### ATTACHMENT F

SOUTH COAST AIR QUALIT Y MANAGEMENT DISTRICT

Final Staff Report
Proposed Rule 1114 – Petroleum Refinery Coking Operations

Final Staff Report

May 2013

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

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

Planning and Rules Manager Planning, Rule Development, & Area Sources Naveen Berry

AUTHOR: Eugen Teszler - Air Quality Specialist

REVIEWED BY: David On o - Program Supervisor William Wong - Principal Deputy District Counsel
CONTRIBUTORS: Barbara Radlein - Air Quality Specialist Shah Dabirian, Ph.D - Air Quality Specialist Mike Garibay, P.E. - Air Quality Supervising Engineer Jason Aspell - Air Quality Engineer Glenn Kasai - Air Quality Engineer Ron Lem - Air Quality Engineer Eric Padilla - Air Quality Engineer Wayne Stredwick - Air Quality Engineer Mei Wang - Air Quality Engineer Carey Willoughby - Air Quality EngineerSOUTH COAST AIR QUALIT Y MANAGEMENT DISTRICT GOVERNING BOARD

Chairman: DR. WILLIAM A. BURKE Speaker of the Assembly Appointee
Vice Chairman: DENNIS YATES Mayor, Chino Cities of San Bernardino County MEMBERS:

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

BEN BENOIT Councilmember, Wildomar Cities of Riverside County
JOHN J. BENOIT Supervisor, Fourth District County of Riverside
MICHAEL A. CACCIOTTI Councilmember, South Pasadena Cities of Los Angeles County/Eastern Region
JOSIE GONZALES Supervisor, Fifth District County of San Bernardino JOSEPH K. LYOU, Ph. D. Governor’s Appointee
JUDITH MITCHELL Mayor Pro Tem, Rolling Hills Estates Cities of Los Angeles County/Western Region
SHAWN NELSON Supervisor, Fourth District County of Orange DR. CLARK E. PARKER, SR. Senate Rules Appointee
JAN PERRY Councilwoman, Ninth District City of Los Angeles
MIGUEL A. PULIDO Mayor, Santa Ana Cities of Orange County EXECUTIVE OFFICER: BARRY R. WALLERSTEIN, D.Env.TABLE OF CONTENTS

EXECUTIVE SUMMA RY ---------------------------------------------------------------------------- ES-1

CHAPTER I - BACK GROUND ------------------------------------------------------------------------ I-1

A. Historical Review ------------------------------------------------------------------------ I-1 B. AQMD Rules for Petrol eum Refineries ----------------------------------------------- I-2 C. Other Districts’ Rules for Coking Units at Petroleum Refineries ------------------ I-4 D. Federal Regulations for Coking Un its at Petroleum Refineries -------------------- I-4 E. Affected Fa cilities ------------------------------------------------------------------------ I-5 F. Process Description ---------------------------------------------------------------------- I-5 G. Legislative Authority -------------------------------------------------------------------- I-7

CHAPTER II – PROPOSED RULE LANGU AGE -------------------------------------------------- II-1
A. Purpose and A pplicability -------------------------------------------------------------- II-1 B. Definiti ons ------------------------------------------------------------------------------- II-1 C. Requirements ---------------------------------------------------------------------------- II-1 D. Monitoring and Recording ------------------------------------------------------------- II-2 E. Notification ------------------------------------------------------------------------------ II-2 F. Recordk eeping --------------------------------------------------------------------------- II-2 G. Exemptions ------------------------------------------------------------------------------ II-3

CHAPTER III – EMISSION INVENTORY -------------------------------------------------------- III-1

A. Affected Faci lities ---------------------------------------------------------------------- III-1 B. Emission Inventory -------------------------------------------------------------------- III-1

CHAPTER IV - CONTROL TECH NOLOGY ASSESSMEN T ---------------------------------- IV-1

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

CHAPTER VI – COST AND COST EFFECTIVENE SS ----------------------------------------- VI-1

A. Costs ------------------------------------------------------------------------------------ VI-1 B. Cost Effectiveness Calculations ------------------------------------------------------ VI-1 C. Incremental Cost Effectivenes s ------------------------------------------------------ VI-2

CHAPTER VII – COMMENTS AND RESPONSES ---------------------------------------------- VII-1

CHAPTER VIII – IMPACT ASSESSMENT ------------------------------------------------------ VIII-1
A. Environmental Impact Assessment ------------------------------------------------ VIII-1 B. Socioeconomic Assessment -------------------------------------------------------- VIII-1 C. Comparative Analysis --------------------------------------------------------------- VIII-3 D. Draft Findings under California Health and Safety Code Section 40727 ----- VIII-4

REFERENCESEXECUTIVE SUMMARY

Proposed Rule 1114 ES-1 May 2013 Achieving attainment status for ambient ozone a nd particulate concentra tion in the South Coast Air Basin (SCAB) as more stringent federal air quality standards are adop ted and implemented is required. The South Coast Air Quality Manage ment District (SCAQMD) is continuously looking for ways to reduce air pollution from all sources, both mobile and stationary under this purview. The 2007 and 2012 Air Quality Manageme nt Plan (AQMP) revisions have been developed in partnership with California Air Resources Board (CARB), U.S. EPA, Southern California Association of Governments (SC AG) and stakeholders throughout the region, including input from local govern ment, health and environmental organizations, and the business community.
The AQMP is the blueprint for how to meet and ma intain state and federal air quality standards. The 2007 AQMP identifies Control Measures needed to demonstrate attainment with the federal annual average PM 2.5 standard by 2015 and federal 8-hr ozone standard by 2023. The 2012 AQMP identifies Control Measures needed to demonstrate attainme nt with the federal 24-hour standard for PM 2.5 by 2014 in the SCAB. In additi on, the 2012 AQMP provides updates on progress towards meeting the 8-hour ozone sta ndard for 2023, an attainment demonstration for the revoked 1-hour ozone standard, a vehicle per miles traveled (V MT) offset demonstration for ozone standards, and a report on the health effects of PM 2.5 . In the 2012 AQMP, Control Measure MCS-01 - All Feasible Measures Assessm ent is a continuation of the former Control Measure MCS-07 from the 2007 AQMP, in which the District has committed to the adoption and implementation of new retrofit control technolog y standards. The 2012 AQMP Control Measure MCS-01 provides the impetus for de veloping Proposed Rule 1114 (PR 1114).
Among stationary sources, petroleum refineries are one of the major emitters, accounting for seven tons per day (tpd) volatile organic comp ounds (VOC), 10 tpd carbon monoxide (CO), 10 tpd nitrogen oxides (NOx), six tpd sulfur oxides (SOx) and five tpd total suspended particulate (TSP) emissions in the year 2011. Over the past ni ne years, District st aff has conducted studies of emissions from atmospheric venting of dela yed coking units (DCU’s) at local refineries, concluding that there is a sufficient amount of VOC, PM, me thane (CH4, a greenhouse gas), sulfur compounds and hazardous air pollutants (HAPs), including polycyclic organic matter (POM * ) compounds, from this operation to warrant consideration. U.S. EPA has also acknowledged that DCU emissions are signifi cant and, as a result, in 2008, U.S. EPA promulgated 40 CFR 60 Subpart Ja, which establis hes a five (5) pounds per square inch, gauge (psig) vent limit for coke drums at new or modified DCU’s.
In 2010, staff initiated discussions with local refi neries and the public on concepts to establish baseline emissions from DCU’s but were unable to reach consensus. Baseline emissions are necessary to establish emission reduction targets. In 2011, the U.S. EPA required refineries to conduct some detailed source testin g on various equipment, including DCU’s. Therefore, based on feedback from the refineries, staff awaited the la test source testing information in an effort to establish an emissions baseline. However, the quali ty of additional data collected left a lot to be desired. Thus, over the past six months, staff ha s worked with U.S. EPA, the refineries, and the

* Polycyclic organic matter (POM) is a federal hazardous air pollutant and was identified in California as a toxic air contaminant in April 1993 under AB 2728. The State of Calif ornia has determined under Proposition 65 that several POM compounds (including benzo[b]fluoranthene, benzo[j]fluoranth ene, benzo[k]fluoranthene, benzo[a]pyrene, chrysene, indeno[1,2,3-cd]pyrene, 3,7-dinitrofluoranthene, a nd 3,9-dinitrofluoranthene) are carcinogencs (CCR, 1997).FINAL STAFF REPORT

Proposed Rule 1114 ES-2 May 2013 public on alternate approaches to estimate em issions from DCU’s and has recently reached

consensus. The purpose of PR 1114 is to minimize the amount of pollutants genera ted during the delayed coking process by requiring that a coke drum be depressurized to less than two (2) psig prior to venting to atmosphere. The propos ed rule includes the following:

 Establishes a limit of less than two psig fo r when a coke drum may be vented to atmosphere.

 Allows for an alternative compliance schedule for facilities not able to meet the rule compliance timeline which extends compliance through the facilities ’ turnaround period that:

o Establishes a facility-specific vent pressu re that facilities cannot exceed based on either a baseline average vent pressures recorded in 2012 or less than five psig;

o Requires facilities with more than one de layed coking unit taking advantage of the alternate compliance schedule to demonstr ate compliance with an interim vent pressure limit of less than five psig for all coke drums following a turnaround or by December 31, 2016, whichever is earlier;

o Allows up to an additional 24 months following completion of the interim period to meet the final depressurization limit.

 A requirement for facilities to submit permit applications for equipment or process modifications no later than nine months prior to the applicable compliance date.

 Monitoring and recording require ments for the coke drum internal pressure, atmospheric vent valve or equivalent interim parame ter, downtime and associated notification provisions, and recordkeeping.

 An exemption from the provisions of SCAQMD Rule 404 for coke drums.

District staff estimates baseline emissions of 268 tons per year (tpy) VOC, 1,140 tpy CH4, and 54 tpy HAPs. The proposed rule is estimated to result in redu ctions of 129 tpy VOC, 547 tpy of CH4 and 26 tpy HAPs at an estimated cost eff ectiveness of $8,700 per ton of VOC. Additional reduction in particulate emissions and sulfur compounds are expected by implementing the lower depressurization limit.
Pursuant to California Environmental Qualit y Act (CEQA) Guidelines §15252 and §15162 and SCAQMD Rule 110, the SCAQMD has prepared an Environmental Assessment (EA) for Proposed Rule 1114. The environmental analysis in the Draft EA concluded that Proposed Rule 1114 would not generate any sign ificant adverse environmental impacts. The Draft EA was released for a 30-day public review and comment period fro m February 28, 2013 to March 29, 2013, resulting in the receipt of two comment lette rs. Both comment letters and responses are included as Appendix D of the EA. Since the release of the Draft EA, minor modifi cations have been made to the document. However, none of the modifications alter any c onclusions reached in th e Draft EA, nor provide new information of substantial importance relative to the draft document. Moreover, these minor revisions do not require reci rculation of the Draft EA pur suant to CEQA Guidelines §15073.5EXECUTIVE SUMMARY

Proposed Rule 1114 ES-3 May 2013 and §15088.5. Therefore, the Draft EA is now a Fina l EA and is included as an attachment to this Governing Board package. Prior to maki ng a decision on the proposed adoption of Rule 1114, the SCAQMD Governing Board must review and certify the Fina l EA as providing adequate information on the potential adverse environmental impacts of the proposed project.
Pursuant to California Environmental Quality Act (CEQA) Guidelines §15252 and §15162 and SCAQMD Rule 110, the SCAQMD has prepared an Environmental Assessment (EA) for proposed Rule 1114. The environmental analysis in the Draft EA conclude d that proposed Rule 1114 would not gene rate any signi ficant adverse environmental impacts. The Draft EA was released for a 30

- day public review and co mment period from February 28, 2013 to March 29, 2013. Any comments received during the public commen t period on the analysis presented in the Draft EA will be responded to and included in the Final EA. Prior to making a decision on the proposed adoption of Rule 1114, the SCAQMD Governing Board must review and certify the Final EA as providing adequate informatio n on the potential adverse environmental impacts of the proposed project.
The 2012 Air Quality Management Plan (AQM P), specifically C ontrol Measure CM#2012 MCS-01 – Application of All Feasible Measures Assessment, commits the District to adopt and implement new retrofit technology control sta ndards based on research and development and other information, that are feasible and cost-e ffective as new Best Available Retrofit Control Technology standards become available. PR 1114 will partially implement CM#2012 MCS-01.C H A P T E R I

BACKGROUNDCHAPTER I - BACKGROUND

Proposed Rule 1114 I-1 May 2013 A. HISTORY
Coking Process Although some early attempts at coking were made in the second part of the nineteenth century, the first delayed coking unit was built by Standard Oil in Whiting, Indiana in 1929. In the 1930’s, Shell Oil refined the technology by separati ng the heater from the coke drum, combined pressure and heat, and made the process semi -continuous by pairing up two drums working in conjunction with each other. Later in the twen tieth century, the process became more popular due to the increase in the number of fluid catalytic cracking units (FCCU’s) [1]. As the availability of light, sweet crude oil dec lined, additional oil refi neries processed heavier and sourer stocks which are more readily available at lower prices. However, in order to do this, changes in process and equipment are needed to accommodate for the increased level of sulfur and heavier molecules present in these feedstoc ks. For that purpose, local refineries have upgraded processing equipment to be able to w ithstand more adverse conditions, have installed additional scrubbing/treating capac ity and expanded the throughput of existing delayed coking units, which thermally break the heavy, long chai n molecules and maximize liquid product yields while also producing petroleum coke. The California refineries typically process Alas ka North Slope (ANS) crude, San Joaquin Valley (SJV) crude and crude from several other oil fields throughout Calif ornia and offshore; they also import crude from Saudi Arabia, Iraq and Ecuador. * Emissions from Coking In April 1997, District enforcement staff noti ced visible emissions from a DCU at a local refinery. The source of visible emissions was traced to a coke drum being vented to the atmosphere prior to being open for coke removal. The incident triggered an investigation of emissions from coke drums atmospheric venting at petroleum refineries located in the SCAB. Subsequently, from 2003 and through 2006, Distri ct staff conducted source tests at the local refineries, initially in order to quantify VOC and PM emissions, and later sulfur compounds and HAP emissions from coke drums. In order to conduct these source tests, staff needed to overcome several adverse conditions, including the unavailability of adequate ports on the coke drums vent pipes, high temperatures inherent to the process, high elevations and ot her physical hazards existent on the top deck of coking drums. District staff developed the necessary testing procedures and was able to complete most of the source tests despite the high moisture content (up to 99% steam) of the stream being vented; in a few instances, however , hazardous conditions developed or the venting was too short to the point where te st results became compromised. After the first couple of tests, it became evident that the tests should be expanded to also quantify sulfur compounds such as hydrogen sulfide (H 2 S) and HAPs such as benzene, toluene, ethyl benzene and xylene (BTEX). Starting in 2006 and until 2009, a second round of source tests was initiated after refineries in stalled ports on coke drum ve nt pipes at staff’s request.

* http://www.energy.ca.gov/2005publicatio ns/CEC-600-2005-031/CEC-600-2005-031.PDF , p. 14.FINAL STAFF REPORT

Proposed Rule 1114 I-2 May 2013 Further, in 2006, U.S. EPA staff became aware of the source tests conducted at the DCU’s and contacted District staff to request copies of th e results. Subsequently, U.S. EPA staff, in an effort to develop an emission inventory fo r DCU’s throughout the U.S., requested several refineries to develop protocols an d conduct source tests for their co ke drum atmospheric venting. The first refineries to conduct the source tests were the Hovens a refinery in St. Croix, U.S. Virgin Islands and the CITGO refinery in Corpus Christi, TX.
As a result, in June 2008, U.S. EPA promul gated new regulation 40 CFR 60 Subpart Ja – Standards of Performance for Petroleum Refine ries for Which Construc tion, Reconstruction or Modification Commenced after May 14, 2007; this new regulation affected, among other process units, DCU’s at petroleum refineries and establ ished a five psig depressurization limit for the atmospheric venting of coke drums at refineri es subject to the rule. Furthermore, in 2011 U.S.EPA issued more source test requests for coke drum vent emissions to several U.S. refineries in an effort to establish emission factors fo r these petroleum refineries emission points and update AP-42, Compilation of Air Pollutant Emission Factors.
B. AQMD RULES FOR PETROLEUM REFINERIES
Current District rules cover a variety of industr ial processes and regulate the amount of criteria pollutants and HAP emissions associated with thes e operations. This section focuses on the rules covering processes and operations di rectly related to petroleum re fineries, most relevant being under Regulation IV – Prohibitions , Regulation XI – Source Speci fic Standards, Regulation XIV – Toxics and Other Non-Criteria Pollutants and Regulation XX - Regiona l Clean Air Incentives Market (RECLAIM).

VOC Emissions
Rule 462 – Organic Liquid Loading
Rule 462 was adopted in 1976 and last amended in 1999. The purpose of the rule is to control VOC emissions from facilities that load organic liquids into any tank truck, trailer or railroad tank car. The rule requires vapor reco very and/or a disposal system for displaced organic vapors, as well as an operator leak in spection program for VOC vapor leaks or liquid leaks from facility piping components. Rule 463 - Organic Liquid Storage
Rule 463 was adopted in 1977 and last amended in 2011. It applies to any aboveground stationary tank used for storag e of organic liquids and any aboveground tank used for storage of gasoline. The purpose of the rule is to control VOC emissions from tanks by requiring them to be pressurized or desi gned and equipped with a vapor cont rol device such as external floating roofs, fixed roofs with an internal fl oating-type cover or a vapor recovery system. Rule 1173 - Control of Volatile Organic Comp ound Leaks and Releases from Components at Petroleum Facilities and Chemical Plants Rule 1173 was adopted in 1989 and last amended in 2009. The purpose of the rule is to minimize fugitive VOC emissions from piping co mponents at petroleum refineries through a self inspection leak detecti on and repair program (LDAR) , done on a quarterly basis.CHAPTER I - BACKGROUND

Proposed Rule 1114 I-3 May 2013 Rule 1176 – VOC Emissions from Wastewater Systems Rule 1176 was originally adopted in 1989 and subsequently amended in 1990, 1994 and 1996. The purpose of the rule is to reduc e VOC emissions from components of the wastewater system such as process drains, sumps, separators, forebays, sewer lines and junction boxes. The emissions are generated whenever the surface of a liquid containing VOC is exposed to the atmosphere. The fa cilities subject to this rule produce VOCcontaining process water that has a potential to emit VOC directly into the atmosphere when routed to an open drain system.
Rule 1178 - Further Reduction of VOC Emissi ons from Storage Tanks at Petroleum Refineries Rule 1178 was adopted in 2001. The purpose of this rule is to further reduce VOC emissions from storage tanks located at pe troleum facilities. It applie s to all aboveground storage tanks that have capacity equal to or greater than 75,000 liters (19,815 gallons), are used to store organic liquids with a true va por pressure greater than 5 mm Hg (0.1 psi) absolute under actual storage conditions, and are located at a ny petroleum facility that emits more than 40,000 pounds (20 tons) per year of VOC in any emission inventory year starting with the emission inventory year 2000. Rule 1189 – Emissions from Hydrogen Plants Vents
Rule 1189 – was adopted in 2000. The purpose of this rule is to reduce emissions of VOC from hydrogen plant process vents. The rule ap plies to all hydrogen pl ants that produce any hydrogen for use in petroleum refining operations.
Particulate Emissions

Rule 404 – Particulate Matter - Concentration Rule 404 limits the concentration of part iculate matter being emitted from a source. Rule 405 – Solid Particulate Matter - Weight Rule 405 limits the mass emissions of particulate matter from a source.
Rule 1105.1 - Reduction of PM 10 and Ammonia Emissions from Fluid Catalytic Cracking Units
Rule 1105.1 was adopted in 2003 with the purpose of reducing emissions of PM 10 and ammonia from fluid catalytic cracki ng units at petroleum refineries. Sulfur Compounds Emissions
Rule 407 – Liquid and Gaseous Air Contaminants Rule 407 limits emissions of sulfur compounds fr om any source to atmosphere, expressed as SO 2 , to 500 ppmv when averaged over 15 minutes.
Rule 431.1 – Sulfur Content of Gaseous Fuels
Rule 431.1 establishes limits for sulfur co mpounds concentration in gaseous fuels. Rule 1118 – Control of Emissions from Refinery FlaresFINAL STAFF REPORT

Proposed Rule 1114 I-4 May 2013 Rule 1118 was first adopted in 1998 and amended in 2005. The purpose of this rule is to monitor and record data on refinery and re lated flaring operations , and to control and minimize flaring and flare related emissions. Rule 1105 – Fluid Catalytic Cracking Units – Oxides of Sulfur Rule 1105 was first adopted in 1978 and last amended in 1984. The purpose of the rule is to limit the sulfur oxide emissions from fluid catalytic units at pe troleum refineries. Rule 2011 - Requirements for Monitoring, Reporting, and Recordkeeping for Oxides of Sulfur (SOx) Emissions Rule 2011 was first adopted in 1993 and last ame nded in 2005. The purpose of this rule is to establish the monitoring, reporting, and recor dkeeping requirements for SOx emissions under the RECLAIM program.

Air Toxics

Rule 1401 - New Source Review of Toxic Air Contaminants Rule 1401 was adopted in 1990 and last amended in 2010. This rule specifies limits for maximum individual cancer risk (MICR), can cer burden, and noncancer acute and chronic hazard index (HI) from new permit units, relo cations, or modifications to existing permit units which emit toxic air contaminants.
Rule 1402 - Control of Toxic Air Co ntaminants from Existing Sources Rule 1402 was adopted in 1994 and last amended in 2005. The purpose of this rule is to reduce the health risk associated with emissi ons of toxic air contaminants from existing sources by specifying limits for maximum indivi dual cancer risk (MICR), cancer burden, and non-cancer acute and chronic hazard index (HI) app licable to total facili ty emissions and by requiring facilities to implement risk reduction plans to achieve specified risk limits, as required by the Hot Spots Act and this rule. Th e rule also specifies public notification and inventory requirements.

C. OTHER DISTRICTS’ RULES FOR DELAYED COKING UNITS
There are no rules at any other Air Pollution Control District in California for DCU’s at this time.

D. FEDERAL REGULATIONS FOR COKING UNITS AT PETROLEUM REFINERIES On June 24, 2008, U.S. EPA issued its final rule 40 CFR60 Subpart Ja th at requires petroleum refineries with newly constructed or modified delayed coking units to depressurize a coke drum to five psig or less before venting it to atmosphere.
40 CFR 63 Subpart CC – National Emission Standa rds for Hazardous Air Pollutants (NESHAP) from Petroleum Refineries, classifi es delayed coke drum vents as miscellaneous process vents; if the atmospheric depressuring of the coke drum is done at a pressure higher than 15 psig it is subject to controls, such as venting to a vapor recovery system, scrubber, etc, depending on the amount and concentration of HAPs emitted.CHAPTER I - BACKGROUND

Proposed Rule 1114 I-5 May 2013 E. AFFECTED FACILITIES
There are currently six petroleum refineries in the SCAQMD that operate delayed coking units, as summarized in Table 1.1 below:
Table 1.1-SCAB Petroleum Refineries with Delayed Coking Units

Facility City
BP Carson Chevron USA El Segundo
ExxonMobil Torrance Phillips 66 Carson Tesoro Wilmington Valero Wilmington

F. PROCESS DESCRIPTION
Coking is the refinery process that converts vac uum distillation bottom fr actions, or resid, into gasoline, light gas oil and heavy gas oil; petroleum coke is a by-product of this process. Resid is fed to a fractionation tower; the bo ttom fraction is then passed th rough a heater th at brings the temperature to 850 ° F – 900 ° F and, under steam injection, is sent to the botto m of an empty coke drum at a pressure of 30-60 psig. The purpos e of steam injection is to delay coking, or solidification of the hot material until it reaches the drum, therefore the name “delayed coker”. The heavy resid molecules at high temperature star t breaking into smaller, lighter molecules that rise and leave the top of the coke drum as vapors, and are routed back to the fractionation tower. The material left behind polymer izes to solid coke w ithin 30 minutes to one hour. Because more feed and steam are forced through the drum, pores are created into the st ructure which gives the coke a sponge-like appearance. Eventually the coke drum is filled to a predetermined level where no more coke can fit and the feed is sw itched to another empty drum for the start of another cycle. Two coke drum s and a feed heater form a m odule that allows for a semicontinuous batch operation. Once the drum is filled and the heavy oil turns into coke, steam is injected to strip leftover hydrocarbons from the coke bed and the vapors are routed to a fractionation tower for a period of time. Quench water is then injected from th e bottom of the drum for a few hours until the drum cools down to the desired temperature, usually in the range of 220 ° F - 300 ° F. As the quench water flashes into steam due to the elevated temp erature in the drum, the vapors continue to be routed to the fractionation tower together w ith light hydrocarbons; on ce the stream becomes mostly water vapors, it is diverted to a blowdow n/flare system until the coke drum pressure and that of the blowdown/flare system become equal. The drum is then vented to atmosphere until its internal pressure equals ambient pressure. The atmospheric depressurization phase is the focus of PR 1114.FINAL STAFF REPORT

Proposed Rule 1114 I-6 May 2013 As the top and bottom lids are removed from th e coke drum, a high pressure water drill is lowered into the drum and is used to remove the coke from the drum. A p ilot hole is drilled first with a small drill head, after whic h a larger drill head is used to remove the bulk of the coke. The coke drops on a pad or into a pit, then is conveyed to a cr usher for size reduction and then conveyed to a barn for storage. On average, th e coke contains 9 - 12 % volatiles, 4% sulfur and 5 - 9% moisture, and as such is ca lled green coke. It is stored in barns and kept moist to prevent fugitive dust emissions. Typically, 18 hours of coking are followed by 18 hours of coke removal or decoking, but due to technologi cal advancements the length of the cycle can be reduced to as low as 12 hours per cycle. Coke with a high percent of impurities is used as fuel for steel foundries; coke that has a low metals and sulfur content is used for ma nufacturing anodes for aluminum and titanium producers. In order to make anode grade c oke, moisture, sulfur and metal impurities are removed from the green coke th rough a process called calcining, wh ere coke is heated at high temperatures in rotary kilns, converting the coke to almost pure carbon wi th a defined structure.

A process flow diagram of a de layed coker is shown below:

Figure 1.1 - Delayed Coker Process Flow Diagram Atmospheric VentCHAPTER I - BACKGROUND

Proposed Rule 1114 I-7 May 2013 G. LEGISLATIVE AUTHORITY
The SCAQMD was created by the California Legisl ature in 1977 (the Lewi s-Presley Air Quality Management Act, Health and Safety Code Sec tion 40400 et seq.) as the agency responsible for developing and enforcing air polluti on control rules and regulations in the SCAB. By statute, the SCAQMD is required to adopt an Air Quality Management Plan (AQMP) demonstrating compliance with all state and federal ambient ai r quality standards for the Basin (Health and Safety Code Section 40460(a)). In addition, the SCAQMD must a dopt rules and regulations that implement the AQMP (Health and Sa fety Code Section 40440(a)).
The long-term trend of the quality of air shows continuous improvement, although recent leveling off in ozone improvement causes mark ed concern. The SCAB, comprising the counties of Los Angeles, Orange, Riverside and San Bern ardino, is the second most populated urban area in the U.S.

− and the smoggiest. To ensure continued progress toward clean air and comply with state and federal requirements, the SCAQMD, in conjunction with CARB, SCAG and the U.S. EPA prepared the 2012 AQMP, which employs the mo st up-to-date science and analytical tools and incorporates a comprehensive strategy aimed at controlling polluti on from all sources, including stationary sources, on-road and o ff-road mobile sources and area sources.
Although the new federal fine particulates (PM 2.5 ) and 8-hour surface level ozone standards provide a longer compliance schedu le, the standards are much more stringent than the previous PM 10 and 1-hour surface level ozone st andards. To reach clean air goals in the next seven to 16 years provided by the Clean Air Act (CCA) d eadlines, Southern California must not only continue its diligence but intensify its polluti on reduction efforts. Continuing the SCAB’s progress toward clean air is a challenging ta sk, not only to recognize and understand complex interactions between emissions and resulting air quality, but also to pursue the most effective possible set of strategies to improve air quality while maintaining a healthy economy.
The purposes of the 2012 AQMP for the SCAB are to set forth a comprehensive and integrated program that will lead the SCAB into compliance with the federal 24-hour PM 2.5 air quality standard, to satisfy the planning re quirements of the federal CCA, a nd to provide an update to the SCAB’s commitments towards meeting the federal 8- hour ozone standards. It will also serve to satisfy the recent U.S. EPA proposed requirement for a new attainment demonstration of the revoked 1-hour ozone standard, as well as a VMT emissions offset demonstration. Specifically, the AQMP serves as the official SIP submittal for the federal 2006 24-hour PM 2.5 standard. In addition, the 2012 AQMP updates specific new control measures and commitments for emissions reductions to implement the atta inment strategy for the 8-hour ozone State Implementation Plan (SIP), and thus help to reduce reliance on CAA S ection 182(e)(5) long-term

measures.C H A P T E R I I

PROPOSED RULE LANGUAGECHAPTER II – PROPOSED RULE LANGUAGE

Proposed Rule 1114 II-1 May 2013 PROPOSED RULE
Proposed Rule 1114 – Petroleum Refinery Coking Operations

A. PURPOSE AND APPLICABILITY
The purpose of the rule is to reduce emissions re sulting from atmospheric venting of coke drums and applies to petroleum re fineries operating DCU’s.

B. DEFINITIONS
The proposed rule has four definitions:

 Coke Drum

 Delayed Coking Unit

 Petroleum Refinery

 Turnaround
C. REQUIREMENTS
The proposed rule requires the ow ner or operator of a DCU to reduc e the pressure in a coke drum to less than two (2) psig prior to venting the coke drum to at mosphere, effective six months following rule adoption.
Facilities not able to comply by this date will be allowed an extra period of time, depending on the number of DCU’s they operate, to make nece ssary process and equipment modifications that can be completed during downtime periods for maintenance and repair known as turnarounds. Effective 12 months after rule adoption, facilities operating a single DCU are required to depressurize each coke drum to less than five ps ig until achieving compliance with the less than two psig limit following the first unit turnar ound scheduled after the effective date or by December 31, 2016, whichever is earlier.
Facilities operating more than one DCU have two options availabl e. Under the fi rst option, they must submit for the Executive Officer’ approval w ithin six months from rule adoption a baseline calculation, along with substantiatin g records identifying the facility wide average coke drum internal pressure at which atmospheric venting was initiated during the year 2012. Facilities currently not equipp ed with monitoring and recording instru mentation necessary to determine the 2012 baseline may use general engineering practi ces for calculating this value, subject to approval.
Effective 12 months from rule adoption, these f acilities must depressu rize a coke drum to atmosphere to a pressure less than 110% of the 2012 baseline pressure until the first turnaround at an affected DCU following the effective date or by December 31, 2016, whichever is earlier. Upon completion of the turnaround th e facility is required to depr essurize each coke drum at an affected DCU prior to venting to atmosphere to less than five psig until achieving compliance with the two psig limit within the following 24 months.
Under the second option, effectiv e 12 months following rule adop tion, facilities operating more than one DCU must depressurize each coke drum to less than five psig until the first turnaroundFINAL STAFF REPORT

Proposed Rule 1114 II-2 May 2013 at an affected DCU following the effective date or by December 31, 2016, whichever is earlier. Upon completion of the turnaround, th ese facilities must depressuri ze their coke drums to less than five psig until achieving less than two psig depressurization requirement within the next 24 months.

Facilities that need extended co mpliance dates must submit any required permit applications to the Executive Officer at least 9 months prior to the applicable compliance dates.

D. MONITORING AND RECORDING Effective six months after rule adoption, the owner or operator of a DCU is required to:

 Monitor and record continuously the internal pressure of a coke drum from the time of feed introduction until the coke drum pressure is less than two psig, us ing a device that is calibrated at least annually according to manufacturer’s specifications;

 Monitor and record continuously the position of the coke drum atmospheric vent valve (open or closed); facilities that do not have the this capa bility upon effective date have the option of either continuously monitoring and recording the coke drum blowdown vent valve position or the temperature of the atmospheric vent line at a location above downstream of the atmospheric vent valve, from feed introduction until atmospheric venting is initiated, until completing the firs t unit turnaround at an affected DCU or by December 31, 2016, whichever is earlier, after which the atmospheric vent valve must be monitored;

 Maintain the monitoring and recording equi pment in good operating condition except for periods of downtime caused by breakdowns , or unplanned maintenance or calibration , which cannot exceed 96 hours per DCU per cale ndar year. During downtime periods, the owner or operator is required to manually reco rd the coke drum internal pressure and the atmospheric vent valve position every five minutes for a period of at least 15 minutes immediately prior to the coke dr um being vented to atmosphere.

For facilities that need an ex tended compliance schedule, these requirements are effective 12 months after rule adoption.

E. NOTIFICATION
In the event of a failure of the monitoring or re cording equipment, the ow ner or operator of a DCU is required to notify the Executive Officer by telephone within 24 hours from the time the failure occurred.

F. RECORDKEEPING
Effective six months after rule adoption, the owne r or operator of a DCU is required to maintain records of the coke drum’s internal pressure, the atmospheric vent valv e position, pressure gauge calibration records and records of monitoring system breakdown periods, along with associated manual readings, and make them available to th e Executive Officer upon request. The records have to be maintained for a period of five years and made available to the Executive Officer upon request. For facilities that need an extend ed compliance schedule, these requirements are effective 12 months after rule adoption.CHAPTER II – PROPOSED RULE LANGUAGE

Proposed Rule 1114 II-3 May 2013 G. EXEMPTIONS
The proposed rule exempts all coke drums from the provisions of Rule 404 – Particulate Matter – Concentration. This exemption merely codifi es an existing legal interpretation, already implemented by Engineering and Compliance, that Rule 404 does not apply to a delayed coking drum.C H A P T E R I I I

EMISSION INVENTORYCHAPTER III – EMISSION INVENTORY

Proposed Rule 1114 III-1 May 2013 A. AFFECTED FACILITIES

Affected facilities are the petroleum refineries with NAICS Code 324110 that operate delayed coking units and are located in the SCAB. There are six refineries operating eight DCU’s with a total of 36 coke drums.

B. EMISSION INVENTORY

Source Tests As stated earlier, beginning in 2003, SCAQMD staff conducted several source tests at the refineries in the basin in order to assess emissi ons from coke drums. During the source tests, staff had little input over the pro cess parameters, such as the pressure and temperature at which the drums were vented and did not run multiple test s at the same location in order to be able to develop any correlations between these paramete rs. Consequently, the results were overall inconclusive, due also to additi onal factors. For example: one test had to be aborted due to hazardous conditions that developed; during anothe r source test samples were not taken due to the extremely short vent time; only qualitative results were obtained as part of a third source test.

The District source test results are summarized in Table 3.1.
Table 3.1 Summary of Distri ct Source Test Results

Refinery Initial Drum Vent Pressure, psig VOC PM Condensable PM/VOC Sulfur Compounds Methane
lbs/cycle

A 3.9 4.28 0.26 0.46 0.45 1.86

B 7 5.3 0.36 1.46 N/A 34
C 0.89 4.44 3.77 0.66 8.18 165.47

D 1 11 1.38 0.34 0.54 N/A 12.72

E 2,3 2.5 N/A N/A N/A N/A N/A

F 0.4 11.16 1.25 12.50 N/A 66.96
1 Results inconclusive, test was not completed due to safety concerns 2 Vent time was very short, not enough sample was collected 3 Qualitative results only Subsequently, the U.S. EPA conducted more compre hensive source tests at the Hovensa refinery in St. Croix, U.S. Virgin Islands [2] in order to quantify emissions from coke drum atmospheric venting. For this reason, staff chose to use th e U.S. EPA source test results as the primary reference for establishing the emission inventory for the delayed coking units in the SCAB. The summary of the Hovensa source test results is presented in Table 3.2:FINAL STAFF REPORT

Proposed Rule 1114 III-2 May 2013 Table 3.2 – Hovensa Source Test Results (lbs/cycle)

VOC PM Semivolatile VOC Methane Drum Vent Pressure (psig)
Average

(4 runs) 178 61.6 6.44 N/A 7.72

Heat Balance Calculation

The PR1114 baseline emission invent ory is estimated based on emissions from all 36 coke drums in the basin. Emissions per single drum are calculated for an average coke drum, assumed cylindrical, with dimensions that represent the we ighted average of all drums; the pressure and temperature under which this drum operates repr esents the weighted average of the operating conditions at the six refineries, based on a survey completed by local refineries [9].

Based on source test results and U.S. EPA input, staff assumed th at prior to venting, the head space of a coke drum is filled with gas contai ning between 97% and 99% steam. In order to calculate the amount of vent ga s, staff assumed that once the atmospheric vent is open, the quench water in the coke drum will flash to st eam and lower the coke bed temperature due to evaporative cooling. Using the h eat balance between the quench water, the coke bed, the coke drum and the steam generated, the amount of steam generated can be calculated such that the drum temperature reaches the water boiling poin t or 212 °F at ambient pressure. The conductive and convective contribution to heat loss from th e coke drum will be assumed minimal for an insulated drum, and is assumed to account for no more than 10% of the heat dissipated.

Assumptions
The following assumptions are used to assist in the estimation of VOC emissions from delayed coking operations.

1. The approximation of the amount of steam generated during the final venting to atmosphere prior to removing coke from the drum based on a heat ba lance of initial and final states is accurate and repres entative for the facilities surveyed.

2. The industry provided survey data, including fac ility specific number and dimensions of coke drums, as well as operating paramete rs for average final depressurization and internal drum temperature prior to venti ng and coking cycle time are accurate and representative for the facilities surveyed.

3. Physical property data for steam, water an d coke, including dens ity, heat capacity and latent heat at operating c onditions identified in the surv ey are representative for the facilities surveyed.

4. Additional physical and operational property da ta (see Tables 3.3, 5.2, and 5.3) related to coke porosity, average drum outage, coke bed height, drum water level prior to venting, as identified through a review of source test results and U.S. EPA input is representative for the facilities surveyed.CHAPTER III – EMISSION INVENTORY

Proposed Rule 1114 III-3 May 2013 5. The final thermodynamic state of a coke drum prior to opening the drum to remove the coke is approximated by a final temperature of 212 °F based on the boiling point of water at atmospheric pressure.

6. The dry vent gas pollutant concentrations as identified through a re view of source test results and U.S. EPA input is represen tative for the facilities surveyed.

Emission Calculations
The heat balance equation for the coke drum is: (1-0.1) x (m c c c + m w c w ) x (t i – t f ) = m s x Δ H vap (1)

where:

m c = coke bed mass (lbs)

c c = coke heat capacity (Btu/lb-°F) t i = average initial temperature of the coke bed (°F) t f = average final temperature of the coke bed (°F)

m s = mass of steam generated (lbs) Δ H vap = water heat of vaporization (Btu/lb) Solving the equation for m s :

m s = 0.9 x (m c c c + m w c w ) x (t i – t f ) / Δ H vap (2) The calculations are performed using weighted averages of parameters obtained from the facilities survey for all 36 drums (see Table 3.3). In order to calculate the emission inventory, the nu mber of annual cycles n eeds to be determined. For the refineries in the SC AQMD, the average cycle durati on for a coke drum is 32.8 hours (16.4 hours coking and 16.4 hours decoking), therefore: For one drum, the number of cycles in a year is: Cycles = 24 hrs/day x 365 days / 32.8 hrs = 267 cycles For all 36 drums in operation, the total number of cycles is: Total cycles = 36 drums x 267 cycl es/drum/year ~ 9,610 cycles/year The emission inventory is determined based on the assumption that the coke drum vent gas moisture is 97% to 99% (steam). As mentioned earlier, the existing emissi ons inventory is based on the U.S. EPA Hovensa source test results, wher e the VOC emissions were 6% by weight of the dry vent gas, the CH4 emissions were 70% of the dry vent gas and HAP emissions were 20% of the VOC emissions. Staff believes that there is not sufficient data to estimate creditable PM and sulfur emissions and emissi on reductions at this time.

The calculations are summarized in Table 3.3.FINAL STAFF REPORT

Proposed Rule 1114 III-4 May 2013 Table 3.3 – Coke Drum Emissi ons Inventory Calculations

Parameter Value Unit Notes Avg drum diameter D 22.3 ft Typical outage 17.15 ft Assumed 0.25 H d Avg. drum height H d 68.6 ft Avg. Coke bed height H c 51.5 ft Assumed 0.75 H d Initial Coke Temp T ci 254 °F Weighted average temperature (survey)
Final coke temp T cf 212 °F Coke density ρ c 84.3 lb/cu ft Coke heat capacity c c 0.27 Btu/lb - °F
Coke porosity p c 0.50 Volume fraction Assumption

Coke mass, m c 847,000 lbs m c = ∏ *D 2 /4*H c * ρ c *p c Water density ρ w 59.5 lb/cu ft Average water level at vent 56. 5 ft Assumed 5' above coke bed Quench water mass 714,000 lbs Water heat of vaporization Δ H vap 960 Btu/lb Water heat content c w 1 Btu/lb - °F Specific volume sat steam V s 21.4 scf/lb At standard conditions
Flashing water mass 37,100 lbs Assume all water is vaporized to saturated steam

Total steam volume V t 794,000 scf Vent gas volume 802,000 scf Displayed @ 99% H 2 O Dry vent gas 8,020 dscf 1 % of total vent gas volume CH4/cycle 237 lbs/cycle 0.7 volume fraction VOC/cycle 55 lbs/cycle As propane (C 3 ) 0.06 vol. fraction HAPs/cycle 11 lbs/cycle
PM/cycle 8 lbs/cycle Based on 0.001 lbs/dscf average from local source tests Average cycle length 16.4 hrs/cycle Number of drums 36 Cycles/year 9610 36 drums VOC inventory 268 tpy CH4 Inventory 1140 tpy HAPs Inventory 54 tpy PM Inventory 38 tpyCHAPTER III – EMISSION INVENTORY

Proposed Rule 1114 III-5 May 2013 Annual emissions are summarized in Table 3.4. It should be noted th at the estimates are conservatively based on a vent stream steam content of 99% although the observed range of moisture content varied between 97% and 99%. The lower mo isture content would imply a higher dry vent gas volume and consequent increase in emission estimates. Based on the methodology used, emissions are proportional to the dry vent gas volume, so that the upper end of the range would be three times higher than the conservative es timate used by staff, as shown in Table 3.4:
Table 3.4 - Coke Drum Annual Emissions Inventory

Estimate VOC HAPs CH4 PM Conservative Estimate (Tons per Year) 268 54 1,140 38
Estimated Range @ 1-3 % Dry Vent Gas (Tons per Year) 268 - 804 54 - 162 1,140 – 3,420 38 - 114

Estimated Potential Emissions
Further review of the source test data by sta ff to determine an upper emission range for DCU operations indicated that a high end temperat ure of roughly 274 °F a pproximated a worse case scenario for comparison purposes and to reflect so me of the existing facilities’ current level of control. Using the calculation steps previous ly outlined for 36 drums with an initial coke temperature of 274 °F results in an estimated district-wide wors e case DCU emission rate of 402 tpy VOC, 80 tpy HAPs, and 1,710 tpy CH4.C H A P T E R I V

CONTROL TECHNOLOGY ASSESSMENTCHAPTER IV - CONTROL TECHNOLOGY ASSESSMENT

Proposed Rule 1114 IV-1 May 2013 Early delayed coker designs had blowdown systems th at were tied into the refinery flare system such that hydrocarbon vapors were flared during coke drum quenching or warming up. Due to environmental considerations though , in modern cokers, the gases are routed back to the main fractionator overhead accumulator where they are recovered and sent to the refinery fuel gas system rather than to the flare. As long as the pr essure in the drum head space is higher than that of the blowdown system it is possible for the va pors to be routed to the blowdown system. However, at the point when the pressures equalize, the operator has to start atmospheric venting in order to depressurize the drum to ambien t pressure and open it for drilling the coke bed.
Since there is a significant amount of pollutant s, including HAPs left in the head space during atmospheric venting, the best way to reduce emissions is to send the vapors in the head space to the maximum extent feasible to the blowdown system prior to switching to atmospheric venting. There are several alternatives for achieving this goal.

One alternative is to increase the drum cooli ng time and reduce the temperature such as to condense more vapors and reduce the drum’s intern al pressure. However, this alternative would increase the coke drum cycle time length a nd therefore reduce the unit throughput, potentially creating a bottleneck in the refinery operations and impacting the refinery’s productivity.

A more realistic alternative is to increase the rate at which va pors are evacuated from the head space to the blowdown system by optionally using either compressors or steam ejectors, thus lowering the drum’s internal pressure as close to ambient pressure as possible and minimizing emissions to atmosphere. Each option has its own advantages and disadvantages. A compressor, which is a complex piece of equipment driven by an electric motor, does not generate any waste stream but has higher capital, ope rating, and maintenance costs. A steam ejector, which uses the Venturi effect of a converging-diverging nozzle to convert the pressure energy of steam to velocity energy which creates a vacuum, cost s less and has lower maintenance and operating costs but generates sour water as a waste stream that needs to be stored and treated.
Staff’s understanding is that the current state of the art for a DC U is to be equipped with steam ejectors for depressurizing the coke drums in a timely manner, thus reducing the length of the cycle and improving the unit’s productivity by bei ng able to process more feed in the same amount of time.
Currently, there are both local and outside California refineries wi th DCU’s that already meet or vent their drums at pressures near the proposed rule depressurization lim it of less than two (2) psig. Considering that the current maximu m allowable atmospheric vent pressure for uncontrolled venting of a coke drum is 15 psig (per 40 CFR 63 Subpart CC), operating at this proposed lower depressurization limit represents a significant emissions reduction (> 90%, see Table 5-4 following). Therefore, the proposed lim its reflect an achieved in practice standard.C H A P T E R V

EMISSION REDUCTIONSCHAPTER V – EMISSION REDUCTIONS

Proposed Rule 1114 V-1 May 2013 This chapter presents the estimated VOC em ission reductions based on the control option incorporated into PR 1114.
From Chapter III – Emissions Inve ntory, the emissions attributed to coke drum venting are as summarized in Table 5.1, reflecting the conserva tive estimate based on one percent dry vent gas and 99% steam:
Table 5.1 Annual Emission Inventory

Pollutant VOC HAPs Methane (CH4) PM

Tons per Year 268 54 1,140 38

Staff estimates that 10 existing coke drums either already achieve the pr oposed depressurization limit or are near the limit, whereas the remaining 26 coke drums, located at four facilities, would need to make modifications to their equipment a nd/or process in order to meet the proposed rule limit. The emission reductions will be determin ed by first calculating the emissions associated with the 26 drums at the current average vent pr essure and temperature and then subtracting the emissions calculated at the proposed rule lim it of less than two psig that approximately corresponds to a temperature of 220 °F. The em issions are calculated based on the same methodology used to calculate the baseline em ission inventory. The parameters used are weighted averages for the 26 dr ums and are listed in Table 5.2.
For one drum, the number of cycles in a year is:
Cycles = 24 hrs/day x 365 days / (17.4 x 2) hrs = 252 cycles For all 26 drums in operation, the total number of cycles is: Total cycles = 26 drums x 252 cycles/drum/year ~ 6,540 cycles/year
The emission inventory calculations are summarized in Table 5.2.FINAL STAFF REPORT

Proposed Rule 1114 V-2 May 2013 Table 5.2 Emissions at Current Condi tions (26 Drums, 7.8 psig avg.)

Parameter Value Unit Notes Avg drum diameter D 20.8 ft Typical outage 17.2 ft Assumed 0.25 of drum height Avg. drum height H d 68.8 ft Avg. Coke bed height H c 51.6 ft Assumed 0.75 of drum height

Initial Coke Temp T ci 220 °F Weighted average temperature (survey) Final coke temp T cf 212 °F Coke density ρ c 84.3 lb/cu ft Coke heat capacity c c 0.27 Btu/lb - °F Coke porosity p c 0.50 Volume fraction Assumption due to channeling Coke mass, m c 739,000 lbs m c = ∏ *D 2 /4*H c * ρ c *p c Water density ρ w 59.5 lb/cu ft Average water level at vent 56.6 ft Assume 5 ft over coke bed Quench water mass 622,700 lbs Water heat of vaporization λ 960 Btu/lb

Water heat content c w 1 Btu/lb - °F Specific volume sat steam V s 21.4 scf/lb Standard conditions
Flashing water mass 32,400 lbs Assume all water is vaporized to saturated steam
Total steam volume V t 692,800 scf Displayed @ 99% steam Vent gas volume (99% H 2 O) 700,000 scf
Dry vent gas 7,000 dscf Methane content/cycle 207 lbs/cycle 0.7 volume fraction VOC content/cycle 48.7 lbs/cycle As propane (C 3 ) 0.06 vol. fraction HAPs content/cycle 9.7 lbs/cycle Assumed 20% of VOC by weight

PM content/cycle 7 lbs/cycle Based on 0.001 lbs/dscf average from local source tests Average cycle time 17.4 hrs/cycle Number of drums 26 Cycles/year 6,540 26 drums VOC 159 tpy Methane 676 tpy HAPs 32 tpy PM 23 tpyCHAPTER V – EMISSION REDUCTIONS

Proposed Rule 1114 V-3 May 2013 The emissions generated when the coke drum is ve nted at less than two psig are calculated based on corresponding coke drum top temperature of 220 °F at the start of venting and the assumption that the final temperature is 212 °F at ambient pressure. Th e results are shown in Table 5.3.FINAL STAFF REPORT

Proposed Rule 1114 V-4 May 2013 Table 5.3 Remaining Emissions after Rule Implementation (26 drums, < 2 psig)

Parameter Value Unit Notes Avg. drum diameter D 20.8 ft Typical outage 17.2 ft Assumed 0.25 of drum height Avg. drum height H d 68.8 ft Avg. Coke bed height H c 51.6 ft Assumed 0.75 of drum height
Initial Coke Temp T ci 254 °F Weighted average temperature (survey) Final coke temp T cf 212 °F Coke density ρ c 84.3 lb/cu ft Coke heat capacity c c 0.27 Btu/lb - °F Coke porosity p c 0.50 Volume fraction Assumption due to channeling Coke mass, m c 739,000 lbs m c = ∏ *D 2 /4*H c * ρ c *p c Water density ρ w 59.5 lb/cu ft Average water level at vent 56.6 ft Assume 5 ft over coke bed

Quench water mass 622,700 lbs Water heat of vaporization λ 960 Btu/lb

Water heat content c w 1 Btu/lb - °F Specific volume sat steam V s 21.4 scf/lb Standard conditions

Flashing water mass 6,170 lbs Assume all water is vaporized to saturated steam Total steam volume V t 132,000 scf Displayed @ 99% steam Vent gas volume (99% H 2 O) 133,000 scf
Dry vent gas 1,330 dscf Methane/cycle 39.3 lbs/cycle 0.7 volume fraction VOC/cycle 9.3 lbs/cycle As propane (C 3 ) 0.06 vol. fraction HAPs/cycle 1.9 lbs/cycle Assumed 20% of VOC by weight
PM/cycle 1.33 lbs/cycle Based on 0.001 lbs/dscf average from local source tests Average cycle time 17.4 hrs/cycle Number of drums 26 Cycles/year 6,540 26 drums VOC Inventory 30 tpy Methane Inventory 129 tpy HAPs Inventory 6 tpy PM Inventory 4 tpyCHAPTER V – EMISSION REDUCTIONS

Proposed Rule 1114 V-5 May 2013 The emissions reduction attributed to the rule are as follows:
VOC = 159 tpy – 30 tpy = 129 tpy
HAPs = 32 tpy – 6 tpy = 26 tpy
CH4 = 676 tpy -129 tpy = 547 tpy
PM = 23 tpy – 4 tpy = 19 tpy

Table 5.4 Estimated Emission Reductions

Estimate VOC HAPs CH4 PM

Baseline Emissions, tpy (All drums) 268 54 1,140 38
Baseline Emissions, tpy (Affected drums) 159 32 676 23 Emissions Reduction (tpy) 129 26 547 19

 % from baseline (all drums) 50

 % from baseline (affected drums) 81

 % from uncontrolled 92*

* Based on upper end of federally allo wable initial vent pressure (see Chap ter III page III-5). The percent reduction from potential emissions independent of existing re gulations would be higher.C H A P T E R V I

COST AND COST EFFECTIVENESSCHAPTER VI - COST AND COST EFFECTIVENESS

Proposed Rule 1114 VI-1 May 2013 A. COSTS
This chapter presents the cost effectiveness ca lculations related to the Proposed Rule 1114 as well as other emission reduction options. Staff evaluated the following options and the cost effectiveness of each is shown be low. Some refineries will incur capital expenditures and annual operating costs for the equipment to be installed that is necessary to ensure compliance with the proposed rule. Following discussi ons with the affected refineri es, staff concluded that two refineries are already able to meet the proposed ru le requirements within six months of the rule adoption. However, four other refineries will ne ed to install new instrumentation and equipment or resize existing equipment in order to compl y. Staff’s understanding is that, due to lower equipment and maintenance costs, these facilities will likely install steam ejectors in order to comply with the depressurization limit required by th e rule, as this is the current design standard for coke drum depressurization.

Based on costs for similar installations at two othe r DCU’s, staff estimates that the total installed cost (TIC) for a steam ejector system is between $1.25 and $3 million. Staff estimates that four steam ejector systems will be installed, of which three will have a $3MM TIC each and one $1.25MM TIC for a total of $10.25 million. Although sta ff believes that the to tal installed costs for similar installations are representative, because of the site-to-site variability that may affect actual upgrades to meet PR 1114, staff is incor porating a contingency f actor of roughly 30%. During individual meetings with refineries, staff was given initial cost estimates for modifications needed to comply with the propose d rule by the affected facilities, amounting to approximately $35 MM.

B. COST EFFECTIVEN ESS CALCULATIONS

In order to calculate the cost effectiveness of the proposed rule , the present value of the capital cost and the operating cost during the useful life of the control equipment and/or program must be calculated, using the following formula:
PV = C + A x PVF, where:
PV = Present Value of the control equipment
C = Capital costs associated with process modifications and/or to install equipment
A = Annual costs incurred to operate the cont rol equipment, estimated at 4% of the capital cost, plus the cost of utilities, estimated at 3% of the capital cost.
PVF = Present Value Factor, which is 15.622 fo r an assumed 25 years equipment life and 4% real interest rate.
The cost effectiveness of the equipment will be calculated using the emission reductions calculated in Chapter V and the formula presented above.
The cost effectiveness of the pr oposed changes and associated cal culations and assumptions used to derive it are shown in the following sections. Cost effectiveness is expressed as the ratioFINAL STAFF REPORT

Proposed Rule 1114 VI-2 May 2013 between the total cost of impl ementing a proposed control measur e and the associated benefits, in this case the emission reduction:
CE = PV / (Emission Reductions x Equipment Life)
The present value is:
PV = $10,250,000 + ($10,250,000 x 0.07 x 15.622) = $ 21,458,785

The cost effectiveness is:
CE = $21,458,785 / (129 tpy x 25 years) = $6,700 / ton VOC reduced
To account for facility-to-facility variability, a contingency factor of 30% has been incorporated as follows:
CE = $6,700 / ton x 1.30 = $8,700 / ton VOC reduced
It should be noted that, because the emission reductions are base d on the 99% steam content in the vent stream, the consequent cost effectiv eness number is conservatively represented at roughly three times the value at th e less conservative end of the range of 97% steam. On an additional note, considering that more vent gas is recovered due to the lo wer depressurization, it is estimated that 1.51 tpd of usable methane in th e vent gas could be recovered, thus lowering the annual fuel costs to the refineries. The 1.51 tpd translates into approximately 268,000 therms per year, which at the current price of $1.072/therm fo r natural gas translates into an estimated $287,300 savings in annual costs fo r the affected facilities.

Table 6.1 – VOC Cost Effectiveness Capital costs ($MM) (Process modifications) $10.25
Present Value ($MM) $21.45
VOC Emission Reduction (TPY) 129
Equipment Life 25
Cost Effectiveness($/ton) $6,700
With 30% Contingency: $8,700/ton

C. INCREMENTAL COST EFFECTIVENESS
Pursuant to Health and Safety Code Section 40920.6, prior to adopting ru les or regulations to meet the requirement for Best Available Re trofit Control Technolog y (BARCT) pursuant toCHAPTER VI - COST AND COST EFFECTIVENESS

Proposed Rule 1114 VI-3 May 2013 Sections 40918, 40919, 40920, and 40920.5, or for a feasib le measure pursuant to Section 40914, SCAQMD is required by the Health and Safety C ode to identify one or more potential control options which achieve emission reduction objectives , determine the cost-effectiveness of each potential control option and determine the increm ental cost-effectiveness of potential control options.
Health and Safety Code 40920.6 re quires determination of incr emental cost-effectiveness of potential control options, defined as “the difference in the dolla r costs divided by the difference in the emission reduction potentials between each progressive/most stringent potential control option as compared to the next less expensive control option”.

Coke Production The most stringent control scenario would be to strive towards eliminating the need for atmospheric venting of the drums by capturing all the vapors and routing them to a fuel gas/blowdown system. In order to achieve this, it is assumed th at an operator would have to increase the cycle time at a minimum by two hour s to condense all the vapors in the headspace below 212 o F prior to opening the drum. The same parameters and assumptions used for calculating the emissions inventory in Table 3.3 Chapter III are ma de in order to calculate the cost of this option. In add ition, the coke bulk density is assumed to be 55 lbs/cu ft. For the average drum the coke bed volume is: V = (22.25^2 x 3.14 / 4 x 52) cu ft x 7.481 ga l / cu ft x 1 bbl / 42 gal = 3,600 bbl The average coking cycle per drum is 16.44 hours, resulting in a charge rate of: Charge rate = 3,600 bbl / 16.44 hrs = 219 bbl/hr If the decoking cycle is extended by two hours, the coking cycle will have to be extended by two hours also, therefore the charge rate in this instance will be: Charge rate = 3,600 bbl / 18.44 hrs = 195 bbl/hr The lower charge rate represents a decrease of: Decrease in charge rate = (219 -195) / 219 x 100 = 11 % The decrease will negatively impact the production of coker gasoline and petroleum coke since less is produced per day. The number of full cycles (2 x 18.44 hr) per year per drum is: Cycles = 24 hrs/day x 365 days/yr / 36.88 hrs/cycle = 238 cycles/yr/drum The number of full cycles (2 x 16.44 hr) cycles per year per drums is: Cycles = 24 hrs/day x 365 days/yr / 32.88 hrs/cycle = 266 cycles/yr/drum The 28 cycles difference represents lost production per year, which can be calculated for all 36 drums: Lost product = (22.25^2 x 3.14 / 4 x 52) cu ft x 55 lbs/cu ft x 36 drums x 28 cycles/yr x 1 ton / 2,000 lbs = 560,178 tons coke/yr At the current petroleum coke market conditions, a ton of c oke can sell for approximately $150/ton; therefore, the va lue of lost production is: Cost of lost coke production = 560,1 78 tons x $150/ton = $84MM/yrFINAL STAFF REPORT

Proposed Rule 1114 VI-4 May 2013 Gasoline Production The 11% decrease in charge rate will also aff ect the gasoline production of the delayed coking unit. In order to calculate the lost gasoline production the following assumptions are made:

 Assume the average feed rate for the six delayed coking units is 40,000 bbl/day

 The typical gasoline yield is 16% wt

 The specific gravity of coker resid feed is 8.37 lb/gal

 The specific gravity of gasoline is 5.6 lb/gal

 Average retail price for a ga llon of gasoline is $ 3.80 The lost gasoline production is: Lost gasoline production = 0.11 x 40,000 bbl/day x 6 x 42 gal/bbl x 8.37 lb/gal x 0.16 / 5.6 lbs/gal = 265,162 gal/day The wholesale price per gallon of gasoline is the retail less federal, state and local taxes, assumed to be approximately 55 cents per gallon based on data from the California Energy Commission The annualized cost of the lost gasoline production is: Cost = 265,162 gal/day x $(3.80- 0.55)/g al x 365 days/yr = $315MM/yr
The total annual cost of lost coke and gasoline production is:
Total cost = $84MM + $315MM = $399 MM/yr

Incremental Cost Effectiveness
The most stringent control is to control all emi ssions from venting, which is the total emission inventory of 268 tpy. The next less expensive c ontrol that is proposed by the rule is to reduce emissions by 129 tpy. As shown before, the cost of the proposed rule high range present value is:
PV = $ 27,896,369 (at a 30% contingency) Per Health and Safety Code 40920.6, the in cremental cost effectiveness is:
Incremental Cost = ($399,000,000 – $27,896,369) / (268 tons – 129 tons) = = $2.7 MM/ton VOC reduced

Table 6.2 summarizes the total annual cost increase, perman ent emission reductions and incremental cost effectiveness of the two scenarios discussed above.CHAPTER VI - COST AND COST EFFECTIVENESS

Proposed Rule 1114 VI-5 May 2013 Table 6.2

Control Option VOC Reductions (tpy) Annual Cost Increase ($) Incremental Cost Effectiveness No Project 0 0 N/A PR 1114 < 2 psig 129 $27,896,369 $8,700 No Atmospheric Venting 268 $399,000,000 $2,700,000C H A P T E R V I I

COMMENTS AND RESPONSESCHAPTER VII – COMMENTS AND RESPONSES

Proposed Rule 1114 VII-1 May 2013 The following comments were received with regards to the public workshop conducted on December 12, 2012 in Wilmington, CA.

Comment #1

What is the rationale for the initial six m onths deadline following rule adoption and the additional extension in the compliance deadline beyond the six months fo r certain facilities?
Response
The initial six month period is proposed to allow for any modifications that can be accomplished outside of a turnaround such as software or proce dural updates, for facilities that can achieve the proposed final compliance limit with existing e quipment but that may require quality control improvements to ensure safety and continuous compliance. Units in petroleum refineries typically operate continuously on approximately fi ve year cycles in-between shutdown periods for maintenance and repair, or “turnaround” pe riods. It is during these turnarounds that necessary modifications can be implemented for ru le compliance. The proposed up to five year period is intended to accommodate the staggere d nature of the various turnaround periods at multiple facilities. Furthermore, projects th at might be required for compliance with the proposed rule involve engineer ing and design, funding, equipmen t procurement, new hardware and require adequate time to complete. Therefor e, staff believes that th e proposed timelines are reasonable.

Comment #2
What are the enforceable mechanisms for ensuring compliance with the proposed rule?
Response
Facilities will be required under the proposed rule to keep and pr ovide records of the coke drum internal pressure, atmospheric vent valve posit ion (open/closed), on a continuously monitored basis. Calibration records for the pressure gauges will also be required under the proposal to further demonstrate compliance.

Comment #3
What are the provisions for failure to comply w ith the interim requirement s associated with the proposed rule?
Response
Failure to comply with the inte rim requirements associated with the proposed rule would put a facility in violation of the ru le, which would trigger the issuan ce of a Notice of Violation, and subsequent enforcement action.

Comment #4
Can the compliance schedule be more explicitly linked to turnaround activities to ensure compliance is achieved as soon as possible?FINAL STAFF REPORT

Proposed Rule 1114 VII-2 May 2013 Response

Staff has evaluated issues associated with th e planning of maintenance turnaround for delayed coking units and the proposed rule language was modified to require compliance following the unit turnaround or a set date , whichever is earlier.

Comment #5
What is the relationship between the quality of crude oil feedstocks and the potential emissions and emission characterization? Can particul ar feedstocks be lim ited or excluded from processing?
Response
Typically, light sweet crude oil feedstocks have a lower amount of sulfur, whereas heavy, sour crude oil feedstocks cont ain a relatively higher amount of su lfur (~4%) as we ll as long chain molecules called asphaltenes which require more intensive processing and pollution controls. While there are no regulations limiting the type of feedstocks used, there are limits on the amount of emissions being generated from proce ssing them in units upstream or downstream of the delayed coking operation.

Comment #6
There should be more community outreach and part icipation in the rule development process to improve awareness and address concerns.
Response
Staff publishes workshop notices on its website as well as local ne wspapers. The public workshop for PR 1114 was held in the Wilmington area on December 12, 2012 at 5:30 PM in an effort to maximize public awareness and participat ion and be able to hear directly from the affected public. Staff will continue to look for additional ways to enhance its outreach efforts and increase community awareness about proposed new regulations.

Comment #7
Staff’s estimated cost for compliance is based on an assessment of “similar” installations. Industry has provided a much higher estimated co st that is more facility specific. The representativeness for the range in costs s hould be reconsidered.
Response
The initial cost estimate provide d by industry are design-based, wh ile the similar installations used by staff for comparison were retrofit projects, therefore staff believes the cost estimate is adequate since they have similar compliance requirements. However, in order to account for site to site variability, staff is broadening the co st estimates by incorporating an additional 30% contingency into the approximation.CHAPTER VII – COMMENTS AND RESPONSES

Proposed Rule 1114 VII-3 May 2013 Comment #8
How does a facility demonstrate compliance with the proposed de pressurization limit?
Response
Once the internal pressure of the coke drum fa lls below two psig while being depressurized to the blowdown system at the end of the coking cy cle, the operator has achieved compliance with the depressurization limit. During the short tran sition period when the drum is isolated from blowdown and until the atmospheric vent valve is open, there may be a spike in the drum pressure that may momentarily exceed the spec ified limit, however these spikes will not be considered a violation of the depressurization limit.

Comment #9
Can a facility calcula te the proposed 2012 interim average depressurization baseline based on general engineering practices due to the lack of necessary monito ring instrumentation that it did not have during the baseline year?
Response
Staff is modifying the rule language to allow, at facilities where monitoring and recording equipment is not yet installed, calculations usi ng general engineering practices and substantiating records to be submitted to the Executive Offi cer for approval for determining the 2012 vent pressure average for all drums at a facility.

Comment #10
Facilities need some time following rule adop tion to implement the continuous monitoring requirement of the proposed rule.
Response
The proposed rule has been modified to ha rmonize the effective dates for the continuous monitoring and depressurization requirements.

Comment #11
The continuous monitoring requirement should allow for downtime to account for maintenance and breakdown periods.
Response
Rule language was modified to allow for 96 ho urs of downtime per calendar year per DCU due to breakdowns , o r maintenance or calibration of the monitoring equipment for the coke drum pressure and the atmospheric valve position. Ma nual readings for pressure and valve position will be required at five minute set intervals for a period of at least 15 minutes immediately prior to venting the coke drum to atmosphere.FINAL STAFF REPORT

Proposed Rule 1114 VII-4 May 2013 Comment #12
The exemption for Rules 404, 405 and 407 under the proposed rule should apply to any delayed coking unit that is compliant with the provisions of th e proposed rule, and not limited to only those that meet the final depr essurization limit of two psig.
Response
Staff is proposing to exempt de layed coking units from the provi sions of Rule 404 only based on a determination that the rule does not apply to delayed coking units. Sta ff does not believe that exemptions from Rules 405 and 407 are necessary after evaluating DCU sour ce test results that show compliance with the mass emission and CO emission limits; Rule 407 provisions for sulfur compounds emissions do not apply to e quipment subject to Regulation XI.

Comment #13
The proposed rule should allow for additional time to meet the final depressurization limit at the Executive Officer’s discretion if scheduling or othe r unforeseen events necessitate a slippage in otherwise planned turnaround events during which the equipment modifications needed to meet the proposed final limit would occur. Rule 1105.1 has a similar provision.
Response
Because the US EPA generally disapproves incor poration of Executive Officer discretion into the State Implementation Plan (SIP), it is the gene ral policy of the District to avoid incorporating this approach into rule language. Other admini strative remedies, such as the Hearing Board, are available for such situations.

Comment #14
For clarification purposes, the definition of delayed coking unit should refer to a “main” fractionators rather than a “single” fractionator, and references to operation should refer to “venting” rather than “discharging” to atmosphere.
Response
The proposed rule language has been updated to replace the words “single” and “discharging” with “main” and “venting”, respectively, as noted, in paragraph (b)(2) and (c)(1).

Comment #15

The emission calculation section in the staff re port should more clearly indicate that the inventory is based on estimates.
Response
An additional section listing the emission calculation assumptions has been added to the staff report.CHAPTER VII – COMMENTS AND RESPONSES

Proposed Rule 1114 VII-5 May 2013 Comment #16
The process flow diagram provided in the prelim inary draft staff report is unclear and should identify fresh feed going to the main fractionators rather than directly to the delayed coker heater.
Response
The process flow diagram has been replaced with a more detailed depicti on, including the initial feed into the main fractionators.

Comment #17
The data from the source test results identified in the staff report do not establish a correlation between the drum initial venting pressure and emissions.
Response
The source tests conducted at local refineries, as not ed in the preliminary draft staff report, were not run to establish correlations. Prior to draw ing any conclusions with respect to correlating pressure and emissions, additional testing wo uld be required. While industry may support additional testing in order to establish correlat ions between process para meters, District staff believes that the use of a theoretical approximati on based on the temperature driven heat balance methodology supported by U.S. EPA is sufficient to establish emission estimates and to demonstrate effectiveness. Based on discu ssions with the refine ries and WSPA, with consideration of the assumptions , facilities concur that a h eat balance methodology is the preferred approach over additional source tests.

Comment #18
Reference to the phrase “near-c ompliance” is subjective and am biguous and should not be used in the staff report.
Response
The phrase “near-compliance” has been remove d. Where appropriate, when describing the current status of affected facili ties, the more objective reference to current operating pressures is used instead.

Comment #19
Would periods of downtime at DCU’s, such as heater tube spal ling or other unplanned breakdowns and repairs be construed as “T urnarounds” and therefore trigger compliance deadlines?
Response

Staff’s intention is to link the planned turnaround activities to deadlines for achieving compliance. Staff would consider a DCU to be shut down for turnaround when all major vessels,FINAL STAFF REPORT

Proposed Rule 1114 VII-6 May 2013 including the main fractionator, have been gas freed and opene d. Stoppages in production for heater spalling, unplanned breakdown and repairs would not be considered turnarounds for the purpose of this rule.

Comment #20
The requirement to continuously monitor th e vent valve position ma y require equipment upgrades dependent on turnaround scheduling. Can alternative pa rameters that are currently being monitored or that do not rely on turn around installation be used in the interim?
Response
The proposed rule has incorporated an alterna tive monitoring provision allowed until the next unit turnaround but no later than December 31, 2016, whichever is earlier, for monitoring the blowdown valve position or coke drum vent pipe temperatur e, in lieu of monitoring the atmospheric vent valve position.

Comment #21
Can a facility’s safety interloc k system for the coke drum ope ration be used to demonstrate compliance with the atmospheric vent valve pos ition monitoring (open or closed) and recording requirement?
Response
The purpose of the vent valve monitoring requireme nt is to determine when atmospheric venting has occurred. District staff w ould consider continuous monitori ng and recording of the vent valve via a safety interlock system to meet the conditions for determining when atmospheric venting has occurred, so long as the safety inte rlock conditions clearly indicate a closed or opened position, and would consider a partially open valve, or valv e that is in the process of being opened or closed, to be opened, until fully closed.C H A P T E R V I I I

IMPACT ASSESSMENTCHAPTER VIII – IMPACT ASSESSMENTS

Proposed Rule 1114 VIII-1 May 2013 A. ENVIRONMENTAL IMPACT ASSESSMENT
Pursuant to California Environmental Qualit y Act (CEQA) Guidelines §15252 and §15162 and SCAQMD Rule 110, the SCAQMD has prepared an Environmental Assessment (EA) for Proposed Rule 1114. The environmental analysis in the Draft EA concluded that Proposed Rule 1114 would not generate any sign ificant adverse environmental impacts. The Draft EA was released for a 30-day public review and comment period fro m February 28, 2013 to March 29, 2013, resulting in the receipt of two comment lette rs. Both comment letters and responses are included as Appendix D of the EA. Since the release of the Draft EA, minor modifi cations have been made to the document. However, none of the modifications alter any c onclusions reached in th e Draft EA, nor provide new information of substantial importance relative to the draft document. Moreover, these minor revisions do not require reci rculation of the Draft EA pur suant to CEQA Guidelines §15073.5 and §15088.5. Therefore, the Draft EA is now a Fina l EA and is included as an attachment to this Governing Board package. Prior to maki ng a decision on the proposed adoption of Rule 1114, the SCAQMD Governing Board must review and certify the Fina l EA as providing adequate information on the potential adverse environmental impacts of the proposed project.
Pursuant to California Environmental Quality Act (CEQA) Guidelines §15252 and §15162 and SCAQMD Rule 110, the SCAQMD has prepared an Environmental Assessment (EA) for P R 1114. The environmental analysis in the Draft EA concluded that P R 1114 would not generate any significant adverse environ mental impacts. The Draft EA was released for a 30

- day public review and comment period from February 28 , 2013 to March 29 , 2013. Any comments received during the public comment period on the analysis presented in the Draft EA will be responded to and in cluded in the Final EA. Prior to making a decisi on on the proposed adoption of P R 1114, the SCAQMD Governing Board must revi ew and certify the Fi nal EA as providing adequate information on the potential adverse environmental impacts of the proposed projec t. C opies of the CEQA document prepared for P R 11 1 4, can be obtained by calling the SC AQMD’s Public Information Center at (909) 396

- 2039 or by downloading it from the SC AQMD’s website at: http://www.aqmd.gov/ceqa/aqmd.html

. B. SOCIOECONOMIC ASSESSMENT
PR 1114 would require petroleum refineries with delayed c oking units (DCU’s) to reduce pressure in coke drums to less than two pounds per pre ssure inch gauge (psi g) prior to venting coke drums to atmosphere. In addition, PR 1114 would require the aff ected facilities to continuously monitor and record th e internal pressure of coke dr ums, and maintain records for a period of five years.

Affected Industries The proposed rule would affect si x refineries. All six affected refineries are located in Los Angeles County. The affected fac ilities belong to the sectors of petroleum refineries [North American Industrial Classificat ion System (NAICS) 324110].
Compliance Cost
It is assumed that affected refineries would in stall steam ejector systems to comply with the proposed pressure limit. Out of the six affected refineries, two are already capable of meetingFINAL STAFF REPORT

Proposed Rule 1114 VIII-2 May 2013 the proposed pressure limits. The remaining four refineries are expected to install four steam ejector systems. The capital and installation cost of three steam ejector systems is estimated at $3 million each. The cost of the remaining steam ejector system is estimated to be $1.25 million. Staff is incorporating a conti ngency factor of 30 percent of capital and installation cost to account for site-to-site va riability that may affect actual upgrades to comply with PR 1114. This would bring the total one-time cost to $13.33 million. Based on the equipment life of each system at 25 years and a four-p ercent real interest rate, the annualized cost of capital and installation for all four systems is estimated to be $0.85 million. The annual operating and maintenance cost of a st eam ejector system is assumed to be seven percent of the capital, installation, and continge ncy cost, and is estimated to be $0.93 million for all four systems. Of the $0.93 million, $0.53 million is assumed for labor maintenance and the remaining for additional utility costs ($0.40 m illion). The annual cost of monitoring and recordkeeping is expected to be minimal and thus is not considered here . The total annual cost of PR 1114 is estimated to be $1.79 million.
Regional Economic Impacts The cost of PR 1114 is used as input to an economic model, REMI, for an assessment of secondary and induced impacts from 2013 to 2035. Costs of equipmen t, installation, and operating and maintenance would result in increase s in the cost of doing business for petroleum refineries. The additional labor required for maintaining steam ejector systems would result in a reduction in labor productivity for the affected refineries because more labor will now be required to produce the same amount of output. Additional purchases of steam ejector systems ar e expected to increase sales of the machinery manufacturing sector. However, none of those facilities are locate d within the four-county area. Installation of the above equipment, however, is expected to benefit the construction, and professional and technical se rvices sectors locally. Overall, five jobs could be created annuall y, on average, between 2013 and 2035, which is about 0.0001 percent of the baseline jobs in the four c ounty area. Table 1 presents the estimated job impact by industry. In the first four years (2013-2016), there would be additional jobs created in the overall economy. The sectors of construction and professional and tec hnical services would gain a larger share of additional jobs due to additional spending on equipment installations. Overall, positive job impacts from the expenditu res made by petroleum refineries would more than offset the jobs forgone from the additiona l cost of doing business. The remaining sectors would incur minor jobs forgone from seconda ry and induced impacts of the proposed rule.CHAPTER VIII – IMPACT ASSESSMENTS

Proposed Rule 1114 VIII-3 May 2013 Table 1 - Job Impacts of Proposed Rule

Industries 2013 2016 2035 Average Annual (2013-2035)

Construction 17 16 -1 2
Manufacturing 2 1 0 0

Wholesale Trade 1 1 0 0

Retail Trade 4 3 -1 0
Professional, Scientific, and Technical Serv. 8 8 0 1
Administrative and Waste Management Serv. 2 2 0 0

Health Care and Social Assistance 3 2 0 0

Accommodation and Food Services 2 2 0 0
Other Services, except Public Administration 2 2 0 0

Government 3 3 0 0

Other Industries 4 3 0 0

Total* 48 43 -2 5

* Numbers may not add up to the total due to rounding. Rule Adoption Relative to the Cost-Effectiveness Schedule On October 14, 1994, the Governing Board adopted a resolution that requi res staff to address whether proposed rules being considered for adoption are presented in rank order by costeffectiveness as defined in the Air Quality Management Plan (AQM P). PR 1114 partially implements Control Measure MCS-01—Applicati on of All Feasible Measures—in the 2012 AQMP. The cost-effectiveness of Control Measure MCS-01 was not assessed for the 2012 AQMP. The overall cost effectiv eness of the proposed rule is es timated to be $8,700 per ton of VOC, which is well below the cost-effectiven ess of recently adopted VOC rules.

C. COMPARATIVE ANALYSIS
Pursuant to Health and Safety Code Section 40727.7 staff has prepared a comparison of existing or proposed AQMD rules, regulations, requirement s with other California Districts and federal air pollution control measures that apply to the same source type. The following table summarizes the analysis:FINAL STAFF REPORT

Proposed Rule 1114 VIII-4 May 2013 Comparison of PR 1114 with 40 CFR 60 Subpart Ja and 40 CFR 63 Subpart CC

Category PR 1114 40 CFR 60 Subpart Ja* 40 CFR 63 Subpart CC
Averaging provisions, units, and any other pertinent provisions associated with emission limits Drum pressure, psig Drum pressu re, psig Drum pressure, psig

Operating parameters and work practice requirements. Depressurize drum to less than two psig Depressurize drum to 5 psig Drum vent gas at > 15 psig must be routed to control device Monitoring, reporting, and recordkeeping requirements, including test methods, format, content, and frequency Continuous pressure and vent valve monitoring and recording. Maintain records for 5 years Not identified Continuous monitoring of the control device relevant parameter, performance test, recordkeeping and semiannual reporting * Applies to new or modified DCU’s

D. DRAFT FINDINGS UNDER CALIFORNIA HEALTH AND SAFETY CODE SECTION 40727
Health and Safety Code Section 40727 requires th at prior to adopting, amending or repealing rules, 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 adopt Rule 1114 – Petroleum Refinery Coking Operations, to pa rtially implement Control Measure CM #2012 MCS-01 – Application of All Feasible Measures Assessment from the 2012 AQMP and help AQMD attain the National Ambient Air Quality Standard for ozone for which AQMD is classified as an Extreme Non-Attainment Area.
Authority: The District obtains its authority to adopt, amend or repeal rules and regulations from California Health and Safety Code Sections 39002, 40000, 40001, 40440, 40441, 40463, 40702, and 40725 through 40728, and 41508.
Clarity: Rule 1114 – Petroleum Refinery Coking Oper ations as proposed to be adopted, is written or displayed so that its meaning can be easily understood by the persons directly affected by it.
Consistency: Proposed Rule 1114 – Petroleum Refinery Coking Operations is in harmony with, and not in conflict with or contradictory to, exis ting statutes, court decisi ons, or federal or state regulations.
Non Duplication: Rule 1114 – Petroleum Refinery Coki ng Operations, as proposed to be adopted, does not impose the same requirements as any existing state or federal regulations, and the amendments are necessary and proper to execute the powers and duties granted to, and imposed upon, the District.

Reference: This regulation would implement, interp ret or make specific the provisions of: Health and Safety Code Sections 40001 (rules to achieve ambient air quality standards),CHAPTER VIII – IMPACT ASSESSMENTS

Proposed Rule 1114 VIII-5 May 2013 40440(a) and (c) (rules to carry out the Air Quality Management Plan and rules which are also cost-effective and efficient), 40702 (do such acts necessary to execute duties imposed by law), and 40910 et seq., (California Clean Air Act).REFERENCES

Proposed Rule 1114 May 2013 1 Paul J. Ellis and Christopher A. Paul, “Tutorial: Delayed Coking Fundamentals”, 1998.

2 http://www.epa.gov/ttn/atw/petref/petrefpg.html

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3 http://en.wikipedia.org/wiki/Delayed_coker

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4 40 CFR 63.640 – National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries, August 18, 1995.

5 Federal Register/Vol. 73, No. 122, June 24, 2008 p. 35857.

6 http://energyalmanac.ca.gov/gasoline/gasoline_taxes.html

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7 “Chemical Engineering”, February 2011, p. 60.

8 Perry, R.H., Green, D.W., “Perry’s Chemi cal Engineer’s Handbook”, Seventh Edition, McGraw-Hill, 1997.

9 SCAQMD Source Tests of Dela yed Coking Units at Six Local Refineries, 2003 – 2009.

10 Communication between U.S. EPA Brenda Shine and Euge n Teszler, SCAQMD, 2012.