ATTACHMENT F 

SOUTH COAST AIR QUALITY 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 Ono - 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 Engineer 
SOUTH COAST AIR QUALITY 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 SUMMARY ---------------------------------------------------------------------------- ES-1 

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

A. Historical Review ------------------------------------------------------------------------ I-1 

B. AQMD Rules for Petroleum Refineries ----------------------------------------------- I-2 

C. Other Districts’ Rules for Coking Units at Petroleum Refineries ------------------ I-4 

D. Federal Regulations for Coking Units at Petroleum Refineries -------------------- I-4 

E. Affected Facilities ------------------------------------------------------------------------ I-5 

F. Process Description ---------------------------------------------------------------------- I-5 

G. Legislative Authority -------------------------------------------------------------------- I-7 

CHAPTER II – PROPOSED RULE LANGUAGE -------------------------------------------------- II-1 

A. Purpose and Applicability -------------------------------------------------------------- II-1 

B. Definitions ------------------------------------------------------------------------------- II-1 

C. Requirements ---------------------------------------------------------------------------- II-1 

D. Monitoring and Recording ------------------------------------------------------------- II-2 

E. Notification ------------------------------------------------------------------------------ II-2 

F. Recordkeeping --------------------------------------------------------------------------- II-2 

G. Exemptions ------------------------------------------------------------------------------ II-3 

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

A. Affected Facilities ---------------------------------------------------------------------- III-1 

B. Emission Inventory -------------------------------------------------------------------- III-1 

CHAPTER IV - CONTROL TECHNOLOGY ASSESSMENT ---------------------------------- IV-1 

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

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

A. Costs ------------------------------------------------------------------------------------ VI-1 

B. Cost Effectiveness Calculations ------------------------------------------------------ VI-1 

C. Incremental Cost Effectiveness ------------------------------------------------------ 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 

REFERENCES 
EXECUTIVE SUMMARY 

Proposed Rule 1114 ES-1 May 2013

Achieving attainment status for ambient ozone and particulate concentration in the South Coast 

Air Basin (SCAB) as more stringent federal air quality standards are adopted and implemented is 

required. The South Coast Air Quality Management 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 Management Plan (AQMP) revisions have been 

developed in partnership with California Air Resources Board (CARB), U.S. EPA, Southern 

California Association of Governments (SCAG) and stakeholders throughout the region, 

including input from local government, health and environmental organizations, and the business 

community. 

The AQMP is the blueprint for how to meet and maintain state and federal air quality standards. 

The 2007 AQMP identifies Control Measures needed to demonstrate attainment with the federal 

annual average PM2.5 standard by 2015 and federal 8-hr ozone standard by 2023. The 2012 

AQMP identifies Control Measures needed to demonstrate attainment with the federal 24-hour 

standard for PM2.5 by 2014 in the SCAB. In addition, the 2012 AQMP provides updates on 

progress towards meeting the 8-hour ozone standard for 2023, an attainment demonstration for 

the revoked 1-hour ozone standard, a vehicle per miles traveled (VMT) offset demonstration for 

ozone standards, and a report on the health effects of PM2.5. In the 2012 AQMP, Control 

Measure MCS-01 - All Feasible Measures Assessment 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 technology standards. The 2012 AQMP Control Measure 

MCS-01 provides the impetus for developing 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 compounds (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 nine years, District staff has conducted studies 

of emissions from atmospheric venting of delayed coking units (DCU’s) at local refineries, 

concluding that there is a sufficient amount of VOC, PM, methane (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 significant and, as a result, in 2008, U.S. EPA 

promulgated 40 CFR 60 Subpart Ja, which establishes 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 refineries 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 testing on various equipment, including DCU’s. Therefore, based 

on feedback from the refineries, staff awaited the latest source testing information in an effort to 

establish an emissions baseline. However, the quality of additional data collected left a lot to be 

desired. Thus, over the past six months, staff has 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 California has determined under Proposition 65 that several POM 

compounds (including benzo[b]fluoranthene, benzo[j]fluoranthene, benzo[k]fluoranthene, benzo[a]pyrene, chrysene, 

indeno[1,2,3-cd]pyrene, 3,7-dinitrofluoranthene, and 3,9-dinitrofluoranthene) are carcinogencs (CCR, 1997). 
FINAL STAFF REPORT 

Proposed Rule 1114 ES-2 May 2013

public on alternate approaches to estimate emissions from DCU’s and has recently reached 

consensus. 

The purpose of PR 1114 is to minimize the amount of pollutants generated 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 proposed rule includes the following: 

 Establishes a limit of less than two psig for 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 pressure 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 delayed coking unit taking advantage of the 

alternate compliance schedule to demonstrate 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 requirements for the coke drum internal pressure, atmospheric 

vent valve or equivalent interim parameter, 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 reductions of 129 tpy VOC, 547 tpy of 

CH4 and 26 tpy HAPs at an estimated cost effectiveness 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 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 concluded that Proposed Rule 

1114 would not generate any significant adverse environmental impacts. The Draft EA was 

released for a 30-day public review and comment period from February 28, 2013 to March 29, 

2013, resulting in the receipt of two comment letters. Both comment letters and responses are 

included as Appendix D of the EA.

Since the release of the Draft EA, minor modifications have been made to the document. 

However, none of the modifications alter any conclusions reached in the Draft EA, nor provide 

new information of substantial importance relative to the draft document. Moreover, these minor 

revisions do not require recirculation of the Draft EA pursuant to CEQA Guidelines §15073.5
EXECUTIVE SUMMARY 

Proposed Rule 1114 ES-3 May 2013

and §15088.5. Therefore, the Draft EA is now a Final EA and is included as an attachment to 

this Governing Board package. 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 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 concluded that proposed Rule 

1114 would not generate any significant adverse environmental 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 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 information on the potential adverse environmental impacts 

of the proposed project.

The 2012 Air Quality Management Plan (AQMP), specifically Control Measure CM#2012 

MCS-01 – Application of All Feasible Measures Assessment, commits the District to adopt and 

implement new retrofit technology control standards based on research and development and 

other information, that are feasible and cost-effective 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 

BACKGROUND 
CHAPTER 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 separating 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 twentieth 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 declined, additional oil refineries 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 feedstocks. For that purpose, local refineries have 

upgraded processing equipment to be able to withstand more adverse conditions, have installed 

additional scrubbing/treating capacity and expanded the throughput of existing delayed coking 

units, which thermally break the heavy, long chain molecules and maximize liquid product yields 

while also producing petroleum coke. 

The California refineries typically process Alaska North Slope (ANS) crude, San Joaquin Valley 

(SJV) crude and crude from several other oil fields throughout California and offshore; they also 

import crude from Saudi Arabia, Iraq and Ecuador.*

Emissions from Coking

In April 1997, District enforcement staff noticed 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, District 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 other 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 test 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 (H2S) 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 installed ports on coke drum vent pipes at staff’s request. 

 

* http://www.energy.ca.gov/2005publications/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 the results. Subsequently, U.S. EPA staff, in an 

effort to develop an emission inventory for DCU’s throughout the U.S., requested several 

refineries to develop protocols and conduct source tests for their coke drum atmospheric venting. 

The first refineries to conduct the source tests were the Hovensa 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 promulgated new regulation 40 CFR 60 Subpart Ja – 

Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction or 

Modification Commenced after May 14, 2007; this new regulation affected, among other process 

units, DCU’s at petroleum refineries and established a five psig depressurization limit for the 

atmospheric venting of coke drums at refineries 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 for 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 industrial processes and regulate the amount of criteria 

pollutants and HAP emissions associated with these operations. This section focuses on the rules 

covering processes and operations directly related to petroleum refineries, most relevant being 

under Regulation IV – Prohibitions, Regulation XI – Source Specific Standards, Regulation XIV 

– Toxics and Other Non-Criteria Pollutants and Regulation XX - Regional 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 recovery and/or a disposal system for displaced 

organic vapors, as well as an operator leak inspection 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 storage 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 designed and equipped with a vapor control device such as external 

floating roofs, fixed roofs with an internal floating-type cover or a vapor recovery system. 

Rule 1173 - Control of Volatile Organic Compound 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 components at petroleum refineries through a 

self inspection leak detection 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 reduce 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 facilities 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 Emissions 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 petroleum facilities. It applies 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 vapor pressure greater than 5 mm Hg (0.1 psi) absolute under 

actual storage conditions, and are located at any 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 applies to all hydrogen plants that produce any 

hydrogen for use in petroleum refining operations. 

Particulate Emissions

Rule 404 – Particulate Matter - Concentration

Rule 404 limits the concentration of particulate 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 PM10 and Ammonia Emissions from Fluid Catalytic Cracking 

Units

Rule 1105.1 was adopted in 2003 with the purpose of reducing emissions of PM10 and 

ammonia from fluid catalytic cracking units at petroleum refineries. 

Sulfur Compounds Emissions

Rule 407 – Liquid and Gaseous Air Contaminants

Rule 407 limits emissions of sulfur compounds from any source to atmosphere, expressed as 

SO2, to 500 ppmv when averaged over 15 minutes. 

Rule 431.1 – Sulfur Content of Gaseous Fuels

Rule 431.1 establishes limits for sulfur compounds concentration in gaseous fuels. 

Rule 1118 – Control of Emissions from Refinery Flares
FINAL 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 related 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 petroleum refineries. 

Rule 2011 - Requirements for Monitoring, Reporting, and Recordkeeping for Oxides of 

Sulfur (SOx) Emissions

Rule 2011 was first adopted in 1993 and last amended in 2005. The purpose of this rule is to 

establish the monitoring, reporting, and recordkeeping 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), cancer burden, and noncancer acute and chronic 

hazard index (HI) from new permit units, relocations, or modifications to existing permit 

units which emit toxic air contaminants. 

Rule 1402 - Control of Toxic Air Contaminants 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 emissions of toxic air contaminants from existing 

sources by specifying limits for maximum individual cancer risk (MICR), cancer burden, and 

non-cancer acute and chronic hazard index (HI) applicable to total facility 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. The 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 that 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 Standards for Hazardous Air Pollutants (NESHAP) 

from Petroleum Refineries, classifies 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 vacuum distillation bottom fractions, 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 bottom fraction is then passed through a heater that brings the 

temperature to 850 °F – 900 °F and, under steam injection, is sent to the bottom of an empty coke 

drum at a pressure of 30-60 psig. The purpose 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 start 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 polymerizes to solid coke within 30 minutes to one hour. Because more 

feed and steam are forced through the drum, pores are created into the structure 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 switched to another empty drum for the start of 

another cycle. Two coke drums and a feed heater form a module 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 the 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 temperature in the drum, the vapors continue to be 

routed to the fractionation tower together with light hydrocarbons; once the stream becomes 

mostly water vapors, it is diverted to a blowdown/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 the coke drum, a high pressure water drill is 

lowered into the drum and is used to remove the coke from the drum. A pilot hole is drilled first 

with a small drill head, after which 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 crusher for size reduction and then 

conveyed to a barn for storage. On average, the coke contains 9 - 12 % volatiles, 4% sulfur and 

5 - 9% moisture, and as such is called 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 technological 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 manufacturing anodes for aluminum and titanium 

producers. In order to make anode grade coke, moisture, sulfur and metal impurities are 

removed from the green coke through a process called calcining, where coke is heated at high 

temperatures in rotary kilns, converting the coke to almost pure carbon with a defined structure. 

A process flow diagram of a delayed coker is shown below: 

Figure 1.1 - Delayed Coker Process Flow Diagram 

Atmospheric 

Vent
CHAPTER I - BACKGROUND 

Proposed Rule 1114 I-7 May 2013

G. LEGISLATIVE AUTHORITY 

The SCAQMD was created by the California Legislature in 1977 (the Lewis-Presley Air Quality 

Management Act, Health and Safety Code Section 40400 et seq.) as the agency responsible for 

developing and enforcing air pollution 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 air quality standards for the Basin (Health and 

Safety Code Section 40460(a)). In addition, the SCAQMD must adopt rules and regulations that 

implement the AQMP (Health and Safety Code Section 40440(a)). 

The long-term trend of the quality of air shows continuous improvement, although recent 

leveling off in ozone improvement causes marked concern. The SCAB, comprising the counties 

of Los Angeles, Orange, Riverside and San Bernardino, 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 most up-to-date science and analytical tools 

and incorporates a comprehensive strategy aimed at controlling pollution from all sources, 

including stationary sources, on-road and off-road mobile sources and area sources. 

Although the new federal fine particulates (PM2.5) and 8-hour surface level ozone standards 

provide a longer compliance schedule, the standards are much more stringent than the previous 

PM10 and 1-hour surface level ozone standards. To reach clean air goals in the next seven to 16 

years provided by the Clean Air Act (CCA) deadlines, Southern California must not only 

continue its diligence but intensify its pollution reduction efforts. Continuing the SCAB’s 

progress toward clean air is a challenging task, 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 PM2.5 air quality 

standard, to satisfy the planning requirements of the federal CCA, and 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 PM2.5 standard. In 

addition, the 2012 AQMP updates specific new control measures and commitments for 

emissions reductions to implement the attainment strategy for the 8-hour ozone State 

Implementation Plan (SIP), and thus help to reduce reliance on CAA Section 182(e)(5) long-term 

measures. 
C H A P T E R I I 

PROPOSED RULE LANGUAGE 
CHAPTER 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 resulting from atmospheric venting of coke drums 

and applies to petroleum refineries 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 owner or operator of a DCU to reduce the pressure in a coke drum 

to less than two (2) psig prior to venting the coke drum to atmosphere, 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 necessary 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 psig until achieving compliance with the less than 

two psig limit following the first unit turnaround scheduled after the effective date or by 

December 31, 2016, whichever is earlier. 

Facilities operating more than one DCU have two options available. Under the first option, they 

must submit for the Executive Officer’ approval within six months from rule adoption a baseline 

calculation, along with substantiating records identifying the facility wide average coke drum 

internal pressure at which atmospheric venting was initiated during the year 2012. Facilities 

currently not equipped with monitoring and recording instrumentation necessary to determine the 

2012 baseline may use general engineering practices for calculating this value, subject to 

approval. 

Effective 12 months from rule adoption, these facilities must depressurize 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 the facility is required to depressurize 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, effective 12 months following rule adoption, facilities operating more 

than one DCU must depressurize each coke drum to less than five psig until the first turnaround 
FINAL 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, these facilities must depressurize 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 compliance 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, using 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 capability 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 first 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 equipment 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 calendar year. During downtime periods, the 

owner or operator is required to manually record 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 drum being vented to atmosphere. 

For facilities that need an extended compliance schedule, these requirements are effective 12 

months after rule adoption. 

E. NOTIFICATION 

In the event of a failure of the monitoring or recording equipment, the owner 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 owner or operator of a DCU is required to maintain 

records of the coke drum’s internal pressure, the atmospheric vent valve position, pressure gauge 

calibration records and records of monitoring system breakdown periods, along with associated 

manual readings, and make them available to the 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 extended 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 codifies 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 INVENTORY 
CHAPTER 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 emissions from coke drums. During the source tests, 

staff had little input over the process parameters, such as the pressure and temperature at which 

the drums were vented and did not run multiple tests at the same location in order to be able to 

develop any correlations between these parameters. Consequently, the results were overall 

inconclusive, due also to additional factors. For example: one test had to be aborted due to 

hazardous conditions that developed; during another 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 District 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 

D1 11 1.38 0.34 0.54 N/A 12.72 

E2,3 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 comprehensive 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 the 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 inventory 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 weighted average of all drums; the pressure and 

temperature under which this drum operates represents 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 that prior to venting, the head 

space of a coke drum is filled with gas containing between 97% and 99% steam. In order to 

calculate the amount of vent gas, staff assumed that once the atmospheric vent is open, the 

quench water in the coke drum will flash to steam and lower the coke bed temperature due to 

evaporative cooling. Using the heat 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 point or 212 °F at ambient pressure. The conductive 

and convective contribution to heat loss from the 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 balance of initial and 

final states is accurate and representative for the facilities surveyed. 

2. The industry provided survey data, including facility specific number and dimensions of 

coke drums, as well as operating parameters for average final depressurization and 

internal drum temperature prior to venting and coking cycle time are accurate and 

representative for the facilities surveyed. 

3. Physical property data for steam, water and coke, including density, heat capacity and 

latent heat at operating conditions identified in the survey are representative for the 

facilities surveyed. 

4. Additional physical and operational property data (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 review of source test 

results and U.S. EPA input is representative for the facilities surveyed. 

Emission Calculations 

The heat balance equation for the coke drum is: 

(1-0.1) x (mccc + mwcw) x (ti – tf) = ms x ΔHvap (1) 

where: 

mc = coke bed mass (lbs) 

cc = coke heat capacity (Btu/lb-°F) 

ti = average initial temperature of the coke bed (°F) 

tf = average final temperature of the coke bed (°F) 

ms = mass of steam generated (lbs) 

ΔHvap = water heat of vaporization (Btu/lb) 

Solving the equation for ms: 

ms = 0.9 x (mccc + mwcw) x (ti – tf) / ΔHvap (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 number of annual cycles needs to be determined. 

For the refineries in the SCAQMD, the average cycle duration 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 cycles/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 emissions inventory is based 

on the U.S. EPA Hovensa source test results, where 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 emission 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 Emissions Inventory Calculations 

Parameter Value Unit Notes 

Avg drum diameter D 22.3 ft 

Typical outage 17.15 ft Assumed 0.25 Hd

Avg. drum height Hd 68.6 ft 

Avg. Coke bed height Hc 51.5 ft Assumed 0.75 Hd

Initial Coke Temp Tci 254 °F Weighted average temperature 

(survey) 

Final coke temp Tcf 212 °F 

Coke density ρc 84.3 lb/cu ft 

Coke heat capacity cc 0.27 Btu/lb - °F 

Coke porosity pc 0.50 Volume 

fraction Assumption 

Coke mass, mc 847,000 lbs mc= ∏*D2/4*Hc*ρc*pc

Water density ρw 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 ΔHvap 960 Btu/lb 

Water heat content cw 1 Btu/lb - °F 

Specific volume sat steam Vs 21.4 scf/lb At standard conditions 

Flashing water mass 37,100 lbs Assume all water is vaporized to 

saturated steam 

Total steam volume Vt 794,000 scf 

Vent gas volume 802,000 scf Displayed @ 99% H2O 

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 (C3) 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 tpy 
CHAPTER III – EMISSION INVENTORY 

Proposed Rule 1114 III-5 May 2013

Annual emissions are summarized in Table 3.4. It should be noted that 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 moisture 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 estimate 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 staff to determine an upper emission range for DCU 

operations indicated that a high end temperature of roughly 274 °F approximated a worse case 

scenario for comparison purposes and to reflect some of the existing facilities’ current level of 

control. Using the calculation steps previously outlined for 36 drums with an initial coke 

temperature of 274 °F results in an estimated district-wide worse 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 ASSESSMENT 
CHAPTER IV - CONTROL TECHNOLOGY ASSESSMENT 

Proposed Rule 1114 IV-1 May 2013 

Early delayed coker designs had blowdown systems that 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 pressure in the drum head space is higher than that 

of the blowdown system it is possible for the vapors 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 ambient pressure and open it for drilling the coke bed. 

Since there is a significant amount of pollutants, 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 cooling time and reduce the temperature such as to 

condense more vapors and reduce the drum’s internal pressure. However, this alternative would 

increase the coke drum cycle time length and 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 vapors 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, operating, 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, costs 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 DCU 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 being able to process more feed in the same 

amount of time. 

Currently, there are both local and outside California refineries with DCU’s that already meet or 

vent their drums at pressures near the proposed rule depressurization limit of less than two (2) 

psig. Considering that the current maximum 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 limits reflect an achieved in practice standard. 
C H A P T E R V 

EMISSION REDUCTIONS 
CHAPTER V – EMISSION REDUCTIONS 

Proposed Rule 1114 V-1 May 2013

This chapter presents the estimated VOC emission reductions based on the control option 

incorporated into PR 1114. 

From Chapter III – Emissions Inventory, the emissions attributed to coke drum venting are as 

summarized in Table 5.1, reflecting the conservative 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 proposed 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 and/or process in order to meet the proposed rule 

limit. The emission reductions will be determined by first calculating the emissions associated 

with the 26 drums at the current average vent pressure and temperature and then subtracting the 

emissions calculated at the proposed rule limit of less than two psig that approximately 

corresponds to a temperature of 220 °F. The emissions are calculated based on the same 

methodology used to calculate the baseline emission inventory. The parameters used are 

weighted averages for the 26 drums 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 Conditions (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 Hd 68.8 ft 

Avg. Coke bed height Hc 51.6 ft Assumed 0.75 of drum height 

Initial Coke Temp Tci

220 °F Weighted average temperature 

(survey) 

Final coke temp Tcf 212 °F 

Coke density ρc 84.3 lb/cu ft 

Coke heat capacity cc 0.27 Btu/lb - °F 

Coke porosity pc 0.50 Volume fraction Assumption due to channeling 

Coke mass, mc 739,000 lbs mc= ∏*D2/4*Hc*ρc*pc

Water density ρw 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 cw 1 Btu/lb - °F 

Specific volume sat 

steam Vs

21.4 scf/lb Standard conditions 

Flashing water mass 32,400 lbs Assume all water is vaporized to 

saturated steam 

Total steam volume Vt 692,800 scf Displayed @ 99% steam 

Vent gas volume (99% 

H2O) 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 (C3) 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 tpy 
CHAPTER V – EMISSION REDUCTIONS 

Proposed Rule 1114 V-3 May 2013

The emissions generated when the coke drum is vented 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. The 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 Hd 68.8 ft 

Avg. Coke bed height Hc 51.6 ft Assumed 0.75 of drum height 

Initial Coke Temp Tci 254 °F Weighted average temperature 

(survey) 

Final coke temp Tcf 212 °F 

Coke density ρc 84.3 lb/cu ft 

Coke heat capacity cc 0.27 Btu/lb - °F 

Coke porosity pc 0.50 Volume fraction Assumption due to channeling 

Coke mass, mc 739,000 lbs mc= ∏*D2/4*Hc*ρc*pc

Water density ρw 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 cw 1 Btu/lb - °F 

Specific volume sat 

steam Vs

21.4 scf/lb Standard conditions 

Flashing water mass 6,170 lbs Assume all water is vaporized to 

saturated steam 

Total steam volume Vt 132,000 scf Displayed @ 99% steam 

Vent gas volume (99% 

H2O) 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 (C3) 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 tpy 
CHAPTER 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 allowable initial vent pressure (see Chapter III page III-5). The percent 

reduction from potential emissions independent of existing regulations would be higher. 
C H A P T E R V I 

COST AND COST EFFECTIVENESS 
CHAPTER VI - COST AND COST EFFECTIVENESS 

Proposed Rule 1114 VI-1 May 2013

A. COSTS 

This chapter presents the cost effectiveness calculations 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 below. 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 discussions with the affected refineries, staff concluded that two 

refineries are already able to meet the proposed rule requirements within six months of the rule 

adoption. However, four other refineries will need to install new instrumentation and equipment 

or resize existing equipment in order to comply. 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 the rule, as this is the current design standard 

for coke drum depressurization. 

Based on costs for similar installations at two other 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 staff believes that the total 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 incorporating a contingency factor of roughly 30%. 

During individual meetings with refineries, staff was given initial cost estimates for 

modifications needed to comply with the proposed rule by the affected facilities, amounting to 

approximately $35 MM. 

B. COST EFFECTIVENESS 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 control 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 for 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 proposed changes and associated calculations and assumptions used 

to derive it are shown in the following sections. Cost effectiveness is expressed as the ratio 
FINAL STAFF REPORT 

Proposed Rule 1114 VI-2 May 2013

between the total cost of implementing a proposed control measure 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 based on the 99% steam content in 

the vent stream, the consequent cost effectiveness number is conservatively represented at 

roughly three times the value at the less conservative end of the range of 97% steam. On an 

additional note, considering that more vent gas is recovered due to the lower depressurization, it 

is estimated that 1.51 tpd of usable methane in the 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 for natural gas translates into an estimated 

$287,300 savings in annual costs for 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 rules or regulations to 

meet the requirement for Best Available Retrofit Control Technology (BARCT) pursuant to 
CHAPTER VI - COST AND COST EFFECTIVENESS 

Proposed Rule 1114 VI-3 May 2013

Sections 40918, 40919, 40920, and 40920.5, or for a feasible measure pursuant to Section 40914, 

SCAQMD is required by the Health and Safety Code 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 incremental cost-effectiveness of potential control 

options. 

Health and Safety Code 40920.6 requires determination of incremental cost-effectiveness of 

potential control options, defined as “the difference in the dollar 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 that an operator would have to 

increase the cycle time at a minimum by two hours 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 made in order to calculate the 

cost of this option. In addition, 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 gal / 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 coke can sell for approximately 

$150/ton; therefore, the value of lost production is: 

Cost of lost coke production = 560,178 tons x $150/ton = $84MM/yr 
FINAL STAFF REPORT 

Proposed Rule 1114 VI-4 May 2013

Gasoline Production

The 11% decrease in charge rate will also affect 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 gallon 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)/gal 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 emissions from venting, which is the total emission 

inventory of 268 tpy. The next less expensive control 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 incremental 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, permanent 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 $2,700,000 
C H A P T E R V I I 

COMMENTS AND RESPONSES 
CHAPTER 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 months deadline following rule adoption and the 

additional extension in the compliance deadline beyond the six months for 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 procedural updates, for facilities that can achieve the 

proposed final compliance limit with existing equipment but that may require quality control 

improvements to ensure safety and continuous compliance. Units in petroleum refineries 

typically operate continuously on approximately five year cycles in-between shutdown periods 

for maintenance and repair, or “turnaround” periods. It is during these turnarounds that 

necessary modifications can be implemented for rule compliance. The proposed up to five year 

period is intended to accommodate the staggered nature of the various turnaround periods at 

multiple facilities. Furthermore, projects that might be required for compliance with the 

proposed rule involve engineering and design, funding, equipment procurement, new hardware 

and require adequate time to complete. Therefore, staff believes that the 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 provide records of the coke drum 

internal pressure, atmospheric vent valve position (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 with the interim requirements associated with the 

proposed rule? 

Response 

Failure to comply with the interim requirements associated with the proposed rule would put a 

facility in violation of the rule, which would trigger the issuance 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 the 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 particular feedstocks be limited or excluded from 

processing? 

Response 

Typically, light sweet crude oil feedstocks have a lower amount of sulfur, whereas heavy, sour 

crude oil feedstocks contain a relatively higher amount of sulfur (~4%) as well 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 processing them in units upstream or downstream of 

the delayed coking operation. 

Comment #6 

There should be more community outreach and participation in the rule development process to 

improve awareness and address concerns. 

Response 

Staff publishes workshop notices on its website as well as local newspapers. 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 participation 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 cost that is more facility specific. The 

representativeness for the range in costs should be reconsidered. 

Response 

The initial cost estimate provided by industry are design-based, while 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 cost 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 depressurization limit? 

Response 

Once the internal pressure of the coke drum falls below two psig while being depressurized to 

the blowdown system at the end of the coking cycle, the operator has achieved compliance with 

the depressurization limit. During the short transition 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 specified limit, however these spikes will not be 

considered a violation of the depressurization limit. 

Comment #9 

Can a facility calculate the proposed 2012 interim average depressurization baseline based on 

general engineering practices due to the lack of necessary monitoring 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 using general engineering practices and substantiating 

records to be submitted to the Executive Officer for approval for determining the 2012 vent 

pressure average for all drums at a facility. 

Comment #10 

Facilities need some time following rule adoption to implement the continuous monitoring 

requirement of the proposed rule. 

Response 

The proposed rule has been modified to harmonize 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 hours of downtime per calendar year per DCU due 

to breakdowns, or maintenance or calibration of the monitoring equipment for the coke drum 

pressure and the atmospheric valve position. Manual 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 the proposed rule, and not limited to only 

those that meet the final depressurization limit of two psig. 

Response 

Staff is proposing to exempt delayed coking units from the provisions of Rule 404 only based on 

a determination that the rule does not apply to delayed coking units. Staff does not believe that 

exemptions from Rules 405 and 407 are necessary after evaluating DCU source test results that 

show compliance with the mass emission and CO emission limits; Rule 407 provisions for sulfur 

compounds emissions do not apply to equipment 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 other 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 incorporation of Executive Officer discretion into 

the State Implementation Plan (SIP), it is the general policy of the District to avoid incorporating 

this approach into rule language. Other administrative 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 report 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 preliminary 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 depiction, 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 noted in the preliminary draft staff report, were 

not run to establish correlations. Prior to drawing any conclusions with respect to correlating 

pressure and emissions, additional testing would be required. While industry may support 

additional testing in order to establish correlations between process parameters, District staff 

believes that the use of a theoretical approximation 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 discussions with the refineries and WSPA, with 

consideration of the assumptions, facilities concur that a heat balance methodology is the 

preferred approach over additional source tests. 

Comment #18 

Reference to the phrase “near-compliance” is subjective and ambiguous and should not be used 

in the staff report. 

Response 

The phrase “near-compliance” has been removed. Where appropriate, when describing the 

current status of affected facilities, the more objective reference to current operating pressures is 

used instead. 

Comment #19 

Would periods of downtime at DCU’s, such as heater tube spalling or other unplanned 

breakdowns and repairs be construed as “Turnarounds” 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 opened. 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 the vent valve position may require equipment 

upgrades dependent on turnaround scheduling. Can alternative parameters that are currently 

being monitored or that do not rely on turnaround installation be used in the interim? 

Response 

The proposed rule has incorporated an alternative 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 temperature, in lieu of monitoring the 

atmospheric vent valve position. 

Comment #21 

Can a facility’s safety interlock system for the coke drum operation be used to demonstrate 

compliance with the atmospheric vent valve position monitoring (open or closed) and recording 

requirement? 

Response 

The purpose of the vent valve monitoring requirement is to determine when atmospheric venting 

has occurred. District staff would consider continuous monitoring 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 interlock conditions clearly indicate a closed or 

opened position, and would consider a partially open valve, or valve 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 ASSESSMENT 
CHAPTER VIII – IMPACT ASSESSMENTS 

Proposed Rule 1114 VIII-1 May 2013

A. ENVIRONMENTAL IMPACT ASSESSMENT 

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 concluded that Proposed Rule 

1114 would not generate any significant adverse environmental impacts. The Draft EA was 

released for a 30-day public review and comment period from February 28, 2013 to March 29, 

2013, resulting in the receipt of two comment letters. Both comment letters and responses are 

included as Appendix D of the EA.

Since the release of the Draft EA, minor modifications have been made to the document. 

However, none of the modifications alter any conclusions reached in the Draft EA, nor provide 

new information of substantial importance relative to the draft document. Moreover, these minor 

revisions do not require recirculation of the Draft EA pursuant to CEQA Guidelines §15073.5

and §15088.5. Therefore, the Draft EA is now a Final EA and is included as an attachment to 

this Governing Board package. 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 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 PR 

1114. The environmental analysis in the Draft EA concluded that PR 1114 would not generate 

any significant adverse environmental 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 included in the Final EA. Prior to making a decision on the proposed adoption 

of PR 1114, the SCAQMD Governing Board must review and certify the Final EA as providing 

adequate information on the potential adverse environmental impacts of the proposed project.

Copies of the CEQA document prepared for PR 1114, can be obtained by calling the 

SCAQMD’s Public Information Center at (909) 396-2039 or by downloading it from the 

SCAQMD’s website at: http://www.aqmd.gov/ceqa/aqmd.html.

B. SOCIOECONOMIC ASSESSMENT 

PR 1114 would require petroleum refineries with delayed coking units (DCU’s) to reduce 

pressure in coke drums to less than two pounds per pressure inch gauge (psig) prior to venting 

coke drums to atmosphere. In addition, PR 1114 would require the affected facilities to 

continuously monitor and record the internal pressure of coke drums, and maintain records for a 

period of five years. 

Affected Industries 

The proposed rule would affect six refineries. All six affected refineries are located in Los 

Angeles County. The affected facilities belong to the sectors of petroleum refineries [North 

American Industrial Classification System (NAICS) 324110]. 

Compliance Cost 

It is assumed that affected refineries would install steam ejector systems to comply with the 

proposed pressure limit. Out of the six affected refineries, two are already capable of meeting 
FINAL 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 contingency factor of 30 percent of capital and installation cost to 

account for site-to-site variability 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-percent 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 steam ejector system is assumed to be seven 

percent of the capital, installation, and contingency 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 million). 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 equipment, installation, and 

operating and maintenance would result in increases 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 are expected to increase sales of the machinery 

manufacturing sector. However, none of those facilities are located within the four-county area. 

Installation of the above equipment, however, is expected to benefit the construction, and 

professional and technical services sectors locally. 

Overall, five jobs could be created annually, on average, between 2013 and 2035, which is about 

0.0001 percent of the baseline jobs in the four county 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 technical services would 

gain a larger share of additional jobs due to additional spending on equipment installations. 

Overall, positive job impacts from the expenditures made by petroleum refineries would more 

than offset the jobs forgone from the additional cost of doing business. The remaining sectors 

would incur minor jobs forgone from secondary 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 requires 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 (AQMP). PR 1114 partially 

implements Control Measure MCS-01—Application 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 effectiveness of the proposed rule is estimated to be $8,700 per ton of 

VOC, which is well below the cost-effectiveness 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, requirements 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 pressure, 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 that 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 partially 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 Operations 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, existing statutes, court decisions, or federal or state 

regulations. 

Non Duplication: Rule 1114 – Petroleum Refinery Coking 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, interpret 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.

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

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. 

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

8 Perry, R.H., Green, D.W., “Perry’s Chemical Engineer’s Handbook”, Seventh Edition, 

McGraw-Hill, 1997. 

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

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