeds an annual performance ta rget must submit a Flare Minimization Plan to the AQMD for approval from the Executive Officer , along with appropriate fees pursuant to Rule 306 but no later than 90 days from the end of the calendar year when the performance target

was exceeded that demonstrates the actions to be ta ken to achieve the performance targets. The main required elements of the plan are:

- A complete description and technical specifications for each flare at a facility;

- Detailed process flow diagrams of upstream equipmen t venting to each flare and an identification of all control equipment;CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-8 October 2005 - Policies and procedures , as well as any additional equipment, to be used to minimize vent gases during emergencies, shutdowns, startups and t urnarounds and during essential operational needs; and

- A complete description of a flare gas recover and t reatment system(s) to be installed to meet the performance target(s).

The AQMD will make available the Flare Mininimizati on Plans, less any confidential information, for public comments for a period of 60 days and respond to them prior to taking action on the plans. Any facility that exceeds it annual sulfur dioxide emission limit during a subsequent calendar year will have to submit to the AQMD a revised Flare Minimization Plan within 90 days from the end of the calendar year, i n which it will detail additional measures for preventing future exceedance. If the Executive Off icer deems the plan deficient, the facility has 45 days to correct and resubmit it. Failure to do so would cause the Executive Officer to deny the plan and issue the facility a Notice of Violati on.
A facility may, without exceeding the performance t argets and on a voluntary basis, submit a Flare Minimization Plan for approval to the Executi ve Officer. The plan would be subject to the same provisions as a mandatory plan, but if denied no Notice of Violation would be issued to the facility.

E. FLARE MONITORING AND RECORDING PLANS

Each existing facility currently in operation must submit a revised Flare Monitoring and Recording Plan by June 30, 2006 for approval by the AQMD, along with appropriate fees pursuant to Rule 306. Any new facility or non-oper ating facility that starts operating after the

rule is amended will have to submit a Flare Monitor ing and Recording Plan and appropriate fees at least 180 days prior to initial start-up and not ify the AQMD seven days prior to startup or resumption of operations. The current monitoring p lans submitted pursuant to Rule 1118, adopted February 13, 1998 will be in effect until t he revised plans are approved by the AQMD. The revised plans must provide, in addition to the existing information, details on installed heat content analyzers, total sulfur analyzers and upgra ded flow meters, where applicable.

F. OPERATION MONITORING AND RECORDING

The proposed amendment has several new requirements for flare monitoring and recording. The new requirements will be phased in as follows:

Effective upon rule amendment January 1, 2006 :

- The presence of a flare pilot flame has to be monit ored using a thermocouple or an equivalent device, such as infrared or ultraviolet cameras.

- Refineries will have to use video monitors equ ipped with date and time stamp to monitor

the flares for visible emissions. The video record ing will have to be maintained at the facility for a period of 90 days and submitted to AQMD personnel upon request.

E ffective January 1, 2006 :

- Facilities subject to this rule are required to t ake a daily representative sample. Only one representative sample is required each day for flar e events that are not sampling flare events. A representative sample collected for a sa mpling flare event on that day may be used to satisfy this requirement. For flare events lasting 15 minutes or less, noCHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-9 October 2005 representative sample is required. A sample shall not be required if the operator demonstrates vent gas is not routed to a flare base d on verifiable records of flare water seal level and/or other parameters as approved by t he Executive Officer in the Flare Monitoring and Recording Plan or the Revised Flare Monitoring and Recording Plan.

Effective July 1, 2006:

- Refineries will have to use video monitors equipp ed with date and time stamp to monitor

the flares for visible emissions. The video record ing will have to be maintained at the facility for a period of 90 days and submitted to A QMD personnel upon request.

Within six months from approval of the Flare Monito ring and Recording Plan, but no later than July 1, 2007:

- Continuous higher heating value and semi-continuous total sulfur analyzers are required for emergency and general service flares to elimina te problems related to sampling and data accuracy, as recommended in the Evaluation Rep ort on Emissions from Flaring Operations at Refineries. The use of analyzers wil l provide a more realistic picture of flare emissions by providing more data points for t he heat content and total sulfur content of the vent gases, thus increasing the accuracy and reliability of emission reporting, that is currently achieved by using data from weekly sam ples. Refineries must begin monitoring within six months from approval of the R evised Flare Monitoring and Recording Plan by the AQMD. Until the analyzers ar e installed and certified by the Executive Officer, the refineries will be required to measure and sample for both higher heating value and total sulfur daily (an increase f rom the current weekly sampling requirement) in addition to collecting representati ve samples during a sampling flare event, using a step by step procedure outlined in T able 2 1 (Effective Until June 30, 2007), footnote 4 of the proposed amended rule. However, if no flar e event takes place during the day, as demonstrated by water seal level records or other parameters as approved in the Flare Monitoring and Recording Plan , no sample is required. In the event that samples cannot be taken due to an exempt occurrence and emissions are estimated, the methods are those in the missing dat a procedures included in an appendix to the rule and estimated emissions have to be repo rted as such in the quarterly flare
report.

Effective January 1, 2007:

- Flow meters are required for monitoring and recordi ng the purge gas and pilot gas flow rates for all emergency and general service flares and have to be approved by the AQMD.

- All emergency and general service flare flow meters will have to be installed at a representative location to indicate an accurate flo w to the flare. This requirement was necessary since there are flow meters located upstr eam of water seals at flares equipped with flare gas recovery systems that may indicate a flow that actually is recovered and not breaking the water seal. The operators monitor the water seal level to determine whether an actual flare event took place. There ar e also problems at low flows, when ambient heat creates a gas flow inside the large di ameter flare headers, resulting in a “ghost” reading on the flow meter. In order to eli minate these problems, flow meters have to be installed downstream of water seals or, if this is not feasible due to physicalCHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-10 October 2005 constraints, they need to be equipped with totalizi ng capability that discounts reverse flows to a recovery compressor or due to turbulence created by ambient heat.

- Each emergency and general service flare that is no t equipped with a total sulfur analyzer will have to be equipped with an automated sampling system capable of alerting the operator that a sampling event has started.

G. RECORDKEEPING REQUIREMENTS

The proposed amendment requires that video recordin gs of all flares be kept for 90 days and all other records mandated by the rule be kept for a pe riod of five years.

H. NOTIFICATION AND REPORTING

The proposed amendment has new notification require ments and enhanced reporting requirements, as follows:

- Facilities subject to this rule will have to prov ide a 24 hour telephone service for access by the public for inquiries about flare events. Th e owner or operator shall provide the Executive Officer in writing the name and number of the initial contact and any contact update.

- Refineries will have to notify the AQMD by telephon e within one hour of a flare event exceeding 100 pounds of VOC, 500 pounds of total su lfur emissions calculated as sulfur dioxide, or 500,000 standard cubic feet of vent gas . The one hour time requirement starts at the time the refinery operator facility knows or should have known that the aforementioned mass levels may have been emitted or the vent gas as measured by the flow meter is determined to exceed 500,000 standard cubic feet of vent gas. A “specific cause analysis”, identifying the cause and duration of the event, mitigation and corrective actions taken, has to be submitted to the AQMD with in 30 days.

- A 24-hour advance notice to the AQMD is required fo r scheduled planned flare events that have the potential to exceed 100 pounds of VOC or 500 pounds of total sulfur, calculated as sulfur dioxide or 500,000 standard cu bic feet of vent gas.

- The quarterly reports will have to be submitted in an electronic format approved by the AQMD and certified in writing by a responsible faci lity official that the information is

true and accurate. Emissions will have to be calcu lated or, in case of missing data, substituted using the guidelines in Attachment B to the rule. The refineries will also have to include in the quarterly report a categorization of flare events by cause and the associated emissions. Lastly, records of leak surv eys done in the quarter for pressure

relief devices connected to flares will have to be reported, including identification of the devices, dates of inspection and the person(s) cond ucting the surveys.

I. TEST METHODS

The following are additions and modifications to th is section of the rule:

- The higher heating value of the flare vent gas has to be monitored with a semi-continuous analyzer meeting or exceeding the specifications in Attachment A to the rule.

- Total sulfur concentration calculated as sulfur dio xide may be monitored with a semicontinuous total sulfur analyzer meeting or exceedi ng the requirements in Attachment ACHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-11 October 2005 to the rule. Until such time as the monitor is cer tified by the Executive Officer, the samples collected by the refinery operator shall be determined using AQMD Method 307-91 or updated ASTM Method 5504-01.

- The accuracy of the flare flow meters has to be ver ified annually according to manufacturer’s procedures.

- For determining visible emissions from flares, refi neries have to use procedures outlined in U.S. EPA Method 22, 40CFR Part 60 Appendix A.

J. EXEMPTIONS

An exemption was added for excluding the flare-rela ted total sulfur emissions, calculated as sulfur dioxide, resulting from external power curta ilments excluding interruptible service agreements, natural disasters and acts of war or te rrorism, from the annual facility emissions established under Performance Targets since these e vents are beyond the reasonable control of the refinery operator. In addition, has added lang uage to clarifying that sampling and analyses of representative samples for higher heating values an d the concentration of total sulfur, expressed as sulfur dioxide, pursuant to paragraph (g)(3) may not be required for any flare event when collecting a sample is unfeasible or constitutes a safety hazard

K. ATTACHMENT A

Attachment A was enhanced by incorporating addition al specifications for the continuous flow measuring device and adding new specifications for the heat content analyzer and the total sulfur analyzer.

L. ATTACHMENT B – GUIDELINES FOR CALCULATING FLARE EMISSIONS

Attachment B was modified to include equations and emission factors for calculating flare emissions for vent gas, natural gas, propane and bu tane, thus making reporting uniform among refineries, sulfur recovery plants and hydrogen pro duction plants. Another addition provides the methodology to be used for data substitution during flow meter, sampling and analyzer down periods or when the representative samples are not measured and recorded pursuant to the rule requirements. Data substitution is not required if it can be demonstrated to the satisfaction of the

Executive Officer that there was no flow to the fla re during the flow meter and/or analyzer outage or a sample was not taken and analyzed. Foo tnote 4 in Table 1 of Rule 1118 further explains that samples specified in Table 1 will not be required if the operator demonstrates that vent gas is not being routed to a flare based on ve rifiable records of flare water seal level and/or other parameters as approved by the Executive Offic er in the Flare Monitoring and Recording Plan or Revised Flare Monitoring and Recording Plan

.

Once the methodology and parameters used to demonst rate that the vent gas is not being routed to a flare is included in the approved Flare Monito ring and Recording Plan or Revised Flare Monitoring and Recording Plan, it is considered to be to the satisfaction of the Executive Officer for the purpose of making the above demonstration. If there was flow, the method shown in equation (1) shall be used to calculate the substit uted data, unless an alternate method using recorded and verifiable operational parameters and/ or process data is approved by the Executive Officer to be representative of the missing paramet ers , including reference to similar events that occurred previously . The goal of the data substitution methodology wa s to provide a conservative estimate based on the operational hist ory of the flare.CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-12 October 2005 

# ( )

Avg Max Max P

P P MP

−

×

− = 5.0 Equation (1)

where:

MP = The missing parameter for which data was not recorded.

P Max = Maximum measured and recorded value of the missin g parameter over a 5

year period.

P Avg = Average measured and recorded value of the missi ng parameter over a 5

year period.

This methodology was developed based on the reporte d flare event data for refineries operating in the South Coast Air Basin (including a sulfur pl ant) between October 1, 1999 through June 30, 2005. The data reported by the refineries and util ized in the analysis included:

• The duration of each individual flare event;

• The total volume of gas released during the flare e vent;

• The higher heating value of the flared gas;

• Basis for which the higher heating value (HHV) of t he flared gas was determined (lab measurement, average of previous events, etc.);

• The sulfur content of the flared gas; and

• Basis for which the concentration of total sulfur, expressed as sulfur dioxide, of the flared gas was determined (lab measurement, average of previous events, etc.).

Data whose origin was not based on a discrete measu rement was discarded. It was discarded so the entirety of the data being analyzed would be re presentative of actual flare events. This would prevent variability in the data being attenuated th rough the introduction of substitute data based

on an average.

The data for each recorded flare event between Octo ber 1999 and June 2005 for each flare were plotted as a function of time. These plots reveale d:

• The concentration of total sulfur, expressed as sul fur dioxide, in the flared gas showed a high degree of data scatter that varied randomly ov er a potential range of 200,000 ppm.

• The volume of gas flared in terms of rate and total volume released showed a high degree of data scatter which varied randomly over a potent ial range of 39,000 MSCF.

• The HHV of the flared gas exhibited the lowest degr ee of data scatter, but still varied randomly. The magnitude of the variation was over a potential range of 5000 Btu/scf.

The large range and randomness exhibited by the pop ulation of data posed the following difficulties in creating a methodology for estimati ng substitute data:CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-13 October 2005 • Requiring the facility to report substitute data ba sed on the single highest historical measured value would result in the facility grossly over-estimating their emissions. The emission would be grossly over-estimated as a resul t of the majority of the flares having a single point outlier for each data set that was o rders of magnitude greater that the majority of the population.

• Requiring the facility to report an average value w ould result in a significant portion of the data falling above the mean value. There would be a large portion of data above the mean value due to the high degree of data scatter e xhibited by the population of data.

• A methodology based on a short term sample of data could result in substitute data being

under-estimated. The data would be under-estimated if the short term sample happened to be taken from a period where the values of the s hort term population were on a downtrend. There were flares in the analyzed data set, which included 23 consecutive quarters (5 years, 9 months) of reported data that demonstra ted cyclic behavior. Coincidently, the refineries have stated that they turnaround their u nits every five years. This behavior showed surges in the value of a given parameter, fo llowed by a lull. Any data that were estimated based on the lull period would provide un der-estimated results during the surge, which is contrary to the goal of the substit ution methodology.

The method shown in Equation (1) accounted for the problems listed above. This method accounts for the average value of the population wi th respect to the deviation from the mean. The use of a five year (20 quarters) averaging peri od also eliminates the potential of underestimating substitute data due to basing it’s value on a short term period where the value of the population could be in a lull. The 0.5 multiplier in equation (1) was empirically determined by fitting the equation to the population of data. Th e equation was fit multiple times with the multiplier incrementally increased between a range of 0.4 and 0.7. The 0.5 multiplier provided the desired result. This value provided a result t hat generally captured 98% of the population of data, but was sufficiently less than the single poi nt outliers that were present in some populations

of data.C H A P T E R IV

EMISSION INVENTORYCHAPTER IV – EMISSION INVENTORY FINAL STAFF REPORT

Proposed Amended Rule 1118 IV-1 October 2005 A. CONTRIBUTING SOURCES

As shown in Chapter I, in the AQMD there are seven petroleum refineries, one sulfur plant and one hydrogen generating plant accounting for 27 fla res categorized as emergency flares, clean flares and general purpose flares. The breakdown b y flare, as reported in the September 2004 Evaluation Report, including flare system design an d flare gas recovery capacities, is shown

below in Table IV – 1.

Table IV – 1 Flare Inventory

* These flares share a flare gas recovery system

Flare ID Capacity

(lbs/hr) Vapor Recovery

Capacity (MMscfd) Notes

Flare No. 1 41,000 0.36

Flare No. 2 232,281 6.96*

Flare No. 3 1,120,000 1.4*

Flare No. 4 600,000 None

Flare No. 5 343,900 None Clean Flare

Flare No. 6 1,300,000 2

Flare No. 7 250,000 None

Flare No. 8 1,040,000 4.8

Flare No. 9 956,000 None

Flare No. 10 133,950 6.96*

Flare No. 11 825,000 None

Flare No. 12 6,000 None Clean Flare

Flare No. 13 1,300,000 6

Flare No. 14 26,718 None Clean Flare

Flare No. 15 3,540,000 9.8

Flare No. 16 176,000 None

Flare No. 17 960,000 6

Flare No. 18 1,400,000 6

Flare No. 19 173,000 None

Flare No. 20 188,000 None

Flare No. 21 1,220,000 1.25

Flare No. 22 655,000 1.4*

Flare No. 23 26,000 None

Flare No. 24 335,847 6.96*

Flare No. 25 498,000 None

Flare No. 26 1,407,000 6

Flare No. 27 70,000 0.06 Clean FlareCHAPTER IV – EMISSION INVENTORY FINAL STAFF REPORT

Proposed Amended Rule 1118 IV-2 October 2005 B. EMISSION INVENTORY

According to the 2003 AQMP, the SO 2 emissions inventory for refinery flares, based on the 1997 annual reports for emissions fee billing (EFB) , is 4.14 tons per day (the initial number, based on unaudited data at the time the AQMP was pu blished, was 4.4 tons per day). For 2006 and 2010, this inventory is projected to be reduced by 50 percent through the implementation of Step II of control measure CMB-07, and the AQMP ass umes concurrent emission reductions for the other criteria pollutants. The proposed amendm ent of Rule 1118 will implement Step II of

the control measure and further reduce emissions to the extent feasible.

Flare emissions are reported on a quarterly basis p er current requirements in Rule 1118, and are calculated based on flare vent gas flows and weekly samples that are analyzed to determine the concentration of total sulfur, expressed as sulfur dioxide, and the higher heating value (HHV) of the vent gas. It has to be noted that these emissi ons are different from the annual emissions reported under EFB program, where reported flare em issions are calculated based on crude throughput and the amount of elemental sulfur produ ced at each facility, using appropriate

emission factors.

A summary of the quarterly reports, showing Rule 11 18 annual flare emissions, from 200 1 0 through 2003, extracted from the September 2004 rep ort presented to the Governing Board and the reported flare emissions for 2004 is shown in T able IV – 2.

Table IV – 2 Rule 1118 Reported Annual Flare Emissions (Tons)

Year Flow

(mmscf) NOx VOC CO PM10 SOx Total

2000 4,085 136 125 733 43 2,633 3,670

2001 8,324 380 456 2,058 87 1,793 4,774

2002 2,440 83 78 450 25 754 1,390

2003 2,235 79 75 423 23 735 1,335

2004 2,392 93 70 364 27 352 906

The data in the table shows that flare emissions ha ve decreased in the years following the adoption of the rule in 1998, as the refineries bec ame more sensitive to flaring issues and implemented voluntary measures to reduce the vent g as flow combusted in the flares and better managed flare operations. It is important to note that these voluntary reductions in flare gas flow and associated emission reductions were generally n ot achieved through the installation or modification of gas recovery capacity or flare gas treatment systems. Since 1998, only one local refinery has installed control equipment in 2001; a flare gas recovery system for one of its flares that resulted in significantly reduced emissions fr om that flare.CHAPTER IV – EMISSION INVENTORY FINAL STAFF REPORT

Proposed Amended Rule 1118 IV-3 October 2005 Another reason for the drop in emissions was found to be the correct measurement of flare flows. A refinery discovered it had erroneous flare flow r eadings that led to reporting inflated emissions. An investigation of the problem conclud ed that the flow meter located before the water seal was counting both the flow towards the f lare and the reverse flow to a recovery compressor, although no actual vent gas was going p ast the water seal and combusted in the flare. The refinery relocated the flow meter in th e flare stack and eliminated the problem. Therefore, in order to get reliable emission data, it is necessary that the flow meters be located in a representative location after the water seals to ensure that a true flow to the flare is registered, or they must be equipped with totalizing capability to subtract any reverse flows to flare gas
recovery systems.

The rest of the reductions resulted primarily from voluntary changes in operations, such as extending the time for shutting down or starting up units to minimize flaring, training operators to avoid routine flaring, as well as a commitment f rom management to minimize flaring. However, none of these measures are required by the current rule and as such, are not considered enforceable and permanent.

An analysis of the flare flow, events, and emission s data submitted to the AQMD since 1999 clearly shows a downward trend, it also shows varia bility from year to year. This variability is due in large part to emergencies, the specific unit (s) that undergo turnaround(s) in that year, other startups and shutdowns, and essential operati onal needs. Since these events can vary year to year, so will the number and type of flare event s and the flare emissions. Therefore, it is appropriate to average the annual flare emissions t o develop a representative baseline emissions inventory for emissions reductions and cost analysi s calculations. Based on an analysis of the data submitted and discussions with refinery repres entatives, staff concluded that the 2000 data may not be very reliable due to compliance issues a nd because of problems related to the implementation of this recently adopted flare monit oring rule. Also, one refinery installed additional vent gas recovery in 2001; this installa tion would result in permanent emissions reductions from 2002 and beyond. Therefore, staff has determined that the most representative data for these variable flare operations and future releases are from years 2002, 2003 and 2004.

Table IV - 3 Flare Emissions Average 2002-2004

Year NO X NMHC CO PM10 SO 2 Total

Average

Emissions (TPY) 85 74 412 25 613 1,209

Average

Emissions (TPD) 0.23 0.20 1.13 0.07 1.68 3.31

Based on emissions data from Table IV – 2, Table IV – 3 shows the flare emissions average for the period 200 1 2 through 2004. The Rule 1118 average reported SO 2 emissions is 613 tons or 1.68 tons per day, while the average emissions tota l for all the criteria pollutants is 1,209 tons, or 3.31 tons per day. This inventory will be used as the baseline for calculating the emission reductions associated with the proposed amended rul e and its cost effectiveness.C H A P T E R V

EMISSION REDUCTIONSCHAPTER V – EMISSION REDUCTIONS FINAL STAFF REPORT

Proposed Amended Rule 1118 V-1 October 2005 As shown in the previous chapter, flare emissions h ave trended lower since the rule was first adopted in 1998. As monitoring of flare flows was initiated to comply with the rule, refinery operators became aware of the high amounts of vent gas routed to flares and implemented procedures to minimize emissions. Although the red uctions are substantial, staff believes that

further emission reductions are feasible for the in dustry. In September 2004, after staff presented the “Evaluation Report on Emissions from Flaring Op erations at Refineries”, the AQMD Governing Board directed staff to initiate the amen dment of Rule 1118. The performance targets

in this rule amendment will result the installation of additional controls for flaring operations, as recommended in the Evaluation Report, to prevent ba cksliding in the emissions that have been reduced over the last several years.

The proposed amended rule requires refineries to gr adually lower their annual sulfur dioxide emissions from a baseline average of approximately 1.68 tons per million barrels of crude processed to 1.5 tons per million barrels of crude processed in calendar year 2006, 1.0 ton per million barrels of crude processed in calendar year 2008, 0.7 ton per million barrels of crude processed in calendar year 2010 and 0.5 ton per mil lion barrels of crude processed in calendar year 2012. The total processing capacity of the re fineries in the basin, based on industry data, is approximately 1 mmbbl/day, therefore projected annu al sulfur dioxide emission s reductions for

2012 are 430.7 tons.

These reductions can be achieved by establishing a requirement that limits the use of flares only for emergencies, shutdowns and startups and certain essential operational needs and elimination of routine flaring. To ensure that total industry emissions will stay below the limit and prevent backsliding, the proposed amended rule has a mitiga tion fee provision in place. However, staff believes that by year 2012, flare sulfur dioxide em issions will be well below 0.5 ton per day and does not expect that any facility will have to pay mitigation fees, based on the current downtrend

in emissions and the effect of the controls in the proposed rule amendment.

As the refineries minimize the amount of vent gas s ent to flares, there will be concurrent emission reductions of other criteria pollutants. This is due to the fact that concurrent emissions are calculated as a function of the flare vent gas volume and the heating value of the flare gas. It is assumed that, since the average heating value of the vent gas is expected to stay constant, the lower vent gas volume will translate into proportio nally lower emissions of NOx, CO, ROG and

PM10.

Refineries E and H have reported significantly high er flare flows when compared to other refineries since the rule was adopted. During the interviews staff had conducted with all refineries subject to PAR 1118, Refinery H has info rmed staff that it has completed a flare gas optimization project in 2004 and that an additional flare gas recovery system will also be installed by 2008; moreover, Refinery E has also co mmitted to the AQMD to increase its vapor recovery and gas treating capacity and to install f lare gas recovery systems to significantly

reduce flare emissions.

Staff has calculated the average total flare flow a nd a breakdown of the reasons for venting for

200 1 2 through 2003, which can be found in Table V – 1. This information was based on data from the September 2004 “Evaluation Report on Flare s at Petroleum Refineries.” For the same reason as explained before, the data for year 2000 and 2001 was were not included in the calculation of the average flow since it the 2000 flow data was determined to be unreliable and a flare gas recovery system was installed at one refi nery in 2001, which significantly reduced

emissions from one of its’ flares.CHAPTER V – EMISSION REDUCTIONS FINAL STAFF REPORT

Proposed Amended Rule 1118 V-2 October 2005 Table V – 1 Average Flare Flows and Reasons for Flaring 2002-20 03

Reasons for Flaring Flow (mscf/year) % of

Total
Emergency Recordable 276,544.5 11.755

Non-Recordable 1,126,875 48.15

Unknown 113474.5 4.775

Maintenance 130,738 5.615
Planned Startup/Shutdown 289,115 12.425

Process Vent 50,985.5 2.155

Turnaround Activities 240,031 10.37Non- EmergencyRecordable Events

Fuel Gas Imbalance 109,730.5 4.76

Total Average Flow 2,337,493 100.00

As stated in Table V – 1, emergencies, maintenance, start-ups and shutdowns, turnaround activities, process vent and fuel gas imbalances re present approximately 5 3 47 percent of the total flow. The remaining 4 5 3 percent represents the volume of non-recordable a nd unknown nonemergency events that has a potential to be recover ed/minimized.

Based on an analysis of the reported flare data and discussions with two “larger” of the three

facilities that have been identified in the staff r eport as needing additional gas recovery and treatment system capacity to comply with PAR 1118, staff has determined that Refineries E, F and H will install flare vent gas recovery and trea tment systems with a maximum capacity of 13.3 million standard cubic feet per day (mmscfd). The average capacity of 9 mmscfd is equivalent to 3,285,000 mscf per year (see Chapter VI – Cost and Cost Effectiveness for additional discussion and analysis of these vent ga s recovery and treatment systems). This average recovery and treatment capacity represents more than 100 percent of the average annual flare flow, as found in Table V-1. Staff anticipat es other refineries will initiate additional measure to minimize vent gases being sent to the fl ares. Therefore, with the increase in vent gas recovery and treatment capacity and additional volu ntary flare minimization measures to be implemented, staff has determined that the baseline (three year average) emissions of criteria air

contaminants other that sulfur dioxide will be redu ced by 75 percent or more. Sulfur dioxide

emissions will be reduced from the baseline of 1.68 tons per year to 0.5 ton per year by year

2012.

From the baseline emissions inventory representing the 200 1 2 -2004 annual emissions averages and using the emissions reduction analysis above, t he projected 201 0 2 flare emissions are as shown in Table V – 2. Although actual sulfur dioxi de emission reductions are anticipated to be significantly higher than what it is assumed in thi s table, for the purpose of this analysis,

emission reduction estimates were based on the 201 0 2 annual sulfur dioxide performance target

of 0. 7 5 ton per million barrels of crude processed for PAR 1118.CHAPTER V – EMISSION REDUCTIONS FINAL STAFF REPORT

Proposed Amended Rule 1118 V-3 October 2005 Table V-2

Summary of AQMD Emission Reductions (Tons per Year)

Year
Pollutant
Baseline 2012 Emissions

Reductions

SO 2 613 183 430

NOx 85 38 47

PM10 25 10 15

VOC 74 41 33

CO 412 198 214

Total 1,209 470 739

.C H A P T E R VI

COST AND COST-EFFECTIVENESSCHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-1 October 2005 A. COSTS

The proposed amendment seeks to implement the most feasible and cost-effective control options in order to reduce flare emissions. This c hapter presents an overview of the costs refineries will have to incur in order to comply wi th the new requirements and the costeffectiveness of implementing these requirements.

Since the proposed rule will only allow venting of vent gases during an emergency, shutdown, startup, turnaround or essential operational need a nd to minimize flaring, it is assumed that some refineries will need to install new flare gas recov ery and gas treating systems, whereas other refineries may have to increase their existing flar e gas recovery and treating capacity in order to comply with this proposed rule requirement. These are technologically feasible pre-combustion controls that were suggested in the conclusion of t he “Evaluation Report on Emissions from Flaring Operations at Refineries" presented to the AQMD Board on September 3, 2004.

As shown in Table IV-1, of the seven oil refineries subject to the rule, three do not have any flare gas recovery for their flares. Staff expects these three refineries to install flare gas recovery systems and additional gas treating capacity. Base d on the last four years, the other four refineries have adequate flare gas recovery capacit y and are not expected to incur significant control equipment costs to comply with the proposed amended rule.

In order to meet the monitoring requirements, the r efineries where the flow meters are located before the water seals at flares equipped with flar e gas recovery compressors will need to upgrade the flow meters with totalizing and low flo w measurement capability to accurately indicate the actual vent gas flow to the flare. Al so, flow meters will need to be installed on all flares for the measurement of the purge and pilot g as flow. All refineries will have to equip their emergency and general purpose flares with heat cont ent analyzers and total sulfur analyzers.

Until the analyzers are certified by the Executive Officer, refinery operators will be required to conduct sampling for both higher heating value and total sulfur daily. If the total sulfur analyzer pilot program to be conducted in 2006 demonstrates that the current sulfur monitoring technology is not feasible, an additional cost for automated sampling systems and the processing of samples for total sulfur content must be include d in the costs to implement PAR 1118.

Staff will calculate the costs associated with the proposed amendment; two scenarios will be

considered. Costs common to both scenarios include additional vent gas recovery and treatment systems (capacity), upgrade flare gas flow meters, install purge/pilot gas flow meters, and annual costs associated with the newly installed equipment (parts and maintenance), surveys of pressure relief devices, conducting flow meter tests and Spe cific Cause Analyses. In Scenario 1, it will be

assumed that all of refineries will install heat co ntent and total sulfur analyzers. In Scenario 2, i t will be assumed that only heat content analyzers ar e installed along with automated sampling systems and that the concentration of total sulfur, expressed as sulfur dioxide, of the vent gas will be determined by laboratory analysis.

Scenario 1

Capital Costs

Under the first scenario, it will be assumed that:

- The three refineries that currently do not have fla re gas recovery systems (for eight flares) will install a total of four flare gas recovery and gas treating systems. Staff assumes thatCHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-2 October 2005 at the first refinery, two systems will be installe d; one system will control three flares and the other two flares. Another system serving a pai r of flares will be installed at the second refinery. The third refinery will install one control system for its one flare.

- Refineries will install 23 heat content analyzers f or the emergency/general service flares;

- Refineries will install 23 total sulfur analyzers f or the emergency/general service flares;

- Refineries will install 50 purge/pilot gas flow met ers (one for each emergency/general service flare); and

- Refineries will upgrade the emergency/general servi ce flare flow meters with totalizing and low flow capability.

A synopsis of the projected rule required changes f or emergency and general service flares is

shown in Table VI-1.

Table VI – 1 Scenario 1 Rule Required Modifications

Flare ID Flare Gas

Recovery Gas

Treatment Higher Heating

Value Analyzer Total Sulfur

Analyzer Flow Meter

Upgrade Purge/Pilot

Flow Meter

1 1 1 1 2

2 1 1 1 2

3 1 1 1 2

4 0.5* 0.5* 1 1 1 2

6 1 1 1 2

7 0.5* 0.5* 1 1 1 2

8 1 1 1 4***

9 0.5* 0.5* 1 1 1 2

10 1 1 1 2

11 1 1 1 1 1 2

13 1 1 1 2

15 1 1 1 4***

16 0.5* 0.5* 1 1 1 2

17 1 1 1 2

18 1 1 1 2

19 0.33** 0.33** 1 1 1 2

20 0.33** 0.33** 1 1 1 2

21 1 1 1 2

22 1 1 1 2

23 1 1 1 2

24 1 1 1 2

25 0.33** 0.33** 1 1 1 2

26 1 1 1 2

Total 4 4 23 23 23 50 * Common flare gas recover and treatment system ser ving two flares ** Common flare gas recover and treatment system se rving three flares *** System consisting of two flares in cascade (com mon flow meter)

The cost for a flare recovery and gas treating syst em will be estimated based on data submitted to the AQMD by two local refineries as part of an appl ication for permits to construct and operate, and data obtained from the Montana Department of En vironmental Quality (DEQ) for a petroleum refinery located in Billings, Montana.CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-3 October 2005 One local refinery installed a 10 million standard cubic feet per day (mmscfd) flare gas recovery system in 1993 for $10 million and a 48 mmscfd gas treating system for $23.2 million. The other local refinery installed in 2001 a flare gas recovery system with a capacity of 6 mmscfd for $9.2 million. The Billings, Montana refinery instal led a flare gas recovery and gas treating system with a design capacity of 4 mmscfd for $7.7 million in 2003. Staff will determine the average normalized cost of the three examples studi ed to calculate the cost of flare gas recovery and gas treating systems needed to comply with the requirements and annual emission targets of

PAR 1118.

Based on the first case study, installed in 1993, t he cost for a flare recovery system and gas treating unit, normalized per one mmscfd, was $1.48 million ($1 million and $0.483 million respectively). In 2005 dollars, based on the Nelso n Farrar Index published in the Oil and Gas Journal, the cost would be $1.43 million and $0.734 million respectively, for a total of $2.16 million per mmscfd

.

Based on the second case study, installed in 2003, the normalized cost of the flare gas recovery system and corresponding gas treating system per on e mmscfd was $1.93 million, of which $1.52 million was for flare gas recovery and $0.41 million was for the gas treating system. In 2005 dollars, based on the Nelson-Farrar Index, the cost would be $1.6 million and $0.48 million, respectively, or $2.08 million per mmscfd

.

Based on the third case study, installed in 2001, t he normalized cost for a flare gas recovery compressor per one mmscfd was $1.53 million. In 20 05, this cost, based on the Nelson Farrar Index, would be $1.645 million. No gas treating s ystem was installed in conjunction with this flare gas recovery system. However, based on the t wo other case studies, the cost of a flare gas recovery system is approximately 72 percent of the cost of a system consisting of both flare gas recovery and gas treating which is calculated as $0 .635 million. Therefore, the total cost of a complete system would be $2.28 million per mmscfd

.

Based on the above case studies, the average cost t o install a flare gas recovery and treating system, based on three different system capacities of 4 mmscfd, 6, mmscfd and 10 mmscfd, is $2.17 million per mmscfd (2005 dollars).

Staff reviewed the Rule 1118 quarterly reports for the year 2003 and selected the quarters with the highest flows for the eight flares without flar e gas recovery systems, then calculated the daily average flows for those quarters. API 521 guidelin es recommends that the capacity of a flare gas recovery system be able to handle a wide variation in flow rates, and an Oil and Gas Journal article published on December 7, 1992, recommends t he recovery capacity to be 2-3 times the average flow rate.

Based on this information, staff has estimated that for the first refinery, one system with a maximum capacity of 6 mmscfd, serving three flares, and a second system serving two flares with a maximum capacity of 4 mmscfd would be adequa te. For the second refinery, staff projected that a system with a capacity of 3 mmscfd serving two flares would be adequate. For the third refinery staff estimated that a system wi th a capacity of 0.3 mmscfd for its flare would be adequate.

The costs to install the flare gas recovery and tre ating systems are estimated by using the average $2.17 million per mmscfd factor times the projected capacities needed by the refineries with no control on their emergency/general service flares t o comply with PAR 1118. The costs are

summarized in Table VI – 2:CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-4 October 2005 Table VI – 2 Total Installed Cost for Flare Gas Recovery and Gas Treatment

Flare ID Maximum

Capacity(mmscfd) Total Installed Cost ($)

19, 20 and 25 6 13,020,000
9 and 16 4 8,680,000
4 and 7 3 6,510,000
11 0.3 651,000 Total 13.3 $28,861,000

The breakdown by flares of the projected installati ons, with the highest average daily flows and maximum capacities is shown in Table VI-3

Table VI – 3 2003 Highest Quarterly Flows and Daily Average Flow s

Projected

Treatment Capacity (mmscf) Flare ID Highest 2003 Quarterly

Flow (mmscf) Daily Average

Flow (mmscfd)

Min. Max.

25 87.03 0.97

20 59.6 0.66

19 Common System

55.98 0.62 2.25 6

16 32.27 0.36

9 Common System 101.61 1.13 1.49 4

4 49.43 0.55

7 Common System 48.53 0.54 1.09 3

11 9.01 0.1 0.1 0.3

Total 4.93 4.93 13.3

The cost of installing flow meters for purge gas an d pilot gas is estimated by assuming that these devices would be connected to computerized control systems and therefore, will need data transmitters. An orifice plate flow meter and tran smitter combination was quoted at $2,280 by a parts supplier, and labor is estimated at 10 hours at a rate of $35 per hour each. The total installed cost, assuming an additional 10 percent f or software, instrumentation, and taxes is therefore estimated at $2,858 per flow meter and fo r 50 flow meters the total cost will be $142,900.CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-5 October 2005 The proposed rule requires the flare gas flow meter s to be upgraded with totalizing and low flow capability. This upgrade was quoted at $10,000 per flow meter by GE Panametrics, therefore the total cost for 23 flow meters will be $230,000.

The cost of the heat content analyzers was quoted a t $70,775 each by Cosa Instruments. Assuming that the total installed cost, including a sample conditioning unit, shelter, piping, electrical, taxes, permitting and certification wil l be $150,000, the total installed cost for 23 analyzers is estimated at $3,450,000.

The cost of a total sulfur analyzer, including taxe s, shipping, startup/commissioning was quoted by ThermoElectron at $79,308. The additional cost of installation for the total sulfur analyzer to the heat content analyzer and sample conditioning s ystem is estimated at $5,000. Therefore the total installed cost is estimated at $84,308 each a nd $1,939,084 for 23 analyzers.

In order to calculate the cost effectiveness of the rule, the capital costs of the proposed

amendment will need to be determined. It will be a ssumed that the flare gas recovery systems, gas treating systems and flow meters have an equipm ent life of 25 years, whereas the heat content analyzers and total sulfur analyzers have a 10 year equipment life. In order to have a common basis for equipment life to calculate the co st effectiveness, the cost of the analyzers will be referenced to a 25 year equipment life. For thi s purpose, it is assumed that during a 25 year period three sets of analyzers will have to be purc hased. The cost of this expenditure is

calculated below:

C analyzers = C1 + C2 + C3

1 st Set Cost is at current cost:

C1 = $3,450,000 + $1,939,084 = $5,389,084

The 2nd set is to be purchased after 10 years. Its cost in today’s dollars is calculated assuming a 4% real interest rate at ten years using the corres ponding present worth factor of 0.6756 will be:

C2 = $5,389,084 * 0.66756 = $3,640,865

The 3rd set of analyzers is to be purchased after 2 0 years. The cost in today’s dollars, at 4% real interest rate at twenty years using the correspondi ng a present value factor of 0.4564 will be:

C3 = $5,389,084 * 0.4564 = $2,459,578

The total cost of the analyzers will therefore be, over a 25 year period:

C analyzers = C1 + C2 + C3 = $11,489,527

The flare gas recovery and gas treatment systems wi ll require a permit to construct and operate from the AQMD. The permit application evaluation f ee for one system is $7,233. As previously
stated, the staff has determined that four control systems will need to be installed and operated to meet the annual sulfur dioxide performance targets in PAR 1118. Therefore, the permit application fees/cost to the refineries is $28,932.CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-6 October 2005 A one-time CEMS certification fee is also required. The certification fee includes the initial application approval, approval of the test protocol and approval of the performance test results. The maximum fee is $7,693 for a monitoring system c onsisting of up to four components. The system required to comply with PAR 1118 consists of three (flow, higher heating value and total sulfur). The industry will install 23 higher heati ng value and total sulfur analyzer systems to comply with the monitoring requirements in PAR 1118 . Therefore, the cost to certify the analyzer systems will be $176,939.

Under Scenario 1, the total estimated capital costs associated with the rule, based on the assumptions stated above, are summarized in Table V I-4.

Table VI – 4 Total Capital Costs Scenario 1

Equipment Cost ($)

Flare Gas Recovery/Treatment Systems 28,861,000

Higher Heating Value/Total Sulfur Analyzers (Initial + 2 replacements) 11,489,527

Pilot/Purge Gas Meters 142,900
Flow Meter Upgrades 230,000
Permit Processing Fees 28,932
Analyzer (CEMS) Certification Fees 176,939

Total Capital Cost $40,929,298

Annual Costs

The refineries will also incur annual costs associa ted with the newly installed equipment (parts and maintenance), surveys of pressure relief device s, conducting flow meter tests and Specific Cause Analyses.

Assuming that annual cost, such as for parts, maint enance, repairs, calibration gases, taxes, insurance and power represent 10 percent of the cap ital cost (including only the initial purchase of analyzers), the annual cost is estimated as $3,4 82,886.

Another annual cost will be for conducting surveys of the pressure relief devices connected to flares. These surveys can be conducted concurrentl y with the Rule 1173 quarterly inspections and it is estimated that on average an additional 2 00 hours per refinery and 100 hours for the hydrogen plant will be spent per year for this task . At $25 per hour, for seven refineries and a hydrogen plant, the annual cost will be $37,500.

Another annual cost will be for verifying the accur acy of flow meters. Flow verification costs were quoted at $1,500 per day for up to two flares. The annual cost for flow verification is estimated as $25,000 as shown below:CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-7 October 2005 Table VI – 5

Annual Cost for Flow Meter Verification

Facility No. of Flares Estimated Annual Cost ($)

A 4 3,000

B 1 1,500

C 3 3,000

D 3 3,000

E 5 4,500

F 1 1,500

G 6 4,500

H 5 4,500

Total 27 $25,500

The proposed rule will require refineries to conduc t Specific Cause Analyses (SCA) for flaring events exceeding 500 pounds of sulfur dioxide, 100 pounds of VOC or 500,000 scf of vent gas. The investigation of flaring events exceeding 500 p ounds of sulfur dioxide would not represent an additional cost since this is a requirement unde r federal law.

A review of the 2003 flaring events meeting these c riteria stated in the previous paragraph found 980 flare events that had less than 500 pounds of s ulfur dioxide emissions. However, these flaring events, representing 80 percent of the vent gas flow, included shutdowns and startups, turnaround activities or fuel gas balancing. The f acilities subject to PAR 1118 are not required to submit an SCA for these categories of vent gas r elease under the proposed rule. Therefore, assuming that a corresponding 80 percent of these 9 80 events would not be required to submit an SCA, approximately 200 additional events would need to be investigated. The local refineries have estimated that the time needed to complete an SCA ranges from 40 to 200 hours. Based on this information, staff has estimated that a refine ry would spend an average of 80 hours conducting SCA investigations, at an average rate o f $50 per hour. The total annual cost of conducting an additional 200 SCA investigations tha t may be required as part of the proposed amended rule is therefore estimated at $800,000. T he total annual costs associated under Scenario 1, as calculated above, are summarized in Table VI - 6:

Table VI -6

Total Annual Costs Scenario 1

Item Annual Cost ($)

Maintenance/Parts for Controls Equipment, Flow Met ers, and Higher Heating Value and Total Sulfur Analyzer s lyzers/TS Analyzers 3,482,886

Leak Surveys 37,500

Flow Meter Verification 25,500

Specific Cause Analyses 800,000

Control Equipment Annual Operating Fee 2,951

Total $4,348,836CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-8 October 2005 Scenario 2

For scenario 2, the estimated capital costs will be identical to Scenario 1, except that it will not include the installation and operation of total sul fur analyzers but will include the addition of 23 automated sampling devices. A summary of the propo sed rule requirements is shown in Table

VI -7:

Table VI – 7 Scenario 2 Rule Required Modifications

Flare ID Flare Gas

Recovery Gas

Treating HHV

Analyzer Automated

Sampler Flow

Meter Upgrade Purge/Pilot

Flow Meter

1 1 1 1 2

2 1 1 1 2

3 1 1 1 2

4 0.5* 0.5* 1 1 1 2

6 1 1 1 2

7 0.5* 0.5* 1 1 1 2

8 1 1 1 4**

9 0.5* 0.5* 1 1 1 2

10 1 1 1 2

11 1 1 1 1 1 2

13 1 1 1 2

15 1 1 1 4**

16 0.5* 0.5* 1 1 1 2

17 1 1 1 2

18 1 1 1 2

19 1 1 1 2

20 0.5* 0.5* 1 1 1 2

21 1 1 1 2

22 1 1 1 2

23 1 1 1 2

24 1 1 1 2

25 0.5* 0.5* 1 1 1 2

26 1 1 1 2

Total 4 4 23 23 23 50

* Common system serving two flares
** System consisting of two flares in cascade (common flow meter)

The total installed cost of the automated sampling system is estimated at $5,000, and for 23 flares the cost will be $115,000.

As in Scenario 1, the cost of the 23 heat content a nalyzers will have to be referenced to a 25 year equipment life cycle; therefore it is assumed that 3 sets of analyzers have to be purchased during this period of time.

The cost for the initial set will be:

C1 = $150,000 * 23 = $3,450,000CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-9 October 2005 After 10 years, in today’s dollars, the cost of the second set in today’s dollars will be:

C2 = $3,450,000 * 0.6756 = $2,330,820

After 20 years the cost of the third set of analyze rs in today’s dollars will be:

C3 = $3,450,000 * 0.4564 = $1,574,580

The total cost of the analyzers, assuming a 25 year s life, will be:

C analyzers = C1 + C2 + C3 = $7,355,400

The capital costs under Scenario 2 are summarized i n Table VI-8:

Table VI – 8

Total Capital Costs Scenario 2

Equipment Cost ($)

FGRS/Amine Scrubbers 28,861,000

Heat Content Analyzers 7,355,400

Pilot/Purge Gas Meter 142,900

Flow Meter Upgrade 230,000

Automated Sampling System 115,000

Permit Processing Fees 28,932

Analyzer (CEMS) Certification Fees 176,939

Total Capital Cost $36,910,171

Under Scenario 2, all refineries will be required t o take six additional daily samples for total sulfur per flare during the week, incurring additio nal annual costs. Assuming that the cost of processing a sample will average $350, the annual c ost of sampling will be:

Annual Sampling Cost = 23 flares * 6 samples /w k * 52 wks * $350/sample

= $2,511,600

The cost of maintenance, parts, power, insurance an d taxes for equipment is assumed to be 10 percent of the total capital cost (including only t he initial purchase of analyzers). Therefore, the total annual cost for the equipment and analyzers w ill be $3,300,477.

A summary of the annual costs under Scenario 2 is p resented in Table VI – 9.CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-10 October 2005 Table VI – 9

Total Annual Costs Scenario 2

Item Annual Cost ($)

Maintenance/Parts for Equipment 3,300,477

Leak Surveys 37,500

Flow Meter Verification 25,500

Specific Cause Analysis 800,000

Daily Sampling 2,511,600

Control Equipment Annual Operating Fee 2,951

Total $6,678,028

Recovered Vent Gas - Cost Savings

The flare gas recovery systems will recover vent ga ses that otherwise would be combusted in the flares. The recovered gas, after treatment, can be used as fuel gas or process feed, thus reducing operating costs for the refineries. Additional sav ings are realized by using less steam for the flare operations and extended flare tip life, minim izing repair costs; for this calculation, only the payback value of the recovered gas to be used as fu el gas or process feed is considered. This would represent annual savings that can lower the a nnual costs.

The following assumptions will be made:

• The annual average recovered gas volume is 3,285 2,337 mmscf (see Chapter V – Emission Reductions)

• On average, only 60 percent of the recovered gas vo lume is valuable product (based on review of recovered gas samples from a local refine ry)

• The value of recovered gas is estimated at $2 per m mBtu (www.johnzink.com – Flare Gas Recovery payback analysis)

• The average heat content of the recovered gas is 1, 000 Btu/scf

Annual Savings = 3,258 2,337 * 10 6 scf * 0.6 * 1,000 Btu/scf * $2/10 6 Btu = $ 3,909,600 2,804,400

As emissions will decrease, the refineries will pay reduced annual emission fees to the AQMD, reducing their annual costs. Table VI – 10 lists t he estimated annual emission fees savings by pollutant and the total savings for the industry.CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-11 October 2005 Table VI – 10 Estimated Annual Emission Fees Savings

Pollutant Fees*

($/ton) Projected

Reduction (tons) Estimated

Savings ($)

ROG 944.16 33 31,157

NOx 543.73 47 25,555

CO 4.64 214 993

PM10 720.72 15 10,811

SO 2 653.98 356 232,817

Total $290,439

*Rule 301 – Table III-Emission Fees (June 3, 2005)

The total annual costs will then be:

For Scenario 1:

Total Annual Cost = $4,285,398 – $ 3,909,600 2,804,400 – $290,439 = $ 85,359 1,190,559

For Scenario 2:

Total Annual Cost = $6,6 14,59 78,028 – $ 3,909,600 2,804,400 – $290,439 = $ 2 ,414,551 3,583,189

B. COST-EFFECTIVENESS

In order to calculate the cost effectiveness of the proposed amendment, the present value of the capital cost and operating cost during the useful l ife of the control equipment and/or program must be calculated, using the following formula:

PV = C + A * PVF

where:

PV = Present Value to implement the proposed new rule requirements

C = Capital costs to implement proposed new rule requirements

A = Annual costs to implement proposed new rule requirements

PVF = Present Value Factor, Equal SeriesCHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-12 October 2005 = 15.62 (25 years equipment life and 4% real int erest rate).

Cost Effectiveness – SOx Emission Reductions Only

Scenario 1:

C = $40,929,298

A = $ 85,359 1,190,559

PV1 = $40,929,298 + $ 8 5

, 3 59 1,190,559 * 15.62 = $ 42,262,606 59,525,830

The cost effectiveness is calculated with the disco unt cash flow (DCF) method:

CE1 = PV1 / (ER * EL)

where:

CE1 = Cost Effectiveness for Scenario 1

ER = Emission Reduction for SO 2 , 431 tons per year

EL = Equipment life, 25 years

CE1 = $ 4 2

, 2 6 2 ,60 6 59,525,830 / (431 tons * 25) = $ 3, 9 22 5,524 per ton of SO 2 reduced

Scenario 2

C = $36,910,171

A = $ 2,414,551 3,583,189

PV2 = $36,910,171 + $ 2,414,551 3,583,189 * 15.62 = $ 74,625,458 92,879,583

CE2 = $ 74,625,458 92,879,583 / (431 tons * 25) = $ 6,926 8,620 per ton SO 2 reduced

Therefore, the cost effectiveness for this proposed amendment is estimated to be between $ 3,922 5,524 and $ 6,926 8,620 per ton of SOx reduced.

Cost Effectiveness – Total Emissions Reductions (Ex cluding CO)

If reductions in the other pollutants were to be co nsidered, the cost effectiveness would be:

CE = PV / (TER * EL)CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-13 October 2005 where:

PV = Present Value to implement the proposed new rule requirements

TER = Total emission reduction for the other crit eria pollutants less CO, tons per year

EL = Equipment life, 25 years

From Table V – 2:

TER = 431 tons + 47 tons + 33 tons + 15 tons = 526 tons

Scenario 1

CE1 = $ 40,929,298 59,525,830 / (526 * 25) = $ 3, 112 4,527 per ton of pollutant reduced

Scenario 2

CE2 = $ 74,625,45 92,879,583 8 / (526 * 25) = $ 5,675 7,063 per ton of pollutant reduced

Therefore, if reductions for the other criteria pol lutants, less CO, are included in calculations, the cost effectiveness of the proposed amendments range s between $ 3, 112 4,527 and $ 5 ,6 75 7,063 per ton of pollutant reduced, excluding CO.

C. INCREMENTAL COST-EFFECTIVENESS

Staff is required under state law to determine an i ncremental cost effectiveness of the most stringent control scenario. Staff believes that th e most stringent control scenario would require petroleum refineries to control all vent gases excl uding off specification gas and vent gases resulting from emergencies.

An analysis of the reported flare gas flow and emis sions data for years 2002, 2003, and 2004 and vent gas recovery and treatment capacity associated with flares is summarized as follows:

Flare gas recovery and treatment system capacity

Current: 51 mmscfd

Future implementing PAR1118 requirements: 64.5 m mscfd

Additional capacity to treat maximum daily flow re corded: 119 mmscfd

(excluding off spec gas and emergencies)

PAR 1118 - 2012 Emissions

SO 2 performance target: 0.50 TPD

Total emissions, less SO 2 and CO: 0.24 TPD

Reported non-emergency, SO 2 : 94% (based on 2002 and 2003 data)CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAF F REPORT

Proposed Amended Rule 1118 VI-14 October 2005 Reported non-emergency, other 68% (based on 2002 a nd 2003 data)

Capital cost of the additional flare gas recovery a nd treatment system capacity

Estimate cost of system based on a previously deter mined cost of $2.17 million per million standard cubic feet per day treatment capac ity (mmscfd)

$2.17 million/mmscfd * 119 mmscfd = $258,227,36 2

Annual cost is estimated to be 10 percent of the ca pital cost

$258,227,362 *0.10 = $25,822,362

SO 2 Emission Reductions Only

PV = $258,227,362 + $25,822,362 * 15.62 = $661 ,578,503

CE = PV / (Incremental ER * EL)

CE = $661,578,503 / [0.5 tons/day * 0.93 * 25 y rs * 365 days/yr]

= $155,918 per ton of SO 2 reduced

Total Emissions Reductions, Less CO

PV = $258,227,362 + $25,822,362 * 15.62 = $661,578,503

CE = $661,578,503 / {[0.5 ton/day * 0.93 + 0.24 ton /day * 0.68] * 25 yrs * 365 days}

= $115,412 per ton of air contaminant reduced

Therefore, the incremental cost effectiveness for t his proposed amendment is estimated to be between $115,412 and $155,918 per ton of air contam inant reduced.C H A P T E R VII

COMPARATIVE ANALYSISCOMPARATIVE ANALYSIS FINAL STAFF REPORTPAR 1118U.S. EPA 40CFR 60.18 and Subpart JProposed Amended Rule 1118 VII-1October 2005−Applicability−Flares at refineries, sulfur recovery plants and hydrogenproduction plants−Flares built or modified after June 11, 1973, subject to 40CFR 60Subpart J−Flares controlling vents from piping components subject to40CFR 60 Subpart GGG, from storage tanks subject to40CFR 60Subpart Kb, or from wastewater systems subject to 40CFR 60Subpart QQQ−Requirements−Flares to be operated with no visible emissions−Flares to be operated with a pilot flame present atall times−Annual acoustical or thermal surveys of PRD’s directly connectedto flares−Specific Cause Analysis of flare events exceeding:o500 lbs SO2o100 lbs VOCo500,000 scf vent gas combusted−Cause of flare events where at least 5,000 scf of vent gas arecombusted−Effective September 1, 2006, submit the following information:oTechnical specifications on flare systems includinganaudit of gas recovery and treating system capacityandstorage capacity for excess vent gasesoA description of equipment installed and proceduresimplemented within the last 5 years to minimize flaringoA description of equipment to be installed or proceduresto be implemented to minimize or eliminate flaring−Effective January 1, 2007, operate flares in such amanner as tominimize flaring and only combust vent gas during emergencies,shutdowns, startups, turnarounds or essential operational needs−Flares to be operated with no visible emissions−Flares to be operated with a pilot flame present atall times−Air or steam assisted flares shall only combust gases with a heatcontent of 300 BTU/scf or more−The exit velocity of the vent gas is limited by thenet heatingvalue of the vent gas−Flares shall not be used to combust gases containing more than0.1 gr/dscf (160 ppm) H2S, averaged over 3 hoursCOMPARATIVE ANALYSIS FINAL STAFF REPORTPAR 1118U.S. EPA 40CFR 60.18 and Subpart JProposed Amended Rule 1118 VII-2October 2005Effective January 1, 2009, combustion in flares of gases withhydrogen sulfide concentration exceeding 160 ppm, averaged over 3hours, is prohibited, unless in an emergency, shutdown, startup orPRD leakage−Performance Targets−Specific annual performance targets for subject facilities based ontheir crudethroughputprocessing capacity−Mitigation fees assessed for exceedance of performance targets−N/A−Flare Minimization Plans−Triggered by exceedance of performance target, or−To include policies and procedures and process and equipmentupgrades implemented to prevent future exceedances−Subject to public review and comment−N/A−Monitoring and Recording−Until July 1, 2007, continuous monitoring of vent gas flow,sample daily and during sampling events for vent gas higher heatcontent and total sulfur as SO2or install continuous or semicontinuous analyzers−After July 1, 2007, continuous monitoring of ventgas flow,higher heat content and semi-continuously for totalsulfur as SO2−The presence of pilot flames monitored with thermocouples orequivalent devices−Effective July 1, 2006, video monitors with date andtime stampmust be used to determine visible emissions−Effective January 1, 2007:oautomated sampling system required for vent gassampling−The presence of pilot flames monitored with thermocouples orequivalent devicesCOMPARATIVE ANALYSIS FINAL STAFF REPORTPAR 1118U.S. EPA 40CFR 60.18 and Subpart JProposed Amended Rule 1118 VII-3October 2005oPilot and purge gas flow must be monitored−Recordkeeping−Video monitoring records to be kept for 90 days−Other records to be kept for five years−Records to be kept at least two years−Records to be kept at least five years for Title V facilities−Notification and Reporting−24 hour telephone service provided for public inquiries on flareevents−1 hour notification of events exceeding:o500 lbs SO2o100 lbs VOCo500,000 scf vent gas combusted−24 hour notification of planned events exceeding:o500 lbs SO2o100 lbs VOCo500,000 scf vent gas combusted−Submittal of Specific Cause Analysis of qualifyingflare eventswithin 30 days or 60 days upon request−Quarterly reports in electronic format certified for accuracy byresponsible facility official, to include:oDaily and quarterly flare emissionsoCauses of flare eventsoRecords of annual PRDoMonitoring system down times−Copies of notifications required by 40CFR 355 pertaining toreportable air releases−Semiannual reports−Notifications required by 40CFR Subchapter 355 EmergencyPlanning and Community Right to Know Act (EPCRA)pertaining to reportable air releases−Testing and Monitoring−Visible Emissions determined with U.S. EPA Method 22,Appendix A, 40CFR 60−Visible Emissions determined with U.S. EPA Method 22,Appendix A, 40CFR 60COMPARATIVE ANALYSIS FINAL STAFF REPORTPAR 1118U.S. EPA 40CFR 60.18 and Subpart JProposed Amended Rule 1118 VII-4October 2005−Vent Gas higher heating value determined:oBy ASTM Method D2382-88, ASTM Method D3588-91 or ASTM Method D4891-89oEffective July 1, 2007 with continuous analyzer−Vent Gas total sulfur expressed as SO2determined:oBy ASTM Method D5504-01 or District Method 307-91oEffective July 1, 2007, with a semi-continuousanalyzer−Flow monitored with a continuous flow measuring devicerequiring annual accuracy verification−Net heating value of the vent gas determined with ASTM MethodD2382-88 or D 4809-95−−Exemptions−Sampling not required if:oThere is a catastrophic event, oroSafety of sampling personnel is at issue−Emissions from flaring events due to force majeure orcircumstances beyond the operators’ control do notcount towardsannual performance targets−Emergency or upset vent gas and relief valve leakagedue tomalfunctions may exceed a H2S concentration exceeding 160ppmFacilities subject to PAR 1118 are also subject tothe following AQMD rules:Rule 401 – Visible EmissionsRule 402 – NuisanceRule 431.1 – Sulfur Content of Gaseous FuelsC H A P T E R VIII

DRAFT FINDINGSCHAPTER VIII – DRAFT FINDINGS FINAL STAFF REPORT

Proposed Amended Rule 1118 VIII-1 October 2005 DRAFT FINDINGS UNDER CALIFORNIA HEALTH AND SAFETY C ODE

Health and Safety Code Section 40727 requires that prior to adopting, amending or repealing a rule or regulation, the AQMD Governing Board shall make findings of necessity, authority, clarity, consistency, non-duplication, and referenc e based on relevant information presented at the hearing. The draft findings are as follows:

Necessity - The AQMD Governing Board has determined that a n eed exists to amend Rule 1118 – Emissions from Refinery Flares

, to make current emission reductions permanent and enforceable, and to achieve emission reductions to meet the federal and state ambient air quality standard for PM 10 and PM 2.5 and to clarify rule l anguage.

Authority - The AQMD Governing Board obtains its authority t o adopt, amend, or repeal rules and regulations from Health and Safety Code Section s 39002, 40000, 40001, 40440, 40702, and

41508.

Clarity - The AQMD Governing Board has determined that the proposed amendments to Rule 1118 - Emissions from Refinery Flares

, are written and displayed so that the meaning can be easily understood by persons directly affected by t hem.

Consistency - The AQMD Governing Board has determined that Pro posed Amended Rule 1118 - Emissions from Refinery Flares

, is in harmony with, and not in conflict with or co ntradictory to, existing statutes, court decisions, federal or state regulations.

Non-Duplication - The AQMD Governing Board has determined that the proposed amendments to Rule 1118 - Emissions from Refinery Flares

, do not impose the same requirement as any existing state or federal regulation, and the propo sed amendments are necessary and proper to execute the powers and duties granted to, and impos ed upon, the AQMD.

Reference - In adopting these amendments, the AQMD Governing Board references the following statutes which the AQMD hereby implements , interprets or makes specific: Health and Safety Code Sections 40001 (rules to achieve ambien t air quality standards), 40440(a) (rules to carry out the Air Quality Management Plan), and 404 40(c) (cost-effectiveness), 40725 through

40728.C H A P T E R IX

COMMENTS AND RESPONSESCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-2 October 2005 

### ARB

Comment 1: Although the phrase “Flare Management ( Minimization ) Plan” is a central

concept of the PAR 1118, the phrase is not included in the list of

definitions. Staff recommends its inclusion.

Response 1: PAR 1118 has been revised using the phrase “Flare Minimization Plan”

(FMP). The latest proposal put greater emphasis on the minimizing flare events and emissions through the annual performance targets, which are significantly lower than previously presented at th e June 29, 2005 Public Workshop. The latest proposal only requires an FMP from those refineries that exceed the annual performance targe ts. The required elements to be submitted as part of the FMP are lis ted under paragraph (e)(1), which effectively defines what an FMP is.

Comment 2: Staff recommends that the definition of “Essential Operational Needs” be

clarified so as to be limited to only those events clearly identified in an approved “Flare Management ( Minimization ) Plan”.

Response 2: PAR 1118 has been revised to include a definition of Essential

Operational Needs.

Comment 3: PAR 1118 ought to explicitly require that any pres sure relief devices

found to be defective or leaking be expeditiously r epaired.

Response 3: Pressure relief devices (PRDs), in particular PRDs that are connected

directly to the flare gas header, can not be repair ed without shutting down the process unit which they serve. Therefore, refi neries typically repair defective or leaking PRDs during the process unit t urnaround. To facilitate expeditious repair, PAR 1118 requires th e refineries to conduct the PRD survey within 90 days prior to a turnaround

.

Comment 4: The district should include a mechanism to allow fo r public comment on

the proposed Flare Management ( Minimization ) Plan [FMP] prior to each FMPs approval. The lack of specific quantifiable st andards for an FMP to attain approval, as well as the fact that each FMP will be unique, make it imperative that a forum for public comment is inclu ded to provide all interested parties with the opportunity to provide critical input.

Response 4: PAR 1118 has been revised to incorporate a provisio n that requires a 60

day public comment period for each Flare Minimizati on Plan (FMP) that has been reviewed and recommended for approval by t he AQMD.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-3 October 2005 Comment 5: Flare Management ( Minimization ) Plans should be required to be updated

on an annual basis to incorporate improvements in f lare management. Additionally, the district ought to include in the rule amendment a future commitment to evaluating Rule 1118 and making futur e recommendations to improve its effectiveness.

Response 5: PAR 1118 has been revised to require submittal of a FMP or revised FMP whenever a refinery exceeds the annual SO 2 performance target. Staff will continue to analyze data that will be submitted to the AQMD as required by PAR 1118. As with other rules, staff will also assess the effectiveness of PAR 1118 to determine if future technologically feasible and cost effective amendments are necessary to achieve and m aintain ambient air quality standards.

Comment 6: In the preliminary draft staff report, the emission reduction calculation for

sulfur compounds was made using a different methodo logy than was used to calculate the reduction of other criteria pollut ants. This discrepancy in

methods should be corrected.

Response 6 The emission reduction for total sulfur, expressed as sulfur dioxide is

based on the performance target in the rule, wherea s the concurrent emission reductions for other combustion pollutants was based on the assumption that the flare vent gas flow will be red uced with the installation of additional flare gas recovery and t reatment system(s).



### Minimization

Comment 7: The language in section (c) Requirements (2)(A) is extremely ambiguous.

The lack of specificity in the language, “take step s to minimize emissions during such events”, could provide a loophole for f acilities operating flares, and could lead to disputes over enforcement

.

Response 7: PAR 1118 has been revised to include the requireme nt to minimize all

flaring.



### Public Input and Involvement

Comment 8: The district should hold a public hearing and provi de the opportunity for

public comment prior to approving any FMP.

Response 8: PAR 1118 has been revised to incorporate a provisio n that requires a 60

day public comment period for each flare minimizati on plan (FMP) that has been reviewed and recommended for approval by t he AQMD.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-4 October 2005 Comment 9: The public should be provided with quarterly flare reports online. The

public has a right to emissions information and pro viding it online will allow the public to bypass the often long delays in herent in the public records request process.

Response 9: Staff will post a summary of the quarterly flare e mission reports on the

AQMD web site.



### Mitigation Fees

Comment 10: Individual facility mitigation fees are preferable to mitigation fees based

on industry-wide thresholds. Requiring mitigation f ees to be paid based upon an industry-wide threshold is not an equitable arrangement for individual facilities, nor is it in keeping with en vironmental justice principles.

Response 10: PAR 1118 has been revised to establish facility-spe cific performance

targets and mitigation fees will only be assessed f or emissions exceeding

the annual SO 2 performance target.

Comment 11: The PAR 1118 indicates that a mitigation fee of $25 ,000 per ton will be

charged for all emissions. The applicability of tha t mitigation fee should be changed so that it pertains only to those emissi ons above the prescribed
target.

Response 11: PAR 1118 has been revised such that mitigation fees will only be assessed

for emissions exceeding the annual SO 2 performance target.

Comment 12: The cost of $25,000 per ton is excessive given prev ious fees of $10,000

per ton or the RECLAIM backstop ceiling of $15,000 per ton. Furthermore, these mitigation fees are being charge d on top of an existing fee (AER). The rule should offer the ability for a facility to propose a local community project for which their mitigation fee pa yments could be used.

Response 12: PAR 1118 has been revised such that any refinery exceeding the specified

performance target in any calendar year, it will have to pay a mitigation fee of $25,000, $50,000 or $100,000 per each ton of sulfur dioxide over the limit, depending on whether excess emissions ar e no more than ten percent, greater than ten percent but no more than twenty percent or greater than twenty percent of the applicable perfo rmance target, respectively. The mitigation fee is capped at $4,0 00,000 dollars in any year that the performance target is exceeded.

Any mitigation fees paid would be used to implemen t emission reduction

projects in the area impacted by the excess emissio ns. The amount of theCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-5 October 2005

mitigation fee is based upon the current and future expected costs of vent gas recovery and treatment equipment needed to miti gate the exceedance of the final annual performance target. It is expe cted that refineries will implement the procedures and install the equipment necessary to achieve compliance with the performance targets

Comment 13: There should be no exemptions from mitigation fee p ayments. High

emissions can still result even from facilities tha t are in compliance with the requirements to be exempted from paying mitigat ion fees.

Response 13: PAR 1118 has been revised such that no facility is exempt from paying

mitigation fees for emissions exceeding the annual SO 2 performance

targets.

Comment 14: In order to be exempt from mitigation fee payments, a facility must meet

emissions standards of 0.25 tons or less of SOx per 1 million barrels of crude throughput. This standard is too low and base d on a one-time best achieved emissions level by a refinery.

Response 14: Under the revised staff proposal, this compliance o ption is no longer necessary and, therefore, staff has removed this co mpliance option from

PAR 1118.

Comment 15: The rationale behind calculating the emission leve l of SOx as a two-year

average needs to be explained.

Response 15: Staff has removed this compliance option from PAR 1 118. However, for

clarification, calculating emissions for compliance purposes using a twoyear average was based on the fact that the frequen cy of flare events (and emissions) do not constant; they can vary from yea r to year. An average would smooth out any anomalies.



### Flare Minimization Plan

Comment 16: The Flare Management Plan requirement could be a st and alone rule. The

requirement simply duplicates the emission reductio ns already imposed by limitations on causes of flaring, the performance g oals, and the 160 ppm vent gas H 2 S limit.

Response 16: PAR 1118 has been revised to only require a flare m inimization plan

(FMP) from refineries that exceed the annual SO 2 performance targets. The FMP requirement is a tool to ensure refineries that take appropriate measures to stay below the annual performance targe ts. Therefore, staff believes the FMP needs to be a part of PAR 1118.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-6 October 2005 Comment 17: The requirement to provide in the FMP application a list of all valves, components, or any equipment at any process units v enting directly to the flares is extremely punitive and burdensome and ser ves no apparent useful

purpose.

Response 17: PAR 1118 has been revised to only require P&IDs f or each flare system in the FMP. Secondly, staff believes refineries will take the necessary steps, including the installation or modification of vapor recovery and gas treatment system(s) to ensure compliance with the a nnual performance standards. Therefore, staff believe that submittal of an FMP (with required data and information) is not likely.

Comment 18: An explanation of policies and procedures to minimi ze flaring emissions

during emergencies, shutdown and startup of each process unit should not be required in the FMP application. Since many poli cies and procedures are not unit-specific and instead have broad applic ability, refineries ought to be able to respond to this requirement in a form and manner appropriate

to their situation.

Response 18: PAR 1118 has been revised to require an FMP only fr om refineries that

exceed the annual SO2 performance targets. Also, t he information required under a FMP submittal has been streamlined to only include refinery policy and procedures to be used and vapor recovery and gas treatment capacity that will be installed to minimi ze flaring.

Comment 19: The district should provide more specific startup/ shutdown requirements

in order to provide better direction to refineries which will in turn help ensure compliance.

Response 19: Because of the differences in the way refineries in the Basin are designed

and operated and the associated complexities of the se operations, as well as safety implications, staff believes that it is b est to leave the election of specific procedures relative to shutdown and startu p to the refinery operators. It is more appropriate, as PAR 1118 doe s, to establish a regulatory framework that requires refineries to mi nimize emissions

.

Comment 20: It is not practical to include in a FMP an estimate of the quantity of vent

gas emitted during each occurrence, the duration of each occurrence, the number of occurrences each quarter, and maximum tot al volume of vent gas being routed to the flares each year is an impr actical request. There is concern over the potential negative ramifications f or refineries who cannot accurately predict the various aspects related to t heir future occurrences.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-7 October 2005 Response 20: PAR 1118 has been revised to require from refinerie s that exceed the

annual SO 2 performance target to include in their FMP applica tion the policies and procedures as well as gas recovery and treatment systems that will be utilized to minimize flaring and relat ed emissions.

Comment 21: There should be no exemption for developing an FMP . Instead, both the

strict emissions targets of .25 tons of SOx per 1 m illion barrels of crude processed and an FMP should be required of all refi neries.

Response 21: The latest proposal of PAR 1118 puts greater empha sis on minimizing

flare events and emissions through the annual perfo rmance targets, which are significantly lower than previously presented a t the June 29, 2005 Public Workshop. The 2010 annual SO 2 performance target of 0.7 tons per million barrels of crude oil processed is much lower than the 2.1 tons per year target stated in the 2003 AQMP. Staff bel ieves the proposed performance targets are real, quantifiable, enforce able, and permanent (with the requirement of a mitigation fee for annua l exceedances) and are technologically feasible and cost effective. A FMP will only be required from refineries that exceed the annual SO 2 performance targets.

Comment 22: The level of emissions .25 tons of SOx per 1 milli on barrels of crude

processed is too low to be practicable for refineri es to meet. At such a low level, reducing emissions is no longer a viable alt ernative to submitting an

FMP. This emission limit of 0.25 tons/MMBbl is base d on the very lowest

emissions data from two refineries. The district sh ould take into

consideration that even at the refineries that did achieve the aforementioned limit, there will always be year to year fluctuations in

emissions.

Response 22: The version of PAR 1118 presented at the Public Wor kshop provided refineries a compliance option to request a permit limit of 0.25 ton of SOx per 1 million barrels of crude processed; refinerie s accepting the permit limit would not be required to submit a FMP. Based on public comment and discussion with the Refinery Working Group, PAR 1118 has been revised to remove this compliance option. PAR 1118 was revised to now require refineries to meet declining performance ta rgets over time and, beginning calendar year, 201 0 2 , to emit no more than 0. 7 5 ton SO 2 per million barrels of crude oil processed per year.



### Specific (Root) Cause Analysis

Comment 23: The 100,000 scf of vent gas or 500 lbs of sulfur di oxide emissions as a

threshold for root cause analysis is too low. 500,0 00scf or 1000 lbs of sulfur dioxide emissions is suggested as a more pra ctical threshold level.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-8 October 2005 Response 23: PAR 1118 has been revised to now require a Specific Cause Analysis

(SCA) when flare emissions or flow rate exceed any one of the following: 100 lbs of VOC; 500 lbs of SO

x emitted or flaring of 500,000 standard cubic feet of vent gas. Under federal requirements , refineries are required to analyze and report SOx emissions exceeding 500 p ounds per release.



### Essential Operational Needs

Comment 24: It is impossible for an operator to foresee in deta il all possible essential

operational needs. Therefore, the rule should provi de pre-defined EON categories with the provision that if a facility en counters a new scenario, the facility has the prerogative to analyze the eve nt, determine if it is and EON and then submit it to AQMD for approval.

Response 24: Staff has revised the definition of Essential Opera tional Need in PAR 1118

to now list specific operational or maintenance rel ated activities where due to the quality or quantity, the vent gas cannot be reasonably recovered, treated, used or delivered for sale with existing equipment

Comment 25: The current definition of Essential Operational Nee ds disqualifies many

scenarios that a refinery could actually identify a s an EON. The district, in deciding whether a scenario qualifies as an EON oug ht to examine not just the technical feasibility of a measure, but also th e practicality, cost, and

cost-effectiveness. The definition of EON should in clude such scenarios as fuel gas system imbalances, PRV leakage, and adding fuel gas to vent gas to support its combustion.

Response 25: In developing standards and requirements, staff con ducts technological

feasibility and cost effectiveness analyses. The d efinition Essential Operational Needs in PAR 1118 has been revised to i nclude such scenarios as fuel gas system imbalances, PRV leakag e, and venting clean service streams to a clean service flare or a gener al service flare, and adding fuel gas to vent gas to support combustion.



### Visible Emissions

Comment 26: PAR 1118s provision to require a visual emissions e valuation within five

minutes of observing visual emissions on the video monitor is impractical at best, and at worst, dangerous. During emergencie s the focus of trained personnel should be on responding to the emergency, not on conducting a

visual emissions evaluation.

Response 26: Staff agrees with the recommendation. PAR 1118 has been revised to

require video monitoring with a date and time stamp to determine and record visible emissions from refinery flaresCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-9 October 2005 Comment 27: The requirement to visually monitor is vague and c ould imply around the

clock monitoring. Such a requirement would mean tha t a facility could be out of compliance if a video monitor appeared to be “unattended” by refinery personnel.

Response 27: PAR 1118 has been revised to remove that requiremen t that a refinery

visually monitor visible emissions from flares. Se e Response 26.

Comment 28: The requirement to operate all flares in a smokele ss manner constitutes

double jeopardy, as visible emissions are already r egulated under Rule

401.

Response 28: Staff disagrees. Although both PAR 1118 and Rule 4 01 address visible

emissions, they are different standards with differ ent requirements and measurement methods. PAR 1118 requires that flares be operated in a smokeless manner, which is defined as no visible em issions except for periods not to exceed a total of five minutes durin g two consecutive hours,

based on USEPA Method 22. Rule 401 limits the visi ble emissions into the atmosphere from any single source of air contaminan t for a period or periods not to exceed more than three minutes in an y one hour to as dark or darker in shade as that designated No. 1 on the Ringelmann Chart or an equivalent opacity, based on USEPA Method 9. Th erefore this does not constitute double jeopardy.

Comment 29: The requirement to operate all flares in a manner w ith no visible emissions

ignores the basic flare design principles such as s mokeless capacity vs. ultimate capacity.

Response 29: Staff understands that vent gas flow exceeding the smokeless capacity may

result in visible emissions. PAR 1118 allows visib le emissions for periods not to exceed a total of five minutes during two co nsecutive hours flare will cause visible emissions. Any visible emission s due to exceedances of the flares smokeless capacity are typically due to emergencies and breakdowns. Such visible emissions caused by the i ncident would be covered by Rule 430 – Breakdown.

Comment 30: Some threshold Ringelmann number must be specified for visible

emissions. If it is not, the smallest wisps of smok e could trigger an NOV or the smallest wisps of smoke could require a “rea der” to go out into the

field and conduct a visible emissions evaluation.

Response 30: PAR 1118 allows visible emissions for periods not t o exceed a total of five

minutes during two consecutive hours. Staff has de leted the requirement that a certified “smoke“ reader monitor visible emi ssions. See Responses

27 and 30.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-10 October 2005 Comment 31: The requirement for a PRD survey to be conducted wi thin 90 days prior to

a scheduled turnaround is not adequate for turnarou nd planning purposes. Instead of specifying timing, the rule should speci fy that the scheduling of any PRD survey should be consistent with the turnar ound planning

timetable.

Response 31: Staff disagrees. Maintenance, repair or replacemen t of defective PRDs is

necessary to minimize flare emissions and often can only be corrected during a turnaround. It is now common practice to conduct unit turnarounds every five years. Conducting the PRD s urvey too far in advance of a scheduled turnaround may not provide t he refinery with the knowledge that a PRD is now leaking and in need of corrective action. Staff believes that conducting the PRD survey withi n 90 days of the turnaround provides the refinery with sufficient ti me to adjust their turnaround timetable and gives the surrounding comm unity a reasonable expectation that they will not have to experience f lare emissions from leaking PRDs for the next five years waiting for th e next scheduled

turnaround.



### Clean Service Flares

Comment 32: Clean service flares should be exempted from the v arious requirements of

PAR 1118. Their emissions are insignificant and the y are already regulated to a certain extent under current Rule 11 18.

Response 32: Staff disagrees. All emissions should be considere d in determining

whether the facility meets its performance targets. In recognition, however, clean service flares may have a more consi stent and typically lower SO2 concentration compared to other flares an d are exempt from the daily sampling requirements.



### H2S Limits

Comment 33: The 160ppm H 2 S limit for flaring is duplicative of limitations o n causes of

flaring, the requirements for FMPs, and the perform ance goals. Furthermore, this limit is an attempt to apply the EPA Subpart J (NSPS) limit to all flaring, an unnecessary rule element a s industry has already achieved the emissions reductions contemplated by t he AQMP measure. Additionally, Subpart J specifies a 3 hour rolling average, while PAR 1118 specifies no time limit. The AQMD has not demo nstrated the feasibility of universal compliance with the 160ppm H 2 S limit NSPSbased requirement that is not currently applicable to all flares.

Response 33: Local refineries currently operate several “NSPS” f lares that comply with proposed 160ppm H 2 S limit. Staff has determined that three refineri es will need to install flare gas recovery and treatin g systems and otherCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-11 October 2005

refineries may consider expansion of flare gas reco very and treating systems to comply with the annual SO 2 performance targets, which can also be designed to comply with the proposed 160ppm H 2 S limit. Staff has concluded that these systems are technologically fe asible, achieved in practice and are cost effective (as part of the mon itoring and control proposal for PAR 1118. PAR 1118 has been revised t o allow averaging over a period of three hours rather than an instant aneous limit. Also, this proposed requirement does not include vent gases re sulting from emergencies, shutdown, startup or relief valve leak age. Staff believes that other possible vent gas can be controlled to comply with the H 2 S limit as part of the new and expanded recovery and treatment systems

Comment 34: Because the H 2 S limit applies to Essential Operational Needs, ref ineries needing to install flare gas vapor recovery and tre atment systems could be out of compliance with this standard until the cont rol systems are installed.

Response 34: Staff has revised PAR 1118 to exclude relief valve leakage (due to a

malfunction) when determining compliance with the H 2 S limit. Staff believe all other essential operational needs, as d efined in paragraph (b)(4), can be collected and treated to compliant l evels. To allow time to install or expand needed control system(s), staff h as revised the compliance date to January 1, 2009.



### Operation Monitoring and Recording Requirements

Comment 35: Six months after Flare Monitoring and Recording Pla n approval may be

insufficient time to install a calorimeter to analy ze emissions.

Response 35: Staff has revised PAR 1118 to require the installat ion and operation of a

continuous higher heating value analyzer by July 1, 2007.

Comment 36: The requirement to take a sample within the first f ifteen minutes of each sampling flare event presents significant logistica l hurdles, and in some cases it is an impossibility.

Response 36: PAR 1118 requires the use of automated sampler to c ollect gases to be

analyzed for higher heating value and total sulfur. Staff has determined that automated samplers are currently available and are in operation at most local refineries. These automated samplers ca n be programmed to take a sample 15 minutes after the start of a flare event.

Comment 37: The requirement for daily sampling is a burdensome and expensive

proposition which serves no purpose. There are mil lions of data points that could be used to develop statistically reliabl e averages.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-12 October 2005 Response 37: Staff believes that increased sampling frequency wi ll greatly increase the

accuracy of emission data until the continuous moni tors are installed. Many data submitted by the refineries was not measu red but rather

substituted data based on calculations. The cost o f daily sampling and analysis has been included in the cost effectivenes s determination for PAR 1118. Staff has determined that PAR 1118, which in cludes daily sampling, is technologically feasible and cost effective.

Comment 38: Sampling during a Sampling Flare Event ought to suf fice as the daily required sample.

Response 38: Staff believes that increased sampling frequency wi ll greatly increase the

accuracy of emission data until the continuous moni tors are installed. Furthermore, the use of data collected during a sam pling flare event, such as an emergency, has in most instances, been docume nted as a value greater than the values measured during a smaller, non-sampling event. However, staff has revised PAR 1118 to allow the us e data collected during a sampling event for the required daily sam ple.

Comment 39: The time limit on breakdowns and unplanned flare m onitoring system

maintenance of 48 hours per quarter is not feasible . Often, more time is needed because vendors must be called out for repai rs. 160 hours annually has been suggested as a viable option to the 48 hou rs per quarter limit.

Response 39: PAR 1118 has been revised to allow flare monitorin g system maintenance

and repair of up to 96 hours per quarter, which is at least as stringent as Rule 218 – Continuous Emission Monitoring.

Comment 40: There is no way to determine whether the 14 day pe r 18 month limit on

planned maintenance is feasible, especially given t he fact that monitoring systems will now include more components than befor e and will be more complex. Instead of the aforementioned limit, Rule 218 to should be used to deal with the issues of monitoring system downti me.

Response 40: Data collected by AQMD on continuous emission monit oring systems

(CEMS) does not suggest additional time will be nee ded. However, staff acknowledges that information on the operation of C EMS for flares is less robust. If the pilot study on the total sulfur ana lyzer shows a potential need for more than 14 days per 18 months, staff can revisit this provision of PAR 1118.

Comment 41: PAR 1118 allows the refinery operator to monitor th e presence of a pilot

flame using a thermocouple or any other equivalent device approved by the Executive Officer. Providing examples of equiv alent devices to aCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-13 October 2005

thermocouple, such as an IR camera, would be helpfu l for both facility operators and District engineers.

Response 41: Staff has determined that thermocouples and video c ameras are currently

being used successfully to monitor the presence of the pilot flame on flares. However, staff did not want to limit a ref inery’s ability to propose an alternate measurement technique it believes equi valent. Any alternative(s) by the refinery can be proposed to a nd analyzed by AQMD staff.

Comment 42: The requirement to install a flow meter to monitor and record the purge

gas and pilot gas flow to each flare has no greater air quality benefit than using engineering estimates. Furthermore the instal lation of the proposed flow monitoring devices are far more expensive than engineering estimates and may require that the flare involved b e out of service.

Response 42: Staff believes that it is important to establish an accurate emission

inventory. Installing flow meters on pilot and purg e gas lines will is needed to obtain an accurate measurement of pilot a nd purge gas to the flares. Flow measuring devices are relatively inex pensive; the cost of this requirement was used in concluding that PAR 1118 is technologically feasible and cost effective.

Comment 43: The language in (g)(5)(B)(i) is unclear. Does the district mean, “all the

gases that are delivered to the flares for combusti on must be measured and recorded.”? Furthermore, the requirement should spe cify “vent gases” because there is a need to specifically exclude any assist air or steam for the purpose of insuring clarity.

Response 43: Yes, Clause (g)(5)(B)(i) clearly states “A flare mo nitoring system may be

used to measure and record the operating parameters required in paragraph (g)(3) of this rule for more than one fla re provided that: All the gases that are delivered to the flares for combusti on must be measured and recovered”. To exclude “assist air or steam” f rom the gas(e) being directed to the flare(s), the refinery will need to demonstrate to the satisfaction of the Executive Officer that assist a ir or steam does not contain anything that will result in the emission o f air contaminant(s). However, the revised definition of Vent Gas exclude s assist air or steam injected directly into the flare combustion zone or flare stack via a separate line (not the flare header).

Comment 44: The requirement for flow monitoring instrumentatio n placement in clause

(g)(5)(E)(i) cannot be justified on the basis of an air quality benefit.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-14 October 2005 Response 44: Accurate emission data, which includes flow measur e to the flares, is

paramount to determining the amount of air contamin ants released to the atmosphere. Staff can not determine the air qualit y benefit without accurate flow data. The AQMD Governing Board, on S eptember 3, 2004, directed staff to proceed with rule development to evaluate the recommendations stated in “Evaluation Report on Emi ssions from Flaring Operations at Refineries”, which included a recomme ndation to improve the measurement of flare vent gas flows. Staff bel ieves that it is important to establish an accurate emission inventory; instal ling flow meters in representative locations will do just that. As an alternative to relocation, an owner or operator may upgrade the meter with a t otalizer to subtract any reverse flow to a flare gas recovery system.

Comment 45: There is no air quality benefit associated with the requirement in clause

(g)(5)(E)(iii) to install an automated flare gas sa mpling system, a costly and unnecessary investment. Such a sampling system will cost $50,000 to $100,000 according to estimates.

Response 45: Accurate emission data, which includes higher heati ng value and total

concentration of total sulfur, expressed as sulfur dioxide, of gases directed to the flares, is paramount to determining the amou nt of air contaminants released to the atmosphere. The AQMD Governing Boa rd, on September 3, 2004, directed staff to proceed with rule develo pment to evaluate the recommendations stated in “Evaluation Report on Emi ssions from Flaring Operations at Refineries”, which included a recomme nded the installation of continuous monitoring systems to measure the hig her heating value and the total sulfur gas concentration of the flared ga s. Several local refineries have already installed and operate autom ated flare gas sampling systems. Staff believes that this equipme nt will improve the logistics of taking samples, especially during an e mergency when refinery personnel are not available to manually collect the required sample(s). Staff has determined the installed cost of the auto mated flare gas sampling system to be approximately $5,000 based on cost inf ormation provided by an engineering general contractor who has installed sampling systems at refineries and the AQMD.

Comment 46: The requirement of installation of Higher Heating Value (HHV)

technology is problematic. It is requested that the y be pilot tested before they are considered as a requirement for flare syst em monitoring.

Response 46: Staff has contacted several petrochemical facilitie s in Texas and

Louisiana where continuous calorimeters have been u sed for a number of years on flare headers for compliance with USEPA 40 CFR 60.18 or Texas regulations. Staff believes, based on those testim onials, that a pilot program is not necessary.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-15 October 2005 Comment 47: Procedures to prevent flaring events caused by rec urring equipment

breakdowns, detailing the adequacy of maintenance s chedules for equipment, process and control instrumentation are not necessary and are a requirement that should be dropped. The issue is already addressed by the requirements for Root Cause Analysis. Furtherm ore, what constitutes a definition of recurring is unclear and no guarant ee can ever be made that there will not be recurring breakdowns. The term “ adequacy” used in the requirement is also subjective and should be replac ed.

Response 47: PAR 1118 has been revised to streamline the require ments of the FMP

and eliminate any redundancy with the “Specific Cau se Analysis” (SCA), which replaces the Root Cause Analysis. An SCA is an investigation of the cause of the flare vent where the facility operator also identifies corrective measures to prevent a recurrence of a similar flare event.

Comment 48: There appears to be a misconception that fuel syste m imbalances only

occur as a result of a temporary interruption of pi peline gas sales. Rather, the interruption of pipeline gas sales is probably one of the least common reasons for fuel system imbalances. There is concer n that the fact that fuel gas imbalances are specifically addressed implies t hat they cannot be claimed as an Essential Operational Need, which the y are.

Response 48 : Staff understands that an interruption in pipeline gas sales is not the only

situation that may cause a temporary fuel gas imbal ance; the loss of a combustion device such as a heater or boiler may al so cause this temporary situation. Staff recognizes that there a re essential operational needs that must be directed to the flare. The defin ition of Essential Operational Needs has been revised to include vent gas resulting from temporary fuel gas system imbalance.

Comment 49: The requirement to specify the schedule and resourc es that will be used to

conduct acoustic and temperature surveys of pressur e relief devices is impractical. First, specifying schedules that far i n advance, is difficult at best. Furthermore, specifying resources so far in a dvance serves no useful purpose as resources that complete a particular job at the same high quality are often interchangeable. For instance, co ntractor A could be replaced by contractor B and the job could be done in the same manner.

Response 49: PAR 1118 has been revised to remove this requirem ent.

Comment 50: The requirement to provide a list of equipment brea kdowns during the

previous five years that resulted in vent gas being directed to the flare cannot be guaranteed to be met since refineries hav e not been required to keep records going back five years.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-16 October 2005 Response 50: PAR 1118 has been revised to remove this requiremen t.

Comment 51: The provision requiring that actions be taken to pr event future breakdown

is problematic because “prevent” is an absolute ter m and there cannot be any assurance that future breakdowns will not occur

.

Response 51: PAR 1118 has been revised to remove this requiremen t.



### Notification and Reporting Requirements

Comment 52: When an unplanned flare event exceeds a threshold of 100,000 scf of

combusted vent gas or 500 lbs of sulfur dioxide emi ssions, the operator is required to contact the Executive Officer within on e hour of the event. This extremely low threshold will result in an exce ssive number of phone

calls to the District. There is also concern that a ny late, or missed calls could result in NOVs, despite the fact that there a re no negative air quality implications.

Response 52: PAR 1118 has been revised to require the refinery t o notify the AQMD

within one hour, by telephone, of the unplanned rel ease of 100 pounds of VOC, 500 pounds of SO

x , or 500,000 standard cubic feet of vent gas from a flare. The one hour notification requirement is consistent with Rule 430 – Breakdown Provisions and staff believes it is app ropriate in order to conduct timely investigations of flaring events and possible public complaints. The AQMD issues NOVs only after carefu l consideration of the facts and merits of the failure to meet its’ ru le requirements promulgated to protect public health.

Comment 53: The requirement to submit a follow-up report to th e Executive Officer

within 30 days carries with it the implication that a Root Cause Analysis should also be completed within this time frame, wh ich is an unreasonable request. Furthermore, the requirement will result i n resources being redistributed from areas that have a greater potentia l for achieving air quality benefits to writing these reports that have no immediate air quality impact.

Response 53: Staff made the requirement for submittal of the Spe cific Cause Analysis

(SCA) consistent with the deadlines in Rule 430 or Regulation XX Rule 2004 (h) for breakdown reports. If needed, a facil ity may request an extension of up to 30 additional days for submittin g the SCA.

Comment 54: The term mitigation used in the requirement for Roo t Cause Analysis

implies that mitigation of emissions is a requireme nt. Clarification isCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-17 October 2005

needed on this point to prevent the consequences of the subjective nature

of the term.

Response 54: PAR 1118 requires minimization of flaring during fl aring events and any

actions taken by the operator with this purpose sho uld be reported in the

SCA.

Comment 55: Facilities are not always able to accurately predic t the exact time period of

even a planned flaring event, thus making the requi rement to notify the district 24 hours prior to such an event difficult at best.

Response 55: Staff understands that emissions reported as part of notification of such schedule changes are estimated at best in which cas e the facility should notify the AQMD of the revised planned event date a nd/or time. However, the facility will have the opportunity to refine th ese estimates once more information about the events become available.

Comment 56: There should be clarification provided that demonst rates that the quarterly

report required for submittal within 30 days after the end of each quarter is

consistent with “standard” certifications such as o ther District requirements, EPA requirements etc.

Response 56: PAR 1118 language was revised to be consistent with the certification

requirements for quarterly reports in other AQMD ru les.

Comment 57: Because of the low thresholds that define a flare e vent, 500 pounds sulfur

dioxide and 100,000 cubic feet of flare gas, many f lare events are likely to be nearly continuous, making the requirement to pro vide an analysis of

each flare event difficult.

Response 57: PAR 1118 language has been revised to require a mor e comprehensive

Specific Cause Analysis (SCA) for larger flare even ts 500 pounds sulfur dioxide, 100 pounds VOC or 500,000 cubic feet of fl are gas is combusted and a basic investigation to determine the relative cause (emergency, shutdown, startup, turnaround, specific essential o perational need, or unknown if undeterminable) where more than 5,000 cu bic feet of flare gas is combusted by the flare. Staff believes that the se thresholds are necessary to reduce emissions from flares since the y will in effect provide operators useful information regarding the use of f lares at their facilities.

Comment 58: Requiring the name of the person who conducted the inspection to be part

of the annual acoustical or temperature leak survey for pressure relief devices (PRDs) is not justifiable in any way. Furth ermore, the clause, “but not limited to”, which is part of the description o f what the report shouldCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-18 October 2005

include ought to be deleted because it is too open ended and will result in confusion and problems later in terms of enforcemen t.

Response 58: For the AQMD to effectively review and verify measu red and reported

data, it is critical that the name of the person(s) conducting the annual inspection of PRDs be recorded. Staff has revised P AR 1118 to remove all “but not limited to” language in the proposed amend ed rule.



### Testing and Monitoring Methods

Comment 59: Neither calorimeters nor sulfur analyzers have bee n demonstrated to be

viable for flare service and both must be tested in a pilot program before PAR 1118 can include a provision requiring the use of semi-continuous heat content analyzer. Furthermore, the District ha s not justified the cost in terms of air quality benefits of installing these a nalyzers systems.

Response 59: Staff has contacted several petrochemical facilitie s in Texas and

Louisiana where continuous higher heating value ana lyzers (calorimeters) have been used for a number of years on flare heade rs for compliance with USEPA 40CFR 60.18 or Texas Commission of Envir onmental Quality (TCEQ) regulations. Staff believes, based on those testimonials, that a pilot program is not necessary for this type of analyzer. A local refinery will be install and operate a total sulfur (TS) analyzer in March 2006. Staff believes that sufficient data will be collected to demonstrate the effective operation of the TS analyzer well in advance of the July 1, 2007 date when petroleum refineries are required to install and operate this type of analyzer. Staff will make a commitmen t in the PAR 1118 adopting Resolution to conduct a study of the TS an alyzer at the local refinery prior to the requirement going into effect . Accurate emission data, which includes total heating value and concen tration of total sulfur, expressed as sulfur dioxide,, is paramount to deter mining the amount of air contaminants released to the atmosphere. Staff can not determine the air quality benefit without accurate emissions data . The AQMD Governing Board, on September 3, 2004, directed sta ff to proceed with rule development to evaluate the recommendations st ated in “Evaluation Report on Emissions from Flaring Operations at Refi neries”, which included a recommendation to improve the measuremen t of flare vent gas. The requirement of continuous monitoring implements that

recommendation.

Comment 60: In subdivision (j) Testing and Monitoring Methods ( B), the sulfur content

of vent gas should be expressed as a reduced sulfur compound rather than

as sulfur dioxide.

Response 60: The 2003 AQMP Control Measure CMB-07 requires a red uction in the

sulfur dioxide emissions from flares operated at pe troleum refineries andCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-19 October 2005

related facilities. Therefore, staff has determine d that it is appropriate to calculate and report concentration of total sulfur, expressed as sulfur dioxide, in the vent gas as sulfur dioxide.

Comment 61: There is absolutely no justification for the provis ion that samples be

analyzed by a third-party. It should be acceptable for the sample to be analyzed in a refinery lab that meets District oper ating standards.

Response 61: PAR 1118 has been revised to allow AQMD approved la boratories to

analyze for higher heating value and concentration of total sulfur, expressed as sulfur dioxide, (reported as sulfur di oxide).

Comment 62: Under subdivision (k) exemptions, the terms “catast rophic” and “major”

are subjective and the language ought to be clarifi ed.

Response 62: Subparagraph (k)(1)(A) relieves a facility from col lecting “grab” samples

for higher heating value and concentration of total sulfur, expressed as sulfur dioxide, during a flare event resulting from a catastrophic event including a major fire or an explosion at a facilit y. Staff agrees with petroleum refineries that safety is paramount; only the facility experiencing a significant flare event and the spec ific circumstances pertaining to that event knows if it is safe to sen d in personnel to collect a sample. PAR 1118 has been revised to better define circumstances during which sampling is infeasible or considered a safety hazard.

Comment 63: Requiring facilities to submit a written document to explain flaring events

caused by natural disasters or acts of war or terro rism is pointless, because the District would already be well aware of such ev ents.

Response 63: Staff believes that, in order to maintain an accura te record, this

requirement is appropriate.

Comment 64: The exemption in paragraph (k)(2) should also inclu de flare sulfur dioxide

emissions resulting from interruptions of power sup ply beyond the refinery’s control.

Response 64: PAR 1118 language has been revised to exclude emiss ions from power

outages, other than due to an interruptible power a greement, from the annual performance target.



### Attachment A:

Comment 65: The District should refrain from specifying the ma terials of construction,

or considering area classifications in a rule. Faci lities must always be inCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-20 October 2005

control of the aforementioned issues as they are th e ones that specify, purchase and operate equipment. This general provis ion extends to specifics in Attachment A such as installation issu es like hot-taps.

Response: 65 The goals of analytic and monitoring requirements a re to ensure that

complete, accurate meaningful and verifiable data a re collected. In that this requirement contributes to ensuring that an an alyzer will not have temperature changes that may compromise its ability to accurately measure flare gas parameters, it is both necessary and within AQMD’s purvey. Area classification requirements were selec ted for harmony with building requirements in the region and to ensure s afety of monitoring staff.

Comment 66: The lower threshold of 0.1 in the velocity range i s possibly unrealistic and

can certainly not be justified based on any air qua lity benefits.

Response 66: The manufacturer of the flow meters used by facilit ies subject to PAR 1118

has stated that the meters can accurately measure f low as low as 0.1 feet per second. However, staff will include a twenty percent margin to account for any fluctuations due to transient flow. PAR 1118 has been revised to raise the threshold to define a flare ev ent as 0.12 feet per second or greater. As previously stated in Respons e 46, accurate flow data is necessary to determine emissions and air qu ality benefit as well as air quality detriment.

Comment 67: It is assumed that data recorded will be transferre d to a Data Collection

System (DCS) and stored there.

Response 67 : The assumption is correct and all required records have to be kept by the

facility for a period of five years.



### Attachment B:

Comment 68: Assuming that the flow rate is the maximum design c apacity of the flare

when the maximum range of the flow meter is exceede d is an overly pessimistic assumption which will quickly cause emi ssions performance goals specified in (d)(1) to be exceeded.

Response 68: Staff has revised PAR 1118 to allow the operators o f facilities subject to this rule to substitute flow data that was not meas ured using both the maximum and the average flow measured during the pr evious 20 quarters. Based on flow data collected from 2000 through June 2005, the proposed methodology would capture approximately 97 percent of flow data previously reported. Operators also have the optio n to demonstrate to theCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-21 October 2005

AQMD that no flow occurred during the time when the flow meter was non operational through the monitoring of the water seal level associated with the flare or through any other operational par ameters and/or other process data. Furthermore, the provisions applicab le to the non-sampling events have been revised to allow these facilities to rely on previously measured events rather than relying on data substit ution procedures. In addition, staff has committed to evaluate the use o f the data substitution procedures by industry during the first year of imp lementation of PAR 1118 and report back to the Governing Board with an y recommendations.

Comment 69: Defining the flow rate at the lower range when the flow rate is below the

valid lower range of the flow meter means that a re finery could never use “zero”. Without a designation of zero a “Flare Even t” as defined would never actually end. This applies to both flow meter s and to a combination

of flow meters and on/off flow indicator switches.

Response 69: Flow meters are capable of measuring flows as low a s 0.1 feet per second.

PAR 1118 has been revised to establish a flare even t at 0.12 feet per second or greater. The twenty percent difference b etween the lower limit capability of the flow meter and what constitutes a flare event is adequate for an operator to discern flow from no flow.

Comment 70: Using the maximum range of the meter as the assumed flow rate for any

missing data is not acceptable. Nothing justifies t his use of worst-case assumptions, especially in light of the mitigation fees that would apply if emissions performance goals are exceeded. Instead o f just using worstcase assumptions, there should be a provision that considers other factors

such as water seals that remained intact.

Response 70: PAR 1118 has been revised to allow facility operato rs to demonstrate to

the AQMD that operational records, such as water se al level or other approved parameters in the Flare Monitoring and Rep orting Plan, that a flare event did not occur. Furthermore, the data s ubstitution provisions of

PAR 1118 have been revised and the worst case assum ptions are no longer applicable.

Comment 71: The requirement to fill in any missing data with th e measurement of the

highest sulfur concentration in the vent gas from t he previous year is exceedingly harsh and based on unrealistic assumpti ons. First, it is unlikely that the peak value from the previous year would always exceed any estimate based on engineering knowledge. Second ly, this requirement could lead to a situation in which the payment of t he mitigation fee would

be based on fictitious emissions instead of real on es. Instead of this worstcase data use, facilities ought to be able to use a nother appropriateCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-22 October 2005

estimate if the facility provides adequate justific ation for that estimate’s

use.

Response 71: Staff has revised PAR 1118 to allow the operators o f facilities subject to this rule to substitute concentration of total sulf ur, expressed as sulfur dioxide, data that was not measured using both the maximum and the average concentration of total sulfur measured duri ng the previous 20 quarters. Based on concentration of total sulfur, expressed as sulfur dioxide, data collected from 2000 through June 2005 , the proposed methodology would capture approximately 97 percent of total sulfur concentration data previously reported. After the continuous total sulfur analyzers are certified by the AQMD, facility opera tors also have the option to collect a “grab” sample during the flare event and use that analysis to substitute data for time when the total sulfur analyzer was non operational. PAR 1118 also allows the facility ope rator the option to demonstrate to the AQMD that total sulfur can be es timated through alternative methods using recorded and verifiable o perational parameters and/or process data to be representative of the tot al sulfur concentration.

Comment 72: There is no reason why the single highest measurem ent of concentration

of sulfur or heat content in the previous 365 days should be used when it would be more equitable to use an average of the va lues from the previous

year.

Response 72: See Response 7 2 1

.



### Definitions

Comment 73: The very low velocity threshold of 0.1 ft/sec that helps define a flare event

is problematic because it means that facilities are very likely to have continuous flare events. Part of the problem is tha t in some flare configurations, vent gases may enter the flare head er, pass by the meter and then be recovered by the vapor recovery system before breaking through the water seal. This typically results in f low meter reading greater than .1 ft/sec to as high as about 1.5 ft/sec with no vent gas released to the flare. Therefore, a flare event defined by the pres ence of flow at a velocity of 0.1 ft/sec would force a recording of a continuo us flare even when there is no flow to the flare. Furthermore, flare events indicated by flow monitor signals, which are not verified by on/off meters, w ater seal monitors, or video monitoring, must be excluded from flare event s, as defined. A better definition of flare event is, “FLARE EVENT is any i ntentional or unintentional release of vent gas to a flare based on positive indications or other instrumentation including, but not limited to , water seal breakthrough, on/off indicators, or video monitorin g.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-23 October 2005 Response 73: The definition of Flare Event has been revised to a ddress the situations

where vent gas is measured by the flow meter but th rough the use of the water seal, the vent gas is processed by the gas re covery system. The revised definition includes the following language: ”the owner or operator can demonstrate that no more vent gas was combusted based upon the monitoring records of the flare water seal level and/or other parameters as approved by the Executive Officer in the Flare Monitoring and Recording Plan.”

Comment 74: The definition of an emergency should include opera tional upsets to be

consistent with federal rules. A better definition would be: “Emergency, for this rule, means a condition beyond the reasona ble control of the owner or operator of a refinery requiring immediate corrective action to restore normal and safe operation, which is caused by any sudden, infrequent, and not reasonably, preventable failure of equipment or of a process to operate in a normal or usual manner, for ce majeure, act of war or terrorism, or external events beyond the control of the operator. Failures that are caused in part by poor maintenance or care less operation are not emergencies.” (Reference: Based on 40 CFR 60, Subpa rt A 60.2 - Malfunctions) In addition, the current definition of Emergency Service Flare in Rule 1118 includes “emergency process upse t condition.”

Response 74: The definition of Emergency was revised to include “not reasonably

preventable”. However, staff does not believe “pro cess upset” should be included in this definition; specific situations wi ll be listed in the definition of Essential Operational Need”. The definitions of Emergency and Emergency Service Flare can not be identical in app lication since clean service flares and general service flares also proc ess vent gases from emergencies.

Comment 75: A better definition for “FLARE” is the one in the d raft BAAQMD rule

(definition 12-12-203).

Response 75: PAR 1118 language was modified to incorporate eleme nts from the

BAAQMD in the definition.

Comment 76: The definition of “FLARE GAS RECOVERY SYSTEM” woul d not apply

in all cases. The following definition should be us ed instead. “Flare Gas Recovery System is a system consisting of permitted equipment used to prevent or minimize the combustion of vent gas in a flare.”

Response76: Staff believes the suggested definition is too vagu e and open-ended.

Comment 77: The definition of “FLARE MONITORING SYSTEM” is ina ppropriate

with the phrase “including but not limited to.” Th ere needs to be a clearCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-24 October 2005

understanding between the AQMD and industry of what a flare monitoring system consists of.

Response 77: PAR 1118 was revised to delete the phrase “but not limited to.” The

definition of Flare Monitoring System includes high er heating value and total sulfur analyzers, flow meters, and on/off flo w indicators.

Comment 78: The definition of “GENERAL SERVICE FLARE” includes activities,

such as tank vapor displacement, blowdowns, and “cl ean up” which

should be included in other definitions and/or in t he listing of allowable flaring at Rule 1118 (c)(2)(A).

Response 78: Staff believes that these activities are within the scope of essential

operational need(s) or qualify as startups, shutdow ns and turnarounds.

Comment 79: The definition of “HYDROGEN PRODUCTION PLANT” is ov erly

specific.

Response 79: Staff believes this definition is appropriate.

Comment 80: Instead of using the current definition of “NATURAL GAS” the District should consider using an existing definition of “pi peline quality natural gas” from either CPUC or EPA.

Response 80: Staff believes the current definition of Natural Ga s is appropriate.

Comment 81: The following definition of “PURGE GAS” is better t han the current

version. “PURGE GAS is a continuous gas stream intr oduced into a flare header, flare stack, and/or, flare tip, for the pur pose of maintaining a positive flow and to prevent the formation of an ex plosive mixture due to ambient air ingress.”

Response 81: The definition of Purge Gas has been revised based on your suggestion.

Comment 82: The definition of a REPRESENTATIVE SAMPLE ought to be consistent

with other requirements such as the specifications for Higher Heating Value and Total Sulfur analyzers.

Response 82: The proposed amended definition for Representative Sample was modified

for consistency with requirements for analyzers.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-25 October 2005 Comment 83: In the definition of SAMPLING FLARE EVENT it must b e made clear

that the refinery must initiate the request.

Response 83: PAR 1118 language was modified to reflect that a fa cility is to propose a

different Sampling Flare Event threshold for the Ex ecutive Officer’s approval.

Comment 84: The definition of SHUTDOWN does not take into acco unt that shutdowns

occur for reasons other than maintenance, repair, o r replacement of equipment. The following definition is more complet e. “Shutdown is the process of stopping the operation of a process unit or piece of equipment for any reason, including preparations necessary fo r maintenance work.”

Response 84: Staff believes that the suggested definition is too vague and may become a

loophole to allow routine flaring.

Comment 85: A more complete definition for STARTUP is the foll owing. “Startup is the

process of initiating and achieving normal operatio n of a process unit or piece of equipment.

Response 85: PAR 1118 has been revised to include an expanded de finition for startup that takes into account parameters, such as pressur e, temperature, feed rate, etc. to characterize normal operation.

Comment 86: In the definition of TURNAROUND it would be helpful to add language

regarding installation of new equipment.

Response 86 : Staff has revised the definition of Turnaround to include “installation of

new equipment.”

Comment 87: The definition of VENT GAS does not specifically ex clude “assisting air

or steam, flare pilot gas and any continuous purge gases.” These exclusions must be included in the proposed definit ion. A more complete definition is the following. “Vent gas is any gas g enerated at a facility subject to this rule that is routed to, and combust ed in a flare, excluding assisting air or steam, flare pilot gas, and any co ntinuous purge gases.

Response 87: Staff has revised definition of Vent Gas to exclude assist air or steam

injected directly into the flare combustion zone or flare stack via a separate line (not the flare header). However, any gas that is generated at a facility subject to PAR 1118 and is directed a fl are is considered vent

gas.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-26 October 2005 MISCELLANEOUS

Comment 88: A flare designed for smokeless flaring at full capa city and designated for

emergency use only should not be required to have a video monitor

installed for it.

Response 88: Staff is not aware of any flare that is smokeless o ver the whole operating

range up to maximum design. Even if this existed, there is always the possibility of losing steam injection that could re sult in visible emission, therefore having a video record is appropriate.

Comment 89: All current activities and uses of the flare should be considered essential

operational needs. Without such designation, facili ties planning to install complete vapor recovery and treatment systems in th e next few years would face challenges relating to certain requireme nts prior to their installation of the vapor recovery system.

Response 89: Staff disagrees with this statement that would effe ctively allow any flaring

to take place and make the rule amendment futile. However, the rule language has been revised to allow more time for th ese facilities that intend to install additional vapor recover treatmen t capacity and have affirmed steps toward that goal.

PRELIMINARY STAFF REPORT COMMENTS

Comment 90: The suggestion that a flare gas recovery and treatment system can prevent

temporary fuel gas imbalances is incorrect; such sy stems are not effective for that purpose.

Response 90: Staff agrees that such a system would not prevent a fuel gas imbalance,

but rather flare emissions may be minimized by the use of this equipment.

Comment 91: The rule is not necessary since the AQMD Basin is i n attainment with the

federal SOx standards and flare emissions have alre ady been reduced by

80%.

Response 91: Staff disagrees. SOx emissions are precursors to p articulate matter (PM)

emissions and the AQMD is not in attainment for PM 10 (particulate matter less than 10 microns aerodynamic diameter) a nd PM 2.5 (particulate matter less time 2.5 microns aerodynam ic diameter). The reductions achieved to date were voluntary and were achieved primarily through operation procedural changes implemented by the refineries. Furthermore, a close look at the current difference s of the recovery and treatment capacity of the various facilities indica tes that additional capacity for some facilities is feasible to further minimize flaring andCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-27 October 2005

associated emissions. There is no mechanism in pla ce that prevents backsliding to previous emission levels. PAR 1118 will make these reductions permanent, real, quantifiable and enforc eable and will establish a framework for further reductions.

Comment 92: It is not fair to assess mitigation fees based on a n industry-wide

performance, where an individual facility has no co ntrol on emissions from a competitor. Also, the standard for an “ultr a-clean facility” is not

attainable.

Response 92: PAR 1118 has been revised to require petroleum refi neries to achieve a

facility-specific declining annual sulfur dioxide p erformance target. Facilities that exceed the annual performance targe t are subject to mitigation fees and must also submit a Flare Minimi zation Plan for public comment and Executive Officer approval. PAR 1118 n o longer contains an “ultra-clean” facility compliance option.

Comment 93: The estimated emission reductions based on 2003 em issions inventory is

not appropriate since it does not take into conside ration further reductions realized in 2004. Further, the use by the District of the DCF method yields a lower number for cost effectiveness.

Response 93: Staff acknowledges that flare emissions have trende d down and that 2004

emissions are lower than the previous stated baseli ne year 2003. Since emissions may vary significantly from year to year due to turnarounds and other unforeseen events in petroleum refinery opera tions, it is appropriate to use a multiple year average as an emissions base line. The staff report has been revised to average sulfur dioxide emission s and vent gas flow rates for the years 2001, 2002, 2003 and 2004 to es tablish the baseline for calculating emission reductions and the cost effect iveness of PAR 1118.

Cost effectiveness analysis is a tool to generate a cost effectiveness factor

for a control measure. By comparing the cost effec tiveness factors of several control measures with each others, one can acquire knowledge about the costs of each control measure relating to their effectiveness in controlling a particular pollutant. It is necessar y to compare cost effectiveness factors of different control measures derived using the same methodology and the same assumptions. The AQMD has been using Discounted Cash Flow Method (with a 4% real interes t rate) to determine the cost effectiveness factor for numerous proposed rules since 1995.

Comment 94: The Staff Report should include the CARB Resolution 86-60 for

reference.

Response 94: CARB Resolution 86-60 is included as an attachment to this staff report.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-28 October 2005 Comment 95: In contrast with the Bay Area Air Quality Manageme nt District

(BAAQMD) flare rule, PAR 1118 is far more complex a nd has duplicative requirements.

Response 95: BAAQMD has two flare rules: one for monitoring and one for control of

flare emissions, whereas PAR 1118 has one rule that includes both these aspects. Moreover, the approach of the two District s to flares is different, BAAQMD is requiring Flare Minimization Plans while AQMD’s PAR 1118 establishes performance targets for controllin g and minimizing flare

emissions.

Comment 96: The Staff Report needs to explain the applicability of New Source performance Standards (NSPS) requirements to flares with respect to

effective dates.

Response 96: Staff has clarified in the Staff Report all applica ble dates that trigger

NSPS requirements for flares (40CFR Subparts A and J).

Comment 97: Acid gas in the Preliminary Draft Staff Report (PD SR) should be

described as "a highly concentrated waste stream of hydrogen sulfide gas (up to 90 percent pure) and sour water stripper gas (about 30 percent pure)” The PDSR incorrectly states EPA’s position i n the October 2000 Enforcement Letter, which is...”refineries should hav e adequate capacity at the back end of the refinery to process acid gas ”.

Response 97: The description of acid gas was enhanced as suggest ed. Staff believes that

the title of the October 2000 Enforcement Letter su mmarizes EPA’s position that routine flaring is not considered “Go od Pollution Control Practice” and it “May violate the Clean Air Act”.

Comment 98: The use of the same concepts in the Consent Decree s that EPA has entered

with some refiners used in the amendment of Rule 11 18 may represent a duplication of a federal regulations and the AQMD B oard must recognize it in its findings upon rule adoption.

Response 98: Staff disagrees. The Consent Decrees are not feder al regulations and they may sunset according to specific clauses in each of them, based on each refinery’s compliance record for a certain period o f time following the signing of the Consent Decree.

Comment 99: The statement in the Staff Report that refineries b urn “waste gases” in

flares is a false assumption.

Response 99: Staff has revise the staff report and the word “was te” was removed.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-29 October 2005 Comment 100: Stating that visible emissions are caused by insuff icient steam is inconsistent with the smokeless capacity of a flare , since there are limits to how much steam can be used. The staff report shoul d mention that a facility with a flare smoking for 5 minutes within 1 hour could receive two Notices of Violations, one for violating Rule 401 a nd one for violating

Rule 1118.

Response 100: Staff agrees that when the smokeless capacity is ex ceeded there is not

enough steam to accommodate the high vent gas flow, but acknowledges that this is due to the limitations in the flare de sign and a clarification was made in the staff report.

Assuming that a flare was found having visible emis sions in excess of Ringelmann 1 or 20 percent opacity for 5 minutes wi thin 1 hour due to a situation other than a valid breakdown, force majeu re or power curtailment beyond the operator’s control, only one NOV would be issued with two counts of violating Rule 401 and Rule 1118 , respectively. If visible emissions were in excess of Ringelmann 2 or 40% opacity, there would be an additional count for violation of Calif ornia Health and Safety

Code 41701.

Comment 101: The operational status of a flare does not involve having just the pilot

lights on and the amount of purge gas used depends on other variables than just the flare design.

Response 101: The Staff Report has been revised to clarify these issues as suggested.

Comment 102: Clean Service Flares should be exempt from all requ irements except for

monitoring and recording as specified in Table 1.

Response 102: Staff disagrees. All flares have emissions potenti al and all significant

flare events need to be accounted for in the form o f a Specific Cause Analysis or a relative cause analysis, as required in PAR 1118. However, a Clean Service Flares is defined as a flare that i s designed and configured by installation to combust only natural gas, hydrogen gas and /or liquefied petroleum gas, or any other gas(es) w ith a fixed composition vented from specific equipment which has been deter mined to be equivalent and approved in writing by the Executive Officer. Therefore, based on this definition, a Clean Service Flare wou ld have very low sulfur dioxide emissions, and as such would contribute ver y little to the annual sulfur dioxide performance target. Clean Service F lares are not required to be monitored with higher heating value or total sulfur analyzers and are not required to have daily vent gas “grab” samp les taken. However, the operator must collect grab samples for all samp ling flare vents.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-30 October 2005 Comment 103 The staff report acknowledges that flares are used as control devices that

prevent the release of VOC to the atmosphere, but t he rule would prohibit this type of use.

Response 103: Staff acknowledges that there are flares being used as control devices for VOCs. These flares were granted far in the past a nd would not be allowed for such use if requested by facilities tod ay since the destruction efficiency for flares varies widely from 70 to 97 p ercent depending on atmospheric conditions and the quality of vent gas combusted. By contrast, thermal oxidizers are designed with a spe cific residence time, are able to maintain stable combustion temperatures , which results in destruction efficiencies in excess of 99%, are ther efore more suited as control devices for VOCs.

Comment 104: Excessive steam may lead to incomplete combustion and odors downwind.

Adding high BTU gases to a flare to improve the com bustion efficiency would be prohibited by the rule.

Response 104: Staff believes that use of excessive steam may ext inguish the flame and

result in potentially high volumes of odorous and/o r toxic substances being released from a flare. Boosting the BTU con tent of a vent gas with low HHV to ensure appropriate combustion efficiency is allowed as an Essential Operational Need in PAR 1118.

Comment 105: Federal Regulation 40CFR60.104 has a 160 ppm limit for H 2 S, averaged

over 3 hours. There should be mention of AQMD Rule s 1123 and 1176 and federal regulations requiring control of VOCs.

Response 105: The staff report was expanded to include the clarif ication on the H

2 S limit. The other rules mentioned do not apply to the opera tion of a flare, only to control of VOCs, and therefore will not be discusse d.

Comment 106: The report should clarify that flares prevent the r elease of raw VOCs to

the atmosphere. The report should substantiate any “concerns” that OSHA and EPA have regarding the petroleum industry and any claims made by EJ groups.

Response 106: The staff report has been revised to clarify these issues.

Comment 107: Most of the "possible alternatives" suggested for m inimizing flaring that

are listed in the staff report are speculative and lack any foundation.

Response 107 : The suggested possible alternatives are taken for m the “Episodic Release Reduction Initiative” document, issued by EPA on Ju ly 5, 2001 as aCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-31 October 2005

collaborative effort of EPA, the (Texas Commission of Environmental Quality (TCEQ), the Louisiana Department of Environ mental Quality (LA-DEQ) in cooperation with 13 petroleum refinerie s.

Comment 108: There is an economic incentive besides the environm ental benefit for flare

gas recovery (FGR), as long as the refinery has ade quate storage for the recovered gas, or else it would have to flare it.

Response 108: Staff agrees and the clarification was made in the staff report.

Comment 109: Staff seems to have relied on an article in the Oil &Gas Journal to

determine the necessary capacity of a flare gas rec overy system. The article represents the author’s opinion, not necess arily universally applicable guidelines.

Response 109: Staff has expanded the staff report to include guid elines as stated in API

521 for flare gas recovery system sizing, where it is recommended that the system be sized such that it is able to operate ove r a “wide” range of dynamically changing flow rates. Thus the opinion e xpressed in the Oil & Gas Journal article is in agreement with the API gu idelines.

Comment 110: The significant emission reductions already realize d suggest that there are

limited benefits for amending the rule.

Response 110: PAR 1118 implements the recommendation of the Gover ning Board regarding improved monitoring, recordkeeping and re cording as well as establishing annual sulfur dioxide, already realize d performance targets which will ensure that emission reductions already realized are permanent, real, quantifiable and enforceable and that further reductions are achieved in the future .

Comment 111: The concept of an alternative to a Flare Minimizat ion Plan is worthwhile;

the District should encourage refineries to opt for SOx performance
targets.

Response 111: PAR 1118 has been revised to require petroleum refi neries to comply with

a declining annual sulfur dioxide performance targe t of 1.5, 1.0, 0.7 and

0.5 tons per year for calendar years, 2006, 2008, 2010 and 2012 respectively. A Flare Minimization Plan will only be required for petroleum refineries exceeding the annual performan ce targets.

Comment 112: There is no need to require continuous HHV analyze rs since on average

this parameter is expected to be constant.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-32 October 2005 Response 112: The fact that, on average, the HHV will be constant was an assumption

used to estimate emission reductions. For calculat ing the emissions of each flare event with accuracy, a continuous monito r is the best option to

use.

Comment 113: The statements by staff regarding the cause of flar e events are misleading,

are based on tabulated data from the September 2004 “Flare Report” that are inconclusive. In addition, please explain your assumptions in calculating emission reductions that are used for c ost analysis and cost

effectiveness calculations.

Response 113: Staff disagrees. The data presented in the Prelimin ary Draft Staff Report

was based on 2003 obtained from the “Evaluation Rep ort on Emissions from Flaring Operations at Refineries” (September 2 004), which is a summary of data submitted by facilities to comply w ith monitoring and reporting requirements of the Rule 1118. The Staff Report has been updated to include data for calendar years 2001 thr ough 2004 to calculate average vent gas flow and emissions from flares. S taff has determined that the average flow and emissions data is most re presentative data for the random, cyclical operation of the flares. Staf f believes that emergencies, startup, shutdown, turnaround and fuel gas balancing events are a significant and determinant event/operation t hat should have been easily identified and reported to the AQMD. The to tal vent gas flow and calculated emissions other that sulfur dioxide and the measured total sulfur emissions, calculated as sulfur dioxide are accurate based on flow measurement, sampling, analytical, and published em ission factors. Staff has met with two of the three facilities that have been identified in the staff report as needing (projected) additional gas recove ry and treatment system capacity. These two “larger” facilities con firmed the need to install four systems totaling 13 mmscf capacity. S taff has determined that the third facility would install a system with 0.3 mmscf capacity. Staff has estimated the size of the systems based on historic al vent gas flow. These systems will minimize vent gas directed to the flar es which will reduce sulfur dioxide and other criteria air contaminants.

Comment 114: Some suggested flare controls might have been consi dered technically

feasible; however, practicality, costs and cost eff ectiveness were not necessarily considered.

Response 114: The staff report language was modified to clarify that these controls were

technologically feasible.

Comment 115: Refineries that may not have to install flare contr ols will still incur

significant costs for monitoring and other requirem ents of PAR 1118; in aggregate, complying with the rule will be a signif icant expenditure.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-33 October 2005 Response 115: Monitoring and other requirement costs were include d by staff in the costeffectiveness analysis of the proposed rule. Staff has determined that PAR 1118 is both technologically feasible and cost effe ctive.

Comment 116: The assumptions made in the staff report for determ ining costeffectiveness will need to be evaluated by individual facilities and commented upon. It is unclear whether three or fou r flare gas recovery and treatment systems are proposed and the number o f flow meters for pilots may be triple than that indicated in the sta ff report.

Response 116: Staff has estimated that four flare gas recovery a nd treatment systems

would have to be installed at three petroleum refin eries; The four systems will minimize vent gases to eight flares that curre ntly are not connected to any gas recovery and treatment systems. Staff’s an alysis is discussed in Chapter VI – Cost and Cost Effectiveness. The numb er of flow meters for the pilot gas was assumed to be one meter per flare , located on the natural gas line before it splits in individual lines for e ach pilot.

Comment 117: The case study used in the staff report to determin e the cost of a flare gas

recovery system was related to acid gas flaring. I t would not be unreasonable for staff to contact each of the eight facilities subject to the rule to evaluate the cost of necessary expenditures required by the rule.

Response 117: Staff has conducted interviews with subject facilit ies to assess compliance

with future proposed rule requirements. For better accuracy in estimating costs, staff has expanded its analysis to two addit ional case studies from the data submitted by two local refineries for the installation and subsequent operation of two flare gas recovery and /or treatment system

in 1993 and 2001.

Comment 118: Staff needs to explain how the necessary size of a recovery system was

determined.

Response 118: The staff report states that for the flare consider ed for upgrade with a

recovery system, the quarters with the highest flow between 2000 and 2003 were selected; then an average daily flow for those quarters was calculated. Based on a review of technical literat ure on flare design, the capacity of the recovery system was estimated at 2- 3 times the daily flow

rate.

Comment 119: It appears that staff may have underestimated some equipment and labor

costs; refineries could provide some data in this r espect.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-34 October 2005 Response 119: Staff used cost information supplied by the refiner y in Billings, Montana, as well as the cost data from two local refineries that installed control equipment in 1993 and 2001. Although the systems i nstalled varied in scope and size, the cost of the flare gas treatment capacity was consistent, ranging from $8.32 to $8.77 million per four millio n cubic feet of gas recovered/treated. Staff will review any cost data supplied by refineries.

Comment 120: The quoted prices for different pieces of equipment should be provided to

refineries for evaluation.

Response 120: Chapter VI - Cost and Cost Effectiveness lists the cost of control,

monitoring and labor. The PAR 1118 Administrative Record contains the actual quotes and facility-specific cost informatio n. Some of this information is considered confidential. Any non-con fidential information can be provided to interested parties upon written request.

Comment 121: When calculating the cost of equipment over time, s taff did not factor in

adjustments for inflation.

Response 121: Staff disagrees. The cost of future expenditures w as adjusted for inflation.

Comment 122: Annual costs should include taxes and insurance.

Response 122: The total installed cost includes taxes and insuran ce.

Comment 123: The annual estimated savings due to recovered gas s hould be based not on

the maximum capacity of the compressors but rather on the average flow rate of the gas recovered. Staff needs to explain the assumptions made in calculating the savings.

Response 123: Staff has revised its analysis to use the annual av erage flow rate of vent

gas recovered through the installation of additiona l vent gas recovery and treatment systems. Please refer to Chapter VI – Co st and Cost Effectiveness for a discussion on the assumptions u sed in calculating the cost savings.

Comment 124: Staff has not clarified the necessity of the rule f or ozone attainment.

Response 124: The proposed rule amendment is necessary since oxid es of sulfur (SOx)

are precursors to PM10 and PM2.5. Since the rule i s designed to minimize flaring and associated emissions, in addit ion to the SOx reductions, the rule will result in concurrent redu ctions of other criteria pollutants such as hydrocarbons, oxides of nitrogen and carbon monoxide, all of which are precursors to ozone.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-35 October 2005 WRITTEN COMMENTS RECEIVED AFTER OCTOBER 7, 2005

Comment 125: We believe that the best way to protect communitie s is to require all the

refineries to submit a Flare Minimization Plan (FMP ), which will be subject to public participation. CBE believes an F MP is the best and most transparent approach to identify unnecessary flarin g practices and equipment and procedures that eliminate routine fla ring. Performance targets, while important, do not identify unnecessa ry flaring categories and allow routine flaring within the performance target s.

Response 125: PAR 1118 establishes a multi-pronged strategy to e nsure that flaring and

associated emissions are minimized. Therefore, the performance targets should not be viewed in isolation from the other pr ovisions of the proposed amendment. Specifically, PAR 1118 has exp licit provisions that would prohibit any unnecessary or so-called routine flaring. The proposed amendment states that no flaring is allowe d other than emergencies, startup, shutdowns or essential operat ional needs. Staff went to great lengths in working with all stakehold ers to carefully define

all these terms in the rule. PAR 1118 would also r equire facilities to complete a detailed analysis of larger flare events and to identify the cause of smaller flare events

In response to the comments received, staff amended its proposal to also require facilities to conduct an audit of their fla re gas recovery and treatment capacity; identify past emission reductio n efforts and future efforts to further reduce flaring and associated em issions, and to evaluate options to reduce flaring during planned events, su ch options as slowing the depressurization of vessels, storing vent gases , etc..

In addition to the flaring minimization strategies mentioned above, PAR 1118 establishes annual facility-wide performance t argets that seek to incrementally reduce emissions starting 2006 throug h 2012. These performance reduction targets, which have been rece ntly strengthened and are now designed to exceed the AQMP targets by at least 75 percent, are accompanied by substantial mitigation fees that would be triggered in the event the performance targets are exceeded. Th e staff proposal also significantly strengthens the emissions data gather ing and monitoring procedures of the rule which will significantly imp rove the emissions data quality and a facility’s ability to refine its flar e minimization strategy.

Staff has also committed to evaluate the Bay Area A ir Quality Management District Rule 12 – Flares at Petroleum R efineries requirement to implement Flare Minimization Plans a nd the resultant installation of controls and report back to the Gov erning Board with any

recommendations.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-36 October 2005 Comment 126: In addition, the FMP should require a Best Availab le Retrofit Control

Technology (BARCT) assessment and an audit (list) o f equipment, processes and procedures to reduce flaring caused b y non-emergency, planned start-ups and shutdowns and flaring events resulting from power

curtailments.

Response 126: As stated in Response 125, staff believes that ann ual performance targets

are more effective than FMPs to reduce flare-relate d emissions from refinery flares. Regardless, staff has revised its proposal to require each facility to conduct an audit of its flare gas recov ery and treatment capacity and identify past and future control actions. Refi neries that exceed the annual performance targets are then required to sub mit an FMP. The required elements of this FMP are nearly identical to the list of elements suggested by the commenter, which includes detailed technical information regarding their flare system, policies and procedures related to emergency and planned flaring, audits of their f lare gas recovery capacities, flare gas storage and treating capaciti es.

Comment 127: PAR 1118 performance targets need to be significant ly lower and a daily

limit for both SO X and VOC should be required to limit the health impa ct of flaring activities on the community.

Response 127: The annual performance target has been lowered to 0.5 ton SO 2 per

million barrels processed effective January 1, 2012 . This revised proposed target is approximately 70 percent lower t han the baseline emissions used in the cost analysis for this propos ed rule and approximately 75 percent lower than the AQMP Contro l Measure CMB07 targets. Also, see Response 125.

Staff has determined that it is impractical at this time to establish a daily emissions target for SO 2 or VOC because the flares are operated to reduce vent gases resulting, in large part from emergencie s, and essential operational needs. These are random events and ass ociated emissions vary significantly. Based on reported emissions da ta (reductions documented since 1999), refineries have initiated p rocedures to minimize vent gas releases from shutdowns and startups.

PAR 1118 implements Step II of Control Measure CMB -07 of the AQMP. In addition, to SO 2 reductions, PAR 1118 will also reduce other criter ia air contaminants, including VOC. PAR 1118 limits t he types of flaring that are allowed, and requires facilities to minimi ze flaring. To meet the

annual SO 2 performance targets, refineries will have to reduc e the amount of vent gas directed to their flare; reducing flow to the flare will have

commensurate VOC reductions.

However, through the Board Resolution, staff commit s to evaluate the feasibility of establishing daily emissions targets and the appropriatenessCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-37 October 2005

of the annual SO 2 emission targets and whether refinements to those targets are warranted, and report back to the Gover ning Board with any

recommendations.

Comment 128: The definition for Essential Operational Needs (EO N) must be tightened

since it could be used as a loophole by refineries for bad engineering practices. Refineries should demonstrate why these operations are

essential.

Response 128: In developing the proposed definition of EON, staf f carefully analyzed which specific operations are essential and can not be reasonably controlled by the facilities subject to PAR 1118. In addition, as suggested, the EON definition has been more clearly delineated to alleviate any potential lack of clarity by requiring AQMD analysi s of the EONs for each refinery to determine if they meet the definition o f EON.

Comment 129: Monitoring is a keystone of the proposed rule and should not be

weakened. The quarterly emission reports should be made available to the public expeditiously on the District’s web site.

Response 129: Staff agrees and has committed to make these repor ts available on the

AQMD website as expeditiously as possible.

Comment 130: Notification requirements during planned events and emergencies should

be improved since many low-income residents do not have health insurance or adequate health care.

Response 130: Effective January 1, 2006, PAR 1118 requires refin eries to provide a 24-

hour telephone service to answer public inquiries a bout planned and current flare events. Staff has also committed in the Board Resolution to continue to work with industry and community member s, and other public agencies to ensure that emergency notification proc edures address the community needs.

Comment 131: A CLEAN SERVICE FLARE is currently defined as a fla re that only

combusts “clean” gases, such as natural gas, hydrog en gas and/or liquefied petroleum gas, or any other clean gases with a fixe d composition vented from specific equipment. The definition of Clean S ervice Flare should be modified to also include gases that meet the Rule 4 31.1 – Sulfur Content of Gaseous Fuels requirement of no more than 40 ppm total sulfur content.

Response 131: Staff disagrees. The original and continuing inte nt of CLEAN SERVICE

FLARE is to limit the combustion of clearly defined clean gas(es) in that specific type of flare. The requirements for clean service flares are lessCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-38 October 2005

than those for emergency and general service flares because the emissions potential is significantly lower for those flare me eting the definition of clean service flare Gases that meet the definition of Rule 431.1 can be refinery gas, which does not have a fixed compositi on. Therefore, unlike the other clean gases listed in the definition of C lean Service Flare, the composition of refinery gas can vary and therefore, so can the emissions of other combustion contaminants, such as NO X , CO, PM10 and VOC.

Comment 132: Hydrogen production plant flares should not be sub ject to PAR 1118 because, as demonstrated by the quarterly flare rep orts, they are low SO X emitters (less than 40 pounds SO X per year). Based on the reported emissions data, there are significant differences b etween a hydrogen production plant flare and a petroleum refinery fla re.

Response 132: The purpose of PAR 1118 is to reduce and minimize flaring and flaring

emissions from petroleum-related operations. Staff acknowledges that hydrogen production flares are low emitters of SO 2 ;compared to the refineries. However, flares at hydrogen plants do use refinery gas and do emit other combustion contaminants, such as NO X , CO, PM10 and VOC, that are in more significant amounts. Hydrogen pro duction plants do use flares to combust vent gases. The requirements for hydrogen production plants are limited to the demonstration of minimizi ng flaring at this type of facility.

Comment 133: Subparagraph (c)(1)(D) requires refineries to cond uct a Specific Cause

Analysis (SCA) when a specific emission or flow rat e level is exceeded. Throughout the discussions at the PAR 1118 Working Group Meetings, staff stated SCAs would be required only for those flare events that did not result from a planned operation (shutdown or startu p). We request that staff clarify this in PAR 1118.

Response 133: Staff will revise subparagraph (c)(1)(D) to emphas ize that the owner or

operator of a facility subject to PAR 1118 will hav e to conduct a SCA for those unplanned flare events exceeding 100 pounds o f VOC, 500 pounds of SO 2 , or 500,000 standard cubic feet of vent gas. For those unplanned flare events less than threshold stated above, the owner or operator needs only to state the cause of the lesser flare event.

Comment 134: We are requesting staff to clarify that under para graph (c)(3), flaring is

only allowed for “planned” shutdowns, “planned: sta rtups and “planned” turnarounds or essential operational needs.

Response 134: Staff disagrees. Operators are required to minimi ze flaring and then only

to flare vent gas resulting from specific operating conditions. The decision/need to shutdown or startup equipment that may result in theCHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-39 October 2005

need to flare, whether planned or not planned in ad vance, can be based on petroleum refineries decision to safely operate spe cific equipment. Staff believes that the declining annual SO 2 performance targets coupled with the progressive mitigation fees and required submit tal of a FMP for exceedences of the annual targets and the requireme nt to identify the cause of smaller flare events and conduct a SCA for large r flare events will require (and provide incentives for) petroleum refi neries to minimize all flaring.

Comment 135 To comply with the annual SO 2 performance targets and the requirement

to minimize flaring, some refineries will need to i nstall a flare gas recovery and treatment system(s). Paragraph (c)(4) allows refineries that will need to install flare gas recovery and treatme nt systems on more than two flares until January 1, 2010, to install the co ntrol system(s) for only those specific additional flares. Paragraph (c)(5) requires all refineries to comply with the H 2 S limit by January 1, 2009. Since the control equipment to comply with paragraph (c)(5) is the sa me equipment that will be used to comply with paragraph (c)(4), we ar e requesting that the AQMD extend the compliance date for refineries with more than two flare that need control equipment to January 1, 2010.

Response 135: Staff has revised PAR 1118 to synchronize the comp liance dates for

paragraphs (c)(4) and (c)(5).

Comment 136: The definition of EMERGENCY in PAR 1118 includes th e phrase “poor

maintenance.” We believe that the phrase poor main tenance is ambiguous

and needs clarification.

Response 136: Staff has revised PAR 1118 to clarify that poor mai ntenance is tied to

repetitive flare events from the same equipment tha t have occurred as a result of the maintenance, or lack of adequate main tenance of that equipment that caused the flare event(s).

Comment 137: The definition of EON includes flaring caused by e mergency situations

resulting from a process vessel operating pressure rising above the pressure relief valve set point. To ensure the safe operation of process vessels, we are requesting that the AQMD also inclu de in the definition emergency situations resulting from operational tem peratures rising above the process vessel temperature set point.

Response 137: Staff agrees that temperatures greater than the de sign operating

temperature specifications for specific equipment c ould result in a flaring event which is necessary for continued safe operati on of that equipment.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-40 October 2005

The definition of EON PAR 1118 has been revised to include “maximum vessel operating temperature set point.”

Comment 138: Throughout the process to amend Rule 1118, our dis cussions on the

annual SO 2 performance targets were based on the crude oil ca pacity ; the current rule version references crude processed . We request that this

clarification be reflected in PAR 1118.

Response 138: During the rule development process, industry ident ified an inequity of

using crude throughput versus crude capacity based on a fixed year of

2004 to establish annual SO 2 performance targets. In any one year, any refinery could be conducting a shutdown or turnarou nd of a major crude processing unit, which could reduce crude throughpu t for that baseline year reflecting an artificially low baseline throug hput for that refinery. Whereas crude processing capacity more accurately a llocates refinery emissions based on normal refinery operations. Loc al refineries are operating at near capacity; therefore, the differen ce in emissions impact and reductions based on throughput or capacity are minimal.

Comment 139: Please clarify that for data substitution, a facil ity can use data from a

previous similar event.

Response 139: Staff has revised the data substitution provisions of PAR 1 118 to clarify

that a facility can use flow, HHV, and total sulfur data from similar flare events that have previously occurred, can be used f or data substitution, with the Executive Officer’s approval.

Comment 140: The terms “relief valve” and “pressure relief devi ce” are used in the

definition of EON and in the requirement to conduct an annual leak survey. Please clarify the meaning for each of the se terms in PAR 1118.

Response 140: A relief valve is the all inclusive, general categ ory that includes all valves

that are designed and installed for the purpose of protecting equipment from operating pressure greater than design pressur e for the safe operation of that equipment. A pressure relief dev ice is a specific type of relief valve.

Comment 141: Staff included language in the rule that allowed s ampling flare events that

occurred within 15 minutes of each other to be coun ted as one sampling event if the facility can show that the events were from a common cause and the same process unit. Similar language should be incorporated in the

definition of SAMPLING FLARE EVENT.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-41 October 2005 Response 141: Staff agrees and has revised the definition of SAM PLING FLARE

EVENT as suggested.

Comment 142: The ARB requests that staff revise the definition of ESSENTIAL

OPERATIONAL NEED in section (b)(4) to include a mec hanism for the District’s Executive Officer to approve or reject a ctivities identified by refinery operators as an “essential operational nee d” and that staff will commit to annually evaluate the continued progress of refineries in the District to minimize their emissions of all polluta nts from flares. As part of this evaluation, District staff should provide a summary of the emissions by year by refinery. District staff shou ld use this information to appropriately develop and recommend future amendmen ts to the rule.

Response 142: Staff agrees. The definition of ESSENTIAL OPERATI ONAL NEED has

been revised to include language that essential ope rational need is “an activity determined by the Executive Officer to mee t” one of the following (specific listed activities). In addition, staff h as committed in the Resolution to review the definition of ESSENTIAL OP ERATIONAL NEED and report back to the Governing Board with any rec ommendations.

Also stated in the Resolution is a commitment by s taff to provide the

Governing Board annual status reports on overall in dustry performance, which will include a summary of the emissions by ye ar, by refinery. As with all AQMD rules, staff will review this and oth er information to appropriately develop and recommend future amendmen ts to this rule.

Comment 14 3: The attached letter from the Western States Petrol eum Association was

received at the end of the comment period. Staff w ill be prepared to respond to these comments at the Public Hearing.CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-42 October 2005CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-43 October 2005CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-44 October 2005CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-45 October 2005CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REP ORT

Proposed Amended Rule 1118 IX-46 October 2005APPENDIX A

REFERENCESAPPENDIX A – REFERENCES DRAFT STAFF REPORT

Proposed Amended Rule 1118 A-1 October 2005 Staff Report for Rule 1118 – Emissions From Refiner y Flares, SCAQMD, December 1997

Evaluation of Refinery Flare Emissions at Petroleu m Refineries, SCAQMD, September 2004

2003 Air Quality Management Plan, SCAQMD, 2003

U.S. EPA, Petroleum Refinery Initiative

U.S. EPA Enforcement Alert, Volume 3, Number 9 EPA3 00-N-00-014, October 2000

U.S. EPA, The Episodic Release Reduction Initiative , July 5, 2001

Hydrocarbon Processing, August 2002, pp76 – 80

Oil and Gas Journal, November 23, 1992, pp 70-76

Oil and Gas Journal, December 7, 1992, pp 68-72

Chevron Texaco Letter to William Norton, BAAQMD, Fe bruary 6, 20030APPENDIX B

CALIFORNIA AIR RESOURCES BOARD RESOLUTION 86-60