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 Supervisor 

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 Inspector 

 
SOUTH 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 Region 

RONALD O. LOVERIDGE 

Mayor, City of Riverside 

Cities Representative, Riverside County 

GARY OVITT 

Supervisor, Fourth District 

San Bernardino County Representative 

JAN PERRY 

Councilmember, 9th 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-45

D. FLARE MINIMIZATION PLAN REQUIREMENTS ---------------------------------III-7

E. FLARE MONITORING AND RECORDING PLANS ------------------------------ III-78

F. OPERATION MONITORING AND RECORDING ----------------------------------III-8

G. RECORDKEEPING REQUIREMENTS --------------------------------------------III-910

H. NOTIFICATION AND REPORTING -----------------------------------------------III-910

I. TEST METHODS ----------------------------------------------------------------------- III-10

J. EXEMPTIONS------------------------------------------------------------------------ III-1011
K. ATTACHMENT A -------------------------------------------------------------------- III-1011

L. ATTACHMENT B -------------------------------------------------------------------- III-1011

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 RESOLUTION 86-60 -------B-1 
E X E C U T I V E S U M M A R Y 
EXECUTIVE SUMMARY FINAL STAFF REPORT 

Proposed Amended Rule 1118 ES-1 October 2005 

Rule 1118 – Emissions from Refinery Flares was originally 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 refinery flares, also found in the 2003 AQMP. 

Pursuant to the AQMD Board’s direction upon the adoption 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 Report 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 enough to warrant the implementation of 

controls. The report suggests possible ways of reducing emissions through the prevention of 

flaring of excess fuel gas, the elimination of leaks from pressure relief devices and the reduction 

of emissions during routine flaring. These objectives can be achieved by installing flare gas 

recovery systems and gas treating systems, expanding current capacities of flare gas recovery 

and treatment systems already in place, and conducting 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 systems to measure the total sulfur gas 

concentration and the higher heating value of the flared gas, as well as the standardization of 

methodologies for flow and emissions calculations and for missing data substitution. Following 

the report presentation, the AQMD Board directed staff to amend Rule 1118 – Emissions from 

Refinery Flares, and implement Step II of Control Measure CMB-07. Step II of the control 

measure aims to reduce emissions of criteria pollutants from refinery flares by identifying and 

requiring the most feasible and cost-effective control 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 minimizing emissions of criteria air contaminants and 

their precursors from flaring activities at petroleum refineries. The proposed amendment would 

eliminate the flaring of vent gases except for those resulting from emergencies, shutdowns and 

startups, turnarounds and essential operational needs; establish operational requirements of 

diagnostic practices to minimize flaring. 

The proposed amendment establishes refinery specific performance targets for flare-related total 

sulfur emissions, calculated as sulfur dioxide, at 1.5 tons per million barrels of crude 

processeding capacity in calendar year 2006, 1 ton per million barrels of crude processeding 

capacity in calendar year 2008, 0.7 tons per million barrels of crude processeding capacity in 

calendar year 2010, and 0.5 tons per million barrels of crude processeding capacity in calendar 

year 2012, respectively, based on the 2004 industry-wide throughputprocessing capacity. During 

the rule development process, industry identified an inequity of using crude throughput versus 

crude capacity based on a fixed year of 2004 to establish annual SO2 performance targets. In any 

one year, any refinery could be conducting a shutdown or 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 crude processing capacity more 

accurately allocates refinery emissions based on normal refinery operations. Local refineries are 

operating at near capacity; therefore, the difference in emissions impact and reductions based on 

throughput or capacity are minimal. Excess flare related total sulfur emissions would be 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 than 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 annual performance targets. Excess emissions 

would also trigger the submittal of a flare minimization plan by the refinery and a possible 

issuance of a Notice of Sulfur Dioxide Exceedance by 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 recommendations from the “Evaluation Report on 

Emissions from Flaring Operations at Refineries”, will also enhance monitoring requirements to 

improve data reporting accuracy, primarily requiring 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 installed, but no later than July 1, 2007, the 

sampling frequency of flare events would be increased to daily from weekly. In addition, the 

rule will require the flare gas flow meters to be installed 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 data procedures and calculations for reporting 

emissions during monitors’ downtime periods. 

The amended rule will set new notification requirements for flaring events, as well as reporting, 

which will require quarterly reports to be submitted in an electronic format certified by the 

facility official and approved by the Executive Officer. 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 reductions achieved to date and future planned flare 

emission reductions. 

The emissions reductions associated with proposed amendments are estimated to be 1.18 tons per 

day of SO2 and 1.44 tons per day overall for all criteria pollutants, excluding carbon monoxide, 

from the emissions baseline average (2002-2004) to 2012. The cost-effectiveness is estimated to 

be between $3,9225,524 and $6,9268,620 per ton of SO2 reduced. When considering additional 

reductions in NOx, VOC and PM10, the cost effectiveness ranges between $3,1124,527 and 

$5,6757,063 per ton of pollutant reduced. 

The proposed amended Rule 1118 is considered a “project” as defined by the California 

Environmental Quality Act (CEQA), and the AQMD is the designated lead agency. Pursuant to 

CEQA and AQMD Rule 110, the AQMD prepared an environmental assessment (EA) evaluating 

potential adverse significant impacts associated with implementing the proposed amended rule. 

The EA concluded that implementing PAR 1118 would have 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 the proposed project. 
C H A P T E R I 

BACKGROUND 
CHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-1 October 2005 

A. RULE HISTORY 

The concept of reducing emissions from petroleum refinery operations was originally formalized 

in the 1982 Air Quality Management Plan (AQMP) as Measure A15. Measure A15 proposed 

increasing the use of blowdown and vapor recovery systems 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 technological feasibility, availability and 

economic reasonableness of continuous emission monitors for refinery flares. CARB granted the 

CBE request and contracted a study with an engineering firm to evaluate the feasibility of 

continuously monitoring flaring operations at petroleum refineries. The study found that no 

refinery in California accurately monitored flow rates to its flares. Several types of flow meters 

had been installed on refinery flares, but the instrumentation 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 monitoring of flare gas flow rates, gas 

composition and remote monitoring of flare plumes were practicable but would require 

substantial further development before they could be 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 relatively inexpensive cost. In 1986, CARB 

determined that monitoring devices were technologically 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 emissions. 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 install on/off status monitors and collect flare gas 

composition data so that a suggested control measure 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 results 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, especially 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 and is no longer used by the refineries. 

Since 1988, staff has tracked the development of available 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 that 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 results. 

In 1993 and 1994, staff required two refineries to conduct flare system studies as a result of 

frequent complaints of odor from emissions associated with their gas flaring operations. 

Recommendations based on these studies were implemented and resulted in a significant 

reduction in violations of Rule 402 – Public Nuisance. These studies and subsequent 
CHAPTER 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 nuisance problems associated with refinery flare 

systems. 

On February 13, 1998, the AQMD Board adopted Rule 1118 with the purpose of monitoring, 

recording and reporting data on refinery and related 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 from October 1, 1999 through December 31, 

2003, staff compiled the “Evaluation Report on Emissions from Flaring Operations at 

Refineries”, which was presented to the AQMD Board on September 3, 2004. The report 

recommended amending Rule 1118, concluding that, although refineries had made important 

progress in reducing emissions since Rule 1118 was originally adopted, flare emissions, 

especially oxides of sulfur (SOx), were still significant enough to warrant further controls. The 

report suggest various ways to reduce flare emissions, 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 emissions, 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 California 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 Monitoring at Petroleum refineries applies to 

refineries in the San Francisco area. The rule requires the monitoring and recording of the vent 

gas and the composition as well as continuously recording 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 calculated 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 Plans was adopted in June 2005, and is similar 

in some respects to PAR 1118. 

The Santa Barbara Air Pollution Control District (SBAPCD) also regulates flares based upon its 

own Rule 359 - Flares and Thermal Oxidizers, adopted on June 28, 1994. This rule applies to oil 

and gas production, petroleum refineries and related sources, natural gas services and 

transportation sources and wholesale trade in petroleum/petroleum products that operate flares or 

thermal oxidizers. Rule 359 specifies sulfur content limits, technology-based standards for flares 

and thermal oxidizers, and emission standards for oxides of nitrogen (NOx) and reactive organic 

compounds (ROC) and operational limits. The rule also incorporates a Flare Minimization Plan, 

monitoring, recordkeeping, reporting and source test requirements for ground flares. However, a 

review of the staff report for Rule 359 indicates that there are no petroleum refinery operations in 

Santa Barbara similar to the petroleum refinery operations in the South Coast Air Basin and that 

Rule 359 applies to non-refinery petroleum operations 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 (VCAPCD) 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 petroleum operations and AQMD staff is not 

aware of any petroleum refinery operations in the jurisdiction of VCAPCD. 

C. U.S. EPA REGULATIONS (EPA) 

The EPA New Source Performance Standards (NSPS), under 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 Subpart 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 pilot flame present at all times the flare is in 

operation and observe certain limits for the net heating 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 – Standards 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 regulation limits the concentration of the 

hydrogen sulfide (H2S) in the vent gases routed to flares to 160 ppm, averaged over three hours. 

However, vent gases that are combusted due to startup, shutdown, process upset or relief valve 

leakage are exempt from this requirement. 

In 1998, EPA launched a program called “The Petroleum Refinery Initiative” consisting of a 

series of investigations at refineries under a multi-faceted compliance approach. One of the 

refinery activities targeted by the investigation was excessive flaring of acid gas (gas with high 

H2S content generated during the oil refining process and from the sour water stripper) that 

results in large amounts of sulfur dioxide being released 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 Clean 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 air pollution practices also include investigating 

the root cause of a flaring incident and taking corrective actions to prevent recurrence in the 

future. In the newsletter, EPA states that a properly designed, operated and maintained flare gas 

recovery system is one way to minimize or avoid flaring. 

In an effort to reduce excessive flaring of acid gas and emissions of SOx and NOx, EPA, to date, 

has entered into 15 global settlements with petroleum refiners representing more than 65% od 

domestic refinery capacity. The settlements now cover 76 refineries and conferences are 

currently ongoing with 11 more petroleum refiners who represent an additional 24 refineries. 

Refineries effected by the global settlements are subject to a consent degree requiring them to 

prepare and submit plans to minimize hydrocarbon flaring, conduct root cause analysies of 

flaring events and implement control options such as installing flare gas recovery systems, 

rerouting hydrocarbon streams away from flares or making 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 mitigation actions, pay fines and provide affirmative 

relief by completing environmentally beneficial projects. These aforementioned requirements of 
CHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-4 October 2005 

the consent decrees are, in part, the concepts on which 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 Products 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 60.104 for combustion devices. 

D. EQUIPMENT AND OPERATION 

Flares are combustion devices used extensively in the 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 devices to reduce the potential for fires and 

explosions due to unburned gaseous hydrocarbon releases. Blowdown systems are designed and 

installed at petroleum refineries to provide for safe containment or safe release of liquids and 

gases that must be disposed of in the refining process. Such systems generally consist of a series 

of venting manifolds which lead from the process equipment to a blowdown recovery system 

(i.e., storage tank, wastewater system, compressor) and flares. 

Flares can be elevated like a stack where the combustion, 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 ground level in a shrouded, refractory lined 

enclosure. Both types of flares are capable of destruction of hydrocarbons and other combustible 

gases. However, as with any type of combustion equipment, they generate air pollutants such as 

NOx, SOx, carbon monoxide (CO), and particulate matter (PM), in addition to the release of 

reactive organic gases (ROG) which have not been completely 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, temperature 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 ambient air to better mix with the hydrocarbons. 

The federal requirement allows refinery flare operators 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 that can be burned without smoke and is also 

expressed in pounds per hour of a specific gas composition, temperature and pressure. 

Typically, flares are operating in a smokeless manner in a range up to 20 percent of their 

maximum design flow; at higher flows the size of the 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 hydrocarbons 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 operation. A stream of combustible gas, called 

purge gas, is continuously flowing into the flare to prevent air from entering the flare header 
CHAPTER 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 burning 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 equipment 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 categories: 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 sulfur 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 areas 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 flare is usually in a standby mode and does not 

create emissions except for those associated with pilot 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 sumps and equipment leaks, startups and 

shutdowns, turnaround activities, etc. 

E. APPLICABLE RULES REVIEW 

In addition to Rule 1118, flares are also subject to 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, are subject to 40CFR 60 Subpart J - New Source 

Performance Standards (NSPS); flares may also be subject to 40CFR 60.18 – General Control 

Device Requirements if either vent gases from storage 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 flare gas with air. Within the smokeless range of 

operation of a flare, if not enough steam is used during 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 percent opacity for periods exceeding more 

than three aggregate minutes within any hour. 40CFR 60.18 requires flares to have no visible 

emissions except for periods of time up to five minutes during two consecutive hours. The two 

standards are not identical, since they use different methods to determine visible emissions: Rule 

401 uses USEPA Reference Method 9 and 40CFR 60.18 uses 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 potentially resulting in a public nuisance. Odors 

could also be emitted if the heat content of the flared 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 to 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 the flare pilot gas and the purge gas, which 

maintain the flare operating continuously, is limited to a concentration of 40 ppm calculated as 

H2S, 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 purge 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 regulation, 40CFR 60 Subpart J, has a limit of 

160 ppm H2S, averaged over a rolling three hour period, for purge and pilot gas combusted in a 

flare, whereas emergency vent gases and relief valve leakage are exempt from this requirement. 

F. AFFECTED FACILITIES 

The types of refinery operations subject to this rule are: petroleum refineries, sulfur recovery 

plants that recover sulfur compounds from acid gases and sour water generated by petroleum 

refineries, and hydrogen production plants that produce hydrogen from refinery gas and supply it 

for petroleum refinery operations. Presently, in the AQMD, there are seven operating petroleum 

refineries, one sulfur recovery plant and one hydrogen production plant, with a total of 10 

distinct physical locations. The following facilities 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 (Los Angeles Refinery) 

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

• ExxonMobil Oil Corporation (Refinery) 

• Paramount Petroleum Corporation (Refinery) 

• Ultramar Inc. (Refinery) 

Table I-1 shows the subject facilities and an inventory of their flares. Since ConocoPhillips and 

Equilon Shell Oil submit one quarterly Rule 1118 report for both their facilities (Carson 
CHAPTER I - BACKGROUND FINAL STAFF REPORT

Proposed Amended Rule 1118 I-7 October 2005 

Plant/Wilmington Plant and L.A. Plant/SRU, respectively) 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 23 
C H A P T E R II 

CONTROL TECHNOLOGY 
CHAPTER II – CONTROL TECHNOLOGY FINAL STAFF REPORT

Proposed Amended Rule 1118 II-1 October 2005 

A. CONTROL OPTIONS 

At petroleum refineries, flares have historically been used to dispose of combustible gases 

resulting from emergency relief, overpressure, process upsets, startups, shutdowns and other 

operational and safety reasons to prevent direct release of toxic and /or odorous substances to the 

atmosphere. In recent years, U.S. Occupational Safety and Health Administration (OSHA) and 

U.S. EPA have become more concerned with refinery operation, resulting in tighter regulations 

on safety and emissions control and enforcement actions 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 surrounding communities, leading to an increase 

in the involvement of community and environmental groups in the regulatory process of 

controlling refinery flares. 

There are two alternatives to control flare emissions: 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 post-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 control devices impractical for elevated flares. 

Controlling flue gases would be very costly under these 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 formation and reduces the amount of vent gases 

routed to refinery flares, or recover the vent gases prior to combustion at the flare. 

B. FLARE MINIMIZATION PLANS

Refineries can obtain meaningful results in their effort 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 vent gas generated by process units at refineries. 

Listed below are several possible alternatives of minimizing flare emissions that could be 

incorporated in flare minimization plans: 

- Better engineering and equipment design

A reevaluation of existing process flow and equipment allowing changes in operating 

parameters such as temperature and pressure settings may result in reduced volumes of 

vent gas being generated. 

- Diverting or eliminating streams vented to the flares

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 reliability

By installing redundant equipment, in case of a breakdown, the spare can be put on line, 

thus avoiding a process upset that results in gas being routed to the flare. 

- Installation of flow monitors for vent gas generated at each process unit

Installation of flow monitors on process units flare headers is a useful tool that allows the 

operator to quickly identify the origin of increased flare flows and take immediate 

corrective actions, potentially avoiding a flare event. 
CHAPTER II – CONTROL TECHNOLOGY FINAL STAFF REPORT

Proposed Amended Rule 1118 II-2 October 2005 

- Periodic monitoring maintenance programs of pressure relief valves that identify leaks to 

the blowdown system, such as acoustic or thermal surveys

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 significant 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 equipment 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 maintenance and repair in order to reduce 

flare emissions. This program is especially valuable 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 turnaround. 

- Conducting Specific Cause Analysis of significant flaring incidents

This investigative procedure is used to identify the cause of significant flaring events and 

whether any equipment and/or operational changes are needed to prevent future 

reoccurrences. Once the investigation is completed, corrective measures need to be taken 

and implemented. It is important to communicate the findings to all parties involved and 

create a mechanism to track corrective actions in order 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 events on the environment and 

teaching them procedures that minimize venting to flares needs to be part of the facility’s 

training program and should have full management support. 

- Optimization of turnaround schedules

Coordination of turnaround schedules for different units can result in reducing flaring 

activity and minimize emissions associated with these periodic maintenance activities. 

- Developing startup and shutdown procedures that do not use flaring

For certain units, it is possible to develop procedures 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 volume 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 environmental concerns, this flare gas recovery system 

control option is becoming popular, especially since there is an economic incentive due to 

recovery of valuable gas. The system usually consists of a set of compressors, a heat exchanger, 

a phase separator and associated pumps. The vent gas 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 generally consists of a header or manifold that 

collects the flare gases from various sources, a knockout 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 system unit connection is typically located 

between the knockout vessel and the flare water seal. 

The primary control variable of the flare gas recovery system is the flare system pressure. As 

vent gases from various process units collect in the flare header, pressure reaches a 

predetermined pressure control set point, triggering the start up of the recovery compressor. The 

suction pressure of the compressor is set lower than that of the water seal, such that under normal 

operation, there is not enough pressure in the flare 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 the flare system is maintained in the event of 

process upset conditions. 

In order to have a high recovery rate, the compressor station should be sized with a capacity two 

to three times the normal flare flow (Oil and Gas Journal, December 7, 1992). API Guideline 

520 states that the normal flow rate is some average 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 AMENDMENTS 
CHAPTER 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 establish diagnostic practices to 

minimize flaring. 

- Prohibit the flaring of gases other than those resulting from emergencies, shutdowns, 

startups, turnarounds and essential operational needs 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 exceedances of a refinery specific 

performance target. 

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

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

- Add and modify requirements for the Flare Monitoring and Recording Plan. 

- Add and modify requirements for the operation monitoring 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 Attachment A – Flare Monitoring 

System Requirements. 

- Modify and enhance Attachment B – Guidelines for Calculating 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 unavoidable 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 emergency. 

- Essential Operational Need – is defined as flare event caused by a specifically listed 

operational or maintenance related activity where due its quality or quantity, the vent gas 

cannot be reasonably recovered, treated, used or delivered 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 contractual 
CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-2 October 2005 

gas purchase agreement, or due to sudden shutdown of a combustion device for 

reasons other than operator error or poor maintenance; 

 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 combustion devices, upsetting the 

process). Whenever the vent gas has a low BTU content 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 service flare or a general service 

flare; 

 Intermittent minor venting from sight glasses, compressor bottles, sampling 

equipment and pumps or compressors casings; 

 Emergency situations when the pressure vessel operationg pressure rises above 

the set point of the pressure relief valvedevice(s). 

- Flare Gas Recovery System - is defined as any system designed to prevent or minimize 

the combustion of vent gases in a flare, composed of, but not limited to, compressors, 

heat exchangers, pumps, water seal drums, etc. 

- Flare Minimization Plan is defined as a document that meets specific rule requirements in 

subdivision (e). 

- Natural Gas - is defined as a mixture of gaseous hydrocarbons, 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 annual performance target is exceeded and 

remains in its compliance record. 

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

- Purge Gas - is defined as a continuous gas stream introduced in the flare header, flare 

stack and /or flare tip for the purpose of maintaining a positive flow that prevents that 

prevents the formation of an explosive mixture due to ambient air ingress. 

- Sampling Flare Event – this definition replaces Recordable 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 parameters of a flare. Sampling flare events 

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

demonstrate to the satisfaction of the Executive Officer that the events had a common 

cause and the release of vent gas originated from the 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 investigation used to identify the cause of 

certain flare events with emissions exceeding either 100 pounds of VOC or 500 pounds 

of sulfur dioxide, or 500,000 standard cubic feet of flared gas, provide corrective 

measure(s), and prevent recurrence of a similar event. 
CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-3 October 2005 

- Startup - is defined as the procedure by which a process unit or piece of equipment 

achieves operational status. The attainment of normal operational status may be 

substantiated by parameters such as temperature, pressure, feed rate and also by products 

meeting quality specifications. 

- Turnaround - is defined as a planned activity involving shutdown and startup of one or 

several process units for the purpose of performing periodic maintenance, repair, 

replacement of equipment, or installation of new equipment. 

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

The following definitions were modified: 

- Flare Event - clarifies that an event takes place when vent gas is combusted in a flare and 

ends when the vent gas velocity drops below 0.12 feet 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 total sulfur analyzer. 

- Gas Flare - was shortened by removing “Gas” since this rule addresses flares used to 

dispose of gases only. 

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

- Representative Sample - was modified by deleting part 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, including those at non-contiguous locations 

operating flares, shall be considered as one petroleum refinery. 

- Sulfur Recovery Plant - was expanded to also include 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 into 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, arranged by the date they become effective. 

The following requirements become effective on January 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 longer 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 directly to flares must have an annual 

inspection using acoustical or thermal surveys in order to detect leaks. The requirement 

applies only to PRDs venting directly to flares (gases that are not collected or controlled 

with flare gas recovery and treatment. The inspection has to be conducted within 90 days 

prior to a scheduled turnaround, if one is scheduled for that calendar year. 

- The owner or operator of a flare having a flaring event 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 Specific 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 and therefore no investigation is 

necessary. 

- The owner or operator of a flare has to identify the cause, where feasible, of any flare 

event where at least 5,000 standard cubic feet of vent gas was released to the flare. For 

some smaller releases, the owner or operator may not have sufficient data to determine 

the cause of the flare event. 

The following requirements are effective January September 1, 20076: 

- 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 recovery 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 such 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 that only vent gases resulting from an 

emergency, shutdown, startup, turnaround or essential operational need are combusted 

and have to minimize flare emissions during these events. 

- Staff acknowledges that some refineries will install gas recovery and treatment system(s) 

to comply with this requirement, and that the refineries 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, or January 1, 2010 if more than two 

flares are to be controlled, provided that those refinery operators submit an application to 

construct and operate the control equipment for approval 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 leakage, cannot exceed 160 ppm H2S 

concentration, averaged over three hours. Staff believes that by January 1, 2009, most 

refineries will have sufficient vent gas recovery and treatment capacity to be able to 

comply with this requirement during essential operational needs, for which this 

requirement would essentially apply. Refineries needing to install gas recovery and 

treatment system(s) for more than two flares to comply with the requirements to limit and 
CHAPTER 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 H2S 

concentration in the vent gas, will be granted a compliance 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 operate 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 those resulting from emergencies, shutdowns, 

startups, turnarounds, and essential operational needs. It also sets decreasing flare total sulfur 

performance targets for the allowed flaring activities, calculated and reported as sulfur dioxide 

(SO2), for subject refineries, based on 2004 throughputscrude processing capacities, with the 

purpose of capturing emission reductions achieved since the rule was adopted and to ensure that 

these and future emission reductions are enforceable, permanent, real, and verifiable. During the 

rule development process, industry identified an inequity of using crude throughput versus crude 

capacity based on a fixed year of 2004 to establish annual SO2 performance targets. In any one 

year, any refinery could be conducting a shutdown or 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 crude processing capacity more accurately 

allocates refinery emissions based on normal refinery operations. Local refineries are operating 

at near capacity; therefore, the difference in emissions impact and reductions based on 

throughput or capacity are minimal. Total SO2 reductions will be determined annually for each 

calendar year. To determine compliance with the SO2 Performance Targets, the annual 

emissions will be divided by the 2004 refinery throughputcrude processing capacity. The 

performance targets proposed and the corresponding milestones, starting with year 2006, are as 

shown in Table III - 1: 

Table III– 1 

SO2 Performance Targets 

(Tons per million barrels crude processeding capacity)

Year 2006 2008 2010 2012 

SO2 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 ton where the exceedance is up to ten percent 

over the performance target, $50,000 for each and every ton where the exceedance is greater than 

ten percent but no more than twenty percent over the 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 excess emissions. 

It is expected that refineries will implement the procedures and install the equipment necessary 

to achieve compliance with the annual sulfur dioxide 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 performance target in any one year. The mitigation 

fee provision offers the refinery an alternative compliance option in that circumstance and allows 

the opportunity for the refinery to take those actions necessary to ensure the performance targets 

are met in future years. For each year an annual performance target is exceeded, the Executive 

Officer may also issue a Notice of Sulfur Dioxide Exceedance 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 (SO2) emissions and flare vent gas flows for the two facilities 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

Refinery SO2 (tons/year) 59 76 27 54 

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

Refinery SO2 (tons/year) 77 45 19 47 

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

As part of their 2004 Emissions Fee Billing (EFB) submittal, .Refinery 1 and Refinery 2 reported 

processing of approximately 95 and 51, million barrels of crude oil during the 2003-2004 fiscal 

year, respectively. Table III-3 is a summary of the permitted annual crude oil throughput (in 

million barrels of crude oil per year), the 20102 performance target for each petroleum refinery 

target (in tons SO2) and the amount of SO2 exceedance at twenty percent over the 2012 annual 

SO2 performance target of 0.5 tons per million barrels of crude oil. 

Table III – 3 

Analysis 

Facility 

Annual Crude 

Oil Throughput 

(million barrels)

20102 Annual SO2

Performance Target 

(tons) 

20% SO2

Exceedance 

(tons) 

Refinery 1 93 47 10 

Refinery 2 50 25 5 

To estimate the vent gas flow associated with the 10 tons and 5 tons of sulfur dioxide excess 

emissions, staff will use the ratio of three year average 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 the approximate vent gas flow for the sulfur 

dioxide excess emissions. 

Therefore, the flow associated with the yearly exceedance, 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

Flow1 = 10 tons * 755 mmscfy / 54 tons = 140 mmscfy = 0.38 mmscfd

Refinery 2: 

Flow2 = 5 tons * 307 mmscfy / 47 tons = 33 mmscfy = 0.09 mmscfd 

To prevent future exceedances, it is assumed that the two facilities would have to install flare gas 

recovery and treating systems to control this amount of vent gas associated with the SO2

exceedance. The capacity of the control system should 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 performance target is: 

Refinery 1 

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

 = $164,920 per ton SO2 reduced 

Refinery 2 

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

 = $78,120 per ton SO2 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 previously stated, the operation of flares and 

resultant emissions are variable based upon periodic events. Therefore, a mitigation fee of 

$100,000 per ton of SO2 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 treatment and therefore would be considered 

reasonable. 

D. FLARE MINIMIZATION PLAN REQUIREMENTS 

Each refinery that exceeds an annual performance target 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 taken 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 equipment 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 turnarounds and during essential 

operational needs; and 

- A complete description of a flare gas recover and treatment system(s) to be installed to 

meet the performance target(s). 

The AQMD will make available the Flare Mininimization 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, in which it will detail additional measures for 

preventing future exceedance. If the Executive Officer 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 Violation. 

A facility may, without exceeding the performance targets and on a voluntary basis, submit a 

Flare Minimization Plan for approval to the Executive 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-operating facility that starts operating after the 

rule is amended will have to submit a Flare Monitoring and Recording Plan and appropriate fees 

at least 180 days prior to initial start-up and notify the AQMD seven days prior to startup or 

resumption of operations. The current monitoring plans submitted pursuant to Rule 1118, 

adopted February 13, 1998 will be in effect until the 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 upgraded 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 amendmentJanuary 1, 2006: 

- The presence of a flare pilot flame has to be monitored using a thermocouple or an 

equivalent device, such as infrared or ultraviolet cameras. 

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

the flares for visible emissions. The video recording will have to be maintained at the 

facility for a period of 90 days and submitted to AQMD personnel upon request.

Effective January 1, 2006:

- Facilities subject to this rule are required to take a daily representative sample. Only one 

representative sample is required each day for flare events that are not sampling flare 

events. A representative sample collected for a sampling flare event on that day may be 

used to satisfy this requirement. For flare events lasting 15 minutes or less, no 
CHAPTER 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 based on verifiable records of flare water 

seal level and/or other parameters as approved by the 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 equipped with date and time stamp to monitor 

the flares for visible emissions. The video recording will have to be maintained at the 

facility for a period of 90 days and submitted to AQMD personnel upon request.

Within six months from approval of the Flare Monitoring 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 eliminate problems related to sampling and 

data accuracy, as recommended in the Evaluation Report on Emissions from Flaring 

Operations at Refineries. The use of analyzers will provide a more realistic picture of 

flare emissions by providing more data points for the 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 samples. Refineries must begin 

monitoring within six months from approval of the Revised Flare Monitoring and 

Recording Plan by the AQMD. Until the analyzers are 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 from the current weekly sampling 

requirement) in addition to collecting representative samples during a sampling flare 

event, using a step by step procedure outlined in Table 21 (Effective Until June 30, 

2007), footnote 4 of the proposed amended rule. However, if no flare 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 data procedures included in an appendix 

to the rule and estimated emissions have to be reported as such in the quarterly flare 

report. 

Effective January 1, 2007: 

- Flow meters are required for monitoring and recording 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 flow to the flare. This requirement was 

necessary since there are flow meters located upstream 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 are also problems at low flows, when 

ambient heat creates a gas flow inside the large diameter flare headers, resulting in a 

“ghost” reading on the flow meter. In order to eliminate these problems, flow meters 

have to be installed downstream of water seals or, if this is not feasible due to physical 
CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-10 October 2005 

constraints, they need to be equipped with totalizing 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 not 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 recordings of all flares be kept for 90 days and all 

other records mandated by the rule be kept for a period of five years.

H. NOTIFICATION AND REPORTING 

The proposed amendment has new notification requirements and enhanced reporting 

requirements, as follows: 

- Facilities subject to this rule will have to provide a 24 hour telephone service for access 

by the public for inquiries about flare events. The 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 telephone within one hour of a flare event 

exceeding 100 pounds of VOC, 500 pounds of total sulfur 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 within 30 days. 

- A 24-hour advance notice to the AQMD is required for 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 cubic 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 facility official that the information is 

true and accurate. Emissions will have to be calculated 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 surveys 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) conducting the surveys. 

I. TEST METHODS 

The following are additions and modifications to this 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 dioxide may be monitored with a semicontinuous total sulfur analyzer meeting or exceeding the requirements in Attachment A 
CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-11 October 2005 

to the rule. Until such time as the monitor is certified 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 verified annually according to 

manufacturer’s procedures. 

- For determining visible emissions from flares, refineries 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-related total sulfur emissions, calculated as 

sulfur dioxide, resulting from external power curtailments excluding interruptible service 

agreements, natural disasters and acts of war or terrorism, from the annual facility emissions 

established under Performance Targets since these events are beyond the reasonable control of 

the refinery operator. In addition, has added language to clarifying that sampling and analyses of 

representative samples for higher heating values and 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 additional 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 butane, thus making reporting uniform among 

refineries, sulfur recovery plants and hydrogen production 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 flare during the flow meter and/or analyzer 

outage or a sample was not taken and analyzed. Footnote 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 verifiable records of flare water seal level and/or 

other parameters as approved by the Executive Officer in the Flare Monitoring and Recording 

Plan or Revised Flare Monitoring and Recording Plan. 

Once the methodology and parameters used to demonstrate that the vent gas is not being routed 

to a flare is included in the approved Flare Monitoring 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 substituted 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 parameters, including reference to similar events that 

occurred previously. The goal of the data substitution methodology was to provide a 

conservative estimate based on the operational history of the flare. 
CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-12 October 2005 

( ) MP = PMax − × PMax − PAvg 5.0 Equation (1) 

 where: 

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

 PMax = Maximum measured and recorded value of the missing parameter over a 5 

year period. 

 PAvg = Average measured and recorded value of the missing parameter over a 5 

year period. 

This methodology was developed based on the reported flare event data for refineries operating 

in the South Coast Air Basin (including a sulfur plant) between October 1, 1999 through June 30, 

2005. The data reported by the refineries and utilized in the analysis included: 

• The duration of each individual flare event; 

• The total volume of gas released during the flare event; 

• The higher heating value of the flared gas; 

• Basis for which the higher heating value (HHV) of the 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 measurement was discarded. It was discarded so 

the entirety of the data being analyzed would be representative of actual flare events. This would 

prevent variability in the data being attenuated through the introduction of substitute data based 

on an average. 

The data for each recorded flare event between October 1999 and June 2005 for each flare were 

plotted as a function of time. These plots revealed: 

• The concentration of total sulfur, expressed as sulfur dioxide, in the flared gas showed a 

high degree of data scatter that varied randomly over 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 potential range of 39,000 MSCF. 

• The HHV of the flared gas exhibited the lowest degree 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 population of data posed the following 

difficulties in creating a methodology for estimating substitute data: 
CHAPTER III –PROPOSED AMENDMENTS FINAL STAFF REPORT

Proposed Amended Rule 1118 III-13 October 2005 

• Requiring the facility to report substitute data based 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 result of the majority of the flares having 

a single point outlier for each data set that was orders of magnitude greater that the 

majority of the population. 

• Requiring the facility to report an average value would 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 exhibited 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 short 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 demonstrated cyclic behavior. Coincidently, the 

refineries have stated that they turnaround their units every five years. This behavior 

showed surges in the value of a given parameter, followed by a lull. Any data that were 

estimated based on the lull period would provide under-estimated results during the 

surge, which is contrary to the goal of the substitution methodology. 

The method shown in Equation (1) accounted for the problems listed above. This method 

accounts for the average value of the population with respect to the deviation from the mean. 

The use of a five year (20 quarters) averaging period 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. The 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 that generally captured 98% of the population of 

data, but was sufficiently less than the single point outliers that were present in some populations 

of data. 
C H A P T E R IV 

EMISSION INVENTORY 
CHAPTER 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 flares categorized as emergency flares, clean 

flares and general purpose flares. The breakdown by flare, as reported in the September 2004 

Evaluation Report, including flare system design and 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 Flare 
CHAPTER IV – EMISSION INVENTORY FINAL STAFF REPORT

Proposed Amended Rule 1118 IV-2 October 2005 

B. EMISSION INVENTORY 

According to the 2003 AQMP, the SO2 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 published, 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 assumes concurrent emission reductions for 

the other criteria pollutants. The proposed amendment 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 per 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 emissions are different from the annual emissions 

reported under EFB program, where reported flare emissions are calculated based on crude 

throughput and the amount of elemental sulfur produced at each facility, using appropriate 

emission factors. 

A summary of the quarterly reports, showing Rule 1118 annual flare emissions, from 20010

through 2003, extracted from the September 2004 report presented to the Governing Board and 

the reported flare emissions for 2004 is shown in Table 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 have decreased in the years following the 

adoption of the rule in 1998, as the refineries became more sensitive to flaring issues and 

implemented voluntary measures to reduce the vent gas 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 not 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 from 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 readings that led to reporting inflated 

emissions. An investigation of the problem concluded that the flow meter located before the 

water seal was counting both the flow towards the flare and the reverse flow to a recovery 

compressor, although no actual vent gas was going past the water seal and combusted in the 

flare. The refinery relocated the flow meter in the 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 from 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 emissions data submitted to the AQMD since 1999 

clearly shows a downward trend, it also shows variability 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 operational needs. Since these events can vary year 

to year, so will the number and type of flare events and the flare emissions. Therefore, it is 

appropriate to average the annual flare emissions to develop a representative baseline emissions 

inventory for emissions reductions and cost analysis calculations. Based on an analysis of the 

data submitted and discussions with refinery representatives, staff concluded that the 2000 data 

may not be very reliable due to compliance issues and because of problems related to the 

implementation of this recently adopted flare monitoring rule. Also, one refinery installed 

additional vent gas recovery in 2001; this installation 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 NOX NMHC CO PM10 SO2 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 20012 through 2004. The Rule 1118 average reported SO2 emissions is 613 tons or 

1.68 tons per day, while the average emissions total 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 rule and its cost effectiveness. 
C H A P T E R V 

EMISSION REDUCTIONS 
CHAPTER V – EMISSION REDUCTIONS FINAL STAFF REPORT

Proposed Amended Rule 1118 V-1 October 2005 

As shown in the previous chapter, flare emissions have 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 reductions are substantial, staff believes that 

further emission reductions are feasible for the industry. In September 2004, after staff presented 

the “Evaluation Report on Emissions from Flaring Operations at Refineries”, the AQMD 

Governing Board directed staff to initiate the amendment 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 backsliding in the emissions that have been 

reduced over the last several years. 

The proposed amended rule requires refineries to gradually 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 million barrels of crude processed in calendar 

year 2012. The total processing capacity of the refineries in the basin, based on industry data, is 

approximately 1 mmbbl/day, therefore projected annual sulfur dioxide emissions 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 mitigation fee provision in place. However, staff 

believes that by year 2012, flare sulfur dioxide emissions 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 sent 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 proportionally lower emissions of NOx, CO, ROG and 

PM10. 

Refineries E and H have reported significantly higher 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 informed 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 committed to the AQMD to increase its vapor 

recovery and gas treating capacity and to install flare gas recovery systems to significantly 

reduce flare emissions. 

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

20012 through 2003, which can be found in Table V – 1. This information was based on data 

from the September 2004 “Evaluation Report on Flares at Petroleum Refineries.” For the same 

reason as explained before, the data for year 2000 and 2001 waswere 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 refinery 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 2002-2003

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

Non- Emergency 

Turnaround Activities 240,031 10.37

Recordable 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 represent approximately 5347 percent of the total 

flow. The remaining 453 percent represents the volume of non-recordable and unknown nonemergency events that has a potential to be recovered/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 report 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 treatment 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 gas 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 anticipates other refineries will initiate additional 

measure to minimize vent gases being sent to the flares. Therefore, with the increase in vent gas 

recovery and treatment capacity and additional voluntary 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 reduced 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 20012-2004 annual emissions averages 

and using the emissions reduction analysis above, the projected 20102 flare emissions are as 

shown in Table V – 2. Although actual sulfur dioxide emission reductions are anticipated to be 

significantly higher than what it is assumed in this table, for the purpose of this analysis, 

emission reduction estimates were based on the 20102 annual sulfur dioxide performance target 

of 0.75 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 

SO2 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-EFFECTIVENESS 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 chapter presents an overview of the costs 

refineries will have to incur in order to comply with 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 and to minimize flaring, it is assumed that some 

refineries will need to install new flare gas recovery and gas treating systems, whereas other 

refineries may have to increase their existing flare 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 the “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. Based on the last four years, the other four 

refineries have adequate flare gas recovery capacity 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 refineries where the flow meters are located 

before the water seals at flares equipped with flare gas recovery compressors will need to 

upgrade the flow meters with totalizing and low flow measurement capability to accurately 

indicate the actual vent gas flow to the flare. Also, flow meters will need to be installed on all 

flares for the measurement of the purge and pilot gas flow. All refineries will have to equip their 

emergency and general purpose flares with heat content 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 included 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 Specific Cause Analyses. In Scenario 1, it will be 

assumed that all of refineries will install heat content and total sulfur analyzers. In Scenario 2, it 

will be assumed that only heat content analyzers are 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 flare gas recovery systems (for eight flares) 

will install a total of four flare gas recovery and gas treating systems. Staff assumes that 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF REPORT

Proposed Amended Rule 1118 VI-2 October 2005

at the first refinery, two systems will be installed; one system will control three flares and 

the other two flares. Another system serving a pair 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 for the emergency/general service flares; 

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

- Refineries will install 50 purge/pilot gas flow meters (one for each emergency/general 

service flare); and 

- Refineries will upgrade the emergency/general service flare flow meters with totalizing 

and low flow capability. 

A synopsis of the projected rule required changes for 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 serving two flares 

** Common flare gas recover and treatment system serving three flares 

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

The cost for a flare recovery and gas treating system will be estimated based on data submitted to 

the AQMD by two local refineries as part of an application for permits to construct and operate, 

and data obtained from the Montana Department of Environmental Quality (DEQ) for a 

petroleum refinery located in Billings, Montana. 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 installed 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 studied 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, the 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 Nelson 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 one 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, the normalized cost for a flare gas recovery 

compressor per one mmscfd was $1.53 million. In 2005, this cost, based on the Nelson Farrar 

Index, would be $1.645 million. No gas treating system was installed in conjunction with this 

flare gas recovery system. However, based on the two 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 to 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 flare gas recovery systems, then calculated the daily 

average flows for those quarters. API 521 guidelines 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 the 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 adequate. 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 with a capacity of 0.3 mmscfd for its flare would 

be adequate. 

The costs to install the flare gas recovery and treating 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 to comply with PAR 1118. The costs are 

summarized in Table VI – 2: 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 installations, 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 Flows 

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 and 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 transmitter 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 for software, instrumentation, and taxes is 

therefore estimated at $2,858 per flow meter and for 50 flow meters the total cost will be 

$142,900. 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF REPORT

Proposed Amended Rule 1118 VI-5 October 2005

The proposed rule requires the flare gas flow meters 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 at $70,775 each by Cosa Instruments. 

Assuming that the total installed cost, including a sample conditioning unit, shelter, piping, 

electrical, taxes, permitting and certification will be $150,000, the total installed cost for 23 

analyzers is estimated at $3,450,000. 

The cost of a total sulfur analyzer, including taxes, 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 system is estimated at $5,000. Therefore the 

total installed cost is estimated at $84,308 each and $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 assumed that the flare gas recovery systems, 

gas treating systems and flow meters have an equipment 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 cost effectiveness, the cost of the analyzers will 

be referenced to a 25 year equipment life. For this purpose, it is assumed that during a 25 year 

period three sets of analyzers will have to be purchased. The cost of this expenditure is 

calculated below: 

 Canalyzers = 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 corresponding 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 20 years. The cost in today’s dollars, at 4% real 

interest rate at twenty years using the corresponding 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: 

Canalyzers = C1 + C2 + C3 = $11,489,527 

The flare gas recovery and gas treatment systems will require a permit to construct and operate 

from the AQMD. The permit application evaluation fee 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 STAFF 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 consisting 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 heating 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 VI-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 associated with the newly installed equipment (parts 

and maintenance), surveys of pressure relief devices, conducting flow meter tests and Specific 

Cause Analyses. 

Assuming that annual cost, such as for parts, maintenance, repairs, calibration gases, taxes, 

insurance and power represent 10 percent of the capital cost (including only the initial purchase 

of analyzers), the annual cost is estimated as $3,482,886. 

Another annual cost will be for conducting surveys of the pressure relief devices connected to 

flares. These surveys can be conducted concurrently with the Rule 1173 quarterly inspections 

and it is estimated that on average an additional 200 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 accuracy 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 STAFF 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 conduct 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 pounds of sulfur dioxide would not represent 

an additional cost since this is a requirement under federal law. 

A review of the 2003 flaring events meeting these criteria stated in the previous paragraph found 

980 flare events that had less than 500 pounds of sulfur 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 facilities subject to PAR 1118 are not required 

to submit an SCA for these categories of vent gas release under the proposed rule. Therefore, 

assuming that a corresponding 80 percent of these 980 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 refinery would spend an average of 80 hours 

conducting SCA investigations, at an average rate of $50 per hour. The total annual cost of 

conducting an additional 200 SCA investigations that may be required as part of the proposed 

amended rule is therefore estimated at $800,000. The 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 Meters, 

and Higher Heating Value and Total Sulfur Analyzers 

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 $4,348,836
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 sulfur analyzers but will include the addition of 23 

automated sampling devices. A summary of the proposed 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 analyzers 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 = $3,450,000 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 analyzers in today’s dollars will be: 

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

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

 Canalyzers = C1 + C2 + C3 = $7,355,400 

The capital costs under Scenario 2 are summarized in 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 to take six additional daily samples for total 

sulfur per flare during the week, incurring additional annual costs. Assuming that the cost of 

processing a sample will average $350, the annual cost of sampling will be: 

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

 = $2,511,600 

The cost of maintenance, parts, power, insurance and taxes for equipment is assumed to be 10 

percent of the total capital cost (including only the initial purchase of analyzers). Therefore, the 

total annual cost for the equipment and analyzers will be $3,300,477. 

A summary of the annual costs under Scenario 2 is presented in Table VI – 9. 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 gases 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 savings are realized by using less steam for the 

flare operations and extended flare tip life, minimizing repair costs; for this calculation, only the 

payback value of the recovered gas to be used as fuel gas or process feed is considered. This 

would represent annual savings that can lower the annual costs. 

The following assumptions will be made: 

• The annual average recovered gas volume is 3,2852,337 mmscf (see Chapter V – Emission 

Reductions) 

• On average, only 60 percent of the recovered gas volume is valuable product (based on 

review of recovered gas samples from a local refinery) 

• The value of recovered gas is estimated at $2 per mmBtu (www.johnzink.com – Flare Gas 

Recovery payback analysis) 

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

Annual Savings = 3,2582,337 * 106 scf * 0.6 * 1,000 Btu/scf * $2/106 Btu = 

$3,909,6002,804,400

As emissions will decrease, the refineries will pay reduced annual emission fees to the AQMD, 

reducing their annual costs. Table VI – 10 lists the estimated annual emission fees savings by 

pollutant and the total savings for the industry. 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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

SO2 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 – $3,909,6002,804,400 – $290,439 = $85,3591,190,559

For Scenario 2: 

Total Annual Cost = $6,614,5978,028 – $3,909,6002,804,400 – $290,439 = 

$2,414,5513,583,189

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 life 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 Series 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF REPORT

Proposed Amended Rule 1118 VI-12 October 2005

 = 15.62 (25 years equipment life and 4% real interest rate). 

Cost Effectiveness – SOx Emission Reductions Only

Scenario 1: 

C = $40,929,298 

A = $85,3591,190,559

PV1 = $40,929,298 + $85,3591,190,559 * 15.62 = $42,262,60659,525,830

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

CE1 = PV1 / (ER * EL) 

where: 

CE1 = Cost Effectiveness for Scenario 1 

ER = Emission Reduction for SO2, 431 tons per year 

EL = Equipment life, 25 years 

CE1 = $42,262,60659,525,830 / (431 tons * 25) = $3,9225,524 per ton of SO2 reduced 

Scenario 2 

C = $36,910,171 

A = $2,414,5513,583,189

PV2 = $36,910,171 + $2,414,5513,583,189 * 15.62 = $74,625,45892,879,583

CE2 = $74,625,45892,879,583 / (431 tons * 25) = $6,9268,620 per ton SO2 reduced 

Therefore, the cost effectiveness for this proposed amendment is estimated to be between 

$3,9225,524 and $6,9268,620 per ton of SOx reduced. 

Cost Effectiveness – Total Emissions Reductions (Excluding CO)

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

CE = PV / (TER * EL) 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF 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 criteria 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 = $40,929,29859,525,830 / (526 * 25) = $3,1124,527 per ton of pollutant reduced 

Scenario 2 

CE2 = $74,625,4592,879,5838 / (526 * 25) = $5,6757,063 per ton of pollutant reduced 

Therefore, if reductions for the other criteria pollutants, less CO, are included in calculations, the

cost effectiveness of the proposed amendments ranges between $3,1124,527 and $5,6757,063

per ton of pollutant reduced, excluding CO. 

C. INCREMENTAL COST-EFFECTIVENESS 

Staff is required under state law to determine an incremental cost effectiveness of the most 

stringent control scenario. Staff believes that the most stringent control scenario would require 

petroleum refineries to control all vent gases excluding off specification gas and vent gases 

resulting from emergencies. 

An analysis of the reported flare gas flow and emissions 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 mmscfd 

 Additional capacity to treat maximum daily flow recorded: 119 mmscfd 

 (excluding off spec gas and emergencies) 

PAR 1118 - 2012 Emissions 

 SO2 performance target: 0.50 TPD 

 Total emissions, less SO2 and CO: 0.24 TPD 

 Reported non-emergency, SO2: 94% (based on 2002 and 2003 data) 
CHAPTER VI – COST AND COST EFFECTIVENESS FINAL STAFF REPORT

Proposed Amended Rule 1118 VI-14 October 2005

 Reported non-emergency, other 68% (based on 2002 and 2003 data) 

Capital cost of the additional flare gas recovery and treatment system capacity 

Estimate cost of system based on a previously determined cost of $2.17 million per 

million standard cubic feet per day treatment capacity (mmscfd) 

$2.17 million/mmscfd * 119 mmscfd = $258,227,362 

Annual cost is estimated to be 10 percent of the capital cost 

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

SO2 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 yrs * 365 days/yr] 

 = $155,918 per ton of SO2 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 this proposed amendment is estimated to be 

between $115,412 and $155,918 per ton of air contaminant reduced. 
C H A P T E R VII 

COMPARATIVE ANALYSIS 
COMPARATIVE ANALYSIS 

PAR 1118 U.S. EPA 40CFR 60.18 a

Proposed Amended Rule 1118 VII-1 

− Applicability 

− Flares at refineries, sulfur recovery plants and hydrogen 

production plants 

− Flares built or modified after June 11

Subpart J 

− Flares controlling vents from piping 

40CFR 60 Subpart GGG, from storaSubpart Kb, or from wastewater syste

Subpart QQQ 

− Requirements 

− Flares to be operated with no visible emissions 

− Flares to be operated with a pilot flame present at all times 

− Annual acoustical or thermal surveys of PRD’s directly connected 

to flares 

− Specific Cause Analysis of flare events exceeding: 

o 500 lbs SO2

o 100 lbs VOC 

o 500,000 scf vent gas combusted 

− Cause of flare events where at least 5,000 scf of vent gas are 

combusted 

− Effective September 1, 2006, submit the following information: 

o Technical specifications on flare systems including an 

audit of gas recovery and treating system capacity and storage capacity for excess vent gases 

o A description of equipment installed and procedures

implemented within the last 5 years to minimize flaring 

o A description of equipment to be installed or procedures 

to be implemented to minimize or eliminate flaring 

− Effective January 1, 2007, operate flares in such a manner as to 

minimize flaring and only combust vent gas during emergencies, shutdowns, startups, turnarounds or essential operational needs 

− Flares to be operated with no visible 

− Flares to be operated with a pilot flam

− Air or steam assisted flares shall only 

content of 300 BTU/scf or more 

− The exit velocity of the vent gas is li

value of the vent gas 

− Flares shall not be used to combust g

0.1 gr/dscf (160 ppm) H2S, averaged 
COMPARATIVE ANALYSIS 

PAR 1118 U.S. EPA 40CFR 60.18 a

Proposed Amended Rule 1118 VII-2 Effective January 1, 2009, combustion in flares of gases with hydrogen sulfide concentration exceeding 160 ppm, averaged over 3 hours, is prohibited, unless in an emergency, shutdown, startup or PRD leakage 

− Performance Targets 

− Specific annual performance targets for subject facilities based on 

their crude throughputprocessing 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 equipment 

upgrades 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 heat content and total sulfur as SO2 or install continuous or semicontinuous analyzers 

− After July 1, 2007, continuous monitoring of vent gas flow, 

higher heat content and semi-continuously for total sulfur as SO2

− The presence of pilot flames monitored with thermocouples or 

equivalent devices 

− Effective July 1, 2006, video monitors with date and time stamp 

must be used to determine visible emissions 

− Effective January 1, 2007: 

o automated sampling system required for vent gas 

sampling 

− The presence of pilot flames monitor

equivalent devices 
COMPARATIVE ANALYSIS 

PAR 1118 U.S. EPA 40CFR 60.18 a

Proposed Amended Rule 1118 VII-3 

o Pilot 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 

− Notification and Reporting 

− 24 hour telephone service provided for public inquiries on flare 

events

− 1 hour notification of events exceeding: 

o 500 lbs SO2

o 100 lbs VOC 

o 500,000 scf vent gas combusted 

− 24 hour notification of planned events exceeding: 

o 500 lbs SO2

o 100 lbs VOC 

o 500,000 scf vent gas combusted 

− Submittal of Specific Cause Analysis of qualifying flare events 

within 30 days or 60 days upon request 

− Quarterly reports in electronic format certified for accuracy by 

responsible facility official, to include: 

o Daily and quarterly flare emissions 

o Causes of flare events 

o Records of annual PRD 

o Monitoring system down times 

− Copies of notifications required by 40CFR 355 pertaining to 

reportable air releases 

− Semiannual reports 

− Notifications required by 40CFR Sub

Planning and Community Right to Kpertaining 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

Appendix A, 40CFR 60 
COMPARATIVE ANALYSIS 

PAR 1118 U.S. EPA 40CFR 60.18 a

Proposed Amended Rule 1118 VII-4 − Vent Gas higher heating value determined: 

o By ASTM Method D2382-88, ASTM Method D3588-

91 or ASTM Method D4891-89 

o Effective July 1, 2007 with continuous analyzer 

− Vent Gas total sulfur expressed as SO2 determined: 

o By ASTM Method D5504-01 or District Method 307-

91 

o Effective July 1, 2007, with a semi-continuous 

analyzer 

− Flow monitored with a continuous flow measuring device 

requiring annual accuracy verification 

− Net heating value of the vent gas det

D2382-88 or D 4809-95 

−

− Exemptions

− Sampling not required if: 

o There is a catastrophic event, or 

o Safety of sampling personnel is at issue 

− Emissions from flaring events due to force majeure or 

circumstances beyond the operators’ control do not count towards 

annual performance targets 

− Emergency or upset vent gas and rel

malfunctions may exceed a H2S conc

ppm 

Facilities subject to PAR 1118 are also subject to the following AQMD rules:  Rule 401 – Visible Emissions  Rule 402 – Nuisance  Rule 431.1 – Sulfur Content of Gaseous Fuels
C H A P T E R VIII 

DRAFT FINDINGS 
CHAPTER VIII – DRAFT FINDINGS FINAL STAFF REPORT

Proposed Amended Rule 1118 VIII-1 October 2005 

DRAFT FINDINGS UNDER CALIFORNIA HEALTH AND SAFETY CODE 

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 reference based on relevant information presented at 

the hearing. The draft findings are as follows: 

Necessity - The AQMD Governing Board has determined that a need 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 language. 

Authority - The AQMD Governing Board obtains its authority to adopt, amend, or repeal rules 

and regulations from Health and Safety Code Sections 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 them. 

Consistency - The AQMD Governing Board has determined that Proposed Amended Rule 1118 

- Emissions from Refinery Flares, is in harmony with, and not in conflict with or contradictory 

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 proposed amendments are necessary and proper to 

execute the powers and duties granted to, and imposed 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 ambient air quality standards), 40440(a) (rules to 

carry out the Air Quality Management Plan), and 40440(c) (cost-effectiveness), 40725 through 

40728. 
C H A P T E R IX 

COMMENTS AND RESPONSES 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 the June 29, 2005 Public 

Workshop. The latest proposal only requires an FMP from those 

refineries that exceed the annual performance targets. The required 

elements to be submitted as part of the FMP are listed 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 pressure relief devices 

found to be defective or leaking be expeditiously repaired. 

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

directly to the flare gas header, can not be repaired without shutting down 

the process unit which they serve. Therefore, refineries typically repair 

defective or leaking PRDs during the process unit turnaround. To 

facilitate expeditious repair, PAR 1118 requires the refineries to conduct 

the PRD survey within 90 days prior to a turnaround. 

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

the proposed Flare Management (Minimization) Plan [FMP] prior to each 

FMPs approval. The lack of specific quantifiable standards 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 included to provide all 

interested parties with the opportunity to provide critical input. 

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

day public comment period for each Flare Minimization Plan (FMP) that 

has been reviewed and recommended for approval by the AQMD. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 flare management. 

Additionally, the district ought to include in the rule amendment a future 

commitment to evaluating Rule 1118 and making future 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 SO2 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 maintain ambient air 

quality standards. 

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

sulfur compounds was made using a different methodology than was used 

to calculate the reduction of other criteria pollutants. 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, whereas the concurrent 

emission reductions for other combustion pollutants was based on the 

assumption that the flare vent gas flow will be reduced with the 

installation of additional flare gas recovery and treatment system(s). 

Minimization 

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

The lack of specificity in the language, “take steps to minimize emissions 

during such events”, could provide a loophole for facilities operating 

flares, and could lead to disputes over enforcement. 

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

flaring. 

Public Input and Involvement 

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

public comment prior to approving any FMP. 

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

day public comment period for each flare minimization plan (FMP) that 

has been reviewed and recommended for approval by the AQMD. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 providing it online will 

allow the public to bypass the often long delays inherent in the public 

records request process. 

Response 9: Staff will post a summary of the quarterly flare emission 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 fees to be paid based 

upon an industry-wide threshold is not an equitable arrangement for 

individual facilities, nor is it in keeping with environmental justice 

principles. 

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

targets and mitigation fees will only be assessed for emissions exceeding 

the annual SO2 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 that mitigation fee should 

be changed so that it pertains only to those emissions above the prescribed 

target. 

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

for emissions exceeding the annual SO2 performance target. 

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

per ton or the RECLAIM backstop ceiling of $15,000 per ton. 

Furthermore, these mitigation fees are being charged 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 payments 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 are no more than ten 

percent, greater than ten percent but no more than twenty percent or 

greater than twenty percent of the applicable performance target, 

respectively. The mitigation fee is capped at $4,000,000 dollars in any 

year that the performance target is exceeded. 

 Any mitigation fees paid would be used to implement emission reduction 

projects in the area impacted by the excess emissions. The amount of the 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 mitigate the exceedance 

of the final annual performance target. It is expected 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 payments. High 

emissions can still result even from facilities that are in compliance with 

the requirements to be exempted from paying mitigation fees. 

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

mitigation fees for emissions exceeding the annual SO2 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 based on a one-time best 

achieved emissions level by a refinery. 

Response 14: Under the revised staff proposal, this compliance option is no longer 

necessary and, therefore, staff has removed this compliance option from 

PAR 1118. 

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

average needs to be explained. 

Response 15: Staff has removed this compliance option from PAR 1118. However, for 

clarification, calculating emissions for compliance purposes using a twoyear average was based on the fact that the frequency of flare events (and 

emissions) do not constant; they can vary from year to year. An average 

would smooth out any anomalies. 

Flare Minimization Plan 

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

requirement simply duplicates the emission reductions already imposed by 

limitations on causes of flaring, the performance goals, and the 160 ppm 

vent gas H2S limit. 

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

(FMP) from refineries that exceed the annual SO2 performance targets. 

The FMP requirement is a tool to ensure refineries that take appropriate 

measures to stay below the annual performance targets. Therefore, staff 

believes the FMP needs to be a part of PAR 1118. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 venting directly to the 

flares is extremely punitive and burdensome and serves no apparent useful 

purpose. 

Response 17: PAR 1118 has been revised to only require P&IDs for 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 annual 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 minimize flaring emissions 

during emergencies, shutdown and startup of each process unit should not 

be required in the FMP application. Since many policies and procedures 

are not unit-specific and instead have broad applicability, 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 from refineries that 

exceed the annual SO2 performance targets. Also, the 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 minimize 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 these operations, as well 

as safety implications, staff believes that it is best to leave the election of 

specific procedures relative to shutdown and startup to the refinery 

operators. It is more appropriate, as PAR 1118 does, to establish a 

regulatory framework that requires refineries to minimize 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 total volume of vent 

gas being routed to the flares each year is an impractical request. There is 

concern over the potential negative ramifications for refineries who cannot 

accurately predict the various aspects related to their future occurrences. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-7 October 2005 

Response 20: PAR 1118 has been revised to require from refineries that exceed the 

annual SO2 performance target to include in their FMP application the 

policies and procedures as well as gas recovery and treatment systems 

that will be utilized to minimize flaring and related 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 million barrels of crude 

processed and an FMP should be required of all refineries. 

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

flare events and emissions through the annual performance targets, which 

are significantly lower than previously presented at the June 29, 2005 

Public Workshop. The 2010 annual SO2 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 believes the proposed 

performance targets are real, quantifiable, enforceable, and permanent 

(with the requirement of a mitigation fee for annual exceedances) and are 

technologically feasible and cost effective. A FMP will only be required 

from refineries that exceed the annual SO2 performance targets. 

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

processed is too low to be practicable for refineries to meet. At such a low 

level, reducing emissions is no longer a viable alternative to submitting an 

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

emissions data from two refineries. The district should 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 Workshop provided 

refineries a compliance option to request a permit limit of 0.25 ton of SOx 

per 1 million barrels of crude processed; refineries 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 targets over time and, 

beginning calendar year, 20102, to emit no more than 0.75 ton SO2 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 dioxide emissions as a 

threshold for root cause analysis is too low. 500,000scf or 1000 lbs of 

sulfur dioxide emissions is suggested as a more practical threshold level. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 SOx 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 pounds per release. 

Essential Operational Needs 

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

operational needs. Therefore, the rule should provide pre-defined EON 

categories with the provision that if a facility encounters a new scenario, 

the facility has the prerogative to analyze the event, determine if it is and 

EON and then submit it to AQMD for approval. 

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

to now list specific operational or maintenance related 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 Needs disqualifies many 

scenarios that a refinery could actually identify as an EON. The district, in 

deciding whether a scenario qualifies as an EON ought to examine not just 

the technical feasibility of a measure, but also the practicality, cost, and 

cost-effectiveness. The definition of EON should include 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 conducts technological 

feasibility and cost effectiveness analyses. The definition Essential 

Operational Needs in PAR 1118 has been revised to include such 

scenarios as fuel gas system imbalances, PRV leakage, and venting clean 

service streams to a clean service flare or a general service flare, and 

adding fuel gas to vent gas to support combustion. 

Visible Emissions 

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

minutes of observing visual emissions on the video monitor is impractical 

at best, and at worst, dangerous. During emergencies 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 flares 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-9 October 2005 

Comment 27: The requirement to visually monitor is vague and could imply around the 

clock monitoring. Such a requirement would mean that 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 requirement that a refinery 

visually monitor visible emissions from flares. See Response 26.

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

double jeopardy, as visible emissions are already regulated under Rule 

401. 

Response 28: Staff disagrees. Although both PAR 1118 and Rule 401 address visible 

emissions, they are different standards with different requirements and 

measurement methods. PAR 1118 requires that flares be operated in a 

smokeless manner, which is defined as no visible emissions except for 

periods not to exceed a total of five minutes during two consecutive hours, 

based on USEPA Method 22. Rule 401 limits the visible emissions into the 

atmosphere from any single source of air contaminant for a period or 

periods not to exceed more than three minutes in any 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. Therefore this does 

not constitute double jeopardy.

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

ignores the basic flare design principles such as smokeless capacity vs. 

ultimate capacity. 

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

result in visible emissions. PAR 1118 allows visible emissions for periods 

not to exceed a total of five minutes during two consecutive hours flare 

will cause visible emissions. Any visible emissions due to exceedances of 

the flares smokeless capacity are typically due to emergencies and 

breakdowns. Such visible emissions caused by the incident 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 smoke could trigger an NOV 

or the smallest wisps of smoke could require a “reader” to go out into the 

field and conduct a visible emissions evaluation. 

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

minutes during two consecutive hours. Staff has deleted the requirement 

that a certified “smoke“ reader monitor visible emissions. See Responses 

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

Proposed Amended Rule 1118 IX-10 October 2005 

Comment 31: The requirement for a PRD survey to be conducted within 90 days prior to 

a scheduled turnaround is not adequate for turnaround planning purposes. 

Instead of specifying timing, the rule should specify that the scheduling of 

any PRD survey should be consistent with the turnaround planning 

timetable. 

Response 31: Staff disagrees. Maintenance, repair or replacement 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 survey too far in 

advance of a scheduled turnaround may not provide the refinery with the 

knowledge that a PRD is now leaking and in need of corrective action. 

Staff believes that conducting the PRD survey within 90 days of the 

turnaround provides the refinery with sufficient time to adjust their 

turnaround timetable and gives the surrounding community a reasonable 

expectation that they will not have to experience flare emissions from 

leaking PRDs for the next five years waiting for the next scheduled 

turnaround. 

Clean Service Flares 

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

PAR 1118. Their emissions are insignificant and they are already 

regulated to a certain extent under current Rule 1118. 

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

whether the facility meets its performance targets. In recognition, 

however, clean service flares may have a more consistent and typically 

lower SO2 concentration compared to other flares and are exempt from 

the daily sampling requirements. 

H2S Limits 

Comment 33: The 160ppm H2S limit for flaring is duplicative of limitations on causes of 

flaring, the requirements for FMPs, and the performance goals. 

Furthermore, this limit is an attempt to apply the EPA Subpart J (NSPS) 

limit to all flaring, an unnecessary rule element as industry has already 

achieved the emissions reductions contemplated by the AQMP measure. 

Additionally, Subpart J specifies a 3 hour rolling average, while PAR 

1118 specifies no time limit. The AQMD has not demonstrated the 

feasibility of universal compliance with the 160ppm H2S limit NSPSbased requirement that is not currently applicable to all flares. 

Response 33: Local refineries currently operate several “NSPS” flares that comply with 

proposed 160ppm H2S limit. Staff has determined that three refineries 

will need to install flare gas recovery and treating systems and other 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-11 October 2005 

refineries may consider expansion of flare gas recovery and treating 

systems to comply with the annual SO2 performance targets, which can 

also be designed to comply with the proposed 160ppm H2S limit. Staff has 

concluded that these systems are technologically feasible, achieved in 

practice and are cost effective (as part of the monitoring and control 

proposal for PAR 1118. PAR 1118 has been revised to allow averaging 

over a period of three hours rather than an instantaneous limit. Also, this 

proposed requirement does not include vent gases resulting from 

emergencies, shutdown, startup or relief valve leakage. Staff believes that 

other possible vent gas can be controlled to comply with the H2S limit as 

part of the new and expanded recovery and treatment systems 

Comment 34: Because the H2S limit applies to Essential Operational Needs, refineries 

needing to install flare gas vapor recovery and treatment systems could be 

out of compliance with this standard until the control systems are installed. 

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

malfunction) when determining compliance with the H2S limit. Staff 

believe all other essential operational needs, as defined in paragraph 

(b)(4), can be collected and treated to compliant levels. To allow time to 

install or expand needed control system(s), staff has revised the 

compliance date to January 1, 2009. 

Operation Monitoring and Recording Requirements 

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

insufficient time to install a calorimeter to analyze emissions. 

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

continuous higher heating value analyzer by July 1, 2007.

Comment 36: The requirement to take a sample within the first fifteen minutes of each 

sampling flare event presents significant logistical hurdles, and in some 

cases it is an impossibility. 

Response 36: PAR 1118 requires the use of automated sampler to collect 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 can 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 millions of data points 

that could be used to develop statistically reliable averages. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-12 October 2005 

Response 37: Staff believes that increased sampling frequency will greatly increase the 

accuracy of emission data until the continuous monitors are installed. 

Many data submitted by the refineries was not measured but rather 

substituted data based on calculations. The cost of daily sampling and 

analysis has been included in the cost effectiveness determination for PAR 

1118. Staff has determined that PAR 1118, which includes daily sampling, 

is technologically feasible and cost effective. 

Comment 38: Sampling during a Sampling Flare Event ought to suffice as the daily 

required sample. 

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

accuracy of emission data until the continuous monitors are installed. 

Furthermore, the use of data collected during a sampling flare event, such 

as an emergency, has in most instances, been documented as a value 

greater than the values measured during a smaller, non-sampling event. 

However, staff has revised PAR 1118 to allow the use data collected 

during a sampling event for the required daily sample. 

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

maintenance of 48 hours per quarter is not feasible. Often, more time is 

needed because vendors must be called out for repairs. 160 hours annually 

has been suggested as a viable option to the 48 hours per quarter limit. 

Response 39: PAR 1118 has been revised to allow flare monitoring 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 per 18 month limit on 

planned maintenance is feasible, especially given the fact that monitoring 

systems will now include more components than before and will be more 

complex. Instead of the aforementioned limit, Rule 218 to should be used 

to deal with the issues of monitoring system downtime. 

Response 40: Data collected by AQMD on continuous emission monitoring systems 

(CEMS) does not suggest additional time will be needed. However, staff 

acknowledges that information on the operation of CEMS for flares is less 

robust. If the pilot study on the total sulfur analyzer 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 the presence of a pilot 

flame using a thermocouple or any other equivalent device approved by 

the Executive Officer. Providing examples of equivalent devices to a 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-13 October 2005 

thermocouple, such as an IR camera, would be helpful for both facility 

operators and District engineers. 

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

being used successfully to monitor the presence of the pilot flame on 

flares. However, staff did not want to limit a refinery’s ability to propose 

an alternate measurement technique it believes equivalent. Any 

alternative(s) by the refinery can be proposed to and 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 installation of the proposed 

flow monitoring devices are far more expensive than engineering 

estimates and may require that the flare involved be out of service. 

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

inventory. Installing flow meters on pilot and purge gas lines will is 

needed to obtain an accurate measurement of pilot and purge gas to the 

flares. Flow measuring devices are relatively inexpensive; 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 combustion must be measured and 

recorded.”? Furthermore, the requirement should specify “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 monitoring system may be 

used to measure and record the operating parameters required in 

paragraph (g)(3) of this rule for more than one flare provided that: All the 

gases that are delivered to the flares for combustion must be measured 

and recovered”. To exclude “assist air or steam” from the gas(e) being 

directed to the flare(s), the refinery will need to demonstrate to the 

satisfaction of the Executive Officer that assist air or steam does not 

contain anything that will result in the emission of air contaminant(s). 

However, the revised definition of Vent Gas excludes 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 instrumentation 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 REPORT

Proposed Amended Rule 1118 IX-14 October 2005 

Response 44: Accurate emission data, which includes flow measure to the flares, is 

paramount to determining the amount of air contaminants released to the 

atmosphere. Staff can not determine the air quality benefit without 

accurate flow data. The AQMD Governing Board, on September 3, 2004, 

directed staff to proceed with rule development to evaluate the 

recommendations stated in “Evaluation Report on Emissions from Flaring 

Operations at Refineries”, which included a recommendation to improve 

the measurement of flare vent gas flows. Staff believes that it is important 

to establish an accurate emission inventory; installing flow meters in 

representative locations will do just that. As an alternative to relocation, 

an owner or operator may upgrade the meter with a totalizer 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 sampling 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 heating value and total 

concentration of total sulfur, expressed as sulfur dioxide, of gases directed 

to the flares, is paramount to determining the amount of air contaminants 

released to the atmosphere. The AQMD Governing Board, on September 

3, 2004, directed staff to proceed with rule development to evaluate the 

recommendations stated in “Evaluation Report on Emissions from Flaring 

Operations at Refineries”, which included a recommended the installation 

of continuous monitoring systems to measure the higher heating value and 

the total sulfur gas concentration of the flared gas. Several local 

refineries have already installed and operate automated flare gas 

sampling systems. Staff believes that this equipment will improve the 

logistics of taking samples, especially during an emergency when refinery 

personnel are not available to manually collect the required sample(s). 

Staff has determined the installed cost of the automated flare gas sampling 

system to be approximately $5,000 based on cost information 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 they be pilot tested before 

they are considered as a requirement for flare system monitoring. 

Response 46: Staff has contacted several petrochemical facilities in Texas and 

Louisiana where continuous calorimeters have been used for a number of 

years on flare headers for compliance with USEPA 40CFR 60.18 or Texas 

regulations. Staff believes, based on those testimonials, that a pilot 

program is not necessary. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-15 October 2005 

Comment 47: Procedures to prevent flaring events caused by recurring equipment 

breakdowns, detailing the adequacy of maintenance schedules 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. Furthermore, what constitutes 

a definition of recurring is unclear and no guarantee can ever be made that 

there will not be recurring breakdowns. The term “adequacy” used in the 

requirement is also subjective and should be replaced. 

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

and eliminate any redundancy with the “Specific Cause 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 system imbalances only 

occur as a result of a temporary interruption of pipeline gas sales. Rather, 

the interruption of pipeline gas sales is probably one of the least common 

reasons for fuel system imbalances. There is concern that the fact that fuel 

gas imbalances are specifically addressed implies that they cannot be 

claimed as an Essential Operational Need, which they are. 

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

situation that may cause a temporary fuel gas imbalance; the loss of a 

combustion device such as a heater or boiler may also cause this 

temporary situation. Staff recognizes that there are essential operational 

needs that must be directed to the flare. The definition 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 resources that will be used to 

conduct acoustic and temperature surveys of pressure relief devices is 

impractical. First, specifying schedules that far in advance, is difficult at 

best. Furthermore, specifying resources so far in advance serves no useful 

purpose as resources that complete a particular job at the same high 

quality are often interchangeable. For instance, contractor 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 requirement. 

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

previous five years that resulted in vent gas being directed to the flare 

cannot be guaranteed to be met since refineries have not been required to 

keep records going back five years. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-16 October 2005 

Response 50: PAR 1118 has been revised to remove this requirement. 

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

is problematic because “prevent” is an absolute term and there cannot be 

any assurance that future breakdowns will not occur. 

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

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 emissions, the operator is 

required to contact the Executive Officer within one hour of the event. 

This extremely low threshold will result in an excessive number of phone 

calls to the District. There is also concern that any late, or missed calls 

could result in NOVs, despite the fact that there are no negative air quality 

implications. 

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

within one hour, by telephone, of the unplanned release of 100 pounds of 

VOC, 500 pounds of SOx, 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 appropriate in order to 

conduct timely investigations of flaring events and possible public 

complaints. The AQMD issues NOVs only after careful consideration of 

the facts and merits of the failure to meet its’ rule requirements 

promulgated to protect public health. 

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

within 30 days carries with it the implication that a Root Cause Analysis 

should also be completed within this time frame, which is an unreasonable 

request. Furthermore, the requirement will result in resources being redistributed from areas that have a greater potential 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 Specific Cause Analysis 

(SCA) consistent with the deadlines in Rule 430 or Regulation XX Rule 

2004 (h) for breakdown reports. If needed, a facility may request an 

extension of up to 30 additional days for submitting the SCA. 

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

implies that mitigation of emissions is a requirement. Clarification is 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 flaring events and any 

actions taken by the operator with this purpose should be reported in the 

SCA.

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

even a planned flaring event, thus making the requirement 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 case the facility should 

notify the AQMD of the revised planned event date and/or time. However, 

the facility will have the opportunity to refine these estimates once more 

information about the events become available. 

Comment 56: There should be clarification provided that demonstrates that the quarterly 

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

consistent with “standard” certifications such as other 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 rules. 

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

dioxide and 100,000 cubic feet of flare gas, many flare events are likely to 

be nearly continuous, making the requirement to provide an analysis of 

each flare event difficult. 

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

Specific Cause Analysis (SCA) for larger flare events 500 pounds sulfur 

dioxide, 100 pounds VOC or 500,000 cubic feet of flare gas is combusted 

and a basic investigation to determine the relative cause (emergency, 

shutdown, startup, turnaround, specific essential operational need, or 

unknown if undeterminable) where more than 5,000 cubic feet of flare gas 

is combusted by the flare. Staff believes that these thresholds are 

necessary to reduce emissions from flares since they will in effect provide 

operators useful information regarding the use of flares 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. Furthermore, the clause, “but 

not limited to”, which is part of the description of what the report should 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 enforcement. 

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

data, it is critical that the name of the person(s) conducting the annual 

inspection of PRDs be recorded. Staff has revised PAR 1118 to remove all 

“but not limited to” language in the proposed amended rule. 

Testing and Monitoring Methods

Comment 59: Neither calorimeters nor sulfur analyzers have been 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 has not justified the cost in 

terms of air quality benefits of installing these analyzers systems. 

Response 59: Staff has contacted several petrochemical facilities in Texas and 

Louisiana where continuous higher heating value analyzers (calorimeters) 

have been used for a number of years on flare headers for compliance 

with USEPA 40CFR 60.18 or Texas Commission of Environmental 

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 commitment in the PAR 1118 

adopting Resolution to conduct a study of the TS analyzer at the local 

refinery prior to the requirement going into effect. Accurate emission 

data, which includes total heating value and concentration of total sulfur, 

expressed as sulfur dioxide,, is paramount to determining 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 staff to proceed with 

rule development to evaluate the recommendations stated in “Evaluation 

Report on Emissions from Flaring Operations at Refineries”, which 

included a recommendation to improve the measurement 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 reduction in the 

sulfur dioxide emissions from flares operated at petroleum refineries and 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-19 October 2005 

related facilities. Therefore, staff has determined 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 provision 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 operating standards. 

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

analyze for higher heating value and concentration of total sulfur, 

expressed as sulfur dioxide, (reported as sulfur dioxide). 

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

are subjective and the language ought to be clarified. 

Response 62: Subparagraph (k)(1)(A) relieves a facility from collecting “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 facility. Staff agrees with 

petroleum refineries that safety is paramount; only the facility 

experiencing a significant flare event and the specific circumstances 

pertaining to that event knows if it is safe to send 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 terrorism is pointless, because 

the District would already be well aware of such events. 

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

requirement is appropriate. 

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

emissions resulting from interruptions of power supply beyond the 

refinery’s control. 

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

outages, other than due to an interruptible power agreement, from the 

annual performance target.

Attachment A:

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

or considering area classifications in a rule. Facilities must always be in 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-20 October 2005 

control of the aforementioned issues as they are the ones that specify, 

purchase and operate equipment. This general provision extends to 

specifics in Attachment A such as installation issues like hot-taps. 

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

complete, accurate meaningful and verifiable data are collected. In that 

this requirement contributes to ensuring that an analyzer 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 selected for harmony with 

building requirements in the region and to ensure safety of monitoring 

staff. 

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

can certainly not be justified based on any air quality benefits. 

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

has stated that the meters can accurately measure flow 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 event as 0.12 feet per 

second or greater. As previously stated in Response 46, accurate flow 

data is necessary to determine emissions and air quality benefit as well as 

air quality detriment. 

Comment 67: It is assumed that data recorded will be transferred 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 capacity of the flare 

when the maximum range of the flow meter is exceeded is an overly 

pessimistic assumption which will quickly cause emissions performance 

goals specified in (d)(1) to be exceeded. 

Response 68: Staff has revised PAR 1118 to allow the operators of facilities subject to 

this rule to substitute flow data that was not measured using both the 

maximum and the average flow measured during the previous 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 option to demonstrate to the 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 parameters and/or other 

process data. Furthermore, the provisions applicable to the non-sampling 

events have been revised to allow these facilities to rely on previously 

measured events rather than relying on data substitution procedures. In 

addition, staff has committed to evaluate the use of the data substitution 

procedures by industry during the first year of implementation of PAR 

1118 and report back to the Governing Board with any 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 refinery could never use 

“zero”. Without a designation of zero a “Flare Event” as defined would 

never actually end. This applies to both flow meters and to a combination 

of flow meters and on/off flow indicator switches. 

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

PAR 1118 has been revised to establish a flare event at 0.12 feet per 

second or greater. The twenty percent difference between 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 this use of worst-case 

assumptions, especially in light of the mitigation fees that would apply if 

emissions performance goals are exceeded. Instead of 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 operators to demonstrate to 

the AQMD that operational records, such as water seal level or other 

approved parameters in the Flare Monitoring and Reporting Plan, that a 

flare event did not occur. Furthermore, the data substitution provisions of 

PAR 1118 have been revised and the worst case assumptions are no 

longer applicable.

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

highest sulfur concentration in the vent gas from the previous year is 

exceedingly harsh and based on unrealistic assumptions. First, it is 

unlikely that the peak value from the previous year would always exceed 

any estimate based on engineering knowledge. Secondly, this requirement 

could lead to a situation in which the payment of the mitigation fee would 

be based on fictitious emissions instead of real ones. Instead of this worstcase data use, facilities ought to be able to use another appropriate 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-22 October 2005 

estimate if the facility provides adequate justification for that estimate’s 

use. 

Response 71: Staff has revised PAR 1118 to allow the operators of facilities subject to 

this rule to substitute concentration of total sulfur, expressed as sulfur 

dioxide, data that was not measured using both the maximum and the 

average concentration of total sulfur measured during 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 operators 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 operator the option to 

demonstrate to the AQMD that total sulfur can be estimated through 

alternative methods using recorded and verifiable operational parameters 

and/or process data to be representative of the total sulfur concentration. 

Comment 72: There is no reason why the single highest measurement 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 values from the previous 

year. 

Response 72: See Response 721. 

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 that in some flare 

configurations, vent gases may enter the flare header, pass by the meter 

and then be recovered by the vapor recovery system before breaking 

through the water seal. This typically results in flow 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 presence of flow at a velocity 

of 0.1 ft/sec would force a recording of a continuous 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, water seal monitors, or 

video monitoring, must be excluded from flare events, as defined. A better 

definition of flare event is, “FLARE EVENT is any intentional 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 monitoring. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-23 October 2005 

Response 73: The definition of Flare Event has been revised to address the situations 

where vent gas is measured by the flow meter but through the use of the 

water seal, the vent gas is processed by the gas recovery 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 operational upsets to be 

consistent with federal rules. A better definition would be: “Emergency, 

for this rule, means a condition beyond the reasonable 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, force 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 careless operation are not 

emergencies.” (Reference: Based on 40 CFR 60, Subpart A 60.2 - 

Malfunctions) In addition, the current definition of Emergency Service 

Flare in Rule 1118 includes “emergency process upset condition.” 

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

preventable”. However, staff does not believe “process upset” should be 

included in this definition; specific situations will be listed in the definition 

of Essential Operational Need”. The definitions of Emergency and 

Emergency Service Flare can not be identical in application since clean 

service flares and general service flares also process vent gases from 

emergencies. 

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

(definition 12-12-203). 

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

BAAQMD in the definition. 

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

in all cases. The following definition should be used 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 vague and open-ended. 

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

with the phrase “including but not limited to.” There needs to be a clear 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 higher heating value and 

total sulfur analyzers, flow meters, and on/off flow indicators. 

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

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

should be included in other definitions and/or in the 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, shutdowns and turnarounds. 

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

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 “pipeline quality natural 

gas” from either CPUC or EPA. 

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

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

version. “PURGE GAS is a continuous gas stream introduced into a flare 

header, flare stack, and/or, flare tip, for the purpose of maintaining a 

positive flow and to prevent the formation of an explosive 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 REPORT

Proposed Amended Rule 1118 IX-25 October 2005 

Comment 83: In the definition of SAMPLING FLARE EVENT it must be made clear 

that the refinery must initiate the request. 

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

different Sampling Flare Event threshold for the Executive Officer’s 

approval. 

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

occur for reasons other than maintenance, repair, or replacement of 

equipment. The following definition is more complete. “Shutdown is the 

process of stopping the operation of a process unit or piece of equipment 

for any reason, including preparations necessary for 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 following. “Startup is the 

process of initiating and achieving normal operation of a process unit or 

piece of equipment. 

Response 85: PAR 1118 has been revised to include an expanded definition for startup 

that takes into account parameters, such as pressure, 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 exclude “assisting air 

or steam, flare pilot gas and any continuous purge gases.” These 

exclusions must be included in the proposed definition. A more complete 

definition is the following. “Vent gas is any gas generated at a facility 

subject to this rule that is routed to, and combusted in a flare, excluding 

assisting air or steam, flare pilot gas, and any continuous 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 flare is considered vent 

gas.
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-26 October 2005 

MISCELLANEOUS 

Comment 88: A flare designed for smokeless flaring at full capacity 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 over the whole operating 

range up to maximum design. Even if this existed, there is always the 

possibility of losing steam injection that could result 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, facilities planning to install 

complete vapor recovery and treatment systems in the next few years 

would face challenges relating to certain requirements prior to their 

installation of the vapor recovery system. 

Response 89: Staff disagrees with this statement that would effectively allow any flaring 

to take place and make the rule amendment futile. However, the rule 

language has been revised to allow more time for these facilities that 

intend to install additional vapor recover treatment 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 systems 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 in attainment with the 

federal SOx standards and flare emissions have already been reduced by 

80%. 

Response 91: Staff disagrees. SOx emissions are precursors to particulate matter (PM) 

emissions and the AQMD is not in attainment for PM 10 (particulate 

matter less than 10 microns aerodynamic diameter) and PM 2.5 

(particulate matter less time 2.5 microns aerodynamic 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 differences of the recovery and 

treatment capacity of the various facilities indicates that additional 

capacity for some facilities is feasible to further minimize flaring and 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-27 October 2005 

associated emissions. There is no mechanism in place that prevents 

backsliding to previous emission levels. PAR 1118 will make these 

reductions permanent, real, quantifiable and enforceable and will 

establish a framework for further reductions. 

Comment 92: It is not fair to assess mitigation fees based on an industry-wide 

performance, where an individual facility has no control on emissions 

from a competitor. Also, the standard for an “ultra-clean facility” is not 

attainable.

Response 92: PAR 1118 has been revised to require petroleum refineries to achieve a 

facility-specific declining annual sulfur dioxide performance target. 

Facilities that exceed the annual performance target are subject to 

mitigation fees and must also submit a Flare Minimization Plan for public 

comment and Executive Officer approval. PAR 1118 no longer contains 

an “ultra-clean” facility compliance option. 

Comment 93: The estimated emission reductions based on 2003 emissions inventory is 

not appropriate since it does not take into consideration 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 trended down and that 2004 

emissions are lower than the previous stated baseline year 2003. Since 

emissions may vary significantly from year to year due to turnarounds and 

other unforeseen events in petroleum refinery operations, it is appropriate 

to use a multiple year average as an emissions baseline. The staff report 

has been revised to average sulfur dioxide emissions and vent gas flow 

rates for the years 2001, 2002, 2003 and 2004 to establish the baseline for 

calculating emission reductions and the cost effectiveness of PAR 1118. 

 Cost effectiveness analysis is a tool to generate a cost effectiveness factor 

for a control measure. By comparing the cost effectiveness 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 necessary 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 interest 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 REPORT

Proposed Amended Rule 1118 IX-28 October 2005 

Comment 95: In contrast with the Bay Area Air Quality Management District 

(BAAQMD) flare rule, PAR 1118 is far more complex and 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 Districts to flares is different, 

BAAQMD is requiring Flare Minimization Plans while AQMD’s PAR 

1118 establishes performance targets for controlling 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 applicable dates that trigger 

NSPS requirements for flares (40CFR Subparts A and J). 

Comment 97: Acid gas in the Preliminary Draft Staff Report (PDSR) 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 in the October 2000 

Enforcement Letter, which is...”refineries should have adequate capacity 

at the back end of the refinery to process acid gas”. 

Response 97: The description of acid gas was enhanced as suggested. Staff believes that 

the title of the October 2000 Enforcement Letter summarizes EPA’s 

position that routine flaring is not considered “Good Pollution Control 

Practice” and it “May violate the Clean Air Act”. 

Comment 98: The use of the same concepts in the Consent Decrees that EPA has entered 

with some refiners used in the amendment of Rule 1118 may represent a 

duplication of a federal regulations and the AQMD Board must recognize 

it in its findings upon rule adoption. 

Response 98: Staff disagrees. The Consent Decrees are not federal regulations and they 

may sunset according to specific clauses in each of them, based on each 

refinery’s compliance record for a certain period of time following the 

signing of the Consent Decree. 

Comment 99: The statement in the Staff Report that refineries burn “waste gases” in 

flares is a false assumption. 

Response 99: Staff has revise the staff report and the word “waste” was removed.
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-29 October 2005 

Comment 100: Stating that visible emissions are caused by insufficient steam is 

inconsistent with the smokeless capacity of a flare, since there are limits to 

how much steam can be used. The staff report should 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 and one for violating 

Rule 1118. 

Response 100: Staff agrees that when the smokeless capacity is exceeded there is not 

enough steam to accommodate the high vent gas flow, but acknowledges 

that this is due to the limitations in the flare design and a clarification was 

made in the staff report. 

 Assuming that a flare was found having visible emissions in excess of 

Ringelmann 1 or 20 percent opacity for 5 minutes within 1 hour due to a 

situation other than a valid breakdown, force majeure 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 California 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 requirements except for 

monitoring and recording as specified in Table 1. 

Response 102: Staff disagrees. All flares have emissions potential and all significant 

flare events need to be accounted for in the form of 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 is designed and 

configured by installation to combust only natural gas, hydrogen gas and 

/or liquefied petroleum gas, or any other gas(es) with a fixed composition 

vented from specific equipment which has been determined to be 

equivalent and approved in writing by the Executive Officer. Therefore, 

based on this definition, a Clean Service Flare would have very low sulfur 

dioxide emissions, and as such would contribute very little to the annual 

sulfur dioxide performance target. Clean Service Flares are not required 

to be monitored with higher heating value or total sulfur analyzers and 

are not required to have daily vent gas “grab” samples taken. However, 

the operator must collect grab samples for all sampling flare vents. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 the 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 and would not be 

allowed for such use if requested by facilities today since the destruction 

efficiency for flares varies widely from 70 to 97 percent depending on 

atmospheric conditions and the quality of vent gas combusted. By 

contrast, thermal oxidizers are designed with a specific residence time, 

are able to maintain stable combustion temperatures, which results in 

destruction efficiencies in excess of 99%, are therefore 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 combustion efficiency 

would be prohibited by the rule. 

Response 104: Staff believes that use of excessive steam may extinguish the flame and 

result in potentially high volumes of odorous and/or toxic substances 

being released from a flare. Boosting the BTU content 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 H2S, averaged 

over 3 hours. There should be mention of AQMD Rules 1123 and 1176 

and federal regulations requiring control of VOCs. 

Response 105: The staff report was expanded to include the clarification on the H2S limit. 

The other rules mentioned do not apply to the operation of a flare, only to 

control of VOCs, and therefore will not be discussed. 

Comment 106: The report should clarify that flares prevent the release 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 minimizing flaring that 

are listed in the staff report are speculative and lack any foundation. 

Response 107: The suggested possible alternatives are taken form the “Episodic Release 

Reduction Initiative” document, issued by EPA on July 5, 2001 as a 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-31 October 2005 

collaborative effort of EPA, the (Texas Commission of Environmental 

Quality (TCEQ), the Louisiana Department of Environmental Quality 

(LA-DEQ) in cooperation with 13 petroleum refineries. 

Comment 108: There is an economic incentive besides the environmental benefit for flare 

gas recovery (FGR), as long as the refinery has adequate 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 recovery system. The 

article represents the author’s opinion, not necessarily universally 

applicable guidelines.

Response 109: Staff has expanded the staff report to include guidelines 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 over a “wide” range of 

dynamically changing flow rates. Thus the opinion expressed in the Oil & 

Gas Journal article is in agreement with the API guidelines. 

Comment 110: The significant emission reductions already realized suggest that there are 

limited benefits for amending the rule. 

Response 110: PAR 1118 implements the recommendation of the Governing Board 

regarding improved monitoring, recordkeeping and recording as well as 

establishing annual sulfur dioxide, already realized 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 Minimization Plan is worthwhile; 

the District should encourage refineries to opt for SOx performance 

targets. 

Response 111: PAR 1118 has been revised to require petroleum refineries to comply with 

a declining annual sulfur dioxide performance target 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 performance targets. 

Comment 112: There is no need to require continuous HHV analyzers since on average 

this parameter is expected to be constant. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 calculating the emissions of 

each flare event with accuracy, a continuous monitor is the best option to 

use. 

Comment 113: The statements by staff regarding the cause of flare 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 cost analysis and cost 

effectiveness calculations. 

Response 113: Staff disagrees. The data presented in the Preliminary Draft Staff Report 

was based on 2003 obtained from the “Evaluation Report on Emissions 

from Flaring Operations at Refineries” (September 2004), which is a 

summary of data submitted by facilities to comply with monitoring and 

reporting requirements of the Rule 1118. The Staff Report has been 

updated to include data for calendar years 2001 through 2004 to calculate 

average vent gas flow and emissions from flares. Staff has determined 

that the average flow and emissions data is most representative data for 

the random, cyclical operation of the flares. Staff believes that 

emergencies, startup, shutdown, turnaround and fuel gas balancing events 

are a significant and determinant event/operation that should have been 

easily identified and reported to the AQMD. The total 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 emission factors. Staff 

has met with two of the three facilities that have been identified in the staff 

report as needing (projected) additional gas recovery and treatment 

system capacity. These two “larger” facilities confirmed the need to 

install four systems totaling 13 mmscf capacity. Staff 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 historical vent gas flow. These 

systems will minimize vent gas directed to the flares which will reduce 

sulfur dioxide and other criteria air contaminants. 

Comment 114: Some suggested flare controls might have been considered technically 

feasible; however, practicality, costs and cost effectiveness 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 controls will still incur 

significant costs for monitoring and other requirements of PAR 1118; in 

aggregate, complying with the rule will be a significant expenditure. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-33 October 2005 

Response 115: Monitoring and other requirement costs were included by staff in the costeffectiveness analysis of the proposed rule. Staff has determined that PAR 

1118 is both technologically feasible and cost effective. 

Comment 116: The assumptions made in the staff report for determining costeffectiveness will need to be evaluated by individual facilities and 

commented upon. It is unclear whether three or four flare gas recovery 

and treatment systems are proposed and the number of flow meters for 

pilots may be triple than that indicated in the staff report. 

Response 116: Staff has estimated that four flare gas recovery and treatment systems 

would have to be installed at three petroleum refineries; The four systems 

will minimize vent gases to eight flares that currently are not connected to 

any gas recovery and treatment systems. Staff’s analysis is discussed in 

Chapter VI – Cost and Cost Effectiveness. The number 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 each pilot. 

Comment 117: The case study used in the staff report to determine the cost of a flare gas 

recovery system was related to acid gas flaring. It 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 facilities to assess compliance 

with future proposed rule requirements. For better accuracy in estimating 

costs, staff has expanded its analysis to two additional 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 considered 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 literature 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 respect. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-34 October 2005 

Response 119: Staff used cost information supplied by the refinery in Billings, Montana, 

as well as the cost data from two local refineries that installed control 

equipment in 1993 and 2001. Although the systems installed 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 million 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 information. Some of this 

information is considered confidential. Any non-confidential information 

can be provided to interested parties upon written request. 

Comment 121: When calculating the cost of equipment over time, staff did not factor in 

adjustments for inflation. 

Response 121: Staff disagrees. The cost of future expenditures was adjusted for inflation. 

Comment 122: Annual costs should include taxes and insurance. 

Response 122: The total installed cost includes taxes and insurance. 

Comment 123: The annual estimated savings due to recovered gas should 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 average flow rate of vent 

gas recovered through the installation of additional vent gas recovery and 

treatment systems. Please refer to Chapter VI – Cost and Cost 

Effectiveness for a discussion on the assumptions used in calculating the 

cost savings. 

Comment 124: Staff has not clarified the necessity of the rule for ozone attainment. 

Response 124: The proposed rule amendment is necessary since oxides of sulfur (SOx) 

are precursors to PM10 and PM2.5. Since the rule is designed to 

minimize flaring and associated emissions, in addition to the SOx 

reductions, the rule will result in concurrent reductions 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 REPORT

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 communities is to require all the 

refineries to submit a Flare Minimization Plan (FMP), which will be 

subject to public participation. CBE believes an FMP is the best and most 

transparent approach to identify unnecessary flaring practices and 

equipment and procedures that eliminate routine flaring. Performance 

targets, while important, do not identify unnecessary flaring categories and 

allow routine flaring within the performance targets.

Response 125: PAR 1118 establishes a multi-pronged strategy to ensure that flaring and 

associated emissions are minimized. Therefore, the performance targets 

should not be viewed in isolation from the other provisions of the 

proposed amendment. Specifically, PAR 1118 has explicit provisions that 

would prohibit any unnecessary or so-called routine flaring. The 

proposed amendment states that no flaring is allowed other than 

emergencies, startup, shutdowns or essential operational needs. Staff 

went to great lengths in working with all stakeholders to carefully define 

all these terms in the rule. PAR 1118 would also require 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 flare gas recovery and 

treatment capacity; identify past emission reduction efforts and future 

efforts to further reduce flaring and associated emissions, and to evaluate 

options to reduce flaring during planned events, such 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 targets that seek to 

incrementally reduce emissions starting 2006 through 2012. These 

performance reduction targets, which have been recently 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. The staff proposal also 

significantly strengthens the emissions data gathering and monitoring 

procedures of the rule which will significantly improve the emissions data 

quality and a facility’s ability to refine its flare minimization strategy.

Staff has also committed to evaluate the Bay Area Air Quality 

Management District Rule 12 – Flares at Petroleum Refineries 

requirement to implement Flare Minimization Plans and the resultant 

installation of controls and report back to the Governing Board with any 

recommendations.
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-36 October 2005 

Comment 126: In addition, the FMP should require a Best Available Retrofit Control 

Technology (BARCT) assessment and an audit (list) of equipment, 

processes and procedures to reduce flaring caused by non-emergency, 

planned start-ups and shutdowns and flaring events resulting from power 

curtailments.

Response 126: As stated in Response 125, staff believes that annual performance targets 

are more effective than FMPs to reduce flare-related emissions from 

refinery flares. Regardless, staff has revised its proposal to require each 

facility to conduct an audit of its flare gas recovery and treatment capacity 

and identify past and future control actions. Refineries that exceed the 

annual performance targets are then required to submit 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 flare gas recovery

capacities, flare gas storage and treating capacities.

Comment 127: PAR 1118 performance targets need to be significantly lower and a daily 

limit for both SOX and VOC should be required to limit the health impact 

of flaring activities on the community.

Response 127: The annual performance target has been lowered to 0.5 ton SO2 per 

million barrels processed effective January 1, 2012. This revised 

proposed target is approximately 70 percent lower than the baseline 

emissions used in the cost analysis for this proposed rule and 

approximately 75 percent lower than the AQMP Control Measure CMB07 targets. Also, see Response 125. 

Staff has determined that it is impractical at this time to establish a daily 

emissions target for SO2 or VOC because the flares are operated to reduce 

vent gases resulting, in large part from emergencies, and essential 

operational needs. These are random events and associated emissions 

vary significantly. Based on reported emissions data (reductions 

documented since 1999), refineries have initiated procedures 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 SO2 reductions, PAR 1118 will also reduce other criteria 

air contaminants, including VOC. PAR 1118 limits the types of flaring 

that are allowed, and requires facilities to minimize flaring. To meet the 

annual SO2 performance targets, refineries will have to reduce 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 commits to evaluate the 

feasibility of establishing daily emissions targets and the appropriateness 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-37 October 2005 

of the annual SO2 emission targets and whether refinements to those 

targets are warranted, and report back to the Governing Board with any 

recommendations.

Comment 128: The definition for Essential Operational Needs (EON) 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, staff 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 analysis of the EONs for each 

refinery to determine if they meet the definition of 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 reports 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 refineries to provide a 24-

hour telephone service to answer public inquiries about planned and 

current flare events. Staff has also committed in the Board Resolution to 

continue to work with industry and community members, and other public 

agencies to ensure that emergency notification procedures address the 

community needs.

Comment 131: A CLEAN SERVICE FLARE is currently defined as a flare that only 

combusts “clean” gases, such as natural gas, hydrogen gas and/or liquefied 

petroleum gas, or any other clean gases with a fixed composition vented 

from specific equipment. The definition of Clean Service Flare should be 

modified to also include gases that meet the Rule 431.1 – Sulfur Content 

of Gaseous Fuels requirement of no more than 40 ppm total sulfur content.

Response 131: Staff disagrees. The original and continuing intent 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 less 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 meeting 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 composition. Therefore, unlike 

the other clean gases listed in the definition of Clean Service Flare, the 

composition of refinery gas can vary and therefore, so can the emissions 

of other combustion contaminants, such as NOX, CO, PM10 and VOC.

Comment 132: Hydrogen production plant flares should not be subject to PAR 1118 

because, as demonstrated by the quarterly flare reports, they are low SOX

emitters (less than 40 pounds SOX per year). Based on the reported 

emissions data, there are significant differences between a hydrogen 

production plant flare and a petroleum refinery flare.

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 SO2;compared to the 

refineries. However, flares at hydrogen plants do use refinery gas and do

emit other combustion contaminants, such as NOX, CO, PM10 and VOC, 

that are in more significant amounts. Hydrogen production plants do use 

flares to combust vent gases. The requirements for hydrogen production 

plants are limited to the demonstration of minimizing flaring at this type of 

facility. 

Comment 133: Subparagraph (c)(1)(D) requires refineries to conduct a Specific Cause 

Analysis (SCA) when a specific emission or flow rate 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 startup). We request that 

staff clarify this in PAR 1118. 

Response 133: Staff will revise subparagraph (c)(1)(D) to emphasize that the owner or 

operator of a facility subject to PAR 1118 will have to conduct a SCA for 

those unplanned flare events exceeding 100 pounds of VOC, 500 pounds 

of SO2, 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 paragraph (c)(3), flaring is 

only allowed for “planned” shutdowns, “planned: startups and “planned” 

turnarounds or essential operational needs.

Response 134: Staff disagrees. Operators are required to minimize 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 the 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-39 October 2005 

need to flare, whether planned or not planned in advance, can be based on 

petroleum refineries decision to safely operate specific equipment. Staff 

believes that the declining annual SO2 performance targets coupled with 

the progressive mitigation fees and required submittal of a FMP for 

exceedences of the annual targets and the requirement to identify the cause 

of smaller flare events and conduct a SCA for larger flare events will 

require (and provide incentives for) petroleum refineries to minimize all 

flaring. 

Comment 135 To comply with the annual SO2 performance targets and the requirement

to minimize flaring, some refineries will need to install a flare gas 

recovery and treatment system(s). Paragraph (c)(4) allows refineries that 

will need to install flare gas recovery and treatment systems on more than 

two flares until January 1, 2010, to install the control system(s) for only 

those specific additional flares. Paragraph (c)(5) requires all refineries to 

comply with the H2S limit by January 1, 2009. Since the control 

equipment to comply with paragraph (c)(5) is the same equipment that 

will be used to comply with paragraph (c)(4), we are 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 compliance dates for 

paragraphs (c)(4) and (c)(5).

Comment 136: The definition of EMERGENCY in PAR 1118 includes the phrase “poor 

maintenance.” We believe that the phrase poor maintenance is ambiguous

and needs clarification. 

Response 136: Staff has revised PAR 1118 to clarify that poor maintenance is tied to 

repetitive flare events from the same equipment that have occurred as a 

result of the maintenance, or lack of adequate maintenance of that 

equipment that caused the flare event(s).

Comment 137: The definition of EON includes flaring caused by emergency 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 include in the definition 

emergency situations resulting from operational temperatures rising above 

the process vessel temperature set point.

Response 137: Staff agrees that temperatures greater than the design operating 

temperature specifications for specific equipment could result in a flaring 

event which is necessary for continued safe operation of that equipment. 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

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 discussions on the 

annual SO2 performance targets were based on the crude oil capacity; 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 identified an inequity of 

using crude throughput versus crude capacity based on a fixed year of 

2004 to establish annual SO2 performance targets. In any one year, any 

refinery could be conducting a shutdown or 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 crude processing capacity more accurately allocates refinery 

emissions based on normal refinery operations. Local refineries are 

operating at near capacity; therefore, the difference in emissions impact 

and reductions based on throughput or capacity are minimal.

Comment 139: Please clarify that for data substitution, a facility can use data from a 

previous similar event.

Response 139: Staff has revised the data substitution provisions of PAR 1118 to clarify 

that a facility can use flow, HHV, and total sulfur data from similar flare 

events that have previously occurred, can be used for data substitution,

with the Executive Officer’s approval. 

Comment 140: The terms “relief valve” and “pressure relief device” are used in the

definition of EON and in the requirement to conduct an annual leak 

survey. Please clarify the meaning for each of these terms in PAR 1118.

Response 140: A relief valve is the all inclusive, general category that includes all valves 

that are designed and installed for the purpose of protecting equipment 

from operating pressure greater than design pressure for the safe 

operation of that equipment. A pressure relief device is a specific type of 

relief valve.

Comment 141: Staff included language in the rule that allowed sampling flare events that 

occurred within 15 minutes of each other to be counted 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 REPORT

Proposed Amended Rule 1118 IX-41 October 2005 

Response 141: Staff agrees and has revised the definition of SAMPLING 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 mechanism for the 

District’s Executive Officer to approve or reject activities identified by 

refinery operators as an “essential operational need” and that staff will 

commit to annually evaluate the continued progress of refineries in the 

District to minimize their emissions of all pollutants from flares. As part 

of this evaluation, District staff should provide a summary of the 

emissions by year by refinery. District staff should use this information to

appropriately develop and recommend future amendments to the rule.

Response 142: Staff agrees. The definition of ESSENTIAL OPERATIONAL NEED has 

been revised to include language that essential operational need is “an 

activity determined by the Executive Officer to meet” one of the following 

(specific listed activities). In addition, staff has committed in the 

Resolution to review the definition of ESSENTIAL OPERATIONAL NEED 

and report back to the Governing Board with any recommendations.

 Also stated in the Resolution is a commitment by staff to provide the 

Governing Board annual status reports on overall industry performance, 

which will include a summary of the emissions by year, by refinery. As 

with all AQMD rules, staff will review this and other information to 

appropriately develop and recommend future amendments to this rule.

Comment 143: The attached letter from the Western States Petroleum Association was 

received at the end of the comment period. Staff will be prepared to 

respond to these comments at the Public Hearing.
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-42 October 2005 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-43 October 2005 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-44 October 2005 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-45 October 2005 
CHAPTER IX – COMMENTS AND RESPONSES FINAL STAFF REPORT

Proposed Amended Rule 1118 IX-46 October 2005 
APPENDIX A 

REFERENCES 
APPENDIX A – REFERENCES DRAFT STAFF REPORT

Proposed Amended Rule 1118 A-1 October 2005 

Staff Report for Rule 1118 – Emissions From Refinery Flares, SCAQMD, December 1997 

Evaluation of Refinery Flare Emissions at Petroleum 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 EPA300-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, February 6, 20030 
APPENDIX B 

CALIFORNIA AIR RESOURCES BOARD RESOLUTION 86-60